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| issue date = 02/29/2016
| issue date = 02/29/2016
| title = NUREG-1437 Dfc, Supp 57, Generic Environmental Impact Statement for License Renewal of Nuclear Plants Regarding LaSalle County Station, Units 1 and 2.
| title = NUREG-1437 Dfc, Supp 57, Generic Environmental Impact Statement for License Renewal of Nuclear Plants Regarding LaSalle County Station, Units 1 and 2.
| author name = Drucker D M
| author name = Drucker D
| author affiliation = NRC/NRR
| author affiliation = NRC/NRR
| addressee name =  
| addressee name =  
Line 14: Line 14:
| page count = 481
| page count = 481
| project =  
| project =  
| stage = Other
| stage = Acceptance Review
}}
}}


=Text=
=Text=
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{{#Wiki_filter:NUREG-1437 Supplement 57 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft Report for Comment Office of Nuclear Reactor Regulation
 
AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material                                      Non-NRC Reference Material As of November 1999, you may electronically access          Documents available from public and special technical NUREG-series publications and other NRC records at          libraries include all open literature items, such as books, NRCs Library at www.nrc.gov/reading-rm.html. Publicly      journal articles, transactions, Federal Register notices, released records include, to name a few, NUREG-series        Federal and State legislation, and congressional reports.
publications; Federal Register notices; applicant,          Such documents as theses, dissertations, foreign reports licensee, and vendor documents and correspondence;          and translations, and non-NRC conference proceedings NRC correspondence and internal memoranda; bulletins        may be purchased from their sponsoring organization.
and information notices; inspection and investigative reports; licensee event reports; and Commission papers      Copies of industry codes and standards used in a and their attachments.                                      substantive manner in the NRC regulatory process are maintained at NRC publications in the NUREG series, NRC regulations,            The NRC Technical Library and Title 10, Energy, in the Code of Federal Regulations        Two White Flint North may also be purchased from one of these two sources.              11545 Rockville Pike Rockville, MD 20852-2738
: 1. The Superintendent of Documents U.S. Government Publishing Office                    These standards are available in the library for reference Mail Stop IDCC                                        use by the public. Codes and standards are usually Washington, DC 20402-0001                            copyrighted and may be purchased from the originating Internet: bookstore.gpo.gov                          organization or, if they are American National Standards, Telephone: (202) 512-1800                            from Fax: (202) 512-2104                                        American National Standards Institute 11 West 42nd Street
: 2. The National Technical Information Service                New York, NY 10036-8002 5301 Shawnee Rd., Alexandria, VA 22312-0002                www.ansi.org www.ntis.gov                                              (212) 642-4900 1-800-553-6847 or, locally, (703) 605-6000 Legally binding regulatory requirements are stated only in A single copy of each NRC draft report for comment is          laws; NRC regulations; licenses, including technical speci-available free, to the extent of supply, upon written          fications; or orders, not in NUREG-series publications. The request as follows:                                            views expressed in contractorprepared publications in this series are not necessarily those of the NRC.
Address: U.S. Nuclear Regulatory Commission                  The NUREG series comprises (1) technical and adminis-Office of Administration                            trative reports and books prepared by the staff (NUREG-XXXX) or agency contractors (NUREG/CR-XXXX), (2)
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at NRCs Web site address www.nrc.gov/reading-rm/              DISCLAIMER: This report was prepared as an account doc-collections/nuregs are updated periodically and may        of work sponsored by an agency of the U.S. Government.
differ from the last printed version. Although references to  Neither the U.S. Government nor any agency thereof, nor any employee, makes any warranty, expressed or implied, material found on a Web site bear the date the material or assumes any legal liability or responsibility for any third was accessed, the material available on the date cited        partys use, or the results of such use, of any information, may subsequently be removed from the site.                    apparatus, product, or process disclosed in this publication, or represents that its use by such third party would not infringe privately owned rights.
 
NUREG-1437 Supplement 57 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft Report for Comment Manuscript Completed: February 2016 Date Published: February 2016 Office of Nuclear Reactor Regulation
 
1 Proposed Action  Issuance of renewed operating licenses NPF-11 and NPF-18 for LaSalle 2                  County Station, Units 1 and 2 (LSCS), in LaSalle County, Illinois 3 Type of Statement Draft Supplemental Environmental Impact Statement 4 Agency Contact    Mr. David Drucker 5                  U.S. Nuclear Regulatory Commission (NRC) 6                  Office of Nuclear Reactor Regulation 7                  Mail Stop O-11F1 8                  Washington, DC 20555-0001 9                  Phone: 1-800-368-5642, extension 6223 10                  E-mail: david.drucker@nrc.gov 11 Comments          Any interested party may submit comments on this draft supplemental 12                  environmental impact statement. Please specify NUREG-1437, 13                  Supplement 57, draft, in your comments, and send them by the end of the 14                  comment period specified in the Federal Register notice announcing the 15                  availability of this report. Comments may be submitted electronically by 16                  searching for docket ID NRC-2014-0268 at the Federal rulemaking Web 17                  site, http://www.regulations.gov. Comments also may be mailed to the 18                  following address:
19                  Chief, Rules, Announcements, and Directives Branch 20                  Division of Administrative Services 21                  Office of Administration 22                  Mail Stop: OWFN-12 H08 23                  U.S. Nuclear Regulatory Commission 24                  Washington, DC 20555-0001 25                  Please be aware that any comments that you submit to the NRC will be 26                  considered a public record and entered into the Agencywide Documents 27                  Access and Management System. Do not provide information you would 28                  not want to be publicly available.
 
1                                          COVER SHEET 2 Responsible Agency: U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor 3 Regulation. There are no cooperating agencies involved in the preparation of this document.
4 Title: Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 5 Supplement 57, Regarding LaSalle County Station, Units 1 and 2, Draft Report for Comment 6 (NUREG-1437). LaSalle County Station is located in LaSalle County, Illinois.
7 For additional information or copies of this document contact:
8                                      Division of License Renewal 9                                U.S. Nuclear Regulatory Commission 10                                Office of Nuclear Reactor Regulation 11                                            Mail Stop O-11F1 12                                          11555 Rockville Pike 13                                      Rockville, Maryland 20852 14                              Phone: 1-800-368-5642, extension 6223 15                                    Email: david.drucker@nrc.gov 16                                            ABSTRACT 17 This supplemental environmental impact statement (SEIS) has been prepared in response to an 18 application submitted by Exelon Generation Company, LLC (Exelon), to renew the operating 19 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years.
20 This SEIS includes the preliminary analysis that evaluates the environmental impacts of the 21 proposed action and alternatives to the proposed action. Alternatives considered include:
22 (1) new nuclear power generation, (2) coal-integrated gasification combined-cycle, (3) natural 23 gas combined-cycle (NGCC), (4) a combination of NGCC, wind, and solar generation, 24 (5) purchased power, and (6) the no-action alternative (i.e., no renewal of the license).
25 The U.S. Nuclear Regulatory Commission (NRC) staffs preliminary recommendation is that the 26 adverse environmental impacts of license renewal for LSCS are not so great that preserving the 27 option of license renewal for energy-planning decisionmakers would be unreasonable. The 28 NRC staff based its recommendation on the following factors:
29
* the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic Environmental 30              Impact Statement for License Renewal of Nuclear Plants; 31
* the Environmental Report submitted by Exelon; 32
* the NRC staffs consultation with Federal, State, local, and Tribal Government 33              agencies; 34
* the NRC staffs independent environmental review; and 35
* the NRC staffs consideration of public comments received during the scoping 36              process.
iii
 
1                                            TABLE OF CONTENTS 2 ABSTRACT .............................................................................................................................. iii 3 TABLE OF CONTENTS ............................................................................................................ v 4 FIGURES ................................................................................................................................. xv 5 TABLES ................................................................................................................................ xvii 6 EXECUTIVE
 
==SUMMARY==
........................................................................................................ xxi 7 ABBREVIATIONS AND ACRONYMS ..................................................................................xxvii 8
 
==1.0  INTRODUCTION==
.......................................................................................................... 1-1 9      1.1      Proposed Federal Action.................................................................................. 1-1 10      1.2      Purpose and Need for Proposed Federal Action .............................................. 1-1 11      1.3      Major Environmental Review Milestones .......................................................... 1-1 12      1.4      Generic Environmental Impact Statement ........................................................ 1-2 13      1.5      Supplemental Environmental Impact Statement ............................................... 1-4 14      1.6      Decisions to Be Supported by the SEIS ........................................................... 1-5 15      1.7      Cooperating Agencies ...................................................................................... 1-5 16      1.8      Consultations ................................................................................................... 1-5 17      1.9      Correspondence .............................................................................................. 1-6 18      1.10    Status of Compliance ....................................................................................... 1-6 19      1.11    Related Federal and State Activities ................................................................ 1-6 20      1.12    References ...................................................................................................... 1-7 21 2.0  ALTERNATIVES INCLUDING THE PROPOSED ACTION .......................................... 2-1 22      2.1      Proposed Action .............................................................................................. 2-1 23                2.1.1          Plant Operations during the License Renewal Term......................... 2-1 24                2.1.2          Refurbishment and Other Activities Associated with License 25                                Renewal ........................................................................................... 2-2 26                2.1.3          Termination of Nuclear Power Plant Operations and 27                                Decommissioning after the License Renewal Term .......................... 2-2 28      2.2      Alternatives ...................................................................................................... 2-3 29                2.2.1          No-Action Alternative ....................................................................... 2-3 30                2.2.2          Replacement Power Alternatives ..................................................... 2-4 31                                2.2.2.1            New Nuclear Alternative ................................................ 2-9 32                                2.2.2.2            IGCC Alternative ......................................................... 2-11 33                                2.2.2.3            NGCC Alternative ........................................................ 2-13 34                                2.2.2.4            Combination Alternative (NGCC, Wind, and Solar)...... 2-13 35                                2.2.2.5            Purchased Power Alternative ...................................... 2-16 36      2.3      Alternatives Considered but Dismissed .......................................................... 2-17 37                2.3.1          Energy Conservation and Energy Efficiency .................................. 2-17 38                2.3.2          Solar .............................................................................................. 2-17 v
 
Table of Contents 1              2.3.3    Wind .............................................................................................. 2-18 2                        2.3.3.1          Offshore Wind ............................................................. 2-18 3                        2.3.3.2          Wind Power with Storage ............................................ 2-19 4                        2.3.3.3          Conclusion .................................................................. 2-19 5              2.3.4    Biomass ......................................................................................... 2-19 6              2.3.5    Hydroelectric .................................................................................. 2-20 7              2.3.6    Wave and Ocean Energy ............................................................... 2-20 8              2.3.7    Fuel Cells ....................................................................................... 2-21 9              2.3.8    Delayed Retirement ....................................................................... 2-21 10              2.3.9    Geothermal .................................................................................... 2-22 11              2.3.10    Municipal Solid Waste .................................................................... 2-22 12              2.3.11    Petroleum ...................................................................................... 2-23 13              2.3.12    Supercritical Pulverized Coal ......................................................... 2-23 14        2.4    Comparison of Alternatives ............................................................................ 2-23 15        2.5    References .................................................................................................... 2-27 16 3.0  AFFECTED ENVIRONMENT ....................................................................................... 3-1 17        3.1    Description of Nuclear Power Plant Facility and Operation .............................. 3-1 18              3.1.1    External Appearance and Setting ..................................................... 3-1 19              3.1.2    Nuclear Reactor Systems................................................................. 3-6 20              3.1.3    Cooling and Auxiliary Water Systems .............................................. 3-6 21              3.1.4    Radioactive Waste Management Systems ..................................... 3-13 22                        3.1.4.1          Radioactive Liquid Waste Management ...................... 3-13 23                        3.1.4.2          Radioactive Gaseous Waste Management .................. 3-15 24                        3.1.4.3          Radioactive Solid Waste Management ........................ 3-16 25                        3.1.4.4          Radioactive Waste Storage ......................................... 3-17 26                        3.1.4.5          Radiological Environmental Monitoring Program ......... 3-17 27              3.1.5    Nonradioactive Waste Management Systems ................................ 3-18 28              3.1.6    Utility and Transportation Infrastructure.......................................... 3-18 29                        3.1.6.1          Electricity ..................................................................... 3-19 30                        3.1.6.2          Fuel ............................................................................. 3-19 31                        3.1.6.3          Water .......................................................................... 3-19 32                        3.1.6.4          Transportation Systems............................................... 3-19 33                        3.1.6.5          Power Transmission Systems ..................................... 3-20 34              3.1.7    Nuclear Power Plant Operations and Maintenance ........................ 3-20 35        3.2    Land Use and Visual Resources .................................................................... 3-21 36              3.2.1    Land Use ....................................................................................... 3-21 37                        3.2.1.1          Onsite Land Use ......................................................... 3-21 38                        3.2.1.2          Coastal Zone ............................................................... 3-22 39                        3.2.1.3          Offsite Land Use ......................................................... 3-22 40              3.2.2    Visual Resources ........................................................................... 3-24 41        3.3    Meteorology, Air Quality, and Noise ............................................................... 3-24 vi
 
Table of Contents 1    3.3.1      Meteorology and Climatology ......................................................... 3-24 2    3.3.2      Air Quality ...................................................................................... 3-25 3    3.3.3      Noise ............................................................................................. 3-28 4 3.4 Geologic Environment .................................................................................... 3-29 5    3.4.1      Physiography and Geology ............................................................ 3-29 6    3.4.2      Soils ............................................................................................... 3-30 7    3.4.3      Seismic Setting .............................................................................. 3-34 8 3.5 Water Resources ........................................................................................... 3-35 9    3.5.1      Surface Water Resources .............................................................. 3-35 10                3.5.1.1          Surface Water Hydrology ............................................ 3-35 11                3.5.1.2          Surface Water Use ...................................................... 3-39 12                3.5.1.3          Surface Water Quality and Effluents ............................ 3-41 13    3.5.2      Groundwater Resources ................................................................ 3-46 14                3.5.2.1          Site Description and Hydrogeology ............................. 3-46 15                3.5.2.2          Groundwater Use ........................................................ 3-48 16                3.5.2.3          Groundwater Quality ................................................... 3-51 17 3.6 Terrestrial Resources ..................................................................................... 3-52 18    3.6.1      LSCS Ecoregion ............................................................................ 3-52 19    3.6.2      LSCS Site Surveys, Studies, and Reports...................................... 3-53 20    3.6.3      LSCS Site ...................................................................................... 3-54 21                3.6.3.1          Vegetation ................................................................... 3-54 22                3.6.3.2          Wildlife ........................................................................ 3-55 23    3.6.4      LSCS Wildlife Management Plan ................................................... 3-55 24    3.6.5      Important Species and Habitats ..................................................... 3-56 25                3.6.5.1          Important Species ....................................................... 3-56 26                3.6.5.2          Important Habitats ....................................................... 3-58 27    3.6.6      Invasive and Non-Native Species................................................... 3-59 28 3.7 Aquatic Resources ......................................................................................... 3-59 29    3.7.1      Illinois River ................................................................................... 3-59 30                3.7.1.1          Aquatic Communities in the Illinois River ..................... 3-60 31    3.7.2      LSCS Cooling Pond ....................................................................... 3-67 32                3.7.2.1          Aquatic Community in the Cooling Pond ..................... 3-68 33                3.7.2.2          Cooling Pond Fish Kill Events...................................... 3-69 34    3.7.3      Important Species and Habitats ..................................................... 3-69 35                3.7.3.1          State-Listed Species ................................................... 3-69 36                3.7.3.2          Important Habitats ....................................................... 3-72 37    3.7.4      Non-Native Species ....................................................................... 3-72 38 3.8 Federally Protected Species and Habitats...................................................... 3-73 39    3.8.1      Action Area .................................................................................... 3-73 40    3.8.2      Federally Protected Species and Habitats Considered................... 3-74 41 3.9 Historic and Cultural Resources ..................................................................... 3-79 vii
 
Table of Contents 1              3.9.1      Cultural Background....................................................................... 3-80 2              3.9.2      Historic and Cultural Resources ..................................................... 3-82 3        3.10  Socioeconomics ............................................................................................. 3-82 4              3.10.1    Power Plant Employment and Expenditures .................................. 3-83 5              3.10.2    Regional Economic Characteristics ................................................ 3-83 6                          3.10.2.1          Employment and Income ............................................. 3-84 7                          3.10.2.2          Unemployment ............................................................ 3-86 8              3.10.3    Demographic Characteristics ......................................................... 3-86 9                          3.10.3.1          Transient Population ................................................... 3-88 10                          3.10.3.2          Migrant Farm Workers ................................................. 3-89 11              3.10.4    Housing and Community Services ................................................. 3-90 12                          3.10.4.1          Housing ....................................................................... 3-91 13                          3.10.4.2          Education .................................................................... 3-91 14                          3.10.4.3          Public Water Supply .................................................... 3-91 15              3.10.5    Tax Revenues ................................................................................ 3-93 16              3.10.6    Local Transportation ...................................................................... 3-95 17        3.11  Human Health ................................................................................................ 3-96 18              3.11.1    Radiological Exposure and Risk ..................................................... 3-96 19              3.11.2    Chemical Hazards .......................................................................... 3-97 20              3.11.3    Microbiological Hazards ................................................................. 3-97 21                          3.11.3.1          Thermophilic Microorganisms of Concern ................... 3-98 22                          3.11.3.2          Prevalence of Waterborne Diseases Associated 23                                            with Recreational Waters............................................. 3-99 24              3.11.4    Electromagnetic Fields ................................................................... 3-99 25              3.11.5    Other Hazards.............................................................................. 3-100 26        3.12  Environmental Justice .................................................................................. 3-101 27              3.12.1    Minority Population ...................................................................... 3-102 28              3.12.2    Low-Income Population................................................................ 3-102 29        3.13  Waste Management and Pollution Prevention.............................................. 3-106 30              3.13.1    Radioactive Waste ....................................................................... 3-106 31              3.13.2    Nonradioactive Waste .................................................................. 3-106 32        3.14  References .................................................................................................. 3-106 33 4.0  ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS ........................ 4-1 34        4.1    Introduction ...................................................................................................... 4-1 35        4.2    Land Use and Visual Resources ...................................................................... 4-1 36              4.2.1      Proposed Action............................................................................... 4-1 37              4.2.2      No-Action Alternative ....................................................................... 4-2 38                          4.2.2.1          Land Use ....................................................................... 4-2 39                          4.2.2.2          Visual Resources .......................................................... 4-2 40              4.2.3      New Nuclear Alternative ................................................................... 4-3 41                          4.2.3.1          Land Use ....................................................................... 4-3 viii
 
Table of Contents 1                4.2.3.2    Visual Resources .......................................................... 4-3 2    4.2.4      IGCC Alternative .............................................................................. 4-3 3                4.2.4.1    Land Use ....................................................................... 4-3 4                4.2.4.2    Visual Resources .......................................................... 4-4 5    4.2.5      Natural Gas Combined-Cycle Alternative ......................................... 4-4 6                4.2.5.1    Land Use ....................................................................... 4-4 7                4.2.5.2    Visual Resources .......................................................... 4-4 8    4.2.6      Combination Alternative (NGCC, Wind, Solar) ................................. 4-5 9                4.2.6.1    Land Use ....................................................................... 4-5 10                4.2.6.2    Visual Resources .......................................................... 4-5 11    4.2.7      Purchased Power Alternative ........................................................... 4-6 12                4.2.7.1    Land Use ....................................................................... 4-6 13                4.2.7.2    Visual Resources .......................................................... 4-6 14 4.3 Air Quality and Noise ....................................................................................... 4-6 15    4.3.1      Proposed Action............................................................................... 4-6 16                4.3.1.1    Air Quality ..................................................................... 4-6 17                4.3.1.2    Noise ............................................................................. 4-7 18    4.3.2      No-Action Alternative ....................................................................... 4-7 19                4.3.2.1    Air Quality ..................................................................... 4-7 20                4.3.2.2    Noise ............................................................................. 4-7 21    4.3.3      New Nuclear Alternative ................................................................... 4-7 22                4.3.3.1    Air Quality ..................................................................... 4-7 23                4.3.3.2    Noise ............................................................................. 4-9 24    4.3.4      IGCC Alternative ............................................................................ 4-10 25                4.3.4.1    Air Quality ................................................................... 4-10 26                4.3.4.2    Noise ........................................................................... 4-13 27    4.3.5      NGCC Alternative .......................................................................... 4-13 28                4.3.5.1    Air Quality ................................................................... 4-13 29                4.3.5.2    Noise ........................................................................... 4-15 30    4.3.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-16 31                4.3.6.1    Air Quality ................................................................... 4-16 32                4.3.6.2    Noise ........................................................................... 4-18 33    4.3.7      Purchased Power Alternative ......................................................... 4-19 34                4.3.7.1    Air Quality ................................................................... 4-19 35                4.3.7.2    Noise ........................................................................... 4-19 36 4.4 Geologic Environment .................................................................................... 4-20 37    4.4.1      Proposed Action............................................................................. 4-20 38    4.4.2      No-Action Alternative ..................................................................... 4-20 39    4.4.3      New Nuclear Alternative ................................................................. 4-20 40    4.4.4      IGCC Alternative ............................................................................ 4-21 41    4.4.5      NGCC Alternative .......................................................................... 4-21 ix
 
Table of Contents 1              4.4.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-21 2              4.4.7      Purchased Power Alternative ......................................................... 4-21 3        4.5    Water Resources ........................................................................................... 4-21 4              4.5.1      Proposed Action............................................................................. 4-22 5                          4.5.1.1    Surface Water Resources ........................................... 4-22 6                          4.5.1.2    Groundwater Resources.............................................. 4-24 7              4.5.2      No-Action Alternative ..................................................................... 4-26 8                          4.5.2.1    Surface Water Resources ........................................... 4-26 9                          4.5.2.2    Groundwater Resources.............................................. 4-26 10              4.5.3      New Nuclear Alternative ................................................................. 4-26 11                          4.5.3.1    Surface Water Resources ........................................... 4-26 12                          4.5.3.2    Groundwater Resources.............................................. 4-27 13              4.5.4      IGCC Alternative ............................................................................ 4-27 14                          4.5.4.1    Surface Water Resources ........................................... 4-27 15                          4.5.4.2    Groundwater Resources.............................................. 4-28 16              4.5.5      NGCC Alternative .......................................................................... 4-28 17                          4.5.5.1    Surface Water Resources ........................................... 4-28 18                          4.5.5.2    Groundwater Resources.............................................. 4-29 19              4.5.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-29 20                          4.5.6.1    Surface Water Resources ........................................... 4-29 21                          4.5.6.2    Groundwater Resources.............................................. 4-30 22              4.5.7      Purchased Power Alternative ......................................................... 4-30 23                          4.5.7.1    Surface Water Resources ........................................... 4-30 24                          4.5.7.2    Groundwater Resources.............................................. 4-30 25        4.6    Terrestrial Resources ..................................................................................... 4-30 26              4.6.1      Proposed Action............................................................................. 4-31 27                          4.6.1.1    Generic GEIS Issues ................................................... 4-31 28                          4.6.1.2    Effects on Terrestrial Resources (Non-Cooling 29                                      System Impacts) ......................................................... 4-31 30                          4.6.1.3    Water Use Conflicts with Terrestrial Resources ........... 4-33 31              4.6.2      No-Action Alternative ..................................................................... 4-34 32              4.6.3      New Nuclear Alternative ................................................................. 4-34 33              4.6.4      IGCC Alternative ............................................................................ 4-35 34              4.6.5      NGCC Alternative .......................................................................... 4-35 35              4.6.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-36 36              4.6.7      Purchased Power Alternative ......................................................... 4-37 37        4.7    Aquatic Resources ......................................................................................... 4-37 38              4.7.1      Proposed Action............................................................................. 4-37 39                          4.7.1.1    GEIS Category 1 Issues .............................................. 4-38 40                          4.7.1.2    Impingement and Entrainment of Aquatic 41                                      Organisms ................................................................... 4-38 x
 
Table of Contents 1                4.7.1.3      Thermal Impacts on Aquatic Organisms ...................... 4-45 2                4.7.1.4      Water Use Conflicts with Aquatic Resources ............... 4-52 3      4.7.2      No-Action Alternative ..................................................................... 4-52 4      4.7.3      New Nuclear Alternative ................................................................. 4-53 5      4.7.4      IGCC Alternative ............................................................................ 4-53 6      4.7.5      NGCC Alternative .......................................................................... 4-54 7      4.7.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-54 8      4.7.7      Purchased Power Alternative ......................................................... 4-54 9 4.8  Special Status Species and Habitats.............................................................. 4-55 10      4.8.1      Proposed Action............................................................................. 4-55 11      4.8.2      No-Action Alternative ..................................................................... 4-57 12      4.8.3      New Nuclear Alternative ................................................................. 4-57 13      4.8.4      IGCC Alternative ............................................................................ 4-58 14      4.8.5      NGCC Alternative .......................................................................... 4-58 15      4.8.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-59 16      4.8.7      Purchased Power Alternative ......................................................... 4-59 17 4.9  Historic and Cultural Resources ..................................................................... 4-59 18      4.9.1      Proposed Action............................................................................. 4-60 19      4.9.2      No-Action Alternative ..................................................................... 4-62 20      4.9.3      New Nuclear Alternative ................................................................. 4-62 21      4.9.4      IGCC Alternative ............................................................................ 4-62 22      4.9.5      NGCC Alternative .......................................................................... 4-63 23      4.9.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-63 24      4.9.7      Purchased Power Alternative ......................................................... 4-64 25 4.10 Socioeconomics ............................................................................................. 4-64 26      4.10.1    Proposed Action............................................................................. 4-65 27      4.10.2    No-Action Alternative ..................................................................... 4-65 28                4.10.2.1    Socioeconomics .......................................................... 4-65 29                4.10.2.2    Transportation ............................................................. 4-66 30      4.10.3    New Nuclear Alternative ................................................................. 4-66 31                4.10.3.1    Socioeconomics .......................................................... 4-66 32                4.10.3.2    Transportation ............................................................. 4-67 33      4.10.4    IGCC Alternative ............................................................................ 4-67 34                4.10.4.1    Socioeconomics .......................................................... 4-67 35                4.10.4.2    Transportation ............................................................. 4-68 36      4.10.5    NGCC Alternative .......................................................................... 4-69 37                4.10.5.1    Socioeconomics .......................................................... 4-69 38                4.10.5.2    Transportation ............................................................. 4-69 39      4.10.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-70 40                4.10.6.1    Socioeconomics .......................................................... 4-70 41                4.10.6.2    Transportation ............................................................. 4-71 xi
 
Table of Contents 1              4.10.7    Purchased Power Alternative ......................................................... 4-71 2                        4.10.7.1      Socioeconomics .......................................................... 4-71 3                        4.10.7.2      Transportation ............................................................. 4-71 4        4.11  Human Health ................................................................................................ 4-72 5              4.11.1    Proposed Action............................................................................. 4-72 6                        4.11.1.1      Normal Operating Conditions ...................................... 4-72 7                        4.11.1.2      Environmental Impacts of Postulated Accidents .......... 4-75 8              4.11.2    No-Action Alternative ..................................................................... 4-88 9              4.11.3    New Nuclear Alternative ................................................................. 4-89 10              4.11.4    IGCC Alternative ............................................................................ 4-89 11              4.11.5    NGCC Alternative .......................................................................... 4-90 12              4.11.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-90 13              4.11.7    Purchased Power Alternative ......................................................... 4-90 14        4.12  Environmental Justice .................................................................................... 4-91 15              4.12.1    Proposed Action............................................................................. 4-91 16              4.12.2    No-Action Alternative ..................................................................... 4-93 17              4.12.3    New Nuclear Alternative ................................................................. 4-93 18              4.12.4    IGCC Alternative ............................................................................ 4-94 19              4.12.5    NGCC Alternative .......................................................................... 4-95 20              4.12.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-95 21              4.12.7    Purchased Power Alternative ......................................................... 4-96 22        4.13  Waste Management ....................................................................................... 4-97 23              4.13.1    Proposed Action............................................................................. 4-97 24              4.13.2    No-Action Alternative ..................................................................... 4-98 25              4.13.3    New Nuclear Alternative ................................................................. 4-98 26              4.13.4    IGCC Alternative ............................................................................ 4-98 27              4.13.5    NGCC Alternative .......................................................................... 4-99 28              4.13.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-99 29              4.13.7    Purchased Power Alternative ......................................................... 4-99 30        4.14  Evaluation of New and Potentially Significant Information .............................. 4-99 31        4.15  Impacts Common to All Alternatives............................................................. 4-100 32              4.15.1    Fuel Cycles .................................................................................. 4-100 33                        4.15.1.1      Uranium Fuel Cycle ................................................... 4-101 34                        4.15.1.2      Replacement Power Plant Fuel Cycles...................... 4-102 35              4.15.2    Terminating Power Plant Operations and Decommissioning ........ 4-102 36                        4.15.2.1      Existing Nuclear Power Plant .................................... 4-103 37                        4.15.2.2      Replacement Power Plants ....................................... 4-103 38              4.15.3    Greenhouse Gas Emissions and Climate Change ....................... 4-104 39                        4.15.3.1      Greenhouse Gas Emissions from the Proposed 40                                        Project and Alternatives............................................. 4-104 41                        4.15.3.2      Climate Change Impacts to Resource Areas ............. 4-107 xii
 
Table of Contents 1      4.16  Cumulative Impacts of the Proposed Action ................................................. 4-113 2            4.16.1          Air Quality and Noise ................................................................... 4-113 3                            4.16.1.1          Air Quality ................................................................. 4-114 4                            4.16.1.2          Noise ......................................................................... 4-115 5            4.16.2          Geology and Soils ........................................................................ 4-115 6            4.16.3          Water Resources ......................................................................... 4-116 7                            4.16.3.1          Surface Water Resources ......................................... 4-116 8                            4.16.3.2          Groundwater Resources............................................ 4-120 9            4.16.4          Terrestrial Resources ................................................................... 4-121 10            4.16.5          Aquatic Resources ....................................................................... 4-124 11                            4.16.5.1          Energy Development ................................................. 4-124 12                            4.16.5.2          Future Urbanization and Transportation 13                                              Development ............................................................. 4-125 14                            4.16.5.3          Wildlife Preserves, Parks, and Recreational Areas .... 4-125 15                            4.16.5.4          Illinois Wildlife Conservation Plan .............................. 4-125 16                            4.16.5.5          Conclusion ................................................................ 4-125 17            4.16.6          Historic and Cultural Resources ................................................... 4-126 18            4.16.7          Socioeconomics ........................................................................... 4-126 19            4.16.8          Human Health .............................................................................. 4-127 20            4.16.9          Environmental Justice .................................................................. 4-127 21            4.16.10 Waste Management ..................................................................... 4-128 22            4.16.11 Global Climate Change ................................................................ 4-129 23            4.16.12 Summary of Cumulative Impacts.................................................. 4-130 24      4.17  Resource Commitments............................................................................... 4-132 25            4.17.1          Unavoidable Adverse Environmental Impacts .............................. 4-132 26            4.17.2          Short-Term Versus Long-Term Productivity ................................. 4-133 27            4.17.3          Irreversible and Irretrievable Commitments of Resources ............ 4-133 28      4.18  References .................................................................................................. 4-134 29
 
==5.0 CONCLUSION==
............................................................................................................. 5-1 30      5.1  Environmental Impacts of License Renewal ..................................................... 5-1 31      5.2  Comparison of Alternatives .............................................................................. 5-1 32      5.3  Recommendation ............................................................................................. 5-1 33 6.0 LIST OF PREPARERS ................................................................................................ 6-1 34 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES 35      OF THIS SEIS ARE SENT .......................................................................................... 7-1 36 8.0 INDEX .......................................................................................................................... 8-1 37 APPENDIX A    COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW ...... A-1 38 APPENDIX B    APPLICABLE LAWS, REGULATIONS, AND OTHER 39              REQUIREMENTS ......................................................................................... B-1 40 APPENDIX C    CONSULTATION CORRESPONDENCE ..................................................... C-1 xiii
 
Table of Contents 1 APPENDIX D      CHRONOLOGY OF ENVIRONMENTAL REVIEW 2                CORRESPONDENCE .................................................................................. D-1 3 APPENDIX E      PROJECTS AND ACTIONS CONSIDERED IN CUMULATIVE IMPACTS 4                ANALYSIS.................................................................................................... E-1 5 APPENDIX F      U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 6                OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 7                LASALLE COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF 8                LICENSE RENEWAL APPLICATION REVIEW............................................ F-1 9 APPENDIX G      TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL ................G-1 xiv
 
1                                            FIGURES 2 Figure 1-1. Environmental Review Process........................................................................ 1-2 3 Figure 1-2. Environmental Issues Evaluated for License Renewal ..................................... 1-4 4 Figure 2-1. Territories of MISO and PJM Interconnection................................................... 2-6 5 Figure 3-1. LSCS 50-mi (80-km) Radius Map .................................................................... 3-2 6 Figure 3-2. LSCS 6-mi (10-km) Radius Map ...................................................................... 3-3 7 Figure 3-3. LSCS Site Layout............................................................................................. 3-4 8 Figure 3-4. LSCS Plant Features ....................................................................................... 3-5 9 Figure 3-5. Closed-Cycle Cooling System with Cooling Pond ............................................ 3-7 10 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities ...................................... 3-9 11 Figure 3-7. Site Physiography, LSCS Vicinity ................................................................... 3-31 12 Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity ...................................... 3-32 13 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity ................................ 3-33 14 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries ..................... 3-37 15 Figure 3-11. LSCS Surface Water and Related Water Resource Features ........................ 3-38 16 Figure 3-12. LSCS Site Hydrogeologic Units...................................................................... 3-47 17 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill .................................... 3-49 18 Figure 3-14. LSCS Hydrogeologic Cross-Section............................................................... 3-50 19 Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure........... 3-62 20 Figure 3-16. Sampling Locations in LSCS Aquatic Surveys ............................................... 3-63 21 Figure 3-17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS .................... 3-104 22 Figure 3-18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS ............. 3-105 23 Figure G-1. Illustration of Truck Stop Model ....................................................................... G-6 xv
 
1                                                      TABLES 2 Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 3            License Renewal............................................................................................. xxiii 4 Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 5            Considered in Depth ........................................................................................ 2-8 6 Table 2-2. Summary of Environmental Impacts of Proposed Action and 7            Alternatives .................................................................................................... 2-25 8 Table 3-1. LSCS Site Land Uses by Area ....................................................................... 3-21 9 Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS ........................................... 3-23 10 Table 3-3. National Ambient Air Quality Standards ......................................................... 3-26 11 Table 3-4. LSCS Air Emissions (MT/year)....................................................................... 3-27 12 Table 3-5. Common Noise Sources and Noise Levels .................................................... 3-28 13 Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, 14            LSCS ............................................................................................................. 3-40 15 Table 3-7. National Pollutant Discharge Elimination System-Permitted Outfalls, 16            LSCS ............................................................................................................. 3-43 17 Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion............................... 3-52 18 Table 3-9. State-Listed Species in LaSalle County ......................................................... 3-56 19 Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River ............ 3-65 20 Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural 21            History Electrofishing Surveys from 1957 through 2009 ................................. 3-67 22 Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 ................................... 3-68 23 Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle 24            County ........................................................................................................... 3-70 25 Table 3-14. Federally Listed Species and Designated Habitat in La Salle County, 26            Illinois............................................................................................................. 3-75 27 Table 3-15. LSCS Employees Residence by County ........................................................ 3-83 28 Table 3-16. Employment by Industry in the LSCS ROI (2014, 1-year estimates and 29            2009-2013, 5-year estimates) ........................................................................ 3-84 30 Table 3-17. Major Employers in LaSalle County in 2009 ................................................... 3-85 31 Table 3-18. Estimated Income Information for the LSCS ROI (2014 estimates, 32            unless otherwise indicated) ............................................................................ 3-85 33 Table 3-19. Population and Percent Growth in LSCS ROI Counties 1980-2010, 34            2014 (estimated), and Projected for 2020-2060 ............................................ 3-86 35 Table 3-20. Demographic Profile of the Population in the LSCS ROI in 2010 ................... 3-87 36 Table 3-21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County) ................... 3-87 37 Table 3-22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of 38            LSCS ............................................................................................................. 3-88 39 Table 3-23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 40            within 50 mi (80 km) of LSCS (2012).............................................................. 3-90 41 Table 3-24. Housing in the LSCS ROI (2014 estimate) ..................................................... 3-91 42 Table 3-25. Local Public Water Supply Systems ............................................................... 3-92 xvii
 
1 Table 3-26. LSCS Power Block Tax Payments and Valuations 2007-2014 (in 2            dollars) ........................................................................................................... 3-93 3 Table 3-27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total 4            Levy ............................................................................................................... 3-94 5 Table 3-28. Annual Payments to Illinois Emergency Management Agency 2009-6            2014............................................................................................................... 3-95 7 Table 3-29. Major Commuting Routes in the Vicinity of LSCS: 2013-2014 Average 8            Annual Daily Traffic Count ............................................................................. 3-95 9 Table 4-1. Land Use and Visual Resource Issues............................................................. 4-2 10 Table 4-2. Air Quality and Noise ....................................................................................... 4-7 11 Table 4-3. Geology and Soils Issues............................................................................... 4-20 12 Table 4-4. Surface Water Resources Issues ................................................................... 4-22 13 Table 4-5. Groundwater Issues ....................................................................................... 4-24 14 Table 4-6. Terrestrial Resource Issues ........................................................................... 4-31 15 Table 4-7. Aquatic Resource Issues ............................................................................... 4-37 16 Table 4-8. Special Status Species and Habitat Issues .................................................... 4-55 17 Table 4-9. Federally Listed Species and Designated Habitat in LaSalle County, 18            Illinois, and NRC Effect Determinations for Proposed LSCS License 19            Renewal ......................................................................................................... 4-56 20 Table 4-10. Historic and Cultural Resources Issue ........................................................... 4-60 21 Table 4-11. Socioeconomic NEPA Issues Affected by License Renewal .......................... 4-65 22 Table 4-12. Human Health Issues ..................................................................................... 4-72 23 Table 4-13. Issues Related to Postulated Accidents ......................................................... 4-76 24 Table 4-14. LSCS CDF for Internal Events ....................................................................... 4-79 25 Table 4-15. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 26            for Internal Events .......................................................................................... 4-81 27 Table 4-16. LSCS Potentially Cost-Beneficial SAMAs ...................................................... 4-84 28 Table 4-17. Environmental Justice NEPA Issue ................................................................ 4-91 29 Table 4-18. Waste Management Issues ............................................................................ 4-97 30 Table 4-19. Issues Related to the Uranium Fuel Cycle ................................................... 4-101 31 Table 4-20. Issues Related to Decommissioning ............................................................ 4-103 32 Table 4-21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)......... 4-105 33 Table 4-22. Direct GHG Emissions from Operation of the Proposed Action and 34            Alternatives .................................................................................................. 4-107 35 Table 4-23. Comparison of GHG Emission Inventories ................................................... 4-130 36 Table 4-24. Summary of Cumulative Impacts on Resource Areas .................................. 4-131 37 Table 6-1. List of Preparers .............................................................................................. 6-1 38 Table B-1. Federal and State Requirements ..................................................................... B-2 39 Table B-2. Licenses and Permits ....................................................................................... B-7 40 Table C-1. ESA Section 7 Consultation Correspondence ..................................................C-2 41 Table C-2. NHPA Correspondence....................................................................................C-3 42 Table D-1. Environmental Review Correspondence ..........................................................D-1 43 Table E-1. Projects and Actions Considered in Cumulative Impact Analysis ..................... E-1
 
Tables 1 Table F-1. LaSalle County Station CDF for Internal Events ............................................... F-3 2 Table F-2. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 3              for Internal Events ............................................................................................ F-4 4 Table F-3. Summary of Major PRA Models and Corresponding CDF and LERF 5              Results............................................................................................................. F-7 6 Table F-4. Dominant LSCS Contributors to Seismic CDF ............................................... F-12 7 Table F-5(a). Dominant LSCS Unit 1 Fire Zone Contributors to Fire CDF of 8.9x10-6 8              per year ......................................................................................................... F-14 9 Table F-5(b). Dominant LSCS Unit 2 Fire Zone Contributors to Fire CDF of 9.4x10-6 10              per year ......................................................................................................... F-14 11 Table F-6. SAMA Cost-Benefit Screening Analysis for LSCS Station .............................. F-33 12 Table G-1. Transportation Route Information for Shipments from LSCS to the 13              Proposed Yucca Mountain Repository Site ..................................................... G-4 14 Table G-2. RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters ....................... G-5 15 Table G-3. Annual Normal (Incident-Free) Radiation Doses to Transport Workers 16              and the Public from Shipping Spent Fuel from LSCS to the Proposed 17              Yucca Mountain Repository Site, Normalized to Reference 18              LWR (880 MWe (net)) ..................................................................................... G-6 19 Table G-4. Radionuclide Inventories Used in Transportation Accident Risk 20              Calculations for the LSCS Reactors ...............................................................G-10 21 Table G-5. Annual Spent Fuel Transportation Accident Impacts from Shipping 22              Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 23              Site, Normalized to Reference LWR Reactor (880 MWe (net)).......................G-11 xix
 
1                                  EXECUTIVE
 
==SUMMARY==
 
2 BACKGROUND 3 By letter dated December 9, 2014, Exelon Generation Company, LLC (Exelon) submitted an 4 application to the U.S. Nuclear Regulatory Commission (NRC) to issue renewed operating 5 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20-year period.
6 Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 51.20(b)(2), the renewal of a 7 power reactor operating license requires preparation of an environmental impact statement 8 (EIS) or a supplement to an existing EIS. In addition, 10 CFR 51.95(c) states that, in connection 9 with the renewal of an operating license, the NRC shall prepare an EIS, which is a supplement 10 to the Commissions NUREG-1437, Generic Environmental Impact Statement (GEIS) for 11 License Renewal of Nuclear Plants.
12 Upon acceptance of Exelons application, the NRC staff began the environmental review 13 process described in 10 CFR Part 51 by publishing a Notice of Intent to prepare a supplemental 14 environmental impact statement (SEIS) and to conduct scoping. In preparation of this SEIS for 15 LSCS, the NRC staff performed the following:
16
* conducted public scoping meetings on March 10, 2015, in Ottawa, Illinois; 17
* conducted a site audit at LSCS from May 5-7, 2015; 18
* reviewed Exelons Environmental Report (ER) and compared it to the GEIS; 19
* consulted with Federal, State, Tribal, and local agencies; 20
* conducted a review of the issues following the guidance set forth in 21              Standard Review Plans for Environmental Reviews for Nuclear Power Plants:
22              Environmental Standard Review Plan for Operating License Renewal (NUREG-1555 23              Supplement 1, Revision 1, Final Report); and 24
* considered public comments received during the scoping process.
25 PROPOSED ACTION 26 Exelon initiated the proposed Federal action (i.e., issuance of renewed power reactor operating 27 licenses) by submitting an application for license renewal of LSCS for which the existing 28 licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023. The NRCs 29 Federal action is to decide whether to renew the licenses for an additional 20 years. The 30 regulation at 10 CFR 2.109 states that, if a licensee of a nuclear power plant files an application 31 to renew an operating license at least 5 years before the expiration date of that license, the 32 existing license will not be deemed to have expired until the safety and environmental reviews 33 are completed and until the NRC has made a final decision on whether to issue a renewed 34 license for the additional 20 years.
35 PURPOSE AND NEED FOR ACTION 36 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 37 option that allows for power generation capability beyond the term of the current nuclear power 38 plant operating licenses to meet future system generating needs. Such needs may be 39 determined by other energy-planning decisionmakers, such as states, operators, and, where 40 authorized, Federal agencies (other than the NRC). This definition of purpose and need reflects xxi
 
Executive Summary 1 the NRCs recognition that, unless there are findings in the safety review required by the Atomic 2 Energy Act of 1954, as amended, or findings in the National Environmental Policy Act of 1969, 3 as amended, environmental analysis that would lead the NRC to reject a license renewal 4 application, the NRC does not have a role in the energy-planning decisions as to whether a 5 particular nuclear power plant should continue to operate.
6 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL 7 The SEIS evaluates the potential environmental impacts of the proposed action. The 8 environmental impacts from the proposed action are designated as SMALL, MODERATE, or 9 LARGE. As established in the GEIS, Category 1 issues are those that meet all of the following 10 criteria:
11
* The environmental impacts associated with the issue          SMALL: Environmental 12            are determined to apply either to all plants or, for some    effects are not detectable or 13            issues, to plants having a specific type of cooling          are so minor that they will 14            system or other specified plant or site characteristics.      neither destabilize nor noticeably alter any important 15
* A single significance level (i.e., SMALL, MODERATE,          attribute of the resource.
16            or LARGE) has been assigned to the impacts except            MODERATE:
17            for collective offsite radiological impacts from the fuel    Environmental effects are 18            cycle and from high-level waste and spent fuel                sufficient to alter noticeably, but not to destabilize, 19            disposal.                                                    important attributes of the 20
* Mitigation of adverse impacts associated with the issue      resource.
21            is considered in the analysis, and it has been                LARGE: Environmental 22            determined that additional plant-specific mitigation          effects are clearly noticeable and are sufficient to 23            measures are likely not to be sufficiently beneficial to destabilize important 24            warrant implementation.                                      attributes of the resource.
25 For Category 1 issues, no additional site-specific analysis is 26 required in this SEIS unless new and significant information is identified. Chapter 4 of this SEIS 27 presents the process for identifying new and significant information. Site-specific issues 28 (Category 2) are those that do not meet one or more of the criteria for Category 1 issues; 29 therefore, an additional site-specific review for these non-generic issues is required, and the 30 results are documented in the SEIS.
31 Neither Exelon nor the NRC identified information that is both new and significant related to 32 Category 1 issues that would call into question the conclusions in the GEIS. This conclusion is 33 supported by the NRC staffs review of the applicants ER and other documentation relevant to 34 the applicants activities, the public scoping process, and the findings from the environmental 35 site audit conducted by the NRC staff. Therefore, the NRC staff relied upon the conclusions of 36 the GEIS for all Category 1 issues applicable to LSCS.
37 The NRC staff did find new information regarding the Category 1 a uranium fuel cycle issue 38 (Transportation), but this new information was not considered significant and therefore did not 39 affect the conclusions for these issues presented in the GEIS. This new information is 40 discussed in Section 4.15.1 and Appendix G of this SEIS.
41 Table ES-1 summarizes the Category 2 issues relevant to LSCS and the NRC staffs findings 42 related to those issues. If the NRC staff determined that there were no Category 2 issues 43 applicable for a particular resource area, the findings of the GEIS, as documented in 44 Appendix B to Subpart A of 10 CFR Part 51, are incorporated for that resource area.
xxii
 
Executive Summary 1          Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 2                                                      License Renewal Resource Area                            Relevant Category 2 Issues                        Impacts Surface Water Resources                  Surface water use conflicts                        SMALL Groundwater Resources                    Groundwater Use Conflicts                          SMALL Groundwater Quality Degradation                    SMALL Radionuclides released to groundwater              SMALL Terrestrial Resources                    Effects on terrestrial resources (non-cooling SMALL system impacts)
Water use conflicts with terrestrial resources SMALL Aquatic Resources                        Impingement and entrainment of aquatic            SMALL organisms Thermal impacts on aquatic organisms              SMALL to MODERATE(a)
Water use conflicts with aquatic resources        SMALL Special Status Species and                Threatened, endangered, and species and            No effect (b)
Habitats                                  essential fish habitat Historic and Cultural                    Historic and cultural resources                    No adverse effect (c)
Resources Human Health                              Microbiological hazards to the public              SMALL Electric shock hazards                            SMALL Environmental Justice                    Minority and low-income populations                See note below (d)
Cumulative Impacts                        Terrestrial Ecology                                MODERATE to LARGE Aquatic Resources                                  MODERATE Socioeconomic                                      See note below (e)
Environmental Justice                              See note below (d)
Global Climate Change                              MODERATE All other resource areas                          SMALL (a) Thermal  impacts would be SMALL for all aquatic resources in the Illinois River and SMALL for aquatic resources in the cooling pond, except for gizzard shad and threadfin shad. Gizzard shad and threadfin shad would experience MODERATE thermal impacts in the cooling pond.
(b) For Federally protected species, the NRC reports the effects from continued operation of LSCS during the license renewal period in terms of its Endangered Species Act of 1973, as amended, findings of no effect, may effect, but not likely to adversely effect, or may affect, and is likely to adversely affect.
(c) The National Historic Preservation Act of 1966, as amended, requires Federal agencies to consider the effects of their undertakings on historic properties.
(d) There would be no disproportionately high and adverse impacts to minority and low-income populations.
(e) The contributory effects from the continued operation of LSCS during the license renewal period would have no new or increased impact on socioeconomic conditions beyond what is currently being experienced.
3 SEVERE ACCIDENT MITIGATION ALTERNATIVES 4 Since severe accident mitigation alternatives (SAMAs) have not been previously considered in 5 an environmental impact statement or environmental assessment for LSCS, xxiii
 
Executive Summary 1 10 CFR 51.53(c)(3)(ii)(L) requires Exelon to submit, with the ER, a consideration of alternatives 2 to mitigate severe accidents. SAMAs are potential ways to reduce the risk or potential impacts 3 of uncommon, but potentially severe accidents. SAMAs may include changes to plant 4 components, systems, procedures, and training.
5 The NRC staff reviewed Exelons ER evaluation of potential SAMAs and concluded that none of 6 the potentially cost-beneficial SAMAs relate to adequately managing the effects of aging during 7 the extended period of operation. Therefore, the potentially cost-beneficial SAMAs identified 8 need not be implemented as part of the license renewal, pursuant to 10 CFR Part 54.
9 ALTERNATIVES 10 The NRC staff considered the environmental impacts associated with alternatives to license 11 renewal. These alternatives include other methods of power generation, as well as not 12 renewing the LSCS operating licenses (the no-action alternative). The NRC staff considered 13 the following feasible and commercially viable replacement power alternatives:
14
* new nuclear power; 15
* coal-integrated gasification combined-cycle; 16
* natural gas combined-cycle (NGCC); and 17
* combination alternative (NGCC, wind, and solar power), and 18
* purchased power.
19 The NRC staff initially considered a number of additional alternatives for analysis as alternatives 20 to the license renewal of LSCS. The NRC staff later dismissed these alternatives because of 21 technical, resource availability, or commercial limitations that currently exist and that the NRC 22 staff believes are likely to continue to exist when the current LSCS licenses expire. The 23 no-action alternative and the effects it would have were also considered by the NRC staff.
24 Where possible, the NRC staff evaluated potential environmental impacts for these alternatives 25 located at both the LSCS site and some other unspecified alternate location. The NRC staff 26 considered the following alternatives, but dismissed them:
27
* energy conservation and energy efficiency, 28
* solar power, 29
* wind power, 30
* biomass, 31
* hydroelectric power, 32
* wave and ocean energy, 33
* fuel cells, 34
* delayed retirement, 35
* geothermal power, 36
* municipal solid waste, 37
* oil-fired power, and 38
* supercritical pulverized coal.
xxiv
 
Executive Summary 1 The NRC staff evaluated each alternative using the same resource areas that were used in 2 evaluating impacts from license renewal.
3 PRELIMINARY RECOMMENDATION 4 The NRC staffs preliminary recommendation is that the adverse environmental impacts of 5 license renewal for LSCS are not so great that preserving the option of license renewal for 6 energy-planning decisionmakers would be unreasonable. The NRC staff based its 7 recommendation on the following:
8
* the analyses and findings in the GEIS; 9
* the ER submitted by Exelon; 10
* the NRC staffs consultation with Federal, State, local, and Tribal Government 11            agencies; 12
* the NRC staffs independent environmental review; and 13
* the NRC staffs consideration of public comments received during the scoping 14            process.
xxv
 
Abbreviations and Acronyms 1        ABBREVIATIONS AND ACRONYMS 2 ac        acre(s) 3 AC        alternating current 4 ACC        averted cleanup and decontamination costs 5 ACHP      Advisory Council on Historic Preservation 6 ADAMS      Agencywide Documents Access and Management System 7 AEA        Atomic Energy Act of 1954 (as amended) 8 AFW        auxiliary feedwater 9 AMSAC      ATWS mitigating system actuation circuitry 10 ANL        Argonne National Laboratory 11 ANS        American Nuclear Society 12 AOC        averted offsite property damage costs 13 AOE        averted occupational exposure 14 AOSC      averted onsite costs 15 AP        auxiliary power 16 APE        averted public exposure 17 ASLB      Atomic Safety and Licensing Board (NRC) 18 ASME      American Society of Mechanical Engineers 19 ATWS      anticipated transient(s) without scram 20 AWEA      American Wind Energy Association 21 BEA        Bureau of Economic Analysis 22 BLM        Bureau of Land Management 23 BLS        Bureau of Labor Statistics 24 BOEM      Bureau of Ocean Energy Management 25 BTU/ft3    British thermal unit(s) per cubic foot 26 CAA        Clean Air Act 27 CAES      compressed air energy storage 28 CCS        carbon capture and storage 29 CCW        component cooling water 30 CDF        core damage frequency 31 CEQ        Council on Environmental Quality 32 CET        containment event tree 33 CFE        early containment failure 34 CFR        Code of Federal Regulations xxvii
 
Abbreviations and Acronyms 1 cfs                        cubic foot (feet) per second 2 CLB                        current licensing basis/bases 3 CO                        carbon monoxide 4 CO2                        carbon dioxide 5 CO2/MWh                    carbon dioxide per megawatt hour 6 COL                        combined license 7 CVCS                      chemical and volume control system 8 CWA                        Clean Water Act 9 div.                      Division 10 DLOOP                      dual unit loss(es) of offsite power 11 DMS                        Diverse Mitigation System 12 DOE                        U.S. Department of Energy 13 DSIRE                      Database of State Incentives for Renewables and Efficiency 14 DSM                        demand-side management 15 ECCS                      emergency core cooling system 16 EFH                        essential fish habitat 17 EIA                        Energy Information Administration 18 EIS                        environmental impact statement 19 ELPC                      Environmental Law and Policy Center 20 Elv.                      elevation 21 EMF                        electromagnetic field 22 EPA                        U.S. Environmental Protection Agency 23 EPRI                      Electric Power Research Institute 24 EPZ                        emergency planning zone 25 ER                        Environmental Report 26 ERC                        Energy Recovery Council 27 ES                        Environmental Services 28 ESA                        Endangered Species Act of 1973, as amended 29 ESF                        engineered safety feature 30 ESFAS                      engineered safety features actuation system 31 ESP                        early site permit 32 ESW                        emergency service water 33 Exelon                    Exelon Generation Company, LLC 34 FEIS                      final environmental impact statement 35 FERC                      Federal Energy Regulatory Commission xxviii
 
Abbreviations and Acronyms 1 FESOP  Federally Enforceable State Operating Permit 2 FIVE  fire-induced vulnerability evaluation 3 FR    Federal Register 4 FRN    Federal Register notice 5 ft3    cubic foot (feet) 6 FW    feedwater 7 FWCA  Fish and Wildlife Coordination Act of 1934, as amended 8 FWS    U.S. Fish and Wildlife Service 9 GEIS  generic environmental impact statement 10 GI    generic issue 11 GL    generic letter 12 gpd    gallon(s) per day 13 gpm    gallon(s) per minute 14 ha    hectare(s) 15 HCLPF  high confidence in low probability of failure 16 HEP    human error probability 17 HFE    human failure event 18 HFO    high winds, floods, and other 19 HRA    human reliability analysis 20 HX    heat exchanger 21 IDNR  Illinois Department of Natural Resources 22 IDOT  Illinois Department of Transportation 23 IDPH  Illinois Department of Public Health 24 IEA    International Energy Agency 25 IEPA  Illinois Environmental Protection Agency 26 IGCC  integrated gasification combined-cycle 27 IHPA  Illinois Historic Preservation Agency 28 ILCS  Illinois Compiled Statutes 29 INEEL  Idaho National Engineering and Environmental Laboratory 30 IPE    individual plant examination 31 IPEEE  individual plant examination(s) of external events 32 ISLOCA interfacing-systems loss-of-coolant accident 33 JHEP  joint human error probability 34 km    kilometer(s) 35 kW    kilowatt(s) xxix
 
Abbreviations and Acronyms 1 kWe                        kilowatt(s) electric 2 kWh/m2/d                  kilowatt hours per square meter per day 3 lb                        pound(s) 4 LER                        large early release 5 LERF                      large early release frequency 6 LMFW                      loss of main feedwater 7 LOCA                      loss-of-coolant accident 8 LOOP                      loss(es) of offsite power 9 Lpd                        liters per day 10 LRA                        license renewal application 11 LSCS                      LaSalle County Station, Units 1 and 2 12 m/s                        meter(s) per second 13 m3                        cubic meter(s) 14 MAAP                      Modular Accident Analysis Program 15 MACCS2                    MELCOR Accident Consequence Code System 2 16 MACR                      maximum averted cost risk 17 MATS                      Mercury and Air Toxics Standards 18 MCR                        main control room 19 mgd                        million gallons per day 20 mi                        mile(s) 21 MISO                      Midcontinent Independent System Operator 22 MMPA                      Marine Mammal Protection Act 23 MOV                        motor-operated valve 24 mph                        mile(s) per hour 25 MSA                        Magnuson-Stevens Fishery Conservation and Management Act, 26                            as amended through 2006 27 MUR                        measurement uncertainty recapture 28 MW                        megawatt(s) 29 MWe                        megawatt(s) electric 30 MWh                        megawatt hour(s) 31 MWt                        megawatt(s) thermal 32 NEIS                      National Energy Information Service 33 NEPA                      National Environmental Policy Act of 1969, as amended 34 NETL                      National Energy Technology Laboratory 35 NGCC                      natural gas combined-cycle xxx
 
Abbreviations and Acronyms 1 NHPA  National Historic Preservation Act of 1966, as amended 2 NMFS  National Marine Fisheries Service (of the National Oceanic and 3      Atmospheric Administration) 4 NO2  nitrogen dioxide 5 NOx  nitrogen oxide(s) 6 NPDES National Pollutant Discharge Elimination System 7 NRC  U.S. Nuclear Regulatory Commission 8 NREL  National Renewable Energy Laboratory 9 NRR  Nuclear Reactor Regulation, Office of (NRC) 10 O3    ozone 11 OECR  offsite economic cost risk 12 ORNL  Oak Ridge National Laboratory 13 Pb    lead 14 PDR  population dose risk 15 PDS  plant damage state 16 PEIS  programmatic environmental impact statement 17 PL    public law 18 PNNL  Pacific Northwest National Laboratory 19 PORV  power-operated relief valve 20 PRA  probabilistic risk assessment 21 PV    photovoltaic 22 PWR  pressurized water reactor 23 RAI  request(s) for additional information 24 RCP  reactor coolant pump 25 RCRA  Resource Conservation and Recovery Act of 1976, as amended 26 rem  roentgen equivalent(s) man 27 RHR  residual heat removal 28 ROI  region(s) of influence 29 RPC  replacement power cost 30 RPS  reactor protection system 31 RPV  reactor pressure vessel 32 RRW  risk reduction worth 33 RTO  Regional Transmission Organization 34 RWST  refueling water storage tank 35 SAMA  severe accident mitigation alternative xxxi
 
Abbreviations and Acronyms 1 SAT                        system auxiliary transformer 2 SBO                        station blackout 3 SCPC                      supercritical pulverized coal 4 SEIS                      supplemental environmental impact statement 5 SER                        safety evaluation report 6 SG                        steam generator 7 SGTR                      steam generator tube rupture 8 SI                        safety injection 9 SMA                        seismic margin assessment 10 SO2                        sulfur dioxide 11 SR                        supporting requirement 12 SSC                        structure, system, and component 13 SSEL                      Safe Shutdown Equipment List 14 Sv                        sievert(s) 15 SW                        service water 16 SX                        essential service water 17 syngas                    synthesis gas 18 TAC                        technical assignment control 19 TEEIC                      Tribal Energy and Environmental Information Clearinghouse 20 TS                        technical specification 21 U.S.                      United States 22 U.S.C.                    United States Code 23 UAT                        unit auxiliary transformer 24 UFSAR                      updated final safety analysis report 25 USDA                      U.S. Department of Agriculture 26 USGS                      U.S. Geological Survey 27 yd 3 cubic yard(s) 28 W/m2                      watt(s) per square meter xxxii
 
1                                       
 
==1.0 INTRODUCTION==
 
2 Under the U.S. Nuclear Regulatory Commissions (NRCs) environmental protection regulations 3 in Part 51 of Title 10 of the Code of Federal Regulations (10 CFR Part 51)which implement 4 the National Environmental Policy Act (NEPA)the issuance or renewal of a nuclear power 5 plant operating license requires the preparation of an environmental impact statement (EIS).
6 The Atomic Energy Act of 1954 (AEA) specified that licenses for commercial power reactors can 7 be granted for up to 40 years. NRC regulations (10 CFR 54.31) allow for an option to renew a 8 license for up to an additional 20 years. The initial 40-year licensing period was based on 9 economic and antitrust considerations rather than on technical limitations of the nuclear facility.
10 The decision to seek a license renewal rests entirely with nuclear power facility owners and, 11 typically, is based on the facilitys economic viability and the investment necessary to continue 12 to meet NRC safety and environmental requirements. The NRC makes the decision to grant or 13 deny license renewal based on whether the applicant has demonstrated that the environmental 14 and safety requirements in the agencys regulations can be met during the period of extended 15 operation.
16 1.1    Proposed Federal Action 17 Exelon Generation Company, LLC (Exelon), initiated the proposed Federal action by submitting 18 an application for license renewal of LaSalle County Station, Units 1 and 2 (LSCS), for which 19 the existing licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023.
20 The NRCs Federal action is to decide whether to renew the licenses for an additional 20 years.
21 1.2    Purpose and Need for Proposed Federal Action 22 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 23 option that allows for power generation capability beyond the term of a current nuclear power 24 plant operating license to meet future system generating needs, as such needs may be 25 determined by other energy-planning decisionmakers. This definition of purpose and need 26 reflects the NRCs recognition that, unless there are findings in the safety review required by the 27 AEA or findings in the NEPA environmental analysis that would lead the NRC to reject a license 28 renewal application (LRA), the NRC does not have a role in the energy-planning decisions of 29 state regulators and utility officials as to whether a particular nuclear power plant should 30 continue to operate.
31 1.3    Major Environmental Review Milestones 32 Exelon submitted an Environmental Report (ER) (Exelon 2014a) as part of its 33 LRA (Exelon 2014b) in December 2014. After reviewing the LRA and ER for sufficiency, the 34 NRC staff published a Federal Register Notice of Acceptability and Opportunity for Hearing 35 (Volume 80 of the Federal Register (FR), page 5822 (80 FR 5822)) on February 3, 2015. Also, 36 on February 3, 2015, the NRC published another notice in the Federal Register (80 FR 5793) on 37 the intent to conduct scoping, thereby beginning the 60-day scoping period.
38 The NRC staff held two public scoping meetings on March 10, 2015, in Ottawa, Illinois. In a 39 letter dated July 2, 2015, the NRC issued a report entitled, Environmental Impact Statement 40 Scoping Process Summary Report, LaSalle County Station, Units 1 and 2, Brookfield Township, 1-1
 
Introduction 1 LaSalle County, IL, which includes both the comments received during the scoping process 2 and the NRC staffs responses to those comments (NRC 2015a).
3 In order to independently verify information provided in the ER, the NRC staff conducted a site 4 audit at LSCS in May 2015. During the site audit, the NRC staff met with plant personnel, 5 reviewed specific documentation, toured the facility, and met with interested local agencies. In 6 a letter dated May 20, 2015, the NRC summarized that site audit and listed the attendees 7 (NRC 2015b).
8 Upon completion of the scoping period and site audit, the NRC staff compiled its findings in a 9 draft supplemental environmental impact statement (SEIS). This document is made available 10 for public comment for 45 days. During this time, the NRC staff will host public meetings and 11 collect public comments. Based on the information gathered, the NRC staff will amend the draft 12 SEIS findings, as necessary, and will publish the final SEIS. Figure 1-1 shows the major 13 milestones of the NRCs LRA environmental review process.
14                            Figure 1-1. Environmental Review Process 15 16 The NRC has established a license renewal process that can be completed in a reasonable 17 period of time with clear requirements to ensure safe plant operation for up to an additional 18 20 years of plant life. The NRC staff conducts the safety review simultaneously with the 19 environmental review. The NRC staff documents the findings of the safety review in a safety 20 evaluation report (SER). The findings in the SEIS and the SER are both factors in the NRCs 21 decision to either grant or deny the issuance of a renewed license.
22 1.4    Generic Environmental Impact Statement 23 The NRC staff performed a generic assessment of the environmental impacts associated with 24 license renewal to improve the efficiency of its license renewal review. NUREG-1437, Generic 25 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) 1-2
 
Introduction 1 (NRC 1996, 1999, 2013), documents the results of the NRC staffs systematic approach to 2 evaluate the environmental consequences of renewing the licenses of individual nuclear power 3 plants and operating them for an additional 20 years. The NRC staff analyzed in detail, and 4 resolved, those environmental issues that could be resolved generically in the GEIS. The NRC 5 originally issued the GEIS in 1996, issued Addendum 1 to the GEIS in 1999, and issued 6 Revision 1 to the GEIS in 2013. Unless otherwise noted, all references to the GEIS include 7 Addendum 1 and Revision 1 to the GEIS.
8 The GEIS establishes separate environmental impact issues for the NRC staff to independently 9 verify. Of these issues, the NRC staff determined that some generic issues are generic to all 10 plants (Category 1). Other issues do not lend themselves to generic consideration (Category 2 11 or uncategorized). The NRC staff evaluated these issues on a site-specific basis in the SEIS.
12 Appendix B to Subpart A of 10 CFR Part 51 summarizes the NRC staffs findings in the GEIS.
13 For each potential environmental issue, the NRC staff does the following in the GEIS:
14
* describes the activity that affects the environment, 15
* identifies the population or resource that is affected, 16
* assesses the nature and magnitude of the impact on the affected population or 17              resource, 18
* characterizes the significance of the effect for both beneficial and adverse effects, 19
* determines whether the results of the analysis apply to all plants, and 20
* considers whether additional mitigation measures would be warranted for impacts 21              that would have the same significance level for all plants.
22 The NRC established its standard of significance for impacts using the Council on 23 Environmental Quality terminology for significant. The NRC established three levels of 24 significance for potential impactsSMALL, MODERATE, and LARGE, as defined below.
25 SMALL: Environmental effects are not 26 detectable or are so minor that they will neither          Significance indicates the importance of likely environmental impacts and is determined by 27 destabilize nor noticeably alter any important            considering two variables: context and intensity.
28 attribute of the resource.
Context is the geographic, biophysical, and social 29 MODERATE: Environmental effects are                        context in which the effects will occur.
30 sufficient to alter noticeably, but not to                Intensity refers to the severity of the impact in 31 destabilize, important attributes of the resource.        whatever context it occurs.
32 LARGE: Environmental effects are clearly 33 noticeable and are sufficient to destabilize important attributes of the resource.
34 The GEIS includes a determination of whether the analysis of the environmental issue could be 35 applied to all plants and whether additional mitigation measures would be warranted. Issues 36 are assigned a Category 1 or a Category 2 designation. As set forth in the GEIS, Category 1 37 issues are those that meet the following criteria:
38
* The environmental impacts associated with the issue have been determined to apply 39              either to all plants or, for some issues, to plants having a specific type of cooling 40              system or other specified plant or site characteristics.
41
* A single significance level (i.e., SMALL, MODERATE, or LARGE) has been assigned 42              to the impacts (except for collective offsite radiological impacts from the fuel cycle 43              and from high-level waste and spent fuel disposal).
1-3
 
Introduction 1
* Mitigation of adverse impacts associated with the issue has been considered in the 2              analysis, and it has been determined that additional plant-specific mitigation 3              measures are likely not to be sufficiently beneficial to warrant implementation.
4 For generic issues (Category 1), no additional site-specific analysis is required in the SEIS 5 unless new and significant information is identified. The process for identifying new and 6 significant information for site-specific analysis is presented in Chapter 4. Site-specific issues 7 (Category 2) are those that do not meet one or more of the criteria of Category 1 issues; 8 therefore, additional site-specific review for these issues is required. A site-specific analysis is 9 required for 17 of those 78 issues evaluated in the GEIS. Figure 1-2 illustrates this process.
10 The results of that site-specific review are documented in the SEIS.
11                Figure 1-2. Environmental Issues Evaluated for License Renewal 12 1.5    Supplemental Environmental Impact Statement 13 The SEIS presents an analysis that considers the environmental effects of the continued 14 operation of LSCS, alternatives to license renewal, and mitigation measures for minimizing 15 adverse environmental impacts. Chapter 4 contains analysis and comparison of the potential 16 environmental impacts from alternatives. Chapter 5 presents the NRCs recommendation on 17 whether the environmental impacts of license renewal are so great that preserving the option of 1-4
 
Introduction 1 license renewal would be unreasonable. The NRC will make its final recommendation after 2 considering comments received on the draft SEIS during the public comment period.
3 In the preparation of the SEIS for LSCS, the NRC staff carried out the following activities:
4
* reviewed the information provided in Exelons ER; 5
* consulted with Federal, state, and local agencies, and tribal nations; 6
* conducted an independent review of the issues during site audit; and 7
* considered the public comments received for the review (during the scoping 8              process).
9 New information can be identified from many 10 sources, including the applicant, the NRC, other        New and significant information. To merit 11 agencies, or public comments. If a new issue is          additional review, information must be both new and bear on the proposed action or its impacts, 12 revealed, it is first analyzed to determine whether      presenting a seriously different picture of the 13 it is within the scope of the license renewal            impacts from those envisioned in the GEIS.
14 environmental evaluation. If the new issue is not 15 addressed in the GEIS, the NRC staff would determine the significance of the issue and 16 document the analysis in the SEIS.
17 1.6    Decisions to Be Supported by the SEIS 18 The decision to be supported by the SEIS is whether to renew the operating licenses for LSCS 19 for an additional 20 years. The NRC decision standard is specified in 10 CFR 51.103(a)(5), as 20 follows:
21              In making a final decision on a license renewal action pursuant to Part 54 22              of this chapter, the Commission shall determine whether or not the 23              adverse environmental impacts of license renewal are so great that 24              preserving the option of license renewal for energy planning 25              decisionmakers would be unreasonable.
26 There are many factors that the NRC takes into consideration when deciding whether to renew 27 the operating license of a nuclear power plant. The analyses of environmental impacts 28 evaluated in this GEIS will provide the NRCs decisionmaker (in this case, the Commission) with 29 important environmental information for use in the overall decisionmaking process. There are 30 also decisions outside the regulatory scope of license renewal that cannot be made on the basis 31 of the GEIS analysis. These decisions include the following issues: changes to plant cooling 32 systems, disposition of spent nuclear fuel, emergency preparedness, safeguards and security, 33 need for power, and seismicity and flooding (NRC 2013).
34 1.7    Cooperating Agencies 35 During the scoping process, no Federal, state, or local agencies were identified as cooperating 36 agencies in the preparation of this SEIS.
37 1.8    Consultations 38 The Endangered Species Act of 1973, as amended (ESA) (16 U.S.C. 1531 et seq.); the 39 Magnuson-Stevens Fisheries Conservation and Management Act of 1996, as amended (MSA) 40 (16 U.S.C. 1801 et seq.); and the National Historic Preservation Act of 1966, as amended 41 (NHPA) (16 U.S.C. 470 et seq.), require Federal agencies to consult with applicable state and 1-5
 
Introduction 1 Federal agencies and groups before taking action that may affect endangered species, 2 fisheries, or historic and archaeological resources, respectively. The NRC consulted with the 3 following agencies and groups; Appendix C provides a discussion of the consultation 4 documents:
5
* U.S. Fish and Wildlife Service (FWS);
6
* Illinois Historic Preservation Agency; 7
* Advisory Council on Historic Preservation; 8
* Ho-Chunk Nation; 9
* Miami Tribe of Oklahoma; 10
* Peoria Tribe of Indians of Oklahoma; 11
* Citizen Potawatomi Nation; 12
* Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki Nation; 13
* Sac and Fox Nation of Missouri in Kansas and Nebraska; 14
* Sac and Fox Nation; 15
* Pokagon Band of Potawatomi; 16
* Forest County Potawatomi; 17
* Hannahville Indian Community, Band of Potawatomi; 18
* Prairie Band Potawatomi Nation; 19
* Winnebago Tribe of Nebraska; 20
* Kickapoo Tribe in Kansas; and 21
* Kickapoo Tribe of Oklahoma.
22 1.9    Correspondence 23 During the course of the environmental review, the NRC staff contacted Federal, state, regional, 24 local, and tribal agencies listed in Section 1.8. Appendix C lists the correspondence associated 25 with the ESA, MSA, and NHPA. Appendix D lists all other correspondence.
26 1.10 Status of Compliance 27 Exelon is responsible for complying with all NRC regulations and other applicable Federal, 28 state, and local requirements. Appendix F of the GEIS describes some of the major applicable 29 Federal statutes. There are numerous permits and licenses issued by Federal, state, and local 30 authorities for activities at LSCS. Appendix B contains further information about LSCSs status 31 of compliance.
32 1.11 Related Federal and State Activities 33 The NRC reviewed the possibility that activities of other Federal agencies might impact the 34 renewal of the operating licenses for LSCS. There are no Federal projects that would make it 35 necessary for another Federal agency to become a cooperating agency in the preparation of 36 this SEIS.
1-6
 
Introduction 1 There are no known American Indian lands within 50 miles (mi) (80 kilometers (km)) of the 2 LSCS. There are three Federally owned facilities within 50 mi (80 km) of the LSCS: (1) Fermi 3 National Accelerator Laboratory, (2) Argonne National Laboratory, and (3) Joliet Army 4 Ammunition Plant.
5 Section 102(2)(C) of NEPA requires the NRC to consult with, and obtain comments from, any 6 Federal agency that has jurisdiction by law or special expertise with respect to any 7 environmental impact involved in the subject matter of the SEIS. For example, during the 8 course of preparing the SEIS, the NRC consulted with the FWS. Appendix C lists all 9 consultation correspondences.
10 1.12 References 11 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 12 protection regulations for domestic licensing and related regulatory functions.
13 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 14 renewal of operating licenses for nuclear power plants.
15 80 FR 5793. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 16 notice of intent to prepare an environmental impact statement and conduct the scoping process; 17 public meetings and request for comment. Federal Register 80(22):5793-5795.
18 February 3, 2015.
19 80 FR 5822. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 20 license renewal application; opportunity to request a hearing and to petition for leave to 21 intervene. Federal Register 80(22):5822-5825. February 3, 2015.
22 Atomic Energy Act of 1954, as amended. 42 U.S.C. §2011 et seq.
23 Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq.
24 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 25 Operating License Renewal Stage, LaSalle County Station. Exelon. December 9, 2014.
26 Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 27 ML14343A897.
28 [Exelon] Exelon Generation Company, LLC. 2014b. License Renewal Application, LaSalle 29 County Station, Units 1 and 2. Exelon. December 9, 2014. ADAMS No. ML14343A849.
30 Magnuson-Stevens Fishery Conservation and Management Act of 1996, as amended.
31 16 U.S.C. §1801 et seq.
32 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq.
33 National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq.
34 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement 35 for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG-1437, 36 Volumes 1 and 2. May 31, 1996. ADAMS Nos. ML040690705 and ML040690738.
37 [NRC] U.S. Nuclear Regulatory Commission. 1999. Section 6.3Transportation, Table 9.1, 38 Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants.
39 In: Generic Environmental Impact Statement for License Renewal of Nuclear Plants.
40 Washington, DC: NRC. NUREG-1437, Volume 1, Addendum 1. August 1999. ADAMS 41 No. ML040690720.
1-7
 
Introduction 1 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 2 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Revision 1, 3 Volumes 1, 2, and 3. June 19, 2013. ADAMS No. ML13107A023.
4 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Letter from BD Wittick (NRC), Branch 5 Chief, to MP Gallagher (Exelon).
 
==Subject:==
Issuance of Scoping Summary Report Associated 6 with the LaSalle County Station, Units 1 and 2, License Renewal Application Environmental 7 Review (TAC Nos. MF5567 and MF5568). July 2, 2015. ADAMS No. ML15147A380.
8 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Letter from BD Wittick (NRC), Branch 9 Chief, to MP Gallagher (Exelon).
 
==Subject:==
Summary of the License Renewal Environmental 10 Audit for LaSalle County Station, Units 1 and 2 (TAC Nos. MF5567 and MF5568).
11 May 20, 2015. ADAMS No. ML15132A674.
1-8
 
1          2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION 2 Although the U.S. Nuclear Regulatory Commissions (NRCs) decisionmaking authority in 3 license renewal is limited to deciding whether or not to renew a nuclear power plants operating 4 license, the NRCs implementation of the National Environmental Policy Act of 1969 (NEPA), as 5 amended (42 U.S.C. 4321 et seq.), requires consideration of the environmental impacts of 6 potential alternatives to renewing a plants operating license. While the ultimate decision about 7 which alternative (or the proposed action) to carry out falls to operator, state, or other non-NRC 8 Federal officials, comparing the impacts of renewing the operating license to the environmental 9 impacts of alternatives allows the NRC to determine whether the environmental impacts of 10 license renewal are so great that preserving the option of license renewal for energy-planning 11 decisionmakers would be unreasonable (Title 10 of the Code of Federal Regulations 12 (10 CFR) 51.95(c)(4)).
13 Energy-planning decisionmakers and owners of the nuclear power plant ultimately decide 14 whether the plant will continue to operate, and economic and environmental considerations play 15 important roles in this decision. In general, the NRCs responsibility is to ensure the safe 16 operation of nuclear power facilities and not to formulate energy policy or encourage or 17 discourage the development of alternative power generation. The NRC does not engage in 18 energy-planning decisions and makes no judgment as to which energy alternatives evaluated 19 would be the most likely alternative in any given case.
20 The remainder of this chapter provides (1) a description of the proposed action, (2) a description 21 of alternatives to the proposed action (including the no-action alternative), and (3) alternatives to 22 LaSalle County Station, Units 1 and 2 (LSCS) license renewal that were considered and 23 eliminated from detailed study. Chapter 4 of this plant-specific supplemental environmental 24 impact statement (SEIS) compares the impacts of renewing the operating licenses of LSCS and 25 continued plant operations to the environmental impacts of alternatives.
26 2.1    Proposed Action 27 As stated in Section 1.1 of this document, the NRCs proposed Federal action is the decision of 28 whether to renew the LSCS operating licenses for an additional 20 years. For the NRC to 29 determine the impacts from continued operation of LSCS, an understanding of that operation is 30 needed. Section 2.1.1 describes normal power plant operations during the license renewal 31 term. LSCS is a two-unit, nuclear-powered steam-electric generating facility that began 32 commercial operation in January 1984 (Unit 1) and October 1984 (Unit 2). The nuclear reactors 33 at both units are General Electric boiling water reactors (BWRs), and together they produce an 34 annual average net output of 2,327 megawatts electric (MWe) (Exelon 2014).
35 2.1.1    Plant Operations during the License Renewal Term 36 Most plant operation activities during license renewal would be the same as, or similar to, those 37 occurring during the current license term (NRC 2013). Section 2.1.1 of NUREG-1437, Generic 38 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS),
39 Revision 1 (NRC 2013), describes the general types of activities that are carried out during the 40 operation of a nuclear power plant, such as LSCS, as follows:
41
* reactor operation; 42
* waste management; 2-1
 
Alternatives Including the Proposed Action 1
* security; 2
* office and clerical work; 3
* surveillance, monitoring, and maintenance; and 4
* refueling and other outages.
5 As stated in the Exelon Generation Company, LLCs (Exelons) Environmental Report (ER) 6 (Exelon 2014), LSCS will continue to operate during the license renewal term in the same 7 manner as it does during the current license term except for, as appropriate, additional aging 8 management programs to address structure and component aging in accordance with 9 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants.
10 2.1.2      Refurbishment and Other Activities Associated with License Renewal 11 Refurbishment activities include replacement and repair of major systems, structures, and 12 components. For example, replacement activities may include replacement of recirculation 13 piping systems for BWRs. The intent of the major refurbishment class of activities characterized 14 in the GEIS (NRC 2013) is to encompass actions that typically take place only once in the life of 15 a nuclear plant, if at all. Refurbishment activities may have an impact on the environment 16 beyond those that occur during normal operations and may require evaluation depending on the 17 type of action and the plant-specific design.
18 In preparation for its license renewal application, Exelon performed an evaluation of LSCS 19 structures, systems, and components in accordance with 10 CFR 54.21, Contents of 20 applicationtechnical information, to identify whether any major refurbishment activities would 21 be necessary to support the continued operation of LSCS during the proposed 20-year period of 22 extended operation (Exelon 2014).
23 Exelon did not identify any major refurbishment or replacement activities needed to support the 24 continued operation of LSCS beyond the existing operating license term (Exelon 2014).
25 Therefore, these activities are not discussed under the proposed action in Chapter 4.
26 2.1.3      Termination of Nuclear Power Plant Operations and Decommissioning after the 27            License Renewal Term 28 NUREG-0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear 29 Facilities: Supplement 1, Regarding the Decommissioning of Nuclear Power Reactors, 30 describes the impacts of decommissioning (NRC 2002). Most activities associated with plant 31 operations would cease with reactor shutdown. Some activities (e.g., security and oversight of 32 spent nuclear fuel) would remain unchanged, whereas others (e.g., waste management; office 33 and clerical work; laboratory analysis; and surveillance, monitoring, and maintenance) would 34 continue at reduced or altered levels. Systems dedicated to reactor operations would cease 35 operations; however, impacts from their physical presence may continue if they are not removed 36 after reactor shutdown. For multiple-unit sites, such as LSCS, shared systems may operate at 37 reduced capacities. Impacts associated with dedicated systems that remain in place or shared 38 systems that continue to operate at normal capacities would remain unchanged.
39 Decommissioning will occur whether LSCS is shut down at the end of its current operating 40 license term or at the end of the period of extended operation. There are no site-specific issues 41 related to decommissioning. The license renewal GEIS concludes that license renewal would 42 have a negligible (SMALL) effect on the impacts of terminating operations and decommissioning 43 on all resources.
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Alternatives Including the Proposed Action 1 2.2      Alternatives 2 As stated above, the NRC has the obligation to consider reasonable alternatives to the 3 proposed action of renewing the licenses for the nuclear reactors at LSCS. To be reasonable, a 4 replacement power alternative must be commercially viable on a utility scale and operational 5 prior to the expiration of the reactors operating licenses, or expected to become commercially 6 viable on a utility scale and operational prior to the expiration of the reactors operating licenses 7 (NRC 2013). The 2013 GEIS update incorporated the latest information on replacement power 8 alternatives; however, rapidly evolving technologies are likely to outpace the information 9 presented in the GEIS. As such, a site-specific analysis of alternatives must be performed for 10 each SEIS, taking into account changes in technology and science since the preparation of the 11 GEIS.
12 Section 2.2.1 below describes the no-action alternative (i.e., the NRC takes no action and does 13 not issue renewed licenses for LSCS). Sections 2.2.2.1-2.2.2.5 describe the characteristics of 14 replacement power alternatives for LSCS.
15 2.2.1    No-Action Alternative 16 At some point, operating nuclear power plants will terminate operations and undergo 17 decommissioning. The no-action alternative represents a decision by the NRC not to renew the 18 operating license of a nuclear power plant beyond the current operating license term. Under the 19 no-action alternative, the NRC does not renew the operating licenses, and the LSCS plant shuts 20 down at or before the end of the current licenses in 2022 and 2023. After shutdown, plant 21 operators will initiate decommissioning in accordance with 10 CFR 50.82, Termination of 22 License.
23 Only those impacts that arise directly as a result of plant shutdown will be addressed in this 24 SEIS. The environmental impacts from decommissioning and related activities are addressed in 25 several other documents, including the decommissioning GEIS (NRC 2002); the license renewal 26 GEIS, Chapter 4 (NRC 2013); and Chapter 4 of this SEIS. These analyses either directly 27 address or bound the environmental impacts of decommissioning whenever Exelon ceases to 28 operate LSCS.
29 Even with renewed operating licenses, LSCS will eventually shut down, and the 30 environmental impacts addressed later in Chapter 4 of this SEIS will occur at that time.
31 As with decommissioning impacts, shutdown impacts are expected to be similar whether they 32 occur at the end of the current license term or at the end of a renewed license term.
33 Termination of operations at LSCS would result in the total cessation of electrical power 34 production. Unlike the alternatives described in Section 2.2.2, the no-action alternative does not 35 meet the purpose and need of the proposed action because it does not provide a means of 36 delivering baseload power to meet future electric system needs. Given the current need for the 37 power generated by LSCS, the no-action alternative would likely create a need for a 38 replacement power alternative. A full range of replacement power alternatives (including new 39 nuclear, fossil fuels, and renewable energy sources) are described in the following section, and 40 their potential impacts are assessed in Chapter 4. Although the NRCs authority only extends to 41 the decision of whether to renew the LSCS operating licenses, the replacement power 42 alternatives described in the following sections represent possible options for energy-planning 43 decisionmakers should the NRC choose not to renew the LSCS operating licenses.
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Alternatives Including the Proposed Action 1 2.2.2      Replacement Power Alternatives 2 In evaluating alternatives to license renewal, the NRC considered energy technologies or 3 options currently in commercial operation, as well as technologies not currently in commercial 4 operation but likely to be commercially available by the time the current LSCS operating 5 licenses expire. The current operating licenses for the LSCS, Units 1 and 2, expire on 6 April 17, 2022, and December 16, 2023, respectively. Alternatives that are not likely to be 7 constructed, permitted, and connected to the grid by the time the LSCS licenses expire were 8 eliminated from detailed consideration.
9 Alternatives that cannot provide the equivalent of LSCSs current generating capacity and, in 10 some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 11 reasonable alternatives, were not considered in detail. Each alternative eliminated is briefly 12 discussed, and the basis for its elimination is provided in Section 2.3. In total, 17 alternatives to 13 the proposed action were considered (see text box) and then narrowed to the 5 alternatives 14 considered in Sections 2.2.2.1-2.2.2.5. The NRC staff evaluated the environmental impacts of 15 these five alternatives and the no-action alternative. They are discussed in depth in Chapter 4 16 of this SEIS.
17 The GEIS presents an overview of some energy technologies but does not reach conclusions 18 about which alternatives are most appropriate. Because many energy technologies are 19 continually evolving in capability and cost and because regulatory structures have changed to 20 either promote or impede development of particular alternatives, the analyses in this chapter 21 may include updated information from the following sources:
22
* U.S. Department of Energy (DOE), U.S. Energy Information Administration (EIA),
23
* other offices within the DOE, 24
* U.S. Environmental Protection Agency (EPA),
25
* industry sources and publications, and 26
* information submitted by Exelon in its ER.
27 The evaluation of each alternative in Chapter 4 of this SEIS considers the environmental 28 impacts across several impact categories: land use and visual resources, air quality and noise, 29 geologic environment, water resources, ecological resources, historic and cultural resources, 30 socioeconomics, human health, environmental justice, and waste management. Most 31 site-specific issues (Category 2) have been assigned a significance level of SMALL, 32 MODERATE, or LARGE. For ecological and historic and archaeological resources, the impact 33 significance determination language is specific to the authorizing legislation (e.g., Endangered 34 Species Act of 1973, as amended (16 U.S.C. 1531 et seq.), and National Historic Preservation 35 Act of 1966, as amended (16 U.S.C. 470 et seq.)). The order of presentation of the alternatives 36 is not meant to imply increasing or decreasing level of impact. Nor does it imply that an 37 energy-planning decisionmaker would be more likely to select any given alternative.
38 To ensure that the alternatives analysis is consistent with state or regional energy policies, the 39 NRC reviewed energy-related statutes, regulations, and policies within the LSCS region. As a 40 result, the staff considers alternatives that include wind power or solar photovoltaic (PV) power, 41 as well as a combination that includes both of them.
42 Region of Influence 43 LSCS is owned and operated by Exelon and provides electricity to the region of influence (ROI) 44 through transmission lines owned by Commonwealth Edison (ComEd) (Exelon 2014). ComEd 2-4
 
Alternatives Including the Proposed Action 1 operates under the PJM Interconnection, LLC Alternatives Evaluated in Depth:
2 (PJM), a regional transmission organization 3 that coordinates the movement of wholesale
* new nuclear 4 electricity in 13 states across the Midwest
* coal-integrated gasification combined-cycle 5 and Northeast (Exelon 2014). ComEd
* natural gas combined-cycle 6 provides service to 3.8 million customers
* combination alternative (wind power, natural gas 7 across northern Illinois. Its service territory        combined-cycle, and solar power) 8 borders Iroquois County to the south, the
* purchased power 9 Wisconsin border to the north, the Iowa 10 border to the west, and the Indiana border to Other Alternatives Considered:
11 the east (ComEd 2015). However, electricity 12 consumption in Illinois is not limited to
* energy efficiency and conservation 13 electricity that is generated within the State.
* solar power 14 Although northern Illinois relies on electricity
* wind power 15 from ComEd, the rest of Illinois and
* biomass 16 surrounding states, which are not part of the
* hydroelectric power 17 PJM, are part of the Midcontinent
* wave and ocean energy 18 Independent System Operator, Inc. (MISO)
* fuel cells 19 (see Figure 2-1) (Exelon 2014).
* delayed retirement 20 If renewed licenses were not issued,
* geothermal power 21 replacement power for LSCS would be
* municipal solid waste 22 required in northern Illinois. Electricity could
* petroleum 23 be replaced by generation sources from a
* supercritical pulverized coal 24 variety of locations. Electricity could be 25 transported from within the PJM; however, the PJM in Illinois is geographically distant from the 26 rest of the PJM region (see Figure 2-1). It is also possible that electricity within MISO could be 27 purchased by PJM, and efforts are currently being made to increase coordination and 28 deliverability between the regional transmission organizations (Ott 2013b). In addition, the State 29 of Illinois has a renewable portfolio standard that includes a stipulation that eligible renewable 30 resources must be procured from facilities located in Illinois or the States that adjoin Illinois 31 (Wisconsin, Indiana, Iowa, Kentucky, Michigan, and Missouri) (ILGA 2011). Renewable 32 resources can be obtained only from other regions of the country if they are not available in 33 Illinois or in the adjoining States (ILGA 2011).
34 Because replacement power would be required in northern Illinois, and any renewable energy 35 resources would need to be procured from facilities in Illinois or the adjoining States, the NRC 36 staff evaluated the impacts of locating replacement power facilities within the States of Illinois, 37 Indiana, Iowa, Kentucky, Michigan, Missouri, and Wisconsin. These seven states constitute the 38 ROI for the NRC staffs analysis of alternatives. The NRC assumes that replacement power 39 would either be produced in northern Illinois within the PJM region or would be purchased by 40 PJM from MISO.
41 In 2012, electric generators in the ROI had a net summer generating capacity of approximately 42 179,000 megawatts (MW). This capacity included units fueled by coal (49 percent), natural gas 43 (27 percent), nuclear (11 percent), and wind (6.6 percent) (EIA 2014c).
44 In 2011, the electric industry in the ROI provided approximately 744 million megawatt hours 45 (MWh) of electricity. Electricity produced in the ROI was dominated by coal (67 percent) and 46 nuclear (21 percent). Although natural gas makes up nearly 30 percent of the installed 47 generating capacity in the ROI, it provides only 6 percent of electricity in the region.
48 Nonhydroelectric renewable energy produced 1.3 percent of the electricity in the ROI 49 (EIA 2014b).
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Alternatives Including the Proposed Action 1                      Figure 2-1. Territories of MISO and PJM Interconnection 2                                    Source: MISO-PJM undated 3 Renewable Energy Legislation in the Region of Influence 4 Renewable energy legislation in Illinois allows the purchase of electricity generation in adjoining 5 States; therefore, any legislation targeting renewable energy in these States could impact a 6 States incentive to develop renewable resources. Five States in the ROI (Illinois, Iowa, 7 Missouri, Wisconsin, and Michigan) have legally mandated renewable energy programs. The 8 State of Indiana has a voluntary program, and State of Kentucky does not have any renewable 9 energy requirements. The paragraphs below briefly outline each States program, including 10 renewable energy goals and benchmarks.
11 In August 2007, Illinois adopted a renewable portfolio standard that requires the States utilities 12 to produce at least 25 percent of their power from renewable sources by 2025, 75 percent of 13 which must come from wind. Solar PV must comprise 6 percent of the annual requirement for 14 calendar year 2015 and thereafter. Other eligible sources include biomass and existing 15 hydroelectric power (DSIRE 2015a). The law also includes an energy efficiency standard that 16 requires utilities to implement cost-effective energy efficiency measures to meet energy savings 17 of 1 percent by calendar year 2016 and thereafter (ILGA 2011). For electric utilities (including 18 ComEd), eligible resources must be located in Illinois; resources can be purchased from 19 adjoining States only if there are insufficient in-State resources (ILGA 2011).
20 Iowas Alternative Energy Production Law requires the States two investor-owned utilities to 21 generate a combined total of 105 MW of their generating capacity from renewable energy 22 sources. A 2007 order allows the utilities to participate in renewable energy credit trading 23 programs by distinguishing between renewable electricity production capacity used to comply 24 with Iowa law and that which can be used to satisfy other states renewable portfolio standards 25 (DSIRE 2014).
26 Missouri adopted a renewable portfolio standard that requires investor-owned utilities to 27 increase their use of renewable sources by 15 percent by 2021 and includes a provision 28 specifying that 2 percent of the renewable portfolio standard requirement must be met by solar 29 energy. Resources can be purchased from outside Missouri, but renewable energy generated 30 in-State receives a multiplier of 1.25 compared to out-of-State generation (DSIRE 2015b).
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Alternatives Including the Proposed Action 1 Wisconsins renewable portfolio standard requires utilities to produce 10 percent of their 2 electricity from renewable sources by 2015. Included in the renewable portfolio standard is a 3 provision that allows electricity providers to create and sell or transfer renewable resource 4 credits and renewable energy certificates. Renewable energy generated outside Wisconsin is 5 eligible, provided that the electricity is distributed to Wisconsin customers (DSIRE 2015c).
6 Michigan enacted a Renewable Energy Standard in 2008 that requires utilities to generate 7 10 percent of their retail electricity sales from renewable energy resources by 2015.
8 The standard also allows energy efficiency and advanced cleaner energy systems to meet part 9 of the requirement. Renewable energy credits can be purchased from in-State or out-of-State 10 facilities, provided that the facilities are located within the retail electric service territory of a 11 utility that is recognized by the Michigan Public Service Commission (DSIRE 2015d).
12 Indiana does not have a mandatory renewable or alternative energy portfolio standard. On 13 July 9, 2012, Indiana adopted a Clean Energy Portfolio Standard, which sets a voluntary goal of 14 10 percent clean energy by 2025, based on the amount of electricity supplied by the utility in 15 2010. Unlike many of the other ROI states, up to 30 percent of the goal may be met with clean 16 coal technology, nuclear energy, combined heat and power systems, natural gas that displaces 17 electricity from coal, and net-metered distributed generation facilities. Fifty percent of qualifying 18 energy must come from within the State. Utilities that participate in the program and meet the 19 program goals are eligible for incentives that are used to pay for the compliance projects 20 (DSIRE 2015e).
21 Kentucky is the only State in the ROI that does not have mandatory or voluntary renewable 22 energy requirements.
23 Given known technological and demographic trends, the EIA predicts that 34 percent of 24 electricity in the United States will be generated by coal in 2040 (EIA 2015). Natural gas 25 generation rose from 16 percent in 2000 to 27 percent in 2013 and is projected to increase to 26 31 percent in 2040 (EIA 2013a, 2015). Electricity generation from renewable energy is 27 expected to grow from 13 percent of total generation in 2013 to 18 percent in 2040 (EIA 2015).
28 However, there are uncertainties that could affect this forecast, particularly the implementation 29 of policies aimed at reducing greenhouse gas emissions, which would have a direct effect on 30 fossil fuel-based generation technologies.
31 The remainder of this section describes replacement power alternatives to license renewal 32 considered in depth. These include a new nuclear alternative in Section 2.2.2.1; a 33 coal-integrated gasification combined-cycle (IGCC) alternative in Section 2.2.2.2; a natural gas 34 combined-cycle (NGCC) alternative in Section 2.2.2.3; a combination natural gas, wind, and 35 solar power alternative in Section 2.2.2.4; and a purchased power alternative in Section 2.2.2.5.
36 Table 2-1 summarizes key design characteristics of the alternative technologies evaluated in 37 depth. The environmental impacts of these alternatives are evaluated in Chapter 4.
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Alternatives Including the Proposed Action 1      Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 2                                          Considered in Depth(a)
New Nuclear                                                              Combination Alternative              IGCC Alternative          NGCC Alternative      Alternative Summary of    Two-unit nuclear          Four 618-MWe units, Five 560-MWe                One 360 MWe Alternative    plant, each with          for a total of            units, for a total of NGCC unit; a 1,120 MWe, for a total 2,472 MWe                    2,800 MWe            1,813 MWe wind of 2,240 MWe                                                              farm; and a 227 MWe installed solar PV facility, for a total of 2,400 MWe Location      An existing nuclear      On the LSCS site or      On the LSCS site. The NGCC plant site or retired    at another existing      New transmission      component would coal plant site outside  power plant site.        line(s) and other    be located on the Illinois. New            New transmission          infrastructure        LSCS site. The transmission line(s)      line(s) and other        upgrades may be      wind and solar and other                infrastructure            required; would      components would infrastructure            upgrades may be          require construction  be spread across upgrades may be          required. Some            of a new or          multiple sites required. Some            facilities (e.g., support upgraded pipeline. throughout the ROI.
facilities (e.g., support buildings, potable        Some facilities buildings, potable        water supply, and        (e.g., support water supply, and        sanitary discharge        buildings, potable sanitary discharge        structures) could be      water supply, and structures) could be      shared with existing      sanitary discharge shared with existing      plant.                    structures) could be plant.                                              shared with existing plant.
Cooling        Closed-cycle with        Closed-cycle with        Closed-cycle with    For the NGCC System        natural draft cooling    mechanical draft          mechanical draft      portion, towers. Cooling          cooling towers.          cooling towers.      closed-cycle with water withdrawal        Cooling water            Cooling water        mechanical draft 56 mgd; consumptive      withdrawal25 mgd;        withdrawal          cooling towers.
water use42 mgd          consumptive water        17 mgd;              Cooling water (NRC 2008).              use20 mgd                consumptive water    would be 15% of (NETL 2013a).            use13 mgd            that required for (NETL 2013a).        NGCC alternative.
Minimal water use for wind and solar.
Land          556 ac (225 ha)          2,000 ac (800 ha) for    94 ac (38 ha) for the Wind farms would Require-      (NRC 2008); 520 ac        the major permanent      plant, including      require 3,376 ac ments          (210 ha) for uranium      facilities; 1,100 ac      pipelines            (1,366 ha) to mining and                (450 ha) per year for    (Exelon 2014);        10,127 ac processing(b)            mining (DOE 2010a)        10,080 ac            (4,098 ha) (WAPA (NRC 2013)                                          (4,079 ha) for gas    and FWS 2013);
extraction and        solar PV facilities collection            would require (NRC 1996)            6,749 ac (2,731 ha)
(Ong et al. 2013).
For the NGCC portion, land use would remain the 2-8
 
Alternatives Including the Proposed Action New Nuclear                                                                    Combination Alternative                IGCC Alternative        NGCC Alternative          Alternative same at 94 ac (38 ha)
(Exelon 2014).
Work Force          3,500 workers during        4,600 workers during    1,783 workers            Solar PV peak construction;          peak construction;      during peak              600 workers during 812 workers during          420 workers during      construction;            peak construction, operations                  operations              94 workers during        60 workers during (NRC 2008)                  (DOE 2010a)              operations                operations (Exelon 2014)            (DOE 2010b).
Wind931 workers during construction, 566 workers during operations (DOE 2008).
NGCCnumber of construction and operations workers would be less than the NGCC alternative but would not be a linear reduction because of the need for a minimum number of workers regardless of the size of the plant.
Key: ac = acres, ha = hectares, IGCC = coal-integrated gasification combined-cycle (alternative), mgd = million gallons per day, MWe = megawatts electric, NGCC = natural gas combined-cycle (alternative), PV = photovoltaic, and ROI = region of influence.
(a) Because  of the speculative nature of using purchased power to replace LSCS capacity and because of the inherent variability of characteristics associated with such an approach, this table does not include the purchased power alternative.
(b) This is normalized to model the light water reactor annual fuel requirement. Forty-two percent of this land requirement is temporarily committed land.
Sources: DOE 2008, 2010a, 2010b; Exelon 2014; NETL 2013a; NRC 1996, 2008, 2013; Ong et al. 2013; WAPA and FWS 2013 1 2.2.2.1        New Nuclear Alternative 2 In this section, the NRC staff describes the new nuclear alternative. The NRC staff evaluates 3 the environmental impacts from this alternative in Chapter 4.
4 The NRC staff considered the construction of a new nuclear plant to be a reasonable alternative 5 to license renewal. For example, nuclear generation currently provides 21 percent of electricity 6 generation in the ROI (EIA 2014b). Twelve nuclear power plants operate in the ROI; 7 eight applicants have received renewed licenses, and three additional applicants have applied 8 for renewed licenses from the NRC (including LSCS) (NRC 2015). In addition, there is interest 9 in new nuclear power plant development in the region; combined operating license (COL) 10 applications have been filed for two new nuclear power plants in the ROI. On July 24, 2008, 2-9
 
Alternatives Including the Proposed Action 1 Union Electric Company submitted a COL application for Callaway Plant, Unit 2, in Callaway 2 County, Missouri, on the existing Callaway site (AmerenUE 2009). However, Ameren UE has 3 since announced that they are canceling their COL application (Barker 2015). An application 4 was also filed in September 2008 for Enrico Fermi Atomic Power Plant, Unit 3, in Monroe 5 County, Michigan, on the existing Fermi site. On May 1, 2015, the NRC issued a COL 6 authorizing DTE Electric Company to build and operate an economic simplified BWR at the 7 Fermi site (Volume 80 of the Federal Register, 26302 (80 FR 26302)). The NRC staff 8 determined that there may be sufficient time for Exelon to prepare and submit an application, 9 build, and operate two new nuclear units using a certified design before the LSCS licenses 10 expire in April 2022 and December 2023.
11 In evaluating the new nuclear alternative, the NRC staff assumed that two new nuclear reactors 12 would be built on an existing nuclear or coal power plant site, allowing for the maximum use of 13 existing ancillary facilities at those locations, such as support buildings and transmission 14 infrastructure. In 1987, Illinois enacted a moratorium preventing the construction of new nuclear 15 power plants within the State. Until the moratorium is lifted, a new nuclear alternative would 16 require siting elsewhere in the ROI. For the purposes of this analysis, the NRC relied on the 17 Vogtle Electric Generating Plant (Vogtle), Units 3 and 4 (located in Waynesboro, Georgia), COL 18 environmental impact statement for technological parameters for the new nuclear alternative 19 because the Vogtle, Units 3 and 4, COL considers two new nuclear reactor units with a similar 20 output as LSCS and is representative of the reactors that could be constructed in the ROI 21 before LSCSs licenses expire (NRC 2011). As such, the NRC staff assumed 22 two Westinghouse AP1000 reactors with a net electrical output of 2,240 MWe would replace 23 LSCSs current reactors for this alternative. The NRC staff estimated that 324 ac (131 ha) of 24 land would be required on a long-term basis because of permanent facilities, and an additional 25 232 ac (94 ha) would be disturbed for temporary facilities, a laydown area, and storage of 26 dredge material (NRC 2008).
27 The heat rejection demands of a new nuclear alternative would be similar to those of LSCS.
28 The new reactors may require a new cooling system (including natural draft cooling towers and 29 intake and discharge structures). The NRC staff assumes that water requirements for the new 30 nuclear alternative would be similar to current water use at LSCS. A new onsite transmission 31 line and drinking water wells may be required if insufficient infrastructure occurs on the site.
32 Construction materials would be delivered by a combination of rail spur, truck, and barge, 33 depending on the specific site location. It is possible that modifications would be required to 34 deliver such materials, depending on the existing infrastructure at the site; modifications could 35 include new rail lines or access roads.
36 The NRC staff also considered the installation of multiple small modular reactors as an 37 alternative to renewing the LSCS licenses. The NRC established the Advanced Reactor 38 Program in the Office of New Reactors because of considerable interest in small modular 39 reactors along with anticipated license applications by vendors. Small modular reactors are 40 approximately 300 MW or less, would have lower initial capacity than that of large-scale units, 41 and would have siting flexibility for locations that are not large enough to accommodate 42 traditional nuclear reactors (DOE undated). As of October 2015, no applications for small 43 modular reactors have been submitted to the NRC. The DOE has estimated that the technology 44 may achieve commercial operation by 2021 to 2025 (DOE undated). Because small modular 45 reactors are not expected to be operational at a commercial scale until near the time LSCSs 46 licenses expire, it is unlikely that eight new small modular reactors (the number of units required 47 to replace LSCSs current output) could be constructed in the ROI; therefore, this analysis 48 focuses on nuclear generation by larger nuclear units.
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Alternatives Including the Proposed Action 1 2.2.2.2      IGCC Alternative 2 In this section, the NRC staff describes the IGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4.
4 Coal provides the greatest share of electrical power in the ROI, and in 2010, coal represented 5 49 percent of installed generation capacity and accounted for 67 percent of all electricity 6 generated in the ROI (EIA 2014b). IGCC is a technology that generates electricity from coal 7 and combines modern coal gasification technology with both gas-turbine and steam-turbine 8 power generation. The technology is cleaner than conventional pulverized coal plants because 9 some of the major pollutants are removed from the gas stream before combustion. An IGCC 10 power plant consists of coal gasification and combined-cycle power generation. Coal gasifiers 11 convert coal into a gas (synthesis gas, also referred to as syngas), which fuels the 12 combined-cycle power generating units. The combined-cycle system for a 618-MWe IGCC 13 power plant includes two combustion turbines, two heat recovery steam generators, and a 14 steam turbine. The combined-cycle units combust gas in one or more combustion turbines, and 15 the resulting hot exhaust gas is then used to heat water into steam to drive a steam turbine.
16 The steam turbine then uses the heat from the gas turbines exhaust through a heat recovery 17 steam generator to produce additional electricity (DOE 2010a). This two-cycle process has a 18 high rate of efficiency because the exhaust heat that would otherwise be lost is captured and 19 reused. In addition, the power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and 20 particulate emissions by removing constituents from the syngas before combustion. Nearly 21 100 percent of the nitrogen from the syngas would be removed before combustion in the gas 22 turbines and would result in lower nitrogen oxide emissions compared to conventional coal-fired 23 power plants (DOE 2010a).
24 IGCC power plants have been in operation since the mid-1990s; the Wabash Rice IGCC 25 repowering project in Indiana and the Polk Power Station in Florida are two examples of 26 operating IGCC plants. Recently, there has been an increased interest in new IGCC projects, 27 and multiple new projects have been proposed or have recently begun operations in the 28 United States. The Duke Energy Edwardsport Generation Station (Edwardsport) in Indiana is a 29 618-MWe IGCC power plant in the ROI that began commercial operation in June 2013. Duke 30 Energy estimates that the IGCC plant will produce 10 times as much power as the retired coal 31 plant it replaced with 70 percent fewer emissions of sulfur dioxide, nitrogen oxides, and 32 particulates. The IGCC plant will reduce carbon emissions per megawatt hour by nearly half 33 compared to conventional coal-fired plants (Duke Energy 2013). In addition, Edwardsport has 34 the potential for carbon capture and geologic sequestration. Space has been reserved at the 35 site for carbon dioxide capture equipment (NETL 2013b).
36 Many IGCC power plants have been designed with carbon capture and storage (CCS) to further 37 reduce carbon dioxide emissions. The Kemper County IGCC project in east-central Mississippi 38 proposes to use CCS to reduce carbon dioxide emissions by almost 70 percent by removing 39 carbon from the syngas post-gasification (DOE 2010a). According to a 2013 National Energy 40 Technology Laboratory (NETL) report, nine IGCC projects totaling over 4,000 MW are currently 41 active; these projects are in the planning stages, or they have begun construction.
42 Thirteen projects have been proposed and subsequently canceled for a variety of reasons, 43 including air quality issues, state laws and regulations, redirected focus on gas-fired generation 44 and renewables, and unanticipated rising costs (NETL 2013c).
45 IGCC technology and proposed projects have experienced a number of setbacks and 46 opposition, hindering IGCCs ability to fully integrate into the energy market. The most 47 significant roadblock is IGCCs high capital cost compared to conventional coal-fired power 48 plants. Cost overruns have been experienced at both the Edwardsport IGCC project and the 2-11
 
Alternatives Including the Proposed Action 1 Kemper County IGCC project. FutureGen, an IGCC plant featuring CCS, lost DOE financial 2 support because of escalating cost estimates (Reuters 2012). Other issues include construction 3 timeline overruns, a limited track record for reliable performance, and opposition from an 4 environmental perspective.
5 Despite some of the current setbacks and concerns associated with IGCC projects, the NRC 6 staff considers IGCC technology to be a reasonable source of baseload power to replace LSCS 7 by the time its licenses expire in 2022 and 2023 because of the current regulatory framework 8 and the number of active IGCC plants within the ROI. On August 3, 2015, EPA signed a final 9 rule for carbon pollution that would apply to new fossil fuel-fired power plants 10 (80 FR 64661-65120). The action establishes performance standards for utility boilers and 11 IGCC units based on partial implementation of a CCS system as a method of emission 12 reduction. The emission limit for these sources is 1,305 lb carbon dioxide per megawatt hour 13 (CO2/MWh), and any new coal-fired power plants could require CCS in order to achieve this 14 emission limit.
15 Overall, the NRC staff considers IGCC power plants as an alternative to LSCS because the 16 Edwardsport IGCC project in Indiana is currently in operation and because the Kemper County 17 IGCC project in Mississippi is under construction. The technology parameters for these plants 18 are considered the current state of technology and are used here to describe a hypothetical 19 IGCC power plant located on an existing power plant site within the ROI.
20 To replace the electricity that LSCS generates, the NRC staff considered four IGCC units, each 21 with a net capacity of 618 MWe. Various coal sources are available to coal-fired power plants in 22 the ROI. For the purpose of this evaluation, the NRC staff assumes that the IGCC alternative 23 would burn a sub-bituminous coal based on the type of coal used in electric plants in Illinois.
24 The NRC staff presumes that coal burned in Illinois will be representative of coal that would be 25 burned in an IGCC alternative regardless of where it may be located (EIA 2012). The IGCC 26 units would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 27 removing constituents from the syngas. In addition, the units would be designed with the 28 potential to add CCS later. Using CCS, carbon dioxide emission would be compressed and 29 piped off site where it could be sold for beneficial use or geologic storage.
30 The IGCC alternative would be located at an existing site (such as an existing power plant site) 31 to maximize availability of infrastructure and to reduce other environmental impacts. Depending 32 on the specific site location, there might be a need to construct new intake and discharge 33 facilities and a new cooling system. The IGCC alternative would use about the same amount of 34 water as LSCS and a similar amount as the Edwardsport IGCC plant. The NRC staff assumes 35 that the cooling system would use a closed-cycle system with mechanical draft cooling towers.
36 This system would withdraw 25 million gallons per day (gpd) (95 million liters per day (Lpd)) of 37 water and would consume 20 million gpd (76 million Lpd). Onsite visible structures could 38 include the boilers, exhaust stacks, intake and discharge structures, mechanical draft cooling 39 towers, transmission lines, and an electrical switchyard. Construction materials would be 40 delivered by a combination of rail spur, truck, and barge, depending on the specific site location.
41 Modifications may be required to deliver such materials; modifications could include new rail 42 lines or access roads.
43 The NRC staff also considered supercritical pulverized coal (SCPC) as an alternative to 44 renewing the LSCS licenses. SCPC was dismissed as the coal alternative because of new 45 regulations aimed at limiting the environmental impacts from conventional pulverized coal 46 plants. The presence of active IGCC plants in the ROI also contributed to the selection of IGCC 47 for analysis.
2-12
 
Alternatives Including the Proposed Action 1 2.2.2.3      NGCC Alternative 2 In this section, the NRC staff describes the NGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4.
4 Natural gas represents nearly 30 percent of installed generation capacity in the ROI but 5 provides only 6 percent of all electrical power in the ROI (EIA 2014b, 2014c). Nationwide, the 6 percentage of power generated by natural gas is expected to rise through 2040, although the 7 actual rise in natural gas generation will depend on future natural gas prices (EIA 2013a). The 8 NRC staff considers the construction of an NGCC power plant to be a reasonable alternative to 9 license renewal because it is a feasible, commercially available option for providing electrical 10 generating capacity beyond the expiration of LSCSs current licenses.
11 Baseload NGCC power plants have proven their reliability and can have capacity factors as high 12 as 85 percent. In an NGCC system, electricity is generated using a gas turbine that burns 13 natural gas. A steam turbine uses the heat from gas turbine exhaust through a heat recovery 14 steam generator to produce additional electricity. This two-cycle process has a high rate of 15 efficiency because the exhaust heat that would otherwise be lost is captured and reused. Like 16 other fossil fuel sources, NGCC power plants are a source of greenhouse gases, including 17 carbon dioxide. An NGCC power plant, however, produces significantly fewer greenhouse 18 gases per unit of electrical output than conventional coal-powered plants.
19 To replace the electricity that LSCS generates, the NRC staff considered five NGCC units, each 20 with a net capacity of 560 MWe (NETL 2007). The NRC staff assumes that each plant 21 configuration consists of two combustion turbine generators, two heat recovery steam 22 generators, and one steam turbine generator with mechanical draft cooling towers for heat 23 rejection. The power plant is assumed to incorporate a selective catalytic reduction system to 24 minimize the plants nitrogen oxide emissions (NETL 2007).
25 This 2,800-MWe NGCC plant would consume 124 billion cubic feet (3,500 million cubic meters) 26 of natural gas annually, assuming an average heat content of 1,021 British thermal units per 27 cubic foot (EIA 2013c). Natural gas would be extracted from the ground through wells, and then 28 it would be treated to remove impurities and blended to meet pipeline gas standards before 29 being piped through the State pipeline system to the plant site. This NGCC alternative would 30 produce relatively little waste, primarily in the form of spent catalysts used for control of nitrogen 31 oxide emissions.
32 The NGCC alternative would be located on undeveloped land at LSCS to maximize availability 33 of infrastructure and to reduce other environmental impacts. Depending on the specific site 34 location, there might be a need to construct new intake and discharge facilities and a new 35 cooling system. Because NGCC power plants generate much of their power from a gas-turbine 36 combined-cycle plant and because the overall thermal efficiency of this type of plant is high, an 37 NGCC alternative would require less cooling water than LSCS would. This system would 38 withdraw 17 million gpd (64 million Lpd) of water and would consume 13 million gpd 39 (49 million Lpd). The NRC staff assumes that the cooling system would use a closed-cycle 40 system with mechanical draft cooling towers. Onsite visible structures could include the cooling 41 towers, exhaust stacks, intake and discharge structures, transmission lines, natural gas 42 pipelines, and an electrical switchyard. Construction materials could be delivered by a 43 combination of rail spur, truck, and barge. Modifications may be required to deliver such 44 materials; modifications could include new rail lines or access roads.
45 2.2.2.4      Combination Alternative (NGCC, Wind, and Solar) 46 In this section, the NRC staff describes the combination alternative to the continued operation of 47 LSCS consisting of an NGCC facility constructed at an existing power plant site and operating in 2-13
 
Alternatives Including the Proposed Action 1 conjunction with land-based wind farms and solar energy facilities, all of which would be located 2 within the ROI. The NRC staff evaluates the environmental impacts from this alternative in 3 Chapter 4.
4 To serve as an effective baseload power alternative to the LSCS reactors, this combination 5 alternative must be capable of providing an equivalent amount of baseload power. For the 6 purpose of this evaluation, the NRC staff presumes that NGCC, wind farms, and solar PV 7 facilities would comprise the combination alternative.
8 NGCC Portion of the Combination Alternative 9 To produce its required share of power (360 MWe), the NGCC portion, operating at an expected 10 capacity factor of 85 percent (NETL 2007), would need to have a nameplate rating of 11 approximately 425 MWe.
12 In 2013, the EIA reported that natural gas-fired power plants are generally used infrequently for 13 shorter periods to meet peak demand. Capacity factors for natural gas plants averaged less 14 than 5 percent during off-peak demand hours for most regions of the country. Natural gas is 15 used for these peaker plants because natural gas combustion turbines can respond quickly; 16 therefore, they tend to be used to meet short-term increases in electricity demand (EIA 2013d).
17 A report prepared by CITI Research stated that gas-fired power plants can help overcome the 18 intermittent nature of renewable energy (Channell et al. 2012). The peaking aspect of natural 19 gas-fired power plants makes natural gas an ideal addition to an otherwise renewable energy 20 combination alternative.
21 The NRC staff assumed that one new NGCC unit of the type described in Section 2.2.2.3 would 22 be constructed and installed at LSCS with a total net capacity of 360 MWe. The appearance of 23 an NGCC unit would be similar to that of the full NGCC alternative considered in 24 Section 2.2.2.3, although only one unit would be constructed. The NRC staff assumes that the 25 NGCC portion of this alternative, which is assumed to be located at LSCS, would use existing 26 electrical switchyards, substations, and transmission lines. Depending on the existing site 27 conditions, it is possible that intake and discharge structures of the existing cooling system 28 could continue in service but would be connected to a new closed-cycle cooling system. For the 29 purposes of this analysis, the NRC staff assumes that the NGCC portion of the combination 30 would use mechanical draft cooling towers.
31 Wind Portion of the Combination Alternative 32 The NRC staff assumes that the wind-generated power from this combination alternative would 33 come from land-based wind farms, which would be located in the ROI within the States of 34 Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, or Wisconsin. The wind portion, assuming 35 a capacity factor of 30 percent, would require a nameplate capacity of 6,042 MWe (WAPA and 36 FWS 2013).
37 The American Wind Energy Association reports a total of more than 67,000 MW of installed 38 wind energy capacity nationwide as of June 30, 2015 (DOE 2015). As of June 2015, Texas is 39 by far the leader in installed land-based capacity with 15,635 MW. Two States in the ROI have 40 the third and fifth largest installed capacity: Iowa with 5,708 MW, followed by Illinois with 41 3,667 MW (DOE 2015). The installed wind capacity in the ROI has been increasing annually by 42 1,000 MWe to 2,500 MWe in each of the past 8 years, for a total of over 13,000 MWe of 43 additional wind capacity from 2007 to 2014 (DOE 2015). Therefore, the NRC staff considers 44 6,042 MW of wind energy to be a reasonable amount by the time the LSCS licenses expire in 45 2022 and 2023. As is the case with other renewable energy sources, the feasibility of wind 46 resources serving as alternative baseload power is dependent on the location (relative to 47 expected load centers), value, accessibility, and constancy of the resource. Wind energy must 2-14
 
Alternatives Including the Proposed Action 1 be converted to electricity at or near the point where it is extracted, and there are limited energy 2 storage opportunities available to overcome the intermittency and variability of wind resources.
3 At the current stage of wind energy technology development, wind resources in wind power 4 class 3 and higher are suitable for most utility scale applications (NREL 2014a). Wind power 5 class 3 is defined as having a wind speed of 15.7 miles per hour (7.0 meters per second) and a 6 wind density of 500 watts per square meter at 164 ft (50 m) (NREL 2014a). Each State in the 7 ROI, other than Kentucky, has wind resources meeting this power class, with the highest 8 concentrations occurring in Iowa and Illinois (NREL 2015a).
9 Individual wind turbine capacity increased from 0.71 MW in 1999 to 1.79 MW in 2010. The size 10 of turbine most frequently installed in the United States in recent years is the 1.5-MW turbine 11 (WAPA and FWS 2013). For the purposes of this analysis, the NRC staff assumes wind 12 turbines with a capacity of 1.79 MW. The capacity factors of land-based wind farms are lower 13 than offshore wind farms (WAPA and FWS 2013). For the wind portion of the combination 14 alternative, the NRC staff assumed a capacity factor of 30 percent, resulting in an estimated 15 total net capacity of 1,813 MWe. Wind turbines must be well separated from each other to 16 avoid interferences to wind flowing through the wind farm, resulting in wind farms requiring 17 substantial amounts of land. Wind turbines may require as much as 1 to 3 ac (0.4 to 1.2 ha) of 18 land for each turbine (WAPA and FWS 2013). Based on the size of the turbines and amount of 19 land required between each turbine, approximately 3,376 turbines and 3,376 to 10,127 ac 20 (1,366 to 4,098 ha) would be required for the wind portion of the combination alternative.
21 Wind energys intermittency affects its viability and value as a baseload power source.
22 However, the variability of wind-generated electricity can be lessened if the proposed wind 23 farms were located at a large distance from one another and were operated as interconnected 24 wind farms, an aggregate controlled from a central point. Distance separation ensures that the 25 two wind farms will not simultaneously experience the same climate, and power will likely be 26 produced at some of the wind farms at any given time (Archer and Jacobson 2007).
27 Solar Photovoltaic Portion of the Combination Alternative 28 The solar portion of the combination alternative would be generated through one or more solar 29 PV energy facilities located in the ROI. Assuming a capacity factor of 19 percent, the solar 30 energy facilities would need a collective nameplate rating of 1,193 MWe. Solar PV technologies 31 could be installed on building roofs at existing residential, commercial, or industrial sites or at 32 larger standalone solar facilities.
33 Nationwide, growth in large solar PV facilities (greater than 5 MW) has resulted in an increase 34 from 70 MW in 2009 to over 700 MW installed capacity in 2011. As of January 2012, it is 35 estimated that more than 11,000 MW of large solar PV projects have signed power purchase 36 agreements (Mendelsohn et al. 2012). Over 9,000 MW of those solar projects are 50 MW or 37 greater, although most are located in the southwestern United States (Mendelsohn et al. 2012).
38 As described in Section 2.2.2, two States in the ROI (Missouri and Illinois) have renewable 39 energy legislation that includes requirements for solar PV technology. Missouris renewable 40 portfolio standard includes a provision specifying that 2 percent of the renewable portfolio 41 standard requirement must be met by solar energy by 2021. Illinois renewable portfolio 42 standard specifies that solar PV must comprise 6 percent of the annual requirement for 43 compliance year 2015-2016 and thereafter. As of 2012, only 33 MW of solar energy capacity 44 had been installed in the ROI (EIA 2014c).
45 Solar PV resources in the ROI range from 4.0 to 5.0 kilowatt hours per square meter per day 46 (kWh/m2/day). The most viable solar resources are located in Missouri, Iowa, and southern 47 Illinois and Indiana (NREL 2015b). Economically viable solar resources are considered to be 48 6.75 kWh/m2/day and greater (BLM and DOE 2010). As is the case with wind energy sources, 2-15
 
Alternatives Including the Proposed Action 1 the feasibility of solar energy resources serving as alternative baseload power is dependent on 2 the location, value, accessibility, and constancy of the resource. Solar PV uses solar panels to 3 convert solar radiation into usable electricity. Solar cells are formed into solar panels that can 4 then be linked into PV arrays to generate electricity. The electricity generated can be stored, 5 used directly, fed into a large electricity grid, or combined with other electricity generators as a 6 hybrid plant. Solar PV can generate electricity whenever there is sunlight, regardless of 7 whether the sun is directly shining on solar panels. Therefore, solar PV technologies do not 8 need to directly face and track the sun, which has allowed solar PV systems to have broader 9 geographical use than concentrated solar power (Ardani and Margolis 2011). Because the ROI 10 contains average solar PV resources and because solar PV is a commercially available option 11 for providing electrical generating capacity, the NRC staff considers the construction of solar PV 12 facilities to be a reasonable alternative to license renewal when combined with wind and NGCC.
13 For the purposes of this analysis, the NRC staff assumes solar PV facilities with a capacity 14 factor of 19 percent (Ardani and Margolis 2011). Solar PV facilities may require 6.2 ac (2.5 ha) 15 of land per megawatt (NRC 2013). Although not all of this land would be cleared of vegetation 16 and permanently impacted, it represents the land enclosed in the total site boundary of the solar 17 facility (Ong et al. 2013). For the solar portion of this combination alternative, approximately 18 7,397 ac (2,993 ha) would be required to support an installed net capacity of 227 MWe. In this 19 analysis, the NRC staff does not speculate on the number and size of individual solar facilities, 20 nor their locations within the ROI. However, as stated above, some of the output could be 21 realized by solar PV installations on building roofs at existing residential, commercial, or 22 industrial sites or at larger standalone solar facilities. To the extent that rooftop or 23 building-integrated solar PV installations remain popular, land impacts would be relatively minor.
24 Solar PV systems do not require water for cooling purposes, but a small amount of water is 25 needed to clean the panels and for potable water for the workforce. Impacts identified in the 26 U.S. Department of the Interior Bureau of Land Management (BLM) and DOEs Solar Energy 27 Programmatic Environmental Impact Statement (PEIS) (BLM and DOE 2010, 2012) provide 28 information used in the analyses presented in the impact sections in Chapter 4.
29 2.2.2.5      Purchased Power Alternative 30 In this section, the NRC staff describes purchased power as an alternative to the continued 31 operation of LSCS.
32 The impacts from purchased power would depend substantially on the generation technologies 33 used to supply the purchased power. Impacts from operation of other electricity generators 34 would likely occur in the ROI. As discussed in Section 2.2.1, replacement power for LSCS 35 would be required in northern Illinois and could come from anywhere within Illinois or adjoining 36 states in either the PJM or MISO Regional Transmission Organizations (RTOs). Given the large 37 geographic area, multiple RTOs within the ROI, and wide-ranging generating facilities, the NRC 38 staff considers purchased power to be a feasible source of baseload power to replace LSCS by 39 the time the licenses expire in 2022 and 2023.
40 Purchased power would likely come from the most common types of electricity generation within 41 the ROI: coal, natural gas, nuclear, and wind. All these power sources are discussed as 42 alternatives to license renewal of LSCS and are identified in Sections 2.2.2.2 to 2.2.2.4.
43 Construction and operational impacts from these sources of electricity generation are 44 considered in Chapter 4. Purchased power may require new transmission lines (which may 45 require new construction) and may also rely on older and less-efficient power plants operating at 46 higher capacities than they currently operate or on new facilities that would be constructed.
47 During operations, impacts from nuclear, coal-fired, and natural gas-fired plants and from wind 2-16
 
Alternatives Including the Proposed Action 1 and solar energy projects would be similar to those described under the new nuclear, coal, 2 natural gas, and combination alternatives described in Chapter 4 for all resource areas.
3 2.3      Alternatives Considered but Dismissed 4 Alternatives to LSCS license renewal that were considered and eliminated from detailed study 5 are presented in this section. These alternatives were eliminated because of technical resource 6 availability or current commercial limitations. Many of these limitations would continue to exist 7 when the current LSCS licenses expire.
8 2.3.1      Energy Conservation and Energy Efficiency 9 Energy conservation can include reducing energy demand through behavioral changes or 10 altering the shape of the electricity load and usually does not require the addition of new 11 generating capacity. Conservation and energy efficiency programs are more broadly referred to 12 as demand-side management.
13 Conservation and energy efficiency programs can be initiated by a utility, transmission 14 operators, the state, or other load-serving entities. The State of Illinois renewable portfolio 15 standard includes an energy efficiency portfolio standard that requires utilities to reduce electric 16 usage by 2 percent of demand by 2015 (DSIRE 2015a), which is equivalent to 4 million MWh, 17 only 20 percent of the amount that would be required to offset LSCSs current electrical 18 generation.
19 In general, residential electricity consumers have been responsible for the majority of peak load 20 reductions, and participation in most programs is voluntary. Therefore, the existence of a 21 program does not guarantee that reductions in electricity demand would occur. The GEIS 22 concludes that, although the energy conservation or energy efficiency potential in the 23 United States is substantial, there are likely no cases where an energy efficiency or 24 conservation program has been implemented expressly to replace or offset a large baseload 25 generation station (NRC 2013). Although significant energy savings are possible in the ROI 26 through demand-side management and energy efficiency programs, conservation and energy 27 efficiency programs are not likely to replace LSCS as a standalone alternative; therefore, the 28 NRC staff does not consider conservation and energy efficiency to be a reasonable alternative 29 to license renewal.
30 2.3.2      Solar 31 Solar power, including solar PV and concentrated solar power technologies, produce power 32 generated from sunlight. PVs convert sunlight directly into electricity using solar cells made 33 from silicon or cadmium telluride. Concentrating solar power uses heat from the sun to boil 34 water and produce steam to drive a turbine connected to a generator to produce electricity 35 (NREL 2014b). To be considered a viable alternative, a solar alternative must replace the 36 amount of electricity LSCS provides. Assuming a capacity factor of 19 percent (Ardani and 37 Margolis 2011), approximately 12,400 MWe of electricity would need to be generated by solar 38 energy facilities in the seven-State ROI.
39 In 2012, 33 MW of solar energy capacity was installed in the ROI (EIA 2014c). The DOEs 40 National Renewable Energy Laboratory (NREL) reports that the States in the ROI receive solar 41 insolation of 4.0 to 5.0 kWh/m2/day, which is considered low to average (NREL 2015b). For 42 utility-scale development, insolation levels below 6.5 kWh/m2/day are not considered 43 economically viable given current technologies (BLM and DOE 2010). There is more potential 44 for solar development using local PV applications, such as rooftop solar panels, than through 2-17
 
Alternatives Including the Proposed Action 1 utility-scale solar facilities. In addition, a solar facility can only generate electricity when the sun 2 is shining. Energy storage can be used to overcome intermittency for concentrating solar power 3 facilities; however, current and foreseeable storage technologies that have been paired with 4 solar power facilities have a much smaller capacity than would be necessary to replace LSCS.
5 Taking all of the factors above into account, it is unlikely that solar PV or concentrated solar 6 power technologies could serve as baseload power in the ROI to replace LSCSs current 7 electricity output. Given the modest levels of solar energy available throughout the ROI, the 8 lack of substantial installed solar capacity in the ROI and the weather-dependent intermittency 9 of solar power, the NRC staff concludes that a solar power energy facility in the ROI would not 10 be a reasonable alternative to license renewal. The NRC staff described an alternative of solar 11 power in combination with wind and an NGCC plant in Section 2.2.2.4.
12 2.3.3      Wind 13 Two States in the ROI have the third and fifth largest installed capacity in the Nation: Iowa with 14 5,708 MW, followed by Illinois with 3,667 MW (DOE 2015). The installed wind capacity in the 15 ROI has been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 8 years, for 16 a total of over 13,000 MWe of additional wind capacity from 2007 to 2014 (DOE 2015). All of 17 the wind energy facilities and the electricity generation from wind currently being produced in 18 the ROI are land based. To be considered a viable alternative, a wind alternative must replace 19 the amount of electricity LSCS provides. Assuming a capacity factor of 30 percent for 20 land-based wind and 40 percent for offshore wind, a range of 5,665 to 7,553 MWe of electricity 21 would need to be generated by some combination of land-based and offshore wind energy 22 facilities in the seven-State ROI.
23 As is the case with other renewable energy sources, the feasibility of wind resources serving as 24 alternative baseload power is dependent on the location (relative to expected load centers),
25 value, accessibility, and constancy of the resource. Wind energy must be converted to 26 electricity at or near the point where it is extracted, and there are limited energy storage 27 opportunities available to overcome the intermittency and variability of wind resource availability.
28 Although wind power is intermittent and although individual facilities are unable to provide 29 baseload power, it has been proposed that multiple interconnected wind installations separated 30 by long distances could theoretically function as a virtual power plant and could provide 31 baseload power since individual facilities would be exposed to different weather and wind 32 conditions. To date, however, no states or utilities operate arrays of wind installations as virtual 33 power plants.
34 Given the amount of wind capacity necessary to replace LSCS and the intermittency of wind 35 power, the NRC staff finds a completely wind-based alternative to be unreasonable. However, 36 the NRC staff also concludes that, when used in combination with other technologies with 37 inherently higher capacity factors, wind energy can provide a viable alternative. The NRC staff 38 described such a possible combination alternative in Section 2.2.2.4.
39 2.3.3.1      Offshore Wind 40 The United States does not have any offshore wind farms in operation; however, approximately 41 20 projects representing more than 2,000 MW of capacity are in the planning and permitting 42 process as of 2010 (Musial and Ram 2010). Offshore wind projects have been developed in 43 Europe, most of which are located close to shore and in shallow water less than 98.4 ft (30 m) in 44 depth. Total worldwide installed capacity has been estimated at 2,377 MW (Musial and 45 Ram 2010).
46 Although wind data suggest a potential for offshore wind farms in the Great Lakes, project costs 47 likely will limit the future potential of large-scale projects (Tidball et al. 2010). NREL 2-18
 
Alternatives Including the Proposed Action 1 (Tidball et al. 2010) estimated that offshore project costs would run approximately 200 to 2 300 percent higher than land-based systems. In addition, based on current prices for wind 3 turbines, the 20-year levelized cost of electricity produced from an offshore wind farm would be 4 above the current production costs from existing power generation facilities. In addition to cost, 5 other barriers include the immature status of the technology, limited resource area, and high 6 risks and uncertainty (Tidball et al. 2010). Because no offshore wind capacity yet exists in 7 either the Great Lakes or on the Atlantic Coast and because none appears likely to exist on a 8 large commercial scale in the Great Lakes by 2022 (given the current state of development), the 9 NRC staff finds that offshore wind will not be a reasonable alternative to LSCS.
10 2.3.3.2      Wind Power with Storage 11 Energy storage is one possible way to overcome intermittency. Besides pumped hydroelectric 12 facilities, compressed air energy storage (CAES) is the technology most suited for storage of 13 large amounts of energy. In CAES systems, electricity generated during low-demand periods 14 can be stored by using a compressor to pressurize and store air; during high-demand periods, 15 the compressed air can be used to drive a turbine to generate electricity. A 2011 DOE report 16 analyzed various power-generation sources, including wind, coupled with CAES systems 17 (Ilic et al. 2011). The report considered siting criteria, using (1) proximity to natural gas lines, 18 high voltage transmission, and a market for wholesale electric power and (2) availability of 19 geology and wind resources. The results show that, within the ROI, the potential exists for 20 one CAES site in northwestern Iowa. Without detailed wind-speed data, specific site 21 information, and detailed information on the energy-storage capacity of the potential CAES site, 22 estimating how much wind capacity would be necessary and determining whether it could 23 provide for an all-wind alternative would be difficult. Furthermore, the NRC staff is not aware of 24 a CAES project coupled with wind generation that is providing baseload power. Therefore, the 25 NRC staff concludes that the use of CAES in combination with wind turbines to replace the 26 LSCS power plant is unlikely.
27 2.3.3.3      Conclusion 28 Despite the relatively high reliability demonstrated by modern turbines, the recent technological 29 advancements in turbine design and wind farm operation, and wind energys dramatic market 30 penetrations of recent years, empirical data on wind farm capacity factors and wind energys 31 limited ability to store power for delayed production of electricity cause the NRC staff to 32 conclude that wind energyon shore, off shore, or a combination thereofcould not serve as a 33 discrete alternative to the baseload power supplied by the LSCS reactors. However, the NRC 34 staff also concludes that, when used in combination with other technologies with inherently 35 higher capacity factors, wind energy can provide a viable alternative. The NRC staff described 36 such a possible combination alternative in Section 2.2.2.4.
37 2.3.4      Biomass 38 Biomass resources used for biomass-fired generation include agricultural residues, animal 39 manure, wood wastes from forestry and industry, residues from food and paper industries, 40 municipal green wastes, dedicated energy crop, and methane from landfills (IEA 2007). Using 41 biomass-fired generation for baseload power depends on the geographic distribution, available 42 quantities, constancy of supply, and energy content of biomass resources. For this analysis, the 43 NRC staff assumed that biomass would be combusted for power generation in the electricity 44 sector. Biomass is also used for space heating in residential and commercial buildings and can 45 be converted to a liquid form for use in transportation fuels (Haq undated).
46 In the GEIS, the NRC staff indicated a wood waste facility could provide baseload power and 47 could operate with capacity factors between 70 and 80 percent (NRC 2013). Although the ROI 2-19
 
Alternatives Including the Proposed Action 1 currently produces electricity from biomass fuels, the plants operating within the ROI generated 2 less than 1 percent of the total power generation in 2011 (EIA 2014b). Based on the relatively 3 low electricity generation currently produced at biomass plants, it is unlikely that these plants, or 4 the construction of several new biomass plants, could increase capacity by adding 2,327 MWe 5 of electricity from biomass-fired generation by the time LSCSs licenses expire in 2022 and 6 2023.
7 For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 8 used for biomass conversion would be similar to fossil fuel plants, including the direct 9 combustion of biomass in a boiler to produce steam (NRC 2013). Biomass generation is 10 generally more cost-effective when co-fired with coal plants (IEA 2007). Biomass-fired 11 generation plants generally are small and can reach capacities of 50 MWe, which means that 12 more than 40 new facilities would be required before the LSCS licenses expire. After 13 reevaluating current technologies, the NRC staff finds biomass-fired alternatives as still unable 14 to reliably replace the LSCS capacity. For this reason, the NRC staff does not consider 15 biomass to be a reasonable alternative to LSCS license renewal.
16 2.3.5      Hydroelectric 17 Hydroelectric power uses the force of water to turn turbines that spin a generator to produce 18 electricity. In a run-of-the-river system, the force of a river current provides the force to create 19 the needed pressure for the turbine. In a storage system, water is accumulated in reservoirs 20 created by dams and is released as needed to generate electricity.
21 The DOEs Idaho National Environmental Engineering Laboratory (now Idaho National 22 Laboratory) completed a comprehensive survey of hydropower resources in 1997. The ROI has 23 hydroelectric generating potential of 1,954 MW, adjusting for environmental, legal, and 24 institutional constraints (Conner et al. 1998). These constraints could include (1) scenic, 25 cultural, historical, and geological values, (2) Federal and state land use, and (3) legal 26 protection issues, such as wild and scenic legislation and threatened or endangered fish and 27 wildlife legislative protection. A separate assessment by DOE of nonpowered dams (dams that 28 do not produce electricity) concluded that there is potential for 4,185 MW of electricity in the ROI 29 (ORNL 2012). These nonpowered dams serve various purposes, such as providing water 30 supply to inland navigation.
31 The EIA reported that the States comprising the ROI generated 2,262 MW of electricity from 32 hydroelectric power in 2012 (EIA 2014c). In order to replace LSCSs current output, 33 hydroelectric generation across the ROI would need to double by 2022. Although there is 34 potential for anywhere between 1,954 MW and 4,185 MW of hydroelectric power, it is unlikely 35 that the maximum levels of development would occur across the entire ROI by the time LSCSs 36 licenses expire in 2022 and 2023 because the generating capacity of hydroelectric power is 37 projected to continue to decrease through 2040 (EIA 2013b). Given the decrease in projected 38 power generation from hydroelectric facilities, the NRC staff does not consider hydroelectric 39 power to be a reasonable alternative to license renewal.
40 2.3.6      Wave and Ocean Energy 41 Waves, currents, and tides are often predictable and reliable, making them attractive candidates 42 for potential renewable energy generation. Four major technologies may be suitable to harness 43 wave energy: terminator devices that range from 500 kilowatts to 2 MW, attenuators, point 44 absorbers, and overtopping devices (BOEM undated). Point absorbers and attenuators use 45 floating buoys to convert wave motion into mechanical energy, driving a generator to produce 46 electricity. Overtopping devices trap a portion of a wave at a higher elevation than the sea 2-20
 
Alternatives Including the Proposed Action 1 surface; waves then enter a tube and compress air that is used to drive a generator that 2 produces electricity (NRC 2013). Some designs are undergoing demonstration testing at 3 commercial scales, but none are currently used to provide baseload power (BOEM undated).
4 The Great Lakes do not experience large tides, and there is limited energy output for wave 5 technologies in the Great Lakes. The Electric Power Research Institute (EPRI) published a 6 document that assessed ocean wave energy resources in the United States. The Great Lakes 7 were not included in the analysis, suggesting that the resource potential is not great enough to 8 use on a commercial scale (EPRI 2011). Consequently, the limited resource availability and 9 infancy of the technologies in the Great Lakes support the NRC staffs conclusion that wave and 10 ocean energy technologies are not feasible substitutes for LSCS.
11 2.3.7      Fuel Cells 12 Fuel cells oxidize fuels without combustion and its environmental side effects. Fuel cells use a 13 fuel (e.g., hydrogen) and oxygen to create electricity through an electrochemical process. The 14 only byproducts (depending on fuel characteristics) are heat, water, and carbon dioxide 15 (depending on hydrogen fuel type) (DOE 2013a). Hydrogen fuel can come from a variety of 16 hydrocarbon resources. Natural gas is a typical hydrogen source.
17 Fuel cells are not economically or technologically competitive with other alternatives for 18 electricity generation. EIA projects that fuel cells may cost $6,835 per installed kilowatt (total 19 overnight capital costs, 2010 dollars), which is high compared to other alternative technologies 20 analyzed in this section (EIA 2010). More importantly, fuel cell units are likely to be small in size 21 (approximately 10 MWe). Replacing the power LSCS provides would be extremely costly; it 22 would require the construction of approximately 230 units and modifications to the existing 23 transmission system. Given the immature status of fuel cell technology and high cost, the NRC 24 staff does not consider fuel cells to be a reasonable alternative to LSCS license renewal.
25 2.3.8      Delayed Retirement 26 A delayed retirement alternative would consider deferring the retirement of generating facilities 27 in Illinois and its six adjoining states that include MISO and PJM RTOs.
28 To maintain reliable operations, electric systems must be able to meet peak load requirements.
29 To ensure sufficient capacity, this must also include a planning reserve margin (FERC 2013).
30 The projected MISO reserve margin for 2021 is 18.6 percent, which exceeds the reserve margin 31 requirement of 17.4 percent. However, recent EPA regulations may lead to increased coal plant 32 retirements at a faster pace than projected. In that case, 3,000 MW to 12,600 MW of plant 33 retirements could decrease the projected reserves anywhere from 16.22 to 6.9 percent, well 34 below the reserve margin requirement (MISO 2011).
35 PJM is facing similar constraints due, in large part, to retirements of coal plants given air quality 36 regulations (Ott 2013a). This indicates an emerging reliability problem potentially affecting 37 major population centers within the PJM region in the near future (Ott 2013a). Because the 38 current generation mix has not resulted in the long-term commitment of generation needed for 39 reliability, generation retirements that have occurred with short notice have created 40 unanticipated reliability problems for PJM (Ott 2013a).
41 The EIA expects that more coal plant retirements will occur before 2016 than those previously 42 predicted. These accelerated retirements are driven by low natural gas prices, slow growth in 43 electricity demand, and the requirements of the Mercury and Air Toxics Standards that will 44 require significant reductions in plant emissions (EIA 2014a, EPA 2015). Exelon also expects 45 increased generation retirements for a variety of reasons, including increased operating costs 2-21
 
Alternatives Including the Proposed Action 1 for older facilities, increased environmental regulations and competition, and decreased load 2 (Exelon undated). As generators are required to adhere to future regulations, some power 3 plants may opt for early retirement of older units rather than incur the cost for compliance.
4 Exelon has further stated that some of their nuclear fleet may be retired early because of low 5 wholesale energy prices and current energy policy (Associated Press 2015). Because of the 6 uncertain regulatory environment and concerns expressed by MISO and PJM concerning the 7 retirement pace of coal power plants, the NRC staff does not consider delayed retirement to be 8 a reasonable alternative to LSCS license renewal.
9 2.3.9    Geothermal 10 Geothermal technologies extract the heat contained in geologic formations to produce steam to 11 drive a conventional steam turbine generator. Facilities producing electricity from geothermal 12 energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 13 a potential source of baseload electric power. However, the feasibility of geothermal power 14 generation to provide baseload power depends on the regional quality and accessibility of 15 geothermal resources. Utility-scale geothermal energy generation requires geothermal 16 reservoirs with a temperature above 200 °F (93 °C). Utility-scale power plants range from small 17 300 kilowatts electric to 50 MWe and greater (TEEIC undated). Geothermal resources are 18 concentrated in the western United States. Specifically, these resources are found in Alaska, 19 Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, 20 Washington, and Wyoming. In general, most assessments of geothermal resources have been 21 concentrated on these western states (DOE 2013b; USGS 2008). Geothermal resources are 22 used in the ROI for heating and cooling purposes, but no electricity is currently being produced 23 from geothermal resources in the ROI (EIA 2014c). Given the low resource potential in the ROI, 24 the NRC staff does not consider geothermal to be a reasonable alternative to license renewal.
25 2.3.10    Municipal Solid Waste 26 Energy recovery from municipal solid waste converts nonrecyclable waste materials into usable 27 heat, electricity, or fuel through combustion (EPA 2014b). The three types of combustion 28 technologies include mass burning, modular systems, and refuse-derived fuel systems 29 (EPA 2014a). Mass burning is the method used most frequently in the United States. The heat 30 released from combustion is used to convert water to steam, which is used to drive a turbine 31 generator to produce electricity. Ash is collected and taken to a landfill, and particulates are 32 captured through a filtering system (EPA 2014a). As of 2010, approximately 33 86 waste-to-energy plants are in operation in 25 states, processing more than 28 million tons of 34 waste per year (EPA 2014b). These waste-to-energy plants have an aggregate capacity of 35 2,720 MWe, and although some plants have expanded to handle additional waste and produce 36 more energy, no new plants have been built in the United States since 1995 (EPA 2014b). The 37 average waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can 38 operate at capacity factors greater than 90 percent (Michaels 2010). Indiana has one waste 39 recovery facility that produces steam; Iowa has one waste-to-energy facility that produces 40 10 MW of electricity; Michigan has three facilities that produce 89.7 MW of electricity; and 41 Wisconsin has two facilities that generate 32.3 MW of electricity (Michaels 2010). In total, as of 42 2010, the ROI had a municipal solid waste generating capacity of 132 MW. More than 43 46 average-sized plants would be necessary to provide the same level of output as LSCS, 44 almost doubling the national waste-to-energy generation.
45 The decision to burn municipal waste to generate energy is usually driven by the need for an 46 alternative to landfills rather than energy considerations. Given the improbability that additional 47 stable supplies of municipal solid waste would be available to support approximately 46 new 2-22
 
Alternatives Including the Proposed Action 1 facilities and that so few existing plants operate in the ROI, the NRC staff does not consider 2 municipal solid waste combustion to be a reasonable alternative to LSCS license renewal.
3 2.3.11    Petroleum 4 In the ROI, oil-fired generation in 2012 had a generating capacity of 4,986 MW (EIA 2014c).
5 The variable costs of oil-fired generation tend to be greater than those of the nuclear or 6 coal-fired operations, and oil-fired generation tends to have greater environmental impacts than 7 natural gas-fired generation. The high cost of oil has resulted in a steady decline in its use for 8 electricity generation (EIA 2013a). Given the high cost of oil and the small generating capacity 9 from oil-fired power plants in the ROI, the NRC staff does not consider oil-fired generation a 10 reasonable alternative to LSCS license renewal.
11 2.3.12    Supercritical Pulverized Coal 12 In general, SCPC power plants are feasible, commercially available options for providing 13 electrical generating capacity. Baseload coal units have proven their reliability and can sustain 14 capacity factors as high as 79 percent. Pulverized coal power generation uses crushed coal 15 that is fed into a boiler where it is burned to create heat. The heat produces steam that is used 16 to spin one or more turbines to generate electricity. Among the technologies available, 17 pulverized coal boilers producing supercritical steam (SCPC boilers) are increasingly common 18 for new coal-fired plants given their high operating temperatures and pressures that increase 19 thermal efficiencies and overall reliability. SCPC facilities consume less fuel per unit output, 20 reducing environmental impacts (NETL undated).
21 As described in Section 2.2.3, EPA has signed a final rule for carbon pollution that would apply 22 to new fossil fuel-fired power plants, including SCPC facilities (80 FR 64661-65120). The 23 action establishes performance standards and has identified a CCS system as a method of 24 emission reduction. The emission limit for these sources of 1,305 lb CO2/MWh, and any new 25 coal-fired power plants could require CCS in order to achieve this emission limit.
26 In addition, given known technology and technological and demographic trends, EIA predicts 27 that by 2040 natural gas will surpass coal as the largest share of U.S. electric power generation 28 (EIA 2013a). This does not consider the EPA rule described above but indicates a general 29 trend away from coal-fired facilities in favor of natural gas-fired power plants due to falling 30 natural gas prices. MISO projected that the EPA regulations could lead to increased coal plant 31 retirements and estimated retirements between 3,000 MW to 12,600 MW, which could have a 32 large impact on MISOs reserve margin in the future (MISO 2011).
33 Although SCPC plants are currently the most widely used source of electricity generation within 34 the ROI, given the potential for stringent air quality regulations and trends toward natural 35 gas-fired power plants, the NRC staff does not consider SCPC to be a reasonable alternative to 36 LSCS license renewal. Instead, the NRC staff describes an IGCC plant under the coal 37 alternative in Section 2.2.2.2.
38 2.4      Comparison of Alternatives 39 In this chapter, the NRC staff considered the following alternatives to LSCS license renewal:
40 new nuclear generation; IGCC generation; NGCC generation; a combination alternative of 41 natural gas, wind, and solar; and purchased power. The NRC also considered the no-action 42 alternative and its effects. The impacts for all alternatives to LSCS license renewal are 43 discussed in Chapter 4 and summarized in Table 2-2 below.
2-23
 
Alternatives Including the Proposed Action 1 The environmental impacts of the proposed action (issuing renewed LSCS operating licenses) 2 would be SMALL for all impact categories. The environmental impacts from all other 3 alternatives would be larger than the proposed license renewal, as shown in Table 2-2.
4 In conclusion, the environmentally preferred alternative is the granting of renewed licenses for 5 LSCS. All other alternatives capable of meeting the needs currently served by LSCS entail 6 potentially greater impacts than those of the proposed action of renewing the license for LSCS.
7 To make up the lost power generation if a renewed license is not issued (the no-action 8 alternative), one or a combination of alternatives would be implemented, all of which have 9 greater impacts than the proposed action. Hence, the NRC staff concludes that the no-action 10 alternative will have environmental impacts greater than or equal to those of the proposed 11 license renewal action.
2-24
 
1                            Table 2-2. Summary of Environmental Impacts of Proposed Action and Alternatives LSCS License                                                          Combination Renewal                                                              Alternative Impact Area              (Proposed                New Nuclear    IGCC          NGCC          (NGCC, Wind,  Purchased (Resource)                Action)      No-Action    Alternative    Alternative  Alternative    and Solar)    Power Land Use and Visual Resources SMALL TO      SMALL TO      SMALL TO      SMALL TO Land Use                SMALL        SMALL                                                                  SMALL MODERATE      LARGE        MODERATE      MODERATE SMALL TO                                    SMALL TO Visual Resources        SMALL        SMALL                      SMALL        SMALL                        SMALL MODERATE                                    LARGE Air Quality and Noise SMALL TO Air Quality              SMALL        SMALL      SMALL          MODERATE      MODERATE      SMALL MODERATE SMALL TO                    SMALL TO      SMALL TO Noise                    SMALL        SMALL      SMALL                        SMALL MODERATE                    MODERATE      MODERATE Geologic Environment      SMALL        SMALL      SMALL          SMALL        SMALL          SMALL          SMALL 2-25  Water Resources Surface Water                                      SMALL TO      SMALL TO                                    SMALL TO SMALL        SMALL                                    SMALL          SMALL Resources                                          MODERATE      MODERATE                                    MODERATE Groundwater SMALL        SMALL      SMALL          SMALL        SMALL          SMALL          SMALL Resources SMALL TO      MODERATE      SMALL TO      SMALL TO Terrestrial Resources    SMALL        SMALL                                                                  SMALL MODERATE      TO LARGE      MODERATE      MODERATE SMALL to                                SMALL to Aquatic Resources                      SMALL      SMALL                        SMALL          SMALL          SMALL MODERATE1                                MODERATE Special Status Species NO EFFECT    SEE NOTE2  SEE NOTE2      SEE NOTE2    SEE NOTE2      SEE NOTE2      SEE NOTE2
      & Habitats Historic and                                                                                    SMALL TO      SMALL TO SEE NOTE3    SMALL      SMALL          SMALL        SMALL Cultural Resources                                                                              LARGE          LARGE Socioeconomics SMALL TO    SMALL TO      SMALL TO      SMALL TO                      SMALL TO Socioeconomics          SMALL                                                                SMALL LARGE      LARGE          LARGE        LARGE                        LARGE Alternatives including the Proposed Action
 
LSCS License                                                                                    Combination Renewal                                                                                          Alternative Impact Area                (Proposed                          New Nuclear          IGCC                NGCC                (NGCC, Wind,        Purchased (Resource)                  Action)      No-Action            Alternative          Alternative        Alternative          and Solar)          Power SMALL TO            SMALL TO            SMALL TO            SMALL TO            SMALL TO Transportation            SMALL              SMALL LARGE                LARGE              LARGE                MODERATE            LARGE Human Health                SMALL              SMALL          SMALL                SMALL              SMALL                SMALL                SMALL Environmental Justice      SEE  NOTE4        SEE  NOTE5    SEE  NOTE6          SEE  NOTE6        SEE  NOTE6          SEE  NOTE6          SEE NOTE6 Waste Management SMALL TO                                                      SMALL TO and Pollution              SMALL              SMALL          SMALL                                    SMALL                SMALL MODERATE                                                      MODERATE Prevention Key: IGCC = coal-integrated gasification combined-cycle (alternative), NGCC = natural gas combined-cycle (alternative), NRHP = National Register of Historic Places, APE = area of potential effect, CRMP = Cultural Response Management Plan, and IHPA = Illinois Historic Preservation Agency.
(1) Thermal  impacts would be SMALL for aquatic resources in the Illinois River and SMALL to MODERATE for aquatic resources in the cooling pond.
Alternatives including the Proposed Action MODERATE thermal impacts would primarily be experienced by gizzard and threadfin shad in the cooling pond.
(2) The magnitude of impacts could vary widely based on site selection and the presence or absence of special status species and habitats when the alternative is implemented; therefore, the NRC staff cannot forecast a level of impact for this alternative.
2-26  (3) Based on (1) there being currently no NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelons draft CRMP, (4) the fact that no license renewal-related physical changes or ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource assessment, license renewal would not affect any known historic properties (36 CFR 800.4(d)(1)).
(4) Continued operation of LSCS would not have disproportionately high and adverse human health and environmental effects on minority and low-income populations.
(5) The no-action alternative could disproportionately affect minority and low-income populations.
(6) Based on this information and the analysis of human health and environmental impacts presented in this SEIS, it is not likely that this alternative would have disproportionately high and adverse human health and environmental effects on minority and low-income populations. However, this determination would depend on the location, plant design, and operational characteristics of the alternative. Therefore, the NRC staff cannot determine whether this alternative would result in disproportionately high and adverse human health and environmental effects on minority and low-income populations.
 
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1                              3.0 AFFECTED ENVIRONMENT 2 In this supplemental environmental impact statement (SEIS), the affected environment is the 3 environment that currently exists at and around LaSalle County Station, Units 1 and 2 (LSCS).
4 Because existing conditions are at least partially the result of past construction and operation at 5 the plant, the impacts of these past and ongoing actions and a discussion on how they have 6 shaped the environment are presented here. The facility and its operation are described in 7 Section 3.1. The affected environment is presented in Sections 3.2 to 3.13.
8 3.1      Description of Nuclear Power Plant Facility and Operation 9 LSCS is a two unit nuclear power plant located in LaSalle County, Illinois. It began commercial 10 operation in January 1984 (Unit 1) and October 1984 (Unit 2). Generally, the U.S. Nuclear 11 Regulatory Commission (NRC) staff drew information about LSCSs facilities and operation from 12 the Exelon Generation Company, LLC (Exelon), Environmental Report (ER) (Exelon 2014a).
13 3.1.1      External Appearance and Setting 14 The LSCS site is approximately 82 driving miles (mi) (132 kilometers (km)) southwest of OHare 15 International Airport in Chicago, Illinois, and approximately 26 mi (42 km) west of Exelons 16 Braidwood Generating Station in Braceville, Illinois. Interstate Highway 80 is 8 mi (13 km) north 17 of the site. Figure 3-1 presents the 50-mi (80-km) area around LSCS.
18 The LSCS site is located in a rural and agricultural setting. However, the surroundings are 19 dominated by many wind turbines. Each wind turbine is 389 feet (ft) (119 meters (m)) tall (which 20 includes the length of one of its three 126.5-ft (38.5-m) rotator blades). The town of Seneca lies 21 6 mi (10 km) northeast of LSCS. The town of Marseilles lies 7 mi (11 km) north-northwest of 22 LSCS. The Illinois River is 5 mi (8 km) north of LSCS. The Chicago, Rock Island and Pacific 23 Railroad, which runs parallel to, and slightly north of, the Illinois River, is the closest railroad line 24 in this area. A 6-mi (10-km) rail spur connects LSCS to the Atchison, Topeka, and Santa Fe 25 Railroad south of the site (Exelon 2014a). Figure 3-2 presents the 6-mi (10-km) area around 26 LSCS.
27 The LSCS site is approximately 3,776 acres (ac) (1,528 hectares (ha)) of which approximately 28 2,058 ac (833 ha) are the cooling pond. Underground pipelines approximately 3.5 mi (5.6 km) 29 long connect the cooling pond to the Illinois River, which is the source of the plants makeup 30 water and the receiving body of water for plant discharges. This pipeline corridor right-of-way 31 intersects the eastern portion of the Marseilles State Fish and Wildlife Area, which is managed 32 by the Illinois Department of Natural Resources (IDNR) for hunting and wildlife habitat. Country 33 Road 6 (also known as North 21st Road) provides access to LSCS and runs along the sites 34 southern boundary (Exelon 2014a). Figure 3-3 presents the LSCS site layout.
35 The LSCS sites main structures include two reactor buildings, an auxiliary building (which 36 houses the control room), a turbine building, a diesel generator building, a switchyard, a training 37 building, an interim radioactive waste (radwaste) storage facility, a radwaste building, sewage 38 and wastewater treatment facilities, and an independent spent fuel storage installation (ISFSI).
39 The sites tallest structure is a 400-ft (122-m) meteorological tower. The area of the LSCS site 40 that is completely enclosed by physical barriers and that allows access only at designated 41 control points is called the protected area. A physical protection program at the LSCS site 42 includes surveillance, observation, and monitoring within the protected area (Exelon 2014a).
43 Figure 3-4 presents the LSCS plant features.
3-1
 
Affected Environment 1                      Figure 3-1. LSCS 50-mi (80-km) Radius Map 2                                Source: Exelon 2014a 3-2
 
Affected Environment 1 Figure 3-2. LSCS 6-mi (10-km) Radius Map 2          Source: Exelon 2014a 3-3
 
Affected Environment 1                      Figure 3-3. LSCS Site Layout 2                          Source: Exelon 2014a 3-4
 
Affected Environment 1 Figure 3-4. LSCS Plant Features 2      Source: Exelon 2014a 3-5
 
Affected Environment 1 3.1.2    Nuclear Reactor Systems 2 The nuclear reactor for each of the two LSCS units is a General Electric boiling water reactor 3 (BWR/5) with Mark II containment. Each LSCS reactor is licensed to produce core power of 4 3,546 megawatts thermal. The annual mean net electrical power capacity for LSCS is 5 2,327 megawatts electric. LSCS uses a 2,058-ac (833-ha) diked cooling pond for core cooling 6 and withdraws makeup water from, and discharges to, the Illinois River (Exelon 2014a).
7 LSCS operates using low-enriched uranium dioxide fuel with enrichment not exceeding a 8 nominal 5.0 percent by weight of uranium-235 and has been historically operated within a 9 maximum analyzed fuel burnup rate of 62,000 megawatt-days per metric ton of 10 uranium (MWd/MTU). In its ER, Exelon stated that, during some future fuel cycles, it expects 11 the peak fuel burnup rate to exceed 62,000 MWd/MTU in some part-length fuel rods.
12 Addendum 1 to Volume 1 of NUREG-1437, Generic Environmental Impact Statement for 13 License Renewal of Nuclear Power Plants (GEIS) (NRC 1999), states that the environmental 14 impacts would be small for transporting spent fuel enriched with up to 5-percent uranium-235 15 with an average burnup for the peak rod of up to 62,000 MWd/MTU. It also states that, if peak 16 fuel burnup is projected to exceed 62,000 MWd/MTU, license renewal applicants must submit 17 an assessment of the implications for the environmental impacts. Exelon submitted an 18 assessment of the environmental impacts of transporting spent fuel enriched with an average 19 burnup for the peak rod exceeding 62,000 MWd/MTU in Section 4.13 of its ER. Appendix G of 20 this document provides the NRC staffs analysis of these projected environmental impacts.
21 Refueling outages for LSCS, Units 1 and 2, are on a staggered 24-month schedule 22 (Exelon 2014a).
23 3.1.3    Cooling and Auxiliary Water Systems 24 LSCS uses a closed-cycle, recirculating cooling system that includes an artificial cooling pond 25 for heat dissipation. In this type of closed-cycle system, the cooling pond serves as the primary 26 source of water to cool plant components and as the primary receiving body for excess heat.
27 In BWRs like those used at LSCS, steam is produced directly in each reactor vessel. The 28 steam passes through moisture separators and steam dryers and then flows to the turbine.
29 Such systems contain only two heat transfer (exchange) loops. The primary loop transports the 30 steam from the reactor vessel directly to the turbine, which generates electricity. The secondary 31 cooling loop removes excess heat from the primary loop in the main condenser. From the 32 condenser, the primary condensate is returned as feedwater to the reactor, and the secondary 33 cooling loop removes the excess heat (NRC 2013). At LSCS, condenser cooling water is 34 discharged directly to the cooling pond, where the heat is dissipated through mixing and 35 evaporation (Exelon 2014a).
36 Cooling water that is not otherwise lost from the pond through evaporation or seepage or that is 37 consumed in the process is recirculated from the cooling pond through the condenser systems 38 in a continuous loop. In addition, a portion of the water in the cooling pond is discharged as 39 blowdown on a near continuously basis under normal conditions. (Blowdown is water that is 40 rinsed from the cooling system (i.e., cooling pond) to remove impurities that may degrade plant 41 performance.) Total dissolved solids are the primary constituents of concern to prevent scale 42 buildup on plant components.
43 All water lost from the recirculating system must be replaced with fresh water; this water is 44 referred to as makeup water (Exelon 2014a; NRC 2013). Makeup water for the onsite cooling 45 pond is withdrawn from, and blowdown is discharged to, the Illinois River, which lies 3.5 mi 46 (5.6 km) north of LSCSs cooling pond. The intake and blowdown pipelines are routed through 3-6
 
Affected Environment 1 a common right-of-way corridor. Figure 3-5 provides a basic schematic diagram of a 2 closed-cycle, recirculating cooling system that uses a cooling pond.
3                  Figure 3-5. Closed-Cycle Cooling System with Cooling Pond 4                              Source: Modified from NRC 2013, Figure 3.1-4 5 Groundwater is also used by LSCS for potable water, sanitary water, and demineralized water 6 makeup systems.
7 Unless otherwise cited, the NRC primarily drew information about LSCSs cooling and auxiliary 8 water systems from Exelons ER (Exelon 2014a, 2015b) and its Updated Final Safety Analysis 9 Report (UFSAR) (Exelon 2014b). The NRC staff visited the facilities cited herein during the 10 May 2015 environmental site audit (NRC 2015b). Descriptions of the individual plant cooling 11 and auxiliary systems and components that interact with the environment are provided below.
12 Cooling Pond and Ultimate Heat Sink. Water for the circulating water system (CWS) for 13 condenser cooling water and for the plant service water system are supplied directly from the 14 cooling pond.
15 The LSCS cooling pond is an engineered impoundment encompassing 2,058 ac (833 ha) with 16 an average depth of 15 ft (4.7 m) (NRC 1978) (Figure 3-6). The pond has an elevation of 700 ft 17 (213 m) above mean sea level (MSL) at normal pool elevation. At this water elevation, the 18 cooling pond has a storage capacity of 31,706 acre-feet (39 million cubic meters (m3)) of water.
19 This impoundment was formed by constructing earthen dikes to enclose the north, east, and 20 south sides of the pond; the natural levee of the Illinois River forms the fourth side. Engineered 21 fill consisting of silty-clay, taken from borrow areas within the pond basin, was used in the 22 construction of these peripheral dikes. A perimeter drainage ditch designed to intercept runoff 23 and to capture and direct seepage toward surface drainages and away from the dikes flanks the 24 ponds dikes (Exelon 2014b).
25 Integral to the ponds construction are three internal baffle or finger dikes (i.e., earthen berms),
26 that total 22,623 ft (6,895 m) in length. These structures direct the flow of water from the 27 discharge canal and through the pond to ensure that the coolest water is available for use by 28 LSCS (Exelon 2014b) (Figure 3-6). The average residence time for water in the cooling pond is 29 5.5 days (NRC 1978).
3-7
 
Affected Environment 1 The peripheral dike system that encloses the cooling pond includes a 300-ft- (91-m)-wide 2 auxiliary spillway structure. The spillway is located northwest of the main plant complex and is 3 adjacent to the discharge canal. The structure is capable of passing a volume of 4 1,069,000 gallons per minute (gpm) (2,380 cubic feet per second (cfs) or 67.2 meters per 5 second (m/s)) of water associated with the probable maximum water level. Discharge from the 6 structure flows north to South Kickapoo Creek, a tributary to the Illinois River (Exelon 2014b).
7 A dedicated portion of the cooling pond located immediately adjacent to the LSCS intake canal 8 serves as the plants ultimate heat sink (UHS). It is also known as the core standby cooling 9 system (CSCS) pond and directly supplies the CSCS equipment cooling water system, as 10 discussed below. This excavated area comprises 83 ac (34 ha) in size and is 5 ft (1.5 m) deep 11 below grade. It can hold 460 acre-feet (567,000 m3) of water. This volume of water is sufficient 12 to supply 30 days of cooling water following safe shutdown from normal operating or accident 13 conditions. The CSCS pond can function even if the perimeter dikes of the cooling pond are 14 breached (Exelon 2014b).
15 Illinois River Water Makeup System. Cooling pond makeup water is withdrawn via the river 16 screen house located on the south bank of the Illinois River at Illinois River Mile (RM) 249.5 17 (River Kilometer (RKm) 401.5) (Figure 3-6). The river screen house is situated approximately 18 3.5 mi (5.6 km) north of the cooling pond. The structure is designed to withstand the 100-year 19 flood of the Illinois River (Exelon 2014b).
20 The river screen house contains three makeup water pumps, each with a capacity of 21 30,000 gpm (67 cfs or 1.9 cubic meters per second (m3/s)). Two pumps are normally operated 22 at all times to meet cooling pond makeup demands, with the third serving as a backup.
23 However, when reduced evaporation demands allow (winter months), the pump discharge ball 24 valves are closed to 30 degrees (one-third open) (Exelon 2015c).
25 River water is first drawn through an intake flume in the bottom of the river and then into a 26 72-ft-- (22-m)-wide funnel inlet basin with concrete dam located 24 ft (7 m) from the shoreline 27 frontage of the river screen house. The inlet is protected by a floating log boom to deflect river 28 debris. From the inlet, water then enters the intake forebay of the screen house and passes first 29 through two adjacent bar grills and then through vertical traveling screens with 3/8-inch (in.)
30 (0.95-centimeter (cm)) openings before entering the pumps (Exelon 2014a, 2015a). The bar 31 grills are galvanized steel and measure 3/8 in. (0.95 cm) thick and 4 in. (10 cm) wide. The 32 narrow dimension of each bar is oriented perpendicular to the incoming water flow, and the 33 centerlines of the narrow dimension of adjacent bars are spaced 3 in. (7.6 cm) apart 34 (Exelon 2015c).
35 Water velocity in the river intake channel is reported as ranging from 0.3 to 0.5 feet per second 36 (fps) (0.10 to 0.15 m/s) with one pump operating and 0.6 to 1.0 fps (0.2 to 0.3 m/s) with two 37 pumps operating. Flow velocity at the travelling screens ranges from about 0.5 to 0.9 fps 38 (0.15 to 0.3 m/s) with one and two makeup pumps in full operation, respectively (NRC 1978; 39 Exelon 2014a). In NRCs Final Environmental Statement for the operating license of LSCS, the 40 NRC staff estimated that the intake velocity at the face of the traveling screens would be 0.5 fps 41 (0.2 m/s) 93 percent of the time and 1.0 fps (0.3 m/s) the remaining 7 percent of the time 42 (NRC 1978). Exelon has not performed any operational studies to further characterize intake 43 flow velocities (Exelon 2015c). Based on the assessment the NRC performed for LSCSs 44 operating license (NRC 1978), the velocity at the face of the traveling screens would typically be 45 within the 0.5fps (0.15m/s) intake velocity now recommended by the U.S. Environmental 46 Protection Agency (EPA) for protection of aquatic organisms (Volume 69 of the Federal 47 Register, page 41576 (69 FR 41576)), although the velocity may be closer to 1.0 fps (0.3m/s) 48 during certain periods during operations.
3-8
 
Affected Environment 1 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities 2            Sources: Modified from Exelon 2014a, 2015b 3-9
 
Affected Environment 1 A backwash system removes debris from the river intake traveling screens, and trash rakes 2 remove debris from bar grills. The backwash system can be set to operate in automatic or 3 manual mode, but the system is normally left in automatic mode unless high debris loading 4 requires manual cleaning. In automatic mode, cleaning is initiated when the measured 5 differential water level across the screens reaches 4 in. (10 cm). With a differential water level 6 of 6 in. (15 cm), the system switches to fast speed. A differential level in excess of 16 in.
7 (40 cm) for at least 15 seconds will cause the associated makeup pumps to trip to prevent 8 cavitation damage. Manual mode with either a slow or fast speed setting may be used during 9 periods of high debris loading (Exelon 2015c).
10 Collected debris, including any impinged biota, is deposited in a trash basket located outside the 11 river screen house, with the debris ultimately disposed of in an offsite permitted landfill. The 12 river screen house is not equipped with a fish return system. Screen backwash and other 13 intermittent discharges from the screen house are discharged to the Illinois River through a 14 National Pollutant Discharge Elimination System (NPDES)-permitted outfall (Outfall 002). The 15 intake forebay of the facility has a floating oil boom to prevent any oil leaks from the screen 16 house from entering the river. Section 3.5.1.3 of this SEIS presents additional information on 17 water quality and LSCSs NPDES permit.
18 With all three river makeup water pumps in operation, LSCSs maximum surface water makeup 19 supply capacity is 90,000 gpm (200 cfs or 5.66 m3/s), which is equivalent to 129.6 million 20 gallons per day (mgd) (491,000 cubic meters per day (m3/day)). Normal peak makeup 21 withdrawal from the Illinois River, with two pumps operating, is 60,000 gpm (134 cfs or 22 3.77 m3/s) or 86.4 mgd (327,000 m3/day). Surface water use is detailed in Section 3.5.1.2.
23 From the river screen house, intake water is pumped south to the northern end of the LSCS 24 cooling pond through a 60-in. (152-cm) pipeline. Upon reaching the pond, the water is 25 conveyed into the pond through a reinforced concrete discharge structure located on the north 26 side of the ponds discharge canal. The structure is designed to prevent erosion of the cooling 27 pond dike (Exelon 2014b) (see Figure 3-6).
28 The river intake pipeline is equipped with air and vacuum relief valves along its course to help 29 guard against pressure surges and other conditions that sometimes occur due to elevation 30 changes along its routing. Nevertheless, the makeup pipeline, which is not a safety-related 31 structure, has experienced a number of breaks resulting in flooding and erosion of areas 32 surrounding the break. The most recent such break occurred on January 23, 2014. Exelon 33 reported the break to both the Illinois Environmental Protection Agency (IEPA) and EPA 34 Region V in accordance with the reporting provisions of Exelons NPDES permit 35 (Exelon 2015c).
36 To address issues associated with pipeline breaks, Exelon has performed maintenance, 37 including replacing relief valves, and has installed instrumentation on the intake traveling 38 screens to alert the LSCS control room operators to abnormal conditions. Exelon has also 39 modified operating and response procedures and has implemented plans and procedures to 40 prevent and quickly respond to any breaks. For example, operational procedures have been 41 modified to include checks on pipeline integrity and to ensure necessary parts are maintained to 42 replace a section of pipeline should a break occur (Exelon 2014a, 2015a).
43 CWS and Blowdown Discharge. The CWS provides cooling water to the main condensers. In 44 addition to the condensers, the system includes the cooling pond, lake screen house, circulating 45 water pumps, piping, valves, and related equipment. The system normally supplies water to the 46 main condensers at temperatures ranging from 32 &deg;F to a maximum of 100 &deg;F (0 to 37.8 &deg;C).
47 However, operating license technical specifications (TS) limit the temperature of the cooling 3-10
 
Affected Environment 1 water supplied to the facility from the UHS portion of the cooling pond to 101.25 &deg;F (38.5 &deg;C) 2 (Exelon 2014b).
3 The main condenser of each unit requires 616,500 gpm (1,373 cfs or 38.8 m3/s), or 888 mgd 4 (3.36 million m3) of circulating water flow to remove waste heat at 100-percent load. Cooling 5 water is withdrawn from the cooling pond through the lake screen house, which is located at the 6 west end of the intake canal (Figure 3-6). The lake screen house contains six circulating water 7 pumps (three for each unit) that take suction from the service water tunnel (Exelon 2014a).
8 Each pump has a capacity of 205,500 gpm (457.7 cfs or 12.9 m3/s) (Exelon 2015c), with two 9 pumps normally in operation per unit to supply water to the condensers. Water first enters the 10 intake forebays after passing through bar grills and traveling screens with 3/8-in. (0.95-cm) 11 openings. Trash rakes prevent larger debris and aquatic biota from entering the system. The 12 design water intake velocity at the screens is approximately 2.2 fps (0.7 m/s), assuming clean 13 screens. Debris removed from the traveling screens by the screen backwash system and from 14 the bar grills by trash rakes is collected in a trash basket and disposed of in an offsite permitted 15 landfill. Similar to the river intake backwash system, the circulating water backwash system can 16 be operated in either automatic or manual mode. When in automatic mode with a differential 17 water level across the screens ranging between 0 and 6 in. (0 to 15 cm), a timer initiates a 18 3-minute wash cycle every 12 to [[estimated NRC review hours::14 hours]]. With a differential level rising to between 6 and 19 10 in. (15 to 25 cm), a continuous backwash cycle starts at slow speed. The fast setting is 20 triggered with a differential water level exceeding 10 in. (25 cm). Manual mode may be used 21 during fish runs or other periods of high debris intake (Exelon 2015c). Like the river screen 22 house, the lake screen house has no fish return system (Exelon 2014a, 2014b).
23 From the lake screen house, water is pumped through the main condenser of each unit.
24 A chemical feed system, located in facilities adjacent to the lake screen house, injects biocide 25 and other chemical treatments to reduce biofouling, silting, and scale buildup in the condenser 26 systems. After passing through the unit condensers, heated circulating water is returned to the 27 cooling pond through the discharge canal. The nominal (design) temperature rise in the 28 circulating water passing through the main condensers is approximately 26.7 &deg;F (10 &deg;C) 29 (Exelon 2014b).
30 As previously stated, a series of parallel dikes in the cooling pond direct and slow the rate of 31 movement of the returned cooling water through the pond to facilitate residence time cooling 32 processes so that the coolest water is available for uptake again at the lake screen house.
33 This heat dissipation is necessary so that cooling pond blowdown to the Illinois River meets 34 temperature limitations and mixing zone requirements under the Illinois thermal water quality 35 standards (35 IAC 302) and Special Condition 3 of Exelons NPDES Permit No. IL0048151 36 (IEPA 2013). The permit also authorizes the discharge of various other effluent streams to the 37 cooling pond in addition to condenser cooling water, as further described in Section 3.5.1.3 of 38 this SEIS.
39 Blowdown combined with other comingled effluent streams flows through an open channel 40 originating at the west shore of the cooling pond (UHS portion) and then northwest to a spillway 41 adjacent to the LSCS discharge canal. This combined effluent stream can include processed 42 liquid radioactive waste (radwaste), which may be discharged on a batch basis directly into the 43 cooling pond blowdown line at a maximum rate of 45 gpm (0.17 cubic meters per minute), as 44 further described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Nevertheless, the blowdown 45 line is equipped with a radiation monitor that will automatically isolate the radwaste discharge 46 line in the event of a high-radiation signal (Exelon 2014b).
47 The blowdown spillway connects to a 66-in. (168-cm) diameter pipeline through which the 48 collected blowdown travels underground via gravity flow. The pipeline discharges into an 3-11
 
Affected Environment 1 approximately 500-ft- (150-m)-long discharge structure consisting of a plunge pool and rip-raped 2 lined swale that connects with the Illinois River at RM 249.4 (RKm 401) and just upstream of the 3 LSCS river screen house (see Figure 3-6). The maximum blowdown rate of the system is 4 equal to the maximum intake rate of 90,000 gpm (200 cfs or 5.66 m3/s). However, 5 motor-operated values at both the river and lake ends of the discharge line can be used to 6 isolate the pipeline for maintenance and are used to adjust the blowdown to an average of 7 58,000 gpm (129 cfs or 3.65 m3/s) or less with a target annual average of 30,000 gpm (67 cfs or 8 1.89 m3/s) (Exelon 2014a, 2014b). The blowdown discharge point is regulated under LSCSs 9 NPDES permit as Outfall 001 (see Section 3.5.1.3).
10 Because the blowdown pipeline functions under gravity flow, it is less susceptible to surges and 11 breakage than the river intake pipeline. It is also equipped with air and vacuum relief valves.
12 Nevertheless, breaks do occur. The most recent such break occurred on July 13, 2012. Exelon 13 reported the break to both the IEPA and EPA Region V. As discussed above for the makeup 14 pipeline, Exelon has implemented a program to reduce the frequency of breaks and their 15 impacts on operations and the environment (Exelon 2015c).
16 Plant Service Water System. The service water system provides cooling water for various 17 nonsafety-related auxiliary systems and components, including cooling water for the turbine 18 generator; various air conditioning condensers; and the fuel pool, turbine building, and reactor 19 building heat exchangers. It also supplies water for the lake screen house traveling screen 20 backwash system and the radwaste system, and it is used to fill the fire protection system and 21 serves as a backup fire water supply. Service water is normally supplied by four pumps, with a 22 fifth pump serving as a backup, located in the lake screen house. Each pump has a capacity of 23 16,000 gpm (35.6 cfs or 1.01 m3/s). The pumps take suction from the lake screen house intake 24 service water tunnel and discharge into a common header. Automatic backwash strainers 25 remove any debris that might be passed through the circulating water screens. In addition, the 26 system has two jockey pumps rated at 5,000 gpm (11.1 cfs or 0.31 m3/s). These pumps are 27 powered by an emergency diesel generator and are used to meet minimum flow requirements 28 during a loss of offsite power. The service water is also treated by the chemical feed system to 29 guard against biofouling, scale buildup, corrosion, and silting. Chemical injection occurs directly 30 to the service water tunnel feed lines. All service water return flows are discharged back to the 31 cooling pond (Exelon 2014a, 2014b).
32 Fire Protection Water System. The cooling pond is the source of fire protection water for the 33 LSCS fire hydrants, the water sprinkler and deluge systems, and the hose valve stations.
34 One of two 75-gpm (0.17-cfs or 0.005-m3/s) jockey pumps normally keep the system 35 pressurized. If a system demand occurs, a 225-gpm (0.50-cfs or 0.014-m3/s) intermediate 36 pump is activated. If the demands of the intermediate pump are exceeded, the first of two 37 diesel-driven pumps are automatically engaged. These pumps, each with a capacity of 38 2,500 gpm (51 cfs or 1.44 m3/s), are located in the lake screen house and take suction directly 39 from the service water tunnel (Exelon 2014b).
40 Core Standby Cooling System. This system is equivalent in purpose to the essential service 41 water systems at other nuclear power plants and provides cooling water for the purpose of 42 cooling safety-related equipment necessary for safe shutdown of the reactors. This equipment 43 includes the residual heat removal heat exchangers, pump seal coolers, and emergency diesel 44 generators; the system also provides emergency spent fuel pool makeup water and a source of 45 water for containment flooding for post-accident recovery. The CSCS withdraws cooling pond 46 water from the UHS portion of the cooling pond (as discussed earlier) via the lake screen house 47 service water tunnel. The water is chemically treated by the chemical feed system as previously 48 described. As a safeguard against blockage of the traveling screens ahead of the service water 49 channel, the system has a 54-in. (137-cm) bypass line that can be opened to directly supply 3-12
 
Affected Environment 1 CSCS water. All pumps and strainers for conveying emergency cooling water are located in 2 watertight spaces within the basements of the various plant buildings (Exelon 2014a, 2014b).
3 Potable Water System. LSCS uses groundwater from two deep wells (Nos. 1 and 2) to supply 4 potable (drinking) water, sanitary water, and raw makeup water for the demineralized water 5 system. The wells were installed during plant construction with completion depths of 1,629 ft 6 (497 m) and 1,620 ft (494 m), respectively (Exelon 2014a). Each well has a pump capacity of 7 300 gpm (1.14 cubic meters per minute) (Exelon 2014b). Water is stored in a 350,000-gallon 8 (gal) (1,325-m3) storage tank before distribution. The plant supply wells and LSCSs 9 groundwater use are further discussed in Section 3.5.2.2.
10 3.1.4    Radioactive Waste Management Systems 11 As part of normal operations and as a result of equipment repairs and replacements due to 12 normal maintenance activities, nuclear power plants routinely generate both radioactive and 13 nonradioactive wastes. Nonradioactive wastes include hazardous and nonhazardous wastes.
14 There is also a class of waste, called mixed waste that is both radioactive and hazardous. The 15 systems used to manage (i.e., treat, store, and dispose of) these wastes are described in this 16 section. Waste minimization and pollution prevention measures commonly employed at nuclear 17 power plants are also discussed in this section.
18 All nuclear plants were licensed with the expectation that they would release very limited 19 quantities of radioactive material to both the air and water during normal operation. However, 20 NRC regulations require that gaseous and liquid radioactive releases from nuclear power plants 21 must meet radiation dose-based limits specified in Title 10 of the Code of Federal Regulations 22 (10 CFR) Part 20, and the as low as is reasonably achievable (ALARA) criteria in Appendix I to 23 10 CFR Part 50. Regulatory limits are placed on the radiation dose that members of the public 24 can receive from radioactive effluents released by a nuclear power plant. All nuclear power 25 plants use radioactive waste management systems to control and monitor radioactive wastes.
26 LSCS uses liquid, gaseous, and solid waste processing systems to collect and process, as 27 needed, radioactive materials produced as a by-product of plant operations. The liquid and 28 gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 29 discharge into the environment. This is to ensure that the dose to members of the public from 30 radioactive effluents is reduced to levels that are ALARA in accordance with NRCs regulations.
31 The radioactive material removed from the effluents is converted into a solid form for eventual 32 disposal at a licensed radioactive disposal facility.
33 Exelon has a radiological environmental monitoring program (REMP) to assess the radiological 34 impact, if any, to the public and the environment from radioactive effluents released during 35 operations at LSCS. The REMP measures the aquatic, terrestrial, and atmospheric 36 environment for radioactivity, as well as the ambient radiation. In addition, the REMP measures 37 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 38 material, including radon) (Teledyne 2015).
39 LSCS has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 40 parameters used to calculate offsite doses resulting from liquid and gaseous radioactive 41 effluents. These methods are used to ensure that radioactive material discharges from the plant 42 meet NRC and EPA regulatory dose standards. The ODCM also contains the requirements for 43 the REMP (Exelon 2013d).
44 3.1.4.1    Radioactive Liquid Waste Management 45 LSCS Units 1 and 2 share a common liquid radioactive waste system (LRWS). The LRWS 46 collects, monitors, and processes any potentially radioactive liquid wastes produced in the plant.
3-13
 
Affected Environment 1 The LRWS also recycles as much processed liquid waste as can be accommodated within the 2 LSCS water balance. Although LSCS tries to limit any radioactive releases via the liquid 3 pathway, discharges from the system are authorized and may occur if treated waste water is not 4 needed for other plant uses. The LRWS is designed so that any liquid radioactive waste 5 discharged from the site will have radioactive nuclide concentrations below the limits specified in 6 10 CFR Part 20 and Appendix I to10 CFR Part 50.
7 Processing of liquids in the LRWS results in a clean product stream and a reject stream. The 8 clean product stream returns water for use by the main plant systems via the condensate 9 storage tanks if the water quality is found acceptable and if the plant has the need for the 10 makeup water. Water in the reject stream is processed for disposal in the solid radioactive 11 waste system. Unused treated waste water can be sent to a discharge tank and held until a 12 discharge batch accumulates. Before any release of a discharge batch, it would be sampled 13 and treated if necessary to ensure radionuclide concentrations and resulting radiation doses to 14 LSCS personnel and the general public comply with NRC regulations in 10 CFR Part 20 and 15 Appendix I to 10 CFR Part 50. The LWRS sends discharge batches directly into the cooling 16 pond blowdown line.
17 The LRWS consists of a waste processing subsystem, a floor drain processing subsystem, a 18 chemical waste subsystem, and a sludge subsystem. All subsystems are shared by LSCS 19 Units 1 and 2. A vendor-provided liquid waste treatment system is also available to supplement 20 the LRWS if needed.
21 The waste processing subsystem collects and processes water from sources such as 22 equipment drains. This water is treated by settling, filtration, and demineralization. After 23 treatment and sampling, the water is returned for reuse through the condensate storage tanks.
24 The floor drain processing subsystem collects and processes water from the floor drain 25 systems. After treatment and sampling, the water is returned for reuse through the condensate 26 storage tanks. The chemical waste subsystem collects and processes water from areas like the 27 laboratory drains and the radwaste building sump. After treatment and sampling, plant 28 procedures are used to determine where the processed water goes, which may include 29 discharge. The sludge subsystem is not a processing stream, but rather a group of tanks and 30 associated pumps that serve as an interface between the LRWS and the solid radioactive waste 31 handling system. After radioactive contaminants have been removed from the LRWS, 32 concentrated, and treated or held up to allow radioactive decay if necessary, they are 33 transferred to the solid radioactive waste system for processing, temporary storage, and 34 shipment for disposal.
35 The use of these radioactive waste systems and the procedural requirements in the ODCM 36 ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 37 dose standards.
38 Dose estimates for members of the public are calculated based on radioactive liquid effluent 39 release data and aquatic transport models. Exelons annual radiological effluent release report 40 contains the radioactive liquid effluents release data from LSCS and the resultant calculated 41 doses. The NRC staff reviewed 5 years of radioactive effluent release data: 2010 through 2014 42 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year period provides a data set that covers a 43 broad range of activities that occur at a nuclear power plant, such as refueling outages, routine 44 operation, and maintenance activities that can affect the generation of radioactive effluents.
45 LSCS did not have any radioactive liquid effluent releases over the period of 2010 through 46 2014.
47 Since LSCS had no radioactive liquid effluent releases for the period of 2010 through 2014, its 48 radioactive liquid effluent control program showed that radiation doses to members of the public 3-14
 
Affected Environment 1 were controlled within the NRCs and EPAs radiation protection standards contained in 2 Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR Part 190. Also, since LSCS had no 3 radioactive liquid effluent releases for the period of 2010 through 2014, no adverse trends were 4 observed in the dose levels.
5 Routine plant refueling and maintenance activities currently performed will continue during the 6 license renewal term. Based on the past performance of the radioactive waste system to 7 maintain doses from radioactive liquid effluents to be ALARA, similar performance is expected 8 during the license renewal term.
9 3.1.4.2      Radioactive Gaseous Waste Management 10 LSCS Units 1 and 2 share a common gaseous radioactive waste system (GRWS) with a 11 common vent stack located on the roof of the containment building between the two units. The 12 GRWS is designed to process and control radioactive gases and minimize the amount of 13 radioactive gaseous material released into the environment. The gaseous radioactive wastes 14 released consist primarily of xenon, argon, iodine, tritium, and carbon. The steam in a BWR 15 plant such as LSCS contains impurities in the form of radioactive gases that are continuously 16 removed during plant operation from the main condenser by an air ejector. This process is the 17 major source of radioactive gases generated by LSCS (Exelon 2014a). The GRWS removes 18 some radioactive gases and delays the release of other radioactive gases by adsorption on 19 charcoal beds to allow time for radioactive decay. As a final step, the gaseous waste stream 20 passes through a high efficiency particulate air filter, and is discharged through the common 21 vent stack. Other plant facilities that are potential sources of radioactive gas emissions include 22 the primary containment, the secondary containments (reactor buildings), the turbine buildings, 23 and the radwaste building. The ventilation systems in each of these facilities have filtration and 24 treatment systems that the air passes through before being discharged through the vent stack 25 (Exelon 2014a).
26 The use of these radioactive waste systems and the procedural requirements in the ODCM 27 ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 28 dose standards.
29 Dose estimates for members of the public are calculated based on radioactive gaseous effluent 30 release data and atmospheric transport models. Exelons annual radioactive effluent release 31 report contains a detailed presentation of the radioactive gaseous effluents released from LSCS 32 and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 33 release data: 2010 through 2014 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year 34 period provides a data set that covers a broad range of activities that occur at a nuclear power 35 plant, such as refueling outages, nonrefueling outage years, routine operation, and maintenance 36 activities that can affect the generation of radioactive effluents. The NRC staff compared the 37 data against NRC dose limits and looked for indication of adverse trends (i.e., increasing dose 38 levels) over the period of 2010 through 2014. Since the radioactive gaseous effluents are 39 released from a common vent stack shared by both Unit 1 and Unit 2, the resultant calculated 40 doses presented in the effluent release are divided in half to evaluate compliance with the 41 Appendix I to 10 CFR Part 50 dose criteria. The following summarizes the calculated doses 42 from radioactive gaseous effluents released from LSCS Units 1 and 2 during 2014:
43 Unit 1 44
* The air dose at the site boundary from gamma radiation in gaseous effluents from 45              LSCS was 2.36x102 millirad (mrad) (2.36x104 milligray (mGy), which is well below 46              the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.
3-15
 
Affected Environment 1
* The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 2            was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 3            dose criterion in Appendix I to 10 CFR Part 50.
4
* The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 5            carbon-14 from LSCS was 4.56x101 millirem (mrem) (4.56x103 millisievert (mSv)),
6            which is well below the 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR 7            Part 50.
8 Unit 2 9
* The air dose at the site boundary from gamma radiation in gaseous effluents from 10            LSCS was 2.36x102 mrad (2.36x104 mGy), which is well below the 10 mrad 11            (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.
12
* The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 13            was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 14            dose criterion in Appendix I to 10 CFR Part 50.
15
* The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 16            carbon-14 from LSCS was 4.56x101 mrem (4.56x103 mSv), which is well below the 17            15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50.
18 The NRC staffs review of LSCSs radioactive gaseous effluent control program showed that 19 radiation doses to members of the public were controlled within NRCs and EPAs radiation 20 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 21 40 CFR Part 190. No adverse trends were observed in the dose levels.
22 Routine plant refueling and maintenance activities currently performed will continue during the 23 license renewal term. Based on the past performance of the radioactive waste system to 24 maintain doses from radioactive gaseous effluents to be ALARA, similar performance is 25 expected during the license renewal term.
26 3.1.4.3    Radioactive Solid Waste Management 27 LSCS Units 1 and 2 share a common solid radioactive waste system (SRWS). The SRWS 28 receives, dewaters, solidifies, packages, handles, and provides temporary storage facilities for 29 all radioactive wet solid wastes prior to offsite shipment and disposal in accordance with NRC 30 regulations in 10 CFR Parts 61 and 71. It also receives, decontaminates, compacts 31 (as necessary), and provides temporary storage facilities for all radioactive dry wastes prior to 32 offsite shipment and disposal (Exelon 2014a). Transportation of the radioactive solid waste is 33 governed by the U.S. Department of Transportation regulations in 49 CFR Parts 171 to 178.
34 LSCS disposes of solid radioactive waste at facilities in Utah and Texas. LSCS also utilizes 35 offsite vendor services in Tennessee for dry active waste processing, including compaction, 36 incineration, thermal processing, and sorting of the dry active waste.
37 LSCS Units 1 and 2 have a shared Interim Radwaste Storage Facility (IRSF) with the capacity 38 to hold 270 containers of Class B and Class C (Class B/C) low-level radioactive wastes in two 39 layers of 135 spots each. In 2011, LSCS Units 1 and 2 both received license amendments to 40 allow their IRSF to store Class B/C waste from Braidwood, Byron, and Clinton Stations in 41 addition to the wastes generated at LSCS. Exelon states that LSCS has sufficient excess 42 storage capacity to accommodate extended storage of the Class B/C wastes generated by all 43 four Exelon stations. Also, LSCS can ship Class B/C wastes for treatment and disposal to the 44 Waste Control Specialists facility in Texas to reduce the demand for any extended onsite 3-16
 
Affected Environment 1 storage of those wastes. Therefore, storage capacity for low-level radioactive wastes should be 2 sufficient for the length of the license renewal term. (Exelon 2014a) 3 LSCS infrequently generates small quantities of mixed waste (waste having both a hazardous 4 component and radioactive component). The IEPA regulates the hazardous component of the 5 waste and the Illinois Emergency Management Agency Division of Nuclear Safety and the NRC 6 regulate the radioactive component. When generated, mixed wastes are accumulated in the 7 Mixed Waste Storage Building before transport to a licensed offsite facility for treatment and 8 disposal (Exelon 2014a).
9 LSCS has contracts to send its low-level waste (LLW) to two licensed LLW disposal sites:
10 EnergySolutions in Clive, Utah, and Waste Control Specialists in Andrews, Texas. LSCS also 11 sends certain wastes to Toxco Materials Management Center in Oak Ridge, Tennessee, and 12 EnergySolutions in Oak Ridge, Tennessee for processing before disposal.
13 In 2014, 30 LLW shipments were made from LSCS for processing and disposal to the 14 EnergySolutions Clive facility in Clive, Utah, the EnergySolutions Bear Creek facility in Oak 15 Ridge, Tennessee, and the Toxco Materials Management Center in Oak Ridge, Tennessee.
16 The total volume and radioactivity of LLW shipped offsite in 2014 was 1.23x103 m3 17 (4.34x104 cubic feet and 1.34x101 curies (4.95x105 megabecquerels)), respectively 18 (Exelon 2015b). Routine plant operation, refueling outages, and maintenance activities that 19 generate radioactive solid waste will continue during the license renewal term. Radioactive 20 solid waste is expected to be generated and shipped off site for disposal during the license 21 renewal term.
22 3.1.4.4      Radioactive Waste Storage 23 Low-level radioactive waste (LLRW) is stored temporarily onsite before being shipped offsite for 24 disposal at a licensed LLRW disposal facility. Exelon (2014a) stated that LSCS has sufficient 25 capability to store Class B/C LLRW from Braidwood, Byron, and Clinton Stations in addition to 26 LSCS Class B/C waste in the IRSF (Exelon 2014a).
27 LSCS stores its spent fuel in a spent fuel pool and also in an onsite independent spent fuel 28 storage installation (ISFSI). The ISFSI is used to safely store spent fuel in licensed and 29 approved dry cask storage containers onsite. The installation and monitoring of this facility is 30 governed by NRC requirements in 10 CFR Part 72, Licensing requirements for the independent 31 storage of spent nuclear fuel, high-level radioactive waste, and reactor-related Greater than 32 class C waste. The LSCS ISFSI will remain in place until the U.S. Department of Energy takes 33 possession of the spent fuel and removes it from the site for permanent disposal or processing.
34 Spent fuel transfers to the ISFSI began in 2010 when fuel from the spent fuel pool was placed 35 in casks and transferred to the ISFSI storage pad. As of December 2014, there are 16 dry 36 casks containing spent fuel on the ISFSI storage pad (Exelon 2015b).
37 3.1.4.5      Radiological Environmental Monitoring Program 38 Exelon conducts a REMP to assess the radiological impact, if any, to the public and the 39 environment from operations at LSCS.
40 The REMP measures the aquatic, terrestrial, and atmospheric environment for ambient 41 radiation and radioactivity. Monitoring is conducted for the following: direct radiation, air, water, 42 groundwater, milk, local agricultural crops, fish, and sediment. The REMP also measures 43 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 44 material, including radon).
45 In addition to the REMP, LSCS has an onsite ground water protection program designed to 46 monitor the onsite plant environment for detection of leaks from plant systems and pipes 3-17
 
Affected Environment 1 containing radioactive liquid (Teledyne 2015). Information on the groundwater protection 2 program is contained in Section 3.5.2 of this document.
3 The NRC staff reviewed 5 years of annual radiological environmental monitoring data:
4 2010 through 2014 (Teledyne 2011, 2012, 2013, 2014, 2015). A 5-year period provides a data 5 set that covers a broad range of activities that occur at a nuclear power plant, such as refueling 6 outages, routine operation, and maintenance activities that can affect the generation and 7 release of radioactive effluents into the environment. The NRC staff looked for indication of 8 adverse trends (i.e., buildup of radioactivity levels) over the period of 2010 through 2014.
9 The NRC staffs review of Exelons data showed no indication of an adverse trend in 10 radioactivity levels in the environment. The data showed that there was no measurable impact 11 to the environment from operations at LSCS.
12 3.1.5    Nonradioactive Waste Management Systems 13 Like any other industrial facility, nuclear power plants generate wastes that are not 14 contaminated with either radionuclides or hazardous chemicals.
15 LSCS has a nonradioactive waste management program to handle its nonradioactive hazardous 16 and nonhazardous wastes. The waste is managed in accordance with Exelons procedures.
17 Listed below is a summary of the types of waste materials generated and managed at LSCS.
18
* LSCS is a small quantity hazardous waste generator; however, hazardous wastes 19              are managed according to large quantity generator standards. LSCS has contracts 20              in place to transfer hazardous waste to licensed offsite treatment and disposal 21              facilities.
22
* LSCSs nonhazardous wastes include potentially infectious medical waste (PIMW),
23              waste/used oil, grease, antifreeze, adhesives, and other petroleum-based liquids.
24              PIMW is generated at a health facility onsite and can include used and unused 25              hypodermic needles and syringes, as well as items contaminated with human blood.
26              PIMW is considered a unique special waste category in Illinois and transportation 27              and disposal of this waste is regulated under the Illinois Administrative Code (IAC) 28              Title 35, Sections 1420 through 1422 and 1450, (35 IAC 1420-1422, 1450).
29
* Universal wastes, such as batteries and mercury-containing lamps are managed in 30              accordance with 35 IAC 733 standards. Other wastes, such as, oils, metals, paper, 31              and other recyclables are managed according to Exelon procedures and Illinois 32              regulations.
33 Exelon operates an onsite sewage treatment plant. Sewage treatment effluent is discharged to 34 the LSCS cooling pond. Nonradioactive industrial wastewater is also processed at the 35 treatment plant and the treated effluent is discharged into the cooling pond. Cooling pond 36 blowdown is discharged to the Illinois River under NPDES permit IL0048151 (Exelon 2014a).
37 3.1.6    Utility and Transportation Infrastructure 38 The utility and transportation infrastructure at nuclear power plants typically interfaces with 39 public infrastructure systems available in the region. Such infrastructure includes utilities, 40 including suppliers of electricity, fuel, and water, as well as roads and railroads that provide 41 access to the site. The following sections briefly describe the existing utility and transportation 42 infrastructure at LSCS.
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Affected Environment 1 3.1.6.1      Electricity 2 Nuclear power plants generate electricity for other users; however, they also use electricity to 3 operate. Offsite power sources provide power to engineered safety features and emergency 4 equipment in the event of a malfunction or interruption of power generation at the plant.
5 Independent backup power sources provide power in the event that power is interrupted from 6 both the plant and offsite power sources.
7 At LSCS, connections to the Commonwealth Edison Company (ComEd) 345-kilovolt (kV) 8 system at the onsite switchyard provide offsite power sources for essential safety systems and 9 emergency equipment (Exelon 2014g). The switchyard is arranged in a double ring bus such 10 that offsite power to both units cannot be lost due to any single failure (Exelon 2014g). In the 11 event of total loss of auxiliary power from offsite sources, onsite diesel generators serve as an 12 independent source of power for safe shutdown (Exelon 2014g). LSCS has six diesel 13 generators (three for each nuclear unit) that can each provide up to 4.16 kV of power, which is 14 ample capacity to supply all power required for the safe shutdown of both units in the event of a 15 total loss of offsite power (Exelon 2014g).
16 3.1.6.2      Fuel 17 The LSCS nuclear units are operated using low-enriched uranium dioxide fuel with enrichment 18 not exceeding 5 percent by weight of uranium-235. At any given time, the LSCS units contain 19 approximately 140 metric tons (MT) (308,600 pounds) of uranium fuel (Exelon 2015e). Exelon 20 replaces about 36 percent of that fuel at each refueling, which occurs on a staggered 24-month 21 cycle (Exelon 2014a). Fresh (i.e., unirradiated) fuel is brought to the site and stored onsite in 22 the LSCS new fuel storage facility prior to installation in the reactor cores (Exelon 2014g).
23 Exelon stores spent fuel in a spent fuel pool and an ISFSI. Nuclear fuel and radioactive waste 24 systems are further described in Section 3.1.4.
25 In addition to nuclear fuel, LSCS requires diesel fuel to operate the emergency diesel power 26 generators. To meet emergency demands, Exelon stockpiles diesel fuel and gasoline on the 27 site. In total, Exelon stores 204,080 gal (772,530 liters) of diesel fuel and gasoline for a variety 28 of uses, including emergency diesel generators, diesel fire pumps, and plant vehicles 29 (Exelon 2015e).
30 3.1.6.3      Water 31 In addition to cooling and auxiliary water (described in Section 3.1.3), nuclear power plants 32 require potable water for sanitary and everyday uses by personnel (e.g., drinking, showering, 33 cleaning, laundry, toilets, and eye washes). At LSCS, two deep wells supply the site with 34 potable water. Water pumped from the wells is routed to an onsite vendor trailer, which 35 deionizes the water and routes the water to a 1.3-million-liter (350,000-gal) storage tank. Water 36 drawn from the storage tank may be used in either the demineralized water makeup system or 37 the potable and sanitary water system. Water withdrawn for use in the potable water system 38 undergoes chlorination prior to entering the system. LSCS withdraws approximately 98 liters 39 per minute (L/min) (26 gpm) from the wells for potable water uses. (Exelon 2014a) 40 3.1.6.4      Transportation Systems 41 All nuclear power plants are served by controlled access roads. In addition to roads, many 42 plants also have railroad connections for moving heavy equipment and other materials. Some 43 plants that are located on navigable waters, such as rivers, Great Lakes, or oceans, have 44 facilities to receive and ship loads on barges.
45 At LSCS, County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, 46 provides access to the site from the southern boundary. Major roads in the area include State 3-19
 
Affected Environment 1 Route 170 (SR-170), which lies 0.8 km (0.5 mi) east of the site, and Interstate 80 (I-80), which 2 lies 13 km (8 mi) north of the site. Section 3.10.6 describes local transportation systems, 3 including roadway access, in more detail.
4 Two major railway systems provide service near the LSCS site: the CSX Railroad runs parallel 5 to and slightly north of the Illinois River, and a 10-km (6-mi) rail spur connects LSCS to the 6 Atchison, Topeka, and Santa Fe Railroad south of the site. Exelon uses a portion of the onsite 7 rail spur to transport spent fuel casks to the onsite storage area, but the spur has not been used 8 to deliver equipment or materials to the site from external sources in many years.
9 (Exelon 2015f) 10 LSCS lies south of the Marseilles Pool in the reach of the Illinois River between the Marseilles 11 Lock and Dam at Marseilles, Illinois, and the Dresden Lock and Dam south of Channahon, 12 Illinois (Exelon 2014a). These lock and dam sites are part of the Illinois Waterway, which flows 13 from Chicago, Illinois, to St. Louis, Missouri, and is composed of seven water systems: Illinois 14 River, Des Plaines River, Chicago Sanitary and Shipping Canal, South Branch Chicago River, 15 Cal-Sag Channel, Little Calumet River, and the Calumet River (USACE 2012). Much of the 16 barge traffic in this area is dominated by transportation of agricultural products (grains, corn, 17 and soybeans) and other commodities, such as cement and concrete (USACE 2012).
18 Exelon (2015g) does not own or maintain a barge slip for LSCS and does not otherwise receive 19 or ship equipment for LSCS by barge.
20 Major airports in the vicinity of LSCS include Chicago Midway International Airport, Chicago 21 OHare International Airport, and Central Illinois Regional Airport, which lie approximately 93 km 22 (58 mi) northeast, 100 km (60 mi) north-northeast, and 110 km (70 mi) south of the site, 23 respectively. Additionally, Illinois Valley Regional Airport in Peru, Illinois, serves LaSalle 24 County, and eight private airports in the county accommodate smaller cargo, passenger, and 25 private aircraft (LaSalle County 2014).
26 3.1.6.5      Power Transmission Systems 27 ComEd owns and operates the 345-kV onsite switchyard that connects LSCS with the regional 28 electric grid. From the switchyard, a total of six transmission lines extend to four substations.
29 Two 345-kV lines travel 66 km (41 mi) north from the site to the Plano substation east of Plano, 30 Illinois. Two 345-kV lines travel 100 km (62 mi) northeast to Braidwood Station, Units 1 and 2, 31 in Braceville, Illinois. Two 138-kV lines are connected to the switchyard through a 345/138-kV 32 transformer. One of the 138-kV line extends 27 km (17 mi) to Mazon, Illinois, and the other 33 138-kV line extends 40 km (25 mi) to Streator, Illinois (AEC 1973; NRC 1978; Exelon 2015h).
34 For license renewal, the NRC (2013) evaluates as part of the proposed action the continued 35 operation of those transmission lines that connect the nuclear power plant to the substation 36 where electricity is fed into the regional power distribution system and transmission lines that 37 supply power to the nuclear plant from the grid. Exelon (2015h) has determined that the four 38 electrical connections between the main plant and the LSCS switchyard are in scope for the 39 license renewal environmental review. These connections extend a distance of 1,300 ft (400 m) 40 across flat, primarily gravel laydown areas and paved roads (Exelon 2015h). Because 41 redundant offsite power is provided to LSCS through the LSCS substation, no offsite 42 transmission lines supply power to the nuclear plant from the grid (Exelon 2015h). All of the 43 in-scope transmission lines lie within the owner-controlled and industrial-use area of the site.
44 3.1.7      Nuclear Power Plant Operations and Maintenance 45 Maintenance activities conducted at LSCS include inspection, testing, and surveillance to 46 maintain the current licensing basis of the facility and to ensure compliance with environmental 3-20
 
Affected Environment 1 and safety requirements. Various programs and activities currently exist at LSCS to maintain, 2 inspect, test, and monitor the performance of facility equipment. These maintenance activities 3 include inspection requirements for reactor vessel materials, boiler and pressure vessel 4 inservice inspection and testing, and maintenance of water chemistry.
5 Additional programs include those carried out to meet TS surveillance requirements, those 6 implemented in response to the NRC generic communications, and various periodic 7 maintenance, testing, and inspection procedures. LSCS must periodically discontinue the 8 production of electricity for outages supporting refueling, periodic in-service inspection and 9 testing, and maintenance activities. The LSCS reactor units are on staggered 24-month 10 refueling cycles (Exelon 2014a).
11 3.2      Land Use and Visual Resources 12 3.2.1      Land Use 13 3.2.1.1      Onsite Land Use 14 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 15 Illinois (Exelon 2015p). The site lies 8 km (5 mi) south of the Illinois River, about 10 km (6 mi) 16 southwest of Seneca, Illinois, and 120 km (75 mi) southwest of downtown Chicago.
17 (Exelon 2014a) 18 A cooling pond occupies the western side of the site and accounts for about half of the site area.
19 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 20 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac). This 21 industrial area is surrounded by about 142 ha (350 ac) of undeveloped natural areas, including 22 grassland, old field, scrub-scrub, and small forested fragments (Exelon 2015p).
23 On the southwest shore of the cooling pond, the IDNR operates the LaSalle Fish Hatchery 24 under a lease agreement with Exelon. The hatchery encompasses approximately 18 ha (45 ac) 25 and includes several small buildings and 16 fish-rearing pools (Exelon 2014a).
26 A 5.6-km (3.5-mi) corridor for the makeup and blowdown pipelineswhich travel underground 27 from the Illinois River screen house south to the cooling pondcontains woodlands, pastures, 28 and wetlands as well as mowed and maintained right-of-way for a portion of the 29 LaSalle-to-Plano 345-kV transmission line (Exelon 2014a).
30 Table 3-1 lists site land uses, and Figure 3-3 depicts the site layout. Sections 3.1 and 3.6 31 describe the developed and natural areas of the site in more detail, respectively.
32                              Table 3-1. LSCS Site Land Uses by Area Land Use                                              Area (in acres)(a)          Percent Open Water                                                  1,976(b)                52.3 Developed, Open Space                                        120                    3.2 Developed, Low Intensity                                      218                    5.8 Developed, Medium Intensity                                    73                  1.9 Developed, High Intensity                                      90                  2.4 Barren Land                                                      5                  0.1 Deciduous Forest                                              386                  10.2 Shrub/Scrub                                                    17                  0.5 3-21
 
Affected Environment Land Use                                                          Area (in acres)(a)              Percent Grassland/Herbaceous                                                        473                      12.5 Pasture/Hay                                                                  11                      0.3 Cultivated Crops                                                            346                      9.2 Woody Wetlands                                                                58                      1.5 Emergent Herbaceous Wetlands                                                  2                      0.1 Total                                                                    3,776                    100.0 (a) To  convert acres to hectares, divide by 2.4711.
(b) Exelon  used the 2011 National Land Cover Database (NLCD) to estimate acreage of site land uses. Of the 3,776-acre site, the 2011 NLCD identified 1,976 acres as open water, most of which consists of the cooling pond. This number of acres is inconsistent with the 2,058 acres reported in ComEds Environmental Report that evaluated the operation of LSCS (ComEd 1977). However, because the methodologies used to estimate land use acreages are different between these documents and the NLCD, and because both methodologies are inherently uncertain, Exelon was unable to resolve the discrepancy between the cooling pond acreage estimates. It is possible that, in the 1977 Environmental Report, features such as dikes, screen house, discharge canals, and storm water ponds were included in the cooling pond acreage estimate. Accordingly, all estimates should be considered approximate.
Source: Exelon 2015d 1 3.2.1.2          Coastal Zone 2 In 1972, Congress promulgated the Coastal Zone Management Act (16 USC 1451 et seq.;
3 CZMA) to encourage and assist States and territories in developing management programs that 4 preserve, protect, develop, and, where possible, restore the resources of the coastal zone 5 (i.e., the coastal waters and the adjacent shore lands strongly influenced by one another, which 6 may include islands, transitional and intertidal areas, salt marshes, wetlands, beaches, and 7 Great Lakes waters). Individual states are responsible for developing a Federally approved 8 Coastal Management Plan and implementing a coastal management program in accordance 9 with such a plan. In Illinois, the IDNR administers the coastal management program.
10 Section 307(c)(3)(A) of the CZMA requires that applicants for Federal permits whose proposed 11 activities could reasonably affect coastal zones certify to the licensing agency (here, the NRC) 12 that the proposed activity would be consistent with the states coastal management program.
13 The regulations that implement the CZMA indicate that this requirement is applicable to renewal 14 of Federal licenses for actions not previously reviewed by the state (15 CFR 930.51(b)(1)).
15 LSCS is outside of the boundary of the Illinois coastal zone (IDNR 2011b, 2015c). Accordingly, 16 a consistency determination is not required for the proposed LSCS license renewal.
17 3.2.1.3          Offsite Land Use 18 Within a 10-km (6mi) radius of the LSCS site, most lands are contained within LaSalle County; 19 however, this radius also includes a small area of land in Grundy County to the east. Land use 20 in this area is primarily agricultural. Cropland or pastures border the LSCS site to the east, 21 south, and west. The Illinois River lies to the north of the site, and the bluffs overlooking the 22 Illinois River are mostly forested. The rivers south bank floodplain includes agricultural fields 23 and woodlots, while the north bank is more developed and includes parts of the incorporated 24 towns of Seneca and Marseilles. The majority of land cover (about 70 percent) within 10 km 25 (6 mi) is used for crop cultivation. Deciduous forest accounts for about 12 percent of land cover, 26 and the remaining 18 percent is composed of various land cover types, including open water, 3-22
 
Affected Environment 1 developed land, wetlands, and grasslands. Table 3-2 characterizes the land uses within a 2 10-km (6-mi) radius of LSCS.
3                    Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS Area Land Use                                          (in acres)(a) Percent Open Water                                          2,915        4.0 Developed, Open Space                                3,124        4.3 Developed, Low Intensity                            2,676        3.7 Developed, Medium Intensity                            451        0.6 Developed, High Intensity                              256        0.4 Barren Land                                            84        0.1 Deciduous Forest                                    8,479      11.7 Evergreen Forest                                        4        0.0 Shrub/Scrub                                            43        0.1 Grassland/Herbaceous                                2,165        3.0 Pasture/Hay                                            966        1.3 Cultivated Crops                                    50,755      70.2 Woody Wetlands                                        425        0.6 Emergent Herbaceous Wetlands                            8        0.0 Total                                              72,351      100.0 (a) To convert acres to hectares, divide by 2.4711.
Source: Exelon 2015i 4 The IDNR manages three areas for public use and recreation within 10 km (6 mi) of LSCS. The 5 LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling pond that is 6 managed by the IDNR and open to the public for fishing and other recreational purposes 7 (Exelon 2014a). The Marseilles State Fish & Wildlife Area is approximately 2.4 km (1.5 mi) 8 north of the LSCS site. The IDNR (2015e) manages this 1,032-ha (2,550-acre) tract of 9 predominantly wooded land for wildlife habitat and hunting. Illini State Park lies approximately 10 10 km (6 mi) northwest of LSCS on the south bank of the Illinois River and encompasses 11 206 ha (510 ac) (Exelon 2014a).
12 LaSalle County, in which LSCS is located, is a predominantly agricultural county; 85 percent of 13 the countys 1,135 square miles (m2) (294,000 ha or 726,400 ac) are in agricultural production 14 (LaSalle County 2014). Much of the countys agricultural lands were formerly prairie. LaSalle 15 Countys major agricultural crops include corn, soybeans, and its major livestock commodities 16 include cattle and calves, hogs and pigs, and sheep and lambs (LaSalle County 2014). The 17 LaSalle County Comprehensive Plan (LaSalle County 2014) anticipates that the county will 18 experience a slight (4 percent) increase in population over the next 15 years and reach an 19 estimated 141,615 people by 2030. The county plans to manage its land resources in a manner 20 that will preserve prime farmland and to encourage continued urban growth in areas where 21 public infrastructure and services already exist so that farmland, open spaces, and natural and 22 cultural resources are preserved.
3-23
 
Affected Environment 1 3.2.2      Visual Resources 2 As described in the previous section, the LSCS site is located in a predominantly agricultural 3 region. The sites grade elevation is approximately 216 m (710 ft) above MSL, which is the 4 highest point within a 3-km (5-mi) radius. The sites generating facilities were built 60 m (200 ft) 5 above the Illinois River floodplain elevation, which ranges from 152 to 155 m (500 to 510 ft) 6 above mean sea level. The tallest structures on the LSCS site are the meteorological tower and 7 the station vent stack, which are 122 m (400 ft) tall and 113 m (370 ft) tall, respectively. The 8 vent stack is painted with thick white and red horizontal stripes. The largest and most visible 9 buildings on the site are the reactor and turbine buildings, which are 56 m (185 ft) and 41 m 10 (134 ft) tall, respectively (Exelon 2014a).
11 To the west and the southwest, the Grand Ridge Energy Center wind farm is situated on slightly 12 higher ground (221 to 227 m (725 to 750 ft) above MSL) on a north-south ridgeline. A second 13 wind farm, Top Crop I, is sited south and east of the Grand Ridge Energy Center. Wind turbines 14 at these facilities stand 118.5 m (389 ft) tall and have rotor blades that are 38.5 m (126.5 ft) 15 long. These two facilities 134 wind turbines dominate the viewscape in the vicinity of LSCS.
16 (Exelon 2014a) 17 From most vantage points, the wind turbines are more noticeable than the LSCS buildings or 18 facilities. A motorist travelling north on Highway 170 from Ranson, Illinois, to Seneca, Illinois, 19 would see wind turbines to the west, south, and east until the motorist crested the bluffs of the 20 Illinois River at an elevation of about 200 m (650 ft) above MSL. The motorist would then lose 21 sight of the turbines at the highway bridge that crosses the Illinois River, at which point the 22 roads elevation descends to approximately 152 m (500 ft) (Exelon 2014a).
23 3.3      Meteorology, Air Quality, and Noise 24 3.3.1      Meteorology and Climatology 25 LSCS is located in LaSalle County in northeastern Illinois, approximately 70 mi (113 km) 26 southwest of Chicago and 35 mi (56 km) southwest of Joliet, Illinois. The regional climate is 27 continental with cold winters; warm summers; and frequent short fluctuations in temperature, 28 humidity, cloudiness, and wind direction (NCDC 2004). During fall, winter, and spring, the polar 29 jet stream is located near or over northeastern Illinois, which causes large-scale synoptic storms 30 to move through the area bringing precipitation, winds, and often dramatic temperature changes 31 (NCDC 2004). Temperature and precipitation conditions vary widely throughout Illinois and 32 between years. A wide range of temperature extremes is common in this region 33 (NCDC 2015a). Tornadoes, thunderstorms, hail, and heat and cold waves are common in the 34 State, and flooding is the most damaging weather-related hazard in Illinois (NCDC 2004).
35 The NRC staff obtained climatological data collected at the Peoria, Illinois, airport station 36 (KPIA), which is located approximately 62 mi (100 km) from LSCS. Additionally, LSCS 37 maintains a meteorological monitoring program that includes a 400-ft (122-m) meteorological 38 tower located approximately 0.5 mi (0.8 km) southeast of the reactor buildings. The tower 39 measures wind direction, wind speed, temperature, and precipitation. Data from these stations 40 were used to characterize the regions climate and are presented below.
41 The prevailing wind direction, for the 1981 through 2010 timeframe, at the KPIA station was 42 from the south-southwest (NCDC 2015a). The mean annual wind speed for the 1981 through 43 2010 timeframe is 8.4 miles per hour (mph) (13.5 kilometers per hour (kph)), and the mean 44 monthly wind speed ranges from 6.0 mph (9.7 kph) in August to 10.2 mph (16.4 kph) in March.
45 The annual predominant wind direction from the meteorological tower at LSCS for the 3-24
 
Affected Environment 1 2010 through 2014 timeframe was from the south-southwest direction (for 2011 and 2012) and 2 from the west-northwest direction (for 2010, 2013, and 2014) (Exelon 2015j). The mean annual 3 wind speed at LSCS for the 2010 through 2014 timeframe is 10.4 mph (16.7 kph) 4 (Exelon 2015j).
5 The mean annual temperature for the 1985 through 2014 period of record at the KPIA station is 6 51.9 &deg;F (11.1 &deg;C), with a mean monthly temperature ranging from a low of 25.2 &deg;F (-3.7 &deg;C) in 7 January to a high of 75.8 &deg;F (24.3 &deg;C) in July (NCDC 2015a). The hottest year over the period 8 of record was in 2012, and coolest was in 1996. The mean annual temperature for the 2010 9 through 2014 timeframe at LSCS is 50.7 &deg;F (10.3 &deg;C), with a mean monthly temperature ranging 10 from a low of 22.5 &deg;F (-5.3 &deg;C) in January to a high of 75.4 &deg;F (24.1 &deg;C) in July (Exelon 2015j).
11 The mean total annual liquid precipitation for the 1985 through 2014 period of record measured 12 at the KPIA station is 35.9 in. (91.2 cm). The wettest year for the period of record is 55.35 in.
13 (140.6 cm) in 1990 (NCDC 2015a); the driest year from the same period is 22.16 in. (56.2 cm) in 14 1988 (NCDC 2015a). Monthly precipitation amounts tend to be evenly distributed throughout 15 the year and range from an average of 1.9 in. (4.8 cm) in January to 4.3 in. (10.9 cm) in May 16 (NCDC 2015a). The mean total annual precipitation measurements taken at LSCSs 17 meteorological tower for the 2010 through 2014 timeframe is 29.83 in. (75.8 cm). Average 18 monthly precipitation ranges from a low of 0.93 in. (2.4 cm) in January to a high of 5.89 in.
19 (14.9 cm) in June (Exelon 2015j).
20 LaSalle County, where LSCS is located, experiences severe weather events, such as 21 tornadoes, floods, and hail. For the 1950 through 2014 period of record, the following events 22 have been recorded (NCDC 2015b):
23
* 40 tornado events, 24
* 26 flash floods events, 25
* 131 hail events, and 26
* 4 blizzard events.
27 3.3.2    Air Quality 28 Under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.), EPA has set 29 primary and secondary National Ambient Air Quality Standards (NAAQS) (40 CFR Part 50) for 30 six common criteria pollutants to protect sensitive populations and the environment. Primary 31 standards specify maximum ambient concentration levels of the criteria pollutants aimed at 32 providing public health protection, including protecting the health of sensitive populations, such 33 as asthmatics, children, and the elderly. Secondary standards specify maximum ambient 34 concentration levels of the criteria pollutants aimed at providing public welfare protection, 35 including protection against decreased visibility and damage to animals, crops, vegetation, and 36 buildings. The NAAQS criteria pollutants include carbon monoxide (CO), lead (Pb), nitrogen 37 dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). Particulate matter 38 is further categorized by sizePM10 (aerodynamic diameter of 10 micrometers (&#xb5;m) or less) 39 and PM2.5 (aerodynamic diameter of 2.5 &#xb5;m or less). Table 3-3 identifies the NAAQS for the six 40 common criteria pollutants.
3-25
 
Affected Environment 1                            Table 3-3. National Ambient Air Quality Standards Primary/Secondary Pollutant                        Standard                      Averaging Time              Level Carbon Monoxide (CO)              Primary                      8 hour                      9 ppm 1 hour                      35 ppm Lead (Pb)                        Primary and Secondary        Rolling 3-month average 0.15 &#xb5;g/m3 Nitrogen Dioxide (NO2)            Primary                      1 hour                      100 ppb Primary and Secondary        Annual                      53 ppb Ozone (O3)                        Primary and Secondary        8 hour                      0.075 ppm Particulate matter less than      Primary                      Annual                      12 &#xb5;g/m3 2.5 &#xb5;m (PM2.5)
Secondary                    Annual                      15 &#xb5;g/m3 Primary and Secondary        24 hour                      35 &#xb5;g/m3 Particulate matter less than      Primary and Secondary        2 hour                      150 &#xb5;g/m3 10 &#xb5;m (PM10)
Sulfur Dioxide (SO2)              Primary                      1 hour                      75 ppb Secondary                    3 hour                      0.5 ppm Key: ppb = parts per billion, ppm = parts per million, &#xb5;g/m3 = micrograms per cubic meter, and &#xb5;m = micrometers.
Source: EPA 2015d 2 EPA designates areas of attainment and nonattainment with respect to the NAAQS. Areas 3 that have insufficient data to determine designation status are denoted as unclassifiable.
4 Areas that were once in nonattainment, but are now in attainment, are called maintenance 5 areas; these areas are under a 10-year monitoring plan to maintain the attainment designation 6 status. States have primary responsibility for ensuring attainment and maintenance of the 7 NAAQS. Under Section 110 of the CAA and related provisions, states are to submit, for EPA 8 approval, State Implementation Plans that provide for the timely attainment and maintenance of 9 the NAAQS.
10 Air quality designations are generally made at the county level. For the purpose of planning and 11 maintaining ambient air quality with respect to the NAAQS, EPA has developed air quality 12 control regions (AQCRs), which are intrastate or interstate areas that share a common airshed 13 (40 CFR Part 81). LSCS is located in LaSalle County, Illinois. This County, along with an 14 additional five neighboring Counties (Bureau, Lee, Marshall, Putnam, and Stark Counties) in 15 Illinois compose the North Central Illinois Intrastate AQCR (40 CFR 81.262). With regard to the 16 NAAQS criteria pollutants, LaSalle County is designated as an attainment area for all NAAQS 17 (40 CFR 81.314). The nearest designated nonattainment area is Grundy County, for the 8-hour 18 ozone 2008 standard. The nearest designated maintenance area is Grundy County for the 19 PM2.5 1997 standard. Grundy County is adjacent to LaSalle County, approximately 4 mi (6 km) 20 from LSCS. Although Grundy County is adjacent to LaSalle County, it is not part of the same 21 AQCR that LaSalle County belongs to.
22 Illinois air pollution control rules are issued under Title 35 of the IAC. Air emission sources at 23 LSCS are regulated under a Federally Enforceable State Operating Permit (FESOP) (Permit 24 No. 099802AAA, issued in December 2000) issued by the IEPA (IEPA 2000). A source is 3-26
 
Affected Environment 1 eligible for a FESOP (also known as synthetic minor air permit) if the potential to emit from the 2 source triggers CAA permit program requirements but if maximum actual emissions are below, 3 or can be restricted to remain below, major source thresholds. LSCSs FESOP permit was 4 issued in December 2000, and expired in December 2005. In accordance with 35 IAC Part 201 5 and the Illinois Environmental Protection Act of 1970 (415 Illinois Compiled Statute (ILCS) 5/39),
6 Exelon submitted a renewal application for the FESOP permit (on July 15, 2005) to the IEPA 7 90 days before the expiration of the permit; therefore, the conditions of the FESOP are 8 administratively extended. On April 7, 2015, the IEPA issued a draft FESOP permit for LSCS 9 for public review and comment (IEPA 2015).
10 Permitted sources at LSCS include five diesel-fired generators, a gasoline storage tank, and 11 gasoline dispensing facilities. The LSCS FESOP permit limits nitrogen oxides, carbon 12 monoxide, particulate matter, volatile organic compounds, and/or the sulfur dioxide emissions 13 from the diesel generators and storage tank, as well as the fuel consumption of the diesel 14 generators and gasoline of the fuel storage tank. LSCS has been in compliance with the 15 requirements established in its FESOP permit, and there have been no reported violations in the 16 past 5 years (Exelon 2015k; EPA 2015b). Emissions from permitted sources at LSCS are 17 presented in Table 3-4. LSCS also has additional air emission sources that are exempt from 18 permitting requirements, but it must still comply with applicable environmental laws and 19 regulations. These air emission sources include diesel pumps and generators that are less than 20 600 horsepower and that are intended to be used during emergency circumstances and only 21 operated during routine surveillance and testing (Exelon 2015j). Air emissions for LaSalle 22 County in 2011 for carbon monoxide, nitrogen oxides, sulfur dioxide, particulate matter less than 23 10 &#xb5;m, and particulate matter less than 2.5 &#xb5;m were 1,213 tons, 2,308 tons, 611 tons, 832 tons, 24 and 483 tons, respectively (EPA 2011). LSCS permitted annual emissions are less than 25 1 percent of the total 2011 emissions for LaSalle County.
26                                Table 3-4. LSCS Air Emissions (MT/year)(a)
Pollutant                2008            2009            2010            2011            2012          2013 CO                        1.10            1.76            1.65            1.52            2.01          1.9 SO2                      0.0042          0.0017          0.0021          0.0017          0.0021        0.001 NOx                      4.18            6.62            6.21            5.73            7.58          6.0 PM10                      0.075            0.12            0.11            0.10            0.14          0.11 PM2.5                    0.075            0.12            0.11            0.10            0.14          0.11 VOC                      0.25            0.33            0.32            0.30            0.35          0.30 CO2                    -(b)            -(b)          315.79            295.46        390.91        308.3 Key: CO = carbon monoxide, NOx = nitrogen oxides, SO2 = sulfur dioxide, PM10 = particulate matter less than 10 micrometers, PM2.5 = particulate matter less than 2.5 micrometers, and VOC = volatile organic compounds.
(a) To convert metric tons (MT) per year to tons per year, multiply by 1.1023.
(b) Carbon dioxide emissions reporting commenced in 2010; therefore, prior year emissions are not available.
Sources: Exelon 2014, 2015k 27 On October 30, 2009, EPA published a rule for the mandatory reporting of greenhouse gases 28 (GHGs) from sources that in general emit 25,000 MT or more of carbon dioxide equivalent 29 (CO2e) per year in the United States (74 FR 56260). Most small facilities across all sectors of 30 the economy fall below the 25,000-MT threshold and are not required to report GHG emissions 31 to EPA. On June 3, 2010, EPA issued the Prevention of Significant Deterioration (PSD) and 3-27
 
Affected Environment 1 Title V GHG Tailoring Rule (75 FR 31514). Beginning January 2, 2011, operating permits 2 issued to major sources of GHGs under the PSD or Title V Federal permit programs must 3 contain provisions requiring the use of best available control technology to limit the emissions of 4 GHGs if those sources would be subject to PSD or Title V permitting requirements because of 5 their non-GHG pollutant emission potentials and because their estimated GHG emissions are at 6 least 75,000 tons per year of CO2e. As discussed above, LSCS is a synthetic minor source, 7 and, as shown in Table 3-4, GHG emissions from sources at LSCS are below the GHG 8 Mandatory Reporting (40 CFR Part 98) and Tailoring Rule thresholds. Section 4.15 of this SEIS 9 further discusses GHG emissions.
10 EPA issued the Regional Haze Rule (RHR) to improve and protect visibility in national parks 11 and wilderness areas from haze, which is caused by numerous, diverse sources located across 12 a broad region (40 CFR 51.308-309). Specifically, Subpart D of 40 CFR Part 81 lists mandatory 13 Class I Federal Areas where visibility is an important value. The Regional Haze Rule requires 14 states to develop State Implementation Plans to reduce visibility impairment at Class I Federal 15 areas. The nearest Class I Federal area for visibility protection is the Mingo National Wildlife 16 Refuge, which is approximately 306 mi (492 km) southwest of the LSCS site. EPA recommends 17 that emission sources located within 62 mi (100 km) of a Class I area be modeled to consider 18 adverse impacts (EPA 1992). Considering the distance to the nearest Class I area and the 19 minor nature of air emissions from the site, there is little likelihood that ongoing activities at 20 LSCS adversely affect air quality and air quality-related values (e.g., visibility or acid deposition) 21 in any of the Class I areas.
22 3.3.3    Noise 23 Noise is unwanted sound and can be generated by many sources. Sound intensity is measured 24 in logarithmic units called decibels (dB). A dB is the ratio of the measured sound pressure level 25 to a reference level equal to a normal persons threshold of hearing. Most people barely notice 26 a difference of 3 dB or less (FHA 2011). Another characteristic of sound is frequency or pitch.
27 Noise may be composed of many frequencies, but the human ear does not hear very low or 28 very high frequencies. To represent noise as closely as possible to the noise levels people 29 experience, sounds are measured using a frequency weighting scheme known as the A scale.
30 Sound levels measured on this A scale are given in units of A-weighted decibels (dBA). Table 31 3-5 presents common noise sources and their respective noise levels. Noise levels can 32 become annoying at 80 dBA and very annoying at 90 dBA. To the human ear, each increase of 33 10 dBA sounds twice as loud (EPA 1981).
34                      Table 3-5. Common Noise Sources and Noise Levels Noise Source                                          Noise Level (dBA)
Human hearing threshold                                          0 Soft whisper                                                    30 Quiet residential area                                          40 Dishwasher                                                    55-70 Lawn mower                                                    65-95 Blender                                                        80-90 Ambulance siren, jet plane                                      120 Source: CHC undated 3-28
 
Affected Environment 1 Several different terms are commonly used to describe sounds that vary in intensity over time.
2 The equivalent sound intensity level (Leq) represents the average sound intensity level over a 3 specified interval, often 1 hour. The day-night average sound intensity level (LDN) is a single 4 value calculated from an hourly Leq over a 24-hour period, with the addition of 10 dBA to sound 5 levels from 10 p.m. to 7 a.m. This addition accounts for the greater sensitivity of most people to 6 nighttime noise. Statistical sound level (Ln) is the sound level that is exceeded n percent of the 7 time during a given period. For example, L90, is the sound level exceeded 90 percent of the 8 time and is considered the background level.
9 There are no Federal regulations1 for public exposures to noise (EPA 2015c). The EPA 10 recommends day-night average sounds levels (LDN) of 55 dBA as guidelines or goals for 11 outdoors in residential areas (EPA 1974). However, these are not standards. The Federal 12 Housing Administration has established noise assessment guidelines for housing projects and 13 finds that day-night average sound levels (LDN) of 65 dBA or less are acceptable (HUD 2014).
14 Sections 25 and 27 of the Illinois Environmental Protection Act of 1970 (Chapter 415) 15 established the authority to create noise regulations. The actual noise regulations are found in 16 the IAC (Title 35, Subtitle H). These noise regulations have allowable octave-band sound levels 17 according to emitting and receiving land class (Class A, B, and C) and time of day.
18 Major offsite noise sources in the vicinity of LSCS include vehicles, wind turbines, and 19 agricultural equipment/machinery (Exelon 2015l). Common noise sources from nuclear power 20 plant operations include transformers, loudspeakers, cooling towers, auxiliary equipment, and 21 worker vehicles (NRC 2013). Major noise sources at LSCS include pumps, turbine building 22 supply and exhaust fans, sirens, generators, transformers, and loudspeakers (Exelon 2015m).
23 However, most of these noise sources are inside buildings, at approximately a 980-ft (300-m) 24 distance from the site boundary, and/or are intermittent. The nearest resident is approximately 25 0.7 mi (1.1 km) from the reactor buildings (Exelon 2014a). Exelon has not received any noise 26 complaints from residents in the vicinity of LSCS (Exelon 2014a). Additional noise sensitive 27 receptors nearby include the LaSalle Lake State Fish and Wildlife Area and Marseilles State 28 Fish and Wildlife Area. LSCS is subject to, and in compliance with, Illinois noise pollution 29 control regulations (Exelon 2015c, 2015m).
30 3.4      Geologic Environment 31 This section describes the current geologic environment of the LSCS site and vicinity, including 32 landforms, geology, soils, and seismic conditions.
33 3.4.1      Physiography and Geology 34 The site is located in an area that contains glacially deposited sediments overlying a bedrock 35 surface. These deposits formed during successive periods of glaciation. The power block and 36 the cooling pond are located on a glacial moraine (a depositional landform directly deposited by 37 a glacier). This area has a flat gently rolling topography. The river screen house is located 38 north of both the power block and cooling pond on the flat-lying river valley of the Illinois River.
39 The river valley is approximately 3.5 mi (5.6 km) north of the site and is topographically 40 separated from the glacial moraine by the bluffs along the Illinois River. The bluffs along the 41 Illinois River are dissected by stream valleys that cut into the glacial sediments and drain north 1  In 1972, Congress passed the Noise Control Act of 1972 (42 U.S.C. 4901 et seq.) establishing a national policy to promote an environment free of noise that impacts the health and welfare of the public. However, in 1982, there was a shift in Federal noise control policy to transfer the responsibility of regulation noise to state and local governments. The Noise Control Act of 1972 was never rescinded by Congress, but it remains unfunded (EPA 2015c).
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Affected Environment 1 to the Illinois River. The maximum topographic relief between the site and the river is 2 approximately 255 ft (78 m) (Exelon 2014a; USDA 2008) (Figure 3-7).
3 In the area of the power block and the cooling pond, the land is covered by a 4- to 8-ft (1.2- to 4 2.4-m) layer of Richland Loess. The loess consists of windblown silt that has been weathered 5 to slightly clayey silt. The Richland Loess is underlain by the Wedron Silty-Clay Till. The till was 6 directly deposited by glacial activity. It consists of unsorted silt and clay sedimentary deposits.
7 In localized areas, the till also contains scattered, disconnected bodies of sand and gravel. In 8 the area of the plant buildings and cooling pond, the Wedron Silty-Clay Till ranges in thickness 9 from 120 to 140 ft (37 to 43 m). Moving north from the plant buildings and the cooling pond to 10 the river, the Wedron Silty-Clay Till decreases in thickness until it disappears near the Illinois 11 River (Figure 3-8) (Exelon 2014a).
12 Below the LSCS site, the Wedron Silty-Clay Till is underlain by bedrock. The topography of the 13 bedrock reflects the surface of the land before glaciation. This topography is now buried by 14 glacially deposited sediments. The site is located between two bedrock valleys that are filled 15 with the Wedron Silty-Clay Till and some alluvial sand and gravel deposits from ancient streams 16 that flowed through the bedrock valleys before they were completely buried. One alluvium-filled 17 buried valley runs east-west and is located between the plant facility and the Illinois River Bluff, 18 and one valley is located south of the plant facility and trends northwest and southeast 19 (Exelon 2014a, 2014c) (Figure 3-9).
20 The underlying bedrock consists of 4,500 ft (1,371 m) of dolomite, sandstone, and shale rock.
21 In turn, these rocks are underlain by granites and metamorphic rocks to a great depth. The 22 Pennsylvanian aged Carbondale Formation forms the top of the bedrock surface over most of 23 the site area. It is composed of alternating strata of shale, sandstone, clay, coal, limestone, and 24 siltstone (Exelon 2014a).
25 LaSalle County contains a number of geologic resources of economic importance. The County 26 is one of a handful of locations that can easily access the St. Peter Sandstone Formation. The 27 unique characteristics of this sandstone make it valuable for a number of commercial uses, 28 including glass, sand filters, sand molding, and abrasives. It is also in high demand for the 29 extraction of oil and gas using conventional horizontal drilling and shale fracking techniques.
30 LaSalle County also contains commercial deposits of gravel and limestone. Limestone and 31 gravel are used in concrete, agricultural limestone, and road surfaces. Clay is mined in the 32 county to manufacture bricks, drain tile, and dinnerware. Coal is no longer mined in the County 33 but historically was mined in bluffs along the Illinois River and around Streator, Illinois 34 (Ataner and Butler 2013; LaSalle County 2014; USDA 2008).
35 The LSCS site is underlain by coal seams, limestone beds, and the St. Peter Sandstone.
36 However, they lie too deep beneath the land surface to be economically accessed. No oil and 37 gas deposits have been identified beneath the site.
38 3.4.2      Soils 39 Eighty-five percent of the soil in LaSalle County is designated as prime farmland, and 9 percent 40 is farmland of State importance (Exelon 2014a). Within the site boundary, almost all the soil is 41 either silty loam or silty clay loam and is designated as prime farmland or farmland of State 42 importance (Exelon 2014a; USDA 2008, 2015b).
43 Following initial construction of the facility, areas surrounding LSCS were graded to control 44 runoff and to minimize erosion. Many areas were revegetated to support this effort 45 (Exelon 2014a).
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Affected Environment 1 Figure 3-7. Site Physiography, LSCS Vicinity 2          Source: NRC Generated 3-31
 
Affected Environment 1              Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity 2                                  (Elevation Exaggerated) 3                            Source: Modified from Exelon 2014a 3-32
 
Affected Environment 1 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity 2                Source: Modified from Exelon 2014e 3-33
 
Affected Environment 1 3.4.3      Seismic Setting 2 The site is located in an area of Illinois that might experience slight damage from earthquakes 3 (FEMA 2015; Mid-America Earthquake Center 2009). A number of earthquakes (USGS 2013a, 4 2013b, 2013c) have originated within Illinois, including the following:
5
* On May 26, 1909, a large earthquake knocked over many chimneys in Aurora and 6              swayed buildings in Chicago.
7
* On July 18, 1909, an earthquake knocked down chimneys in Petersburg.
8
* On August 14, 1965, a sharp local earthquake knocked down chimneys in Elco, 9              Unity, Olive Branch, and Olmstead.
10
* On November 9, 1968, a magnitude 5.3 earthquake was felt over the entire State of 11              Illinois and in 22 other states.
12 Dozens of earthquakes originating outside Illinois have been felt inside the State without 13 causing damage. These earthquakes originated in Missouri, Arkansas, Kansas, Nebraska, 14 Tennessee, Indiana, Ohio, Michigan, Kentucky, and Canada. Illinois can be affected by two 15 major seismic zones, the Wabash Valley Seismic Zone and the New Madrid Seismic Zone. The 16 Wabash Valley Zone lies between southeastern Illinois and southwestern Indiana about 322 mi 17 (518 km) from the site. The New Madrid Seismic Zone is about 300 mi (483 km) from the site in 18 southern Illinois, Missouri, Kentucky, and Tennessee. Of these two seismic zones, the New 19 Madrid Seismic Zone is capable of producing very powerful earthquakes. If a large magnitude 20 earthquake occurs in the New Madrid Seismic Zone, major damage could be experienced in 21 southern Illinois (Missouri Department of Natural Resources 2013; USGS 2009).
22 The NRC requires every nuclear power plant to be designed for site-specific ground motions 23 that are appropriate for its location. Nuclear power plants, including LSCS, Units 1 and 2, are 24 designed and built to withstand site-specific ground motion based on their location and nearby 25 earthquake activity. For LSCS, this includes earthquakes originating in either the Wabash 26 Valley Zone or the New Madrid Seismic Zone (Exelon 2014a). The seismic design basis is 27 established during the initial siting process using site-specific seismic hazard assessments. For 28 each nuclear power plant site, applicants estimate a design-basis ground motion based on 29 earthquake sources, wave propagations, and site responses; this estimate is then accounted for 30 in the design of the plant. In this way, nuclear power plants are designed to withstand the 31 maximum credible earthquake for a given site. Because methods of assessing seismic hazards 32 evolve over time and the scientific understanding of earthquake hazards improve (NRC 2014c),
33 the NRCs understanding of the seismic hazard for a given nuclear power plant may change 34 over time. As new seismic information becomes available, the NRC evaluates the new 35 information to determine whether changes are needed at existing plants or to NRC regulations.
36 The NRCs evaluation of the impact of seismic activity on a nuclear power plant is an ongoing 37 process that is separate from the license renewal process.
38 On December 23, 2011, the Consolidated Appropriations Act (Public Law 112-074) was signed 39 into law. Section 402 of the law directs the NRC to require reactor licensees to re-evaluate the 40 seismic hazard at their sites against current applicable Commission requirements and 41 thereafter, when appropriate, as determined by the Commission (NRC 2012). In 2012, the NRC 42 required all licensees to re-evaluate the seismic hazards at their sites using updated seismic 43 information and present-day regulatory guidance and methodologies (NRC 2012). The purpose 44 of that request was to gather information to update the seismic hazards analysis to enable the 45 NRC staff to determine whether individual site licenses should be modified, suspended, or 46 revoked (NRC 2014a). On March 31, 2014, Exelon responded to this request and provided its 3-34
 
Affected Environment 1 Seismic Hazard and Screening Report (SHSR) for LSCS (Exelon 2014d). On April 21, 2015, 2 the NRC staff issued an assessment (NRC 2015a) documenting its review of the Seismic 3 Hazard and Screening Report. The NRC staff concluded that Exelon met the intent of the 4 guidance for determining the re-evaluated seismic hazard and that it had provided an 5 acceptable response to the request. In addition, the NRC staff directed Exelon to perform 6 further seismic evaluations for NRC review.
7 3.5      Water Resources 8 3.5.1      Surface Water Resources 9 This section describes the current surface water resources within and near LSCS.
10 NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants 11 (GEIS) (NRC 2013), states that surface water encompasses all water bodies that occur above 12 the ground surface, including rivers, streams, lakes, ponds, and man-made reservoirs or 13 impoundments.
14 3.5.1.1      Surface Water Hydrology 15 The major surface water body in the region is the Illinois River, located approximately 4 mi 16 (6.4 km) to the north of the LSCS main plant complex (see Figure 3-2). The LSCS site is 17 situated within the lowermost portion of the Upper Illinois River Basin, which includes the 18 10,949- mi2 (28,369-square-kilometer (km2)) drainage area upstream from Ottawa, Illinois 19 (Figure 3-10). The Illinois River is formed from the confluence of the Kankakee and Des 20 Plaines Rivers at a point approximately 10 mi (16 km) east of Morris, Illinois. The main stem of 21 the Illinois River is joined by the Fox River at Ottawa (Arnold et al. 1999; USGS 1998).
22 The Illinois River is also central to the Illinois Waterway, which provides for navigation from Lake 23 Michigan to the Mississippi River and on to the Gulf of Mexico. The origins of this waterway 24 began with the construction of canals from the lake to the Chicago and Illinois Rivers, beginning 25 in the 1830s. Construction of the formal Illinois Waterway began in 1919 with the State of 26 Illinois leading efforts in the upper part of the river basin and the U.S. Army Corps of Engineers 27 (USACE) in the lower part. Today, the Illinois Waterway includes part of the Chicago River, the 28 Chicago Sanitary and Ship Canal, the Des Plaines River, and the Illinois River. Navigation is 29 made possible by a series of eight major locks and dams and associated navigation pools along 30 the Illinois River and its tributaries. Each pool is named for the dam downstream of each pool 31 (Exelon 2014a; Talkington 1991). Along its length, the waterway contains a navigation channel 32 at least 9 ft (2.7 m) deep and 300 ft (91 m) wide (Talkington 1991). In the vicinity of LSCS, at 33 normal pool elevation, the river has a depth of 12 ft (3.7 m) and a width of 800 ft (244 m) 34 (Exelon 2014a).
35 LSCS is located along the Marseilles Pool portion of the Illinois River. The Marseilles Lock and 36 Dam at Illinois RM 247 (RKm 397.5) is approximately 2.4 mi (3.9 km) downstream of the LSCS 37 intake and discharge structures near RM 249.5 (RKm 401.5) (see Section 3.1.3). However, the 38 lock itself is located a further 2.5 mi (4.0 km) downstream of the dam on a bypass canal 39 (Marseilles Canal) (USACE 2014). The Dresden Island Lock and Dam is 22 mi (35 km) 40 upstream of the LSCS intake structure at RM 271.5 (RKm 437) (Exelon 2014a). The Marseilles 41 Dam is 24 ft (7.3 m) high, and the Dresden Dam is 22 ft (6.7 m) high (Talkington 1991).
42 In total, the main stem of the Illinois River flows for approximately 270 mi (439 km) through 43 Illinois and ultimately discharges into the Mississippi River at Grafton, Illinois (Exelon 2014a; 44 USGS 1994; Talkington 1991). However, when accounting for the other components of the 45 Illinois Waterway, the total length of the river system is 327 mi (526 km) (Talkington 1991).
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Affected Environment 1 The U.S. Geological Survey (USGS) maintains a gaging station on the Illinois River at 2 Marseilles, Illinois (Station 05543500) and RM 246.5 (RKm 396.7). This station is 3 approximately 3 mi (4.8 km) downstream from the LSCS river screen house intake and nearby 4 discharge structure near RM 249.4 (RKm 401). The gaging station is also 0.5 mi (0.8 km) 5 downstream of the Marseilles Dam and 6.9 mi (11 km) upstream from the confluence of the Fox 6 River with the main stem of the Illinois River (Exelon 2014a; USGS 1999b, USGS 2015).
7 The mean annual discharge measured at the USGS gage at Marseilles for water years 1920 8 through 2014 is 10,750 cfs (304 m3/s). For water year 2014, the mean discharge was 9 11,190 cfs (316 m3/s). The mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the 10 period of record (USGS 2015). The 90 percent exceedance flow is an indicator value of 11 hydrologic drought. It signifies a rate of streamflow that is equaled or exceeded 90 percent of 12 the time, as compared to the average flow for the period of record. Based on average monthly 13 flow over the period of record at the station, November is the low-flow month, and April is the 14 high-flow month for the Marseilles Pool (USGS 2015).
15 Tributaries to the Illinois River in the immediate vicinity of LSCS include South Kickapoo Creek, 16 Spring Brook, Deadly Run, Armstrong Run, and Hog Run (Figure 3-11). These headwater 17 streams and manmade ditches drain the glacial upland on which LSCS is located and generally 18 flow north toward the dissected bluffs of the river and across the river valley and into the Illinois 19 River. The most extensive of these nearby tributaries is South Kickapoo Creek. With its 20 headwaters on the northwest side of the LSCS property, this stream receives stormwater runoff, 21 cooling pond dike seepage collected by the LSCS perimeter drainage ditch, and overflow from 22 the cooling pond auxiliary spillway (see Figures 3-3 and 3-5). The main channel of South 23 Kickapoo Creek flows north to northwest from LSCS, with the main channel discharging to the 24 Illinois River at a point approximately 3.5 mi (5.6 km) northwest of the LSCS cooling pond and 25 approximately 0.4 mi (0.6 km) downstream of the LSCS blowdown discharge structure 26 (Exelon 2014a).
27 On the northeast perimeter of the cooling pond is Armstrong Run. Armstrong Run previously 28 drained much of the area that is now occupied by LSCS before plant construction. Like many of 29 the manmade drainage channels (called runs) in the region, it was constructed to convey 30 drainage collected by agricultural drain tile systems (NRC 1978). Armstrong Run now receives 31 runoff and seepage collected from the northeast end of the peripheral dike drainage ditch.
32 It discharges to the Illinois River at a point approximately 3.2 RM (5.1 RKm) northeast of the 33 cooling pond and about 4.5 RM (7.2 RKm) upstream of the river screen house (Exelon 2014a).
34 As further described in Section 3.1.3, the dominant surface water feature within the LSCS site 35 and vicinity is the 2,058- ac (833- ha) cooling pond (Figure 3-5). Other surface water features 36 on the LSCS plant site include two stormwater management ponds (North and South Storm 37 Water Ponds), two sewage treatment lagoons, and a collection of hatchery ponds as 38 summarized below. The NRC staff visited the facilities cited herein during the May 2015 39 environmental site audit (NRC 2015b).
40 The North and South Storm Water Ponds are located west of the LSCS main plant complex and 41 receive stormwater runoff from the protected area, serving the north and south zones of the 42 plant, respectively. Within the site, a system of ditches, storm drains, culverts, and underground 43 storm sewers collect runoff and drainage from the protected area and convey much of it to 44 either of the two ponds. Uncontaminated runoff from the north zone of the plant is conveyed to 45 the North Storm Water Pond, with some runoff sources first passing through the Unit 2 oil-water 46 separator. A portion of the switchyard also drains toward the north zone, although most of the 47 switchyard drains east to the cooling pond.
3-36
 
Affected Environment 1 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries 2                  Source: Modified from Arnold et al. 1999 3-37
 
Affected Environment 1          Figure 3-11. LSCS Surface Water and Related Water Resource Features 2                        Source: Modified from Exelon 2014a, 2015b 3-38
 
Affected Environment 1 Most runoff from the south zone enters the smaller South Storm Water Pond; this pond then 2 discharges to the cooling pond discharge canal through internal Outfall H01. Before entering 3 the pond, some flows first pass through the Unit 1 oil-water separator. The south pond also 4 receives runoff from the firing range. Areas of the plant site to the northwest and south of the 5 developed plant complex do not drain to the ponds but instead are drained by existing surface 6 stream segments and ditches (Exelon 2014a, 2014c).
7 Stormwater management and pollution control at LSCS is subject to Exelons Storm Water 8 Pollution Prevention Plan (SWPPP) (Exelon 2013e), which Exelon has implemented in 9 accordance with Special Condition 8 of the sites NPDES permit (IEPA 2013). The SWPPP 10 applies to industrial stormwater runoff from the site, which is not otherwise process-related and 11 not captured and processed by LSCSs wastewater treatment facilities. It describes the best 12 management practices, controls, inspection, and monitoring requirements, and the associated 13 implementing procedures and personnel responsibilities for reducing pollutants in stormwater 14 discharge and for ensuring compliance with the terms and conditions of the site NPDES permit 15 (Exelon 2013e).
16 Two open sewage treatment lagoons provide primary and secondary treatment for LSCSs 17 sanitary effluent. These lagoons are geotextile-lined impoundments and are located to the north 18 of the main plant complex adjacent to LSCSs sewage treatment plant (as shown in 19 Figure 3-3). Together, the NRC staff estimates the two impoundments cover an area of about 20 1.6 ac (0.65 ha). After filtration and final disinfection in the sewage treatment plant, the final 21 effluent from the treatment system is discharged into the cooling pond via NPDES internal 22 Outfall B01 (Exelon 2014a, 2014c).
23 A cluster of 16 small fish-rearing ponds is located on the southwest shore of the cooling pond 24 (see Figures 3-3 and 3-5). The NRC staff estimates that the ponds total approximately 29 ac 25 (12 ha) of open water. These ponds comprise the LaSalle Fish Hatchery operated by the IDNR 26 on plant property and subject to a lease agreement with Exelon. The hatchery uses the cooling 27 pond as a makeup water source. Runoff and drainage from the hatchery ponds flow back to the 28 cooling pond and are ultimately subject to LSCSs NPDES permit provisions 29 (Exelon 2014a, 2014c). The LSCS sites NPDES permit is further discussed in Section 3.5.1.3.
30 LSCS is not susceptible to riverine flooding because it is located upland and away from the 31 Illinois River.
32 The grade elevation at the plant site is 710 ft (216 m) above MSL, and the floor elevation of the 33 LSCS facilities is 710.5 ft (217 m) above MSL. The plant floor lies at an elevation that is 188 ft 34 (57 m) above the level of a postulated probable maximum flood on the Illinois River 35 (Exelon 2014a, 2014g). Although the river screen house is not a safety-related structure, it is 36 designed to withstand the 100-year flood on the Illinois River. Its loss would not impact the 37 ability to safely shut down the plant as water could still be drawn from the cooling pond and from 38 the UHS portion of the cooling pond, as described in Section 3.1.3 of the SEIS (Exelon 2014a, 39 2014g).
40 Furthermore, a failure of the peripheral dike system enclosing the cooling pond would not flood 41 the power plant area because the onsite topography would cause cooling pond water to flow 42 north and away from the plant following the existing drainage network (Exelon 2014a, 2014g).
43 3.5.1.2      Surface Water Use 44 LSCS withdraws surface water from the Illinois River as makeup water for the plants cooling 45 pond. The cooling pond provides water for the plants circulating water, service water, and 46 essential cooling water systems. Cooling tower blowdown and other permitted effluent streams 47 are discharged back to the Illinois River via the plants primary NPDES outfall (Outfall 001) at a 3-39
 
Affected Environment 1 point located about 900 ft (270 m) downstream from LSCSs river intake structure and 2 associated river screen house.
3 The maximum (nominal) surface water withdrawal rate for LSCS, Units 1 and 2, is 90,000 gpm 4 (200 cfs or 5.66 m3/s). This is equivalent to 129.6 million gallons per day (mgd) 5 (491,000 m3/day). However, Exelon reports in its ER that LSCSs normal peak makeup 6 withdrawal rate from the Illinois River is 60,000 gpm (134 cfs or 3.77 m3/s) or 86.4 mgd 7 (327,000 m3/day). This rate assumes a two-pump operation with valves open at 100 percent.
8 The third makeup pump located in the river screen house normally serves as a backup 9 (see Section 3.1.3).
10 The NRC staff reviewed submittals by Exelon to the Illinois State Water Survey that document 11 the volume of surface water withdrawn from, and discharged back to, the Illinois River during 12 the period 2009 to 2013 (Table 3-6). Based on these data, LSCS surface water withdrawals 13 have averaged 24,745 million gallons per year (mgy) (93.7 million cubic meters per year 14 (m3/yr)). This is equivalent to an average withdrawal rate of approximately 105 cfs (2.96 m3/s or 15 67.8 mgd). Return discharges (blowdown) to the Illinois River have averaged 13,046 mgy 16 (49.4 million m3/yr), which is equivalent to an average discharge rate of about 55.3 cfs 17 (1.56 m3/s or 35.7 mgd). The difference between withdraw and discharge (i.e., approximately 18 49.7 cfs (1.40 m3/s)) generally reflects process consumptive use or other losses, evaporative 19 losses, and presumably seepage from the cooling pond. In total, these data indicate a 20 consumptive use rate averaging 47 percent.
21    Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, LSCS Withdrawals                                      Discharges Year              (mgy)          mgd            cfs            (mgy)              mgd              cfs 2009            28,598.4          78.5            121          19,405.0              53.2            82.2 2010            25,876.8          70.9            110          13,686.0              37.5            58.0 2011            23,328.0          63.9            98.9        11,961.1              32.8            50.7 2012            28,857.6          79.1            122          14,005.7              38.4            59.4 2013            17,064.0          46.7            72.3          6,173.0              16.9            26.2 Average            24,745.0          67.8            105          13,046.1              35.7            55.3 Note: Reported and calculated values are rounded. To convert million gallons per year (mgy) to million cubic meters (m3), divide by 264.2. To convert, million gallons per day (mgd) to cubic feet per second (cfs), multiply by 1.547.
Sources: Exelon 2011a, 2012a, 2013a, 2014a, 2014d 22 LSCSs surface water withdrawals and consumptive water use are not subject to any water 23 allocation or related permitting requirements at the present time. In 2006, the Governor of 24 Illinois issued an executive order establishing a Statewide program for State and regional water 25 supply planning and management, which included the development and approval of regional 26 plans in designated Priority Water Quantity Planning Areas (State of Illinois 2006). LaSalle 27 County, where LSCS is located, is not included within any of the three designated planning 28 areas (Exelon 2014a; ISWS 2015a). Nevertheless, as referenced above, Exelon reports its 29 surface water withdrawals to the State of Illinois under the State Illinois Water Inventory 30 Program (Exelon 2014a; ISWS 2015b). Reporting is required in accordance with the Illinois 31 Water Use Act of 1983 (525 ILCS 45) and its 2010 amendments. The general purpose and 32 intent of the Act is to establish a means of reviewing potential water conflicts before damage to 3-40
 
Affected Environment 1 any person is incurred and to establish a rule for mitigating water shortage conflicts. The 2 2010 amendments to the Illinois Water Use Act added high-capacity intakes as subject to the 3 Acts water use reporting provisions. Such intakes are surface water intakes on a property in 4 which the rate or capacity of water withdrawal of all intakes for the property is equal to, or in 5 excess of, 100,000 gal (380 m3) during any 24-hour period (525 ILCS 45).
6 Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and 7 cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat 8 Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan 9 and associated procedures to mitigate the impacts of summer drought and/or high river 10 temperature and river low-flow conditions. Depending on predefined conditions set forth in the 11 plan and implementing procedures, such actions may include a combination of monitoring and 12 modeling of river intake and mixing zone temperatures; manipulation of the water level of the 13 cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the 14 cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the TS 15 limits on condenser inlet temperature from the cooling pond (Exelon 2014a, 2015c).
16 Two other industrial facilities withdraw water from the Marseilles Pool of the Illinois River in the 17 vicinity of LSCS (Figure 3-5) and are listed in the Illinois Water Inventory Program. These are 18 Agrium U.S., Inc., and PCE Phosphate, Marseilles Operation. The volume of water withdrawn 19 by these commercial facilities is not publicly available (Exelon 2014a). Because they are 20 included in the States inventory, the NRC staff presumes that each facility withdraws in excess 21 of 100,000 gpd (380 m3). Both are also currently subject to NPDES individual permits 22 (i.e., Permits IL0001708 and IL0036463). Based on reported return discharges to the Illinois 23 River, it is estimated that Agriums surface water withdrawals are on the order of 5 mgd 24 (18,900 m3) (EPA 2015a).
25 The public water supply systems in the vicinity of LSCS (i.e., the city of Marseilles and the 26 village of Seneca) do not withdraw water from the Illinois River but instead rely upon 27 groundwater-supplied systems (Exelon 2014a) (see Section 3.5.2.2).
28 Surface water withdrawals within the Marseilles Pool have shown no significant effects on water 29 availability to date (Exelon 2014a).
30 3.5.1.3      Surface Water Quality and Effluents 31 The Illinois Pollution Control Board (IPCB), a sister agency to the IEPA, promulgates water 32 quality standards in the State. Two Sections of Title 35 of the IAC (35 IAC 302 and 35 IAC 303) 33 contain the standards applicable to lakes and streams. Procedures that must be followed in 34 using water quality standards to set NPDES permit limits appear in Section 309 (35 IAC 309).
35 Designated uses prescribed by 35 IAC 303 are those uses specified in water quality standards 36 for each lake, river, stream, and groundwater resource. In designating uses for a waterbody, 37 the IPCB considers the use and value of the waterbody for public water supply; propagation of 38 fish, shellfish, and wildlife; and recreational, agricultural, industrial, and navigational purposes.
39 The main stem of the Illinois River is designated a general use water by the IPCB. Waters in 40 the general use category must meet water quality standards protective of aquatic life, wildlife, 41 agricultural use, and secondary contact use, as well as most industrial uses and aesthetic 42 quality (35 IAC 303.201). These standards pertain to pH; phosphorus; dissolved oxygen; 43 radioactivity (gross beta, strontium-90, and radium-226 and -228); various chemical constituents 44 (metals and organic compounds); fecal coliform; and other toxic substances. In addition, a 45 segment of the main stem of the Illinois River within LaSalle and Grundy Counties, and 46 encompassing the entire Marseilles Pool on which LSCS is located, is afforded enhanced 47 dissolved oxygen protection. Dissolved oxygen levels must be not less than 5.0 milligrams per 3-41
 
Affected Environment 1 liter at any time during March through July and not less than 4.0 milligrams per liter at any time 2 during August through February (35 IAC 302.206).
3 Over the last 150 years, water quality within the whole of the Illinois River Basin has historically 4 suffered from rapid population growth; urbanization; and industrial development, including the 5 conversion of prairie, wetlands, and forests. This change resulted in the discharge of untreated 6 and inadequately treated sewage, the discharge of industrial pollutants and refuse, runoff of 7 agricultural chemicals and sediments, and the alteration of the natural river hydrology due to 8 navigation and flood control projects (Exelon 2014a; Talkington 1991).
9 Over the last 50 years, substantial improvements in water quality have occurred because of 10 municipal and industrial waste treatment and management efforts to address both point and 11 nonpoint pollutant sources. Ongoing water quality concerns within the upper Illinois River Basin 12 include the atmospheric deposition of pesticides and trace metals; endocrine disrupting 13 compounds in surface and groundwater; nutrient enrichment of surface and groundwater; the 14 transport and fate of pesticides, trace elements, and volatile organic compounds in surface and 15 ground water; and the effects of urbanization on biodiversity, habitat, and water quality 16 (USGS 1998).
17 Section 303(d) of the Federal Water Pollution Control Act (i.e., Clean Water Act of 1977, as 18 amended (CWA) (33 U.S.C. 1251 et seq.)) requires the State of Illinois and other states to 19 identify all impaired waters for which effluent limitations and pollution control activities are not 20 sufficient to attain water quality standards in such waters. The Section 303(d) list includes those 21 water quality-limited stream segments that require the development of total maximum daily 22 loads (TMDLs) to ensure future compliance with water quality standards. The TMDLs specify 23 the maximum amount of a pollutant that a waterbody can receive and still meet water quality 24 standards. Once established, TMDLs are typically implemented through watershed-based 25 programs administered by the State, primarily through the NPDES permit program and 26 associated point and nonpoint source water quality improvement plans and associated best 27 management practices. The IEPA has classified a 30.1-mi- (48.4-km)-long segment (IL_D-23) 28 of the Illinois River between Morris and Ottawa, Illinois, that includes the LSCS site as impaired.
29 This segment is listed as impaired because it does not meet designated uses for fish 30 consumption due to polychlorinated biphenyls (PCBs) and mercury contamination. It is also 31 impaired for primary contact recreation use due to fecal coliform bacteria (IEPA 2014b). Special 32 Condition 13 of the NPDES permit for LSCS prohibits the discharge of PCBs in plant effluents 33 (IEPA 2013). The river segment is classified as fully supporting its designated use for aquatic 34 life. IEPA has assigned a medium priority for the development of TMDLs for segment IL_D-23 35 (IEPA 2014b).
36 As for other streams and runs in the vicinity of LSCS, IEPA (2014b) designates them as 37 Category 3, which are waters for which no use-support determination can be made due to 38 insufficient available data and/or information.
39 The LSCS cooling pond is included in the IEPAs CWA Section 314 inventory of lakes and has 40 also been designated as Category 3 (IEPA 2014b). However, LSCSs cooling pond is defined 41 by the State of Illinois as a wastewater treatment works pursuant to 35 IAC 301.415. Under this 42 definition, the cooling pond is not waters of the State under 35 IAC 301.440. Likewise, as 43 defined in 40 CFR 230.3, pursuant to the Federal CWA, waste treatment systems, including 44 treatment ponds or lagoons designed to meet the requirements of the Clean Water Act are 45 explicitly excluded from the definition of waters of the United States. Therefore, the cooling 46 pond is not subject to State or Federal water quality standards.
47 To operate a nuclear power plant, licensees must comply with the CWA, including associated 48 requirements imposed by EPA or the state as part of the NPDES permitting system under 3-42
 
Affected Environment 1 Section 402 of the CWA, as well as state water quality certification requirements under 2 Section 401 of the CWA. The EPA or the state, not the NRC, sets the limits for effluents and 3 operational parameters in plant-specific NPDES permits. Nuclear power plants cannot operate 4 without a valid NPDES permit and a current CWA Section 401 Water Quality Certification. The 5 EPA has delegated responsibility to the State of Illinois for the administration of the NPDES 6 program in Illinois. NPDES permits are issued by the IEPA on a 5-year cycle.
7 LSCS is authorized to discharge various wastewater (effluent) streams, including cooling pond 8 blowdown and stormwater under NPDES Permit IL0048151, reissued on July 5, 2013; the 9 current permit expires on July 31, 2018 (Exelon 2014a; IEPA 2013). The permit specifies the 10 discharge standards and monitoring requirements for effluent chemical and thermal quality 11 through the plants outfalls to the Illinois River, as summarized in Figure 3-7. The location of 12 the LSCSs primary outfall (001) to the Illinois River is shown in Figure 3-5.
13                          Table 3-7. National Pollutant Discharge Elimination 14                                    System-Permitted Outfalls, LSCS Average Flow Outfall        Rate (mgd)(a)    Description 001(b,c,d,e)  34.9              Cooling Pond Blowdown; includes effluents from internal Outfalls A01 through H01, as well as IDNR fish hatchery effluents; discharge to the Illinois River A01(b,f,g)    Intermittent      Demineralizer Regenerant Wastes; includes makeup demineralizer regenerant wastes, off-specification demineralized water, makeup demineralizer maintenance wastewater, unit waterbox vacuum pump condensate, and radioactive waste (radwaste) treatment acid/caustic system drains discharges B01(b,c,f,g,h) 0.06              Sewage Treatment Plant Effluent; includes sanitary wastewater and eyewash station wastewater C01(b,c,f,g,i) 0.044            Wastewater Treatment System Effluent; includes nonsanitary drains composed of turbine building fire and miscellaneous nonradioactive wastewater sump, greensand filter backwash, diesel fuel storage and service water building sump, auxiliary boiler blowdown, water softener regenerant waste, demineralizer regenerant wastes, heat bay building roof area, fire protection system flushing and maintenance, service water system flushing and maintenance, domestic water system flushing and maintenance, clean condensate system flushing and maintenance, laboratory liquid wastes, station heat system condensate, diesel generator cooling water, standby liquid control test skid flush water, and groundwater D01(f)        Intermittent      Cooling Water Intake Screen Backwash E01(b,f g,i)  Intermittent      Unit 1 and 2 Radwaste Treatment System Effluent; includes equipment and floor drains in the turbine, auxiliary, and reactor buildings, as well as condensate polisher waste from the turbine building and decontamination and laundry waste F01(f)        Intermittent      Auxiliary Reactor Equipment Cooling and Flushing Water G01(f,j)      Intermittent      North Site Stormwater Runoff H01(f,j)      Intermittent      South Site Stormwater Runoff I01(b,f,g)    Intermittent      Reverse Osmosis System Reject Water and Greensand Filter Backwash 3-43
 
Affected Environment Average Flow Outfall          Rate (mgd)(a)          Description 002(k)            Intermittent          Illinois River Makeup Water Intake Screen Backwash; includes river intake screen backwash; trench wash water; process sampling discharge; lake makeup pump gland leakoff; coolers/reliefs flow; lake makeup pump strainer backwash; air compressor receiver and prefilter drainage; dewatering pump discharge; fire protection water; and river screen house switchyard stormwater runoff, floor drains, and roof drains; discharge to the Illinois River at the river screen house (a) To  convert million gallons per day (mgd) to million cubic meters (m3), divide by 264.2.
(b) Flow  is subject to monitoring and reporting in units of mgd as a monthly average and as a daily maximum on Discharge Monitoring Report (DMR) (NPDES permit Special Condition 1).
(c) pH is subject to limit of 6.0 to 9.0 (NPDES permit Special Condition 2).
(d) Temperature is subject to continuous monitoring and DMR reporting of maximum monthly, as well as with temperature limits and mixing zone criteria (NPDES permit Special Condition 3). The calculated temperature at the edge of the mixing zone is limited to no more than 5 &deg;F (2.8 &deg;C) higher than ambient river temperature. The temperature beyond the mixing zone cannot exceed specified monthly limits for longer than 1 percent (i.e., 87.[[estimated NRC review hours::6 hours]]) of any 12-month period and cannot at any time exceed the specified monthly limit by more than 1.7 &deg;C (3 &deg;F). During the months of April through November, the calculated temperature outside the mixing cannot exceed 93 &deg;F (34 &deg;C).
(e) Total residual chlorine is subject to a limit of 0.05 milligrams per liter (NPDES permit Special Conditions 4 and 16).
(f) This outfall is the NPDES permit internal monitoring point before the numbered point source outfall.
(g) Total suspended solids are subject to specified limits and monitoring.
(h) Carbonaceous biochemical oxygen demand is subject to specified limits and monitoring.
(i) Oil and grease are subject to specified limits and monitoring.
(j) Stormwater is subject to requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8).
(k) Adequate maintenance of intake screen system is required to prevent discharge of floating debris back to the river. The stormwater portion is subject to the requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8).
Note: The release of complex metal-bearing waste streams and polychlorinated biphenyls (PCBs) from all outfalls is prohibited by NPDES permit Special Conditions 5 and 13, respectively. Special Condition 9 authorizes the use of water treatment additives that were requested by Exelon as part of the renewed NPDES permit application.
Source: IEPA 2013 1 As indicated in Table 3-7, the NPDES permit for LSCS requires Exelon to monitor and sample 2 site effluents for various parameters in accordance with applicable effluent limits. Monitoring 3 results are reported in monthly Discharge Monitoring Reports (DMRs) submitted to the State.
4 The NRC staff reviewed the DMRs submitted by Exelon to the IEPA for the period 2010 through 5 2014. This review encompassed the results of recorded maximum cooling pond blowdown 6 temperatures to the Illinois River and associated calculations of river mixing zone temperatures 7 as reported in the DMRs for the past 5 years (2010 through 2014) and as compiled by Exelon 8 (Exelon 2015c). Based on the NRCs staff review and Exelons responses to the NRCs 9 requests for additional information, LSCS has received no notices of violation associated with 10 NPDES permitted discharges during the 2010 through 2014 time period. Nonetheless, Exelon 11 recorded several unusual occurrences in its DMR reports. These included reports of a makeup 12 pipeline line failure on January 29, 2010; a blowdown line failure on July 13, 2012; a makeup 13 pipeline line failure on January 25, 2013; a blowdown line air release valve failure on 3-44
 
Affected Environment 1 February 8, 2013; a makeup pipeline failure on May 21, 2013; and a makeup pipeline failure on 2 January 23, 2014 (Exelon 2015c).
3 The DMR submittals also document actions taken to comply with provisional variances granted 4 by the IEPA to Exelon with respect to LSCSs effluent discharges to the Illinois River and 5 associated river mixing zone temperature limits. Specifically, these variances 6 (IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in 7 March, July, and August 2012, respectively, due to unusual weather conditions and associated 8 high ambient river water temperatures that impacted the ability for LSCS thermal discharges to 9 meet the requirements of Special Condition 3 of LSCSs NPDES permit. This limits the number 10 of temperature excursion hours to 1 percent (87.[[estimated NRC review hours::6 hours]]) of the hours in a 12-month period, 11 ending with any month (see footnote d in Table 3-7). During the variance period(s), Exelon was 12 required, in part, to continuously monitor both the discharge and receiving water temperatures 13 and visually inspect all discharge areas at least three times each day to assess the impact on 14 aquatic life. These thermal discharge excursions were not found to have any impact on aquatic 15 life (Exelon 2015c).
16 An applicant (in this case, Exelon) for a Federal license to conduct activities that may cause a 17 discharge of regulated pollutants into navigable waters of the United States is required by 18 Section 401 of the CWA to provide the licensing agency (in this case, the NRC) with water 19 quality certification from the state (in this case, the State of Illinois). This certification implies 20 that discharges from the project or facility to be licensed will comply with CWA requirements and 21 will not cause or contribute to a violation of state water quality standards. If the applicant has 22 not received Section 401 certification, the NRC cannot issue a renewed license unless that state 23 has waived the requirement. The NRC recognizes that some NPDES-delegated states explicitly 24 integrate their 401 certification process with NPDES permit issuance. However, LSCSs 25 NPDES permit does not explicitly convey water quality certification under CWA Section 401.
26 By letter dated February 4, 2014, Exelon submitted an application to the IEPA Bureau of Water 27 that requested certification from the IEPA that renewal of Exelons NRC operating licenses for 28 LSCS would not violate State water quality standards (Exelon 2014h). The IEPA Division of 29 Water Pollution Control issued a letter to the NRC, and copied Exelon, which provides 30 Section 401 water quality certification for renewal of the operating licenses for LSCS. The 31 certification was issued with the condition that Exelon shall be responsible for obtaining NPDES 32 permits required for wastewater or stormwater discharges to waters of the State (IEPA 2014c).
33 As previously stated in this section, NRC licensees must comply with the CWA, including 34 associated requirements imposed by EPA or the state, as part of the NPDES permitting system 35 under CWA Section 402. The NRC staff concludes that the IEPAs response provides the 36 necessary certification pursuant to CWA Section 401.
37 To maintain LSCSs surface water intake system on Marseilles Pool of the Illinois River, Exelon 38 conducts occasional maintenance dredging at the river screen house (Exelon 2014a). The 39 need for maintenance dredging at the river screen house forebay is periodically evaluated in 40 accordance with an Exelon operating procedure. Currently, needed dredging is conducted 41 under a USACE Section 10 permit, which is issued pursuant to the Rivers and Harbors 42 Appropriation Act of 1899 (33 U.S.C. 403) (USACE 2006). Dredging was most recently 43 conducted in October 2013 in compliance with the provisions of the permit. Less than 100 cubic 44 yards (76 m3) of sediment was removed, and the material was dewatered and placed out of the 45 floodplain near the screen house. Future maintenance dredging will be conducted as needed 46 and with the necessary permits. Exelon does not expect to perform any dredging in the vicinity 47 of the LSCS discharge channel during the license renewal term and does not anticipate the 48 need to conduct any fill activities (Exelon 2015c).
3-45
 
Affected Environment 1 3.5.2      Groundwater Resources 2 This section describes the current groundwater resources at the LSCS site and in the vicinity.
3 3.5.2.1      Site Description and Hydrogeology 4 The site is characterized by five hydrogeologic units. By increasing depth, they are as follows:
5
* the Alluvial Aquifer, 6
* the Glacial Drift Aquitard, 7
* the Buried Bedrock Valley Aquifers, 8
* the Pennsylvanian Aquitard, and 9
* the Cambrian-Ordovician Aquifer System.
10 The hydrogeologic characteristics of these units are summarized in Figure 3-12.
11 Alluvial (stream) deposits are found beneath, and extend along each side of, the Illinois River.
12 These deposits form the Alluvial Aquifer that lays on top of the bedrock (the Pennsylvanian 13 Aquitard) (Figure 3-8). The river functions as a hydrologic boundary, which prevents 14 groundwater within the Alluvial Aquifer from flowing from one side of the river to the other. The 15 Alluvial Aquifer is generally 2 to 4 ft (0.6 to 1.2 m) thick, is located in the vicinity of the river 16 screen house, and ranges from 3,500 to 4,800 ft (1,067 to 1,463 m) in width. Yields in the 17 Alluvial Aquifer are restricted by the limited areal extent and thickness of the sand and gravel 18 deposits that make up the aquifer. Small dependable yields suitable for domestic purposes are 19 only locally available. The aquifer receives recharge primarily by precipitation and from the 20 river. Well yields from the Alluvial Aquifer in the vicinity of the river screen house are most likely 21 adequate only for domestic use (Exelon 2014a).
22 The Glacial Drift Aquitard is made up of the Richland Loess and the Wedron Silty-Clay Till 23 (see Section 3.4.1). The aquitard largely consists of silty-clay till (unsorted sediment containing 24 a range of grain sizes) with very low permeability. In the area of the plant buildings, the Glacial 25 Drift Aquitard is over 200 ft (61 m) thick (CRA 2006). Any extractable groundwater in this 26 aquitard is produced from thin discontinuous sand and gravel pockets that are recharged by the 27 slow infiltration of precipitation through the silty-clay till. The volume of groundwater produced 28 from these pockets is limited so that it is primarily used as a source of water for domestic or 29 farm activities (Exelon 2014a).
30 As discussed in Section 3.4.1, the site is located between two buried bedrock valleys that 31 contain alluvial deposits of sandy gravels and gravelly sands with lesser amounts of silt and clay 32 in scattered thin layers. These alluvial deposits are overlain and merge with the Wedron 33 Silty-Clay Till. They are recharged by the slow infiltration of precipitation through the thick 34 overlying Glacial Drift Aquitard. Therefore, the volume of groundwater that can be produced 35 from the Buried Bedrock Valley Aquifers is limited to supplying water for domestic or farm 36 activities (Exelon 2014a).
37 The Pennsylvanian Aquitard forms the bedrock. It consists of alternating beds of shale, 38 siltstone, underclay, sandstone, limestone, coal, and many gradational layers. Low permeability 39 shale and siltstone comprise more than 90 percent of the aquitard. In the area of the plant 40 buildings, the Pennsylvanian Aquitard is approximately 176 ft (54 m) thick. Groundwater in the 41 aquitard occurs under artesian conditions. Wells finished in the aquitard get water primarily 42 from thin sandstone and limestone beds within the aquitard, which are recharged by seepage 43 through the overlying shales and through the silty-clay till of the Glacial Drift Aquitard. In 44 general, the sandstone and limestone beds within the aquitard can only supply enough water for 3-46
 
Affected Environment 1 domestic or farm use because well yields are commonly less than 36 L/min (10 gpm) 2 (Exelon 2014a).
3                        Figure 3-12. LSCS Site Hydrogeologic Units 4                            Source: Modified from Exelon 2014a 3-47
 
Affected Environment 1 The Pennsylvanian Aquitard is underlain by the Cambrian-Ordovician Aquifer, which is an 2 important aquifer in the region. Beneath the site, this aquifer is composed of the following strata 3 (listed from shallowest to deepest):
4
* Platteville Group, 5
* GlenwoodSt. Peter Sandstone, 6
* Potosi Dolomite, 7
* Franconia Formation, 8
* Ironton Sandstone, and 9
* Galesville Sandstone.
10 At the site, the Cambrian-Ordovician Aquifer is approximately 1,090 ft (469 m) thick. Although 11 numerous alternating layers of sandstones, limestone, and dolomites impart a heterogeneous 12 character to the system, these units are hydraulically connected and behave as a single aquifer 13 (Exelon 2014a). The Cambrian-Ordovician Aquifer is the most important supplier of public 14 water in the region.
15 The Cambrian-Ordovician Aquifer is underlain by 450 ft (137 m) of the Eau Claire Formation 16 Aquitard, which is underlain by 2,500 ft (762 m) of the Mt. Simon Aquifer. The Mt. Simon 17 Aquifer is underlain by granitic and metamorphic rock.
18 In addition to the hydrogeologic units previously described, the plant area is directly underlain by 19 engineered granular fill that has been placed on top of the Wedron Silty-Clay Till. The 20 engineered granular fill underlies and surrounds the plant buildings and structures. It is 21 composed of sand and gravel and silty clay and contains groundwater that is recharged by local 22 precipitation. Because the underlying Wedron Silty-Clay Till has a very low permeability, 23 groundwater in the granular fill flows laterally eastward until it discharges into the intake canal, 24 or it flows laterally and discharges to the stormwater ponds and the discharge canal to the west 25 (CRA 2006) (Figures 3-12 and 3-13).
26 3.5.2.2      Groundwater Use 27 LaSalle County has an adequate supply of groundwater to meet current needs for industrial, 28 municipal, and domestic purposes. Regionally, the most abundant groundwater supplies are 29 obtained from the Cambrian-Ordovician Aquifer (LaSalle County 2014).
30 At the site, water for potable usage is obtained from two cased onsite wells completed into the 31 Cambrian-Ordovician Aquifer. These wells were installed in 1972 and 1974 in the area of the 32 plant buildings. They were drilled to a depth of 1,620 and 1,629 ft (494 and 496 m) and cased 33 to a depth of 921 and 989 ft (281 and 301 m) (Exelon 2014a, 2014f; ISGS 2015). Together the 34 two wells withdraw groundwater at an average rate of 26.1 gpm (98.7 L/min) (Exelon 2014a).
3-48
 
Affected Environment 1 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill 2                Source: Modified from Exelon 2014a 3-49
 
Affected Environment 1                      Figure 3-14. LSCS Hydrogeologic Cross-Section 2                                  (Elevation Exaggerated) 3                              Source: Modified from CRA 2006 3-50
 
Affected Environment 1 Within 10 mi (16 km) of the LSCS site, almost all water used for public water supplies is 2 obtained from the Cambrian-Ordovician Aquifer. However, the Village of Ransom withdraws 3 water from both the Cambrian-Ordovician Aquifer and from permeable zones in the 4 Pennsylvanian Aquitard, and the Village of Grand Ridge obtains water from the Buried Bedrock 5 Valley Aquifers. People in small communities within 10 mi (16 km) of the LSCS site that are not 6 served by a public water supply system obtain water from individual wells in the glacial drift, the 7 Pennsylvanian strata, or the upper portion of the Cambrian-Ordovician Aquifer (Exelon 2014a).
8 3.5.2.3      Groundwater Quality 9 In general, the quality of groundwater in the Alluvial Aquifer, the Glacial Drift Aquitard, the 10 Buried Bedrock Valley Aquifers, the Pennsylvanian Aquitard, and the Cambrian-Ordovician 11 Aquifer is suitable for public use and consumption. A search of Illinois State Geological Survey 12 water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant 13 buildings. With the exception of one well completed in the Pennsylvanian Aquitard, all these 14 wells withdraw water from the Cambrian-Ordovician Aquifer (ISGS 2015).
15 In 1985, a condensate line broke in the area east-southeast of the LSCS reactor building.
16 Tritium was detected near the broken line in groundwater near the surface. The line was 17 repaired soon after it broke. In 1986, the highest tritium concentrations detected in the 18 groundwater was approximately 11,000 picocuries per liter (pCi/L). Tritium concentrations in the 19 groundwater near the broken line have declined to the point that, since 2007, tritium 20 concentrations in the groundwater have been below the lower limit of detection (Exelon 2014a; 21 Exelon Nuclear 2008, 2009, 2010, 2011, 2012, 2013, 2014, 2015).
22 In September 2001, a spill of water from a recycled condensate storage tank resulted in tritium 23 contamination into groundwater near the land surface. Tritium concentrations in the 24 groundwater ranged from 766 to 1,280 pCi/L in 2006 (Exelon 2014a; Exelon Nuclear 2007).
25 These concentrations are well below the EPA Maximum Contaminant Level for tritium of 26 20,000 pCi/L. In 2014, tritium concentrations in the groundwater had further decreased below 27 the lower limit of detection (Exelon Nuclear 2015).
28 Another leak from a recycled condensate tank was identified in 2010. The tank is located near 29 the plant buildings and is underlain by 10 ft (3 m) of engineered granular fill. In turn, the fill is 30 underlain by the Wedron Silty-Clay Till. Soon after the leak was detected, the tank was drained 31 and repaired. The leak contaminated groundwater in engineered granular fill with condensate 32 water that contained tritium. Contamination in the engineered granular fill is being addressed 33 through natural monitored attenuation and by active remediation. Exelon is pumping 34 contaminated groundwater from both a well and a French drain installed in the engineered 35 granular fill and then discharging the recovered water into the cooling pond where it is greatly 36 diluted to below the lower limit of detection (Exelon 2014a). Exelon has been monitoring the 37 cleanup of the engineered granular fill using monitor wells. In June 2015, samples from all of 38 the monitor wells recorded tritium concentrations below the EPA Maximum Contaminant Level 39 for tritium of 20,000 pCi/L (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015; Exelon 2015a, 40 2015c). Although the engineered granular fill has been contaminated with tritium and is being 41 cleaned up, it is not an aquifer. No aquifers are known to have been contaminated by 42 inadvertent releases of radionuclides to groundwater.
43 One nonradiological release to groundwater occurred in 1999 when an oil tank was discovered 44 to have leaked. The spill was remediated, and on February 9, 2005, IEPA issued a letter of No 45 Further Remediation for the cleanup activities (Exelon 2014a).
3-51
 
Affected Environment 1 3.6      Terrestrial Resources 2 3.6.1      LSCS Ecoregion 3 LSCS lies within the Illinois/Indiana Prairies Level IV Ecoregion. This ecoregion encompasses 4 19,557 mi2 (50,652 km2) in eastern and central Illinois and western Indiana (Woods et al. 2006).
5 It is composed of vast glaciated, flat to rolling plains with terminal and recessional moraines, 6 prairie potholes, and old lake beds. Historically, tallgrass prairie covered the majority of the land 7 surface. Oak-hickory forests were common on moraines and floodplains, and marshes and wet 8 prairies occurred in poorly drained areas. Beginning in the 19th century, agricultural land began 9 to replace the natural vegetation, and it is now the dominant land type (Woods et al. 2006).
10 Prairie remnants lack many natural ecosystem functions due to their small size, and areas of 11 prairie restoration often lack forbs (broad-leaved herbs other than grass) or are overly 12 dominated by big bluestem (Andropogon gerardii) (a grass) or Indiangrass (Sorghastrum 13 nutans) (IDNR 2005). Historically, forests were dominated by oak (Quercus spp.), hickory 14 (Carya spp.), elm (Ulmus spp.), ash (Fraxinus spp.), beech (Fagus spp.), and maple (Acer spp.)
15 species (CEC 2008). Remaining forests are highly fragmented and are experiencing species 16 composition shifts to sugar maple (A. saccharum) and other mesophytic species (IDNR 2005).
17 This shift is in part due to fire suppression, which has favored species that do not rely on 18 periodic fires as part of their life cycle (IDNR 2005). Many wetland areas have been drained for 19 row crops, and agriculture now accounts for over 75 percent of land use within this ecoregion 20 (IDNR 2005).
21 Table 3-8 lists representative wildlife for this ecoregion, as well as species that the Illinois 22 Department of Natural Resources (IDNR) considers to be critical to the conservation and 23 restoration of the regions native habitats; species that are indicative of ecosystem health 24 (known as indicator species); and species that are native to the region, but are now extirpated 25 or imperiled.
26 The IDNR maintains the Illinois Wildlife Action Plan (IDNR 2005), which addresses native 27 habitat and species decline and contains a statewide conservation plan.
28              Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion Wildlife representative of the ecoregion American black bear                eastern bluebird                  North American porcupine (Ursus americanus)                (Sialia sialis)                  (Erethizon dorsatum)
American redstart                  eastern chipmunk                  raccoon (Setophaga ruticilla)              (Tamias striatus)                (Procyon lotor) bobcat                            eastern gray squirrel            tree sparrow (Lynx rufus)                      (Sciurus carolinensis)            (Passer montanus)
Canada warbler                    gray fox                          white-footed mouse (Cardellina canadensis)            (Urocyon cinereoargenteus)        (Peromyscus leucopus) coyote                            indigo bunting                    white-tailed deer (Canis latrans)                    (Passerina cyanea)                (Odocoileus virginianus) 3-52
 
Affected Environment Wildlife critical to the conservation and restoration of the ecoregions native habitats American badger                          Henslows sparrow                        northern harrier (Taxidea taxus)                          (Ammodramus henslowii)                  (Circus cyaneus) eastern massasauga(a)                    Illinois chorus frog                    ornate box turtle (Sistrurus catenatus)                    (Pseudacris streckeri illinoensis)      (Terrapene ornata ornata) four-toed salamander                    Indiana bat(b)                          red squirrel (Hemidactylium scutatum)                (Myotis sodalis)                        (Sciurus vulgaris) gray bat(a)                              Kirtlands snake                        short-eared owl (Myotis grisescens)                      (Clonophis kirtlandii)                  (Asio flammeus)
Wildlife indicative of ecosystem health (indicator species) black rat snake                          eastern meadowlark                      prairie vole (Elaphe obsoleta obsoleta)              (Sturnella magna)                        (Microtus ochrogaster) black-capped chickadee                  great blue heron                        red-headed woodpecker (Poecile atricapillus)                  (Ardea herodias)                        (Melanerpes erythrocephalus) eastern box turtle                      horned lark                              red-tailed hawk (Terrapene carolina carolina)            (Eremophila alpestris)                  (Buteo jamaicensis) eastern kingbird                        prairie king snake                      tufted titmouse (Tyrannus tyrannus)                      (Lampropeltis calligaster                (Baeolophus bicolor) calligaster)
Extirpated or imperiled wildlife American bison                          Blandings turtle                        Franklins ground-squirrel (Bison bison)                            (Emys blandingii)                        (Poliocitellus franklinii)
(a) The  eastern massasauga is a candidate for listing under the Endangered Species Act of 1973, as amended (ESA), and the gray bat is listed as endangered under the ESA. While these species occur within the Illinois/Indiana Prairies Level IV Ecoregion, the FWS (2015d) indicates that they do not occur within the area that would be affected by the proposed LSCS license renewal.
(b) The Indiana bat is Federally listed as endangered under the ESA and is discussed in detail in Section 3.8.
Sources: CEC 1997; IDNR 2005; WIken et al. 2011 1 3.6.2          LSCS Site Surveys, Studies, and Reports 2 A number of vegetation and wildlife surveys have been conducted on the LSCS site beginning 3 with baseline surveys prior to LSCS construction in the early 1970s. This section summarizes 4 these surveys in chronological order.
5 Baseline Terrestrial Surveys (1971-1972) 6 In July and December 1971, and April, July, and October 1972, baseline ecological studies were 7 conducted at the LSCS site. The 1971 studies were primarily qualitative, and the 1972 studies 8 gathered quantitative data on vegetation, mammals, birds, reptiles, and invertebrates present on 9 the LSCS site. The ER for operation of LSCS (ComEd 1977) describes these studies and the 10 associated results in detail.
11 Final Environmental Statement for Construction (1973) 12 In February 1973, the U.S. Atomic Energy Commission (AEC), the NRCs predecessor agency, 13 issued a Final Environmental Statement that evaluated the construction of LSCS (FES-C) 14 (AEC 1973). Although no specific studies were conducted to support the preparation of the 3-53
 
Affected Environment 1 FESC, the report briefly summarizes the terrestrial wildlife and habitats on the site, including 2 those that were altered or destroyed during the construction of the cooling pond.
3 Terrestrial Monitoring during LSCS Construction (1974-1978) 4 Following the commencement of LSCS construction, ComEd commissioned NALCO 5 Environmental Sciences to conduct a 5-year monitoring program to evaluate the effects of 6 temporary and permanent ecological disturbances related to construction from 1974 7 through 1978. The ER for operation of LSCS (ComEd 1977) describes the results of the first 8 2 years of this monitoring.
9 Final Environmental Statement for Operation (1978) 10 In November 1978, the NRC issued a Final Environmental Statement that evaluated the 11 operation of LSCS (FES-O) (NRC 1978). The report includes updates to the terrestrial habitat 12 and wildlife information presented in the FES-C based on the 5 years of terrestrial monitoring 13 conducted during LSCS construction.
14 Wildlife Habitat Council Vegetation and Wildlife Surveys (2007) 15 In September 2007, Wildlife Habitat Council (WHC) biologists performed a baseline habitat 16 survey for the Wildlife at Work program. The survey results are documented in the LSCS 17 Wildlife Management Plan (Exelon 2013b).
18 LSCS Wildlife Habitat Team Monitoring (Ongoing) 19 The LSCS Wildlife Habitat Team conducts periodic wildlife surveys of the site in the spring 20 (April), summer (July), and fall (September) to monitor changes in wildlife communities and to 21 document any new species found on the site. Results of periodic surveys are collected in 22 Exelons Wildlife Management Plan (Exelon 2013b).
23 3.6.3      LSCS Site 24 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 25 Illinois. The cooling pond, generating facilities and associated infrastructure, and LaSalle Fish 26 Hatchery occupy the majority (66 percent) of the site. The remaining areas are undeveloped 27 and include the following terrestrial communities: forest, shrub-scrub, grassland, old-field, and 28 wetlands.
29 A cooling pond occupies the western side of the site and accounts for about half of the site area.
30 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 31 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac) 32 (Exelon 2015p). This industrial area is surrounded by about 142 ha (350 ac) of undeveloped 33 natural areas, including grassland, old field, schub-scrub, and small forested fragments 34 (Exelon 2015p).
35 3.6.3.1      Vegetation 36 Because the majority of the LSCS site is developed or occupied by the cooling pond, only small 37 areas of terrestrial habitat occur on the site. An open grassy area lies between the cooling pond 38 and the sites industrial area. This area is bounded on the north by the discharge canal and on 39 the south by the property boundary. Another grassy area lies to the southwest of the industrial 40 area. These two areas have a few scattered trees (Exelon 2014a).
41 The makeup and blowdown pipeline corridor extends north from the cooling pond to the Illinois 42 River and supports upland habitats, including shrub-scrub, forest, grassland, and old-fields, and 43 scattered wetlands. Common tree species in the upland forest areas, which comprise the 3-54
 
Affected Environment 1 majority of the corridor, include white oak (Quercus alba), red oak (Q. rubra), shagbark hickory 2 (Carya ovata), sugar maple, hop hornbeam (Ostrya virginiana), hawthorn (Crataegus spp.),
3 black cherry (Prunus serotina), and American elm (Ulmus americana) (Exelon 2014a). The 4 corridor widens as it approaches the Illinois River where it contains several small freshwater 5 emergent and freshwater forested/scrub wetlands. These wetlands are discussed in 6 Section 3.6.5.2.
7 3.6.3.2      Wildlife 8 Mammals 9 During the baseline terrestrial surveys in 1971 and 1972, 29 species of mammals were recorded 10 on the LSCS site. The most commonly observed mammals included raccoon (Procyon lotor),
11 mink (Mustela vison), red fox (Vulpes fulva), gray fox (Urocyon cinereoargenteus), gray squirrel 12 (Sciurus carolinensis), fox squirrel (Sciurus niger), beaver (Castor canadensis), muskrat 13 (Ondatra zibethicus), eastern cottontail (Sylvilagus floridanus), and white-tailed deer 14 (ComEd 1977). During the 2007 WHC baseline inventory of the LSCS site, coyote (Canis 15 latrans), beaver, opossum (Didelphis virginiana), groundhog (Marmota monax), striped skunk 16 (Mephitis mephitis), white-tailed deer, and gray squirrel were observed on the site (Exelon 17 2013b).
18 Birds 19 During the baseline terrestrial surveys in 1971 and 1972, 129 species of birds were recorded on 20 or near the LSCS site. Of these, 41 are considered permanent residents, 45 are summer 21 residents, 13 are winter residents, and 21 are transients (ComEd 1977). Permanent residents 22 included mallard (Anas platyrhynchos), black duck (A. rubripes), red-tailed hawk (Buteo 23 jamaicensis), red-shouldered hawk (Buteo lineatus), bald eagle (Haliaeetus leucocephalus),
24 bobwhite (Colinus virginianus), ring-necked pheasant (Phasianus colchicus), killdeer 25 (Charadrius vociferus), rock dove (Columba livia), mourning dove (Zenaida macroura), great 26 horned owl (Bubo virginianus), short-eared owl (Asio flammeus), saw-whet owl (Aegolius 27 acadicus), northern flicker (Colaptes auratus), red-bellied woodpecker (Melanerpes carolinus),
28 red-headed woodpecker (M. erythrocephalus), horned lark (Eremophila alpestris), blue jay 29 (Cyanocitta cristata), American crow (Corvus brachyrhynchos), black-capped chickadee 30 (Poecile atricapillus), northern mockingbird (Mimus polyglottos), eastern bluebird (Sialia sialis),
31 cedar waxwing (Bombycilla cedrorum), loggerhead shrike (Lanius ludovicianus), starling 32 (Sturnus vulgaris), and house sparrow (Passer domesticus) (ComEd 1977). During the 2007 33 WHC baseline inventory of the LSCS site, 15 species of birds were observed, all of which had 34 been previously recorded as occurring on the site during baseline surveys (Exelon 2013b).
35 Reptiles and Amphibians 36 No reptiles or amphibians were collected on the LSCS site in the 1971 baseline surveys 37 (ComEd 1977). In 1972, two Eastern plains garter snakes (Thamnophis radix radix) were 38 observed in pastureland near an intermittent stream (ComEd 1977). The 2007 WHC baseline 39 inventory did not include reptiles or amphibians.
40 3.6.4    LSCS Wildlife Management Plan 41 The LSCS Wildlife Management Plan (Exelon 2013b) outlines the goals and projects of LSCSs 42 Wildlife at Work program. Some of the plans past and planned wildlife habitat enhancement 43 and conservation activities at the LSCS site include:
44
* planting native vegetation, including swamp white oak (Quercus bicolor) near the 45            cooling pond, 3-55
 
Affected Environment 1
* controlling invasive common reed (Phragmites australis) near the cooling pond, 2
* enhancing existing habitat for grassland nesting birds through seeding, mowing, and 3              controlled burns, 4
* maintaining nesting boxes for eastern bluebirds, and 5
* installing osprey (Pandion haliaetus) platforms near the cooling pond 6              (Exelon 2014a).
7 Exelon (2015n), as a corporation, has been a member of the WHC since 2005, and Exelon first 8 received WHC certification for its Wildlife at Work program at LSCS in November 2011.
9 3.6.5      Important Species and Habitats 10 3.6.5.1      Important Species 11 State-Listed Species 12 The Illinois Endangered Species Protection Act of 1972, as amended, makes illegal the transfer, 13 sale, and possession of species (including skins and products) listed by the State as 14 endangered or threatened. The Act establishes an Endangered Species Protection Board, 15 which maintains a list of endangered and threatened species and advises the IDNR on the 16 conservation of those species.
17 Within LaSalle County, the IDNRs (2014b) Natural Heritage Database indicates that 18 28 State-listed terrestrial species (19 plants, 3 birds, 2 reptiles, 2 mammals, 1 insect, and 19 1 amphibian) occur in the county (see Table 3-9). In September 2013, Exelon generated an 20 IDNR Ecological Compliance Assessment Tool (EcoCAT) report that used Illinois Natural 21 Heritage Database information to further refine the list of State-listed species that could occur 22 on the LaSalle site and that could potentially be affected by the proposed license renewal. The 23 EcoCAT report is included in Appendix C of the applicants ER (Exelon 2014a). The report 24 indicates that there are no terrestrial State-listed species on or near the LSCS site that may be 25 affected by the proposed license renewal. In a May 2014 letter to Exelon, the IDNR (2014c) 26 confirmed that the EcoCAT report was accurate, and in its letter, the IDNR mentioned no 27 records of State-listed terrestrial species on or near the site. Federally protected species are 28 discussed in Section 3.8.
29                          Table 3-9. State-Listed Species in LaSalle County Common Name            Species Name                        Status(a)
Amphibians four-toed salamander    Hemidactylium scutatum                ST Birds cerulean warbler        Dendroica cerulea                      ST loggerhead shrike      Lanius ludovicianus                  SE upland sandpiper        Bartramia longicauda                  SE Insects regal fritillary        Speyeria idalia                        ST 3-56
 
Affected Environment Common Name                Species Name                                Status(a)
Mammals gray bat(b)                Myotis grisescens                              SE Indiana bat(b)              Myotis sodalis                                SE Plants American brooklime          Veronica americana                            SE bunchberry                  Cornus canadensis                              SE cliff goldenrod            Solidago sciaphila                              ST decurrent false aster(b)    Boltonia decurrens                              ST fibrous-rooted sedge        Carex communis                                  ST forked aster                Aster furcatus                                  ST golden corydalis            Corydalis aurea                                SE hairy woodrush              Luzula acuminata                              SE hemlock panic grass        Dichanthelium portoricense                    SE long beech fern            Phegopteris connectilis                        SE pink corydalis              Corydalis sempervirens                        SE plantain-leaved sedge      Carex plantaginea                              SE queen-of-the-prairie        Filipendula rubra                              SE red pine                    Pinus resinosa                                SE red-berried elder          Sambucus racemosa ssp. pubens                  SE shadbush                    Amelanchier sanguinea                          SE snowberry                  Symphoricarpos albus var. albus                SE spike                      Elliptio dilatata                              ST weak bluegrass              Poa languida                                  SE Reptiles blanding's turtle          Emydoidea blandingii                          SE timber rattlesnake          Crotalus horridus                              ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) These species are also Federally listed under the Endangered Species Act of 1973, as amended (ESA) and are discussed in detail in Section 3.8.
Source: IDNR 2014b 1 Although not listed as occurring in LaSalle County by the IDNR, Exelon (2014a) reports that it 2 has observed the State-threatened peregrine falcon (Falco peregrinus) on the LSCS site. A pair 3 of peregrine falcons nested on the roof of the auxiliary building several years ago. Exelon 4 (2014a) personnel have not observed peregrine falcon nesting in recent years, but personnel 3-57
 
Affected Environment 1 occasionally observe peregrines in flight on the site. The FES-O (NRC 1978) notes the 2 observance of a single peregrine falcon in November 1972 in an offsite woodland.
3 Bald Eagles 4 The bald eagle is protected under the Bald and Golden Eagle Protection Act (16 USC 668 5 et seq.). This Federal act prohibits anyone from taking or disturbing bald eagles or golden 6 eagles (Aquila chrysaetos), including their nests or eggs, without a U.S. Fish and Wildlife 7 Service (FWS)-issued permit. The bald eagle was observed near the LSCS site in April 1972, 8 on the rivers north-facing bluffs (ComEd 1977; NRC 1978). However, Exelon (2014a) is not 9 aware of bald eagle observations at the site in recent years.
10 3.6.5.2      Important Habitats 11 Illinois Natural Areas Inventory Sites 12 In its Illinois Natural Areas Inventory (INAI), the IDNR (2014a) identifies 28 LaSalle County sites 13 as Category I (high quality natural community and natural community restorations), Category II 14 (specific suitable habitat for state-listed species or state-listed species relocations),
15 Category III (State-dedicated Nature Preserves, Land and Water Reserves, & Natural Heritage 16 Landmarks), or a combination of the three categories. The 2013 EcoCAT report (contained in 17 Appendix D of the applicants ER (Exelon 2014a)) indicates that one of these sites with 18 terrestrial habitat lies near the LSCS site: Marseilles Hill Prairie.
19 The Marseilles Hill Prairie (INAI Site No. 1520) lies 3 mi (4.8 km) north of the LSCS main site 20 boundary (Exelon 2015o). It is 39.71 ac (16.07 ha) in size and managed by the IDNR (2014a) 21 to conserve prairie habitat. The IDNR (2014a) designates this INAI site as Category I.
22 State Parks and Wildlife Areas 23 The IDNR manages three areas for State parks or wildlife areas within 10 km (6 mi) of LSCS:
24 LaSalle Lake State Fish & Wildlife Area, Marseilles State Fish & Wildlife Area, and Illini State 25 Park. The LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling 26 pond that is managed by the IDNR and open to the public for fishing and other recreational 27 purposes (Exelon 2014a). The Marseilles State Fish & Wildlife Area is open to seasonal 28 hunting of turkey (Meleagris gallopavo), pheasant, quail, dove, deer, rabbit, squirrel, and coyote 29 (IDNR 2015e). Illini State Park provides habitat for a number deciduous trees, including hickory, 30 ash (Fraxinus spp.), walnut (Juglans spp.), elm, cottonwood (Populus deltoids), oak, and maple, 31 as well as white-tailed deer, eastern gray squirrels, opossums, beavers, raccoon, groundhogs, 32 and a variety of waterfowl and songbirds (IDNR 2015b).
33 Wetlands 34 The National Wetlands Inventory Wetlands Mapper identifies eight small areas of freshwater 35 emergent wetland and freshwater forested/scrub wetland on the LSCS site near the Illinois 36 River that total about 10 ac (4 ha) (FWS 2015e). Common tree species in the freshwater 37 forested/scrub wetland include American elm, black cherry, white oak, red oak, black oak, 38 shagbark hickory, bitternut hickory (Carya cordiformis), hackberry (Celtis occidentalis), elm, 39 willow (Salix spp.), and sycamore (Platanus occidentalis) (Exelon 2014a). The freshwater 40 emergent wetlands contain cattail (Typha spp.), horsetail (Equisetum spp.), and other 41 herbaceous vegetation (Exelon 2014a).
42 Managed Prairie Habitat 43 In partnership with Pheasants Forever, Inc., Exelon (2014a) actively manages 4 ha (10 ac) of 44 native prairie to the west of the cooling pond.
3-58
 
Affected Environment 1 3.6.6      Invasive and Non-Native Species 2 The invasive common reed inhabits parts of the cooling pond, particularly along the ponds 3 western edge. In 2007, as part of its Wildlife at Work program, Exelon (2014a) began an effort 4 to eradicate the species through mechanical harvesting and application of aquatic-safe 5 herbicides.
6 3.7      Aquatic Resources 7 The aquatic communities of interest for the LSCS site occur in the Illinois River and in the sites 8 artificial cooling pond. The Illinois River lies 5 mi (8 km) north of the site. It supplies makeup 9 water to LSCSs cooling system and receives cooling system blowdown. The cooling pond is 10 the sites main source of cooling water and is the plants UHS. Section 3.1.3 describes the 11 cooling system in detail, and Section 3.5.1 describes the surface water characteristics of the 12 Illinois River and the cooling pond.
13 The sections below describe the two main aquatic ecosystems at the LSCS site, the Illinois 14 River and the LSCS cooling pond (see Sections 3.7.1 and 3.7.2, respectively). In addition, 15 Section 3.7.3 describes State-listed species and important habitats and Section 3.7.4 describes 16 non-native species.
17 3.7.1      Illinois River 18 The Illinois River begins southwest of Chicago, at the confluence of the Des Plaines and 19 Kankakee Rivers. It flows south until it reaches the Mississippi River north of St. Louis, 20 Missouri. The total length of the Illinois River is approximately 322 mi (518 km) (IDNR 2011a).
21 The Illinois Rivers watershed drains a total of 29,010 mi2 (75,136 km2) from Illinois, Wisconsin, 22 and Indiana (IDNR 2011a). Major tributaries include the Des Plaines, Fox, Kankakee, 23 Vermilion, Mackinaw, Sangamon, Spoon, and La Moine rivers.
24 Prior to the 1800s, the Illinois River Basin was comprised of prairie savannas and oak-hickory 25 forests. The river provided diverse aquatic habitats including backwater lakes, side channels, 26 and a narrow main channel (USGS 1999a). The rapid expansion of agricultural activities 27 throughout the 1800s and early 1900s converted wet and mesic (relatively well drained) 28 floodplain prairies to crop lands. This land use conversion resulted in increased erosion, 29 sediment loading, and nutrient and herbicide transport to the Illinois River. Beginning in the 30 1900s, several efforts occurred to divert water from Lake Michigan and construct navigation 31 dams or levees to increase the navigability of the Illinois River to the Mississippi River and 32 provide a navigable passage from Chicago (Lake Michigan) to the Gulf of Mexico (USGS 33 1999a). As the population in Chicago continued to grow, sewage disposal and toxic waste 34 disposal further contributed to the degradation of aquatic habitat in the Illinois River (Parker 35 2014). By the 1960s, the biodiversity of fish within the upper Illinois River was low and 36 freshwater mussels were nearly absent (Sietman et al. 2001). Pollution tolerant, non-native 37 common carp (Cyprinus carpio) and goldfish (Carassius auratus) dominated fish populations 38 (Parker 2014). Since the passage of the CWA in 1974, water quality within the Illinois River has 39 improved and more diverse fish assemblages inhabit the upper Illinois River (Parker 2014).
40 Similarly, freshwater mussels have recolonized portions of the upper Illinois River since the 41 1980s (Sietman et al. 2001).
42 Currently, a series of locks and dams along the Illinois River continue to limit habitat connectivity 43 and fish passage along the Illinois River. Four of the locks and dams (Thomas J. OBrien, 44 Lockport, Brandon Road, and Dresden Island) are upstream of LSCS and four (Marseilles, 45 Starved Rock, Peoria, and LaGrange) are downstream (USACE 1998). The closest locks and 3-59
 
Affected Environment 1 dams to LSCS include the Dresden Island Lock and Dam, 22 mi (26 km) upstream of the LSCS 2 intake, and the Marseilles Lock and Dam, 2.4 mi (3.5 km) downstream of the LSCS discharge 3 (USACE 1998; Exelon 2015c).
4 In 2005, IEPA most recently classified the water quality within the Illinois River as fair, which 5 means that the water quality has been impaired, and the water body meets the needs of a 6 designated use most of the time (IDNR 2011a). Current factors that continue to contribute to 7 the degradation of the Illinois River include the increase in invasive fish, accumulated 8 sediments, continued sedimentation, and agricultural chemical runoff (USGS 1999a; 9 Parker et al. 2005).
10 3.7.1.1      Aquatic Communities in the Illinois River 11 Plankton 12 Plankton are small organisms that float or drift in rivers and other water bodies. Plankton is a 13 primary food source for many whales, fish, and other animals, and consists of bacteria, 14 protozoans, certain algae, tiny crustaceans such as copepods, and many other organisms.
15 ComEd, the previous owner of LSCS, conducted surveys for plankton within the Illinois River 16 both upstream and downstream of the LSCS discharge and river intake structures. ComEd 17 initially sampled plankton prior to operations, from August 1972 through January 1973, and 18 again during construction, from February 1974 through November 1976. These studies are 19 summarized in the Final Environmental Statement for Operations of LSCS (NRC 1978).
20 Phytoplankton. Phytoplankton are microscopic floating photosynthetic organisms that form 21 one base of aquatic food webs by producing biomass from inorganic compounds and sunlight.
22 As primary producers, phytoplankton play key ecosystem roles in the distribution, transfer, and 23 recycling of nutrients and minerals.
24 Diatoms were the most abundant phytoplankton in the Illinois River near LSCS in the 1970s, 25 and reached peak densities in August (NRC 1978). The most common diatom genera included 26 Cyclotella, Melosira, and Stephanodiscus. The NRC staff noted that many of the diatoms 27 collected in preoperational studies were pollution tolerant (NRC 1978). Other phytoplankton 28 followed similar trends with primary production peaking in August and dipping in winter months.
29 The NRC staff is not aware of any additional phytoplankton surveys that have been conducted 30 in the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.
31 Periphyton. Periphyton includes a mixture of algae, cyanobacteria (in the past often called 32 blue-green algae), heterotrophic microbes, other small organisms, and detritus that attach to 33 submerged surfaces. Like phytoplankton, periphyton are primary producers and provide a 34 source of nutrients to many bottom-feeding organisms.
35 During ComEds initial study prior to construction, diatom densities upstream of the LSCS 36 discharge and intake areas accounted for 75 percent of the total periphyton density in 37 August 1972 and 100 percent in January 1973. The next dominant taxa was green algae, which 38 accounted for 7 percent of the total periphyton density in 1972 and none of the total periphyton 39 density in 1973. Downstream of the LSCS discharge and intake, diatom densities accounted for 40 94 percent of the total periphyton density in August 1972 and 92 percent in January 1973, while 41 the green algae accounted for 1 percent in 1972 and none in 1973 (NRC 1978). Diatoms were 42 the dominant periphyton group during the warmer months (May, August, and November),
43 whereas green algae was dominant during February from 1974 to 1976 (NRC 1978). Dominant 44 diatom genera included Cyclotella, Navicula, and Nitzschia; dominant green algae genera 45 included Stigeoclonium, Cladophora, Rhizoclonium, and Ulothrix (NRC 1978).
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Affected Environment 1 The NRC staff is not aware of any additional periphyton surveys that have been conducted in 2 the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.
3 Zooplankton. Zooplankton are small animals that float, drift, or weakly swim in the water column 4 and include ichthyoplankton (fish eggs and larvae) with no or limited swimming ability and larvae 5 of benthic invertebrates. Zooplankton are important trophic links between primary producers 6 (e.g., phytoplankton and periphyton) and carnivores (e.g., fish).
7 During preoperational studies, copepods and rotifers dominated zooplankton samples both prior 8 to and during construction (NRC 1978). Dominant copepod genera included Cyclops and 9 Eucyclops, and dominant rotifer genera included Asplanchna, Brachionus, Filinia, Notholca, 10 Polyarthra, and Synchaeta (NRC 1978). Peak densities for both copepods and rotifers 11 generally occurred in August, and minimum densities generally occurred in February.
12 In 2014, EA Engineering, Science, and Technology, Inc. (EA) (2015) collected icthyoplankton 13 samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected 14 samples using 0.5-m (1.6-ft) conical plankton nets with 505-&#xb5;m mesh suspended from the 15 forebay bridge in front of the river intake (see Figure 3-15). EA (2015) collected samples during 16 the 2014 spawning season, from late April through August, when icthyoplankton densities would 17 likely be highest.
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Affected Environment 1      Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure 2                  Key: LSCS: LaSalle County Station; RSH: River Screen House 3                                          Source: EA (2015) 4 EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 5 27 distinct taxa. The most common taxa included carps, minnows, and suckers, which 6 combined comprised 79 percent of the number of organisms within ichthyoplankton sample.
7 EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was 8 not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles.
9 The most common taxa by life stage included Ictiobinae (buffalo fish) yolk-sac larvae 10 (24 percent), cyprinidae (carps and minnows) yolk-sac larvae (23 percent), and common carp 11 yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent 12 of the icthyoplankton samples (EA 2015).
13 Benthic Macroinvertebrates 14 Benthic macroinvertebrates include aquatic annelids (e.g., aquatic worms or oligochaetes, 15 leeches), mollusks, crustaceans, and insect larvae that inhabit aquatic sediments and 16 submerged surfaces. They accelerate detrital decomposition and nutrient cycling, and serve as 3-62
 
Affected Environment 1 a food source for fish and other aquatic biota. ComEd, Exelon, and their contractors sampled 2 benthic invertebrates during three time periods: preoperational studies from February through 3 November, 1972 through 1976 (as summarized in NRC 1978); a 1999 study in response to low 4 flow and high air temperatures (EA 2000); and a 2013 study in preparation for Exelons license 5 renewal application (EA 2014).
6 During the preoperational and the 2013 study, ComEd and Exelon sampled benthic 7 macroinvertebrates at one location upstream of the river intake and blowdown discharge 8 (location 1), at one location immediately downstream of the blowdown discharge (location 2),
9 and at two locations further downstream of the blowdown discharge (locations 3 and 4) (Figure 10 3-16). ComEd and Exelon sampled each location with a Hester-Dendy artificial substrate 11 sampler and a Ponar grab sampler (NRC 1978; EA 2014).
12 In 1999, Exelon also collected benthos using a Ponar grab at one site upstream and one site 13 downstream of the blowdown discharge, similar to the sampling sites for the preoperational and 14 2013 study. In addition, EA collected benthos using a Ponar grab at a second downstream site 15 that was further downstream than South Kickapoo Creek (EA 2000).
16                  Figure 3-16. Sampling Locations in LSCS Aquatic Surveys 17                                          Source: EA 2014 18 Collections during preoperational studies resulted in the identification of 143 taxa (NRC 1978).
19 Chironomidae and Oligochaeta were the most dominant groups. The most common 20 oligochaete genera were Limnodrilus and Nais. The most abundant chironomid genera 21 included Cryptochironomous, Dicrotendipes, Procladius, Cricotopus, and Orthocladius.
22 EA (2000) collected a total of 34 taxa from Ponar grab samples. Chironomidae and Oligochaeta 23 were the most taxa-rich groups, with 12 taxa each. EA (2000) determined that the dominant 24 taxa at all sampling sites are considered tolerant to poor water quality. Both total richness and 25 the number of Ephemeroptera, Plecoptera, and Trichoptera species, which are considered 26 intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) 27 compared to upstream (location 1) of the intake and discharge structures.
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Affected Environment 1 EA (2014) collected a total of 61 taxa from the Hester-Dendy artificial substrate collections.
2 Chironomidae was the most taxa rich group with 21 taxa followed by Ephemeroptera and Bivalvia, 3 with 8 taxa each. The dominant taxa from the Hester-Dendy collections included the following 4 insect larvae: Dicrotendipes modestus (a non-biting midge), Maccaffertium integrum (a mayfly),
5 Cyrnellus fraternus (a caddisfly), and Dicrotendipes neomodestus. Among the 10 most dominant 6 taxa for the Hester-Dendy artificial substrate samples, only one taxon is considered tolerant of 7 environmental degradation, Glyptotendipes (IEPA 1987; EA 2014). The remaining taxa are 8 considered facultative to slightly intolerant to poor water quality (IEPA 1987; EA 2014).
9 For the Ponar grab samples, Chironomidae was the most taxa rich group with 15 taxa, followed 10 by 8 Bivalvia and 4 Ephemeroptera taxa. EA (2014) observed the highest taxa richness at 11 locations 1 and 3 (20 to 29 taxa) as compared to locations 2 and 4 (16 to 27 taxa). Species 12 richness among pollution sensitive Ephemeroptera, Plecoptera, and Trichoptera was similar 13 among all locations, ranging from three to five taxa (EA 2014). At all sampling sites, EA (2014) 14 observed dominant taxa that were relatively tolerant to poor water quality as well as dominant 15 taxa that were relatively intolerant or facultative to poor water quality.
16 Fish 17 ComEd, Exelon, and their contractors sampled fish near LSCS during three time periods:
18 preoperational studies from May through November, 1972 through 1976 (as summarized in 19 NRC 1978); a post-operational study in response to low flow and high air temperatures in July 20 through October, 1999 (EA 2000); and a post-operational study in August 2013 in preparation 21 for Exelons license renewal application (EA 2014).
22 During both the preoperational and 2013 study, Exelon sampled fish at one location upstream of 23 the river intake and blowdown discharge (location 1) and at two locations downstream of the 24 blowdown discharge (locations 2 and 5), one of which was South Kickapoo Creek 25 (Figure 3-16). Exelon sampled fish at each sampling site by electrofishing in a downstream 26 direction for 500 m (1,640 ft). In addition, Exelon seined for fish along the shoreline at all three 27 locations using a 25-ft (8-m) long by 6-ft (2-m) deep seine with 0.19- in. (0.48-cm) mesh.
28 Exelon hauled the seine along 15 m (49 ft) of shoreline in a downstream direction.
29 In 1999, EA also electrofished at one site upstream and one site downstream of the blowdown 30 discharge, similar to the sampling sites for the preoperational and 2013 study. In addition, EA 31 electrofished at second downstream site that was further downstream than South Kickapoo 32 Creek (EA 2000).
33 All three studies looked for external parasites or other abnormalities. EA (2000 and 2014) 34 specifically examined all fish for external DELT (deformities, erosions, lesions, or tumors) 35 anomalies.
36 During the preoperational monitoring period, NRC (1978) determined that the most dominant 37 species included emerald shiner (Notropis atherinoides), gizzard shad (Dorosoma cepedianum),
38 common carp, green sunfish (Lepomis cyanellus), bluntnose minnow (Pimephales notatus), and 39 white sucker (Catostomus commersonii) (see Table 3-10). Prior to operations, downstream 40 collection stations generally had lower species abundance and higher species diversity than 41 upstream stations (NRC 1978). The NRC (1978) concluded that the low species abundance 42 and diversity, low condition factors, and the degree of external parasitism and physical damage 43 of the fishes in this area of the Illinois River were indicative of a poor quality aquatic 44 environment. Barge traffic, habitat alteration, and heavy pollution loads contributed significantly 45 to the poor water quality in the Illinois River near LSCS, which primarily supported populations 46 of pollution-tolerant fish in the 1970s (NRC 1978).
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Affected Environment 1 During the 1999 survey, EA (2000) collected 27 species and 1 hybrid for a total of 960 fish. The 2 most commonly collected fish species included gizzard shad (24 percent), smallmouth buffalo 3 (Ictiobus bubalus) (12 percent), spotfin shiner (Cyprinella spiloptera) (10 percent), green sunfish 4 (9 percent) and bluegill (Lepomis macrochirus) (8 percent) (Table 3-10). EA (2000) observed a 5 total of 63 fish (6.6 percent of the catch) with DELT anomalies. Channel catfish (Ictalurus 6 punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest 7 DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin 8 erosion (52 percent) and deformities (38 percent).
9 During the 2013 study, EA (2014) collected 12 fish species for a total of 1,295 fish. The most 10 commonly collected species during electrofishing included gizzard shad (48 percent), spotfin 11 shiner (16.5 percent), smallmouth buffalo (6 percent), golden redhorse (Moxostoma erythrurum) 12 (5 percent), smallmouth bass (Micropterus dolomieu) (4 percent), and freshwater drum 13 (4 percent; EA 2014) (Table 3-10). Gizzard shad dominated samples both upstream and 14 downstream of the intake and discharge (EA 2014). The most commonly collected species 15 during seining surveys included emerald shiner (83 percent), spotfin shiner (9.5 percent),
16 bluntnose minnow (2 percent), and sand shiner (Notropis stramineus) (2 percent) (EA 2014) 17 (Table 3-10). Emerald shiner dominated samples both upstream and downstream of the intake 18 and discharge (EA 2014). EA (2014) observed DELT anomalies on 2 of the 1,295 fish collected 19 (0.2 percent), both of which were eroded fins on freshwater drum. EA (2014) did not observe 20 any external parasites or other abnormalities.
21        Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River Commonly Collected Species(d)
Species                    Common Name                1974-1976(a)    1999(b)        2013(c)
Cyprinidae Cyprinella spiloptera      spotfin (spottail) shiner      X          X                X Cyprinus carpio            common carp                    X Notropis atherinoides      emerald shiner                  X          X                X Notropis stramineus        sand shiner                                                  X Pimephales notatus          bluntnose minnow                X                            X Pimephales vigilax          bullhead minnow                X                            X Centrarchidae Lepomis cyanellus          green sunfish                  X          X Lepomis macrochirus        bluegill                                    X Catostomidae Catostomus commersoni      white sucker                    X Ictiobus bubalus            smallmouth buffalo                          X                X Micropterus dolomieu        smallmouth bass                                              X Moxostoma erythrurum        golden redhorse                                              X Atherinopsidae Labidesthes sicculus        brook silverside                                              X Clupeidae Dorosoma cepedianum        gizzard shad                    X          X                X 3-65
 
Affected Environment Commonly Collected Species(d)
Species                          Common Name                      1974-1976(a)        1999(b)            2013(c)
Sciaenidae Aplodinotus grunniens            freshwater drum                                                            X (a) NRC 1978 (b) EA 2000 (c) EA 2014 (d) X= one of the sixth most commonly collected species, based on the number of individuals collected during electrofishing or seining sampling within a single time period. Note that a species may still have been observed during the collection period even if it was not one of the sixth most commonly collected species.
Sources: NRC 1978; EA 2000, 2014 1 Common carp and white sucker were commonly collected during preoperational studies but 2 were not commonly collected during the 1999 or 2013 study. Ohio EPA (1987) classifies both of 3 these species as pollution tolerant. Brook silverside (Labidesthes sicculus), freshwater drum, 4 sand shiner, smallmouth bass, smallmouth buffalo, golden redhorse, and bluegill were among 5 the commonly collected species in the 1999 or 2013 studies but were not commonly collected in 6 the preoperational studies. Five of these seven species (brook silverside, sand shiner, 7 smallmouth bass, golden redhorse, and bluegill) are native species that are sensitive to declines 8 in water quality or habitat degradation (Lerczak 1996; Smith 2002).
9 These results are consistent with other fish surveys (Lerczak 1996; McClelland et al. 2012) 10 within the upper Illinois River that since the mid-1950s through 1990s and the 2000s, show a 11 decline in fish species that are tolerant of poor water quality and an increase in fish species that 12 are sensitive to habitat degradation. For example, Lerczak (1996) examined fish population 13 data from the Illinois Natural History Survey (INHS), which began monitoring fish populations in 14 the Illinois River in 1957. Since 1957, INHS conducted annual electrofishing surveys at set 15 locations throughout the entire Illinois River, including sampling locations approximately 1 RM 16 downstream of the LSCS river intake, within the vicinity of the LSCS river intake, and 11 RM 17 upstream of the LSCS river intake. Within the upper 50 mi (80 km) of the Illinois River, which 18 includes LSCS, Lerczak (1996) concluded that common carp, which is pollution tolerant, has 19 become less common while bluegill, which is intolerant to degraded habitats, has become more 20 common. For example, in the 1960s, INHS captured an average of 35 common carp per hour 21 as compared to 6 common carp per hour in the 1990s. Bluegill increased from averages of less 22 than 1 per hour in the 1960s to 12 per hour in the 1990s. Lerczak (1996) also noted that in the 23 1990s, fish communities were more evenly distributed among a greater number of species than 24 in the 1960s. For example, in 1962 and 1963, four species comprised 95 percent of all catches:
25 gizzard shad, emerald shiner, common carp, and goldfisha species with pollution tolerance 26 similar to common carp. In 1995, 10 species comprised 95 percent of all catches including 27 several species that are sensitive to habitat degradation, such as the bluegill, largemouth bass 28 (Micropterus salmoides), and several species of small minnows.
29 McClellan et al. (2012) also examined fish populations during three time periods from 1957 30 through 2009 based on INHS data. Table 3-11 describes the species that contributed to 31 approximately 90 percent of all electrofishing catches in the Illinois River (McClelland 32 et al. 2012). The NRC staff further classified fish as either pollution tolerant or intolerant. In 33 addition, the NRC staff determined whether McClelland reported increases or decreases in the 34 relative abundance of each species over time. The NRC staff notes that these general trends 35 were not assessed using regression analyses or other statistical analyses. The most common 3-66
 
Affected Environment 1  species during the 1957 through 1969 surveys (common carp, gizzard shad, emerald shiner, 2  and goldfish) are considered pollution tolerant species and the relative abundance of these 3  species has generally declined over time. All pollution intolerant species listed in 4  Table 3-11 have generally increased overtime. These data suggest that water quality within the 5  Illinois River has improved over time, allowing species that are pollution sensitive to increase in 6  relative abundance.
7    Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural History 8                                Electrofishing Surveys from 1957 through 2009 Species(a)                      Common Name                  1957-1969        1970-1989        1990-2009        Trend(c)
Pollution Tolerant Species(b)                                                      Percent of Catch Cyprinus carpio                  common carp                      24.9              16.4              7.6 Dorosoma cepedianum gizzard shad                                  20.4              23.0            16.2 Notropis atherinoides            emerald shiner                  19.3              10.7            10.6 Carassius auratus                goldfish                          6.6              2.2              -
Cyprinus carpio x                common carp x goldfish            3.0              -                -
Carassius auratus Lepomis cyanellus                green sunfish                      2.4              6.3              5.3 Ictiobus cyprinellus            bigmouth buffalo                  1.8              1.8              1.3 Ameiurus melas                  black bullhead                    1.4              -                -
Pimephales vigilax              bullhead minnow                    -                -                2.9 Pimephales notatus              bluntnose minnow                    -                -                2.3 Lepomis humilis                  orangespotted sunfish              -                -                1.2 Aplodinotus grunniens            freshwater drum                    -              3.8              4.8 Pollution Intolerant Species(b)                                                    Percent of Catch Lepomis macrochirus              bluegill                          2.8              6.2            13.1 Micropterus salmoides            largemouth bass                    2.2              5.1              6.4 Pomoxis nigromaculatus          black crappie                      1.8              4.2              2.9 Ictalurus punctatus              channel catfish                    -                3.5              5.6 Morone chrysops                  white bass                          -                2.9              2.8 Micropterus dolomieu            smallmouth bass                    -                -                1.4 Notes: (-) = Fish species not part of 90 percent of the catch during specified time period (a) Species ordered by decreasing relative abundance based on McClelland et al 2012; species contributed to approximately 90 percent of all electrofishing catches in the Illinois River and could be classified as either pollution tolerant or intolerant.
(b) Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015.
(c) Inclines or declines in the relative abundance of each species are general trends; the NRC staff did not evaluate these trends using regression analyses or other statistical analyses.
Sources: Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015; McClelland et al. 2012 9  3.7.2        LSCS Cooling Pond 10  As described in Section 3.5, the 2,058-ac (833-ha) cooling pond was created in 1978 by 11  pumping water from the Illinois River into the excavated pond. Exelon leases a large portion of 12  the LSCS cooling pond to the IDNR, which maintains the LSCS cooling pond as an outdoor 3-67
 
Affected Environment 1 recreation area for public use and fishing. IDNR has actively managed the LSCS cooling pond 2 since 1984 (Exelon 2014a). For example, IDNR surveys the cooling pond each year and 3 determines which fish to stock based on fishermen preferences, fish abundance, different 4 species tolerance to warm waters, predator and prey dynamics, and other factors (Exelon 2002, 5 2014a, 2015a). The cooling pond can be characterized as a highly managed ecosystem in 6 which IDNR fish stocking and other human activities primarily influence the species composition 7 and population dynamics.
8 3.7.2.1        Aquatic Community in the Cooling Pond 9 IDNR stocks the LSCS cooling pond each year. In 1981, IDNRs fish hatchery located adjacent 10 to the cooling pond started operations, at which point IDNR started stocking the cooling pond 11 with species from the hatchery (EA 2002). Initially, IDNR stocked the LSCS cooling pond with 12 largemouth bass and bluegill (EA 2002).
13 Currently, commonly stocked species include largemouth bass, smallmouth bass, black crappie 14 (Pomoxis nigromaculatus), white crappie (Pomoxis annularis), channel catfish, blue catfish 15 (Ictalurus furcatus), striped bass hybrid (Morone saxatilis x M. chrysops), walleye (Sander 16 vitreus), and bluegill (See Table 3-12; Exelon 2002 and 2015a). Because of the high water 17 temperatures experienced in the summer months, introductions of warm-water species, such as 18 largemouth bass and blue catfish, have been more successful than introductions of cool-water 19 species, such as walleye and tiger muskellunge.
20 In addition to the stocked species, gizzard shad and threadfin shad (Dorosoma petenense) 21 together called shadalso occur in the cooling pond. Shad are not recreationally fished, and 22 IDNR does not currently stock these fish. IDNR stocks some recreationally fished species that 23 consume shad (e.g., catfish and striped bass) in part to limit the size of shad populations 24 (Exelon 2002).
25                  Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 Common                                                              Annual Species(a)          Name            2008  2009    2010      2011  2012  2013    2014  Average Percent Lepomis            bluegill      55,466 11,740 84,661 364,731 73,681    25,031 100,130 102,206  40%
macrochirus Micropterus        largemouth 66,395 51,207 50,434 30,470 84,166        48,753  2,660  47,726  19%
salmoides          bass Morone saxatilis striped          80,889 68,404 41,284 52,642        0  20,580 26,047  48,308  19%
hybrid              bass hybrid Ictalurus          blue catfish 18,560 34,452 19,800 23,368          0    0    18,200  22,876  9%
furcatus Micropterus        smallmouth 25,365 21,155 21,118 22,733 20,683        22,354 20,582  21,999  9%
dolomieu            bass Lepomis            redear        34,151    0    4,830      4,830  0    0          0 14,604  6%
microlophus        sunfish (a) Species are ordered by relative abundance (highest to lowest).
Sources: Exelon 2014a; IDNR and Exelon 2014 and 2015 3-68
 
Affected Environment 1 3.7.2.2      Cooling Pond Fish Kill Events 2 LSCS has had four reportable fish kills in the cooling pond since 2001, including fish kills in 3 July 2001, June 2005, June 2009, and August 2010 (Exelon 2014a, 2015a). The temperature in 4 the cooling pond during these events ranged from 93 &deg;F (33.9 &deg;C) to 101&deg;F (38.3 &deg;C) 5 (Exelon 2001, 2009, 2010). In addition, several smaller non-reportable fish kills have occurred 6 when the cooling pond was 95 &deg;F (35 &deg;C) or above (Exelon 2015c). Exelon attributes these fish 7 kills to high cooling pond temperatures as a result of high summer temperatures combined with 8 low winds and high humidity, as described below (Exelon 2001, 2009, 2010).
9 The largest fish kill occurred in July 2001 when IDNR reported approximately 94,500 dead fish 10 due to high temperatures that peaked at 98.2 &deg;F (36.9 &deg;C) (Exelon 2001). IDNR found the 11 maximum temperature in the cooling pond discharge canal to be 120 &deg;F (48.9 &deg;C) and dissolved 12 oxygen levels to range from 6.2 to 18.8 parts per million. The majority of dead fish (96 percent) 13 were gizzard shad (90,800) (Exelon 2001). IDNR identified other dead fish to include 14 1,279 carp, 1,143 smallmouth buffalo, 610 freshwater drum, 345 channel catfish, 238 striped 15 bass hybrid, 93 smallmouth bass, 24 walleye, 13 bluegill, 12 white bass (Morone chrysops),
16 6 yellow bullhead catfish (Ameiurus natalis), and 4 yellow bass (M. mississippiensis) 17 (Exelon 2001).
18 In a June 2005 fish kill, IDNR counted 1,515 dead fish, including 1,439 striped bass hybrids 19 (95 percent), 36 smallmouth bass (2 percent), 20 walleye (1 percent),11 channel catfish (less 20 than 1 percent), 4 blue catfish (less than 1 percent), 3 yellow bass (less than 1 percent), and 21 2 sauger (less than 1 percent) (Exelon 2015c). The LSCS cooling pond peaked at 95 &deg;F (35 &deg;C) 22 during the fish kill (Exelon 2015c).
23 In the June 2009 fish kill, 3,000 to 4,000 gizzard shad comprised 99 percent of the dead fish 24 shad (Exelon 2009). Exelon (2009) also observed 26 smallmouth bass, 4 striped bass, and 25 4 walleye. Immediately prior to and during the fish kill, the LSCS cooling pond increased 10 &deg;F 26 from 83 &deg;F (28 &deg;C) on June 20 to 93 &deg;F (34 &deg;C) on June 23.
27 In the August 2010 fish kill, IDNR concluded that over 90 percent of the dead fish were small 28 threadfin and gizzard shad less than 3 in. (8 cm) long (Exelon 2010). IDNR also observed dead 29 carp, striped bass hybrids, walleye, and smallmouth bass (Exelon 2010). The LSCS cooling 30 pond peaked at 101.3 &deg;F (38.5 &deg;C) the day before the fish kill.
31 3.7.3      Important Species and Habitats 32 3.7.3.1      State-Listed Species 33 IDNR lists 35 fish and 26 mussel species as State-endangered or threatened (IDNR 2015a). Of 34 these, IDNR (2014b) indicates that 7 species (5 fish, 2 mussels) occur in LaSalle County (see 35 Table 3-13).
3-69
 
Affected Environment 1    Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle County Recorded Occurrences Near LSCS LSCS River Intake(d)
Starved Rock or Preoperational Studies (b)      Marseilles Pool(c)
Species                                  Common Name                      State Status(a)
Fish Fundulus diaphanous                      banded killifish                        ST                                  x                  x Moxostoma carinatum                      river redhorse                          ST Moxostoma valenciennesi                  greater redhorse                        SE Notropis heterolepis                    blacknose shiner                        SE Notropis texanus                        weed shiner                            SE Mussels Alasmidonta viridis                      slippershell                            ST Elliptio dilatata                        spike                                  ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) NRC  1978 (c) McClelland and Sass 2007; Fritts 2013 (d) EA 2014, 2015; Exelon 2015c, 2015p Sources: NRC 1978; IDNR 2014b; McClelland and Sass 2007; Fritts 2013; EA 2014, 2015; Exelon 2014a, 2015a 2  Banded killifish. Banded killifish occur in clear glacial lakes, streams, or tributaries, often near 3  vegetation (Nyboer et al. 2006). This fish forms small schools near the surface of weedy lakes 4  (Nyboer et al. 2006). In recent years, this species has been documented in the Illinois River 5  (McClelland and Sass 2007; McClelland et al. 2012). In 2006, the INHS collected two banded 6  killifish at RM 241.5 in the Starved Rock Pool sampling area, approximately 8 RM (13 Rkm) 7  downstream of the LSCS river intake (McClelland and Sass 2007). However, from 1993 8  through 2012, the INHS did not observe banded killifish in the Marseilles Pool sampling area, 9  which included sampling locations approximately 1 RM (1.6 Rkm) downstream of the LSCS river 10  intake, within the vicinity of the LSCS river intake, and 11 RM (18 Rkm) upstream of the LSCS 11  river intake (Fritts 2013).
12  In 2014, EA (2015) collected a juvenile banded killifish during an impingement and entrainment 13  study at the LSCS river intake. In response to this collection, Exelon noted that EA Engineering 14  intends to request a scientific collectors permit report from IDNR. This species was not 15  collected during preoperational surveys (NRC 1978) or during operational studies in 1999 and 16  2013 (EA 2000, 2014).
17  River Redhorse. The river redhorse inhabits large river systems, including impoundments and 18  pools, in areas of moderate to swift current and clean gravel substrate (NatureServe 2014a).
19  Barbour et al. (1999) classify this species as an insectivore that is intolerant of pollution and 20  other environmental stressors. INHS electrofishing surveys that began in 1957 have 21  documented this species in the Illinois River (McClelland and Sass 2007). However, from 1993 3-70
 
Affected Environment 1 through 2012, INHS did not observe river redhorse in the Marseilles Pool sampling area, which 2 included sampling locations approximately 1 RM (1.6 RKm) downstream of the LSCS river 3 intake, within the vicinity of the LSCS river intake, and 11 RM (18 RKm) upstream of the LSCS 4 river intake (Fritts 2013). The river redhorse was not collected during preoperational surveys 5 (NRC 1978) or operational surveys in 1999 and 2013 (EA 2000, 2014). From 2013 through 6 2015, EA (2015) conducted an impingement and entrainment study near the LSCS river intake.
7 Although EA (2015) collected several Moxostoma fish that were not identified to species, EA 8 (2015) concluded that these species were most likely the more common Moxostoma spp., such 9 as shorthead, golden, silver, and black redhorse, given that these common species were 10 conclusively identified during the study.
11 Greater Redhorse. The greater redhorse inhabits lakes and large rivers with sandy to rocky 12 pools (Nyboer et al. 2006). This fish was considered extirpated in Illinois until it was observed in 13 the upper Illinois River basin in 1985 (Nyboer et al. 2006). IDNR (2014) recorded three 14 observations of this species in LaSalle County, most recently in July 2004. This species is rare 15 in the Illinois River, and INHS did not observe this species from 1957 through 2006 at any 16 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 17 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 18 (EA 2000, 2014), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 19 1993 through 2012 (Fritts 2013). From 2013 through 2015, EA (2015) conducted an 20 impingement and entrainment study near the LSCS river intake. Although EA (2015) collected 21 several Moxostoma fish that were not identified to species, EA (2015) concluded that these 22 species were most likely the more common Moxostoma spp., such as shorthead, golden, silver, 23 and black redhorse given that these common species were conclusively identified during the 24 study.
25 Blacknose shiner. The blacknose shiner inhabits clear vegetated lakes, and pools and runs of 26 clear streams (Nyboer et al. 2006). Increased turbidity and decreases in aquatic vegetation 27 have contributed to the decline of this species (Nyboer et al. 2006). IDNR (2014) recorded two 28 observations of this species in LaSalle County, most recently in October 2013. This species is 29 rare in the Illinois River and INHS did not observe this species from 1957 through 2006 at any 30 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 31 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 32 (EA 2000, 2014), an impingement and entrainment study at the LSCS river intake from 2013 33 through 2015 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling 34 area from 1993 through 2012 (Fritts 2013).
35 Weed shiner. In Illinois, the weed shiner inhabits clear sand-bottom creeks with some 36 submerged vegetation (Nyboer et al. 2006). IDNR (2014) recorded one observation of this 37 species in LaSalle County, most recently in October 2013. This species is rare in the Illinois 38 River and INHS did not observe this species from 1957 through 2006 at any sampling station in 39 the Illinois River (McClelland and Sass 2007). This species was not collected during 40 preoperational surveys (NRC 1978), operational studies in 1999 and 2013 (EA 2000, 2014), an 41 impingement and entrainment study at the LSCS river intake from 2013 through 2015 42 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 1993 43 through 2012 (Fritts 2013).
44 Slippershell. The slippershell is a freshwater mussel that inhabits small to medium sized 45 streams where it is usually found buried in sandy substrates in shallow water 46 (Nyboer et al. 2006). IDNR (2014) recorded five observations of this species in LaSalle County, 47 most recently in October 2013. In 1994, 1995, and 1999, Sietman et al. (2001) conducted 48 freshwater mussel surveys in the Illinois River from RM 232.0 to 271.2 (RKm 373 to 436),
49 including the Starved Rock and Marseilles Pools sampling areas. Sietman et al. (2001) did not 3-71
 
Affected Environment 1 collect this species during the surveys. Similarly, this species was not observed in 2013 when 2 IDNR collected 14,850 live mussels, representing 23 species, near the Marseilles Dam after a 3 boating accident (Kanter 2013). This species was not collected during LSCS preoperational 4 surveys (NRC 1978), operational studies in 2013 (EA 2014), or during impingement and 5 entrainment studies at the LSCS river intake from 2013 through 2015 (EA 2015).
6 Spike. The spike is a freshwater mussel that inhabits shoals of medium streams to large 7 rivers, reservoirs, and lakes with sand and gravel substrates (Minnesota DNR 2014). It is 8 distributed throughout the eastern United States, the Mississippi River system, and portions of 9 the Great Lakes (NatureServe 2014b). IDNR (2014) recorded one observation of this species in 10 LaSalle County in August 2010. This species was not collected during LSCS preoperational 11 surveys (NRC 1978); the freshwater mussel survey from RM 232.0 to 271.2 in 1994, 1995, and 12 1999 (Sietman et al. 2001); IDNRs collection of mussels near the Marseilles Dam in 2013 13 (Kanter 2013); operational studies in 2013 (EA 2014); or during impingement and entrainment 14 studies at the LSCS river intake from 2013 through 2015 (EA 2015).
15 3.7.3.2      Important Habitats 16 LaSalle Lake State Fish and Wildlife Area is part of the 2,058 ac (833 ha) cooling pond. As 17 described above in Section 3.7.2, IDNR manages this area for public boating and fishing.
18 The Marseilles State Fish and Wildlife Area occurs approximately 1.5 mi (2.4 km) north of the 19 LSCS site and the makeup and blowdown pipeline corridor right-of-way crosses the eastern 20 portion of the area. The Marseilles State Fish and Wildlife Area is a 1,032-ha (2,550-ac) area 21 managed by IDNR for hunting and wildlife habitat (IDNR 2015d). It is a joint-use area with the 22 Illinois Department of Military Affairs, and periodically used by the Illinois National Guard for 23 training (IDNR 2015d).
24 3.7.4    Non-Native Species 25 Several non-native species, including the common carp, goldfish, and Asian carps 26 (Hypophthalmichthys spp.), have been introduced into the Illinois River (McClelland et al. 2012).
27 Common carp and goldfish have been present in the vicinity of LSCS prior to operations 28 (McClelland et al. 2012; Exelon 2014a). Both species dominated non-native fish collections in 29 INHSs long term monitoring surveys from 1957 and 1985 (McClelland et al. 2012). Common 30 carp and goldfish are tolerant of degraded aquatic habitats and can tolerate low levels of 31 dissolved oxygen and high water turbidity.
32 Beginning in 1985, the number of non-native fish observed in the Illinois River increased 33 (McClelland et al. 2012). Species documented in the Illinois River since 1985 include grass 34 carp (Ctenopharyngodon idella), bighead carp (Hypophthalmycthys nobilis), silver carp 35 (Hypophthalmycthys molitrix), round goby (Neogobius melanostomus), white perch (Morone 36 americana), and the white perch-yellow bass hybrid (M. americana x M. mississippiensis) 37 (McClelland et al. 2012).
38 In addition to fish, Exelon has documented the occurrence of invertebrate non-native species 39 near the river intake, the cooling pond intake, and within the cooling system. Bryozoans are 40 aquatic invertebrates that grow into large sessile colonies. Zebra mussels are native to the 41 Black and Caspian Seas, and have invaded Europe and North America. These organisms can 42 cause biofouling of LSCSs underwater piping systems or water intakes. In 1996, Exelon 43 discovered bryozoans at the cooling pond screen house and removed the colony by using a 44 continuous chlorination treatment. In 2010, Exelon observed the bryozoan Plumatella reticulata 45 in the Unit 1 cooling water system and unidentified bryozoans at the river intake and in the 46 cooling pond (HDR 2011). Within the past 5 years, Exelon has continued to regularly observe 3-72
 
Affected Environment 1 bryozoan colonies and zebra mussels at both the river intake and the cooling pond intake, and 2 limits the growth of these organisms by using biocides (HDR 2012, 2013, 2014; Exelon 2014a).
3 When necessary, Exelon also follows procedures to remove zebra mussels manually.
4 3.8      Federally Protected Species and Habitats 5 Because NRCs issuance of a renewed license for power plants is a Federal action, the NRCs 6 National Environmental Policy Act (NEPA) process considers species and habitats that are 7 protected under Federal acts and possibly affected by license renewal. Federal acts that 8 protect species and habitats possibly affected by the renewal of a nuclear plant license include 9 the Endangered Species Act of 1973, as amended (ESA); the Bald and Golden Eagle 10 Protection Act of 1940, as amended; the Migratory Bird Treaty Act of 1918, as amended; the 11 Magnuson-Stevens Fishery Conservation and Management Act, as amended (MSA); and the 12 Marine Mammal Protection Act of 1972, as amended. Of these, the NRC has direct 13 responsibilities only under the ESA and MSA. No species protected under the MSA, which 14 protects habitat for certain marine and anadromous fish species, occur near LSCS. Species 15 protected under the ESA are discussed in this section, and species protected under other 16 Federal acts where the NRC has no direct responsibilities and under State acts are discussed in 17 Section 3.6 for terrestrial resources and Section 3.7 for aquatic resources.
18 Section 7(a)(2) of the ESA states that each Federal agency shall, in consultation with the 19 Secretary (Secretary of Commerce or Secretary of the Interior), insure that any action 20 authorized, funded, or carried out by that agency is not likely to jeopardize the continued 21 existence of a listed species or result in the destruction or adverse modification of designated 22 critical habitat. In fulfilling these requirements, each agency is to use the best scientific and 23 commercial data available. Section 7 of the ESA sets out the consultation process, which is 24 further implemented by regulation (50 CFR Part 402). The ESA makes it unlawful for a person 25 to take a listed animal without a permit, where take under the ESA is defined as to harass, 26 harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such 27 conduct. Through regulations, the term harm is defined as an act which actually kills or 28 injures wildlife. Such an act may include significant habitat modification or degradation where it 29 actually kills or injures wildlife by significantly impairing essential behavioral patterns, including 30 breeding, feeding or sheltering (50 CFR 17.3). Listed plants are not protected from take, 31 although collecting or maliciously harming them on Federal land is illegal.
32 The FWS and the National Marine Fisheries Service jointly administer the ESA. The FWS 33 manages the protection of and recovery efforts for listed terrestrial and freshwater species, and 34 the National Marine Fisheries Service manages the protection of and recovery efforts for listed 35 marine and anadromous species, of which none occur in the Illinois River near LSCS.
36 3.8.1    Action Area 37 The ESA regulations at 50 CFR 402.02 define action area to mean all areas to be affected 38 directly or indirectly by the Federal action and not merely the immediate area involved in the 39 action. The action area essentially bounds the analysis of ESA-protected species because 40 species that occur within the action area may be affected by the Federal action, while species 41 that do not occur within the action area would likely not be affected by the Federal action. The 42 NRC staff recognizes that, although the action area is stationary, Federally listed species can 43 move in and out of the action area. For instance, a migratory fish species could occur in the 44 action area periodically and then travel to freshwater streams to spawn. Similarly, a flowering 45 plant known to occur near, but outside of, the action area could appear within the action area 46 over time if its seeds are carried into the action area by wind, water, or animals. Thus, in its 3-73
 
Affected Environment 1 analysis, the NRC staff considers not only those species known to occur directly within the 2 action area but also those species that may passively or actively move into the action area. The 3 NRC staff then considers whether the life history of each species makes the species likely to 4 move into the action area where it could be affected by the proposed LSCS license renewal.
5 Depending on habitat requirements, migration patterns, or other biological or physical 6 requirements, different species may require different action areas.
7 The LSCS site occupies about 1,528 ha (3,776 ac) in Marseilles, La Salle County, Illinois 8 (Exelon 2015p), about 8 km (5 mi) south of the Illinois River (Exelon 2014a). A cooling pond on 9 the eastern side of the site accounts for about half of the site area. A 5.6-km (3.5-mi) corridor 10 for the makeup and blowdown pipelineswhich travel underground from the Illinois River 11 screen house south to the cooling pondconnects the cooling pond with the Illinois River, from 12 which LSCS withdraws makeup water and discharges blowdown (Exelon 2014a). The intake 13 structure on the Illinois River has bar grills, traveling screens with 3/8 in. (9.5 mm) openings, 14 and no fish return system (Exelon 2014a).
15 For Federally protected terrestrial species, the action area is the site, including the water intake 16 and discharge pipe ROW, and areas immediately around the site that could include natural 17 populations affected by plant operations. Within the action area, Federally listed terrestrial 18 species could experience impacts such as habitat disturbance associated with transmission 19 lines, exposure to radionuclides, and other direct and indirect impacts associated with station, 20 cooling system, and in-scope transmission line operation and maintenance (NRC 2013).
21 For Federally protected aquatic species, the action area is the site and the Illinois River in the 22 area affected by water withdrawal and discharge as well as the range of any species affected by 23 water withdrawal and discharge. The license renewal of nuclear plants action can affect 24 Federally listed aquatic species in several ways, such as impingement or entrainment of 25 individuals into the cooling system, alteration of the riverine environment through water level 26 reductions, changes in dissolved oxygen, gas supersaturation, eutrophication, thermal 27 discharges from cooling system operation, habitat loss or alteration from dredging, and 28 exposure to radionuclides (NRC 2013a).
29 3.8.2    Federally Protected Species and Habitats Considered 30 Exelons ER (2014a) documents correspondence between Exelon and the FWS about the 31 effects of the proposed LSCS license renewal on Federally listed species. In July 2014, the 32 FWS concurred with Exelons March 2014 conclusion that license renewal would not adversely 33 affect any Federally listed species and noted that Exelon should consider an additional species:
34 Northern long-eared bat, a proposed species known to occur in the plant vicinity. In 35 August 2014, Exelon submitted a biological evaluation including the northern long-eared bat, 36 and the FWS concurred with Exelons conclusion that license renewal would not affect any 37 Federally listed species. Exelon (2014a, Appendix D) includes copies of this correspondence.
38 In late February 2015, NRC staff filled in an online form for an updated protected species list for 39 LSCS on FWSs Environmental Conservation Online System, Information for Planning and 40 Conservation. The FWS (2015b) responded with a list of threatened and endangered species 41 that may be affected by the LSCS license renewal. In October 2015, the NRC staff checked the 42 FWS (2015a) online Illinois County distribution of listed species for updates. Exelon (2014a) 43 reports that no federally listed species have been observed on the LSCS property. Terrestrial 44 and wildlife studies conducted by Exelon associated with LSCS that may have discovered and 45 reported Federally listed species are described in Section 3.6.2 of this SEIS.
46 Exelon commissioned several aquatic monitoring studies in the past, and none of them reported 47 Federally listed species in the Illinois River near LSCS. EA (2000) reported the results of a 3-74
 
Affected Environment 1 1999 monitoring study at three locations in the Illinois River upstream and downstream of the 2 LSCS intake and discharge in late summer. Fish were sampled by electrofishing and seining 3 and benthic macroinvertebrates by Ponar grab. The physical condition of fish put the study area 4 in the poorest category using Ohio criteria, and a benthic macroinvertebrate (macrobenthos) 5 community indicative of poor conditions was present. No Federally listed threatened or 6 endangered species were observed.
7 EA (2014) reported results of fish and macrobenthos monitoring above and below LSCS in 8 summer 2013 and compared results with past studies. Fish were sampled by electrofishing and 9 seining and benthic macroinvertebrates by Ponar grab, kick net samplers, and artificial 10 substrate samplers. No Federally listed threatened or endangered species were observed.
11 EA (2015) reported results of impingement sampling from April 2014 through March 2015 and 12 entrainment sampling in April through August 2014. No Federally listed fish or shellfish species 13 were observed in entrainment or impingement samples.
14 Table 3-14 shows Federally listed species that may occur in LaSalle County near LSCS and 15 habitat notes. Descriptions of the species follow.
16  Table 3-14. Federally Listed Species and Designated Habitat in La Salle County, Illinois Federally Listed                    Federal Group          Species          Common Name        Status(a) Habitat Mussels        Plethobasus      sheepnose              E      Shallow areas in larger rivers and cyphyus          mussel                        streams.
Flowering      Boltonia        decurrent false        T      Moist, sandy floodplains and prairie Plants        decurrens        aster                        wetlands along the Illinois River.
Platanthera      eastern prairie        T      Mesic prairie, wetlands, sedge leucophaea      fringed orchid                meadows, marsh edges, and bogs with full sun and little to no woody encroachment.
Delea foliosa    leafy prairie-        E      Prairie remnants on thin soil over clover                        limestone.
Mammals        Myotis sodalis  Indiana bat            E      Caves, mines (hibernacula); small stream corridors with well-developed riparian woods; upland forests (foraging).
Myotis          northern long-        T      Hibernates in caves and mines -
septentrionalis  eared bat                    swarming in surrounding wooded areas in autumn. Roosts and forages in upland forests and woods.
Critical Habitat Myotis sodalis  Indiana bat                  Blackball Mine (a) E=endangered; T=threatened Sources: FWS 2015b, 2015a 17 Sheepnose Mussel (Plethobasus cyphyus). The FWS listed the sheepnose mussel (also called 18 just sheepnose) as endangered on March 13, 2012, with an effective date of April 12, 2012, but 19 could not designate critical habitat at that time (77 FR 14914). The sheepnose mussel is a 20 freshwater mussel in the family Unionidae. According to Parmalee and Bogan (1998), adult 3-75
 
Affected Environment 1 mussels may reach 11 to 12 cm (4.3 to 4.8 in.) in length. Adult mussels are found partially or 2 completely buried in the substrate. They are suspension feeders and eat bacteria, algae, 3 microscopic animals, and detritus (77 FR 14914). Sheepnose is found in large rivers in gravel 4 or mixed sand and gravel (INHS 2013). Further, in unimpounded rivers, sheepnose mussels 5 can be found in less than 0.6 m (2 ft) of water and in relatively fast currents. In reservoirs, 6 sheepnose mussels occupy depths of 3.6 to 4.6 m (12 to 15 ft) (Parmalee and Bogan 1998),
7 though they have also been reported at depths exceeding 6 m (20 ft) (77 FR 14914).
8 Sheepnose mussels are long-lived and can live nearly 100 to 200 years (FWS 2013b).
9 Like other unionids, sheepnose has an unusual life cycle. After fertilization, the eggs live in 10 special gill chambers of the females and develop into microscopic larvae called glochidia.
11 Females brood the glochidia. When the glochidia are ready, the female expels the glochidia, 12 which then must attach to the host fishs gills or fins to complete development by enclosing 13 themselves in a cyst (encysting). They drop off the host fish as newly transformed juveniles.
14 The sauger (Sander canadensis) is the only known natural host for sheepnose mussel 15 glochidia. The FWS (77 FR 14914) reports that in laboratory studies, sheepnose glochidia 16 have successfully transformed on several other species, including fathead minnow (Pimephales 17 promelas), creek chub (Semotilus atromaculatus), central stoneroller (Campostoma anomalum),
18 and brook stickleback (Culaea inconstans), although interactions between these species and 19 sheepnose may be rare and infrequent in nature due to habitat preferences. The FWS (2015c) 20 identifies golden shiner (Notemigonus crysoleucas) as another possible host species.
21 The sheepnose mussel is found across the Southeast and the Midwest, although it has been 22 eliminated from about two-thirds of its range. Today, the sheepnose mussel is found in 23 Alabama, Illinois, Indiana, Iowa, Kentucky, Minnesota, Mississippi, Missouri, Ohio, 24 Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin.
25 In a study for Exelon, EA (2014) sampled fish, benthic invertebrates, and physical and chemical 26 parameters during summer 2013 in the Illinois River both upstream and downstream of LSCS 27 and compared the results to past studies for LSCS in 1974 through 1978 and 1999. EA 28 sampled fish using electrofishing and seines and benthic invertebrates using artificial substrate 29 samples and a grab sampler. EA found no threatened or endangered fish or macroinvertebrate 30 species, including endangered mussels, near LSCS in this study or in past studies.
31 Exelon (2014a) reports not observing any Federally listed species at LSCS.
32 Decurrent False Aster (Boltonia decurrens). Decurrent false aster is a flowering perennial plant 33 in the aster family. The aster-like flowers appear from the tall (typically about 1.5 m (60 in.) or 34 more), bushy plants from August to October, and the flower rays range in color from white to 35 pale violet. Decurrent refers to leaf stem bases that run down along the stem where they 36 attach. Decurrent false aster lives in the wet prairies in disturbed alluvial ground and open 37 shores of floodplain forests along the Illinois and Mississippi Rivers, and historically ranged from 38 LaSalle, Illinois, downstream to St. Louis, Missouri, on the Mississippi River. In 1988, the FWS 39 proposed to list the species as threatened (53 FR 5598) because it found only 12 extant 40 populations remaining in 5 Illinois counties and one Missouri County. In addition, destruction 41 and modification of the floodplain forest along the Illinois and Mississippi Rivers due to wetland 42 drainage and agricultural expansion threatened survival of the species. In November 1988, the 43 FWS determined the decurrent false aster to be a threatened species under the ESA but did not 44 designate critical habitat (53 FR 45858). At that time, the FWS thought the species to be 45 extirpated from 13 counties in Illinois and 3 counties in Missouri. Twelve remaining extant 46 populations were located along the Illinois River in Morgan, Schuyler, Fulton, and Marshall 47 Counties; one population along the Mississippi River in St. Clair County; and two populations in 48 St. Charles County, Missouri. It was often found in disturbed alluvial soil where the forest 49 overstory and understory are open due to frequent flooding. It prefers moist, sandy areas 3-76
 
Affected Environment 1 around natural lakes in the Illinois River floodplain, but these areas now receive 2 or 3 in. (5 to 2 7.5 cm) of silt per year due to extensive row crop agricultural practices and numerous levee 3 systems that increase the amount of silt deposited on river banks during floods, and the silt 4 prevents seed germination.
5 The FWS initiated 5-year status reviews of decurrent false aster in 1990 and 2011, requested 6 new information on the species, and found no reason to change the ESA threatened status. In 7 its Recovery Plan that incorporated new information, FWS (1990) reported 18 known 8 populations for this species in Illinois and 2 in Missouri, although not all were self-sustaining. In 9 its 2012 5-year Review, FWS (2012b) found that research since the Recovery Plan indicated 10 that this species may best be described as a metapopulation (a group of spatially separated 11 populations of the same species that interact at some level) that colonizes and disappears from 12 available habitat patches. In a metapopulation, as local populations fluctuate in size, they 13 become vulnerable to extinction during periods when their numbers are low, and the regional 14 persistence of the species depends on the existence of a metapopulation. Elimination of much 15 of the metapopulation structure can increase the chance of regional extinction of the species.
16 The plants abundance appears to fluctuate widely in response to annual changes in site 17 conditions and the dynamic Illinois River hydrology. In a metapopulation model of decurrent 18 false aster (Smith et al. 2005), flood pulses characterized by spring floods and midsummer 19 periods of low water maintain subpopulations and help establish new sub-populations. The 20 flood pulses provide necessary disturbance and reduce competition to facilitate the colonization 21 of habitats. Impoundment of the Illinois River and periodic prolonged high water events during 22 the growing season have reduced available habitat and contributed to the species decline. The 23 FWS has not reported extant populations in LaSalle County and Exelon (2014a) reports no 24 threatened or endangered species on the LSCS site.
25 Eastern Prairie Fringed Orchid (Platanthera leucophaea). The eastern prairie fringed orchid is 26 1 of at least 200 North American orchid species and is a perennial herb. Plants are about 8 to 27 40 in. (0.2 to 1 m) tall. An upright leafy stem carries a flower cluster called an inflorescence.
28 The 3- to 8-in. (76- to 200-cm) lance-shaped leaves sheath the stem. Each plant has one single 29 flower spike composed of 5 to 40 creamy white flowers, and the blossoms often rise just above 30 the height of the surrounding grasses and sedges. Blooming occurs in late June and early July.
31 Night-flying hawkmoths (family Sphingidae) pollinate the nocturnally fragrant flowers 32 (FWS 2013a).
33 This species typically inhabits tallgrass prairies east of the Mississippi River that have 34 calcareous silt loam soils and calcareous wetlands with open portions of fends, sedge 35 meadows, marshes, and bogs. While once numerous and widespread, populations have 36 declined with the disappearance of eastern prairies by conversion of habitat for crop fields, 37 grazing, intensive and continuous hay mowing, drainage, and related human uses. Other 38 reasons for the decline include succession to woody vegetation, competition from non-native 39 species, and over-collection. Remaining populations tend to be small, unprotected, and 40 unmanaged. The FWS designated the eastern prairie fringed orchid as an endangered species 41 in 1989 (54 FR 39857) and in 2012 initiated a 5-year status review of the listing (77 FR 38762).
42 The FWS did not designate critical habitat for this species. Exelon (2014a) reports not 43 observing any Federally listed species on the LaSalle site.
44 Leafy Prairie-Clover (Delea foliosa). The FWS listed the leafy prairie-clover as endangered 45 throughout its range in 1991 (56 FR 19953), when it was known to be present only in two sites 46 in Alabama, nine sites in Tennessee, and three sites in Illinois. The FWS did not designate 47 critical habitat for leafy prairie-clover. The species is perennial and a member of the pea family 48 (Fabaceae). The plants grow erect stems about 0.5-m (1.5-ft) tall, on the end of which grow 3-77
 
Affected Environment 1 small purple flowers in dense spikes. Flowering begins in August, and seeds ripen in early 2 October, after which the above-ground portion of the plant dies while the below-ground portion 3 survives the winter (56 FR 19953).
4 This plant is typically found in dry prairies, often in dolomitic soils. In Illinois, leafy prairie-clover 5 was originally known from six counties in the northeastern part of the State, but by 1991 only 6 three populations were known in the State, all in Will County in prairie remnants along the 7 Des Plaines River (56 FR 19953). The U.S. Forest Service (USFS) (undated a) lists the 8 reasons for its decline as plant and habitat loss from inundation by dams, road work, and 9 right-of-way management, including herbicide effects; botanical and horticultural collection; 10 off-road vehicle impacts to plants and habitat; predation by deer and rabbits; encroachment of 11 woody plants; and severe drought. Its habitat is being lost as dolomite prairies are being 12 converted to industrial, commercial, and residential uses (USFS undated b). Recovery efforts 13 by a partnership of the FWS (Chicago Field Office), the USFS, the Forest Preserve District of 14 Will County, the Department of the Army (Joliet Training Area), the IDNR, the Forest Preserve 15 District of Kane County, and Midewin National Tallgrass Prairie are underway in northeastern 16 Illinois (USFS undated b). Exelon (2014a) reports not observing any Federally listed species on 17 the LSCS site.
18 Indiana Bat (Myotis sodalis). The FWS listed the Indiana bat as endangered in 1967 19 (32 FR 4001). The FWS designated critical habitat for the Indiana bat in 1976 (41 FR 41914) to 20 include 11 caves and 2 mines in six states, including a cave in LaSalle County, Illinois. The 21 Indiana bat is an insectivorous, migratory bat that inhabits the central portion of the Eastern 22 United States and hibernates colonially in caves and mines. The decline of Indiana bats is 23 attributed to urban expansion, habitat loss and degradation, human-caused disturbance of 24 caves or mines, insecticide poisoning, and white-nose syndrome (WNS) (FWS 2011; 25 Pruitt and TeWinkel 2007).
26 During summer months, reproductive female bats tend to roost in colonies under slabs of 27 peeling tree bark or cracks within trees in forest fragments, often near agricultural areas 28 (Pruitt and TeWinkel 2007). Colonies may also inhabit closed-canopy, bottomland deciduous 29 forest; riparian habitats; wooded wetlands and floodplains; and upland communities 30 (Pruitt and TeWinkel 2007). Maternity colonies typically consist of 60 to 80 adult females 31 (Whitaker and Brack 2002). Colonies occupy multiple trees for roosting and rearing young 32 (Watrous et al. 2006) and, once established, usually return to the same areas each year 33 (Pruitt and TeWinkel 2007). Nonreproductive females and males do not roost in colonies during 34 the summer; they may remain near the hibernacula or migrate to summer habitat 35 (Pruitt and TeWinkel 2007). A hibernaculum is an area where bats gather and hibernate in 36 winter. High-quality summer habitat includes mature forest stands containing open 37 subcanopies, multiple moderate- to high-quality snags, and trees with exfoliating bark 38 (Farmer et al. 2002). In summer, bats forage for insects along forest edges, riparian areas, and 39 in semi-open forested habitats. In the winter, Indiana bats rely on caves for hibernation. The 40 species prefers hibernacula in areas with karst (limestone, dolomite, and gypsum), although it 41 may also use other cave-like locations, such as mines.
42 The Indiana Bat Recovery Plan (Pruitt and TeWinkel 2007) indicates that Indiana bats are 43 distributed across 36 of the 102 counties in Illinois. Twenty-two winter hibernacula (16 extant, 44 4 of uncertain status, and 2 historic) are located throughout these counties. Additionally, 45 29 extant maternity colonies occur in Illinois, and adult males, nonreproductive females, or both 46 have been captured during summer surveys within 26 of the 36 counties. For 2011, the 47 FWS (2009) estimated that Illinoiss total population of Indiana bats was 54,095 individuals.
48 According to more recent estimates, the Illinois population of Indiana bats has increased by 3-78
 
Affected Environment 1 almost 2,000 over in 2011 to 55,956 individuals (FWS 2012a). Exelon (2014a) reports not 2 observing any Federally listed species on the LSCS site.
3 Northern Long-Eared Bat (Myotis septentrionalis). In December 2013, the FWS (78 FR 72058) 4 found that listing of the northern long-eared bat as an endangered species under the ESA was 5 warranted. Earlier in October 2013, the FWS (78 FR 61046) had found that it could not 6 determine critical habitat for this species. The FWS listed the northern long-eared bat as 7 threatened throughout its range on April 2, 2015 (80 FR 17974). The following information is 8 from those listing documents. The northern long-eared bat is a medium-sized bat species with 9 average adult body weights of 5 to 8 grams (0.2 to 0.3 ounces), adult body lengths between 10 77 to 95 mm (3.0 to 3.7 in.) and wingspans between 228 and 258 mm (8.9 to 10.2 in.). Adult fur 11 is typically brown, darker on top than below. The range includes much of the eastern and north 12 central United States (it occurs in 39 states) and all Canadian provinces west to the southern 13 Yukon Territory and eastern British Columbia. Throughout the majority of this range, however, it 14 is patchily distributed, and historically it was less common in the southern and western part of its 15 range than in the northern portion. The bats gather and hibernate in winter typically in mines 16 and caves, where they are now usually found only in low numbers. They migrate out of the 17 hibernacula in summer, when they forage at night and roost during daylight in small numbers in 18 live and dead trees and change roosts often. Their diet includes moths, flies, leafhoppers, 19 caddisflies, and beetles, although the diet differs geographically and seasonally, and an 20 individual can consume 3,000 insects each night. Mating occurs in the autumn and birthing in 21 May or June. Mature forests are an important habitat type for northern long-eared bats, 22 although they occasionally act as forager over forest clearings and along roads. The northern 23 long-eared bat has experienced a sharp decline, estimated at approximately 99 percent from 24 hibernaculum data, in the northeastern portion of its range due to the recent emergence of a 25 fungal disease known as WNS (currently called Geomycetes destructans), and the FWS 26 expects similar declines in the western part of its range as this disease spreads. The 27 FWS (2013c) confirmed the existence of WNS in northern long-eared and little brown bats from 28 LaSalle and Monroe Counties, Illinois. Human activities that threaten this species include 29 constructing physical barriers at cave accesses and destruction of habitat through mining, 30 flooding, vandalism, development, timber harvest, and other activities. Exelon (2014a) reports 31 not observing any Federally listed species on the LSCS site.
32 Summary of the Occurrence of Listed Species within the Action Area. The six species listed in 33 Table 3-14 are under the FWSs jurisdiction within LaSalle County, although the information is 34 not specific to the LSCS site. For the six species identified for LaSalle County, the NRC staff 35 did not identify any within the action area after review of the ER (Exelon 2014a), a site visit that 36 included discussions with site staff and review of onsite documents, and published and online 37 sources. Sections 3.6 Terrestrial Resources and 3.7 Aquatic Resources summarize the 38 ecological surveys performed on and near the LSCS site that would detect protected species.
39 Exelon (2014a) reports not observing any Federally listed species on the LSCS site.
40 3.9    Historic and Cultural Resources 41 This section discusses the cultural background and the known historic and cultural resources 42 found on or near LSCS. The discussion is based on a review of historic and cultural resource 43 surveys and other background information on the region surrounding LSCS. In addition, a 44 records search was performed via the Illinois Historic Preservation Agency to obtain the most 45 updated information about historic and cultural resources in the region.
46 The Area of Potential Effect (APE) is the area at the LSCS power plant site, the transmission 47 lines up to the first substation, and immediate environs that may be affected by the license 3-79
 
Affected Environment 1 renewal decision and land-disturbing activities associated with continued reactor operations.
2 For this analysis, the first substation (345 kV LSCS switchyard) is located on the LSCS site 3 (Exelon 2014a). The APE may extend beyond the immediate environs in instances where 4 land-disturbing maintenance and operations activities during the license renewal term or 5 refurbishment activities could potentially have an effect. In the case of LSCS, the APE includes 6 the corridor between the cooling pond and the Illinois River containing the makeup and 7 blowdown water pipelines within the site boundary. These pipelines traverse a distance of 8 approximately 5.6 km (3.5 mi) from the cooling pond to the Illinois River. See Figure 3-3.
9 3.9.1      Cultural Background 10 Human occupation near the LSCS site is generally characterized according to the following 11 chronological sequence (Pauketat 1993):
12
* Paleo-Indian Period (12,000 - 10,000 before present (BP)),
13
* Archaic Period (10,000 - 3,000 BP),
14
* Woodland Period (3,000 - 1,100 BP),
15
* Mississippian Period (1,100 - 400 BP (ca. A.D. 900 - 1600)), and 16
* Protohistoric/Historic Period (400 - present (ca. A.D. 1600 - present)).
17 Paleo-Indian Period (12,000 - 10,000 B.P.). The earliest evidence of people living in Illinois 18 dates to the Paleo-Indian Period. Paleo-Indian sites are generally found upland or on river 19 terraces and are characterized by specific types of projectile points (i.e., fluted Clovis and 20 Folsom points) and stone tools such as gravers, scrapers or large blades. These artifacts often 21 occur in association with mastodon remains, suggesting a reliance on megafauna 22 (e.g., mammoth, ground sloth, and saber-tooth tiger) for subsistence along with plants, small 23 game, birds, and amphibians. Social organization consisted of small, highly nomadic bands of 24 hunter-gathers, leaving Paleo-Indian sites with little detailed archaeological information 25 (Neusius and Gross 2007; Pauketat 1993).
26 Archaic Period (10,000 - 3,000 B.P.). The Archaic Period was a time of major climatic shifts as 27 colder environments transitioned to warmer environments similar to modern conditions. In 28 response to this shift, new technologies and subsistence strategies were developed during this 29 time. The Archaic Period is often divided into early, middle, and late subperiods. The Early 30 Archaic Period is characterized by a shift from nomadic to sedentary settlement patterns, with 31 central base camps located on river terraces and smaller hunting camps located in upland 32 areas. This subperiod also shows an increased reliance on wild plant foods, small game, and 33 aquatic resources. The Middle Archaic Period is characterized by an increased number of 34 settlement sites on high stream terraces, which may reflect population increases. While 35 subsistence and settlement patterns remained fairly similar to the Early Archaic Period, artifact 36 assemblages suggest increased exploitation of aquatic resources as well as new artifacts such 37 as pecked and ground stone tools used for intensive processing of nuts; banner stones that 38 signaled the innovation of a new projectile technology called the atlatl or spear-thrower; and 39 grooved axes. The Late Archaic Period is characterized by an increase in the number and size 40 of settlement sites, which indicates an increase in population and a more sedentary lifestyle.
41 New features of Late Archaic artifact assemblages, such as crude ceramic vessels, represent a 42 shift towards increased reliance on horticulture as a subsistence strategy, although hunting and 43 gathering would have continued (Fagan 2005; Neusius and Gross 2007; Pauketat 1993).
44 Woodland Period (3,000 - 1,100 B.P.). The Woodland Period is also often divided into early, 45 middle, and late periods. However, the distinction between the early and middle period is not 3-80
 
Affected Environment 1 fixed. The Woodland Period is marked by an increase in more permanent settlements, changes 2 in burial practices, increased cultivation of plants such as sunflowers and cucurbits 3 (e.g., squashes, gourds, melons), and a rise in the manufacture and use of pottery 4 (Fagan 2005). During the Middle Woodland Period, the large and complex Hopewell Culture 5 emerged in the northeastern and Midwestern United States, including Illinois. This culture is 6 characterized by settlement in villages, increased reliance on intensive horticulture, burial 7 mounds, and long distance trade networks. These long distance networks allowed the trade of 8 exotic materials, such as marine shells from the Gulf Coast, obsidian from the Rocky Mountains, 9 copper from Lake Superior, and mica from the Appalachian Mountains far outside their 10 immediate locations. Evidence of the Illinois Hopewell culture is found primarily in the bluffs and 11 floodplains of the Illinois River Valley. The burial mounds of this period often included central 12 features, lined with logs, and filled with grave goods. Different burial treatments within the 13 mounds point to social stratification within society, but through sex and age rather than 14 hereditary lineage (Neusius and Gross 2007). The Late Woodland Period is characterized by 15 an increase in settlement sites, which suggests (a) a rise in population, or (b) a change in 16 settlement patterns from large, centralized village sites to smaller, dispersed habitation sites, or 17 both (Fagan 2005).
18 Mississippian Period (1,100 - 400 B.P. (ca. A.D. 900 - 1600)). The Mississippian Period is 19 characterized by major changes in settlement, subsistence patterns, and social structure. Large 20 highly centralized chiefdoms with permanent settlements sites supported by numerous satellite 21 villages emerged during this period. The platform mound, a new ceremonial earthen mound 22 appeared in association with these permanent settlements. Platform mounds, burial mounds, 23 and defensive structures, such as moats and palisades, were often constructed in clusters in 24 settlements of this period and were common in the larger river valleys of the Midwest.
25 Mississippian Period subsistence relied heavily on maize agriculture, as well as hunting and 26 gathering. Long distance trading increased and craft specialists produced highly specialized 27 lithic and ceramic artifacts, beadwork and shell pendants (Fagan 2005). Examples of 28 Mississippian Period occupation within LaSalle County is the Starved Rock State Park area.
29 Starved Rock is a 1,065 ha (2,632 ac) area along the south bank of the Illinois River between 30 the towns of LaSalle and Ottawa, Illinois. Mississippian period artifacts have been found in 31 some 62 sites in the region surrounding Starved Rock State Park with 16 sites recorded in the 32 park itself (DOI 1998).
33 Protohistoric/Historic Period (A.D. 1600 - Present). The end of the Mississippian Period is 34 characterized by severe social, political, and demographic changes that resulted from indirect 35 and direct contact with Europeans. In particular, it is believed that the introduction of European 36 infectious diseases such as smallpox, typhoid, and influenza severely decimated Native 37 American populations, which had no immunity to these diseases. The spread of these 38 diseases, which were fatal to large numbers of Native Americans, resulted in the widespread 39 abandonment of villages and a concurrent collapse of Native American socioeconomic 40 networks, such that by the time of widespread European contact and settlement, the 41 Mississippian chiefdoms were gone (Fagan 2005). During the historic period, Illinois was 42 primarily populated with a confederation of tribes known as the Illinois, or Illiniwek, and the 43 Miami tribe. During the 1700s and early 1800s, new tribes migrated to Illinois, including the 44 Iroquois, Fox (Mesquakie), Ioway, Kickapoo, Mascouten, Piankashaw, Potawatomi, Sauk, 45 Shawnee, Wea, and Winnebago. Competition for resources led to sporadic war among the 46 Illinois, surrounding tribes, and European immigrants to the area for approximately the next 47 120 years (ISM 2002). In approximately 1673, French explorers traveled along the Mississippi 48 River and up the Illinois River to present-day LaSalle County. Robert Cavalier, also known as 49 Louis de La Salle, made the first European settlement in LaSalle County. French influence in 50 the Illinois territory began to wane by the mid-1700s due to being ejected from the area by the 3-81
 
Affected Environment 1 British. Illinois became part of the Northwestern Territory at the close of the American 2 Revolution. LaSalle County was organized by the Illinois legislature during the 1830-1831 3 legislative session (Baldwin 1877). The State of Illinois joined the Union in 1818. The area 4 surrounding the LSCS site has principally been used for agriculture and coal mining from this 5 period onward (Exelon 2014a).
6 3.9.2      Historic and Cultural Resources 7 LSCS historic and cultural resources include prehistoric era and historic era archaeological 8 sites, historic districts, and buildings, as well as any site, structure, or object that may be 9 considered eligible for listing on the National Register of Historic Places (NRHP). Historic and 10 cultural resources also include traditional cultural properties that are important to a living 11 community of people for maintaining their culture. Historic property is the legal term for a 12 historic or cultural resource that is eligible for listing on the NRHP.
13 A review of databases maintained by the National Park Service (NPS) indicates that there are 14 31 properties listed in the NRHP within LaSalle County, including three that have been 15 designated as National Historic Landmarks (DOI 2015). These historic properties reflect the 16 historic cultural contexts for the LSCS property and include Starved Rock State Park, and 17 structures and districts dating from the mid-18th through mid-20th centuries. None of the 18 historic properties is located within the boundaries of the LSCS property (DOI 2015). The 19 closest NRHP site is the Illinois and Michigan Canal (NR200462), approximately 5 mi (8 km) to 20 the north of the plant.
21 A number of surveys of the LSCS site were conducted between 1972 and 1994. In 1972, a 22 Phase I archaeological survey was done by the Illinois Archaeological Survey of the LSCS 23 siteoriginally known as the Collins Generating Station. Five sites were discovered on LSCS 24 property. However, these sites were not recorded or evaluated because, in 1972, isolated finds 25 were not recognized as sites and therefore not evaluated. Three of the sites were assigned 26 Illinois Archaeological Survey accession numbersLS00207, LS00208, and LS00209. The 27 1972 survey concluded that construction of the LSCS would not significantly affect 28 archaeological resources (Exelon 2014a). These findings were accepted by the NRC in its Final 29 Environmental Statement for LSCS issued in 1978 (NRC 1978). In 1993, the Illinois 30 Department of Military Affairs did a survey to support the siting of a military training area 31 immediately northwest of LSCS. This survey found 48 archaeological sites, one of which is 32 located on the LSCS siteLS00514. This site was also determined not to be NRHP eligible 33 (Exelon 2014a).
34 The NRC staff searched the Illinois State Archaeological Site Files, a database maintained by 35 the Illinois State Historic Preservation Officer, and identified the LSCS sites listed in the 36 1972 and 1993 surveys as well as one additional siteLS00527which was determined to be 37 NRHP ineligible. No other cultural resources within the current confines of the LSCS site were 38 identified (NRC 2015c).
39 3.10    Socioeconomics 40 This section describes current socioeconomic factors that have the potential to be directly or 41 indirectly affected by changes in operations at LSCS. LSCS, and the communities that support 42 it, can be described as a dynamic socioeconomic system. The communities supply the people, 43 goods, and services required to operate the nuclear power plant. Power plant operations, in 44 turn, supply wages and benefits for people and dollar expenditures for goods and services. The 45 measure of a communitys ability to support LSCS operations depends on its ability to respond 46 to changing environmental, social, economic, and demographic conditions.
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Affected Environment 1 3.10.1      Power Plant Employment and Expenditures 2 The socioeconomics region of influence (ROI) is defined by the areas where LSCS employees 3 and their families reside, spend their income, and use their benefits, thus affecting the economic 4 conditions of the region. Exelon employs a permanent workforce of approximately 5 890 employees and 30 long-term contract employees (Exelon 2014a). Approximately 6 83 percent of LSCS employees reside in a three-county area in northeastern Illinois in Grundy, 7 LaSalle, and Will Counties. Most of the remaining 17 percent of the workforce are spread 8 among 23 other counties in Illinois, with numbers ranging from 1 to 40 employees per county 9 (Exelon 2014a). Given the residential locations of LSCS employees, the most significant effects 10 of plant operations are likely to occur in Grundy, LaSalle, and Will Counties.
11 Table 3-15 summarizes the LSCS workforce geographic distribution. The focus of the 12 socioeconomic impact analysis in this SEIS is, therefore, on the impacts of continued LSCS 13 operations on these three counties, also termed the ROI.
14                        Table 3-15. LSCS Employees Residence by County County                                Number of Employees              Percentage of Total Illinois Bureau                                          12                              1 Cook                                            10                              1 Grundy                                          161                              18 Kendall                                          38                              4 LaSalle                                        490                              55 Livingston                                      40                              5 Will                                            86                              10 Other counties                                  52                              6 Total                                          889                            100 Source: Exelon 2014 15 Exelon purchases goods and services to facilitate LSCS operations. While specialized 16 equipment and services are procured from a wider region, some proportion of the goods and 17 services used in plant operations are acquired from within the ROI. These transactions fuel a 18 portion of the local economy, as jobs are provided and additional local purchases are made by 19 plant suppliers.
20 The LSCS units are on staggered 24-month refueling cycles lasting approximately 25 days 21 each. During refueling outages, site employment typically increases by an additional 22 800 temporary workers (Exelon 2014a). Approximately 75 to 80 percent of the outage workers 23 are permanent residents of the ROI. The remaining 20 to 25 percent stay in Morris, Ottawa, or 24 Joliet, Illinois (Exelon 2014a).
25 3.10.2      Regional Economic Characteristics 26 This section presents information on employment and income in the LSCS socioeconomic ROI.
27 Grundy and LaSalle counties are predominantly rural with agricultural and forested land 28 comprising the majority (90 percent) of the land use in the county. Conversely, Will County is 29 more urban with developed land comprising about 34 percent of total land area in the county 30 (USDA 2015a).
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Affected Environment 1 3.10.2.1      Employment and Income 2 From 2010 to 2014, the labor force in the LSCS ROI decreased approximately 0.8 percent to 3 approximately 440,000. However, the number of employed persons increased by about 4 3.4 percent, to approximately 406,000. Consequently, the number of unemployed people in the 5 ROI decreased by 33.6 percent, by approximately 17,000 persons to approximately 33,000, or 6 about 7.6 percent of the current workforcedown from 11.3 percent in 2010 (BLS 2015).
7 According to the U.S. Census Bureaus (USCBs) 2014 American Community Survey 1-Year 8 Estimates for LaSalle and Will Counties and 2009-2013 American Community Survey 5-Year 9 Estimates for Grundy County, the educational, health, and social services industry represented 10 the largest employment sector in the socioeconomic ROI (22.8 percent) followed by 11 manufacturing and retail (both at 12 percent) (USCB 2015a). A list of employment by industry in 12 each county of the ROI is provided in Table 3-16.
13                        Table 3-16. Employment by Industry in the LSCS ROI 14                      (2014, 1-year estimates and 2009-2013, 5-year estimates)
Industry                                            Grundy(a) LaSalle(b)  Will(b)  Total Percent Total employed civilian workers                      22,931  47,159    342,888  412,978  -
Agriculture, forestry, fishing, hunting, and mining      334    1,645      1,488    3,467  0.8 Construction                                          1,920    2,556    21,997  26,473  6.4 Manufacturing                                          2,872    7,495    39,037  49,404  12.0 Wholesale Trade                                          760    1,015    10,581  12,356  3.0 Retail Trade                                          2,677    7,030    40,265  49,972  12.1 Transportation, warehousing, and utilities            2,215    3,157    25,581  30,953  7.5 Information                                              268      397      7,992    8,657  2.1 Finance, insurance,                                    1,037    2,348    22,388  25,773  6.2 real estate, rental, and leasing Professional, scientific, management,                  1,559    3,081    34,365  39,005  9.4 administrative, and waste management services Educational, health, and social services              4,893  10,252    78,846  93,991  22.8 Arts, entertainment, recreation, accommodation,        2,566    3,737    31,560  37,863  9.2 and food services Other services (except public administration)            936    3,026    16,930  20,892  5.1 Public administration                                    894    1,420    11,858  14,172  3.4 (a) 2009-2013 American Community Survey 5-Year Estimates.
(b) 2014 American Community Survey 1-Year Estimates.
Source: USCB 2015a 15 Major employers in LaSalle County, the county in which LSCS is located, are listed in 16 Table 3-17. Exelon is shown as the largest employer in the county.
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Affected Environment 1                          Table 3-17. Major Employers in LaSalle County in 2009 Employer                                          Number of Employees Exelon Generation                                            890 OSF, Saint Elizabeth Medical Center                          730 PetSmart                                                      500 Clover Technology Group                                      450 HR Imaging                                                    425 Office Max                                                    375 SABIC Innovative Plastics                                    275 Kohls                                                        270 Seattle Sutton Healthy Eating                                170 Mitsuboshi Belting                                            168 Pilkington Industries                                        157 Tysons                                                      130 U.S. Silica                                                  130 Source: Ottawa Area Chamber of Commerce & Industry, 2009 2 Estimated income information for the LSCS ROI is presented in Table 3-18. According to the 3 USCBs 2014 American Community Survey 1-year estimates, 10.5 percent of families and 4 14.4 percent of individuals in Illinois were living below the Federal poverty threshold and the 5 median household and per capita income for Illinois was $57,444 and $30,417, respectively 6 (USCB 2015b). In the socioeconomic ROI, people living in LaSalle County had median 7 household and per capita incomes below the State average. The median household and per 8 capita income average in LaSalle County was $50,432 and $25,129, respectively, with 9 9.6 percent of families and 13.3 percent of individuals living below the poverty level.
10 Conversely, Will County had a higher median household and per capita income average 11 ($74,828 and $32,148, respectively) and a lower percentage of families (6.3 percent) and 12 individuals (7.9 percent) living below the official poverty level. According to the USCBs 13 2011-2013 American Community Survey 3-Year Estimates, Grundy County also had higher 14 median household and per capita income averages ($63,978 and $28,465, respectively) and 15 lower percentages of families (7.2 percent) and individuals (9.4 percent) living below the poverty 16 level than the State of Illinois and LaSalle County (USCB 2015b).
17                        Table 3-18. Estimated Income Information for the LSCS ROI 18                                  (2014 estimates, unless otherwise indicated)
Grundy(b)        LaSalle        Will      Illinois Median household income          (dollars)(a)          63,978          50,432        74,828    57,444 Per capita income (dollars)(a)                        28,465          25,129        32,148    30,417 Individuals living below the poverty level                  9.4            13.3          7.9        14.4 (percent)
Families living below the poverty level (percent)          7.2              9.6          6.3        10.5 (a) In 2012 inflation adjusted dollars.
(b) 2011-2013  American Community Survey 3-Year Estimates.
Source: USCB 2015b.
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Affected Environment 1 3.10.2.2      Unemployment 2 According to the USCBs 2014 American Community Survey estimates, the unemployment 3 rates in LaSalle County and the State of Illinois were 8.1 and 10.5 percent, respectively.
4 Comparatively, the Will County unemployment rate during this same time period was 5 6.0 percent. According to the USCBs 2013 American Community Survey 3-year estimates, the 6 unemployment rates in Grundy County was 9.6 percent (USCB 2015c).
7 3.10.3      Demographic Characteristics 8 According to the 2010 Census, an estimated 103,000 people lived within 20 mi (32 km) of 9 LSCS, which equates to a population density of approximately 81 persons per square mile 10 (persons/mi2) (CAPS 2014). This translates to a Category 3, least sparse population density 11 using the GEIS measure of sparseness (60 to 120 persons/mi2 within 20 mi). An estimated 12 1,926,000 people live within 50 mi (80 km) of LSCS with a population density of approximately 13 245 persons/mi2 (CAPS 2014). This translates to a Category 4 in close proximity population 14 density, using the GEIS measure of proximity (greater than or equal to 190 persons/mi2 within 15 50 mi). Therefore, LSCS is located in a high population area based on the GEIS sparseness 16 and proximity matrix.
17 Table 3-19 shows population projections and percent growth from 1980 to 2060 in the 18 three-county LSCS ROI. The ROI population continues to increase over the past two decades 19 (2000 and 2010). Based on forecasts, the population is expected to continue these trends at 20 moderate to high rates. Population projections for years 2020 and 2040 shown in the table 21 were developed for the Illinois Department of Transportation.
22      Table 3-19. Population and Percent Growth in LSCS ROI Counties 1980-2010, 2014 23                                (estimated), and Projected for 2020-2060 Grundy County                    LaSalle County                  Will County Percent                          Percent                        Percent Year          Population        change        Population        change    Population          change 1980            30,582              -          112,033              -        324,460              -
1990            32,337              5.7        106,913            -4.6      357,313            10.1 2000            37,535            16.1          111,509              4.3      502,266            40.6 2010            50,063            33.4          113,924              2.2      677,560            34.9 2014            50,425              0.7        111,241            -2.4      685,419              1.2 2020            61,265            22.4          118,178              3.7      868,986            28.3 2030            72,463            18.3          121,928              3.2    1,146,722            32.0 2040            83,665            15.5          125,686              3.1    1,366,456            19.2 2050            94,864            13.4          129,439              3.0    1,624,858            18.9 2060            106,064            11.8          133,193              2.9    1,873,593            15.3 Sources: Decennial population data for 1980-2010, and estimated 2014 (USCB 2015d); projections for 2020-2040 Illinois Department of Transportation (IDOT 2012); 2050-2060 calculated.
24 The 2010 Census demographic profile of the three-county ROI population is presented in Table 25 3-20. According to the 2010 Census, minorities (race and ethnicity combined) comprised 26 28.6 percent of the total three-county population. The largest minority populations in the ROI 3-86
 
Affected Environment 1 were Hispanic or Latino of any race (14.1 percent) and Black or African American (9.2 percent) 2 (USCB 2015e).
3          Table 3-20. Demographic Profile of the Population in the LSCS ROI in 2010 Grundy    LaSalle        Will      ROI Total Population                                      50,063    113,924    677,560      841,547 Race (percent of total population, Not-Hispanic or Latino)
White                                                  88.9      88.3      67.2        71.4 Black or African American                              1.2        1.8        11.0        9.2 American Indian & Alaska Native                        0.1        0.2        0.1          0.1 Asian                                                  0.6        0.7        4.5          3.7 Native Hawaiian & Other Pacific Islander              0.0        0.0        0.0          0.0 Some other race                                        0.0        0.0        0.1          0.1 Two or more races                                      0.9        1.0        1.4          1.3 Ethnicity Hispanic or Latino                                    4,096      9,135      105,817      119,048 Percent of total population                            8.2        8.0        15.6        14.1 Minority population (including Hispanic or Latino ethnicity)
Total minority population                              5,537      13,379    221,983      240,899 Percent minority                                      11.1      11.7      32.8        28.6 Source: USCB 2015e 4 According to the USCBs 2014 and 2013 American Community Survey estimates, since 2010 5 minority populations in the ROI were estimated to have increased by approximately 6 17,700 persons and now comprise 30.5 percent of the ROI population (see Table 3-21). The 7 largest increase occurred in the Hispanic or Latino population (nearly 8,900 persons since 2010, 8 an increase of 7.5 percent). The next largest increase in minority population was Asian, an 9 increase of approximately 5,800 persons or 18.5 percent from 2010 (USCB 2015f).
10          Table 3-21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County)
Grundy(a)  LaSalle        Will          ROI Total Population                                50,425      111,241    685,419        847,085 Race (percent of total population, Not-Hispanic or Latino)
White                                            87.4        86.9      65.3          69.5 Black or African American                        1.4        2.1        11.3          9.5 American Indian & Alaska Native                  0.1        0.2        0.1            0.1 Asian                                            0.8        0.9        5.3            4.4 Native Hawaiian & Other Pacific Islander        0.0        0.0        0.0            0.0 Some other race                                  0.0        0.0        0.0            0.0 Two or more races                                1.0        1.0        1.4            1.4 3-87
 
Affected Environment Grundy(a)  LaSalle        Will      ROI Ethnicity Hispanic or Latino                                  4,667      9,854      113,470    127,991 Percent of total population                          9.3        8.9        16.6      15.1 Minority population (including Hispanic or Latino ethnicity)
Total minority population                            6,351      14,558      237,731    258,640 Percent minority                                    12.6      13.1        34.7      30.5 (a) 2011-2013 American Community Survey 3-Year Estimates.
Source: USCB 2015f 1 3.10.3.1      Transient Population 2 Within 50 mi (80 km) of LSCS, colleges and recreational opportunities attract daily and seasonal 3 visitors who create a demand for temporary housing and services. In 2015, approximately 4 57,000 students attended colleges and universities within 50 mi (80 km) of LSCS 5 (NCES 2015a).
6 Based on 2009-2013 American Community Survey 5-Year Estimates, approximately 7 23,000 seasonal housing units are located within 50 mi (80 km) of LSCS. Of those, 1,785 were 8 located in the LSCS ROI. Table 3-22 presents information about seasonal housing for the 9 counties located all or partly within 50 mi (80 km) of LSCS.
10  Table 3-22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of LSCS Vacant Housing Units:
for Seasonal, Recreational, or County(a)                            Total Housing Units            Occasional Use      Percent Illinois Bureau                                      15,679                        216          1.4 Cook                                      2,176,266                      16,059          0.7 DeKalb                                      40,983                        246          0.6 DuPage                                      356,217                      1,125          0.3 Ford                                          6,259                          7          0.1 Grundy                                      20,027                        187          0.9 Iroquois                                    13,452                        200          1.5 Kane                                        182,145                        623          0.3 Kankakee                                    45,135                        436          1.0 Kendall                                      40,415                          35          0.1 LaSalle                                      49,905                        744          1.5 Lee                                          15,035                        313          2.1 Livingston                                  15,851                          55          0.3 McLean                                      69,979                        390          0.6 Marshall                                      5,905                        405          6.9 3-88
 
Affected Environment Vacant Housing Units:
for Seasonal, Recreational, or County(a)                                Total Housing Units                  Occasional Use              Percent Ogle                                              22,558                              377              1.7 Peoria                                            83,162                              114              0.1 Putnam                                              3,084                              375              12.2 Tazewell                                          57,608                              164              0.3 Will                                            237,806                                854              0.4 Woodford                                          15,207                              109              0.7 Total                                        3,472,678                            23,034                1.6 (a) Counties within 50 mi (80 km) of LSCS with at least one block group located within the 50-mi (80-km) radius.
Note: ROI counties are in bold italics.
Source: USCB 2015g 1 3.10.3.2      Migrant Farm Workers 2 Migrant farm workers are individuals whose employment requires travel to harvest agricultural 3 crops. These workers may or may not have a permanent residence. Some migrant workers 4 follow the harvesting of crops, particularly fruit, throughout rural areas of the United States.
5 Others may be permanent residents living near LSCS and travel from farm to farm harvesting 6 crops.
7 Migrant workers may be members of minority or low-income populations. Because they travel 8 and can spend a significant amount of time in an area without being actual residents, migrant 9 workers may be unavailable for counting by census takers. If uncounted, these minority and 10 low-income workers would be underrepresented in the decennial Census population counts.
11 In the 2002 Census of Agriculture, farm operators were asked for the first time whether or not 12 they hired migrant workersdefined as a farm worker whose employment required travelto 13 do work that prevented the migrant workers from returning to their permanent place of residence 14 the same day. The Census is conducted every 5 years and results in a comprehensive 15 compilation of agricultural production data for every county in the nation.
16 Information about migrant and temporary labor (working less than 150 days) was collected in 17 the 2012 Census of Agriculture. Table 3-23 supplies information about migrant and temporary 18 farm labor within 50 mi (80 km) of LSCS. According to the 2012 Census, approximately 19 12,000 farm workers were hired to work for less than 150 days and were employed on 20 5,563 farms within 50 mi (80 km) of LSCS. The county with the highest number of temporary 21 farm workers (1,101) on 253 farms was DeKalb County, Illinois (NASS 2015).
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Affected Environment 1      Table 3-23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 2                                      within 50 mi (80 km) of LSCS (2012)
Number of Number of Farms          Number of Farm                Farms Number of Farms          Hiring Workers for      Workers Working            Reporting with Hired Farm            Less Than 150          for Less Than          Migrant Farm County(a)                      Labor(b)                  Days(b)              150 Days(b)              Labor(b)
Illinois Bureau                            357                        308                  877                        7 Cook                              55                        32                  195                        0 DeKalb                            338                        253                1,101                        7 DuPage                            38                        29                  258                        3 Ford                              175                        136                  329                        4 Grundy                            144                        119                  258                        0 Iroquois                          482                        385                  909                        2 Kane                              220                        133                  472                        3 Kankakee                          258                        225                  837                      17 Kendall                          127                        99                  263                        2 LaSalle                          526                        411                  933                        8 Lee                              271                        224                  506                        1 Livingston                        459                        369                  840                        3 McLean                            565                        422                  951                        2 Marshall                          137                        110                  303                        1 Ogle                              318                        240                  534                        0 Peoria                            199                        162                  546                        4 Putnam                            53                        44                    (D)                      0 Tazewell                          265                        215                  735                        3 Will                              278                        212                  694                        3 Woodford                          298                        242                  685                        1 Total                          5,563                      4,370              12,226                      71 (a) Counties within 50 mi of LSCS with at least one block group located within the 50 mi radius.
(b) Table 7. Hired farm Labor - Workers and Payroll: 2012.
ROI counties are in bold italics. (D) Indicates that data was withheld to avoid disclosing data for individual farms.
Source: 2012 Census of Agriculture - County Data (NASS 2015) 3 A total of 71 farms, in the 50-mi (80 km) radius of the LSCS, reported hiring migrant workers in 4 the 2012 Census. Kankakee County, Illinois, reported the most farms with migrant farm labor 5 (17 farms) (NASS 2015).
6 3.10.4      Housing and Community Services 7 This section presents information regarding housing and local public services, including 8 education and water supply.
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Affected Environment 1 3.10.4.1    Housing 2 Table 3-24 lists the total number of occupied and vacant housing units, vacancy rates, and 3 median value in the ROI. Based on USCBs 2014 American Community Survey estimates, 4 there were nearly 310,000 housing units in the ROI, of which nearly 285,000 were occupied.
5 The median values of owner-occupied housing units in the ROI range from $121,700 in LaSalle 6 County to $209,400 in Will County. The vacancy rate also varied considerably between the 7 three counties, from 6.6 percent in Will County to 13.9 percent in LaSalle County 8 (USCB 2015h).
9                        Table 3-24. Housing in the LSCS ROI (2014 estimate)
Grundy(a)          LaSalle        Will            ROI Total housing units                  20,078              49,867      239,857        309,802 Occupied housing units                18,119              42,956      224,012        285,087 Total vacant housing units              1,959              6,911      15,845          24,715 Percent total vacant                      9.8                13.9          6.6            8.0 Owner occupied units                  13,706              32,020      180,129        225,855 Median value (dollars)              178,200            121,700      209,400        195,073 Owner vacancy rate (percent)              3.2                1.4          0.9            1.1 Renter occupied units                  4,413            10,936      43,883          59,232 Median rent (dollars/month)              953                685      1,054            978 Rental vacancy rate (percent)            5.4                11.9          4.4            5.9 (a) 2011-2013 American Community Survey 3-Year Estimates.
Source: USCB 2015h 10 3.10.4.2    Education 11 Grundy County has 12 public school districts with 24 public schools and approximately 12 13,000 students during the 2013-2014 school year. LaSalle County, the county in which LSCS 13 is located, has 26 public school districts with 47 public schools and approximately 14 17,000 students during the 2013-2014 school year. Will County has 30 public school districts 15 with 171 public schools and approximately 117,000 students during the 2013-2014 school year 16 (NCES 2015b).
17 3.10.4.3    Public Water Supply 18 The City of LaSalle pumps and treats groundwater. The city's water treatment and distribution 19 system serves the City of LaSalle. The City of LaSalle treatment plant has a treatment capacity 20 of approximately 500,000 gallons per day. Water and wastewater treatment services are 21 provided by a number of townships and municipalities in LaSalle County which service 22 residential, commercial, and industrial customers. Other residents within the county are served 23 by private, onsite well and wastewater disposal systems.
24 Table 3-25 lists the largest public water suppliers in Grundy, LaSalle, and Will Counties and 25 provides water source and population served for those suppliers. Most of the major public water 26 suppliers in Grundy, LaSalle, and Will Counties obtain their supplies from groundwater.
27 Currently, there is excess capacity in every major public water system in the three counties.
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Affected Environment 1                          Table 3-25. Local Public Water Supply Systems Public Water System                    Source                  Population Served(a)
Grundy County Coal City                              Groundwater                    5,587 Diamond                                Groundwater                    2,200 Minooka                                Groundwater                    10,924 Morris                                  Groundwater                    12,000 LaSalle County Illinois American-Streator              Surface water                  19,000 LaSalle                                Groundwater                    9,700 Marseilles                              Groundwater                    4,800 Mandota                                Groundwater                    7,272 Oglesby                                Groundwater                    4,000 Ottawa                                  Groundwater                    18,307 Peru                                    Groundwater                    11,000 Seneca                                  Groundwater                    2,371 Utility Inc. - Lake Holiday            Groundwater                    6,479 Exelon/LaSalle                          Groundwater                    1,000 Will County Aqua Illinois - University Park        Groundwater                    6,913 Aqua Illinois - Willowbrook            Groundwater                    3,422 Breecher                                Groundwater                    4,359 Braidwood                              Groundwater                    6,191 Channahon                              Groundwater                    9,160 Crest Hill                              Groundwater                    20,837 Crete                                  Groundwater                    8,259 Elwood                                  Groundwater                    2,300 Frankfort                              Groundwater                    24,648 Illinois American - Homer Township      Surface water purchased        22,036 Illinois American - West Suburban      Surface water purchased        66,429 Joliet                                  Groundwater                  147,589 Lockport                                Groundwater                    24,839 Lockport Township Water System          Groundwater                    2,610 Manhattan                              Groundwater                    6,000 Mokena                                  Surface water purchased        19,500 Monee                                  Groundwater                    5,148 New Lenox                              Surface water purchased        24,394 Peotone                                Groundwater                    4,142 Plainfield                              Surface water purchased        36,600 Romeoville                              Groundwater                    52,000 3-92
 
Affected Environment Public Water System                                Source                    Population Served(a)
Shorewood                                          Groundwater                      15,615 Southeast Joliet                                    Groundwater                      2,000 Stateville Correctional Center                      Groundwater purchased            3,500 Wilmington                                          Surface water                    5,724 (a) Safe Drinking Water Search for the State of Illinois (EPA 2015e).
Source: EPA 2015e 1 3.10.5      Tax Revenues 2 Exelon pays taxes on LSCS property to LaSalle County, public schools, libraries, townships, 3 districts, and other taxing authorities. Property taxes paid by Exelon for LSCS for the years of 4 2007 through 2013 are listed in Table 3-26. As shown in the table, total property tax payments 5 for the reported years fluctuated from year to year.
6 Property taxes paid on LSCS are based partially on settlement agreements for the valuation of 7 the power block, with the remaining land taxed on the assessment of fair market value, as 8 established by Illinois State tax law. Power block tax payments have been approximately 9 98 percent of the total tax payment. Settlement agreements in 1999 and 2006 covered the 10 years 2000 through 2004 and 2005 through 2008, respectively. Negotiations for the next 11 settlement agreement began in 2009 and was not completed until mid-2013. Consequently, 12 without the settlement agreement, the LaSalle County tax assessor increased the assessed 13 value of the LSCS power block, which resulted in sharply increased tax payments by Exelon.
14 As shown in Table 3-26, tax payments more than doubled in 2009 in keeping with the increased 15 assessment of the power block made by the County Assessor, as affirmed or amended on 16 appeal by the LaSalle County Board of Review. Based on independent appraisals, Exelon 17 appealed the assessments for tax years 2009 through 2012 to the Illinois Property Tax Appeal 18 Board because the company did not believe the assessments accurately reflected the value of 19 the LSCS power block. In July 2013, Exelon and all taxing bodies agreed to a new long-term 20 settlement agreement that sets the Equalized Assessed Value of the LSCS power block for the 21 next 7 years, starting with the 2013 tax year. The settlement agreement was fully executed and 22 approved by the Court for the 13th Judicial District in LaSalle County, Illinois, in February 2014.
23 At the request of all parties, the Property Tax Appeal Board dismissed the appeals with 24 prejudice in May 2014 (Exelon 2014a).
25 Exelon intends to negotiate additional tax settlement agreements during the license renewal 26 term, as it helps the company and taxing authorities plan for future income revenue and 27 expenditures (Exelon 2014a).
28    Table 3-26. LSCS Power Block Tax Payments and Valuations 2007-2014 (in dollars)
Equalized Assessed Year                  Value                    Inferred Fair Market Value  Taxes Paid by Exelon 2007                235,000,000(a)                      1,566,700,000            12,258,540 2008                235,000,000(a)                      1,566,700,000            12,181,812 2009                525,000,000(b)                      3,571,500,000            24,595,282 2010                525,000,000(b)                      3,571,500,000            24,652,781 3-93
 
Affected Environment Equalized Assessed Year                  Value          Inferred Fair Market Value        Taxes Paid by Exelon 2011                504,000,000(b)              3,360,000,000                23,888,466 2012                488,250,000(b)              3,255,000,000                23,383,171 2013                485,000,000(a)              3,233,333,333                23,749,334 2014                455,000,000(a)              3,033,333,333                22,490,721 (a) Under  settlement agreement.
(b) Set by Board of Review.
NA=Not available.
Source: Exelon 2014a, 2015c 1 Taxes paid in 2013 to local taxing bodies constitute between 94 percent and less than 1 percent 2 of the total levy for any individual taxing body, as shown in Table 3-27. Tax payments under 3 any new settlement agreement would likely continue at similar percentages (Exelon 2014a).
4    Table 3-27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total Levy Exelon Payment          Total levy    Percent of total Taxing Body                                          (dollars)          (dollars)        levy (%)
Brookfield Township                                  76,547              81,290            94 Brookfield Township Road                            409,211            432,957              94 South Prairie Park District                          32,009              35,118            91 Allen-Brookfield District                            34,719              39,041            89 Seneca Grade School # 170                        6,424,862          7,330,695              87 Seneca High School # 160                          8,816,393          10,602,732              83 Seneca Library                                      608,884            731,132              83 Seneca Fire-Ambulance                              491,752            633,545              78 Marseilles Fire District                            536,095            777,223              69 Illinois Valley Community College # 513          1,790,079          8,027,119              22 LaSalle County                                    4,772,514          23,342,931              20 Allen Fire District                                    5,354            151,128              3 Allen Township                                        2,913              97,044              3 Allen Township Road                                    3,950            128,063              3 Allen Township School # 65                          20,340          1,125,258              2 City of Marseilles                                      697            963,696              <1 Grand Ridge School # 95                                  364          2,289,613              <1 Marseilles Library                                        53            70,300            <1 Ottawa High School # 140                                288        12,691,310              <1 Reddick Library                                            32        2,289,613              <1 Streator High School # 40                              3,645          5,512,552              <1 Village of Ransom                                        136              36,982            <1 Source: Exelon 2014a 3-94
 
Affected Environment 1 In addition, Exelon makes annual payments to the Illinois Emergency Preparedness Agency for 2 LSCS. These annual payments are listed in Table 3-28. Smaller amounts are paid on an 3 intermittent and voluntary basis to local emergency management agencies and government 4 agencies that participate in emergency management activities.
5      Table 3-28. Annual Payments to Illinois Emergency Management Agency 2009-2014 Year          Amount Paid (dollars) 2009                  3,356,117 2010                  3,575,454 2011                  3,790,603 2012                  4,084,540 2013                  4,084,540 2014                  4,014,846 Source: Exelon 2014a 6 Exelon anticipates no change in State or local tax laws, rates or assessments that would result 7 in notable future increases or decreases in property taxes or other payments to State or local 8 governments with respect to LSCS during the license renewal term. However, new property tax 9 settlement agreements could result in higher property tax assessments and higher property tax 10 payments.
11 3.10.6      Local Transportation 12 The region surrounding LSCS has a highly developed roadway network. Interstate 80 (I-80) 13 runs east and west approximately 8 mi (13 km) north of LSCS. Interstate 55 runs northeast to 14 southwest approximately 15 mi (24 km) east of LSCS. US-51/I-39 runs north and south 15 approximately 21 mi (35 km) west of LSCS. Interstate 80 and I-55 provide access to the LSCS 16 site from Chicago to the northeast.
17 County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, runs parallel to 18 LSCSs southern boundary and provides access to the LSCS site. State Highway 170 is 0.5 mi 19 (0.8 km) east of the site and County Road 30, also known as East 25th Road, is slightly west of 20 the site. The Chicago, Rock Island & Pacific Railroad is the closest railroad line to LSCS. It 21 runs parallel to and slightly north of the Illinois River. A 6 mi (10 km) rail spur connects LSCS to 22 the Atchison, Topeka, and Santa Fe Railroad south of the site (Exelon 2014a).
23 Table 3-29 lists commuting routes to the LSCS site and average annual daily traffic volume 24 values. The average annual daily traffic values represent traffic volumes for a 24-hour period 25 factored by both the day of the week and the month of the year.
26      Table 3-29. Major Commuting Routes in the Vicinity of LSCS: 2013-2014 Average 27                                      Annual Daily Traffic Count Average Annual Daily Roadway and Location                                                            Traffic (AADT)
County Road 6 (North 21st Road) near LSCS                                            2,200 County Road 6 (North 21st Road) and Illinois 170 (East 29th Road)                    1,800 Illinois 170 (East 29th Road) between River Street and US 6 in Seneca                7,500 3-95
 
Affected Environment Average Annual Daily Roadway and Location                                                                Traffic (AADT)
I-80 at US 6                                                                            30,200 County Road 30 (East 25th Road) and County Road 6 (North 21st Road)                      1,350 County Road 30 (East 25th Road) and County Road 15 (Main Street)                          3,800 County Road 15 (Main Street) in Marseilles                                                6,600 County Road 15 (Rutland Street)                                                          5,200 I-80 at County Road 15 (Rutland Street)                                                  29,100 I-80 at Illinois 23 (Columbus Street)                                                    30,100 Illinois 23 (Columbus Street) south                                                      18,500 Illinois 23/71 (Columbus Street) in Ottawa                                              12,300 Illinois 23/71 (Columbus Street) over Illinois River                                    27,500 Illinois 23 (Bloomington Avenue) and County Road 6 (East Main Street)                    6,500 County Road 6 (East Main Street)                                                          2,650 Source: Illinois DOT 2015 1 3.11    Human Health 2 3.11.1      Radiological Exposure and Risk 3 As required by NRC regulation 10 CFR 20.1101, Exelon has a radiation protection program 4 designed to protect onsite personnel, including employees, contractor employees, visitors, and 5 offsite members of the public from radiation and radioactive material generated at LSCS.
6 The radiation protection program is extensive and includes, but is not limited to the following:
7
* Organization and Administration (i.e., a Radiation Protection Manager who is 8              responsible for the program and having trained and qualified workers),
9
* Implementing procedures, 10
* ALARA Program to minimize dose to workers and members of the public, 11
* Dosimetry Program (i.e., measure radiation dose of plant workers),
12
* Radiological Controls (i.e., protective clothing, shielding, filters, respiratory 13              equipment, and individual work permits with specific radiological requirements),
14
* Radiation Area Entry and Exit Controls (i.e., locked or barricaded doors, interlocks, 15              local and remote alarms, personnel contamination monitoring stations),
16
* Posting of Radiation Hazards (i.e., signs and notices alerting plant personnel of 17              potential hazards),
18
* Record Keeping and Reporting (i.e., documentation of worker dose and radiation 19              survey data),
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Affected Environment 1
* Radiation Safety Training (i.e., classroom training and use of mockups to simulate 2            complex work assignments),
3
* Radioactive Effluent Monitoring Management (i.e., control and monitor radioactive 4            liquid and gaseous effluents released into the environment),
5
* Radioactive Environmental Monitoring (i.e., sampling and analysis of environmental 6            media, such as air, water, vegetation, food crops, direct radiation, and milk to 7            measure the levels of radioactive material in the environment that may impact human 8            health), and 9
* Radiological Waste Management (i.e., control, monitor, process, and dispose of 10            radioactive solid waste).
11 Regarding the radiation exposure to LSCS personnel, the NRC staff reviewed the data 12 contained in NUREG-0713, Occupational Radiation Exposure at Commercial Nuclear Power 13 Reactors and Other Facilities 2012: Forty-Fifth Annual Report (NUREG-0713, Volume 34) 14 (NRC 2014b). This report, which was the most recent available at the time of this review, 15 summarizes the occupational exposure data through 2012 that are maintained in the NRCs 16 Radiation Exposure Information and Reporting System database. Nuclear power plants are 17 required by 10 CFR 20.2206 to report their occupational exposure data to the NRC annually.
18 NUREG-0713 calculates a 3-year average collective dose per reactor for all nuclear power 19 reactors licensed by the NRC. The 3-year average collective dose is one of the metrics that the 20 NRC uses in the Reactor Oversight Program to evaluate the applicants ALARA program.
21 Collective dose is the sum of the individual doses received by workers at a facility licensed to 22 use radioactive material over a 1-year time period. There are no NRC or EPA standards for 23 collective dose. Based on the data for operating BWRs like those at LSCS, the average annual 24 collective dose per reactor was 133 person-rem. In comparison, LSCS had a reported annual 25 collective dose per reactor of 158 person-rem.
26 In addition, as reported in NUREG-0713, for 2012, no worker at LSCS received an annual dose 27 greater than 2.0 rem (0.02 Sv), which is less than half of the NRC occupational dose limit of 28 5.0 rem (0.05 Sv) in 10 CFR 20.1201.
29 3.11.2    Chemical Hazards 30 The use, storage, and discharge of chemicals, biocides, and sanitary wastes, as well as minor 31 chemical spills are regulated by state and Federal environmental agencies. Chemical hazards 32 to LSCSs workers during the license renewal term are expected to be minimized by 33 implementing good industrial hygiene practices as required by Federal and State regulations.
34 Discharges of chemical and sanitary wastes are monitored and controlled as part of the LSCSs 35 NPDES permit IL0048151 to minimize impacts to the public and the environment 36 (Exelon 2014a).
37 3.11.3    Microbiological Hazards 38 Nuclear plants such as LSCS that discharge thermal effluents to cooling ponds, lakes, canals, 39 or rivers have the potential to promote the increased growth of thermophilic microorganisms, 40 which could result in adverse health effects for plant workers and the public. Microorganisms of 41 particular concern include several types of bacteria (Legionella spp., Salmonella spp.,
42 Shigella spp., thermophilic fungi, and Pseudomonas aeruginosa) and the free-living amoeba 43 Naegleria fowleri.
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Affected Environment 1 Nuclear plant workers can be exposed to Legionella spp. when performing maintenance 2 activities on plant cooling systems if workers inhale cooling tower vapors because vapors are 3 often within the optimum temperature range for Legionella growth. Plant personnel most likely 4 to come in contact with Legionella aerosols would be workers who clean biofilms off of 5 condenser tubes, cooling towers, and related system components or equipment. Exposure of 6 the public to Legionella from nuclear plant operations is generally not a concern because 7 Legionella exposure would be confined to a small area of the site within the protected area.
8 LSCS does not have cooling towers so exposure of workers to Legionella is unlikely.
9 The public can be exposed to the thermophilic microorganisms Salmonella, Shigella, 10 P. aeruginosa, and N. fowleri during swimming, boating, or other recreational uses of 11 freshwater. If a nuclear plants thermal effluent enhances the growth of thermophilic 12 microorganisms, recreational users could experience an elevated risk of exposure when using 13 waters near the plants discharge.
14 3.11.3.1    Thermophilic Microorganisms of Concern 15 Legionella is a genus of common warm water bacteria that occurs in lakes, ponds, and other 16 surface waters, as well as some groundwater sources and soils. The bacteria are pathogenic to 17 humans when aerosolized and inhaled into the lungs. Approximately 2 to 5 percent of those 18 exposed in this way to Legionella develop an acute bacterial infection of the lower respiratory 19 tract known as Legionnaires disease (Pearson 2003). Optimal growth occurs in stagnant 20 surface waters with biofilms or slimes that range in temperature from 35 to 45 &deg;C (95 to 113 &deg;F),
21 though the bacteria can persist in waters from 20 to 50 &deg;C (68 to 122 &deg;F) (Pearson 2003).
22 Elderly and immunocompromised individuals are most susceptible to Legionnaires disease 23 (Pearson 2003). According to data from the Centers for Disease Control and Prevention (CDC) 24 (CDC 2011a) from 2000 through 2009, New England and Mid-Atlantic states generally had the 25 highest number of reported legionellosis cases each year.
26 Approximately 2,000 serotypes of Salmonella spp. cause the bacterial infection salmonellosis in 27 humans. Of these, the serotypes Typhimurium and Enteritidis are the most common in the 28 United States (CDC 2010a). Salmonellosis is most common in summer months, and it is 29 transmitted through contact with food, water, or animals contaminated with human or animal 30 feces (CDC 2010a). The bacteria have an optimal growth temperature of 37 &deg;C (98.6 &deg;F) but 31 can grow at temperatures ranging from 6 to 46 &deg;C (43 to 115 &deg;F) (Albrecht 2013a). Studies 32 examining the persistence of Salmonella spp. outside of a host have found that Salmonella can 33 survive for several months in water and in aquatic sediments (Moore et al. 2003).
34 Shigella is a genus of bacteria species that causes shigellosis (i.e., bacterial dysentery), which 35 is spread through consuming fecal-contaminated food or water, by swimming in contaminated 36 water, or by contact with an infected person through contaminated feces and unhygienic 37 handling of food. Its optimum growth temperature is 37 &deg;C (98.6 &deg;F), though it can grow in water 38 temperatures ranging from 10 to 40 &deg;C (50 to 104 &deg;F) (Albrecht 2013b). Shigellosis is most 39 common in summer months and among toddlers age 2 to 4 who are not fully toilet trained and in 40 childcare settings (CDC 2013e).
41 Pseudomonas aeruginosa is a free-living bacterium found in soil, water, sewage, plant surfaces 42 and the skin of healthy individuals. It is most commonly linked to infections transmitted in 43 healthcare settings. However, as a waterborne pathogen, it can cause ear infections 44 (i.e., swimmers ear), eye infections, and skin rashes after exposure to contaminated hot tubs, 45 swimming pools, or other recreational waters (CDC 2013a). Its optimum growth temperature is 46 37 &deg;C (98.6 &deg;F), though it can grow at temperatures as high as 42 &deg;C (107.6 &deg;F) (Todar 2004).
47 P. aeruginosa almost exclusively infects immunocompromised individuals or already injured or 48 inflamed sites on the skin (Todar 2004).
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Affected Environment 1 Naegleria fowleri is a free-living amoeba that occurs in warm lakes, rivers, or hot springs. It is 2 the causative agent of human primary amoebic meningoencephalitis (PAM). Infection occurs 3 when contaminated freshwater enters the nose, and the amoeba migrates to brain tissue; the 4 ensuing illness is usually fatal (CDC 2013b). N. fowleri grows best at higher temperatures up to 5 46 &deg;C (115 &deg;F) (CDC 2013b), though it has also been isolated from thermally altered waters 6 surrounding power plant discharges at temperatures ranging from 35 to 41 &deg;C (95 to 105.8 &deg;F) 7 (Stevens et al. 1977).
8 3.11.3.2    Prevalence of Waterborne Diseases Associated with Recreational Waters 9 From 2002 through 2011, the CDC (2003, 2004a, 2005, 2006a, 2007, 2008a, 2009, 2010b, 10 2011b, 2012) reported an average of 2,774 cases of Legionnaires disease per year, of which 11 between 28 and 151 per year were reported from Illinois.
12 The Illinois Department of Public Health (IDPH) indicates that approximately 1,500 to 13 2,000 cases of salmonellosis are reported in the State each year (IDPH 2009), and the 14 overwhelming majority of salmonellosis cases are foodborne (CDC 2010a). The CDC reports 15 biannually on waterborne disease outbreaks associated with recreational waters. A review of 16 the past 10 available data years (1999 through 2008) of these reports indicates that no 17 outbreaks or cases of waterborne Salmonella infection from recreational waters occurred in the 18 United States during this timeframe (CDC 2002, 2004b, 2006b, 2008b, 2011c). From 2006 to 19 2013, all CDC-reported salmonellosis outbreaks have been caused by contaminated produce, 20 meats, or prepared foods or through contact with contaminated animals (CDC 2013d).
21 Approximately 1,300 confirmed cases of shigellosis are reported in Illinois each year 22 (IDPH 2013). CDC reports (2002, 2004b, 2006b, 2008b, 2011c) indicate that less than a 23 dozen shigellosis outbreaks have been attributed to lakes, reservoirs, and other recreational 24 waters in the past 10 available data years (1999 through 2008). None of these cases was 25 in Illinois.
26 Infections attributed to Pseudomonas aeruginosa are most commonly contracted in pools, spas, 27 and hot tubs. No cases of infection linked to contaminated recreational waters in the 28 United States have been reported within the past 10 available data years (1999 through 2008) 29 (CDC 2002, 2004b, 2006b, 2008b, 2011c).
30 The N. fowleri-caused disease, PAM, is rare in the United States. Since 1962, between zero 31 and eight cases of PAM have been reported to the CDC annually, and no cases have been 32 reported in Illinois (CDC 2013c).
33 3.11.4    Electromagnetic Fields 34 Based on the GEIS, the Commission found that electric shock resulting from direct access to 35 energized conductors or from induced charges in metallic structures has not been found to be a 36 problem at most operating plants and generally is not expected to be a problem during the 37 license renewal term. However, a site-specific review is required to determine the significance 38 of the electric shock potential along the portions of the transmission lines that are within the 39 scope of this SEIS.
40 In the GEIS, the NRC found that without a review of the conformance of each nuclear plant 41 transmission line with National Electrical Safety Code (NESC) criteria, it was not possible to 42 determine the significance of the electric shock potential (IEEE 2002). Evaluation of individual 43 plant transmission lines is necessary because the issue of electric shock safety was not 44 addressed in the licensing process for some plants. For other plants, land use in the vicinity of 45 transmission lines may have changed, or power distribution companies may have chosen to 46 upgrade line voltage. To comply with 10 CFR 51.53(c)(3)(ii)(H), the applicant must provide an 3-99
 
Affected Environment 1 assessment of the impact of the proposed action on the potential shock hazard from the 2 transmission lines if the transmission lines that were constructed for the specific purpose of 3 connecting the plant to the transmission system do not meet the recommendations of the NESC 4 for preventing electric shock from induced currents. The NRC uses the NESC criteria and the 5 applicants adherence to those criteria during the current operating license as a baseline to 6 assess the potential human health impact of the induced current from an applicants 7 transmission lines. As discussed in the GEIS, the issue of electric shock is of small significance 8 for transmission lines that are operated in adherence with the NESC criteria.
9 As discussed in Section 3.1.6 of this SEIS, transmission lines that are within the scope of the 10 NRCs license renewal environmental review are limited to those transmission lines that connect 11 the nuclear plant to the substation where electricity is fed into the regional distribution system 12 and transmission lines that supply power to the nuclear plant from the grid (NRC 2013).
13 As indicated by Exelon in its ER, no offsite transmission lines are in-scope for the environmental 14 review for license renewal. The only transmission lines that are in scope for license renewal are 15 onsite; the lines from the LSCS power block to the LSCS switchyard (Exelon 2014a). The 16 public does not have access to this area and could not come into contact with these lines.
17 Therefore, there is no potential shock hazard to members of the public from these transmission 18 lines. As discussed in Section 3.11.5 of this SEIS, LSCS maintains an occupational safety 19 program in accordance with the Occupational Safety & Health Administration regulations for its 20 workers, which includes protection from acute electric shock.
21 3.11.5    Other Hazards 22 Two additional human health issues are addressed in this section: physical occupational 23 hazards and electric shock hazards.
24 Nuclear power plants are industrial facilities that have many of the typical occupational hazards 25 found at any other electric power generation facility. Workers at or around nuclear power plants 26 would be involved in some electrical work, electric power line maintenance, repair work, and 27 maintenance activities and exposed to some potentially hazardous physical conditions 28 (e.g., falls, excessive heat, cold, noise, electric shock, and pressure). The issue of physical 29 occupational hazards is generic to all nuclear power plants.
30 The Occupational Safety and Health Administration (OSHA) is responsible for developing and 31 enforcing workplace safety regulations. OSHA was created by the Occupational Safety and 32 Health Act of 1970 (29 USC 651 et seq.), which was enacted to safeguard the health of 33 workers. With specific regard to nuclear power plants, plant conditions that result in an 34 occupational risk, but do not affect the safety of licensed radioactive materials, are under the 35 statutory authority of OSHA rather than the NRC as set forth in a Memorandum of 36 Understanding (53 FR 43950) between the NRC and OSHA. Occupational hazards can be 37 minimized when workers adhere to safety standards and use appropriate protective equipment; 38 however, fatalities and injuries from accidents can still occur.
39 LSCS participates in the OSHA Voluntary Protection Program (VPP) (OSHA 2015a). The VPP 40 recognizes employers and workers in the private industry and federal agencies who have 41 implemented effective safety and health management systems and maintain injury and illness 42 rates below national Bureau of Labor Statistics averages for their respective industries. In the 43 VPP, management, labor, and OSHA establish cooperative relationships at workplaces that 44 have implemented a comprehensive safety and health management system. Approval into VPP 45 is OSHAs official recognition of the outstanding efforts of employers and employees who have 46 achieved exemplary occupational safety and health (OSHA 2015b). LSCS holds the Star 47 rating in the VPP, which indicates participants whose safety and health management systems 3-100
 
Affected Environment 1 operate in a highly effective, self-sufficient manner and meet all VPP requirements. Star is the 2 highest level of VPP participation (OSHA 2008).
3 3.12    Environmental Justice 4 Under Executive Order (EO) 12898 (59 FR 7629), Federal agencies are responsible for 5 identifying and addressing, as appropriate, disproportionately high and adverse human health 6 and environmental impacts on minority and low-income populations. Independent agencies, 7 such as the NRC, are not bound by the terms of EO 12898 but are, as stated in 8 paragraph 6-604 of the EO, requested to comply with the provisions of [the] order. In 2004, 9 the Commission issued a Policy Statement on the Treatment of Environmental Justice Matters 10 in NRC Regulatory and Licensing Actions (69 FR 52040), which states, The Commission is 11 committed to the general goals set forth in EO 12898, and strives to meet those goals as part of 12 its NEPA review process.
13 The Council on Environmental Quality (CEQ) provides the following information in 14 Environmental Justice: Guidance Under the National Environmental Policy Act (CEQ 1997):
15            Disproportionately High and Adverse Human Health Effects.
16            Adverse health effects are measured in risks and rates that could result in latent 17            cancer fatalities, as well as other fatal or nonfatal adverse impacts on human 18            health. Adverse health effects may include bodily impairment, infirmity, illness, or 19            death. Disproportionately high and adverse human health effects occur when the 20            risk or rate of exposure to an environmental hazard for a minority or low-income 21            population is significant (as employed by NEPA) and appreciably exceeds the 22            risk or exposure rate for the general population or for another appropriate 23            comparison group (CEQ 1997).
24            Disproportionately High and Adverse Environmental Effects.
25            A disproportionately high environmental impact that is significant (as employed 26            by NEPA) refers to an impact or risk of an impact on the natural or physical 27            environment in a low-income or minority community that appreciably exceeds the 28            environmental impact on the larger community. Such effects may include 29            ecological, cultural, human health, economic, or social impacts. An adverse 30            environmental impact is an impact that is determined to be both harmful and 31            significant (as employed by NEPA). In assessing cultural and aesthetic 32            environmental impacts, impacts that uniquely affect geographically dislocated or 33            dispersed minority or low-income populations or American Indian tribes are 34            considered (CEQ 1997).
35 The environmental justice analysis assesses the potential for disproportionately high and 36 adverse human health or environmental effects on minority and low-income populations that 37 could result from the operation of LSCS during the renewal term. In assessing the impacts, the 38 following definitions of minority individuals and populations and low-income population were 39 used (CEQ 1997):
40            Minority individuals 41            Individuals who identify themselves as members of the following population 42            groups: Hispanic or Latino, American Indian or Alaska Native, Asian, Black or 43            African American, Native Hawaiian or Other Pacific Islander, or two or more 44            races, meaning individuals who identified themselves on a Census form as being 45            a member of two or more races, for example, White and Asian.
46            Minority populations 3-101
 
Affected Environment 1            Minority populations are identified when (1) the minority population of an affected 2            area exceeds 50 percent or (2) the minority population percentage of the affected 3            area is meaningfully greater than the minority population percentage in the 4            general population or other appropriate unit of geographic analysis.
5            Low-income population 6            Low-income populations in an affected area are identified with the annual 7            statistical poverty thresholds from the Census Bureau's Current Population 8            Reports, Series P60, on Income and Poverty.
9 3.12.1    Minority Population 10 According to 2010 Census data, approximately 21 percent of the population residing within a 11 50-mi (80-km) radius of LSCS identified themselves as minority individuals. The largest minority 12 group was Hispanic or Latino (of any race) (9.7 percent), followed by Black or African American 13 (6.4 percent) (USCB 2015e).
14 According to USCBs (USCBs) 2010 Census data, minority populations in the socioeconomic 15 ROI (LaSalle, Grundy, and Will Counties) composed 28.6 percent of the total three-county 16 population (see Table 3-20). Figure 3-17 shows predominantly minority population block 17 groups, using 2010 Census data for race and ethnicity, within a 50-mi (80-km) radius of LSCS.
18 Census block groups were considered minority population block groups if the percentage of the 19 minority population within any block group exceeded 21 percent (the percent of the minority 20 population within the 50-mi radius of LSCS). A minority population exists if the percentage of 21 the minority population within the block group is meaningfully greater than the minority 22 population percentage in the 50-mi (80-km) radius. Approximately 400 of the census block 23 groups located within the 50-mi (80-km) radius of LSCS have meaningfully greater minority 24 populations.
25 As shown in Figure 3-17, minority population block groups (race and ethnicity) are mostly 26 clustered near Chicago, Illinois. None of the block groups near to LSCS have meaningfully 27 greater minority populations.
28 According to the USCBs 2014 American Community Survey 1-Year Estimates, since 2010, 29 minority populations in the ROI increased by approximately 17,700 persons (an increase of 30 7.4 percent) and now comprise 30.5 percent of the ROI population (see Table 2.10.3-3). The 31 largest increases occurred in the Hispanic or Latino population (an increase of approximately 32 8,900 persons or 7.5 percent) and Asian population (an increase of approximately 33 5,800 persons or 18.5 percent) (USCB 2015b).
34 3.12.2    Low-Income Population 35 According to 2010 American Community Survey data, 9 percent of individuals residing within a 36 50-mi (80-km) radius of LSCS were identified as living below the Federal poverty threshold in 37 2010 (USCB 2015e). The 2010 Federal poverty threshold was $22,113 for a family of four.
38 Figure 3-18 shows the location of predominantly low-income population block groups within a 39 50-mi (80 km) radius of LSCS. Census block groups were considered low-income population 40 block groups if the percentage of individuals living below the Federal poverty threshold within 41 any block group exceeded the percent of the individuals living below the Federal poverty 42 threshold within the 50-mi radius of LSCS. Approximately 490 of the 1,269 census block groups 43 located within the 50-mi (80-km) radius of LSCS have meaningfully greater low-income 44 populations.
3-102
 
Affected Environment 1 As shown in Figure 3-18, low-income population block groups are evenly distributed around 2 LSCS. The LSCS site is not located in a low-income population block group. The nearest 3 low-income population block group is located south and east of the block group containing 4 LSCS.
5 According to the USCBs 2014 American Community Survey 1-Year Estimates, 10.5 percent 6 of families and 14.4 percent of individuals in Illinois were living below the Federal poverty 7 threshold and the median household and per capita incomes for Illinois was $57,444 and 8 $30,417, respectively (USCB 2015b). In the socioeconomic ROI, people living in LaSalle 9 County had median household and per capita incomes below the State average. The median 10 household and per capita income averages in LaSalle County were $50,432 and $25,129, 11 respectively, with 9.6 percent of families and 13.3 percent of individuals living below the poverty 12 level. In comparison to the State of Illinois and LaSalle County, Will County had higher median 13 household and per capita income averages ($74,828 and $32,148, respectively) and lower 14 percentages of families (6.3 percent) and individuals (7.9 percent) living below the poverty level 15 (USCB 2015b). According to the USCBs 2011-2013 American Community Survey 3-Year 16 Estimates, Grundy County also had higher median household and per capita income averages 17 ($63,978 and $28,465, respectively) and lower percentages of families (7.2 percent) and 18 individuals (9.4 percent) living below the poverty level than the State of Illinois and LaSalle 19 County (USCB 2015b).
3-103
 
Affected Environment 1        Figure 3-17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS 2                                    Source: USCB 2015e 3-104
 
Affected Environment 1 Figure 3-18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS 2                            Source: USCB 2015e 3-105
 
Affected Environment 1 3.13    Waste Management and Pollution Prevention 2 3.13.1    Radioactive Waste 3 As discussed in Section 3.1.4 of this SEIS, LSCS uses liquid, gaseous, and solid waste 4 processing systems to collect and treat, as needed, radioactive materials produced as a 5 byproduct of plant operations. Radioactive materials in liquid and gaseous effluents are 6 reduced prior to being released into the environment so that the resultant dose to members of 7 the public from these effluents is well within NRC and EPA dose standards. Radionuclides that 8 can be efficiently removed from the liquid and gaseous effluents prior to release are converted 9 to a solid waste form for disposal in a licensed disposal facility.
10 3.13.2    Nonradioactive Waste 11 Waste minimization and pollution prevention are important elements of operations at all nuclear 12 power plants. Licensees are required to consider pollution prevention measures as dictated by 13 the Pollution Prevention Act (Public Law 101-508) and Resource Conservation and Recovery 14 Act of 1976, as amended (Public Law 94-580) (NRC 2013).
15 As described in Section 3.1.5, LSCS has a nonradioactive waste management program to 16 handle nonradioactive waste in accordance with Federal, State, and corporate regulations and 17 procedures. LSCS has waste minimization measures in place, as verified during the site visit 18 conducted by the NRC staff in May 2015. This program includes appropriate recycling, thereby 19 effecting waste reduction.
20 LSCS has a Storm Water Pollution Prevention Plan (SWPPP) that identifies potential sources of 21 pollution that may affect the quality of storm water discharges from each permitted outfall. The 22 SWPPP also describes practices that are used to reduce pollutants in storm water discharges to 23 assure compliance with the sites NPDES permit. As part of LSCSs Spill Prevention Control 24 and Countermeasure Plan, measures are in place to monitor areas within the site that have the 25 potential for spills of regulated substances, such as oil (Exelon 2014a).
26 3.14    References 27 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, Standards for 28 protection against radiation.
29 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 30 production and utilization facilities.
31 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 32 protection regulations for domestic licensing and related regulatory functions.
33 10 CFR Part 61. Code of Federal Regulations, Title 10, Energy, Part 61, Licensing 34 requirements for land disposal of radioactive waste.
35 10 CFR Part 71. Code of Federal Regulations, Title 10, Energy, Part 71, Packaging and 36 transportation of radioactive material.
37 10 CFR Part 72. Code of Federal Regulations, Title 10, Energy, Part 72, Licensing 38 requirements for the independent storage of spent nuclear fuel, high-level radioactive waste, 39 and reactor-related Greater than Class C waste.
40 15 CFR Part 930. Code of Federal Regulations, Title 15, Commerce and Foreign Trade, 41 Part 930, Federal consistency with approved coastal management programs.
3-106
 
Affected Environment 1 40 CFR Part 50. Code of Federal Regulations, Title 40, Protection of Environment, Part 50, 2 National primary and secondary ambient air quality standards.
3 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 50, 4 National Primary and Secondary Ambient Air Quality Standards, Washington, DC.
5 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 51, 6 Requirements for Preparation, Adoptions, and Submittal of Implementation Plans."
7 Washington, D.C.
8 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 9 "Designation of areas for air quality planning purposes."
10 40 CFR Part 98. Code of Federal Regulations, Title 40, Protection of Environment, Part 98, 11 Mandatory Greenhouse Gas Reporting.
12 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 13 Environmental radiation protection standards for nuclear power operations.
14 40 CFR Part 230. Code of Federal Regulations, Title 40, Protection of Environment, Part 230, 15 Section 404(b)(1) Guidelines for Specification of Disposal Sites for Dredged or Fill Material.
16 49 CFR Parts 171-178. Code of Federal Regulations, Title 49, Transportation, Subchapter C 17 Hazardous Materials Regulations and Specifications for packagings.
18 50 CFR 17.3. U.S. Fish and Wildlife Service. 2006. Endangered and Threatened Wildlife and 19 Plants; Definitions.
20 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 21 Interagency CooperationEndangered Species Act of 1973, as Amended.
22 32 FR 4001. U.S. Fish and Wildlife Service. 1967. Endangered Species. Federal 23 Register 32(48):4001. March 11, 1967.
24 41 FR 41914. U.S. Fish and Wildlife Service. 1976. Endangered and Threatened Wildlife and 25 Plants; Determination of Critical Habitat for American Crocodile, California Condor, Indiana Bat, 26 and Florida Manatee. Federal Register 41(187):41914-41916. September 24, 1976.
27 53 FR 43950. U.S. Department of Labor. Memorandum of Understanding Between the 28 Nuclear Regulatory Commission and the Occupational Safety and Health Administration; 29 Worker Protection at NRC-licensed Facilities. Federal Register 53 (210):43950-43952.
30 October 31, 1988.
31 53 FR 5598. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 32 Plants; Proposal to Determine Boltonia decurrens (Decurrent false aster) to be a Threatened a 33 Threatened Species. Federal Register 53(37):5598-5602. February 25, 1988.
34 53 FR 45858. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 35 Plants; Determination of Threatened Status for Boltonia decurrens (Decurrent False Aster).
36 Federal Register 53(219):45858-45861. November 14, 1988.
37 54 FR 39857. U.S. Fish and Wildlife Service. 1989. Endangered and Threatened Wildlife and 38 Plants; Determination of Threatened Status for Eastern and Western Prairie Fringed Orchids.
39 Federal Register 54(187):29857-39863. September 28, 1989.
40 56 FR 19953. U.S. Fish and Wildlife Service. 1991. Endangered and Threatened Wildlife and 41 Plants; Dalea foliosa (Leafy Prairie-Clover) Determined to be Endangered. Federal Register 42 56(84):19953-19959. May 1, 1991.
3-107
 
Affected Environment 1 59 FR 7629. Executive Order No. 12898. Federal actions to address environmental justice in 2 minority populations and low-income populations. Federal Register 59(32):7629-7634.
3 February 16, 1994.
4 69 FR 52040. U.S. Nuclear Regulatory Commission. Policy statement on the treatment of 5 environmental justice matters in NRC regulatory and licensing actions. Federal Register 6 69(163):52040-52048. August 24, 2004.
7 69 FR 41576. U.S. Environmental Protection Agency. National Pollutant Discharge 8 Elimination SystemFinal Regulations to Establish Requirements for Cooling Water Intake 9 Structures at Phase II Existing Facilities. Federal Register 69(131):41576-41693.
10 July 9, 2004.
11 74 FR 56260. Environmental Protection Agency. Mandatory Reporting of Greenhouse 12 Gases. Federal Register 74(209): 56260-56519. October 30, 2009.
13 75 FR 31514. Environmental Protection Agency. Prevention of Significant Deterioration and 14 Title V Greenhouse Gas Tailoring Rule. Federal Register 75(106):31514-31608.
15 77 FR 14914. U.S. Fish and Wildlife Service. Endangered and Threatened Wildlife and Plants:
16 Determination of Endangered Status for the Sheepnose and Spectaclecase Mussels 17 Throughout Their Range. Federal Register 77(49):14914-14949. March 13, 2012.
18 77 FR 38762. U.S. Fish and Wildlife Service. 2012. Endangered and Threatened Wildlife and 19 Plants; 5-Year Status Reviews of Seven Listed Species. Federal Register 20 77(126):38762-38764. June 29, 2012.
21 78 FR 61046. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 22 Plants; 12-Month Finding on a Petition To List the Eastern Small-Footed Bat and the Northern 23 Long-Eared Bat as Endangered or Threatened Species; Listing the Northern Long-Eared Bat as 24 an Endangered Species; Proposed Rule. Federal Register 78(194):61046-61080.
25 October 2, 2013.
26 78 FR 72058. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 27 Plants; Listing the Northern Long-Eared Bat as an Endangered Species. Federal Register 28 78(231):72058-72059. December 2, 2013.
29 80 FR 17974. U.S. Fish and Wildlife Service. Endangered and Threatened Wildlife and 30 Plants; Threatened Species Status for the Northern Long-Eared Bat with 4(d) Rule. Federal 31 Register 80(63):17974-8033. April 2, 2015.
32 35 IAC 1420.140(a). Illinois Administrative Code, Title 35, Environmental Protection, Part 1420, 33 General Provisions, Section 140, Prohibitions.
34 35 IAC 201. Illinois Administrative Code, Title 35, Environmental Protection, "Subtitle B," Air 35 Pollution Control Board Subchapter a, "Permits and General Provisions," Part 201 Permit and 36 General Provisions.
37 35 IAC 301. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 38 Pollution," Chapter I, "Pollution Control Board," Part 301, Introduction. Illinois Pollution Control 39 Board. Available at <http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulations-40 Title35.aspx> (accessed 21 August 2015).
41 35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 42 Pollution," Chapter I, "Pollution Control Board," Part 302, Water Quality Standards. Illinois 43 Pollution Control Board. Available at <http://www.ipcb.state.il.us/SLR/IPCBandIEPA 44 EnvironmentalRegulations-Title35.aspx> (accessed 21 August 2015).
3-108
 
Affected Environment 1 35 IAC 303. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, Water 2 Pollution, Chapter I, Pollution Control Board, Part 303, Water Use Designations and Site 3 Specific Water Quality Standards. Illinois Pollution Control Board. Available at 4 <http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulations-Title35.aspx>
5 (accessed 21 August 2015).
6 35 IAC 309. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, Water 7 Pollution, Chapter I, Pollution Control Board, Part 309, Permits, Subpart A, NPDES 8 Permits. Illinois Pollution Control Board. Available at <http://www.ipcb.state.il.us/SLR/
9 IPCBandIEPAEnvironmentalRegulations-Title35.aspx> (accessed 21 August 2015).
10 35 IAC 733. Illinois Administrative Code, Title 35, Environmental Protection, Part 733, 11 Standards for Universal Waste Management.
12 35 IAC 900, Illinois Administrative Code, Title 35, Environmental Protection, Subtitle H, Noise, 13 Chapter I, "Pollution Control Board."
14 525 ILCS 45. Illinois Compiled Statutes. Chapter 525, Conservation, Act, Water Use 15 Act of 1983, as amended. Available at <http://www.ilga.gov/legislation/ilcs/
16 ilcs3.asp?ActID=1743&ChapterID=44> (accessed 21 August 2015).
17 [AEC] U.S. Atomic Energy Commission. 1973. Final Environmental Statement Related to the 18 LaSalle County Nuclear Station. February 1972. Washington, DC: AEC. 287 p. ADAMS 19 No. ML15043A501.
20 Albrecht JA. 2013a. University of Nebraska-Lincoln: UNL Food: Bacteria Causing Foodborne 21 Illness: Salmonella. Available at <http://food.unl.edu/web/safety/salmonella> (accessed 22 23 October 2013).
23 Albrecht JA. 2013b. University of Nebraska-Lincoln: UNL Food: Bacteria Causing Foodborne 24 Illness: Shigella. Available at <http://food.unl.edu/web/safety/shigella> (accessed 25 23 October 2013).
26 Arnold TL, Sullivan DJ, Harris MA, Fitzpatrick FA, Scudder BC, Ruhl PM, Hanchar DW, Stewart 27 JS. 1999. Environmental Setting of the Upper Illinois River Basin and Implications for Water 28 Quality. Urbana, IL: U.S. Geological Survey, WRD. Water-Resources Investigations 29 Report 98-4268. Available at <http://il.water.usgs.gov/nawqa/uirb/pubs/reports/WRIR_98-30 4268.pdf> (accessed 21 August 2015).
31 Ataner S, Butler S. 2013. Geologic Field Trip to the Starved Rock State Park Area, LaSalle 32 County, Illinois, Guidebook for the field trip held on October 6, 2013 in conjunction with the 50th 33 Anniversary Annual Meeting of The Clay Minerals Society held at the University of Illinois at 34 Urbana-Champaign. October 6, 2013. Available at 35 <http://www.clays.org/annual%20meeting/50th_annual_meeting_website/docs/CMS13-Fieldtrip-36 Guide-StarvedRock.pdf> (accessed 31 December 2014).
37 Bald and Golden Eagle Protection Act of 1940, as amended. 16 U.S.C. &sect;668-668c.
38 Baldwin, E. 1877. History of LaSalle County Illinois: Its Topography, Geology, Botany, Natural 39 History, History of the Mound Builders, Indian Tribes, French Explorations, and A Sketch of the 40 Pioneer Settlers of Each Town to 1840, with an Appendix, Giving the Present Status of the 41 County, Its Population, Resources, Manufactures, and Institutions. Chicago, IL: Rand McNally 42 and Company, 552 p.
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Affected Environment 1 Barbour MT, Gerritsen J, Snyder BD, Stribling JB. 1999. Rapid Bioassessment Protocols for 2 Use in Streams and Wadeable Rivers: Periphyton, Benthic Macroinvertebrates, and Fish.
3 Second Edition. Appendix C: Tolerance and Trophic Guilds of Selected Fish Species.
4 Washington, DC: U.S. Environmental Protection Agency. EPA 841-B-99-002. Available at 5 <http://water.epa.gov/scitech/monitoring/rsl/bioassessment/index.cfm> (accessed 3 April 2014).
6 [BLS] Bureau of Labor Statistics. 2015. Local Area Unemployment Statistics. July 1, 2015.
7 Available at <http://www.bls.gov/data/> (accessed October 2015).
8 [CAPS] Circular Area Profiles. 2014. Missouri Census Data Center. Circular Area Profiles 9 (CAPS) - Version 10C (Revision 4-24-14) Using Data from Summary File 1, 2010 Census. In a 10 20-mile and 50-mile radius around LSCS (41.24555 Lat., 88.66826 Long). Available at 11 <http://mcdc.missouri.edu/websas/caps10c.html> (accessed October 2015).
12 [CDC] Centers for Disease Control and Prevention. 2002. Surveillance for 13 Waterborne-Disease OutbreaksUnited States, 1999-2000. Morbidity and Mortality Weekly 14 Report 51(8):1-28. November 22, 2002. Available at <http://www.cdc.gov/mmwr/
15 preview/mmwrhtml/ss5108a1.htm> (accessed 23 October 2013).
16 [CDC] Centers for Disease Control and Prevention. 2003. Summary of Notifiable Diseases 17 United States, 2001. Morbidity and Mortality Weekly Report 50(53). Atlanta, GA: CDC.
18 May 2, 2003. 136 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5053.pdf> (accessed 19 22 October 2013).
20 [CDC] Centers for Disease Control and Prevention. 2004a. Summary of Notifiable Diseases 21 United States, 2002. Morbidity and Mortality Weekly Report 51(53). Atlanta, GA: CDC.
22 April 30, 2004. 88 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5153.pdf> (accessed 23 22 October 2013).
24 [CDC] Centers for Disease Control and Prevention. 2004b. Surveillance for 25 Waterborne-Disease Outbreaks and Other Health Events Associated with Recreational Water 26 United States, 2001-2002. Morbidity and Mortality Weekly Report 53(8):1-22.
27 October 22, 2004. Available at <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5308a1.htm>
28 (accessed 23 October 2013).
29 [CDC] Centers for Disease Control and Prevention. 2005. Summary of Notifiable Diseases 30 United States, 2003. Morbidity and Mortality Weekly Report 52(54). Atlanta, GA: CDC.
31 April 22, 2005. 88 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5254.pdf> (accessed 32 22 October 2013).
33 [CDC] Centers for Disease Control and Prevention. 2006a. Summary of Notifiable Diseases 34 United States, 2004. Morbidity and Mortality Weekly Report 53(53). Atlanta, GA: CDC.
35 June 16, 2006. 84 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5353.pdf> (accessed 36 22 October 2013).
37 [CDC] Centers for Disease Control and Prevention. 2006b. Surveillance for Waterborne 38 Disease and Outbreaks and Other Health Events Associated with Recreational Water 39 United States, 2003-2004. Morbidity and Mortality Weekly Report 55(12):1-24.
40 December 22, 2006. Available at 41 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5512a1.htm> (accessed 23 October 2013).
42 [CDC] Centers for Disease Control and Prevention. 2007. Summary of Notifiable Diseases 43 United States, 2005. Morbidity and Mortality Weekly Report 54(53). Atlanta, GA: CDC.
44 March 30, 2007. 96 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5453.pdf>
45 (accessed 22 October 2013).
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Affected Environment 1 [CDC] Centers for Disease Control and Prevention. 2008a. Summary of Notifiable Diseases 2 United States, 2006. Morbidity and Mortality Weekly Report 55(53). Atlanta, GA: CDC.
3 March 21, 2008. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5553.pdf>
4 (accessed 22 October 2013).
5 [CDC] Centers for Disease Control and Prevention. 2008b. Surveillance for Waterborne 6 Disease and Outbreaks Associated with Recreational Water Use and Other Aquatic 7 Facility-AssociatedUnited States, 2005-2006. Morbidity and Mortality Weekly 8 Report 57(9):1-29. September 9, 2008. Available at 9 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5709a1.htm> (accessed 23 October 2013).
10 [CDC] Centers for Disease Control and Prevention. 2009. Summary of Notifiable Diseases 11 United States, 2007. Morbidity and Mortality Weekly Report 56(53). Atlanta, GA: CDC.
12 July 9, 2009. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5653.pdf> (accessed 13 22 October 2013).
14 [CDC] Centers for Disease Control and Prevention. 2010a. General Information on 15 Salmonella. April 5, 2012. Available at <http://www.cdc.gov/salmonella/general/> (accessed 16 23 October 2013).
17 [CDC] Centers for Disease Control and Prevention. 2010b. Summary of Notifiable Diseases 18 United States, 2008. Morbidity and Mortality Weekly Report 57(54). Atlanta, GA: CDC.
19 June 25, 2010. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5754.pdf>
20 (accessed 22 October 2013).
21 [CDC] Centers for Disease Control and Prevention. 2011a. LegionellosisUnited States, 22 2000-2009. Morbidity and Mortality Weekly Report 60(32):1083-1086. August 19, 2011.
23 Available at <http://www.cdc.gov/mmwr/preview/mmwrhtml/mm6032a3.htm> (accessed 24 23 October 2013).
25 [CDC] Centers for Disease Control and Prevention. 2011b. Summary of Notifiable Diseases 26 United States, 2009. Morbidity and Mortality Weekly Report 58(53). Atlanta, GA: CDC.
27 May 13, 2011. 104 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5853.pdf>
28 (accessed 22 October 2013).
29 [CDC] Centers for Disease Control and Prevention. 2011c. Surveillance for Waterborne 30 Disease Outbreaks and Other Health Events Associated with Recreational Water 31 United States, 2007-2008. Morbidity and Mortality Weekly Report 60(12):1-32.
32 September 23, 2011. Available at 33 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss6012a1.htm?s_cid=ss6012a1_w> (accessed 34 23 October 2013).
35 [CDC] Centers for Disease Control and Prevention. 2012. Summary of Notifiable Diseases 36 United States, 2010. Morbidity and Mortality Weekly Report 59(53). Atlanta, GA: CDC.
37 June 1, 2012. 116 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5953.pdf> (accessed 38 22 October 2013).
39 [CDC] Centers for Disease Control and Prevention. 2013a. Pseudomonas aeruginosa in 40 Healthcare SettingsHAI. Available at <http://www.cdc.gov/hai/organisms/
41 pseudomonas.html> (accessed 23 October 2013).
42 [CDC] Centers for Disease Control and Prevention. 2013b. Naegleria fowleriPrimary 43 Amebic Meningoencephalitis (PAM). Available at <http://www.cdc.gov/parasites/naegleria/>
44 (accessed 23 October 2013).
3-111
 
Affected Environment 1 [CDC] Centers for Disease Control and Prevention. 2013c. Naegleria fowleriSources of 2 InfectionNumber of Case-reports of Primary Amebic Meningoencephalitis by State of 3 Exposure: United States, 1962-2012. June 6, 2013. Available at 4 <http://www.cdc.gov/parasites/naegleria/state-map.html> (accessed 21 October 2013).
5 [CDC] Centers for Disease Control and Prevention. 2013d. Reports of Selected Salmonella 6 Outbreak Investigations. Available at <http://www.cdc.gov/salmonella/outbreaks.html>
7 (accessed 23 October 2013).
8 [CDC] Centers for Disease Control and Prevention. 2013e. Shigellosis: General 9 InformationNCZVED. May 14, 2013. Available at <http://www.cdc.gov/nczved/divisions/
10 dfbmd/diseases/shigellosis/> (accessed 23 October 2013).
11 [CEC] Commission for Environmental Cooperation. 1997. Ecological Regions of North 12 America: Toward a Common Perspective. Available at 13 <http://www.cec.org/storage/42/3484_eco-eng_en.pdf> (accessed 5 August 2015).
14 [CEC] Commission for Environmental Cooperation. 2008. Ecoregions of North America-15 Level II. Available at <http://www.eoearth.org/view/article/152145/> (accessed 9 March 2015).
16 [CEQ] Council on Environmental Quality. 1997. Environmental Justice: Guidance under the 17 National Environmental Policy Act. Available at 18 <http://www.epa.gov/oecaerth/environmentaljustice/resources/policy/ej_guidance_nepa_ceq129 19 7.pdf>.
20 [CHC] Center for Hearing and Communication. undated. Common Environmental Noise 21 Levels Factsheet. Available at <http://www.chchearing.org/noise-center-home/facts-22 noise/common-environmental-noise-levels> (accessed 3 August 2015).
23 Clean Air Act of 1970. 42 U.S.C. &sect;7401 et seq.
24 Coastal Zone Management Act of 1972. 16 U.S.C. &sect;1451 et seq.
25 [ComEd] Commonwealth Edison Company. 1977. LaSalle County Station Environmental 26 Report Operating License Stage. Volume 1. May 10, 1977. ADAMS Nos. ML15273A414 and 27 ML15273A415.
28 Consolidated Appropriations Act of 2012. Pub. L. No. 112-74, 402, 125 Stat. 786, 883 (2011),
29 Section 402.
30 [CRA] Conestoga-Rovers & Associates. 2006. Hydrogeologic Investigation Report, Fleetwide 31 Assessment LaSalle Generating Station Marseilles, Illinois, Revision 1. September 2006.
32 ADAMS No. ML062760008.
33 [DOI] U.S. Department of the Interior, National Park Service. 1998. National Register of 34 Historic Places, Multiple Property Documentation Form, Archaeological Sites of Starved Rock 35 State Park (9,000-150 B.P.). Available at 36 http://pdfhost.focus.nps.gov/docs/NRHP/Text/64500198.pdf (accessed 16 June 2015).
37 [DOI] U.S. Department of the Interior, National Park Service. 2015. National Register of 38 Historic Places: Research. Available at <http://www.nps.gov/nr/research/> (accessed 39 28 August 2015).
40 [EA] EA Engineering, Science, and Technology, Inc. 2000. Final Report LaSalle Station 41 Aquatic Monitoring 1999, RM 249.7-248.8. Prepared for Commonwealth Edison Company, 42 Marseilles, Illinois. September 2000. Deerfield, Illinois. ADAMS No. ML15273A420.
3-112
 
Affected Environment 1 [EA] EA Engineering, Science, and Technology, Inc. 2002. Assessment of the LaSalle County 2 Station Cooling Pond. Prepared for Exelon Generation Company, LLC, March 2002. Deerfield, 3 IL. ADAMS No. ML15195A368.
4 [EA] EA Engineering, Science, and Technology, Inc. 2014. LaSalle County Station 2013 Fish 5 and Benthos Monitoring and Historical Fish and Benthos Comparisons. Prepared for Exelon 6 Generation Company, LLC, Kennett Square, Pennsylvania. May 2014. Deerfield, Illinois.
7 ADAMS No. ML15273A419.
8 [EA] EA Engineering, Science, and Technology, Inc. 2015. Final Impingement and Entrainment 9 Characterization Study LaSalle County Station. Prepared for Exelon Generation Company, 10 LLC, Kennett Square, Pennsylvania. August 2015. Deerfield, Illinois. ADAMS 11 No. ML15273A204.
12 Endangered Species Act of 1973, as amended. 16 U.S.C. &sect;1531 et seq.
13 [EPA] Environmental Protection Agency. 1974. Information on Levels of Environmental Noise 14 Requisite to Protect Public Health and Welfare with an Adequate Safety of Margin. Available at 15 <http://www.fican.org/pdf/EPA_Noise_Levels_Safety_1974.pdf> (accessed 15 July 2015).
16 [EPA] Environmental Protection Agency. 1981. Noise Effects Handbook: A Desk Reference to 17 Health and Welfare. Available at <http://nepis.epa.gov/Exe/ZyNET.exe/9100OOAJ.TXT?
18 ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=&Time=&EndTi 19 me=&SearchMethod=1&TocRestrict=n&Toc=&TocEntry=&QField=&QFieldYear=&QFieldMonth 20 =&QFieldDay=&IntQFieldOp=0&ExtQFieldOp=0&XmlQuery=&File=D%3A%5Czyfiles%5CIndex 21 %20Data%5C81thru85%5CTxt%5C00000018%5C9100OOAJ.txt&User=ANONYMOUS&Passw 22 ord=anonymous&SortMethod=h%7C-&MaximumDocuments=1&FuzzyDegree=0&ImageQuality 23 =r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchBack=ZyActionL&B 24 ack=ZyActionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x&Zy 25 PURL> (accessed 24 April 2015).
26 [EPA] Environmental Protection Agency. 1992. Clarification of Prevention of Significance 27 Deterioration (PSD) Guidance for Modelling Class I Area Impacts. Available at 28 <http://www.epa.gov/ttn/nsr/gen/u3-11.txt> (accessed 15 July 2015).
29 [EPA] Environmental Protection Agency. 2011. 2011 National Emissions Inventory Data.
30 Available at <http://www3.epa.gov/ttn/chief/net/2011inventory.html> (accessed 24 April 2015).
31 [EPA] U.S. Environmental Protection Agency. 2015a. Envirofacts Search: PCS-ICIS. [Permit 32 Compliance System (PCS) and Integrated Compliance Information System (ICIS) databases].
33 Page updated June 24, 2014. Available at <http://www.epa.gov/enviro/facts/pcs-34 icis/search.html> (accessed 31 August 2015).
35 [EPA] Environmental Protection Agency. 2015b. EPA, Enforcement and Compliance History 36 Online, Exelon LaSalle County Station. Available at <http://echo.epa.gov/?redirect=echo>
37 (accessed 22 April 2015).
38 [EPA] Environmental Protection Agency. 2015c. EPA History: Noise and the Noise Control 39 Act. Available at <http://www2.epa.gov/aboutepa/epa-history-noise-and-noise-control-act>
40 (accessed 15 July 2015).
41 [EPA] Environmental Protection Agency. 2015d. National Ambient Air Quality Standards.
42 Available at <http://www.epa.gov/air/criteria.html> (accessed 10 July 2015).
43 [EPA] U.S. Environmental Protection Agency. 2015e. Safe Drinking Water Information System 44 (SDWIS), County Search Grundy, LaSalle and Will Counties, Illinois. Available at 45 <http://www.epa.gov/enviro/facts/sdwis/search.html> (accessed October 2015).
3-113
 
Affected Environment 1 [ESPA] Illinois Compiled Statutes, Chapter 520, Wildlife, Part 10, Illinois Endangered Species 2 Protection Act.
3 [Exelon] Exelon Generation Company, LLC. 2001. Letter from W. Riffer, Regulatory Assurance 4 Manager, LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
 
5 Environmental Non-Routine Event Report for Exelon Generation Company, LLCLaSalle 6 County Station. August 17, 2001. ADAMS No. ML012330070.
7 [Exelon] Exelon Generation Company, LLC. 2002. Letter from G.T. Kaegi, Regulatory 8 Assurance Manager, LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
 
9 Environmental Protection Plan and Operating Report Appendix B to Facility License No. NPF-11 10 and NPF-18. April 29, 2002. ADAMS No. ML021330421.
11 [Exelon] Exelon Generation Company, LLC. 2009. Letter from D. Rhoads, Plant Manager, 12 LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
Environmental 13 Non-Routine Event Report for Exelon Generation Company, LLCLaSalle County Station.
14 July 22, 2009. ADAMS No. ML092040381.
15 [Exelon] Exelon Generation Company, LLC. 2010. Letter from P.J. Karaba, Plant Manager, 16 LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
Environmental Non-17 Routine Event Report for Exelon Generation Company, LLCLaSalle County Station.
18 August 25, 2010. ADAMS No. ML102371289.
19 [Exelon] Exelon Generation Co. LLC. 2011a. Illinois Water Inventory Program [LaSalle County 20 Station report submitted to the Illinois State Water Survey for calendar year 2010]. ADAMS 21 No. ML15195A385.
22 [Exelon] Exelon Generation Company, LLC. 2011b. LaSalle County Station, 2010 Radioactive 23 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 26, 2011. ADAMS 24 No. ML11124A101.
25 [Exelon] Exelon Generation Co. LLC. 2012a. Illinois Water Inventory Program [LaSalle County 26 Station report submitted to the Illinois State Water Survey for calendar year 2011]. ADAMS 27 No. ML15195A385. [RAI response SW-01]
28 [Exelon] Exelon Generation Company, LLC. 2012b. LaSalle County Station, 2011 Radioactive 29 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 20, 2012. ADAMS 30 No. ML12116A148.
31 [Exelon] Exelon Generation Co. LLC. 2013a. Illinois Water Inventory Program [LaSalle County 32 Station report submitted to the Illinois State Water Survey for calendar year 2012]. ADAMS 33 No. ML15195A385.
34 [Exelon] Exelon Generation Company, LLC. 2013b. LaSalle County Generating Station Wildlife 35 Management Plan. ADAMS No. ML15273A416.
36 [Exelon] Exelon Generation Company, LLC. 2013c. LaSalle County Station, 2012 Radioactive 37 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 26, 2013. ADAMS 38 No. ML131280052.
39 [Exelon] Exelon Generation Company, LLC. 2013d. Offsite Dose Calculation Manual (ODCM).
40 Revision 4. Marseilles, IL: Exelon Nuclear. CY-LA-170-301. April 2013. ADAMS 41 No. ML13128A059.
3-114
 
Affected Environment 1 [Exelon] Exelon Generation Company, LLC. 2013e Storm Water Pollution Prevention Plan, 2 LaSalle County Station, Marseilles, Illinois. June 2013. In Letter from M.P. Gallagher, Vice 3 President, License Renewal Projects, to NRC Document Desk.
 
==Subject:==
Response to NRC 4 Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County Station, 5 Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. ADAMS 6 No. ML15195A389.
7 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 8 Operating License Renewal Stage LaSalle County Station, Unit 1 and Unit 2. Chicago, Illinois:
9 Exelon. December 9, 2014. ADAMS Nos. ML14343A849, ML14343A883, and ML14343A897.
10 [Exelon] Exelon Generation Co. LLC. 2014b. Illinois Water Inventory Program [LaSalle County 11 Station report submitted to the Illinois State Water Survey for calendar year 2013]. ADAMS 12 No. ML15195A385.
13 [Exelon] Exelon Generation Company, LLC. 2014c. LaSalle County Station, 2013 Radioactive 14 Effluent Release Report. Marseilles, IL: Exelon Nuclear. May 1, 2014. ADAMS 15 No. ML14121A217.
16 [Exelon] Exelon Generation Company, LLC. 2014d. LaSalle County Station, Units 1 and 2 17 Seismic Hazard and Screening Report. Chicago, Illinois: Exelon. March 31, 2014. ADAMS 18 No. ML14091A013.
19 [Exelon] Exelon Generation Company, LLC. 2014e. LaSalle, Units 1 and 2, Updated Final 20 Safety Analysis Report, Revision 20, Chapter 2.0, Figure 2.5-19, Sheet 40 through 21 Figure 2.5-92. Chicago, Illinois: Exelon. April 11, 2014. ADAMS No. ML14113A086.
22 [Exelon] Exelon Generation Company, LLC. 2014f. LaSalle, Units 1 and 2, Updated Final 23 Safety Analysis Report, Revision 20, Chapter 2.0Site Characteristics. Chicago, Illinois:
24 Exelon. April 11, 2014. ADAMS No. ML14113A084.
25 [Exelon] Exelon Generation Company, LLC. 2014g. LaSalle County Station, Updated Final 26 Safety Analysis Report, Revision 20. Chicago, Illinois: Exelon. April 11, 2014. ADAMS 27 No. ML14113A099.
28 [Exelon] Exelon Generation Company, LLC. 2014h. Letter from M.P. Gallagher, Vice 29 President, License Renewal Projects, to Illinois Environmental Protection Agency, Bureau of 30 Water.
 
==Subject:==
Application for Clean Water Act Section 401 Certification associated with 31 Renewal of LaSalle County Station Units 1 and 2 Operating Licenses. February 4, 2014. In:
32 LaSalle County Station, Units 1 and 2, License Renewal Application, Appendix E, Applicants 33 Environmental Report, Operating License Renewal Stage. ADAMS No. ML14343A897 34 (Appendix B).
35 [Exelon] Exelon Generation Company, LLC. 2015a. Corrected LaSalle Groundwater Tritium 36 Concentrations. Chicago, Illinois: Exelon. July 28, 2015. ADAMS No. ML15195A402.
37 [Exelon] Exelon Generation Company, LLC. 2015b. LaSalle County Station, 2014 Radioactive 38 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 30, 2015. ADAMS 39 No. ML15120A282.
40 [Exelon] Exelon Generation Company, LLC. 2015c. Letter from M.P. Gallagher, Vice 41 President, License Renewal Projects, to the NRC Document Control Desk.
 
==Subject:==
 
===Response===
42 to NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 43 Station, Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015.
44 ADAMS No. ML15195A351.
3-115
 
Affected Environment 1 [Exelon] Exelon Generation Company, LLC. 2015d. Letter from M.P. Gallagher, Vice President 2 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 6 Review Requests for Additional Information. Response to Request for Additional Information 7 LU-01. July 2, 2015. ADAMS No. ML15195A373.
8 [Exelon] Exelon Generation Company, LLC. 2015e. Letter from M.P. Gallagher, Vice President 9 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 10 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 11 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
12 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 13 Review Requests for Additional Information. Response to Request for Additional Information 14 LU-02. July 2, 2015. ADAMS No. ML15195A374.
15 [Exelon] Exelon Generation Company, LLC. 2015f. Letter from M.P. Gallagher, Vice President 16 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 18 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
19 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 20 Review Requests for Additional Information. Response to Request for Additional Information 21 LU-03. July 2, 2015. ADAMS No. ML15195A375.
22 [Exelon] Exelon Generation Company, LLC. 2015g. Letter from M.P. Gallagher, Vice President 23 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 24 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 25 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
26 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 27 Review Requests for Additional Information. Response to Request for Additional Information 28 LU-04. July 2, 2015. ADAMS No. ML15195A376.
29 [Exelon] Exelon Generation Company, LLC. 2015h. Letter from M.P. Gallagher, Vice President 30 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 31 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 32 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
33 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 34 Review Requests for Additional Information. Response to Request for Additional Information 35 LU-05. July 2, 2015. ADAMS No. ML15195A377.
36 [Exelon] Exelon Generation Company, LLC. 2015i. Letter from M.P. Gallagher, Vice President 37 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 38 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 39 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
40 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 41 Review Requests for Additional Information. Response to Request for Additional Information 42 LU-06. July 2, 2015. ADAMS No. ML15195A378.
3-116
 
Affected Environment 1 [Exelon] Exelon Generation Company, LLC. 2015j. Letter from M.P. Gallagher, Vice President 2 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 6 Review Requests for Additional Information. Response to Request for Additional Information 7 MA-01. July 2, 2015. ADAMS No. ML15195A344.
8 [Exelon] Exelon Generation Company, LLC. 2015k. Letter from M.P. Gallagher, Vice President 9 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 10 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 11 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
12 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 13 Review Requests for Additional Information. Response to Request for Additional Information 14 MA-05. July 2, 2015. ADAMS No. ML15195A348.
15 [Exelon] Exelon Generation Company, LLC. 2015l. Letter from M.P. Gallagher, Vice President 16 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 18 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
19 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 20 Review Requests for Additional Information. Response to Request for Additional Information 21 MA-09. July 2, 2015. ADAMS No. ML15195A353.
22 [Exelon] Exelon Generation Company, LLC. 2015m. Letter from M.P. Gallagher, Vice 23 President License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
 
24 Response to NRC Request for Additional Information, dated May 22, 2015, Regarding the 25 LaSalle County Station, Units 1 and 2, License Renewal Application, Environmental Review.
26 Enclosure B: LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal 27 Environmental Review Requests for Additional Information. Response to Request for Additional 28 Information MA-10. July 2, 2015. ADAMS No. ML15195A354.
29 [Exelon] Exelon Generation Company, LLC. 2015n. Letter from M.P. Gallagher, Vice President 30 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 31 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 32 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
33 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 34 Review Requests for Additional Information. Response to Request for Additional Information 35 TE-02. July 2, 2015. ADAMS No. ML15195A380.
36 [Exelon] Exelon Generation Company, LLC. 2015o. Letter from M.P. Gallagher, Vice President 37 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 38 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 39 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
40 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 41 Review Requests for Additional Information. Response to Request for Additional Information 42 TE-03. July 2, 2015. ADAMS No. ML15195A381.
43 [Exelon] Exelon Generation Company, LLC. 2015p. Letter from M.P. Gallagher, Vice President 44 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Revisions to 45 LaSalle County Station, Units 1 and 2, License Renewal Application, Applicant's Environmental 46 Report - Operating License Renewal Stage. July 31, 2015. ADAMS No. ML15212A259.
3-117
 
Affected Environment 1 Exelon Nuclear. 2007. LaSalle County Station Units 1 and 2, Annual Radiological 2 Environmental Operating Report, 1 January Through 31 December 2006. May 2007. ADAMS 3 No. ML071410244.
4 Exelon Nuclear. 2008. LaSalle County Station Units 1 and 2, Annual Environmental Operating 5 Report, Annual Radiological Environmental Operating Report, 1 January through 6 31 December 2007. May 2008. ADAMS No. ML081420473.
7 Exelon Nuclear. 2009. LaSalle County Station Units 1 and 2, Annual Environmental Operating 8 Report, Annual Radiological Environmental Operating Report, 1 January through 9 31 December 2008. May 2009. ADAMS No. ML091350485.
10 Exelon Nuclear. 2010. LaSalle County Station Units 1 and 2, Annual Environmental Operating 11 Report, Annual Radiological Environmental Operating Report, 1 January through 12 31 December 2009. May 2010. ADAMS No. ML101320380.
13 Exelon Nuclear. 2011. LaSalle County Station Units 1 and 2, Annual Environmental Operating 14 Report, Annual Radiological Environmental Operating Report, 1 January through 15 31 December 2010. May 2011. ADAMS No. ML111320602.
16 Exelon Nuclear. 2012. LaSalle County Station Units 1 and 2, Annual Environmental Operating 17 Report, Annual Radiological Environmental Operating Report, 1 January through 18 31 December 2011. May 2012. ADAMS No. ML12130A420.
19 Exelon Nuclear. 2013. LaSalle County Station Units 1 and 2, Annual Environmental Operating 20 Report, Annual Radiological Environmental Operating Report, 1 January through 21 31 December 2012. May 2013. ADAMS No. ML13136A007.
22 Exelon Nuclear. 2014. LaSalle County Station Units 1 and 2, Annual Environmental Operating 23 Report, Annual Radiological Environmental Operating Report, 1 January through 24 31 December 2013. May 2014. ADAMS No. ML14135A214.
25 Exelon Nuclear. 2015. LaSalle County Station Units 1 and 2, Annual Environmental Operating 26 Report, Annual Radiological Environmental Operating Report, 1 January through 27 31 December 2014. May 2015. ADAMS Nos. ML15141A195 and ML15141A219.
28 Fagan BM. 2005. Ancient North America. 4th ed. London: Thames & Hudson Ltd. 568 p.
29 Farmer A, Cade S, Staufer DF. 2002. Evaluation of Habitat Suitability Index Model. In: Kurta 30 A, Kennedy J, editors. The Indiana Bat: Biology and Management of an Endangered Species.
31 Austin, TX: Bat Conservation International. pp. 172-181.
32 Federal Water Pollution Control Act (Clean Water Act) of 1972, as amended.
33 33 U.S.C. &sect;1251 et seq. Rivers and Harbors Appropriation Act of 1899, as amended.
34 33 U.S.C. &sect;403 Section 10.
35 [FEMA] Federal Emergency Management Agency. 2015. Earthquake hazard maps available at 36 <www.fema.gov/earthquake/earthquake-hazard-maps#0> (accessed 16 June 2015).
37 [FHA] Federal Highway Administration. 2011. Highway Traffic Noise Analysis and Abatement 38 Policy and Guidance. Available at <https://www.fhwa.dot.gov/environment/noise/
39 regulations_and_guidance/polguide/polguide02.cfm> (accessed August 2015).
40 Fritts, MW. 2013. Email from M.W. Fritts, Illinois Natural History Survey, to P. Moore, Tetra 41 Tech.
 
==Subject:==
RE: Request: Illinois River Reports. June 24, 2013. ADAMS No.
42 ML15273A418.
3-118
 
Affected Environment 1 [FWS] U.S. Fish and Wildlife Service. 1990. Decurrent False Aster Recovery Plan. U.S. Fish 2 and Wildlife Service, Twin Cities, Minnesota. 26 p. Available at 3 <http://ecos.fws.gov/docs/recovery_plans/1990/900928c.pdf.> (accessed 28 August 2015).
4 [FWS] U.S. Fish and Wildlife Service. 2009. Indiana Bat (Myotis sodalis) 5-Year Review:
5 Summary and Evaluation. Midwest Region - Region 3. Available at 6 <http://www.fws.gov/midwest/endangered/recovery/5yr_rev/pdf/INBA5Yr30Sept2009.pdf.>
7 (accessed 28 August 2015).
8 [FWS] U.S. Fish and Wildlife Service. 2011. A National Plan for Assisting States, Federal 9 Agencies, and Tribes in Managing White-Nose Syndrome in Bats. Hadley, MA: FWS.
10 May 2011. 21 p. Available at <http://static.whitenosesyndrome.org/sites/default/files/
11 white-nose_syndrome_national_plan_may_2011.pdf> (accessed 22 August 2013).
12 [FWS] U.S. Fish and Wildlife Service. 2012a. 2011 Rangewide Population Estimate for the 13 Indiana Bat (Myotis sodalis) by USFWS Region. ADAMS No. ML14265A502.
14 [FWS] U.S. Fish and Wildlife Service. 2012b. Decurrent False Aster (Boltonia decurrens) 15 5-Year Review: Summary and Evaluation 2012. Midwest Region. Available at 16 <http://www.fws.gov/midwest/endangered/plants/5yrreviews/Boltonia5YrRev2012.pdf.>
17 (accessed 28 August 2015).
18 [FWS] U.S. Fish and Wildlife Service. 2013a. USFWS: Eastern Prairie Fringed Orchid 19 (Platanthera leucophaea) Fact Sheet. July 9, 2013. Available at 20 <http://www.fws.gov/midwest/endangered/plants/epfo.html> (accessed 18 December 2013).
21 [FWS] U.S. Fish and Wildlife Service. 2013b. USFWS: Endangered Species: Sheepnose 22 Mussel (Plethobasus cyphyus). January 3, 2013. Available at 23 <http://www.fws.gov/midwest/endangered/clams/sheepnose/> (accessed 20 December 2013).
24 [FWS] U.S. Fish and Wildlife Service. 2013c. White-Nose Syndrome Confirmed in Illinois Bats:
25 Illinois becomes 20th state in U.S. to confirm deadly disease in bats. Midwest Region.
26 November 4, 2013. Available at <http://www.fws.gov/midwest/news/621.html.> (accessed 27 1 September 2015).
28 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 29 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 30 September 30, 2015. Available at <http://www.fws.gov/midwest/endangered/lists/illinois-31 cty.html> (accessed 9 October 2015).
32 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC.
 
==Subject:==
LaSalle 33 Power Plant License Renewal. List of threatened and endangered species that may occur in 34 your proposed project location, and/or may be affected by your proposed project.
35 February 27, 2015. ADAMS ML15126A069.
36 [FWS] U.S. Fish and Wildlife Service. 2015c. Letter from L. Nelson, Regional Environmental 37 Officer, FWS, to D. Wrona, NRC. May 8, 2015. ADAMS No. ML15131A004.
38 [FWS] U.S. Fish and Wildlife Service. 2015d. Letter from Rock Island Ecological Services 39 Field Office, FWS, to NRC.
 
==Subject:==
List of threatened and endangered species that may occur 40 in your proposed project location, and/or may be affected by your proposed project.
41 February 27, 2015. ADAMS No. ML15126A069.
42 [FWS] U.S. Fish and Wildlife Service. 2015e. National Wetlands Inventory Wetlands Mapper.
43 Available at <http://www.fws.gov/wetlands/Data/Mapper.html> (accessed 10 March 2015).
3-119
 
Affected Environment 1 [HDR] HDR Engineering, Inc. 2010. Zebra Mussel Monitoring Program at LaSalle Nuclear 2 Station, 2009. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2010. Woodstock, 3 Illinois. ADAMS No. ML15273A421.
4 [HDR] HDR Engineering, Inc. 2011. Zebra Mussel Monitoring Program at LaSalle Nuclear 5 Station, 2010. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2011. Woodstock, 6 Illinois. ADAMS No. ML15273A422.
7 [HDR] HDR Engineering, Inc. 2012. Zebra Mussel Monitoring Program at LaSalle Nuclear 8 Station, 2011. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2012. Woodstock, 9 Illinois. ADAMS No. ML15273A440.
10 [HDR] HDR Engineering, Inc. 2013. Zebra Mussel Monitoring Program at LaSalle Nuclear 11 Station, 2012. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2013. Woodstock, 12 Illinois. ADAMS No. ML15273A441.
13 [HDR] HDR Engineering, Inc. 2014. Zebra Mussel Monitoring Program at LaSalle Nuclear 14 Station, 2013. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2014. Woodstock, 15 Illinois. ADAMS No. ML15273A442.
16 [HUD] U.S. Department of Housing and Urban Development. 2014. Noise and Abatement 17 Control. Available at <https://www.hudexchange.info/environmental-review/noise-abatement-18 and-control/> (accessed 15 July 2015).
19 [IDNR] Illinois Department of Natural Resources. 2005. The Illinois Comprehensive Wildlife 20 Conservation Plan & Strategy. Version 1.0. July 11, 2005. 380 p. Available at 21 <http://www.dnr.illinois.gov/conservation/IWAP/Documents/WildlifeActionPlanFinal.pdf>
22 (accessed 9 March 2015).
23 [IDNR] Illinois Department of Natural Resources. 2007. Status of the Catfish Fishery. Illinois 24 Department of Natural Resources, Division of Fisheries. March 2007. Available at 25 <http://www.dnr.state.il.us/orc/fisheries/07/07%20catfish%20status%20report.pdf> (accessed 26 21 May 2015).
27 [IDNR] Illinois Department of Natural Resources. 2009. Status of the Striped Bass/Hybrid 28 Striped Bass Fishery. Illinois Department of Natural Resources, Division of Fisheries.
29 March 2009. Available at 30 <http://www.prairiestateoutdoors.com/images/uploads/2009_Striped_Bass_Status.pdf>
31 (accessed 21 May 2015).
32 [IDNR] Illinois Department of Natural Resources. 2011a. Illinois Rivers and Lakes, Fact 33 Sheets. Illinois Department of Natural Resources, Aquatic Illinois, DNR158-6/12. Available at 34 <http://dnr.state.il.us/education/aquatic/aquaticillinoisrivlakefactshts.pdf> (accessed 35 10 September 2015).
36 [IDNR] Illinois Department of Natural Resources. 2011b. State of Illinois Coastal Management 37 Program. Available at <http://www.dnr.illinois.gov/cmp/Documents/ICMPPD.pdf> (accessed 38 6 March 2015).
39 [IDNR] Illinois Department of Natural Resources. 2014a. Illinois Natural Areas Inventory (INAI) 40 Sites. October 2014. Available at <http://dnr.state.il.us/conservation/
41 naturalheritage/Documents/INAI_by_County.pdf> (accessed 10 March 2015).
42 [IDNR] Illinois Department of Natural Resources. 2014b. Illinois Threatened and Endangered 43 Species By County. Updated October 2014. Available at 44 <http://www.dnr.illinois.gov/ESPB/Documents/ET_by_County.pdf> (accessed 9 March 2015).
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Affected Environment 1 [IDNR] Illinois Department of Natural Resources. 2014c. Letter from S.R. Fairfield, Impact 2 Assessment Section, to M.P. Gallagher, Vice President License Renewal, Exelon Nuclear. Re:
3 Renewal of Facility Operating Licenses by the U.S. Nuclear Regulatory Commission (NRC) for 4 LaSalle Generating Station, Units 1 and 2 - Correspondence dated March 7, 2014 County:
5 LaSalle. May 22, 2014. In Appendix D of Exelon 2014a.
6 [IDNR] Illinois Department of Natural Resources. 2015a. Checklist of Illinois Endangered and 7 Threatened Animals and Plants, Illinois Endangered Species Protection Board. May 19, 2015.
8 Available at <http://www.dnr.illinois.gov/ESPB/Documents/2015_ChecklistFINAL_for_webpage 9 _051915.pdf> (accessed 15 October 2015).
10 [IDNR] Illinois Department of Natural Resources. 2015b. Illini State Park. Available at 11 <http://dnr.state.il.us/lands/Landmgt/parks/i&m/east/illini/park.htm> (accessed 10 March 2015).
12 [IDNR] Illinois Department of Natural Resources. 2015c. Illinois Coastal Management 13 Program Boundaries. Available at <http://www.dnr.illinois.gov/cmp/Pages/boundaries.aspx>
14 (accessed 6 March 2015).
15 [IDNR] Illinois Department of Natural Resources. 2015d. Marseilles State Fish and Wildlife 16 Area. Available at <http://dnr.state.il.us/lands/Landmgt/parks/r1/MARSEIL.HTM> (accessed 17 15 October 2015).
18 [IDNR] Illinois Department of Natural Resources. 2015e. Marseilles State Fish & Wildlife Area 19 (Upland) Hunter Fact Sheet. Available at 20 <http://www.dnr.illinois.gov/hunting/FactSheets/Pages/MarseillesStateFishWildlifeAreaUpland.a 21 spx> (accessed 6 March 2015).
22 [IDNR and Exelon] Illinois Department of Natural Resources and Exelon Generation Company, 23 LLC. 2014. IDNR and Exelon Meeting Notes, Review of Braidwood, Clinton and LaSalle, Lake 24 Fishery and Land Management Plans. March 5, 2014. ADAMS No. ML15195A368.
25 [IDNR and Exelon] Illinois Department of Natural Resources and Exelon Generation Company, 26 LLC. 2015. IDNR and Exelon Meeting Notes, Review of Braidwood, Clinton and LaSalle, Lake 27 Fishery and Land Management Plans. March 4, 2015. ADAMS No. ML15195A368.
28 [IDPH] Illinois Department of Public Health. 2009. Salmonella. January 2009. Available at 29 <http://www.idph.state.il.us/public/hb/hbsam.htm> (accessed 23 October 2013).
30 [IDPH] Illinois Department of Public Health. 2013. Shigellosis Healthbeat. Available at 31 <http://www.idph.state.il.us/public/hb/hbshigellosis.htm> (accessed 23 October 2013).
32 [IDPH] Illinois Department of Public Health. 2014. Email from K. Marshall, IDPH, to N. Ranek, 33 Exelon,
 
==Subject:==
RE: LaSalle County Station Units 1 and 2- Consultation about thermophilic 34 organisms. February 19, 2014. ADAMS No. ML15273A445.
35 [IEPA] Illinois Environmental Protection Agency. 1987. Field and Laboratory Methods Manual:
36 Section C, Macroinvertebrate Monitoring. IEPA. Springfield, IL. 55 p.
37 [IEPA] Illinois Environmental Protection Agency. 2000. Federally Enforceable State Operating 38 Permit for LaSalle County Generating Station No. 75040086. December 11, 2000. ADAMS 39 No. ML15195A419.
40 [IEPA] Illinois Environmental Protection Agency. 2013. NPDES Permit No. IL0048151, National 41 Pollutant Discharge Elimination System, Reissued (NPDES) Permit. Exelon Generation 42 Company, LLC, LaSalle County Generating Station. Effective date, August 1, 2013.
43 Springfield, IL: Division of Water Pollution Control. In: LaSalle County Station, Units 1 and 2, 44 License Renewal Application, Appendix E, Applicants Environmental Report, Operating License 45 Renewal Stage. ADAMS No. ML14343A897 (Appendix C).
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Affected Environment 1 [IEPA] Illinois Environmental Protection Agency. 2014a. Email from G. Good, IEPA, to 2 N. Ranek, Exelon.
 
==Subject:==
RE: LaSalle County Station Units 1 and 2- Consultation about 3 thermophilic organisms. February 19, 2014. ADAMS No. ML15273A446.
4 [IEPA] Illinois Environmental Protection Agency. 2014b. Illinois Integrated Water Quality 5 Report and Section 303(d) List, 2014 - Volume I: Surface Water, Appendix A-1, Illinois' 2014 6 303(d) List and Prioritization, Appendix A-5, 2014 Illinois Water Quality Maps, Appendix B-2, 7 Specific Assessment Information for Streams, 2014, Appendix B-3, Specific Assessment 8 Information for Lakes, 2014. Illinois Environmental Protection Agency, Bureau of Water.
9 March 2014. (Final submitted to USEPA Region 5.) Available at 10 <http://www.epa.illinois.gov/topics/water-quality/watershed-management/tmdls/303d-list>
11 (accessed 21 August 2015).
12 [IEPA] Illinois Environmental Protection Agency. 2014c. Letter from A. Keller, Manager, Permit 13 Section, Division of Water Pollution Control, to U.S. Nuclear Regulatory Commission, Division of 14 License Renewal- Office of Nuclear Reactor Regulation.
 
==Subject:==
Exelon Generation Company 15 (LaSalle County Station), Renewal of Nuclear Regulatory Commission Operating Licenses for 16 Exelon LaSalle Station Units I and 2 (NPF-11 and NPF-18), Log # C-0054-14 [NPF-11 17 and NPF-18]. December 29, 2014. ADAMS No. ML15022A325.
18 [IEPA] Illinois Environmental Protection Agency. 2015. Illinois Permit Database, All Permit 19 Records: Available at <http://www.epa.gov/reg5oair/permits/ilonline.html> (accessed 20 10 July 2015).
21 [Illinois DOT] Illinois Department of Transportation. 2012. The Illiana Expressway Corridor -
22 Historic and Forecasted Growth of Employment and Population in the Extended Region of 23 Chicago. Market-Driven versus Policy-Based Socio-Economic Forecasts (2010-2040), No-Build 24 Illiana Expressway Scenario. February 2012. Available at 25 <http://www.idot.illinois.gov/Assets/uploads/files/Transportation-26 System/Reports/Desenv/Enviromental/Illiana/Appendix%20E1%20-27 %20%20Historic%20and%20Forecasted%20Growth%20of%20Employment%20and%20Popula 28 tion%20February%202012.pdf> (accessed October 2015).
29 [Illinois DOT] Illinois Department of Transportation. 2015. Getting Around Illinois - 2013-2014 30 Annual Average Daily Traffic. Map. Available at 31 <http://www.gettingaroundillinois.com/default.htm> (accessed October 2015).
32 [IHPA] Illinois Historic Preservation Agency. 2013. National Register of Historic Places in 33 Illinois. 50 p. Available at <http://www.illinois.gov/ihpa/Preserve/SiteAssets/Pages/Places/
34 National%20Register%20Properties%20in%20Illinois.pdf> (accessed 28 August 2015).
35 Illinois Environmental Protection Act of 1970. 415 ILCS 5/Title VI. Illinois Compiled Statutes.
36 Chapter 415, 5, Noise.
37 [ISGS] Illinois State Geological Survey. 2015. Illinois Water Well (ILWATER) Interactive Map.
38 Available at <http://maps.isgs.illinois.edu/ilwater/> (accessed 13 July 2015).
39 [ISM] Illinois State Museum. 2002. Native Americans: American Indian Tribes of Illinois.
40 October 2, 2002. Available at 41 <http://www.museum.state.il.us/muslink/nat_amer/post/index.html> (accessed 15 June 2015).
42 [ISWS] Illinois State Water Survey. 2015a. Water Supply Planning. Illinois State Water 43 Survey, Prairie Research Institute University of Illinois at Urbana-Champaign. Available at 44 <http://www.isws.illinois.edu/wsp> (accessed 21 August 2015).
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Affected Environment 1 [ISWS] Illinois State Water Survey. 2015b. Illinois Water Inventory Program. Illinois State 2 Water Survey, Prairie Research Institute University of Illinois at Urbana-Champaign. Available 3 at <http://www.isws.illinois.edu/gws/iwip/> (accessed 21 August 2015).
4 Kanter R. Environmental Almanac: Rare mussel found in Illinois River. News Gazette.
5 Sunday, July 7, 2013.
6 LaSalle County. 2014. LaSalle County Comprehensive Plan, LaSalle County, Illinois.
7 Available at <http://www.lasallecounty.org/envsvcs/lccp-2014.pdf> (accessed 11 May 2015).
8 Lerczak TV, Sparks RE, Blodgett, KD. 1994. The Long Term Illinois River Fish Population 9 Monitoring Program: Final Report. Project F-101-R. Illinois Natural History Survey. River 10 Research Laboratory. Havana, IL. June 1994. Available at 11 <https://www.ideals.illinois.edu/bitstream/handle/2142/10575/inhscaev01994i00006_opt.pdf?se 12 quence=2> (accessed 19 March 2015).
13 Lerczak TV. 1996. Illinois River Fish Communities: 1960s vs. 1990s. Illinois Natural History 14 Survey. April 4, 1996. Available at <http://wwx.inhs.illinois.edu/resources/inhsreports/may-15 jun96/fish/> (accessed 19 March 2015).
16 Magnuson-Stevens Fishery Conservation and Management Act, as amended.
17 16 U.S.C. &sect;1801 et seq.
18 Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. &sect;1361 et seq.
19 [Maryland DNR] Maryland Department of Natural Resources. 2015. Maryland Fish Facts, 20 American Gizzard Shad. Available at <http://dnr2.maryland.gov/Fisheries/Pages/Fish-21 Facts.aspx?fishname=American%20Gizzard%20Shad> (accessed 29 October 2015).
22 McClelland MA, Sass GG. 2007. The Long-Term Illinois River Fish Population Monitoring 23 Program, Project F-101-R-18. Illinois Natural History Survey. River Research Laboratory.
24 Havana, IL. April 2007. Available at 25 <https://www.ideals.illinois.edu/bitstream/handle/2142/48748/INHS2007_24.pdf?sequence=2>
26 (accessed 20 August 2015).
27 McClelland MA, Sass GG, Cook TR, Irons KS, Michaels NM, OHara NM, Smith CS. 2012. The 28 Long-Term Illinois River Fish Population Monitoring Program. Fisheries 37(8): 340-350.
29 Mid-America Earthquake Center. 2009. New Madrid Seismic Zone Catastrophic Earthquake 30 Response Planning ProjectImpact of New Madrid Seismic Zone Earthquakes on the Central 31 USA, Volume I. October 2009. Available at 32 <https://www.ideals.illinois.edu/bitstream/handle/2142/14810/ImpactofNewMadridSeismicZone 33 Earthquakeso%20theCentral%20USAVol1.pdf?sequence=3> (accessed 11 May 2015).
34 Migratory Bird Treaty Act of 1918, as amended. 16 U.S.C. &sect;703 et seq.
35 [Minnesota DNR] Minnesota Department of Natural Resources. 2014. Species Profile: Rare 36 Species Guide: Spike (Elliptio dilatata). Available at <http://www.dnr.state.mn.us/rsg/
37 profile.html?action=elementDetail&selectedElement=IMBIV14100> (accessed 7 April 2014).
38 [Mississippi DNR] Mississippi Department of Natural Resources. 2015. Step in Establishing 39 Indicators. Available at <http://www.dakotaswcd.org/pdfs/Final%20Indicators%20MDNR.pdf>
40 (accessed 29 October 2015).
41 Missouri Department of Natural Resources. 2013. The New Madrid Seismic Zone, Division of 42 Geology and Land Survey Fact Sheet Number 26. January 2013. Available at 43 <http://www.dnr.mo.gov/pubs/pub2465.pdf> (accessed 11 May 2015).
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Affected Environment 1 Moore BC, Martinez E, Gay JM, Rice DH. 2003. Survival of Salmonella enterica in freshwater 2 and sediments and transmission by the aquatic midge Chironomus tentans (Chironomidae:
3 Diptera). Applied and Environmental Microbiology 69(8):4556-4560. Available at 4 <http://www.ncbi.nlm.nih.gov/pmc/articles/PMC169145/> (accessed 23 October 2013).
5 [NASS] National Agricultural Statistics Service, U.S. Department of Agriculture. 2015. 2012 6 Census of Agriculture, Volume 1, Chapter 2, County Level, Table 7. Hired Farm Labor -
7 Workers and Payroll: 2012. 2012 Census of Agriculture, Volume 1 Chapter 2, County Level 8 Data for Illinois. Last modified: 4/15/2014. Available at 9 <http://www.agcensus.usda.gov/Publications/2012/Full_Report/Census_by_State/> (accessed 10 October 2015).
11 National Environmental Policy Act of 1969, as amended. 42 U.S.C. &sect;4321 et seq.
12 [NatureServe] NatureServe Explorer. 2014a. Moxostoma carinatum. Available at 13 <http://explorer.natureserve.org> (accessed 7 April 2014).
14 [NatureServe] NatureServe Explorer. 2014b. Elliptio dilatata. Available at 15 <http://explorer.natureserve.org> (accessed 7 April 2014).
16 [NCES] National Center for Education Statistics. 2015a. College Navigator. U.S. Department 17 of Education, Washington, D.C. College and university student population within 50 mi of ZIP 18 code 61341. Released July 2015. Available at 19 <http://nces.ed.gov/collegenavigator/default.aspx> (accessed October 2015).
20 [NCES] National Center for Education Statistics. 2015b. Grundy County, LaSalle County and 21 Will County Public and Private School Districts. 2013-2014 school year. Available at 22 <http://nces.ed.gov/ccd/districtsearch/> (accessed October 2015).
23 [NCDC] National Climatic Data Center. 2004. Climate of Illinois. Available at 24 <http://www.crh.noaa.gov/Image/dvn/downloads/Clim_IL_01.pdf> (accessed 10 July 2015) 25 [NCDC] National Climatic Data Center. 2015a. Local Climatological Data Annual Summary 26 with Comparative Data, Peoria, Illinois (KPIA). Available at 27 <http://www.ncdc.noaa.gov/IPS/lcd/lcd.html> (accessed 14 July 2015).
28 [NCDC] National Climatic Data Center. 2015b. Storm Events Database, LaSalle County.
29 Available at <https://www.ncdc.noaa.gov/stormevents/> (accessed 10 July 2015).
30 [NEI] Nuclear Energy Institute. 2007. Industry Ground Water Protection Initiative - Final 31 Guidance Document. Washington, DC: NEI. NEI 07-07. August 2007. ADAMS 32 No. ML072600295.
33 Neusius SW, Gross GT. 2007. Seeking Our Past: An Introduction to North American 34 Archaeology. New York, NY: Oxford University Press, Inc. 720 p.
35 Noise Control Act of 1972. 42 U.S.C. &sect;4901 et seq.
36 [NRC] U.S. Nuclear Regulatory Commission. 1978. Final Environmental Statement Related to 37 Operation of LaSalle County Nuclear Power Station Unit Nos. 1 and 2. Washington, DC: NRC.
38 NUREG-0486. November 1978. ADAMS No. ML14353A388.
39 [NRC] U.S. Nuclear Regulatory Commission. 1999. Generic Environmental Impact Statement 40 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Volume 1, 41 Addendum 1. August 1999.
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Affected Environment 1 [NRC] U.S. Nuclear Regulatory Commission. 2012. Letter from E.J. Leeds, Director, Office 2 Nuclear Reactor Regulation, and MJ Johnson, Director, Office of New Reactors to All Power 3 Reactor Licensees and Holders of Construction Permits in Active or Deferred Status.
 
==Subject:==
 
4 Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) 5 Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review of Insights 6 from the Fukushima Dai-ichi Accident. March 12, 2012. ADAMS No. ML12053A340.
7 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 8 for License Renewal of Nuclear Plants. Revision 1. Washington, DC: NRC. NUREG-1437, 9 Volumes 1, 2, and 3. June 2013. 1,535 p. ADAMS No. ML13107A023.
10 [NRC] U.S. Nuclear Regulatory Commission. 2014a. Letter from E.J. Leeds, Director, Office 11 Nuclear Reactor Regulation to All Power Reactor Licensees and Holders of Construction 12 Permits in Active or Deferred Status.
 
==Subject:==
Seismic Screening and Prioritization Results 13 Regarding Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) 14 Regarding Seismic Hazard Reevaluations for Recommendation 2.1 of the Near-Term Task 15 Force Review of Insights from the Fukushima Dai-ichi Accident. May 9, 2014. ADAMS 16 No. ML14111A147.
17 [NRC] U.S. Nuclear Regulatory Commission. 2014b. Occupational Radiation Exposure at 18 Commercial Nuclear Power Reactors and Other Facilities 2012: Forty-Fifth Annual Report.
19 Washington, DC: NRC. NUREG-0713, Volume 34, April 2014. ADAMS No. ML14126A597.
20 [NRC] U.S. Nuclear Regulatory Commission. 2014c. Probabilistic Seismic Hazard Analysis:
21 Background Information. May 20, 2014. ADAMS No. ML14140A648.
22 [NRC] U.S. Nuclear Regulatory Commission. 2015a. LaSalle County Station, Units 1 and 2 23 Staff Assessment of Information Provided Pursuant to Title 10 of the Code of Federal 24 Regulations Part 50, Section 50.54(F), Seismic Hazard Reevaluations for Recommendation 2.1 25 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident 26 (TAC Nos. MF3881 AND MF3882). April 21, 2015. ADAMS No. ML15013A132.
27 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Memorandum from B. Wittick, Chief, 28 Projects Branch 2, Division of License Renewal, Office of Nuclear Reactor Regulation, to 29 M.P. Gallagher, Vice President, License Renewal Projects, Exelon Generation Company, LLC.
30
 
==Subject:==
Summary of the License Renewal Environmental Audit for LaSalle County Station, 31 Units 1 And 2. May 20, 2015. 5 p. ADAMS No. ML15132A674.
32 [NRC] U.S. Nuclear Regulatory Commission. 2015c. Note to File: Summary of Visit to Illinois 33 Historic Preservation Agency Associated with the LaSalle County Station, Units 1 and 2, 34 License Renewal Application Environmental Audit, May 2015. ADAMS No. ML15205A286.
35 Nyboer RW, Herkert JR, Ebinger JE, editors. 2006. Endangered and Threatened Species of 36 Illinois: Status and Distribution, Volume 2 - Animals. Illinois Endangered Species Protection 37 Board, Springfield, Illinois. 181 p. Available at 38 <https://www.dnr.illinois.gov/ESPB/Pages/Publications.aspx> (accessed 20 August 2015).
39 Occupational Safety and Health Act of 1970, as amended. 29 U.S.C. &sect;651 et seq.
40 [OEPA] Ohio Environmental Protection Agency. 1987. Biological Criteria for the Protection of 41 Aquatic Life. Ohio Environmental Protection Agency. July 1987. Columbus, Ohio. Available at 42 http://www.epa.state.oh.us/Portals/35/documents/Vol1.pdf (accessed on 26 October 2015).
43 [OSHA] Occupational Safety and Health Administration. 2008. OSHA Directive 44 CSP 03-01-003, Voluntary Protection Programs (VPP): Policies and Procedures Manual, 45 April 18, 2008, at page 7. Available at <https://www.osha.gov/OshDoc/Directive_pdf/CSP_03-46 01-003.pdf> (accessed May 29, 2015).
3-125
 
Affected Environment 1 [OSHA] Occupational Safety and Health Administration. 2015a. OSHA Voluntary Protection 2 Programs, Current Federal and State Plan Sites. Available at 3 <https://www.osha.gov/dcsp/vpp/sitebystate.html> (accessed May 29, 2015).
4 [OSHA] Occupational Safety and Health Administration. 2015b. Voluntary Protection 5 Programs. Available at <https://www.osha.gov/dcsp/vpp/> (accessed May 29, 2015).
6 Osmond DL, Line DE, Gale JA, Gannon RW, Knott CB, Bartenhagen KA, Turner MH, Coffey 7 SW, Spooner J, Wells J, Walker JC, Hargrove LL, Foster MA, Robillard PD, Lehning DW. 1995.
8 WATERSHEDSS: Water, Soil and Hydro-Environmental Decision Support System 9 <http://www.water.ncsu.edu/watershedss/info/aqlife.html> (accessed 28 October 2015).
10 Ottawa Area Chamber of Commerce & Industry. 2009. Community Profile Overview - Major 11 Industries. Available at <http://www.ottawaindustrialpark.com/comm-profile.html> (accessed 12 October 2015).
13 Parmalee PW, Bogan AE. 1998. Freshwater Mussels of Tennessee. University of Tennessee 14 Press, Knoxville, Tennessee.
15 Pauketat TR. 1993. A Guide to the Prehistory and Native Cultures of Southwestern Illinois and 16 the Greater St. Louis Area. Illinois Archaeological Educational Series No. 2. Springfield, IL:
17 Illinois Historic Preservation Agency. 60 p.
18 Pearson WE. 2003. Legionella 2003: An Update and Statement by the Association of Water 19 Technologies (AWT). Rockville, MD: Association of Water Technologies. June 2003. 33 p.
20 Available at <http://awt.org/IndustryResources/Legionella03.pdf> (accessed 21 October 2013).
21 Pruitt L, TeWinkel L, editors. 2007. Indiana Bat (Myotis sodalis) Draft Recovery Plan.
22 First Revision. Fort Snelling, MN: U.S. Fish and Wildlife Service. April 2007. 258 p. Available 23 at <http://ecos.fws.gov/docs/recovery_plan/070416.pdf> (accessed 26 September 2013).
24 [RESA] Will Regional Educational Service Agency. 2014. Districts and PSA [Public School 25 Academies]. Available at <http://www.resa.net/aboutus/districts/> (accessed December 2014).
26 Rivers and Harbors Appropriation Act of 1899. 33 U.S.C. &sect;403 Section 10.
27 Sietman BE, Whitney SD, Kelner DE, Blodgett DK, Dunn HL. Post-Extirpation Recovery of the 28 Freshwater Mussel (Bivalve: Unionidea) Fauna in the Upper Illinois River. Journal of 29 Freshwater Ecology 16(2):273-281.
30 Smith PW. 2002. The Fishes of Illinois. University of Illinois Press, Urbana and Chicago, IL.
31 Smith M, Caswell H, Mettler-Cherry P. 2005. Stochastic flood and precipitation regimes and 32 the dynamics of a threatened floodplain plant. Ecological Applications 15(3):1036-1052.
33 State of Illinois. 2006. 2006-01 Executive Order for the Development of State and Regional 34 Water-Supply Plans. Executive Department. January 9, 2006. Available at 35 <http://www.illinois.gov/Government/ExecOrders/Documents/2006/execorder2006-1.pdf>
36 (accessed 21 August 2015).
37 Stevens AR, Tyndall RL, Coutant CC, Willaert E. 1977. Isolation of the etiological agent of 38 primary amoebic meningoencephalitis from artificially heated waters. Applied and 39 Environmental Microbiology 34(6):701-705. Available at 40 <http://aem.asm.org/content/34/6/701.full.pdf+html> (accessed 23 October 2013).
41 Talkington, LM. 1991. The Illinois River--Working for our State. Champaign, IL: Illinois State 42 Water Survey. January 1991. Miscellaneous Publication 128. Available at 43 <http://www.isws.illinois.edu/pubdoc/MP/ISWSMP-128.pdf> (accessed 21 August 2015).
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Affected Environment 1 [Teledyne] Teledyne Brown Engineering Environmental Services. 2011. LaSalle County 2 Station, 2010 Annual Radiological Environmental Operating Report, 1 January through 3 31 December 2010. Marseilles, IL: Exelon Nuclear. May 12, 2011. ADAMS 4 No. ML111320602.
5 [Teledyne] Teledyne Brown Engineering Environmental Services. 2012. LaSalle County 6 Station, 2011 Annual Radiological Environmental Operating Report, 1 January through 7 31 December 2011. Marseilles, IL: Exelon Nuclear. May 9, 2012. ADAMS No. ML12130A420.
8 [Teledyne] Teledyne Brown Engineering Environmental Services. 2013. LaSalle County 9 Station, 2012 Annual Radiological Environmental Operating Report, 1 January through 10 31 December 2012. Marseilles, IL: Exelon Nuclear. May 15, 2013. ADAMS 11 No. ML13136A007.
12 [Teledyne] Teledyne Brown Engineering Environmental Services. 2014. LaSalle County 13 Station, 2013 Annual Radiological Environmental Operating Report, 1 January through 14 31 December 2013. Marseilles, IL: Exelon Nuclear. May 15, 2014. ADAMS 15 No. ML14135A214.
16 [Teledyne] Teledyne Brown Engineering Environmental Services. 2015. LaSalle County 17 Station, 2014 Annual Radiological Environmental Operating Report, 1 January through 18 31 December 2014. Marseilles, IL: Exelon Nuclear. May 13, 2015. ADAMS No. ML15141A19.
19 Todar K. 2004. Todars Online Textbook of Bacteriology. University of Wisconsin, 20 Department of Bacteriology. Available at <http://textbookofbacteriology.net/index.html>
21 (accessed 23 October 2013).
22 [USACE] United States Army Corps of Engineers. 1998. Illinois Waterway Navigational Charts.
23 Available at <http://www2.mvr.usace.army.mil/NIC2/ilwwcharts.cfm> (assessed on 24 8 September 2015).
25 [USACE] U.S. Army Corps of Engineers. 2006. Department of the Army Permit, CEMVR 26 OD-P-2006-185. Issued to Exelon Generating Company, LLC. U.S. Army Corps of Engineers, 27 Rock Island District. Issued April 12, 2006; expiration 31 December 2015. ADAMS 28 No. ML15195A399.
29 [USACE] U.S. Army Corps of Engineers. 2012. Illinois Waterway Locks & Dams. Available at 30 <http://www.mvr.usace.army.mil/Portals/48/docs/CC/FactSheets/IL/Illinois_Waterway_Locksand 31 Dams%20(2012).pdf> (accessed 6 March 2015).
32 [USACE] U.S. Army Corps of Engineers. 2014. Marseilles Lock & Dam. Rock Island, IL: Rock 33 Island District. October 2014. Available at 34 <http://www.mvr.usace.army.mil/Missions/Navigation/MarseillesLockandDam.aspx> (accessed 35 21 August 2015).
36 [USCB] U.S. Census Bureau. 2015a. American FactFinder, American Community Survey, 37 Table DP03 - Selected Economic Characteristics, 2014, 1-Year Estimates for LaSalle and Will 38 Counties, Illinois, and 2009-2013, 5-Year Estimates, for Grundy, County, Illinois. Available at 39 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015).
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Affected Environment 1 [USCB] U.S. Census Bureau. 2015b. American FactFinder, 2014 American Community 2 Survey 1-Year Estimates for Illinois and LaSalle and Will Counties, Table S1701 - Poverty 3 Status in the Past 12 Months, Table S1702 - Poverty Status in the Past 12 Months of 4 Families, Table B19013 - Median Household Income in the Past 12 Months (In 2014 5 Inflation-Adjusted Dollars), and Table B19301 - Per Capita Income in the Past 12 Months (In 6 2014 Inflation-Adjusted Dollars). American FactFinder, 2011-2013 American Community 7 Survey 3-Year Estimates for Grundy, County, Illinois, Table DP05 - ACS Demographic and 8 Housing Estimates, Table S1701 - Poverty Status in the Past 12 Months, Table S1702 -
9 Poverty Status in the Past 12 Months of Families, Table B19013 - Median Household Income 10 in the Past 12 Months (In 2013 Inflation-Adjusted Dollars), and Table B19301 - Per Capita 11 Income in the Past 12 Months (In 2013 Inflation-Adjusted Dollars). Available at 12 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015).
13 [USCB] U.S. Census Bureau. 2015c. American FactFinder, 2014 American Community 14 Survey 1-Year Estimates for Illinois and LaSalle and Will Counties, Table S2301 -
15 Employment Status, and 2011-2013 American Community Survey 3-Year Estimates for 16 Grundy, County, Illinois, Table S2301 - Employment Status. Available at 17 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015).
18 [USCB] U.S. Census Bureau. 2015d. American FactFinder, 1980 - 2010 Decennial Census:
19 1900 to 1990; Table DP Profile of General Demographic Characteristics: 2000, and Table 20 DP Profile of General Population and Housing Characteristics: 2010 for Grundy, LaSalle, 21 and Will Counties Illinois. Available at 22 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015).
23 [USCB] U.S. Census Bureau. 2015e. American FactFinder, 2010 Census Summary File 1, 24 Table DP Profile of General Population and Housing Characteristics: 2010. Available at 25 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015).
26 [USCB] U.S. Census Bureau. 2015f. American FactFinder, 2014 American Community Survey 27 1-Year Estimates for Illinois and LaSalle and Will Counties, Table PEPSR6H - Annual 28 Estimates of the Residential Population by Sex, Race, and Hispanic Origin for the United 29 States, and Counties: April 1, 2010 to July 1, 2014 - 2014 Population Estimates, and 30 2011-2013 American Community Survey 3-Year Estimates for Grundy, County, Illinois, Table 31 DP05 - ACS Demographic and Housing Estimates. Available at 32 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015).
33 [USCB] U.S. Census Bureau. 2015g. American FactFinder, 2009-2013 American Community 34 Survey 5-Year Estimates, Table 25001 - Housing Units and Table B25004 - Vacancy 35 Status. Available at <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed 36 October 2015).
37 [USCB] U.S. Census Bureau. 2015h. American FactFinder, 2014 American Community 38 Survey 1-Year Estimates for LaSalle and Will Counties, Table DP04 - Selected Housing 39 Characteristics, and 2011-2013 American Community Survey 3-Year Estimates for Grundy, 40 County, Illinois, Table DP04 - Selected Housing Characteristics. Available at 41 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015).
42 [USDA] U.S. Department of Agriculture. 2008. Soil Survey of LaSalle County, Illinois.
43 Available at 44 <http://www.nrcs.usda.gov/Internet/FSE_MANUSCRIPTS/illinois/IL099/0/La_Salle_IL.pdf>
45 (accessed 11 May 2015).
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Affected Environment 1 [USDA] U.S. Department of Agriculture. 2015a. CropScape - Cropland Data Layer. 2014 2 Cropland Data Layer Statistics for LaSalle, Illinois. Available at 3 <http://nassgeodata.gmu.edu/CropScape/> (accessed October 2015).
4 [USDA] U.S. Department of Agriculture. 2015b. Custom Soil Resource Report for LaSalle 5 County, Illinois. National Resources Conservation Service. Available at 6 <http://websoilsurvey.nrcs.usda.gov/app/WebSoilSurvey.aspx> (accessed 5 January 2015).
7 [USFS] U.S. Forest Service. undated a. Threatened, Endangered, and Proposed (TEP) Plant 8 Profile: Dalea foliosa, Leafy Prairie-Clover. Available at 9 <http://www.fs.fed.us/wildflowers/Rare_Plants/profiles/TEP/dalea_foliosa/index.shtml>
10 (accessed 3 January 2013).
11 [USFS] U.S. Forest Service. undated b. Celebrating Wildflowers: Contributing to the 12 Recovery of Leafy Prairie-Clover in Northeastern Illinois by Growing Plants from Seed and 13 Planting in Restored Dolomite Prairie Habitat. Available at 14 <http://www.fs.fed.us/wildflowers/Rare_Plants/conservation/success/
15 dalea_foliosa_recovery.shtml> (accessed 3 January 3 2013).
16 [USGS] U.S. Geological Survey. 1994. National Water Quality Assessment Program, The 17 Lower Illinois River Basin. Urbana, IL: U.S. Geological Survey. USGS FS 94-018. Page dated 18 June 1994. Available at <http://il.water.usgs.gov/proj/lirb/pubs/factsheet.html#head1>
19 (accessed 21 August 2015).
20 [USGS] U.S. Geological Survey. 1998. National Water-Quality Assessment Program, Upper 21 Illinois River Basin. Urbana, IL: U.S. Geological Survey, WRD. USGS Fact Sheet FS-072-98.
22 June 1998. Available at <http://il.water.usgs.gov/pubs/fs072_98.pdf> (accessed 23 21 August 2015).
24 [USGS] United States Geological Survey. 1999a. Ecological status and trends of the Upper 25 Mississippi River System 1998: A report of the Long Term Resource Monitoring Program.
26 U.S. Geological Survey, Upper Midwest Environmental Sciences Center, La Crosse, Wisconsin.
27 April 1999. LTRMP 99-T001. 236 p. Available at 28 <http://www.umesc.usgs.gov/reports_publications/status_and_trends.html> (accessed 29 21 October 2015).
30 [USGS] U.S. Geological Survey. 1999b. Illinois River at Marseilles. Page dated 31 October 12, 1999. Available at 32 <http://il.water.usgs.gov/proj/lirb/bst/site_descrip/marseilles.html> (accessed 21 August 2015).
33 [USGS] U.S. Geological Survey. 2009. Earthquake Hazard in the New Madrid Seismic Zone 34 Remains a Concern. Available at <http://pubs.usgs.gov/fs/2009/3071/pdf/FS09-3071.pdf>
35 (accessed 5 September 2013).
36 [USGS] U.S. Geological Survey. 2013a. Earthquake History of Illinois. Available at 37 <http://earthquake.usgs.gov/earthquakes/states/illinois/history.php> (accessed 38 4 September 2013).
39 [USGS] U.S. Geological Survey. 2013b. Largest Earthquake in Illinois. Available at 40 <http://earthquake.usgs.gov/earthquakes/states/events/1968_11_09.php> (accessed 41 4 September 2013).
42 [USGS] U.S. Geological Survey. 2013c. Isoseismal Map of 1968 Earthquake. Available at 43 <http://earthquake.usgs.gov/earthquakes/states/events/1968_11_09_iso.php> (accessed 44 4 September 2013).
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Affected Environment 1 [USGS] U.S. Geological Survey. 2015. USGS Water-Year Summary 2014, 05543500 Illinois 2 River at Marseilles, Illinois. Available at 3 <http://waterdata.usgs.gov/nwis/inventory/?site_no=05543500&agency_cd=USGS> (accessed 4 5 June 2015).
5 Watrous KS, Donovan TM, Mickey RM, Darling SR, Hicks AC, Von Oettingen SL. 2006.
6 Predicting minimum habitat characteristics for the Indiana bat in the Champlain Valley. The 7 Journal of Wildlife Management 70(5):1228-1237.
8 Whitaker JO Jr, Brack V Jr. 2002. Distribution and summer ecology in Indiana. pp. 48-54. In:
9 Kurta A, Kennedy J, editors. 2002. The Indiana Bat: Biology and Management of an 10 Endangered Species. Austin, TX: Bat Conservation International. 253 p.
11 Wiken E, Nava FJ, Griffith G. 2011. North American Terrestrial EcoregionsLevel III.
12 Commission for Environmental Cooperation, Montreal, Canada. April 2011. Available at 13 <http://www3.cec.org/islandora/en/item/10415-north-american-terrestrial-ecoregionslevel-iii-14 en.pdf> (accessed 5 August 2015).
15 Woods AJ, Omerinik JM, Pederson CL, Moran BC. 2006. Level III and Level IV Ecoregions of 16 Illinois. EPA/600/R-06/104. Prepared on behalf of Oregon State University, U.S. Geological 17 Survey, Eastern Illinois University, U.S. Environmental Protection Agency. Washington, DC:
18 EPA. 45 p. Available at <ftp://ftp.epa.gov/wed/ecoregions/il/il_report.pdf> (accessed 19 9 March 2015).
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4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS 4.1      Introduction In this chapter, the U.S. Nuclear Regulatory Commission (NRC) evaluates the environmental consequences of the proposed action (i.e., license renewal of LaSalle County Station, Units 1 and 2 (LSCS)), including the (1) impacts associated with continued operations similar to those that have occurred during the current license terms; (2) impacts of various alternatives to the proposed action; (3) impacts from the termination of nuclear power plant operations and decommissioning after the license renewal term (with emphasis on the incremental effect caused by an additional 20 years of operation); (4) impacts associated with the uranium fuel cycle; (5) impacts of postulated accidents (design-basis accidents and severe accidents);
(6) cumulative impacts of the proposed action; and (7) resource commitments associated with the proposed action, including unavoidable adverse impacts, the relationship between short-term use and long-term productivity, and irreversible and irretrievable commitment of resources. The NRC also considers new and potentially significant information on environmental issues related to operation during the renewal term.
NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS) (NRC 2013d) identifies 78 issues to be evaluated in the license renewal environmental review process. Generic issues (Category 1) rely on the analysis presented in the GEIS, unless otherwise noted. Applicable site-specific issues (Category 2) have been analyzed for LSCS and assigned a significance level of SMALL, MODERATE, or LARGE. Section 1.4 of this supplemental environmental impact statement (SEIS) provides an explanation of the criteria for Category 1 and Category 2 issues, as well as the definitions of SMALL, MODERATE, and LARGE. Resource-specific impact significance level definitions are provided where applicable.
4.2      Land Use and Visual Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on land use and visual resources.
4.2.1      Proposed Action Section 3.2 describes land use and visual resources in the vicinity of the LSCS site. Table 4-1 identifies the issues that apply to land use and visual resources during the proposed license renewal period. The GEIS (NRC 2013d) discusses these issues in Section 4.2.1. The GEIS does not identify any site-specific (Category 2) land use or visual resource issues.
The NRC staff did not identify any new and significant information related to the generic (Category 1) land use and visual resource issues during the review of the applicants Environmental Report (ER) (Exelon 2014a), the site audit, or the scoping process. Therefore, the NRC staff expects no impacts associated with these issues beyond those discussed in the GEIS. The GEIS concludes that the impact level for each of these issues is SMALL.
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Environmental Consequences and Mitigating Actions Table 4-1. Land Use and Visual Resource Issues Issue                                                                                    GEIS Section        Category Land Use Onsite land use                                                                              4.2.1.1              1 Offsite land use                                                                            4.2.1.1              1 Offsite land use in transmission line right-of-ways        (ROWs)(a)                        4.2.1.1            N/A(b)
Visual Resources Aesthetic impacts                                                                            4.2.1.2              1 (a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid. As described in Section 3.1.6, all in-scope transmission lines subject to the evaluation of environmental impacts for license renewal are located within the LSCS site property boundary.
(b) This issue does not apply to LSCS because no offsite transmission lines are within the scope of license renewal.
Section 3.1.6 describes the in-scope transmission lines.
Source: Table B-1 in Appendix B, Subpart A, to Title 10 of the Code of Federal Regulations (10 CFR) Part 51 4.2.2        No-Action Alternative 4.2.2.1        Land Use If LSCS were to shut down, the impacts to land use would remain similar to those during operations until the plant is fully decommissioned. Temporary buildings and staging or laydown areas may be required during large component and structure dismantling. LSCS is likely to have sufficient space within previously disturbed areas for these needs; therefore, no additional land would need to be disturbed that would result in changes to current land uses. In NUREG-0586, Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities, Supplement 1, the NRC (2002) concludes generically that land use during decommissioning activities would be SMALL. The GEIS (NRC 2013b) notes that land use impacts could occur in other areas beyond the immediate nuclear plant site as a result of the noaction alternative if new power plants are needed to replace lost capacity. The NRC staff did not identify any impacts that may result at LSCS beyond those discussed in NUREG-0586, and the NRC staff concludes that the noaction alternative is unlikely to noticeably alter or have more than minor effects on land use. Thus, the NRC staff concludes that the impacts of the no-action alternative on land use during the proposed license renewal term would be SMALL.
4.2.2.2        Visual Resources If LSCS were to shut down, visual resource impacts would remain similar to those experienced during operations until the site is fully decommissioned. The vent stack, reactor buildings, and turbine buildings, which create the largest visual impact, would eventually be dismantled, which would reduce the already SMALL impacts to visual resources that would occur during the proposed license renewal term. Thus, the NRC staff concludes that the impacts of the no-action alternative on visual resources would be SMALL.
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Environmental Consequences and Mitigating Actions 4.2.3    New Nuclear Alternative 4.2.3.1      Land Use The new nuclear alternative assumes that Exelon Generation Company, LLC (Exelon) would build a new nuclear facility in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin at an existing power plant site. Construction of the facility would require an estimated 324 ac (131 ha) for permanent buildings and facilities and an additional 232 ac (94 ha) for temporary facilities, laydown areas, and other temporary land disturbances. Additional offsite land would be required for uranium mining, although this impact would result in no net change in land use impacts from those that would be associated with the proposed license renewal of LSCS.
During construction, the use of an existing power plant site would maximize the availability of existing infrastructure and minimize disruption to land that had not been previously disturbed for industrial uses. However, given the land requirements, some undisturbed or non-industrial-use lands would likely be affected or converted to industrial areas. Such impacts would likely be noticeable within the direct footprint of the facility but would not result in changes that would destabilize surrounding land uses such that those lands would no longer function for their designated uses. Accordingly, the NRC staff concludes that construction impacts would be MODERATE.
Operation of a new nuclear facility would incur impacts similar to those assessed for the proposed LSCS license renewal, which the NRC staff concludes, in Section 4.2.1, would be SMALL.
Overall, impacts of a new nuclear alternative on land use would be MODERATE during construction and would be SMALL during operation.
4.2.3.2      Visual Resources Because the facility would be located on an existing power plant site, visual resource impacts of most new buildings and infrastructure would be minimal. The construction of natural draft cooling towers would be the largest visual impact because both the towers themselves and the plume could be visible from a distance. The magnitude of this impact would vary based on the topography of the chosen site and surrounding area. The NRC staff concludes that the impacts to visual resources from construction and operation of a new nuclear alternative would be SMALL to MODERATE.
4.2.4    IGCC Alternative 4.2.4.1      Land Use The integrated gasification combined-cycle (IGCC) alternative assumes that the new facility would be built at an existing power plant site in Illinois, including the LSCS site, or at another power plant site in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin. The facility would require 2,000 ac (800 ha) of land to construct the facility. If the facility were to be sited on the LSCS site, the area currently occupied by the LSCS facilities, the undeveloped areas immediately surrounding the facility, and the area occupied by the Illinois fish hatchery would be affected. Exelon would also need to acquire adjacent parcels of land to provide the full complement of acreage required for the IGCC facility. Additional offsite land would be required for coal mining, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS.
During construction, the use of an existing site would maximize availability of existing infrastructure. However, construction would likely significantly affect surrounding natural areas 4-3
 
Environmental Consequences and Mitigating Actions on the site and within purchased adjacent land parcels because it would require the clearing and grading of these areas for industrial use. Whether sited on the LSCS site or elsewhere, the large footprint of the facility would likely require the conversion of land to industrial use from other land uses. Accordingly, construction would likely noticeably alter land uses, and the large area of land required for the IGCC facility could destabilize important attributes or functions of sensitive lands, such as nearby wetlands, if present. Accordingly, the NRC staff concludes that construction impacts would be MODERATE to LARGE.
Operation of an IGCC facility would likely not incur additional land use changes; therefore, operational impacts would be SMALL.
Overall, impacts of an IGCC alternative on land use would be MODERATE to LARGE during construction, depending on the location and types of lands affected by construction, and would be SMALL during operation.
4.2.4.2      Visual Resources Because the IGCC facility would be located on an existing industrial site, additional visual resource impacts would be minimal. The visibility of the plant stacks and mechanical draft cooling towers would vary based on the topography of the chosen site and surrounding area.
Some temporary visual impacts may occur during construction from cranes and other construction equipment that may be visible off site. During operation, cooling tower plumes could create noticeable visual impacts. The NRC staff concludes that the impacts from the construction and operation of an IGCC alternative on visual resources would be SMALL.
4.2.5    Natural Gas Combined-Cycle Alternative 4.2.5.1      Land Use The natural gas combined-cycle (NGCC) alternative assumes that a new NGCC facility would be built at the LSCS site. The facility would require 94 ac (38 ha) of land and would be sited on the undeveloped land immediately surrounding the LSCS. Some infrastructure upgrades could be required, as well as a new or upgraded pipeline, which would affect additional land.
Additional offsite land would be required for gas extraction and collection, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS.
During construction, the use of the existing site would maximize the availability of existing infrastructure. However, construction would convert natural areas to industrial use because the new facility would be built outside the existing industrial footprint. Although these land use changes would be noticeable, construction would be unlikely to destabilize important attributes of surrounding lands, due to the small size of the facility footprint. Accordingly, the NRC staff concludes that construction impacts would be MODERATE.
Operation of an NGCC facility would likely not incur additional land use changes; therefore, operational impacts would be SMALL.
Overall, impacts of the NGCC alternative on land use would be MODERATE during construction and would be SMALL during operation.
4.2.5.2      Visual Resources Because the NGCC facility would be located on an existing industrial site, additional visual resource impacts would be minimal. The mechanical draft cooling towers would likely not be taller than other buildings on site. Some temporary visual impacts may occur during construction from cranes and other construction equipment that may be visible off site. During 4-4
 
Environmental Consequences and Mitigating Actions operation, cooling tower plumes could create some visual impacts in the immediate vicinity of the facility. The NRC staff concludes that the impacts from the construction and operation of an NGCC alternative on visual resources would be SMALL.
4.2.6      Combination Alternative (NGCC, Wind, Solar) 4.2.6.1      Land Use The NGCC component of the combination alternative would have the same land requirements as discussed for the NGCC alternative in Section 4.3.3.1. Accordingly, the impacts to land use would be similar to those concluded for the NGCC alternative and, therefore, would be MODERATE during construction and SMALL during operation.
The wind component of this alternative would require an estimated 3,376 to 10,127 ac (1,366 to 4,098 ha) of land at onshore wind farm sites and agricultural cropland across the region of influence (ROI). However, the majority of this land would only be temporarily disturbed during construction. Permanently disturbed land would hold the wind turbines, access roads, and transmission lines and would account for 5 to 10 percent of the estimated required acreage.
Land used for equipment laydown and turbine component assembly and erection could be returned to its original state following construction. Given the large footprint of the wind component, land use could be affected, although most land uses, such as agriculture, could continue once the wind turbines are operational. Land use impacts for the wind component would range from SMALL to MODERATE depending on the amount and types of land that would be affected by wind turbine construction.
The solar component would require an estimated 6,749 ac (2,731 ha) of land across the ROI.
The majority of solar installations could be installed on building roofs at existing residential, commercial, or industrial sites or at larger standalone solar facilities; therefore, only a little land would possibly be required for construction. However, the exact magnitude of impacts on land use would depend on the amount of land that must be converted for construction of solar installations. Unlike wind power, solar-powered installations often cannot be collocated with existing land uses (such as in crop-producing agricultural fields). The impacts of the solar component of this alternative on land use would range from SMALL to MODERATE, depending on the amount and types of land that would be affected by construction of the solar installations.
The NRC staff concludes that the overall impacts of the combination alternative on land use would be SMALL to MODERATE. This range is primarily the result of the variability in land required for the wind and solar components.
4.2.6.2      Visual Resources Visual resource impacts for the NGCC component of this alternative would be similar to or less than those described in Section 4.3.3.2 for the NGCC alternative and, therefore, would be SMALL. Visual resources would be significantly affected by construction of the wind component. Although specific effects would vary based on the topography and remoteness of the wind turbine locations, the visual impact of wind energy is often one of the most significant energy-generating visual impacts and could range from MODERATE to LARGE. The visual impacts of the solar component would also vary, based on the topography of the area, but the NRC staff expects these impacts to be minimal because individual solar installations are not tall or expansive, and many of the installations could be constructed on building roofs at existing residential, commercial, or industrial sites. Larger standalone solar facilities could have a greater visual impact, depending on the location, but the impacts of the solar component would likely be SMALL overall. The NRC staff concludes that the impacts of the combination 4-5
 
Environmental Consequences and Mitigating Actions alternative on visual resources would be SMALL to LARGE. This range is primarily the result of the potential visual impacts from the wind component of the alternative.
4.2.7      Purchased Power Alternative 4.2.7.1      Land Use The purchased power alternative would have wide ranging impacts that are hard to specifically assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI. This alternative would likely have little-to-no construction impacts because it would include power from already existing power generating facilities. The construction of additional transmission lines could affect land uses if the lines require the clearing of new transmission line corridors. However, if collocated with existing lines, transmission-line construction would be unlikely to alter existing land uses. The types of operational impacts from this alternative would be similar to the effects discussed in the preceding alternative sections. This alternative would be more likely to intensify already existing effects at power generating facilities than create wholly new effects on land use. Existing facilities would likely have best management practices (BMPs) and other procedures in place to ensure that effects to the environment during operations are minimized. The NRC staff concludes that the impacts on land use from the purchased power alternative would be SMALL.
4.2.7.2      Visual Resources The purchased power alternative would likely not result in the construction of any buildings or facilities or any other changes to existing visual resources. Visual impacts from transmission-line construction could be minimized by collocating lines within existing transmission line corridors. The NRC staff concludes that the purchased power alternative would not have noticeable impacts on visual resources, and as such, would be SMALL.
4.3      Air Quality and Noise This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on air quality and noise conditions.
4.3.1      Proposed Action 4.3.1.1      Air Quality Section 3.3 describes the meteorological, air quality, and noise conditions in the vicinity of LSCS. Table 4-2 identifies two Category 1 air quality issues that are applicable to LSCS:
(1) air quality impacts (all plants) and (2) air quality effects of transmission lines. There are no Category 2 issues for air quality. The Category 1 issue, air quality effects of transmission lines, considers the production of ozone and nitrogen oxides (NOx); the GEIS (NRC 2013d) found that minute and insignificant amounts of ozone and nitrogen oxides are generated during the transmission of power to the nuclear plant from the grid. The Category 1 issue, air quality impacts (all plants), considers the air quality impacts from continued operation and refurbishment associated with license renewal.
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Environmental Consequences and Mitigating Actions Table 4-2. Air Quality and Noise Issue                                                                    GEIS Section    Category Air quality impacts (all plants)                                            4.3.1.1          1 Air quality effects of transmission lines                                  4.3.1.1          1 Noise impacts                                                              4.3.1.2          1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 The NRC staff did not identify any new and significant information during the review of LSCSs ER (Exelon 2014a), the site audit, or the scoping process. As a result, the NRC did not identify any information or impacts related to these issues that would change the conclusions presented in the GEIS. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. The GEIS concludes that the impact level for each of these issues is SMALL.
4.3.1.2        Noise One Category 1 noise issue is applicable to LSCS: noise impacts (Table 4-2). The 1996 GEIS (NRC 1996) concluded that noise was not a problem at operating plants and that it was not expected to be a problem at any nuclear plant during the license renewal term. The GEIS (NRC 2013d) did not identify new information that would alter this conclusion; therefore, impacts are expected to be SMALL. The NRC staff did not identify any new and significant information during the review of LSCSs ER (Exelon 2014a, 2015j), the site audit, or the scoping process.
As a result, the NRC did not identify any information or impacts related to this issue that would change the conclusions presented in the GEIS. Therefore, there are no impacts related to this issue beyond those discussed in the GEIS. The GEIS concludes that the impact level for this issue is SMALL.
4.3.2      No-Action Alternative 4.3.2.1        Air Quality When the plant stops operating, there will be a reduction in emissions from many activities related to plant operation, such as the use of stationary combustion sources (i.e., diesel generators and pumps) and vehicle traffic (i.e., employee and delivery vehicles). Therefore, if emissions decrease, the impact on air quality from shutting down LSCS would be SMALL.
4.3.2.2        Noise When the plant stops operating, there will a reduction in noise from activities related to plant operations, such as the turbines, switchyard/transformers, sirens, loudspeakers, and vehicle traffic (i.e., employee and delivery vehicles). As activity from noise sources is reduced below levels associated with operation of LSCS, impacts would remain SMALL.
4.3.3      New Nuclear Alternative 4.3.3.1        Air Quality This alternative includes the construction and operation of two Westinghouse AP1000 reactors, each with an approximate generating capacity of 1,120 megawatts electric (MWe). Due to the moratorium preventing the construction of new nuclear power plants within Illinois, the new nuclear alternative would have to be located elsewhere in the ROI (Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin) at an existing nuclear plant or retired coal site to maximize the use of existing infrastructure. Because the new nuclear alternative could be located 4-7
 
Environmental Consequences and Mitigating Actions anywhere within the seven-state ROI, it is unknown at this time whether the specific site(s) would be located within a designated attainment area.
Construction of the new nuclear plant would result in temporary impacts on local air quality.
During the construction phase, the primary sources of air emissions would consist of engine exhaust and fugitive dust emissions. Engine exhaust emissions would be from heavy construction equipment and commuter, delivery, and support vehicular traffic traveling within, to, and from the facility. Fugitive dust emissions would be from soil disturbances by heavy construction equipment (e.g., earthmoving, excavating, and bulldozing); vehicle traffic on unpaved surfaces; concrete batch plant operations (if any); and wind erosion to a lesser extent.
Air emissions include criteria pollutants (i.e., particulate matter, nitrogen oxide, carbon monoxide, and sulfur dioxide); volatile organic compounds (VOCs); hazardous air pollutants (HAPs), and greenhouse gases (GHGs). Small quantities of VOC and HAP emissions would be released from equipment refueling; organic solvents used in cleaning, onsite storage, and use of petroleum-based fuels; onsite maintenance of the heavy construction equipment; and certain painting and other construction-finishing activities.
Air emissions would be intermittent and would vary, based on the level and duration of a specific activity throughout the construction phase. Based on the State and Federal permits and regulated practices for managing air emissions from construction equipment and temporary stationary sources, controlling fugitive dust, and inspecting vehicles and traffic management plans, the NRC staff expects that potential impacts on air quality from building a nuclear power plant would be minimal. Because air emissions from construction activities would be limited, local, and temporary, the NRC staff concludes that the overall air quality impacts associated with construction of a new nuclear alternative would be SMALL.
Operation of a new nuclear generating plant would result in similar air emissions to those at LSCS. Nuclear power plants do not burn fossil fuels to generate electricity. Sources of air emissions include stationary combustion sources (e.g., diesel generators and diesel pumps),
cooling towers, and mobile sources (e.g., worker vehicles, onsite heavy equipment and support vehicles, and delivery of materials and disposal of wastes). Air pollutants emitted from stationary combustion sources (e.g., criteria pollutants, VOCs, HAPs, and GHGs) and from cooling towers (particulate matter as drift) associated with operating a nuclear power plant would be permitted in accordance with state and Federal regulatory requirements. As noted in Section 3.3, LSCS maintains a Federally Enforceable State Operating Permit (also known as a synthetic minor air permit). A synthetic minor source has the potential to emit air pollutants in quantities at or above the major source threshold levels but has accepted Federally enforceable limitations to keep the emissions below such levels. Because air emissions would be similar for a new nuclear plant, the NRC staff expects similar air permitting conditions and regulatory requirements. Subpart P of 40 CFR 51.307 contains the visibility protection regulatory requirements, including the review of the new sources that may affect visibility in any Federal Class I area. If a new nuclear plant were located near a mandatory Class I area, additional air pollution control requirements may be required.
In general, most stationary combustion sources at a nuclear power plant would operate only for limited periods, often for periodic maintenance testing. Thus, emissions from stationary combustion sources would fall far below the threshold for major sources (100 U.S. short tons per year) and the threshold for mandatory GHG reporting (25,000 metric tons (MT) per year).
The NRC staff expects similar air emissions for combustion sources from a new nuclear plant as are currently being emitted from LSCS (Exelon 2014a), as follows:
* carbon monoxide (CO)2.2 tons (2 MT),
* nitrogen oxides (NOx)8.4 tons (7.6 MT),
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Environmental Consequences and Mitigating Actions
* sulfur dioxide (SO2)0.002 tons (0.002 MT),
* particulate matter (PM10)0.15 tons (0.14 MT), and
* particulate matter (PM2.5)0.15 tons (0.14 MT).
Additional particulate matter emissions would result from cooling tower operation and worker vehicles commuting to and from the plant. However, a nuclear power plant located in the ROI would use cooling water taken from a nearby river or lake, which would have relatively low concentrations of total dissolved solids. In addition, modern cooling towers would be equipped with drift eliminators to minimize the loss of cooling water from the tower via drift. Thus, particulate matter emissions from cooling towers would be anticipated to be minimal.
The NRC staff evaluated potential impacts on air quality associated with criteria pollutants and GHG emissions from operating a new nuclear alternative. The NRC staff determined that the impacts would be minimal. Therefore, the NRC staff concludes that the impacts of operation of a new nuclear alternative on air quality from emissions of criteria pollutants and GHGs would be SMALL. The NRC staff concludes that the air quality impacts associated with construction and operation of a new nuclear alternative would be SMALL.
4.3.3.2      Noise Construction of a new nuclear power plant is similar to that of other large industrial projects and involves many noise-generating activities. In general, noise emissions vary with each phase of construction, depending on the level of activity, the mix of construction equipment for each phase, and site-specific conditions. Noise propagation to receptors is affected by several factors, including source-receptor configuration; land cover; meteorological conditions (i.e., temperature, relative humidity, and vertical profiles of wind and temperature); and screening (e.g., topography and natural or manmade barriers). Typical construction equipment, such as dump trucks, loaders, bulldozers, graders, scrapers, air compressors, generators, and mobile cranes, would be used, and pile-driving and blasting activities would take place during the construction of a new nuclear power plant. Other noise sources include commuter, delivery, and support vehicular traffic traveling within, to, and from the facility.
During the construction phase, a variety of construction equipment would be used and at varying duration. Noise emissions from construction equipment are predicted to be in the 85- to 100-dBA range (FHWA 2006); however, noise levels attenuate rapidly with distance.
At a 0.5-mi (0.8-km) distance from construction equipment, 85 to 90-dBA noise levels can drop to 51 to 61 dBA (NRC 2002). Additionally, noise abatement and controls can be incorporated to reduce noise impacts. Accounting for attenuation from the construction site and noise controls, predicted noise levels can exceed the U.S. Environmental Protection Agency (EPA) guideline of 55 dBA but can be less than the U.S. Department of Housing and Urban Development acceptable noise level guideline of 65 dBA. Based on the temporary nature of construction activities, consideration of noise attenuation from the construction site to residences, the location and characteristics (i.e., ground cover), and good noise control practices, the NRC staff concludes that the potential noise impacts of construction activities from a new nuclear alternative would be SMALL.
During the operation phase, noise sources from the new nuclear power plant would include cooling towers; transformers; turbines; pumps; compressors; other auxiliary equipment (e.g., standby generators); and vehicular traffic (e.g., commuting, delivery, and support), similar to those for LSCS discussed in Section 3.3.2 of this SEIS.
Although the plant layout and the distance from primary noise sources to the nearby receptors at LSCS might be different from those at a new nuclear alternative site and the new nuclear 4-9
 
Environmental Consequences and Mitigating Actions alternative will likely have cooling towers, the NRC staff does not expect noise impacts for a new nuclear plant to be any greater than those analyzed for the existing LSCS site. Although there would be noise generated by the impact of falling water associated with the cooling tower, noise from fans would not occur because the cooling tower would be a natural draft cooling tower, thus resulting in lower noise levels. Therefore, the noise impacts from operations of a new nuclear plant located within the ROI region would be SMALL.
The NRC staff concludes that the noise impacts associated with construction and operation of a new nuclear alternative would be SMALL.
4.3.4      IGCC Alternative 4.3.4.1      Air Quality This alternative includes the construction and operation of four IGCC units with a total output of 2,472 MWe and a capacity factor of 85 percent. The new power plant is assumed to be located at an existing power plant site(s). These sites could be located in Illinois (including the LSCS site) or other adjoining States in the ROI (i.e., Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin). New infrastructure and infrastructure upgrades would depend on specific-site locations. Because the IGCC alternative could be located anywhere within the seven-state ROI, it is unknown at this time whether the specific site(s) would be located within a designated attainment area. If the IGCC alternative were to be located at LSCS, it would be located in LaSalle County; LaSalle County is designated as an attainment area for all National Ambient Air Quality Standards (NAAQS) (40 CFR 81.314).
Construction of an IGCC plant would be similar to that of other large industrial projects and involves many activities similar to those for a new nuclear alternative presented in Section 4.3.3.
Construction of an IGCC plant would result in the release of various criteria pollutants (i.e., particulate matter, nitrogen oxides, carbon monoxide, and sulfur dioxide); VOCs; HAPs; and GHGs from operation of internal combustion engines in construction vehicles, equipment, delivery vehicles, and vehicles used by the commuting construction workforce. In addition, soil disturbance activities, such as earthmoving and material handling, would generate fugitive dust.
The onsite storage and dispensing of vehicle and equipment fuels result in VOC releases. Air emissions would be intermittent and would vary, based on the level and duration of a specific activity throughout the construction phase. Construction lead times for IGCC plants are estimated to be 3 years (NETL 2013). Impacts would be localized, intermittent, and short lived, and adherence to standard construction BMPs would mitigate such impacts. The NRC staff concludes that construction-related impacts on air quality from an IGCC alternative would be of relatively short duration and would be SMALL.
The sources of air emissions during operation include heat recovery steam generator (HRSG) stacks, the wet gas sulfuric acid (WSA) exhaust system, acid gas removal process startup/shutdown vents, startup stacks, flares, material-handling equipment, and mechanical draft cooling towers (DOE 2010a). The HRSG stacks would release the most emissions.
Auxiliary boilers and diesel-driven pumps would also generate emissions on an infrequent basis.
Compared to conventional coal-fired power plants, the proposed IGCC power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate matter emissions by removing constituents from the synthetic syngas (syngas) (i.e., gasifiers convert coal into a gas)
(DOE 2010a). The IGCC alternative would also result in lower nitrogen oxide emissions because nearly 100 percent of the fuel-bound nitrogen from the syngas would be removed from the syngas before combustion in the gas turbine. Sulfur removal technology would remove more than 99 percent of the sulfur in the syngas. The use of sulfide-activated carbon could remove more than 92 percent of mercury from the syngas. More than 99.9 percent of 4-10
 
Environmental Consequences and Mitigating Actions particulate matter emissions would be removed from the syngas using high-temperature, high-pressure filtration.
Various Federal and state regulations aimed at controlling air pollution would affect an IGCC alternative located in the seven-state ROI. A new IGCC plant would qualify as a new major source because of its potential to emit greater than 100 tons per year of criteria pollutants and would be subject to the requirements of a new source review (NSR) permitting program under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.) (EPA 2015f). An NSR permit or construction permit would specify emission limits for each pollutant, along with monitoring and reporting requirements; specifications for fuel and control equipment; and monitoring and performance testing for the IGCC units, auxiliary boiler, and WSA process. The new IGCC plant would be required to secure a Title V operating permit from the state agency.
An NSR review would limit emissions for criteria pollutants and would reflect existing ambient air quality at the selected location. An analysis regarding NAAQS compliance would be conducted at the specific site location. The IGCC alternative also would need to comply with the standard of performance for new stationary sources set forth in Subpart Da, Standards of Performance for Electric Utility Steam Generating Units, of 40 CFR Part 60.
If the IGCC alternative were located close to a mandatory Class I area, additional air pollution control requirements would be necessary (Subpart P of 40 CFR Part 51) as mandated by the Regional Haze Rule. Within the ROI, there are five Class I Federal areas, including Mammoth Cave National Park in Kentucky (40 CFR 81.411), Isle Royale National Park and Seney Wilderness Area in Michigan (40 CFR 81.414), and Hercules-Glades Wilderness Area and Mingo Wilderness Area in Missouri (40 CFR 81.416). The rule could apply to the IGCC alternative but would depend on specific site location(s). If the IGCC alternative were to be located at the LSCS, the nearest Class I Federal area for visibility protection is the Mingo National Wildlife Refuge, which is approximately 306 mi (492 km) southwest of LSCS.
Air emissions for the IGCC alternative were estimated based on emission factors presented in Table 4.3-1 in the GEIS (NRC 2013d). The resulting estimated emissions are as follows:
* sulfur dioxide (SO2)820 tons (740 MT) per year,
* nitrogen oxides (NOx)3,000 tons (2,720 MT) per year,
* particulate matter (PM10)480 tons (435 MT) per year,
* carbon monoxide (CO)2,045 tons (1,850 MT) per year, and
* carbon dioxide equivalent (CO2e)14.3 million tons (13.0 million MT) per year.
The IGCC alternative would produce 820 tons (740 MT) per year of sulfur dioxide and 3,000 tons (2,072 MT) per year of nitrogen oxides. The IGCC plant would have to comply with Title IV of the CAA (42 U.S.C. 7651) reduction requirements for sulfur oxides and nitrogen oxides, which are the main precursors of acid rain and are the major causes of reduced visibility. Title IV establishes maximum sulfur oxide and nitrogen oxide emission rates from the existing plants and a system of sulfur oxide emission allowances that can be used, sold, or saved for future use by the new plants. The new plant would be subjected to the continuous monitoring requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75.
The Cross-State Air Pollution Rule (Volume 76 of the Federal Register, page 48208 (FR 48208)) requires 28 states (including Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin) to improve air quality and requires power plants to reduce annual sulfur dioxide and/or nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. A new IGCC plant would be subject to these additional rules and regulations.
4-11
 
Environmental Consequences and Mitigating Actions The IGCC alternative would emit approximately 14.3 million tons (approximately 13 million MT) per year of CO2e emissions. The plant would be subjected to the continuous monitoring requirements for carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued a final rule tailoring the criteria that determine which stationary sources and modifications to existing projects become subject to permitting requirements for GHG emissions under the prevention of significant deterioration (PSD) and Title V Federal permit programs of the CAA (77 FR 41051). Beginning January 2, 2011,2 operating permits issued to major sources of GHG under the PSD or Title V permit programs must contain provisions requiring the use of best available control technology to limit the emissions of GHGs, if those sources would be subject to PSD or Title V permitting requirements because of their non-GHG pollutant emission potentials and if their estimated GHG emissions are at least 75,000 tons per year of CO2e. If the IGCC alternative meets PSD or Title V permitting requirements for non-GHG pollutant emissions and the GHG emission thresholds established in the rule, GHG emissions from this alternative would be regulated under the PSD and Title V permit programs. Furthermore, the IGCC alternative would be subject to carbon dioxide emission performance rate standards set forth in the Clean Power Plan aimed at reducing carbon pollution from power plants (80 FR 64661-65120).
In response to the Consolidated Appropriations Act of 2008 (Public Law 110-161), EPA issued final mandatory GHG reporting regulations for major sources effective in December 2009 (74 FR 56260). Major sources are defined as those sources emitting more than 25,000 MT per year of all GHGs. An IGCC alternative would be subject to these reporting regulations with or without carbon capture. On January 8, 2014, EPA issued a new proposal for GHG emissions from new fossil fuel-fired electric utility steam generating units (79 FR 1430). It also proposes standards of performance for IGCC units that burn coal. The performance standards are based on partial implementation of carbon capture and sequestration (CCS) as the best system of emission reduction. Although the proposed rule has not been finalized, the IGCC alternative analysis includes an option for future implementation of CCS.
An IGCC alternative also would be subject to the Mercury and Air Toxics Standards (MATS) final rule, which was finalized by EPA on December 16, 2011 (77 FR 9304). Standards for emissions of heavy metals (i.e., mercury, arsenic, chromium, and nickel) and acid gases (i.e., hydrochloric acid and hydrofluoric acid) are set by MATS. Mercury is the most prominent HAP emitted and is subject to regulation by the MATS rule. New IGCC units are required to meet a mercury emission limit of 0.003 lb per gigawatt hour (Subpart UUUUU of 40 CFR Part 63). The NRC staff estimates that an IGCC alternative replacing the electrical output of LSCS would generate 0.03 ton (0.02 MT) of mercury per year.
The impact from sulfur dioxide, nitrogen oxide, particulate matter, and carbon monoxide emissions would be significant and would be subject to Title V permitting. GHG emissions also would be noticeable and significant; GHG emissions would be much larger than the threshold in the EPA GHG Tailoring Rule (77 FR 41051), and GHG emissions may be regulated under the PSD and Title V permit programs that would trigger a regulated NSR. In the near future, carbon dioxide emissions could be reduced considerably if CCS technology were installed.
2  On June 23, 2014, the U.S. Supreme Court issued a decision that EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a PSD or Title V permit but could continue to require PSD and Title V permits otherwise required, based on emissions of conventional pollutants. In July 2014, EPA issued a memorandum in response to the Supreme Courts decision and acknowledged that, although the decision is pending judicial action, EPA will no longer require PSD or Title V permits for GHG-emitting sources that are not sources subject to PSD or Title V permits based on emissions of conventional pollutants (e.g., nitrogen oxides and carbon monoxide) (EPA 2015b).
4-12
 
Environmental Consequences and Mitigating Actions As result of the significant criteria air emissions, a major air source, and significant GHG emissions, the NRC staff concludes that the air quality impacts associated with operation of an IGCC alternative would be MODERATE.
The NRC staff concludes that the overall air quality impacts associated with construction and operation of an IGCC alternative would be MODERATE.
4.3.4.2    Noise Construction of an IGCC plant is similar to that of other large industrial projects, and construction-related noise sources would be virtually the same as those for construction of the nuclear alternative. However, the construction period for the IGCC alternative would be shorter, and activities would be scattered over a wider area as compared with construction of a nuclear alternative. Consequently, with construction-related noise for the nuclear alternative as a bounding condition, the NRC staff concludes that construction-related noise impacts associated with the IGCC alternative would be SMALL.
Operation of an IGCC plant would introduce mechanical sources of noise that would be audible off site. Continuous sources include the mechanical equipment associated with normal plant operations and mechanical draft cooling towers. Mechanical draft cooling towers may result in greater sound levels than natural draft cooling towers as a result of the mechanical noise associated with the movement of fans. However, mechanical draft cooling towers can be equipped with fans with sound attenuators. Intermittent sources include the equipment related to coal handling, solid waste disposal, transportation related to coal and lime/limestone delivery, and the commuting of plant employees. Noise associated with rail delivery of coal and lime/limestone would extend beyond the plant site boundary and would be most significant for residents living in the vicinity of the facility and along the rail route. Transportation-related noise sources have the potential for causing impacts, as these noise sources reach beyond the plant site boundary. Noise impacts associated with rail delivery are predicted to be in the 80- to 96-dBA range (NRC 2002).
As a result of additional noise associated with both the mechanical cooling towers and the rail line and unknown distance from primary noise sources to nearby sensitive receptors, the NRC staff concludes that the potential offsite noise impacts on residents in the vicinity of an IGCC alternative site would range from SMALL to MODERATE The NRC staff concludes that the overall potential impacts of noise associated with construction and operation of the IGCC alternative and the rail line are considered to range from SMALL to MODERATE.
4.3.5    NGCC Alternative 4.3.5.1    Air Quality This alternative includes the construction and operation of five NGCC 560-MWe units (total 2,800 MWe) and a capacity factor of 85 percent. These sites could be located at an existing power plant site in the ROI (including the LSCS site). Some infrastructure upgrades may be required and would require construction of a new or upgraded pipeline. Using existing power plant sites maximizes availability of infrastructure and reduces disruption to land and populations. Because the NGCC alternative could be located anywhere within the seven-state ROI, it is unknown at this time whether the specific site(s) would be located within a designated attainment area. If the NGCC alternative were to be located at LSCS, it would be located in LaSalle County; LaSalle County is designated as an attainment area for all NAAQS (40 CFR 81.314).
4-13
 
Environmental Consequences and Mitigating Actions Construction of an NGCC power plant would be similar to that of other large industrial projects.
Construction of an NGCC power plant would result in the release of various criteria pollutants (i.e., particulate matter, nitrogen oxides, carbon monoxide, and sulfur dioxide); VOCs; HAPs; and GHGs from the operation of internal combustion engines in construction vehicles, equipment, delivery vehicles, and vehicles used by the commuting construction workforce. In addition, onsite soil disturbance activities, such as earthmoving and material handling, would generate fugitive dust. Releases of VOCs will also result from the onsite storage and dispensing of vehicle and equipment fuels. Air emissions would be intermittent and would vary, based on the level and duration of a specific activity throughout the construction phase.
Gas-fired power plants are constructed relatively quickly; construction lead times for NGCC plants are around 2 to 3 years (EIA 2011; OECD/NEA 2005). Impacts would be localized, intermittent, and short lived, and adherence to standard construction BMPs would mitigate such impacts. Therefore, the NRC staff concludes that construction-related impacts on air quality from an NGCC alternative would be of relatively short duration and would be SMALL.
Operation of the NGCC plant could result in significant emissions of certain criteria pollutants, including carbon monoxide, nitrogen oxides, and particulate matter. The sources of air emissions during operation include gas turbines through HRSG stacks and mechanical draft cooling towers. An analysis regarding NAAQS compliance would be conducted at the specific site location. Various Federal and state regulations aimed at controlling air pollution would affect an NGCC alternative located in the seven-state ROI. An NGCC plant would be subject to NSR permitting program requirements to ensure that air emissions are minimized and that the local air quality is not substantially degraded (EPA 2015e). The new NGCC plant would be required to secure a Title V operating permit from the state agency. The NGCC plant would need to comply with the standards of performance for stationary combustion turbines set forth in Subpart KKKK of 40 CFR Part 60. If the NGCC alternative were located close to a mandatory Class I area, additional air pollution control requirements would be required (Subpart P of 40 CFR Part 51), as mandated by the Regional Haze Rule. A detailed discussion of these Federal and state regulations is provided in Section 4.3.4 (see the air quality operation discussion for the IGCC alternative).
Emissions for the NGCC alternative were estimated using emission factors developed by the U.S. Department of Energys (DOEs) National Energy Technology Laboratory (NETL) NGCC analysis (NETL 2010). Assuming a total gross capacity of 2,800 MWe and a capacity factor of 0.85, the resulting estimated NGCC emissions are as follows:
* sulfur dioxide (SO2)32 tons (29 MT) per year,
* nitrogen oxides (NOx)700 tons (635 MT) per year,
* particulate matter (PM10)51 tons (46 MT) per year,
* carbon monoxide (CO)72 tons (65 MT) per year, and
* carbon dioxide equivalent (CO2e)9.8 million tons (8.2 million MT) per year.
The NGCC alternative would produce 32 tons (29 MT) per year of sulfur dioxide and 700 tons (635 MT) per year of nitrogen oxides. The new plant would be subjected to the continuous monitoring requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75. A new NGCC plant would be subject to these additional rules and regulations set forth in the Cross-State Air Pollution Rule (see Section 4.3.4 above).
The NGCC alternative would emit approximately 9.8 million tons (approximately 8.2 million MT) per year of CO2e. The plant would be subjected to the continuous monitoring requirements for carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued a final rule 4-14
 
Environmental Consequences and Mitigating Actions tailoring the criteria that determine which stationary sources and modifications to existing projects become subject to permitting requirements for GHG emissions under the PSD and Title V programs of the CAA (77 FR 41051). Beginning January 2, 2011, operating permits issued to major sources of GHG under PSD or Title V Federal permit programs must contain provisions requiring the use of best available control technology to limit the emissions of GHGs, if those sources would be subject to PSD or Title V permitting requirements because of their non-GHG pollutant emission potentials and if their estimated GHG emissions are at least 75,000 tons per year of carbon dioxide equivalent (CO2e) emissions. If the NGCC alternative meets PSD or Title V permitting requirements for non-GHG pollutant emissions and the GHG emission thresholds established in the rule, GHG emissions from this alternative would be regulated under the PSD and Title V permit programs. Furthermore, the NGCC alternative would be subject to carbon dioxide emission performance rate standards set forth in the Clean Power Plan aimed at reducing carbon pollution from power plants (80 FR 64661-65120).
In response to the Consolidated Appropriations Act of 2008 (Public Law 110-161), EPA issued final mandatory GHG reporting regulations for major sources effective in December 2009 (74 FR 56260). Major sources are defined as those emitting more than 25,000 MT per year of all GHGs. An NGCC alternative would be subject to these reporting regulations with or without carbon capture.
On January 8, 2014, EPA issued a new proposal for GHG emissions from new fossil fuel-fired electric utility steam generating units (79 FR 1430). It also proposes standards of performance for natural gas-fired stationary combustion turbines based on modern, efficient NGCC technology as the best system of emission reduction.
In December 2000, EPA issued regulatory findings on emissions of HAPs from electric utility steam-generating units (65 FR 79825). These findings indicated that natural gas-fired plants emit HAPs, such as arsenic, formaldehyde, and nickel and stated the following:
[T]he impacts due to HAP emissions from natural gas-fired electric utility steam generating units were negligible based on the results of the study. The Administrator finds that regulation of HAP emissions from natural gas-fired electric utility steam generating units is not appropriate or necessary
[65 FR 79825].
Mercury is not emitted from NGCC power plants because natural gas used as fuel does not contain mercury.
Nitrogen oxide emissions from an NGCC alternative would be significant and subject to Title V permitting. GHG emissions also would be noticeable and significant; carbon dioxide emissions would be much larger than the threshold in the EPA GHG Tailoring Rule. The NRC staff concludes that the overall air quality impacts associated with operation of an NGCC alternative would be MODERATE.
The NRC staff concludes that the overall air quality impacts associated with construction and operation of an NGCC alternative would be MODERATE.
4.3.5.2      Noise The construction-related noise sources for an NGCC alternative would be virtually the same as those for construction of the IGCC alternative. Construction vehicles and equipment associated with the construction of the NGCC plant would generate noise; these impacts would be intermittent and would last only through the duration of plant construction. Noise emissions from common construction equipment would be in the 85- to 100-dBA range (FHWA 2006).
However, noise abatement and controls can be incorporated to reduce noise impacts. The 4-15
 
Environmental Consequences and Mitigating Actions NRC staff concludes that construction-related noise impacts associated with the NGCC alternative would be SMALL.
Noise impacts from operations would include mechanical draft cooling towers, transformers, turbines, pumps, compressors, exhaust stacks, the combustion inlet filter house, condenser fans, high-pressure steam piping, and vehicles (Saussus 2012). As discussed under the IGCC alternative, mechanical draft cooling towers can be equipped with fans with sound attenuators.
Pipelines delivering natural gas fuel could be audible off site near gas compressor stations, but such noise impacts would be similar to impacts already occurring in the vicinity of the existing pipeline to which the new NGCC site would connect. Most noise-producing equipment is located inside the power block buildings, and no outside fuel-handling activities will occur.
Minor offsite noise sources could include pipeline compressor stations. The NRC staff concludes that operation-related noise impacts from the NGCC alternative would be SMALL.
The NRC staff concludes that construction- and operation-related noise impacts from the NGCC alternative would be SMALL.
4.3.6      Combination Alternative (NGCC, Wind, Solar)
The combination alternative relies on NGCC-, wind-, and solar-generating capacity. The solar photovoltaic (PV) portion would consist of a total net capacity of 227 MWe; the onshore wind portion would consist of a total net capacity of 1,813 MWe; and the NGCC portion would consist of a total net capacity of 360 MWe. The NGCC portion of this alternative would be located at LSCS and in an attainment area (LaSalle County) for all NAAQS. The solar and wind portion of this alternative would be located in Illinois or other adjoining States in the ROI (i.e., Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin).
4.3.6.1      Air Quality Air emissions associated with the construction of the NGCC portion of the combination alternative are similar to the NGCC alternative but due to its smaller size, would be proportionally reduced. As discussed in Section 4.3.5.1, construction activities for an NGCC alternative would cause some temporary impacts to air quality from dust generation during operation of the earth-moving and material-handling equipment and exhaust emissions from worker vehicles and construction equipment. These emissions include criteria pollutants, VOCs, GHGs, and small amounts of HAPs. However, these impacts would be localized, intermittent, and short lived, and adherence to standard construction BMPs would mitigate such impacts. The NRC staff concludes that construction-related impacts on air quality from an NGCC portion of the combination alternative would be of relatively short duration and would be SMALL.
For the wind portion of the combination alternative, the total estimated land requirement would be between 3,376 and 10,127 ac (1,366 to 4,098 ha), but only a small percentage of the committed land area (5 to 10 percent or less) would be disturbed by construction activities because wind turbines need to be separated from one another to maximize energy production and to avoid wake turbulences created by upwind turbines. Construction of the wind portion of the combination alternative would involve a number of activities, including road and staging/laydown area construction, land clearing, topsoil stripping, earth-moving operations, grading, ground excavation, drilling, foundation treatment, erecting wind turbines, ancillary building/structure construction, and electrical and mechanical installation. For most wind energy facilities, the site preparation phase would last for only a few months, followed by a year-long construction phase (depending on the size of the wind energy facilities) (Tegen 2006). Air emissions associated with construction activities result from fugitive dust from soil disturbances and engine exhaust from heavy equipment and vehicular traffic. These emissions include 4-16
 
Environmental Consequences and Mitigating Actions criteria pollutants, VOCs, GHGs, and HAPs. Dust-suppression methods and other mitigation measures could reduce impacts from fugitive dust. The wind portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the heavy equipment used, workforce, level of activities, and construction duration would be substantially lower than other alternatives. Therefore, the NRC staff concludes that the overall air quality impacts associated with construction of the wind portion of the combination alternative would be SMALL.
Construction of the solar portion of the combination alternative would cause temporary impacts to air quality from fugitive dust from soil disturbances and engine exhaust from heavy equipment and vehicular traffic. Air emissions associated with construction activities include criteria pollutants, VOCs, GHGs, and HAPs to a lesser amount. Dust-suppression methods and other mitigation measures could reduce impacts from fugitive dust. The solar PV portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the number of heavy equipment and workforce, level of activities, and construction duration would be substantially lower than those for other alternatives. Therefore, the NRC staff concludes that the overall air quality impacts associated with construction of the solar PV portion of the combination alternative would be SMALL.
Air emissions associated with the operation of the NGCC portion of the combination alternative are similar to the NGCC alternative in Section 4.3.5.1 but are reduced proportionally because its generating capacity is approximately 13 percent of the NGCC alternative.
Emissions for the NGCC alternative were estimated using emission factors developed by DOEs NETL NGCC analysis (NETL 2010). Assuming a total gross capacity of 360 MWe and a capacity factor of 0.85, the resulting estimated NGCC emissions are as follows:
* sulfur dioxide (SO2)4.2 tons (3.8 MT) per year,
* nitrogen oxides (NOx)90 tons (81 MT) per year,
* particulate matter (PM10)6.5 tons (5.9 MT) per year,
* carbon monoxide (CO)9.3 tons (8.4 MT) per year, and
* carbon dioxide equivalent (CO2e)1.2 million tons (1.1 million MT) per year.
Estimated annual emissions of sulfur dioxide, nitrogen oxides, carbon monoxide, and particulate matter would be lower than the major source threshold. Furthermore, the NGCC portion of this alternative would be located at LSCS and would be a designated attainment area (LaSalle County) for all NAQQS. Therefore, the overall air quality impacts associated with operation of the NGCC portion of the combination alternative would be SMALL.
Emissions from the operation of wind energy facilities would include minor dust and engine exhaust emissions from vehicles and heavy equipment associated with site inspections, maintenance activities, and wind erosion from cleared land and access roads. The types of emission sources and pollutants during operation would be similar to those during construction, but emissions would be much less during operation. The NRC staff concludes that the overall air quality impacts associated with the operation of the wind portion of the combination alternative would be SMALL.
In general, air emissions associated with the operation of solar energy facilities are negligible because no fossil fuels are burned to generate electricity. Emissions from solar fields would include fugitive dust and engine exhaust emissions from vehicles and heavy equipment associated with site inspections, maintenance activities (e.g., panel washing or replacement),
and wind erosion from cleared lands and access roads. The types of emission sources and 4-17
 
Environmental Consequences and Mitigating Actions pollutants during operation would be similar to those during construction, but emissions would be much lower during operation. These emissions should not cause exceedances of air quality standards or have any impacts on climate change. The NRC staff concludes that the overall air quality impacts associated with the operation of the solar PV portion of the combination alternative would be SMALL.
The overall air quality impacts associated with construction and operation of the combination alternative would be SMALL.
4.3.6.2      Noise The construction-related noise sources for the NGCC portion of the combination alternative would be virtually the same as those for construction of the NGCC alternative. The construction period for the NGCC portion would be shorter, and the level of construction activities would be less extensive than for the NGCC alternative. Consequently, the NRC staff concludes that construction-related noise impacts associated with the NGCC portion of the combination alternative would be SMALL.
Construction of the wind portion of the combination alternative would involve a number of activities, as described above. The wind portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the number of heavy equipment and workforce, level of activities, and construction duration would be substantially lower than other alternatives. Considering these factors, the NRC staff concludes that construction-related noise impacts associated with the wind portion of the combination alternative would be SMALL.
Construction of the solar PV portion of the combination alternative would involve a number of activities. The solar PV portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the number of heavy equipment and workforce, level of activities, and construction duration would be substantially lower than other alternatives. Considering these factors, the NRC staff concludes that construction-related noise impacts associated with the solar PV portion of the combination alternative would be SMALL.
Besides noise from the power block area, cooling towers, and vehicular traffic, operation-related noise for the NGCC portion would include limited outdoor waste-handling activities. Pipelines delivering natural gas fuel could be audible off site near gas compressor stations, but such sound impacts would be similar to impacts already occurring in the vicinity of the existing pipeline to which the new NGCC site would connect. Most noise-producing equipment is located inside the power block buildings, and no outside fuel-handling activities would occur.
The NRC staff concludes that operation-related noise impacts from the NGCC portion of the combination alternative would be SMALL.
Noise impacts from wind generation operations would include aerodynamic noise from the turbine rotors and mechanical noise from the turbine drive-train components. Noise levels are dependent on the wind and atmospheric conditions, which vary with time, and site-specific conditions, including the number and size of wind turbines, their layout, their distance to nearby sensitive receptors, land cover, and topography. Wind turbine noise levels can reach 105 dBA; however, studies show that at approximately 1,000 ft (300 m) from a wind turbine, noise levels can reach 43 dBA (GE 2010; Hessler 2011). Therefore, masking effects of background noise should be taken into consideration. Unless noise from wind turbines is masked by high background levels (e.g., near major highways or industrial complexes), it can be noticeable and annoying at farther distances. One study indicated that, for the same A-weighted sound level, proportions of respondents annoyed by wind turbine noise are higher than for other community 4-18
 
Environmental Consequences and Mitigating Actions noise, such as aircraft, road, or railway traffic, and that the proportion of respondents annoyed by the noise increases more rapidly (Pedersen and Persson Waye 2004). Therefore, the NRC staff concludes that operation-related noise impacts from the wind portion of the combination alternative would be SMALL to MODERATE, depending on the layout and location of the wind facility and on its distance to nearby sensitive receptors.
The solar PV portion of the combination alternative would have no power block and cooling towers; therefore, there would be a minimal number of noise sources with low-level noises.
Noise sources include small-scale cooling systems to dissipate heat from solar module assemblies, solar tracking devices, inverters, transformers, and vehicle traffic for maintenance and inspection. Because of minimal noise-generating activities, noise from a solar PV facility would be anticipated to be inaudible or barely perceptible at the facility boundaries. Considering the minimum number of sources with low-noise levels and the area size of the solar PV facility, the NRC staff concludes that operation-related noise impacts from the solar PV portion of the combination alternative would be SMALL.
The noise impacts associated with construction and operation of the combination alternative would be SMALL to MODERATE.
4.3.7      Purchased Power Alternative 4.3.7.1      Air Quality As discussed in Section 2.2.2.5, purchased power would come from common types of existing technology (i.e., coal, natural gas, and nuclear) within the ROI, and the construction of new facilities to replace LSCS would be unlikely. Construction of new transmission lines would result in additional amounts of air emissions. Air emissions associated with the construction of transmission lines would be from operation of the earth-moving and material-handling equipment and exhaust emissions from worker vehicles and construction equipment. These emissions include criteria pollutants, VOCs, GHGs, and HAPs. However, these impacts would be temporary and would not likely be high. For purchased power from existing plants, the impacts on air quality are expected to be SMALL because change to existing plant operations would be minimal.
If new facilities were to be constructed for purchased power, the impact on air quality would depend on the plant technology constructed and the air quality status (i.e., attainment, nonattainment, or maintenance status) where the generating plant is located because air emissions can vary substantially based on the alternative air quality discussions provided above. For instance, natural gas- and coal-fired plants emit higher amounts of nitrogen oxides, sulfur oxides, particulate matter, and carbon dioxide than nuclear power plants do. Purchased power from new nuclear plants would not have noticeable impacts on air quality. New natural gas- and coal-fired plants would have noticeable impacts on air quality as a result of the higher amounts of air emissions. Furthermore, if the plant is sited in a designated nonattainment or maintenance area, emission impacts from plant operation can be greater than those for a designated attainment area.
Based on the above, impacts on air quality from purchased power from new plants would be SMALL to MODERATE.
4.3.7.2      Noise Purchased power from existing electricity generating facilities would not have noticeable impacts on noise because change to existing plant operations would be minimal. Purchased power from new generating facilities could have impacts on noise. Construction and operation of new facilities could result in additional noise sources, including mechanical equipment 4-19
 
Environmental Consequences and Mitigating Actions associated with normal plant operations and vehicular traffic. Additionally, construction of new transmission lines could increase noise levels. Increase in noise levels from construction of new transmission lines and new facilities would be dependent on the distance of residents to the noise sources. Noise levels from operation would also be dependent on the type of technology; for instance, operation of nuclear or wind power. Therefore, impacts from purchased power on noise would be SMALL to MODERATE.
4.4      Geologic Environment This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on geologic and soil resources.
4.4.1      Proposed Action Section 3.4 describes the local and regional geologic environment of the LSCS site. Table 4-3 identifies the issue related to geology and soils that is applicable to the LSCS site during the license renewal term.
Table 4-3. Geology and Soils Issues Issue                                                                GEIS Section      Category Geology and Soils                                                          4.4.1            1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 The NRC staff did not identify any new and significant information associated with the Category 1 geology and soils issue identified in Table 4-3 during the review of the applicants ER, the site audit, the scoping process, or the evaluation of other available information. As a result, the staff did not identify any information or impacts related to this issue that would change the conclusions presented in the GEIS (NRC 2013d). For this issue, the GEIS concludes that the impacts are SMALL. It is expected that there would be no incremental impacts related to this Category 1 issue during the renewal term beyond those discussed in the GEIS; therefore, the impacts associated with this issue are SMALL.
4.4.2      No-Action Alternative There would not be any impacts to the geology and soils at the LSCS site with the shutdown of the facility. With the shutdown of the facility, no additional land would be disturbed. Therefore, impacts would be SMALL.
4.4.3      New Nuclear Alternative For the new nuclear alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. During construction, sources of aggregate material, such as crushed stone and sand and gravel, would be required to construct buildings, foundations, roads, and parking lots. These resources would likely be obtained from commercial suppliers using local or regional sources. Land clearing during construction and the installation of power plant structures and impervious surfaces would expose soils to erosion and would alter surface drainage. Best management practices would be implemented in accordance with applicable permitting requirements to reduce soil erosion.
These practices would include the use of sediment fencing, staked hay bales, check dams, 4-20
 
Environmental Consequences and Mitigating Actions sediment ponds, riprap aprons at construction and laydown yard entrances, mulching and geotextile matting of disturbed areas, and rapid reseeding of temporarily disturbed areas.
Removed soils and any excavated materials would be stored on site for redistribution, such as for backfill, at the end of construction. Construction activities would be temporary and localized.
Therefore, the impacts of the new nuclear alternative on geology and soil resources would be SMALL.
4.4.4      IGCC Alternative For the coal IGCC alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. Geologic construction material would be obtained, and BMPs would be applied as described in the new nuclear alternative in Section 4.4.3. Therefore, the impacts of the IGCC alternative on geology and soil resources would be SMALL.
4.4.5      NGCC Alternative For the NGCC generation alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. Geologic construction material would be obtained, and BMPs would be applied as described in the new nuclear alternative in Section 4.4.3. Therefore, the impacts of the NGCC on geology and soil resources would be SMALL.
4.4.6      Combination Alternative (NGCC, Wind, Solar)
For the combination NGCC, wind, and solar alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. Geologic construction material would be obtained, and BMPs would be applied as described in the new nuclear alternative in Section 4.4.3. The solar PV and the wind farm part of this alternative would require a large amount of land. However, much of the land would be undisturbed because road and facility construction would disturb only a small fraction.
Therefore, the impacts of the combination NGCC, wind, and solar alternative on geology and soil resources would be SMALL.
4.4.7      Purchased Power Alternative The impacts of the purchased power alternative are likely to be bounded by the impact descriptions of the other alternatives. Purchased power is likely to come from existing facilities, or if new facilities are constructed, it would likely be from one of the previously discussed alternatives. These alternatives have SMALL impacts. Therefore, the impact of this alternative on geology and soil resources would be SMALL.
4.5      Water Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on surface water and groundwater resources.
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Environmental Consequences and Mitigating Actions 4.5.1      Proposed Action 4.5.1.1      Surface Water Resources Section 3.5.1 describes surface water resource-related aspects and conditions relevant to the LSCS site. Table 4-4 identifies the Category 1 (generic) and Category 2 surface water use and quality issues applicable to LSCS.
Table 4-4. Surface Water Resources Issues Issue                                                                    GEIS Section      Category Surface water use and quality (non-cooling system impacts)                  4.5.1.1            1 Altered current patterns at intake and discharge structures                4.5.1.1            1 Scouring caused by discharged cooling water                                4.5.1.1            1 Discharge of metals in cooling system effluent                              4.5.1.1            1 Discharge of biocides, sanitary wastes, and minor chemical spills          4.5.1.1            1 Surface water use conflicts (plants with cooling ponds or cooling towers    4.5.1.1            2 using makeup water from a river)
Effects of dredging on surface water quality                                4.5.1.1            1 Temperature effects on sediment transport capacity                          4.5.1.1            1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 Generic Surface Water Resources Issues The NRC staff did not identify any new and significant information associated with the Category 1 surface water issues identified in Table 4-4 during the review of the applicants ER (Exelon 2014a, 2015b), the applicants responses to the NRCs requests for additional information (RAIs), the scoping process, the results of the environmental site audit, or the evaluation of other available information as documented under Section 3.5.1 of this SEIS. As a result, no information or impacts related to these issues were identified that would change the conclusions presented in the GEIS (NRC 2013d). For these issues, the GEIS concludes that the impacts are SMALL. It is expected that there would be no incremental impacts related to these Category 1 issues during the renewal term beyond those discussed in the GEIS.
The Category 2 (Table 4-4) issue related to surface water during the renewal term is discussed in the following text.
Surface Water Use Conflicts This section presents the NRC staffs review of the plant-specific (Category 2) surface water use conflict issue listed in Table 4-4.
For nuclear power plants using cooling towers or cooling ponds supplied with makeup water from a river, the potential impact on the flow of the river and water availability to meet the demands of other users is a Category 2 issue. This designation requires a plant-specific assessment.
In evaluating the potential impacts resulting from surface water use conflicts associated with license renewal, the NRC staff uses as its baseline the surface water resource conditions as described in Sections 3.1.3 and 3.5.1. These baseline conditions encompass the defined hydrologic (flow) regime of the surface water(s) that is potentially affected by continued 4-22
 
Environmental Consequences and Mitigating Actions operations, as well as the magnitude of surface water withdrawals for cooling and other purposes (as compared to relevant appropriation and permitting standards). The baseline also considers other downstream uses and users of surface water.
The mean annual discharge of the Illinois River (described in Section 3.5.1.1) measured at the U.S. Geological Survey (USGS) gage at Marseilles, Illinois, is 10,750 cubic feet per second (cfs)
(304 cubic meters per second (m3/s)). This gaging station is approximately 3 mi (4.8 km) downstream from the LSCS river screen house and associated river intake structure and blowdown discharge canal. Flows measured at this gaging station are also inclusive of surface water withdrawals that other entities make in the same general vicinity as LSCS and that withdraw surface water from the same portion of the Marseilles Pool as LSCS. These include Agrium U.S., Inc., and PCE Phosphate, Marseilles Operation. These facilities are discussed in Section 3.5.1.2 and shown in Figure 3-5.
As described in Section 3.5.1.2, LSCSs average surface water withdrawal rate from the Marseilles Pool of the Illinois River is approximately 105 cfs (2.96 m3/s or 67.8 million gallons per day (mgd)), with consumptive use averaging about 49.7 cfs (1.4 m3/s or 32.1 mgd). This consumptive use is equivalent to about 0.5 percent of the Illinois Rivers average annual flow.
The NRC staff also evaluated the impacts of continued LSCS operations on low-flow conditions in the Illinois River. The lowest annual mean flow recorded for the Illinois River at Marseilles is 5,583 cfs (157.7 m3/s), and the mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the period of record (USGS 2015). The 90-percent exceedance flow is an indicator value of hydrologic drought. It signifies the flow rate that is equaled or exceeded 90 percent of the time as compared to the average flow for the period of record. Compared to these measures of reduced river flow, LSCSs current consumptive water use (i.e., 49.7 cfs (1.4 m3/s or 32.1 mgd))
represents a 0.9- and a 1.1-percent reduction, respectively, in the flow of the river downstream of the LSCS site. LSCSs consumptive water use is not expected to increase during the license renewal term (Exelon 2015b).
As Exelon noted in its ER (Exelon 2014a), drought conditions could cause the flows in the main stem of the Illinois River and surface water elevations to fall below levels that could impact LSCS operations. As previously discussed in Section 3.5.1.2 of this SEIS, Exelon maintains an Extreme Heat Implementation Plan that is part of an overall Summer Readiness Plan. The Extreme Heat Implementation Plan provides procedural guidance to plant personnel for responding to worst-case summer weather and hydrologic conditions to ensure compliance with LSCSs National Pollutant Discharge Elimination System (NPDES) permit for thermal discharge limits and to safeguard plant equipment. As necessary, plant personnel run thermal models and will adjust makeup pumping rates to the cooling pond or the rate of blowdown to the river to maintain permit compliance. Under extreme cases, it may be necessary for Exelon to reduce LSCSs power output or to shut down the plant (e.g., under conditions of extremely low water levels).
In conclusion, the NRC staffs review of available data indicates that consumptive water use associated with LSCS operations combined with other surface water withdrawals within the Marseilles Pool have no substantial impact on downstream water availability. LSCSs surface water withdrawals and low rate of consumptive use of flow in the Illinois River are very unlikely to substantially impact downstream water availability or instream uses of surface water within the Marseilles Pool during the license renewal term. Thus, operation of LSCS during the license renewal term is not expected to result in a water use conflict on the Illinois River.
In addition, in the event of worst-case summer weather and hydrologic conditions affecting LSCS, Exelon has operational procedures in place to minimize hydrologic and thermal impacts on the river. In total, the NRC staff concludes that the potential impacts on surface water 4-23
 
Environmental Consequences and Mitigating Actions resources and downstream water availability from LSCSs continued withdrawals and consumptive water use during the license renewal term would be SMALL.
4.5.1.2    Groundwater Resources Section 3.5.2 describes groundwater resources at LSCS. Table 4-5 identifies issues related to groundwater that are applicable to LSCS during the license renewal term.
Table 4-5. Groundwater Issues Issue                                                                      GEIS Section  Category Groundwater contamination and use (non-cooling system impacts)                4.5.1.2        1 Groundwater use conflicts (plants that withdraw less than 100 gpm)            4.5.1.2        1 Groundwater use conflicts (plants with closed-cycle cooling systems that      4.5.1.2        2 withdraw makeup water from a river)
Groundwater quality degradation (plants with cooling ponds at inland sites)    4.5.1.2        2 Radionuclides released to groundwater                                          4.5.1.2        2 Source: Table B-1 in Appendix B, Subpart A to 10 CFR Part 51 The NRC staff did not identify any new and significant information associated with the Category 1 groundwater issues identified in Table 4-5 during the review of the applicants ER, the site audit, the scoping process, or the evaluation of other available information. As a result, no information or impacts related to these issues were identified that would change the conclusions presented in the GEIS (NRC 2013d). For these issues, the GEIS concludes that the impacts are SMALL. Therefore, it is expected that there would be no incremental impacts related to these Category 1 issues during the renewal term beyond those discussed in the GEIS; therefore, the impacts associated with these issues are SMALL.
The three Category 2 issues (see also Table 4-5) related to groundwater during the renewal term are discussed below.
Groundwater Use Conflicts (Plants with Closed-Cycle Cooling Systems That Withdraw Makeup Water from a River)
This issue looks at the potential impact of the consumption of river water on the availability of groundwater supplies. LSCS uses a cooling pond and withdraws water from a small river. In turn, the cooling pond loses water to the atmosphere by evaporation. As a result, less water is returned to the Illinois River than that withdrawn. This issue evaluates the impact of river water consumption and lowered river water levels on groundwater supplies.
The Illinois River alluvium is hydrologically connected to the Alluvial Aquifer. The Alluvial Aquifer is found below and on each side of the Illinois River. It is underlain by the Pennsylvanian Aquitard (see Figure 3-8 in Section 3.4.1 of this document). Because the Pennsylvanian Aquitard is not a significant source of groundwater, the Alluvial Aquifer is the aquifer that would be most impacted by changes in Illinois River water levels.
The average flow in the Illinois River at the Marseilles stream gage (5 mi (8 km) downstream from the intake and discharge structures) is 10,750 cfs (304 m3/s) (Exelon 2014a; USGS 1979, 2015). LSCSs normal peak withdrawal rate from the river at the intake structure is 134 cfs (3.8 m3/s), and 67 cfs (1.89 m3/s) of blowdown is discharged to the river from the cooling pond.
This means that 67 cfs (1.89 m3/s) is not returned to the river. This rate of consumption is 0.6 percent of the normal river flow in the area of the intake and discharge structures. From 4-24
 
Environmental Consequences and Mitigating Actions 1920 through 2014, the lowest annual river flow recorded at the Marseilles stream gage was 5,583 cfs (158 m3/s) in 1964 (USGS 2015). During this period of low flow, the average rate of consumption by the plant would be 1.2 percent of the flow in the river. This rate of consumption is also unlikely to have much impact on river levels and little or no impact on water levels in the Alluvial Aquifer. Therefore, the NRC staff concludes that impacts to groundwater use would be SMALL.
Groundwater Quality Degradation (Plants with Cooling Ponds at Inland Sites)
This issue looks at the potential for the use of closed-cycle inland unlined cooling ponds to degrade the surrounding groundwater quality and the water quality of offsite wells. The total dissolved solids concentration in the cooling pond is limited by LSCS operational procedures to a maximum of 750 milligrams per liter (mg/L), which is less than half the total dissolved solids concentration (1,709 mg/L) in water obtained from the Cambrian-Ordovician Aquifer. The water quality of the cooling pond is good enough to support a highly successful recreational fishery.
With the exception of a few tritium samples that were near background values, between 2009 and 2014, radionuclide concentrations in the cooling pond have not been detected above background values (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015).
The cooling pond is enclosed on the north, east, and south by dikes. On the west side of the cooling pond, the natural topography serves as the shoreline. Seepage from the cooling pond is negligible because the pond was built on the Glacial Drift Aquitard (Wedron Silty-Clay Till),
which has a very low permeability and is 120- to 140-ft (37- to 43-m) thick in the area of the cooling pond. Seepage modeling, using data from test boring and pits in the reservoir area, indicates that any seepage rates would be very low (Exelon 2014a). As previously discussed in Section 3.5.2.1, this aquitard contains only small volumes of extractable groundwater (Exelon 2014a). Therefore, the impact of the cooling pond on groundwater quality would be SMALL.
Radionuclides Released to Groundwater This issue looks at the potential contamination of groundwater from the inadvertent release of radioactive liquids from plant systems into the environment. Section 3.5.2.3 of this SEIS characterizes the groundwater quality at the LSCS site and vicinity, including historical releases of tritium to groundwater. In evaluating the potential impacts on groundwater quality associated with license renewal, the NRC staff uses, as its baseline, the existing groundwater conditions as described in Section 3.5.2.3 of this SEIS. These baseline conditions encompass the existing quality of groundwater potentially affected by continued operations (as compared to relevant State or EPA primary drinking water standards), as well as the current and potential onsite and offsite uses and users of groundwater for drinking and other purposes. The baseline also considers other down-gradient or in-aquifer uses and users of groundwater.
Historical releases of liquids containing tritium have not impacted groundwater quality in aquifers within or beyond the LSCS site boundary. With the exception of the 2010 leak from the recycled condensate tank, all radiological leaks into groundwater have been successfully remediated. The 2010 leak from the recycled condensate tank contaminated groundwater in engineered granular fill but did not contaminate groundwater in an aquifer. The groundwater contaminated by this leak into the engineered fill has undergone significant cleanup, and because of the low permeability, thickness, and lateral extent of the surrounding Wedron Silty-Clay Till, it is very unlikely that the leak will impact offsite groundwater.
The Cambrian-Ordovician Aquifer System is overlain by 312 ft (95 m) of aquitard and is too deep to be impacted by site activities. A search of Illinois State Geological Survey water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant buildings 4-25
 
Environmental Consequences and Mitigating Actions (ISGS 2015). With the exception of one well completed in the Pennsylvanian Aquitard, all the wells have been completed in the Cambrian-Ordovician Aquifer.
Given the low permeability, thickness, and lateral extent of the Wedron Silty-Clay Till, there is little chance of significant impact to the groundwater quality of onsite and offsite aquifers.
Present and future LSCS operations are not expected to impact the quality of groundwater in any aquifers that are a current or potential future source of water for offsite users. Therefore, the NRC staff concludes that the impacts on groundwater use and quality during the license renewal term would be SMALL.
4.5.2      No-Action Alternative 4.5.2.1      Surface Water Resources Surface water withdrawals and the rate of consumptive water use would greatly decrease and eventually cease after LSCS is shut down. Wastewater discharges would be reduced considerably. Therefore, shutdown would reduce the overall impacts on surface water use and quality. Stormwater would continue to be discharged from the plant site throughout plant shutdown and decommissioning. Overall, the impact of this alternative on surface water resources would be SMALL.
4.5.2.2      Groundwater Resources With the cessation of operations, there should be little or no impacts on groundwater quality, and the consumption of groundwater would be much less. The Glacial Drift Aquitard (Wedron Silty-Clay Till) and surrounding dikes would continue to limit groundwater movement either into or out of the cooling pond. Therefore, the impact of this alternative on groundwater resources would be SMALL.
4.5.3      New Nuclear Alternative 4.5.3.1      Surface Water Resources Impacts from construction activities on surface water resources associated with the new nuclear alternative would be considerable in scale by virtue of the land area required for new nuclear units (i.e., 556 ac (225 ha). Deep excavation work for the nuclear island, extensive site clearing, and a large laydown area for facility construction would have the potential for direct and indirect impacts on water resources, which would vary based on site-specific conditions.
Construction activities would alter any onsite surface water drainage features. Some temporary impacts to surface water quality may result from increased sediment loading and from any pollutants in stormwater runoff from disturbed areas, from excavation, and from any dredge-and-fill activities. Stormwater runoff from construction areas and spills and leaks from construction equipment could potentially affect downstream surface water quality.
Nevertheless, application of BMPs in accordance with a State-issued NPDES general permit, including appropriate waste management, water discharge, stormwater pollution prevention, and spill prevention practices, would prevent or minimize surface water or groundwater quality impacts during construction.
The NRC staff assumes that any existing intake and discharge infrastructure at an alternative site location would be refurbished and used to reduce construction-related impacts on surface water quality. Dredge-and-fill operations would be conducted under a permit from the U.S. Army Corps of Engineers (USACE) and State-equivalent permits requiring the implementation of applicable BMPs to minimize associated impacts.
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Environmental Consequences and Mitigating Actions The staff assumes that there would be no direct use of surface water during construction and that water would be obtained from onsite groundwater or from a local water utility or trucked to the point of use. During construction, the dewatering of excavations would not be expected to affect offsite surface water bodies.
The operation of the two new nuclear units using closed-cycle cooling with natural draft cooling towers would require an estimated 86.6 cfs (2.45 m3/s or 56 mgd) of surface water for cooling makeup and related processes. Consumptive water use would be approximately 65 cfs (1.84 m3/s or 42 mgd). The projected consumptive water use under this alternative represents about a 31-percent increase as compared to current LSCS operations, which consume approximately 49.7 cfs (1.4 m3/s or 32.1 mgd) of surface water (see Sections 3.5.1.2 and 4.5.1.1). However, a State or regional permitting within the ROI could impose limits on surface water withdrawals and consumption, which would potentially reduce the cited makeup water and consumptive use demands for this alternative on an annualized basis, particularly during periods of drought.
The NRC staff further expects that water treatment additives for new nuclear plant operations and effluent discharges would be relatively similar in quality and volume to LSCS. Effluent discharges and stormwater discharges would be subject to a State-issued NPDES permit, and surface water withdrawals would be subject to applicable State water appropriation and registration requirements. To prevent and respond to accidental non-nuclear releases to surface water, facility operations would be conducted in accordance with a spill prevention, control, and countermeasures plan; storm water pollution prevention plan; or equivalent plans and associated BMPs and procedures.
Based on the above, the overall impacts on surface water use and quality from construction and operations under the new nuclear alternative would be SMALL to MODERATE.
4.5.3.2      Groundwater Resources For the new nuclear alternative, the staff assumed that construction water would be obtained from onsite groundwater or from a local water utility. During construction and throughout the life of this alternative, groundwater withdrawals would be subject to applicable State water appropriation and registration requirements. The application of BMPs in accordance with a State-issued NPDES general permit, including appropriate waste management, water discharge, stormwater pollution prevention plan, and spill prevention practices, would prevent or minimize groundwater quality impacts during construction. During operations, the consumptive use of groundwater for potable water and water for fire protection would be similar to the proposed action. Therefore, the impact of this alternative on groundwater resources would be SMALL.
4.5.4      IGCC Alternative 4.5.4.1      Surface Water Resources Impacts from construction activities associated with the IGCC alternative on surface water resources would be expected to be similar to, but somewhat greater than, those under the new nuclear alternative (see Section 4.5.3.1). The potential for greater impacts is attributable to the additional land required for construction of the power blocks for four IGCC units and for excavation and construction of other onsite facilities for coal handling and storage and for coal ash and scrubber waste management. The same assumptions for construction and operations also apply to this alternative, except as noted.
Some temporary impacts to surface water quality may result from increased sediment loading and from pollutants in stormwater runoff from disturbed areas and from excavation and 4-27
 
Environmental Consequences and Mitigating Actions dredge-and-fill activities. In addition, hydrologic and water-quality impacts could occur from the extension or refurbishment of rail spurs to transport coal and other materials to potential site locations and to transfer coal ash from those sites. Using an existing power plant site would allow the use of the existing cooling water intake, effluent discharge, and rail infrastructure. If the IGCC plant is located at the LSCS site, portions of the cooling pond and other plant areas may be repurposed to construct IGCC facilities, including closed-cycle mechanical draft cooling towers. Regardless, as described in Section 4.5.3.1 for the new nuclear alternative, water-quality impacts from construction activities would be minimized by the application of BMPs and through compliance with State-issued NPDES permits. Any dredge-and-fill operations would be conducted under a permit from the USACE and State-equivalent permits requiring the implementation of BMPs to minimize impacts.
Operation of an IGCC plant would require less makeup water and would have lower consumptive use than that of either the new nuclear alternative or current LSCS operations.
The projected cooling water makeup requirement for an IGCC plant under this alternative is approximately 39 cfs (1.09 m3/s or 25 mgd), with consumptive use of about 31 cfs (0.87 m3/s or 20 mgd). This alternative would consume about 38 percent less surface water than that under current LSCS operations, which consumes approximately 49.7 cfs (1.4 m3/s or 32.1 mgd).
As summarized in Section 4.5.3.1 for the new nuclear alternative, surface water withdrawals and effluent discharges would be subject to applicable regulatory requirements under this alternative. However, management of runoff and leachate from coal and ash storage facilities would require additional regulatory oversight and would present an additional risk to surface water resources near site locations.
For this alternative, based on the projected magnitude of ground disturbance and hydrologic alteration and potential water quality impacts from coal and ash handling and management, impacts on surface water resources would range from SMALL to MODERATE.
4.5.4.2      Groundwater Resources The impact significance level on groundwater resources for the coal IGCC alternative is less than the new nuclear alternative described in Section 4.5.3.2. Approximately the same amount of groundwater would be consumed during the operation of the facility, but less groundwater would be consumed in the construction of the facility than for the new nuclear alternative.
Therefore, impacts of the IGCC alternative on groundwater resources would be SMALL.
4.5.5    NGCC Alternative 4.5.5.1      Surface Water Resources Direct impacts from construction activities associated with the NGCC alternative on surface water resources would be expected to be much smaller than those under either the new nuclear or IGCC alternative. A new NGCC plant and associated pipelines would occupy a much smaller footprint (i.e., about 94 ac (38 ha)) than that of the current LSCS facility or the proposed new nuclear or IGCC facilities. This smaller footprint would result in less extensive excavation and earthwork. Otherwise, the same assumptions for construction and operations also apply to this alternative, except as noted.
Some temporary impacts to surface water quality may result from increased sediment loading, any pollutants in stormwater runoff from disturbed areas, excavation, and dredge-and-fill activities. Depending on the path of any required new gas pipelines and transmission lines to service the NGCC plant, some stream crossings could be necessary. However, because of the short-term nature of any required dredge-and-fill operations and stream-crossing activities, the hydrologic alterations and sedimentation would be localized, and water-quality impacts would be 4-28
 
Environmental Consequences and Mitigating Actions temporary and would cease after construction has been completed and the site has been stabilized. The use of modern pipeline construction techniques, such as horizontal directional drilling, would further minimize the potential for water-quality impacts in the affected streams. In addition, as described in Section 4.5.3.1 for the new nuclear alternative, water-quality impacts would be minimized by the application of BMPs and through compliance with State-issued NPDES permits for construction. Any dredge-and-fill operations would be conducted under a permit from the USACE and State-equivalent permits requiring the implementation of BMPs to minimize impacts.
For onsite facility operations, a five-unit NGCC plant would have a smaller cooling water demand and lower consumptive water use as compared to that under current LSCS operations and for the new nuclear and IGCC alternatives. It is projected that an NGCC plant would require approximately 26.3 cfs (0.74 m3/s or 17 mgd) of surface water for cooling and related processes, with consumptive use totaling about 20.1 cfs (0.57 m3/s or 13 mgd). Thus, this alternative would consume about 60 percent less surface water than that under current LSCS operations, which consumes approximately 49.7 cfs (1.4 m3/s or 32.1 mgd).
Based on this analysis, the overall impacts on surface water resources from construction and operations under the NGCC alternative would be SMALL.
4.5.5.2    Groundwater Resources The impact significance level on groundwater resources for the NGCC alternative are less than the new nuclear alternative described in Section 4.5.3.2. Approximately the same amount of groundwater would be consumed during the operation of the facility, but less groundwater would be consumed in the construction of the facility. Therefore, impacts of the NGCC alternative on groundwater resources would be SMALL.
4.5.6      Combination Alternative (NGCC, Wind, Solar) 4.5.6.1    Surface Water Resources For the NGCC component of this alternative, the impacts on surface water resources from facility construction and operations at either the LSCS site or another existing power plant site would be a fraction of those described in Section 4.5.5.1 because the NGCC plant would be scaled back to a single 360-megawatt (MW) unit. As a result, operational cooling water demands would be reduced by roughly 90 percent.
Impacts on surface water resources from constructing land-based wind turbines would primarily be limited to the relatively small amounts of water needed at each installation site for dust suppression and soil compaction during site clearing, turbine pad preparation, and concrete production. Construction of utility-scale solar PV farms would require relatively larger volumes of water per site due to the larger land area required per megawatt of replacement power produced. For both components under this alternative, the NRC assumes that required construction water would be procured from offsite sources and trucked to the point of use on an as-needed basis. Water could also be supplied via a local water utility. The likely use of ready-mix concrete would also reduce the need for onsite use of nearby water sources for construction.
Installation of land-based wind turbines and utility-scale solar PV farms would also require construction of access roads and possibly transmission lines (especially for sites that are not already proximal to transmission line corridors). Access road construction would also require some water for dust suppression and roadbed compaction and would have the potential to result in soil erosion and stormwater runoff from cleared areas. For such activities, construction water would likely be trucked to the point of use from offsite locations, along with road 4-29
 
Environmental Consequences and Mitigating Actions construction materials. In all cases, it is expected that construction activities would be conducted in accordance with State-issued NPDES or equivalent permits for stormwater discharges associated with construction activity, which would require the implementation of appropriate BMPs to prevent or mitigate water-quality impacts. In contrast to land-based wind turbine sites and utility-scale solar PV farms, installation of small solar PV units on rooftops and at already-developed sites within the electric service ROI (see Section 2.2.2) would have little or no impact on surface water resources.
To support the operation of wind turbine and PV installations, no direct use of surface water would be expected. Water would likely be obtained from groundwater or purchased from a water utility. Regardless, only very small amounts of water would be needed to periodically clean turbine blades and motors, and water could be trucked to the point of use as part of routine servicing. Water also would be required to clean panels at solar PV farms or those situated in rooftop arrays. Adherence to appropriate waste management and minimization plans, spill prevention practices, and pollution prevention plans during servicing of wind turbine and solar PV installations and operation of vehicles connected with site operations would minimize the risks to soils and surface water resources from spills of petroleum, oil, and lubricant products and stormwater runoff.
Given the information presented above, the impacts on surface water resources from construction and operations under the combination alternative would be SMALL.
4.5.6.2      Groundwater Resources Construction dewatering would be minimal because of the small footprint of foundation structures, pad sites, and piling emplacements. Little or no impacts on groundwater use or water quality would be expected from routine operations. Consequently, the impacts on groundwater use and quality under this combination alternative would be SMALL.
4.5.7    Purchased Power Alternative 4.5.7.1      Surface Water Resources The impacts of this alternative on surface water resources are likely to be bounded by the impact descriptions for the other alternatives, although new transmission lines may be required.
Specifically, new and continued operation of nuclear, coal-fired, and natural gas-fired plants and renewable energy projects would not be expected to result in incremental impacts on surface water use and quality that are greater than those described in Sections 4.5.3, 4.5.4, 4.5.5, and 4.5.6, as long as all energy-generating facilities operate within the bounds of applicable water use and NPDES permits. Therefore, the impact of this alternative on surface water resources would be expected to range from SMALL to MODERATE.
4.5.7.2      Groundwater Resources The impacts of the purchased power alternative on groundwater resources are likely to be bounded by the impact descriptions for the other alternatives. Purchased power is likely to come from existing facilities, or if new facilities are constructed, it would likely be from one of the previously discussed alternatives. These alternatives have SMALL impacts. Therefore, the impact of this alternative on groundwater resources would be SMALL.
4.6    Terrestrial Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on terrestrial resources.
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Environmental Consequences and Mitigating Actions 4.6.1        Proposed Action Section 3.6 describes terrestrial resources on and in the vicinity of the LSCS site. Table 4-6 identifies the generic (Category 1) and site-specific (Category 2) issues that apply to terrestrial resources during the proposed license renewal period.
Table 4-6. Terrestrial Resource Issues Issue                                                                                    GEIS Section        Category Effects on terrestrial resources (non-cooling system impacts)                                4.6.1.1              2 Exposure of terrestrial organisms to radionuclides                                          4.6.1.1              1 Cooling system impacts on terrestrial resources (plants with                                4.6.1.1              1 once-through cooling systems or cooling ponds)
Cooling tower impacts on vegetation (plants with cooling towers)                            4.6.1.1            N/A(a)
Bird collisions with plant structures and transmission lines(b)                              4.6.1.1              1 Water use conflicts with terrestrial resources (plants with cooling ponds                    4.6.1.1              2 or cooling towers using makeup water from a river)
Transmission line right-of-way (ROW) management impacts on                                  4.6.1.1              1 terrestrial resources(b)
Electromagnetic fields on flora and fauna (plants, agricultural crops,                      4.6.1.1              1 honeybees, wildlife, livestock)(b)
(a) This issue does not apply because LSCS does not have cooling towers.
(b) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid.
Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 4.6.1.1        Generic GEIS Issues For the generic (Category 1) terrestrial resource issues listed in Table 4-6, the NRC staff did not identify any new and significant information related to the generic (Category 1) issues listed above during the review of the applicants ER (Exelon 2014a), the site audit, or the scoping process. Therefore, the NRC staff expects no impacts associated with these issues beyond those discussed in the GEIS. The GEIS concludes that the impact level for each of these issues is SMALL.
4.6.1.2        Effects on Terrestrial Resources (Non-Cooling System Impacts)
In the GEIS (NRC 2013d), the NRC staff determined that noncooling system effects on terrestrial resources is a Category 2 issue (see Table 4-6) that requires site-specific evaluation during each license renewal review. According to the GEIS, non-cooling system impacts can include those impacts that result from landscape maintenance activities, stormwater management, elevated noise levels, and other ongoing operations and maintenance activities that would occur during the renewal period and that could affect terrestrial resources on and near a plant site.
Landscape Maintenance Activities Approximately 25 percent (379 ha (936 ac)) of the LSCS site remains as undeveloped, uncultivated natural areas (see Table 3-1, in Section 3.2.1 of this document). The majority of 4-31
 
Environmental Consequences and Mitigating Actions site landscape maintenance is performed within the protected area and not within natural areas on the site (Exelon 2015f). Typically, only grassy areas within the developed, industrial portion of the site are mown to keep vegetation short. Small trees or brush that might pose a safety concern may also be removed from these areas as needed. Leased agricultural land is maintained by the leasee and in accordance with the standing lease. Exelon (2014a) has no plans to disturb undeveloped areas of the site as part of the proposed license renewal.
Several ongoing restoration projects would result in positive impacts to terrestrial resources during the license renewal term. These projects are discussed in Section 3.6 and include ongoing management of a small area of native prairie, native vegetation plantings, removal of the invasive common reed (Phragmites australis) around the cooling pond, and various bird habitat enhancements.
Stormwater Management Natural drainage of the LSCS site is generally toward the cooling pond. Two stormwater ponds on the west side of the LSCS site receive stormwater runoff from the sites protected area, which is divided into two zones (I and II) for purposes of stormwater management. A system of surface ditches and underground piping drain the two zones. Zone I discharges to the north stormwater pond, and Zone II discharges to the south stormwater water pond. Each stormwater pond discharges to the cooling pond discharge canal via NPDES-permitted Outfalls G01 (north stormwater pond) and H01 (south stormwater pond). Some storm drains on the site are routed through oil separators before entering the stormwater ponds. Areas to the northwest and south of the protected area are drained away by existing creeks and gullies (Exelon 2014a).
Exelon maintains a stormwater pollution prevention (SWPP) plan in accordance with Special Condition 8 of the sites NPDES permit (Permit No. IL0048151; IEPA 2013). The SWPP plan identifies potential sources of pollutants that could affect stormwater discharges at Outfalls G01, H01, and 002 and practices that Exelon uses to reduce pollutants in stormwater discharges and ensure compliance with applicable conditions of the NPDES permit (Exelon 2014c). The NPDES permit also requires that the SWPP plan identify areas with a high potential for significant soil erosion due to topography, activities, or other factors, and that the SWPP plan contain measures to limit erosion in these areas (IEPA 2013). Exelon further monitors areas with potential for spills of oil or other regulated substances under the LSCS Spill Prevention Control and Countermeasure Plan (Exelon 2014c). Collectively, these measures ensure that the effects to terrestrial resources from pollutants carried by stormwater would be small during the proposed license renewal term.
Noise The GEIS (NRC 2013d) indicates that elevated noise levels could be a non-cooling system impact to terrestrial resources. However, the GEIS also concludes that generic noise impacts would be small because noise levels would remain well below regulatory guidelines for offsite receptors during continued operations and refurbishment associated with license renewal. The NRC staff did not identify any information during its review that would indicate that noise impacts to terrestrial resources at LSCS would be unique or require separate analysis.
Other Operations and Maintenance Activities Exelon (2014a) anticipates no refurbishment or other operations or maintenance activities during the license renewal term that would disturb terrestrial habitats or result in changes to existing land uses.
Exelon (2015e) states that it would continue to comply with all applicable environmental laws and regulations and would adhere to its company policy of regularly evaluating and 4-32
 
Environmental Consequences and Mitigating Actions implementing options that move beyond compliance. Such options may include maintaining Exelons Wildlife Management Plan and Wildlife Habitat Council certification for LSCS throughout the proposed license renewal term.
When new activities that could impact the environment occur at LSCS, Exelon states that it follows several procedures to ensure that potential environmental effects are considered and appropriately addressed. Exelon (2015g) maintains an Environmental Review procedure (EN-AA-103) that provides a process for screening proposed activities to determine if an activity requires further evaluation for environmental impacts and risks. Such activities include engineering configuration changes, maintenance activities, and operational changes. If further environmental evaluation is warranted, Exelons (2015g) Environmental Evaluations procedure (EN-AA-103-0001) provides guidance on identifying the environmental and regulatory impacts of an activity. If Exelon personnel determine that implementation of a proposed activity would result in an unacceptable environmental condition or risk, the proposed activity is not implemented until the environmental impact is appropriately addressed. These procedures would continue to be implemented during the proposed license renewal term and would ensure that environmental impacts to terrestrial resources would be addressed or mitigated prior to site operational or maintenance activities.
Conclusion Based on the NRC staffs independent review, the staff concludes that the landscape maintenance activities, stormwater management, elevated noise levels, and other ongoing operations and maintenance activities that Exelon might undertake during the renewal term would primarily be confined to disturbed areas of the LSCS site. These activities would not have noticeable effects on terrestrial resources, nor would they destabilize any important attribute of the terrestrial resources on or in the vicinity of the LSCS site. Therefore, the staff expects non-cooling system impacts on terrestrial resources during the license renewal term to be SMALL.
4.6.1.3      Water Use Conflicts with Terrestrial Resources In the GEIS (NRC 2013d), the NRC staff determined that effects of water use conflicts on terrestrial resources is a Category 2 issue (see Table 4-6) that requires site-specific evaluation during each license renewal review. Water use conflicts occur when the amount of water needed to support terrestrial riparian communities is diminished as a result of demand for agricultural, municipal, or industrial use; decreased water availability due to droughts; or a combination of these factors.
As indicated in Section 4.5.1.1, the amount of Illinois River water LSCS consumes is minor in comparison to the flow of water past the plant. In Section 4.5.1.1, the NRC staff found that water use conflicts with surface water resources would be SMALL during the proposed license renewal term because the surface flows in the Illinois River are able to meet the consumptive demand and because regulatory mechanisms are in place that limit LSCSs consumptive use.
These regulatory mechanisms ensure that LSCS does not consume an amount that would be harmful to riparian communities during low river flow conditions. The terrestrial resources near the plant (described in Section 3.6) do not appear to be affected by the consumption of water from the river. The NRC staff concludes that water use conflicts would not occur from the proposed license renewal or would be so minor that the effects on terrestrial resources would be undetectable. Thus, the NRC staff concludes that the impacts of water use conflicts on terrestrial resources during the proposed license renewal term would be SMALL.
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Environmental Consequences and Mitigating Actions 4.6.2      No-Action Alternative If LSCS were to shut down, the impacts to terrestrial ecology would remain similar to those during operations until the plant is fully decommissioned. Temporary buildings and staging or laydown areas may be required during large component and structure dismantling. LSCS is likely to have sufficient space within previously disturbed areas for these needs, and therefore, no additional land disturbances would occur on previously undisturbed land. Adjacent lands may experience temporary increases in erosional runoff, dust, or noise, but these impacts could be minimized with the implementation of standard BMPs (NRC 2002). In NUREG-0586, the NRC (2002) concludes generically that impacts to terrestrial ecology during decommissioning activities would be SMALL. The GEIS (NRC 2013d) notes that terrestrial resource impacts could occur in other areas beyond the immediate nuclear plant site as a result of the noaction alternative if new power plants are needed to replace lost capacity. The NRC staff concludes that the noaction alternative is unlikely to noticeably alter or have more than minor effects on terrestrial resources. Thus, the NRC staff concludes that the impacts of the no-action alternative on terrestrial resources during the proposed license renewal term would be SMALL.
4.6.3      New Nuclear Alternative The new nuclear alternative assumes that Exelon would build a new nuclear facility in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin at an existing power plant site. Construction of the facility would require an estimated 324 ac (131 ha) for permanent buildings and facilities and an additional 232 ac (94 ha) for temporary facilities, laydown areas, and other temporary land disturbances. Additional offsite land would be required for uranium mining, although this impact would result in no net change in land use impacts from those that would be associated with the proposed license renewal of LSCS.
During construction, terrestrial species could experience habitat loss or fragmentation, loss of food resources, and altered behavior due to noise and other construction-related disturbances.
Erosion and sedimentation from clearing, leveling, and excavating land could affect adjacent riparian and wetland habitats, if present. Implementation of appropriate BMPs would minimize these effects. This alternative could also require construction of new transmission lines or upgrades to existing lines. Because the new nuclear facility would be located on an existing energy-producing site, transmission lines could likely be collocated within existing transmission line corridors to minimize land disturbance. Although construction activities could noticeably alter terrestrial resources through habitat loss or fragmentation, construction is unlikely to destabilize any important attributes of the terrestrial environment. The exact magnitude of impacts would vary based on the chosen location of the facility and the amount and types of undisturbed habitat that would be affected by construction of the alternative, and thus, impacts of construction could range from SMALL to MODERATE.
During operation, impacts would be similar in type and magnitude to those assessed in Section 4.6.1 for continued operation of LSCS under the proposed renewal term and would, therefore, be SMALL.
The NRC staff concludes that the impacts of the new nuclear alternative on terrestrial resources would be SMALL to MODERATE during construction and SMALL during operation. The range in construction impacts is primarily the result of the uncertainty in the amount and types of undisturbed habitat that construction would affect.
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Environmental Consequences and Mitigating Actions 4.6.4      IGCC Alternative The IGCC alternative assumes that the new facility would be built at an existing power plant site in Illinois, including the LSCS site, or at another power plant site in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin. The facility would require 2,000 ac (800 ha) of land to construct the facility. If the facility were to be sited on the LSCS site, the area currently occupied by the LSCS facilities, the undeveloped areas immediately surrounding the facility, and the area occupied by the Illinois fish hatchery would be affected. Exelon would also need to acquire adjacent parcels of land to provide the full complement of acreage required for the IGCC facility. Additional offsite land would be required for coal mining, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS.
During construction, impacts to terrestrial habitats and species are likely to be similar to the types of impacts described for the new nuclear alternative in Section 4.6.3 but would likely be larger in magnitude due to the larger footprint of the IGCC facility. If the facility were to be sited on the LSCS site, the purchase of additional parcels of land could affect sensitive habitats, including wetlands and riparian areas. Accordingly, construction would likely noticeably alter terrestrial resources and could destabilize important attributes of the terrestrial environment.
The exact magnitude of impacts would vary, based on the chosen location of the facility and the amount and types of undisturbed habitat that would be disturbed for construction of the alternative. Thus, impacts of construction could range from MODERATE, if some disturbances to terrestrial habitats occur, to LARGE, if significant disturbances to terrestrial habitats occur, especially if disturbed habitats are wetlands or other sensitive habitat types.
The GEIS (NRC 2013d) concludes that impacts on terrestrial resources from the operation of fossil energy alternatives would essentially be similar to those from continued operations of a nuclear facility. Unique impacts would include periodic maintenance dredging if coal is delivered by barge, which could create noise, dust, and sedimentation. Dredging and delivery of coal to the site could introduce minerals and trace elements to water resources on which terrestrial biota rely. Elements from these minerals could also bioaccumulate in nearby riparian or wetland habitats. Air emissions during operation would include sulfur oxides and nitrogen oxides, which can combine with water vapor and create sulfuric and nitric acids. These acids would then be released back into the environment through precipitation, which could affect the acidity levels of water resources and have detrimental effects to plant foliage. Acid precipitation has the potential to destabilize the terrestrial environment by creating conditions that are too acidic for certain plants or animals and by mobilizing certain metals. The IGCC facility would also emit various GHGs during operation, which is an effect that can have far-reaching consequences because GHGs contribute to climate change. The effects of climate change on terrestrial resources are discussed in Section 4.13.3.2. The various air emissions during operation of the IGCC facility could create noticeable impacts on the terrestrial environment, and therefore, the operational impacts would be MODERATE.
The NRC staff concludes that the impacts of the IGCC alternative on terrestrial resources would be MODERATE to LARGE during construction and MODERATE during operation. The range in construction impacts is primarily the result of the uncertainty in the amount and types of undisturbed habitat that construction would affect.
4.6.5      NGCC Alternative The NGCC alternative assumes that a new NGCC facility would be built at the LSCS site. The facility would require 94 ac (38 ha) of land and would be sited on the undeveloped land immediately surrounding the LSCS. Some infrastructure upgrades could be required, as well as 4-35
 
Environmental Consequences and Mitigating Actions a new or upgraded pipeline, which would affect additional land. Additional offsite land would be required for gas extraction and collection, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS.
During construction, impacts to terrestrial habitats and species are likely to be similar to the types of impacts described for the new nuclear alternative in Section 4.6.3 but would likely be smaller in magnitude, due to the smaller footprint of the NGCC facility. Because the NGCC facility would be built outside of the existing industrial footprint of LSCS, construction would require the conversion of natural areas to industrial use, which would result in the direct destruction of some existing terrestrial habitats. Although construction would noticeably alter terrestrial resources, it would be unlikely to destabilize important attributes of the terrestrial environment due to the small footprint size and the pre-disturbed nature of much of the existing land on the LSCS site. Thus, impacts of construction would likely be MODERATE.
The GEIS (NRC 2013d) concludes that impacts to terrestrial resources from the operation of fossil energy alternatives would essentially be similar to those from continued operations of a nuclear facility. Unique impacts would include air emissions of GHGs such as nitrogen oxides, carbon dioxide, and methane, all of which can have far-reaching consequences because they contribute to climate change. The effects of climate change on terrestrial resources are discussed in Section 4.13.3.2. Although the impacts of operating the NGCC alternative may be noticeable, they are unlikely to destabilize any important attribute of the terrestrial environment and would, therefore, be SMALL.
The NRC staff concludes that the impacts of the NGCC alternative on terrestrial resources would be MODERATE during construction and SMALL during operation.
4.6.6    Combination Alternative (NGCC, Wind, Solar)
The NGCC component of the combination alternative would have the same land requirements as discussed for the NGCC alternative in Section 4.3.3.1. Accordingly, the impacts to terrestrial resources would be similar to those concluded for the NGCC alternative and, therefore, would be MODERATE during construction and SMALL during operation.
The wind component of this alternative would require an estimated 3,376 to 10,127 ac (1,366 to 4,098 ha) of land at onshore wind farm sites and agricultural cropland across the ROI.
Permanently disturbed land would hold the wind turbines, access roads, and transmission lines.
Land used for equipment laydown and turbine component assembly and erection could be returned to its original state. Use of BMPs would ensure that disturbed lands were appropriately restored to reduce long-term impacts to the terrestrial environment. Operation of wind turbines could uniquely affect terrestrial species through mechanical noise, collision with turbines and meteorological towers, and interference with migratory behavior. Bat and bird mortality from turbine collisions is an ongoing concern for operating wind farms; however, recent developments in turbine design have reduced the potential for bird and bat strikes. The NRC staff expects that this component has the potential to noticeably alter terrestrial resources, primarily through the loss of habitat and bird and bat mortalities associated with wind turbine operation. However, it is unlikely that the wind component would destabilize any important attribute of the terrestrial environment, and thus, impacts would be MODERATE.
The solar component of this alternative would require an estimated 6,749 ac (2,731 ha) of land across the ROI. The majority of solar installations could be installed on building roofs at existing residential, commercial, or industrial sites or at larger standalone solar facilities, and thus, it is possible that little terrestrial habitat would be disturbed during construction. However, the exact magnitude of impacts on terrestrial resources would depend on the amount of terrestrial habitat that is lost or fragmented during construction of solar installations. Operation would have no 4-36
 
Environmental Consequences and Mitigating Actions measurable effects on the terrestrial environment. Overall impacts from construction and operation of this component of the alternative would range from SMALL to MODERATE, depending on the locations of solar installations and the amount of terrestrial habitat affected.
Overall, the NRC staff concludes that the impacts of the combination alternative on terrestrial resources would be SMALL to MODERATE. This range is primarily the result of the variability in land required for the wind and solar components and the types of terrestrial habitats that would be disturbed by construction of these components.
4.6.7      Purchased Power Alternative The purchased power alternative would have wide-ranging impacts that are hard to specifically assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI. This alternative would likely have little to no construction impacts because it would include power from already existing power generating facilities. The construction of additional transmission lines would require implementation of BMPs to minimize erosion and sedimentation in nearby streams, ponds, or rivers. The types of operational impacts would be similar to the effects discussed in the preceding alternative sections. This alternative would be more likely to intensify already existing effects at power generating facilities than create wholly new effects on terrestrial species and habitats. Existing facilities would likely have BMPs and other procedures in place to ensure that effects to the environment during operations are minimized. The NRC staff concludes that the impacts on terrestrial resources from the purchased power alternative would be SMALL.
4.7      Aquatic Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on aquatic resources.
4.7.1      Proposed Action Section 3.1.3 describes the LSCS cooling and auxiliary water systems, and Section 3.7 describes the aquatic resources of interest. Table 4-7 identifies the generic (Category 1) and site-specific (Category 2) issues that apply to aquatic resources at LSCS during the proposed license renewal period.
Table 4-7. Aquatic Resource Issues Issue                                                                    GEIS Section    Category All plants Entrainment of phytoplankton and zooplankton                                4.6.1.2          1 Infrequently reported thermal impacts                                      4.6.1.2          1 Effects of cooling water discharge on dissolved oxygen, gas                4.6.1.2          1 supersaturation, and eutrophication Effects of non-radiological contaminants on aquatic organisms              4.6.1.2          1 Exposure of aquatic organisms to radionuclides                              4.6.1.2          1 Effects of dredging on aquatic organisms                                    4.6.1.2          1 Effects on aquatic resources (non-cooling system impacts)                  4.6.1.2          1 Impacts of transmission line right-of-way (ROW) management on              4.6.1.2          1 aquatic resources(a) 4-37
 
Environmental Consequences and Mitigating Actions Issue                                                                                    GEIS Section        Category Losses from predation, parasitism, and disease among organisms                              4.6.1.2              1 exposed to sublethal stresses Plants with once-through cooling systems or cooling ponds Impingement and entrainment of aquatic organisms                                            4.6.1.2              2 Thermal impacts on aquatic organisms                                                        4.6.1.2              2 Plants with cooling ponds or cooling towers using makeup water from a river Water use conflicts with aquatic resources                                                  4.6.1.2              2 (a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid.
Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 4.7.1.1        GEIS Category 1 Issues The GEIS concludes that the nine Category 1 issues listed in Table 4-7 would have a SMALL impact on aquatic resources during the license renewal term for all plants. For these issues, no additional plant-specific analysis is required unless new and significant information is identified.
During its review, the NRC staff considered Exelons ER, aquatic surveys and studies performed at LSCS and in the Illinois River, and available scientific literature; participated in a site audit; and considered Federal and State agency and public comments received during the scoping process. The NRC staff did not identify any new and significant information related to any of the Category 1 issues. Therefore, no site-specific analysis is required for these issues, and there would be no impacts associated with these issues beyond those discussed in the GEIS.
4.7.1.2        Impingement and Entrainment of Aquatic Organisms In the GEIS (NRC 2013d), the NRC determined that impingement and entrainment of aquatic organisms is a Category 2 issue (see Table 4-7) that requires site-specific evaluation during each license renewal review for plants with once-through cooling systems or cooling ponds, such as LSCS.
Impingement is the entrapment of all life stages of fish and shellfish on the outer part of an intake structure or against a screening device during periods of water withdrawal (40 CFR 125.83). Impingement can kill organisms immediately or contribute to a slower death resulting from exhaustion, suffocation, injury, and other physical stresses. The potential for injury or death is generally related to the amount of time an organism is impinged, its susceptibility to injury, and the physical characteristics of the screen washing system and fish return (if present) of the plant.
Entrainment is the incorporation of all life stages of fish and shellfish with intake water flow entering and passing through a cooling-water intake structure and into a circulating water system (CWS) (40 CFR 125.83). Organisms susceptible to entrainment are generally of smaller size than those susceptible to impingement and include ichthyoplankton (fish eggs and larvae),
larval stages of shellfish and other macroinvertebrates, zooplankton, and phytoplankton.
Entrained organisms may experience physical trauma and stress, pressure changes, excess heat, and exposure to chemicals, all of which may result in injury or death (Mayhew et al. 2000).
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Environmental Consequences and Mitigating Actions A particular species can be subject to both impingement and entrainment if some individual fish are impinged on screens while others pass through the screens and are entrained. For instance, adults could be impinged while juveniles could be entrained, if they are small enough to pass through the intake screen openings.
At LSCS, aquatic organisms may be impinged or entrained at two locations. Organisms that inhabit the Illinois River may be impinged or entrained when makeup water is drawn from the river, through the river screen house, and into the cooling pond. Organisms that inhabit the cooling pond may be impinged or entrained when water is drawn from the pond, through the cooling pond screen house, and into the CWS. Organisms that are entrained by passing through the cooling ponds screen house and into the LSCS CWS are subject to mechanical, thermal, and toxic stresses that make survival unlikely.
This sections analysis uses a retrospective assessment of the present and past impacts to the aquatic ecosystem resulting from LSCS operation in order to provide a prospective assessment for the future impacts over the proposed license renewal term (i.e., through 2042 for Unit 1 and through 2043 for Unit 2). The timeframe and geographic extent are two components of the assessment that bound the analysis. The timeframe defines how far back and how far forward the analysis will extend. In assessing the level of impact, the staff looked at the projected effects in comparison to a baseline condition. In agreement with National Environmental Policy Act (NEPA) guidance (CEQ 1997), the baseline of the assessment is the condition of the resource without the action (i.e., under the no-action alternative). Under the no-action alternative, the plant would shut down, and the resource would conceptually return to its condition without the plant, which is not necessarily the same as the condition before the plant was constructed. The timeframe for analyzing ecological resources extends far enough into the past to understand trends and to determine whether the resource is stable, which the NRC definitions of impact levels require. For assessing direct and indirect impacts, the geographic boundaries depend on the biology of the species under consideration.
The NRC staff used a modified weight-of-evidence (WOE) approach to evaluate the effects of impingement and entrainment on the aquatic resources in the Illinois River and LSCS cooling pond. The NRC chose this approach because EPA recommends a WOE approach for ecological risk assessment (EPA 1998). The WOE approach is a useful tool due to the complex nature of assessing risk (or impact), and the NRC has used this approach in other evaluations of the effects of nuclear power plant cooling systems on aquatic communities (e.g., NRC 2010, 2013b, 2015a, 2015b). Menzie et al. (1996) defines WOE as the process by which multiple measurement endpoints are related to an assessment endpoint to evaluate whether significant risk of harm is posed to the environment. In the present WOE approach, the NRC staff examined five lines of evidence (LOE) to determine if operation of LSCS is contributing to adverse impacts on aquatic resources in the Illinois River or LSCS cooling pond.
The lines of evidence are as follows:
LOE      Description 1      Results of impingement studies performed at LSCS 2      Results of entrainment studies performed at LSCS 3      Temporal trends in fish populations in the Illinois River 4      Spatial differences in fish populations in the Illinois River 5      Consideration of engineered designs and operational controls that affect impingement and entrainment rates 4-39
 
Environmental Consequences and Mitigating Actions LOE 1: Impingement Studies Exelon contracted EA Engineering, Science, and Technology, Inc. (EA) to conduct a study to determine the impingement rates among the fish and shellfish in the Illinois River. From April 2014 through March 2015, EA (2015) collected 20 samples of all fish and shellfish impinged at the river screen house within set 24-hour collection periods. EA identified all impinged fish and shellfish to species, or the lowest taxonomic level possible. EA (2015) extrapolated annual impingement rates for each species by multiplying the number of fish collected during a 24-hour collection period by the volume of water that would be withdrawn during 1 year and dividing it by the volume of water withdrawn during the 24-hour collection period.
EA (2015) collected a total of 635 fish representing 41 species, 9 crayfish representing 2 taxa, and 9 mussels representing 3 species. The most commonly impinged fish include gizzard shad (Dorosoma cepedianum; 29 percent of all samples), round goby (Neogobius melanostomus; 11 percent), threadfin shad (Dorosoma petenense; 9 percent), bluegill (Lepomis macrochirus; 6 percent), freshwater drum (Aplodinotus grunniens; 6 percent), and bluntnose minnow (Pimephales notatus; 5 percent). Gizzard shad was the most commonly impinged species and the most commonly collected species during electrofishing surveys in 2013 (EA 2014 and 2015). In addition, EA (2014) collected gizzard shad more often downstream of the intake as compared to upstream, which would suggest that impingement is not noticeably altering populations of gizzard shad near LSCS.
Bluegill, bluntnose minnow, and freshwater drum each comprised 5 to 6 percent of the impinged fish and each comprised 2 to 3 percent of the electrofishing or seining samples in 2013 (EA 2014, 2015). These results suggest that the impingement rate is similar to the occurrence rate in monitoring surveys in the river near LSCS. In addition, EA (2014) reported similar numbers of these three fish species directly upstream and downstream of the river intake, which would suggest that impingement is not noticeably altering populations of bluegill, bluntnose minnow, and freshwater drum near LSCS. The NRC staff notes that EA (2014) may not conclusively determine whether impingement affects populations of fish near LSCS due to the limited sample size and because some fish may migrate sufficient distances such that a noticeable difference would not likely be identified between samples collected immediately upstream and downstream of the intake.
Both round goby and threadfin shad are invasive species. All other impinged species comprised less than 5 percent of the impinged fish (EA 2015).
The nine impinged crayfish included eight Orconectes species, seven of which were northern Clearwater crayfish (Orconectes propinquus) and one Procamarus sp. (EA 2015). The nine impinged mussels included two fragile papershell (Leptodea fragilis), one pink heelsplitter (Potamilus alatus), and six paper pondshell (Utterbackia imbecillis).
EA (2015) estimated the annual impingement to be 10,673 organisms per year. The estimated annual impingement rates at LSCS are approximately 1 to 6 percent of the impingement rate at Dresden Nuclear Station, which is located at the confluence of the Kankakee and Illinois Rivers (EA 2015; Exelon 2015b). Dresden Nuclear Station operates in either an indirect-open cycle or operates its cooling pond in a closed-cycle mode, similar to LSCS. NRC (2004) determined that the impacts from impingement would be SMALL on aquatic resources at Dresden Nuclear Station.
LOE 1 Conclusion Based on the available impingement studies, intake of makeup water from the Illinois River appears to have a minor effect on the aquatic community in the vicinity of LSCS, and the NRC 4-40
 
Environmental Consequences and Mitigating Actions staff finds that impingement is not likely to noticeably alter or destabilize any important attributes of the community.
Although fish and aquatic biota are also impinged at the lake screen house when cooling pond water is drawn into LSCSs cooling system, the impacts of impingement on the aquatic community within the cooling pond are unknown because they have not been addressed in studies.
LOE 2: Entrainment Studies Exelon contracted EA to conduct a study to determine the entrainment rates among the fish and shellfish taxa in the Illinois River. As part of this study, EA (2015) collected icthyoplankton samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected samples using 0.5-m (1.6-ft) conical plankton nets with 505 micron mesh suspended from the forebay bridge in front of the river intake (see Figure 3.7-1). EA (2015) collected samples during the 2014 spawning season, from late April 2014 through August 2014, when icthyoplankton densities would likely be highest. EA (2015) extrapolated annual entrainment rates for each taxa based on the number of taxa collected during a 24-hour collection period, the volume of water that would be withdrawn during 1 year, and the volume of water withdrawn during the 24-hour collection period.
EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 27 distinct taxa. The most common taxa included carps, minnows, and suckers, which combined comprised 79 percent of the ichthyoplankton sample. EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles. The most common taxa by life stage included lctiobinae yolk-sac larvae (24 percent), cyprinidae yolk-sac larvae (23 percent), and common carp yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent of the icthyoplankton samples (EA 2015).
EA (2015) estimated the annual entrainment rate to be about 38 million organisms per year.
The estimated annual entrainment rates at LSCS are approximately 28 to 38 percent of the entrainment rate at Dresden Nuclear Station, which is located at the confluence of the Kankakee and Illinois Rivers (EA 2015; Exelon 2015b). Dresden Nuclear Station operates in either an indirect-open cycle or operates its cooling pond in a closed-cycle mode, similar to LSCS. NRC (2004) determined that the impacts from entrainment would be SMALL on aquatic resources at Dresden Nuclear Station.
LOE 2 Conclusion Based on the available entrainment studies, intake of makeup water from the Illinois River appears to have a minor effect on the aquatic community in the vicinity of LSCS, and the NRC staff finds that entrainment is not likely to noticeably alter or destabilize any important attributes of the community.
Although fish and aquatic biota are also entrained at the lake screen house when cooling pond water is drawn into LSCSs cooling system, the impacts of entrainment on the aquatic community within the cooling pond are unknown because they have not been addressed in studies.
LOE 3: Temporal Trends in Fish Populations in the Illinois River Impingement and entrainment from the withdrawal of makeup water from the Illinois River have removed individuals from the river ecosystem since LSCS began operating in 1982. Over this period of time, the aquatic community has changed in a number of ways, including species richness (the number of species present), species composition (the kinds of species present),
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Environmental Consequences and Mitigating Actions and species evenness (the relative abundance of species). This LOE compares fish populations prior to and during operations to determine whether changes have occurred and if such changes can be attributed to LSCS operations. If impingement and entrainment were to affect fish within the vicinity of LSCS, fish abundances and species richness would likely be lower post-operation as compared to before operations.
In the section below, the NRC staff made general characterizations of fish populations during preoperational and operational surveys. However, differences between time periods could occur for multiple reasons, including variations in sampling equipment, the frequency and timing of sampling events, and sampling locations. Furthermore, the lack of repeated samples over time prevented the NRC staff from conducting statistical analyses on the changes in fish populations over time. Therefore, the trends presented below for LSCS studies describe general patterns in fish populations that have not been tested for statistical significance.
As discussed in Section 3.7, fish populations near LSCS have changed over time. The main trends have been an increase in species richness and increases in the abundance of species that are sensitive to poor water quality. For example, two commonly collected species during preoperational surveys, common carp (Cyprinus carpio) and white sucker (Catostomus commersonii), were not commonly collected during the 1999 or 2013 study (NRC 1978; EA 2000, 2014). OEPA (1987) classifies both of these species as pollution tolerant. On the other hand, brook silverside (Labidesthes sicculus), sand shiner (Notropis stramineus),
smallmouth bass (Micropterus dolomieu), smallmouth buffalo (Ictiobus bubalus), golden redhorse (Moxostoma erythrurum), and blue gill (Lepomis macrochirus) were among the six most commonly collected species in the 1999 or 2013 study but were not commonly collected in the preoperational studies (NRC 1978; EA 2000, 2014). Five of these seven species are native species that are sensitive to declines in water quality or habitat degradation (Smith 2002; Lerczak 1996). These results suggest that the quality of aquatic habitat within the Illinois River near LSCS has improved since the 1970s. Similar trends of improved water quality, increased species richness, and increases in the relative abundance of pollution-sensitive species have been documented in several studies on the Illinois River (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012; Fritts 2013). These results suggest that the major changes in fish populations near LSCS are the result of improved water quality, likely from the protections provided in the Clean Water Act (CWA), advances in municipal and industrial waste treatment, agricultural conservation measures, and other factors.
Conclusion Given that species richness and populations of pollution-sensitive fish have increased since LSCS began operations, and populations of pollution-tolerant fish have decreased, the NRC staff concludes that impingement and entrainment are not having a noticeable impact on temporal changes in fish population in the Illinois River near LSCS. Other factors, such as improved habitat diversity and quality, are having a more noticeable impact on the temporal patterns in fish populations (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012).
LOE 4: Spatial Differences in Fish Populations in the Illinois River This LOE compares fish populations upstream and downstream of the river intake structure to determine whether spatial changes have occurred since LSCS began operating and if such changes can be attributed to LSCS operations. If impingement and entrainment were to affect fish populations within the vicinity of LSCS, fish abundances and species richness would likely be lower downstream of the river intake structure as compared to upstream of the river intake structure, due to the removal of fish, eggs, and larvae from impingement and entrainment. The NRC staff notes that this LOE may not conclusively determine whether LSCS operation affects populations of fish near LSCS due to the limited sample size and because some fish may 4-42
 
Environmental Consequences and Mitigating Actions migrate sufficient distances such that a noticeable difference would not likely be identified between samples collected immediately upstream and downstream of the intake.
In the section below, the NRC staff made general characterizations of the fish populations upstream and downstream of the river intake. Neither EA (2014) nor the NRC staff conducted statistical analyses on the differences in fish populations among the sample sites. Therefore, the trends presented below for LSCS studies describe general patterns in fish populations that have not been tested for statistical significance.
In 2013, EA (2014) conducted fish surveys and compared fish abundances and species richness between upstream and downstream of the river intake. During electrofishing surveys, EA (2014) collected more fish downstream of the intake (43 fish) as compared to upstream (36 fish). However, species richness was moderately higher upstream of the intake (13 species) compared to downstream of the intake (9 species). For seining samples, EA (2014) collected more fish and species of fish upstream (location 1; 245 fish; 6 species) as compared to the closest downstream location (location 2; 65 fish; 3 fish species). EA (2014) attributed the higher fish abundances and species richness upstream of the river intake to better habitat quality, particularly regarding instream cover for sunfish. The NRC staff is not aware of any studies to determine whether the heated effluent has affected the density of aquatic plants that may provide cover for fish. Rocks and tree limbs could also provide cover for fish.
EA (2014) collected the most amount of fish and species of fish at the furthest downstream sampling site near South Kickapoo Creek (location 5; 906 fish; 12 species). During seining surveys, EA (2014) collected four species exclusively at the furthest downstream sampling site (location 5). EA (2014) attributed the high fish abundance and diversity at the furthest downstream location to its proximity to South Kickapoo Creek, as well as the habitat diversity at the site and the suitability of that location to seining.
Conclusion Given that no clear pattern exists regarding the species richness and species abundances upstream and downstream of the river intake structure, the NRC staff concludes that impingement and entrainment are not having a noticeable impact on spatial patterns in fish population in the Illinois River near LSCS. Other factors, such as habitat diversity and quality, are likely having a more noticeable impact on temporal fish population trends near LSCS (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012).
LOE 5: Engineered Design and Operational Controls In August 2014, EPA published a final rule establishing requirements under section 316(b) of the CWA for cooling-water intake structures at existing facilities (79 FR 48300). The final rule indicates that two basic approaches can reduce impingement and entrainment mortality:
(1) flow reduction and (2) including technologies into the cooling-water intake design that gently exclude organisms or collect and return organisms without harm to the water body. The EPA also notes that two additional approaches can reduce impingement and entrainment but that these technologies may not be available to all facilities. The two additional approaches are:
relocating the facilitys intake to a less biologically rich area in a water body and reducing the intake velocity. The LSCS CWS on the Illinois River incorporates several of these approaches.
Flow Reduction Reducing the amount of water that is withdrawn for cooling purposes from a water body reduces the number of aquatic organisms that are drawn through the intake structure and subject to impingement or entrainment. Because LSCS uses a cooling-pond-based heat-dissipation system, the majority of cooling water needed for plant operation is drawn from the cooling pond 4-43
 
Environmental Consequences and Mitigating Actions rather than the Illinois River. The cooling pond system is similar to a closed-cycle cooling system in that water in the pond continues to be recirculated through the plant for cooling, and only makeup water (water lost to evaporation or discharged as blowdown) is drawn directly from the Illinois River. Depending on the quality of the makeup water, closed-cycle cooling systems can consume significantly less water than if the same facility were to use a once-through cooling system. Exelon (2014a) determined that the maximum withdrawal rate, with all three makeup pumps operating at capacity, would withdraw approximately 1.8 percent of the rivers 92-year annual average mean flow. Similarly, NRC (1978) estimated that the annual average amount of water withdrawn from the Illinois River for cooling pond makeup would be about 1 percent of the typical flow, or 3 percent of the 7Q10 (e.g., the 7-day, 10-year low flow) flow.
Technologies That Exclude or Collect and Return Organisms The LSCS cooling system has several technologies that help exclude organisms from becoming impinged or entrained. Water enters the river screen house through an intake bay equipped with bar grills and 3/8-in. (9.5-mm) mesh travelling screens to prevent debris and aquatic biota from entering the system (Exelon 2014a). The EPA indicates that, ideally, traveling screens would be used with a fish handling and return system (79 FR 48300). LSCSs river screen house does not contain a fish return system (Exelon 2014a). However, the intake velocity (discussed below) should allow some fish to swim away and escape impingement.
Intake Flow Water velocity associated with the intake structure greatly influences the rate of impingement and entrainment. The higher the approach velocity, through-screen velocity, or both, the greater the number of organisms that will be impinged or entrained. At an approach velocity of 0.5 ft/s (0.15 m/s) or less, most fish can swim away and escape from the intake current (79 FR 48300). As indicated in Section 3.1.3, water velocity within the intake channel ranges from 0.3 to 0.5 ft/s (0.1 to 0.2 m/s) with one pump operating to 0.6 to 1.0 ft/s (0.2 to 0.3 m/s) with two pumps operating (EA 2015). The velocity at the face of the travelling screens is 0.5 ft/s (0.2 m/s) during one-pump full-flow operation and 0.9 ft/s (0.3 m/s) during two-pump full-flow operation (EA 2015). Thus, when one pump is operating, the river screen house intake velocities are within the 0.5-fps (0.15-m/s) intake velocity recommended by EPA for protection of aquatic organisms. However, the through-screen velocity when two or three pumps are operating could contribute to impingement and entrainment effects.
Best Technology Available On July 5, 2013, the Illinois EPA (IEPA) renewed LSCSs NPDES permit (No. IL0048151).
Special Condition 15 relates to potential impacts from cooling water intake and whether LSCS utilizes the Best Technology Available (BTA) for cooling-water intake structures to prevent or minimize impingement mortality in accordance with the Best Professional Judgment (BPJ) provisions of 40 CFR 125.3. In the permit, IEPA determined that:
The facility utilizes a closed-cycle recirculating cooling system, a 2058 acre cooling pond, for cooling of plant condensers and is determined to be the equivalent of BTA for cooling water intake structures to prevent/minimize impingement mortality in accordance with the BPJ provisions of 40 CFR 125.3 because it allows the facility to only withdraw the amount of water necessary to maintain the cooling pond level rather than the entire volume used for cooling of the plant condensers.
Conclusion While flow control measures, traveling screens, and low intake velocities reduce the effects of impingement and entrainment mortality at LSCS, the lack of a fish return system and the 4-44
 
Environmental Consequences and Mitigating Actions through-screen velocity when two or three pumps are operating could contribute to impingement and entrainment effects. This LOE does not conclusively indicate whether impingement or entrainment at LSCS is creating detectable effects on the Illinois River aquatic community.
Thus, this LOE, considered alone, is inconclusive.
Overall Impingement and Entrainment Conclusion The NRC staff reviewed available impingement and entrainment studies, assessed spatial and temporal changes in fish populations near LSCS in the Illinois River, and considered engineered designs and operational controls that affect impingement and entrainment rates. The NRC staff concludes that the impacts to aquatic resources in the Illinois River from impingement and entrainment would be SMALL and would not likely noticeably alter aquatic resources in the vicinity of LSCS based on the following:
* relatively low impingement and entrainment rates,
* increases in species richness and relative abundance of pollution-sensitive species since LSCS began operations,
* reduced flow due to operation as a closed-cycle system with the use of the LSCS cooling pond,
* bar grills and traveling screens with 3/8 in. (0.95-cm) openings to exclude fish, and
* IEPAs determination of BTA for use of a closed-cycle recirculating cooling system.
Although fish and aquatic biota are also impinged and entrained at the cooling pond screen house when cooling pond water is drawn into LSCSs cooling system, the impacts of impingement on the aquatic community within the cooling pond are unknown because Exelon has not conducted any impingement or entrainment studies at the cooling pond intake, nor have any consistent fish monitoring studies been implemented in the cooling pond. The NRC staff notes that the use of bar grills and traveling screens with 3/8-in. (0.95-cm) openings would reduce the impacts from impingement and entrainment in the cooling pond.
4.7.1.3      Thermal Impacts on Aquatic Organisms In the GEIS (NRC 2013d), the NRC determined that thermal impacts on aquatic organisms is a Category 2 issue (see Table 4-7) that requires site-specific evaluation during each license renewal review for plants with once-through cooling systems or cooling ponds, such as LSCS.
The NRCs regulations at 10 CFR Part 51 concerning license renewal reviews and the GEIS direct the NRC to consider all aquatic resources that may be affected by plant operations, regardless of the type of water body in which such resources reside. For instance, Section 4.2.2 of the 1996 GEIS specifically notes that aquatic biota of cooling ponds may be affected by thermal discharges and that these effects should be considered the same as those considered for once-through cooling systems, except that such effects mainly influence aquatic communities that did not exist before the creation of the cooling pond. The 2013 GEIS did not identify new information that would alter this methodology or alter any conclusions regarding impacts to aquatic populations in cooling ponds. Consideration of the impact on aquatic resources in cooling ponds is consistent with previous NRC license renewal reviews (e.g., NRC 2008b, 2013c, 2015b).
The NRC staff used a modified WOE approach to evaluate thermal impacts on the aquatic resources in the Illinois River and LSCS cooling pond. The NRC staff examined the five LOEs as follows.
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Environmental Consequences and Mitigating Actions LOE      Description 1      Results of past NRC reviews on thermal impacts of LSCS operations 2      A review of regulatory and administrative controls on thermal effluents 3      Population trends of indicator species 4      Health of fish populations as an indicator of water quality 5      Fish kills LOE 1: Past NRC Reviews The NRC (1978) previously assessed the potential thermal impacts of LSCS operations in the Final Environmental Impact Statement for LSCS Operations. The NRC (1978) estimated the size of the thermal plume under two scenarios, one in March and one in July, using relatively conservative assumptions (e.g., the 7Q10 low-flow estimate, maximum blowdown rate, 100 percent load factor). For the March scenario, the NRC (1978) determined that the 5 &deg;F (3 &deg;C) isotherm would range from 2,500 m2 (27,000 ft2) in March to 400 m2 (4,300 ft2) in July.
The thermal plume would cover approximately 9 percent of the river in March and 8 percent in July (NRC 1978). The zone of passage for fish would be 91 to 92 percent, which would be greater than the minimum 75 percent required by Illinois water quality standards. Thus, the NRC (1978) concluded that juvenile and adult fish would either be able to avoid the thermal plume, or a small number of organisms may be exposed to the thermal plume for a short period of time. The NRC staff concluded that the discharge impacts would likely be minimal and of little influence on the natural biotic populations in the Illinois River.
LOE 1 Conclusion The NRCs past review of the thermal impacts from LSCS discharges to the Illinois River indicated that the thermal impacts on the aquatic community would be minor.
LOE 2: Regulatory and Administrative Controls The Illinois Administrative Code (IAC) and the LSCS NPDES permit (IEPA 2013) impose regulatory controls on LSCSs thermal effluent that ensure that impacts on the aquatic environment are reduced or mitigated.
Title 35, Environmental Protection, Section 302, Water Quality Standards, of the IAC contains stipulations pertaining to effluent temperature as well as mixing zones and zones of initial dilution. The following limitations and requirements included in Section 302 pertain to effluent temperature and serve to protect aquatic biota from the effects of such effluents.
The maximum temperature rise shall not exceed 2.8 &deg;C (5 &deg;F) above natural receiving water body temperatures. [35 IAC 302.211(d)]
Water temperature at representative locations in the main river shall at no time exceed 33.7 &deg;C (93 &deg;F) from April through November and 17.7 &deg;C (63 &deg;F) in other months. [35 IAC 302.211(e)]
Several IAC stipulations pertaining to mixing zones also protect aquatic biota from thermal effluents.
Mixing is not allowed in waters which include a tributary stream entrance.
[35 IAC 302.102(b)(2)]
Mixing is not allowed in waters containing mussel beds, endangered species habitat, fish spawning areas, areas of important aquatic life habitat, or any other natural features vital to the well-being of aquatic life. [35 IAC 302.102(b)(4)]
Mixing must allow for a zone of passage for aquatic life. [35 IAC 302.102(b)(6)]
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Environmental Consequences and Mitigating Actions The area and volume of mixing must not contain more than 25 percent of the cross-sectional area or volume of a stream and must not intersect any body of water in such a manner that the maintenance of aquatic life in the body of water as a whole would be adversely affected. [35 IAC 302.102(b)(7) and (8)]
The area and volume in which mixing occurs must be as small as is practicable, and in no circumstances larger than 26 ac (11 ha). [35 IAC 302.102(b)(12)]
The LSCS NPDES permit (IEPA 2013) also contains requirements related to thermal effluents.
Special Condition 3 of the permit, which limits the maximum temperature rise above ambient conditions and maximum water temperatures during various times of the year, mirrors the temperature requirements at 35 IAC 302.211 listed above.
The NRC staff reviewed the results of recorded maximum cooling pond blowdown temperatures to the Illinois River and associated calculations of river mixing zone temperatures as reported in the discharge monitoring reports (DMR) for the past 5 years (2010 through 2014) and as compiled by Exelon (Exelon 2015b). Based on the NRCs staff review and Exelons responses to the NRCs RAIs, LSCS has received no notices of violation associated with NPDES permitted discharges during the 2010 through 2014 time period (see Section 3.5.1). Nonetheless, Exelon requested three variances with respect to LSCSs effluent discharges to the Illinois River and associated river mixing zone temperature limits. Specifically, these variances (IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in March, July, and August 2012, respectively, due to unusual weather conditions and associated high ambient river water temperatures that impacted the ability for LSCS thermal discharges to meet the requirements of Special Condition 3 of LSCSs NPDES permit. This limits the number of temperature excursion hours to 1 percent (87.[[estimated NRC review hours::6 hours]]) of the hours in a 12-month period, ending with any month (see footnote d in Table 3-7 of this document). During the variance period(s), Exelon was required, in part, to continuously monitor both the discharge and receiving water temperatures and visually inspect all discharge areas at least three times each day to assess the impact on aquatic life. These thermal discharge excursions were not found to have any impact on aquatic life (Exelon 2015b).
Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan and associated procedures to mitigate the impacts of summer drought and/or high river temperature and river low-flow conditions. Depending on predefined conditions set forth in the plan and implementing procedures, such actions may include a combination of monitoring and modeling of river intake and mixing zone temperatures; manipulation of the water level of the cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the technical specification limits on the condenser inlet temperature from the cooling pond (Exelon 2014a; 2015a).
LOE 2 Conclusion The LSCS thermal effluent is limited by the IAC and the LSCS NPDES permit to ensure that it does not create adverse effects on the aquatic communities in the Illinois River. In the past 5 years, Exelon received no notices of violations and IEPA granted three provisional variances to allow higher-than-permitted temperatures. Exelon reported no fish kills or other events to the IEPA or the NRC that would indicate adverse environmental effects resulting from the provisional variances. The NRC depends on the State to enforce the regulatory controls in place at LSCS and effectively ensure that any environmental effects to Illinois River aquatic 4-47
 
Environmental Consequences and Mitigating Actions communities are not detectable or are so minor as to neither destabilize nor noticeably alter the community.
LOE 3: Spatial and Temporal Trends for Indicator Species Heat shock has the potential to kill or injure individual fish and other organisms in the Illinois River ecosystem. This LOE compares the population trends of indicator species prior to and during operations and upstream and downstream of the discharge structure to determine whether changes have occurred and if such changes can be attributed to LSCS operations. If heat shock were to affect aquatic resources within the vicinity of LSCS, the NRC staff would expect the following:
* Fish and macroinvertebrate abundances and species richness would likely be lower after operations began as compared to prior to operations, and lower downstream as compared to upstream of the discharge, and
* Populations of pollution-sensitive fish and macroinvertebrates would likely be lower after operations began as compared to prior to operations, and lower downstream of the discharge as compared to upstream of the discharge.
As described in LOE 3 and 4 in Section 4.7.1.2, the NRC staff reviewed fish population trends in the Illinois River near LSCS from the 1970s through 2013 (NRC 1978; EA 2000, 2014). The NRC staff determined that species richness and populations of pollution-sensitive fish have increased since LSCS began operations, and populations of pollution-tolerant fish have decreased. In addition, the NRC staff did not identify any clear patterns regarding the species richness and species abundances upstream and downstream of the river intake and discharge structures. Therefore, the thermal effluent is not likely having a noticeable impact on the temporal patterns of fish populations in the Illinois River near LSCS. Other factors, such as habitat diversity and improved water quality, are likely having a more noticeable impact on the spatial patterns in fish populations.
As described in Section 3.7.1.1.2, EA (2000, 2014) compared the macroinvertebrate communities upstream and downstream of the LSCS discharge. During 1999 surveys, EA (2000) determined that the dominate macroinvertebrate taxa at sites both upstream and downstream of the discharge structure were tolerant to poor water quality. EA (2000) also determined that both total species richness and the number of Ephemeroptera, Plecoptera, and Trichoptera (EPT) species, which are considered intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) compared to upstream (location 1) of the discharge structure.
During 2013 surveys, EA (2014) observed dominant taxa that were relatively tolerant to poor water quality as well as dominant taxa that were relatively intolerant or facultative to poor water quality, both upstream and downstream of the discharge. Similarly, species richness among pollution-sensitive EPT was similar among all locations, ranging from three to five taxa (EA 2014). Given that the NRC staff did not identify any clear patterns regarding the species richness and species abundances upstream and downstream of the river discharge structures, the thermal effluent is not likely having a noticeable impact on fish populations near LSCS.
Other factors, such as habitat diversity and quality, are having a more noticeable impact on the spatial patterns in fish populations.
LOE 3 Conclusion Given that species richness and populations of pollution-sensitive fish have increased since LSCS began operations and no clear pattern exists regarding the species richness and species abundances upstream and downstream of the discharge, the NRC staff concludes that heat 4-48
 
Environmental Consequences and Mitigating Actions shock is not having a noticeable impact on aquatic resources in the Illinois River near LSCS.
Other factors, such as habitat diversity and quality, are likely having a more noticeable impact on the temporal and spatial patterns in fish populations.
LOE 4: Health of Fish Populations as an Indicator of Water Quality Fish parasites and anomalies generally occur most often in fish that inhabit waterbodies with poor water quality (OEPA 1989). Therefore, if the LSCS thermal effluent were to result in heat stress for fish near LSCS, one would expect an increase in the occurrence of parasites and anomalies since operations began.
During preoperational studies, the NRC (1978) noted a high level of external parasitism, disease, and physical abnormalities associated with fish near LSCS. The NRC (1978) did not provide any quantitative estimates of the amount of fish that had external parasitism, diseases, or physical abnormalities.
In 1999, EA (2000) observed a total of 63 fish (6.6 percent of the catch) with DELT (deformities, erosions, lesions, or tumors) anomalies. Channel catfish (Ictalurus punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin erosion (52 percent) and deformities (38 percent).
In 2013, EA (2014) observed a 0.2-percent DELT rate of all the 1,295 fish collected during electrofishing and seining studies in the Illinois River. Both fish were freshwater drum that exhibited eroded fins. One fish was collected upstream of the discharge structure (location 1) and the other fish was collected downstream of the discharge structure (location 2). EA (2014) did not observe any fish with parasites.
These results suggest that the quality of aquatic habitat within the Illinois River near LSCS has improved since the 1970s. Similar trends of improved water quality and decreased rates of fish parasites and DELT anomalies have been documented in other studies on the Illinois River. For example, McClelland and Pegg (2005) reviewed trends in fish parasites and anomalies from Illinois Natural History Survey (INHS) data and found a decrease in anomalies over time, with no anomalies in 2004. These results suggest that the major changes in fish parasites and physical anomalies on fish near LSCS are the result of improved water quality, likely from the protections provided in the CWA, advances in municipal and industrial waste treatment, implementation of agricultural conservation measures, and other factors.
LOE 4 Conclusion Given the decreasing rate of fish parasites and DELT anomalies observed on fish in the Illinois River near LSCS, the NRC staff concludes that heat shock from LSCSs thermal effluent is not having a noticeable impact on fish health in the Illinois River near LSCS. Other factors, such as water quality, are likely having a more noticeable impact on the rate of fish parasites and DELT anomalies (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012).
LOE 5: Fish Kills Since 2001, Exelon has reported four fish kill events in the LSCS cooling pond; Section 3.7.4 describes these events. Exelon attributes these fish kills to high cooling pond temperatures as a result of high summer temperatures combined with low winds and high humidity (Exelon 2001, 2009, 2010). Each event resulted in the mortality of several hundred to several thousand fish. The largest of these events occurred in July 2001 and included approximately 94,500 dead fish (Exelon 2001). The majority of dead fish (96 percent) were gizzard shad (90,800).
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Environmental Consequences and Mitigating Actions The majority of the fish in kills since 2001 were either gizzard shad or threadfin shad (Exelon 2001, 2009, and 2010). Fish kills have had a noticeable impact on shad populations in the cooling pond. For example, during Illinois Department of Natural Resources (IDNR) surveys in the cooling pond, the gizzard shad catch per hour was 451 in 2000 and in 2001, after the largest fish kill, it was 108 (Exelon 2002). Similarly, in a status review of the cooling pond in 2011, 2012, and in 2014, IDNR noted the decline in the threadfin shad population due to fish kills during each summer (Exelon 2015b). Shad populations generally recovered within 1 year after a kill occurred (Exelon 2002, 2015a) and loss of shad did not substantially affect the community dynamics within the cooling pond (Exelon 2010, 2015a). The NRC staff also did not identify any long-term or destabilizing changes from previous fish kills.
Stocked species are generally a small percentage of fish affected by fish kills in the LSCS cooling pond (Exelon 2001, 2009, 2010). IDNR generally stocks the pond with fish that are tolerant to high temperatures. In addition, if a fish kill or other environmental conditions have negatively impacted a stocked species, IDNR can increase the stocking level during the following spring (Exelon 2014a, 2015b). Further, IDNR has often reported abundant, growing populations of various stocked fish, such as striped bass hybrids and channel catfish (IDNR 2007, 2009; Exelon 2015b).
The NRC expects that fish kills would continue during the proposed license renewal period because fish kills in the LSCS cooling pond can occur when temperatures rise above 95 &deg;F (35 &deg;C), the temperature at which most fish in the cooling pond are thermally stressed (Exelon 2014a, 2015a). Past temperature records indicate that the cooling pond regularly exceeded 95 &deg;F (35 &deg;C) during the past 10 summers (Exelon 2015b). Further, EA concluded that the LSCS cooling pond has reached a point where fish kills should be expected every summer (Exelon 2002).
On August 3, 2015, the NRC staff published an Environmental Assessment in the Federal Register (80 FR 46062) as part of the NRC staffs review of Exelons application to amend LSCS Technical Specification 3.7.3, Ultimate Heat Sink, by increasing the cooling water temperature supplied to the plant from the ultimate heat sink (UHS) from 101.25 degrees Fahrenheit (&deg;F) (38.47 degrees Celsius (&deg;C)) to a variable limit between 101.25 and 104 &deg;F (38.47 and 40 &deg;C), depending on the time of day. On November 19, 2015, NRC approved the amendment (NRC 2015g). In its Environmental Assessment, the NRC staff determined that raising the maximum allowable temperature of the UHS would increase cooling pond water temperatures, especially during extreme warm weather conditions. Fish kills would be more likely to occur, especially when cooling pond temperatures rise above 95 &deg;F (35 &deg;C), the temperature at which most fish in the cooling pond are thermally stressed. The NRC staff concluded that there would likely be an increase in the number or intensity of fish kills, and that the majority of fish killed would be gizzard shad and threadfin shad. The increase in intensity and number of fish kills would not result in a significant impact because the cooling pond is a managed ecosystem where fish populations affected by fish kills generally recover within a year and do not significantly alter the fish community structure. Lastly, any impacts from the increased temperatures would be confined to the cooling pond and would not affect aquatic resources in the Illinois River.
Exelon leases the cooling pond to the IDNR for IDNR to manage and stock a portion of the cooling pond. However, Exelon retains the authority to terminate the lease. If the lease were to be terminated during the license renewal period, the NRC staff assumes that the fish community would continue to exist in the cooling pond without stocking, although the distribution of species and population sizes may change without artificial replenishment and with the elimination of recreational fishing pressure. The NRC staff made this determination based on observations of 4-50
 
Environmental Consequences and Mitigating Actions other cooling ponds at nuclear power plants that are not stocked with fish but contain a growing fish community based on the withdrawal of water from a river (e.g., NRC 2013c).
Exelon has not reported any fish kills on the Illinois River since LSCS began operating.
Furthermore, discharge to the Illinois River remained within the NPDES-allowed limits during each of the reportable fish kills (Exelon 2015b).
LOE 5 Conclusion No fish kills have occurred on the Illinois River. Thus, this LOE indicates that the effects of the thermal discharge on Illinois River aquatic biota are not detectable.
Fish kills in the LSCS cooling pond are expected to occur during the license renewal term (Exelon 2002, NRC 2015g). The NRC staff concluded that such fish kills have noticeable effects on threadfin and gizzard shad, based on a decreased population size following a fish kill.
Fish kills are not destabilizing to shad populations because they tend to recover within a year.
Stocked species are a minor portion of affected fish during most fish kills, and therefore, the NRC staff concludes that fish kills do not noticeably alter populations of stocked species. In addition, if a fish kill negatively impacts a stocked species, IDNR can increase the stocking level during the following spring.
Summary of Thermal Impacts Conclusion The NRC staff reviewed past NRC studies of thermal impacts, regulatory and administrative controls to limit the temperature in the LSCS discharge, spatial and temporal patterns of species richness and pollution-sensitive species, the health of fish prior to and during LSCS operations, and the occurrence of fish kills. The NRC staff concluded that the impacts to aquatic resources from heat shock would be SMALL for all fish within the Illinois River and for stock fish within the LSCS cooling pond, based on the following:
* fish could avoid the thermal plume, which would cover up to 9 percent of the Illinois River,
* the LSCS thermal effluent is limited by the IAC and the LSCS NPDES permit,
* species richness and the relative abundance of pollution-sensitive species have increased since LSCS began operations,
* the occurrence of fish parasites and physical abnormalities, which are indicative of poor water quality, has decreased since LSCS began operations, and
* stocked species are a minor portion of affected fish during most fish kills in the LSCS cooling pond.
The NRC staff determined that fish kills in the LSCS cooling pond would continue to occur during the license renewal term and would have noticeable effects on threadfin shad and gizzard shad, based on a decreased population size following a fish kill. Fish kills would not be destabilizing to shad populations because they tend to recover within a year. Therefore, the NRC staff concluded the impacts from heat shock would be MODERATE to gizzard shad and threadfin shad in the LSCS cooling pond. The applicant has proposed no mitigation to reduce the MODERATE environmental impacts associated with heat stress to gizzard shad and threadfin shad in the cooling pond (Exelon 2015b). However, because the cooling pond is a highly managed system, any cascading effects resulting from the loss of shad (such as a reduction in prey for stocked species, which in turn could affect a stocked species population) could be mitigated through IDNRs annual stocking and continual management of the pond.
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Environmental Consequences and Mitigating Actions 4.7.1.4      Water Use Conflicts with Aquatic Resources In the GEIS (NRC 2013d), the NRC determined that effects of water use conflicts on aquatic resources is a Category 2 issue (see Table 4-7) that requires site-specific evaluation during each license renewal review. Water use conflicts occur when the amount of water needed to support aquatic resources is diminished as a result of demand for agricultural, municipal, or industrial use or decreased water availability due to droughts, or a combination of these factors.
The mean annual discharge of the Illinois River (described in Section 3.5.1.1) measured at the USGS gage at Marseilles, Illinois, is 10,750 cfs (304 m3/s). As described in Section 3.5.1.2, LSCSs average surface water withdrawal rate from the Marseilles Pool of the Illinois River is 105 cfs (2.96 m3/s or 67.8 mgd), with consumptive use averaging about 49.7 cfs (1.4 m3/s or 32.1 mgd). This consumptive use is equivalent to about 0.5 percent of the Illinois Rivers average annual flow. During periods of low flow, LSCSs current consumptive water use (i.e., 49.7 cfs (1.4 m3/s or 32.1 mgd)) represents a 0.9- and a 1.1-percent reduction, respectively, in the flow of the river downstream of the LSCS site.
As previously discussed in Section 3.5.1.2 of this SEIS, Exelon maintains an Extreme Heat Implementation Plan that is part of an overall Summer Readiness Plan. The Extreme Heat Implementation Plan provides procedural guidance to plant personnel for responding to worst-case summer weather and hydrologic conditions to ensure compliance with LSCSs NPDES permit for thermal discharge limits and to safeguard plant equipment. As necessary, plant personnel run thermal models and will adjust makeup pumping rates to the cooling pond or the rate of blowdown to the river to maintain permit compliance. Under extreme cases, it may be necessary for Exelon to reduce LSCSs power output or to shut down the plant (e.g., under conditions of extremely low water levels).
The amount of Illinois River water LSCS consumes is minor in comparison to the flow of water past the plant, and administrative mechanisms are in place so LSCS does not consume an amount that would be harmful to aquatic biota during low-flow conditions. The NRC staff did not identify any information that indicates that the Illinois River biota are affected by the loss of river water consumed by LSCSs makeup water withdrawals. The NRC staff concludes that water use conflicts would not occur from the proposed license renewal or would be so minor that the effects on aquatic resources would be undetectable. Thus, the NRC staff concludes that the impacts of water use conflicts on aquatic resources during the proposed license renewal term would be SMALL.
4.7.2      No-Action Alternative If LSCS were to cease operating, impacts to aquatic ecology would decrease or stop following reactor shutdown. Some withdrawal of water from the Illinois River would continue during the shutdown period as the fuel is cooled, although the amount of water withdrawn would decrease over time. The reduced demand for cooling water would substantially decrease the effects of impingement, entrainment, and thermal effluents. These effects would likely stop following the removal of fuel from the reactor cores and shutdown of the spent fuel pool. Given the small area of the thermal plume in the Illinois River under normal operating conditions (less than 9 percent), effects from cold shock are unlikely. The cooling pond, however, would likely experience shifts in the relative abundances of fish populations because less heat-tolerant species would no longer be stressed by thermal additions to the pond. Some fish populations, such as stocked recreational species that thrive in warmer waters, may experience population declines or cease to occur in the cooling pond.
NUREG-0586 (NRC 2002) concludes generically that impacts to aquatic ecology during decommissioning activities would be SMALL for facilities at which the decommissioning 4-52
 
Environmental Consequences and Mitigating Actions activities would be limited to existing operational areas. In the case of LSCS, the NRC staff did not identify any effects that would have more than minor impacts on aquatic resources. Thus, the NRC staff concludes that the impacts of the no-action alternative on aquatic resources during the proposed license renewal term would be SMALL.
4.7.3    New Nuclear Alternative Construction of a new nuclear alternative would occur at an existing nuclear power plant site (other than the LSCS site) or a retired coal plant site. Construction activities could degrade water quality of nearby streams, ponds, or rivers through erosion and sedimentation; result in loss of habitat through pond or wetland filling; or result in direct mortality of aquatic organisms from dredging or other in-water work. Due to the relatively short-term nature of construction activities, these effects would likely be relatively localized and temporary. Siting the plant on an existing site could make use of existing transmission lines, roads, parking areas, and other infrastructure, which would limit the amount of habitat disturbance that would be required. Less habitat disturbance would create less erosion and sedimentation. The construction of intake and discharge structures could result in direct mortality of individuals as well as water quality degradation. Appropriate permits would ensure that water quality impacts would be addressed through mitigation or BMPs, as stipulated in the permits. The EPA, USACE, or the State would oversee applicable permitting, including a CWA Section 404 permit, Section 401 certification, and Section 402(p) NPDES general stormwater permit. The NRC (2013a) has completed the review of one combined license application to build and operate a new nuclear plant in the ROI (Fermi 3 in Michigan) and concluded that construction would have SMALL impacts on aquatic resources. Without more specific details on the location of the new nuclear alternative, the NRC staff finds it reasonable to adopt its previous construction conclusions regarding Fermi 3 for the construction portion of this alternative.
Operational impacts would include those listed in Table 4-7, and the GEIS (NRC 2013d) conclusions of SMALL for Category 1 issues in the table would apply during the operational phase of the new nuclear alternative. Because this alternative would use a closed-cycle system, impingement, entrainment, and thermal effects would also be SMALL. Water use conflicts with aquatic resources would depend on the site location, water body, and specific aquatic community present and cannot be determined without more specific details on the location of this alternative.
The NRC staff concludes that the impacts to aquatic resources from construction and operation of a new nuclear alternative would be SMALL.
4.7.4    IGCC Alternative Construction of an IGCC alternative would occur at the LSCS site or another existing power plant site in the ROI. The GEIS (NRC 2013d) indicates that the impacts of new power plant construction on ecological resources would be qualitatively similar. Thus, those impacts discussed under the new nuclear alternative would apply during the construction phase. Thus, construction impacts would be SMALL.
Operation of the IGCC alternative would require less cooling water than LSCS because the plant would operate with a closed-cycle system. Accordingly, impingement, entrainment, and thermal effects on aquatic resources would likely be smaller than for continued operation of LSCS, though the exact magnitude would depend upon the water body and specific aquatic communities present. Chemical discharges from the cooling system would be similar to those at LSCS. Operation would require coal deliveries, cleaning, and storage, which would require periodic dredging (if coal is delivered by barge); create dust, sedimentation, and turbidity; and 4-53
 
Environmental Consequences and Mitigating Actions introduce trace elements and minerals into the water. Air emissions from the IGCC units would include small amounts of sulfur dioxide, particulates, and mercury that would settle on water bodies or be introduced into the water from soil erosion. If the IGCC plant were located on the same water body (the Illinois River) in the vicinity of the LSCS site, overall operational impacts would be less than for the continued operation of LSCS because of the reduced impingement, entrainment, and thermal effects. However, without knowing the location of the IGCC plant, the associated water body, aquatic species, and their interactions within the ecosystem, the NRC staff cannot assume that overall impacts of operation of an IGCC plant would be less than those for the continued operation of LSCS.
The NRC staff concludes that the impacts to aquatic resources from construction of an IGCC plant would be SMALL and the impacts from operation would be SMALL to MODERATE.
4.7.5    NGCC Alternative Construction of an NGCC alternative would occur at the LSCS site. The GEIS (NRC 2013d) indicates that the impacts of new power plant construction on ecological resources would be qualitatively similar. Thus, those impacts discussed under the new nuclear alternative would apply during the construction phase. Construction of new pipelines, if necessary, could impact previously undisturbed habitats. This impact would vary depending on the location of the plant and would be more likely to impact terrestrial resources than aquatic resources. Because the NGCC alternative would be built at the LSCS site, new pipelines could be collocated in existing corridors to reduce impacts. Overall, construction impacts would be SMALL.
Operation of the NGCC alternative cooling system would be qualitatively similar to the IGCC alternative but would result in smaller impacts because the NGCC alternative would consume about half as much cooling water. Air emissions from the NGCC units would include nitrogen oxide, carbon dioxide, and particulates that would settle on water bodies or be introduced into the water from soil erosion. Given that the NGCC plant would be located on the same water body (the Illinois River) as LSCS, overall operational impacts would be less than for the continued operation of LSCS, due to the reduced impingement, entrainment, and thermal effects, which were determined to be SMALL for aquatic resources in the Illinois River.
The NRC staff concludes that the impacts to aquatic resources from construction and operation of an NGCC plant would be SMALL.
4.7.6    Combination Alternative (NGCC, Wind, Solar)
The NGCC portion of this alternative would be located at the LSCS site. Construction and operation impacts would be qualitatively similar to those discussed for the NGCC alternative but would be much less in magnitude because of the smaller footprint of the plant, reduced cooling water consumption, and lowered air emissions. The wind and solar portions of the alternative, which account for 85 percent of the alternatives power generation, would not require cooling or consumptive water use during operation and thus, would not affect aquatic resources. The NRC staff concludes that the impacts on aquatic resources from the combination alternative would be SMALL.
4.7.7    Purchased Power Alternative The purchased power alternative would have wide-ranging impacts that are hard to specifically assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI. This alternative would likely have little to no construction impacts because it would include power from already-existing power generating facilities, and 4-54
 
Environmental Consequences and Mitigating Actions the types of operational impacts would be similar to the effects discussed in the preceding alternative sections. This alternative would be more likely to intensify already existing effects at power generating facilities than create wholly new effects on aquatic species and habitats.
Existing facilities would likely have permits with appropriate mitigation, BMPs, or other procedures in place to ensure that effects to the environment during operations are minimized.
The NRC staff concludes that the impacts on aquatic resources from the purchased power alternative would be SMALL.
4.8    Special Status Species and Habitats This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on special status species and habitats.
4.8.1    Proposed Action Section 3.8 describes the special status species and habitats that have the potential to be affected by the proposed action. The discussion of species and habitats protected under the Endangered Species Act of 1973, as amended (ESA), includes a description of the action area as defined by the ESA section 7 regulations at 50 CFR 402.02. The action area encompasses all areas that would be directly or indirectly affected by the proposed LSCS license renewal.
Table 4-8 lists the one site-specific (Category 2) issue related to special status species and habitats applicable to LSCS. Appendix C contains information on the NRC staffs consultation with the U.S. Fish and Wildlife Service (FWS) for the proposed action pursuant to section 7 of the ESA. No listed species under the National Marine Fisheries Services (NMFS) jurisdiction occur in the action area, therefore, the NRC staff did not consult with NMFS.
Table 4-8. Special Status Species and Habitat Issues Issue                                                                    GEIS Section    Category Threatened, endangered, and protected species, critical habitat and        4.6.1.3          2 essential fish habitat Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 Correspondence In late February 2015, the NRC staff filled in an online form to obtain an updated protected species list for LSCS on the FWSs Environmental Conservation Online System, Information for Planning and Conservation. The FWS (2015b) responded with a list of threatened and endangered species that may occur in the project location and may be affected by the Federal action. In October 2015, the NRC staff checked the FWS (2015a) online Illinois County distribution of listed species for updates.
Analysis and Determination of Effects Exelon (2014a) reports that no Federally listed species identified in Section 3.8, have been reported in the action area and no designated or proposed critical habitat under the ESA occurs in the action area. Thus, the NRC staff concludes that the proposed action would have no effect on the Federally listed species identified in Section 3.8. The FWS (2014) does not typically provide its concurrence with no effect determinations by Federal agencies. Thus, the ESA 4-55
 
Environmental Consequences and Mitigating Actions does not require further informal consultation or the initiation of formal consultation with the FWS for the proposed license renewal.
ESA regulations at 50 CFR 402.12(f)(4) direct Federal agencies to consider cumulative effects as part of the proposed action effects analysis. Under the ESA, cumulative effects are defined as those effects of future State or private activities, not involving Federal activities, that are reasonably certain to occur within the action area of the Federal action subject to consultation (50 CFR 402.02). Unlike the NEPA definition of cumulative impacts (see Section 4.16),
cumulative effects under the ESA do not include past actions or other Federal actions requiring separate ESA section 7 consultation. When formulating biological opinions under formal section 7 consultation, the FWS and the National Marine Fisheries Service (NMFS) (FWS and NMFS 1998) consider cumulative effects when determining the likelihood of jeopardy or adverse modification. Therefore, consideration of cumulative effects under the ESA is necessary only if listed species will be adversely affected by the proposed action (FWS 2014). Since the NRC staff concludes that no species would be adversely affected by license renewal, the NRC staff did not assess cumulative effects.
Reporting Requirements If in the future, a Federally listed species is observed on the LSCS site, the NRC has measures in place to ensure that NRC staff would be appropriately notified so that the NRC staff could determine the appropriate course of action. If the renewed licenses have not yet been issued, the NRCs response could include the initiation of consultation pursuant to section 7 of the ESA.
LSCSs Unit 1 and Unit 2 operating licenses, Appendix B, Environmental Protection Plan (see NRC 2001), require Exelon to report to the NRC within [[estimated NRC review hours::24 hours]] any unusual or important event that indicates or could result in significant environmental impact causally related to plant operation. The licenses give the specific example of mortality or unusual occurrence of any species protected by the Endangered Species Act of 1973. Additionally, the NRCs regulations containing notification requirements require that operating nuclear power reactors report to the NRC within [[estimated NRC review hours::4 hours]] any event or situation, related toprotection of the environment, for which a news release is planned or notification to other government agencies has been or will be made (10 CFR 50.72(b)(2)(xi)). Such notifications include reports regarding Federally listed species, as described in Section 3.2.12 of NUREG-1022, Event Reporting Guidelines for 10 CFR 50.72 and 50.73 (NRC 2013b).
Special Status Species and Habitats Impacts Summary Table 4-9 summarizes the NRC staffs findings.
Table 4-9. Federally Listed Species and Designated Habitat in LaSalle County, Illinois, and NRC Effect Determinations for Proposed LSCS License Renewal Federally Listed                                  Federal Group                  Species                  Common Name              Status(a)  Determination Clams and Mussels      Plethobasus cyphyus      sheepnose mussel              E      no effect Flowering Plants      Boltonia decurrens      decurrent false aster        T      no effect Platanthera leucophaea eastern prairie fringed        T      no effect orchid Delea foliosa            leafy prairie clover          E      no effect Mammals                Myotis sodalis          Indiana bat                  E      no effect Myotis septentrionalis  northern long-eared bat      T      no effect 4-56
 
Environmental Consequences and Mitigating Actions Federally Listed                                  Federal Group                    Species                Common Name              Status(a) Determination Critical Habitat Myotis sodalis          Indiana bat                        no effect (a) E=endangered; T=threatened Sources: FWS 2015a, 2015b 4.8.2      No-Action Alternative Under the no-action alternative, the plant would shut down. Federally listed species and designated critical habitat can be affected not only by operation of nuclear power plants but also by activities during shutdown. The ESA action area for the no-action alternative would most likely be the same as discussed in Section 3.8. The plant would require substantially less cooling water, so potential impacts to aquatic species and habitats discussed in Section 4.8.1 would be reduced, although the plant would still require some cooling water for some time.
Changes in land use and other shutdown activities might affect terrestrial species differently than under continued operation.
Under the no-action alternative, the NRC would assess the need for ESA consultation if any activities associated with plant shutdown have the potential to affect a Federally listed species and if the activities meet the criteria in 50 CFR Part 402 for initiation of section 7 consultation.
The ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct. In the case of a take, ESA section 7 requires that the NRC initiate consultation with the FWS or NMFS. If consultation was initiated and then completed, the implementing regulations at 50 CFR 402.16 also direct Federal agencies to reinitiate consultation in circumstances where (a) the incidental take limit in a biological opinion is exceeded, (b) new information reveals effects to Federally listed species or designated critical habitats that were not previously considered, (c) the action is modified in a manner that causes effects not previously considered, or (d) new species are listed or new critical habitat is designated that may be affected by the action. An ESA section 7 consultation could identify impacts on Federally listed species or critical habitat, require monitoring and mitigation to minimize such impacts, and provide a level of exempted takes. Regulations and guidance regarding the ESA section 7 consultation process are provided in 50 CFR Part 402 and in the Endangered Species Consultation Handbook (FWS and NMFS 1998).
Typically, the effects on ESA-listed aquatic species would be smaller than the effects under continued operation but would depend on the listed species and habitats present if shutdown were to occur. The types and magnitudes of adverse impacts to terrestrial ESA-listed species would depend on the shutdown activities and the listed species and habitats present when the alternative is implemented. Therefore, the NRC cannot forecast a particular level of impact for this alternative.
4.8.3      New Nuclear Alternative This alternative entails shutdown and decommissioning of LSCS and construction of a new nuclear unit at an alternative industrial location, possibly in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS.
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Environmental Consequences and Mitigating Actions Because the new nuclear alternative would be built on an existing power plant site outside of Illinois, which has restrictions on new nuclear power plant construction, the special status species and habitats affected by the action would be different than those considered under the proposed action. Because the NRC would be the licensing agency under this alternative, the ESA would require the NRC to initiate consultation with FWS and NMFS, as applicable, prior to construction to ensure that the construction and operation of the new nuclear plant would not adversely affect any Federally listed species or adversely modify or destroy designated critical habitat. Section 4.8.2 discusses general ESA considerations.
In the unlikely event that the new nuclear plant is sited in an area that could affect water bodies with designated EFH, which applies only to certain commercially harvested marine and anadromous fish species, consultation with NMFS under the MSA would be required to assess potential impacts to that habitat. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, plant design, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative.
4.8.4      IGCC Alternative This alternative entails shutdown and decommissioning of LSCS and construction of a new IGCC facility at either the LSCS site or an alternative industrial location. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS.
Unlike the new nuclear alternative, the NRC does not license IGCC facilities, and the NRC would not be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative. If no other federal agency was involved in licensing the facilities, the facilities themselves would be responsible for protecting listed species because the ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct.
If the IGCC alternative were to be built on the LSCS site, the ESA action area might still be different because the activities and structures associated with the construction and operations of an IGCC plant would be different than those described under continued operation of LSCS. If the IGCC alternative were to be built at a site other than the LSCS site, the listed species and habitats affected by the action would be different than those identified for LSCS. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, plant design, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative.
4.8.5      NGCC Alternative This alternative entails the shutdown and decommissioning of LSCS and construction of a new NGCC facility at either the LSCS site or an alternative industrial location. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS.
Unlike the new nuclear alternative, the NRC does not license NGCC facilities, and the NRC would not be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative. If no other federal agency was involved in licensing the facilities, the facilities themselves would be responsible for protecting listed species because the ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct.
If the NGCC alternative were to be built on the LSCS site, the ESA action area might still be different because the activities and structures associated with construction and operation of an 4-58
 
Environmental Consequences and Mitigating Actions NGCC plant would be different than those described under continued operation of LSCS. If the NGCC alternative were to be built at a site other than the LSCS site, the listed species and habitats affected by the action would be different than those identified for LSCS. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, plant design, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative.
4.8.6      Combination Alternative (NGCC, Wind, Solar)
This alternative entails the shutdown and decommissioning of LSCS and construction of new non-nuclear facilities at the LSCS site and alternative industrial locations. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS.
The combination alternative would involve construction and operation of wind turbines and solar PV systems throughout the ROI, as well as an NGCC plant at the LSCS site. Unlike the new nuclear alternative, the NRC does not license NGCC, wind, or solar facilities, and the NRC would not be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative. If no other federal agency was involved in licensing the facilities, the facilities themselves would be responsible for protecting listed species because the ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct.
Even though the NGCC portion of the combination alternative would be located on the LSCS site, the ESA action area might be different because the activities and structures associated with the construction and operation of the NGCC portion of the combination alternative would be different than those described under continued operation of LSCS. Since the wind and solar parts of the combination alternative would be located on a site or sites other than the LSCS site, the listed species and habitats affected by the action would be different than those identified for LSCS. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, wind and solar component designs, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative.
4.8.7      Purchased Power Alternative Because the purchased power alternative might include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI, the special status species and habitats affected by the action would be different than those considered under continued operation. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed sites, plant designs, operation, and species and habitats listed at the various sites when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative. As with the other alternatives discussed previously, the facilities themselves, or a different federal regulator, but not the NRC, would be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative.
4.9      Historic and Cultural Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on historic and cultural resources.
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Environmental Consequences and Mitigating Actions 4.9.1      Proposed Action Section 3.9 describes the historic and cultural resources that have the potential to be affected by the proposed action. Table 4-10 identifies the historic and cultural resource issue applicable to LSCS during the license renewal term.
Table 4-10. Historic and Cultural Resources Issue Issue                                                                    GEIS Section  Category Historic and cultural resources                                            4.7.1            2 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 The National Historic Preservation Act of 1966, as amended (54 USC 300101 et seq. (NHPA))
requires Federal agencies to consider the effects of their undertakings on historic properties, and renewing the operating license of a nuclear power plant is an undertaking that could potentially affect historic properties. Historic properties are defined as resources eligible for listing in the National Register of Historic Places (NRHP). The criteria for eligibility are listed in 36 CFR 60.4, and include: (1) association with significant events in history, (2) association with the lives of persons significant in the past, (3) embodiment of distinctive characteristics of type, period, or construction, and (4) sites or places that have yielded, or are likely to yield, important information.
The historic preservation review process (Section 106 of the NHPA) is outlined in regulations issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800.
In accordance with the provisions of the NHPA, the NRC is required to make a reasonable effort to identify historic properties included in or eligible for inclusion in the NRHP in the Area of Potential Effect (APE). The APE for a license renewal action is the area at the power plant site, the transmission lines up to the first substation and immediate environs that may be affected by the license renewal decision, and land-disturbing activities associated with continued reactor operations. For LSCS, the first substation is located on site at the 345-kV LSCS Station switchyard. Additionally, LSCS property containing the makeup and blowdown piping from the cooling lake to the Illinois River are included in the APE (Exelon 2014a).
If historic properties are present within the APE, the NRC is required to contact the State Historic Preservation Office (SHPO), assess the potential impact, and resolve any possible adverse effects of the undertaking (license renewal) on historic properties. In addition, the NRC is required to notify the SHPO if historic properties would not be affected by license renewal or if no historic properties are present. The SHPO is part of the Illinois Historic Preservation Agency (IHPA).
Consultation In accordance with 36 CFR 800.8(c), on February 9, 2015, the NRC initiated consultations on the proposed action by writing to the ACHP and IHPA (NRC 2015c, 2015d). Also on February 9, 2015, the NRC initiated consultation with the following 14 Federally recognized Tribes (NRC 2015e) (see Appendix C for a list of these letters):
* Ho-Chunk Nation,
* Miami Tribe of Oklahoma,
* Peoria Tribe of Indians of Oklahoma, 4-60
 
Environmental Consequences and Mitigating Actions
* Citizen Potawatomi Nation,
* Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki,
* Sac and Fox Nation of Missouri in Kansas and Nebraska,
* Sac and Fox Nation,
* Pokagon Band of Potawatomi,
* Forest County Potawatomi,
* Hannahville Indian Community, Band of Potawatomi,
* Prairie Band of Potawatomi Nation,
* Winnebago Tribe of Nebraska,
* Kickapoo Tribe in Kansas, and
* Kickapoo Tribe of Oklahoma.
By letter, the NRC provided information about the proposed action, defined the APE, and indicated that the NHPA review would be integrated with the NEPA process, according to 36 CFR 800.8(c). The NRC invited participation in the identification and possible decisions concerning historic properties and also invited participation in the scoping process. The NRC received no scoping comments from any of the tribes contacted. In April 2015, the NRC received a determination from the IHPA stating no objection to the undertaking and that no historic properties would be affected (Leibowitz 2015) (see Appendix C). The NRC met with the Illinois SHPO in May 2015. The Illinois SHPO did not express any concerns about the proposed LSCS license renewal during the meeting (NRC 2015f).
Exelon currently has no planned physical changes or license-renewal-related refurbishment activities at the LSCS site. Any future ground-disturbing activities at the LSCS site will be done in accordance with established LSCS procedures to determine whether the proposed activities will impact known or potential cultural and historic resources (Exelon 2015b). Exelon would consult with the SHPO, if necessary, to determine what measures would be needed to minimize and mitigate the impacts (Exelon 2014a). Supplemental cultural resource surveys may be performed of the affected areas based on consultation with the SHPO. As described in Section 3.9, there are no historic properties or known NRHP-eligible historic or cultural resources located within the LSCS APE. Exelon has established a draft Cultural Resource Management Plan (CRMP) to help ensure historic and cultural resources are considered prior to ground-disturbing activities. The CRMP instructs Exelons staff on how to evaluate land disturbing activity for possible impacts to historic and cultural resources and identifies previously disturbed areas of the LSCS property and any areas with the potential to contain undiscovered resources (Exelon 2015b). Additionally, Exelon has established procedures in the event that historic or cultural resources are inadvertently discovered during operational activities. These procedures direct the Exelon staff to stop work, protect exposed resources, and contact Exelon environmental personnel to take appropriate action (Exelon 2015b). Cultural resource training is not currently required for LSCS staff members (Exelon 2015b).
The NRC staff concludes that license renewal would not affect any known historic properties (36 CFR Section 800.4(d)(1)) based on (1) no current NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelons draft CRMP, (4) no current plan for license-renewal-related physical changes or ground-disturbing activities, (5) IHPA input, and, (6) cultural resource assessment. The NRC staff notes that Exelon could reduce the risk of potential impacts to historic and cultural resources located on or near the LSCS site by finalizing its draft CRMP, 4-61
 
Environmental Consequences and Mitigating Actions with input from the SHPO, and by providing training on cultural resources for Exelons staff engaged in planning and executing ground-disturbing activities.
4.9.2    No-Action Alternative Not renewing the operating licenses and terminating reactor operations would have no effect on historic properties and cultural resources within the site boundaries of LSCS. In the decommissioning GEIS, the NRC staff determined that, for all nuclear plant sites at which decommissioning does not anticipate disturbing lands beyond existing site boundaries, impacts to cultural resources would be SMALL. If disturbance beyond the operational areas is anticipated, the impacts may or may not be detectable or destabilizing, depending on site-specific conditions, and cannot be predicted generically. In those cases, the NRC staff concludes that, if disturbance beyond the operation areas is anticipated, the potential impacts may be SMALL, MODERATE, or LARGE and must be determined through site-specific analysis (NRC 2002).
Title 10 of CFR Section 50.82 requires power reactor licensees to submit to the NRC a post-shutdown decommissioning activities report (PSDAR). The PSDAR is required to be submitted within 2 years following permanent cessation of operations and contains a description of planned decommissioning activities to be completed at that time. Until the PSDAR is submitted, the NRC staff does not know whether land disturbance will remain within the existing site boundary after the plant is shut down.
4.9.3    New Nuclear Alternative Any land areas potentially affected by the construction of the new nuclear alternative power plant would need to be surveyed to identify and record historic and archaeological cultural resources. An inventory of a previously disturbed former plant industrial site may still be necessary if the site has not been previously surveyed or to verify the level of previous disturbance and to evaluate the potential for intact subsurface cultural resources to be present.
Power plant developers would need to survey all potentially affected land areas associated with operation of the alternative (e.g., land required for new roads, transmission corridors, other ROWs). Any cultural resources found during these surveys would need to be recorded and evaluated for eligibility for listing on the NRHP. Mitigation of adverse effects would need to be considered if eligible resources properties were encountered. Areas with the greatest sensitivity and most significant cultural resources should be avoided. Visual impacts on significant cultural resources, such as the historic property viewsheds near the proposed power plant site, should also be assessed and evaluated.
The potential for impacts to historic and cultural resources from the new nuclear alternative would vary greatly, depending on the location of the site selected for the proposed new nuclear power plant site. Cooling towers could impact historic property viewsheds. However, given the preference to use a previously disturbed former power plant site, avoidance of undisturbed land could further reduce potential impacts to historic and cultural resources. The NRC staff concludes that the impacts on historic and cultural resources from the construction and operation of a new nuclear alternative power plant would be SMALL.
4.9.4    IGCC Alternative Any areas potentially affected by the construction of the IGCC alternative may need to be surveyed to identify and record historic and cultural resources if a Federal undertaking under NHPA is present. If the IGCC alternative is located on the existing LSCS site, previously disturbed areas known to not contain historic and cultural resources could be used. If the 4-62
 
Environmental Consequences and Mitigating Actions alternative is sited on the approximately 250 ac (101 ha) of undeveloped land on the LSCS site, a survey and inventory for potential historic and cultural resources may need to be performed. If the IGCC power plant is sited at an existing power plant site other than LSCS and a Federal undertaking under NHPA is present, a cultural resource survey may still be necessary if the site has not been previously surveyed or to verify the level of disturbance and evaluate the potential for intact subsurface resources. Any resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered. Areas with the greatest sensitivity should be avoided. Visual impacts on significant cultural resources, such as the historic property viewshed of historic properties near the proposed power plant site, should also be assessed and evaluated.
The potential for impacts on historic and cultural resources from the IGCC alternative would vary greatly depending on the location of the proposed site. Given that the preference is to use a previously disturbed former plant site and no major infrastructure upgrades are necessary, avoidance of significant historic and cultural resources should be possible and effectively managed under current laws and regulations. The NRC staff concludes that the impacts on historic and archaeological resources from the IGCC alternative would be SMALL.
4.9.5    NGCC Alternative Any areas potentially affected by the construction and operation of an NGCC power plant may need to be surveyed to identify and record historic and cultural resources if a Federal undertaking under NHPA is present. If the NGCC power plant is constructed at the existing LSCS site, previously disturbed areas known to not contain historic and cultural resources could be used. If the power plant is sited on the approximately 250 ac (101 ha) of undeveloped land on the LSCS site and a Federal undertaking under NHPA is present, a survey and inventory of potential historic and cultural resources would need to be performed. Additionally, plant operators would need to survey all areas associated with the alternative (e.g., a new pipeline, roads, transmission corridors, other ROWs). Any resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered. Areas with the greatest sensitivity should be avoided. Visual impacts on significant cultural resources, such as the viewsheds of historic properties near the proposed power plant site, should also be assessed and evaluated.
Given that the NGCC alternative is assumed to be sited at LSCS, avoidance of significant historic and cultural resources should be possible. However, historic and archaeological resources could potentially be affected, depending on the resource richness of the land required for a new gas pipeline; but, as with the plant site itself, avoidance of significant historic and cultural resources should be possible and effectively managed under current laws and regulations. The NRC staff concludes that the impacts on historic and cultural resources from the NGCC alternative would be SMALL.
4.9.6    Combination Alternative (NGCC, Wind, Solar)
Areas potentially affected by the construction of the NGCC, wind, and solar alternative may need to be surveyed to identify and record historic and archaeological resources if a Federal undertaking under NHPA is present. Any resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered.
Impacts to historic and cultural resources from the NGCC portion of this alternative are similar to the NGCC alternative in Section 4.9.5. The potential for impacts on historic and cultural 4-63
 
Environmental Consequences and Mitigating Actions resources from the wind portion of this alternative would vary greatly, depending on the location of the proposed sites. Areas with the greatest sensitivity could be avoided or effectively managed under current laws and regulations. However, construction of wind farms and their support infrastructure have the potential to notably impact historic and archaeological resources because of earthmoving activities (e.g., grading and digging) and the aesthetic changes they may bring to the viewshed of historic properties located nearby. The impacts of the construction of a new solar alternative on historic and cultural resources will vary, depending on the form of the solar capacity installed. Rooftop installations minimize land disturbance and the modifications necessary to the transmission system, thereby minimizing impacts to historic and cultural resources. Land-based installations are larger than rooftop installations and will require some degree of land disturbance for installation purposes, potentially causing greater impacts to historic and archaeological resources. Aesthetic changes caused by the installation of both forms could have a noticeable effect on the viewshed of nearby historic properties. Using previously disturbed sites for land-based installations and collocating any new transmission lines with existing ROWs could minimize impacts to historic and archaeological resources.
Areas with the greatest sensitivity could be avoided or effectively managed under current laws and regulations. The NRC staff concludes that, depending on the resource richness of the sites chosen for the NGCC, wind, and solar alternative, the impacts could range from SMALL to LARGE.
4.9.7    Purchased Power Alternative No direct impacts on historic and cultural resources are expected from purchased power. If new transmission lines were needed to convey power to the PJM Interconnection area, surveys similar to those discussed in Section 4.9.3 may need to be performed if a Federal undertaking under NHPA is present. However, transmission lines would likely be collocated with existing ROWs, minimizing any impacts to historic and cultural resources.
Indirectly, construction of new nuclear, coal-fired, and natural-gas-fired plants, or wind energy projects, and any new transmission lines to support increased demand in the purchased power alternative could affect historic and cultural resources. If the amount of purchased power exceeds the available supply, new electrical power generating facilities may be needed. Any areas potentially affected by construction may need to be surveyed to identify and record historic and cultural resources if a Federal undertaking under NHPA is present. Resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered. Plant operators would need to survey all areas associated with operation of the alternative (e.g., roads, transmission corridors, other ROWs). The potential for impacts on historic and cultural resources would vary greatly, depending on the location of the proposed sites; however, using previously disturbed sites could greatly minimize impacts to historic and cultural resources. Areas with the greatest sensitivity could be avoided or effectively managed under current laws and regulations. The NRC staff concludes that, depending on the resource richness of the sites chosen, the impacts on historic and cultural resources could range from SMALL to LARGE.
4.10    Socioeconomics This section describes the potential socioeconomic impacts of the proposed action (license renewal) and alternatives to the proposed action.
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Environmental Consequences and Mitigating Actions 4.10.1    Proposed Action Socioeconomic effects of ongoing reactor operations at LSCS have become well established as regional socioeconomic conditions have adjusted to the presence of the nuclear power plant.
These conditions are described in Section 3.10. Any changes in employment and tax payments caused by license renewal and any associated refurbishment activities could have a direct and indirect impact on community services and housing demand, as well as traffic volumes in the communities around a nuclear power plant.
Table 4-11 identifies the socioeconomic NEPA issues from Table B-1 in Appendix B to Subpart A of Part 51, applicable to LSCS during the license renewal term.
Table 4-11. Socioeconomic NEPA Issues Affected by License Renewal Issue                                                          GEIS Sections          Category Employment and income, recreation and tourism                    4.8.1.1                  1 Tax revenues                                                      4.8.1.2                  1 Community services and education                                  4.8.1.3                  1 Population and housing                                            4.8.1.4                  1 Transportation                                                    4.8.1.5                  1 Source: Table B-1 in Appendix B, Subpart A of 10 CFR Part 51 The supplemental site-specific socioeconomic impact analysis for the license renewal of LSCS included a review of Exelons ER, scoping comments, other information records, and a data-gathering site visit to LSCS. The NRC staff did not identify any new and significant information during the review that would result in impacts that would exceed the predicted socioeconomic impacts evaluated in the GEIS, and no additional socioeconomic NEPA issues were identified beyond those listed in Table B-1.
In addition, Exelon indicated in its ER that it has no plans to add non-outage workers during the license renewal term and that increased maintenance and inspection activities could be managed using the current workforce. Consequently, people living in the vicinity of LSCS are not likely to experience any changes in socioeconomic conditions during the license renewal term beyond what is currently being experienced. Therefore, the impact of continued reactor operations during the license renewal term would not exceed the socioeconomic impacts predicted in the GEIS. For these issues, the GEIS predicted that the impacts would be SMALL for all nuclear plants.
4.10.2    No-Action Alternative 4.10.2.1    Socioeconomics Not renewing the operating license and terminating reactor operations would have a noticeable impact on socioeconomic conditions in the communities located near LSCS. The loss of jobs and income would have an immediate socioeconomic impact. Some, but not all, of the approximately 890 employees would begin to leave after reactor operations are terminated, and overall tax revenue generated by plant operations would be reduced (Exelon 2014a). Exelon pays annual property taxes to various entities to partially fund their respective operating budgets. The property tax revenue is used to fund public schools, libraries, county and local township operations, and other services. The loss of tax revenue could reduce or eliminate 4-65
 
Environmental Consequences and Mitigating Actions some public and educational services. Indirect employment and income generated by power plant operations would also be reduced.
Former LSCS workers and their families could leave in search of employment elsewhere. The increase in available housing along with decreased demand could cause housing prices to fall.
Since the majority of employees reside in LaSalle and Grundy Counties, socioeconomic impacts from the termination of reactor operations would be concentrated in these counties, with a corresponding reduction in purchasing activity and tax revenue in the regional economy.
Income and revenue losses from the termination of reactor operations at LSCS would directly affect LaSalle County and nearby communities most reliant on income from power plant operations. The impact of the job loss, however, may not be as noticeable in local communities, given the amount of time required for decommissioning. The socioeconomic impacts from the termination of nuclear plant operations (which may not entirely cease until after decommissioning) would, depending on the jurisdiction, range from SMALL to LARGE.
4.10.2.2    Transportation Traffic congestion caused by commuting workers and truck deliveries on roads in the vicinity of LSCS would be reduced after power plant shutdown. Most of the reduction in traffic volume would be associated with the loss of jobs. The number of truck deliveries to LSCS would be reduced until decommissioning. Traffic-related transportation impacts would be SMALL as a result of the shutdown of the nuclear power plant.
4.10.3    New Nuclear Alternative 4.10.3.1    Socioeconomics Socioeconomic impacts are defined in terms of changes to the demographic and economic characteristics and social conditions of a region. For example, the number of jobs created by the construction and operation of a power plant could affect regional employment, income, and expenditures.
Two types of jobs would be created by this alternative: (1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of a new nuclear power plant were evaluated to measure their possible effects on current socioeconomic conditions.
The construction workforce could peak at 3,500 workers (NRC 2008a). The relative economic effect of this many workers on the local economy and tax base would vary, with the greatest impacts occurring in the communities where the majority of construction workers would reside and spend their income. As a result, local communities could experience a short-term economic boom from increased tax revenue and income generated by construction expenditures and the increased demand for temporary (rental) housing and public as well as commercial services.
After construction, local communities could experience a return to preconstruction economic conditions. Based on this information and given the number of workers, socioeconomic impacts during construction in communities near an existing nuclear power plant or retired coal site could range from MODERATE to LARGE.
Approximately 800 workers would be required during nuclear power plant operations (NRC 2008a). Some LSCS operations workers could transfer to the new nuclear power plant.
Local communities near the new nuclear power plant would experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for 4-66
 
Environmental Consequences and Mitigating Actions housing and public as well as commercial services. The amount of property tax payments under the new nuclear alternative may also increase if additional land is required to support this alternative.
This alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS and a corresponding reduction in purchasing activity and revenue contributions to the regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region. The impact of the job loss, however, may not be noticeable in local communities, given the amount of time required for decommissioning of the existing LSCS facilities. Based on this information and given the number of operations workers, socioeconomic impacts during nuclear power plant operations on local communities could range from SMALL to MODERATE.
4.10.3.2    Transportation Transportation impacts associated with construction and operation of a new nuclear power plant would consist of commuting workers and truck deliveries of construction materials to the power plant site. During periods of peak construction activity, up to 3,500 workers could be commuting daily to the construction site (NRC 2008a). Workers commuting to the construction site would arrive via site access roads and the volume of traffic on nearby roads could increase substantially during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Materials could also be delivered by rail or barge, depending on the location. Traffic-related transportation impacts during construction would likely range from MODERATE to LARGE.
Traffic-related transportation impacts on local roads would be greatly reduced after the completion of the power plant. Approximately 800 operations workers would be commuting daily to the new nuclear power plant site (NRC 2008a). Transportation impacts would include daily commuting by the operating workforce, material deliveries, and the removal of commercial waste material to offsite disposal or recycling facilities by truck. Traffic on roadways would peak during shift changes and refueling outages, resulting in temporary levels of service impacts and delays at intersections. Overall, at the new nuclear power plant site, transportation impacts would be SMALL to MODERATE during operations.
4.10.4    IGCC Alternative 4.10.4.1    Socioeconomics As explained in Section 4.10.3, two types of jobs would be created by this alternative:
(1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of a new IGCC power plant were evaluated to measure their possible effects on current socioeconomic conditions.
The construction workforce could peak at 4,600 workers (DOE 2010a). The relative economic effect of this many workers on the local economy and tax base would vary, with the greatest impacts occurring in the communities where the majority of construction workers would reside and spend their income. As a result, local communities could experience a short-term economic 4-67
 
Environmental Consequences and Mitigating Actions boom from increased tax revenue and income generated by construction expenditures and the increased demand for temporary (rental) housing and public as well as commercial services.
After construction, local communities could experience a return to preconstruction economic conditions. Based on this information and given the number of workers, socioeconomic impacts during construction in communities near an existing power plant site could range from MODERATE to LARGE.
An estimated 420 workers would be required during power plant operations (DOE 2010a).
Local communities would experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for housing and public as well as commercial services. The amount of property tax payments under the IGCC alternative may also increase if additional land is required to support this alternative.
This alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS and a corresponding reduction in purchasing activity and revenue contributions to the regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region. The impact of the job loss, however, may not be noticeable in local communities, given the amount of time required for decommissioning the existing LSCS facilities. Based on this information and given the number of operations workers, socioeconomic impacts during IGCC power plant operations on local communities could range from SMALL to MODERATE.
4.10.4.2    Transportation Transportation impacts associated with construction and operation of the two-unit, IGCC power plant would consist of commuting workers and truck deliveries of construction materials to the power plant site. During periods of peak construction activity, up to 4,600 workers could be commuting daily to the construction site. Workers commuting to the construction site would arrive via site access roads, and the volume of traffic on nearby roads could increase substantially during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Materials could also be delivered by rail or barge, depending on location. Traffic-related transportation impacts during construction would likely range from MODERATE to LARGE.
Traffic-related transportation impacts on local roads would be greatly reduced after the completion of the power plant. The estimated maximum number of operations workers commuting daily to the power plant site could be 420 (DOE 2010a). Fewer workers would be required if multiple units are operated at the same site. Frequent coal and limestone deliveries and ash removal by rail would add to the overall transportation impact. The increase in traffic on roadways would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Onsite coal storage would make it possible to receive several trains per day at a site with rail access. If the IGCC power plant is located on navigable waters, coal and other materials could be delivered by barge. Coal and limestone delivery and ash removal via rail would cause levels of service impacts due to delays at railroad crossings. Overall, transportation impacts would be SMALL to MODERATE during IGCC power plant operations.
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Environmental Consequences and Mitigating Actions 4.10.5    NGCC Alternative 4.10.5.1    Socioeconomics As explained in Section 4.10.3, two types of jobs would be created by this alternative:
(1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of a new NGCC power plant were evaluated to measure their possible effects on current socioeconomic conditions.
The construction workforce could peak at 1,783 workers (Exelon 2014a). The relative economic effect of this many workers on the local economy and tax base would vary, with the greatest impacts occurring in the communities where the majority of construction workers would reside and spend their income. As a result, local communities could experience a short-term economic boom from increased tax revenue and income generated by construction expenditures and the increased demand for temporary (rental) housing and public as well as commercial services.
After construction, local communities could experience a return to preconstruction economic conditions. Based on this information and given the number of workers, socioeconomic impacts during construction in communities near an existing power plant site could range from MODERATE to LARGE.
An estimated 94 workers would be required during power plant operations (Exelon 2014a).
Local communities would experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for housing and public as well as commercial services. The amount of property tax payments under the NGCC alternative may also increase if additional land is required to support this alternative.
This alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS and a corresponding reduction in purchasing activity and revenue contributions to the regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region. The impact of the job loss, however, may not be noticeable in local communities given the amount of time required for decommissioning the existing LSCS facilities. Based on this information and given the number of operations workers, socioeconomic impacts during NGCC power plant operations on local communities could range from SMALL to MODERATE.
4.10.5.2    Transportation Transportation impacts associated with construction and operation of a three-unit, NGCC power plant would consist of commuting workers and truck deliveries of construction materials to the power plant site. During periods of peak construction activity, up to 1,783 workers could be commuting daily to the construction site. Workers commuting to the construction site would arrive via site access roads, and the volume of traffic on nearby roads could increase substantially during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thus increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Pipeline construction and modification of existing natural gas pipeline systems could also have a temporary impact. Materials also could be delivered by barge or rail, depending on location.
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Environmental Consequences and Mitigating Actions Traffic-related transportation impacts during construction would likely range from MODERATE to LARGE.
Traffic-related transportation impacts would be greatly reduced after completing the installation of the NGCC alternative. Transportation impacts would include daily commuting by the operating workforce, equipment and materials deliveries, and the removal of commercial waste material to offsite disposal or recycling facilities by truck. The operations workforce of 94 workers would likely not be noticeable relative to total traffic volumes on local roadways.
Since fuel is transported by pipeline, the transportation infrastructure would experience little to no increased traffic from plant operations. Overall, given the relatively small operations workforce estimate of 94 workers, transportation impacts would be SMALL during power plant operations.
4.10.6    Combination Alternative (NGCC, Wind, Solar) 4.10.6.1    Socioeconomics As explained in Section 4.10.3, two types of jobs would be created by this alternative:
(1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of the NGCC, wind, and solar generation components of this combination alternative were evaluated to estimate their possible effects on current socioeconomic conditions.
Fewer workers would be required to construct the single NGCC unit at the LSCS site than the full-power NGCC alternative. Installation of an estimated 3,376 wind turbines would likely be done in stages and could require up to 931 construction workers (NREL 2013). Additional workers would be required to install solar PV systems on existing buildings or structures at already-developed residential, commercial, or industrial sites. Similar to the wind farms, installation would likely be done in stages and could require up to 600 construction workers (DOE 2010b).
Conversely, a small number of operations workers would be needed to operate the single NGCC unit and additional small numbers of workers would be required to maintain the wind farms and PV systems. Local communities could experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for housing and public as well as commercial services. The amount of property tax payments under the wind and solar PV components may also increase if additional land is required to support this combination alternative.
This combination alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS, and a corresponding reduction in purchasing activity, tax payments, and revenue contributions would occur in the surrounding regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave),
and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region.
The impact of the job loss, however, may not be noticeable in local communities, given the amount of time required for decommissioning of the existing LSCS facilities. Based on this information and given the relatively small numbers of construction and operations workers, socioeconomic impacts during construction and operations on local communities would be SMALL.
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Environmental Consequences and Mitigating Actions 4.10.6.2    Transportation Transportation impacts during the construction and operation of the NGCC unit as well as the wind and solar components of this combination alternative would be less than the impacts for any of the previous alternatives discussed. This is because the construction workforce for each component and the volume of materials and equipment needing to be transported to the respective construction site would be smaller than for any one of the individual replacement power alternatives. In other words, the transportation impacts would not be concentrated as in the other alternatives but spread out over a wider area.
Workers commuting to the construction site would arrive via site access roads, and the volume of traffic on nearby roads could increase during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Transporting heavy and oversized components on local roads could have a noticeable impact over a large area. Some components and materials could also be delivered by rail or barge, depending on location. Traffic-related transportation impacts during construction could range from SMALL at the LSCS site and SMALL to MODERATE at the wind farms and solar installations; depending on current road capacities and average daily traffic volumes.
During operations, transportation impacts would be less noticeable during shift changes and maintenance activities. Given the small numbers of operations workers, the levels of service traffic impacts on local roads from NGCC, wind farm, and solar PV operations would be SMALL.
4.10.7    Purchased Power Alternative 4.10.7.1    Socioeconomics Purchased power from existing power generating facilities would not have any socioeconomic impact, because there would be no change in power plant operations or workforce. If the amount of purchased power exceeds the available supply, new electrical power generating facilities would be needed. Construction and operation of a new electrical power generating facility to supply purchased power could cause noticeable socioeconomic impacts in the communities located near the new facility. The intensity of the impact would depend on the number of workers required to build and operate the new electrical power generating facility and the amount of increased demand for housing and public services.
Whether or not there would be a socioeconomic impact would depend on whether a new electrical power generating facility was needed to supply purchased power. If a new power generating facility is needed, socioeconomic impacts would range anywhere from SMALL to LARGE.
4.10.7.2    Transportation Similarly, purchased power from existing power generating facilities would also not have any transportation impact, because there would be no change in power plant operations or workforce. If necessary, construction and operation of a new electrical power generating facility could cause noticeable transportation impacts, depending on the number of workers and truck deliveries required to build and operate the new electrical power generating facility.
Consequently, traffic volumes could increase noticeably on local roads near the new power plant site during shift changes.
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Environmental Consequences and Mitigating Actions Whether or not there would be a transportation impact would depend on whether a new electrical power generating facility were needed to supply purchased power. If a new power generating facility is needed, transportation impacts would range anywhere from SMALL to LARGE.
4.11        Human Health This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on human health resources.
4.11.1      Proposed Action Section 3.11 describes the human health resources associated with LSCS. Table 4-12 identifies the human health resource issues applicable to LSCS during the license renewal term.
Table 4-12. Human Health Issues Issue                                                                                    GEIS Section        Category Radiation exposures to the public                                                          4.9.1.1.1              1 Radiation exposures to plant workers                                                        4.9.1.1.1              1 Human health impact from chemicals                                                          4.9.1.1.2              1 Microbiological hazards to the public (plants with cooling ponds or                        4.9.1.1.3              2 canals or cooling towers that discharge to a river)
Microbiological hazards to plant workers                                                    4.9.1.1.3              1 Chronic effects of electromagnetic fields      (EMFs)(a)                                  4.9.1.1.4            N/A(b)
Physical occupational hazards                                                              4.9.1.1.5              1 Electric shock    hazards(a)                                                                4.9.1.1.5              2 (a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid.
(b) N/A (not applicable) The categorization and impact finding definition does not apply to this issue.
Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 4.11.1.1        Normal Operating Conditions Generic Human Health Issues (Category 1)
The NRC staff did not identify any new and significant information during its review of Exelons ER (Exelon 2014a), the site audit, or the scoping process for the Category 1 issues listed in Table 4-12. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. For these Category 1 issues, the GEIS concluded that the impacts are SMALL.
Chronic Effects of Electromagnetic Fields (EMFs)
In the GEIS (NRC 2013d), the chronic effects of 60-Hz electromagnetic fields (EMFs) from power lines were not designated as Category 1 or 2 and will not be until a scientific consensus is reached on the health implications of these fields.
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Environmental Consequences and Mitigating Actions The potential for chronic effects from these fields continues to be studied and is not known at this time. The National Institute of Environmental Health Sciences (NIEHS) directs related research through DOE.
The report by NIEHS (NIEHS 1999) contains the following conclusion:
The NIEHS concludes that ELF-EMF (extremely low frequency-electromagnetic field) exposure cannot be recognized as entirely safe because of weak scientific evidence that exposure may pose a leukemia hazard. In our opinion, this finding is insufficient to warrant aggressive regulatory concern. However, because virtually everyone in the United States uses electricity and therefore is routinely exposed to ELF-EMF, passive regulatory action is warranted such as continued emphasis on educating both the public and the regulated community on means aimed at reducing exposures. The NIEHS does not believe that other cancers or non-cancer health outcomes provide sufficient evidence of a risk to currently warrant concern.
This statement is not sufficient to cause the NRC staff to change its position with respect to the chronic effects of EMFs. The NRC staff considers the GEIS finding of UNCERTAIN still appropriate and will continue to follow developments on this issue.
Site-Specific Human Health Issues (Category 2)
Microbiological Hazards to the Public In the GEIS (NRC 2013d), the NRC staff determined that effects of thermophilic microorganisms on the public for plants using cooling ponds, lakes, or canals or cooling towers that discharge to a river is a Category 2 issue (see Table 4-12) that requires site-specific evaluation during each license renewal review.
In order to determine whether the continued operations of LSCS could promote increased growth of thermophilic microorganisms and thus have an adverse effect on the public, the NRC staff considered several factors: the thermophilic microorganisms of concern, LSCSs thermal effluent characteristics, Exelons chlorination procedures, recreational use of the LSCS cooling pond and the Illinois River, and input from the Illinois Environmental Protection Agency (IEPA) and Illinois Department of Public Health (IDPH).
Section 3.11.3 describes the thermophilic microorganisms that the GEIS identified to be of potential concern at nuclear power plants and summarizes data from the Centers for Disease Control and Prevention (CDC) on the prevalence of waterborne diseases associated with these microorganisms that have been linked to recreational water from 2002 through 2011. CDC data indicate that no outbreaks or cases of waterborne Salmonella or Pseudomonas aeruginosa infection from recreational waters have occurred in the United States during this time frame.
Shigella and Naegleria fowleri infections linked to exposure in recreational waters were rarely reported, and none of the reported cases occurred in Illinois. Public exposure to aerosolized Legionella from nuclear plant operations is generally not a concern because such exposure would be confined to a small area of the site to which the public would not have access. In the case of LSCS, which does not have cooling towers, exposure of workers to Legionella is unlikely. Based on the information presented in Section 3.11.3, the thermophilic organisms most likely to be of potential concern at Illinois are Shigella and N. fowleri.
LSCSs circulating water system and two service water systems discharge heated water to the sites artificial cooling pond through a discharge canal. LSCS also continuously discharges blowdown to the Illinois River, and this discharge is subject to the limitations set forth in the sites NPDES permit (IEPA 2013). The permit limits blowdown discharges to the river (Outfall 001) to a maximum rate of 45 gallons per minute (gpm) (0.17 m3 per minute (m3/min)),
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Environmental Consequences and Mitigating Actions as further described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Sections 3.1.3 and 3.5.1 describe the cooling system and surface water characteristics, respectively.
The temperature in the cooling pond is generally below the optimal growth temperature of both Shigella and N. fowleri (95 to 106 &deg;F (35 to 41 &deg;C)). From 2001 through 2014, there have been a few periods during summer months that the temperatures in the cooling pond exceeded 95 &deg;F (35 &deg;C) (Exelon 2015b). Although these temperatures could reasonably enhance survival or growth of Shigella and N. fowleri, the short duration and periodicity of these temperatures are unlikely to have produced a measurable effect on the Shigella and N. fowleri population, if present in the pond.
For blowdown to the Illinois River, Special Condition 3 of the NPDES permit limits the maximum temperature rise above ambient conditions and maximum water temperatures at Outfall 001.
This condition stipulates that, at the edge of the thermal mixing zone, discharges from Outfall 001 shall not cause the Illinois River water to rise above natural temperatures by more than 2.8 &deg;C (5 &deg;F). The temperature beyond the mixing zone cannot exceed specified monthly limits for longer than 1 percent (i.e., 87.[[estimated NRC review hours::6 hours]]) of any 12-month period and cannot at any time exceed the specified monthly limit by more than 1.7 &deg;C (3 &deg;F). During the months of April through November, the calculated temperature outside the mixing zone cannot exceed 93 &deg;F (34 &deg;C). These limits are consistent with Title 35, Environmental Protection, Section 302, Water Quality Standards, of the IAC, which stipulates that, for thermal effluents, the maximum temperature rise shall not exceed 2.8 &deg;C (5 &deg;F) above natural receiving water body temperatures and that the water temperature at representative locations in the main river shall at no time exceed 33.7 &deg;C (93 &deg;F) from April through November and 17.7 &deg;C (63 &deg;F) in other months (35 IAC 302.211). These temperature limits in the NPDES permits are below the optimal growth temperature for both Shigella and N. fowleri, and thus, would not enhance the growth or survival of these thermophilic organisms, if present in Illinois River water.
In addition to temperature limitations, the IAC prohibits the area and volume of thermal mixing from being more than 25 percent of the cross-sectional area or volume of stream flow (35 IAC 302.102). The NRC (1978) determined that LSCSs thermal mixing zone meets the IACs criteria: the surface area of the thermal mixing zone was estimated to be 2,500 m2 (27,000 ft2) in March to 400 m2 (4,300 ft2) in July, which would cover approximately 8 to 9 percent of the river. Thus, the IACs thermal mixing limitations effectively minimize the area and volume over which microorganisms could experience enhanced growth or survival in the Illinois River near the LSCS discharge.
Chlorine is an effective disinfectant for water containing the microorganisms of concern. The EPA (1999a) reports that chlorination at concentrations of 1 to 2 milligrams per liter (mg/L) in water at a pH of 6.0 to 8.0 can effectively eliminate health hazards caused by bacteria, including Shigella. The CDC (CDC 2013) reports that chlorine at a concentration of 1 part per million ((ppm) (1 mg/L)) added to 77 &deg;F (25 &deg;C) clear water at a pH of 7.5 will reduce the number of viable N. fowleri trophozoites by 99.99 percent in 12 minutes.
Exelon treats water entering the circulating water system and service water systems with sodium hypochlorite to control biofouling (Exelon 2014a). Water discharged to the Illinois River may not contain more than an instantaneous maximum concentration of 0.2 mg/L of residual chlorine or 0.05 mg/L of residual oxides, as measured at Outfall 001, per Special Condition 4 of the NPDES permit (IEPA 2013). Chlorination of the system is likely to prevent some increased growth and survival of microorganisms that might otherwise result from operation of LSCS.
Both the cooling pond and the Illinois River are used for recreational purposes. The cooling pond is part of the LaSalle Lake State Fish and Wildlife Area, which Exelon and the IDNR jointly manage. It is generally open to the public from mid-March until mid-October (Exelon 2014a).
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Environmental Consequences and Mitigating Actions Portions of the cooling pond within the exclusion zone, which includes the essential cooling pond, are off limits to the public (Exelon 2014a). Swimming, wading, water skiing, and use of non-motorized boats are prohibited at LaSalle Lake (IDNR 2015b), which further reduces the potential for human exposure to the microorganisms of concern, if present in the cooling pond.
As discussed above, LSCSs thermal mixing zone in the Illinois River is relatively small (0.1 ha (0.22 ac)), and the temperature limitations set forth in the NPDES permit are lower than those that would promote increased growth or survival of thermophilic microorganisms. In accordance with the IAC, the discharge is not located near any public access areas because thermal mixing is prohibited in water adjacent to bathing beaches, bank fishing areas, boat ramps or dockages or any other public access area (35 IAC 302.102(b)(3)). Given the small area of thermally altered waters and the unlikelihood of the water to create conditions favorable to thermophilic microorganisms, exposure of recreational Illinois River users to elevated concentrations of the microorganisms of concern is unlikely.
The environmental standard review plan for license renewal directs the NRC staff to consult with the State public health department regarding concerns about the potential for waterborne disease outbreaks associated with license renewal. In response to RAIs, Exelon (2015b) included copies of correspondence between Exelon and IDPH and IEPA regarding this issue.
Exelon requested information from IEPA and IDPH on the potential increase in adverse effects on public health from exposure to N. fowleri or any other thermophilic pathogen in the Illinois River. In response, IEPA and IDPH each indicated that its staff does not have the expertise necessary to adequately evaluate Exelons assessment (IEPA 2014; IDPH 2014). Accordingly, the NRC staff did not separately contact the IDPH or IEPA during its license renewal review.
Conclusion The thermophilic microorganisms Shigella and N. fowleri have been linked to waterborne outbreaks in recreational waters within the United States. However, based on these microorganisms temperature tolerances, Shigella and N. fowleri are unlikely to be present in the vicinity of LSCS. Additionally, Exelons chlorination procedures and the small thermal mixing zones in the cooling pond and Illinois River make exposure of recreational water users to elevated levels of these microorganisms unlikely. The NRC staff concludes that the impacts of thermophilic microorganisms on the public are SMALL for LSCS license renewal.
Electric Shock Hazards Based on the GEIS, the Commission found that electric shock resulting from direct access to energized conductors or from induced charges in metallic structures has not been found to be a problem at most operating plants and generally is not expected to be a problem during the license renewal term. However, a site-specific review is required to determine the significance of the electric shock potential along the portions of the transmission lines that are within the scope of this SEIS.
As discussed in Section 3.11.4, there are no offsite transmission lines that are in scope for this SEIS. Therefore, there are no potential impacts to members of the public.
As discussed in Section 3.11.5, LSCS maintains an occupational safety program in accordance with the Occupational Safety and Health Administration regulations for its workers, which includes protection from acute electric shock. Therefore, the NRC staff concludes that the potential impacts from acute electric shock during the license renewal term would be SMALL.
4.11.1.2    Environmental Impacts of Postulated Accidents This section describes the environmental impacts from postulated accidents that LSCS might experience during the period of extended operation. The term accident refers to any 4-75
 
Environmental Consequences and Mitigating Actions unintentional event outside the normal plant operational envelope that results in a release or the potential for release of radioactive materials into the environment. The two classes of postulated accidents listed in Table 4-13 are contained in Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 and are evaluated in detail in the GEIS. These two classes of accidents are design-basis accidents (DBAs) and severe accidents.
Table 4-13. Issues Related to Postulated Accidents Issue                                                            GEIS Section        Category DBAs                                                                  4.9.1.2              1 Severe accidents                                                      4.9.1.2              2 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 Design-Basis Accidents In order to receive NRC approval to operate a nuclear power facility, an applicant for an initial operating license must submit a Safety Analysis Report (SAR) as part of its application. The SAR presents the design criteria and design information for the proposed reactor and comprehensive data on the proposed site. The SAR also discusses various hypothetical accident situations and the safety features that are provided to prevent and mitigate accidents.
The NRC staff reviews the application to determine whether the plant design meets the Commissions regulations and requirements and includes, in part, the nuclear plant design and its anticipated response to an accident.
Design-basis accidents are those accidents that both the applicant and the NRC staff evaluate to ensure that the plant can withstand normal and abnormal transients and a broad spectrum of postulated accidents, without undue hazard to the health and safety of the public. Many of these postulated accidents are not expected to occur during the life of the plant but are evaluated to establish the design basis for the preventive and mitigative safety systems of the nuclear power plant. Parts 50 and 100 of 10 CFR describe the acceptance criteria for DBAs.
The environmental impacts of DBAs are evaluated during the initial licensing process, and the ability of the plant to withstand these accidents is demonstrated to be acceptable before issuance of the operating license. The results of these evaluations are found in license documentation such as the applicants Final Safety Analysis Report, the safety evaluation report, the final environmental statement (FES), and Section 4.11 of this SEIS. A licensee is required to maintain the acceptable design and performance criteria throughout the life of the plant, including any extended-life operation. The consequences for these events are evaluated for the hypothetical maximum exposed individual; as such, changes in the plant environment will not affect these evaluations. Because of the requirements that continuous acceptability of the consequences and aging management programs be in effect for the period of extended operation, the environmental impacts as calculated for DBAs should not differ significantly from initial licensing assessments over the life of the plant, including the period of extended operation. Accordingly, the design of the plant relative to DBAs during the period of extended operation is considered to remain acceptable, and the environmental impacts of those accidents were not examined further in the GEIS.
The Commission has generically determined that the environmental impacts of DBAs are of SMALL significance for all plants because the plants were designed to successfully withstand these accidents. Therefore, for the purposes of license renewal, DBAs are designated as a Category 1 issue. The early resolution of the DBAs makes them a part of the current licensing 4-76
 
Environmental Consequences and Mitigating Actions basis of the plant; the current licensing basis of the plant is to be maintained by the licensee under its current license and, therefore, under the provisions of 10 CFR 54.30, is not subject to review under license renewal.
No new and significant information related to DBAs was identified during the review of the LSCS ER (Exelon 2014a), the site audit, the scoping process, or evaluation of other available information. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS.
Severe Accidents Severe nuclear accidents are those that are more severe than DBAs because they could result in substantial damage to the reactor core, whether or not there are serious offsite consequences. In the GEIS, the NRC staff assessed the effects of severe accidents during the period of extended operation, using the results of existing analyses and site-specific information to conservatively predict the environmental impacts of severe accidents for each plant during the period of extended operation.
Severe accidents initiated by external phenomena such as tornadoes, floods, earthquakes, fires, and sabotage have not traditionally been discussed in quantitative terms in FESs and were not specifically considered for the LSCS site in the GEIS (NRC 1996). However, the GEIS did evaluate existing impact assessments performed by the NRC and by the industry at 44 nuclear plants in the United States and concluded that the risk from beyond-design-basis earthquakes at existing nuclear power plants is SMALL. The GEIS for license renewal performed a discretionary analysis of terrorist acts in connection with license renewal and concluded that the core damage and radiological release from such acts would be no worse than the damage and release expected from internally initiated events. In the GEIS, the Commission concludes that the risk from sabotage and beyond-design-basis earthquakes at existing nuclear power plants is small and, additionally, that the risks from other external events are adequately addressed by a generic consideration of internally initiated severe accidents (NRC 1996, 2013a).
Based on information in the GEIS, the staff found the following to be true:
The probability weighted consequences of atmospheric releases, fallout onto open bodies of water, releases to ground water, and societal and economic impacts from severe accidents are small for all plants. However, alternatives to mitigate severe accidents must be considered for all plants that have not considered such alternatives.
The NRC staff identified no new and significant information related to postulated accidents during the review of Exelons ER for LSCS (Exelon 2014a), the site audit, the scoping process, or evaluation of other available information. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. However, in accordance with 10 CFR 51.53(c)(3)(ii)(L), the staff has reviewed severe accident mitigation alternatives (SAMAs) for LSCS.
Severe Accident Mitigation Alternatives If the NRC staff has not previously evaluated SAMAs for the applicants plant in an environmental impact statement or related supplement or in an environmental assessment, 10 CFR Part 51.53(c)(3)(ii)(L) requires license renewal applicants to consider alternatives to mitigate severe accidents. The purpose of this consideration is to ensure that plant changes (i.e., hardware, procedures, and training) with the potential for improving severe accident safety performance are identified and evaluated. Pursuant to 10 CFR Part 54, the only changes that the applicant must implement as part of the license renewal process are those that are identified 4-77
 
Environmental Consequences and Mitigating Actions as being cost beneficial, that provide a significant reduction in total risk, and that are related to adequately managing the effects of aging during the period of extended operation.
Overview of SAMA Process This section presents a summary of the SAMA evaluation for LSCS, as described in the ER (Exelon 2014a), additional requested information (Exelon 2015h), and the NRC staffs review of those evaluations. The NRC staff performed its review with contract assistance from the Center for Nuclear Waste Regulatory Analyses. Appendix F to this SEIS provides the NRC staffs detailed review, and Appendix F to Exelons ER provides Exelons LSCS SAMA evaluation.
The SAMA evaluation for LSCS conducted by Exelon contained the following four main components:
(1)  Exelon quantified the level of risk associated with potential reactor accidents using the plant-specific probabilistic risk assessment (PRA) and other risk models.
(2)  Exelon examined the major risk contributors and identified possible ways (SAMAs) of reducing that risk. Common ways of reducing risk are changes to components, systems, procedures, and training.
(3)  Exelon estimated how much each SAMA could reduce risk. Referred to as potential benefits of implementing each SAMA, those estimates were developed in terms of dollars in accordance with NRC guidance for performing regulatory analyses. The costs of implementing the candidate SAMAs were also estimated.
Sensitivity analyses were performed by Exelon to quantify effects on the SAMA evaluation.
(4)  Exelon compared the cost and benefit of each remaining SAMA to determine whether it was cost beneficial (the benefits of the SAMA exceeded its cost).
Estimate of Risk Exelon submitted an assessment of SAMAs for LSCS in Appendix F of the ER (Exelon 2014a).
The assessment was based on the most recent LSCS PRA available at that time, a plant-specific offsite consequence analysis performed using the MELCOR Accident Consequence Code System (MACCS2) Version 1.13.1 computer code, and insights from the combined individual plant examination (IPE) and individual plant examination of external events (IPEEE) for LSCS (Commonwealth Edison Company (CECO) 1994).
Exelon combined two distinct analyses to form the basis for estimating risk in the SAMA analysis: (1) LSCS Level 1 and Level 2 PRA models and (2) a supplemental analysis of offsite consequences and economic impacts (essentially a Level 3 PRA model) developed specifically for the SAMA analysis. The Level 1 model is a significant upgrade and revision to the IPE Level 1 model, whereas the Level 2 model is an update of the prior large early release frequency (LERF) models. The SAMA analysis is based on the most recent LSCS Level 1 and 2 PRA models available at the time of the ER, referred to as the LSCS PRA 2013A (or LS213A) model. This LSCS PRA includes internal floods but does not include external events.
The LSCS core damage frequency (CDF) is approximately 2.6x106 per year (Exelon 2014a).
Exelon did not explicitly include the contribution from external events within the LSCS SAMA risk estimates; however, it did account for the potential risk reduction benefits associated with external events by multiplying the estimated benefits for internal events by a factor of 5.2.
Section F.2.2.2 of Appendix F discusses this issue further. Using the calculated risk reduction as a quantitative measure of the potential benefit from SAMA implementation, Exelon performed a cost-benefit comparison with estimated implementation costs for each SAMA.
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Environmental Consequences and Mitigating Actions The breakdown of CDF by initiating event is provided in Table 4-14. As shown in this table, events initiated by a turbine trip with bypass, a dual unit loss of offsite power, a loss of instrument air, and a loss of condenser vacuum are the dominant contributors to the CDF.
Exelon found that station blackout contributes 6.4x107 per year, or 25 percent of the total CDF for internal events, whereas anticipated transients without scram (ATWS) contribute 4.9x107 per year, or approximately 19 percent of the total CDF for each unit (Exelon 2015h).
Exelon stated the following:
The expansion of the LERF model to a full Level 2 model involved a reassessment of the timing and release categorization of each containment event tree (CET) endstate. To perform this reassessment, MAAP [Modular Accident Analysis Program] calculations for each accident class were performed and used to assess the CET endstates. Each CET node was evaluated and updated to reflect the current state of knowledge regarding Level 2 accident phenomenology. The endstate timing was also updated to reflect the current emergency plan and evacuation time estimates.
The Level 2 model uses three general CET types to assess the accident progression during a core damage event. CETs contain both phenomenological and containment system status events. Level 1 core damage sequences are binned into plant damage states or accident classes, which provide the interface between the Level 1 and Level 2 CET analysis. Each accident class bin is entered into the CET, resulting in 15 LSCS-specific CETs. The CET is linked directly to the Level 1 event trees, and CET nodes are evaluated using supporting fault trees (Exelon 2015h).
Table 4-14. LSCS CDF for Internal Events Initiating Event                                                CDF(a) (per year)      Percent CDF Contribution Turbine Trip with Bypass                                            5.6x107                        22 Dual Unit Loss of Offsite Power                                      3.1x107                        12 Loss of Instrument Air                                              2.8x107                        11 Loss of Condenser Vacuum                                            2.7x107                        10 Fire Protection System Pipe Rupture in Reactor                      1.9x107                          7 Building Main Steam Isolation Valve Closure                                  1.4x107                          5 Loss of Turbine Building Component Cooling Water                    1.2x107                          5 Loss of Feedwater                                                    1.1x108                          4 Loss of Offsite Power                                                7.2x108                          3 Manual Shutdown                                                      5.9x108                          2 Inadvertently Open Relief Valve                                      5.9x108                          2 Loss of 125-V Direct-Current Bus 2A                                  5.1x108                          2 Loss of 125-V Direct-Current Buses 2A and 2B                        3.9x108                          2 Other Initiating Events(b)                                          3.3x107                        13 Total (Internal Events)(c)                                          2.58x106                        100 (a) CDF is based on Fussell-Vesely importance and total CDF.
(b) For Other Initiating Events, each event would contribute less than 2 percent to the total CDF.
(c) Column totals may be different because of rounding.
Key: CDF = core damage frequency, and V = volt(s).
Source: Exelon 2014a 4-79
 
Environmental Consequences and Mitigating Actions The result of the Level 2 PRA is a set of 13 release bins or categories with their respective frequency and release characteristics. The results of this analysis for LSCS are provided in Tables F.2-5, F.2-6, F.3-15, F.3-16, and F.3-19 of the ER (Exelon 2014a). The categories were defined based on the timing of release (three release time ranges) and the magnitude of release (four release magnitude ranges). One additional release category was included for an intact containment.
For use in the SAMA analysis, the release category for high magnitude and early timing was divided into two bins (one with containment isolation and one without such isolation). Due to the small release category contributions from six categories, the number of release category bins was reduced to eight cases. The frequency of each release category was obtained by summing the frequency of the individual accident progression CET endpoints binned into the release category. Source terms were developed for each of the 13 release categories using the results of MAAP Version 4.0.5 computer code calculations (Exelon 2014a).
Exelon computed offsite consequences for potential releases of radiological material using the MACCS2 Version 1.13.1 code and analyzed exposure and economic impacts from its determination of offsite and onsite risks. Inputs for these analyses include plant-specific and site-specific input values for core radionuclide inventory, source term and release characteristics, site meteorological data, projected population distribution and growth within a 50-mi (80-km) radius, emergency response evacuation modeling, and economic data. The estimation of onsite impacts (in terms of cleanup costs, decontamination costs, and occupational dose) is based on guidance in NUREG/BR-0184, Regulatory Analysis Technical Evaluation Handbook (NRC 1997). In its calculation for replacement power costs, Exelon accounted for the increased electric power output of LSCS compared to the generic reactor power output presented in NUREG/BR-0184 (NRC 1997).
In the ER, as updated by Exelons response to RAIs from the NRC staff (Exelon 2015h), Exelon estimated the dose risk to be 0.0764 person-sievert (Sv) per year (7.64 person-rem per year) to the population within 50 mi (80 km) of the LSCS site. The offsite economic cost risk was calculated to be $57,700 per year. Table 4-15 summarizes the breakdown of the population dose risk by containment release mode. The medium-magnitude intermediate release category accounted for 52 and 62 percent of the population dose risk and offsite economic cost risk, respectively. Additionally, two categories (1) medium-magnitude early release and (2) high-magnitude early release for breaks outside containment) together accounted for approximately 41 and 31 percent of the population dose risk and offsite economic cost risk, respectively.
The NRC staff has reviewed Exelons data and evaluation methods and concludes that the quality of the risk analyses is adequate to support an assessment of the risk reduction potential for candidate SAMAs. Accordingly, the staff based its assessment of offsite risk on the CDFs and offsite doses reported by Exelon.
Potential Plant Improvements Exelon considered potential plant improvements (SAMAs) that addressed the major contributors to CDF and release frequency at LSCS and considered SAMA candidates from six other boiling water reactor (BWR) plants, as follows:
(1)    Susquehanna Steam Electric Station; (2)    Cooper Nuclear Station; (3)    Duane Arnold Energy Center; (4)    Nine Mile Point, Unit 2; 4-80
 
Environmental Consequences and Mitigating Actions (5)    Columbia Generating Station; and (6)    Grand Gulf Nuclear Station.
Exelon identified potential plant improvements by reviewing the following:
* LSCS PRA results and PRA group insights;
* Potentially cost-effective Phase 2 SAMAs from the following:
            -  Susquehanna Steam Electric Station SAMA analysis;
            -  Cooper Nuclear Station SAMA analysis;
            -  Duane Arnold Energy Center SAMA analysis;
            -  Nine Mile Point, Unit 2, SAMA analysis;
            -  Columbia Generating Station SAMA analysis; and
            -  Grand Gulf Nuclear Station SAMA analysis;
* LSCS IPE; and
* LSCS IPEEE.
Table 4-15. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk for Internal Events Release Mode                  Population Dose Risk(a)    Offsite Economic Cost Risk Frequency ID(b)        (per year)      person-rem/yr    % Contribution    $/yr    % Contribution H/E-BOC(c)          8.3x108            1.3x100            18        7.2x103          13 H/E                  6.0x108          3.2x101            4        2.8x103          5 H/I(d)              1.9x108          1.1x101            1        9.7x102          2 M/E                  2.4x107            1.7x100            23        1.0x104          18 M/I(d)              1.0x106            3.9x100            52        3.6x104          62 L/E                  3.9x107          8.7x102            1        1.3x102          0.2 L/I(d)              1.5x107          1.1x101            1        1.8x102          0.3 CI                  6.2x107          1.4x103          <0.1        1x100        <0.1 Total                2.6x106            7.6x100          100        5.8x104        100 4-81
 
Environmental Consequences and Mitigating Actions Release Mode                        Population Dose Risk(a)              Offsite Economic Cost Risk (a) Unit Conversion Factor: 1 Sv = 100 rem.
(b) Release  Mode Nomenclature (Magnitude/Timing)
Magnitude:
High (H)greater than 10-percent release fraction for cesium iodide Medium (M)1- to 10-percent release fraction for cesium iodide Low (L)0.1- to 1-percent release fraction for cesium iodide Low-Low (LL)less than 0.1-percent release fraction for cesium iodide Containment intact (CI)much less than 0.1-percent release fraction for cesium iodide Timing:
Early (/E)less than [[estimated NRC review hours::5 hours]] Intermediate (/I)5 to [[estimated NRC review hours::24 hours]] Late (/L)greater than [[estimated NRC review hours::24 hours]] (c) These are contributions from initiators with breaks outside containment (BOC).
(d) The release categories for late timing were negligible and subsumed into the intermediate release categories for H, M, and L releases. Categories for LL magnitude releases were negligible and subsumed into the L release category with intermediate timing.
Sources: Exelon 2014a, 2015h Exelon indicated that, in addition to the Industry Phase 2 SAMA review identified above, an industry-based SAMA list in Nuclear Energy Institute (NEI) 05-01, Severe Accident Mitigation Alternative (SAMA) Analysis Guidance Document, issued November 2005 (NEI 2005), was used to help identify the types of changes that could be used to address the areas of concern identified through the LSCS importance list review.
Based on this review, Exelon identified an initial set of 26 SAMA candidates, referred to as Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the initial list of SAMAs and eliminated SAMAs from further consideration using the following criteria:
Applicability to the Plant. If a proposed SAMA does not apply to the LSCS design or has already been implemented, it is not retained.
Implementation Cost Greater Than the Screening Cost. If the estimated cost of implementation is greater than the maximum averted cost risk, the SAMA is screened out from further analysis.
During this process, two SAMA candidates were screened out based on the excessive cost criterion. Table F.6-1 of the ER (Exelon 2014a) provides a description of each of the 24 Phase II SAMA candidates, which was later changed3 to 25 Phase II SAMA candidates in Exelons revised analysis (Exelon 2015h).
In Phase II, a detailed evaluation was performed for each remaining SAMA candidate, as discussed in Sections F.4 and F.6 of Appendix F. To account for the potential impact of external events, the estimated benefits based on internal events were multiplied by a factor of 5.2, as discussed in Section F.2.2.2 of Appendix F.
3  The results of a sensitivity analysis to determine the impact of a correction to the Level 2 model resulted in the retention of one of the Phase I SAMAs (SAMA 26), which was originally screened out.
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Environmental Consequences and Mitigating Actions Evaluation of Risk Reduction and Costs of Improvements Exelon evaluated the risk-reduction potential of the 25 SAMAs retained for the Phase II evaluation in a revised analysis (Exelon 2015h). The SAMA evaluations were generally performed by Exelon in a realistic or slightly conservative fashion that overestimates the benefit of the SAMA. In most cases, the failure likelihood of the added equipment is taken to be optimistically low, thereby overestimating the benefit of the SAMA. Other cases assumed that the SAMA eliminated all the risk associated with the proposed enhancement. The NRC staff notes that this bounding approach overestimates the benefit and is conservative.
Exelon used model requantification to determine the potential benefits for each of the SAMAs.
The CDFs, population dose reductions, and offsite economic cost reductions were estimated using the LSCS PRA model. The changes made to the model to quantify the impact of each SAMA are described in Section F.6 of the ER. Table 4-16 summarizes the assumptions used to estimate the risk reduction for each evaluated SAMA, the estimated risk reduction in terms of CDF percent reduction, population dose, offsite economic cost, and the estimated total benefit (present value) of the averted risk. The determination of the benefits for the various SAMAs is further discussed in Section F.6 of Appendix F.
The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction estimate of each SAMA, as described in the Section F.6 of the ER. The resolution of RAIs that resulted from this review is discussed in Section F.4 of Appendix F. The determination of the benefits for the various SAMAs is further discussed in Section F.6 of Appendix F.
Exelon estimated the costs of implementing the 25 Phase II SAMAs through the use of other licensees estimates for similar improvements and the development of site-specific cost estimates, where appropriate. SAMA cost estimates were based on initial hardware, installation, and implementation costs. In response to an NRC staff RAI to provide further information as to what was included in the LSCS cost estimates, Exelon explained that maintenance and testing costs during the license renewal period were conservatively not included in the estimate (Exelon 2015h).
The NRC staff reviewed the applicants cost estimates presented in Section F.6 of the ER (Exelon 2014a). For certain improvements, the NRC staff also compared the cost estimates to estimates developed elsewhere for similar improvements, including estimates developed as part of other licensees analyses of SAMAs for operating reactors.
The NRC staff noted that a few SAMAs (e.g., SAMAs 8, 14, and 27) involve use of equipment that may be available as a result of the B.5.b program. In response to an NRC staff RAI to discuss this further, Exelon responded that the B.5.b program at LSCS includes a small generator that is used to support two individual safety relief valve (SRV) solenoids to hold the SRVs open after 125-V direct-current (DC) battery depletion, but the generator does not power the station battery chargers, and it is not designed to support the reactor core isolation cooling (RCIC) system through DC feeds. Because of these limitations, the B.5.b generator is not a viable substitute for the generators that have been proposed for SAMAs 8, 14, and 27; therefore, the availability of the B.5.b generator would not reduce the implementation costs for these SAMAs. With the above clarifications, the NRC staff concludes that the cost estimates provided by Exelon are sufficient and appropriate for use in the SAMA evaluation.
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1                                            Table 4-16. LSCS Potentially Cost-Beneficial SAMAs(a)
                                                                                      % Risk Reduction(b)            Total Benefit ($)(c)
Baseline with Individual SAMA and Assumptions                                                                            Baseline                    Cost ($)(c)
Population                          Uncertainty CDF                    OECR      (Internal +
Dose                                  (95th External)
Percentile) 2AUTOMATE SUPPRESSION POOL COOLING                                      14          20            25      1.4M          3.1M          400K SAMA 2 Modeling: The fault tree incorporated the automation of suppression pool cooling alignment by changing the independent basic event IDs for suppression pool cooling initiation to alternate IDs. This accomplishes two functions: (1) assignment of alternate failure probabilities that are representative of an automated function and (2) prevention of the recovery logic from identifying suppression pool cooling initiation failures as human actions and preclusion of the suppression pool cooling initiation failures from dependent human error combinations.
3INSTALL PASSIVE VENT PATH                                              36          51            61      1.0M          2.2M              1.0M SAMA 3 Modeling: The basic event for the operator action for venting was replaced with a new placeholder event with a value of      1x106, which prevents the creation of dependent operator actions, including the vent action. The hardware failures associated with the vent path valves have been retained to approximate the potential failures of the rupture disk (with the support system dependencies removed).
4INSTALL A KEYLOCK MSIV LOW-LEVEL ISOLATION 16          12        10      674K          1.4M          635K 4-84  BYPASS SWITCH SAMA 4 Modeling: The independent human error probability to bypass the main steam isolation valve low-level isolation interlock was set to Environmental Consequences and Mitigating Actions 1x105, and the joint human error probabilities that include this action have been eliminated.
5AUTOMATE SBLC INITIATION                                                8            7            6        386K          827K          400K SAMA 5 Modeling: The automatic SBLC initiation capability is modeled by manipulation of associated basic events. Early SBLC initiation basic event ID (2SLOP-LVLCTRLH--) was changed to SAMA5 and set to a probability of 1x106 to reduce the independent failure contribution to a small value and to prevent the inclusion of dependent operator action combinations with SBLC initiation failures, consistent with the automated action.
8OBTAIN A 480-V AC PORTABLE GENERATOR TO SUPPLY THE 125-V DC BATTERY CHARGERS AND DEVELOP                                  4            4            4        259K          554K          400K PROCEDURES FOR ITS USE SAMA 8 Modeling: The 480-V AC generator capability has been approximated by adding the diesel fire pump as a low-pressure injection source for station blackout scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480-V AC power source that feeds the Division 1 battery chargers.
9DEVELOP FLOOD ZONE-SPECIFIC PROCEDURES                                  9            3            3      224K        479K          115K SAMA 9 Modeling: Initiating event frequencies for flooding events were set to zero in the cutsets.
 
                                                                                    % Risk Reduction(b)            Total Benefit ($)(c)
Baseline with Individual SAMA and Assumptions                                                                          Baseline                    Cost ($)(c)
Population                          Uncertainty CDF                    OECR    (Internal +
Dose                                (95th External)
Percentile) 10CHANGE THE LOGIC TO CLOSE THE TURBINE DRIVEN FEEDWATER PUMP DISCHARGE VALVES WHEN THE PUMPS                              9        21          23          1.3M          2.8M        260K ARE NOT RUNNING SAMA 10 Modeling: The human failure event associated with closing the turbine-driven feedwater pump discharge valves was changed to a new event with a failure probability of 1x104. This treatment reduces the independent contribution of the isolation failure and precludes the generation of dependent human error combination, including the operator action to isolate the valves.
14PROVIDE A PORTABLE DC SOURCE TO SUPPORT RCIC 9          7            7          444K          949K        489K AND SRV OPERATION SAMA 14 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low-pressure injection source for station blackout scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480-V AC power source that feeds the Division 1 battery chargers.
15TIE RHRSW TO THE LPCS SYSTEM FOR ISLOCA 37        57          57          3.4M          7.2M        1.4M MITIGATION 4-85  SAMA 15 Modeling: Changes were made to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system).
ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the cross-tie. The cross-tie logic was added at the sequence level for BOC and ISLOCA sequences for which credit was not previously taken for any low-pressure injection systems, and was added to the existing fault tree structure in scenarios for which venting or containment failure resulted in the loss of injection systems.
16PROVIDE PORTABLE FANS FOR ALTERNATE ROOM 14          12            15      866K          1.9M          475K COOLING IN THE CSCS VAULTS SAMA 16 Modeling: The alternate CSCS room cooling capability was approximated by deleting the gates associated with room cooling failures (excluding the automatic initiation failures, which are already addressed in the model).
18IMPROVE THE CONNECTION BETWEEN THE FIRE 9          9        10      609K        1.3M          649K PROTECTION AND FEEDWATER SYSTEMS SAMA 18 Modeling: The fault tree was updated to credit the FPS in places for which LPCI and LPCS are credited, but the system is failed for the LOCA and IORV initiating event and for water hammer scenarios. In addition, the logic was changed to include the FPS injection capability in the early station blackout scenarios in which the ADS is available for those sequences not impacted by the LPCS-LPCI gate.
19PROVIDE REMOTE ALIGNMENT CAPABILITY OF RHRSW 38          58        58      3.4M        7.3M          2.9M TO THE LPCS SYSTEM FOR LOCA MITIGATION Environmental Consequences and Mitigating Actions
 
                                                                                              % Risk Reduction(b)  Total Benefit ($)(c)
Baseline with Individual SAMA and Assumptions                                                                            Baseline                      Cost ($)(c)
Population                            Uncertainty CDF                      OECR (Internal +
Dose                                  (95th External)
Percentile)
SAMA 19 Modeling: The inclusion of the RHRSW-LPCS cross-tie required changes to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event for failure to align the cross-tie. Cross-tie logic was added at the sequence level for BOC and ISLOCA sequences for which credit was not previously taken for any low-pressure injection systems and was added to the existing fault tree structure in scenarios in which venting or containment failure resulted in the loss of injection systems.
21INSTALL AUTOMATIC ATWS LEVEL CONTROL SYSTEM                                    14            14          12          754K            1.6M            1.5M SAMA 21 Modeling: The SAMA is modeled by setting the early and late level control actions to zero in the fault tree.
23ENHANCE THE FUEL POOL EMERGENCY MAKEUP PUMP 27          46            52          3.0M            6.5M            1.4M AND CONNECTION SAMA 23 Modeling: The inclusion of the fuel pool emergency makeup pump cross-tie required changes to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the residual heat removal B injection path (existing logic from the LPCI system). The 4-86  logic was added to the existing fault tree structure in scenarios in which venting or containment failure resulted in the loss of injection systems.
(a) Potentiallycost-beneficial SAMAs relate to LSCS, Unit 1 and Unit 2.
Environmental Consequences and Mitigating Actions (b) Risk reduction percentages displayed in this table were obtained from the ER (Exelon, 2014) before Exelons revised results (Exelon 2015h). Risk reduction percentages for the revised benefit results were not provided.
(c) Exelon identified potentially cost-beneficial SAMAs by comparing the total benefit with uncertainty at the 95th percentile to the estimated implementation cost.
Total benefit and cost values presented in this table were obtained from Exelons revised results (Exelon 2015h).
Key: AC = alternating current, ADS = automatic depressurization system, ATWS = anticipated transients without scram, BOC = break outside containment, CDF = core damage frequency, CSCS = core standby cooling system, DC = direct current, ECCS = emergency core cooling system, FPS = fire protection system, ID = identification, IORV = inadvertent/stuck open relief valve, ISLOCA = interfacing-systems loss-of-coolant accident, LPCI = low-pressure coolant injection, LPCS = low-pressure core spray, LOCA = loss-of-coolant accident, MSIV = main steam isolation valve, OECR = offsite economic cost risk, RCIC = reactor core isolation cooling, RHRSW = residual heat removal service water, SAMA = severe accident mitigation alternative, SBLC = standby liquid control, and SRV = safety relief valve.
Sources: Exelon 2014a, 2015h 1
 
Environmental Consequences and Mitigating Actions 1 Cost-Benefit Comparison 2 If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 3 was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 4 SAMA candidate was considered to be potentially cost beneficial. Table 4-16 presents the 5 results of the cost-benefit evaluation. Exelons cost-benefit analysis identified 14 SAMA 6 candidates determined to be potentially cost beneficial at the 95th percentile on an individual 7 basis, as follows:
8
* SAMA 2: Automate suppression pool cooling.
9
* SAMA 3: Install passive vent path.
10
* SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level isolation 11              bypass switch.
12
* SAMA 5: Automate SBLC initiation.
13
* SAMA 8: Obtain a 480-V AC portable generator to supply the 125-V DC battery 14              chargers and develop procedures for its use.
15
* SAMA 9: Develop flood zone-specific procedures.
16
* SAMA 10: Change the logic to close the turbine-driven feedwater pump discharge 17              valves when the pumps are not running.
18
* SAMA 14: Provide a portable DC source to support RCIC and SRV operation.
19
* SAMA 15: Tie RHRSW to the LPCS system for ISLOCA mitigation.
20
* SAMA 16: Provide portable fans for alternate room cooling in the core standby 21              cooling system vaults.
22
* SAMA 18: Improve the connection between the fire protection and 23              feedwater systems.
24
* SAMA 19: Provide remote alignment capability of RHRSW to the LPCS system for 25              LOCA mitigation.
26
* SAMA 21: Install automatic ATWS level control system.
27
* SAMA 23: Enhance the fuel pool emergency makeup pump and connection.
28 When the planned installation of a hardened vent pipe is considered as the base case, the 29 number of SAMA candidates considered to be potentially cost beneficial at the 95th percentile 30 may be reduced. Because a new baseline is established following the implementation of a 31 SAMA, which further influences the benefits provided by the remaining SAMA candidates, 32 Exelon defined an optimal set to containing SAMAs that, if implemented, would render the 33 remaining SAMAs to be not cost beneficial. Acknowledging Exelons commitment to install the 34 hardened vent pipe (SAMA 1), additional modifications included in the optimal set are 35 SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a). Assessment of the optimal set 36 was performed before Exelon generated revised results in response to the NRC staffs RAIs 37 (Exelon 2015h). Because Exelon did not take a priori credit for installation of the hardened vent 38 pipe, revision to the optimal set assessment was not required. Exelon is referring the 39 14 potentially cost-beneficial SAMAs from its revised analysis (Exelon 2015h) to the LSCS Plant 40 Health Committee for further implementation considerations within the established plant 41 procedural process, as indicated in Section 4.15 of the ER (Exelon 2014a).
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Environmental Consequences and Mitigating Actions 1 Conclusions 2 Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 3 updated probabilistic safety assessment models, SAMA-related industry documentation, 4 plant-specific enhancements, and its review of SAMA candidates from potential improvements 5 primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 6 SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 7 been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 8 costs and benefits associated with each of the 25 potential SAMAs. Exelon concluded that 9 14 SAMA candidates were potentially cost beneficial at the 95th percentile (shown in 10 Table 4-16). Exelon has decided to proceed with the modification to install a hardened vent 11 pipe regardless of cost even though it is not cost beneficial. From a sensitivity analysis, no 12 additional SAMA candidates were identified as potentially cost beneficial. Because the 13 potentially cost-beneficial SAMAs do not relate to aging management during the period of 14 extended operation, their implementation is not required as part of license renewal pursuant to 15 10 CFR Part 54. Nevertheless, as stated in Section 4.15 of the ER (Exelon 2014a), Exelon 16 indicated that the potentially cost-beneficial SAMAs are being referred to the LSCS Plant Health 17 Committee for further implementation considerations within the established plant procedural 18 process.
19 The NRC staff reviewed Exelons SAMA analysis and concludes that, based on the discussion 20 in Appendix F of this document, the methods used and implementation of those methods were 21 sound. On the basis of the applicants treatment of SAMA benefits and costs, the NRC staff 22 finds that the SAMA evaluations performed by Exelon are reasonable and are sufficient for the 23 license renewal submittal. The NRC staff concurs with Exelons conclusion that 14 SAMA 24 candidates are potentially cost beneficial for LSCS and notes that Exelons assessment was 25 based on generally conservative treatment of costs, benefits, and uncertainties. Based on the 26 NRC staffs review of Exelons SAMA evaluations, including Exelons response to the NRC 27 staffs RAIs, the NRC staff concludes that Exelon has adequately identified areas in which risk 28 can be further reduced in a cost-beneficial manner through the implementation of the identified 29 potentially cost-beneficial SAMAs. Given the potential for cost-beneficial risk reduction, the 30 NRC staff agrees that further evaluation by Exelon of the 14 SAMA candidates identified by 31 Exelon as being potentially cost beneficial is warranted.
32 The NRC staff also evaluated whether the identified potentially cost-beneficial SAMAs are 33 subject to aging management. The evaluation considered any structures, systems, and 34 components associated with these SAMAs that perform intended functions without moving parts 35 or without a change in configuration or properties and that would not be subject to replacement 36 based on a qualified life or specified time period. The NRC staff determined that the potentially 37 cost-beneficial SAMAs do not relate to adequately managing the effects of aging during the 38 period of extended operation. Therefore, they do not need to be implemented as part of license 39 renewal in accordance with 10 CFR Part 54.
40 4.11.2    No-Action Alternative 41 Human health risks would be smaller following plant shutdown. The two reactor units, which are 42 currently operating within regulatory limits, would emit less gaseous, liquid, and solid radioactive 43 material to the environment. In addition, following shutdown, the variety of potential accidents at 44 the plant (radiological or industrial) would be reduced to a limited set associated with shutdown 45 events and fuel handling and storage. In Section 4.11.1, the NRC staff concluded that the 46 impacts of continued plant operation on human health would be SMALL, except for chronic 47 effects of electromagnetic fields (EMFs), for which the impacts are UNCERTAIN. In 48 Section 4.11.1.2, the NRC staff concluded that the impacts of accidents during operation were 4-88
 
Environmental Consequences and Mitigating Actions 1 SMALL. Therefore, as radioactive emissions to the environment decrease, and as the likelihood 2 and types of accidents decrease following shutdown, the NRC staff concludes that the risk to 3 human health following plant shutdown would be SMALL.
4 4.11.3    New Nuclear Alternative 5 Impacts on human health from construction of two new nuclear units would be similar to impacts 6 associated with the construction of any major industrial facility. Compliance with worker 7 protection rules would control those impacts on workers at acceptable levels. Impacts from 8 construction on the general public would be minimal, since limiting active construction area 9 access to authorized individuals is expected. Impacts on human health from the construction of 10 two new nuclear units would be SMALL.
11 The human health effects from the operation of two new nuclear units would be similar to those 12 of operating the two existing LSCS units. As presented in Section 4.11.1, impacts on human 13 health from the operation of LSCS would be SMALL, except for chronic effects of 14 electromagnetic fields (EMFs), for which the impacts are UNCERTAIN. Therefore, the impacts 15 on human health from the operation of two new nuclear units would be SMALL.
16 4.11.4    IGCC Alternative 17 Impacts from construction on workers are expected to be similar to those experienced during 18 construction of any major industrial facility. Impacts from construction of an IGCC facility are 19 expected to be the same as those for construction of fossil fuel facilities. Construction would 20 increase traffic on local roads, which could affect the health of the general public. Human health 21 impacts would be the same for all facilities, whether located on greenfield sites or at an existing 22 power plant. Personal protective equipment, training, and engineered barriers would protect the 23 workforce (NRC 2013d). Therefore, the impacts on human health from the construction of an 24 IGCC facility would be SMALL.
25 The IGCC alternative introduces worker risks from coal and limestone mining, worker and public 26 risk from coal and lime/limestone transportation, worker and public risk from disposal of 27 coal-combustion waste, and public risk from inhalation of stack emissions. In addition, human 28 health risks are associated with the management and disposal of coal combustion waste. Coal 29 combustion generates waste in the form of ash, and equipment for controlling air pollution 30 captures additional ash and produces scrubber sludge, which must be managed as coal 31 combustion waste. Human health risks may extend beyond the facility workforce to the public, 32 depending on their proximity to the coal combustion waste storage and/or disposal facility. The 33 character and the constituents of coal combustion waste depend on both the chemical 34 composition of the source coal and the technology used to combust it. Generally, the primary 35 sources of adverse consequences from coal combustion waste are from exposure to sulfur 36 oxide and nitrogen oxide in air emissions and radioactive elements, such as uranium and 37 thorium, as well as the heavy metals and hydrocarbon compounds contained in fly ash and 38 bottom ash, and scrubber sludge (NRC 2013d).
39 Regulatory agencies, including EPA and state agencies, base air emission standards and 40 requirements on human health impacts. These agencies also impose site-specific emission 41 limits as needed to protect human health. Given the regulatory oversight exercised by EPA and 42 state agencies, the NRC staff concludes that the human health impacts from radiological doses 43 and inhaled toxins and particulates generated from the IGCC alternative would be SMALL 44 (NRC 2013d).
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Environmental Consequences and Mitigating Actions 1 4.11.5    NGCC Alternative 2 Impacts on human health from construction of the NGCC alternative would be similar to effects 3 associated with the construction of any major industrial facility. Compliance with worker 4 protection rules would control those impacts on workers at acceptable levels. Impacts from 5 construction on the general public would be minimal, since crews would limit active construction 6 area access to authorized individuals. Based on the above, the NRC staff concludes that the 7 impacts on human health from the construction of the NGCC alternative would be SMALL.
8 Impacts from the operation of an NGCC facility include public risk from inhalation of gaseous 9 emissions. The risk may be attributable to nitrogen oxide emissions that contribute to ozone 10 formation, which in turn contribute to health risk. Regulatory agencies, including the EPA and 11 state agencies, base air emission standards and requirements on human health impacts.
12 These agencies also impose site-specific emission limits as needed to protect human health.
13 Given the regulatory oversight exercised by EPA and state agencies, the NRC staff concludes 14 that the human health impacts from the NGCC alternative would be SMALL.
15 4.11.6    Combination Alternative (NGCC, Wind, Solar) 16 Impacts on human health from construction of a combination of NGCC, wind, and solar 17 alternative would be similar to effects associated with the construction of any major industrial 18 facility. Compliance with worker protection rules and personal protective equipment, training, 19 and engineered barriers would protect the workforce (NRC 2013d). Impacts from construction 20 on the general public would be minimal, since crews would limit active construction area access 21 to authorized individuals. Based on the above, the NRC staff concludes that the Impacts on 22 human health from the construction of the NGCC, wind, and solar alternative would be SMALL.
23 Operational hazards at an NGCC facility are discussed in Section 4.11.5.
24 Operational hazards at a wind facility for the workforce include working at heights, near rotating 25 mechanical or electrically energized equipment, and in extreme weather. Potential impacts to 26 workers and the public include ice thrown from rotor blades and broken blades thrown as a 27 result of mechanical failure. Potential impacts also include EMF exposure, aviation safety 28 (hazards), and exposure to noise and vibration from the rotating blades.
29 Operational hazards at a solar PV facility may involve exposure to airborne toxic metals 30 (e.g., cadmium) and silicon if the PV cell loses its integrity from a fire. Workers could also inhale 31 silicon dust if a PV cell were smashed by an object or from a fall to the ground. However, based 32 on worker and environmental protection rules, it is expected that remediation of toxic material 33 would occur. Such remediation would minimize the impact to workers and the environment.
34 Therefore, given the expected compliance with worker and environmental protection rules and 35 the use of personal protective equipment, training, and engineered barriers, the NRC staff 36 concludes that the potential human health impacts would be SMALL.
37 4.11.7    Purchased Power Alternative 38 Purchased power is expected to come from the types of electricity generation available within 39 the ROI: coal, natural gas, nuclear, and wind. The human health impacts from the operation of 40 these types of power plants are discussed in Sections 4.11.3, 4.11.4, 4.11.5, and 4.11.6. Based 41 on the information in those sections, the NRC staff concludes that the human health impacts of 42 the purchased power alternative using nuclear, coal, natural gas, wind, and solar would be 43 SMALL.
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Environmental Consequences and Mitigating Actions 1 4.12    Environmental Justice 2 This section describes the potential human health and environmental effects of the proposed 3 action (license renewal) and alternatives to the proposed action on minority and low-income 4 populations.
5 4.12.1    Proposed Action 6 Section 3.12 identifies minority and low-income populations living in the vicinity of LSCS.
7 Table 4-17 identifies the environmental justice issue applicable to LSCS during the license 8 renewal term.
9                          Table 4-17. Environmental Justice NEPA Issue Issue                                                                GEIS Section      Category Minority and low-income populations                                    4.10.1            2 Source: Table B-1 in Appendix B, Subpart A of 10 CFR Part 51 10 The NRC addresses environmental justice matters for license renewal by (1) identifying the 11 location of minority and low-income populations that may be affected by the continued operation 12 of the nuclear power plant during the license renewal term, (2) determining whether there would 13 be any potential human health or environmental effects to these populations and special 14 pathway receptors, and (3) determining if any of the effects may be disproportionately high and 15 adverse. Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal 16 adverse impacts on human health. Disproportionately high and adverse human health effects 17 occur when the risk or rate of exposure to an environmental hazard for a minority or low-income 18 population is significant and exceeds the risk or exposure rate for the general population or for 19 another appropriate comparison group. Disproportionately high environmental effects refer to 20 impacts or risks of impacts on the natural or physical environment in a minority or low-income 21 community that are significant and appreciably exceed the environmental impact on the larger 22 community. Such effects may include biological, cultural, economic, or social impacts.
23 Figures 3-17 and 3-18 show the location of predominantly minority and low-income population 24 block groups residing within a 50-mi (80-km) radius of LSCS. This area of impact is consistent 25 with the impact analysis for public and occupational health and safety, which also focuses on 26 populations within a 50-mi (80-km) radius of the plant. Chapter 4 presents the assessment of 27 environmental and human health impacts for each resource area. The analyses of impacts for 28 all environmental resource areas indicated that the impact from license renewal would be 29 SMALL.
30 Potential impacts on minority and low-income populations (including migrant workers or Native 31 Americans) would mostly consist of socioeconomic and radiological effects; however, radiation 32 doses from continued operations during the license renewal term are expected to continue at 33 current levels, and they would remain within regulatory limits. Section 4.11.1.2 of this SEIS 34 discusses the environmental impacts from postulated accidents that might occur during the 35 license renewal term, which include both design basis and severe accidents. In both cases, the 36 Commission has generically determined that impacts associated with DBAs are small because 37 nuclear plants are designed and operated to successfully withstand such accidents, and the 38 probability-weighted consequences of severe accidents are small.
39 Therefore, based on this information and the analysis of human health and environmental 40 impacts presented in Chapter 4 of this SEIS, there would be no disproportionately high and 4-91
 
Environmental Consequences and Mitigating Actions 1 adverse human health and environmental effects on minority and low-income populations from 2 the continued operation of LSCS during the license renewal term.
3 As part of addressing environmental justice concerns associated with license renewal, the NRC 4 staff also assessed the potential radiological risk to special population groups (such as migrant 5 workers or Native Americans) from exposure to radioactive material received through their 6 unique consumption practices and interaction with the environment, including subsistence 7 consumption of fish and wildlife, native vegetation, surface waters, sediments, and local 8 produce; absorption of contaminants in sediments through the skin; and inhalation of airborne 9 radioactive material released from the plant during routine operation. This analysis is presented 10 below.
11 Subsistence Consumption of Fish and Wildlife 12 The special pathway receptors analysis is an important part of the environmental justice 13 analysis because consumption patterns may reflect the traditional or cultural practices of 14 minority and low-income populations in the area, such as migrant workers or Native Americans.
15 Section 4-4 of Executive Order 12898 (1994) directs Federal agencies, whenever practical and 16 appropriate, to collect and analyze information about the consumption patterns of populations 17 that rely principally on fish and/or wildlife for subsistence and to communicate the risks of these 18 consumption patterns to the public. In this SEIS, the NRC considered whether there were any 19 means for minority or low-income populations to be disproportionately affected by examining 20 impacts on American Indian, Hispanics, migrant workers, and other traditional lifestyle special 21 pathway receptors. The assessment of special pathways considered the levels of radiological 22 and nonradiological contaminants in vegetation, crops, soils and sediments, groundwater, 23 surface water, fish, and game animals on or near LSCS.
24 Radionuclides released to the atmosphere may deposit on soil and vegetation and, therefore, 25 may eventually be incorporated into the human food chain. To assess the impact of LSCS 26 operations to humans from the ingestion pathway, samples of fish, milk, green leafy vegetables, 27 surface water, sediment, and groundwater are collected and analyzed for radioactivity. The 28 following describes Exelons radiological environmental monitoring program (REMP).
29 Exelon has an ongoing comprehensive REMP to assess the impact of LSCS operations on the 30 environment. To assess the impact of nuclear power plant operations, samples are collected 31 annually from the environment and analyzed for radioactivity. A plant effect would be indicated 32 if the radioactive material detected in a sample were larger or higher than background levels.
33 Two types of samples are collected. The first type, a control sample, is collected from areas 34 that are beyond the influence of the nuclear power plant or any other nuclear facility. These 35 samples are used as reference data to determine normal background levels of radiation in the 36 environment. These samples are then compared with the second type of samples, indicator 37 samples, collected near the nuclear power plant. Indicator samples are collected from areas 38 where any contribution from the nuclear power plant will be at its highest concentration. These 39 samples are then used to evaluate the contribution of nuclear power plant operations to 40 radiation or radioactivity levels in the environment. An effect would be indicated if the 41 radioactivity levels detected in an indicator sample were larger or higher than the control sample 42 or background levels.
43 Samples were collected from the aquatic and terrestrial environment in the vicinity of LSCS in 44 2014. The aquatic environment includes groundwater, surface water, fish, and river sediment.
45 Aquatic monitoring results for 2014 of water, sediment, and fish showed only naturally occurring 46 radioactivity and radioactivity associated with fallout from past atmospheric nuclear weapons 47 testing and were consistent with levels measured prior to the operation of LSCS. No 4-92
 
Environmental Consequences and Mitigating Actions 1 radioactivity was detected greater than the minimum detectable activity in any aquatic sample 2 during 2014, and no adverse long-term trends were identified in aquatic monitoring data 3 (Exelon 2015a).
4 The terrestrial environment includes airborne particulates, milk, and food products (i.e., beets, 5 kohlrabi, potatoes, Swiss chard, and kale). However, cow milk samples were not analyzed in 6 2014, as the dairy herd was sold prior to the first sample in 2014 (Exelon 2015a). Terrestrial 7 monitoring results for 2014 of groundwater and leafy garden vegetable samples, showed only 8 naturally occurring radioactivity. The radioactivity levels detected were consistent with levels 9 measured prior to the operation of LSCS. No radioactivity was detected greater than the 10 minimum detectable activity in any terrestrial samples during 2014. The terrestrial monitoring 11 data also showed no adverse trends in the terrestrial environment (Exelon 2015a).
12 Analyses performed on 1,393 samples collected from the environment at LSCS in 2014 showed 13 no significant measurable radiological constituent above background levels. Overall, 14 radioactivity levels detected in 2014 were consistent with previous levels, as well as radioactivity 15 levels measured prior to the operation of LSCS. REMP sampling in 2014 did not identify any 16 radioactivity above the minimum detectable activity (Exelon 2015a).
17 Based on the radiological environmental monitoring data from LSCS, the NRC staff finds that no 18 disproportionately high and adverse human health impacts would be expected in special 19 pathway receptor populations in the region as a result of subsistence consumption of water, 20 local food, fish, and wildlife. Continued operation of LSCS would not have disproportionately 21 high and adverse human health and environmental effects on these populations.
22 4.12.2    No-Action Alternative 23 This section evaluates the potential for disproportionately high and adverse human health and 24 environmental effects on minority and low-income populations that could result from the 25 no-action alternative. Impacts on minority and low-income populations would depend on the 26 number of jobs and the amount of tax revenues lost by communities in the immediate vicinity of 27 the power plant after LSCS ceases operations. Not renewing the operating licenses and 28 terminating reactor operations would have a noticeable impact on socioeconomic conditions in 29 the communities located near LSCS. The loss of jobs and income would have an immediate 30 socioeconomic impact. Some, but not all, of the approximately 890 employees would begin to 31 leave after reactor operations are terminated; and overall tax revenue generated by plant 32 operations would be reduced. The reduction in tax revenue would decrease the availability of 33 public services in LaSalle County. This could disproportionately affect minority and low-income 34 populations that may have become dependent on these services. See also Appendix J of 35 NUREG-0586, Supplement 1 (NRC 2002), for additional discussion of these impacts.
36 4.12.3    New Nuclear Alternative 37 This section evaluates the potential for disproportionately high and adverse human health and 38 environmental effects on minority and low-income populations that could result from the 39 construction and operation of a new nuclear power plant. Some of these potential effects have 40 been identified in resource areas discussed in this SEIS. For example, increased demand for 41 rental housing during replacement power plant construction could disproportionately affect 42 low-income populations. Everyone living near the proposed power plant site could be affected 43 by the construction and operation of a new nuclear power plant, including minority and 44 low-income populations.
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Environmental Consequences and Mitigating Actions 1 Potential impacts to minority and low-income populations from the construction and operation of 2 a new nuclear power plant at an existing nuclear power plant or retired coal plant site would 3 mostly consist of environmental and socioeconomic effects (e.g., noise, dust, traffic, 4 employment, and housing impacts). Noise and dust impacts from construction would be short 5 term and primarily limited to onsite activities. Minority and low-income populations residing 6 along site access roads would be affected by increased commuter vehicle traffic during shift 7 changes and truck traffic. However, these effects would be temporary during certain hours of 8 the day and would not likely be high and adverse. Increased demand for rental housing during 9 construction could affect low-income populations. However, given the proximity of some 10 existing nuclear power plant or retired coal plant sites to metropolitan areas, construction 11 workers could commute to the site, thereby reducing the potential demand for rental housing.
12 Potential impacts to minority and low-income populations from new nuclear power plant 13 operations would mostly consist of radiological effects; however, radiation doses are expected 14 to be well below regulatory limits. All people living near the new nuclear power plant would be 15 exposed to the same potential effects from power plant operations, and permitted air emissions 16 are expected to remain within regulatory standards.
17 Based on this information and the analysis of human health and environmental impacts 18 presented in this SEIS, it is not likely that the construction and operation of a new nuclear power 19 plant would have disproportionately high and adverse human health and environmental effects 20 on minority and low-income populations. However, this determination would depend on the 21 location, plant design, and operational characteristics of the new power plant. Therefore, the 22 NRC staff cannot determine whether this alternative would result in disproportionately high and 23 adverse human health and environmental effects on minority and low-income populations.
24 4.12.4    IGCC Alternative 25 This section evaluates the potential for disproportionately high and adverse human health and 26 environmental effects on minority and low-income populations that could result from the 27 construction and operation of a new IGCC power plant. Some of these potential effects have 28 been identified in resource areas discussed in this SEIS. For example, increased demand for 29 rental housing during replacement power plant construction could disproportionately affect 30 low-income populations. Everyone living near the proposed power plant site could be affected 31 by the construction and operation of a new IGCC power plant, including minority and 32 low-income populations.
33 Potential impacts to minority and low-income populations from the construction and operation of 34 a new IGCC plant at the LSCS site or at another existing power plant site would consist of 35 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 36 impacts). Noise and dust impacts from construction would be short term and primarily limited to 37 onsite activities. Minority and low-income populations residing along site access roads would 38 be affected by increased commuter vehicle traffic during shift changes and truck traffic.
39 However, these effects would be temporary during certain hours of the day and would not likely 40 be high and adverse. Increased demand for rental housing during construction could affect 41 low-income populations. However, given the proximity of some existing power plant sites to 42 Chicago (LSCS site) and other metropolitan areas (at another existing power plant site),
43 construction workers could commute to the site, thereby reducing the potential demand for 44 rental housing.
45 Emissions from the IGCC plant during power plant operations could disproportionately affect 46 minority and low-income populations. However, permitted air emissions are expected to remain 47 within regulatory standards.
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Environmental Consequences and Mitigating Actions 1 Based on this information and the analysis of human health and environmental impacts 2 presented in this SEIS, it is not likely that the construction and operation of a new IGCC plant 3 would have disproportionately high and adverse human health and environmental effects on 4 minority and low-income populations. However, this determination would depend on the 5 location, plant design, and operational characteristics of the new power plant at the LSCS site or 6 at another existing power plant site. Therefore, the NRC staff cannot determine whether this 7 alternative would result in disproportionately high and adverse human health and environmental 8 effects on minority and low-income populations.
9 4.12.5    NGCC Alternative 10 This section evaluates the potential for disproportionately high and adverse human health and 11 environmental effects on minority and low-income populations that could result from the 12 construction and operation of a new NGCC plant. Some of these potential effects have been 13 identified in resource areas discussed in this SEIS. For example, increased demand for rental 14 housing during replacement power plant construction could disproportionately affect low-income 15 populations. Everyone living near the proposed power plant site could be affected by the 16 construction and operation of a new NGCC power plant, including minority and low-income 17 populations.
18 Potential impacts to minority and low-income populations from the construction and operation of 19 a new NGCC plant at the LSCS site would mostly consist of environmental and socioeconomic 20 effects (e.g., noise, dust, traffic, employment, and housing impacts). Noise and dust impacts 21 from construction would be short term and primarily limited to onsite activities. Minority and 22 low-income populations residing along site access roads would be affected by increased 23 commuter vehicle traffic during shift changes and truck traffic. However, these effects would be 24 temporary during certain hours of the day and would not likely be high and adverse. Increased 25 demand for rental housing during construction could affect low-income populations in the vicinity 26 of the LSCS site. However, given the proximity of LSCS to the Chicago metropolitan area, 27 many construction workers could commute to the site, thereby reducing the potential demand 28 for rental housing.
29 Emissions from the NGCC plant during power plant operations could disproportionately affect 30 minority and low-income populations living in the vicinity of the new power plant. However, 31 permitted air emissions are expected to remain within regulatory standards.
32 Based on this information and the analysis of human health and environmental impacts 33 presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant 34 would have disproportionately high and adverse human health and environmental effects on 35 minority and low-income populations. However, this determination would depend on the 36 location, plant design, and operational characteristics of the new power plant at LSCS.
37 Therefore, the NRC staff cannot determine whether this alternative would result in 38 disproportionately high and adverse human health and environmental effects on minority and 39 low-income populations.
40 4.12.6    Combination Alternative (NGCC, Wind, Solar) 41 This section evaluates the potential for disproportionately high and adverse human health and 42 environmental effects on minority and low-income populations that could result from the 43 construction and operation of a combination of NGCC, wind, and solar PV electrical power 44 generating activities. Some of these potential effects have been identified in resource areas 45 discussed in this SEIS. For example, increased demand for rental housing during construction 46 could disproportionately affect low-income populations. Everyone living near the new NGCC, 4-95
 
Environmental Consequences and Mitigating Actions 1 wind farms, and solar PV installations could be affected by construction activities and facility 2 operations, including minority and low-income populations.
3 Potential impacts to minority and low-income populations from the construction and operation of 4 a new NGCC plant, wind turbines, and solar PV installations would mostly consist of 5 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 6 impacts). Noise and dust impacts from construction would be short term and primarily limited to 7 onsite activities. Minority and low-income populations residing along site access roads would 8 be affected by increased commuter vehicle traffic during shift changes and truck traffic.
9 However, these effects would be temporary during certain hours of the day and would not likely 10 be high and adverse. Increased demand for rental housing during construction could affect 11 low-income populations. However, given the small number of construction workers and the 12 possibility that many workers could commute to these construction sites, the potential need for 13 rental housing would not be significant.
14 Minority and low-income populations living in close proximity to wind farm and solar PV power 15 generating installations could be disproportionately affected by maintenance and operations 16 activities. However, operational impacts from the wind turbines and solar PV installations would 17 mostly be limited to noise and aesthetic effects.
18 Based on this information and the analysis of human health and environmental impacts 19 presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant, 20 wind farms, and solar PV installations would have disproportionately high and adverse human 21 health and environmental effects on minority and low-income populations. However, this 22 determination would depend on the location, plant design, and operational characteristics of 23 these new power generating facilities. Therefore, the NRC staff cannot determine whether this 24 alternative would result in disproportionately high and adverse human health and environmental 25 effects on minority and low-income populations.
26 4.12.7    Purchased Power Alternative 27 This section evaluates the potential for disproportionately high and adverse human health and 28 environmental effects on minority and low-income populations that could result from purchasing 29 electric power. As previously discussed, such effects may include human health, biological, 30 cultural, economic, or social impacts.
31 Purchased power from existing power generating facilities would not likely have any 32 disproportionately high and adverse effects on minority populations, because there would be no 33 change in power plant operations or workforce. However, low-income populations could be 34 disproportionately affected by increased utility bills, due to the cost of purchased power, 35 although programs are available to assist low-income families in paying for increased electrical 36 costs.
37 If the amount of purchased power needed exceeds the available supply, new electric power 38 generating facilities would be needed. Construction and operation of a new electrical power 39 generating facility to supply purchased power could create new human health and 40 environmental effects in communities located near the new facility. Everyone living near the 41 new electric power generating facility could be affected by construction activities and facility 42 operations, including minority and low-income populations.
43 Potential human health and environmental effects from constructing and operating a new power 44 generating facility have been described in the previous sections. Operational impacts for all 45 new power generating facilities would mostly be limited to noise, air emissions, and aesthetic 46 effects. Minority and low income populations could experience disproportionate human health 4-96
 
Environmental Consequences and Mitigating Actions 1 and environmental effects from the emissions from fossil-fueled power plants (e.g., increased 2 asthma). However, any human health or environmental effects would depend on the location of 3 the new power plant in relation to minority and low-income communities and the magnitude of 4 the change in ambient air quality conditions. Also, permitted air emissions would be expected to 5 remain within regulatory standards.
6 Based on this information and the analysis of human health and environmental impacts 7 presented in this SEIS, it is not likely that purchasing electrical power from existing power 8 generating facilities would have disproportionately high and adverse human health and 9 environmental effects on minority and low-income populations. In addition, this determination 10 would depend on whether a new electrical power generating facility were needed to supply 11 purchased power. If a new power generating facility is needed, impacts to minority and 12 low-income populations would depend on the location, plant design, and operational 13 characteristics of these new power generating facilities. Therefore, the NRC staff cannot 14 determine whether this alternative would result in disproportionately high and adverse human 15 health and environmental effects on minority and low-income populations.
16 4.13      Waste Management 17 This section describes the potential impacts of the proposed action (license renewal) and 18 alternatives to the proposed action on waste management and pollution prevention.
19 4.13.1      Proposed Action 20 Section 3.12 describes LSCS waste management and pollution prevention. Table 4-18 21 identifies the waste management issues applicable to LSCS during the license renewal term.
22                                    Table 4-18. Waste Management Issues Issue                                                                                GEIS Section        Category Low-level waste storage and disposal                                                      4.11.1.1              1 Onsite storage of spent nuclear fuel                                                    4.11.1.2(a)            1 Offsite radiological impacts of spent nuclear fuel and high-level waste                  4.11.1.3(b)            1 disposal Mixed-waste storage and disposal                                                          4.11.1.4              1 Nonradioactive waste storage                                                              4.11.1.4              1 (a) The environmental impact of this issue for the time frame beyond the licensed life for reactor operations is contained in NUREG-2157 (NRC 2014).
(b) The environmental impact of this issue is contained in NUREG-2157 (NRC 2014).
Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 23 The NRC staffs evaluation of the environmental impacts associated with spent nuclear fuel is 24 addressed in two issues in Table 4-18, Onsite storage of spent nuclear fuel and Offsite 25 radiological impacts of spent nuclear fuel and high-level waste disposal. The issue of onsite 26 storage of spent nuclear fuel now incorporates the generic environmental impact determinations 27 codified in Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 and in the revised 28 10 CFR 51.23, pursuant to the Continued Storage Rule (79 FR 56238)4. The issue of offsite 4  79 FR 56238. U.S. Nuclear Regulatory Commission. Continued Storage of Spent Nuclear Fuel.
Federal Register 79 (182): 56238-56263. September 19, 2014.
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Environmental Consequences and Mitigating Actions 1 radiological impacts of spent nuclear fuel and high-level waste disposal are codified in 2 Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51, and the technical feasibility of disposal 3 in a geologic repository is discussed in NUREG-2157, Generic Environmental Impact 4 Statement for Continued Storage of Spent Nuclear Fuel, Volumes 1 and 2 (NRC 2014).
5 The NRC staff did not identify any new and significant information related to waste management 6 issues listed in Table 4-18 during its review of the applicants ER (Exelon 2014a), the site visit, 7 or the scoping process. Therefore, there are no impacts related to these issues beyond those 8 discussed in the GEIS (NRC 2013d) and NUREG-2157 (NRC 2014). During the license 9 renewal term, for these Category 1 issues discussed in the GEIS, the NRC staff concludes that 10 the impacts are SMALL.
11 4.13.2    No-Action Alternative 12 If the no-action alternative were implemented, LSCS would cease operation at the end of the 13 term of the initial operating licenses, or sooner, and enter decommissioning. The plants, which 14 are currently operating within regulatory limits, would generate less spent nuclear fuel and emit 15 less gaseous and liquid radioactive effluents into the environment. In addition, following 16 shutdown, the variety of potential accidents at the plants (radiological and industrial) would be 17 reduced to a limited set associated with shutdown events and fuel handling and storage. In 18 Section 4.14.2 of this SEIS, the NRC staff concludes that the impacts from decommissioning 19 would be SMALL. Therefore, as radioactive emissions to the environment decrease, and the 20 likelihood and variety of accidents decrease following shutdown and decommissioning, the NRC 21 staff concludes that impacts from implementation of the no-action alternative would be SMALL.
22 4.13.3    New Nuclear Alternative 23 Construction-related debris would be generated during construction activities and would be 24 recycled or disposed of in approved landfills.
25 During normal plant operations, routine plant maintenance, and cleaning activities would 26 generate radioactive low-level waste, spent nuclear fuel, and high-level waste, as well as 27 nonradioactive waste. Sections 3.1.4 and 3.1.5 discuss radioactive and nonradioactive waste 28 management at LSCS. Quantities of radioactive and nonradioactive waste generated by LSCS 29 would be comparable to that generated by the two new nuclear plants.
30 According to the GEIS (NRC 2013d), the generation and management of solid radioactive and 31 nonradioactive waste during the license renewal term are not expected to result in significant 32 environmental impacts.
33 Based on this information, the waste impacts would be SMALL for the new nuclear alternative.
34 4.13.4    IGCC Alternative 35 Construction-related debris would be generated during plant construction activities and would 36 be recycled or disposed of in approved landfills.
37 Coal combustion generates waste in the form of fly ash and bottom ash. In addition, equipment 38 for controlling air pollution generates additional ash, spent selective catalytic reduction (SCR) 39 catalyst, and scrubber sludge. The management and disposal of the large amounts of coal 40 combustion waste is a significant part of the operation of a coal-fired power generating facility.
41 Although an IGCC facility is likely to use offsite disposal of coal combustion waste, some 42 short-term storage of coal combustion waste (either in open piles or in surface impoundments) 4-98
 
Environmental Consequences and Mitigating Actions 1 is likely to take place on site, thus establishing the potential for leaching of toxic chemicals into 2 the local environment.
3 The impacts of managing the substantial amounts of solid waste, especially fly ash and 4 scrubber sludge, generated during operation of this alternative would be MODERATE 5 (NRC 1996). The amount of the construction waste would be small compared to the amount of 6 waste generated during the operational stage and much of it could be recycled (i.e., marketed 7 for beneficial use). Therefore, the NRC staff concludes that the overall waste management 8 impacts from construction of this alternative would be SMALL and from operation of this 9 alternative would be MODERATE.
10 4.13.5    NGCC Alternative 11 Construction-related debris would be generated during plant construction activities, and would 12 be recycled or disposed of in approved landfills.
13 Waste generation from NGCC technology would be minimal. The only significant waste 14 generated at an NGCC power plant would be spent SCR catalyst, which is used to control 15 nitrogen oxide emissions.
16 The spent catalyst would be regenerated or disposed of offsite. Other than the spent SCR 17 catalyst, waste generation at an operating natural-gas-fired plant would be limited largely to 18 typical operations and maintenance of nonhazardous waste. Overall, the NRC staff concludes 19 that waste impacts from the NGCC alternative would be SMALL.
20 4.13.6    Combination Alternative (NGCC, Wind, Solar) 21 Construction-related debris would be generated during construction activities and would be 22 recycled or disposed of in approved landfills.
23 Waste generation from NGCC technology is discussed in Section 4.13.5.
24 Waste generation from a combination of wind and solar PV alternatives would be minimal, 25 consisting of debris from routine maintenance and the disposal of worn or broken parts. Based 26 on this information, the NRC staff concludes that waste impacts from the construction and 27 operation of a combination wind and solar PV alternative would be SMALL.
28 4.13.7    Purchased Power Alternative 29 The types of waste generated by the alternative electricity generation sources (i.e., coal, natural 30 gas, nuclear, and wind) used in the purchased power alternative are discussed in 31 Sections 4.13.3, 4.13.4, 4.13.5, and 4.13.6. Depending on types of power generation plants 32 used to provide the electricity for the purchased power alternative, the NRC staff concludes that 33 the waste management impacts would range from SMALL to MODERATE.
34 4.14    Evaluation of New and Potentially Significant Information 35 New and significant information must be new based on a review of the GEIS (NRC 2013d) and 36 codified in Table B-1 of Appendix B to Subpart A of 10 CFR Part 51, and must bear on the 37 proposed action or its impacts, presenting a seriously different picture of the impacts from those 38 envisioned in the GEIS (i.e., impacts of greater severity than impacts considered in the GEIS, 39 considering their intensity and context).
40 In accordance with 10 CFR 51.53(c), the ER that the applicant submits must provide an analysis 41 of the Category 2 issues in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B. Additionally, 4-99
 
Environmental Consequences and Mitigating Actions 1 it must discuss actions to mitigate any adverse impacts associated with the proposed action and 2 environmental impacts of alternatives to the proposed action. In accordance with 3 10 CFR 51.53(c)(3), the ER does not need to contain an analysis of any Category 1 issue 4 unless there is new and significant information on a specific issue.
5 The NRC process for identifying new and significant information is described in NUREG-1555, 6 Supplement 1, Standard Review Plans for Environmental Reviews for Nuclear Power Plants, 7 Supplement 1: Operating License Renewal (NRC 2013f). The search for new information 8 includes:
9
* review of an applicants ER and the process for discovering and evaluating the 10            significance of new information; 11
* review of public comments; 12
* review of environmental quality standards and regulations; 13
* coordination with Federal, state, and local environmental protection and resource 14            agencies; and 15
* review of technical literature.
16 New information that the staff discovers is evaluated for significance using the criteria set forth 17 in the GEIS. For Category 1 issues in which new and significant information is identified, 18 reconsideration of the conclusions for those issues is limited in scope to assessment of the 19 relevant new and significant information; the scope of the assessment does not include other 20 facets of an issue that the new information does not affect.
21 The NRC staff reviewed the discussion of environmental impacts associated with operation 22 during the renewal term in the GElS and has conducted its own independent review, including a 23 public involvement process (e.g., public meetings) to identify new and significant issues for the 24 LSCS license renewal application environmental review. The NRC staff has not identified new 25 and significant information on environmental issues related to operation of LSCS during the 26 renewal term. The NRC staff also determined that information provided during the public 27 comment period did not identify any new issue that requires site-specific assessment.
28 The NRC staff did, however, find new, but not significant, information regarding the uranium fuel 29 cycle issue, and this information is discussed in Section 4.15.1 and Appendix G of this SEIS.
30 4.15    Impacts Common to All Alternatives 31 This section describes the impacts that are considered common to all alternatives discussed in 32 this SEIS, including the proposed action and replacement power alternatives. The continued 33 operation of a nuclear power plant and replacement fossil fuel power plants both involve the 34 mining, processing, and consumption of fuel, which results in comparative impacts 35 (NRC 2013d). In addition, the termination of operations and the decommissioning of both a 36 nuclear power plant and replacement fossil-fueled power plants, as well as GHG emissions, are 37 discussed in the following sections.
38 4.15.1    Fuel Cycles 39 This section describes the environmental impacts associated with the fuel cycles of the 40 proposed action and replacement power alternatives. Most replacement power alternatives 41 employ a set of steps in the utilization of their fuel sources, which can include extraction, 4-100
 
Environmental Consequences and Mitigating Actions 1 transformation, transportation, and combustion. Emissions generally occur at each stage of the 2 fuel cycle (NRC 2013d).
3 4.15.1.1      Uranium Fuel Cycle 4 The uranium fuel cycle issues applicable to LSCS are discussed below and listed in Table 4-19 5 for Category 1 issues. Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 contains more 6 information on these issues.
7                        Table 4-19. Issues Related to the Uranium Fuel Cycle Issue                                                                    GEIS Section      Category Offsite radiological impactsindividual impacts from other than the        4.12.1.1          1 disposal of spent fuel and high-level waste Offsite radiological impactscollective impacts from other than the        4.12.1.1          1 disposal of spent fuel and high-level waste Nonradiological impacts of the uranium fuel cycle                          4.12.1.1          1 Transportation                                                              4.12.1.1          1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 8 The uranium fuel cycle includes uranium mining and milling, production of uranium hexafluoride, 9 isotopic enrichment, fuel fabrication, reprocessing of irradiated fuel, transportation of radioactive 10 materials, and management of low-level wastes and high-level wastes related to uranium fuel 11 cycle activities. The generic potential impacts of the radiological and nonradiological 12 environmental impacts of the uranium fuel cycle and transportation of nuclear fuel and wastes 13 are described in detail in NUREG-1437 (NRC 2013d).
14 The NRC staff did not identify any new and significant information related to the uranium fuel 15 cycle issues Offsite radiological impactsindividual impacts from other than the disposal of 16 spent fuel and high level waste, Offsite radiological impactscollective impacts from other 17 than the disposal of spent fuel and high-level waste, and Nonradiological impacts of the 18 uranium fuel cycle, listed above in Table 4-19, during its review of the applicants ER 19 (Exelon 2014a), the site visit, and the scoping process. Therefore, there are no impacts related 20 to these issues beyond those discussed in the GEIS. For these Category 1 issues, the GEIS 21 concludes that the impacts are SMALL, except for the issue, Offsite radiological impacts 22 collective impacts, to which the NRC has not assigned an impact level. This issue assesses 23 the 100-year radiation dose to the U.S. population (i.e., collective effects or collective dose) from 24 radioactive effluent released as part of the uranium fuel cycle for a nuclear power plant during 25 the license renewal term compared to the radiation dose from natural background exposure. It 26 is a comparative assessment for which there is no regulatory standard to base an impact level.
27 The NRC staff did, however, find new information regarding the uranium fuel cycle issue 28 Transportation, listed above in Table 4-19, in its review of the applicants ER. The NRC has 29 generically determined, in its license renewal application reviews, that the environmental 30 impacts of the transportation of fuel and radioactive wastes to and from nuclear power facilities 31 are small for all reactors as long as certain specific conditions are met. The application for 32 license renewal of LSCS stated that the specific conditions that allow the transportation impacts 33 of spent fuel to be generically determined to be small may not be met for LSCS. Therefore, the 34 NRC staff analyzed the environmental impacts of transporting spent fuel from LSCS in 35 Appendix G of this SEIS. From this analysis, the NRC staff concludes that the environmental 36 impacts of the transportation of spent fuel from LSCS would be consistent with the 4-101
 
Environmental Consequences and Mitigating Actions 1 environmental impacts associated with the transportation of fuel and radioactive wastes to and 2 from current-generation reactors presented in Table S-4 of 10 CFR 51.52, and thus would be 3 SMALL.
4 4.15.1.2    Replacement Power Plant Fuel Cycles 5 Fossil Fuel Energy Alternatives 6 Fuel cycle impacts for a fossil-fuel-fired plant result from the initial extraction of fuel, cleaning 7 and processing of fuel, transport of fuel to the facility, and management and ultimate disposal of 8 solid wastes from fuel combustion. These impacts are discussed in more detail in 9 Section 4.12.1.2 of the GEIS (NRC 2013d) and can generally include:
10
* significant changes to land use and visual resources; 11
* impacts to air quality, including release of criteria pollutants, fugitive dust, VOCs, and 12              coalbed methane in the atmosphere; 13
* noise impacts; 14
* geology and soil impacts due to land disturbances and mining; 15
* water resource impacts, including degradation of surface water and groundwater 16              quality; 17
* ecological impacts, including loss of habitat and wildlife disturbances; 18
* historic and cultural resources impacts within the mine footprint; 19
* socioeconomic impacts from employment of both the mining workforce and service 20              and support industries; 21
* environmental justice impacts; 22
* health impacts to workers from exposure to airborne dust and methane gases; and 23
* generation of coal and industrial wastes.
24 New Nuclear Energy Alternatives 25 Uranium fuel cycle impacts for a nuclear plant result from the initial extraction of fuel, transport 26 of fuel to the facility, and management and ultimate disposal of spent fuel. The environmental 27 impacts of the uranium fuel cycle are discussed above in Section 4.15.1.1.
28 Renewable Energy Alternatives 29 The fuel cycle for renewable energy facilities is difficult to define for technologies such as wind 30 and solar because these natural resources exist regardless of any effort to harvest them for 31 electricity production. Impacts from the presence or absence of these renewable energy 32 technologies are often difficult to determine (NRC 2013d).
33 4.15.2    Terminating Power Plant Operations and Decommissioning 34 This section describes the environmental impacts associated with the termination of operations 35 and the decommissioning of a nuclear power plant and replacement power alternatives. All 36 operating power plants will terminate operations and be decommissioned at some point after the 37 end of their operating life or after a decision is made to cease operations. For the proposed 38 action, license renewal would delay this eventuality for an additional 20 years beyond the 39 current license period, which ends in 2022 and 2023 for LSCS Units 1 and 2, respectively.
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Environmental Consequences and Mitigating Actions 1 4.15.2.1    Existing Nuclear Power Plant 2 Environmental impacts from the activities associated with the decommissioning of any reactor 3 before or at the end of an initial or renewed license are evaluated in Supplement 1 of 4 NUREG-0586 (NRC 2002). Additionally, the incremental environmental impacts associated 5 with decommissioning activities resulting from continued plant operation during the renewal term 6 are discussed in the GEIS.
7 Table 4-20 lists the Category 1 issues in Table B-1 of Title 10 of the CFR Part 51, Subpart A, 8 Appendix B, that are applicable to LSCS decommissioning following the license renewal term.
9                          Table 4-20. Issues Related to Decommissioning Issue                                                                    GEIS Section    Category Radiation doses                                                            4.12.2.1          1 Waste management                                                          4.12.2.1          1 Air quality                                                                4.12.2.1          1 Water quality                                                              4.12.2.1          1 Ecological resources                                                      4.12.2.1          1 Socioeconomic impacts                                                      4.12.2.1          1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 10 Decommissioning would occur whether LSCS were shut down at the end of its current operating 11 license or at the end of the period of the license renewal term. Exelon stated in its ER 12 (Exelon 2014a) that it is not aware of any new and significant information on the environmental 13 impacts of LSCS during the license renewal term. The NRC staff has not found any new and 14 significant information during its independent review of Exelons ER, the site visit, or the scoping 15 process. Therefore, the NRC staff concludes that there are no impacts related to 16 decommissioning, beyond those discussed in the GEIS. For all of these issues, the NRC staff 17 concluded, in the GEIS, that the impacts are SMALL.
18 4.15.2.2    Replacement Power Plants 19 Fossil Fuel Energy Alternatives 20 The environmental impacts from the termination of power plant operations and 21 decommissioning of a fossil-fuel-fired plant are dependent on the facilitys decommissioning 22 plan. General elements and requirements for a fossil fuel plant decommissioning plan are 23 discussed in Section 4.12.2 of the GEIS and can include the removal of structures to at least 24 3 ft (1 m) below grade; removal of all coal, combustion waste, and accumulated sludge; removal 25 of intake and discharge structures; and the cleanup and remediation of incidental spills and 26 leaks at the facility. The decommissioning plan outlines the actions necessary to restore the 27 site to a condition equivalent in character and value to the greenfield or brownfield site on which 28 the facility was first constructed (NRC 2013d).
29 The environmental consequences of decommissioning are discussed in Section 4.12.2 of the 30 GEIS and can generally include:
31
* short-term impacts on air quality and noise from the deconstruction of facility 32              structures, 33
* short-term impacts on land use and visual resources, 4-103
 
Environmental Consequences and Mitigating Actions 1
* long-term reestablishment of vegetation and wildlife communities, 2
* socioeconomic impacts due to the decommissioning workforce and the long-term 3              loss of jobs, and 4
* elimination of health and safety impacts on operating personnel and the general 5              public.
6 New Nuclear Alternative 7 Termination of operations and decommissioning impacts for a nuclear plant include all activities 8 related to the safe removal of the facility from service and the reduction of residual radioactivity 9 to a level that permits release of the property under restricted conditions or unrestricted use and 10 termination of a license (NRC 2013d). The environmental impacts of the uranium fuel cycle are 11 discussed above in Section 4.15.1.1.
12 Renewable Alternative 13 Termination of power plant operation and decommissioning for renewable energy facilities 14 would be similar to the impacts discussed for fossil-fuel-fired plants above. Decommissioning 15 would involve the removal of facility components and operational wastes and residues in order 16 to restore the site to a condition equivalent in character and value to the greenfield or brownfield 17 site on which the facility was first constructed (NRC 2013d).
18 4.15.3    Greenhouse Gas Emissions and Climate Change 19 The following sections discuss GHG emissions released from operation of LSCS and the 20 environmental impacts that could occur from changes in climate conditions. The cumulative 21 impacts of GHG emissions on climate are discussed in Section 4.16.11, Global Climate 22 Change.
23 4.15.3.1    Greenhouse Gas Emissions from the Proposed Project and Alternatives 24 Gases found in the Earths atmosphere that trap heat and play a role in the Earths climate are 25 collectively termed GHG. GHGs include carbon dioxide (CO2); methane (CH4); nitrous 26 oxide (N2O); water vapor (H2O); and fluorinated gases, such as hydrofluorocarbons (HFCs),
27 perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The Earths climate responds to 28 changes in concentrations of GHGs in the atmosphere because GHGs affect the amount of 29 energy absorbed and heat trapped by the atmosphere. Increasing GHG concentrations in the 30 atmosphere generally increases Earths surface temperature. Atmospheric concentrations of 31 carbon dioxide, methane, and nitrous oxide have significantly increased since 1750 32 (IPCC 2007c, 2013). Carbon dioxide, methane, nitrous oxide, water vapor, and fluorinated 33 gases (termed long-lived GHGs) are well mixed throughout the Earths atmosphere, and their 34 impact on climate is long lasting as a result of their long atmospheric lifetime (EPA 2009a).
35 Carbon dioxide is of primary concern for global climate change, due to its long atmospheric 36 lifetime, and it is the primary gas emitted as a result of human activities. Climate change 37 research indicates that the cause of the Earths warming over the last 50 years is due to the 38 buildup of GHGs in the atmosphere resulting from human activities (USGCRP 2014; 39 IPCC 2013). The EPA has determined that GHGs may reasonably be anticipated both to 40 endanger public health and to endanger public welfare (74 FR 66496).
41 Proposed Action 42 Operation of LSCS does not directly emit GHG emissions because fossil fuel is not used to 43 generate electricity. However, plant operations at LSCS release GHG emissions from 44 stationary combustion sources, such as diesel generators on site. Other GHG emission 4-104
 
Environmental Consequences and Mitigating Actions 1 sources from LSCS plant operations include refrigerant appliances that contain fluorinated 2 gases, mobile combustion sources (e.g., employee vehicles and nonroad equipment), LSCSs 3 carbon dioxide injection system and fire protection system, use of sulfur hexafluoride to locate 4 leaks in condensers, and indirect purchased electricity emissions (Exelon 2015d). Annual GHG 5 emissions at LSCS are presented in Table 4-21 for the 2010 to 2014 timeframe. Employee 6 vehicle GHG emissions are not provided in Table 4-21 because Exelon does not compile or 7 report GHG data for mobile sources. The NRC staff estimates annual GHG emissions resulting 8 from employee vehicles to be approximately 9,400 metric tons (MT) per year of carbon dioxide 9 equivalent emissions.
10        Table 4-21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)(a)
Stationary Combustion            Fugitive          Purchased        Refrigerant-Related Year              Sources(a)            Emissions(b)        Electricity(c)        Sources(d)                Total 2010                1,022                    1,355              34,260                1,104                37,741 2011                  322                    2,980              36,066                  629                39,997 2012                  350                    1,792              36,066                  360                38,568 2013                  245                    2,508              30,520                  955                34,228 2014                  605                    4,566              32,978                  474                38,623 (a) Stationary  combustion sources include emissions from large (greater than 600 horsepower) and small (less than 600 horsepower) diesel engines. These emissions were calculated based on fuel-use data and EPA AP-42 emission factors.
(b) Fugitive emissions account for LSCSs (1) CO injection system used to adjust pH in the cooling pond, (2) the CO 2                                                                  2 fire protection system, and (3) SF6 used to locate leaks in the condensers. These emissions assume that all purchased CO2 and SF6 were released.
(c) Purchased electricity emissions were calculated based on monthly billings from the offsite electricity supplier for LSCS.
(d) Refrigerant-related sources include emissions from direct HFC/PFC refrigerants and ozone-depleting refrigerants.
The emissions assume all purchased refrigerants were released.
Key: MT/yr of CO2e = metric ton(s) per year of carbon dioxide equivalent (emissions).
Source: Exelon 2015d 11 No-Action Alternative 12 As discussed in previous no-action alternative sections, the no-action alternative represents a 13 decision by the NRC not to renew the operating license of a nuclear power plant beyond the 14 current operating license term. At some point, all nuclear plants will terminate operations and 15 undergo decommissioning. Under the no-action alternative, plant operations for LSCS would 16 terminate at or before the end of the current license. When the plant stops operating, a 17 reduction in GHG emissions from activities related to plant operation, such as use of diesel 18 generators and employee vehicles, will occur. The GHG emissions are anticipated to be less 19 than those presented in Table 4-21.
20 New Nuclear Alternative 21 As discussed in Section 2.2.2.1, the NRC staff evaluated the new nuclear power plant 22 alternative that would consist of two units with an approximate generating capacity of 23 1,120 megawatt electric (MWe) each. The GEIS (NRC 2013d) presents life-cycle GHG 24 emissions associated with nuclear power generation. As presented in Tables 4.12-4 4-105
 
Environmental Consequences and Mitigating Actions 1 through 4.12-6 of the GEIS, life-cycle5 GHG emissions from nuclear power generation can 2 range from 1 to 288 grams of carbon equivalent per kilowatt hour (g Ce/kWh). Operation of 3 nuclear power plants does not burn fossil fuels to generate electricity and, therefore, does not 4 directly emit GHG emissions. Sources of GHG emissions include stationary combustion 5 sources (e.g., emergency diesel generators and diesel-driven pumps) and mobile sources 6 (e.g., worker vehicles, onsite heavy equipment, support vehicles, delivery of materials, and 7 disposal of wastes). It is anticipated that air emissions from a new nuclear power plant would 8 be similar to those from LSCS.
9 IGCC Generation Alternative 10 As discussed in Section 2.2.2.2, the NRC staff evaluated the IGCC plant alternative that would 11 consist of four 618-MWe units for a total 2,472 MW. The GEIS presents life-cycle GHG 12 emissions associated with coal power generation. As presented in Table 4.12-4 of the GEIS, 13 life-cycle GHG emissions from coal power generation can range from 264 to 1,689 g Ceq/kWh.
14 However, these life-cycle emission factors are for conventional coal power plants; recent studies 15 estimate life-cycle GHG emissions for an IGCC plant to be 937 kilograms of carbon dioxide 16 equivalent per megawatt-hour (kg CO2e/MWh) (NETL 2012). The NRC staff estimates that 17 operation of the IGCC alternative directly will emit about 14.3 million tons per year 18 (13.0 million MT per year) of carbon dioxide equivalent emissions.
19 NGCC Generation Alternative 20 As discussed in Section 2.2.2.3, the NRC staff evaluated an NGCC alternative that consists of 21 five NGCC 560-MWe units (total 2,800 MWe). The GEIS presents life-cycle GHG emissions 22 associated with natural gas power generation. As presented in Table 4.12-5 of the GEIS, 23 life-cycle GHG emissions from natural gas can range from 120 to 930 g Ceq/kWh. The NRC 24 staff estimates that operation of the NGCC alternative directly will emit about 9.8 million tons 25 (8.2 million MT) per year of carbon dioxide equivalent emissions.
26 Combination Alternative (NGCC, Wind, and Solar) 27 As discussed in Section 2.2.2.4, the NRC staff evaluated an alternative that relies on NGCC 28 (15 percent), wind (75 percent), and solar (10 percent) capacity to replace LSCS. The 29 combination alternative would consist of a 360-MWe NGCC unit, a 227-MWe solar PV facility, 30 and a 1,813-MWe windfarm. For this combination alternative, it is assumed that the majority of 31 the GHG emissions result from the NGCC portion only because renewable portions (wind and 32 solar PV) do not burn fossil fuels to generate electricity. As discussed in Section 4.3.5., GHG 33 emissions associated with the operation of the NGCC portion are reduced proportionally 34 because its electricity output is approximately 13 percent that of the NGCC alternative. The 35 NRC staff estimates that operation of the combination alternative will directly result in about 36 1.2 million tons (1.1 million MT) per year of carbon dioxide equivalent emissions.
37 Purchased Power Alternative 38 Purchased power would come from common types of existing technology (coal, natural gas, 39 nuclear, and renewable sources) within the ROI. GHG emissions from purchased power will 40 vary and will depend on the type and combination of technology from which purchased power 41 originates. In 2014, coal, natural gas, and nuclear power accounted for 39-, 27-, and 19-percent 42 shares, respectively, of total U.S. electricity generation (EIA 2015b). Using these percentage 43 shares for the purchased power alternative, the NRC staff estimates 8.0 million ton 44 (7.3 million MT) per year of carbon dioxide equivalent emissions. However, GHG emissions 5  Life-cycle carbon emissions analyses consider construction, operation, decommissioning, and associated processing of fuel (e.g., gas and coal).
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Environmental Consequences and Mitigating Actions 1 may be greater or less than this estimate and will depend on the technology from which the 2 purchased power originates.
3 Summary of GHG Emissions from the Proposed Action and Alternatives 4 Table 4-22 presents the direct GHG emissions from operation of the proposed action and 5 alternatives. GHG emissions from the proposed action (continued operation at LSCS) and the 6 new nuclear alternative would be the lowest. GHG emissions for IGCC, NGCC, combination, 7 and purchased power alternatives are higher than those for the proposed action and a new 8 nuclear alternative by several orders of magnitude. GHG emissions from the purchased power 9 alternative are expected to be greater than those from the NGCC alternative but less than those 10 from the IGCC alternative.
11                            Table 4-22. Direct(a) GHG Emissions from Operation 12                                    of the Proposed Action and Alternatives Technology                                                            CO2e (MT/yr)
LSCS continued operation                                                    1,022 New Nuclear                                                                  1,022 IGCC                                                                      13.0x106 NGCC                                                                        8.2x106 Combination(b)                                                              1.1x106 Purchased Power(c)                                                          7.3x106 (a) The  GHG emissions presented include only direct emissions from operation of the electricity-generating technology. For the NGCC and IGCC alternatives, GHG emissions result from direct combustion of the gas and coal. For the proposed action and new nuclear alternatives, direct GHG emissions are a result of stationary combustion sources.
(b) This technology is only the NGCC portion of GHG emissions.
(c) Air emissions were estimated by assuming that purchased-power coal accounted for a 39-percent share, natural gas accounted for a 27-percent share, nuclear accounted for a 19-percent share, and renewable accounted for a 15-percent share of electricity generation.
13 4.15.3.2      Climate Change Impacts to Resource Areas 14 Climate change is the decades or longer change in climate measurements (e.g., temperature 15 and precipitation) that has been observed on a global, national, and regional level (IPCC 2007c; 16 EPA 2014; USGCRP 2014). Climate change can vary regionally, spatially, and seasonally, 17 depending on local, regional, and global factors. Just as regional climate differs throughout the 18 world, the impacts of climate change can vary between locations.
19 On a global level, from 1901 to 2013, average surface temperatures rose at a rate of 0.15 F 20 (0.08 C) per decade, and total annual precipitation increased at an average rate of 0.2 percent 21 per decade (EPA 2014). The observed global change in average surface temperature and 22 precipitation has been accompanied by an increase in sea surface temperatures, a decrease in 23 global glacier ice, an increase in sea level, and changes in extreme weather events. Such 24 extreme events include an increase in the frequency of heat waves, heavy precipitation, and 25 recorded maximum daily high temperatures (IPCC 2007c; USGCRP 2009, 2014; EPA 2014).
26 In the United States, the U.S. Global Change Research Program (USGCRP) reports that, from 27 1895 to 2012, average surface temperature increased by 1.3 &deg;F to 1.9 &deg;F (0.72 to 1.06 &deg;C) and, 28 since 1900, average annual precipitation has increased by 5 percent. On a seasonal basis, 4-107
 
Environmental Consequences and Mitigating Actions 1 warming has been the greatest in winter and spring. Since the 1980s, an increase in the length 2 of the frost-free season, the period between the last occurrence of 32 F (0 &deg;C) in the spring and 3 first occurrence of 32 F (0 &deg;C) in the fall, has been observed for the contiguous United States; 4 between 1991 and 2011, the average frost-free season was 10 days longer than between 1901 5 and 1960 (USGCRP 2014). Since the 1970s, the United States has warmed at a faster rate as 6 the average surface temperature rose at an average rate of 0.31 to 0.45 F (0.17 to 0.25 &deg;C) per 7 decade (EPA 2014). The year 2014 was the warmest on record (AMS 2015). Observed 8 climate-related changes in the United States include increases in the frequency and intensity of 9 heavy precipitation, earlier onset of spring snowmelt and runoff, rise of sea level in coastal 10 areas, increase in occurrence of heat waves, and a decrease in occurrence of cold waves 11 (USGCRP 2014).
12 Temperature data indicate that the Midwest region, where LSCS is located, experienced a 13 0.06 C (0.11 F) per decade increase in annual mean temperature during the 1900 to 14 2010 period (NOAA 2013). Temperature data for the recent past indicate an increased rate of 15 warming for the Midwest region of 0.12 &deg;C (0.22 &deg;F) per decade for the 1950-to-2010 time 16 period and a 0.26 C (0.47 F) temperature increase for the 1979-to-2010 time period. Average 17 annual precipitation data for the Midwest region exhibit an increasing trend of 0.31 in. (0.79 cm) 18 per decade for the long-term period (1895 to 2011) (NOAA 2013). The NRC staff analyzed 19 temperature and precipitation trends for the period of 1865 to 2014 in the northeast region 20 (Climate Division No. 2) of Illinois (NCDC 2015). Average annual temperatures during this time 21 period show large year-to-year variations; however, since 1865, temperatures have increased 22 0.1 &deg;F (0.05 &deg;C) per decade. Average annual precipitation also displays year-to-year variations, 23 although precipitation has increased at a rate of 0.48 in. (1.2 cm) per decade.
24 Future GHG emission concentrations (emission scenarios) and climate models are commonly 25 used to project possible climate change. Climate models indicate that over the next few 26 decades, temperature increases will continue due to current GHG emission concentrations in 27 the atmosphere (USGCRP 2014). Over the longer term, the magnitude of temperature 28 increases and climate change effects will depend on both past and future GHG emissions 29 (IPCC 2007c; USGCRP 2009, 2014).
30 For the license renewal period of LSCS, Units 1 and Unit 2 (2022 to 2042 and 2023 to 2043, 31 respectively), climate model simulations (between 2021 and 2050 relative to the reference 32 period (1971 to 1999)) indicate an increase in annual mean temperature in the Midwest region 33 of 2.5 to 3.5 F (4.5 to 6.3 &deg;C) for both a low- and high-emission-modeled scenario 34 (NOAA 2013). The predicted increase in temperature during this time period occurs for all 35 seasons, with the largest increase occurring in the summertime (June, July, and August).
36 Climate model simulations (for the time period 2021 to 2050) suggest spatial differences in 37 annual mean precipitation changes for the Midwest, with northern areas experiencing an 38 increase in precipitation and with the southern areas experiencing a decrease in precipitation.
39 For Illinois, the models indicate a 0- to 3-percent increase in annual mean precipitation, with fall, 40 winter, and spring seasons experiencing precipitation change increases and with the summer 41 season experiencing a decrease in precipitation. However, these changes in precipitation were 42 only statistically significant under a high-emission-modeled scenario (NOAA 2013).
43 The implications of climate change on LSCS operations are outside the scope of the NRCs 44 license renewal environmental review, which documents the potential environmental impacts 45 from continued reactor operations. Site-specific environmental conditions are considered when 46 siting nuclear power plants, including consideration of meteorological and hydrologic siting 47 criteria in 10 CFR Part 100. LSCS was designed and constructed in accordance with the 48 General Design Criteria of Appendix A to 10 CFR Part 50. NRC regulations require that plant 49 structures, systems, and components important to safety be designed to withstand the effects of 4-108
 
Environmental Consequences and Mitigating Actions 1 natural phenomena, such as flooding, without loss of capability to perform safety functions.
2 Furthermore, nuclear power plants are required to operate within technical safety specifications 3 in accordance with the NRC operating license, including coping with natural phenomena 4 hazards. The NRC conducts safety reviews before allowing licensees to make operational 5 changes due to changing environmental conditions. Additionally, the NRC evaluates nuclear 6 power plant operating conditions and physical infrastructure to ensure ongoing safe operations 7 through its Reactor Oversight Process. If new information about changing environmental 8 conditions becomes available, the NRC will evaluate the new information to determine whether 9 any safety-related changes are needed at existing nuclear power plants. This process is 10 separate and distinct from the NRCs license renewal environmental review that is conducted in 11 accordance with NEPA (42 U.S.C. 4321 et seq.).
12 Changes in climate have broader implications for public health, water resources, land use and 13 development, and ecosystems. For instance, changes in precipitation patterns and an increase 14 in air temperature can affect water availability and quality, distribution of plant and animal 15 species, land-use patterns, and land cover; these impacts can, in turn, affect terrestrial and 16 aquatic habitats. The sections below discuss how future climate change may impact air quality, 17 land use, water resources, aquatic resources, terrestrial resources, human health, and minority 18 and low-income populations in the ROI for LSCS. Although the future effects of climate change 19 are uncertain, the following discussions describe the potential implications of climate change in 20 affected environmental resource areas.
21 Air Quality 22 As discussed above, an increase in average temperatures in Illinois has been observed.
23 Despite the strong year-to-year variations, climate models project continued warming in the 24 Midwest region during the license renewal period. Air pollutant concentrations result from 25 complex interactions between physical and dynamic properties of the atmosphere, land, and 26 ocean. The formation, transport, dispersion, and deposition of air pollutants depend, in part, on 27 weather conditions (IPCC 2007a). Air pollutant concentrations are sensitive to winds, 28 temperature, humidity, and precipitation (EPA 2009a). Hence, climate change can impact air 29 quality as a result of the changes in meteorological conditions.
30 Ozone has been found to be particularly sensitive to climate change (IPCC 2007a; EPA 2009b).
31 Ozone is formed, in part, as a result of the chemical reaction of nitrogen oxides and VOCs in the 32 presence of heat and sunlight. Nitrogen oxides and VOC sources include both natural 33 emissions (e.g., biogenic emissions from vegetation or soils) and human-activity-related 34 emissions (e.g., motor vehicles and power plants). Sunshine, high temperatures, and air 35 stagnation are favorable meteorological conditions to produce higher levels of ozone 36 (IPCC 2007a; EPA 2009a). The emission of ozone precursors also depends on temperature, 37 wind, and solar radiation (IPCC 2007a); both nitrogen oxide and biogenic VOC emissions are 38 expected to be higher in a warmer climate (EPA 2009b). Although surface temperatures are 39 expected to increase in the Midwest, this may not necessarily result in an increase in ozone 40 concentrations. The observed correlation between increased ozone concentrations and 41 temperature has been found to occur in polluted and urban regions (i.e., those areas where 42 ozone concentration are greater than 60 parts per billion). Additionally, increases in ozone 43 concentrations correlated with temperature increases occur in combination with cloud-free 44 regions and air stagnation episodes (Jacob and Winner 2009; IPCC 2013). Furthermore, 45 climate models do not agree on the sign of ozone response to climate change. Some models 46 indicate increases in ozone concentrations with climate change for the Midwest and Northeast 47 (e.g., Wu et al. 2008), and others project decreases in ozone concentrations with climates for 48 the northern regions of the United States (e.g., Tagaris et al. 2009).
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Environmental Consequences and Mitigating Actions 1 Land Use 2 Anthropogenic land use is both a contributor to climate change and a receptor of climate change 3 impacts (Dale 1997). As described previously in this section, the Midwest will likely experience 4 rising temperatures and heavier precipitation events during the proposed license renewal 5 period. Agriculture (the major land use in the vicinity of LSCS) and growing urban areas will 6 further exacerbate these changes by continuing to inhibit natural ecosystem functions that could 7 moderate climate change effects. For instance, air temperatures and near-surface moisture 8 levels change in areas where natural vegetation is converted to agricultural use, and higher 9 temperatures have been observed in the Midwest as a result of converting land to agricultural 10 use (USGCRP 2014). The USGCRP (2014) indicates that land use changes, such as the 11 continued expansion of urban areas, paired with climate change effects, such as heavier 12 precipitation events, can exacerbate climate change effects, including reduced water filtration 13 into the soil and increased surface runoff. Although anthropogenic land uses will contribute to 14 climate change in these and other ways, land uses will also be affected by climate change in 15 several ways. For instance, plant winter hardiness zones are likely to shift one-half to one full 16 zone by the end of the proposed license renewal period (USGCRP 2014). This shift will affect 17 the ability to grow certain crops as the Midwest will likely contain plants now associated with the 18 Southeast by the end of the century (USGCRP 2014). Additionally, the USGCRP (2014) 19 projects that the Midwest will experience a loss in cropland cover and an expansion in exurban 20 and suburban areas. Changes in cropland cover and expansion of exurban and suburban 21 areas could then reduce the quality and availability of land resources and agricultural 22 productivity.
23 Water Resources 24 Predicted changes in the timing, intensity, and distribution of precipitation will likely result in 25 changes in surface water runoff affecting water availability across the Midwest. As discussed 26 above, the Midwest may experience an increase in mean precipitation during the fall, winter, 27 and spring and an increase in the frequency and intensity of extreme (heavy) precipitation 28 (USGCRP 2014). As cited by the USGCRP, in spite of increased annual average precipitation, 29 the loss of moisture from soils because of higher temperatures, along with increased 30 evapotranspiration from vegetation and the increased average number of days without 31 precipitation, is likely to intensify short-term (seasonal or shorter) droughts across the region 32 into the future (USGCRP 2009, 2014). Such conditions can potentially reduce the amount of 33 water available for surface runoff and streamflow on a seasonal timeframe. Runoff and 34 streamflow at a regional scale for the Midwest region indicate no clear trend during the last half 35 century; however, annual runoff and river flow are projected to increase in the upper Midwest.
36 Climate change impacts on groundwater availability depend on basin geology, frequency and 37 intensity of high-rainfall periods, recharge, soil moisture, and groundwater and surface water 38 interactions (USGCRP 2014). Precipitation and evapotranspiration are key drivers in aquifer 39 recharge. Increased precipitation in the fall, winter, and spring is likely to result in increased 40 groundwater recharge. More precipitation during these seasons (as opposed to summer) would 41 percolate into the groundwater because it would experience lower evaporation and transpiration 42 rates. Furthermore, a portion of the winter precipitation would fall as snow. Instead of running 43 off the land, much of the snow is likely to slowly melt in place and contribute to groundwater 44 recharge.
45 Terrestrial Resources 46 As described above, the Midwest will likely experience rising temperatures and heavier 47 precipitation events during the proposed license renewal period. As the climate changes, 48 terrestrial resources will either need to be able to tolerate the new physical conditions or shift 4-110
 
Environmental Consequences and Mitigating Actions 1 their population range to new areas with a more suitable climate. Scientists currently estimate 2 that species are shifting their ranges at a rate of 20 to 36 ft (6.1 to 11 m) in elevation per decade 3 and 3.8 to 10.5 mi (6.1 to 16.9 km) in latitude per decade (Chen et al. 2011; Thuiller 2007).
4 Although some species may readily adapt to a changing climate, others may be more prone to 5 experience adverse effects. For example, species whose ranges are already limited by habitat 6 loss or fragmentation or who require very specific environmental conditions may not be able to 7 successfully shift their ranges over time. Migratory birds that travel long distances may also be 8 disproportionately affected because they may not be able to pick up on environmental clues that 9 a warmer, earlier spring is occurring in the United States while overwintering in tropical areas.
10 Fraser et al. (2013) found that songbirds overwintering in the Amazon did not leave their winter 11 sites earlier, even when spring sites in the eastern United States experienced a warmer spring.
12 As a result, the song birds missed periods of peak food availability. For many Midwest species, 13 migration to changed habitats is projected to be slow due to flat topography, high latitudes, and 14 fragmented habitats (USGCRP 2014). For instance, in its final rule to list the red knot (Calidris 15 canutus rufa), a shorebird that uses the Great Lakes during spring and fall migration, FWS cites 16 several effects resulting from climate change as factors contributing to the species decline 17 (79 FR 73705). These effects include habitat loss from sea level rise, asynchronies in the 18 timing of annual cycles, and increased frequency of severe storm events. Special status 19 species and habitats, such as those that are Federally protected by the ESA, would likely be 20 more sensitive to climate changes because these species populations are already experiencing 21 threats that are endangering their continued existence throughout all, or a significant portion of 22 their ranges. Habitat ranges for forest systems in the Midwest, such as paper birch 23 (Betula papyrifera), balsam fir (Abies balsamea), and black spruce (Picea mariana), are 24 projected to decline across the Midwest as they shift northward, and species that are common 25 farther south, such as oaks (Quercus spp.) and pines (Pinus spp.), will expand their range north 26 into the Midwest region (USGCRP 2014). Climate changes could also favor non-native, 27 invasive species and promote population increases of insect pests and plant pathogens, which 28 may be more tolerant to a wider range of climate conditions.
29 Aquatic Resources 30 The potential effects of climate change, whether from natural cycles or manmade activities, 31 could result in changes that could affect aquatic resources in the Illinois River. Raised air 32 temperatures could result in higher water temperatures in the cooling pond and in the Illinois 33 River and its tributaries. Higher water temperatures would increase the potential for thermal 34 effects on aquatic biota, such as fish kills within the cooling pond, and could exacerbate existing 35 environmental stressors, such as excess nutrients, sedimentation, and lowered dissolved 36 oxygen associated with eutrophication (USGCRP 2014). The Midwest will likely experience an 37 increased frequency of extreme rainfall events, which will cause erosion and could lead to a 38 decline in water quality (USGCRP 2014). Species that require cleaner waters, such as 39 freshwater mussels, could experience further population declines. The USGCRP (2014) 40 predicts habitat loss and local extinctions of fish and other aquatic species throughout the 41 United States from the combined effects of water withdrawal and climate change. Shifts in 42 species assemblages and distributions are also likely as climate change continues 43 (USGCRP 2014), which could alter the balance of the aquatic community in the Illinois River.
44 As discussed below under the section entitled, Terrestrial Resources, special status species, 45 such as those that are Federally protected under the ESA (16 U.S.C. 1531 et seq.), would be 46 more sensitive to climate changes. Invasions of non-native species that thrive under a wide 47 range of environmental conditions and warmer waters could further disrupt the current 48 composition of aquatic communities (NRC 2013d).
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Environmental Consequences and Mitigating Actions 1 Historic and Cultural Resources 2 Increases in river levels because of changes in meteorological conditions due to climate change 3 could result in the loss of historic and cultural resources from flooding, erosion, or inundation.
4 Due to water-level changes, some resources could be lost before they could be documented or 5 otherwise studied. However, the limited extent of climate change that may occur during the 6 20-year license renewal term would not likely result in any significant loss of historic and cultural 7 resources at LSCS.
8 Socioeconomics 9 Rapid changes in climate conditions could have an impact on the availability of jobs in certain 10 industries. For example, tourism and recreation are major job creators in some regions, 11 bringing billions of dollars to regional economies. Across the Nation, fishing, hunting, and other 12 outdoor activities make important economic contributions to rural economies and are also a part 13 of the cultural tradition. A changing climate would mean reduced opportunities for some 14 activities in some locations and expanded opportunities for others. Hunting and fishing 15 opportunities could also change as animals habitats shift and as relationships among species 16 are disrupted by their different responses to climate change (USGCRP 2014).
17 Water-dependent recreation could also be affected (USGCRP 2009). The USGCRP reports 18 that increasing heat and humidity associated with climate change in parts of the Midwest region 19 by the year 2050 could create unfavorable conditions for summertime outdoor recreation and 20 tourism activity (USGCRP 2014). However, the limited extent of climate change that may occur 21 during the 20-year license renewal term would not likely cause any significant changes in 22 socioeconomic conditions in the vicinity of LSCS.
23 Human Health 24 Increasing temperatures due to changes in climate conditions could have an impact on human 25 health. However, changes in climate conditions that may occur during the license renewal term 26 will not result in any significant change to the impacts discussed in Section 4.11.1 from LSCSs 27 radioactive and nonradioactive effluents.
28 Environmental Justice 29 Rapid changes in climate conditions could disproportionately affect minority and low-income 30 populations. The USGCRP (2009) indicates that infants and children, pregnant women, the 31 elderly, people with chronic medical conditions, outdoor workers, and people living in poverty 32 are especially at risk from a variety of climate-related health effects. Examples of these effects 33 include increased heat stress; air pollution; extreme weather events; and diseases carried by 34 food, water, and insects. The greatest health burdens related to climate change are likely to fall 35 on the poor, especially those lacking adequate shelter and access to other resources, such as 36 air conditioning. Elderly people on fixed incomes, who are more likely to be poor, are more 37 likely to have debilitating chronic diseases or limited mobility. In addition, the elderly have a 38 reduced ability to regulate their own body temperature or the ability to sense when they are too 39 hot. According to the USGCRP (2009), the elderly are at greater risk of heart failure, which is 40 further exacerbated when cardiac demand increases in order to cool the body during a heat 41 wave. The USGCRP (2009) also found that people taking medications, such as diuretics for 42 high blood pressure, have a higher risk of dehydration. The USGCRP (2014) reconfirmed the 43 previous report findings regarding the risks of climate change on low-income populations and 44 also warns that climate change could affect the availability and access to local plant and animal 45 species, thus impacting the people who have historically depended on them for food or 46 medicine. However, minority and low-income populations at LaSalle are not likely to experience 4-112
 
Environmental Consequences and Mitigating Actions 1 disproportionately high and adverse impacts from climate change, based on the expected small 2 or slow change, effectively, in the environment during the 20-year license renewal term.
3 4.16    Cumulative Impacts of the Proposed Action 4 The NRC staff considered potential cumulative impacts in the environmental analysis of 5 continued operation of LSCS during the 20-year license renewal period. Cumulative impacts 6 may result when the environmental effects associated with the proposed action are overlaid or 7 added to temporary or permanent effects associated with other past, present, and reasonably 8 foreseeable actions. Cumulative impacts can result from individually minor, but collectively 9 significant, actions taking place over a period of time. An impact that may be SMALL by itself 10 possibly could result in a MODERATE or LARGE cumulative impact when it is considered in 11 combination with the impacts of other actions on the affected resource. Likewise, if a resource 12 is regionally declining or imperiled, even a SMALL individual impact could be important if it 13 contributes to, or accelerates, the overall resource decline.
14 For the purposes of this cumulative analysis, past actions are those before the receipt of the 15 license renewal application; present actions are those related to the resources at the time of 16 current operation of the power plant; and future actions are those that are reasonably 17 foreseeable through the end of plant operation, including the period of extended operation.
18 Therefore, the analysis considers potential impacts through the end of the current license terms, 19 as well as the 20-year license renewal term. The geographic area over which past, present, 20 and reasonably foreseeable actions would occur depends on the type of action considered and 21 is described below for each resource area.
22 To evaluate cumulative impacts, the incremental impacts of the proposed action, as described 23 in Sections 4.2 to 4.15, are combined with other past, present, and reasonably foreseeable 24 future actions, regardless of which agency (Federal or non-Federal) or person undertakes such 25 actions. The NRC staff used the information provided in Exelons ER; responses to RAIs; 26 information from other Federal, State, and local agencies; scoping comments; and information 27 gathered during visits to the LSCS site to identify other past, present, and reasonably 28 foreseeable actions. For a project to be considered in the cumulative analysis, the NRC staff 29 determined whether it would occur within the noted geographic areas of interest and within the 30 period of extended operation, whether it was reasonably foreseeable, and whether there would 31 be a potential overlapping effect with the proposed project. For past actions, consideration 32 within the cumulative impacts assessment is resource and project specific. In general, the 33 effects of past actions are included in the description of the affected environment in Chapter 3, 34 which serves as the baseline for the cumulative impacts analysis. However, past actions that 35 continue to have an overlapping effect on a resource that potentially could be affected by the 36 proposed action are considered in the cumulative analysis.
37 Appendix E describes other actions and projects identified during this review and considered in 38 the NRC staffs analysis of the potential cumulative effects. Not all actions or projects listed in 39 Appendix E are considered in each resource area because of the uniqueness of the resource 40 and its geographic area of consideration.
41 4.16.1    Air Quality and Noise 42 This section addresses the direct and indirect effects of license renewal on air quality and noise 43 when added to the aggregate effects of other past, present, and reasonably foreseeable future 44 actions. As described in Section 4.3.1, the incremental impacts on air quality and noise levels 45 from the proposed license renewal would be SMALL.
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Environmental Consequences and Mitigating Actions 1 4.16.1.1      Air Quality 2 The geographic area considered in the cumulative air quality analysis is the county where the 3 proposed action is located, as air quality designations for criteria air pollutants are generally 4 made at the county level. Counties are further grouped together based on a common airshed 5 known as an Air Quality Control Region (AQCR)to provide for the attainment and 6 maintenance of the NAAQS. LSCS is located in LaSalle County, Illinois, which is part of the 7 North Central Illinois Intrastate AQCR (40 CFR 81.262).
8 With regard to NAAQS criteria pollutants, LaSalle County and the entire North Central Illinois 9 Intrastate AQCR are designated as attainment for all NAAQS (40 CFR 81.314). According to 10 EPAs Enforcement and Compliance History Online, there are 20 facilities designated as major6 11 air emission sources, 9 synthetic minor air emissions sources, and 160 facilities designated as 12 minor air emission sources located in LaSalle County (EPA 2015b). LSCS, as discussed in 13 Section 3.3.2 of this SEIS, is a synthetic minor air source. Air emissions from permitted sources 14 at LSCS are presented in Chapter 3, Table 3-4. There will be no refurbishment-related 15 activities during the license renewal period. Additionally, Exelon does not anticipate equipment 16 or operational upgrades or replacement activities that would increase air emissions during the 17 license renewal term (Exelon 2015c). As a result, the NRC staff expects emissions from LSCS 18 during the license renewal period to be similar to those emissions presented in Section 3.3.2.
19 Appendix E provides a list of current projects and reasonably foreseeable future actions that 20 could contribute to cumulative impacts to air quality. Air emissions sources that contribute to air 21 quality identified in Appendix E are currently operating and, given the designated attainment 22 status for all NAAQS in LaSalle County, these emissions have not contributed to a violation of 23 the NAAQS. Consequently, cumulative impacts to air quality in LaSalle County would be the 24 result of changes to present-day emissions and future actions within the county. Development 25 and construction activities associated with regional growth of housing, business, and industry, 26 as well as associated vehicular traffic, can increase air emissions. Regional air quality 27 conditions could deteriorate from the effects of the growth of the county as construction 28 activities give rise to dust, exhaust, and emissions that can degrade air quality. Population 29 growth is estimated to increase by 4 percent per decade in LaSalle County (LaSalle 30 County 2014). Air quality effects of development are monitored through the statewide ambient 31 air quality monitoring network. If degradation in air quality is observed, the IEPA can develop air 32 quality control programs to mitigate the effects of development. Furthermore, any new 33 stationary sources of emissions that would be established in the region would be required to 34 apply for an air permit from the IEPA and be operated in accordance with regulatory 35 requirements. IEPA will examine the potential air quality impacts using various modeling tools 36 to assess any potential changes to compliance with the NAAQS prior to issuing an air permit to 37 a new source (or to an existing source that proposes to undergo significant modification).
38 Climate change can impact air quality as a result of changes in meteorological conditions. Air 39 pollutant concentrations are sensitive to winds, temperature, humidity, and precipitation 40 (EPA 2009a). As discussed in Section 4.15.3.2, ozone levels have been found to be particularly 41 sensitive to climate change influences (EPA 2009b; IPCC 2007c). Climate change may make it 42 difficult for regions to meet ozone NAAQS (USGCRP 2009). However, as discussed in 43 Section 4.15.3, while surface temperatures are expected to increase in the Midwest, this may 44 not necessarily result in an increase in ozone concentrations. Changes in air emission 6  Major sources emit or have the potential to emit 10 tons per year of any one hazardous air pollutant (HAP), 25 tons per year of any combination of HAPs, or 100 tons per year of any other regulated air contaminant. A minor source has a potential to emit that is less than the major source thresholds. A minor synthetic source is an air pollution source that has a Federally Enforceable State Operating Permit (FESOP) with conditions that legally restrict its potential to emit to below threshold levels.
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Environmental Consequences and Mitigating Actions 1 concentrations will depend on the combination of higher temperatures, current levels of ozone 2 (increases in ozone concentrations and temperature correlations have been observed in urban 3 regions), stagnant air masses, sunlight, and emissions of pollutant precursors. Furthermore, 4 climate models do not agree on the direction of ozone changes (increase or decrease) in 5 response to climate change for the Midwest (Wu et al. 2008; Tagaris et al. 2009).
6 Because of the small quantity of emissions from LSCS and that no emissions increase 7 associated with license renewal is expected, the potential for LSCS to contribute to a cumulative 8 impact with other air pollutant sources is SMALL. Given the current designated attainment 9 status of LaSalle County and few reasonably foreseeable projects that may increase air 10 emissions in the region of interest, the NRC staff concludes that, combined with the emissions 11 from other past, present, and reasonably foreseeable future actions, cumulative impacts on air 12 quality would be SMALL.
13 4.16.1.2    Noise 14 Section 3.3.3 presents a summary of noise sources at LSCS and in the vicinity of the site.
15 Noise levels in the vicinity of a nuclear power plant could increase from planned activities 16 associated with urban, industrial, and commercial development. The magnitude of cumulative 17 impacts depends on the nuclear plants proximity to other noise sources. A 3 -A-weighted 18 decibels (-dBA) change in sound level is considered barely discernable (FHWA 2011), as 19 discussed in Section 3.3.3 of this SEIS. A 3-dBA increase would occur with the placement of 20 another identical source over an existing source (e.g., a doubling of the traffic volume).
21 Ongoing or foreseeable future projects in and around LSCS, as identified in Appendix E, would 22 increase noise levels only in the vicinity of the noise sources. Therefore, contributions to noise 23 levels from future actions are limited to projects in the vicinity of LSCS (within a 2 mi (3.3 km) 24 radius).
25 For example, wind farm projects in the immediate vicinity of LSCS may contribute to noise 26 impacts, particularly the Grand Ridge Wind Farm. As discussed in Section 4.3.6, noise impacts 27 from wind generation operations would include aerodynamic noise from the turbine rotors and 28 mechanical noise from the turbine drivetrain components. Wind-turbine-generated noise will 29 vary depending on the speed of the turbine, environmental conditions, and the distance of the 30 receptor from the turbine. Exelon stated that any additional noise from installation and 31 operation of the wind turbine in the vicinity has been imperceptible (Exelon 2015j). The NRC 32 staff identified noise concerns raised by the public regarding wind farm installations in counties 33 surrounding LaSalle (News-Gazette 2013, Daily Herald 2010, FarmProgress 2010; 34 FairWindEnergy undated). However, the NRC staff did not identify noise concerns raised 35 specifically in LaSalle County or the immediate area surrounding LSCS. Furthermore, 36 wind-turbine-generated noise, and other projects, must comply with noise regulations found in 37 IAC Title 35, Subtitle H. Accordingly, the NRC staff concludes that the cumulative impact to the 38 noise environment from past, present, and reasonably foreseeable actions is SMALL.
39 4.16.2    Geology and Soils 40 This section addresses the direct and indirect effects of license renewal on geology and soils 41 when added to the aggregate effects of other past, present, and reasonably foreseeable future 42 actions. As noted in Section 4.4.1, the NRC staff concludes that the impacts of the proposed 43 action (license renewal) on geology and soils would be SMALL. The cumulative impacts on the 44 geologic environment primarily relate to land disturbance and the potential for soil erosion and 45 loss, as well as the projected consumption of geologic resources. Exelon has no plans to 46 conduct refurbishment or replacement actions. Ongoing operation and maintenance activities at 47 LSCS are expected to be confined to previously disturbed areas. Any use of geologic materials 4-115
 
Environmental Consequences and Mitigating Actions 1 such as aggregates to support operation and maintenance activities would be procured from 2 local and regional sources. Thus, activities associated with continued operations are not 3 expected to affect the geologic environment.
4 The NRC staff assumes that any construction activities would use material from local and 5 regional sources, as these materials are abundant in the region. These identified projects are of 6 such a scale as to not be likely to impact regional sources and supplies of the identified 7 resources. Furthermore, construction activities would need to be conducted in accordance with 8 State and local requirements and development activities would be subject to BMPs for soil 9 erosion and sediment control, which would serve to minimize soil erosion and loss. Considering 10 ongoing activities and reasonably foreseeable actions, the NRC staff concludes the cumulative 11 impacts on geology and soils during the license renewal term would be SMALL.
12 4.16.3    Water Resources 13 This section addresses the direct and indirect effects of the proposed action (license renewal) 14 on water resources when added to the aggregate effects of other past, present, and reasonably 15 foreseeable future actions.
16 4.16.3.1      Surface Water Resources 17 As described in Section 4.5.1.1, the incremental impacts on surface water resources from 18 continued operations of LSCS during the license renewal term would be SMALL. The NRC staff 19 has also evaluated other projects and actions for consideration in determining their contribution 20 to cumulative impacts on surface water resources (see Appendix E).
21 The description of the affected environment under Section 3.5.1 of this SEIS serves as the 22 baseline for the cumulative impacts assessment for surface water resources. The geographic 23 area of analysis for the surface water resources component of the cumulative impacts analysis 24 includes the lowermost portion of the Upper Illinois River Basin, as described in Section 3.5.1.1, 25 with a detailed focus on the Marseilles Pool of the Illinois River and its tributaries. As such, this 26 review focused on those projects and activities that would withdraw water from or discharge 27 effluent to the Marseilles Pool. The cumulative impacts on surface water use and quality, along 28 with associated climate change considerations, are presented below.
29 Water Use Considerations 30 The Upper Illinois River Basin is composed of a 10,949 square mile (mi2) (28,369 square 31 kilometer (km2)) drainage area upstream from Ottawa, Illinois. LSCS is located on the 32 Marseilles Pool of the main stem of the Illinois River. This pool is one of eight such navigation 33 pools along the Illinois River and major tributaries that includes an associated lock and dam.
34 Each pool includes a navigation channel that is at least 9 ft (2.7 m) deep and 300 ft (91 m) wide.
35 Together, the navigation pools are part of the Illinois Waterway, which enables commercial river 36 traffic to travel from Lake Michigan to the Mississippi River and from there to the Gulf of Mexico 37 (Arnold et al. 1999; Talkington 1991; USGS 1998).
38 Operation of the navigation pools using the locks and dams has the effect of decreasing overall 39 river flow velocity and stabilizing river water levels, particularly during low flows. As a result of 40 this extensive management, some 60 percent of the State of Illinois commodities travel the 41 waterway annually. This includes grain, petroleum products, coal, chemicals, sand and gravel, 42 pulp, paper, and others (Talkington 1991).
43 In support of this cumulative impacts analysis, the NRC staff obtained and evaluated the best 44 available data on water consumption and projected trends in water use, as compiled by 45 responsible water resources management agencies. The USGS published a comprehensive 4-116
 
Environmental Consequences and Mitigating Actions 1 investigation of hydrologic and water quality conditions in the Upper Illinois River Basin in 1999 2 that also considered water use (Arnold et al. 1999).
3 Excluding surface water diversions from Lake Michigan in the Chicago area, nearly five times as 4 much groundwater as surface water is used in the Upper Illinois River Basin for public water 5 supply. Within the basin, surface water is primarily used for cooling and associated 6 thermoelectric power generation, followed by public water supply and industrial and commercial 7 use. In total, more than 90 percent of all reported water use in the basin is for the cooling and 8 thermoelectric power generation sector, with nearly all of the water from surface water sources.
9 This percentage reflects total water demands and does not account for water that is withdrawn 10 and not consumptively used (i.e., water that is returned to the water source rather than being 11 lost) (Arnold et al. 1999). Thermoelectric power generating plants that use once-through cooling 12 systems return most of the water they withdraw back to the source. In contrast, those using 13 closed-cycle cooling systems, which are now the standard for new facilities, withdraw much less 14 water (i.e., about 90 percent less than those with once-through cooling systems) but their 15 operation entails consumptive loses (i.e., primarily due to evaporation) of greater than 16 50 percent, resulting in the return of less water (NRC 2013d).
17 The rankings by water use sector cited above in Arnold et al. (1999) are mirrored in the 18 county-level forecasts of water use prepared by Southern Illinois University for the Illinois State 19 Water Survey (Dziegielewski et al. 2005). As part of its analysis, the NRC staff considered the 20 counties in the lowermost Upper Illinois River Basin, including counties that border LaSalle 21 County, where LSCS is located, and the immediately upstream portion of the Marseilles Pool in 22 Grundy County. Total water demand (both groundwater and surface water) overall in the Illinois 23 counties within the lowermost part of the Upper Illinois River Basin is projected to increase by 24 about 30 percent by 2025, as compared to water use in the year 2000. This is a 1,148 mgd 25 (4.35 million m3/d) (equivalent to 1,776 cfs (50.2 m3/s)) increase over water use in 2000 26 (Dziegielewski et al. 2005).
27 By 2025, the demand for public water use within the lowermost Upper Illinois River Basin is 28 projected to increase by about 36 percent. This reflects an increase of approximately 29 69 mgd (261,000 m3/d) as compared to public water use in the year 2000. For self-supplied 30 commercial and industrial water use, an increase of approximately 16 mgd (60,600 m3/d) by 31 2025 is forecast (Dziegielewski et al. 2005).
32 The NRC staff believes that the county-level total water demand projections likely overestimate 33 future demand, as they are heavily influenced by large forecasted increases in water demand 34 for thermoelectric power generation, which have not been realized to date. In addition, the 35 thermoelectric power generation component of these projections includes the Collins 36 Generating Station, a fossil-fuel fired power plant in Morris (Grundy County), Illinois, which 37 withdrew water from the Illinois River. This facility was permanently decommissioned in 2004 38 and, as a result, the county-level projections, particularly for Grundy County, probably 39 overestimate future total water demand.
40 In LaSalle County, total water demands are projected to increase by approximately 41 3.8 mgd (14,400 m3) to 89.8 mgd (340,000 m3/d) by 2025 as compared to the countys total 42 water use in 2000. This is a rate of increase of about 0.15 mgd (570 m3/d) per year, or an 43 increase of about 4 percent as compared to water use in 2000. This total county demand 44 includes 62.9 mgd (238,100 m3/d) attributable to LSCS operations. This total projected increase 45 by 2025 includes 0.3 mgd (1,140 m3/d) for public water supply (3 percent increase) and 2.5 mgd 46 (9,500 m3/d) increase for self-supplied commercial and industrial uses (a nearly 70 percent 47 increase), with the remainder attributable to use for thermoelectric power generation 48 (Dziegielewski et al. 2005). The projected increase in public water supply demand is in line with 4-117
 
Environmental Consequences and Mitigating Actions 1 the historical trend in LaSalle Countys population growth, which has averaged about 2 percent 2 per decade. Most recently, the Illinois Department of Commerce and Economic Opportunity has 3 projected county population to grow at a rate of about 4 percent between 2020 and 2030, or 4 about 0.4 percent per year (LaSalle County 2014).
5 Based on the discussion above, the NRC staff estimates that by the end of the period of 6 extended operations for LSCS in 2043, LaSalle Countys total water demands could increase to 7 96.5 mgd (365,000 m3/d). This conservative projection assumes water demand will increase by 8 about 0.4 percent per year equally across all water use sectors and that LSCSs river makeup 9 water withdrawals, which dominate water withdrawals in the county and across the lowermost 10 Upper Illinois River Basin, will also increase proportionally.
11 However, even if the entire projected water demand for LaSalle County (96.5 mgd, equivalent to 12 149 cfs (4.2 m3/s)) which includes water needs by LSCS were to be withdrawn from the 13 Marseille Pool of the Illinois River and not returned, this would be equivalent to approximately 14 1.4 percent of the mean annual flow of the Illinois River through the Marseilles Pool. This small 15 percentage increase would be less because some of the water withdrawn from the pool would 16 be returned, as more than 50 percent of the water withdrawn by LSCS at present (i.e., about 17 55 cfs (1.6 m3/s) is returned directly to the Marseilles Pool). It is extremely likely that future 18 demands for public water supply will continue to be met by groundwater and not surface water.
19 There are no municipalities that use the Marseilles Pool of the Illinois River as a public water 20 supply source. All identified public water supplies within 10 mi (16 km) of LSCS rely on 21 groundwater (Exelon 2014a, 2014b). Given the abundant groundwater supplies in the county 22 and also the higher cost of surface water treatment, the NRC staff does not anticipate public 23 water supplies to switch to surface water as a water source during the license renewal term.
24 Thus, it is extremely unlikely that continued LSCS operations withdrawing surface water from 25 the Marseilles Pool of the Illinois River, combined with those of other users in the county, would 26 substantially impact the downstream availability of surface water.
27 Water Quality Considerations 28 Water quality within the whole of the Illinois River Basin has historically suffered from rapid 29 population growth, urbanization, and industrial development. This resulted in the discharge of 30 poorly treated sewage, the discharge of industrial pollutants and refuse, runoff of agricultural 31 chemicals and sediments, and the alteration of the natural hydrology of the river (Exelon 2014a; 32 Talkington 1991).
33 Nonetheless, over the last 50 years, substantial improvements in water quality have occurred, 34 due to municipal and industrial waste treatment and management efforts to address both point 35 and nonpoint pollutant sources. Ongoing water quality concerns within the Upper Illinois River 36 Basin remain and include the atmospheric deposition of pesticides and trace metals; endocrine 37 disrupting compounds in surface and groundwater; nutrient enrichment of surface and 38 groundwater; the transport and fate of pesticides, trace elements, and volatile organic 39 compounds in surface and groundwater; and the effects of urbanization on biodiversity, habitat, 40 and water quality (USGS 1998, Groschen 2004).
41 As discussed in Section 3.5.1.3 of this SEIS, a segment of the Illinois River that encompasses 42 the Marseilles Pool does not meet designated uses and associated water-quality standards and 43 is listed as an impaired waterway. The segment is listed as impaired for not meeting designated 44 uses for fish consumption due to polychlorinated biphenyls (PCBs) and mercury as well as for 45 primary contact recreation use, due to fecal coliform bacteria. However, the segment is 46 classified as fully supporting its designated use for aquatic life. IEPA has assigned a medium 47 priority for the development of Total Maximum Daily Load (TMDL) limits to improve water quality 4-118
 
Environmental Consequences and Mitigating Actions 1 in this river segment pursuant to Section 303(d) of the Federal Water Pollution Control Act 2 (i.e., Clean Water Act (CWA)) (33 U.S.C. 1251).
3 As noted previously, development in the lowermost Upper Illinois River Basin, including 4 associated population growth and industrial development, is expected. Upstream development 5 could lead to increased discharges and pollutant loading to the Marseilles Pool of the Illinois 6 River with impacts on ambient water quality. The magnitude of cumulative impacts would 7 depend on the nature and location of the actions relative to receiving surface water bodies, the 8 number of actions (facilities or projects), and the extent of municipal, county, and state 9 regulatory agency development planning and environmental regulatory controls. At a minimum, 10 new and modified industrial and large commercial facilities would be subject to regulation under 11 the Federal CWA (33 U.S.C. 1251) (i.e., Section 402). This would include IEPA-administered 12 NPDES permit limits on stormwater and point source discharges designed to be protective of 13 surface water resources. Likewise, it is this regulatory framework that presently governs 14 industrial effluent and thermal discharges from LSCS and other major industrial facilities in the 15 lowermost Upper Illinois River Basin.
16 Climate Change Considerations 17 The NRC staff also considered the USGCRPs most recent compilations of the state of 18 knowledge relative to global climate change effects (Melillo et al. 2014). Climate change can 19 impact surface water as a result of changes in temperature and precipitation. As discussed in 20 Section 4.15.3.2, climate model simulations for the Midwest region indicate an increase in 21 annual mean temperature as well as precipitation. More especially, the frequency and intensity 22 of heavy precipitation events is forecast to increase. Increased precipitation results in greater 23 runoff and streamflow. The USGCRP (Melillo et al. 2014) predicts that runoff and streamflow for 24 the upper Midwest will increase overall.
25 In its ER, Exelon (2014a) cites an analysis prepared by the Illinois State Water Survey 26 (Knapp 2009) that assesses trends in stream flows encompassing the Illinois River Basin and 27 their implications for flood frequency. For stream gaging sites with a long period of record 28 (90 years), the analysis indicates a consistent trend of increasing stream flows in the upper 29 Midwest, attributed to a 7- to 10-percent increase in precipitation over the past 30 years 30 (through 2008). Results from an earlier study prepared by USGS (Arnold et al. 1999) and 31 specific to the Upper Illinois River Basin also indicate a statistically significant increase in mean 32 annual stream flow (over the period 1950-1997) at all seven stations selected for analysis, 33 including as measured at the USGS gage at Marseilles, Illinois. In contrast to Knapp (2009), the 34 USGS study was not able to correlate any trends in precipitation with the apparent increases in 35 streamflow. Rather, the authors concluded that the observed trends were more likely 36 attributable to land-use changes in the affected watersheds, causing more rapid runoff of 37 precipitation, and to increases in groundwater usage and associated increased return effluent to 38 receiving waters from wastewater treatment plants in the basin. These two studies serve to 39 point to the uncertainty over whether there has been an observable trend in precipitation and/or 40 streamflow in the upper Midwest, as forecast by the USGCRP.
41 Despite any observable trends to date, rapid runoff events occurring due to more frequent and 42 intensive precipitation events associated with climate change, especially over cleared or 43 urbanized areas, will result in increases in erosion and transport of sediment and other 44 pollutants to receiving waters. This can negatively affect ambient water quality.
45 Further, higher air temperatures and increased runoff associated with heavy precipitation events 46 could impact the thermal regime of the Marseilles Pool of the Illinois River, along with increases 47 in runoff laden with nutrients, sediment, and other contaminants. Higher surface water 48 temperatures decrease the cooling efficiency of thermoelectric power generating facilities as 4-119
 
Environmental Consequences and Mitigating Actions 1 well as plant capacity, due to the need to reduce the discharge of thermal effluent 2 (Melillo et al. 2014). As intake water temperatures warm, cooling water makeup requirements 3 increase. Degradation in ambient surface water quality increases the costs of water treatment 4 for both industrial cooling water and potable water, due to the need for increased filtration and 5 higher additions of chemical treatments for such uses as antiscaling and disinfection. With 6 respect to LSCS operations, these potential climate-induced changes can lead to higher cooling 7 pond temperatures and an increase in evaporative losses from LSCSs cooling pond. This can 8 conceivably result in additional makeup water withdrawals from the Marseilles Pool and an 9 increased need for blowdown discharges from the cooling pond to the Illinois River. At present, 10 the data available to the NRC staff is not sufficient to indicate whether or not a warming trend is 11 evident in the waters of the Illinois River, including the Marseilles Pool. Exelon (2015b) has not 12 identified any increasing trend in cooling pond temperatures to date, although this observation is 13 based on limited data. Regardless, as detailed in Section 3.5.1.3 of this SEIS, the chemical and 14 thermal quality of LSCSs discharges to the Illinois River are subject to the effluent limitations 15 and monitoring requirements prescribed by its NPDES permit (IEPA 2013). Additionally, 16 thermal mixing zone limits set by LSCSs NPDES permit indirectly limit surface water 17 withdrawals and consumptive water use during low river flow and extreme summer weather 18 events.
19 Future thermal and pollutant discharges from new and modified industrial and large commercial 20 facilities in the lowermost Upper Illinois River Basin would be required to comply with applicable 21 NPDES permit requirements under the Federal CWA, local and regional health standards, and 22 TMDLs imposed by the State of Illinois.
23 Conclusion 24 Surface water availability is expected to continue to be sufficient through the license renewal 25 term, based on the projections and associated assumptions cited above. Surface water from 26 the Marseilles Pool of the Illinois River has been able to support ongoing demands for uses 27 ranging from navigation to cooling and thermoelectric power generation to commercial and 28 industrial water supply. Flows within the Upper Illinois River Basin and through the Marseilles 29 Pool are not likely to decrease and may trend higher during the LSCS license renewal term, in 30 part due to climate-induced hydrologic changes. No increase in LSCS consumptive water use 31 is expected during the license renewal term. Surface water withdrawals and associated 32 consumptive water use for LSCS operations are expected to remain a small percentage of the 33 mean annual and 90-percent exceedance flow through the Marseilles Pool of the Illinois River.
34 It is reasonable to anticipate that water-quality-based limits imposed by the IEPA through 35 NPDES permits and other measures on cooling water, wastewater, and stormwater discharges 36 and similar limits on sources of development, agricultural, and urban runoff will continue to 37 maintain or improve ambient surface water quality in the Illinois River. LSCSs combined 38 cooling pond blowdown, wastewater, and stormwater discharges to the Illinois River are 39 regulated under an IEPA-administered NPDES permit. Available data indicate that LSCS 40 operations are a very small contributor to the pollutant and thermal loading to the Illinois River.
41 Based on the foregoing, the NRC staff concludes that the cumulative impacts from past, 42 present, and reasonably foreseeable future actions and trends on surface water resources 43 during the license renewal term would be SMALL.
44 4.16.3.2      Groundwater Resources 45 This section addresses the direct and indirect effects of license renewal on groundwater use 46 and quality when added to the aggregate effects of other past, present, and reasonably 47 foreseeable future actions. As noted in Section 4.5.1.2, the NRC staff concludes the impacts of 48 the proposed action (license renewal) on groundwater consumption and quality would be 4-120
 
Environmental Consequences and Mitigating Actions 1 SMALL. All groundwater consumed at LSCS is obtained from two wells completed in the 2 Cambrian-Ordovician Aquifer (see Section 3.5.2.2).
3 LaSalle County has an adequate supply of groundwater for industrial, municipal, and domestic 4 purposes (LaSalle County 2014). The Cambrian-Ordovician Aquifer System is a major source 5 of water in LaSalle County. Groundwater levels in the Cambrian-Ordovician Aquifer System of 6 LaSalle County and the plant area have shown little change from 1995 to 2007 7 (Burch 2002, 2008). Even if this trend does not continue, the plant is unlikely to have a 8 significant impact on the Cambrian-Ordovician Aquifer System.
9 Ongoing operations have not impacted the groundwater quality of aquifers on or off the site.
10 The Cambrian-Ordovician Aquifer System is overlain by 312 ft (95 m) of aquitards, which 11 prevent the groundwater quality from being impacted by site activities. Whether an aquifer is 12 located on site or off site, the low permeability, thickness, and lateral extent of the Wedron 13 Silty-Clay Till means there is little chance of significant impact to groundwater quality from site 14 activities.
15 Considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes 16 that the cumulative impacts on groundwater use and quality during the LSCS license renewal 17 term would be SMALL.
18 4.16.4    Terrestrial Resources 19 This section addresses the direct and indirect effects of license renewal on terrestrial resources 20 when added to the aggregate effects of other past, present, and reasonably foreseeable future 21 actions. Section 4.6 of this SEIS finds that the direct and indirect impacts on terrestrial 22 resources from the proposed license renewal, when considered in the absence of the aggregate 23 effects, would be SMALL. The cumulative impact is the total effect on terrestrial resources of all 24 actions taken, no matter who has taken the actions (the second principle of cumulative effects 25 analysis in CEQ 1997).
26 Two related concepts bound the analysis of cumulative impacts: (1) the timeframe and 27 (2) geographic extent. The timeframe for cumulative analyses for ecological resources extends 28 far enough into the past to understand the processes that affect the present resource conditions 29 and to examine whether and why terrestrial resources are stable or unstable, which the NRCs 30 definitions of impact levels require. The timeframe for cumulative impact analysis is more 31 extensive than that for the direct and indirect impact analysis.
32 The geographic extent considered in this cumulative terrestrial resource analysis depends on 33 the particular cumulative impacts being discussed. Direct and indirect impacts from LSCS 34 operation are largely limited to the LSCS site and immediate vicinity. However, projects or 35 actions located beyond this geographic area could directly or indirectly affect terrestrial 36 resources in this area. This section focuses on the cumulative effects of such actions.
37 The level of cumulative impacts is measured against a baseline. Consistent with other Federal 38 agencies and the Council on Environmental Qualitys (CEQ 1997) NEPA guidance, the term 39 baseline pertains to the condition of the resource without the action (i.e., under the no-action 40 alternative). Under the no-action alternative, the plant would shut down, and the resource would 41 conceptually return to its condition without the plant (which is not necessarily the same as the 42 condition before the plant was constructed). The baseline, or benchmark, for assessing 43 cumulative impacts on terrestrial resources takes into account the preoperational environment, 44 as recommended by EPA (1999b) for its review of NEPA documents.
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Environmental Consequences and Mitigating Actions 1 Past Development and Habitat Alteration 2 The LSCS site was partially disturbed during the construction of the facility to develop site 3 buildings and infrastructure and to create the cooling pond. Of the sites 1,528 ha (3,776 ac),
4 65 ha (160 ac) were permanently converted for industrial use to support buildings and 5 infrastructure, and approximately 800 ha (1,976 ac) are occupied by the cooling pond. During 6 construction, some additional land may have been temporarily disturbed to allow for laydown 7 areas for construction supplies or storage of construction equipment.
8 In the broader areathe Illinois/Indiana Prairies Level IV Ecoregionnative tallgrass prairies, 9 wetlands, and floodplain forests have been converted to agricultural and urban land, which now 10 account for the major land-use types. Habitat loss, in general, can negatively affect breeding 11 success, dispersal success, predation rate, and other animal behaviors (Fahrig 2003). Habitat 12 fragmentation (the breaking up of a larger area of habitat into smaller patches of smaller total 13 area) can also negatively affect terrestrial biota. In a study of breeding bird communities in 14 24 Illinois grassland fragments, Herkert (1994) found that fragmentation was likely a factor in 15 Midwestern grassland bird population declines. A study conducted in 2012 on the partridge pea 16 (Chamaecrista fasciculata) concludes that native prairie plant species that occur in smaller, 17 isolated prairie fragments are likely to suffer a reduction in genetic fitness (Mannouris and 18 Byers 2013). IDNR (2005) reports that remaining prairie remnants within the State lack many 19 natural ecosystem functions, due to their small size, and areas of prairie restoration often lack 20 forbs or are overly dominated by big bluestem (Andropogon gerardii) or Indiangrass 21 (Sorghastrum nutans). Accordingly, remaining native populations in these habitats are likely to 22 suffer from reduced genetic fitness, which is further exacerbated by fragmentation.
23 Energy Production and Development 24 Two nuclear power plant sites with four operating reactors (Braidwood Station, Units 1 and 2, 25 and Dresden Nuclear Power Station, Units 2 and 3) lie within 50 mi (80 km) of the LSCS site.
26 Because the effects of these facilities would primarily be limited to the terrestrial resources on 27 each plants site and the immediate vicinity, the operation of these two facilities during the 28 proposed LSCS license renewal term would not result in cumulative effects to the terrestrial 29 resources affected by LSCS operation.
30 Four fossil-fuel-fired energy facilities occur in the region (Table E-1 in Appendix E) and each is 31 about 20 mi (30 km) from LSCS. Although no coal or gas energy projects are under 32 construction in the region at this time, other energy development may arise over the proposed 33 license renewal term. Air emissions from these facilities include GHGs, such as nitrogen 34 oxides, carbon dioxide, and methane, all of which can have far-reaching consequences 35 because they cumulatively contribute to climate change. The effects of climate change on 36 terrestrial resources are discussed in Section 4.15.3.2.
37 Four wind energy facilities exist in the region (Table E-1 in Appendix E). Grand Ridge Wind 38 Farm is a 140-unit wind facility located immediately west of the LSCS property, and it extends 39 southwest for approximately 8 mi (13 km). The other three wind facilities are located between 40 6 mi (10 km) and 27 mi (43 km) from the LSCS site and consist of a total of 450 wind units.
41 Operation of wind farms can result in direct mortality of birds and bats through collision with 42 turbine blades as well as indirect effects, such as wildlife avoidance, habitat disruption, reduced 43 nesting or breeding density, habitat abandonment, and behavioral effects 44 (Stewart et al. 2005, 2007). Given that the majority of bird and bat species are migratory, 45 effects of wind farms on bird and bat populations can be far reaching.
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Environmental Consequences and Mitigating Actions 1 Development, Urbanization, and Habitat Fragmentation 2 As the region surrounding the LSCS site becomes more developed, habitat fragmentation will 3 increase, and the amount of forested, prairie, and wetland habitat is likely to decline further.
4 Transmission lines, pipelines, and associated corridors established to connect new buildings to 5 the regional electric grid and to utilities could further fragment habitats if the corridors split 6 otherwise continuous tracts of habitat. Edge species that prefer open or partially open habitats 7 will likely benefit from the fragmentation, whereas species that require interior forest or wetland 8 habitat will likely suffer.
9 Continued urbanization in the future will likely include construction of additional housing units 10 and associated commercial buildings; roads, bridges, and rail; and water or wastewater 11 treatment and distribution facilities and associated pipelines. Increased development will likely 12 decrease the overall availability and quality of terrestrial habitats. Species that require larger 13 ranges, especially larger predators, will likely suffer reductions in their populations. Similarly, 14 species with threatened or endangered Federal or State status or otherwise declining 15 populations would be more sensitive to declines in habitat availability and quality. Native prairie 16 plants will likely continue to experience reductions in genetic fitness, as previously discussed.
17 Wildlife Refuges, State Parks, and Recreational Areas 18 A number of State parks, State Fish and Wildlife Areas, and State Natural Areas and 19 recreational areas are located near LSCS (Table E-1 in Appendix E) that provide valuable 20 habitat to native wildlife, migratory birds, and protected terrestrial species and habitats. Illini 21 State Park, which comprises 510 ac (206 ha) and lies 6 mi (10 km) north-northwest of the LSCS 22 site, provides habitat for a number deciduous trees, including hickory (Carya spp.), ash 23 (Fraxinus spp.), walnut (Juglans spp.), elm (Ulmus spp.), cottonwood (Populus deltoids), oak 24 (Quercus spp.), and maple (Acer spp.), as well as white-tailed deer (Odocoileus virginianus),
25 eastern gray squirrels (Sciurus carolinensis), opossums (Didelphis virginiana), beavers (Castor 26 canadensis), raccoon (Procyon lotor), groundhogs (Marmota monax), and a variety of waterfowl 27 and songbirds (IDNR 2015a). Starved Rock State Park, which comprises 2,700 ac (1,090 ha) 28 and lies 15 mi (24 km) northwest of the LSCS site along the Illinois River, contains a variety of 29 habitats, including canyons, sandstone bluffs, rolling plains, forest, upland prairies, waterfalls, 30 rivers, and streams, and provides particularly high-quality habitat to many species of native 31 wildlife and migrating birds. As fragmentation and land-use changes continue, these protected 32 areas will become ecologically more important because they provide large, uninterrupted areas 33 of minimally disturbed habitat.
34 Conclusion 35 The NRC staff concludes that the cumulative impacts on terrestrial resources in the vicinity of 36 the LSCS site are MODERATE to LARGE, based on past, present, and reasonably foreseeable 37 future actions. This level of impact is primarily the result of past habitat alteration and loss on 38 the LSCS site and within the larger Illinois/Indiana Prairies Level IV Ecoregion. The 39 environmental effects of these actions are clearly noticeable and have destabilized important 40 attributes of certain terrestrial communities. The loss of genetic fitness of native prairie species 41 and the loss of tallgrass prairies, wetlands, and floodplains are demonstrative of such effects.
42 The incremental, site-specific impact from the continued operation of LSCS during the license 43 renewal period would be an unnoticeable or minor contributor to cumulative impacts on 44 terrestrial resources.
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Environmental Consequences and Mitigating Actions 1 4.16.5    Aquatic Resources 2 This section addresses the direct and indirect effects of license renewal on aquatic resources 3 when added to the aggregate effects of other past, present, and reasonably foreseeable future 4 actions. Section 4.7 finds that the direct and indirect impacts on aquatic resources from the 5 proposed license renewal would be SMALL for all aquatic ecology issues, with the exception of 6 MODERATE impacts to shad from heat shock in the cooling pond. The geographic area 7 considered in the cumulative aquatic resources analysis includes the LSCS cooling pond and 8 the vicinity of the intake and discharge structures on the Illinois River affected by LSCS water 9 withdrawal and discharge. The baseline, or benchmark, for assessing cumulative impacts on 10 aquatic resources takes into account the preoperational environment as recommended by EPA 11 (1999b) for its review of NEPA documents.
12 Section 3.7 presents an overview of the current condition of the LSCS cooling pond and Illinois 13 River and the history and factors that led to current conditions. In summary, the direct and 14 indirect impacts from draining wetlands, construction of locks and dams, maintenance of 15 navigation channels, industrial effluent, and sewage discharge are some of the most influential 16 human activities on the Illinois River Basin (Parker 2014). By the 1960s, biodiversity of fish 17 within the upper Illinois River was low and freshwater mussels were nearly absent from the 18 upper Illinois River (Sietman et al. 2001). Pollution-tolerant non-native common carp (Cyprinus 19 carpio) and goldfish (Carassius auratus) dominated fish populations (Parker 2014). Since the 20 passage of the CWA in 1974, water quality within the Illinois River has improved, and more 21 diverse fish assemblages have inhabited the upper Illinois River (Parker 2014). Similarly, 22 freshwater mussels have recolonized portions of the upper Illinois River since the 1980s 23 (Sietman et al. 2001).
24 Many natural and anthropogenic activities can influence the current and future aquatic biota in 25 the area surrounding the LSCS site and the Illinois River Basin. Potential biological stressors 26 include operational impacts from LSCS (as described in Section 4.7), energy development, and 27 urbanization.
28 4.16.5.1    Energy Development 29 Several other power plants withdraw water from and discharge water to the Illinois River (see 30 Appendix E). The largest nuclear power plant near LSCS and located on the Illinois River is the 31 Dresden Nuclear Station, located on River Mile 272.3 of the Illinois River. Dresden Nuclear 32 Station withdraws water from the Kankakee River and discharges to the Illinois River (EA 2015).
33 For 3.5 months of the year, Dresden operates in an indirect-open-cycle mode, and during the 34 remainder of the year (8.5 months), Dresden operates its cooling pond in a closed-cycle mode, 35 similar to LSCS. Operating in a closed-cycle mode reduces the impacts to aquatic resources 36 because less water is withdrawn and discharged, and therefore, less thermal effluent is 37 discharged to the Illinois River. The NRC (2004) determined that the impacts from 38 impingement, entrainment, and heat shock from Dresden Nuclear Station would be SMALL on 39 aquatic resources. Furthermore, it is unlikely that the thermal effluent from Dresden Nuclear 40 Station and LSCS overlap, given that both thermal plumes dissipate within the vicinity of each 41 respective discharge structure and the distance between the two plants (NRC 2004; 42 Exelon 2014a). Impingement and entrainment at both plants could affect similar fish 43 populations; however, operating in the closed-cycle mode would reduce impacts to fish 44 (NRC 2004; EA 2015).
45 Kendall County Generation is a natural-gas-fueled plant with 1,140 MW generating capacity that 46 withdraws water from and discharges water to the Illinois River. This plant is approximately 47 27 mi (43 km) northeast of LSCS. Given that the discharge plumes are limited to the vicinity of 4-124
 
Environmental Consequences and Mitigating Actions 1 the discharge structures, the heated effluent from the two plants would not likely overlap.
2 However, many of the same fish populations could be affected by impingement and entrainment 3 at LSCS and Kendall County Generation.
4 The other power plants located on the Illinois River have a much smaller generating capacity 5 less than 180 MW (see Appendix E)and therefore require less cooling water. Given the lower 6 withdraw and discharge rates, effects to aquatic resources from impingement, entrainment, and 7 thermal effluents would also be lower at these facilities.
8 Several wind and solar farms operate within 50 mi (80 km) of LSCS (see Appendix E). These 9 facilities would not have detectable impacts on aquatic resources in the Illinois River because, in 10 general, they do not require water during operation.
11 4.16.5.2    Future Urbanization and Transportation Development 12 Future urbanization in the vicinity of LSCS would likely include construction of new housing units 13 and associated commercial buildings; roads, bridges, and rail; and water or wastewater 14 treatment (or both), distribution facilities, and associated pipelines. Continued development of 15 the area has the potential to increase the rate and volume of stormwater runoff and reduce 16 groundwater recharge. If not managed appropriately, such development could result in 17 increased flooding, higher and more frequent storm-related flows, and low flows of longer 18 duration in streams. The increased runoff rates and high channel velocities from inappropriately 19 managed sites could result in excessive bank erosion and associated sedimentation and stream 20 degradation in the Illinois River and its tributaries. As a result, aquatic biota populations may 21 experience habitat degradation or loss, reduced food or prey availability, and increased 22 susceptibility to exotic species invasions. Such potential impacts can be mitigated through 23 implementation of BMPs that address stormwater quality, quantity, and discharge. Stormwater 24 BMPs are often required by state and local regulations, which would ensure that impacts to 25 aquatic resources resulting from future development would be appropriately mitigated.
26 4.16.5.3    Wildlife Preserves, Parks, and Recreational Areas 27 Several wildlife preserves, parks, and recreation sites lie within the vicinity of LSCS (see 28 Appendix E), including the Marseilles State Fish and Wildlife Area, which lies 1.5 mi (2.4 km) 29 north of the LSCS site. The continued preservation of these areas will protect aquatic habitats 30 and, as land development continues, these areas will become ecologically more important 31 because they will provide large areas of unfragmented natural habitat.
32 4.16.5.4    Illinois Wildlife Conservation Plan 33 The State of Illinois maintains a Comprehensive Wildlife Conservation Plan and Strategy 34 (IDNR 2005), which is implemented by the IDNR and numerous Federal, State, local, and 35 private partners. The plan addresses long-range landscape-level planning initiatives, which 36 include projects to address declining wildlife populations and conservation and restoration of 37 ecologically important, sensitive, and rare habitats. Part of the plan includes the Conservation 38 Reserve Enhancement Program, which is a voluntary program to assist landowners in 39 protecting environmentally sensitive land, decreasing erosion, restoring wildlife habitat, 40 increasing populations of threatened and endangered species, and safeguarding groundwater 41 and surface water in the Illinois River Basin (IDNR 2005). Commitment to this plan will help 42 protect or restore aquatic habitats and continue to support a diversity of aquatic life in the future.
43 4.16.5.5    Conclusion 44 The stresses from past river flow alterations, increasing urbanization, and demand for water 45 resources across the geographic area of interest depend on many factors that the NRC staff 46 cannot quantify but that are likely to noticeably alter aquatic resources when all stresses on the 4-125
 
Environmental Consequences and Mitigating Actions 1 aquatic communities are assessed cumulatively. Continued protection of aquatic habitats 2 through wildlife preserves, parks, and recreational areas, as well as the implementation of the 3 Illinois Wildlife Conservation Plan, will likely mitigate some of these effects, and, therefore, the 4 NRC staff finds it reasonable to assume that these activities will ensure that future actions do 5 not destabilize important attributes of the aquatic resources in the vicinity of LSCS. Accordingly, 6 the NRC staff concludes that the cumulative impacts from the proposed license renewal and 7 other past, present, and reasonably foreseeable projects would be MODERATE.
8 4.16.6    Historic and Cultural Resources 9 This section addresses the direct and indirect effects of license renewal on historic and cultural 10 resources when added to the aggregate effects of other past, present, and reasonably 11 foreseeable future actions. The geographic area considered in this analysis is the APE 12 associated with the proposed undertaking, as described in Section 3.9.
13 The archaeological record for the region indicates prehistoric and historic occupation of the 14 LSCS site and its immediate vicinity. Given the location of identified cultural resources, the 15 construction of LSCS may have resulted in destruction of cultural resources within the LSCS 16 site and its immediate vicinity.
17 Other land uses in the vicinity of LSCS may have resulted in impacts on and the loss of, cultural 18 resources on the LSCS site and its immediate vicinity. However, there remains the possibility 19 for additional historic or cultural resources to be located within the LSCS site. The present and 20 reasonably foreseeable projects that could affect these resources, reviewed in conjunction with 21 license renewal, are noted in Appendix E of this document. Direct impacts would occur if 22 historic and cultural resources in the APE were physically removed or disturbed. It is unlikely 23 that the projects discussed in Appendix E would impact historic and cultural resources on the 24 LSCS site because those resources are not in areas that would be subject to foreseeable future 25 development.
26 As described in Section 4.9 of this document, no known cultural resources would be adversely 27 affected by LSCS license renewal activities, as no associated changes or ground-disturbing 28 activities will occur (Exelon 2014a). Moreover, as discussed in Section 4.9, Exelon has 29 established draft procedures to ensure cultural resources are considered in project planning 30 during operation of LSCS.
31 The NRC staff concludes that the cumulative impact of the proposed license renewal on historic 32 and cultural resources, when combined with other past, present, and reasonably foreseeable 33 future activities, would be SMALL.
34 4.16.7    Socioeconomics 35 This section addresses socioeconomic factors that have the potential to be directly or indirectly 36 affected by changes in operations at LSCS, in addition to the aggregate effects of other past, 37 present, and reasonably foreseeable future actions. The primary geographic area of interest 38 considered in this cumulative analysis includes LaSalle, Grundy, and Will Counties, where 39 approximately 83 percent of LSCS employees reside (see Table 3-15). This is where the 40 economy, tax base, and infrastructure would most likely be affected because the majority of 41 LSCS workers and their families reside, spend their incomes, and use their benefits within these 42 counties.
43 As discussed in Section 4.10, continued operation of LSCS during the license renewal term 44 would have no impact on socioeconomic conditions in the region beyond what is already being 45 experienced. Since Exelon has no plans to hire additional workers during the license renewal 4-126
 
Environmental Consequences and Mitigating Actions 1 term, overall expenditures and employment levels at LSCS would remain relatively unchanged 2 with no new or increased demand for housing and public services. Based on this and other 3 information presented in Chapter 4, there would be no contributory effect on socioeconomic 4 conditions in the region during the license renewal term from the continued operation of LSCS 5 beyond what is currently being experienced. Therefore, the only contributory effects would 6 come from reasonably foreseeable future planned activities at LSCS, unrelated to the proposed 7 action (license renewal), and other reasonably foreseeable planned offsite activities. For 8 example, offsite residential development is planned throughout the LSCS region. The 9 availability of new housing could attract individuals and families from outside the region, 10 increasing the local population and causing increased traffic on local roads, as well as increased 11 demand for public services.
12 When combined with other past, present, and reasonably foreseeable future activities, the 13 contributory effects of continued reactor operations at LSCS would have no new or increased 14 impact on socioeconomic conditions in the region beyond what is currently being experienced.
15 4.16.8    Human Health 16 The NRC and EPA established radiological dose limits for protection of the public and workers 17 from both acute and long-term exposure to radiation and radioactive materials. These dose 18 limits are codified in 10 CFR Part 20 and 40 CFR Part 190. As discussed in Section 4.11.1, the 19 NRC staff concluded that impacts to human health from continued plant operations are SMALL.
20 For the purposes of this analysis, the geographical area considered is the area included within 21 an 80-km (50-mi) radius of the LSCS plant site. There are four other nuclear power plants 22 within the applicable geographical area: Braidwood Station, Units 1 and 2, and Dresden 23 Nuclear Power Station, Units 2 and 3. Also, LSCSs 80-km (50-mi) radius overlaps with the 24 80-km (50-mi) radii of Byron Station, Units 1 and 2; Quad Cities Nuclear Power Station, Units 1 25 and 2; and Clinton Power Station, Unit 1. As discussed in Section 3.1.4.4, in addition to storing 26 its spent nuclear fuel in a storage pool, LSCS stores some of its spent nuclear fuel in an onsite 27 independent spent fuel storage installation (ISFSI).
28 EPA regulations in 40 CFR Part 190 limit the dose to members of the public from all sources in 29 the nuclear fuel cycle, including nuclear power plants, fuel fabrication facilities, waste disposal 30 facilities, and transportation of fuel and waste. As discussed in Section 3.1.4.5, LSCS has a 31 REMP that measures radiation and radioactive materials in the environment from LSCS, its 32 ISFSI, and all other sources. The NRC staff reviewed the radiological environmental monitoring 33 results for the 5-year period from 2010 to 2014 as part of the cumulative impacts assessment.
34 The NRC staffs review of Exelons data showed no indication of an adverse trend in 35 radioactivity levels in the environment from LSCS or its ISFSI. The data showed that there was 36 no measurable impact to the environment from operations at LSCS.
37 The NRC staff concludes that the cumulative radiological impacts of the proposed license 38 renewal, when combined with other past, present, and reasonably foreseeable future activities, 39 would be SMALL. This is based on the NRC staffs review of REMP data, radioactive effluent 40 release data, worker dose, and LSCSs expected continued compliance with Federal radiation 41 protection standards during continued operation, and regulation of any future development or 42 actions in the vicinity of the LSCS site by the NRC and the State of Illinois.
43 4.16.9    Environmental Justice 44 The environmental justice cumulative impact analysis evaluates the potential for 45 disproportionately high and adverse human health and environmental effects on minority and 46 low-income populations that could result from past, present, and reasonably foreseeable future 4-127
 
Environmental Consequences and Mitigating Actions 1 actions, including the continued operational effects of LSCS during the renewal term. Everyone 2 living near LSCS currently experiences its operational effects, including minority and low-income 3 populations. The NRC addresses environmental justice matters for license renewal by 4 identifying the location of minority and low-income populations, determining whether there would 5 be any potential human health or environmental effects to these populations, and determining if 6 any of the effects may be disproportionately high and adverse.
7 Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal adverse 8 impacts on human health. Disproportionately high and adverse human health effects occur 9 when the risk or rate of exposure to an environmental hazard for a minority or low-income 10 population is significant and exceeds the risk or exposure rate for the general population or for 11 another appropriate comparison group. Disproportionately high environmental effects refer to 12 impacts or risks of impacts on the natural or physical environment in a minority or low-income 13 community that are significant and appreciably exceed the environmental impact on the larger 14 community. Such effects may include biological, cultural, economic, or social impacts. Some of 15 these potential effects have been identified in resource areas presented in preceding sections of 16 Chapter 4 in this SEIS. As previously discussed in this chapter, the impact from license renewal 17 for all resource areas (e.g., land, air, water, ecology, and human health) would be SMALL.
18 As discussed in Section 4.12 of this SEIS, there would be no disproportionately high and 19 adverse impacts on minority and low-income populations from the continued operation of LSCS 20 during the license renewal term. Since Exelon has no plans to hire additional workers during 21 the license renewal term, employment levels at LSCS would remain relatively constant, and 22 there would be no additional demand for housing or increased traffic. Based on this information 23 and the analysis of human health and environmental impacts presented in the preceding 24 sections, it is not likely there would be any disproportionately high and adverse contributory 25 effect on minority and low-income populations from the continued operation of LSCS during the 26 license renewal term. Therefore, the only contributory effects would come from the other 27 reasonably foreseeable future planned activities at LSCS, unrelated to the proposed action 28 (license renewal), and other reasonably foreseeable planned offsite activities.
29 Conclusion 30 Exelon has no reasonably foreseeable future planned activities at LSCS beyond continued 31 reactor operations. When combined with other past, present, and reasonably foreseeable future 32 activities, the ongoing contributory effects of continued reactor operations at LSCS would not 33 likely cause disproportionately high and adverse human health and environmental effects on 34 minority and low-income populations residing in the vicinity of LSCS beyond what is currently 35 being experienced.
36 4.16.10 Waste Management 37 This section describes waste management impacts during the license renewal term when added 38 to the aggregate effects of other past, present, and reasonably foreseeable future actions. For 39 the purpose of this cumulative impacts analysis, the area within a 50-mi (80-km) radius of LSCS 40 was considered. The NRC staff concluded, in Section 4.11, that the potential human health 41 impacts from LSCSs waste during the license renewal term would be SMALL.
42 As discussed in Sections 3.1.4 and 3.1.5, Exelon maintains waste management programs for 43 radioactive and nonradioactive waste generated at LSCS and is required to comply with Federal 44 and State permits and other regulatory requirements for the management of waste material.
45 The nuclear power plants and other facilities within a 50-mi (80-km) radius of LSCS are also 46 required to comply with appropriate NRC, EPA, and state requirements for the management of 47 radioactive and nonradioactive waste. Current waste management activities at LSCS would 4-128
 
Environmental Consequences and Mitigating Actions 1 likely remain unchanged during the license renewal term, and continued compliance with 2 Federal and State requirements for radioactive and nonradioactive waste is expected.
3 Based on the above, the NRC staff concludes that the potential cumulative impacts from 4 radioactive and nonradioactive waste during the license renewal term would be SMALL.
5 Continued compliance with Federal and State requirements for radioactive and nonradioactive 6 waste management by Exelon is expected.
7 4.16.11 Global Climate Change 8 This section addresses the impact of GHG emissions resulting from continued operation of 9 LSCS on global climate change when added to the aggregate effects of other past, present, and 10 reasonably foreseeable future actions.
11 The impacts of climate change on air, water, and ecological resources are discussed in 12 Section 4.15.3. Climate is influenced by both natural and human-induced factors; the observed 13 global warming (increase in Earths surface temperature) in the 21st century has been attributed 14 to the increase in GHG emissions resulting from human activities (USGCRP 2009). Climate 15 model projections indicate that future climate change is dependent on current and future GHG 16 emissions (IPCC 2007b; USGCRP 2009, 2014). As described in Section 4.15.3.1, operations at 17 LSCS emit GHG emissions.
18 The cumulative impact of a GHG emission source on climate is global. GHG emissions are 19 transported by wind and become well mixed in the atmosphere as a result of their long 20 atmospheric residence time. Therefore, the extent and nature of climate change is not specific 21 to where GHGs are emitted. In April 2015, EPA published the official U.S. inventory of GHG 22 emissions, which identifies and quantifies the primary anthropogenic sources and sinks of 23 GHGs. The EPA GHG inventory is an essential tool for addressing climate change and 24 participating with the United Nations Framework Convention on Climate Change to compare the 25 relative global contribution of different emission sources and GHGs to climate change. In 2013, 26 the United States emitted 6,673 teragrams (Tg) (6,673 million metric tons (MMT)) of carbon 27 dioxide equivalents (CO2eq), and from 1990 to 2013, emissions increased by 5.9 percent 28 (EPA 2015d). In 2012 and 2013, the total amount of CO2eq emissions related to electricity 29 generation was 2,022 Tg (2,022 MMT) and 2,039 Tg (2,039 MMT), respectively (EPA 2015d).
30 The Energy Information Administration (EIA) reported that, in 2013, electricity production alone 31 in Illinois was responsible for 94.1 MMT CO2eq (EIA 2015a). Facilities that emit 25,000 MT 32 CO2eq or more per year are required to annually report their GHG emissions to EPA. These 33 facilities are known as direct emitters, and the data are publicly available in EPAs facility-level 34 information on GHGs tool (FLIGHT). In 2013, FLIGHT identified 11 facilities in LaSalle County, 35 Illinois, where LSCS is located, that emitted a total of 0.89 MT CO2eq (EPA 2015c). In 2012, 36 FLIGHT identified 290 facilities in Illinois that emitted a total of 134 MMT CO2eq (EPA 2015c).
37 Appendix E provides a list of current and reasonably foreseeable future projects and actions 38 that could contribute to GHG emissions. Permitting and licensing requirements and other 39 mitigative measures can minimize the impacts of GHG emissions. For instance, in 2012, EPA 40 issued a final GHG Tailoring Rule (77 FR 41051) to address GHG emissions from stationary 41 sources under the CAA permitting requirements; the GHG Tailoring Rule establishes when an 42 emission source will be subject to permitting requirements and control technology to reduce 43 GHG emissions. On June 25, 2013, President Obama set forward a plan to reduce carbon 44 pollution. The Climate Action Plan will reduce carbon pollution, prepare the United States for 45 the impacts of climate change, and lead international efforts to combat global climate change.
46 The Clean Power Plan Final Rule (80 FR 64661-65120), aimed at reducing carbon pollution 47 from power plants, requires carbon emissions from the power sector to be 32 percent below 4-129
 
Environmental Consequences and Mitigating Actions 1 2005 levels (870 million tons less). The Clean Power Plan sets forth carbon dioxide emission 2 performance rate standards for power plants that should be achieved by 2030. Future actions 3 and steps taken to reduce GHG emissions can lessen the impacts on climate change.
4 EPAs U.S. inventory of GHG emissions illustrates the diversity of GHG sources, such as 5 electricity generation, industrial processes, and agriculture. As presented in Section 4.15.3, 6 direct GHG emissions from combustion sources resulting from operations at LSCS range from 7 245 to 1,022 MT CO2eq, and total emissions range from 34,228 to 39,997 MT CO2eq. In 8 comparing LSCSs GHG emission contribution to different emissions sources, whether it be total 9 U.S. GHG emissions, emissions from electricity production in Illinois, or emissions on a county 10 level, GHG emissions from LSCS are minor relative to these inventories; this is evident, as 11 presented in Table 4-23. The emissions impact of a single source on climate change requires 12 that a climate model account for that specific emissions source in order to project the magnitude 13 and extent of climate change. Climate models indicate that short-term climate change (through 14 the year 2030) is dependent on past GHG emissions. Therefore, climate change is projected to 15 occur with or without present and future GHG emissions from LSCS. The NRC staff concludes 16 that the incremental impact from the contribution of GHG emissions from continued operation of 17 LSCS on climate change would be SMALL.
18 Due to the global significance of GHG emissions, this global climate change cumulative impacts 19 analysis considers the entire Earths atmosphere and therefore global emissions (as opposed to 20 county, state, or national emissions). As discussed in Section 4.15.3.2, climate change and 21 climate-related environmental changes have been observed on a global level, and climate 22 models indicate that future climate change will depend on present and future GHG emissions.
23 With continued increases in GHG emission rates, climate models project that Earths average 24 surface temperature will continue to increase and climate-related changes will persist.
25 Therefore, the cumulative impact of GHG emissions on climate change is noticeable but not 26 destabilizing. The NRC staff concludes that the cumulative impacts of GHG emissions from 27 past, present, and reasonably foreseeable future actions are MODERATE. However, as 28 discussed above, the incremental addition of GHG emissions from continued operation of 29 LSCS, when compared to global emissions, are minor.
30                        Table 4-23. Comparison of GHG Emission Inventories Source                                                                                    CO2eq MMT/year Global Fossil Fuel Combustion Emissions        (2013) (a)                                      36,000 U.S. Emissions (2013)(b)                                                                          6,673 Illinois (2013)(c)                                                                                  134 LaSalle County, Illinois (2013)(c)                                                                    0.89 LSCS(d)                                                                                                0.04 (a) Source: GCP 2014 (b) Source: EPA 2015d (c) GHG emissions account only for direct emitters, those facilities that emit 25,000 MT or more a year (EPA 2015c).
(d) Emissions rounded from and obtained from Exelon 2015c.
31 4.16.12 Summary of Cumulative Impacts 32 The NRC staff considered the potential impacts resulting from the operation of LSCS during the 33 period of extended operation and other past, present, and reasonably foreseeable future actions 4-130
 
Environmental Consequences and Mitigating Actions 1 near LSCS. The preliminary determination is that the potential cumulative impacts would range 2 from SMALL to LARGE, depending on the resource. Table 4-24 summarizes the cumulative 3 impacts on resource areas.
4                Table 4-24. Summary of Cumulative Impacts on Resource Areas Resource Area    Cumulative Impact Air Quality and  Past, present, and reasonably foreseeable future activities exist in the geographic Noise            areas of interest (local for noise; local and regional for criteria pollutants) that could affect air quality and noise resources. However, the incremental contribution of impacts on air quality and noise resources from plant operations at LSCS would be minimal. The NRC staff concludes that cumulative impacts from LSCS related actions and other past, present, and reasonably foreseeable future actions on air quality and noise resources in the geographic areas of interest would be SMALL.
Geology and      Any use of geologic materials, such as aggregates to support operation and Soils            maintenance activities, would be procured from local and regional sources. These materials are abundant in the region, and geologic conditions are not expected to change during the license renewal term. Thus, activities associated with continued operations are not expected to affect the geologic environment. Considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes that the cumulative impacts on geology and soils during the LSCS license renewal term would be SMALL.
Water            No increase in LSCS consumptive water use is expected during the license renewal Resources        term. Surface water availability is expected to continue to be sufficient through the license renewal term, and surface water withdrawals and associated consumptive water use for LSCS operations are expected to remain a small percentage of the flow through the Marseilles Pool of the Illinois River. LaSalle County has an adequate supply of groundwater for industrial, municipal and domestic purposes, and ongoing operations at LSCS have not affected groundwater quality. Therefore, considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes that cumulative impact of the proposed license renewal, combined with other past, present, and reasonably foreseeable future activities, would be SMALL on surface water and groundwater resources.
Terrestrial      NRC staff concludes that the cumulative impacts on terrestrial resources in the vicinity Ecology          of the LSCS site are MODERATE to LARGE based on past, present, and reasonably foreseeable future actions. This level of impact is primarily the result of past habitat alteration and loss on the LSCS site and within the larger region. The environmental effects of these actions are clearly noticeable and have destabilized important attributes of certain terrestrial communities. The incremental, site-specific impact from the continued operation of LSCS during the license renewal period would be an unnoticeable or minor contributor to cumulative impacts on terrestrial resources.
Aquatic Ecology The stresses from past river flow alterations, increasing urbanization, and demand for water resources across the geographic area of interest depend on many factors that NRC staff cannot quantify, but that are likely to noticeably alter aquatic resources when all stresses on the aquatic communities are assessed cumulatively. Continued protection of aquatic habitats through wildlife preserves, parks, and recreational areas, as well as the implementation of the Illinois Wildlife Conservation Plan will likely mitigate some of these effects, and, therefore, the NRC staff finds it reasonable to assume that these activities will ensure that future actions do not destabilize important attributes of the aquatic resources in the vicinity of LSCS. Accordingly, the NRC staff concludes that the cumulative impacts from the proposed license renewal and other past, present, and reasonably foreseeable projects would be MODERATE.
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Environmental Consequences and Mitigating Actions Resource Area    Cumulative Impact Historical      No known cultural resources would be adversely affected by LSCS license renewal and Cultural    activities as no associated changes or ground-disturbing activities would occur.
Resources        Exelon has established draft procedures to ensure cultural resources are considered in project planning during operation of LSCS. Therefore, the NRC staff concludes that the cumulative impact of the proposed license renewal when combined with other past, present, and reasonable foreseeable future activities on historic and cultural resources would be SMALL.
Socioeconomics When combined with other past, present, and reasonably foreseeable future activities, the contributory effects from the continued operation of LSCS during the license renewal period would have no new or increased impact on socioeconomic conditions beyond what is currently being experienced.
Human Health    The NRC staff concludes that the cumulative radiological impacts of the proposed LSCS license renewal, when combined with other past, present, and reasonably foreseeable future activities, would be SMALL.
Environmental    The NRC staff concludes that the contributory effects of continued reactor operations Justice          at LSCS, when combined with other past, present, and reasonably foreseeable future activities considered, would not likely cause disproportionately high and adverse human health and environmental effects on minority and low-income populations residing in the vicinity of LSCS.
Waste            NRC staff concludes that the potential cumulative impacts from radioactive and Management      nonradioactive waste during the license renewal term would be SMALL. Continued compliance with Federal and State requirements for radioactive and nonradioactive waste management by Exelon is expected.
Global Climate  Climate change and climate-related changes have been observed on a global level, Change          and climate models indicate that future climate change will depend on present and future GHG emissions. Climate models project that Earths average surface temperature will continue to increase and climate-related changes will persist.
Therefore, the cumulative impact of GHG emissions on climate change during the LSCS license renewal timeframe would be noticeable but not destabilizing. The NRC staff concludes that the cumulative impacts from the proposed license renewal and other past, present, and reasonably foreseeable projects would be MODERATE.
1 4.17    Resource Commitments 2 4.17.1      Unavoidable Adverse Environmental Impacts 3 Unavoidable adverse environmental impacts are impacts that would occur after implementation 4 of all workable mitigation measures. Carrying out any of the energy alternatives considered in 5 this SEIS, including the proposed action, would result in some unavoidable adverse 6 environmental impacts.
7 Minor unavoidable adverse impacts on air quality would occur, due to emission and release of 8 various chemical and radiological constituents from power plant operations. Nonradiological 9 emissions resulting from power plant operations are expected to comply with EPA emissions 10 standards, although the alternative of operating a fossil-fueled power plant in some areas may 11 worsen existing attainment issues. Chemical and radiological emissions would not exceed the 12 national emission standards for hazardous air pollutants.
13 During nuclear power plant operations, workers and members of the public would face 14 unavoidable exposure to radiation and hazardous and toxic chemicals. Workers would be 4-132
 
Environmental Consequences and Mitigating Actions 1 exposed to radiation and chemicals associated with routine plant operations and the handling of 2 nuclear fuel and waste material. Workers would have higher levels of exposure than members 3 of the public, but doses would be administratively controlled and would not exceed standards or 4 administrative control limits. In comparison, the alternatives involving the construction and 5 operation of a non-nuclear power generating facility would also result in unavoidable exposure 6 to hazardous and toxic chemicals to workers and the public.
7 The generation of spent nuclear fuel and waste material, including low-level radioactive waste, 8 hazardous waste, and nonhazardous waste, would be unavoidable. Hazardous and 9 nonhazardous wastes would be generated at non-nuclear power generating facilities. Wastes 10 generated during plant operations would be collected, stored, and shipped for suitable 11 treatment, recycling, or disposal in accordance with applicable Federal and state regulations.
12 Due to the costs of handling these materials, power plant operators would be expected to carry 13 out all activities and optimize all operations in a way that generates the smallest amount of 14 waste possible.
15 4.17.2    Short-Term Versus Long-Term Productivity 16 The operation of power generating facilities would result in short-term uses of the environment, 17 as described in Chapter 4. Short term is the period of time that continued power generating 18 activities take place.
19 Power plant operations require short-term use of the environment and commitment of resources 20 (e.g., land and energy), indefinitely or permanently. Certain short-term resource commitments 21 are substantially greater under most energy alternatives, including license renewal, than under 22 the no-action alternative because of the continued generation of electrical power and the 23 continued use of generating sites and associated infrastructure. During operations, all energy 24 alternatives entail similar relationships between local short-term uses of the environment and 25 the maintenance and enhancement of long-term productivity.
26 Air emissions from power plant operations introduce small amounts of radiological and 27 nonradiological constituents to the region around the plant site. Over time, these emissions 28 would result in increased concentrations and exposure, but they are not expected to impact air 29 quality or radiation exposure to the extent that public health and long-term productivity of the 30 environment would be impaired.
31 Continued employment, expenditures, and tax revenues generated during power plant 32 operations directly benefit local, regional, and state economies over the short term. Local 33 governments investing project-generated tax revenues into infrastructure and other required 34 services could enhance economic productivity over the long term.
35 The management and disposal of spent nuclear fuel, low-level radioactive waste, hazardous 36 waste, and nonhazardous waste requires an increase in energy and consumes space at 37 treatment, storage, or disposal facilities. Regardless of the location, the use of land to meet 38 waste disposal needs would reduce the long-term productivity of the land.
39 Power plant facilities are committed to electricity production over the short term. After 40 decommissioning these facilities and restoring the area, the land could be available for other 41 future productive uses.
42 4.17.3    Irreversible and Irretrievable Commitments of Resources 43 This section describes the irreversible and irretrievable commitments of resources that have 44 been noted in this SEIS. Resources are irreversible when primary or secondary impacts limit 4-133
 
Environmental Consequences and Mitigating Actions 1 the future options for a resource. An irretrievable commitment refers to the use or consumption 2 of resources that are neither renewable nor recoverable for future use. Irreversible and 3 irretrievable commitments of resources for electrical power generation include the commitment 4 of land, water, energy, raw materials, and other natural and man-made resources required for 5 power plant operations. In general, the commitments of capital, energy, labor, and material 6 resources are also irreversible.
7 The implementation of any of the energy alternatives considered in this SEIS would entail the 8 irreversible and irretrievable commitments of energy, water, chemicals, andin some cases 9 fossil fuels. These resources would be committed during the license renewal term and over the 10 entire life cycle of the power plant, and they would be unrecoverable.
11 Energy expended would be in the form of fuel for equipment, vehicles, and power plant 12 operations and electricity for equipment and facility operations. Electricity and fuel would be 13 purchased from offsite commercial sources. Water would be obtained from existing water 14 supply systems. These resources are readily available, and the amounts required are not 15 expected to deplete available supplies or exceed available system capacities.
16 4.18    References 17 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, Standards for 18 protection against radiation.
19 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 20 production and utilization facilities.
21 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 22 protection regulations for domestic licensing and related regulatory functions.
23 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 24 renewal of operating licenses for nuclear power plants.
25 10 CFR Part 100. Code of Federal Regulations, Title 10, Energy, Part 100, Reactor site 26 criteria.
27 36 CFR 60.4. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, Part 28 60, National Register of Historic Places, Section 60.4, Criteria for evaluation.
29 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property.
30 Part 800, Protection of Historic Properties.
31 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 32 Requirements for preparation, adoption, and submittal of implementation plans.
33 40 CFR Part 60. Code of Federal Regulations, Title 40, Protection of Environment, Part 60, 34 Standards of Performance for New Stationary Sources.
35 40 CFR Part 63. Code of Federal Regulations, Title 40, Protection of Environment, Part 63, 36 National emission standards for hazardous air pollutants for source categories.
37 40 CFR Part 75. Code of Federal Regulations, Title 40, Protection of Environment, Part 75, 38 Continuous emission monitoring.
39 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 40 Designation of areas for air quality planning purposes.
41 40 CFR Part 125. Code of Federal Regulations, Title 40, Protection of Environment, Part 125, 42 Criteria and standards for the National Pollutant Discharge Elimination System.
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Environmental Consequences and Mitigating Actions 1 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 2 Environmental radiation protection standards for nuclear power operations.
3 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 4 Interagency cooperationEndangered Species Act of 1973, as amended.
5 49 FR 34658. U.S. Nuclear Regulatory Commission. Waste confidence decision and 6 requirements for licensee actions regarding the disposition of spent fuel upon expiration of 7 reactor operating licenses; Final Rules. Federal Register 49 (171): 34658-34696.
8 August 31, 1984.
9 55 FR 38472. U.S. Nuclear Regulatory Commission. Consideration of environmental impacts 10 of temporary storage of spent fuel after cessation of reactor operation; and waste confidence 11 decision review; Final Rules. Federal Register 55 (181): 38472-38514. September 18, 1990.
12 59 FR 7629. Executive Order No. 12898. Federal actions to address environmental justice in 13 minority populations and low-income populations. Federal Register 59 (32): 7629-7634.
14 February 16, 1994.
15 61 FR 28467. U.S. Nuclear Regulatory Commission. Environmental review for renewal of 16 nuclear power plant operating licenses. Final Rule. Federal Register 61 (109): 28467-28497.
17 June 5, 1996.
18 61 FR 66537. U.S. Nuclear Regulatory Commission. Environmental review for renewal of 19 nuclear power plant operating licenses. Federal Register 61 (244): 66537-66544.
20 December 18, 1996.
21 64 FR 68005. U.S. Nuclear Regulatory Commission. Waste confidence decision review:
22 status. Federal Register 64 (233): 68005-68007. December 6, 1999.
23 65 FR 79825. U.S. Environmental Protection Agency. Regulatory finding on the emissions of 24 hazardous air pollutants from electric utility steam generating units. Federal Register 65 (245):
25 79825-79831. December 20, 2000 26 74 FR 38117. U.S. Nuclear Regulatory Commission. Revisions to environmental review for 27 renewal of nuclear power plant operating licenses. Proposed Rule. Federal Register 74 (146):
28 38117-38140. July 31, 2009.
29 74 FR 56260. U.S. Environmental Protection Agency. Mandatory Reporting of Greenhouse 30 Gases. Federal Register 74 (209): 56260-56519. October 30, 2009.
31 74 FR 66496. U.S. Environmental Protection Agency. 2009. Endangerment and cause or 32 contribute findings for greenhouse gases under Section 202(a) of the Clean Air Act.
33 Federal Register 74 (239): 66496-66546. December 15, 2009.
34 75 FR 81032. U.S. Nuclear Regulatory Commission. Consideration of environmental impacts 35 of temporary storage of spent fuel after cessation of reactor operation.
36 Federal Register 75 (246): 81032-81037. December 23, 2010.
37 75 FR 81037. U.S. Nuclear Regulatory Commission. Waste confidence decision update.
38 Federal Register 75 (246): 81037-81076. December 23, 2010.
39 76 FR 48208. U.S. Environmental Protection Agency. Federal Implementation Plans:
40 Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals.
41 Federal Register 76 (152): 48208-48483 4-135
 
Environmental Consequences and Mitigating Actions 1 77 FR 9304. Environmental Protection Agency. National emission standards for hazardous air 2 pollutants from coal- and oil-fired electric utility steam generating units and standards of 3 performance for fossil-fuel-fired electric utility, industrial commercial institutional, and small 4 industrial commercial institutional generating units. Federal Register 77 (32): 9304-9513.
5 77 FR 41051. Environmental Protection Agency. Prevention of significant deterioration and 6 Title V greenhouse gas tailoring rule step 3 and GHG plantwide applicability limits.
7 Federal Register 77 (134): 41051-41075.
8 78 FR 37282. U.S. Nuclear Regulatory Commission. Revisions to environmental review for 9 renewal of nuclear power plant operating licenses. Federal Register 78 (119): 37282-37324.
10 June 20, 2013.
11 79 FR 1430. U.S. Environmental Protection Agency. Standards of Performance for 12 Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units.
13 Federal Register 79 (5): 1430-1519. January 8, 2014.
14 79 FR 48300. U.S. Environmental Protection Agency. National Pollutant Discharge 15 Elimination SystemFinal Regulations to Establish Requirements for Cooling Water Intake 16 Structures at Existing Facilities and Amend Requirements at Phase I Facilities.
17 Federal Register 79 (158): 48300-48439. August 15, 2014.
18 79 FR 56263. U.S. Nuclear Regulatory Commission. Generic environmental impact statement 19 for continued storage of spent nuclear fuel. Federal Register 79 (182): 56263-56264.
20 September 19, 2014.
21 79 FR 56238. U.S. Nuclear Regulatory Commission. Continued storage of spent nuclear fuel.
22 Federal Register 79 (182): 56238-56263. September 19, 2014.
23 79 FR 73705. U.S. Fish and Wildlife Service. 2014. Endangered and threatened wildlife and 24 plants; threatened species status for the rufa red knot. Federal Register 79 (238):
25 73705-73748. December 11, 2014.
26 80 FR 46062. U.S. Nuclear Regulatory Commission. Exelon Generation Company, LLC; LaSalle 27 County Station, Units 1 and 2; Environmental assessment and finding of no significant impact; 28 issuance. Federal Register 80 (148): 46062-46066. August 3, 2015.
29 80 FR 64661. U.S. Environmental Protection Agency. Carbon Pollution Emission Guidelines 30 for Existing Stationary Sources: Electric Utility Generating Units. Federal Register 80 (205):
31 64661-65120. October 23, 2015.
32 35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Part 302, Water 33 Quality Standards.
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35 54 USC 300101. United States Code. Title 54, National Park Service and Related Programs, 36 Section 300101 et seq., National Historic Preservation Act.
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6 (accessed 21 August 2015).
7 Burch, SL. 2002. A Comparison of Potentiometric Surfaces for the Cambrian-Ordovician 8 Aquifers of Northeastern Illinois, 1995 and 2000. Data/Case Study 2002-02, Illinois State 9 Water Survey. 2002. Available at 10 <http://www.isws.illinois.edu/pubdoc/dcs/iswsdcs2002-02.pdf> (accessed 16 June 2015).
11 Burch, SL. 2008. A Comparison of Potentiometric Surfaces for the Cambrian-Ordovician 12 Aquifers of Northeastern Illinois, 2000 and 2007, Data/Case Study 2008-04, Illinois State Water 13 Survey. 2008. Available at <http://www.isws.illinois.edu/pubdoc/DCS/ISWSDCS2008-04.pdf>
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23 Available at 24 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/G-CEQ-ConsidCumulEff 25 ects.pdf> (accessed 21 August 2015).
26 Chen IC, Hill JK, Ohlemuller R, Roy DB, Thomas CD. 2011. Rapid range shifts of species 27 associated with high levels of climate warming. Science 333(6045): 1024-1026.
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30 Daily Herald. 2010. Illinois Emerges as One of the Countrys Leaders in Wind Energy.
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Environmental Consequences and Mitigating Actions 1 Dziegielewski B, Yang X, Bik T, Margono H, Richey M. 2005. County-Level Forecasts of Water 2 Use in Illinois: 2005-2025: Project Completion Report. Carbondale, IL: Southern Illinois 3 University Carbondale. March 30, 2005. 211 p. Available at 4 <http://www.isws.illinois.edu/wsp/waterdemand.asp> (accessed 5 September 2015).
5 [EA] EA Engineering, Science, and Technology, Inc. 2000. Final Report LaSalle Station 6 Aquatic Monitoring 1999, RM 249.7-248.8. Prepared for Commonwealth Edison Company, 7 Marseilles, Illinois. September 2000. Deerfield, Illinois. ADAMS No. ML15273A420.
8 [EA] EA Engineering, Science, and Technology, Inc. 2014. LaSalle County Station 2013 Fish 9 and Benthos Monitoring and Historical Fish and Benthos Comparisons. Prepared for Exelon 10 Generation Company, LLC, Kennett Square, Pennsylvania. May 2014. Deerfield, Illinois.
11 ADAMS No. ML15273A419.
12 [EA] EA Engineering, Science, and Technology, Inc. 2015. Final Impingement and Entrainment 13 Characterization Study LaSalle County Station. Prepared for Exelon Generation Company, 14 LLC, Kennett Square, Pennsylvania. August 2015. Deerfield, Illinois. ADAMS 15 No. ML15243A204.
16 [EIA] U.S. Energy Information Administration. 2011. International Energy Outlook 2011.
17 Washington, DC: EIA. DOE/EIA-0484(2011). September 2011. 301 p. Available at 18 <http://www.eia.gov/forecasts/archive/ieo11/pdf/0484(2011).pdf> (accessed August 2015).
19 [EIA] U.S. Energy Information Administration. 2015a. Electricity, 1990-2013, U.S. Electric 20 Power Industry Estimated Emissions by State (EIA-767, EIA-906, EIA-920, EIA-923).
21 Available at <http://www.eia.gov/electricity/data/state/> (accessed August 2015).
22 [EIA] U.S. Energy Information Administration. 2015b. Frequently Asked Questions, What is 23 U.S. electricity generation by energy source? Available at 24 <http://www.eia.gov/tools/faqs/faq.cfm?id=427&t=3> (accessed August 2015) 25 [ESA] Endangered Species Act of 1973, as amended. 16 U.S.C. &sect;1531 et seq.
26 [EPA] U.S. Environmental Protection Agency. 1998. Guidelines for Ecological 27 Risk Assessment. Washington, DC: EPA Risk Assessment Forum. EPA/630/R-95/002F.
28 188 p. Available at <http://www.epa.gov/raf/publications/pdfs/ECOTXTBX.PDF>
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32 Available at <http://www.epa.gov/ogwdw/mdbp/alternative_disinfectants_guidance.pdf>
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34 [EPA] U.S. Environmental Protection Agency. 1999b. Consideration of Cumulative Impacts in 35 EPA Review of NEPA Documents. EPA-315-R-99-002, Office of Federal Activities (2252A),
36 Washington, D.C. Available at 37 <http://www2.epa.gov/sites/production/files/2014-08/documents/cumulative.pdf>
38 (accessed 20 October 2015).
39 [EPA] U.S. Environmental Protection Agency. 2004. Technical Development Document for the 40 Final Section 316(b) Phase II Existing Facilities Rule. Washington, DC: EPA Office of Water.
41 EPA 821-R-04-007. February 12, 2004. 228 p. Available at 42 <http://water.epa.gov/lawsregs/lawsguidance/cwa/316b/upload/Cooling-Water_Phase-2_TDD_2 43 004.pdf> (accessed 3 June 2014).
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4 [EPA] U.S. Environmental Protection Agency. 2009b. Assessment of the Impacts of Global 5 Change on Regional U.S. Air Quality: A synthesis of Climate Change Impacts on Ground-Level 6 Ozone. EPA/600/R-07/094F. April 2009. Available at 7 <http://ofmpub.epa.gov/eims/eimscomm.getfile?p_download_id=491176>
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9 [EPA] U.S. Environmental Protection Agency. 2014. Climate Change Indicators in the 10 United States, 2014. EPA-430-R-14-004. Available at 11 <http://www.epa.gov/climatechange/pdfs/climateindicators-full-2014.pdf>
12 (accessed 4 August 2015).
13 [EPA] U.S. Environmental Protection Agency. 2015a. Clean Air Act Permitting for Greenhouse 14 Gases. Available at <http://www.epa.gov/nsr/ghgpermitting.html> (accessed August 2015) 15 [EPA] U.S. Environmental Protection Agency. 2015b. Enforcement and Compliance History 16 Online, LaSalle County. Available at <http://echo.epa.gov/?redirect=echo>
17 (accessed August 2015).
18 [EPA] U.S. Environmental Protection Agency. 2015c. EPA Facility Level GHG Emissions Data, 19 Illinois and LaSalle County. Available at <http://ghgdata.epa.gov/ghgp/main.do>
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21 [EPA] U.S. Environmental Protection Agency. 2015d. Inventory of U.S. Greenhouse Gas 22 Emissions and Sinks: 1990-2013. April 15, 2015. Available at 23 <http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2015-Main-T 24 ext.pdf> (accessed August 2015).
25 [EPA] U.S. Environmental Protection Agency. 2015e. Learn About New Source Review.
26 Available at <http://www2.epa.gov/nsr/learn-about-new-source-review>
27 (accessed 5 October 2015).
28 [EPA] U.S. Environmental Protection Agency. 2015f. New Source Review Basic Information 29 on PSD. Available at <http://www.epa.gov/NSR/psd.html> (accessed August 2015).
30 [Exelon] Exelon Generation Company, LLC. 2001. Letter from W. Riffer, Regulatory Assurance 31 Manager, LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
 
32 Environmental Non-Routine Event Report for Exelon Generation Company, LLCLaSalle 33 County Station. August 17, 2001. ADAMS No. ML012330070.
34 [Exelon] Exelon Generation Company, LLC. 2002. Letter from G.T. Kaegi, Regulatory 35 Assurance Manager, LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
 
36 Environmental Protection Plan and Operating Report Appendix B to Facility License 37 No. NPF-11 and NPF-18. April 29, 2002. ADAMS No. ML021330421.
38 [Exelon] Exelon Generation Company, LLC. 2009. Letter from D. Rhoads, Plant Manager, 39 LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
Environmental 40 Non-Routine Event Report for Exelon Generation Company, LLCLaSalle County Station.
41 July 22, 2009. ADAMS No. ML092040381.
42 [Exelon] Exelon Generation Company, LLC. 2010. Letter from P.J. Karaba, Plant Manager, 43 LaSalle County Station to U.S. NRC, Document control Desk.
 
==Subject:==
Environmental 44 Non-Routine Event Report for Exelon Generation Company, LLCLaSalle County Station.
45 August 25, 2010. ADAMS No. ML102371289.
4-139
 
Environmental Consequences and Mitigating Actions 1 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 2 Operating License Renewal Stage LaSalle County Station, Unit 1 License No. NPF-11, Unit 2 3 License No. NPF-18. Chicago, Illinois: Exelon. December 9, 2014. ADAMS 4 Nos. ML14343A849, ML14343A883, and ML14343A897.
5 [Exelon] Exelon Generation Company, LLC. 2014b. LaSalle County Station, Updated Final 6 Safety Analysis Report (UFSAR). Revision 20, April 2014. ADAMS No. ML14113A099.
7 [Exelon] Exelon Generation Company, LLC. 2014c. Letter from M.P. Gallagher, Vice President 8 License Renewal Projects, Exelon, to Dan Heacock, Facility Evaluation Manager, Illinois 9 Environmental Protection Agency.
 
==Subject:==
Application for Clean Water Act Section 401 10 Certification Associated with Renewal of LaSalle County Stations Units 1 and 2 Operating 11 Licenses. February 4, 2014. In Appendix B of ADAMS No. ML14343A883.
12 [Exelon] Exelon Generation Company, LLC. 2015a. LaSalle County Station, Units 1 and 2, 13 Annual Radiological Environmental Operating Report, 1 January through 31 December 2014.
14 May 13, 2015. ADAMS No. ML15141A195.
15 [Exelon] Exelon Generation Company, LLC. 2015b. Letter from M.P. Gallagher, Vice 16 President, License Renewal Projects, to NRC Document Control Desk.
 
==Subject:==
Response to 17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 18 Station, Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015.
19 ADAMS No. ML15195A351.
20 [Exelon] Exelon Generation Company, LLC. 2015c. Letter from M.P. Gallagher, Vice President 21 License Renewal Projects, to NRC Document Control Desk.
 
==Subject:==
Response to NRC 22 Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County Station, 23 Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: LaSalle 24 County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental Review 25 Requests for Additional Information. Response to Request for Additional Information MA-04.
26 July 2, 2015. ADAMS No. ML15195A347.
27 [Exelon] Exelon Generation Company, LLC. 2015d. Letter from M.P. Gallagher, Vice President 28 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 29 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 30 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
31 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 32 Review Requests for Additional Information. Response to Request for Additional Information 33 MA-07. July 2, 2015. ADAMS No. ML15195A350.
34 [Exelon] Exelon Generation Company, LLC. 2015e. Letter from M.P. Gallagher, Vice President 35 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 36 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 37 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
38 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 39 Review Requests for Additional Information. Response to Request for Additional Information 40 TE-02. July 2, 2015. ADAMS No. ML15195A380.
41 [Exelon] Exelon Generation Company, LLC. 2015f. Letter from M.P. Gallagher, Vice President 42 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 43 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 44 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
45 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 46 Review Requests for Additional Information. Response to Request for Additional Information 47 TE-04. July 2, 2015. ADAMS No. ML15195A382.
4-140
 
Environmental Consequences and Mitigating Actions 1 [Exelon] Exelon Generation Company, LLC. 2015g. Letter from M.P. Gallagher, Vice President 2 License Renewal Projects, Exelon, to NRC Document Control Desk.
 
==Subject:==
Response to 3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B:
5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 6 Review Requests for Additional Information. Response to Request for Additional Information 7 TE-05. July 2, 2015. ADAMS No. ML15195A383.
8 [Exelon] Exelon Generation Company, LLC. 2015h. Letter from M.P. Gallagher, Vice 9 President - License Renewal Projects to NRC Document Control Desk.
 
==Subject:==
Response to 10 NRC Request for Additional Information on Severe Accident Mitigation Alternatives Regarding 11 the LaSalle County Station, Units 1 and 2 License Renewal Application Environmental Review.
12 Letter RA15-032. May 29, 2015. ADAMS No. ML15149A370.
13 [Exelon] Exelon Generation Company, LLC. 2015i. Letter from M.P. Gallagher, Vice President 14 License Renewal Projects to NRC Document Control Desk.
 
==Subject:==
Revised Response to 15 Request for Additional Information (RAI) #TR-09 Regarding the LaSalle County Station, Units 1 16 and 2, License Renewal Application, Environmental Review August 28, 2015. ADAMS 17 No. ML15240A002.
18 [Exelon] Exelon Generation Company, LLC. 2015j. Letter from M.P. Gallagher, Vice President, 19 License Renewal Projects, to NRC Document Control Desk.
 
==Subject:==
Revisions to LaSalle 20 County Station, Units 1 and 2, License Renewal Application, Applicants Environmental 21 ReportOperating License Renewal Stage. July 31, 2015. ADAMS No. ML15212A259.
22 Exelon Nuclear. 2010. LaSalle County Station Units 1 and 2, Annual Environmental Operating 23 Report, Annual Radiological Environmental Operating Report, 1 January through 24 31 December 2009. May 2010. ADAMS No. ML101320380.
25 Exelon Nuclear. 2011. LaSalle County Station Units 1 and 2, Annual Environmental Operating 26 Report, Annual Radiological Environmental Operating Report, 1 January through 27 31 December 2010. May 2011. ADAMS No. ML111320602.
28 Exelon Nuclear. 2012. LaSalle County Station Units 1 and 2, Annual Environmental Operating 29 Report, Annual Radiological Environmental Operating Report, 1 January through 30 31 December 2011. May 2012. ADAMS No. ML12130A420.
31 Exelon Nuclear. 2013. LaSalle County Station Units 1 and 2, Annual Environmental Operating 32 Report, Annual Radiological Environmental Operating Report, 1 January through 33 31 December 2012. May 2013. ADAMS No. ML13136A007.
34 Exelon Nuclear. 2014. LaSalle County Station Units 1 and 2, Annual Environmental Operating 35 Report, Annual Radiological Environmental Operating Report, 1 January through 36 31 December 2013. May 2014. ADAMS No. ML14135A214.
37 Exelon Nuclear. 2015. LaSalle County Station Units 1 and 2, Annual Environmental Operating 38 Report, Annual Radiological Environmental Operating Report, 1 January through 39 31 December 2014. May 2015. ADAMS Nos. ML15141A195 and ML15141A219.
40 Fahrig L. 2003. Effects of habitat fragmentation on biodiversity. Annual Review of Ecology, 41 Evolution, and Systematics 34: 487-515.
42 FairWindEnergy. undated. Life in the Vermilion Co., IL, Envernergy LLC Industrial Wind 43 Project. Available at <http://fairwindenergy.org/VermilionWind.php> (accessed August 2015).
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Environmental Consequences and Mitigating Actions 1 FarmProgress. 2010. Wind Farms Generate Conflict Across State. June 2010. Available at 2 <http://farmprogress.com/library.aspx/wind-farms-generate-conflict-across-state-90/93/546>
3 (accessed August 2015).
4 [FHWA] Federal Highway Administration. 2006. Construction Noise Handbook. Available at 5 <http://www.fhwa.dot.gov/environment/noise/construction_noise/handbook/>
6 (accessed June 2015).
7 [FHWA] Federal Highway Administration. 2011. Highway Traffic Noise Analysis and 8 Abatement Policy and Guidance. Available at 9 <https://www.fhwa.dot.gov/environment/noise/regulations_and_guidance/polguide/
10 polguide02.cfm> (accessed August 2015).
11 Federal Water Pollution Control Act (Clean Water Act) of 1972, as amended.
12 33 U.S.C. &sect;1251 et seq.
13 Fraser KC, Silverio C, Kramer P, Mickle N, Aeppli R, Stutchbury BJM. 2013. A 14 trans-hemispheric migratory songbird does not advance spring schedules or increase migration 15 rate in response to record-setting temperatures at breeding sites. PLoS ONE 8(5): e64587.
16 Fritts, MW. 2013. Email from M.W. Fritts, Illinois Natural History Survey, to P. Moore, Tetra 17 Tech.
 
==Subject:==
RE: Request: Illinois River Reports. June 24, 2013. ADAMS 18 No. ML15273A418.
19 [FWS] U.S. Fish and Wildlife Service. 2014. Guidance for Preparing a Biological Assessment.
20 6 p. Available at <http://www.fws.gov/midwest/endangered/section7/pdf/BAGuidance.pdf>
21 (accessed 29 May 2014).
22 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 23 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 24 September 30 2015. Accessed 9 October 2015. Available at 25 http://www.fws.gov/midwest/endangered/lists/illinois-cty.html 26 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC.
 
==Subject:==
LaSalle 27 Power Plant License Renewal. List of threatened and endangered species that may occur in 28 your proposed project location, and/or may be affected by your proposed project.
29 27 February 2015. ADAMS No. ML15126A069.
30 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998.
31 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 32 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p.
33 Available at <http://www.nmfs.noaa.gov/pr/pdfs/laws/esa_section7_handbook.pdf>
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36 Available at <http://www.globalcarbonproject.org/carbonbudget/14/hl-compact.htm>
37 (accessed August 2015).
38 [GE] General Electric. 2010. How Loud is a Wind Turbine? Available at 39 <http://www.gereports.com/how-loud-is-a-wind-turbine/> (August 2015).
40 Groschen GE, Arnold TL, Harris MA, Dupr&#xe9; DH, Fitzpatrick FA, Scudder BC, Morrow WS, 41 Terrio PJ, Warner KL, Murphy EA. 2004. Water Quality in the Upper Illinois River Basin, 42 Illinois, Indiana, Wisconsin, 1999-2001. Reston, VA: U.S. Geological Survey. Circular 1230.
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3 Hessler DM (Hessler Associates, Inc.). 2011. Assessing Sound Emissions from Proposed 4 Wind Farms and Measuring the Performance of Completed Projects. Washington, DC: The 5 National Association of Regulatory Utility Commissioners (NARUC). October 13, 2011. 69 p.
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28 [IDPH] Illinois Department of Public Health. 2014. Letter from K. Marshall, IDPH, to Exelon.
29
 
==Subject:==
LaSalle County Station Units 1 and 2 - Consultation about thermophilic organisms.
30 February 28, 2014. ADAMS No. ML15273A445.
31 [IEPA] Illinois Environmental Protection Agency. 2013. NPDES Permit No. IL0048151, National 32 Pollutant Discharge Elimination System, Reissued (NPDES) Permit. Exelon Generation 33 Company, LLC, LaSalle County Generating Station. Effective date, August 1, 2013.
34 Springfield, IL: Division of Water Pollution Control. In: LaSalle County Station, Units 1 and 2, 35 License Renewal Application, Appendix E, Applicants Environmental Report, Operating License 36 Renewal Stage. ADAMS No. ML14343A897 (Appendix C).
37 [IEPA] Illinois Environmental Protection Agency. 2014. Letter from G. Good, Manager, IEPA, to 38 Exelon.
 
==Subject:==
LaSalle County Station Units 1 and 2 - Consultation about thermophilic 39 organisms. February 28, 2014. ADAMS No. ML15273A446.
40 [IPCC] Intergovernmental Panel on Climate Change. 2007a. Climate Change 2007: Impacts, 41 Adaptation and Vulnerability. Contribution of Working Group II to the Fourth Assessment 42 Report of the Intergovernmental Panel on Climate Change. Parry ML, Canziani OF, 43 Palutikof JP, van der Linden PJ, Hanson CE, editors. Cambridge University Press, Cambridge, 44 United Kingdom.
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5 [IPCC] Intergovernmental Panel on Climate Change. 2007c. Climate Change 2007: The 6 Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of 7 the Intergovernmental Panel on Climate Change. Solomon S, Qin D, Manning M, Chen Z, 8 Marquis M, Averyt KB, Tignor M, Miller HL, editors. Cambridge University Press, Cambridge, 9 United Kingdom, and New York, New York, United States.
10 [IPCC] Intergovernmental Panel on Climate Change. 2007c. Climate Change 2007: The 11 Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of 12 the Intergovernmental Panel on Climate Change.
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==Subject:==
LaSalle County Station, Units 1 and 2 License 17 Renewal Application Review. February 9, 2015. ADAMS No. ML15022A578.
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==Subject:==
LaSalle County Station, Units 1 and 2 20 License Renewal Application Review. February 9, 2015. ADAMS No. ML15023A094.
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22
 
==Subject:==
Request for Scoping Comments concerning the LaSalle County Station, Units 1 and 2 23 License Renewal Application Review. February 9, 2015. ADAMS No. ML15023A139.
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1                                     
 
==5.0 CONCLUSION==
 
2 This draft supplemental environmental impact statement (SEIS) contains the environmental 3 review of the application for renewed operating licenses for LaSalle County Station, Units 1 4 and 2 (LSCS), submitted by Exelon Generation Company, LLC (Exelon), as required by the 5 Code of Federal Regulations (CFR), Part 51 of Title 10 (10 CFR Part 51), the U.S. Nuclear 6 Regulatory Commissions (NRCs) regulations that implement the National Environmental Policy 7 Act (NEPA). This chapter presents conclusions and recommendations from the site-specific 8 environmental review of LSCS. Section 5.1 summarizes the environmental impacts of license 9 renewal; Section 5.2 presents a comparison of the environmental impacts of license renewal 10 and energy alternatives; and Section 5.3 presents the NRC staff preliminary conclusions and 11 recommendation.
12 5.1    Environmental Impacts of License Renewal 13 The NRC staffs review of site-specific environmental issues in this SEIS leads to the conclusion 14 that issuing renewed licenses at LSCS would have SMALL to MODERATE impacts for the 15 Category 2 issues applicable to license renewal at LSCS. The NRC staff considered mitigation 16 measures for each Category 2 issue, as applicable. The NRC staff concluded that no additional 17 mitigation measure is warranted.
18 5.2    Comparison of Alternatives 19 In Chapter 4, the staff considered the following alternatives to LSCS license renewal:
20
* no-action alternative, 21
* new nuclear alternative, 22
* integrated gasification combined-cycle alternative, 23
* natural gas combined-cycle (NGCC) alternative, 24
* combination alternative (NGCC, wind, solar), and 25
* purchased power.
26 Based on the summary of environmental impacts provided in Table 2-2, the NRC staff 27 concluded that the environmental impacts of renewal of the operating licenses for LSCS would 28 be smaller than those of feasible and commercially viable alternatives. The no-action 29 alternative, the act of shutting down LSCS on or before its license expiration dates, would have 30 SMALL environmental impacts with the exception of socioeconomic impacts which would have 31 SMALL to LARGE environmental impacts. Continued operation of LSCS would have SMALL to 32 MODERATE environmental impacts for aquatic resources and SMALL environmental impacts in 33 all other areas. The NRC staff concluded that continued operation of LSCS is the 34 environmentally preferred alternative.
35 5.3    Recommendation 36 The NRCs preliminary recommendation is that the adverse environmental impacts of license 37 renewal for LSCS are not great enough to deny the option of license renewal for 38 energy-planning decisionmakers. This recommendation is based on the following:
5-1
 
Conclusion 1
* the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic Environmental 2          Impact Statement for License Renewal of Nuclear Plants; 3
* the environmental report submitted by Exelon; 4
* the NRC staffs consultation with Federal, State, local, and Tribal Government 5          agencies; 6
* the NRC staffs environmental review; and 7
* the NRC staffs consideration of public comments received during the scoping 8          process.
5-2
 
1                                  6.0 LIST OF PREPARERS 2 This supplemental environmental impact statement (SEIS) was prepared by members of the 3 Office of Nuclear Reactor Regulation (NRR) with assistance from other U.S. Nuclear Regulatory 4 Commission (NRC) organizations and contract support from Pacific Northwest National 5 Laboratory (PNNL), the Center for Nuclear Waste Regulatory Analyses (CNWRA), a private 6 contractor and Idoneous Consulting, Inc. (Idoneous). Table 6-1 lists the NRC staff who 7 contributed to the development of the SEIS. PNNL provides contract support for analysis of 8 transportation impacts of high burnup fuel. CNWRA provides contract support for severe 9 accident mitigation alternative (SAMA) reviews. Idoneous provides contract support for 10 technical editing reviews.
11                                      Table 6-1. List of Preparers Name                    Education/Experience                    Function or Expertise NRC-NRR Jim Danna              M.S., Civil Engineering/Geology          Management oversight 29 years of experience in engineering and project management including 16 years at NRC, including as an NRC technical and projects branch manager David Wrona            B.S., Electrical Engineering; 27 years of Management oversight nuclear plant experience, including as an NRC resident inspector, reactor engineer, project manager, and projects and technical branch manager David Drucker          B.S., General Engineering;                Project management M.S., Engineering Management; 34 years of project and program management experience Jeffrey Rikhoff        M.R.P., Regional Planning;                Socioeconomics and environmental M.S., Economic Development and            justice Appropriate Technology; B.A., English; 35 years of combined industry and government experience including 28 years in NEPA compliance, environmental impact analysis, socioeconomics and environmental justice impact analysis, cultural resource impacts, and comprehensive land-use and development planning Bill Rautzen          B.S., Health Physics; B.S., Industrial    Human health, radiological, and waste Hygiene; M.S. Health Physics; 5 years    management of experience in environmental impact analysis 6-1
 
List of Preparers Name              Education/Experience                    Function or Expertise Kevin Folk        B.A., Geoenvironmental Studies;          Surface water resources M.S., Environmental Biology; 25 years of experience in NEPA compliance; geologic, hydrologic, and water quality impacts analysis; utility infrastructure analysis; and environmental regulatory compliance and water supply and wastewater discharge permitting Briana Grange      B.S., Conservation Biology; 10 years of  Terrestrial ecology, land use, and visual experience in environmental impact      resources analysis, section 7 consultations, and essential fish habitat consultations Nancy Martinez    A.M., Earth and Planetary Science;      Air quality, noise, and climate change B.S., Earth and Environmental Science; 4 years of experience in environmental impact analysis Michelle Moser    M.S., Biological Sciences;              Aquatic ecology and microbiological B.S., Environmental Sciences;            hazards 13 years of experience in ecological studies, environmental impact assessment, and protected resource management Jerry Dozier      M.S. Reliability Engineering; M.B.A. SAMA Business Administration; B.S.
Mechanical Engineering; 30 years of experience including operations, reliability engineering, technical reviews, and NRC branch management Russell Chazell  B.S., Liberal Studies; J.D, Law;          Historic and cultural resources M.S., Nuclear Engineering; Certificate    Non-radioactive waste management in Project Management; Certificate in    Non-radioactive human health NEPA; 26 years of combined industry and government experience including analytical and environmental laboratory science, laboratory project management, technical business development, engineering project management, and NEPA compliance William Ford      M.S., Geology; 41 years of combined      Geologic environment and groundwater industry and government experience        resources working on groundwater, surface water, and geology projects and associated technical and environmental analyses Robert Hoffman    B.S., Environmental Resource            Alternatives and cumulative effects Management; 29 years of experience in NEPA compliance, environmental impact assessment, alternatives identification and development, and energy facility siting 6-2
 
List of Preparers Name                          Education/Experience                      Function or Expertise Dennis Logan                Ph.D., Marine Studies and Biological      Threatened and endangered species Oceanography; M.S., Biological Sciences, Marine Biology; B.S.,
Zoology; 40 years of experience in ecological studies, ecological risk assessment, environmental impact assessment, protected resource management, and project management Don Palmrose                B.S., Nuclear Engineering; M.S.,          High burnup fuel transportation impacts Nuclear Engineering; Ph.D., Nuclear Engineering; 30 years of relevant experience National Laboratory Personnel Steve Maheras,                B.A. Zoology;                            High burnup fuel transportation impacts PNNL(a)                      M.S. Health Physics Ph.D. Health Physics 27 years of experience in health physics and transportation risk assessment Commercial Contractors R. Benke, CNWRA (b) Ph.D., Nuclear Engineering,                        SAMA M. Eng., Radiological Health B.S., Nuclear Engineering, 20 years of experience in nuclear engineering, radiological health, risk analysis, and is a certified health physicist D. Speaker, CNWRA B.S., Nuclear Engineering                            SAMA M.S., Nuclear Engineering 10 years of experience in nuclear engineering, radiation detection, instrumentation, nondestructive evaluation, and nuclear reactor design and analysis E.R. Schmidt,                B.S., Mechanical Engineering;            SAMA Contractor                    M.S., Nuclear Engineering 50 years of nuclear industry experience including 35 year experience in performing, managing and reviewing Probabilistic Risk Assessments Susan Anastasi,                                                        Technical Editing Idoneous (a) Pacific Northwest National Laboratory (PNNL) is operated by Battelle for the U.S. Department of Energy.
(b) CNWRA    is a federally funded research and development center sponsored by the NRC.
1 6-3
 
1 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM 2                        COPIES OF THIS SEIS ARE SENT Name                        Affiliation J. Barrett                  Tribal NationCitizen Potawatomi Nation H. Frank                    Tribal NationForest County Potawatomi K. Meshigaud                Tribal NationHannahville Indian Community, Band of Potawatomi J. Greendeer                Tribal NationHo-Chunk Nation S. Cadue                    Tribal NationKickapoo Tribe in Kansas G. Salazar                  Tribal NationKickapoo Tribe of Oklahoma D. Lankford                Tribal NationMiami Tribe of Oklahoma J. Froman                  Tribal NationPeoria Tribe of Indians in Oklahoma J. Warren                  Tribal NationPokagon Band of Potawatomi S. Ortiz                    Tribal NationPrairie Band of Potawatomi Nation J. Bender                  Tribal NationSac and Fox Tribe of the Mississippi in lowa/Meskwaki B. Robidoux                Tribal NationSac and Fox Nation of Missouri in Kansas and Nebraska G. Thurman                  Tribal NationSac and Fox Nation J. Blackhawk                Tribal NationWinnebago Tribe of Nebraska R. Nelson                  Advisory Council on Historic Preservation J. Duyvejonck              U.S. Fish & Wildlife Service R. Leibowitz                Illinois Historic Preservation Agency Alan Keller                Illinois Environmental Protection Agency Nathan Grider              Illinois Department of Natural Resources Patty Smith                Mayor, City of Marseilles, Illinois Bob Eschbach                Mayor, City of Ottawa, Illinois David Spicer                Mayor, Village of Seneca, Illinois Kay Hines                  Mayor, City of Grand Ridge, Illinois EIS Scoping Meeting Participants Reed Wilson                Office of U.S. Representative Kinzinger Elizabeth Poole            U.S. EPA Region 5 Jerry Hicks                LaSalle County Board Chairman Rick Zuffa                  Illinois Emergency Management Agency Cecil Settles              Illinois Emergency Management Agency Doug OBrien                Illinois Clean Energy Coalition Jim Carlson                Superintendent, Seneca Township High School Roger Blumquist            Argonne National Laboratory Beth Jung                  Nuclear Power Illinois Linda Lewison              Nuclear Energy Information Service Ruth Thomas                Environmentalists, Inc.
Marvin Lewis                Public 7-1
 
List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent Name                        Affiliation Tom Walsh                  LaSalle County Board, District 18 Connie Brooks              Director, LaSalle County Emergency Management Agency Nelson Dewey                Public Shelli Ocepak              United Way of Eastern LaSalle County Mike Gallagher              Exelon Generation Company Chris Wilson                Exelon Generation Company Krista Lopykinski          Exelon Generation Company John Keenan                Exelon Generation Company Megan Borchers              Exelon Generation Company Bryan Mooney                Exelon Generation Company Pete Karaba                Exelon Generation Company Harold Vinyard              Exelon Generation Company Jay Houston                Exelon Generation Company Nancy Ranek                Exelon Generation Company 7-2
 
1                                                            8.0 INDEX 2 A                                                              42 Coastal Zone Management Act 43  (CZMA).......................... 3-22, 3-112, B-4 3 accidents ............................ xxiv, xxix, xxx, 4  3-8, 3-12, 3-72, 3-100, 4-75, 4-76, 4-77,                    44 cold shock ..........................................4-52 5  4-78, 4-79, 4-80, 4-86, 4-88, 4-91, 4-98,                    45 consumptive use ......................3-40, 4-23, 6  F-1, F-2, F-8, F-9, F-10, F-11, F-12,                        46  4-27, 4-28, 4-29, 4-33, 4-52 7  F-13, F-15, F-16, F-17, F-18, F-24, F-25,                    47 cooling system ............................ xxii, xxiii, 8  F-34, F-37, F-39, F-41, F-46, G-1, G-3,                      48  xxviii, 1-3, 1-5, 2-10, 2-12, 2-13, 2-14, 9  G-4, G-9, G-11, G-12                                          49  3-6, 3-7, 3-8, 3-59, 3-72, 3-74, 3-98, 10  Advisory Council on Historic                                    50  4-19, 4-22, 4-24, 4-31, 4-32, 4-33, 4-37, 11    Preservation (ACHP) ..................... xxvii,              51  4-39, 4-41, 4-44, 4-45, 4-53, 4-54, 4-74, 12    1-6, 4-60, 4-147, 7-1, B-6, C-3                              52  4-86, 4-87, 4-117, F-6, F-9, F-25, F-26, 13  aesthetic ................3-41, 3-101, 4-64, 4-96              53  F-30, F-37 14  alternatives .................................... iii, xxiv,    54 core damage frequency (CDF) ......... xxvii, 15    1-4, 2-1, 2-3, 2-4, 2-5, 2-7, 2-16, 2-17,                    55  4-78, 4-79, 4-80, 4-83, 4-84, 4-86, F-1, 16    2-20, 2-21, 2-23, 2-24, 4-1, 4-6, 4-17,                      56  F-2, F-3, F-5, F-6, F-7, F-9, F-10, F-11, 17    4-18, 4-20, 4-21, 4-29, 4-30, 4-35, 4-36,                    57  F-12, F-13, F-14, F-15, F-17, F-20, F-24, 18    4-37, 4-55, 4-59, 4-64, 4-71, 4-72, 4-77,                    58  F-27, F-30, F-31, F-32, F-33, F-37, F-40, 19    4-91, 4-97, 4-99, 4-100, 4-102, 4-107,                        59  F-42 20    4-132, 4-133, 4-134, 5-1, 6-2, B-2, C-2,                      60 Council on Environmental Quality 21    F-29, F-30, F-43                                              61  (CEQ) ....................................... xxvii, 1-3, 22  archaeological resources ............1-6, 2-4,                  62  3-101, 3-112, 4-39, 4-121, 4-137 23    3-80, 3-82, 4-62, 4-63, 4-64, 4-126                          63 critical habitat ...........................3-73, 3-75, 64  3-76, 3-77, 3-78, 3-79, 4-55, 4-57, 4-58, 24 B                                                                65  B-6, C-1, C-2 25  biocide ................................................3-11    66 cultural resources ....................... xxiii, 2-4, 26  biological assessment ................ C-1, C-2                67  2-26, 3-23, 3-79, 3-82, 4-59, 4-60, 4-61, 68  4-62, 4-63, 4-64, 4-102, 4-112, 4-126, 27  biota ......3-10, 3-11, 3-63, 4-35, 4-41, 4-44,                69  4-132, 6-1, 6-2, B-1, B-6 28    4-45, 4-46, 4-51, 4-52, 4-111, 4-122, 29    4-124, 4-125                                                  70 D 30  boiling water reactor ....................2-1, 3-6, 71 decommissioning........................ 2-2, 2-3, 31    4-80, F-1, G-2 72  4-1, 4-2, 4-26, 4-34, 4-52, 4-57, 4-58, 32  burnup ................. 3-6, 6-3, G-2, G-9, G-11              73  4-59, 4-62, 4-66, 4-67, 4-68, 4-69, 4-70, 74  4-98, 4-100, 4-102, 4-103, 4-104, 4-105, 33 C                                                                75  4-106, 4-133, E-1, E-10 34 chronic effects ........4-72, 4-73, 4-88, 4-89                  76 design-basis accident ................ 4-1, 4-76 35 Clean Air Act (CAA) ................. xxvii, 3-25,              77 discharges ................................. 2-8, 2-10, 36    3-26, 3-27, 3-112, 4-11, 4-12, 4-15,                          78  2-12, 2-13, 2-14, 3-1, 3-6, 3-7, 3-8, 3-10, 37    4-129, 4-135, 4-137, 4-139, B-3, B-8                          79  3-11, 3-12, 3-13, 3-14, 3-22, 3-35, 3-36, 38 closed-cycle cooling ..................2-8, 2-12,                80  3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 39    2-13, 2-14, 3-6, 3-7, 4-24, 4-25, 4-27,                      81  3-48, 3-54, 3-60, 3-63, 3-64, 3-65, 3-69, 40    4-28, 4-40, 4-41, 4-44, 4-45, 4-53, 4-117,                    82  3-74, 3-75, 3-97, 3-98, 3-99, 3-106, 4-22, 41    4-124                                                        83  4-23, 4-24, 4-26, 4-27, 4-28, 4-30, 4-32, 84  4-37, 4-45, 4-46, 4-47, 4-48, 4-49, 4-51, 8-1
 
Index 1  4-52, 4-53, 4-72, 4-73, 4-74, 4-75, 4-85,                      48  3-30, 3-32, 3-33, 3-34, 3-35, 3-36, 3-38, 2  4-87, 4-103, 4-116, 4-118, 4-119, 4-120,                      49  3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 3  4-124, 4-125, 6-2, B-3, B-4, E-4, E-8,                        50  3-46, 3-47, 3-48, 3-49, 3-51, 3-54, 3-55, 4  F-29, F-34, F-41, G-7, G-9                                    51  3-56, 3-57, 3-58, 3-59, 3-60, 3-63, 3-64, 5 dose ...........................................xxxi, 3-13,      52  3-67, 3-68, 3-69, 3-70, 3-72, 3-74, 3-76, 6  3-14, 3-15, 3-16, 3-96, 3-97, 3-106, 4-80,                    53    3-77, 3-78, 3-79, 3-80, 3-82, 3-83, 3-84, 7  4-83, 4-101, 4-127, 4-148, B-2, B-5, F-3,                    54    3-85, 3-92, 3-93, 3-94, 3-95, 3-96, 3-97, 8  F-19, F-20, F-21, F-22, F-30, F-31, F-39,                    55    3-100, 3-106, 3-113, 3-114, 3-115, 9  F-40, F-42, G-1, G-3, G-4, G-5, G-7, G-8,                    56    3-116, 3-117, 3-118, 3-120, 3-121, 10  G-9, G-10, G-11, G-12                                        57    3-122, 3-125, 3-127, 4-1, 4-3, 4-7, 4-8, 58  4-22, 4-23, 4-24, 4-25, 4-31, 4-32, 4-33, 11 dredging ...................................2-10, 3-45, 59  4-34, 4-35, 4-38, 4-40, 4-41, 4-44, 4-45, 12  3-74, 4-22, 4-26, 4-28, 4-35, 4-37, 4-53, 60  4-47, 4-49, 4-50, 4-51, 4-52, 4-55, 4-56, 13  B-7 61  4-60, 4-61, 4-65, 4-69, 4-72, 4-73, 4-74, 14 E                                                                62  4-75, 4-77, 4-78, 4-79, 4-80, 4-81, 4-82, 63  4-83, 4-86, 4-87, 4-88, 4-92, 4-93, 4-98, 15 education ........................3-90, 3-120, 4-65              64  4-101, 4-103, 4-105, 4-113, 4-114, 16 electromagnetic fields ..................... xxviii,            65  4-115, 4-118, 4-119, 4-120, 4-124, 17  4-72, 4-73, 4-88, 4-89                                        66  4-126, 4-127, 4-128, 4-129, 4-130, 18 endangered and threatened                                        67  4-132, 4-136, 4-138, 4-139, 4-140, 19  species ....................................1-6, 3-56,        68  4-141, 4-143, 4-146, 4-147, 5-1, 5-2, 7-2, 20  3-74, 3-75, 3-76, 3-77, 3-79, 3-119, 4-46,                    69  B-7, B-8, C-2, D-1, D-2, E-4, E-8, F-1, 21  4-55, 4-125, 4-136, 4-142, 6-3, B-1, B-6,                      70  F-2, F-3, F-4, F-5, F-6, F-9, F-10, F-11, 22  C-1, C-2, C-5                                                  71  F-12, F-13, F-14, F-15, F-16, F-17, F-18, 72  F-19, F-20, F-21, F-22, F-23, F-24, F-25, 23 Endangered Species Act (ESA)......... xxiii,                    73  F-26, F-27, F-28, F-29, F-30, F-31, F-32, 24  xxviii, 1-5, 1-6, 1-7, 2-4, 2-30, 3-53, 3-57,                  74  F-37, F-38, F-39, F-40, F-41, F-42, F-43, 25  3-73, 3-76, 3-77, 3-79, 3-107, 3-113,                          75  F-44, F-45, F-46, G-2, G-4, G-5, G-9, 26  4-55, 4-56, 4-57, 4-58, 4-59, 4-111,                          76  G-11, G-13 27  4-135, 4-138, 4-142, B-6, B-8, C-1, C-2, 28  C-5                                                            77 F 29 entrainment ............................... xxiii, 3-61, 30  3-70, 3-71, 3-72, 3-74, 3-75, 4-38, 4-39,                      78 Fish and Wildlife Coordination Act 31  4-41, 4-42, 4-43, 4-44, 4-45, 4-52, 4-53,                      79  (FWCA) ..................................... xxix, B-8 32  4-54, 4-124, 4-125, 4-144 80 G 33 environmental justice (EJ)..................2-4, 34  3-101, 3-108, 4-91, 4-92, 4-102, 4-127,                        81 Generic Environmental Impact 35  4-135, 6-1                                                    82  Statement (GEIS) ......................... iii, xxi, 83  xxii, xxv, xxix, 1-2, 1-3, 1-4, 1-5, 1-6, 1-7, 36 essential fish habitat (EFH) ............... xxiii, 84  1-8, 2-1, 2-2, 2-3, 2-4, 2-17, 2-19, 2-31, 37  xxviii, 4-55, 4-58, 6-2, B-6, C-3 85  2-32, 3-6, 3-35, 3-86, 3-99, 3-124, 3-125, 38 eutrophication ................ 3-74, 4-37, 4-111                86  4-1, 4-2, 4-6, 4-7, 4-11, 4-20, 4-22, 4-24, 39 evaporative loss ......................3-40, 4-120              87  4-31, 4-32, 4-33, 4-34, 4-35, 4-36, 4-37, 40 Exelon Generation Company                                        88  4-38, 4-45, 4-52, 4-53, 4-54, 4-55, 4-60, 41  (LLC) ...................................... iii, xxi, xxii,  89  4-62, 4-65, 4-72, 4-73, 4-75, 4-76, 4-77, 42  xxiv, xxv, 1-1, 1-5, 1-6, 1-7, 1-8, 2-1, 2-2,                  90  4-91, 4-97, 4-98, 4-99, 4-100, 4-101, 43  2-3, 2-4, 2-8, 2-9, 2-10, 2-21, 2-26, 2-27,                    91  4-102, 4-103, 4-105, 4-106, 4-145, 44  2-28, 2-30, 3-1, 3-2, 3-3, 3-4, 3-5, 3-6,                      92  4-146, 4-147, 5-2, G-2, G-14 45  3-7, 3-8, 3-9, 3-10, 3-11, 3-12, 3-13,                        93 greenhouse gases..................... 2-7, 2-13, 46  3-14, 3-15, 3-16, 3-17, 3-18, 3-19, 3-20,                      94  3-27, 4-8, 4-135, 4-136 47  3-21, 3-22, 3-23, 3-24, 3-25, 3-27, 3-29, 8-2
 
Index 1 groundwater .............................. xxiii, 3-13,  46  3-57, 3-58, 3-59, 3-60, 3-61, 3-62, 3-63, 2    3-17, 3-18, 3-41, 3-42, 3-43, 3-46, 3-48,            47  3-64, 3-65, 3-66, 3-67, 3-68, 3-69, 3-70, 3    3-51, 3-91, 3-98, 4-21, 4-24, 4-25, 4-26,            48    3-71, 3-72, 3-73, 3-74, 3-75, 3-76, 3-77, 4    4-27, 4-28, 4-29, 4-30, 4-92, 4-93, 4-102,            49    3-78, 3-79, 3-80, 3-82, 3-83, 3-84, 3-85, 5    4-110, 4-117, 4-118, 4-119, 4-120,                    50    3-86, 3-87, 3-88, 3-89, 3-90, 3-91, 3-93, 6    4-121, 4-125, 4-131, 6-2, B-1, E-4                    51    3-94, 3-95, 3-96, 3-97, 3-98, 3-100, 52    3-101, 3-102, 3-103, 3-104, 3-105, 7 H                                                        53    3-106, 3-110, 3-112, 3-113, 3-114, 8 hazardous waste ...............................3-18,    54    3-115, 3-116, 3-117, 3-118, 3-121, 9    4-133, B-5, B-7, B-8                                  55    3-122, 3-125, 3-127, 4-1, 4-2, 4-3, 4-4, 56    4-6, 4-7, 4-8, 4-9, 4-10, 4-11, 4-12, 4-13, 10 heat shock .............4-48, 4-49, 4-51, 4-124          57    4-16, 4-17, 4-19, 4-20, 4-22, 4-23, 4-24, 11 high burnup fuel................... 6-1, D-1, D-2        58  4-25, 4-26, 4-27, 4-28, 4-29, 4-31, 4-32, 12 high-level waste ...........................xxii, 1-3,    59  4-33, 4-34, 4-35, 4-36, 4-37, 4-38, 4-39, 13    4-97, 4-98, 4-101, G-2                                60  4-40, 4-41, 4-42, 4-43, 4-44, 4-45, 4-46, 61  4-47, 4-48, 4-49, 4-50, 4-51, 4-52, 4-53, 14 I                                                        62  4-54, 4-55, 4-56, 4-57, 4-58, 4-59, 4-60, 63  4-61, 4-62, 4-63, 4-65, 4-66, 4-67, 4-68, 15 Illinois Department of Natural 64  4-69, 4-70, 4-71, 4-72, 4-73, 4-74, 4-75, 16    Resources ................................xxix, 3-1, 65  4-77, 4-78, 4-79, 4-80, 4-81, 4-82, 4-83, 17    3-21, 3-22, 3-23, 3-39, 3-43, 3-52, 3-53,              66  4-84, 4-86, 4-87, 4-88, 4-89, 4-91, 4-92, 18    3-56, 3-57, 3-58, 3-59, 3-60, 3-67, 3-68, 67  4-93, 4-94, 4-95, 4-97, 4-98, 4-100, 19    3-69, 3-70, 3-71, 3-72, 3-78, 3-120, 68  4-101, 4-102, 4-103, 4-104, 4-105, 20    3-121, 4-50, 4-51, 4-74, 4-122, 4-123,                69  4-106, 4-107, 4-108, 4-109, 4-110, 21    4-125, 4-143, 7-1, B-7, E-5, E-6, E-8, E-9 70  4-112, 4-113, 4-114, 4-115, 4-116, 22 impingement.............................3-70, 3-71,      71  4-117, 4-118, 4-119, 4-120, 4-121, 23    3-72, 3-74, 3-75, 4-38, 4-39, 4-40, 4-41,              72  4-122, 4-123, 4-124, 4-125, 4-126, 24    4-42, 4-43, 4-44, 4-45, 4-52, 4-53, 4-54,              73  4-127, 4-128, 4-129, 4-130, 4-131, 25    4-124, 4-125                                          74  4-132, 4-136, 4-138, 4-139, 4-140, 26 independent spent fuel storage                            75  4-141, 4-143, 4-144, 4-147, 5-1, A-1, 27    installation (ISFSI) ..................3-1, 3-17,      76  B-2, B-6, B-7, B-8, C-1, C-2, C-4, D-1, 28    3-19, 4-127                                            77  D-2, E-1, E-2, E-8, F-1, F-2, F-3, F-4, 29 Indian tribes ...........................3-81, 3-101,    78  F-5, F-6, F-7, F-8, F-9, F-10, F-11, F-12, 30    3-122, 4-91, 4-92                                      79  F-13, F-14, F-15, F-16, F-17, F-18, F-19, 80  F-20, F-21, F-22, F-23, F-24, F-25, F-26, 31 invasive species......................4-40, 4-111 81  F-27, F-28, F-29, F-30, F-31, F-33, F-37, 82  F-38, F-40, F-41, F-42, F-43, F-44, F-45, 32 L 83  F-46, G-1, G-2, G-3, G-4, G-6, G-7, G-8, 33 LaSalle County Station ................... iii, xxi,      84  G-9, G-10, G-11, G-12, G-13 34    xxii, xxiii, xxiv, xxv, xxx, 1-1, 1-2, 1-4,            85 long-term dose .................................. F-40 35    1-5, 1-6, 1-7, 1-8, 2-1, 2-2, 2-3, 2-4, 2-5, 86 low-level waste ...............3-17, 4-98, 4-101 36    2-8, 2-9, 2-10, 2-12, 2-13, 2-14, 2-16, 37    2-17, 2-18, 2-19, 2-20, 2-21, 2-22, 2-23, 87 M 38    2-24, 2-25, 2-26, 2-30, 3-1, 3-2, 3-3, 3-4, 39    3-5, 3-6, 3-7, 3-8, 3-9, 3-10, 3-11, 3-12,            88 Magnuson-Stevens Fishery 40    3-13, 3-14, 3-15, 3-16, 3-17, 3-18, 3-19,              89  Conservation and Management Act 41    3-20, 3-21, 3-22, 3-23, 3-24, 3-25, 3-26,              90  (MSA) ................................. xxx, 1-5, 1-6, 42    3-27, 3-28, 3-29, 3-30, 3-31, 3-32, 3-33,              91  3-73, 4-58, 4-145, B-6, B-9, C-3 43    3-34, 3-35, 3-36, 3-38, 3-39, 3-40, 3-41,              92 Marine Mammal Protection Act 44    3-42, 3-43, 3-44, 3-45, 3-46, 3-47, 3-49,              93  (MMPA) .................. xxx, 3-73, 3-123, B-9 45    3-50, 3-51, 3-52, 3-53, 3-54, 3-55, 3-56, 8-3
 
Index 1 mitigation.....................................xxii, xxxi,  43 R 2  1-3, 1-4, 4-17, 4-51, 4-53, 4-55, 4-57, 44 radioactive nuclides...........................3-14 3  4-63, 4-64, 4-86, 4-87, 4-132, 4-148, 5-1, 4  D-1, F-9, F-37, F-41                                      45 radon .................................. 3-13, 3-17, G-8 5 mixed waste ..............................3-13, 3-17        46 reactor............................ xxi, xxxi, 2-1, 2-2, 47  2-3, 2-9, 2-10, 2-28, 3-1, 3-6, 3-12, 3-15, 6 Myotis sodalis .................3-53, 3-57, 3-75, 48  3-17, 3-19, 3-21, 3-24, 3-29, 3-34, 3-43, 7  3-78, 3-119, 3-126, 3-130, 4-56, 4-57 49  3-51, 3-80, 3-97, 3-106, 4-2, 4-52, 4-60, 50  4-62, 4-65, 4-66, 4-76, 4-77, 4-78, 4-80, 8 N 51  4-83, 4-86, 4-88, 4-93, 4-97, 4-103, 9 National Environmental Policy Act                            52  4-108, 4-127, 4-128, 4-132, 4-135, 6-1, 10  (NEPA) ...................................... xxii, xxx,  53  6-3, E-1, E-10, F-3, F-9, F-10, F-12, 11  1-1, 1-7, 2-1, 2-31, 3-73, 3-101, 3-112,                  54  F-16, F-18, F-20, F-25, F-26, F-32, F-37, 12  3-124, 4-39, 4-56, 4-61, 4-65, 4-91,                      55  F-40, G-1, G-2, G-3, G-4, G-7, G-11, 13  4-109, 4-121, 4-124, 4-137, 4-138,                        56  G-12 14  4-145, 4-146, 5-1, 6-1, 6-2, B-2, C-1,                    57 refurbishment ............................ 2-2, 3-80, 15  C-3, C-5, G-12, G-14                                      58  4-6, 4-28, 4-32, 4-61, 4-65, 4-114, 4-115 16 National Marine Fisheries Service                            59 replacement power ....................xxiv, xxxi, 17  (NMFS)....................................xxxi, 3-73,      60  2-3, 2-5, 2-7, 2-16, 4-29, 4-71, 4-80, 18  4-55, 4-56, 4-57, 4-58, 4-142, B-6, C-1,                  61  4-93, 4-94, 4-95, 4-100, 4-102, F-3, F-22, 19  C-2, C-3, C-5                                              62  F-39, F-40 20 National Pollutant Discharge Elimination 21  System (NPDES) ....................xxxi, 3-10,            63 S 22  3-11, 3-12, 3-18, 3-39, 3-41, 3-42, 3-43, 64 scoping .............................. iii, xxi, xxii, xxv, 23  3-44, 3-45, 3-97, 3-106, 3-108, 3-109, 65  1-1, 1-2, 1-5, 1-7, 4-1, 4-7, 4-20, 4-22, 24  3-121, 4-23, 4-26, 4-27, 4-28, 4-29, 4-30, 66  4-24, 4-31, 4-38, 4-61, 4-65, 4-72, 4-77, 25  4-32, 4-44, 4-46, 4-47, 4-51, 4-52, 4-53, 67  4-98, 4-101, 4-103, 4-113, 5-2, A-1, C-2, 26  4-73, 4-74, 4-75, 4-119, 4-120, 4-134, 68  C-3, C-4, D-1 27  4-136, 4-143, B-1, B-4, B-7, B-8, E-4, 28  E-7                                                        69 seismic...................................... xxxii, 3-29, 70  3-34, F-4, F-9, F-11, F-12, F-15, F-24, 29 Native American tribes .....................3-81, 71  F-27, F-28 30  3-122, 4-91, 4-92 72 severe accident mitigation alternative 31 no-action alternative ..................... iii, xxiv, 73  (SAMA) .................................... xxiii, xxxi, 32  2-1, 2-3, 2-4, 2-23, 2-24, 2-26, 4-2, 4-34, 74  4-77, 4-78, 4-80, 4-81, 4-82, 4-83, 4-84, 33  4-39, 4-53, 4-57, 4-93, 4-98, 4-105, 75  4-85, 4-86, 4-87, 4-88, 4-145, 6-1, 6-2, 34  4-121, 4-133, 5-1 76  6-3, D-1, F-1, F-2, F-4, F-6, F-10, F-11, 35 nonattainment ...........................3-26, 4-19          77  F-13, F-14, F-15, F-16, F-17, F-18, F-19, 78  F-20, F-21, F-22, F-23, F-24, F-25, F-26, 36 O                                                            79  F-27, F-28, F-29, F-30, F-31, F-32, F-33, 37 once-through cooling..................4-31, 4-38,            80  F-34, F-35, F-36, F-37, F-38, F-39, F-41, 38  4-44, 4-45, 4-117                                          81  F-42, F-43, F-45 82 severe accidents ........................ xxiii, xxxi, 39 P                                                            83  4-1, 4-76, 4-77, 4-86, 4-91, 6-1, D-1, F-1, 40 postulated accidents .................4-1, 4-75,            84  F-11, F-20, F-37, F-40 41  4-76, 4-77, 4-91, G-1                                      85 solid waste.................................xxiv, 2-22, 42 pressurized water reactor...................xxxi            86  3-13, 3-16, 3-17, 3-97, 3-106, 4-13, 4-99, 87  4-102, B-1, E-4 8-4
 
Index 1 spent fuel .............................. xxii, 1-3, 3-6,    41  2-9, 2-10, 2-11, 2-12, 2-14, 2-15, 2-16, 2    3-12, 3-17, 3-19, 3-20, 4-52, 4-101,                      42  2-17, 2-18, 2-19, 2-20, 2-21, 2-22, 2-27, 3    4-102, 4-135, E-1, G-1, G-2, G-3, G-4,                    43  2-28, 2-29, 2-30, 2-31, 2-33, 3-17, 4-10, 4    G-6, G-7, G-8, G-9, G-11, G-12                            44  4-14, 4-17, 4-67, 4-68, 4-70, 4-73, 4-137, 5 State Historic Preservation Office                          45  4-138, 4-145, 6-3, G-3, G-5, G-7, G-13 6    (SHPO)...................................3-82, 4-60,      46 U.S. Environmental Protection Agency 7    4-61, 4-62, 4-147                                        47  (EPA) ..................................... xxviii, xxix, 8 State Pollutant Discharge Elimination                        48  1-1, 2-4, 2-12, 2-21, 2-22, 2-23, 2-30, 9    System (SPDES) .............................. B-1        49  3-8, 3-10, 3-12, 3-13, 3-14, 3-15, 3-16, 50  3-25, 3-26, 3-27, 3-28, 3-29, 3-41, 3-42, 10 stormwater ...............................3-36, 3-39, 51  3-45, 3-51, 3-66, 3-67, 3-73, 3-93, 3-97, 11    3-43, 3-44, 3-45, 3-48, 4-26, 4-27, 4-28, 52  3-106, 3-108, 3-110, 3-113, 3-115, 12    4-29, 4-30, 4-31, 4-32, 4-33, 4-53, 4-119, 53  3-121, 3-122, 3-125, 3-130, 4-9, 4-11, 13    4-120, 4-125, B-4 54  4-12, 4-14, 4-15, 4-25, 4-39, 4-43, 4-44, 14 surface runoff .............................3-7, 3-30,      55    4-53, 4-73, 4-74, 4-89, 4-90, 4-104, 15    3-36, 3-39, 3-42, 3-44, 3-60, 4-26, 4-27,                56    4-105, 4-107, 4-108, 4-109, 4-114, 16    4-28, 4-29, 4-30, 4-32, 4-34, 4-108,                    57    4-121, 4-124, 4-127, 4-128, 4-129, 17    4-110, 4-118, 4-119, 4-120, 4-125, B-4                  58    4-130, 4-132, 4-135, 4-136, 4-138, 18 surface water ............................3-10, 3-35,        59  4-139, 4-140, 4-143, 4-147, 5-1, 7-1, B-1, 19    3-36, 3-39, 3-40, 3-41, 3-45, 3-59, 3-98,                60  B-3, B-4, B-5, B-8, B-9, D-1, E-3, E-4, 20    4-21, 4-22, 4-23, 4-26, 4-27, 4-28, 4-29,                61  E-5, E-8, E-9, F-20 21    4-30, 4-33, 4-47, 4-52, 4-74, 4-92, 4-102,                62 U.S. Fish and Wildlife Service 22    4-110, 4-116, 4-117, 4-118, 4-119,                        63  (FWS) ................................ xxix, 1-6, 1-7, 23    4-120, 4-125, 4-131, 6-2, B-1, B-4                        64  2-8, 2-9, 2-14, 2-15, 2-33, 3-53, 3-58, 65  3-73, 3-74, 3-75, 3-76, 3-77, 3-78, 3-79, 24 T                                                            66  3-107, 3-108, 3-119, 3-126, 4-55, 4-56, 25 taxes .................................3-93, 3-95, 4-65      67  4-57, 4-58, 4-111, 4-136, 4-142, B-6, 26 transmission line corridors ................4-6,            68  C-1, C-2, C-5 27    4-29, 4-34                                                69 uranium................................. xxii, 2-8, 3-6, 28 transmission lines ..............................2-4,        70  3-19, 4-1, 4-3, 4-4, 4-34, 4-35, 4-36, 29    2-12, 2-13, 2-14, 2-16, 3-1, 3-7, 3-20,                  71  4-89, 4-100, 4-101, 4-102, 4-104, G-1, 30    3-21, 3-72, 3-74, 3-78, 3-79, 3-99, 3-100,                72  G-2, G-4, G-9 31    4-2, 4-5, 4-6, 4-7, 4-19, 4-20, 4-28, 4-29, 32    4-30, 4-31, 4-34, 4-36, 4-37, 4-38, 4-53,                73 W 33    4-60, 4-62, 4-63, 4-64, 4-72, 4-75                        74 wastewater................................. 3-1, 3-18, 34 tritium ...............................3-15, 3-51, 4-25      75  3-39, 3-42, 3-43, 3-45, 3-91, 4-119, 76  4-120, 4-123, 4-125, 6-2, E-4, E-7, E-8 35 U 77 Y 36 U.S. Army Corps of Engineers ......... 3-20, 37    3-35, 3-45, 3-59, 3-127, 4-26, 4-28, 4-29,                78 Yucca Mountain ......................... G-2, G-3, 38    4-53, B-4, B-7, B-8                                      79  G-4, G-6, G-7, G-8, G-9, G-11, G-12, 39 U.S. Department of Energy                                    80  G-13 40    (DOE) ............................... xxviii, 2-4, 2-8, 8-5
 
APPENDIX A COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW
 
A. COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW Comments Received During the Scoping Period The scoping process for the environmental review of the license renewal application for LaSalle County Station, Units 1 and 2 (LSCS) began on February 3, 2015, with the publication of the U.S. Nuclear Regulatory Commissions (NRCs) notice of intent to conduct scoping in the Federal Register (80 FR 5793). The scoping process included two public meetings held in Ottawa, Illinois, on March 10, 2015. Approximately 30 people attended the meetings. After the NRCs prepared statements pertaining to the license renewal process, the meetings were open for public comments. Attendees provided oral statements that were recorded and transcribed by a certified court reporter. A summary and transcripts of the scoping meetings are available using the NRCs Agencywide Documents Access and Management System (ADAMS). The ADAMS Public Electronic Reading Room is accessible at http://www.nrc.gov/reading-rm/adams.html. The scoping meetings summary is available at ADAMS No. ML15091A329.
Transcripts for the afternoon and evening meetings are available at ADAMS Nos. ML15083A538 and ML15089A580, respectively. In addition to comments received during the public meetings, one comment was received electronically.
A total of 15 commenters provided comments during the scoping period. Comments from 12 of the 15 commenters were in support of license renewal for LSCS or in support of nuclear power in general. These comments are not within the scope of this license renewal review and, thus, were not responded to by the NRC staff. These commenters, along with their affiliation and the source of their comments (i.e., afternoon or evening scoping meeting transcript) are listed in the LSCS Scoping Summary Report available at ADAMS No. ML15147A380.
Comments received from the other 3 of the 15 commenters (Linda Lewison, Marvin Lewis, and Nelson Dewey) do not fall within or are specifically excluded from the purview of the NRCs environmental review related to license renewal. These comments addressed the disposition of spent nuclear fuel and safety concerns associated with fuel enrichment and hydraulic fracturing.
These comments and the NRC staffs responses to these comments are available in the LSCS Scoping Summary Report at ADAMS No. ML15147A380.
A-1
 
APPENDIX B APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS
 
1 B. APPLICABLE LAWS, REGULATIONS, AND OTHER 2    REQUIREMENTS 3 There are a number of Federal laws and regulations that affect environmental protection, health, 4 safety, compliance, and consultation at every nuclear power plant licensed by the U.S. Nuclear 5 Regulatory Commission (NRC). Certain Federal environmental requirements have been 6 delegated to state authorities for implementation, enforcement, or oversight. Furthermore, 7 states have also enacted laws to protect public health and safety and the environment. It is the 8 NRCs mission, among other things, to ensure that U.S. nuclear power plants are operated in a 9 manner that provides adequate protection of the public health and safety and of the 10 environment through compliance with applicable Federal and state laws, regulations, and other 11 requirements.
12 The requirements that may be applicable to the operation of NRC-licensed nuclear power plants 13 encompass a broad range of Federal and state laws and regulations, addressing environmental, 14 historic and cultural, health and safety, transportation, and other concerns. Generally, these 15 laws and regulations are relevant to how the work involved in performing the proposed action 16 would be conducted to protect workers, the public, and environmental resources. Some of 17 these laws and regulations require permits or consultation with other Federal agencies or state, 18 tribal, or local governments.
19 The Atomic Energy Act of 1954, as amended (AEA) (42 United States Code (U.S.C.) &sect;2011 20 et seq.), authorizes any state to enter into agreement with the NRC to assume regulatory 21 authority for certain activities (see 42 U.S.C. &sect;2021). For example, through this Agreement 22 State Program, Illinois assumed regulatory responsibility over certain byproduct, source, and 23 quantities of special nuclear materials not sufficient to form a critical mass. The Illinois 24 Emergency Management Agency (IEMA), Division of Nuclear Safety, administers several 25 programs to protect citizens and the environment, including: a comprehensive monitoring 26 system for the 11 operating nuclear power reactors in Illinois, inspection and regulation of 27 radioactive materials licensees and x-ray machines, and oversight of cleanup efforts at sites 28 contaminated with radioactive materials (IEMA undated).
29 In addition to carrying out some Federal programs, state legislatures develop their own laws.
30 State statutes supplement, as well as implement, Federal laws for the protection of air, water 31 quality, and groundwater. State legislation may address solid waste management programs, 32 locally rare or endangered species, and historic and cultural resources.
33 The Clean Water Act (CWA) (33 U.S.C. &sect;1251 et seq.) allows for primary enforcement and 34 administration through state agencies, provided that the state program is at least as stringent as 35 the Federal program. The state program must conform to the CWA and to the delegation of 36 authority for the Federal National Pollutant Discharge Elimination System (NPDES) program 37 from the U.S. Environmental Protection Agency (EPA) to the state. The primary mechanism to 38 control water pollution is the requirement for direct dischargers to obtain an NPDES permit or, in 39 the case of states where the authority has been delegated from the EPA, such as Illinois, a 40 State Pollutant Discharge Elimination System permit.
41 One important difference between Federal regulations and certain state regulations is the 42 definition of waters regulated by the state. Certain state regulations may include underground 43 waters, whereas the CWA only regulates surface waters. The Illinois Environmental Protection 44 Agency (IEPA), Bureau of Water, Water Pollution Control, conducts the numerous programs, 45 including permit programs and surface water quality monitoring and assessment programs, to 46 protect and enhance the quality of the states surface waters (IEPA undated).
B-1
 
Appendix B 1        Federal and State Requirements 2 LaSalle County Station, Units 1 and 2 (LSCS), are subject to Federal and State requirements.
3 Table B-1 lists the principal Federal and State laws and regulations that are used or mentioned 4 in this supplemental environmental impact statement (SEIS) for LSCS.
5                                          Federal and State Requirements Law/regulation              Requirements Current operating license and license renewal Atomic Energy Act of 1954,  The AEA and the Energy Reorganization Act of 1974, as amended as amended (AEA),          (42 U.S.C. &sect;5801 et seq.), give the NRC the licensing and regulatory 42 U.S.C. &sect;2011 et seq. authority for nuclear energy uses within the commercial sector. These regulations give the NRC responsibility for licensing and regulating commercial uses of atomic energy and allow the NRC to establish dose and concentration limits for protection of workers and the public for activities under NRC jurisdiction. The NRC implements these responsibilities through regulations set forth in Title 10 of the Code of Federal Regulations (10 CFR).
National Environmental      NEPA requires Federal agencies to integrate environmental values into Policy Act of 1969, as      their decisionmaking process by considering the environmental impacts of amended (NEPA),            proposed Federal actions and reasonable alternatives to those actions.
42 U.S.C. &sect;4321 et seq. NEPA establishes policy, sets goals (in Section 101), and provides means (in Section 102) for carrying out the policy. Section 102(2) contains action-forcing provisions to ensure that Federal agencies follow the letter and spirit of the Act. For major Federal actions significantly affecting the quality of the human environment, Section 102(2)(C) of NEPA requires Federal agencies to prepare a detailed statement that includes the environmental impact of the proposed action and other specified information.
Title 10 of the Code of    Regulations in 10 CFR Part 51, Environmental protection regulations for Federal Regulations        domestic licensing and related regulatory functions, contain (10 CFR), Energy, Part 51  environmental protection regulations applicable to the NRCs domestic licensing and related regulatory functions. These regulations implement Section 102(2) of NEPA.
10 CFR Part 54              Regulations in 10 CFR Part 54, Requirements for renewal of operating licenses for nuclear power plants, govern the issuance of renewed operating licenses and renewed combined licenses for nuclear power plants licensed pursuant to Sections 103 or 104b of the AEA and Title II of the Energy Reorganization Act. The regulations focus on managing the effects of aging during the period of extended operation on the functionality of specific structures and components. The rule is intended to ensure that important systems, structures, and components will maintain their intended functions during the period of extended operation.
B-2
 
Appendix B Law/regulation                Requirements 10 CFR Part 50                Regulations in 10 CFR Part 50, Domestic licensing of production and utilization facilities, are NRC regulations issued under the AEA and Title II of the Energy Reorganization Act to provide for the licensing of production and utilization facilities. This part also gives notice to all persons who knowingly provide to any licensee, applicant, contractor, or subcontractor, components, equipment, materials, or other goods or services, that relate to a licensees or applicants activities subject to this part, that they may be individually subject to NRC enforcement action for violation of 10 CFR 50.5.
Air quality protection Clean Air Act (CAA),          The CAA is intended to protect and enhance the quality of the Nations air 42 U.S.C. &sect;7401 et seq.      resources so as to promote the public health and welfare and the productive capacity of its population. The CAA establishes requirements to ensure maintenance of air quality standards and authorizes individual states to manage permits. Section 118 of the CAA requires each Federal agency, with jurisdiction over properties or facilities engaged in any activity that may result in the discharge of air pollutants, to comply with all Federal, state, inter-state, and local requirements with regard to the control and abatement of air pollution. Section 109 of the CAA directs the U.S. Environmental Protection Agency (EPA) to set National Ambient Air Quality Standards (NAAQS) for criteria pollutants. The EPA has identified and set NAAQS for the following criteria pollutants: particulate matter, sulfur dioxide, carbon monoxide, ozone, nitrogen dioxide, and lead.
Section 111 of the CAA requires establishment of national performance standards for new or modified stationary sources of atmospheric pollutants. Section 160 of the CAA requires that specific emission increases must be evaluated before permit approval to prevent significant deterioration of air quality. Section 112 requires specific standards for release of hazardous air pollutants (including radionuclides). These standards are implemented through plans developed by each state and approved by the EPA. The CAA requires sources to meet standards and obtain permits to satisfy those standards. Nuclear power plants may be required to comply with the CAA Title V, Sections 501-507, for sources subject to new source performance standards or sources subject to National Emission Standards for Hazardous Air Pollutants. Emissions of air pollutants are regulated by the EPA in 40 CFR Parts 50 to 99.
Illinois Administrative Code This part of the IAC sets standards for air emissions from auxiliary boilers, (IAC), Title 35,              emergency generators, radwaste volume reduction system, cooling Environmental Protection, towers, and ancillary operations.
Subtitle B, Air Pollution, Chapter I, Pollution Control Board, Subchapter a, Permits and General Provisions, Part 201, Permits and General Provisions B-3
 
Appendix B Law/regulation                Requirements Water resources protection Clean Water Act (CWA),        The CWA was enacted to restore and maintain the chemical, physical, 33 U.S.C. &sect;1251 et seq.,      and biological integrity of the Nations waters. The Act requires each and the NPDES                  Federal agency, with jurisdiction over properties or facilities engaged in (40 CFR 122)                  any activity that may result in the discharge or runoff of pollutants to surface waters, to comply with all Federal, state, inter-state, and local requirements. As authorized by the CWA, the National Pollutant Discharge Elimination System (NPDES) permit program controls water pollution by regulating point sources that discharge pollutants into waters of the United States. The NPDES program requires all facilities that discharge pollutants from any point source into waters of the United States to obtain an NPDES permit. A nuclear power plant may also participate in the NPDES General Permit for Industrial Stormwater due to stormwater runoff from industrial or commercial facilities to waters of the United States. EPA is authorized under the CWA to directly implement the NPDES program; however, EPA has authorized many states to implement all or parts of the national program. Section 401 of the CWA requires states to certify that the permitted discharge would comply with all limitations necessary to meet established state water quality standards, treatment standards, or schedule of compliance.
The U.S. Army Corps of Engineers is the lead agency for enforcement of CWA wetland requirements (33 CFR Part 320). Under Section 401 of the CWA, the EPA or a delegated state agency has the authority to review and approve, condition, or deny all permits or licenses that may result in a discharge to waters of the State, including wetlands.
Coastal Zone Management        Congress enacted the CZMA in 1972 to address the increasing pressures Act of 1972, as amended        of over-development upon the Nations coastal resources. The National (CZMA), 16 U.S.C. &sect;1451 et    Oceanic and Atmospheric Administration administers the Act. The CZMA seq.                          encourages states to preserve, protect, develop, and, where possible, restore or enhance natural coastal resources such as wetlands, floodplains, estuaries, beaches, dunes, barrier islands, and coral reefs, as well as the fish and wildlife using those habitats. Participation by states is voluntary. To encourage states to participate, the CZMA makes Federal financial assistance available to any coastal state or territory, including those on the Great Lakes, that are willing to develop and implement a comprehensive coastal management program.
IAC, Title 35,                This part of the IAC implements the NPDES program under the CWA.
Environmental Protection, Subtitle C, Water Pollution, Chapter I, Pollution Control Board, Part 309, Permits Wild and Scenic Rivers Act, The Wild and Scenic Rivers Act created the National Wild and Scenic 16 U.S.C. &sect;271 et seq.        Rivers System, which was established to protect the environmental values of free flowing streams from degradation by impacting activities, including water resources projects.
415 Illinois Compiled          This part of the ILCS sets forth Illinois State standards for water pollution.
Statutes (ILCS) 5, Environmental Protection Act, Title III, Water Pollution B-4
 
Appendix B Law/regulation                Requirements Waste management and pollution prevention Resource Conservation and RCRA requires the EPA to define and identify hazardous waste; establish Recovery Act (RCRA),          standards for its transportation, treatment, storage, and disposal; and 42 U.S.C. &sect;6901 et seq.        require permits for persons engaged in hazardous waste activities.
Section 3006 (42 U.S.C. &sect;6926) allows states to establish and administer these permit programs with EPA approval. EPA regulations implementing the RCRA are found in 40 CFR Parts 260 through 283. Regulations imposed on a generator or on a treatment, storage, and/or disposal facility vary according to the type and quantity of material or waste generated, treated, stored, and/or disposed. The method of treatment, storage, and/or disposal also impacts the extent and complexity of the requirements.
Pollution Prevention Act,      The Pollution Prevention Act establishes a national policy for waste 42 U.S.C. &sect;13101 et seq.      management and pollution control that focuses first on source reduction, then on environmental issues, safe recycling, treatment, and disposal.
10 CFR Part 20                Regulations in 10 CFR Part 20, Standards for protection against radiation, establish standards for protection against ionizing radiation resulting from activities conducted under licenses issued by the NRC.
These regulations are issued under the AEA and the Energy Reorganization Act.
The purpose of these regulations is to control the receipt, possession, use, transfer, and disposal of licensed material by any licensee in such a manner that the total dose to an individual (including doses resulting from licensed and unlicensed radioactive material and from radiation sources other than background radiation) does not exceed the standards for protection against radiation prescribed in the regulations in this part.
IAC Title 35, Environmental This part of the IAC establishes standards for generators of hazardous Protection, Subtitle G,      waste.
Waste Disposal, Chapter I, Pollution Control Board, Subchapter c, Hazardous Waste Operating Requirements, Part 722, Standards Applicable to Generators of Hazardous Waste IAC Title 35, Environmental  This part of the IAC presents criteria for transporting, storing, and applying Protection, Subtitle C,      sludge on land in an environmentally acceptable manner. In addition, it Water Pollution, Chapter II, identifies methods of sludge transportation, handling, storage, application Environmental Protection      and monitoring to control potential environmental problems.
Agency, Part 391, Design Criteria for Sludge Application on Land B-5
 
Appendix B Law/regulation              Requirements IAC Title 32, Energy,      This part of the IAC establishes one of the systems for the regulation of Chapter II, Illinois        the use of facilities in the State of Illinois to: (1) collect, store, treat or Emergency Management        dispose of low-level radioactive waste; (2) maintain a data base as to the Agency, Subchapter d,      location of all such waste in the State of Illinois; and (3) implement some Low Level Radioactive      of the requirements, prohibitions and mandates of the Compact, the Waste/Transportation,      Radioactive Waste Compact Enforcement Act (45 ILCS 141), the Part 609, Access to        Radioactive Waste Tracking and Permitting Act (420 ILCS 37) and the Facilities for Treatment,    Illinois Low-Level Radioactive Waste Management Act (420 ILCS 20).
Storage, or Disposal of      This Part establishes a system for monitoring and tracking shipments of Low-Level Radioactive        low-level radioactive waste into, out of or within the State of Illinois for the Waste                      purpose of tracking the points of origin of the shipments, as transported to the places of destination of the shipments. This Part establishes an enforcement and verification system directed to the movements of low-level radioactive waste into, out of or within the State of Illinois. This Part applies to any generator, broker, owner or operator of any treatment or disposal facility, or to any person who sends low-level radioactive waste into, within or out of the State of Illinois.
Protected species Endangered Species Act      The Endangered Species Act (ESA) was enacted to prevent the further (ESA), 16 U.S.C. &sect;1531      decline of endangered and threatened species and to restore those et seq.                      species and their critical habitats. Section 7 of the Act requires Federal agencies to consult with the U.S. Fish and Wildlife Service or the National Marine Fisheries Service (NMFS) on agency actions that may affect listed species or designated critical habitats.
Magnuson-Stevens Fishery    The MSA governs marine fisheries management in U.S. Federal waters.
Conservation and            The Act created eight regional fishery management councils and includes Management Act (MSA),        measures to rebuild overfished fisheries, protect essential fish habitat, and 16 U.S.C. &sect;1801 et seq.      reduce bycatch. Under Section 305 of the Act, Federal agencies are required to consult with NMFS for any agency actions that may adversely affect essential fish habitat.
Historic preservation and cultural resources National Historic            The NHPA was enacted to create a national historic preservation program, Preservation Act (NHPA),    including the National Register of Historic Places and the Advisory Council 16 U.S.C. &sect;470 et seq.      on Historic Preservation. Section 106 of the Act requires Federal agencies to take into account the effects of their undertakings on historic properties. The Advisory Council on Historic Preservation regulations implementing Section 106 of the Act are found in 36 CFR Part 800. The regulations call for public involvement in the Section 106 consultation process, including Indian Tribes and other interested members of the public, as applicable.
1      Operating Licenses and Other Permits 2 Table B-2 lists the licenses and permits issued by Federal, state, and local authorities for 3 activities at LSCS.
B-6
 
Appendix B 1                                                          Licenses and Permits Permit                                  Number                    Dates                    Responsible Agency Operating license                      NPF-11                    Issued: 04/17/1982        NRC Expires: 04/17/2022 Operating license                      NPF-18                    Issued: 12/16/1983        NRC Expires: 12/16/2023 NPDES permit                            IL0048151                  Issued: 07/05/2013        IEPA, Division of Expires: 07/31/2018      Water Pollution Control Federally enforceable state            Application                Issued: 12/11/2000        IEPA, Division of operating permit (FESOP) for #750440086                            Expires: 12/11/2005      Air Pollution Control air emissions from                      ID# 099802AA              Renewal application emergency generators,                                              submitted storage tanks, and                                                7/15/2005(a) dispensing facilities Notification of hazardous              ILD000803643              Not Applicable            IEPA, Bureau of Land waste activity as a small quantity generator of hazardous waste Department of Army permit              CEMVR-OD-P-2006-          Issued: 04/16/2006        U.S. Army Corps of for maintenance dredging at            185                        Expires: 12/31/2015(b) Engineers river screen house intake Waste tracking permit for              IL-0104                    Not Applicable            IEMA, Division of shipments of low-level                                                                      Nuclear Safety radioactive waste License to deliver radioactive T-IL009-L14                        Renewed annually          Tennessee Department material to processing facility                                                              of Environment and in Tennessee                                                                                Conservation Permit to deliver radioactive          010000028                  Renewed annually          Utah Department of material to disposal facility in                                                            Environmental Quality Utah Dam safety regarding                    DS2000237                  Issued: 12/20/2000        Illinois Department of operation and maintenance of                                      Expires: Not              Natural Resources, Office cooling reservoir dam                                              Applicable                of Water Resources Hazardous materials                    051713 550 083VX          Issued: 05/17/2013        U.S. Department of certificate of registration                                        Expires: 06/30/2016      Transportation, Pipeline and Hazardous Materials Safety Administration (a) 415 ILCS 5, Title II, Air Pollution, Sec. 9.1(f) extends the effective term of the FESOP if the permit holder submits a completed application for renewal to the IEPA at least 90 days prior to the permit expiration. Exelon met this requirement, therefore, the permit is administratively extended (415 ILCS 5/9.1).
(b) Extension of this permit must be filed at least 1 month prior to the permit expiration date (Permit CEMVR-OD-P-2006-185, p.2, General Condition #1). LSCS applied for a renewed permit on 11/20/2015.
Sources: Exelon 2014, 2015 B-7
 
Appendix B 1        References 2 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 3 production and utilization facilities.
4 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 5 protection regulations for domestic licensing and related regulatory functions.
6 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 7 renewal of operating licenses for nuclear power plants.
8 40 CFR Part 122. Code of Federal Regulations, Title 40, Protection of Environment, Part 122, 9 EPA administered permit programs: the National Pollutant Discharge Elimination System.
10 49 CFR Part 107. Code of Federal Regulations, Title 49, Transportation, Part 107, Hazardous 11 materials program procedures.
12 49 U.S.C. 5108. United States Code, Title 49, Chapter 51, Part 5108, Registration.
13 [IAC] Illinois Administrative Code Title 32, Chapter II, Subchapter d, Part 609, Access to 14 facilities for treatment, storage, or disposal of low-level radioactive waste.
15 [IAC] Illinois Administrative Code Title 35, Subtitle B, Chapter I, Subchapter a, Part 201, 16 Permits and general provisions.
17 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter I, Part 309, Permits.
18 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter II, Part 391, Design criteria for 19 sludge application on land.
20 [IAC] Illinois Administrative Code Title 35, Subtitle G, Chapter I, Subchapter c, Part 722, 21 Standards applicable to generators of hazardous waste.
22 415 ILCS 5/Tit. II. Illinois Compiled Statutes. Chapter 415, 5, Environmental Protection Act, 23 Title II, Air pollution.
24 415 ILCS 5/Tit. III. Illinois Compiled Statutes. Chapter 415, 5, Environmental Protection Act, 25 Title III, Water pollution.
26 [AEA] Atomic Energy Act of 1954, as amended. 42 U.S.C. &sect;2011 et seq.
27 [CAA] Clean Air Act of 1963, as amended. 42 U.S.C. &sect;7401 et seq.
28 [CWA] Clean Water Act of 1977, as amended. 33 U.S.C. &sect;1251 et seq.
29 [ESA] Endangered Species Act of 1973, as amended. 16 U.S.C. &sect;1531 et seq.
30 [Exelon] Exelon Generation Company, LLC. 2014. LaSalle County Station, Units 1 and 2 31 License Renewal Application, Applicants Environmental Report. December 9, 2014.
32 Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 33 ML14343A897.
34 [Exelon] Exelon Generation Company, LLC. 2015. E-mail from N. Ranek, Exelon, to 35 D. Drucker, NRC.
 
==Subject:==
RE: USACE permit. December 10, 2015. ADAMS 36 No. ML15363A237.
37 [FWCA] Fish and Wildlife Coordination Act of 1934, as amended. 16 U.S.C. &sect;661 et seq.
38 [IEMA] Illinois Emergency Management Agency, Division of Nuclear Safety. undated. Available 39 at <http://www.illinois.gov/iema/Pages/default.aspx> (accessed September 3, 2015).
B-8
 
Appendix B 1 [IEPA] Illinois Environmental Protection Agency, Bureau of Water. undated. Water Pollution 2 Control. Available at <http://www.epa.state.il.us/water/index-wpc.html> (accessed 3 3 September 2015).
4 [MMPA] Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. &sect;1361 et seq.
5 [MSA] Magnuson-Stevens Fishery Conservation and Management Act, as amended.
6 16 U.S.C. &sect;1801 et seq.
7 [NHPA] National Historic Preservation Act of 1966, as amended. 16 U.S.C. &sect;470 et seq.
8 Pollution Prevention Act of 1990. 42 U.S.C. &sect;13101 et seq.
9 [RCRA] Resource Conservation and Recovery Act of 1976, as amended. 42 U.S.C. &sect;6901 10 et seq.
11 Wild and Scenic Rivers Act, as amended. 16 U.S.C. &sect;1271 et seq.
B-9
 
1          APPENDIX C 2 CONSULTATION CORRESPONDENCE
 
1 C. CONSULTATION CORRESPONDENCE 2      Endangered Species Act (ESA) Section 7 Consultation 3 C.1.1. Federal Agency Obligations Under ESA Section 7 4 As a Federal agency, the U.S. Nuclear Regulatory Commission (NRC) must comply with the 5 Endangered Species Act of 1973, as amended (16 United States Code (U.S.C.) 1531 et seq.,
6 herein referred to as ESA), as part of any action authorized, funded, or carried out by the 7 agency, such as the proposed agency action that this supplemental environmental impact 8 statement (SEIS) evaluates whether to issue renewed licenses for the continued operation of 9 LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years beyond the current 10 license terms. Under section 7 of the ESA, the NRC must consult with the U.S. Fish and 11 Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS) (referred to jointly as 12 the Services and individually as Service), as appropriate, to ensure that the proposed agency 13 action is not likely to jeopardize the continued existence of any endangered or threatened 14 species or result in the destruction or adverse modification of designated critical habitat.
15 The ESA and the regulations that implement ESA section 7 (Title 50 of the Code of Federal 16 Regulations (50 CFR) Part 402, Interagency cooperationEndangered Species Act of 1973, 17 as amended) describe the consultation process that Federal agencies must follow in support of 18 agency actions. As part of this process, the Federal agency shall either request that the 19 Services provide a list of any listed or proposed species or designated or proposed critical 20 habitats that may be present in the action area or request that the Services concur with a list of 21 species and critical habitats that the Federal agency has created (50 CFR 402.12(c)). If it is 22 determined that any such species or critical habitats may be present, the Federal agency is to 23 prepare a biological assessment to evaluate the potential effects of the action and determine 24 whether the species or critical habitat are likely to be adversely affected by the action 25 (16 U.S.C. 1536(c), 50 CFR 402.12(a)). Further, biological assessments are required for any 26 agency action that is a major construction activity (50 CFR 402.12(b)), which the ESA 27 regulations define to include major Federal actions significantly affecting the quality of the 28 human environment under the National Environmental Policy Act of 1969, as amended 29 (42 U.S.C. 4321 et seq., herein referred to as NEPA) (50 CFR 402.02).
30 Federal agencies may fulfill their obligations to consult with the Services under ESA section 7 31 and to prepare a biological assessment in conjunction with the interagency cooperation 32 procedures required by other statutes, including NEPA (50 CFR 402.06(a)). In such cases, the 33 Federal agency should include the results of the ESA section 7 consultation in the NEPA 34 document (50 CFR 402.06(b)). Accordingly, Section C.1.2 describes the biological assessment 35 prepared for the proposed agency action evaluated in this SEIS, and Section C.1.3 describes 36 the chronology and results of the ESA section 7 consultation.
37 C.1.2. Biological Assessment 38 The NRC considers this SEIS to fulfill its obligation to prepare a biological assessment under 39 ESA section 7. Accordingly, the NRC did not prepare a separate biological assessment for the 40 proposed LSCS license renewal.
41 Although the contents of a biological assessment are at the discretion of the Federal agency 42 (50 CFR 402.12(f)), the ESA regulations suggest information that agencies may consider for 43 inclusion. The NRC has considered this information in the following sections.
C-1
 
Appendix C 1 Section 3.8 describes the action area and the Federally listed and proposed species and 2 designated and proposed critical habitat that have the potential to be present in the action area.
3 This section includes information pursuant to 50 CFR 402.12(f)(1), (2), and (3).
4 Section 4.8 provides an assessment of the potential effects of the proposed LSCS license 5 renewal on the species and critical habitat present and the NRCs effect determinations, which 6 are consistent with those identified in Section 3.5 of the Endangered Species Consultation 7 Handbook (FWS and NMFS 1998). The NRC also addresses alternatives to the proposed 8 action. This section includes information pursuant to 50 CFR 402.12(f)(4) and (5).
9 C.1.3. Chronology of ESA Section 7 Consultation 10 Upon receipt of Exelons license renewal application, the NRC staff considered whether any 11 Federally listed or proposed species or designated or proposed critical habitats may be present 12 in the action area (as defined at 50 CFR 402.02) for the proposed LSCS license renewal. No 13 species under the NMFSs jurisdiction occur within the action area. Therefore, the NRC staff did 14 not consult with the NMFS. With respect to species under the FWSs jurisdiction, in late 15 February 2015, NRC staff filled an online form for an updated protected species list for LSCS on 16 the FWSs Environmental Conservation Online System (ECOS), Information for Planning and 17 Conservation (IPaC). FWS (2015b) responded with a list of threatened and endangered 18 species that may occur in the project location and may be affected by the Federal action. In 19 October 2015, NRC staff checked the FWS (2015a) online Illinois County distribution of listed 20 species for updates. From this, the NRC staff compiled a list of ESA-protected species and 21 critical habitats in the vicinity of the facility.
22 In Section 3.8, the NRC staff concludes that no ESA-protected species or critical habitats occur 23 in the action area, and, in Section 4.8, concludes that the proposed action would have no effect 24 on any ESA-protected species or critical habitats. The FWS (2013) does not typically provide its 25 concurrence with no effect determinations by Federal agencies. Thus, the ESA does not 26 require further informal consultation or the initiation of formal consultation with the FWS for the 27 proposed LSCS license renewal. Nonetheless, because this SEIS constitutes the NRCs 28 biological assessment, the NRC staff submitted a copy of the draft SEIS to the FWS for its 29 review in accordance with 50 CFR 402.12(j).
30 Table C-1 lists the correspondence related to the NRCs ESA obligations with respect to its 31 review of the LSCS license renewal application. This table will be updated in the final SEIS, as 32 applicable, to include correspondence transpiring between the issuance of the draft and final 33 SEIS.
34                                    ESA Section 7 Consultation Correspondence Sender and Date                Recipient      Description                                    ADAMS No.(a)
February 27, 2015 FWS to NRC List of threatened and endangered species that ML15126A069 may occur in your proposed project location, and/or may be affected by your proposed project March 3, 2015        NRC to FWS Request for scoping comments/notification of        ML15062A534 scoping meetings (a) These documents can be accessed through the NRCs Agencywide Documents Access and Management System (ADAMS) at http://adams.nrc.gov/wba/.
C-2
 
Appendix C 1        Essential Fish Habitat Consultation 2 The NRC must comply with the Magnuson-Stevens Fishery Conservation and Management 3 Act, as amended (16 U.S.C. &sect;1801 et seq., herein referred to as MSA), for any actions 4 authorized, funded, or undertaken, or proposed to be authorized, funded, or undertaken that 5 may adversely affect any essential fish habitat (EFH) identified under the MSA.
6 In Sections 3.8 and 4.8 of this SEIS, the NRC staff concludes that the NMFS has not designated 7 EFH under the MSA in the Illinois River and that the proposed LSCS license renewal would 8 have no effect on EFH. Thus, the MSA does not require the NRC to consult with the NMFS for 9 the proposed LSCS license renewal.
10        National Historic Preservation Act of 1966 Consultation 11 The National Historic Preservation Act (NHPA) requires Federal agencies to consider the effects 12 of their undertakings on historic properties and consult with applicable state and Federal 13 agencies, tribal groups, and individuals and organizations with a demonstrated interest in the 14 undertaking before taking action. Historic properties are defined as resources that are eligible 15 for listing on the National Register of Historic Places. The historic preservation review process 16 (Section 106 of the National Historic Preservation Act of 1966, as amended) is outlined in 17 regulations issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800.
18 In accordance with 36 CFR 800.8(c), the NRC has elected to use the NEPA process to comply 19 with its obligations under Section 106 of the NHPA.
20 Table C-2 lists the chronology of consultations and consultation documents related to the NRC 21 Section 106 review. The NRC staff is required to consult with the noted agencies and 22 organizations in accordance with the statutes listed above. Table C-2 will be updated in the 23 final SEIS, as applicable, to include correspondence transpiring between the issuance of the 24 draft and final SEIS.
25                                                NHPA Correspondence Date              Sender and Recipient                  Description              ADAMS No. (a)
February 9, 2015 D. Wrona (NRC) to R. Nelson (ACHP)      Request for scoping      ML15023A094 comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to A. Haaker, Illinois    Request for scoping      ML15022A578 Historic Preservation Agency          comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Greendeer,          Request for scoping      ML15023A139 Ho-Chunk Nation                        comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to S. Cadue, Kickapoo Request for scoping          ML15023A139 Tribe of Indians of the Kickapoo      comments/notification of Reservation in Kansas                  Section 106 review February 9, 2015 D. Wrona (NRC) to G. Salazar,            Request for scoping      ML15023A139 Kickapoo Tribe of Oklahoma            comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to D. Lankford, Miami    Request for scoping      ML15023A139 Tribe of Oklahoma                      comments/notification of Section 106 review C-3
 
Appendix C Date                Sender and Recipient                    Description                  ADAMS No. (a)
February 9, 2015 D. Wrona (NRC) to J. Froman, Peoria        Request for scoping          ML15023A139 Tribe of Indians of Oklahoma            comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Barrett, Citizen      Request for scoping          ML15023A139 Potawatomi Nation                        comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Bender, Sac and        Request for scoping          ML15023A139 Fox Tribe of the Mississippi in          comments/notification of Iowa/Meskwaki                            Section 106 review February 9, 2015 D. Wrona (NRC) to B. Robidoux, Sac          Request for scoping          ML15023A139 and Fox Nation of Missouri in Kansas    comments/notification of and Nebraska                            Section 106 review February 9, 2015 D. Wrona (NRC) to G. Thurman, Sac          Request for scoping          ML15023A139 and Fox Nation                          comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Warren, Pokagon Request for scoping                ML15023A139 Band of Potawatomi                      comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to H. Frank, Forest          Request for scoping          ML15023A139 County Potawatomi                        comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to K. Meshigaud,            Request for scoping          ML15023A139 Hannahville Indian Community            comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to S. Ortiz, Prairie        Request for scoping          ML15023A139 Band of Potawatomi Nation                comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Blackhawk,            Request for scoping          ML15023A139 Winnebago Tribe of Nebraska              comments/notification of Section 106 review April 1, 2015      R Leibowitz, Illinois Historic          Illinois Historic            ML15106A791 Preservation Agency to D. Wrona          Preservation Agency (NRC)                                    Section 106 Clearance (IHPA Log #009031615)
August 6, 2015      R. Chazell (NRC) to File                Summary of Visit to          ML15205A286 Illinois Historic Preservation Agency associated with the LaSalle County Station, Units 1 and 2, License Renewal Application Environmental Audit (a) These documents can be accessed through the NRCs ADAMS at http://adams.nrc.gov/wba/.
C-4
 
Appendix C 1      References 2 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 3 Part 800, Protection of historic properties.
4 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 5 Interagency cooperationEndangered Species Act of 1973, as amended.
6 Endangered Species Act of 1973, as amended. 16 U.S.C. &sect;1531 et seq.
7 [FWS] U.S. Fish and Wildlife Service. 2013. Endangered Species Program: What We Do:
8 Consultations: Frequently Asked Questions. July 15, 2013. Available at 9 <http://www.fws.gov/endangered/what-we-do/faq.html#8> (accessed 5 June 2014).
10 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 11 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 12 September 30, 2015. Available at http://www.fws.gov/midwest/endangered/lists/illinois-cty.html 13 (accessed 9 October 2015).
14 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC.
 
==Subject:==
LaSalle 15 Power Plant License Renewal. List of threatened and endangered species that may occur in 16 your proposed project location, and/or may be affected by your proposed project.
17 February 27, 2015. ADAMS No. ML15126A069.
18 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998.
19 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 20 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p.
21 Available at <http://www.fws.gov/endangered/esa-library/pdf/esa_section7_handbook.pdf>
22 (accessed 8 July 2013).
23 Magnuson-Stevens Fishery Conservation and Management Act, as amended.
24 16 U.S.C. &sect;1801 et seq.
25 National Environmental Policy Act of 1969, as amended. 42 U.S.C. &sect;4321 et seq.
26 National Historic Preservation Act of 1966, as amended. 16 U.S.C. &sect;470 et seq.
C-5
 
1          APPENDIX D 2 CHRONOLOGY OF ENVIRONMENTAL 3    REVIEW CORRESPONDENCE
 
1 D. CHRONOLOGY OF ENVIRONMENTAL REVIEW 2      CORRESPONDENCE 3 This appendix contains a chronological listing of correspondence between the U.S. Nuclear 4 Regulatory Commission (NRC) and external parties as part of its license renewal application 5 (LRA) environmental review for LaSalle County Station, Units 1 and 2 (LSCS) other than 6 consultation correspondence and comments received during the scoping process. Consultation 7 correspondence is listed and discussed in Appendix C of this supplemental environmental 8 impact statement (SEIS). Scoping comments are provided and addressed in Appendix A of this 9 SEIS and in the Scoping Summary Report (see Table D-1 below). All documents are available 10 electronically from the NRCs Public Electronic Reading Room found on the Internet at the 11 following Web address: http://www.nrc.gov/reading-rm.html. From this site, the public can gain 12 access to the NRCs Agencywide Documents Access and Management System (ADAMS),
13 which provides text and image files of the NRCs public documents in ADAMS. The ADAMS 14 No. for each document is included in the following table.
15      Environmental Review Correspondence 16 Table D-1 lists the environmental review correspondence, by date, beginning with the request 17 by Exelon Generation Company, LLC (Exelon) to renew the operating licenses for LSCS.
18                                    Environmental Review Correspondence Date                  Correspondence Description                                    ADAMS No.
December 9, 2014      Transmittal of LSCS LRA from Exelon to NRC                    ML14343A840 December 11, 2014      Receipt and availability of LSCS LRA                          ML14337A267 December 29, 2014      Letter from Illinois Environmental Protection Agency to NRC  ML15022A325 regarding LSCS Clean Water Act Section 401 Certification January 26, 2015      Determination of acceptability and sufficiency for docketing, ML15021A451 proposed review schedule, and opportunity for a hearing regarding the application, for renewal of the operating licenses for LSCS January 27, 2015      Notice of intent to prepare an environmental impact          ML15005A480 statement and conduct scoping for LSCS license renewal March 10, 2015        Transcript from afternoon public scoping meeting              ML15083A538 March 10, 2015        Transcript from evening public scoping meeting                ML15089A580 March 31, 2015        Transmittal of severe accident mitigation alterative (SAMA)  ML15083A546 audit plan from NRC to Exelon April 24, 2015        SAMA audit summary                                            ML15106A812 April 28, 2015        Transmittal of environmental audit plan from NRC to Exelon    ML15106A392 April 30, 2015        Transmittal of SAMA requests for additional information      ML15114A320 (RAIs) from NRC to Exelon May 20, 2015          Environmental audit summary                                  ML15132A674 May 22, 2015          Transmittal of environmental RAIs from NRC to Exelon          ML15142A764 May 29, 2015          Exelon response to SAMA RAIs                                  ML15149A370 June 25, 2015          Summary of teleconference between NRC and Exelon              ML15167A486 regarding transportation impacts for LSCS high burnup fuel D-1
 
Appendix D Date              Correspondence Description                                  ADAMS No.
June 25, 2015      Transmittal of RAIs regarding transportation impacts for    ML15167A488 LSCS high burnup fuel from NRC to Exelon July 2, 2015      Exelon response to environmental RAIs                        ML15195A351 July 8, 2015      Scoping Summary Report                                      ML15147A380 July 24, 2015      Exelon response to RAIs regarding transportation impacts for ML15205A003 LSCS high burnup fuel July 31, 2015      Exelon transmittal of revisions to the License Renewal      ML15212A259 Application Environmental Report August 28, 2015    Revised response to RAIs regarding transportation impacts    ML15240A002 for LSCS high burnup fuel September 21, 2015 Resubmittal of Index Item # 058 (ER References to be        ML15273A423 Docketed) from Exelon D-2
 
1          APPENDIX E 2 PROJECTS AND ACTIONS CONSIDERED 3  IN CUMULATIVE IMPACTS ANALYSIS
 
1 E. PROJECTS AND ACTIONS CONSIDERED IN THE CUMULATIVE 2      IMPACTS ANALYSIS 3 Table E-1 identifies actions and projects considered in the U.S. Nuclear Regulatory 4 Commission (NRC) staffs analysis of cumulative impacts related to the environmental analysis 5 of the continued operation of LaSalle County Station, Units 1 and 2 (LSCS). Potential 6 cumulative impacts associated with these actions and projects are addressed in Section 4.16 of 7 this supplemental environmental impact statement. However, not all actions or projects listed in 8 this appendix are considered in each resource area because of the uniqueness of the resource 9 and its geographic area of consideration.
10                      Projects and Actions Considered in Cumulative Impacts Analysis Location (Relative Project Name            Summary of Project            to LSCS)            Status Nuclear Projects Clinton Power Station,  Nuclear power plant,          DeWitt County, IL,  Operational (NRC 2015a)
Unit 1                  one 1,067-MWe                approximately General Electric Type 6      75 mi (121 km) reactor                      south. 50-mi (80 km) radius overlaps with that of LSCS Byron Station, Units 1  Nuclear power plant,          Ogle County, IL,    Operational (NRC 2015b, and 2                  two 1,121-MWe                approximately      2015c)
Westinghouse 4-loop reactors 65 mi (105 km) north-northwest.
50-mi (80 km) radius overlaps with that of LSCS Braidwood Station,      Nuclear power plant,          Will County, IL,    Operational (NRC 2015d, Units 1 and 2          two 1,121-MWe                approximately      2015e)
Westinghouse 4-loop reactors 23 mi (37 km) east Dresden Nuclear        Nuclear power plant,          Grundy County, IL, Operational (NRC 2015f, Power Station, Units 2  two 867-MWe                  approximately      2015g) and 3                  General Electric Type 3      23 mi (37 km) east-reactors                      northeast Dresden Nuclear        Nuclear power plant          Grundy County, IL,  Shut down in Power Station, Unit 1  (undergoing                  approximately      October 1978 and is decommissioning)              23 mi (37 km) east- currently in SAFSTOR.
northeast          No dismantlement activities are under way.
All spent fuel from DNPS Unit 1 transferred to the onsite Independent Spent Fuel Storage Installation (NRC 2015h)
E-1
 
Appendix E Location (Relative Project Name          Summary of Project              to LSCS)            Status Quad Cities Nuclear    Nuclear power plant,            Rock Island        Operational Power Station, Units 1 two 867-MWe General Electric    County, IL,        (NRC 2015i, 2015j) and 2                  Type 3 reactors                  approximately 91 mi (146 km) west-northwest. 50 mi (80 km) radius overlaps with that of LSCS Renewable Energy Projects Grand Ridge Wind      140-unit wind farm with          Immediately west    Operational Farm                  210 MW generating capacity      of LSCS property    (Invenergy 2015a, 2015b, and 34 MW energy storage        and extending      2015c, 2015d; Windpower support facility                southwest          2015a, 2015b, 2015c, approximately      2015d) 8 mi (13 km)
Top Crop Wind Farm    200-unit wind farm with          Grundy, LaSalle    Operational (EIA 2015a, 300 MW generating capacity      and Livingston      2015b; Windpower 2015e, Counties, IL,      2015f; approximately 6 mi  EDP Renewables 2015)
(10km) south-southeast Grand Ridge Solar      Solar photovoltaic facility with Streator, IL,      Operational Farm                  20 MW generating capacity        approximately 8 mi (EIA 2015c, (13 km) southwest Invenergy 2015e)
Minonk Wind Farm      100-unit wind farm with          Woodford and        Operational (EIA 2015d, 192 MW generating                Livingston          Mortenson 2015) capacity                        Counties, IL, approximately 27 mi (43 km) southwest Streator-Cayuga Ridge 150-unit wind farm with          Livingston County,  Operational (EIA 2015e, Wind Farm              300 MW generating                IL, approximately  Windpower 2015g) capacity                        18 mi (29 km) southeast Starved Rock Power    Hydroelectric dam with 6.8      On Illinois River,  Operational (EIA 2015f)
Station                MW generating capacity          approximately 17 mi (28 km) west-northwest Midwest Hydro LLC      Hydroelectric dam with 3.6      On Fox River,      Operational (EIA 2015g)
MW generating capacity          approximately 12 mi (19 km) northwest Morris Genco LLC      Waste-to-energy biomass-        Grundy County, IL, Operational (EIA 2015h) fueled facility with 2 MW        approximately generating capacity              17 mi (27 km) northwest Prairie View          Waste-to-energy biomass-        Will County, IL,    Operational (EIA 2015i)
Renewable Energy      fueled facility with 4.8 MW      approximately generating capacity              30 mi (49 km) east-northeast E-2
 
Appendix E Location (Relative Project Name          Summary of Project              to LSCS)            Status Fossil Fuel Projects Peru City Power Plant Petroleum-fueled plant with      Peru, IL,          Operational (EIA 2015g) 27.5 MW generating capacity      approximately 24 mi (38 km) north Oglesby Gas Plant    Natural gas-fueled plant with    Oglesby, IL,        Operational (EIA 2015j) 54 MW generating capacity        approximately 21 mi (34 km) west-northwest Morris Cogeneration  Natural gas-fueled plant with    Morris IL,          Operational (EIA 2015k)
LLC                  176 MW generating capacity      approximately 21 mi (34 km) northwest Kendall County        Natural gas-fueled plant with    Kendall County, IL, Operational (EIA 2015l)
Generation            1,140 MW generating              approximately capacity                        27 mi (43 km) northeast Manufacturing Facilities Agrium Inc.          Fertilizer solution              Marseilles, IL      Operational (Agrium 2015, storage facility                approximately 5 mi EPA 2015a)
(8 km) north Glen-Gery Marseilles  Brick manufacturer              Marseilles, IL      Operational (EPA 2015a, Plant                                                  approximately 5 mi Glen-Gery 2015)
(8 km) north Independence Tube    Structural steel tubing          Marseilles, IL      Operational (EPA 2015a, Corporation          manufacturer                    approximately 5 mi Independence 2015)
(8 km) north PotashCorp - PCS      Phophate animal feed            Marseilles, IL      Operational (EPA 2015a, Phosphate Marseilles  production                      approximately 5 mi PotashCorp 2015)
Operation                                              (8 km) north SABIC Innovative      Plastic fabrication              Ottawa IL,          Operational (EPA 2015a, Plastics                                              approximately      SABIC 2015) 7.5 mi (12 km) northwest CF Industries Seneca  Fertilizer distribution terminal Seneca, IL          Operational (CFIndustries Ammonia Terminal                                      approximately 5 mi 2015, (8 km) northeast    EPA 2015a)
H.B. Fuller          Industrial adhesive, coating,    Morris, IL          Operational (EPA 2015a, and sealant manufacturer        approximately 7 mi H.B. Fuller 2015)
(11 km) northeast E-3
 
Appendix E Location (Relative Project Name            Summary of Project                to LSCS)          Status Landfills LandComp Landfill      188 ac (76 ha) municipal solid Ottawa, IL,          Operational until 2034 waste landfill                    approximately      (IEPA 2013, 2015) 14 mi (2 km) northwest Environtech, Inc.      169 ac (68 ha) municipal solid Morris, IL,          Expected to close 2015 waste landfill                    approximately      (IEPA 2013, 2015) 17 mi (27 km) northeast Livingston Landfill    550 ac (223 ha) municipal        Livingston, IL,    Operational until 2037 solid waste landfill              approximately      (IEPA 2013, 2015) 22 mi (35 km) south Prairie View Recycling  408 ac (165 ha) municipal        Wilmington, IL,    Operational until 2040, and Disposal Facility  solid waste landfill              approximately      (IEPA 2013, 2015) 30 mi (48 km) northeast within former Joliet Army Ammunition Plant Water Supply and Treatment Facilities City of Marseilles,    Withdraws groundwater            Approximately 6 mi Operational (EPA 2015b, water supply            obtained from wells in the        (10 km) north-    Exelon 2014)
Cambrian-Ordovician Aquifer. northwest City of Seneca, water  Withdraws groundwater            Approximately 6 mi Operational (EPA 2015b, supply                  obtained from wells in the        (10 km) north-    Exelon 2014)
Cambrian-Ordovician Aquifer. northeast Village of Grand Ridge, Withdraws groundwater            Approximately      Operational (EPA 2015a, water supply            obtained from wells in the        8.5 mi (13.5 km)  Exelon 2014)
Buried Bedrock Valleys            east Aquifer.
City of Marseilles,    Water treatment with              Approximately 6 mi Operational (EPA 2015a) wastewater treatment    discharge to the Illinois River  (10 km) north-northwest Various minor NPDES Various businesses with              Within 50 mi      Operational (EPA 2015a) wastewater discharges smaller wastewater                  (80 km) discharges Mining Projects U.S. Silica            Sandstone mine and silica        Ottawa, IL,        Operational (EPA 2015a, production facility              approximately      U.S. Silica 2015) 12 mi (19.5 km) northwest Unimin Corporation      Sandstone mine and silica        Utica, IL,        Operational (EPA 2015a, production facility              approximately      Unimin 2015) 18.5 mi (30 km) northwest E-4
 
Appendix E Location (Relative Project Name          Summary of Project              to LSCS)          Status Northern White Sand    Sandstone mine and silica      Utica, IL,        Operational Proposed LLC                    production facility that is    approximately      expansion is pending proposing 350 ac (142 ha)      16.5 mi (26.5 km)  before the LaSalle County expansion.                      northwest          Board (EPA 2015a, NewsTribune 2014)
Mississippi Sand LLC  Proposed 314 ac (127 ha)        Ottawa, IL,        On hold pending legal sandstone mine near eastern    approximately      challenges entrance to Starved Rock        17 mi (27 km)      (NewsTribune 2014)
State Park                      north-northwest, near eastern entrance to Starved Rock State Park Remediation Site Joliet Army            14-sq mi (36-sq. km) military  Joliet, IL,        Ongoing remediation Ammunition Plant      complex operated from early    approximately      under the purview of the 1940s through 1977 to          28 mi (45 km)      U.S. Army. Land use manufacture, load, assemble,    northeast          controls are restricting and package high-explosive                        land uses; portions are artillery shells, bombs, mines,                    now under productive and small-arms ammunition.                        reuse by the U.S. Forest Other activities on site                          Service (Midewin National included testing of                                Tallgrass Prairie), the ammunition, washout and                            Veterans Administration renovation of shells, and                          (Abraham Lincoln National burning and demolition of                          Cemetery), Will County explosives.                                        (500-ac [202-ha] landfill),
and productive uses through commercial and industrial redevelopment (EPA 2013).
Parks and Recreation Sites LaSalle Lake State    2,058 ac (833 ha) lake that    Onsite            Operational. Managed by Fish and Wildlife Area serves as the cooling lake for                    Illinois Department of LaSalle Generating Station.                        Natural Resources Managed for public boating                        (IDNR 2015a) and fishing.
Marseilles State Fish  2,550 ac (1,032 ha) tract that  Approximately      Operational.
and Wildlife Area      serves as joint-use area for    1.5 mi (2.4 km)    Cooperatively managed the Illinois Department of      north              by Illinois Department of Natural Resources (as a                            Natural Resources and hunting and habitat                                Illinois Department of management site) and the                          Military Affairs through Illinois National Guard (for                      Memorandum of live-fire training when hunting                    Agreement seasons are closed).                              (IDNR 2015b, ING undated)
E-5
 
Appendix E Location (Relative Project Name          Summary of Project                to LSCS)          Status Illini State Park      510 ac (206 ha) park along        Approximately 6 mi Operational. Managed by the south bank of the Illinois    (10 km) north-    Illinois Department of River. Hiking, fishing, boating northwest            Natural Resources and camping occur within the                        (IDNR 2015c) park.
Buffalo Rock State    298 ac (121 ha) park along        Approximately      Operational. Managed by Park                  the north bank of the Illinois    13.5 mi (22 km)    Illinois Department of River. Hiking, fishing, and      northwest          Natural Resources camping occur within the                            (IDNR 2015d) park.
Gebhard Woods          30 ac (12 ha) park along the      Approximately      Operational. Managed by State Park            north bank of the Illinois River. 14 mi (23 km)      Illinois Department of Hiking, fishing, boating and      northeast          Natural Resources camping occur within the                            (IDNR 2015e) park.
Starved Rock State    2,700 ac (1,093 ha) park          On Illinois River, Operational. Managed by Park                  containing sandstone buttes,      approximately      Illinois Department of 18 canyons, waterfalls, and      15 mi (24 km)      Natural Resources 13 mi (21 km) of hiking trails. northwest          (IDNR 2015f)
Camping, fishing, boating and hunting also occur within the park.
Matthiessen State Park 1,938 ac (784 ha) park            18 mi (29 km) west Operational. Managed by containing forested canyons,                        Illinois Department of rock formations and water                            Natural Resources falls. Hiking, camping, biking,                      (IDNR 2015g) and horseback riding occur within the park.
Goose Lake Prairie    2,537 ac (1,026 ha) area          Approximately      Operational. Managed by State Natural Area    representing largest remnant      20 mi (31 km)      Illinois Department of of prairie in Illinois. Used for  north-northeast. Natural Resources hiking, picnicking, cross-        Adjacent to        (IDNR 2015h) country skiing and hunting        Heidecke Lake State Fish and Wildlife Area Heidecke Lake State    1,300 ac (526 ha) lake            Approximately      Operational. Managed by Fish and Wildlife Area managed for public fishing        20 mi (31 km)      Illinois Department of and hunting. Originally          north-northeast. Natural Resources constructed in 1978 as the        Adjacent to Goose  (IDNR 2015i) cooling lake for the former      Lake Prairie State Collins Generating Station        Natural Area Recreational Areas    Various parks, boat launches, Within 10 mi          Operational and campgrounds                  (16 km)
E-6
 
Appendix E Location (Relative Project Name              Summary of Project                to LSCS)              Status Other Projects Future Urbanization        Construction of housing units Throughout region          Construction would occur and associated commercial                                in the future, as described buildings; roads, bridges, and                          in State and local land-use rail; water and/or wastewater                            planning documents.
treatment and distribution facilities; and associated pipelines as described in local land-use planning documents Key: ac = acres; ha = hectares; km = kilometers; mi = miles; NPDES = National Pollutant Discharge Elimination System; sq. = square 1      References 2 Agrium. 2015. Marseilles Solution Storage. Available at <http://www.agrium.com/en/what-3 we-do/locations> (accessed 8 September 2015).
4 CFIndustries. 2015. Seneca Ammonia Terminal. Available at 5 <http://www.cfindustries.com/distribution_seneca-terminal.html> (accessed 18 August 2015).
6 EDP Renewables. 2015. Illinois/Top Crop Factsheet. Available at <http://topcrop.edpr-7 windfarms.com/wp-content/uploads/sites/14/2014/03/Top-Crop_Fact-Sheet_6.25.15.pdf>
8 (accessed 7 August 2015).
9 [EIA] U.S. Energy Information Administration. 2015a. Illinois State Profile and Energy 10 Estimates, Profile Overview Interactive Map - Blackstone [Top Crop] Wind Farm LLC.
11 Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015).
12 [EIA] U.S. Energy Information Administration. 2015b. Illinois State Profile and Energy 13 Estimates, Profile Overview Interactive Map - Blackstone II [Top Cropn II] Wind Farm LLC.
14 Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015).
15 [EIA] U.S. Energy Information Administration. 2015c. Illinois State Profile and Energy 16 Estimates, Profile Overview Interactive Map - Grand Ridge Solar Farm. Available at 17 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).
18 [EIA] U.S. Energy Information Administration. 2015d. Illinois State Profile and Energy 19 Estimates, Profile Overview Interactive Map - Minonk Wind Farm. Available at 20 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).
21 [EIA] U.S. Energy Information Administration. 2015e. Illinois State Profile and Energy 22 Estimates, Profile Overview Interactive Map - Streator Cayuga Ridge South. Available at 23 <http://www.eia.gov/state/?sid=IL> (accessed 30 September 2015).
24 [EIA] U.S. Energy Information Administration. 2015f. Illinois State Profile and Energy 25 Estimates, Profile Overview Interactive Map - Peru Hydro. Available at 26 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015).
27 [EIA] U.S. Energy Information Administration. 2015g. Illinois State Profile and Energy 28 Estimates, Profile Overview Interactive Map - Dayton Hydro. Available at 29 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).
E-7
 
Appendix E 1 [EIA] U.S. Energy Information Administration. 2015h. Illinois State Profile and Energy 2 Estimates, Profile Overview Interactive Map - Morris Genco LLC. Available at 3 <http://www.eia.gov/state/?sid=IL> (accessed 30 September 2015).
4 [EIA] U.S. Energy Information Administration. 2015i. Illinois State Profile and Energy 5 Estimates, Profile Overview Interactive Map - Prairie View. Available at 6 <http://www.eia.gov/state/?sid=IL> (accessed 17 August 2015).
7 [EIA] U.S. Energy Information Administration. 2015j. Illinois State Profile and Energy 8 Estimates, Profile Overview Interactive Map - Oglesby. Available at 9 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).
10 [EIA] U.S. Energy Information Administration. 2015k. Illinois State Profile and Energy 11 Estimates, Profile Overview Interactive Map - Morris Cogeneration LLC. Available at 12 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).
13 [EIA] U.S. Energy Information Administration. 2015l. Illinois State Profile and Energy 14 Estimates, Profile Overview Interactive Map - Kendall County Generation Facility. Available at 15 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015).
16 [EPA] U.S. Environmental Protection Agency. 2013. Region 5 Cleanup Sites: Joliet Army 17 Ammunition Plant. November 14, 2013. Available at 18 <http://www.epa.gov/region05/cleanup/jolietarmy/index.html> (accessed 17 August 2015).
19 [EPA] U.S. Environmental Protection Agency. 2015a. Envirofacts PCS/ICIS search results for 20 Peru Illinois: Facilities with permits to discharge wastewater to waters of the United States.
21 August 14, 2015. Available at <http://oaspub.epa.gov/enviro/PCSICISQuery.list?minx=-
22 89.148560&miny=40.996484&maxx=-88.187256&maxy=4l> (accessed 14 August 2015).
23 [EPA] U.S. Environmental Protection Agency. 2015b. Envirofacts SDWIS search results for 24 LaSalle, Illinois: List of Safe Drinking Water Systems. August 17, 2015. Available at 25 <http://www.epa.gov/enviro/facts/sdwis/search.html> (accessed 17 August 2015).
26 [Exelon] Exelon Generation Company, LLC. 2014. Applicants Environmental Report -
27 Operating License Renewal Stage, LaSalle County Station, Units 1 and 2, License Renewal 28 Application. Kennett Square, PA: Exelon. December 9, 2014. ADAMS No. ML14343A883.
29 [Glen-Gery] Glen-Gery Corporation. 2015. Marseilles Plant. Available at 30 <http://www.glengery.com/about-us/locations/item/164981492-marseilles-plant/164981492-31 marseilles-plant> (accessed 1 October 2015).
32 H.B. Fuller. 2015. Available at <http://www.hbfuller.com/north-america>
33 (accessed 1 October 2015) 34 [IDNR] Illinois Department of Natural Resources. 2015a. LaSalle Lake State Fish & Wildlife 35 Area. Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/LASALLE.HTM>
36 (accessed 18 August 2015).
37 [IDNR] Illinois Department of Natural Resources. 2015b. Marseilles State Fish & Wildlife 38 Area. Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/MARSEIL.HTM>
39 (accessed 18 August 2015).
40 [IDNR] Illinois Department of Natural Resources. 2015c. Illini State Park. Available at 41 <http://www.dnr.illinois.gov/Parks/Pages/Illini.aspx> (accessed 18 August 2015).
42 [IDNR] Illinois Department of Natural Resources. 2015d. Buffalo Rock State Park. Available 43 at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/I&M/EAST/BUFFALO/Home.htm>
44 (accessed 18 August 2015).
E-8
 
Appendix E 1 [IDNR] Illinois Department of Natural Resources. 2015e. Gebhard Woods State Park.
2 Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/I&M/EAST/
3 GEBHARD/Park.htm> (accessed 18 August 2015).
4 [IDNR] Illinois Department of Natural Resources. 2015f. Starved Rock State Park. 2015.
5 Available at <http://www.dnr.illinois.gov/Parks/Pages/StarvedRock.aspx> (accessed 6 18 August 2015).
7 [IDNR] Illinois Department of Natural Resources. 2015g. Matthiessen State Park. Available 8 at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/mttindex.htm> (accessed 9 18 August 2015).
10 [IDNR] Illinois Department of Natural Resources. 2015h. Goose Lake Prairie State Natural 11 Area. Available at <http://www.dnr.illinois.gov/Parks/Pages/GooseLakePrairie.aspx>
12 (accessed 18 August 2015).
13 [IDNR] Illinois Department of Natural Resources. 2015i. Heidecke Lake State Fish and Wildlife 14 Area. Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R2/Heidecke.htm>
15 (accessed 18 August 2015).
16 [IEPA] Illinois Environmental Protection Agency. 2013. Nonhazardous Solid Waste 17 Management and Landfill Capacity in Illinois: 2012. Springfield, IL: IEPA. October 2013. 67 p.
18 Available at <http://www.epa.state.il.us/land/landfill-capacity/2012/report.pdf> (accessed 19 14 August 2015).
20 [IEPA] Illinois Environmental Protection Agency. 2015. Illinois Landfill Projections of Disposal 21 Capacity as of January 1, 2015. Springfield, IL: IEPA. July 2015. 48 p. Available at 22 <http://www.epa.illinois.gov/Assets/iepa/waste-management/landfills/landfill-capacity/landfill-23 capacity-report-2015.pdf> (accessed 14 August 2015).
24 [Independence] Independence Tube Corporation. 2015. Available at 25 <http://www.independencetube.com/history> (accessed 1 October 2015).
26 [ING] Illinois National Guard. undated. Marseilles Training Area. Available at 27 <http://www.il.ngb.army.mil/MilitaryAffairs/MTA/> (accessed 18 August 2015).
28 [Invenergy] Invenergy, LLC. 2015a. Grand Ridge I. Available at 29 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeI.aspx> (accessed 30 14 August 2015).
31 [Invenergy] Invenergy, LLC. 2015b. Grand Ridge II - IV. Available at 32 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeIIIV.aspx> (accessed 33 14 August 2015).
34 [Invenergy] Invenergy, LLC. 2015c. Grand Ridge IV Storage. Available at 35 http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeIVStorage.aspx 36 (accessed 14 August 2015).
37 [Invenergy] Invenergy, LLC. 2015d. Grand Ridge Energy Storage. Available at 38 http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeEnergyStorage.aspx 39 (accessed 14 August 2015).
40 [Invenergy] Invenergy, LLC. 2015e. Grand Ridge Solar. Available at 41 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeSolar.aspx>
42 (accessed 14 August 2015).
43 Mortenson 2015. Minonk Wind Farm Project. Available at 44 <http://www.mortenson.com/wind/projects/minonk-wind-farm> (accessed 14 August 2015).
E-9
 
Appendix E 1 [NewsTribune] LaSalle News Tribune. 2014. Sorting out LaSalle Countys four newest sand 2 mines. July 2, 2014. Available at <http://newstrib.com/main.asp?SectionID=
3 2&SubSectionID=232&ArticleID=37558> (accessed 8 September 2015).
4 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Clinton Power Station, Unit 1.
5 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/clin.html> (accessed 6 11 August 2015).
7 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Byron Station, Unit 1. June 30, 2015.
8 Available at <http://www.nrc.gov/info-finder/reactor/byro1.html> (accessed 11 August 2015).
9 [NRC] U.S. Nuclear Regulatory Commission. 2015c. Byron Station, Unit 2. June 30, 2015.
10 Available at <http://www.nrc.gov/info-finder/reactor/byro2.html> (accessed 11 August 2015).
11 [NRC] U.S. Nuclear Regulatory Commission. 2015d. Braidwood Station, Unit 1.
12 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/brai1.html> (accessed 13 11 August 2015).
14 [NRC] U.S. Nuclear Regulatory Commission. 2015e. Braidwood Station, Unit 2.
15 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/brai2.html> (accessed 16 11 August 2015).
17 [NRC] U.S. Nuclear Regulatory Commission. 2015f. Dresden Nuclear Power Station, Unit 2.
18 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/dres2.html> (accessed 19 11 August 2015).
20 [NRC] U.S. Nuclear Regulatory Commission. 2015g. Dresden Nuclear Power Station, Unit 3.
21 July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/dres3.html> (accessed 22 11 August 2015).
23 [NRC] U.S. Nuclear Regulatory Commission. 2015h. Dresden - Unit 1. June 12, 2015.
24 Available at <http://www.nrc.gov/info-finder/decommissioning/power-reactor/
25 dresden-nuclear-power-station-unit-1.html> (accessed 11 August 2015).
26 [NRC] U.S. Nuclear Regulatory Commission. 2015i. Quad Cities Nuclear Power Station, 27 Unit 1. July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/quad1.html>
28 (accessed 11 August 2015).
29 [NRC] U.S. Nuclear Regulatory Commission. 2015j. Quad Cities Nuclear Power Station, 30 Unit 2. July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/quad2.html>
31 (accessed 11 August 2015).
32 PotashCorp 2015. PotashCorp - Marseilles. Available at 33 <http://www.potashcorp.com/about/facilities/phosphate/marseilles/> (accessed 34 18 August 2015).
35 [SABIC] Saudi Basic Industries Corporation. 2015. Annual Report 2014. Available at 36 <http://www.sabic.com/me/en/newsandmediarelations/publications/overview_annual_report>
37 (accessed 1 October 2015).
38 [Unimin] Unimin Corporation. 2015. Unimin Locations. Available at 39 <http://www.unimin.com/unimin-locations.cfm> (accessed 9 September 2015.)
40 U.S. Silica 2015. U.S. Silica Locations - Ottawa IL. Available at 41 <http://www.ussilica.com/locations/ottawa-il> (accessed 19 August 2015).
42 Windpower 2015a. The Windpower - Grand Ridge I Wind Farm. Available at 43 <http://www.thewindpower.net/windfarm_en_4022_grand-ridge-i.php> (accessed 44 7 August 2015).
E-10
 
Appendix E 1 Windpower 2015b. The Windpower - Grand Ridge II Wind Farm. Available at 2 <http://www.thewindpower.net/windfarm_en_10985_grand-ridge-ii.php> (accessed 3 7 August 2015).
4 Windpower 2015c. The Windpower - Grand Ridge III Wind Farm. Available at 5 <http://www.thewindpower.net/windfarm_en_10986_grand-ridge-iii.php> (accessed 6 7 August 2015).
7 Windpower 2015d. The Windpower - Grand Ridge IV Wind Farm. Available at 8 <http://www.thewindpower.net/windfarm_en_18016_grand-ridge-iv.php> (accessed 9 7 August 2015).
10 Windpower 2015e. The Windpower - Top Crop Wind Farm. Available at 11 <http://www.thewindpower.net/windfarm_en_724_top-crop.php> (accessed 7 August 2015).
12 Windpower 2015f. The Windpower - Top Crop II Wind Farm. Available at 13 <http://www.thewindpower.net/windfarm_en_21266_top-crop-ii.php> (accessed 7 August 2015).
14 Windpower 2015g. The Windpower - Streator Cayuga Ridge Wind Farm. Available at 15 <http://www.thewindpower.net/windfarm_en_10983_streator-cayuga-ridge-wind-farm.php>
16 (accessed 14 August 2015).
E-11
 
1                        APPENDIX F 2 U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 3  SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR LASALLE 4    COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF LICENSE 5              RENEWAL APPLICATION REVIEW
 
1 F. U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 2      OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 3      LASALLE COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF 4      LICENSE RENEWAL APPLICATION REVIEW 5        Introduction 6 Exelon Generation Company, LLC (Exelon) submitted a license renewal application for LaSalle 7 County Station (LSCS), Units 1 and 2. Exelon assessed severe accident mitigation alternatives 8 (SAMAs) for LSCS in Appendix F of its Environmental Report (ER) (Exelon 2014a). This 9 assessment was based on the most recent LSCS probabilistic risk assessment (PRA) available 10 at that time, a plant-specific offsite consequence analysis performed using the MELCOR 11 Accident Consequence Code System (MACCS2) Version 1.13.1 computer code, and insights 12 from the LSCS individual plant examination (IPE) and individual plant examination of external 13 events (IPEEE). In identifying and evaluating potential SAMAs, Exelon considered SAMAs that 14 addressed the major contributors to core damage frequency (CDF) and release frequency at 15 LSCS, as well as SAMA candidates from six other boiling water reactor (BWR) plants. Exelon 16 initially identified 27 potential SAMAs. Then, Exelon reduced the list to 25 unique SAMA 17 candidates by eliminating SAMAs that are not applicable to LSCS, that have already been 18 implemented at LSCS, or that have excessive implementation costs. Next, Exelon assessed 19 the costs and benefits associated with each of the 25 potential SAMAs and concluded that 20 14 SAMA candidates were potentially cost beneficial at the 95th percentile. Exelon performed 21 sensitivity analyses on the real discount rate, CDF uncertainty at the 95th percentile, as well as 22 the offsite consequence parameters, and considered those results in the cost-benefit analysis.
23 As an additional sensitivity analysis in the ER, Exelon considered the planned installation of a 24 hardened vent pipe as the base case to provide supplemental information on potentially 25 cost-beneficial SAMAs following the vent pipe installation.
26 Based on a review of Exelons SAMA assessment and the SAMA audit held on April 78, 2015, 27 the U.S. Nuclear Regulatory Commission (NRC) staff issued requests for additional information 28 (RAIs) to Exelon by letter dated April 30, 2015 (NRC 2015). Key questions concerned the 29 differences between LSCS Units 1 and 2, systems shared between the two units and how these 30 are modeled in the PRA; the definition and assignment of accident classes; additional details on 31 the Level 2 and 3 PRA models, including the basis for representative sequences for each 32 release category; the determination of the frequency of the intact release category; the 33 identification and screening of candidate SAMAs; the potential for additional SAMAs to mitigate 34 fire risk; the evaluation of the risk reduction of certain SAMAs; and the basis for the SAMA cost 35 estimates. By letter dated May 29, 2015, Exelon submitted additional information that included 36 revisions and a correction, which changed the determination of one SAMA from potentially cost 37 beneficial in the ER to not cost beneficial (Exelon 2015). Exelons responses addressed the 38 NRC staffs concerns.
39 The evaluation of the LSCS SAMA analysis is presented below.
40        Estimate of Risk for LSCS 41 Exelons estimates of offsite risk at LSCS are summarized in Section F.2.1. The summary is 42 followed by the NRC staffs review of Exelons risk estimates in Section F.2.2.
F-1
 
Appendix F 1 F.2.1. Exelons Risk Estimates 2 Exelon combined two distinct analyses to form the basis for risk estimates used in the SAMA 3 analysis: (1) the LSCS Level 1 and 2 PRA models and (2) a supplemental analysis of offsite 4 consequences and economic impacts (essentially a Level 3 PRA model) developed specifically 5 for the SAMA analysis. The Level 1 model is a significant upgrade and revision of the IPE 6 Level 1 model, while the Level 2 model is an update of the prior large early release frequency 7 (LERF) models. The SAMA analysis is based on the most recent LSCS Level 1 and 2 PRA 8 models available at the time of the ER, referred to as the LSCS PRA 2013A (or LS213A) model.
9 This LSCS PRA includes internal flooding but does not include external events.
10 The LSCS CDF is approximately 2.6x106 per year (Exelon 2014a). Exelon did not explicitly 11 include the contribution from external events within the LSCS SAMA risk estimates; however, it 12 did account for the potential risk reduction benefits associated with external events by 13 multiplying the estimated benefits for internal events by 5.2. This is discussed further in 14 Section F.2.2.2.
15 The breakdown of CDF by initiating event is provided in Table F-1. As shown in this table, 16 events initiated by a turbine trip with bypass, a dual unit loss of offsite power (LOOP), a loss of 17 instrument air, and a loss of condenser vacuum are the dominant contributors to the CDF. In a 18 response to RAIs, Exelon identified that station blackout (SBO) contributes 6.4x107 per year, or 19 25 percent of the total CDF for internal events while anticipated transients without scram 20 (ATWS) contributes 4.9x107 per year, or approximately 19 percent, of the total CDF for each 21 unit (Exelon 2015).
22 Regarding Level 2 analysis, Exelon stated:
23            The expansion of the LERF model to a full Level 2 model involved a 24            reassessment of the timing and release categorization of each containment event 25            tree (CET) end state. To perform this reassessment, MAAP calculations for each 26            accident class were performed and used to assess the CET end states. Each 27            CET node was evaluated and updated to reflect the current state of knowledge 28            regarding Level 2 accident phenomenology. The end state timing was also 29            updated to reflect the current emergency plan and evacuation time estimates.
30 The Level 2 model uses three general containment event tree (CET) types to assess the 31 accident progression during a core damage event. CETs contain both phenomenological and 32 containment system status events. Level 1 core damage sequences are binned into plant 33 damage states (PDSs) or accident classes, which provide the interface between the Level 1 and 34 Level 2 CET analysis. Each accident class bin is entered into the CET, resulting in 35 15 LSCS-specific CETs. The CET is linked directly to the Level 1 event trees, and CET nodes 36 are evaluated using supporting fault trees (Exelon 2015).
37 The result of the Level 2 PRA is a set of 13 release bins or categories with their respective 38 frequency and release characteristics. The results of this analysis for LSCS are provided in 39 Tables F.2-5, F.2-6, F.3-15, F.3-16, and F.3-19 of the ER (Exelon 2014a). The categories 40 were defined based on the timing of release (three release time ranges) and the magnitude of 41 release (four release magnitude ranges). One additional release category was included for an 42 intact containment.
43 For the SAMA analysis, the release category for high magnitude and early timing was divided 44 into two bins (one with containment isolation and one without). Due to the small release 45 category contributions from six categories, the number of release category bins was reduced to 46 eight cases. The frequency of each release category was obtained by summing the frequency 47 of the individual accident progression CET endpoints binned into the release category. Source F-2
 
Appendix F 1 terms were developed for each of the 13 release categories using the results of Modular 2 Accident Analysis Program (MAAP) Version 4.0.5 computer code calculations (Exelon 2014a).
3 Exelon computed offsite consequences for potential releases of radiological material using the 4 MACCS2 Version 1.13.1 code and analyzed exposure and economic impacts from its 5 determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 6 site-specific input values for core radionuclide inventory, source term and release 7 characteristics, site meteorological data, projected population distribution and growth within a 8 50-mile (80-km) radius, emergency response evacuation modeling, and economic data. The 9 estimation of onsite impacts (in terms of cleanup costs, decontamination costs, and 10 occupational dose) is based on guidance in NUREG/BR-0184 (NRC 1997a). In its calculation 11 for replacement power costs, Exelon accounted for the increased electric power output of LSCS 12 compared to the generic reactor power output presented in NUREG/BR-0184 (NRC 1997a).
13                                      LaSalle County Station CDF for Internal Events CDF(a)  Percent CDF Initiating Event                                                      (per year)  Contribution Turbine Trip with Bypass                                                5.6x107      22 Dual Unit Loss of Offsite Power                                          3.1x107      12 Loss of Instrument Air                                                  2.8x107      11 Loss of Condenser Vacuum                                                2.7x107      10 Fire Protection System Pipe Rupture in Reactor Building                  1.9x107        7 Main Steam Isolation Valve Closure                                      1.4x107        5 Loss of Turbine Building Component Cooling Water                        1.2x107        5 Loss of Feedwater                                                        1.1x108        4 Loss of Offsite Power                                                    7.2x108        3 Manual Shutdown                                                          5.9x108        2 Inadvertently Open Relief Valve                                          5.9x108        2 Loss of 125 V Direct Current Bus 2A                                      5.1x108        2 Loss of 125 V Direct Current Buses 2A and 2B                            3.9x108        2 Other Initiating    Events(b)                                            3.3x107      13 Total (Internal Events)(c)                                              2.58x106    100 (a) CDF based on Fussell-Vesely importance and total CDF.
(b) Other initiating events each contributing less than 2% to total CDF.
(c) Column totals may be different because of rounding.
Key: CDF = core damage frequency Source: Exelon 2014a 14 In the ER, as updated by the response to RAIs (Exelon 2015), Exelon calculated the dose risk 15 to be 0.0764 person-sievert (Sv) per year (7.64 person-rem per year) to the population within 16 80 km (50 mi) of the LSCS site. The offsite economic cost risk was calculated to be 17 $57,700 per year. The breakdown of the population dose risk by containment release category 18 is summarized in Table F-2. The medium magnitude, intermediate release category accounted 19 for 52 and 62 percent of the population dose risk and offsite economic cost risk, respectively.
F-3
 
Appendix F 1 Additionally, two categories (medium magnitude, early release and high magnitude, early 2 releases for breaks outside containment) together accounted for approximately 41 and 3 31 percent of the population dose risk and offsite economic cost risk, respectively.
4 F.2.2. Review of Exelons Risk Estimates 5 Exelons determination of offsite risk at the LSCS site is based on the following three major 6 elements of the analysis:
7          (1)  Upgraded Level 1 risk model that supersedes the 1994 IPE/IPEEE submittal 8              (CECO 1994), a new interim fire PRA and the seismic and other external event 9              analyses of the 1994 IPE/IPEEE submittal; 10          (2)  Expanded Level 2 risk model; and 11          (3)  MACCS2 analyses performed by Exelon to translate fission product source terms 12              and release frequencies from the Level 2 PRA model into offsite consequence 13              measures.
14 The NRC staff reviewed each of these analyses to determine the acceptability of the LSCS risk 15 estimates for the SAMA analysis.
16                                Base Case Mean Population Dose Risk and 17                        Offsite Economic Cost Risk for Internal Events Release Category              Population Dose Risk(a)          Offsite Economic Cost Risk Frequency ID(b)      (per year)    person-rem/year    % Contribution        $/year      % Contribution H/E-BOC(c)    8.3x108      1.3x100                18            7.2x103            13 H/E        6.0x108      3.2x101                4            2.8x103            5 H/I(d)      1.9x108      1.1x101                1            9.7x102            2 M/E        2.4x107      1.7x100                23            1.0x104            18 M/I(d)      1.0x106      3.9x100                52            3.6x104            62 L/E        3.9x107      8.7x102                1            1.3x102            0.2 L/I(d)      1.5x107      1.1x101                1            1.8x102            0.3 CI        6.2x107      1.4x103                <0.1          1.0x100            <0.1 Total      2.6x106 7.6x10 0 100            5.8x10 4 100 F-4
 
Appendix F Release Category                    Population Dose Risk(a)                Offsite Economic Cost Risk (a) Unit Conversion Factor: 1 Sv = 100 rem (b) Release  Mode Nomenclature (Magnitude/Timing)
Magnitude:
High (H)Greater than 10 percent release fraction for cesium iodide Medium (M)1 to 10 percent release fraction for cesium iodide Low (L)0.1 to 1 percent release fraction for cesium iodide Low-Low (LL)Less than 0.1 percent release fraction for cesium iodide Containment intact (CI)Much less than 0.1 percent release fraction for cesium iodide Timing:
Early (/E)Less than [[estimated NRC review hours::5 hours]] Intermediate (/I)5 to [[estimated NRC review hours::24 hours]] Late (/L)Greater than [[estimated NRC review hours::24 hours]] (c) Contributions from initiators with breaks outside containment (BOC)
(d) The release categories for late timing were negligible and subsumed into the intermediate release categories for H, M, and L releases. Categories for LL magnitude releases were negligible and subsumed into the L release category with intermediate timing.
Sources: Exelon 2014a, 2015 1 F.2.2.1. Internal Events CDF Model 2 Commonwealth Edison Company submitted a combined IPE/IPEEE report to fulfill the 3 requirements of Generic Letter 88-20 (NRC 1988). This submittal was brief and referred to the 4 information in NUREG/CR-4832, Analysis of the LaSalle Unit 2 Nuclear Power Plant: Risk 5 Methods Integration and Evaluation Program (RMIEP), which was performed by Sandia 6 National Laboratories (SNL) and sponsored by the NRC (NRC 1992).
7 The NRC staffs review of the LSCS IPE is described in its 1995 memorandum (NRC 1995).
8 Based on its review of the LSCS nuclear power plant IPE submittal and associated 9 documentation, the NRC staff concluded that the licensee met the intent of Generic Letter 88-20 10 (NRC 1988). As indicated in the NRC staff review, while the licensee concluded that no 11 vulnerabilities exist at LSCS, the licensee cited potential improvements identified and discussed 12 in Volume 3, Part 1 of the RMIEP report. These potential improvements are discussed in 13 Section F.3.2.
14 There have been numerous revisions to the LSCS PRA since the original 1994 IPE submittal.
15 A listing of the complete revision history of the LSCS PRA, since the original IPE submittal, was 16 provided in the ER (Exelon 2014a) and in response to an NRC staff RAI (Exelon 2015). The 17 PRA revision history is summarized in Table F-3. A comparison of the CDF for internal events 18 between the 1994 IPE and the current PRA model indicates there has been a significant 19 reduction in total CDF (point estimate including internal floods from 3.4x105 per year7 to 20 2.6x106 per year).
21 The CDF value from the 1994 IPE (3.4x105 per year) is within the range of CDF values 22 reported in the IPEs for BWR 5/6 plant units. In NUREG-1560, CDF values ranged from 1x105 7  The 3.4x106 per year total CDF is the sum of the point estimates for internal events and internal floods from RMIEP, as given in the Technical Evaluation Report attached to the NRC review of the LSCS IPE (NRC 1995).
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Appendix F 1 per year to 4x105 per year (NRC 1997b). It is recognized that other plants have updated the 2 values for CDF subsequent to the IPE submittals to reflect modeling and hardware changes.
3 The NRC staff considered the peer review performed for the LSCS PRA and the potential 4 impact of the review findings on the SAMA evaluation. In the ER, Exelon described the 5 2008 Boiling Water Reactor Owners Group (BWROG) peer review of the LSCS PRA. The peer 6 review was indicated to be performed against Addendum B of the then current PRA Standard 7 (ASME/ANS 2005) with the criteria in Regulatory Guide 1.200, Revision 1 (NRC 2007),
8 including the NRC positions stated in Appendix A of the regulatory guide.
9 Exelon indicated that a PRA update was conducted in 2011 that addressed the majority of 10 2008 peer review findings and American Society of Mechanical Engineers/American Nuclear 11 Society (ASME/ANS) PRA standards supporting requirements assigned a Capability Category II 12 or lower. In ER Table F.2-7 (Exelon 2014a), a summary was presented on the remaining open 13 supporting requirements identified from the peer review as not meeting Capability Category II 14 and associated findings, along with an assessment of the impact on the base PRA. Of the six 15 open supporting requirements, three are related to documentation and three have a relatively 16 minor impact on the PRA results.
17 The NRC staff has determined that Exelon has demonstrated sufficient internal events PRA 18 quality by addressing the peer review open findings noted above consistent with the guidance in 19 Nuclear Energy Institute (NEI) 05-01 (NEI 2005) and that the final resolution of the findings 20 provides reasonable assurance of a minimal impact on the results of the SAMA analysis. As 21 previously indicated, the 2013A update to the PRA model (LS213A) is the most recent 22 evaluation of the risk profile at LSCS for internal events. Exelon indicates this PRA model is 23 documented as an application-specific model developed for use in the SAMA application. The 24 current PRA model of record is the 2011A PRA. In the 2013A model, Level 1 logic from the 25 2011A model was not changed beyond what was required to integrate it with the Level 2 model.
26 CDF portions of the 2011A and 2013A PRA models are identical. Therefore, updates 27 performed in the 2011A model to resolve the peer review comments were carried into the 28 2013A model.
29 Section F.2 of the ER states that the LSCS PRA is a Unit 2 model. Because the units are nearly 30 identical, the PRA for Unit 2 is considered to be applicable to Unit 1, unless otherwise noted. In 31 an RAI, the NRC staff asked Exelon to provide a brief description of the differences between the 32 units, particularly those differences that might impact internal flooding and their impacts on the 33 unit risk. Exelon responded that the major difference between the units is that the common or 34 0 diesel generator is located in the Unit 1 Auxiliary Building and the 0 diesel generator 35 cooling water pump is located in the Unit 1 Division 1 core standby cooling system (CSCS) 36 pump room. A flood event that initiates in the Unit 1 Division 1 CSCS pump room does not 37 propagate from this room, because the surrounding areas are protected by a water tight door 38 and walls. Exelon indicated that this specific flood scenario is a negligible contributor to risk on 39 both units because it only impacts one division of CSCS equipment. The Unit 1 CDF 40 contribution from a flood in this area would be slightly higher than Unit 2 because the internal 41 flood also will impact the Unit 1 residual heat removal service water (RHRSW) pumps. The 42 Unit 1 RHRSW pumps do not have a function for Unit 2; therefore, loss of these pumps has no 43 quantitative impacts on the Unit 2 CDF values. Because these flood scenarios have a negligible 44 CDF impact and a limited impact on plant equipment and operator response, Exelon concluded 45 there would be no impact on the SAMA evaluation. Exelon also discussed the general plant 46 layout; internal flooding scenarios; and other asymmetries between units, including the power 47 supplies for the shared systems. Exelon concluded and the NRC staff agrees that none of the 48 minor differences has an impact on the SAMA evaluation (Exelon 2015).
F-6
 
Appendix F 1              Summary of Major PRA Models and Corresponding CDF and LERF Results CDF(a)(b)    LERF(a)(b)
PRA Model    Summary of Significant Changes From Prior Model              (per year)    (per year)
IPE (4/1994)
* IPE                                                        3.4x105        Not mean value    Quantified Updated IPE
* Converted to CAFTA linked fault tree                        1.0x105 (c)      Not (1996)
* Incorporated plant procedure changes and modifications                  Quantified 1999 Rev.1
* Increased credit for offsite AC power recovery              8.6x106      1.5x106 (11/1999)
* Took appropriate credit for turbine-driven feedwater pump and main condenser
* Corrected RCIC AC power dependency
* Revised containment modeling to not always core damage upon containment failure
* Revised service water system model
* Credited diesel fire pump for injection post containment challenge 2000A
* Credited increased 125 V DC battery life for extended      5.9x106(d)    1.0x106 (1/2000)      RCIC operability
* Included room cooling dependency for ECCS systems
* Included realistic assessment of post venting equipment reliability
* Updated CCF probabilities
* Expanded treatment of HRA dependencies
* Incorporated internal flood scenarios
* Incorporated unit electrical crossties
* Credited recovery of station air for containment venting during long-term loss of decay heat removal 2000C(e)
* Revised turbine building flood model                      8.2x106(d)      Not (3/2000)
* Updated HRA                                                              Quantified 2001A
* Changed turbine building flood model to reflect changes in 5.7x106(d)    6.7x107 (8/2001)      the pipe inspection program
* revised the scram failure probabilities based on new industry data
* incorporated updated service water pump success criteria based on LSCS historical operating practices F-7
 
Appendix F CDF(a)(b)  LERF(a)(b)
PRA Model  Summary of Significant Changes From Prior Model              (per year)  (per year) 2003A
* Revised component failure data including extensive use of  6.6x106(d)  3.6x107 (6/2003)      plant-specific component failure data gathered from the LSCS Maintenance Rule program
* Revised initiating events data utilizing the latest LSCS operating experience
* Added alternate configuration logic for all systems with alternate/standby trains
* Added logic for newly installed redundant 125 V DC backup battery chargers on both divisions of Unit 2
* Added new logic for the trailer-mounted Station Air compressor to the model
* Revised Station Air success criteria 2006A
* Model modified to reflect the emergency operating            8.1x106    3.1x107 (1/2007)      procedures for LSCS which differ from the generic BWROG EPGs in that they do not direct ADS inhibit unless a failure to scram occurs (or power is unknown)
* Updated the turbine building flooding accident sequences
* Allocated LOCA frequencies on a location and size-
* specific basis
* Updated data to use the most current industry data and plant-specific data 2006B
* Completely revised internal flooding analysis                3.6x106    3.0x107 (5/2007)
* Added additional dependent HEPs to recovery files
* Quantified several support system initiator fault trees and added frequencies to model 2006C      Subject of 2008 Peer Review                                    4.0x106    3.0x107 (1/2008)
* Revised RHR suppression pool cooling model to address error
* Updated several fault tree logics to address internal review issue
* Revised several CCF probabilities
* Revised frequency for medium below core LOCA
* Added additional flood scenario links in system fault tree models
* Added coincident maintenance links in system fault trees F-8
 
Appendix F CDF(a)(b)        LERF(a)(b)
PRA Model          Summary of Significant Changes From Prior Model                      (per year)        (per year) 2011A
* Updated transient frequencies and component failure                2.6x106          1.3x107 (3/2013)              rates using latest plant data
* Deleted loss of bus 241Y and 242Y as initiating events because loss of these buses does not result in a scram
* Refined treatment of the ECCS water hammer scenarios
* Crediting closure of the reactor building ventilation check dampers as a potential flood mitigation strategy
* Deleted most coincident maintenance terms as these events did not meet the current definition of the ASME/ANS PRA Standard
* Re-evaluated categorization of mitigated ATWS (i.e., SLC successfully injected) scenarios with subsequent failure of containment heat removal from Class IV to Class II
* Corrected probability of failure of ADS due to environment from 1.0 to 103 based on the controls/steam sensitive portion of the ADS system is not in the reactor building
* Revised the probability for preexisting containment failure modes from 5x103 to 2.3x103 to be consistent with current industry information 2013A
* Replace LERF model with full Level 2 model                          2.6x106          1.4x107 (7/2014)
(a) All values assumed to be point estimates unless indicated to be otherwise.
(b) Models  prior to 2000A version did not include internal flooding.
(c) CDF value based on information in NUREG-1560, Volume 3, Table B-1. Note that this NUREG volume did not contain specific details on the reported CDF values.
(d) CDF values include 1x10-7 per year due to seismic events. LERF value is unknown.
(e) 2000B model was not issued in any regulatory applications.
Key: AC = alternating current; ADS = automatic depressurization system; ATWS = anticipated transients without scram; BWROG = Boiling Water Reactor Owners Group; CAFTA = Computer-Aided Fault Tree Analysis; CDF = core damage frequency; CCF = common cause failure; DC = direct current; ECCS = emergency core cooling systems; EPG = emergency procedure guidelines; HEP = human error probability; HRA = human reliability analysis; IPE = individual plant examination; LERF = large early release frequency; LOCA = loss-of-coolant accident; LSCS = LaSalle County Station; PRA = probabilistic risk assessment; RCIC = reactor core isolation cooling, RHR = residual heat removal; SLC = standby liquid control Sources: Exelon 2014a, 2015 1  In response to an NRC staff RAI to identify shared plant systems, or those that could be 2  cross-tied between units, and to describe the modeling, including the treatment of unavailability 3  during outages or accidents involving the other unit, Exelon responded that the most significant 4  piece of equipment shared between units is the common or 0 diesel generator. This diesel 5  generator is shared between the Unit 1 and Unit 2 Division 1 AC power divisions. Modeling of 6  this component assumes that it loads automatically to the modeled unit 50 percent of the time 7  when demanded. The model includes an operator action to manually align the 0 diesel 8  generator to the modeled unit if the 0 diesel generator does not automatically align to the unit.
9  The model also includes an operator action related to the failure to control the loading of the 10  diesel generator when it is aligned to both units. Exelon further indicated that the Division 1 and F-9
 
Appendix F 1 Division 2 AC safety-related 4 (kV) buses can be cross-tied between units, which provides a 2 means to power these buses via the opposite unit offsite power sources. The PRA model 3 includes the opposite unit offsite power sources, divisional crosstie breakers, and the operator 4 action necessary to complete this alignment.
5 Other shared systems include the instrument air system, the service water system, and the fire 6 protection system (FPS). Other than the 0 diesel generator, crosstie breakers, and AC power 7 supplies, the model does not explicitly consider the impacts of events occurring at one unit that 8 affect the other unit. Service water and instrument air have the capability to support both units 9 simultaneously during events at both units. With respect to the FPS, it could be aligned to both 10 units and could be shared for injection. However, the PRA model does not account for this 11 condition probabilistically. For all shared systems, system unavailability during outages is 12 considered in the development of system maintenance unavailability basic events.
13 (Exelon 2015).
14 Exelon stated in the ER:
15              The freeze date for data and plant modifications to be considered for the Level 1 16              portion of the LS213A model (the 2011 LSCS PRA update, LS211A) is 17              December 31, 2010. The Emergency Operating Procedures (EOPs) and Severe 18              Accident Guidelines (SAGs) used in this analysis are those in place as of the 19              freeze date. No significant plant modifications affecting the risk profile were 20              performed since the PRA model freeze date. EOP and SAG changes made 21              since the freeze date were reviewed and incorporated, as necessary, into the 22              LS213A model. The freeze date for the LS213A model was December 31, 2013.
23 In an RAI, the NRC staff asked Exelon to identify any planned changes or modifications to the 24 LSCS design (other than the hardened pipe vent), operation, reactor power level, fuel cycle, or 25 fuel design that might affect the SAMA analysis and describe their expected impacts. In 26 response, Exelon indicated that the PRA open items tracking database (commonly referred to 27 as the updating requirement evaluation (URE) database) was reviewed and no outstanding 28 modifications were identified, with the exception of the necessary plant modifications to meet 29 the NRC order related to the Near Term Task Force (NTTF) on Fukushima. In particular, these 30 changes will be made in relation to mitigating strategies (EA-12-049) and the installation of the 31 hardened pipe containment vent (EA-12-050) (Exelon 2015).
32 As noted above, the CDF due to ATWS events is 4.9x10-7 per year8 or 19 percent of the total 33 CDF for internal events. In response to an RAI to discuss the reasons for the relatively high 34 contribution to the total CDF for internal events, Exelon responded by summarizing the plant 35 design and operating features that affect the ATWS CDF. The joint human error probabilities 36 (HEPs) for operator actions that must be performed in short time windows are prevalent in the 37 ATWS cutsets and are the dominant contributors to CDF from this accident class. Some short 38 time windows for response are due to the plant design and the lack of a redundant, 39 high-pressure, high-volume injection system for use in these scenarios. The only high-pressure, 40 high-volume injection system available in an ATWS is feedwater. Emergency operating 41 procedures require the high-pressure core spray system to be secured, and the Reactor Core 42 Isolation Cooling System (RCIC) is a low-volume system. The capability of feedwater is limited 43 by the rate at which water can be made up to the condenser.
44 Exelon further provided the ATWS CDF and relative contribution to total CDF for a number of 45 other BWR units. Exelon concluded that, in general, ATWS CDF and the percent contribution of 8 This value does not include the CDF contribution from mitigated ATWS events for which standby liquid control (SBLC) injection is successful but core damage occurs due to subsequent coolant injection or heat removal failures.
F-10
 
Appendix F 1 ATWS to the CDF vary significantly in the industry, and values can be found both above and 2 below those documented for LSCS (Exelon 2015).
3 The NRC staff noted that Section F.2.3.1 of the ER states all ATWS events are modeled as a 4 turbine trip. In response to an RAI to clarify this statement, Exelon indicated that this statement 5 was intended to explain the prior statement in the ER that The turbine trip initiating event is 6 important to note because it also represents the ATWS frequency. A better way to describe the 7 relationship of the turbine trip initiator to the ATWS is that ATWS sequences are a large 8 contributor to the percentage of CDF attributed to the turbine trip initiating event. Exelon noted 9 that other initiating events also result in ATWS sequences (Exelon 2015).
10 On the basis of the NRC staffs evaluation of internal events Level 1 PRA previously described 11 in this subsection, and Exelons response to the NRC staff RAIs, the NRC staff concludes that 12 the internal events Level 1 PRA model is of sufficient quality to support the SAMA evaluation.
13 F.2.2.2. External Events 14 As previously indicated, the LSCS PRA used for the SAMA analysis does not include external 15 events. In the absence of such an analysis, Exelon used the results of a new interim fire PRA 16 and the LSCS IPEEE to identify the highest risk accident sequences and the potential means of 17 reducing the risk posed by those sequences and to estimate the benefit of potential SAMAs, as 18 discussed below and in Section F.3.2.
19 The LSCS IPEEE was submitted in April 1994 (CECO 1994) in response to Supplement 4 of 20 Generic Letter 88-20 (NRC 1991). The submittal cited the external events analysis performed 21 as part of the NRC-sponsored RMIEP analysis of LSCS (NRC 1992). This analysis included 22 internal fire, internal flood, and seismic risk assessments, as well as a probabilistic bounding 23 analysis of the other external hazards (turbine-generated missiles, accidental aircraft impacts, 24 high winds, transportation and nearby facility accidents, and external flooding). The IPEEE did 25 not provide a definition of a vulnerability and did not identify any plant improvements resulting 26 from the fire, seismic, or other external hazard analyses in the IPEEE submittal. The RMIEP 27 report identified two issues in the fire area that were provided to the station for disposition.
28 These were (1) to install tops on the main control room electrical panels and (2) to institute an 29 inspection program for penetration seals at the top of switchgear panels. The disposition of 30 these improvements is discussed in Section F.3. Upon completion of the NRC staff review of 31 the IPEEE submittal and the supporting RMIEP work, the NRC staff concluded that the 32 licensees IPEEE process is capable of identifying the most likely severe accidents and severe 33 accident vulnerabilities and the LSCS IPEEE has met the intent of Supplement 4 to Generic 34 Letter 88-20 (NRC 2000).
35 The LSCS IPEEE seismic assessment used the simplified seismic PRA performed for the 36 RMIEP project. This analysis resulted in a point estimate CDF of 6.0x10-7 per year due to 37 seismic events. The dominant seismic CDF sequences are listed in Table F-4.
38 The RMIEP seismic PRA used seismic hazard curves available at that time. In the ER, Exelon 39 provided an updated seismic CDF utilizing currently available hazard curves and the conditional 40 core damage probabilities for each accident sequence and ground motion acceleration range 41 provided in the RMIEP report. This yielded a seismic CDF of 6.6x10-7 per year. In response to 42 an NRC staff RAI to provide more information on the source of these hazard curves, Exelon 43 indicated that the LSCS hazard curves used in the SAMA analysis are the same as the LSCS 44 hazard curves included in the response to the NRCs NTTF on Fukushima Recommendation 2.1 45 (Exelon 2014b, 2015).
F-11
 
Appendix F 1 Also in response to an NRC staff RAI, Exelon provided the LSCS seismic CDF using the 2 simplified methodology from the Generic Issue (GI) 199 evaluation (NRC 2010). The LSCS 3 seismic CDF using this methodology was found to be 2.3x10-6 per year, based on peak ground 4 acceleration (Exelon 2015). The NRC staff notes that this seismic CDF is somewhat larger than 5 that based on the RMIEP conditional core damage probabilities, which can be expected based 6 on the simplified nature of the GI-199 estimate.
7                                    Dominant LSCS Contributors to Seismic CDF Contribution to Total CDF*        Seismic CDF*
Sequence            Sequence Description                                      (per year)      (percent)
LOOP-Trans-3        LOOP, HPCS, and RCIC fail due to seismic failure        2.8x10-7      42 of CST, low-pressure injection fails due to random electrical support failures LOOP-Trans-4        LOOP, HPCS, and RCIC fail due to failure of              2.2x10-7      35 reactor level instrumentation or seismic failure of CST, depressurization fails LOOP-Trans-1        LOOP, HPCS fails due to random events,                  7.5x10-8      11 containment heat removal fails and low-pressure injection fails Small-LOCA-3        Small LOCA, HPCS, and RCIC fail, low-pressure            3.4x10-8      5 injection fails
    *Based on RMIEP seismic CDF of 6.6x10-7 per year (NRC 1992) and percent contribution given in the ER (Exelon 2014a)
Key: CDF = core damage frequency; CST = condensate storage tank; ER = environmental report; HPCS = high pressure core spray; LOCA = loss-of-coolant accident; LOOP = loss of offsite power; LSCS = LaSalle County Station; RCIC = reactor core isolation cooling; RMIEP = Risk Methods Integration and Evaluation Program 8 As discussed in Section F.3, Exelon reviewed the dominant sequences listed in Table F-4 to 9 identify potential SAMAs to mitigate those sequences. The total updated seismic CDF was 10 used in developing the external events multiplier, as discussed later in this subsection.
11 Seismic walkdowns of LSCS Units 1 and 2 were conducted as part of Exelons actions in 12 response to the 50.54(f) letter (NRC 2012a) requesting information related to the Fukushima 13 Daiichi NTTF recommendations. Exelon reported that the walkdowns resulted in no adverse 14 anchorage conditions, no adverse seismic spatial interactions, and no other adverse seismic 15 conditions associated with the items on the seismic walkdown equipment list (SWEL) for either 16 unit. Similarly, area walk-bys resulted in no adverse seismic conditions associated with other 17 systems, structures, or components located in the vicinity of the SWEL item(s). The Unit 1 18 seismic walkdown identified 9 minor conditions while the Unit 2 walkdown identified 10 minor 19 conditions. Other than these minor conditions, the seismic walkdowns identified no degraded, 20 nonconforming, or unanalyzed conditions that required either immediate or follow-on action 21 (Exelon 2012a, 2012b). The NRC staff notes that the agencys and industrys response to the 22 Fukushima Daiichi event includes additional seismic evaluations, as outlined in the 23 NRCs 50.54(f) letter dated March 12, 2012 (NRC 2012a).
F-12
 
Appendix F 1 While the LSCS IPEEE/RMIEP included an internal fire PRA, it has been superseded by a new 2 interim LSCS fire PRA. The current LSCS fire PRA gives a fire CDF of 8.9x10-6 per year for 3 Unit 1 and 9.4x10-6 per year for Unit 2. Table F-5(a) and Table F-5(b) provide a summary of 4 dominant fire zone CDF results from the LSCS fire PRA. The LSCS IPEEE fire assessment did 5 not provide a definition of the term fire vulnerability nor identify fire-related improvements. As 6 discussed above, the RMIEP report identified two issues in the fire area that were provided to 7 the station for disposition. These were (1) to install tops on the main control room electrical 8 panels and (2) to institute an inspection program for penetration seals at the top of switchgear 9 panels. The disposition of these improvements is discussed in Section F.3.
10 Exelon considers this fire model to be an interim implementation of NUREG/CR-6850 11 (NRC 2005) because all tasks identified in that document were not completely addressed or 12 implemented in the model. The ER includes a listing of limitations of the current LSCS fire PRA 13 relative to the tasks of NUREG/CR-6850 (NRC 2005). While some limitations may result in 14 additional fire scenarios or impact the frequency of existing scenarios, others lead to 15 conservatisms in the current result. Exelon also notes that the fire PRA utilizes the 16 2006C internal events PRA, which is not integrated with the current internal events 2013A PRA.
17 Accordingly, the LSCS fire PRA cannot be used in an integrated analysis with the internal 18 events PRA. Therefore, the total fire CDF from the analysis was used to determine the external 19 events multiplier, while the listing of dominant sequences was used to identify potential 20 cost-beneficial SAMAs as allowed by the industry guidance in NEI 05-01 and further discussed 21 in Section F.3.
22 The LSCS IPEEE/RMIEP analysis of high winds, tornadoes, external floods, and other external 23 events (HFO) consisted of a bounding probabilistic assessment. For these events, the 24 IPEEE/RMIEP concluded that these events were not significant contributors to plant risk and 25 there were no improvements identified for these events (CECO 1994).
26 The ER discusses each of these external events and provides the following CDF estimates from 27 RMIEP.
Turbine Generated Missiles (mean)                            9.5x10-8 per year Accidental Aircraft Impact (median)                          5.0x10-7 per year High Winds (median)                                          3.0x10-8 per year Transportation & Nearby Facility Accidents9                  3.0x10-8 per year External Flooding3                                          3.0x10-8 per year Total HFO external events                                    6.9x10-7 per year 28 The NRC staff considers the use of these CDFs consistent with the guidance provided in 29 NEI 05-01.
9 For the purposes of the SAMA analysis, external event frequencies for external flooding as well as transportation and nearby facility accidents are taken to be the same as the frequency for high winds.
F-13
 
Appendix F 1                          Table F-5(a). Dominant LSCS Unit 1 Fire Zone 2                            Contributors to Fire CDF of 8.9x10-6 per year Contribution to Total Fire CDF          CDF Fire Zone Zone Description                                            (per year)    (percent) 4F1          Unit 1Division 1 Essential Switchgear Room                2.7x10-6      30 4E3-2        Unit 1Division 2 Essential Switchgear Room                2.7x10-6      30 4C1          Control Room                                              5.9x10-7        7 4E1-2        Unit 1Auxiliary Electric Equipment RoomMain AER          3.9x10-7        4 Room 3                          Table F-5(b). Dominant LSCS Unit 2 Fire Zone 4                            Contributors to Fire CDF of 9.4x10-6 per year Contribution CDF          to CDF Fire Zone Zone Description                                          (per year)    (percent) 4E4-2        Unit 2Division 2 Essential Switchgear Room              2.9x10-6        30 4F2          Unit 2Division 1 Essential Switchgear Room              2.7x10-6        29 4E2-2        Unit 2Auxiliary Electric Equipment Room-Main AER        7.7x10-7        8 Room 4C1          Control Room                                              5.9x10-7        6 Key: CDF = core damage frequency; LSCS = LaSalle County Station 5 The NRC staff notes that Exelons response to the NRCs 50.54(f) letter (NRC 2012a) 6 requesting information related to the Fukushima Daiichi NTTF recommendations includes a 7 flooding walkdown and a flood hazards reevaluation. As reported in the NRC staff assessment 8 of the walkdown report (NRC 2014), five deficiencies were identified during the course of the 9 flooding walkdowns and entered into the corrective action program for tracking and resolution.
10 Two deficiencies were related to lack of seal or significant rust in penetrations.
11 Three deficiencies were related to exterior doors threshold elevations being lower than the 12 calculated flood elevation. The NRC staff concluded that the licensees implementation of 13 flooding walkdown methodology meets the intent of the walkdown guidance.
14 In the flood hazards reevaluation (Exelon 2014c), Exelon concluded that The current design 15 basis flood does not bound the reevaluated hazard for all applicable flood-causing mechanisms, 16 combined-effect floods, associated effects, and/or flood event duration parameters. Because 17 of this result, Exelon is preparing a fully integrated assessment of these flood hazards. Exelons 18 flood hazard evaluation also includes a summary of interim evaluations and actions taken or 19 planned to address the instances for which the reevaluated hazard exceeds the design basis.
20 These issues are being addressed via the ongoing Japan Lessons Learned program and 21 implementation of the Fukushima Daiichi NTTF recommendations, including NRC Order 22 EA-12-049, Order to Modify Licenses with Regard to Requirements for Mitigation Strategies for 23 Beyond-Design-Basis External Events (NRC 2012b) and is outside the scope of the SAMA 24 analysis.
F-14
 
Appendix F 1 As discussed in the ER, there are no up-to-date quantitative external event models for LSCS, so 2 a multiplier to the internal events PRA results was developed to account for risk contributions 3 from external events in the SAMA evaluation. For seismic contributions to risk, Exelon used the 4 updated RMIEP seismic CDF value of 6.6x107 per year. For fire contributions to risk, Exelon 5 used a Unit 2 fire CDF of 9.4x106 per year, discussed above. For HFO events, the value of 6 6.9x10-7 per year was used.
7 Based on these results, Exelon indicated in the ER that the total CDF for external events is 8 approximately 1.08x105 per year. The total CDF (internal and external events) is then 9 approximately 1.33x105 per year or 5.2 times the CDF for internal events. This multiplier was 10 used by Exelon in the SAMA analysis to account for the impact of external events on the 11 calculated benefits.
12 The NRC staff agrees with the applicants overall conclusion concerning use of the multiplier to 13 represent the impact of external events and finds that a multiplier of 5.2 will reasonably account 14 for external events in the SAMA evaluation.
15 F.2.2.3. Level 2 Fission Product Release Analysis 16 The NRC staff reviewed the general process Exelon used to translate the results of the Level 1 17 PRA into containment releases, as well as the results of the Level 2 analysis, as described in 18 the ER (Exelon 2014a) and Exelons responses to NRC staff RAIs (Exelon 2015). Exelon 19 indicates this PRA model is documented as an application-specific model developed for the use 20 in the SAMA application. The SAMA Level 2 model is an expansion of the prior LERF-only 21 model to a full Level 2 model.
22 The LSCS Level 1 PRA postulates accident sequences that lead to core damage and potentially 23 challenge containment. These discrete accident sequences contribute to the CDF, represent 24 the spectrum of possible challenges to containment, and are placed into functional sequence 25 groupings (i.e., accident classes and subclasses). The Level 1 accident class bins are then 26 used as the starting point for the Level 2 PRA CET analysis. Level 1 accident sequences and 27 resulting cutsets are incorporated directly into the Level 2 analysis to maintain the propagation 28 of dependencies. The accident classes and subclasses used for the LSCS SAMA analysis are 29 summarized in ER Table F.2-3 (Exelon 2014a).
30 The response of containment to core damage is analyzed by a CET for each accident class or 31 subclass. Each node in the CET is evaluated using the nodal functional fault trees that include 32 the following considerations:
33
* fault tree models from the Level 1 analysis for the system or function, 34
* any Level 2 limitations in timing, procedures, access, or dependencies, 35
* phenomenological effects, and 36
* environmental impacts on equipment or operator actions.
37 The CETs and the end-state assignments are based on deterministic core melt progression 38 calculations. Exelon directly links the Level 1 and Level 2 models using a single top logic 39 structure and quantifies them using the Electric Research Power Institute (EPRI) 40 Computer-Aided Fault Tree Analysis (CAFTA) software. Functional event nodes of the LSCS 41 Level 2 CET are:
42
* Containment Isolated (IS),
43
* RPV Depressurization (OP),
F-15
 
Appendix F 1
* Core Melt Arrested In-Vessel (RX),
2
* Combustible Gas Venting Initiated (GV),
3
* Containment Remains Intact (CZ),
4
* Injection Established to RPV or Drywell (TD),
5
* Containment Flooding Occurs with Drywell Vent (FC),
6
* Containment Heat Removal (HR),
7
* Containment Vent (CV),
8
* Suppression Pool Bypass (SP),
9
* No Large Containment Failure (NC),
10
* Inventory Makeup Available (MU),
11
* Drywell Intact (DI),
12
* Wetwell (WW) Airspace Failure, and 13
* Reactor Building Effectiveness (RB).
14 As described in ER Section F.2.1 (Exelon 2014a), the release categories were defined based on 15 the timing and magnitude of releases. Each CET end state represents a radionuclide release to 16 the environment and is assigned to a release category based on the CET sequence 17 characteristics, MAAP 4.0.5 results, and a set of release category rules. When MAAP is not 18 well suited to modeling the accident phenomena associated with a scenario, the scenario is 19 modeled using conservative estimates (e.g., steam explosion) and insights from other Level 2 20 PRA models from plants of a similar type.
21 ER Table F.2-6 provides a summary of the LSCS Level 2 release category frequencies for each 22 of the 15 accident classes or subclasses (Exelon 2014a). For accident class II (accident 23 sequences involving a loss of containment heat removal with the reactor pressure vessel initially 24 intact but with post containment failure or venting induced by core damage), the NRC staff 25 noted in an RAI that the subclasses listed in ER Table F.2-6 were different from those in ER 26 Table F.2-3. In response, Exelon indicated that the four accident Class II subclasses 27 (II, IIE, IIV, IIVE), used in the SAMA analysis and included in ER Table F.2-6, represent early 28 (IIE and IIVE) releases resulting from containment failure and containment venting, respectively; 29 and non-early (II and IIV) releases resulting from containment failure and containment venting, 30 respectively. Exelon indicated that for convenience in modeling, the Class II accident classes 31 are separated into two CETs; one representing the early releases and the other representing 32 intermediate or late (non-early) releases for the containment failure sequences and two similar 33 ones for venting sequences.
34 Exelon further indicated that the analysis of the timing of a General Emergency declaration has 35 been evaluated from a probabilistic standpoint for Class II accident scenarios. This evaluation 36 was performed because of the potential differences in interpretation of the Emergency Action 37 Levels (EALs) and the probability that the Emergency Director could delay the declaration of the 38 General Emergency resulting in an early release. Interviews of key emergency response 39 personnel were performed to determine the best estimate probability that the EALs would be 40 interpreted such that the General Emergency declaration would be delayed resulting in an early 41 release as opposed to an intermediate or late release. These interviews consisted of case 42 studies and a discussion of EALs. The mean probability of failure to declare a General 43 Emergency with adequate time to take protection measures for the general public prior to F-16
 
Appendix F 1 containment failure is 5 percent or 0.05 based on expert opinions. As a result, the LSCS 2 Level 2 model is structured such that 5 percent of the Class II accidents can result in an Early 3 release, but 95 percent of the Class II accident releases are non-early releases.
4 The NRC staff noted in an RAI that ER Table F.2-6, which provides the accident class 5 frequency contribution to each release category, includes a significant intact containment 6 frequency for the Class II accident subclasses. Class II accidents are normally considered, and 7 defined in ER Table 2-3, to include sequences where core damage occurs after containment 8 failure; therefore, there should be no intact containment sequences in Class II. In response to 9 the RAI to discuss the reasons for these results, Exelon indicated that the intact frequency was 10 obtained from the difference between the CDF for each accident subclass and the total of all the 11 other release category frequencies. As discussed above, the Class II accident classes are split 12 into two timing categories; early and non-early and a separate Class II event tree was used for 13 each category. For the early release class, the total Class II frequency is multiplied by 14 0.05 when the CDF value is transferred into the Level 2 model. Then, the remaining event tree 15 nodes are evaluated. This results in truncation of low-frequency sequences leading to the total 16 of all the release categories being significantly less than the CDF for the Class II subclasses.
17 To account for this undercounting of Class II releases, Exelon performed a sensitivity study to 18 determine the impact of this truncation issue. The study was performed by setting the PRA 19 model basic event related to the General Emergency declaration to 1.0 (instead of 0.95 and 20 0.05) and requantifying the model. After quantification, the 95 percent and 5 percent split 21 between non-early and early releases were calculated. Because the results demonstrated that 22 low-frequency sequences had previously been truncated from the final results, Exelon revised 23 the release category frequencies in its response to the RAI (Exelon 2015, Table F.2-6 revised).
24 Exelon noted that in the requantified results, there is still a very small unaccounted for frequency 25 in the Level 2 release results due to additional truncated sequences (approximately 5 percent of 26 the CDF). This release frequency was divided proportionally among each release category 27 applicable to that accident class (i.e., Class II, IIE, IIV and IIVE). Exelon indicated that model 28 truncation is a known source of uncertainty in model results and while the proportional 29 redistribution of the truncated cutsets does not provide an exact solution to this quantification 30 issue, it is considered to be a reasonable approximation of how these low contributors should be 31 allocated to the release categories. Exelon concluded that any deviations between the true 32 release category allocations of the truncated frequency and those resulting from the proportional 33 distribution of the frequency would correlate to very small changes to the cost-benefit results; 34 therefore, no impacts on the conclusions of the SAMA analysis were expected.
35 Exelon noted further that the Class II accident subclasses are the only accident classes where 36 the CDF values were multiplied by a split fraction before transferring into the Level 2 fault trees.
37 Therefore, the larger impact observed for this accident class is not applicable to other accident 38 classes. Other truncation issues would be small and are bounded by the uncertainty in other 39 inputs. Exelon concluded that the SAMA evaluation would not be impacted by model truncation 40 issues.
41 The NRC staff agrees, for the purposes of the SAMA analysis, with the Exelon approach to 42 resolving the issue associated with the original ER analysis of Class II release category 43 assessment, the conclusions associated with this issue, and the more general issue of impacts 44 from model truncation. The NRC staff also notes that the issue of how the intact release 45 category frequency was determined for other accident classes would have a very small impact 46 on the SAMA analysis because major accident class contributors to those other-than-Class II 47 release categories that are most important to offsite cost risk (Classes IIID, IV, and V) had a 48 zero intact containment frequency in the original ER analysis. Exelons revisions to F-17
 
Appendix F 1 the release category frequencies influenced the base case maximum averted cost risk (MACR) 2 and the cost-benefit analysis for each SAMA (Exelon 2015).
3 Exelon developed the accident progression and associated release characteristics for each 4 release category by using the results of MAAP Version 4.0.5 computer code calculations.
5 A MAAP case was identified as a representative case for each of the LSCS Level 2 PRA 6 release categories based on a review of the Level 2 model cutsets and the dominant types of 7 scenarios that contribute to the release category. Tables F.3-17 and F.3-18 in the ER provide 8 a description of the representative cases for each release category and additional information 9 on the selection of these representative cases (Exelon 2014a).
10 With regard to the selection of representative cases, the NRC staff noted in an RAI that the 11 dominant contributor to the low-magnitude early (L/E) release category is an ATWS sequence.
12 This event sequence involves successful depressurization of the reactor pressure vessel (RPV) 13 with core melt arresting in the vessel and a WW airspace failure. However, the MAAP scenario 14 stated in ER Tables F.3-17 and F.3-18 to be used as the reference MAAP case for this 15 sequence was not used to represent this release category. Instead, an alternate MAAP case 16 with a significantly lower cesium iodide release fraction was stated to have been used.
17 In response to the RAI, Exelon clarified that the reference MAAP cases in the Level 2 analysis 18 are not necessarily exact models of the sequence but are instead used along with the Level 2 19 Release Category rules to assign an appropriate end state to the Level 2 sequence 20 (Exelon 2015). A specific MAAP scenario modeling the dominant sequence for the L/E release 21 category was not developed for the LSCS SAMA analysis. Rather, expert judgment and review 22 of similar MAAP cases were used. In-vessel retention would be expected to reduce 23 radionuclide release fractions significantly because (1) RPV injection post-core damage 24 prevents further heat up of radionuclides, and (2) the suppression pool is not bypassed 25 (i.e., fission products are retained in the pool instead of being released directly to the 26 environment).
27 Exelon noted that while Tables F.3-17 and F.3-18 of the ER indicate that MAAP 28 case LS130533B was used to represent the L/E release category, MAAP case LS130524B was 29 actually used to represent the L/E release category indicated in Table F.3-19 of the ER. Use of 30 the LS130524B scenario in place of the LS130533B scenario is conservative because the 31 LS130524B release fractions bound the release fractions from the LS130533B scenario, and 32 the LS130524B scenario results in a substantial release of radionuclides several hours earlier 33 than the LS130533B scenario (containment breach in LS130524B vs. containment vent in 34 LS130533B). Both scenarios are containment flooding scenarios. As indicated above, the 35 dominant release category sequence is an ATWS sequence with a WW airspace failure, 36 successful RPV depressurization, in-vessel retention, and no suppression pool bypass. The 37 MAAP case LS130524B represents an ATWS sequence with WW airspace failure, successful 38 RPV depressurization, core spray available after core damage at vessel breach, and 39 containment flooding. Use of MAAP scenario LS130524B to model this sequence as a 40 surrogate for the L/E release category was judged by Exelon to be reasonable since 41 LS130524B models containment flooding shortly after vessel breach, which mimics the actions 42 of in-vessel retention by both cooling debris and retaining fission products in the local water 43 inventory (i.e., scrubbing the release). The NRC staff reviewed the logic of this assessment of 44 the release characteristics for the L/E release category and concludes that the results are 45 acceptable for the purposes of the SAMA analysis because the release category is bounding 46 and conservative.
47 In response to an NRC staff RAI to provide justification for the adequacy of the MAAP release 48 fraction results from simulation times less than [[estimated NRC review hours::48 hours]] past the declaration of a general F-18
 
Appendix F 1 emergency, Exelon discussed each of these MAAP analysis cases. The run times were 2 considered adequate based on either: (i) results at the end of the run having reached an 3 obvious plateau and being stable well before the end of the run, or (ii) the core debris being 4 quenched in a large body of water (the suppression pool) and stabilized at a relatively low 5 temperature (Exelon 2015). Based on this discussion and the fact that the run times were no 6 more than 8.[[estimated NRC review hours::5 hours]] less than the desired run time, the NRC staff agrees that the run times 7 used in Exelons SAMA analysis are acceptable.
8 Section F.2.2.11 of the ER, titled "2013A UPGRADE" (Exelon 2014a), states:
9            In order to support the SAMA analysis, the LSCS LERF model was replaced by a 10            full Level 2 model. The Level 1 logic from the 2011A model was not changed 11            beyond what was required to integrate it with the Level 2 model.
12 In response to an NRC staff RAI to describe the changes in the Level 2 model that are 13 considered upgrades as opposed to updates and to describe the steps taken to assure technical 14 adequacy of the 2013A Level 2 model, Exelon responded that the word upgrade in the 15 subheading 2013A Upgrade in Section F.2.2.11 of the ER was intended to have its common 16 meaning rather than the meaning ascribed by the ASME/ANS PRA Standard (ASME/ANS 2009) 17 and, in retrospect, was misleading. No change to the LERF analysis or methodology that would 18 be considered an upgrade by the ASME/ANS PRA Standard definition was made during the 19 model update that created the 2013A model. Accordingly, the 2013A model did not require a 20 peer review. Exelon further indicated that it has implemented procedures and processes to 21 assure the technical adequacy of the full power internal event (FPIE) PRA models.
22 The 2013A model was reviewed and approved in accordance with these procedures and 23 processes. (Exelon 2015).
24 On the basis of the NRC staffs review of Exelons Level 2 model, the peer review performed on 25 the 2006C PRA model, the general process Exelon used to translate the results of the Level 1 26 PRA into containment releases, and Exelons responses to NRC staff RAIs, the NRC staff 27 concludes that the Level 2 PRA as modified in response to the NRC staff RAIs is of sufficient 28 quality to support the SAMA evaluation.
29 F.2.2.4. Level 3 Offsite Consequence Analysis 30 The NRC staff reviewed Exelons process to propagate the containment performance (Level 2) 31 portion of the PRA to an assessment of offsite consequences (Level 3 PRA). Using the 32 MACCS2 Version 1.13.1 code, Exelon determined the offsite consequences from potential 33 releases of radioactive material (Exelon 2014a). In the Level 3 analysis, Exelon combined 34 release fractions and release categories, discussed in Section F.2.2.3, with the calculated core 35 inventory to yield potential source terms of radionuclides released to the outside environment.
36 In response to an NRC staff RAI, Exelon indicated that the LSCS radionuclide inventory was 37 calculated with ORIGEN Version 2.1 software (Exelon 2015). The NRC staff finds the 38 MACCS2 and ORIGEN codes to be acceptable for the SAMA evaluation because the codes are 39 widely used for radiological dose calculations resulting from airborne releases of radioactive 40 material and radionuclide source term determinations, respectively.
41 Exelon determined radionuclide inventories in the core for a thermal power output of 42 3489 (MWt). Because the current licensed core power level is 3546 MWt, Exelon applied a 43 scaling factor of 1.0163 (3546 MWt/3489 MWt = 1.0163) to the radionuclide inventories in the 44 core presented in Table F.3-11 of the ER (Exelon 2014a). In response to an NRC staff RAI on 45 the core inventory calculation performed by Exelon for Unit 1, Exelon indicated that the core 46 inventory calculation was bounding for either unit because time spent during refueling outages 47 was ignored, an extended cycle length was modeled, and the higher activity value for each F-19
 
Appendix F 1 radioisotope was chosen from two results for the end of the fuel cycle (Exelon 2015).
2 Furthermore, Exelon reported the core design process ensures that the core inventory of each 3 unit remains within the single design basis source term. The NRC staff finds these reasons 4 provide reasonable assurance that actual radionuclide core inventories will be lower than the 5 radionuclide inventories used in the SAMA analysis.
6 In response to an NRC staff RAI on planned changes or modifications to the LSCS design, 7 operation, reactor power level, fuel cycle, or fuel characteristics, Exelon indicated planned 8 modifications in response to the NRC order arising from the severe accidents at the Fukushima 9 Daiichi nuclear generating station, include mitigating strategies and installing a hardened pipe 10 containment vent, as required by EA-12-050 and described within the ER. Additionally, Exelon 11 highlighted its PRA sensitivity study that indicated modifications excluding the hardened pipe 12 containment vent lowered the CDF by approximately 5 percent (Exelon 2015). The NRC staff 13 finds the Exelon approach to not take credit for the hardened pipe containment vent or other 14 modifications in the SAMA analysis to be conservative and acceptable because this treatment 15 does not cause potentially cost-beneficial SAMAs to be missed.
16 The NRC staff also requested additional information on the assumptions used to calculate the 17 inventories of radioactive cobalt, and Exelon described that guidance values for cobalt were 18 scaled to the core thermal power level of the LSCS units (Exelon 2015). Exelon further 19 described that one of the cobalt radioisotopes was overestimated and explained the limited 20 influence of cobalt radioisotopes to the offsite dose and offsite economic costs, which are 21 dominated by other radionuclides in the core inventory. Because the radionuclide inventories 22 for cobalt have not been underestimated and the offsite dose and offsite economic cost 23 components provide the largest contributions to the MACR, the NRC staff agrees that the 24 inventories for the radioisotopes of cobalt are acceptable for use in the SAMA analysis.
25 The NRC staff concludes that the current radionuclide inventory calculations in Table F.3-11 of 26 the ER (Exelon 2014a) are adequate for the estimation of offsite consequences because current 27 calculations bound the expected radionuclide inventory for either reactor core, and Exelons 28 additional information further justifies the appropriateness of the calculated core inventory.
29 Exelon presented the major input parameter values and assumptions of the offsite consequence 30 analyses in Appendix F of the ER (Exelon 2014a). Exelon considered site-specific 31 meteorological data for the calendar years 2010, 2011, and 2012. Meteorological data from 32 2012 were selected for input to the MACCS2 code because they resulted in the highest 33 population dose risk and offsite economic cost risk, as described in Section F.3.7 of the ER 34 (Exelon 2014a). Exelon acquired meteorological data, such as wind speed, wind direction, 35 atmospheric stability class, and precipitation, from onsite meteorological monitoring stations at 36 LSCS. Atmospheric mixing heights were obtained from information published by the 37 U.S. Environmental Protection Agency. The NRC staff finds the applicants modeling of 38 atmospheric conditions and plume dispersion to be acceptable because it is supported by 39 site-specific annual meteorological data and implemented using widely accepted software.
40 Because selection of the 2012 meteorological data set resulted in the highest population dose 41 risk and offsite economic cost risk, the NRC staff accepts its use in the SAMA evaluation.
42 Exelon addressed missing meteorological data either by interpolation or by substitution. For 43 missing wind-speed data, a power law was used to convert wind speeds measured at different 44 heights. For data gaps less than [[estimated NRC review hours::6 hours]], interpolation was performed with valid data 45 immediately before and after the data gap. For data gaps greater than [[estimated NRC review hours::6 hours]], data 46 substitution was performed with valid data for the same times from either the day before or after 47 the missing data. Exelon indicated that missing data represented 2 percent or less for each of 48 the three annual meteorological data sets. Because these percentages of missing data are F-20
 
Appendix F 1 reasonable and the methods used to substitute missing data are common remedies, the NRC 2 staff finds these approaches to be acceptable for use in the SAMA analysis.
3 Having assessed the sensitivity to different annual meteorological data sets, release heights, 4 plume heat, and deposition velocities, Exelon found the population dose risk and offsite 5 economic cost risk either decreased (by as much as 9 percent) or increased slightly (by as 6 much as 3 percent) due to the alternative inputs. In response to an NRC staff RAI, Exelon 7 quantified the influence of precipitation on the population dose risk and offsite economic cost 8 risk. Specifically, Exelon compared the total annual precipitation, population dose risk, and total 9 offsite economic cost risk for the previously identified calendar years 2010, 2011, and 2012 and 10 reported that the single year (2012) with the highest population dose risk and total economic 11 cost risk had the lowest total annual precipitation (Exelon 2015). This observation indicated that 12 other atmospheric parameters during the modeled release had a greater influence on the 13 consequence analysis results than the time-integrated precipitation for the entire year.
14 The NRC staff finds that the selection of the 2012 meteorological data and the other parameter 15 values for atmospheric dispersion are appropriate for use in the SAMA analysis because 16 changes to the analysis typically lower expected benefits for individual SAMAs and any small 17 increases would not change the identification of cost-beneficial SAMAs. As previously 18 described, the sources of data and models for atmospheric dispersion used by the applicant are 19 appropriate for calculating consequences from potential airborne releases of radioactive 20 material.
21 Exelon used the SECPOP2000 Version 3.12 code, projected the expected growth and 22 distribution of population out to the year 2043, and reported that the total population within 23 80 km (50 mi) surrounding LSCS is anticipated to increase from 1,546,445 in the year 2000 to 24 approximately 3,107,897 in the year 2043, as shown in Table F.3-7 of the ER (Exelon 2014a).
25 From Section F.3.2, as well as Tables F.3-1 and F.3-2 of the ER, Exelon considered census 26 data from years 2000 and 2010, county growth rates for the year 2030, and transient population 27 contributions in the projection. The NRC staff finds that the methodology for population 28 projection is consistent with relevant guidance (NEI 2005). In response to an NRC staff RAI, 29 Exelon indicated the county population growth rate data were based on projections published by 30 the State of Illinois (Exelon 2015). The NRC staff verified the appropriateness of selected data 31 and compared the county growth rate data reported in the ER with the data source and found no 32 discrepancies.
33 Compared to the previously discussed atmospheric parameters, Exelon reported greater 34 influences on potential increases to the population dose risk and offsite economic cost risk from 35 sensitivity assessments of the population within 80 km [50 mi], evacuation speed, intermediate 36 phase resettlement, wealth values, and other economic inputs and rates. These results were 37 presented in Section F.7.3 of the ER (Exelon 2014a). In response to an NRC staff RAI, Exelon 38 confirmed that known SECPOP errors were prevented from influencing the SAMA analysis 39 results and that manual entry of population and economic data conformed to formatting 40 requirements (Exelon 2015). The NRC staff also requested supporting justification for spatial 41 distribution assumptions used in the population projections. Exelon responded by explaining 42 that the uniform population distribution within a county overestimates the population within 43 80 km (50 mi) of the LSCS site because many of the highly dense population areas lie outside 44 the radial distance of 80 km (50 mi), and portions of the highest populated counties that lie 45 within that radial distance tend to be more rural, more suburban, and much less populated 46 (Exelon 2015). The NRC staff finds the use of block-level census data to be acceptable 47 because it is site-specific and more representative than uniformly distributed population 48 estimates within a county. Because the applicant provided adequate RAI responses on the 49 population projection, and because an additional analysis was performed by the applicant that F-21
 
Appendix F 1 demonstrated the current approach was conservative, the NRC staff finds the methods, 2 assumptions, and data used for estimating population to be reasonable and acceptable for 3 purposes of the SAMA evaluation.
4 For the 16-km (10-mi) emergency planning zone at LSCS, Exelon considered site-specific 5 information in LSCS evacuation time estimates in its determination of evacuation times, time 6 delays, and travel speeds. For the baseline Level 3 calculation described in Section F.3.6 of the 7 ER (Exelon 2014a), Exelon assumed 95 percent of the population within the emergency 8 planning zone would evacuate with an evacuation speed of 1.6 meters per second (3.6 miles 9 per hour). In a sensitivity analysis (Exelon 2014a), Exelon reported an increase in the 10 population dose risk by 5 percent (negligible change to the offsite economic cost risk) due to an 11 assumed factor-of-2 reduction in the average evacuation speed. Because Exelon used 12 site-specific information and applied more pessimistic (lower) fractions for the evacuating 13 population in the emergency planning zone compared to generic values, the NRC staff 14 concludes that the evacuation assumptions and analyses are reasonable and acceptable for the 15 purposes of the SAMA analysis at LSCS.
16 Exelon developed economic values using data from the 2007 National Census of Agriculture 17 and Bureau of Economic Analysis for the counties within the 80-km (50-mi) radius of LSCS.
18 Exelon updated economic values to a reference timeframe of July 2013 using the consumer 19 price index from the Bureau of Labor Statistics. As stated in Table F.3-9 of the ER, weighted 20 average wealth values were $283,637/person for nonfarm wealth and $11,937/hectare for 21 farmland wealth. The NRC staff considers the values for nonfarm wealth to be reasonable 22 ranges that would not be expected to result in underestimates of offsite economic cost risk.
23 In response to an NRC RAI on more recent data from the 2012 National Census of Agriculture, 24 Exelon assessed the differences and indicated that annual sales of farm products and farm 25 wealth values from 2012 were typically larger than the 2007 data adjusted to 2013 values by the 26 consumer price index (Exelon 2015). Overall differences in county data for the fraction of 27 farmland and fraction of dairy farms were small between the 2012 and 2007 data sets. Having 28 calculated that the farm-dependent costs comprise 5 percent of the total offsite economic cost 29 risk, Exelon concluded that incorporation of the data from the 2012 National Census of 30 Agriculture would not have a significant impact on the SAMA analysis (Exelon 2015).
31 Farm-dependent costs do not influence the onsite and replacement power components of the 32 total averted cost risk. Given that estimated benefits at the 95th percentile for SAMA candidates 33 determined to be not cost beneficial were more than 20 percent below their estimated 34 implementation costs in Exelons revised analysis (Exelon 2015), the NRC staff concludes that 35 incorporation of 2012 agricultural data would not change the determination of cost-beneficial 36 SAMAs. Additionally, extrapolation of economic data to the year of the assessment, and not 37 through the period of extended operation, is consistent with guidance accepted by NRC 38 (NEI 2005). Because Exelons assessment included site-specific data and followed an 39 approach that is consistent with economic guidance, the NRC staff finds the data sources, 40 adjustments, and considerations made by the applicant in the Level 3 analysis to be acceptable 41 for the SAMA analysis.
42 Exelon estimated present dollar values based on the internal events PRA at LSCS and applied 43 a multiplication factor of 5.2 to account for external events. As shown in Section F.4.6 of the ER 44 (Exelon 2014a), offsite economic costs and offsite exposure costs provided the greatest 45 contributions to the total dollar value at approximately 74 and 20 percent, respectively. Onsite 46 cleanup and replacement power costs collectively contributed about 6.5 percent to the baseline 47 total dollar value for a real discount rate of 3 percent. Onsite exposure costs contributed less 48 than 1 percent. Section F.6 provides more detailed information on the cost-benefit calculation F-22
 
Appendix F 1 and its evaluation. Changes to the maximum averted cost risk as a result of Exelons revised 2 analysis are presented in Section F.6.1.
3 Based on its review of Exelons submissions, the NRC staff concludes that Exelons 4 methodology to estimate offsite consequences for LSCS provides an acceptable basis to 5 assess the risk reduction potential for SAMA candidates. Because the conservative modeling 6 assumptions were included in the assessment and input data were either obtained for the LSCS 7 site or found to be consistent with guidance values, the NRC staff concludes that data and 8 modeling assumptions for the Level 3 analysis are appropriate for the SAMA evaluation.
9 Accordingly, the NRC staff based its assessment of offsite risk on the core damage frequencies, 10 population doses, and offsite economic costs reported by Exelon.
11        Potential Plant Improvements 12 The process for identifying potential plant improvements, an evaluation of that process, and the 13 improvements evaluated in detail by Exelon are discussed in this section.
14 F.3.1. Process for Identifying Potential Plant Improvements 15 Exelon identified potential plant improvements (SAMAs) by review of:
16
* LSCS PRA results and PRA group insights; 17
* Potentially cost-effective Phase 2 SAMAs from 18                -  Susquehanna Steam Electric Station SAMA Analysis, 19                -  Cooper Nuclear Station SAMA Analysis, 20                -  Duane Arnold Energy Center SAMA Analysis, 21                -  Nine Mile Point Unit 2 SAMA Analysis, 22                -  Columbia Generating Station SAMA Analysis, and 23                -  Grand Gulf Nuclear Station SAMA Analysis; 24
* LSCS IPE; and 25
* LSCS IPEEE.
26 Exelon indicated that in addition to the Industry Phase 2 SAMA review identified above, an 27 industry-based SAMA list from NEI 05-01 (NEI 2005) was used to help identify the types of 28 changes that could be used to address the areas of concern identified through the LSCS 29 importance list review.
30 Based on this review, Exelon identified an initial set of 26 SAMA candidates, referred to as 31 Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the 32 initial list of SAMAs and eliminated SAMAs from further consideration using the following 33 criteria:
34
* Applicability to the plant: If a proposed SAMA does not apply to the LSCS design or 35                has already been implemented, it is not retained.
36
* Implementation cost greater than the screening cost: If the estimated cost of 37                implementation is greater than the MACR, the SAMA is screened out from further 38                analysis.
F-23
 
Appendix F 1 During this process, SAMA candidates 17 and 26 in Table F.5-4 of the ER (Exelon 2014a) were 2 screened out based on exceeding the cost criteria.10 Table F.6-1 of the ER (Exelon 2014a) 3 provides a description of each of the 24 Phase II SAMA candidates, which was later revised to 4 25 Phase II SAMA candidates in Exelons revised analysis (Exelon 2015).
5 In Phase II, a detailed evaluation was performed for each remaining SAMA candidate, as 6 discussed in Sections F.4 and F.6. To account for the potential impact of external events, the 7 estimated benefits based on internal events were multiplied by a factor of 5.2, as discussed in 8 Section F.2.2.2.
9 F.3.2. Review of Exelons Process 10 Exelons efforts to identify potential SAMAs focused primarily on areas associated with LSCS 11 specific internal initiating events. The NRC staff reviewed the discussions of the SAMA 12 identification process and the listing of Phase I candidate SAMAs included in the ER.
13 The primary source of candidate SAMAs (22 of a total of 26) was the review of the LSCS 14 Level 1 and Level 2 importance analysis. Four additional SAMAs were identified based on the 15 review of other BWR cost-effective SAMAs and the review of external events.
16 In the ER, Exelon provided a tabular listing of the Level 1 PRA basic events sorted according to 17 their risk reduction worth (RRW) (Exelon 2014a). These results were reviewed by Exelon to 18 identify those potential risk contributors that made a significant contribution to CDF. The RRW 19 rankings were reviewed down to 1.01. Events below this point would influence the CDF by less 20 than 1 percent and are judged, by Exelon, to be highly unlikely contributors for the identification 21 of cost-beneficial enhancements. These basic events, which include component failures, 22 operator actions, initiating events, and sequence identification markers (or flags), were reviewed 23 to determine any additional mitigating actions that may need to be considered.
24 In the ER, Exelon provides a discussion of the appropriate importance threshold for the 25 identification of candidate SAMAs. Guidance in NEI 05-01 indicates that dominant risk 26 contributors should be considered, but a dominant risk contributor was not clearly defined.
27 The NEI 05-01 example uses an RRW of 1.005, which corresponds to the ASME/ANS PRA 28 Standards (ASME/ANS 2009) definition of risk significant events. A 1 percent change in LSCS 29 CDF corresponds to approximately 3x10-8 per year compared to Regulatory Guide 1.174 30 (NRC 2011) definition that anything less than a 1x10-6 per year is a very small change. It is 31 noted that an RRW of 1.01 corresponds to a maximum averted cost risk (including external 32 events) of approximately $56,000, if it is assumed that a SAMA is 100 percent effective in 33 eliminating the events contribution to CDF and that the total cost-risk is proportional to CDF.
34 As Exelon indicates, while this is larger than a typically assumed simple procedure change cost 35 of $50,000, the cost for a procedure change can vary widely depending on complexity of the 36 change and the systems involved.
37 Considering the above and that (1) the Exelon review of the LSCS importance analyses results 38 includes, in addition to basic events, accident sequence markers and the individual contributors 39 to these sequences, which effectively results in looking at risk contributors that are lower than 40 the RRW threshold; and (2) a separate review of the important contributors to fire and seismic 41 risk for candidate SAMAs was performed, as discussed below, the NRC staff therefore 42 concludes that Exelons use of an RRW threshold of 1.01 for identifying candidate SAMAs from 43 the Level 1 internal events importance analysis is acceptable.
10 The results of a sensitivity analysis to determine the impact of a correction to the Level 2 model discussed above, resulted in one of the Phase I SAMAs (SAMA 26) being retained that was originally screened out.
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Appendix F 1 In the ER, Exelon also provided tabular listings of the Level 2 PRA basic events for the 2 combined High (H/E-BOC, H/E, H/I), the Medium Early (M/E), and the Medium 3 Intermediate (M/I) release categories. These release categories combine to represent over 4 97 percent of the offsite risk. Exelon used an RRW cutoff of 1.03 when reviewing these basic 5 events for additional SAMA candidates. While higher than the cutoff used for the Level 1 6 review, the NRC staff considers this to be acceptable based on their combined contribution to 7 offsite risk, the release frequency of each is a relatively small part of the total release frequency 8 (6 to 36 percent), and many of the events are also included in the Level 1 importance review.
9 The NRC staff developed several RAIs during its review of Exelons assessment of SAMAs.
10 The following discussion summarizes these RAIs and Exelons responses (Exelon 2015).
11 The NRC staff noted that the turbine trip with bypass initiating event (%TT) is indicated to have 12 a frequency of 0.8 per year, which implies that a number of turbine trips with bypass have 13 occurred over the LSCS operating history and asked if any of these occurrences suggest 14 possible cost-beneficial SAMAs. Exelon responded that the LSCS turbine trip initiating event 15 frequency is based on a Bayesian update of a generic prior for the period of 20062010, which 16 includes two plant-specific events (one for each unit). Review of the two plant-specific events 17 used in the Bayesian update indicates that the causes of the events are not related to one 18 another, and that the site has taken corrective action to address the root causes of the events.
19 These conditions do not imply any outlier behavior at LSCS or indicate that there is a potential 20 to identify cost-beneficial SAMAs related to turbine trip events.
21 The NRC staff noted that the discussion of potential SAMAs for a significant number of events 22 involve water-hammer-induced loss of coolant accidents (LOCAs) related to the generation of a 23 LOCA signal on high drywell pressures when an actual LOCA does not exist. These events are 24 mitigated by SAMA 7, and the NRC staff asked Exelon to provide more detail on the water 25 hammer scenarios and the potential for other SAMAs to mitigate the water-hammer-induced 26 core damage. In response, Exelon provided a discussion of the four typical cases associated 27 with water hammer events at LSCS and the potential for other SAMAs. Exelon indicated that 28 procedures already are in place and credited in the PRA for the operators to prevent residual 29 heat removal (RHR) starting (and thereby preventing the conditions that led to a water hammer) 30 for certain scenarios and that installing fast-acting valves (that also would prevent the conditions 31 that led to water hammer) would be expensive and have some adverse consequences. Exelon 32 clarified that the LOOP-delayed LOCA scenario, that was stated to not have been modeled in 33 the PRA, is a series of operator actions required to address the automated actuations that occur 34 in some potential water hammer scenarios. These actions are not explicitly included in the PRA 35 because the dominant contributors to core damage are considered to be the water hammer 36 events. Exelon concluded and the NRC staff agrees that including these scenarios in the PRA 37 model would result in a very small change in plant risk that would impact neither the SAMA 38 identification process nor the conclusions of the SAMA analysis.
39 The NRC staff noted that for an event involving an emergency core cooling systems (ECCS) 40 room cooling fan failing to run, Exelon indicated that previous LSCS evaluations could not 41 demonstrate that portable fans would provide adequate cooling for the reactor building corner 42 rooms when the normal cooling system failed. Exelon was asked to discuss this previous 43 evaluation and if sufficient cooling can be achieved if the portable fans can provide air 44 movement through the room coolers, assuming cooling water remains available. In response, 45 Exelon provided the results of a cost-benefit assessment for a SAMA that utilized portable fans 46 and ducting to provide air flow through modified room coolers. This assessment assumed that 47 the previously described commitment to install a reliable hardened pipe containment vent 48 (SAMA 1) had been implemented thereby resulting in a benefit including uncertainty of 49 approximately $42,000 versus a cost of $475,000.
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Appendix F 1 The NRC staff noted that for an event where the operator fails to recover low-pressure systems, 2 the discussion indicates that low-pressure systems would not have the power to function.
3 Exelon was asked to consider the potential for utilizing a fire truck or other portable 4 self-powered pumps for injection into the containment. Exelon responded that SAMA 1 (reliable 5 hardened pipe containment vent) with its planned implementation and SAMA 8 (portable 6 480V AC generator) were determined to be potentially cost beneficial and are proposed in the 7 ER to address the risk contributions from this event. The combination of these two SAMAs 8 would help prevent core damage by providing a means for (i) containment heat 9 removal/pressure control via the reliable hardened pipe containment vent, and (ii) maintaining 10 RPV injection using the existing FPS connection, by providing long-term support for the safety 11 relief valves (SRVs) so that they do not reclose and cause RPV re-pressurization. The addition 12 of a portable self-powered injection pump without SAMA 8 for these contributors would provide 13 very little additional benefit. There would be no apparent reduction in the implementation cost, 14 and it would serve the less desirable function of mitigating a core-damage event rather than 15 preventing core damage. Exelon concluded and the NRC staff agrees that the use of a portable 16 self-powered pump is not considered to be the optimal choice for mitigating the risk associated 17 with the cited event.
18 Exelons discussion of the review of industry cost-beneficial SAMAs included Grand Gulf 19 SAMA 59 (to increase operator training to alternate the operation of ECCS pumps for 20 loss-of-room cooling). Exelon stated that rather than cycling large pumps in scenarios where 21 the cooling system is lost, a more effective means of maintaining injection with the ECCS 22 pumps is considered to be through the use of portable/temporary cooling alignment, which is 23 addressed in the LSCS importance list review by SAMA 16. In an RAI, the NRC staff asked 24 Exelon to consider a SAMA similar to Grand Gulfs SAMA 59 for rooms where the use of 25 portable fans may not be effective. In response, Exelon provided a discussion of the various 26 cases where use of portable fans may not be effective and pointed out that most are mitigated 27 by the hardened pipe containment vent (SAMA 1), which Exelon has already committed to 28 installing. Exelon concluded and the NRC staff agrees that once the requirement to install the 29 reliable hardened pipe containment vent has been implemented, the potential benefit of a 30 procedure change to cycle the ECCS pumps would be small (Exelon 2015).
31 While the LSCS IPE submittal did not identify any vulnerability, as discussed in the NRCs IPE 32 Safety Evaluation Report, the IPE did cite NUREG/CR-4832, Volume 3, Part 1, for insights into 33 potential improvements to:
34
* Eliminate the sneak circuit in the RCIC isolation logic that results in the RCIC steam 35              line inboard isolation valve closing when offsite AC power is lost and the appropriate 36              diesel generator starts.
37
* Change the RCIC room temperature isolation logic so that, in cases where AC power 38              from Train A has failed but AC power from Train B is available, this isolation logic 39              does not isolate if no other ECCS is working.
40
* Change the venting procedure so that venting does not result in severe 41              environments in the reactor building.
42 In response to an NRC staff RAI to discuss the current status of these potential improvements, 43 Exelon replied, for the first two improvements listed above, changes have been made so that 44 the described sneak circuit and the RCIC isolation no longer exist at LSCS. For the third listed 45 improvement, design improvements were considered and dispositioned at the time of the IPE 46 and no design changes were made at that time to install a hardened pipe containment vent and 47 prevent the rupture of the containment vent piping. Rather, procedure changes were made to 48 acknowledge the design deficiency and initiate alignment of alternate injection systems prior to F-26
 
Appendix F 1 containment venting, if at all possible. Changes also were made to procedures to control 2 containment pressure within a specific range during the venting evolution. The potential for 3 containment vent path rupture/failure will be addressed through the installation of the reliable 4 hardened pipe containment vent (SAMA 1) (Exelon 2015).
5 Based on the above discussion, the NRC staff concludes that the set of SAMAs evaluated in the 6 ER, together with those identified in response to NRC staff RAIs, addresses the major 7 contributors to the CDF for internal events.
8 As previously discussed, the best available information on seismic and internal fire risk is not 9 compatible with the internal events risk model. Consequently, the search for SAMA candidates 10 to mitigate these risks was based on a review of the dominant risk contributors identified and 11 discussed in Section F.2.2.2.
12 In the ER, Exelon discussed the dominant seismic risk sequences listed in Table F-4 13 (Exelon 2014a), remarked that changes to LSCS as well as reanalysis of important failures has 14 led to reductions in the significance of several of these sequences, and identified two SAMA 15 candidates that mitigate the seismic risk. The NRC staff notes that the lowest seismic risk 16 contribution considered has a CDF of approximately 1 percent of the CDF for internal events.
17 This value corresponds to a benefit of $11,000 if mitigating only the seismic risk, or $56,000 if 18 mitigating all the other risk contributors. The NRC staff concludes that this is an acceptably low 19 cutoff for identification of SAMA candidates since it is lower than the typical cost for revising a 20 procedure.
21 The ER also includes a discussion of the contributors to the dominant fire zone risks listed in 22 Table F-5(a) and Table F-5(b) (Exelon 2014a). This discussion describes the important fire 23 scenarios that contribute to the fire CDF for this fire zone, the results of a review of the 24 important cutsets, and those SAMAs that would reduce the frequency of these fire scenarios.
25 Exelons review and analysis did not identify any unique SAMAs for mitigating these fire 26 scenarios, but Exelon concluded that three of the previous SAMA internal events would 27 significantly impact the fire risk.
28 Exelon noted that the largest unreviewed fire zone represents less than 2.5 percent of the 29 overall total CDF, including external events or about $142,000. In response to an RAI to 30 consider additional fire zones, Exelon provided a discussion of 15 additional fire zones with 31 benefits down to $37,500 per unit. This value was based on a procedure development cost of 32 $50,000 for the first unit and half of that for the second unit, averaging $37,500 per unit. The 33 contributors to the fire risk for each of these zones were reviewed by Exelon to determine if 34 there were any procedure changes that could be potentially cost beneficial. The results of this 35 review are presented in the RAI response on a zone-by-zone basis. No potentially 36 cost-beneficial procedure changes were identified (Exelon 2015).
37 In an RAI, the NRC staff noted that fires in the Division 1 and Division 2 essential switchgear 38 rooms for each unit comprise 60 percent of the total fire CDF and that the only SAMA proposed 39 for mitigating these fires is SAMA 1, installing a reliable hardened pipe containment vent.
40 SAMA 1 only mitigates the adverse consequences of venting and does not mitigate the direct 41 impact of the fire. The NRC staff asked Exelon to discuss these fire scenarios and the potential 42 for other SAMAs to directly mitigate the fire at an earlier stage of the scenario or to mitigate 43 events in the cutsets other than adverse conditions due to venting. Exelon indicated that 44 79 percent of the contributions are cases in which injection is initially available but subsequently 45 fails due to harsh environmental conditions after containment failure. The unavailability of the 46 containment vent is due to fire-induced failures associated with vent valve support systems, with 47 the vent valve control cables, or both. The reliable hardened pipe containment vent (SAMA 1)
F-27
 
Appendix F 1 eliminates support system requirements and would provide a means of preventing the 2 containment failures and vent path failures that lead to loss of injection capability.
3 Further, for the remaining 21 percent of the contributors, hardware failures result in the 4 unavailability of injection systems, such that even if a containment vent path were available, 5 core damage would still occur. The hardware failures are comprised of both failures of the 6 4 kV AC power sources that support the injection systems and the failures of the injection 7 system components themselves. LSCS already has the B.5.b pump, which can provide this 8 RPV injection capability for the long-term scenarios that are characteristic of these contributors, 9 but it is not currently credited in the PRA model. LSCS operators have been trained to use the 10 B.5.b pump and the current emergency operating procedures include the B.5.b pump as a 11 potential alternate RPV injection source that could be used to mitigate the Division 1 and 12 Division 2 essential switchgear room fire scenarios. In addition, diverse and flexible coping 13 capability, FLEX (NRC 2012b), is intended to provide a separate set of portable makeup 14 pumps that also could be used to perform this function. While the details of the FLEX changes 15 are not finalized, they would further improve the capability of LSCS to respond to these types of 16 scenarios (Exelon 2015).
17 In an RAI, the NRC staff noted that the largest contributing fire scenario to the Auxiliary 18 Electrical Equipment Room fire risk is a bounding cable fire caused by hot work but no SAMAs 19 were identified to mitigate this risk. The NRC staff asked Exelon to discuss the potential for a 20 SAMA to mitigate this risk. In response, Exelon indicated that the transient fire ignition 21 frequency calculated for a fire compartment considers the potential for ignition due to hot work 22 (cutting, grinding, or welding tasks), among other sources. Based on the 2009 LSCS Fire PRA, 23 the hot work influence factor for the Auxiliary Electrical Equipment Room is low, which is the 24 lowest possible factor for this area. Procedures already are in place that require a fire watch to 25 be posted (with portable extinguishes available) and for nearby equipment to be protected when 26 hot work is being performed. These practices already are accounted for in the fire risk 27 evaluation for the Auxiliary Electrical Equipment Room. Based on these considerations, no 28 potential SAMAs related to hot work limitations are available that would yield a measurable 29 change in Auxiliary Electrical Equipment Room fire risk. Because the hot work is associated 30 with a bounding transient fire scenario that is assumed to lead to failure of all equipment in the 31 fire compartment, further details are not available to generate additional SAMAs to mitigate the 32 fire beyond those associated with the initiating event frequency (Exelon 2015).
33 As discussed in Section F.2.2.2, the LSCS IPEEE did not provide a definition of vulnerability 34 and did not identify any plant improvements resulting from the fire, seismic, or other external 35 events analyses. However, the RMIEP report identified two issues in the fire area that were 36 provided to the station for disposition. These issues were to install tops on the main control 37 room electrical panels and to institute an inspection program for penetration seals at the top of 38 switchgear panels. As discussed in the ER, these improvements were not implemented. Based 39 on the current understanding of fires in electrical panels, such as those installed at LSCS, and 40 on industry guidance for the treatment of fire in these panels in NUREG/CR-6285, Exelon 41 concluded that these two identified potential improvements would not be effective in mitigating 42 the associated fire risk.
43 In an RAI, the NRC staff noted that the RMIEP Summary (NUREG/CR-4832, Volume 1) 44 identifies the common cause failures (CCF) of the CSCS cooling water pumps as the dominant 45 events in the seismic risk reduction importance assessment. In response to the RAI to discuss 46 these events and their importance in the seismic analysis used for SAMA identification, Exelon 47 discussed the internally cited conflicting information in Volume 1 (Summary) and Volume 8 48 (Seismic Analysis) and concluded that CCFs of the CSCS cooling water pumps do not appear 49 to drive the results of seismic risk at LSCS. While no SAMAs were generated to directly F-28
 
Appendix F 1 address these specific failures, the consequences of the CCF of the CSCS cooling water pumps 2 is essentially a long-term SBO, a scenario previously addressed by SAMAs evaluated in the 3 LSCS analysis. SAMA 27 mitigates cases in which RCIC remains available (not failed by 4 seismically induced failure of the condensate storage tank), and SAMA 26 reduces the risk 5 associated with scenarios in which RCIC is not available. These SAMAs are considered by 6 Exelon to adequately address any potential contributions from CCF of the CSCS cooling water 7 pumps. In addition, Exelon stated that review of the LOOP and dual unit LOOP contributors 8 from the LSCS 2013A PRA model indicates that CCFs of the CSCS pumps are low contributors 9 to those scenarios. If, as stated in Section 4.5.1 of NUREG/CR-4832 Volume 1, the dominant 10 seismic sequences are all seismically induced losses of offsite power and look exactly like the 11 equivalent internally initiated sequences except that no credit is given for recovering offsite 12 power, then the conclusion would be that CCF of the CSCS cooling water pumps are not 13 significant contributors to seismic risk. Exelon also noted that subsequent to the completion of 14 the RMIEP analysis, Commonwealth Edison (now Exelon) performed a review of that study and 15 largely used the results as the basis for the combined IPE and IPEEE submittal. Exelon 16 indicated that one of the conclusions of the review effort, documented in the executive summary 17 of the April 1994 IPE/IPEEE (CECO 1994), is that Commonwealth Edison considered the Beta 18 factor CCF process used in the RMEIP analysis to be overly conservative (Exelon 2015). As 19 stated earlier, the Exelon IPEEE analysis of other external hazards (high winds, tornadoes, 20 external floods, and other external events) did not identify opportunities for improvements for 21 these events.
22 As discussed in Section F.2.2.2, the LSCS external flooding design and capability was 23 assessed in the engineering walkdowns and flood hazard reevaluation required for the response 24 to the Fukushima NTTFs Recommendation 2.3 (NRC 2012a). The walkdown identified 25 deficiencies that are being addressed through the LSCS corrective action program, while the 26 results of the hazard reevaluation led to the requirement for the performance of a full external 27 flooding integrated assessment, now underway. These issues are being addressed via the 28 ongoing Japan Lessons Learned program and implementation of the Fukushima Daiichi NTTF 29 recommendations, including NRC Order EA-12-049, Order to Modify Licenses with Regard to 30 Requirements for Mitigation Strategies for Beyond-Design-Basis External Events (NRC 2012b).
31 The NRC staff concludes that for the purposes of SAMA identification, external flooding is 32 adequately addressed. Since external flooding is not a significant contributor to plant risk, a 33 cost-beneficial SAMA is not likely to be identified. Additionally, the ongoing programs described 34 above provide improvements to the external flooding risk that are more conservative than a 35 cost-beneficial SAMA.
36 Regarding the prevention of water hammer events, the NRC staff questioned Exelon about 37 potentially lower cost alternatives to SAMA 7 (alter the LOCA signal logic to require both high 38 drywell pressure and low RPV water level for initiation of a LOCA signal). In non-LOCA 39 transient scenarios, the heat load rejected to the containment is sufficient to prompt the initiation 40 of suppression pool cooling (SPC), but even with SPC in operation, the drywell pressure will 41 reach 2 psig and a LOCA signal will register. If a consequential LOOP occurs with the LOCA 42 signal, the RHR discharge line can drain to the suppression pool in the ~45 seconds between 43 RHR pump load shed and the time it is reloaded on the diesel-backed bus, which sets up a 44 water hammer condition in the voided pipe. The lower cost alternative would be to change the 45 suppression pool cooling operating procedures or practices to reduce the chances of the 2 psi 46 high drywell pressure signal being reached for normal transients. In response, Exelon indicated 47 that no changes to the LSCS operating procedures would reduce the chance that the 2 psig 48 high drywell pressure signal would be reached in the scenarios of interest. The issue is that in 49 the scenarios of interest (initiators that result in the loss of containment cooling), SPC does not 50 have the capacity to remove enough heat to prevent the containment pressure from exceeding F-29
 
Appendix F 1 2 psig without venting containment in accordance with normal operating procedures to maintain 2 containment pressure less than the LOCA signal initiation pressure setpoint. Any changes to 3 the suppression pool cooling system operating procedures intended to increase the time 4 available between the initiating event and the 2 psig high drywell pressure signal would have a 5 very small impact on risk. Human error probabilities (HEPs) are influenced by a number of 6 factors, including time available for response. In this case, the HEP for the operator action to 7 vent the containment to prevent the high drywell signal is not significantly impacted by timing 8 considerations, and increasing the time available to the operators would correlate to very small 9 averted cost-risk values. The more difficult mitigating actions for water hammer scenarios are 10 associated with the approximate 20-second time interval between the occurrence of the loss of 11 the running pump on the LOCA-induced LOOP and the time when the pumps are automatically 12 started and reloaded onto the emergency bus. This short time period is not associated with the 13 operation of suppression pool cooling; therefore, a SAMA would have no benefit to these 14 scenarios. In these scenarios, the operators must put the pump in pull-to-lock to prevent restart 15 and then fill and vent the system to ensure a water hammer does not occur (Exelon 2015).
16 The NRC staff notes that the set of SAMAs submitted is not all-inclusive because additional, 17 possibly even less expensive, alternatives can always be postulated. However, the NRC staff 18 concludes that the benefits of any additional modifications are unlikely to exceed the benefits of 19 the modifications evaluated and that the alternative improvements would not likely cost less 20 than the least expensive alternatives evaluated, when the subsidiary costs associated with 21 maintenance, procedures, and training are considered.
22 The NRC staff concludes that Exelon used a systematic and comprehensive process for 23 identifying potential plant improvements for LSCS, and that the set of potential plant 24 improvements identified by Exelon is reasonably comprehensive and, therefore, acceptable.
25 This search included reviewing insights from the plant-specific risk studies, and reviewing plant 26 improvements considered in previous SAMA analyses. While explicit treatment of external 27 events in the SAMA identification process was limited, the NRC staff has determined that the 28 prior implementation of plant modifications and the absence of external event vulnerabilities 29 reasonably justify examining primarily the internal events risk results for this purpose.
30      Risk Reduction Potential of Plant Improvements 31 Exelon evaluated the risk-reduction potential of the 25 SAMAs retained for the Phase II 32 evaluation in a revised analysis (Exelon 2015). The SAMA evaluations were generally 33 performed by Exelon in a realistic or slightly conservative fashion that overestimates the benefit 34 of the SAMA. In most cases, the failure likelihood of the added equipment is taken to be 35 optimistically low, thereby overestimating the benefit of the SAMA. In other cases, it was 36 assumed that the SAMA eliminated all of the risk associated with the proposed enhancement.
37 The NRC staff notes that this bounding approach overestimates the benefit and therefore 38 is appropriately conservative.
39 Exelon used model requantification to determine the potential benefits for each of the SAMAs.
40 The CDFs, population dose reductions, and offsite economic cost reductions were estimated 41 using the LSCS PRA model. The changes made to the model to quantify the impact of each 42 SAMA are described in Section F.6 of the ER. Table F-6 summarizes the assumptions used to 43 estimate the risk reduction for each evaluated SAMA, the estimated risk reduction in terms of 44 CDF percent reduction, population dose, offsite economic cost, and the estimated total benefit 45 (present value) of the averted risk. The determination of the benefits for the various SAMAs is 46 further discussed in Section F.6.
F-30
 
Appendix F 1 The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction 2 estimate of each SAMA, as described in the Section F.6 of the ER. The resolution of RAIs that 3 resulted from this review follow.
4 The discussions of SAMA 8 in Section F.6.8 of the ER and SAMA 14 in Section F.6.13 of the 5 ER include the statement Flow from the fire protection system, in its current configuration, is 6 only adequate in cases where RCIC.... In response to an RAI to discuss what is meant by 7 current configuration, and the potential for a SAMA to address the FPS configuration and 8 make it possible to use without prior RCIC operation, Exelon responded that there are two major 9 issues that preclude the use of the FPS for RPV makeup in early time frames to prevent core 10 damage. The first is related to the low flow rate of the makeup path, and the second is related 11 to the relatively long time that is required to align the FPS for injection. The connection that is 12 currently used to provide RPV makeup from the FPS consists of fire hoses that are manually 13 aligned between the FPS header and the feedwater injection lines. The RPV pressure must be 14 reduced below 75 psig for Unit 1 and 60 psig for Unit 2 to achieve a flow rate of 200 gpm into 15 the RPV and would be successful only after [[estimated NRC review hours::4 hours]] following initial high pressure injection and 16 subsequent RPV depressurization. Prior to [[estimated NRC review hours::4 hours]], decay heat levels would be such that 17 200 gpm would be insufficient for RPV makeup. Relative to the second issue, Exelon indicated 18 that operator interviews indicate that about 40 minutes are required to establish the flow path 19 from the FPS to the RPV. It would not be possible to align this injection path even if adequate 20 flow could be obtained from the FPS to make up for boil-off. Exelon indicated and the NRC staff 21 agrees that both of these issues were assumed mitigated by SAMA 18, Improvement of the 22 Connection Between the Fire Protection and Feedwater Systems. While this SAMA was 23 developed to reduce the alignment time such that it would be possible to perform the alignment 24 in cases where RCIC injection fails, one of the assumptions made in the SAMA 18 assessment 25 was that the improved connection also would improve the flow rate of FPS injection to a point 26 where it could provide adequate makeup in loss of all injection scenarios (Exelon 2015).
27 In Section F.6.13 of the ER, the discussion of SAMA 14 (provide a portable DC source to 28 support RCIC and SRV operation) indicates that the PRA model was changed to include a 29 lumped event to represent the 480 V AC power source that feeds the Division 1 battery 30 chargers. The SAMA description and the basic events cited to be mitigated by this SAMA 31 indicated that a DC power source to directly supply an engineered safety feature (ESF) DC 32 distribution panel is needed. In response to an RAI to discuss the inclusion of an AC power 33 supply in the model, Exelon responded that the description of the PRA model changes related 34 to the lumped event that was added to represent the 480V AC power source that feeds the 35 Division 1 battery charger is erroneous and that the text should read a lumped event was 36 added to represent the 125 V DC generator that would supply 125 V ESF DC distribution 37 panel 1(2)11Y. The detailed PRA model change descriptions documented in Section F.6.13 of 38 the ER accurately describe how the lumped event (basic event ID SAMA 14) was incorporated 39 into the PRA model for SAMA 14 (Exelon 2015).
40 In an RAI, the NRC staff noted that SAMA 7 (water hammer prevention) and SAMA 25 (periodic 41 training on water hammer scenarios resulting from a false LOCA signal) both are intended to 42 mitigate the water hammer scenarios involving SPC operation interrupted by a LOOP. The 43 changes made to the model and the impacts on population dose risk and offsite economic cost 44 risk are significantly different for the two SAMAs. In response to the NRC staff RAI to discuss 45 these SAMAs and their analyses in more detail to justify these differences, Exelon responded 46 that SAMA 7 and SAMA 25 are different approaches to addressing the risk associated with 47 water hammer events at LSCS. While the different approaches might be expected to lead to 48 some differences in the CDF and risk impact of the two SAMAs, the difference in person-rem 49 and offsite economic risk impacts reported in the ER was found to be due to a recently F-31
 
Appendix F 1 discovered error in a supporting spreadsheet calculation for SAMA 25. Exelon provided 2 corrected values in the RAI response and indicated that the reduced benefit for SAMA 25 3 changed its disposition from cost beneficial to not cost beneficial (Exelon 2015). The NRC staff 4 agrees that these values are correct.
5 The NRC staff noted that SAMA 9 (Develop flood zone specific procedures) and SAMA 11 6 (Provide the capability to trip the FPS pumps) both address internal flooding; whose principal 7 contributor is a FPS pipe rupture in the reactor building. The assumption that all of the relevant 8 internal flooding risk will be eliminated by implementing SAMA 9, lowers the overall CDF by 9 9 percent and results in this SAMA being cost beneficial. As stated in Section F.6.11 of the ER, 10 SAMA 11 is designed to eliminate the FPSs flow. For SAMA 11, there is less than a 2 percent 11 reduction in CDF. In response to an RAI to discuss the FPS design, the FPS pipe break 12 scenarios, and associated modeling to support the above results, Exelon responded that the 13 primary reason for the significant difference between SAMA 9 and SAMA 11 risk reductions is 14 that they target different portions of flooding risk. SAMA 9 targets all flooding initiators while 15 SAMA 11 targets only a subset of FPS flooding scenarios. SAMA 9 was conservatively 16 modeled by assuming that it eliminated all internal flooding risk. The 9 percent reduction in CDF 17 is consistent with the CDF values reported for the internal flooding initiators in Table F.2-2 of 18 the ER. SAMA 11 provides only a means of tripping the FPS pumps in the main control room, 19 which helps reduce the risk of FPS flooding events that require a rapid response (i.e., large 20 breaks) but would only have a small impact on the longer term FPS flooding scenarios. Since 21 SAMA 11 only improves the reliability of one human action in the PRA model, only a small 22 improvement in CDF is expected. In contrast, SAMA 9 improves the reliability of all human 23 response actions to all flood scenarios and, therefore, has a larger overall impact on the model 24 (Exelon 2015).
25 The NRC staff reviewed Exelons bases for calculating the risk reduction for the various plant 26 improvements and concludes, with the above clarifications and corrections, that the rationale 27 and assumptions for estimating risk reduction are reasonable and generally conservative 28 (i.e., the estimated risk reduction is higher than what would actually be realized). Accordingly, 29 the NRC staff based its estimates of averted risk for the various SAMAs on Exelons risk 30 reduction estimates.
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1                                                  SAMA Cost-Benefit Screening Analysis for LSCS Station(a)
                                                                                        % Risk Reduction(b)              Total Benefit ($)(c)
Baseline With Baseline    Uncertainty Population                  (Internal +    (95th          Cost Individual SAMA and Assumption                                            CDF      Dose          OECR        External)  percentile)        ($)(c) 1 - INSTALL RELIABLE HARD PIPE CONTAINMENT VENT                                28        36          43      2.5M            5.4M            13M SAMA 1 Modeling: The model was modified by eliminating the support system dependencies, improving the reliability of the venting action to reflect simplification of the controls, and eliminating the events related to vent path rupture and leakage.
2 - AUTOMATE SUPPRESSION POOL COOLING                                          14        20          25      1.4M            3.1M          400K SAMA 2 Modeling: The fault tree incorporated the automation of suppression pool cooling alignment by changing the independent basic event IDs for suppression pool cooling initiation to alternate IDs. This accomplishes two functions: (i) assignment of alternate failure probabilities that are representative of an automated function, and (ii) prevent the recovery logic from identifying suppression pool cooling initiation failures as human actions and preclude the suppression pool cooling initiation failures from dependent human error combinations.
3 - PASSIVE VENT PATH                                                          36        51          61      1.0M            2.2M          1.0M SAMA 3 Modeling: The basic event for the operator action for venting was replaced with a new placeholder event with a value of 106 (prevents the creation of dependent operator actions, including the vent action). The hardware failures associated with the vent path valves have been F-33  retained to approximate the potential failures of the rupture disk (with the support system dependencies removed).
4 - INSTALL A KEYLOCK MSIV LOW LEVEL ISOLATION 16          12        10          674K          1.4M        635K BYPASS SWITCH SAMA 4 Modeling: The independent human error probability to bypass the main steam isolation valve low level isolation interlock was set to 105 and the joint human error probabilities that include this action have been eliminated.
5 - AUTOMATE SBLC INITIATION                                            8        7              6          386K            827K        400K SAMA 5 Modeling: The automatic SBLC initiation capability is modeled by manipulation of associated basic events. Early SBLC initiation basic event ID (2SLOP-LVLCTRLH--) was changed to SAMA5 and set to a probability of 106 to reduce the independent failure contribution to a small value and prevent the inclusion of dependent operator action combinations with SBLC initiation failures, consistent with the automated action.
6 - CREATE ECCS SUCTION STRAINER BACKFLUSH 1          1            1          88K          186K        2.9M CAPABILITY WITH RHRSW SAMA Modeling: The contribution related to common cause failure strainer clogging was eliminated by setting the corresponding basic events in the cutset files to zero.
Appendix F
 
                                                                                      % Risk Reduction(b)              Total Benefit ($)(c)
Baseline With Baseline    Uncertainty Population                (Internal +    (95th          Cost      Appendix F Individual SAMA and Assumption                                          CDF      Dose          OECR        External)  percentile)      ($)(c) 7 - WATER HAMMER PREVENTION                                                7          <1            <1          51K          108K        962K SAMA 7 Modeling: Water hammer events were eliminated from the results through manipulation of the cutsets. The relevant water hammer scenarios are all characterized by two events that identify the residual heat removal train that is placed in suppression pool cooling mode in response to the high suppression pool temperature. Setting these events to zero approximates the impact of eliminating the water hammer events associated with the LOCA signal actuated solely on high drywell pressure.
8 - OBTAIN A 480V AC PORTABLE GENERATOR TO SUPPLY THE 125V DC BATTERY CHARGERS AND PROCEDURALIZE ITS                          4            4              4        259K          554K        400K USE SAMA 8 Modeling: The 480V AC generator capability has been approximated by adding the diesel fire pump as a low pressure injection source for SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480V AC power source that feeds the Division 1 battery chargers.
9 - DEVELOP FLOOD ZONE SPECIFIC PROCEDURES                                  9          3            3          224K          479K        115K F-34  SAMA 9 Modeling: Initiating event frequencies for flooding events were set to zero in the cutsets.
10 - CHANGE THE LOGIC TO CLOSE THE TURBINE DRIVEN FEEDWATER PUMP DISCHARGE VALVES WHEN THE PUMPS                              9          21            23            1.3M          2.8M        260K ARE NOT RUNNING SAMA 10 Modeling: The human failure event associated with closing the turbine driven feedwater pump discharge valves was changed to a new event with a failure probability of 104. This treatment reduces the independent contribution of the isolation failure and precludes the generation of dependent human error combination, including the operator action to isolate the valves.
11 - PROVIDE THE CAPABILITY TO TRIP THE FPS PUMPS 2          <1          <1          21K          44K      217K FROM THE MAIN CONTROL ROOM SAMA 11 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low pressure injection source for SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480V AC power source that feeds the Division 1 battery chargers.
12 - CROSSTIE THE HIGH PRESSURE CORE SPRAY AND 19          21          16          1.1M          2.3M          4.4M FEEDWATER INJECTION LINES FOR ATWS MITIGATION SAMA 12 Modeling: This SAMA makes use of an existing injection system (high pressure core spray) to provide high pressure injection in ATWS scenarios. This SAMA eliminates the contribution of all ATWS events by setting the accident Class IV flag (RCVCL-4A) to zero in the cutsets.
 
                                                                                    % Risk Reduction(b)              Total Benefit ($)(c)
Baseline With Baseline    Uncertainty Population              (Internal +    (95th            Cost Individual SAMA and Assumption                                            CDF      Dose        OECR        External)  percentile)        ($)(c) 14 - PROVIDE A PORTABLE DC SOURCE TO SUPPORT RCIC 9          7          7          444K          949K          489K AND SRV OPERATION SAMA 14 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low pressure injection source for SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480V AC power source that feeds the Division 1 battery chargers.
15 - TIE RHRSW TO THE LPCS SYSTEM FOR ISLOCA 37        57          57          3.4M            7.2M          1.4M MITIGATION SAMA 15 Modeling: Changes were made to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system).
ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the cross-tie. The cross-tie logic was added at the sequence level for BOC and ISLOCA sequences where credit was not previously taken for any low pressure injection systems. The logic also was added to the existing fault tree structure in scenarios where venting or containment failure resulted in the loss of injection systems.
F-35  16 - PROVIDE PORTABLE FANS FOR ALTERNATE ROOM 14        12          15          866K            1.9M        475K COOLING IN THE CSCS VAULTS SAMA 16 Modeling: The alternate CSCS room cooling capability was approximated by deleting the gates associated with room cooling failures (excluding the automatic initiation failures, which are already addressed in the model).
18 - IMPROVE THE CONNECTION BETWEEN THE FIRE 9            9        10          609K          1.3M        649K PROTECTION AND FEEDWATER SYSTEMS SAMA 18 Modeling: The fault tree was updated to credit the FPS in the places where LPCI and LPCS are credited, but the system is failed for the LOCA and IORV initiating event and for water hammer scenarios. In addition, the logic was changed to include the FPS injection capability in the early SBO scenarios in which the ADS is available for those sequences not impacted by the LPCS-LPCI gate.
19 - PROVIDE REMOTE ALIGNMENT CAPABILITY OF RHRSW 38          58        58          3.4M          7.3M        2.9M TO THE LPCS SYSTEM FOR LOCA MITIGATION SAMA 19 Modeling: The inclusion of the RHRSW-LPCS cross-tie required changes to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the cross-tie. The cross-tie logic was added at the sequence level for BOC and ISLOCA sequences where credit was not previously taken for any low pressure injection systems. The logic also was added to the existing fault tree structure in scenarios where venting or containment failure resulted in the loss of injection systems.
Appendix F
 
                                                                                      % Risk Reduction(b)              Total Benefit ($)(c)
Baseline With Baseline    Uncertainty Population                  (Internal +    (95th          Cost      Appendix F Individual SAMA and Assumption                                            CDF      Dose          OECR        External)  percentile)        ($)(c) 20 - IMPROVE VACUUM BREAKER RELIABILITY BY INSTALLING 1          2              2        113K        243K            1.2M REDUNDANT VALVES IN EACH LINE SAMA 20 Modeling: The installation of the redundant vacuum breakers is modeled by setting the probability of the vacuum breakers failing to reclose to zero. It is assumed that there are no negative consequences associated with installing the redundant vacuum breakers (i.e., the failure to open probability of the vacuum breakers is not increased).
21 - INSTALL AUTOMATIC ATWS LEVEL CONTROL SYSTEM                        14        14              12        754K        1.6M            1.5M SAMA 21 Modeling: The SAMA is modeled by setting the early and late level control actions to zero in the fault tree.
22 - HYDROGEN IGNITORS IN PRIMARY CONTAINMENT                              <1        1            1          34K            72K          205K SAMA 22 Modeling: The SAMA is modeled by setting the failure probability of hydrogen detonation to zero in the cutsets.
23 - ENHANCE FUEL POOL EMERGENCY MAKEUP PUMP 27        46          52          3.0M            6.5M          1.4M AND CONNECTION SAMA 23 Modeling: The inclusion of the fuel pool emergency makeup pump cross-tie required changes to be made to both the main fault tree F-36  and the recovery fault tree. The cross-tie was assumed to require the residual heat removal B injection path (existing logic from the LPCI system). The logic was added to the existing fault tree structure in scenarios where venting or containment failure resulted in the loss of injection systems.
24 - PROVIDE INTER DIVISION 4 KV AC CROSSTIE CAPABILITY                  5          5            6        367K          785K        1.8M SAMA 24 Modeling: The implementation of the inter-division cross-tie is modeled by including the other two diesel generators from the same unit as potential power supply sources for a given emergency bus.
25 - PERIODIC TRAINING ON WATER HAMMER SCENARIOS 5          <1            <1          42K            89K          112K RESULTING FROM A FALSE LOCA SIGNAL SAMA 25 Modeling: This SAMA was modeled by changing basic event values in the cutsets to reflect the improved reliability of the drywell venting action for preventing a LOCA signal in non-LOCA cases.
26 - SEISMICALLY QUALIFIED LOW-PRESSURE RPV MAKEUP 28            33          39        2.3M          4.9M          6.0M CAPABILITY SAMA 26 Modeling: Changes were made to both the main fault tree and the recovery fault tree. Logic was added to the existing fault tree structure in scenarios where LPCI and LPCS are credited and where containment failure results in the loss of injection systems due to adverse environmental conditions. Logic was included in the fault tree preclude credit for loss of inventory scenarios where the 600 gallons per minute makeup rate may be inadequate (e.g., LOCA events and makeup to prevent RPV melt-through).
 
                                                                                              % Risk Reduction(b)                  Total Benefit ($)(c)
Baseline With Baseline    Uncertainty Population                    (Internal +    (95th              Cost Individual SAMA and Assumption                                                    CDF        Dose          OECR          External)  percentile)          ($)(c) 27 - PRECLUDE EMERGENCY DEPRESSURIZATION WHEN RCIC IS THE ONLY INJECTION SYSTEM AVAILABLE AND                        4          3            3          196K            420K          512K PROVIDE LONG-TERM DC POWER SAMA 27 Modeling: The SAMA is modeled by setting the failure probability of sequences in which RCIC is initially operational in a SBO to zero in the cutsets.
(a) SAMAs  in bold are potentially cost beneficial. Potentially cost-beneficial SAMAs relate to both LSCS units, Unit 1 and Unit 2.
(b) Risk reduction percentages displayed in this table were obtained from the ER (Exelon 2014a) prior to Exelons revised results (Exelon 2015). Risk reduction percentages for the revised benefit results were not provided.
(c) Exelon identified potentially cost-beneficial SAMAs by comparing the total benefit with uncertainty at the 95th percentile to the estimated implementation cost.
Total benefit and cost values presented in this table were obtained from Exelons revised results (Exelon 2015).
Key: AC = alternating current; ADS = automatic depressurization system; ATWS = anticipated transients without scram; BOC = break outside containment; CDF = core damage frequency; CSCS = core standby cooling system; DC = direct current; ECCS = emergency core cooling system; FPS = fire protection system; ID = identification; IORV = inadvertent/stuck open relief valve; ISLOCA = interfacing-systems loss-of-coolant accident; LPCI = low pressure coolant F-37    injection; LPCS = low pressure core spray; LOCA = loss-of-coolant accident; LSCS = LaSalle County Station; MSIV = main steam isolation valve; OECR = offsite economic cost risk; RCIC = reactor core isolation cooling; RHRSW = residual heat removal service water; RPV = reactor pressure vessel; SAMA = severe accident mitigation alternative; SBO = station blackout; SBLC = standby liquid control; SRV = safety relief valve Sources: Exelon 2014a, 2015 Appendix F
 
Appendix F 1      Cost Impacts of Candidate Plant Improvements 2 Exelon estimated the costs of implementing the 25 Phase II SAMAs through the use of other 3 licensees estimates for similar improvements and the development of site-specific cost 4 estimates where appropriate.
5 SAMA cost estimates were based on initial hardware, installation, and implementation costs.
6 In response to an NRC staff RAI to provide further information as to what was included in the 7 LSCS cost estimates, Exelon clarified that maintenance and testing costs during the license 8 renewal period were conservatively not included in the estimate (Exelon 2015).
9 The NRC staff reviewed the applicants cost estimates presented in Section F.6 of the ER 10 (Exelon 2014a). For certain improvements, the NRC staff also compared the cost estimates to 11 estimates developed elsewhere for similar improvements, including estimates developed as part 12 of other licensees analyses of SAMAs for operating reactors.
13 The NRC staff noted that a few SAMAs (e.g., 8, 14, and 27) involve use of equipment that may 14 be available as a result of the B.5.b program and asked Exelon to discuss this further and the 15 impact on the cost-benefit analysis. Exelon responded that the B.5.b program at LSCS includes 16 a small generator that is used to support two individual SRV solenoids to hold the SRVs open 17 after 125V DC battery depletion, but the generator does not power the station battery chargers 18 and it is not designed to support the RCIC system through direct DC feeds. Because of these 19 limitations, the B.5.b generator is not a viable substitute for the generators that have been 20 proposed for SAMAs 8, 14, and 27; therefore, the availability of the B.5.b generator would not 21 reduce the implementation costs for these SAMAs. With the above clarifications, the NRC staff 22 concludes that the cost estimates provided by Exelon are sufficient and appropriate for use in 23 the SAMA evaluation.
24      Cost-Benefit Comparison 25 Exelons cost-benefit analysis and the NRC staffs review are described in the following 26 sections.
27 F.6.1. Exelons Evaluation 28 The methodology used by Exelon was based primarily on NRCs guidance for performing 29 cost-benefit analysis, NUREG/BR-0184 (NRC 1997a) and industry guidance (NEI 2005) 30 endorsed by NRC. As described in Section F.4 of the ER (Exelon 2014a), the modified 31 maximum averted cost risk (MMACR) was determined for each SAMA according to the 32 following formula, which the staff accepts as mathematically equivalent to the formula in the 33 NUREG/BR-0184:
34 MMACR = EEM (W PHA + WEA + W O + W CD + W RP) 35 where 36 EEM      =      external event multiplier (unitless) 37 WPHA    =      present value of averted offsite exposure cost ($)
38 WEA      =      present value of averted offsite economic cost ($)
39 WO      =      present value of averted onsite exposure cost ($)
40 WCD      =      present value of averted onsite cleanup cost ($)
F-38
 
Appendix F 1 WRP      =      present value of averted replacement power cost ($)
2 Exelons derivation of each of the associated costs is presented separately in this section. For 3 each SAMA, the applicants analysis determined percentage reductions in population dose risk 4 (PDR%), offsite economic cost risk (OECR%), and onsite cost risk (OCR%). The internal and 5 external benefit from the implementation of an individual SAMA is determined from these 6 percentage reductions and their associated present value costs according to the following 7 formula:
8 SAMA Benefit = EEM [PDR% W PHA + OECR% WEA + OCR% (W O + W CD + W RP)]
9 For each SAMA, the estimated benefit is compared to the cost of implementation. If the cost of 10 implementing the SAMA is larger than the benefit associated with the SAMA, the SAMA is not 11 considered to be cost beneficial. If the cost of implementing the SAMA is smaller than the 12 benefit associated with the SAMA, the SAMA is considered to be cost beneficial. In the ER, 13 Exelon calculated the net value for individual SAMAs in a similar manner. Positive net values 14 indicated a potentially cost-beneficial SAMA, and negative net values implied that the SAMA 15 was not cost beneficial.
16 In accordance with NUREG/BR-0058 guidance (NRC 2004) that states present worth estimates 17 should be developed using both the 3 percent and 7 percent discount rates, Exelon conducted a 18 baseline analysis using the 3 percent discount rate and a sensitivity analysis using the 7 percent 19 discount rate (Exelon 2014a). Additional sensitivity analyses were performed by the applicant to 20 quantify influences on the calculated benefits from the 95th percentile PRA results, offsite 21 consequence modeling parameter changes, and assumed implementation of a hardened pipe 22 containment vent. Additional details on the sensitivity analysis are presented in Section F.6.2.
23 Averted Offsite Exposure Cost (W PHA) 24 Exelon defined WPHA cost as the monetary value of accident risk avoided from population doses 25 after discounting (Exelon 2014a). The W PHA costs were calculated using the following formula:
26          WPHA = Averted public dose risk (person-rem per year) 27                  x monetary equivalent of unit dose ($2,000 per person-rem) 28                  x present value conversion factor (NRC 1997a) 29 As stated in NUREG/BR-0184 (NRC 1997a), it is important to note that the monetary value of 30 the public health risk after discounting does not represent the expected reduction in public 31 health risk because of a single accident. Rather, it is the present value of a stream of potential 32 losses extending over the remaining lifetime (in this case, the 20-year renewal period) of the 33 facility. Thus, it reflects the expected annual loss caused by a single accident, the possibility 34 that such an accident could occur at any time over the renewal period, and the effect of 35 discounting these potential future losses to present value. For a discount rate of 3 percent, 36 Exelon calculated the W PHA cost of $213,863 due to internal events in the ER (Exelon 2014a).
37 Averted Offsite Economic Cost (W EA) 38 Exelon defined WEA as the monetary value of risk avoided from offsite property damage after 39 discounting (Exelon 2014a). The W EA values were calculated using the following formula:
40          WEA = Annual offsite property damage risk before discounting in dollars per year 41                  x present value conversion factor (NRC 1997a) 42 For a discount rate of 3 percent, Exelon calculated the W EA cost of $802,484 due to internal 43 events in the ER (Exelon 2014a).
F-39
 
Appendix F 1 Averted Onsite Exposure Cost (W O) 2 Exelon defined W O as the avoided onsite exposure (Exelon 2014a). Similar to the W PHA 3 calculations, the applicant calculated costs for immediate onsite exposure. Long-term onsite 4 exposure costs were calculated consistent with guidance in the Regulatory Analysis Technical 5 Evaluation Handbook (NRC 1997a), which included an additional term for accrual of 6 long-term doses.
7 Exelon derived the values for averted occupational exposure from information provided in 8 Section 5.7.3 of the Regulatory Analysis Technical Evaluation Handbook (NRC 1997a). Best 9 estimate values providing for an immediate occupational dose (3,300 person-rem) and 10 long-term occupational dose (20,000 person-rem over a 10-year cleanup period) were used.
11 The present value of these doses was calculated using the equations provided in the handbook 12 in conjunction with a monetary equivalent of unit dose of $2,000 per person-rem, a real discount 13 rate of 7 percent, and a time period of 20 years to represent the license renewal period.
14 Immediate and long-term onsite exposure costs were summed to determine the W O cost. For a 15 discount rate of 3 percent, Exelon calculated the WO cost of $1,597 due to internal events in the 16 ER (Exelon 2014a).
17 Averted Onsite Cleanup Cost (W CD) 18 Exelon defined W CD as the avoided cost for cleanup and decontamination of the site 19 (Exelon 2014a). The applicant derived the values for W CD based on information provided in 20 Section 5.7.6 of NUREG/BR-0184, the Regulatory Analysis Technical Evaluation Handbook 21 (NRC 1997a).
22 Averted cleanup and decontamination costs were calculated using the following formula:
23 WCD = Annual CDF x present value of cleanup costs per core damage event x present value 24 conversion factor.
25 The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 26 the Regulatory Analysis Technical Evaluation Handbook to be $1.5x109 (undiscounted). This 27 value was converted to present costs over a 10-year cleanup period and integrated over the 28 term of the proposed license extension. For a discount rate of 3 percent, Exelon calculated the 29 WCD cost of $50,284 due to internal events in the ER (Exelon 2014a).
30 Averted Replacement Power Cost (W RP) 31 Exelon defined W RP as the avoided costs of replacement power (Exelon 2014a). Long-term 32 replacement costs were calculated using the following formula:
33        WRP = Annual CDF x present value of replacement power for a single event 34                x factor for remaining service years for which replacement power is required 35                x reactor power scaling factor 36 Exelon based its calculations on the net electric output for LSCS, specifically 37 1,210 megawatt-electric (MWe), and scaled up from reference plant value of 910 MWe specified 38 in NUREG/BR-0184 (NRC 1997a). For a discount rate of 3 percent, Exelon calculated W RP 39 costs of $18,955 due to internal events in the ER (Exelon 2014a).
40 Modified Maximum Averted Cost Risk (MMACR) 41 Using the above equations and an annual CDF of 2.58x106, Exelon estimated the total present 42 dollar value equivalent associated with completely eliminating severe accidents caused by 43 internal events, referred to as the MACR, to be about $1,087,183 at a single unit for a discount 44 rate of 3 percent in the ER (Exelon 2014a). In Exelons revised analysis, the MACR increased F-40
 
Appendix F 1 to approximately $1,168,000. To account for the risk contributions from external events and 2 yield the internal and external benefit, Exelon selected an external event multiplier (EEM) value 3 of 5.2 for LSCS, as described in Section F.4.6.2 of the ER (Exelon 2014a). By multiplying 4 MACR and EEM, Exelon estimated MMACR to be about $5,657,600 for a single unit with a 5 discount rate of 3 percent, as presented in Section F.4.6.3 of the ER (Exelon 2014a). In 6 Exelons revised analysis, the MMACR increased to $6,073,600 (Exelon 2015). As described 7 above in the SAMA benefit formula, components of the MMACR calculation factor into the 8 benefit determination for individual SAMAs. When Exelon revised its analysis in response to 9 RAIs from the NRC staff, updates were not presented for the individual components of MACR 10 (W PHA, W EA, W O, W CD, WRP).
11 Exelons Results 12 If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 13 was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 14 SAMA candidate was considered to be potentially cost beneficial. Results of the cost-benefit 15 evaluation are presented in Table F-6. Exelons cost-benefit analysis identified 14 SAMA 16 candidates determined to be potentially cost beneficial at the 95th percentile on an individual 17 basis:
18
* SAMA 2: Automate suppression pool cooling.
19
* SAMA 3: Passive vent path.
20
* SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level isolation 21            bypass switch.
22
* SAMA 5: Automate standby liquid control (SBLC) initiation.
23
* SAMA 8: Obtain a 480 V AC portable generator to supply the 125 V DC battery 24            chargers and proceduralize its use.
25
* SAMA 9: Develop flood zone specific procedures.
26
* SAMA 10: Change the logic to close the turbine driven feedwater pump discharge 27            valves when the pumps are not running.
28
* SAMA 14: Provide a portable DC source to support RCIC and SRV operation.
29
* SAMA 15: Tie RHRSW to the low-pressure core spray (LPCS) system for interfacing 30            systems loss-of-coolant accident (ISLOCA) mitigation.
31
* SAMA 16: Provide portable fans for alternate room cooling in the CSCS vaults.
32
* SAMA 18: Improve the connection between the fire protection and 33            feedwater systems.
34
* SAMA 19: Provide remote alignment capability of RHRSW to the LPCS system for 35            LOCA mitigation.
36
* SAMA 21: Install Automatic ATWS level control system.
37
* SAMA 23: Enhance fuel pool emergency makeup pump and connection.
38 When the planned installation of a hardened pipe containment vent is considered as the base 39 case, the number of SAMA candidates considered to be potentially cost beneficial at the 40 95th percentile may reduce. Because a new baseline is established following the 41 implementation of a SAMA, which further influences the benefits provided by the remaining 42 SAMA candidates, Exelon defined an optimal set to containing SAMAs that, if implemented, F-41
 
Appendix F 1 would render the remaining SAMAs to be not cost beneficial. Acknowledging Exelons planned 2 installation of the hardened pipe containment vent (SAMA 1), additional modifications included 3 in the optimal set are SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a).
4 Assessment of the optimal set was performed prior to Exelon generating revised results in 5 response to the NRC staffs RAIs (Exelon 2015). Because a priori credit for installation of the 6 hardened pipe containment vent was not taken by Exelon, revision of the optimal set 7 assessment was not required. Exelon is referring the 14 potentially cost-beneficial SAMAs from 8 its revised analysis (Exelon 2015) to the LSCS Plant Health Committee for further 9 implementation considerations within the established plant procedural process, as indicated in 10 Section 4.15 of the ER (Exelon 2014d).
11 F.6.2. Review of Exelons Cost-Benefit Evaluation 12 During its review of the cost-benefit analysis performed by Exelon, the NRC staff compared the 13 applicants approach with guidance in NUREG/BR-0184 (NRC 1997a) and discount rate 14 guidelines in NEI 05-01 (NEI 2005). NEI guidance states that two sets of estimates should be 15 developed for discount rates of 7 percent and 3 percent (NEI 2005). Exelon performed 16 assessments using both discount rates. Exelon provided a baseline set of results using a 17 discount rate of 3 percent. For the other types of potential sensitivity analyses suggested 18 (NEI 2005), the NRC staff finds that Exelons information provided in the ER submittal and 19 subsequent RAI responses on plant modifications, peer review findings or observations, and 20 evacuation speeds have been adequately addressed in the baseline analysis, as discussed in 21 this appendix. As previously indicated, Exelon performed the cost-benefit evaluation using an 22 analysis time period of 20 years. Because Exelon explicitly accounted for uncertainty in its 23 sensitivity analysis by applying a multiplication factor of 2.14 and the results of the sensitivity 24 analysis were used to identify additional potentially beneficial SAMAs, the NRC staff finds that 25 an additional sensitivity analysis for a timeframe longer than 20 years is not necessary.
26 Although longer timeframes would increase estimated benefits compared to baseline results, 27 the 20-year timeframe is consistent with the later expiration month of December 2043 for a 28 renewed license of Unit 2 stated in Section 1.1 of the ER (Exelon 2014a), and it is unlikely that 29 influences from a longer timeframe would exceed the factor of 2.14 already considered by 30 Exelon. Based on its review of the applicants cost-benefit evaluation, the NRC staff determined 31 that the applicants approach is consistent with the guidance and acceptable.
32 The applicant considered possible increases in benefits from analysis uncertainties on the 33 results of the SAMA assessment. In the ER (Exelon 2014a), Exelon indicated that the 34 95th percentile value of the LSCS CDF was greater than the mean CDF by a factor of 2.14, and 35 thus, a multiplication factor of 2.14 was selected to account for uncertainty. This multiplication 36 factor was applied in addition to the separate external events multiplication factor of 5.2 37 (Exelon 2014a). Exelons assessment accounted for the potential risk-reduction benefits 38 associated with both internal and external events. The NRC staff considers the multipliers 39 of 2.14 for uncertainty and 5.2 for external events at LSCS provide an adequate margin and are 40 acceptable for the SAMA analysis.
41 Using Exelons information presented in the ER (Exelon 2014a), the NRC staff spot checked the 42 applicants calculations of delta CDF (i.e., percentage reduction in CDF due to accumulated 43 differences in the release categories for a specific SAMA candidate compared to the base 44 case), population dose risk, and offsite economic cost risk. By applying the formula for SAMA 45 benefit presented in Section F.6.1 and comparing the results with those presented in the ER 46 (Exelon 2014a), the NRC staff found the results to be in agreement and within small round-off 47 errors.
F-42
 
Appendix F 1 Exelons revised cost-benefit analysis identified 14 SAMA candidates as potentially cost 2 beneficial at the 95th percentile (Exelon 2015). From its sensitivity analyses in the ER, no 3 additional SAMA candidates were determined to be potentially cost beneficial. As described in 4 Section F.3.2, the NRC staff asked the applicant to evaluate potentially lower cost alternatives 5 to SAMA 7. From its review of the original SAMA analysis and additional information, the NRC 6 staff agrees with Exelons disposition of potentially lower cost alternatives.
7 Because Exelons cost-benefit evaluations have been reviewed by the NRC staff and Exelon 8 satisfactorily addressed NRC staff questions regarding the evaluations, the NRC staff concludes 9 that the cost-benefit evaluations are of sufficient quality to support the SAMA evaluation.
10 Therefore, the NRC staff concludes that, with the exception of the potentially cost-beneficial 11 SAMAs discussed above, the costs of the other SAMAs evaluated would be higher than their 12 associated benefits and not cost beneficial.
13      Conclusions 14 Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 15 updated probabilistic safety assessment models, SAMA-related industry documentation, 16 plant-specific enhancements, and its review of SAMA candidates from potential improvements 17 primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 18 SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 19 been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 20 costs and benefits associated with each of the 25 potential SAMAs shown in Table F-6. Exelon 21 concluded that 14 SAMA candidates were potentially cost beneficial at the 95th percentile.
22 Despite it being not cost beneficial, Exelon has decided to proceed with the modification to 23 install a hardened pipe containment vent regardless of cost. Exelon also performed a sensitivity 24 analysis, and no additional SAMA candidates were identified as potentially cost beneficial.
25 Because the potentially cost-beneficial SAMAs do not relate to aging management during the 26 period of extended operation, their implementation is not required as part of license renewal 27 pursuant to Title 10 of the Code of Federal Regulations (10 CFR) Part 54, Requirements for 28 Renewal of Operating Licenses for Nuclear Power Plants. Nevertheless, as stated in 29 Section 4.15 of the ER (Exelon 2014d), Exelon indicated that the potentially cost-beneficial 30 SAMAs are being referred to the LSCS Plant Health Committee for further implementation 31 considerations within the established plant procedural process.
32 The NRC staff reviewed Exelons SAMA analysis and concludes that the methods used and 33 implementation of the methods were sound. On the basis of the applicants treatment of SAMA 34 benefits and costs, the NRC staff finds that the SAMA evaluations performed by Exelon are 35 reasonable and sufficient for the license renewal submittal. The NRC staff concurs with 36 Exelons conclusion that 14 SAMA candidates are potentially cost beneficial for LSCS and notes 37 that Exelons assessment was based on generally conservative treatment of costs, benefits, and 38 uncertainties. Based on the NRC staffs review of Exelons SAMA evaluations, including 39 Exelons response to the NRC staffs RAIs, the NRC staff concludes that Exelon has adequately 40 identified areas where risk can be further reduced in a cost-beneficial manner through the 41 implementation of the identified potentially cost-beneficial SAMAs. Given the potential for 42 cost-beneficial risk reduction, the NRC staff concludes that further evaluation by Exelon of the 43 14 SAMA candidates identified by Exelon as being potentially cost beneficial is warranted.
44 The NRC staff also evaluated whether any of the potentially cost-beneficial SAMAs identified 45 are subject to aging management such that they would be within the scope of license renewal.
46 The evaluation considered any structures, systems, and components associated with these 47 SAMAs that perform intended functions without moving parts or without a change in F-43
 
Appendix F 1 configuration or properties and would not be subject to replacement based on a qualified life or 2 specified time period. The NRC staff determined that the potentially cost-beneficial SAMAs do 3 not relate to adequately managing the effects of aging during the period of extended operation.
4 Therefore, they need not be implemented as part of license renewal in accordance with 5 10 CFR Part 54.
6      References 7 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 8 Renewal of Operating Licenses for Nuclear Power Plants.
9 [ASME/ANS] (American Society of Mechanical Engineers/American Nuclear Society). 2005.
10 Addenda RA-Sa-2003 and RA-Sb-2005 to ASME RA-S-2002, Standard for Probabilistic Risk 11 Assessment for Nuclear Power Plant Applications. December 2005.
12 [ASME/ANS] American Society of Mechanical Engineers and American Nuclear Society. 2009.
13 Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency 14 Probabilistic Risk Assessment for Nuclear Power Plant Applications. New York, NY: ASME.
15 ASME/ANS RA-Sa-2009. February 2, 2009. 352 p. This document is proprietary and available 16 for sale on www.asme.org.
17 [CECO] Commonwealth Edison Company. 1994. LaSalle County Nuclear Power Station, 18 Individual Plant Examination and Individual Plant Examination (External Events). April 1994.
19 [Exelon] Exelon Generating Company, LLC. 2012a. Seismic Walkdown Report In Response 20 To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 21 Recommendation 2.3: Seismic for the LaSalle County Station, Unit 1, Report Number:
22 12Q0108.50-R-001, Revision 1. November 27, 2012. ADAMS No. ML12353A225.
23 [Exelon] Exelon Generating Company, LLC. 2012b. Seismic Walkdown Report In Response 24 To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 25 Recommendation 2.3: Seismic for the LaSalle County Station, Unit 2, Report Number:
26 12Q0108.50-R-002, Revision 1. November 27, 2012. ADAMS No. ML12353A207.
27 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report, 28 Operating License Renewal Stage, LaSalle County Station. Appendix F: Severe Accident 29 Mitigation Alternatives Analysis. ADAMS No. ML14343A897. December 2014.
30 [Exelon] Exelon Generation Company, LLC. 2014b. Letter from Glen T. Kaegi to NRC 31 Document Control Desk.
 
==Subject:==
Exelon Generation Company, LLC, Seismic Hazard and 32 Screening Report (Central and Eastern United States (CEUS) Sites), Response to NRC 33 Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the 34 Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident. Exelon letter 35 RS-14-068. March 31, 2014. ADAMS No. ML14091A013.
36 [Exelon] Exelon Generation Company, LLC. 2014c. Letter from T. John Conner to NRC 37 Document Control Desk.
 
==Subject:==
Exelon Generation Company, LLC Response to 38 March 12, 2012, Request for Information Enclosure 2, Recommendation 2.1, Flooding, 39 Required Response 2, Flood Hazard Reevaluation Report. Exelon letter RS-14-055.
40 March 12, 2014. ADAMS Nos. ML14079A425 and ML14079A426.
41 [Exelon] Exelon Generation Company, LLC. 2014d. Applicants Environmental Report, 42 Operating License Renewal Stage, LaSalle County Station. ADAMS No. ML14343A883.
43 December 2014.
F-44
 
Appendix F 1 [Exelon] Exelon Generation Company, LLC. 2015. Letter from Michael P. Gallagher, Vice 2 President, License Renewal Projects Exelon Generation Company, LLC, to NRC Document 3 Control Desk.
 
==Subject:==
Response to NRC Request for Additional Information on Severe 4 Accident Mitigation Alternatives Regarding the LaSalle County Station, Units 1 and 2 License 5 Renewal Application Environmental Review. Letter RA15-032. May 29, 2015. ADAMS 6 No. ML15149A370.
7 [NEI] Nuclear Energy Institute. 2005. Severe Accident Mitigation Alternative (SAMA) Analysis 8 Guidance Document. Revision A. Washington, DC: NEI. NEI 05-01. November 2005. 79 p.
9 ADAMS No. ML060530203.
10 [NRC] U.S. Nuclear Regulatory Commission. 1988. Individual Plant Examination for Severe 11 Accident Vulnerabilities10 CFR 50.54(f). Washington, DC: NRC. Generic Letter No. 88-20.
12 November 23, 1988. Available at <http://www.nrc.gov/reading-rm/doc-collections/gen-13 comm/gen-letters/1988/gl88020.html> (accessed 21 October 2014).
14 [NRC] U.S. Nuclear Regulatory Commission. 1991. Individual Plant Examination of External 15 Events for Severe Accident Vulnerabilities. Washington, DC: NRC. Generic Letter No. 88-20, 16 Supplement 4. June 28, 1991.
17 [NRC] U.S. Nuclear Regulatory Commission. 1992. Analysis of the LaSalle Unit 2 Nuclear 18 Power Plant: Risk Methods Integration and Evaluation Program (RMIEP). Washington, DC:
19 NRC. NUREG/CR-4832, Vols. 19, 19921993.
20 [NRC] U.S. Nuclear Regulatory Commission. 1995. Memorandum from M. Wayne Hodges, 21 NRC, to Steven A Varga, NRC.
 
==Subject:==
Review of LaSalle Individual Plant Examination (IPE) 22 Submittal-Internal Events. November 1, 1995.
23 [NRC] U.S. Nuclear Regulatory Commission. 1997a. Regulatory Analysis Technical Evaluation 24 Handbook. Washington, DC: NRC. NUREG/BR-0184. January 1997. 308 p. ADAMS 25 No. ML050190193.
26 [NRC] U.S. Nuclear Regulatory Commission. 1997b. Individual Plant Examination Program:
27 Perspectives on Reactor Safety and Plant Performance, NUREG-1560, Washington, D.C.
28 1997.
29 [NRC] U.S. Nuclear Regulatory Commission. 2000. Letter from Donna M. Skay to Oliver D.
30 Kingsley, Commonwealth Edison Company.
 
==Subject:==
LaSalle County Station, Units 1 and 2, 31 NRC Staff Evaluation of the Individual Plant Examination of External Events (IPEEE) Submittal.
32 (TAC Nos. M83634 and M83635). December 8, 2000. ADAMS No. ML003776159.
33 [NRC] U.S. Nuclear Regulatory Commission. 2004. Regulatory Analysis Guidelines of the 34 U.S. Nuclear Regulatory Commission. Revision 4. Washington, DC: NRC. NUREG/BR-0058.
35 September 2004. 56 p. Available at<http://www.nrc.gov/reading-rm/doc-collections/nuregs/
36 brochures/br0058/> (accessed 21 October 2014).
37 [NRC] U.S. Nuclear Regulatory Commission. 2005. EPRI/NRC-RES Fire PRA Methodology 38 for Nuclear Power Facilities. Vols. 1 and 2. Washington, DC: NRC. NUREG/CR-6850.
39 September 2005. ADAMS Nos. ML052580075 and ML052580118.
40 [NRC] U.S. Nuclear Regulatory Commission. 2007. An Approach for Determining the 41 Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities.
42 Revision 1. Regulatory Guide 1.200. January 2007. ADAMS No. ML070240001.
F-45
 
Appendix F 1 [NRC] U.S. Nuclear Regulatory Commission. 2010. Letter from T. McGinty, Director, to All 2 Holders of an Operating License.
 
==Subject:==
NRC Information Notice 2010-18: Generic 3 Issue 199, Implications of Updated Probabilistic Seismic Hazard Estimates in Central and 4 Eastern United States on Existing Plants. September 2, 2010. ADAMS No. ML101970221.
5 [NRC] U.S. Nuclear Regulatory Commission. 2011. An Approach for Using Probabilistic Risk 6 Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis.
7 Revision 2. Regulatory Guide 1.174. May 2011. ADAMS No. ML100910006.
8 [NRC] U.S. Nuclear Regulatory Commission. 2012a. Letter from E. Leeds, Director, to All 9 Power Reactor Licensees.
 
==Subject:==
Request for information pursuant to Title 10 of the Code of 10 Federal Regulations 50.54(f) regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term 11 Task Force review of insights from the Fukushima Dai-ichi accident. March 12, 2012. ADAMS 12 No. ML12053A340.
13 [NRC] U.S. Nuclear Regulatory Commission. 2012b. Letter from E. Leeds, Director, to All 14 Power Reactor Licensees and Holders of Construction Permits in Active or Deferred Status.
15 EA-12-049.
 
==Subject:==
Issuance of Order to Modify Licenses with Regard to Requirements for 16 Mitigation Strategies for Beyond-Design-Basis External Events. March 12, 2012. ADAMS 17 No. ML12054A735.
18 [NRC] U.S. Nuclear Regulatory Commission. 2014. Letter from Blake Purnell, Project 19 Manager, NRC, to Michael J. Pacilio, Senior Vice President, Exelon Generation Company.
20
 
==Subject:==
LaSalle County Station, Units 1 and 2 - Staff Assessment of the Flooding Walkdown 21 Report Supporting Implementation of the Near-Term Task Force Recommendation 2.3 Related 22 to the Fukushima Dai-ichi Accident. (TAC Nos. MF0240 and MF0241). June 30, 2014.
23 ADAMS No. ML14177A859.
24 [NRC] U.S. Nuclear Regulatory Commission. 2015. Letter from D. Drucker, Environmental 25 Project Manager, to Michael P. Gallagher, Vice President License Renewal Projects, Exelon 26 Generation Company, LLC.
 
==Subject:==
Request for Additional Information on Severe Accident 27 Mitigation Alternatives Regarding the LaSalle County Station, Units 1 and 2, License Renewal 28 Application Environmental Review (TAC Nos. MF5567 and MF5568). April 30, 2015. ADAMS 29 Nos. ML15114A320 and ML15114A102.
F-46
 
1                  APPENDIX G 2 TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL
 
1 G. TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL 2        Introduction 3 The U.S. Nuclear Regulatory Commission (NRC) has generically determined in its license 4 renewal application reviews that the environmental impacts of the transportation of fuel and 5 radioactive wastes to and from nuclear power facilities are small for all reactors as long as 6 certain specific conditions are met. The application for license renewal of LaSalle County 7 Station, Units 1 and 2 (LSCS) stated that the specific conditions that allow the transportation 8 impacts of spent fuel to be generically determined to be small may not be met for LSCS.
9 Therefore, this appendix provides the NRC staffs analysis of the environmental impacts of 10 transporting spent fuel from LSCS.
11        Background 12 The U.S. Nuclear Regulatory Commission (NRC) performed a generic analysis of the 13 environmental effects of the transportation of fuel and waste to and from light-water reactors 14 (LWRs) in WASH-1238, Environmental Survey of Transportation of Radioactive Materials to 15 and from Nuclear Power Plants (AEC 1972), and in a supplement to WASH-1238, 16 NUREG-75/038 (NRC 1975), and found the impact to be small. These documents provided the 17 basis for Table S-4 in Title 10 of the Code of Federal Regulations (CFR) Part 51.52(b) that 18 summarizes the environmental impacts of transportation of fuel and waste to and from one 19 3,000- to 5,000-megawatt-thermal (MWt) (1,000- to 1,500-megawatt-electric (MWe)) LWR.
20 Impacts are provided for normal conditions of transport and accidents in transport for a 21 reference 1,100-MWe LWR.11 Dose to transportation workers during normal transportation 22 operations was estimated to result in a collective dose of 4 person-rem per reference 23 reactor-year. The combined dose to the public along the route and the dose to onlookers were 24 estimated to result in a collective dose of 3 person-rem per reference reactor-year.
25 Environmental risks of radiological effects during accident conditions, as stated in Table S-4, 26 are small. Nonradiological impacts from postulated accidents were estimated as one fatal injury 27 in 100 reference reactor-years and one nonfatal injury in 10 reference reactor-years.
28 Subsequent reviews of transportation impacts in NUREG-0170, Final Environmental Statement 29 on the Transportation of Radioactive Material by Air and Other Modes (NRC 1977), and 30 NUREG/CR-6672, Reexamination of Spent Fuel Shipment Risk Estimates (Sprung et al. 2000),
31 concludes that impacts were bounded by Table S-4 in 10 CFR 51.52. In accordance with 32 10 CFR 51.52(a), a full description and a detailed analysis of transportation impacts are not 33 required in the initial licensing of an LWR (i.e., impacts are assumed to be bounded by 34 Table S-4) if the reactor meets the following criteria:
35
* The reactor has a core thermal power level that does not exceed 3,800 MWt.
36
* Fuel is in the form of sintered uranium oxide pellets having a uranium-235 37              enrichment not exceeding 4 percent by weight, and the pellets are encapsulated in 38              Zircaloy-clad fuel rods.
11 The transportation impacts associated with LSCS were normalized for a reference 1,100-MWe LWR at an 80-percent capacity factor for comparisons to Table S-4.
G-1
 
Transportation Impacts of High Burnup Fuel 1
* The average level of irradiation of the fuel from the reactor does not exceed 2            33,000 megawatt-days per metric ton of uranium (MWd/MTU), and no irradiated fuel 3            assembly is shipped until at least 90 days after it is discharged from the reactor.
4
* With the exception of irradiated fuel, all radioactive waste shipped from the reactor is 5            packaged and in a solid form.
6
* Unirradiated fuel is shipped to the reactor by truck; irradiated fuel is shipped from the 7            reactor by truck, rail, or barge; and radioactive waste other than irradiated fuel is 8            shipped from the reactor by truck or rail.
9 The environmental impacts of the transportation of fuel and radioactive wastes to and from 10 nuclear power facilities are resolved generically in 10 CFR 51.52 as long as the specific 11 conditions in the rule (see above) are met.
12 10 CFR 51.52 does not specifically address license renewal. However, NUREG-1437, Generic 13 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) 14 (NRC 2013), points out that nuclear fuel is needed for the operation of light water reactors 15 during the license renewal term in the same way that it is needed during the current license 16 period. Therefore, the factors that affect the data presented in Table S-4 of 10 CFR 51.52 do 17 not change when a light water reactor is operating under a renewed license. The GEIS further 18 states that the NRC reevaluated the transportation issues and the adequacy of Table S-4 for 19 license renewal application reviews (NRC 2013). In 1999, the NRC issued an addendum to the 20 GEIS (NRC 1999) in which the agency evaluated the applicability of Table S-4 to future license 21 renewal proceedings, particularly because shipments of spent fuel were likely to involve more 22 highly enriched fresh fuel (more than 4 percent as assumed in Table S-4) and higher-burnup 23 spent fuel (higher than 33,000 MWd/MTU as assumed in Table S-4). On the basis of the 24 evaluations, the NRC concluded that the values given in Table S-4 would still be bounding, as 25 long as the (1) enrichment of the fresh fuel was 5 percent or less, (2) burnup of the spent fuel 26 was 62,000 MWd/MTU or less, and (3) higher-burnup spent fuel (higher than 27 33,000 MWd/MTU) was cooled for at least 5 years before being shipped offsite.
28 The GEIS (NRC 2013) quotes the conclusion of the 1999 addendum as follows:
29        The impacts of transporting spent fuel enriched up to 5 percent uranium-235 with 30        average burnup for the peak rod to current levels approved by NRC up to 31        62,000 MWd/MTU and the cumulative impacts of transporting high-level waste to 32        a single repository, such as Yucca Mountain, Nevada are found to be consistent 33        with the impact values contained in 10 CFR 51.52(c), Summary Table S-4, 34        Environmental Impact of Transportation of Fuel and Waste to and from One 35        Light-Water-Cooled Nuclear Power Reactor. If fuel enrichment or burnup 36        conditions are not met, the applicant must submit an assessment of the 37        implications for the environmental impact values reported in 10 CFR 51.52.
38 Therefore, when the fuel burnup rate may exceed 62,000 MWd/MTU during the period of 39 extended operation, further analysis of transportation impacts is warranted.
40 Exelon Generation Company, LLC (Exelon), submitted an environmental report (ER) 41 (Exelon 2014a) as part of its license renewal application (Exelon 2014b) for LSCS in 42 December 2014. LSCS is located in north-eastern Illinois. Each LSCS reactor is a General 43 Electric boiling water reactor (BWR), Type 5, with a thermal power rating of 3,546 MWt. The 44 two reactors at LSCS have a combined electrical output of 2,327 MWe. Both LSCS units 45 operate using low-enriched uranium dioxide fuel with enrichment not exceeding a nominal 46 5.0 percent by weight of uranium-235; these units have been historically operated within a 47 maximum analyzed fuel burnup rate of 62,000 MWd/MTU. However, during some future fuel G-2
 
Transportation Impacts of High Burnup Fuel 1 cycles, the peak fuel burnup is projected to exceed 62,000 MWd/MTU in some part-length fuel 2 rods. The part-length fuel rods are attached to the fuel bundle lower tie plate and typically 3 experience higher burnups and higher power than full-length rods due to the bottom-peaked 4 axial power shapes that exist throughout a large portion of a BWR fuel cycle, and a 5 representative high-burnup case was identified based on a burnup of 75,000 MWd/MTU and a 6 uranium-235 enrichment of 5.0 percent by weight. Accordingly, Exelon provided a full 7 description and detailed analyses of the transportation impacts of shipping irradiated fuel from 8 LSCS in its ER (Exelon 2014a) and provided an update to that analysis by letter dated 9 August 28, 2015 (Exelon 2015). In this analysis, the radiological impacts of transporting 10 irradiated fuel from LSCS were calculated using the RADTRAN 6.02 computer code 11 (Weiner et al. 2015). RADTRAN 6.02 was also used in this SEIS and is the most commonly 12 used transportation impact analysis software in the nuclear industry.
13        NRC Analysis of LSCS High Burnup Fuel Transportation Impacts 14 This section provides the NRC staffs analysis of the environmental impacts of transporting 15 spent fuel from LSCS to a monitored retrievable storage facility or a permanent repository for 16 normal operating conditions and transportation accidents.
17 For the purposes of this analysis, the NRC staff considered the proposed Yucca Mountain 18 repository site in Nevada as a surrogate destination. Currently, the NRC has not made a 19 decision about the U.S. Department of Energy (DOE) application for the proposed geologic 20 repository at Yucca Mountain. However, the NRC staff considers that an estimate of the 21 impacts of the transportation of spent fuel to a possible repository in Nevada is a reasonable 22 bounding estimate of the transportation impacts on a storage or disposal facility because of the 23 distances involved and the representativeness of the distribution of members of the public in 24 urban, suburban, and rural areas (i.e., population distributions) along the shipping routes.
25 The NRC Yucca Mountain adjudicatory proceeding is currently suspended, and Yucca 26 Mountain-related matters are pending in Federal Court. Regardless of the outcome of these 27 proceedings, the NRC staff concludes that transportation impacts are roughly proportional to the 28 distance from the reactor site to the repository site, in this case, Illinois to Nevada.
29 This NRC staffs analysis is based on shipment of spent fuel by legal-weight trucks in shipping 30 casks with characteristics similar to currently available casks (i.e., massive, heavily shielded, 31 cylindrical metal pressure vessels). Because of the large size and weight of spent fuel shipping 32 casks, each shipment is assumed to consist of a single shipping cask loaded on a modified 33 trailer. These assumptions are consistent with those made in the evaluation of the 34 environmental impacts of transportation of spent fuel in Addendum 1 to NUREG-1437 35 (NRC 1999). Because the alternative transportation methods involve rail transportation or 36 heavy-haul trucks, which would reduce the overall number of spent fuel shipments (NRC 1999),
37 thereby reducing impacts, these assumptions are conservative. In addition, the use of current 38 shipping cask designs for this analysis results in conservative impact estimates because the 39 current designs are based on transporting short-cooled spent fuel (approximately 120 days out 40 of reactor). Future shipping casks would be designed to transport longer cooled fuel (greater 41 than 5 years out of reactor) and would require much less shielding to meet external dose 42 limitations. Therefore, future shipping casks are expected to have higher cargo capacities, thus 43 reducing the numbers of shipments and associated impacts.
44 The NRC staff calculated radiological impacts of transportation of spent fuel using the 45 RADTRAN 6.02 computer code (Weiner et al. 2015). Routing and population data used in 46 RADTRAN 6.02 for truck shipments were obtained from the Transportation Routing Analysis 47 Geographical Information System (TRAGIS) routing code (ORNL 2015). The population data in G-3
 
Transportation Impacts of High Burnup Fuel 1 the TRAGIS code are based on the 2010 Census. The traffic accident rates input to 2 RADTRAN 6.02 were taken from Weiner et al. (2015).
3 G.3.1. Normal Conditions 4 Normal conditions, sometimes referred to as incident free transportation, are transportation 5 activities in which shipments reach their destination without an accident occurring en route.
6 Impacts from these shipments would be from the low levels of radiation that penetrate the 7 heavily shielded spent fuel shipping cask. Radiation exposures would occur to the following 8 populations: (1) persons residing along the transportation corridors between LSCS and the 9 proposed repository location, (2) persons in vehicles traveling on the same route as a spent fuel 10 shipment, (3) persons at vehicle stops for refueling, rest, and vehicle inspections, and 11 (4) transportation crew workers (drivers). This analysis assumed that the surrogate destination 12 for the spent fuel shipments is the proposed Yucca Mountain repository site in Nevada. This 13 assumption is conservative because it tends to maximize the shipping distance from LSCS.
14 The NRC staff assumed that the capacity of a truck shipment of reactor spent fuel was 15 0.5 metric ton of uranium (MTU) per shipment, the same capacity as that used in WASH-1238 16 (AEC 1972). Exelon assumed a shipping cask capacity of 0.5 MTU per shipment in its analysis 17 (Exelon 2014a, 2015).
18 Appendix G input to RADTRAN 6.02 includes the total shipping distance between the origin and 19 destination sites and the population distributions along the routes. This information was 20 obtained by running the TRAGIS computer code (ORNL 2015) for highway routes from LSCS to 21 the proposed Yucca Mountain repository site. The resulting route characteristics information is 22 shown in Table G-1. For truck shipments, all the spent fuel is assumed to be shipped to the 23 proposed Yucca Mountain repository site over designated highway-route controlled-quantity 24 routes. In addition, TRAGIS data were used in RADTRAN 6.02 on a state-by-state basis. The 25 use of state-specific data from TRAGIS increases precision and could allow the results to be 26 presented for each state along the route between LSCS and the proposed Yucca Mountain 27 repository site, if desired.
28                                Transportation Route Information for Shipments from 29                        LSCS to the Proposed Yucca Mountain Repository Site(a)
Population Density,          Stop Time One-Way Shipping Distance, km                        persons/km2              per Trip, Reactor Site        Total    Rural      Suburban        Urban    Rural    Suburban        Urban      hr LSCS                2,871    2,418        393            60        10        334          1,649      2.5 (a) This table presents aggregated route characteristics from Exelon (2014a, 2015). Input to the RADTRAN 6.02 computer code was disaggregated to a state-by-state level.
30 Radiation doses are a function of many parameters, including vehicle speed, traffic count, dose 31 rate, packaging dimensions, number in the truck crew, stop time, and population density at 32 stops. A list of the values for these and other parameters and the sources of the information is 33 provided in Table G-2 34 For the purposes of this analysis, the transportation crew for spent fuel shipments delivered by 35 truck is assumed to consist of two drivers. Escort vehicles and drivers were considered, but 36 they were not included because their distance from the shipping cask would reduce the dose 37 rates to levels well below the dose rates experienced by the drivers and the dose rates would be G-4
 
Transportation Impacts of High Burnup Fuel 1 negligible (DOE 2002a). Stop times for refueling and rest were assumed to occur at the rate of 2 30 minutes per [[estimated NRC review hours::4 hours]] of driving time. TRAGIS outputs were used to determine the number of 3 stops. Doses to the public at truck stops have been significant contributors to the doses 4 calculated in previous RADTRAN 6.02 analyses. For this analysis, doses to the public at 5 refueling and rest stops (i.e., stop doses) are the sum of the doses to individuals located in two 6 annular rings centered at the stopped vehicle, as illustrated in Figure G-1. The inner ring 7 represents persons who may be at the truck stop at the same time as a spent fuel shipment and 8 extends 1 to 10 m from the edge of the vehicle. The outer ring represents persons who reside 9 near a truck stop and it extends from 10 to 800 m from the vehicle. This scheme is similar to 10 that used by Sprung et al. (2000). Population densities and shielding factors were also taken 11 from Sprung et al. (2000), which were based on observations in Griego et al. (1996).
12                          RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters RADTRAN 6.02 Parameter                            Input Value      Source Vehicle speed, km/hr                State Specific  Weiner et al. (2015)
Traffic countRural, vehicles/hr    State Specific  Weiner et al. (2015)
Traffic countSuburban, vehicles/hr State Specific    Weiner et al. (2015)
Traffic countUrban, vehicles/hr    State Specific  Weiner et al. (2015)
Vehicle occupancy, persons/vehicle  1.5              DOE 2002b Dose rate at 1 m from vehicle,      14              Exelon (2015a, 2015b). Approximate dose mrem/hr                                              rate at 1 m that is equivalent to the maximum dose rate allowed by Federal regulations (i.e., 10 mrem/hr at 2 m from the side of a transport vehicle)
Packaging dimensions, m              Length5.03      Exelon (2015a, 2015b)
Diameter0.88 Number of truck crew                2                AEC 1972; NRC 1977; DOE 2002b Stop time, hr/trip                  Route Specific  See Table G-1 Population density at stops,        30,000          Sprung et al. 2000. Nine persons within 10 m persons/km2                                          of vehicle. See Figure G-1.
Minimum/maximum radii of annular    1 to 10          Sprung et al. 2000 area around vehicle at stops, m Shielding factor applied to annular  1                Sprung et al. 2000 area surrounding vehicle at stops,  (no shielding) dimensionless Population density surrounding truck 340              Sprung et al. 2000 stops, persons/km2 Minimum/maximum radius of annular 10 to 800          Sprung et al. 2000 area surrounding truck stop, m Shielding factor applied to annular  0.2              Sprung et al. 2000 area surrounding truck stop, dimensionless 13 The results of these normal (incident-free) exposure calculations are shown in Table G-3 14 Population dose estimates are given for workers (truck crew members), onlookers (doses to G-5
 
Transportation Impacts of High Burnup Fuel 1 persons at stops and persons on highways exposed to the spent fuel shipment), and persons 2 along the route (persons living near the highway).
3 Shipping schedules for spent fuel generated by LSCS have not been determined. The NRC 4 staff determined that it is reasonable to calculate annual doses assuming the annual number of 5 spent fuel shipments is equivalent to the annual refueling requirements. Population doses were 6 normalized to the reference LWR in WASH-1238 (880 MWe (net)) (AEC 1972). This 7 corresponds to a 1,100-MWe LWR operating at 80-percent capacity.
8                            Figure G-1. Illustration of Truck Stop Model 9              Annual Normal (Incident-Free) Radiation Doses to Transport Workers and the 10 Public from Shipping Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 11                      Site, Normalized to Reference LWR (880 MWe (net))
Normalized Impacts, Person-rem/yr Normalized Average                Public        Public Site                                Annual Shipments      Workers    Onlookers    Along Route Reference LWR (WASH-1238)                    60          2.1            26            0.48 LSCS                                        40          1.4            17            0.32 Table S-4 Condition                          -          4                3            3 G-6
 
Transportation Impacts of High Burnup Fuel 1 The bounding cumulative doses to the exposed population given in Table S-4 are as follows:
2
* 4 person-rem per reactor-year to transport workers and 3
* 3 person-rem per reactor-year to general public (onlookers) and members of the 4            public along the route.
5 The calculated population doses to onlookers for the reference LWR and the LSCS shipments 6 exceed Table S-4 values. One of the key reasons for the higher population doses relative to 7 Table S-4 is the longer shipping distances assumed for this analysis (i.e., to a proposed 8 repository in Nevada) than the distances used in WASH-1238 (AEC 1972). WASH-1238 9 assumed that each spent fuel shipment would travel a distance of 1,000 mi, whereas the 10 shipping distances used in this SEIS were about 1,800 mi. If the shorter distance were used to 11 calculate the impacts for LSCS spent fuel shipments, the doses to onlookers would be reduced 12 by about 40 percent to 14 person-rem for the reference LWR and to 9.5 person-rem for the 13 LSCS shipments. In addition, some of the other key conservative assumptions in the analysis 14 were as follows:
15
* Use of the regulatory maximum dose rate (10 millirem (mrem) per hour at 2 m) in the 16            RADTRAN calculations. The shipping casks assumed in the environmental impact 17            statement prepared by DOE in support of the application for a geologic repository at 18            the proposed Yucca Mountain repository site (DOE 2002a) would transport spent 19            fuel that has cooled for a minimum of 5 years (see Subpart B of 10 CFR Part 961).
20            Most spent fuel would have cooled for much longer than 5 years before being 21            shipped to a possible geologic repository. Based on this, shipments from LSCS also 22            are expected to be cooled for longer than 5 years. Consequently, the estimated 23            population doses in Table G-3 could be further reduced if more realistic dose rate 24            projections are used.
25
* Use of the shipping cask capacity used in WASH-1238 (AEC 1972). The 26            WASH-1238 analyses that form the basis for Table S-4 assumed that spent fuel 27            would be shipped at least 90 days after discharge from a current LWR. The spent 28            fuel shipping casks described in WASH-1238 were designed to transport 29            90-day-cooled fuel; therefore, their shielding and containment designs must 30            accommodate this highly radioactive cargo. Shipping cask capacities assumed in 31            WASH-1238 were approximately 0.5 MTU per truck cask. DOE (2008) assumed a 32            10-year cooling period for spent fuel to be shipped to the repository. This cooling 33            period allowed DOE to increase the assumed shipping cask capacity to about 34            0.88 MTU per truck shipment of spent fuel. The NRC staff believes this is a 35            reasonable projection for future spent fuel truck shipping cask capacities. If this 36            assumption was used in this SEIS, the number of shipments of spent fuel would be 37            reduced by about 40 percent to 23 shipments with a similar reduction in incident-free 38            radiological impacts.
39
* Use of 30 minutes as the average time at a truck stop in the calculations. Many 40            stops made for actual spent fuel shipments are of short duration (i.e., 10 minutes) for 41            brief visual inspections of the cargo (e.g., checking the cask tie-downs). These stops 42            typically occur in minimally populated areas (e.g., an overpass or freeway ramp in an 43            unpopulated area). Furthermore, empirical data provided by Griego et al. 1996 44            indicate that a 30-minute duration is toward the high end of the stop time distribution.
45            Average stop times observed by Griego et al. 1996 were about 18 minutes. More 46            realistic stop times would further reduce the population doses in Table G-3 G-7
 
Transportation Impacts of High Burnup Fuel 1 A sensitivity study was performed by the NRC staff to demonstrate the effects of using more 2 realistic dose rates and stop times on the incident-free population dose calculations for 3 shipments of LSCS spent fuel. For this sensitivity study, the dose rate was reduced to 5 mrem 4 per hour, which is the approximate 50-percent confidence interval of the dose rate distribution 5 estimated by Sprung et al. (2000) for future spent fuel shipments. The number of shipments 6 was reduced to 23 shipments per year, and the stop time was reduced to 18 minutes per stop.
7 All other RADTRAN 6.02 input values were unchanged. The result is that the annual crew 8 doses, onlooker doses, and doses to persons along the route were reduced by about 80 percent 9 of the annual doses shown in Table G-3 to 0.29 person-rem, 2.7 person-rem, and 10 0.078 person-rem, respectively. If the shipping distance was reduced from 1,800 mi to 1,000 mi 11 as discussed above, the annual crew doses, onlooker doses, and doses to persons along the 12 route would be further reduced to 0.16 person-rem, 1.5 person-rem, and 0.043 person-rem, 13 respectively.
14 Radiation protection experts assume that any amount of radiation may pose some risk of 15 causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 16 exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 17 relationship between radiation dose and detriments, such as cancer induction. The National 18 Research Council (National Research Council 2006) uses the linear, no-threshold dose 19 response model as a basis for estimating the risks from low doses. This approach is accepted 20 by the NRC as a conservative method for estimating health risks from radiation exposure, 21 recognizing that the model may overestimate those risks. Based on this method, the NRC staff 22 estimated the risk to the public from radiation exposure using the nominal probability coefficient 23 for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 24 severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem.
25 The coefficient is taken from the International Commission on Radiological Protection (ICRP) 26 Publication 103 (ICRP 2007).
27 Both the National Council on Radiation Protection and Measurements (NCRP) and ICRP 28 suggest that when the collective effective dose is smaller than the reciprocal of the relevant risk 29 detriment (in other words, less than 1/0.00057, which is less than 1,754 person-rem), the risk 30 assessment should note that the most likely number of excess health effects is zero 31 (NCRP 1995; ICRP 2007). The annual public dose impacts for transporting spent fuel from 32 LSCS to the proposed Yucca Mountain repository site were estimated to be about 33 17 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 34 NCRP (1995) suggest would most likely result in zero excess health effects.
35 To place these impacts in perspective, the average U.S. resident receives about 311 mrem per 36 year effective dose equivalent from natural background radiation (i.e., exposures from cosmic 37 radiation; naturally occurring radioactive materials, such as radon; and global fallout from testing 38 of nuclear explosive devices) (NCRP 2009). Using this average effective dose, the collective 39 population dose from natural background radiation to the population along the route from LSCS 40 to the proposed Yucca Mountain repository site would be about 1.6x105 person-rem. Therefore, 41 the radiation doses from transporting irradiated fuel from LSCS to the proposed Yucca Mountain 42 repository site are minimal compared to the collective population dose to the same population 43 from exposure to natural sources of radiation. This assessment is a comparative assessment 44 for which there is no regulatory standard to base an impact level, and, again, it is provided only 45 to place the impacts in perspective.
G-8
 
Transportation Impacts of High Burnup Fuel 1 G.3.2. Radiological Impacts of Accidents 2 As discussed previously, the NRC staff used the RADTRAN 6.02 computer code to estimate the 3 impacts of transportation accidents involving spent fuel shipments. RADTRAN 6.02 considers a 4 spectrum of postulated transportation accidents, ranging from those with high frequencies and 5 low consequences (e.g., fender benders) to those with low frequencies and high 6 consequences (i.e., accidents in which the shipping container is exposed to severe mechanical 7 and thermal conditions).
8 Radionuclide inventories are important parameters in the calculation of accident risks. The 9 radionuclide inventories used in this analysis were from the Exelon ER (Exelon 2014a, 2015).
10 The spent fuel inventory used in the NRC staff analysis is listed in Table G-4 and is based on a 11 burnup of 75,000 MWd/MTU.
12 Robust shipping casks are used to transport spent fuel because of the radiation shielding and 13 accident resistance required by 10 CFR Part 71. Spent fuel shipping casks must be certified 14 Type B packaging systems, which means that they must withstand a series of severe postulated 15 accident conditions with essentially no loss of containment or shielding capability. These casks 16 also are designed with fissile material controls to ensure that the spent fuel remains subcritical 17 under normal and accident conditions. According to Sprung et al. (2000), the probability of 18 encountering accident conditions that would lead to shipping cask failure is less than 19 0.01 percent (i.e., more than 99.99 percent of all accidents would result in no release of 20 radioactive material from the shipping cask). The NRC staff assumed that shipping casks 21 approved for transportation of LSCS spent fuel would provide equivalent mechanical and 22 thermal protection of the spent fuel cargo.
23 Accident frequencies are calculated in RADTRAN 6.02 using user-specified accident rates and 24 conditional shipping cask failure probabilities. State-specific accident rates were taken from 25 Weiner et al. (2015) and used in the RADTRAN 6.02 calculations. Conditional shipping cask 26 failure probabilities (i.e., the probability of cask failure as a function of the mechanical and 27 thermal conditions applied in an accident) were taken from Sprung et al. 2000.
28 The RADTRAN 6.02 accident risk calculations were performed using the radionuclide 29 inventories (curie(s) per metric ton of uranium [Ci/MTU]) in Table G-4 multiplied by the shipping 30 cask capacity (0.5 MTU). The resulting risk estimates were then multiplied by assumed annual 31 spent fuel shipments (shipments per year) to derive estimates of the annual accident risks 32 associated with spent fuel shipments from LSCS to the proposed Yucca Mountain repository 33 site in Nevada. As was done for routine exposures, the NRC staff assumed that the numbers of 34 shipments of spent fuel per year are equivalent to the annual discharge quantities. For this 35 assessment, release fractions for current-generation LWR fuel designs (Sprung et al. 2000) 36 were used.
37 The NRC staff used RADTRAN 6.02 to calculate the population dose from the released 38 radioactive material from four of five possible exposure pathways.12 These pathways are as 39 follows:
40
* External dose from exposure to the passing cloud of radioactive material 41                (cloudshine).
42
* External dose from the radionuclides deposited on the ground by the passing plume 43                (groundshine). The NRC staffs analysis included the radiation exposure from this 12 Internal dose from ingestion of contaminated food was not considered because the NRC staff assumed evacuation and subsequent interdiction of foodstuffs following a postulated transportation accident.
G-9
 
Transportation Impacts of High Burnup Fuel 1          pathway even though the area surrounding a potential accidental release would be 2          evacuated and decontaminated, thus preventing long-term exposures from this 3          pathway.
4
* Internal dose from inhalation of airborne radioactive contaminants (inhalation).
5
* Internal dose from resuspension of radioactive materials that were deposited on the 6          ground (resuspension). The NRC staffs analysis included the radiation exposures 7          from this pathway even though evacuation and decontamination of the area 8          surrounding a potential accidental release would prevent long-term exposures.
9                            Radionuclide Inventories Used in Transportation 10                    Accident Risk Calculations for the LSCS Reactors(a)(b)
Radionuclide            Inventory Ci/Assembly          Inventory Ci/MTU Am-241                  1.87x102                    1.06x103 Am-243                  1.76x101                    9.96x101 Ce-144                  2.42x103                    1.37x104 Cm-242                  7.42                        4.20x101 Cm-243                  8.06                        4.56x101 Cm-244                  3.46x103                    1.96x104 Cs-134                  1.38x104                    7.81x104 Cs-137                  3.65x104                    2.07x105 Eu-154                  1.52x103                    8.60x103 Eu-155                  5.84x102                    3.31x103 H-3                    1.83x102                    1.04x103 Kr-85                  2.39x103                    1.35x104 Np-239                  1.76x101                    9.96x101 Pm-147                  8.70x103                    4.92x104 Pu-238                  1.43x103                    8.09x103 Pu-239                  4.37x101                    2.47x102 Pu-240                  1.22x102                    6.90x102 Pu-241                  1.81x104                    1.02x105 Ru-106                  5.22x103                    2.95x104 Sb-125                  8.88x102                    5.03x103 Sr-90                  2.41x104                    1.36x105 Sr-89                  1.33x10-6                    7.53x10-6 Y-90                    2.41x104                    1.36x105 Co-60                  5.93x102                    3.36x103 Co-58                  3.96x10-6                    2.24x10-5 Fe-59                  3.65x10-11                  2.07x10-10 G-10
 
Transportation Impacts of High Burnup Fuel Radionuclide                  Inventory Ci/Assembly              Inventory Ci/MTU Fe-55                          3.50x102                        1.98x103 Mn-54                          2.42                            1.37x101 Cr-51                          6.48x10-17                      3.67x10-16 Total                        1.45x105                        8.19x105 (a) Multiply curie per assembly or MTU by 3.7x1010 to obtain becquerel per assembly or MTU.
(b) Radionuclide  inventory is based on a burnup of 75,000 MWd/MTU.
Sources: Exelon (2014a, 2015) 1 Table G-5 presents the environmental consequences of transportation accidents when shipping 2 spent fuel from LSCS to the proposed Yucca Mountain repository site. The shipping distances 3 and population distribution information for the routes were the same as those used for the 4 normal incident-free conditions (see Section G.3.1). The results are normalized to the 5 WASH-1238 (AEC 1972) reference reactor (880-MWe) net electrical generation (1,100-MWe 6 reactor operating at 80-percent capacity) to provide a common basis for comparison to the 7 impacts listed in Table S-4. Note that the impacts (1.2x105 person-rem per year) are less than 8 the reference LWR impacts (1.8x105 person-rem per year). The transportation accident impact 9 analysis conducted by Exelon (Exelon 2014a, 2015) used methods and data that are similar to 10 those used in this SEIS. The differences are insignificant in terms of the overall results.
11                Annual Spent Fuel Transportation Accident Impacts from Shipping Spent Fuel 12  from LSCS to the Proposed Yucca Mountain Repository Site, Normalized to Reference 13                                            LWR Reactor (880 MWe (net))
Normalized Average Annual        Normalized Population Impacts, Site                                Shipments                          Person-rem/yr Reference LWR (WASH-1238)                                60                                1.8x105 LSCS                                                    40                                1.2x105 14 Radiation protection experts assume that any amount of radiation may pose some risk of 15 causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 16 exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 17 relationship between radiation dose and detriments, such as cancer induction. The National 18 Research Council (National Research Council 2006) uses the linear, no-threshold dose 19 response model as a basis for estimating the risks from low doses. This approach is accepted 20 by the NRC as a conservative method for estimating health risks from radiation exposure, 21 recognizing that the model may overestimate those risks. Based on this method, the NRC staff 22 estimated the risk to the public from radiation exposure using the nominal probability coefficient 23 for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 24 severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem.
25 The coefficient is taken from ICRP Publication 103 (ICRP 2007).
26 Both the NCRP and ICRP suggest that when the collective effective dose is smaller than the 27 reciprocal of the relevant risk detriment (in other words, less than 1/0.00057, which is less than 28 1,754 person-rem), the risk assessment should note that the most likely number of excess 29 health effects is zero (NCRP 1995; ICRP 2007). The annual accident impacts from transporting G-11
 
Transportation Impacts of High Burnup Fuel 1 spent fuel from LSCS to the proposed Yucca Mountain repository site were estimated to be 2 about 1.2x10-5 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 3 NCRP (1995) suggest would most likely result in zero excess health effects.
4 In addition, the collective population dose from natural background radiation to the population 5 along the representative routes from LSCS to the proposed Yucca Mountain repository site 6 would be about 1.6x105 person-rem. Therefore, the accident impacts from transporting spent 7 fuel to the proposed Yucca Mountain repository site are minimal compared to the collective 8 population dose to the same population from exposure to natural sources of radiation. This 9 assessment is a comparative assessment for which there is no regulatory standard to base an 10 impact level and is provided only to place the impacts in perspective.
11 G.3.3. Nonradiological Impacts of Accidents 12 A nonradiological accident is a truck accident in which the property damage, injuries, or fatalities 13 are caused by the force of the impact; no release of, or exposure to, radiological materials 14 occurs as a result of the truck accident. In WASH-1238 (AEC 1972) and NUREG-75/038 15 (NRC 1975), the NRC staff assessed the impacts of these nonradiological truck accidents that 16 may occur during the transport of fuel and waste to and from LWRs and estimated the impacts 17 from these nonradiological accidents as one fatal injury in 100 reference reactor-years and one 18 nonfatal injury in 10 reference reactor-years. Using data from the National Highway 19 Transportation Safety Administration for large trucks over the period 2009 through 2013, NRC 20 staff estimated that there would be less than one fatal injury per 100 reference reactor-years 21 and less than one nonfatal injury per 10 reference reactor-years for shipments of spent fuel from 22 LSCS to the proposed Yucca Mountain repository site. Therefore, the nonradiological impacts 23 of accidents from the transportation of LSCS spent fuel would be small.
24      Conclusions for Transportation Impacts of High Burnup Fuel 25 The NRC staff performed an independent confirmatory analysis of the impacts under normal 26 operating and accident conditions of transporting irradiated fuel from LSCS to the proposed 27 Yucca Mountain repository site. To make comparisons to Table S-4, the environmental impacts 28 were adjusted (i.e., normalized) to the environmental impacts associated with the reference 29 LWR in WASH-1238 (AEC 1972) by multiplying the LSCS impact estimates by the ratio of the 30 total electric output for the reference reactor to the electric output of the LSCS reactors.
31 Because of the conservative approaches and data used to calculate impacts, the NRC staff 32 does not expect the actual environmental effects to exceed those calculated in this SEIS. Thus, 33 the NRC staff concludes that the environmental impacts of the transportation of irradiated fuel 34 from LSCS would be SMALL and would be consistent with the environmental impacts 35 associated with the transportation of fuel and radioactive wastes to and from current-generation 36 reactors presented in Table S-4 of 10 CFR 51.52.
37 The NRC staff concludes that transportation impacts are roughly proportional to the distance 38 from LSCS to the repository sitein this case Illinois to Nevada. The distance from LSCS to 39 any new planned repository in the contiguous United States would be no more than double the 40 distance from LSCS to the proposed Yucca Mountain repository site. Doubling the 41 environmental impact estimates from the transportation of spent reactor fuel, as presented in 42 this section, would provide a reasonable bounding estimate of the impacts to meet the 43 requirements of the National Environmental Policy Act of 1969, as amended (42 U.S.C. 4321 44 et seq.). The NRC staff concludes that the environmental impacts of these doubled estimates 45 would not be significant and, therefore, would still be SMALL.
G-12
 
Transportation Impacts of High Burnup Fuel 1      References 2 10 CFR Part 50. 2012. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic 3 licensing of production and utilization facilities.
4 10 CFR Part 51. 2011. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 5 protection regulations for domestic licensing and related regulatory functions.
6 10 CFR Part 71. 2011. Code of Federal Regulations, Title 10, Energy, Part 71, Packaging and 7 transportation of radioactive material.
8 10 CFR Part 961. 2002. Code of Federal Regulations, Title 10, Energy, Part 961, Standard 9 contract for disposal of spent nuclear fuel and/or high-level radioactive waste.
10 65 FR 794. U.S. Nuclear Regulatory Commission. FirstEnergy Nuclear Operating Company, 11 Davis-Besse Nuclear Power Station, Unit 1; Environmental Assessment and Finding of No 12 Significant Impact. Federal Register (65):794. January 6, 2000.
13 [AEC] U.S. Atomic Energy Commission. 1972. Environmental Survey of Transportation of 14 Radioactive Materials to and from Nuclear Power Plants. Washington, DC: AEC.
15 WASH-1238. December 2002. ADAMS No. ML14092A626.
16 [DOE] U.S. Department of Energy. 2002a. Final Environmental Impact Statement for a 17 Geologic Repository for the Disposal of Spent Nuclear Fuel and High-Level Radioactive Waste 18 at Yucca Mountain, Nye County, Nevada. Washington, DC: DOE. DOE/EIS-0250, Office of 19 Civilian Radioactive Waste Management. February 2002. Available at 20 <http://energy.gov/nepa/downloads/eis-0250-final-environmental-impact-statement> (accessed 21 5 October 2015).
22 [DOE] U.S. Department of Energy. 2002b. A Resource Handbook on DOE Transportation Risk 23 Assessment. Washington, DC: DOE. DOE/EM/NTP/HB-01. July 2002. ADAMS 24 No. ML12192A286.
25 [DOE] U.S. Department of Energy. 2008. Final Supplemental Environmental Impact 26 Statement for a Geologic Repository for the Disposal of Spent Nuclear Fuel and High-Level 27 Radioactive Waste at Yucca Mountain, Nye County, Nevada. Washington, DC: DOE.
28 DOE/EIS-0250F-S1. June 2008. Available at http://energy.gov/downloads/final-supplemental-29 environmental-impact-statement-geologic-repository-disposal-spent-2 (accessed 30 5 October 2015).
31 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 32 Operating License Renewal Stage, LaSalle County Station. Chicago, Illinois: Exelon.
33 December 9, 2014. ADAMS Nos. ML14343A883 and ML14343A897.
34 [Exelon] Exelon Generation Company, LLC. 2014b. License Renewal Application, LaSalle 35 County Station, Units 1 and 2. Chicago, Illinois: Exelon. December 9, 2014.
36 ADAMS No. ML14343A849.
37 [Exelon] Exelon Generation Company, LLC. 2015. LaSalle County Station, Units 1 and 2 38 Revised Response to Request for Additional Information (RAI) #TR-09 Re License Renewal 39 Application, Environmental Review. Chicago, Illinois: Exelon. August 28, 2015. ADAMS 40 No. ML15240A002.
41 Griego, NR, Smith JD, Neuhauser KS. 1996. Investigation of RADTRAN Stop Model Input 42 Parameters for Truck Stops. Albuquerque, New Mexico: Sandia National Laboratories.
43 March 13, 1996. ADAMS No. ML14111A188.
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Transportation Impacts of High Burnup Fuel 1 [ICRP] International Commission on Radiological Protection. 2007. The 2007 2 Recommendations of the International Commission on Radiological Protection.
3 ICRP Publication 103, Elsevier, Maryland Heights, Missouri. Available at 4 <http://www.sciencedirect.com/science/journal/01466453/37/2-4> (accessed 9 October 2015).
5 National Environmental Policy Act of 1969, as amended. 42 U.S.C. &sect;4321 et seq.
6 National Research Council. 2006. Health Risks from Exposure to Low Levels of Ionizing 7 Radiation BEIR VII Phase 2. National Academies Press, Washington, DC. Available at 8 <http://www.nap.edu/openbook.php?record_id=11340&page=1> (accessed 9 October 2015).
9 [NCRP] National Council on Radiation Protection and Measurements. 1995. Principles and 10 Applications of Collective Dose in Radiation Protection. NCRP Report No. 121, Bethesda, 11 Maryland. Available at <http://www.ncrppublications.org/Reports/121>.
12 [NCRP] National Council on Radiation Protection and Measurements. 2009. Ionizing Radiation 13 Exposure of the Population of the United States. NCRP Report No. 160, Bethesda, Maryland.
14 Available at <http://app.knovel.com/web/toc.v/cid:kpIREPUS05> (accessed 9 October 2015).
15 [NRC] U.S. Nuclear Regulatory Commission. 1975. Environmental Survey of Transportation of 16 Radioactive Materials to and from Nuclear Power Plants, Supplement 1. Washington, DC:
17 NRC. NUREG-75/038. April 30, 1975. ADAMS No. ML14091A176.
18 [NRC] U.S. Nuclear Regulatory Commission. 1977. Final Environmental Statement on the 19 Transportation of Radioactive Material by Air and Other Modes. Washington, DC: NRC.
20 NUREG-0170, Volume 1. December 31, 1977. ADAMS No. ML12192A283.
21 [NRC] U.S. Nuclear Regulatory Commission. 1999. Generic Environmental Impact Statement 22 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Volume 1, 23 Addendum 1. August 31, 1999. ADAMS No. ML040690720.
24 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 25 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Revision 1, 26 Volumes 1, 2, and 3. June 19, 2013. ADAMS No. ML13107A023.
27 [ORNL] Oak Ridge National Laboratory. 2015. WebTRAGIS, v.6. Transportation Routing 28 Analysis GIS. Available at <https://webtragis.ornl.gov/tragis/app/login> (accessed 29 1 August 2015).
30 Sprung J, Ammerman DJ, Breivik NL, Dukart RJ, Kanipe FL, Koski JA, Mills GS, Neuhauser KS, 31 H.D. Radloff, Weiner RF, and Yoshimura HR. 2000. Reexamination of Spent Fuel Shipment 32 Risk Estimates. Albuquerque, NM: Sandia National Laboratories. NUREG/CR-6672.
33 March 31, 2000. ADAMS No. ML003698324.
34 Weiner RF, Hinojosa D, Heames TJ, and Farnum CO. 2015. RADTRAN 6/RadCat 6 User 35 Guide.
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NUREG-1437    Generic Environmental Impact Statement for License Renewal of Nuclear Plants February 2016 Supplement 57                Regarding LaSalle County Station, Units 1 and 2 Draft
 
NUREG-1437 Supplement 57 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft Report for Comment Office of Nuclear Reactor Regulation
 
AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material                                      Non-NRC Reference Material As of November 1999, you may electronically access          Documents available from public and special technical NUREG-series publications and other NRC records at          libraries include all open literature items, such as books, NRCs Library at www.nrc.gov/reading-rm.html. Publicly      journal articles, transactions, Federal Register notices, released records include, to name a few, NUREG-series        Federal and State legislation, and congressional reports.
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NUREG-1437 Supplement 57 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft Report for Comment Manuscript Completed: February 2016 Date Published: February 2016 Office of Nuclear Reactor Regulation
 
1 Proposed Action  Issuance of renewed operating licenses NPF-11 and NPF-18 for LaSalle 2                  County Station, Units 1 and 2 (LSCS), in LaSalle County, Illinois 3 Type of Statement Draft Supplemental Environmental Impact Statement 4 Agency Contact    Mr. David Drucker 5                  U.S. Nuclear Regulatory Commission (NRC) 6                  Office of Nuclear Reactor Regulation 7                  Mail Stop O-11F1 8                  Washington, DC 20555-0001 9                  Phone: 1-800-368-5642, extension 6223 10                  E-mail: david.drucker@nrc.gov 11 Comments          Any interested party may submit comments on this draft supplemental 12                  environmental impact statement. Please specify NUREG-1437, 13                  Supplement 57, draft, in your comments, and send them by the end of the 14                  comment period specified in the Federal Register notice announcing the 15                  availability of this report. Comments may be submitted electronically by 16                  searching for docket ID NRC-2014-0268 at the Federal rulemaking Web 17                  site, http://www.regulations.gov. Comments also may be mailed to the 18                  following address:
19                  Chief, Rules, Announcements, and Directives Branch 20                  Division of Administrative Services 21                  Office of Administration 22                  Mail Stop: OWFN-12 H08 23                  U.S. Nuclear Regulatory Commission 24                  Washington, DC 20555-0001 25                  Please be aware that any comments that you submit to the NRC will be 26                  considered a public record and entered into the Agencywide Documents 27                  Access and Management System. Do not provide information you would 28                  not want to be publicly available.
 
1                                          COVER SHEET 2 Responsible Agency: U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor 3 Regulation. There are no cooperating agencies involved in the preparation of this document.
4 Title: Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 5 Supplement 57, Regarding LaSalle County Station, Units 1 and 2, Draft Report for Comment 6 (NUREG-1437). LaSalle County Station is located in LaSalle County, Illinois.
7 For additional information or copies of this document contact:
8                                      Division of License Renewal 9                                U.S. Nuclear Regulatory Commission 10                                Office of Nuclear Reactor Regulation 11                                            Mail Stop O-11F1 12                                          11555 Rockville Pike 13                                      Rockville, Maryland 20852 14                              Phone: 1-800-368-5642, extension 6223 15                                    Email: david.drucker@nrc.gov 16                                            ABSTRACT 17 This supplemental environmental impact statement (SEIS) has been prepared in response to an 18 application submitted by Exelon Generation Company, LLC (Exelon), to renew the operating 19 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years.
20 This SEIS includes the preliminary analysis that evaluates the environmental impacts of the 21 proposed action and alternatives to the proposed action. Alternatives considered include:
22 (1) new nuclear power generation, (2) coal-integrated gasification combined-cycle, (3) natural 23 gas combined-cycle (NGCC), (4) a combination of NGCC, wind, and solar generation, 24 (5) purchased power, and (6) the no-action alternative (i.e., no renewal of the license).
25 The U.S. Nuclear Regulatory Commission (NRC) staffs preliminary recommendation is that the 26 adverse environmental impacts of license renewal for LSCS are not so great that preserving the 27 option of license renewal for energy-planning decisionmakers would be unreasonable. The 28 NRC staff based its recommendation on the following factors:
29
* the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic Environmental 30              Impact Statement for License Renewal of Nuclear Plants; 31
* the Environmental Report submitted by Exelon; 32
* the NRC staffs consultation with Federal, State, local, and Tribal Government 33              agencies; 34
* the NRC staffs independent environmental review; and 35
* the NRC staffs consideration of public comments received during the scoping 36              process.
iii
 
1                                            TABLE OF CONTENTS 2 ABSTRACT .............................................................................................................................. iii 3 TABLE OF CONTENTS ............................................................................................................ v 4 FIGURES ................................................................................................................................. xv 5 TABLES ................................................................................................................................ xvii 6 EXECUTIVE
 
==SUMMARY==
........................................................................................................ xxi 7 ABBREVIATIONS AND ACRONYMS ..................................................................................xxvii 8
 
==1.0  INTRODUCTION==
.......................................................................................................... 1-1 9      1.1      Proposed Federal Action.................................................................................. 1-1 10      1.2      Purpose and Need for Proposed Federal Action .............................................. 1-1 11      1.3      Major Environmental Review Milestones .......................................................... 1-1 12      1.4      Generic Environmental Impact Statement ........................................................ 1-2 13      1.5      Supplemental Environmental Impact Statement ............................................... 1-4 14      1.6      Decisions to Be Supported by the SEIS ........................................................... 1-5 15      1.7      Cooperating Agencies ...................................................................................... 1-5 16      1.8      Consultations ................................................................................................... 1-5 17      1.9      Correspondence .............................................................................................. 1-6 18      1.10    Status of Compliance ....................................................................................... 1-6 19      1.11    Related Federal and State Activities ................................................................ 1-6 20      1.12    References ...................................................................................................... 1-7 21 2.0  ALTERNATIVES INCLUDING THE PROPOSED ACTION .......................................... 2-1 22      2.1      Proposed Action .............................................................................................. 2-1 23                2.1.1          Plant Operations during the License Renewal Term......................... 2-1 24                2.1.2          Refurbishment and Other Activities Associated with License 25                                Renewal ........................................................................................... 2-2 26                2.1.3          Termination of Nuclear Power Plant Operations and 27                                Decommissioning after the License Renewal Term .......................... 2-2 28      2.2      Alternatives ...................................................................................................... 2-3 29                2.2.1          No-Action Alternative ....................................................................... 2-3 30                2.2.2          Replacement Power Alternatives ..................................................... 2-4 31                                2.2.2.1            New Nuclear Alternative ................................................ 2-9 32                                2.2.2.2            IGCC Alternative ......................................................... 2-11 33                                2.2.2.3            NGCC Alternative ........................................................ 2-13 34                                2.2.2.4            Combination Alternative (NGCC, Wind, and Solar)...... 2-13 35                                2.2.2.5            Purchased Power Alternative ...................................... 2-16 36      2.3      Alternatives Considered but Dismissed .......................................................... 2-17 37                2.3.1          Energy Conservation and Energy Efficiency .................................. 2-17 38                2.3.2          Solar .............................................................................................. 2-17 v
 
Table of Contents 1              2.3.3    Wind .............................................................................................. 2-18 2                        2.3.3.1          Offshore Wind ............................................................. 2-18 3                        2.3.3.2          Wind Power with Storage ............................................ 2-19 4                        2.3.3.3          Conclusion .................................................................. 2-19 5              2.3.4    Biomass ......................................................................................... 2-19 6              2.3.5    Hydroelectric .................................................................................. 2-20 7              2.3.6    Wave and Ocean Energy ............................................................... 2-20 8              2.3.7    Fuel Cells ....................................................................................... 2-21 9              2.3.8    Delayed Retirement ....................................................................... 2-21 10              2.3.9    Geothermal .................................................................................... 2-22 11              2.3.10    Municipal Solid Waste .................................................................... 2-22 12              2.3.11    Petroleum ...................................................................................... 2-23 13              2.3.12    Supercritical Pulverized Coal ......................................................... 2-23 14        2.4    Comparison of Alternatives ............................................................................ 2-23 15        2.5    References .................................................................................................... 2-27 16 3.0  AFFECTED ENVIRONMENT ....................................................................................... 3-1 17        3.1    Description of Nuclear Power Plant Facility and Operation .............................. 3-1 18              3.1.1    External Appearance and Setting ..................................................... 3-1 19              3.1.2    Nuclear Reactor Systems................................................................. 3-6 20              3.1.3    Cooling and Auxiliary Water Systems .............................................. 3-6 21              3.1.4    Radioactive Waste Management Systems ..................................... 3-13 22                        3.1.4.1          Radioactive Liquid Waste Management ...................... 3-13 23                        3.1.4.2          Radioactive Gaseous Waste Management .................. 3-15 24                        3.1.4.3          Radioactive Solid Waste Management ........................ 3-16 25                        3.1.4.4          Radioactive Waste Storage ......................................... 3-17 26                        3.1.4.5          Radiological Environmental Monitoring Program ......... 3-17 27              3.1.5    Nonradioactive Waste Management Systems ................................ 3-18 28              3.1.6    Utility and Transportation Infrastructure.......................................... 3-18 29                        3.1.6.1          Electricity ..................................................................... 3-19 30                        3.1.6.2          Fuel ............................................................................. 3-19 31                        3.1.6.3          Water .......................................................................... 3-19 32                        3.1.6.4          Transportation Systems............................................... 3-19 33                        3.1.6.5          Power Transmission Systems ..................................... 3-20 34              3.1.7    Nuclear Power Plant Operations and Maintenance ........................ 3-20 35        3.2    Land Use and Visual Resources .................................................................... 3-21 36              3.2.1    Land Use ....................................................................................... 3-21 37                        3.2.1.1          Onsite Land Use ......................................................... 3-21 38                        3.2.1.2          Coastal Zone ............................................................... 3-22 39                        3.2.1.3          Offsite Land Use ......................................................... 3-22 40              3.2.2    Visual Resources ........................................................................... 3-24 41        3.3    Meteorology, Air Quality, and Noise ............................................................... 3-24 vi
 
Table of Contents 1    3.3.1      Meteorology and Climatology ......................................................... 3-24 2    3.3.2      Air Quality ...................................................................................... 3-25 3    3.3.3      Noise ............................................................................................. 3-28 4 3.4 Geologic Environment .................................................................................... 3-29 5    3.4.1      Physiography and Geology ............................................................ 3-29 6    3.4.2      Soils ............................................................................................... 3-30 7    3.4.3      Seismic Setting .............................................................................. 3-34 8 3.5 Water Resources ........................................................................................... 3-35 9    3.5.1      Surface Water Resources .............................................................. 3-35 10                3.5.1.1          Surface Water Hydrology ............................................ 3-35 11                3.5.1.2          Surface Water Use ...................................................... 3-39 12                3.5.1.3          Surface Water Quality and Effluents ............................ 3-41 13    3.5.2      Groundwater Resources ................................................................ 3-46 14                3.5.2.1          Site Description and Hydrogeology ............................. 3-46 15                3.5.2.2          Groundwater Use ........................................................ 3-48 16                3.5.2.3          Groundwater Quality ................................................... 3-51 17 3.6 Terrestrial Resources ..................................................................................... 3-52 18    3.6.1      LSCS Ecoregion ............................................................................ 3-52 19    3.6.2      LSCS Site Surveys, Studies, and Reports...................................... 3-53 20    3.6.3      LSCS Site ...................................................................................... 3-54 21                3.6.3.1          Vegetation ................................................................... 3-54 22                3.6.3.2          Wildlife ........................................................................ 3-55 23    3.6.4      LSCS Wildlife Management Plan ................................................... 3-55 24    3.6.5      Important Species and Habitats ..................................................... 3-56 25                3.6.5.1          Important Species ....................................................... 3-56 26                3.6.5.2          Important Habitats ....................................................... 3-58 27    3.6.6      Invasive and Non-Native Species................................................... 3-59 28 3.7 Aquatic Resources ......................................................................................... 3-59 29    3.7.1      Illinois River ................................................................................... 3-59 30                3.7.1.1          Aquatic Communities in the Illinois River ..................... 3-60 31    3.7.2      LSCS Cooling Pond ....................................................................... 3-67 32                3.7.2.1          Aquatic Community in the Cooling Pond ..................... 3-68 33                3.7.2.2          Cooling Pond Fish Kill Events...................................... 3-69 34    3.7.3      Important Species and Habitats ..................................................... 3-69 35                3.7.3.1          State-Listed Species ................................................... 3-69 36                3.7.3.2          Important Habitats ....................................................... 3-72 37    3.7.4      Non-Native Species ....................................................................... 3-72 38 3.8 Federally Protected Species and Habitats...................................................... 3-73 39    3.8.1      Action Area .................................................................................... 3-73 40    3.8.2      Federally Protected Species and Habitats Considered................... 3-74 41 3.9 Historic and Cultural Resources ..................................................................... 3-79 vii
 
Table of Contents 1              3.9.1      Cultural Background....................................................................... 3-80 2              3.9.2      Historic and Cultural Resources ..................................................... 3-82 3        3.10  Socioeconomics ............................................................................................. 3-82 4              3.10.1    Power Plant Employment and Expenditures .................................. 3-83 5              3.10.2    Regional Economic Characteristics ................................................ 3-83 6                          3.10.2.1          Employment and Income ............................................. 3-84 7                          3.10.2.2          Unemployment ............................................................ 3-86 8              3.10.3    Demographic Characteristics ......................................................... 3-86 9                          3.10.3.1          Transient Population ................................................... 3-88 10                          3.10.3.2          Migrant Farm Workers ................................................. 3-89 11              3.10.4    Housing and Community Services ................................................. 3-90 12                          3.10.4.1          Housing ....................................................................... 3-91 13                          3.10.4.2          Education .................................................................... 3-91 14                          3.10.4.3          Public Water Supply .................................................... 3-91 15              3.10.5    Tax Revenues ................................................................................ 3-93 16              3.10.6    Local Transportation ...................................................................... 3-95 17        3.11  Human Health ................................................................................................ 3-96 18              3.11.1    Radiological Exposure and Risk ..................................................... 3-96 19              3.11.2    Chemical Hazards .......................................................................... 3-97 20              3.11.3    Microbiological Hazards ................................................................. 3-97 21                          3.11.3.1          Thermophilic Microorganisms of Concern ................... 3-98 22                          3.11.3.2          Prevalence of Waterborne Diseases Associated 23                                            with Recreational Waters............................................. 3-99 24              3.11.4    Electromagnetic Fields ................................................................... 3-99 25              3.11.5    Other Hazards.............................................................................. 3-100 26        3.12  Environmental Justice .................................................................................. 3-101 27              3.12.1    Minority Population ...................................................................... 3-102 28              3.12.2    Low-Income Population................................................................ 3-102 29        3.13  Waste Management and Pollution Prevention.............................................. 3-106 30              3.13.1    Radioactive Waste ....................................................................... 3-106 31              3.13.2    Nonradioactive Waste .................................................................. 3-106 32        3.14  References .................................................................................................. 3-106 33 4.0  ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS ........................ 4-1 34        4.1    Introduction ...................................................................................................... 4-1 35        4.2    Land Use and Visual Resources ...................................................................... 4-1 36              4.2.1      Proposed Action............................................................................... 4-1 37              4.2.2      No-Action Alternative ....................................................................... 4-2 38                          4.2.2.1          Land Use ....................................................................... 4-2 39                          4.2.2.2          Visual Resources .......................................................... 4-2 40              4.2.3      New Nuclear Alternative ................................................................... 4-3 41                          4.2.3.1          Land Use ....................................................................... 4-3 viii
 
Table of Contents 1                4.2.3.2    Visual Resources .......................................................... 4-3 2    4.2.4      IGCC Alternative .............................................................................. 4-3 3                4.2.4.1    Land Use ....................................................................... 4-3 4                4.2.4.2    Visual Resources .......................................................... 4-4 5    4.2.5      Natural Gas Combined-Cycle Alternative ......................................... 4-4 6                4.2.5.1    Land Use ....................................................................... 4-4 7                4.2.5.2    Visual Resources .......................................................... 4-4 8    4.2.6      Combination Alternative (NGCC, Wind, Solar) ................................. 4-5 9                4.2.6.1    Land Use ....................................................................... 4-5 10                4.2.6.2    Visual Resources .......................................................... 4-5 11    4.2.7      Purchased Power Alternative ........................................................... 4-6 12                4.2.7.1    Land Use ....................................................................... 4-6 13                4.2.7.2    Visual Resources .......................................................... 4-6 14 4.3 Air Quality and Noise ....................................................................................... 4-6 15    4.3.1      Proposed Action............................................................................... 4-6 16                4.3.1.1    Air Quality ..................................................................... 4-6 17                4.3.1.2    Noise ............................................................................. 4-7 18    4.3.2      No-Action Alternative ....................................................................... 4-7 19                4.3.2.1    Air Quality ..................................................................... 4-7 20                4.3.2.2    Noise ............................................................................. 4-7 21    4.3.3      New Nuclear Alternative ................................................................... 4-7 22                4.3.3.1    Air Quality ..................................................................... 4-7 23                4.3.3.2    Noise ............................................................................. 4-9 24    4.3.4      IGCC Alternative ............................................................................ 4-10 25                4.3.4.1    Air Quality ................................................................... 4-10 26                4.3.4.2    Noise ........................................................................... 4-13 27    4.3.5      NGCC Alternative .......................................................................... 4-13 28                4.3.5.1    Air Quality ................................................................... 4-13 29                4.3.5.2    Noise ........................................................................... 4-15 30    4.3.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-16 31                4.3.6.1    Air Quality ................................................................... 4-16 32                4.3.6.2    Noise ........................................................................... 4-18 33    4.3.7      Purchased Power Alternative ......................................................... 4-19 34                4.3.7.1    Air Quality ................................................................... 4-19 35                4.3.7.2    Noise ........................................................................... 4-19 36 4.4 Geologic Environment .................................................................................... 4-20 37    4.4.1      Proposed Action............................................................................. 4-20 38    4.4.2      No-Action Alternative ..................................................................... 4-20 39    4.4.3      New Nuclear Alternative ................................................................. 4-20 40    4.4.4      IGCC Alternative ............................................................................ 4-21 41    4.4.5      NGCC Alternative .......................................................................... 4-21 ix
 
Table of Contents 1              4.4.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-21 2              4.4.7      Purchased Power Alternative ......................................................... 4-21 3        4.5    Water Resources ........................................................................................... 4-21 4              4.5.1      Proposed Action............................................................................. 4-22 5                          4.5.1.1    Surface Water Resources ........................................... 4-22 6                          4.5.1.2    Groundwater Resources.............................................. 4-24 7              4.5.2      No-Action Alternative ..................................................................... 4-26 8                          4.5.2.1    Surface Water Resources ........................................... 4-26 9                          4.5.2.2    Groundwater Resources.............................................. 4-26 10              4.5.3      New Nuclear Alternative ................................................................. 4-26 11                          4.5.3.1    Surface Water Resources ........................................... 4-26 12                          4.5.3.2    Groundwater Resources.............................................. 4-27 13              4.5.4      IGCC Alternative ............................................................................ 4-27 14                          4.5.4.1    Surface Water Resources ........................................... 4-27 15                          4.5.4.2    Groundwater Resources.............................................. 4-28 16              4.5.5      NGCC Alternative .......................................................................... 4-28 17                          4.5.5.1    Surface Water Resources ........................................... 4-28 18                          4.5.5.2    Groundwater Resources.............................................. 4-29 19              4.5.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-29 20                          4.5.6.1    Surface Water Resources ........................................... 4-29 21                          4.5.6.2    Groundwater Resources.............................................. 4-30 22              4.5.7      Purchased Power Alternative ......................................................... 4-30 23                          4.5.7.1    Surface Water Resources ........................................... 4-30 24                          4.5.7.2    Groundwater Resources.............................................. 4-30 25        4.6    Terrestrial Resources ..................................................................................... 4-30 26              4.6.1      Proposed Action............................................................................. 4-31 27                          4.6.1.1    Generic GEIS Issues ................................................... 4-31 28                          4.6.1.2    Effects on Terrestrial Resources (Non-Cooling 29                                      System Impacts) ......................................................... 4-31 30                          4.6.1.3    Water Use Conflicts with Terrestrial Resources ........... 4-33 31              4.6.2      No-Action Alternative ..................................................................... 4-34 32              4.6.3      New Nuclear Alternative ................................................................. 4-34 33              4.6.4      IGCC Alternative ............................................................................ 4-35 34              4.6.5      NGCC Alternative .......................................................................... 4-35 35              4.6.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-36 36              4.6.7      Purchased Power Alternative ......................................................... 4-37 37        4.7    Aquatic Resources ......................................................................................... 4-37 38              4.7.1      Proposed Action............................................................................. 4-37 39                          4.7.1.1    GEIS Category 1 Issues .............................................. 4-38 40                          4.7.1.2    Impingement and Entrainment of Aquatic 41                                      Organisms ................................................................... 4-38 x
 
Table of Contents 1                4.7.1.3      Thermal Impacts on Aquatic Organisms ...................... 4-45 2                4.7.1.4      Water Use Conflicts with Aquatic Resources ............... 4-52 3      4.7.2      No-Action Alternative ..................................................................... 4-52 4      4.7.3      New Nuclear Alternative ................................................................. 4-53 5      4.7.4      IGCC Alternative ............................................................................ 4-53 6      4.7.5      NGCC Alternative .......................................................................... 4-54 7      4.7.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-54 8      4.7.7      Purchased Power Alternative ......................................................... 4-54 9 4.8  Special Status Species and Habitats.............................................................. 4-55 10      4.8.1      Proposed Action............................................................................. 4-55 11      4.8.2      No-Action Alternative ..................................................................... 4-57 12      4.8.3      New Nuclear Alternative ................................................................. 4-57 13      4.8.4      IGCC Alternative ............................................................................ 4-58 14      4.8.5      NGCC Alternative .......................................................................... 4-58 15      4.8.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-59 16      4.8.7      Purchased Power Alternative ......................................................... 4-59 17 4.9  Historic and Cultural Resources ..................................................................... 4-59 18      4.9.1      Proposed Action............................................................................. 4-60 19      4.9.2      No-Action Alternative ..................................................................... 4-62 20      4.9.3      New Nuclear Alternative ................................................................. 4-62 21      4.9.4      IGCC Alternative ............................................................................ 4-62 22      4.9.5      NGCC Alternative .......................................................................... 4-63 23      4.9.6      Combination Alternative (NGCC, Wind, Solar) ............................... 4-63 24      4.9.7      Purchased Power Alternative ......................................................... 4-64 25 4.10 Socioeconomics ............................................................................................. 4-64 26      4.10.1    Proposed Action............................................................................. 4-65 27      4.10.2    No-Action Alternative ..................................................................... 4-65 28                4.10.2.1    Socioeconomics .......................................................... 4-65 29                4.10.2.2    Transportation ............................................................. 4-66 30      4.10.3    New Nuclear Alternative ................................................................. 4-66 31                4.10.3.1    Socioeconomics .......................................................... 4-66 32                4.10.3.2    Transportation ............................................................. 4-67 33      4.10.4    IGCC Alternative ............................................................................ 4-67 34                4.10.4.1    Socioeconomics .......................................................... 4-67 35                4.10.4.2    Transportation ............................................................. 4-68 36      4.10.5    NGCC Alternative .......................................................................... 4-69 37                4.10.5.1    Socioeconomics .......................................................... 4-69 38                4.10.5.2    Transportation ............................................................. 4-69 39      4.10.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-70 40                4.10.6.1    Socioeconomics .......................................................... 4-70 41                4.10.6.2    Transportation ............................................................. 4-71 xi
 
Table of Contents 1              4.10.7    Purchased Power Alternative ......................................................... 4-71 2                        4.10.7.1      Socioeconomics .......................................................... 4-71 3                        4.10.7.2      Transportation ............................................................. 4-71 4        4.11  Human Health ................................................................................................ 4-72 5              4.11.1    Proposed Action............................................................................. 4-72 6                        4.11.1.1      Normal Operating Conditions ...................................... 4-72 7                        4.11.1.2      Environmental Impacts of Postulated Accidents .......... 4-75 8              4.11.2    No-Action Alternative ..................................................................... 4-88 9              4.11.3    New Nuclear Alternative ................................................................. 4-89 10              4.11.4    IGCC Alternative ............................................................................ 4-89 11              4.11.5    NGCC Alternative .......................................................................... 4-90 12              4.11.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-90 13              4.11.7    Purchased Power Alternative ......................................................... 4-90 14        4.12  Environmental Justice .................................................................................... 4-91 15              4.12.1    Proposed Action............................................................................. 4-91 16              4.12.2    No-Action Alternative ..................................................................... 4-93 17              4.12.3    New Nuclear Alternative ................................................................. 4-93 18              4.12.4    IGCC Alternative ............................................................................ 4-94 19              4.12.5    NGCC Alternative .......................................................................... 4-95 20              4.12.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-95 21              4.12.7    Purchased Power Alternative ......................................................... 4-96 22        4.13  Waste Management ....................................................................................... 4-97 23              4.13.1    Proposed Action............................................................................. 4-97 24              4.13.2    No-Action Alternative ..................................................................... 4-98 25              4.13.3    New Nuclear Alternative ................................................................. 4-98 26              4.13.4    IGCC Alternative ............................................................................ 4-98 27              4.13.5    NGCC Alternative .......................................................................... 4-99 28              4.13.6    Combination Alternative (NGCC, Wind, Solar) ............................... 4-99 29              4.13.7    Purchased Power Alternative ......................................................... 4-99 30        4.14  Evaluation of New and Potentially Significant Information .............................. 4-99 31        4.15  Impacts Common to All Alternatives............................................................. 4-100 32              4.15.1    Fuel Cycles .................................................................................. 4-100 33                        4.15.1.1      Uranium Fuel Cycle ................................................... 4-101 34                        4.15.1.2      Replacement Power Plant Fuel Cycles...................... 4-102 35              4.15.2    Terminating Power Plant Operations and Decommissioning ........ 4-102 36                        4.15.2.1      Existing Nuclear Power Plant .................................... 4-103 37                        4.15.2.2      Replacement Power Plants ....................................... 4-103 38              4.15.3    Greenhouse Gas Emissions and Climate Change ....................... 4-104 39                        4.15.3.1      Greenhouse Gas Emissions from the Proposed 40                                        Project and Alternatives............................................. 4-104 41                        4.15.3.2      Climate Change Impacts to Resource Areas ............. 4-107 xii
 
Table of Contents 1      4.16  Cumulative Impacts of the Proposed Action ................................................. 4-113 2            4.16.1          Air Quality and Noise ................................................................... 4-113 3                            4.16.1.1          Air Quality ................................................................. 4-114 4                            4.16.1.2          Noise ......................................................................... 4-115 5            4.16.2          Geology and Soils ........................................................................ 4-115 6            4.16.3          Water Resources ......................................................................... 4-116 7                            4.16.3.1          Surface Water Resources ......................................... 4-116 8                            4.16.3.2          Groundwater Resources............................................ 4-120 9            4.16.4          Terrestrial Resources ................................................................... 4-121 10            4.16.5          Aquatic Resources ....................................................................... 4-124 11                            4.16.5.1          Energy Development ................................................. 4-124 12                            4.16.5.2          Future Urbanization and Transportation 13                                              Development ............................................................. 4-125 14                            4.16.5.3          Wildlife Preserves, Parks, and Recreational Areas .... 4-125 15                            4.16.5.4          Illinois Wildlife Conservation Plan .............................. 4-125 16                            4.16.5.5          Conclusion ................................................................ 4-125 17            4.16.6          Historic and Cultural Resources ................................................... 4-126 18            4.16.7          Socioeconomics ........................................................................... 4-126 19            4.16.8          Human Health .............................................................................. 4-127 20            4.16.9          Environmental Justice .................................................................. 4-127 21            4.16.10 Waste Management ..................................................................... 4-128 22            4.16.11 Global Climate Change ................................................................ 4-129 23            4.16.12 Summary of Cumulative Impacts.................................................. 4-130 24      4.17  Resource Commitments............................................................................... 4-132 25            4.17.1          Unavoidable Adverse Environmental Impacts .............................. 4-132 26            4.17.2          Short-Term Versus Long-Term Productivity ................................. 4-133 27            4.17.3          Irreversible and Irretrievable Commitments of Resources ............ 4-133 28      4.18  References .................................................................................................. 4-134 29
 
==5.0 CONCLUSION==
............................................................................................................. 5-1 30      5.1  Environmental Impacts of License Renewal ..................................................... 5-1 31      5.2  Comparison of Alternatives .............................................................................. 5-1 32      5.3  Recommendation ............................................................................................. 5-1 33 6.0 LIST OF PREPARERS ................................................................................................ 6-1 34 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES 35      OF THIS SEIS ARE SENT .......................................................................................... 7-1 36 8.0 INDEX .......................................................................................................................... 8-1 37 APPENDIX A    COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW ...... A-1 38 APPENDIX B    APPLICABLE LAWS, REGULATIONS, AND OTHER 39              REQUIREMENTS ......................................................................................... B-1 40 APPENDIX C    CONSULTATION CORRESPONDENCE ..................................................... C-1 xiii
 
Table of Contents 1 APPENDIX D      CHRONOLOGY OF ENVIRONMENTAL REVIEW 2                CORRESPONDENCE .................................................................................. D-1 3 APPENDIX E      PROJECTS AND ACTIONS CONSIDERED IN CUMULATIVE IMPACTS 4                ANALYSIS.................................................................................................... E-1 5 APPENDIX F      U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 6                OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 7                LASALLE COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF 8                LICENSE RENEWAL APPLICATION REVIEW............................................ F-1 9 APPENDIX G      TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL ................G-1 xiv
 
1                                            FIGURES 2 Figure 1-1. Environmental Review Process........................................................................ 1-2 3 Figure 1-2. Environmental Issues Evaluated for License Renewal ..................................... 1-4 4 Figure 2-1. Territories of MISO and PJM Interconnection................................................... 2-6 5 Figure 3-1. LSCS 50-mi (80-km) Radius Map .................................................................... 3-2 6 Figure 3-2. LSCS 6-mi (10-km) Radius Map ...................................................................... 3-3 7 Figure 3-3. LSCS Site Layout............................................................................................. 3-4 8 Figure 3-4. LSCS Plant Features ....................................................................................... 3-5 9 Figure 3-5. Closed-Cycle Cooling System with Cooling Pond ............................................ 3-7 10 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities ...................................... 3-9 11 Figure 3-7. Site Physiography, LSCS Vicinity ................................................................... 3-31 12 Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity ...................................... 3-32 13 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity ................................ 3-33 14 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries ..................... 3-37 15 Figure 3-11. LSCS Surface Water and Related Water Resource Features ........................ 3-38 16 Figure 3-12. LSCS Site Hydrogeologic Units...................................................................... 3-47 17 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill .................................... 3-49 18 Figure 3-14. LSCS Hydrogeologic Cross-Section............................................................... 3-50 19 Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure........... 3-62 20 Figure 3-16. Sampling Locations in LSCS Aquatic Surveys ............................................... 3-63 21 Figure 3-17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS .................... 3-104 22 Figure 3-18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS ............. 3-105 23 Figure G-1. Illustration of Truck Stop Model ....................................................................... G-6 xv
 
1                                                      TABLES 2 Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 3            License Renewal............................................................................................. xxiii 4 Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 5            Considered in Depth ........................................................................................ 2-8 6 Table 2-2. Summary of Environmental Impacts of Proposed Action and 7            Alternatives .................................................................................................... 2-25 8 Table 3-1. LSCS Site Land Uses by Area ....................................................................... 3-21 9 Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS ........................................... 3-23 10 Table 3-3. National Ambient Air Quality Standards ......................................................... 3-26 11 Table 3-4. LSCS Air Emissions (MT/year)....................................................................... 3-27 12 Table 3-5. Common Noise Sources and Noise Levels .................................................... 3-28 13 Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, 14            LSCS ............................................................................................................. 3-40 15 Table 3-7. National Pollutant Discharge Elimination System-Permitted Outfalls, 16            LSCS ............................................................................................................. 3-43 17 Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion............................... 3-52 18 Table 3-9. State-Listed Species in LaSalle County ......................................................... 3-56 19 Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River ............ 3-65 20 Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural 21            History Electrofishing Surveys from 1957 through 2009 ................................. 3-67 22 Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 ................................... 3-68 23 Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle 24            County ........................................................................................................... 3-70 25 Table 3-14. Federally Listed Species and Designated Habitat in La Salle County, 26            Illinois............................................................................................................. 3-75 27 Table 3-15. LSCS Employees Residence by County ........................................................ 3-83 28 Table 3-16. Employment by Industry in the LSCS ROI (2014, 1-year estimates and 29            2009-2013, 5-year estimates) ........................................................................ 3-84 30 Table 3-17. Major Employers in LaSalle County in 2009 ................................................... 3-85 31 Table 3-18. Estimated Income Information for the LSCS ROI (2014 estimates, 32            unless otherwise indicated) ............................................................................ 3-85 33 Table 3-19. Population and Percent Growth in LSCS ROI Counties 1980-2010, 34            2014 (estimated), and Projected for 2020-2060 ............................................ 3-86 35 Table 3-20. Demographic Profile of the Population in the LSCS ROI in 2010 ................... 3-87 36 Table 3-21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County) ................... 3-87 37 Table 3-22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of 38            LSCS ............................................................................................................. 3-88 39 Table 3-23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 40            within 50 mi (80 km) of LSCS (2012).............................................................. 3-90 41 Table 3-24. Housing in the LSCS ROI (2014 estimate) ..................................................... 3-91 42 Table 3-25. Local Public Water Supply Systems ............................................................... 3-92 xvii
 
1 Table 3-26. LSCS Power Block Tax Payments and Valuations 2007-2014 (in 2            dollars) ........................................................................................................... 3-93 3 Table 3-27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total 4            Levy ............................................................................................................... 3-94 5 Table 3-28. Annual Payments to Illinois Emergency Management Agency 2009-6            2014............................................................................................................... 3-95 7 Table 3-29. Major Commuting Routes in the Vicinity of LSCS: 2013-2014 Average 8            Annual Daily Traffic Count ............................................................................. 3-95 9 Table 4-1. Land Use and Visual Resource Issues............................................................. 4-2 10 Table 4-2. Air Quality and Noise ....................................................................................... 4-7 11 Table 4-3. Geology and Soils Issues............................................................................... 4-20 12 Table 4-4. Surface Water Resources Issues ................................................................... 4-22 13 Table 4-5. Groundwater Issues ....................................................................................... 4-24 14 Table 4-6. Terrestrial Resource Issues ........................................................................... 4-31 15 Table 4-7. Aquatic Resource Issues ............................................................................... 4-37 16 Table 4-8. Special Status Species and Habitat Issues .................................................... 4-55 17 Table 4-9. Federally Listed Species and Designated Habitat in LaSalle County, 18            Illinois, and NRC Effect Determinations for Proposed LSCS License 19            Renewal ......................................................................................................... 4-56 20 Table 4-10. Historic and Cultural Resources Issue ........................................................... 4-60 21 Table 4-11. Socioeconomic NEPA Issues Affected by License Renewal .......................... 4-65 22 Table 4-12. Human Health Issues ..................................................................................... 4-72 23 Table 4-13. Issues Related to Postulated Accidents ......................................................... 4-76 24 Table 4-14. LSCS CDF for Internal Events ....................................................................... 4-79 25 Table 4-15. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 26            for Internal Events .......................................................................................... 4-81 27 Table 4-16. LSCS Potentially Cost-Beneficial SAMAs ...................................................... 4-84 28 Table 4-17. Environmental Justice NEPA Issue ................................................................ 4-91 29 Table 4-18. Waste Management Issues ............................................................................ 4-97 30 Table 4-19. Issues Related to the Uranium Fuel Cycle ................................................... 4-101 31 Table 4-20. Issues Related to Decommissioning ............................................................ 4-103 32 Table 4-21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)......... 4-105 33 Table 4-22. Direct GHG Emissions from Operation of the Proposed Action and 34            Alternatives .................................................................................................. 4-107 35 Table 4-23. Comparison of GHG Emission Inventories ................................................... 4-130 36 Table 4-24. Summary of Cumulative Impacts on Resource Areas .................................. 4-131 37 Table 6-1. List of Preparers .............................................................................................. 6-1 38 Table B-1. Federal and State Requirements ..................................................................... B-2 39 Table B-2. Licenses and Permits ....................................................................................... B-7 40 Table C-1. ESA Section 7 Consultation Correspondence ..................................................C-2 41 Table C-2. NHPA Correspondence....................................................................................C-3 42 Table D-1. Environmental Review Correspondence ..........................................................D-1 43 Table E-1. Projects and Actions Considered in Cumulative Impact Analysis ..................... E-1
 
Tables 1 Table F-1. LaSalle County Station CDF for Internal Events ............................................... F-3 2 Table F-2. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 3              for Internal Events ............................................................................................ F-4 4 Table F-3. Summary of Major PRA Models and Corresponding CDF and LERF 5              Results............................................................................................................. F-7 6 Table F-4. Dominant LSCS Contributors to Seismic CDF ............................................... F-12 7 Table F-5(a). Dominant LSCS Unit 1 Fire Zone Contributors to Fire CDF of 8.9x10-6 8              per year ......................................................................................................... F-14 9 Table F-5(b). Dominant LSCS Unit 2 Fire Zone Contributors to Fire CDF of 9.4x10-6 10              per year ......................................................................................................... F-14 11 Table F-6. SAMA Cost-Benefit Screening Analysis for LSCS Station .............................. F-33 12 Table G-1. Transportation Route Information for Shipments from LSCS to the 13              Proposed Yucca Mountain Repository Site ..................................................... G-4 14 Table G-2. RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters ....................... G-5 15 Table G-3. Annual Normal (Incident-Free) Radiation Doses to Transport Workers 16              and the Public from Shipping Spent Fuel from LSCS to the Proposed 17              Yucca Mountain Repository Site, Normalized to Reference 18              LWR (880 MWe (net)) ..................................................................................... G-6 19 Table G-4. Radionuclide Inventories Used in Transportation Accident Risk 20              Calculations for the LSCS Reactors ...............................................................G-10 21 Table G-5. Annual Spent Fuel Transportation Accident Impacts from Shipping 22              Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 23              Site, Normalized to Reference LWR Reactor (880 MWe (net)).......................G-11 xix
 
1                                  EXECUTIVE
 
==SUMMARY==
 
2 BACKGROUND 3 By letter dated December 9, 2014, Exelon Generation Company, LLC (Exelon) submitted an 4 application to the U.S. Nuclear Regulatory Commission (NRC) to issue renewed operating 5 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20-year period.
6 Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 51.20(b)(2), the renewal of a 7 power reactor operating license requires preparation of an environmental impact statement 8 (EIS) or a supplement to an existing EIS. In addition, 10 CFR 51.95(c) states that, in connection 9 with the renewal of an operating license, the NRC shall prepare an EIS, which is a supplement 10 to the Commissions NUREG-1437, Generic Environmental Impact Statement (GEIS) for 11 License Renewal of Nuclear Plants.
12 Upon acceptance of Exelons application, the NRC staff began the environmental review 13 process described in 10 CFR Part 51 by publishing a Notice of Intent to prepare a supplemental 14 environmental impact statement (SEIS) and to conduct scoping. In preparation of this SEIS for 15 LSCS, the NRC staff performed the following:
16
* conducted public scoping meetings on March 10, 2015, in Ottawa, Illinois; 17
* conducted a site audit at LSCS from May 5-7, 2015; 18
* reviewed Exelons Environmental Report (ER) and compared it to the GEIS; 19
* consulted with Federal, State, Tribal, and local agencies; 20
* conducted a review of the issues following the guidance set forth in 21              Standard Review Plans for Environmental Reviews for Nuclear Power Plants:
22              Environmental Standard Review Plan for Operating License Renewal (NUREG-1555 23              Supplement 1, Revision 1, Final Report); and 24
* considered public comments received during the scoping process.
25 PROPOSED ACTION 26 Exelon initiated the proposed Federal action (i.e., issuance of renewed power reactor operating 27 licenses) by submitting an application for license renewal of LSCS for which the existing 28 licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023. The NRCs 29 Federal action is to decide whether to renew the licenses for an additional 20 years. The 30 regulation at 10 CFR 2.109 states that, if a licensee of a nuclear power plant files an application 31 to renew an operating license at least 5 years before the expiration date of that license, the 32 existing license will not be deemed to have expired until the safety and environmental reviews 33 are completed and until the NRC has made a final decision on whether to issue a renewed 34 license for the additional 20 years.
35 PURPOSE AND NEED FOR ACTION 36 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 37 option that allows for power generation capability beyond the term of the current nuclear power 38 plant operating licenses to meet future system generating needs. Such needs may be 39 determined by other energy-planning decisionmakers, such as states, operators, and, where 40 authorized, Federal agencies (other than the NRC). This definition of purpose and need reflects xxi
 
Executive Summary 1 the NRCs recognition that, unless there are findings in the safety review required by the Atomic 2 Energy Act of 1954, as amended, or findings in the National Environmental Policy Act of 1969, 3 as amended, environmental analysis that would lead the NRC to reject a license renewal 4 application, the NRC does not have a role in the energy-planning decisions as to whether a 5 particular nuclear power plant should continue to operate.
6 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL 7 The SEIS evaluates the potential environmental impacts of the proposed action. The 8 environmental impacts from the proposed action are designated as SMALL, MODERATE, or 9 LARGE. As established in the GEIS, Category 1 issues are those that meet all of the following 10 criteria:
11
* The environmental impacts associated with the issue          SMALL: Environmental 12            are determined to apply either to all plants or, for some    effects are not detectable or 13            issues, to plants having a specific type of cooling          are so minor that they will 14            system or other specified plant or site characteristics.      neither destabilize nor noticeably alter any important 15
* A single significance level (i.e., SMALL, MODERATE,          attribute of the resource.
16            or LARGE) has been assigned to the impacts except            MODERATE:
17            for collective offsite radiological impacts from the fuel    Environmental effects are 18            cycle and from high-level waste and spent fuel                sufficient to alter noticeably, but not to destabilize, 19            disposal.                                                    important attributes of the 20
* Mitigation of adverse impacts associated with the issue      resource.
21            is considered in the analysis, and it has been                LARGE: Environmental 22            determined that additional plant-specific mitigation          effects are clearly noticeable and are sufficient to 23            measures are likely not to be sufficiently beneficial to destabilize important 24            warrant implementation.                                      attributes of the resource.
25 For Category 1 issues, no additional site-specific analysis is 26 required in this SEIS unless new and significant information is identified. Chapter 4 of this SEIS 27 presents the process for identifying new and significant information. Site-specific issues 28 (Category 2) are those that do not meet one or more of the criteria for Category 1 issues; 29 therefore, an additional site-specific review for these non-generic issues is required, and the 30 results are documented in the SEIS.
31 Neither Exelon nor the NRC identified information that is both new and significant related to 32 Category 1 issues that would call into question the conclusions in the GEIS. This conclusion is 33 supported by the NRC staffs review of the applicants ER and other documentation relevant to 34 the applicants activities, the public scoping process, and the findings from the environmental 35 site audit conducted by the NRC staff. Therefore, the NRC staff relied upon the conclusions of 36 the GEIS for all Category 1 issues applicable to LSCS.
37 The NRC staff did find new information regarding the Category 1 a uranium fuel cycle issue 38 (Transportation), but this new information was not considered significant and therefore did not 39 affect the conclusions for these issues presented in the GEIS. This new information is 40 discussed in Section 4.15.1 and Appendix G of this SEIS.
41 Table ES-1 summarizes the Category 2 issues relevant to LSCS and the NRC staffs findings 42 related to those issues. If the NRC staff determined that there were no Category 2 issues 43 applicable for a particular resource area, the findings of the GEIS, as documented in 44 Appendix B to Subpart A of 10 CFR Part 51, are incorporated for that resource area.
xxii
 
Executive Summary 1          Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 2                                                      License Renewal Resource Area                            Relevant Category 2 Issues                        Impacts Surface Water Resources                  Surface water use conflicts                        SMALL Groundwater Resources                    Groundwater Use Conflicts                          SMALL Groundwater Quality Degradation                    SMALL Radionuclides released to groundwater              SMALL Terrestrial Resources                    Effects on terrestrial resources (non-cooling SMALL system impacts)
Water use conflicts with terrestrial resources SMALL Aquatic Resources                        Impingement and entrainment of aquatic            SMALL organisms Thermal impacts on aquatic organisms              SMALL to MODERATE(a)
Water use conflicts with aquatic resources        SMALL Special Status Species and                Threatened, endangered, and species and            No effect (b)
Habitats                                  essential fish habitat Historic and Cultural                    Historic and cultural resources                    No adverse effect (c)
Resources Human Health                              Microbiological hazards to the public              SMALL Electric shock hazards                            SMALL Environmental Justice                    Minority and low-income populations                See note below (d)
Cumulative Impacts                        Terrestrial Ecology                                MODERATE to LARGE Aquatic Resources                                  MODERATE Socioeconomic                                      See note below (e)
Environmental Justice                              See note below (d)
Global Climate Change                              MODERATE All other resource areas                          SMALL (a) Thermal  impacts would be SMALL for all aquatic resources in the Illinois River and SMALL for aquatic resources in the cooling pond, except for gizzard shad and threadfin shad. Gizzard shad and threadfin shad would experience MODERATE thermal impacts in the cooling pond.
(b) For Federally protected species, the NRC reports the effects from continued operation of LSCS during the license renewal period in terms of its Endangered Species Act of 1973, as amended, findings of no effect, may effect, but not likely to adversely effect, or may affect, and is likely to adversely affect.
(c) The National Historic Preservation Act of 1966, as amended, requires Federal agencies to consider the effects of their undertakings on historic properties.
(d) There would be no disproportionately high and adverse impacts to minority and low-income populations.
(e) The contributory effects from the continued operation of LSCS during the license renewal period would have no new or increased impact on socioeconomic conditions beyond what is currently being experienced.
3 SEVERE ACCIDENT MITIGATION ALTERNATIVES 4 Since severe accident mitigation alternatives (SAMAs) have not been previously considered in 5 an environmental impact statement or environmental assessment for LSCS, xxiii
 
Executive Summary 1 10 CFR 51.53(c)(3)(ii)(L) requires Exelon to submit, with the ER, a consideration of alternatives 2 to mitigate severe accidents. SAMAs are potential ways to reduce the risk or potential impacts 3 of uncommon, but potentially severe accidents. SAMAs may include changes to plant 4 components, systems, procedures, and training.
5 The NRC staff reviewed Exelons ER evaluation of potential SAMAs and concluded that none of 6 the potentially cost-beneficial SAMAs relate to adequately managing the effects of aging during 7 the extended period of operation. Therefore, the potentially cost-beneficial SAMAs identified 8 need not be implemented as part of the license renewal, pursuant to 10 CFR Part 54.
9 ALTERNATIVES 10 The NRC staff considered the environmental impacts associated with alternatives to license 11 renewal. These alternatives include other methods of power generation, as well as not 12 renewing the LSCS operating licenses (the no-action alternative). The NRC staff considered 13 the following feasible and commercially viable replacement power alternatives:
14
* new nuclear power; 15
* coal-integrated gasification combined-cycle; 16
* natural gas combined-cycle (NGCC); and 17
* combination alternative (NGCC, wind, and solar power), and 18
* purchased power.
19 The NRC staff initially considered a number of additional alternatives for analysis as alternatives 20 to the license renewal of LSCS. The NRC staff later dismissed these alternatives because of 21 technical, resource availability, or commercial limitations that currently exist and that the NRC 22 staff believes are likely to continue to exist when the current LSCS licenses expire. The 23 no-action alternative and the effects it would have were also considered by the NRC staff.
24 Where possible, the NRC staff evaluated potential environmental impacts for these alternatives 25 located at both the LSCS site and some other unspecified alternate location. The NRC staff 26 considered the following alternatives, but dismissed them:
27
* energy conservation and energy efficiency, 28
* solar power, 29
* wind power, 30
* biomass, 31
* hydroelectric power, 32
* wave and ocean energy, 33
* fuel cells, 34
* delayed retirement, 35
* geothermal power, 36
* municipal solid waste, 37
* oil-fired power, and 38
* supercritical pulverized coal.
xxiv
 
Executive Summary 1 The NRC staff evaluated each alternative using the same resource areas that were used in 2 evaluating impacts from license renewal.
3 PRELIMINARY RECOMMENDATION 4 The NRC staffs preliminary recommendation is that the adverse environmental impacts of 5 license renewal for LSCS are not so great that preserving the option of license renewal for 6 energy-planning decisionmakers would be unreasonable. The NRC staff based its 7 recommendation on the following:
8
* the analyses and findings in the GEIS; 9
* the ER submitted by Exelon; 10
* the NRC staffs consultation with Federal, State, local, and Tribal Government 11            agencies; 12
* the NRC staffs independent environmental review; and 13
* the NRC staffs consideration of public comments received during the scoping 14            process.
xxv
 
Abbreviations and Acronyms 1        ABBREVIATIONS AND ACRONYMS 2 ac        acre(s) 3 AC        alternating current 4 ACC        averted cleanup and decontamination costs 5 ACHP      Advisory Council on Historic Preservation 6 ADAMS      Agencywide Documents Access and Management System 7 AEA        Atomic Energy Act of 1954 (as amended) 8 AFW        auxiliary feedwater 9 AMSAC      ATWS mitigating system actuation circuitry 10 ANL        Argonne National Laboratory 11 ANS        American Nuclear Society 12 AOC        averted offsite property damage costs 13 AOE        averted occupational exposure 14 AOSC      averted onsite costs 15 AP        auxiliary power 16 APE        averted public exposure 17 ASLB      Atomic Safety and Licensing Board (NRC) 18 ASME      American Society of Mechanical Engineers 19 ATWS      anticipated transient(s) without scram 20 AWEA      American Wind Energy Association 21 BEA        Bureau of Economic Analysis 22 BLM        Bureau of Land Management 23 BLS        Bureau of Labor Statistics 24 BOEM      Bureau of Ocean Energy Management 25 BTU/ft3    British thermal unit(s) per cubic foot 26 CAA        Clean Air Act 27 CAES      compressed air energy storage 28 CCS        carbon capture and storage 29 CCW        component cooling water 30 CDF        core damage frequency 31 CEQ        Council on Environmental Quality 32 CET        containment event tree 33 CFE        early containment failure 34 CFR        Code of Federal Regulations xxvii
 
Abbreviations and Acronyms 1 cfs                        cubic foot (feet) per second 2 CLB                        current licensing basis/bases 3 CO                        carbon monoxide 4 CO2                        carbon dioxide 5 CO2/MWh                    carbon dioxide per megawatt hour 6 COL                        combined license 7 CVCS                      chemical and volume control system 8 CWA                        Clean Water Act 9 div.                      Division 10 DLOOP                      dual unit loss(es) of offsite power 11 DMS                        Diverse Mitigation System 12 DOE                        U.S. Department of Energy 13 DSIRE                      Database of State Incentives for Renewables and Efficiency 14 DSM                        demand-side management 15 ECCS                      emergency core cooling system 16 EFH                        essential fish habitat 17 EIA                        Energy Information Administration 18 EIS                        environmental impact statement 19 ELPC                      Environmental Law and Policy Center 20 Elv.                      elevation 21 EMF                        electromagnetic field 22 EPA                        U.S. Environmental Protection Agency 23 EPRI                      Electric Power Research Institute 24 EPZ                        emergency planning zone 25 ER                        Environmental Report 26 ERC                        Energy Recovery Council 27 ES                        Environmental Services 28 ESA                        Endangered Species Act of 1973, as amended 29 ESF                        engineered safety feature 30 ESFAS                      engineered safety features actuation system 31 ESP                        early site permit 32 ESW                        emergency service water 33 Exelon                    Exelon Generation Company, LLC 34 FEIS                      final environmental impact statement 35 FERC                      Federal Energy Regulatory Commission xxviii
 
Abbreviations and Acronyms 1 FESOP  Federally Enforceable State Operating Permit 2 FIVE  fire-induced vulnerability evaluation 3 FR    Federal Register 4 FRN    Federal Register notice 5 ft3    cubic foot (feet) 6 FW    feedwater 7 FWCA  Fish and Wildlife Coordination Act of 1934, as amended 8 FWS    U.S. Fish and Wildlife Service 9 GEIS  generic environmental impact statement 10 GI    generic issue 11 GL    generic letter 12 gpd    gallon(s) per day 13 gpm    gallon(s) per minute 14 ha    hectare(s) 15 HCLPF  high confidence in low probability of failure 16 HEP    human error probability 17 HFE    human failure event 18 HFO    high winds, floods, and other 19 HRA    human reliability analysis 20 HX    heat exchanger 21 IDNR  Illinois Department of Natural Resources 22 IDOT  Illinois Department of Transportation 23 IDPH  Illinois Department of Public Health 24 IEA    International Energy Agency 25 IEPA  Illinois Environmental Protection Agency 26 IGCC  integrated gasification combined-cycle 27 IHPA  Illinois Historic Preservation Agency 28 ILCS  Illinois Compiled Statutes 29 INEEL  Idaho National Engineering and Environmental Laboratory 30 IPE    individual plant examination 31 IPEEE  individual plant examination(s) of external events 32 ISLOCA interfacing-systems loss-of-coolant accident 33 JHEP  joint human error probability 34 km    kilometer(s) 35 kW    kilowatt(s) xxix
 
Abbreviations and Acronyms 1 kWe                        kilowatt(s) electric 2 kWh/m2/d                  kilowatt hours per square meter per day 3 lb                        pound(s) 4 LER                        large early release 5 LERF                      large early release frequency 6 LMFW                      loss of main feedwater 7 LOCA                      loss-of-coolant accident 8 LOOP                      loss(es) of offsite power 9 Lpd                        liters per day 10 LRA                        license renewal application 11 LSCS                      LaSalle County Station, Units 1 and 2 12 m/s                        meter(s) per second 13 m3                        cubic meter(s) 14 MAAP                      Modular Accident Analysis Program 15 MACCS2                    MELCOR Accident Consequence Code System 2 16 MACR                      maximum averted cost risk 17 MATS                      Mercury and Air Toxics Standards 18 MCR                        main control room 19 mgd                        million gallons per day 20 mi                        mile(s) 21 MISO                      Midcontinent Independent System Operator 22 MMPA                      Marine Mammal Protection Act 23 MOV                        motor-operated valve 24 mph                        mile(s) per hour 25 MSA                        Magnuson-Stevens Fishery Conservation and Management Act, 26                            as amended through 2006 27 MUR                        measurement uncertainty recapture 28 MW                        megawatt(s) 29 MWe                        megawatt(s) electric 30 MWh                        megawatt hour(s) 31 MWt                        megawatt(s) thermal 32 NEIS                      National Energy Information Service 33 NEPA                      National Environmental Policy Act of 1969, as amended 34 NETL                      National Energy Technology Laboratory 35 NGCC                      natural gas combined-cycle xxx
 
Abbreviations and Acronyms 1 NHPA  National Historic Preservation Act of 1966, as amended 2 NMFS  National Marine Fisheries Service (of the National Oceanic and 3      Atmospheric Administration) 4 NO2  nitrogen dioxide 5 NOx  nitrogen oxide(s) 6 NPDES National Pollutant Discharge Elimination System 7 NRC  U.S. Nuclear Regulatory Commission 8 NREL  National Renewable Energy Laboratory 9 NRR  Nuclear Reactor Regulation, Office of (NRC) 10 O3    ozone 11 OECR  offsite economic cost risk 12 ORNL  Oak Ridge National Laboratory 13 Pb    lead 14 PDR  population dose risk 15 PDS  plant damage state 16 PEIS  programmatic environmental impact statement 17 PL    public law 18 PNNL  Pacific Northwest National Laboratory 19 PORV  power-operated relief valve 20 PRA  probabilistic risk assessment 21 PV    photovoltaic 22 PWR  pressurized water reactor 23 RAI  request(s) for additional information 24 RCP  reactor coolant pump 25 RCRA  Resource Conservation and Recovery Act of 1976, as amended 26 rem  roentgen equivalent(s) man 27 RHR  residual heat removal 28 ROI  region(s) of influence 29 RPC  replacement power cost 30 RPS  reactor protection system 31 RPV  reactor pressure vessel 32 RRW  risk reduction worth 33 RTO  Regional Transmission Organization 34 RWST  refueling water storage tank 35 SAMA  severe accident mitigation alternative xxxi
 
Abbreviations and Acronyms 1 SAT                        system auxiliary transformer 2 SBO                        station blackout 3 SCPC                      supercritical pulverized coal 4 SEIS                      supplemental environmental impact statement 5 SER                        safety evaluation report 6 SG                        steam generator 7 SGTR                      steam generator tube rupture 8 SI                        safety injection 9 SMA                        seismic margin assessment 10 SO2                        sulfur dioxide 11 SR                        supporting requirement 12 SSC                        structure, system, and component 13 SSEL                      Safe Shutdown Equipment List 14 Sv                        sievert(s) 15 SW                        service water 16 SX                        essential service water 17 syngas                    synthesis gas 18 TAC                        technical assignment control 19 TEEIC                      Tribal Energy and Environmental Information Clearinghouse 20 TS                        technical specification 21 U.S.                      United States 22 U.S.C.                    United States Code 23 UAT                        unit auxiliary transformer 24 UFSAR                      updated final safety analysis report 25 USDA                      U.S. Department of Agriculture 26 USGS                      U.S. Geological Survey 27 yd 3 cubic yard(s) 28 W/m2                      watt(s) per square meter xxxii
 
1                                       
 
==1.0 INTRODUCTION==
 
2 Under the U.S. Nuclear Regulatory Commissions (NRCs) environmental protection regulations 3 in Part 51 of Title 10 of the Code of Federal Regulations (10 CFR Part 51)which implement 4 the National Environmental Policy Act (NEPA)the issuance or renewal of a nuclear power 5 plant operating license requires the preparation of an environmental impact statement (EIS).
6 The Atomic Energy Act of 1954 (AEA) specified that licenses for commercial power reactors can 7 be granted for up to 40 years. NRC regulations (10 CFR 54.31) allow for an option to renew a 8 license for up to an additional 20 years. The initial 40-year licensing period was based on 9 economic and antitrust considerations rather than on technical limitations of the nuclear facility.
10 The decision to seek a license renewal rests entirely with nuclear power facility owners and, 11 typically, is based on the facilitys economic viability and the investment necessary to continue 12 to meet NRC safety and environmental requirements. The NRC makes the decision to grant or 13 deny license renewal based on whether the applicant has demonstrated that the environmental 14 and safety requirements in the agencys regulations can be met during the period of extended 15 operation.
16 1.1    Proposed Federal Action 17 Exelon Generation Company, LLC (Exelon), initiated the proposed Federal action by submitting 18 an application for license renewal of LaSalle County Station, Units 1 and 2 (LSCS), for which 19 the existing licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023.
20 The NRCs Federal action is to decide whether to renew the licenses for an additional 20 years.
21 1.2    Purpose and Need for Proposed Federal Action 22 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 23 option that allows for power generation capability beyond the term of a current nuclear power 24 plant operating license to meet future system generating needs, as such needs may be 25 determined by other energy-planning decisionmakers. This definition of purpose and need 26 reflects the NRCs recognition that, unless there are findings in the safety review required by the 27 AEA or findings in the NEPA environmental analysis that would lead the NRC to reject a license 28 renewal application (LRA), the NRC does not have a role in the energy-planning decisions of 29 state regulators and utility officials as to whether a particular nuclear power plant should 30 continue to operate.
31 1.3    Major Environmental Review Milestones 32 Exelon submitted an Environmental Report (ER) (Exelon 2014a) as part of its 33 LRA (Exelon 2014b) in December 2014. After reviewing the LRA and ER for sufficiency, the 34 NRC staff published a Federal Register Notice of Acceptability and Opportunity for Hearing 35 (Volume 80 of the Federal Register (FR), page 5822 (80 FR 5822)) on February 3, 2015. Also, 36 on February 3, 2015, the NRC published another notice in the Federal Register (80 FR 5793) on 37 the intent to conduct scoping, thereby beginning the 60-day scoping period.
38 The NRC staff held two public scoping meetings on March 10, 2015, in Ottawa, Illinois. In a 39 letter dated July 2, 2015, the NRC issued a report entitled, Environmental Impact Statement 40 Scoping Process Summary Report, LaSalle County Station, Units 1 and 2, Brookfield Township, 1-1
 
Introduction 1 LaSalle County, IL, which includes both the comments received during the scoping process 2 and the NRC staffs responses to those comments (NRC 2015a).
3 In order to independently verify information provided in the ER, the NRC staff conducted a site 4 audit at LSCS in May 2015. During the site audit, the NRC staff met with plant personnel, 5 reviewed specific documentation, toured the facility, and met with interested local agencies. In 6 a letter dated May 20, 2015, the NRC summarized that site audit and listed the attendees 7 (NRC 2015b).
8 Upon completion of the scoping period and site audit, the NRC staff compiled its findings in a 9 draft supplemental environmental impact statement (SEIS). This document is made available 10 for public comment for 45 days. During this time, the NRC staff will host public meetings and 11 collect public comments. Based on the information gathered, the NRC staff will amend the draft 12 SEIS findings, as necessary, and will publish the final SEIS. Figure 1-1 shows the major 13 milestones of the NRCs LRA environmental review process.
14                            Figure 1-1. Environmental Review Process 15 16 The NRC has established a license renewal process that can be completed in a reasonable 17 period of time with clear requirements to ensure safe plant operation for up to an additional 18 20 years of plant life. The NRC staff conducts the safety review simultaneously with the 19 environmental review. The NRC staff documents the findings of the safety review in a safety 20 evaluation report (SER). The findings in the SEIS and the SER are both factors in the NRCs 21 decision to either grant or deny the issuance of a renewed license.
22 1.4    Generic Environmental Impact Statement 23 The NRC staff performed a generic assessment of the environmental impacts associated with 24 license renewal to improve the efficiency of its license renewal review. NUREG-1437, Generic 25 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) 1-2
 
Introduction 1 (NRC 1996, 1999, 2013), documents the results of the NRC staffs systematic approach to 2 evaluate the environmental consequences of renewing the licenses of individual nuclear power 3 plants and operating them for an additional 20 years. The NRC staff analyzed in detail, and 4 resolved, those environmental issues that could be resolved generically in the GEIS. The NRC 5 originally issued the GEIS in 1996, issued Addendum 1 to the GEIS in 1999, and issued 6 Revision 1 to the GEIS in 2013. Unless otherwise noted, all references to the GEIS include 7 Addendum 1 and Revision 1 to the GEIS.
8 The GEIS establishes separate environmental impact issues for the NRC staff to independently 9 verify. Of these issues, the NRC staff determined that some generic issues are generic to all 10 plants (Category 1). Other issues do not lend themselves to generic consideration (Category 2 11 or uncategorized). The NRC staff evaluated these issues on a site-specific basis in the SEIS.
12 Appendix B to Subpart A of 10 CFR Part 51 summarizes the NRC staffs findings in the GEIS.
13 For each potential environmental issue, the NRC staff does the following in the GEIS:
14
* describes the activity that affects the environment, 15
* identifies the population or resource that is affected, 16
* assesses the nature and magnitude of the impact on the affected population or 17              resource, 18
* characterizes the significance of the effect for both beneficial and adverse effects, 19
* determines whether the results of the analysis apply to all plants, and 20
* considers whether additional mitigation measures would be warranted for impacts 21              that would have the same significance level for all plants.
22 The NRC established its standard of significance for impacts using the Council on 23 Environmental Quality terminology for significant. The NRC established three levels of 24 significance for potential impactsSMALL, MODERATE, and LARGE, as defined below.
25 SMALL: Environmental effects are not 26 detectable or are so minor that they will neither          Significance indicates the importance of likely environmental impacts and is determined by 27 destabilize nor noticeably alter any important            considering two variables: context and intensity.
28 attribute of the resource.
Context is the geographic, biophysical, and social 29 MODERATE: Environmental effects are                        context in which the effects will occur.
30 sufficient to alter noticeably, but not to                Intensity refers to the severity of the impact in 31 destabilize, important attributes of the resource.        whatever context it occurs.
32 LARGE: Environmental effects are clearly 33 noticeable and are sufficient to destabilize important attributes of the resource.
34 The GEIS includes a determination of whether the analysis of the environmental issue could be 35 applied to all plants and whether additional mitigation measures would be warranted. Issues 36 are assigned a Category 1 or a Category 2 designation. As set forth in the GEIS, Category 1 37 issues are those that meet the following criteria:
38
* The environmental impacts associated with the issue have been determined to apply 39              either to all plants or, for some issues, to plants having a specific type of cooling 40              system or other specified plant or site characteristics.
41
* A single significance level (i.e., SMALL, MODERATE, or LARGE) has been assigned 42              to the impacts (except for collective offsite radiological impacts from the fuel cycle 43              and from high-level waste and spent fuel disposal).
1-3
 
Introduction 1
* Mitigation of adverse impacts associated with the issue has been considered in the 2              analysis, and it has been determined that additional plant-specific mitigation 3              measures are likely not to be sufficiently beneficial to warrant implementation.
4 For generic issues (Category 1), no additional site-specific analysis is required in the SEIS 5 unless new and significant information is identified. The process for identifying new and 6 significant information for site-specific analysis is presented in Chapter 4. Site-specific issues 7 (Category 2) are those that do not meet one or more of the criteria of Category 1 issues; 8 therefore, additional site-specific review for these issues is required. A site-specific analysis is 9 required for 17 of those 78 issues evaluated in the GEIS. Figure 1-2 illustrates this process.
10 The results of that site-specific review are documented in the SEIS.
11                Figure 1-2. Environmental Issues Evaluated for License Renewal 12 1.5    Supplemental Environmental Impact Statement 13 The SEIS presents an analysis that considers the environmental effects of the continued 14 operation of LSCS, alternatives to license renewal, and mitigation measures for minimizing 15 adverse environmental impacts. Chapter 4 contains analysis and comparison of the potential 16 environmental impacts from alternatives. Chapter 5 presents the NRCs recommendation on 17 whether the environmental impacts of license renewal are so great that preserving the option of 1-4
 
Introduction 1 license renewal would be unreasonable. The NRC will make its final recommendation after 2 considering comments received on the draft SEIS during the public comment period.
3 In the preparation of the SEIS for LSCS, the NRC staff carried out the following activities:
4
* reviewed the information provided in Exelons ER; 5
* consulted with Federal, state, and local agencies, and tribal nations; 6
* conducted an independent review of the issues during site audit; and 7
* considered the public comments received for the review (during the scoping 8              process).
9 New information can be identified from many 10 sources, including the applicant, the NRC, other        New and significant information. To merit 11 agencies, or public comments. If a new issue is          additional review, information must be both new and bear on the proposed action or its impacts, 12 revealed, it is first analyzed to determine whether      presenting a seriously different picture of the 13 it is within the scope of the license renewal            impacts from those envisioned in the GEIS.
14 environmental evaluation. If the new issue is not 15 addressed in the GEIS, the NRC staff would determine the significance of the issue and 16 document the analysis in the SEIS.
17 1.6    Decisions to Be Supported by the SEIS 18 The decision to be supported by the SEIS is whether to renew the operating licenses for LSCS 19 for an additional 20 years. The NRC decision standard is specified in 10 CFR 51.103(a)(5), as 20 follows:
21              In making a final decision on a license renewal action pursuant to Part 54 22              of this chapter, the Commission shall determine whether or not the 23              adverse environmental impacts of license renewal are so great that 24              preserving the option of license renewal for energy planning 25              decisionmakers would be unreasonable.
26 There are many factors that the NRC takes into consideration when deciding whether to renew 27 the operating license of a nuclear power plant. The analyses of environmental impacts 28 evaluated in this GEIS will provide the NRCs decisionmaker (in this case, the Commission) with 29 important environmental information for use in the overall decisionmaking process. There are 30 also decisions outside the regulatory scope of license renewal that cannot be made on the basis 31 of the GEIS analysis. These decisions include the following issues: changes to plant cooling 32 systems, disposition of spent nuclear fuel, emergency preparedness, safeguards and security, 33 need for power, and seismicity and flooding (NRC 2013).
34 1.7    Cooperating Agencies 35 During the scoping process, no Federal, state, or local agencies were identified as cooperating 36 agencies in the preparation of this SEIS.
37 1.8    Consultations 38 The Endangered Species Act of 1973, as amended (ESA) (16 U.S.C. 1531 et seq.); the 39 Magnuson-Stevens Fisheries Conservation and Management Act of 1996, as amended (MSA) 40 (16 U.S.C. 1801 et seq.); and the National Historic Preservation Act of 1966, as amended 41 (NHPA) (16 U.S.C. 470 et seq.), require Federal agencies to consult with applicable state and 1-5
 
Introduction 1 Federal agencies and groups before taking action that may affect endangered species, 2 fisheries, or historic and archaeological resources, respectively. The NRC consulted with the 3 following agencies and groups; Appendix C provides a discussion of the consultation 4 documents:
5
* U.S. Fish and Wildlife Service (FWS);
6
* Illinois Historic Preservation Agency; 7
* Advisory Council on Historic Preservation; 8
* Ho-Chunk Nation; 9
* Miami Tribe of Oklahoma; 10
* Peoria Tribe of Indians of Oklahoma; 11
* Citizen Potawatomi Nation; 12
* Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki Nation; 13
* Sac and Fox Nation of Missouri in Kansas and Nebraska; 14
* Sac and Fox Nation; 15
* Pokagon Band of Potawatomi; 16
* Forest County Potawatomi; 17
* Hannahville Indian Community, Band of Potawatomi; 18
* Prairie Band Potawatomi Nation; 19
* Winnebago Tribe of Nebraska; 20
* Kickapoo Tribe in Kansas; and 21
* Kickapoo Tribe of Oklahoma.
22 1.9    Correspondence 23 During the course of the environmental review, the NRC staff contacted Federal, state, regional, 24 local, and tribal agencies listed in Section 1.8. Appendix C lists the correspondence associated 25 with the ESA, MSA, and NHPA. Appendix D lists all other correspondence.
26 1.10 Status of Compliance 27 Exelon is responsible for complying with all NRC regulations and other applicable Federal, 28 state, and local requirements. Appendix F of the GEIS describes some of the major applicable 29 Federal statutes. There are numerous permits and licenses issued by Federal, state, and local 30 authorities for activities at LSCS. Appendix B contains further information about LSCSs status 31 of compliance.
32 1.11 Related Federal and State Activities 33 The NRC reviewed the possibility that activities of other Federal agencies might impact the 34 renewal of the operating licenses for LSCS. There are no Federal projects that would make it 35 necessary for another Federal agency to become a cooperating agency in the preparation of 36 this SEIS.
1-6
 
Introduction 1 There are no known American Indian lands within 50 miles (mi) (80 kilometers (km)) of the 2 LSCS. There are three Federally owned facilities within 50 mi (80 km) of the LSCS: (1) Fermi 3 National Accelerator Laboratory, (2) Argonne National Laboratory, and (3) Joliet Army 4 Ammunition Plant.
5 Section 102(2)(C) of NEPA requires the NRC to consult with, and obtain comments from, any 6 Federal agency that has jurisdiction by law or special expertise with respect to any 7 environmental impact involved in the subject matter of the SEIS. For example, during the 8 course of preparing the SEIS, the NRC consulted with the FWS. Appendix C lists all 9 consultation correspondences.
10 1.12 References 11 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 12 protection regulations for domestic licensing and related regulatory functions.
13 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 14 renewal of operating licenses for nuclear power plants.
15 80 FR 5793. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 16 notice of intent to prepare an environmental impact statement and conduct the scoping process; 17 public meetings and request for comment. Federal Register 80(22):5793-5795.
18 February 3, 2015.
19 80 FR 5822. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 20 license renewal application; opportunity to request a hearing and to petition for leave to 21 intervene. Federal Register 80(22):5822-5825. February 3, 2015.
22 Atomic Energy Act of 1954, as amended. 42 U.S.C. &sect;2011 et seq.
23 Endangered Species Act of 1973, as amended. 16 U.S.C. &sect;1531 et seq.
24 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 25 Operating License Renewal Stage, LaSalle County Station. Exelon. December 9, 2014.
26 Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 27 ML14343A897.
28 [Exelon] Exelon Generation Company, LLC. 2014b. License Renewal Application, LaSalle 29 County Station, Units 1 and 2. Exelon. December 9, 2014. ADAMS No. ML14343A849.
30 Magnuson-Stevens Fishery Conservation and Management Act of 1996, as amended.
31 16 U.S.C. &sect;1801 et seq.
32 National Environmental Policy Act of 1969, as amended. 42 U.S.C. &sect;4321 et seq.
33 National Historic Preservation Act of 1966, as amended. 16 U.S.C. &sect;470 et seq.
34 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement 35 for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG-1437, 36 Volumes 1 and 2. May 31, 1996. ADAMS Nos. ML040690705 and ML040690738.
37 [NRC] U.S. Nuclear Regulatory Commission. 1999. Section 6.3Transportation, Table 9.1, 38 Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants.
39 In: Generic Environmental Impact Statement for License Renewal of Nuclear Plants.
40 Washington, DC: NRC. NUREG-1437, Volume 1, Addendum 1. August 1999. ADAMS 41 No. ML040690720.
1-7
 
Introduction 1 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 2 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Revision 1, 3 Volumes 1, 2, and 3. June 19, 2013. ADAMS No. ML13107A023.
4 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Letter from BD Wittick (NRC), Branch 5 Chief, to MP Gallagher (Exelon).
 
==Subject:==
Issuance of Scoping Summary Report Associated 6 with the LaSalle County Station, Units 1 and 2, License Renewal Application Environmental 7 Review (TAC Nos. MF5567 and MF5568). July 2, 2015. ADAMS No. ML15147A380.
8 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Letter from BD Wittick (NRC), Branch 9 Chief, to MP Gallagher (Exelon).
 
==Subject:==
Summary of the License Renewal Environmental 10 Audit for LaSalle County Station, Units 1 and 2 (TAC Nos. MF5567 and MF5568).
11 May 20, 2015. ADAMS No. ML15132A674.
1-8
 
1          2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION 2 Although the U.S. Nuclear Regulatory Commissions (NRCs) decisionmaking authority in 3 license renewal is limited to deciding whether or not to renew a nuclear power plants operating 4 license, the NRCs implementation of the National Environmental Policy Act of 1969 (NEPA), as 5 amended (42 U.S.C. 4321 et seq.), requires consideration of the environmental impacts of 6 potential alternatives to renewing a plants operating license. While the ultimate decision about 7 which alternative (or the proposed action) to carry out falls to operator, state, or other non-NRC 8 Federal officials, comparing the impacts of renewing the operating license to the environmental 9 impacts of alternatives allows the NRC to determine whether the environmental impacts of 10 license renewal are so great that preserving the option of license renewal for energy-planning 11 decisionmakers would be unreasonable (Title 10 of the Code of Federal Regulations 12 (10 CFR) 51.95(c)(4)).
13 Energy-planning decisionmakers and owners of the nuclear power plant ultimately decide 14 whether the plant will continue to operate, and economic and environmental considerations play 15 important roles in this decision. In general, the NRCs responsibility is to ensure the safe 16 operation of nuclear power facilities and not to formulate energy policy or encourage or 17 discourage the development of alternative power generation. The NRC does not engage in 18 energy-planning decisions and makes no judgment as to which energy alternatives evaluated 19 would be the most likely alternative in any given case.
20 The remainder of this chapter provides (1) a description of the proposed action, (2) a description 21 of alternatives to the proposed action (including the no-action alternative), and (3) alternatives to 22 LaSalle County Station, Units 1 and 2 (LSCS) license renewal that were considered and 23 eliminated from detailed study. Chapter 4 of this plant-specific supplemental environmental 24 impact statement (SEIS) compares the impacts of renewing the operating licenses of LSCS and 25 continued plant operations to the environmental impacts of alternatives.
26 2.1    Proposed Action 27 As stated in Section 1.1 of this document, the NRCs proposed Federal action is the decision of 28 whether to renew the LSCS operating licenses for an additional 20 years. For the NRC to 29 determine the impacts from continued operation of LSCS, an understanding of that operation is 30 needed. Section 2.1.1 describes normal power plant operations during the license renewal 31 term. LSCS is a two-unit, nuclear-powered steam-electric generating facility that began 32 commercial operation in January 1984 (Unit 1) and October 1984 (Unit 2). The nuclear reactors 33 at both units are General Electric boiling water reactors (BWRs), and together they produce an 34 annual average net output of 2,327 megawatts electric (MWe) (Exelon 2014).
35 2.1.1    Plant Operations during the License Renewal Term 36 Most plant operation activities during license renewal would be the same as, or similar to, those 37 occurring during the current license term (NRC 2013). Section 2.1.1 of NUREG-1437, Generic 38 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS),
39 Revision 1 (NRC 2013), describes the general types of activities that are carried out during the 40 operation of a nuclear power plant, such as LSCS, as follows:
41
* reactor operation; 42
* waste management; 2-1
 
Alternatives Including the Proposed Action 1
* security; 2
* office and clerical work; 3
* surveillance, monitoring, and maintenance; and 4
* refueling and other outages.
5 As stated in the Exelon Generation Company, LLCs (Exelons) Environmental Report (ER) 6 (Exelon 2014), LSCS will continue to operate during the license renewal term in the same 7 manner as it does during the current license term except for, as appropriate, additional aging 8 management programs to address structure and component aging in accordance with 9 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants.
10 2.1.2      Refurbishment and Other Activities Associated with License Renewal 11 Refurbishment activities include replacement and repair of major systems, structures, and 12 components. For example, replacement activities may include replacement of recirculation 13 piping systems for BWRs. The intent of the major refurbishment class of activities characterized 14 in the GEIS (NRC 2013) is to encompass actions that typically take place only once in the life of 15 a nuclear plant, if at all. Refurbishment activities may have an impact on the environment 16 beyond those that occur during normal operations and may require evaluation depending on the 17 type of action and the plant-specific design.
18 In preparation for its license renewal application, Exelon performed an evaluation of LSCS 19 structures, systems, and components in accordance with 10 CFR 54.21, Contents of 20 applicationtechnical information, to identify whether any major refurbishment activities would 21 be necessary to support the continued operation of LSCS during the proposed 20-year period of 22 extended operation (Exelon 2014).
23 Exelon did not identify any major refurbishment or replacement activities needed to support the 24 continued operation of LSCS beyond the existing operating license term (Exelon 2014).
25 Therefore, these activities are not discussed under the proposed action in Chapter 4.
26 2.1.3      Termination of Nuclear Power Plant Operations and Decommissioning after the 27            License Renewal Term 28 NUREG-0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear 29 Facilities: Supplement 1, Regarding the Decommissioning of Nuclear Power Reactors, 30 describes the impacts of decommissioning (NRC 2002). Most activities associated with plant 31 operations would cease with reactor shutdown. Some activities (e.g., security and oversight of 32 spent nuclear fuel) would remain unchanged, whereas others (e.g., waste management; office 33 and clerical work; laboratory analysis; and surveillance, monitoring, and maintenance) would 34 continue at reduced or altered levels. Systems dedicated to reactor operations would cease 35 operations; however, impacts from their physical presence may continue if they are not removed 36 after reactor shutdown. For multiple-unit sites, such as LSCS, shared systems may operate at 37 reduced capacities. Impacts associated with dedicated systems that remain in place or shared 38 systems that continue to operate at normal capacities would remain unchanged.
39 Decommissioning will occur whether LSCS is shut down at the end of its current operating 40 license term or at the end of the period of extended operation. There are no site-specific issues 41 related to decommissioning. The license renewal GEIS concludes that license renewal would 42 have a negligible (SMALL) effect on the impacts of terminating operations and decommissioning 43 on all resources.
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Alternatives Including the Proposed Action 1 2.2      Alternatives 2 As stated above, the NRC has the obligation to consider reasonable alternatives to the 3 proposed action of renewing the licenses for the nuclear reactors at LSCS. To be reasonable, a 4 replacement power alternative must be commercially viable on a utility scale and operational 5 prior to the expiration of the reactors operating licenses, or expected to become commercially 6 viable on a utility scale and operational prior to the expiration of the reactors operating licenses 7 (NRC 2013). The 2013 GEIS update incorporated the latest information on replacement power 8 alternatives; however, rapidly evolving technologies are likely to outpace the information 9 presented in the GEIS. As such, a site-specific analysis of alternatives must be performed for 10 each SEIS, taking into account changes in technology and science since the preparation of the 11 GEIS.
12 Section 2.2.1 below describes the no-action alternative (i.e., the NRC takes no action and does 13 not issue renewed licenses for LSCS). Sections 2.2.2.1-2.2.2.5 describe the characteristics of 14 replacement power alternatives for LSCS.
15 2.2.1    No-Action Alternative 16 At some point, operating nuclear power plants will terminate operations and undergo 17 decommissioning. The no-action alternative represents a decision by the NRC not to renew the 18 operating license of a nuclear power plant beyond the current operating license term. Under the 19 no-action alternative, the NRC does not renew the operating licenses, and the LSCS plant shuts 20 down at or before the end of the current licenses in 2022 and 2023. After shutdown, plant 21 operators will initiate decommissioning in accordance with 10 CFR 50.82, Termination of 22 License.
23 Only those impacts that arise directly as a result of plant shutdown will be addressed in this 24 SEIS. The environmental impacts from decommissioning and related activities are addressed in 25 several other documents, including the decommissioning GEIS (NRC 2002); the license renewal 26 GEIS, Chapter 4 (NRC 2013); and Chapter 4 of this SEIS. These analyses either directly 27 address or bound the environmental impacts of decommissioning whenever Exelon ceases to 28 operate LSCS.
29 Even with renewed operating licenses, LSCS will eventually shut down, and the 30 environmental impacts addressed later in Chapter 4 of this SEIS will occur at that time.
31 As with decommissioning impacts, shutdown impacts are expected to be similar whether they 32 occur at the end of the current license term or at the end of a renewed license term.
33 Termination of operations at LSCS would result in the total cessation of electrical power 34 production. Unlike the alternatives described in Section 2.2.2, the no-action alternative does not 35 meet the purpose and need of the proposed action because it does not provide a means of 36 delivering baseload power to meet future electric system needs. Given the current need for the 37 power generated by LSCS, the no-action alternative would likely create a need for a 38 replacement power alternative. A full range of replacement power alternatives (including new 39 nuclear, fossil fuels, and renewable energy sources) are described in the following section, and 40 their potential impacts are assessed in Chapter 4. Although the NRCs authority only extends to 41 the decision of whether to renew the LSCS operating licenses, the replacement power 42 alternatives described in the following sections represent possible options for energy-planning 43 decisionmakers should the NRC choose not to renew the LSCS operating licenses.
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Alternatives Including the Proposed Action 1 2.2.2      Replacement Power Alternatives 2 In evaluating alternatives to license renewal, the NRC considered energy technologies or 3 options currently in commercial operation, as well as technologies not currently in commercial 4 operation but likely to be commercially available by the time the current LSCS operating 5 licenses expire. The current operating licenses for the LSCS, Units 1 and 2, expire on 6 April 17, 2022, and December 16, 2023, respectively. Alternatives that are not likely to be 7 constructed, permitted, and connected to the grid by the time the LSCS licenses expire were 8 eliminated from detailed consideration.
9 Alternatives that cannot provide the equivalent of LSCSs current generating capacity and, in 10 some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 11 reasonable alternatives, were not considered in detail. Each alternative eliminated is briefly 12 discussed, and the basis for its elimination is provided in Section 2.3. In total, 17 alternatives to 13 the proposed action were considered (see text box) and then narrowed to the 5 alternatives 14 considered in Sections 2.2.2.1-2.2.2.5. The NRC staff evaluated the environmental impacts of 15 these five alternatives and the no-action alternative. They are discussed in depth in Chapter 4 16 of this SEIS.
17 The GEIS presents an overview of some energy technologies but does not reach conclusions 18 about which alternatives are most appropriate. Because many energy technologies are 19 continually evolving in capability and cost and because regulatory structures have changed to 20 either promote or impede development of particular alternatives, the analyses in this chapter 21 may include updated information from the following sources:
22
* U.S. Department of Energy (DOE), U.S. Energy Information Administration (EIA),
23
* other offices within the DOE, 24
* U.S. Environmental Protection Agency (EPA),
25
* industry sources and publications, and 26
* information submitted by Exelon in its ER.
27 The evaluation of each alternative in Chapter 4 of this SEIS considers the environmental 28 impacts across several impact categories: land use and visual resources, air quality and noise, 29 geologic environment, water resources, ecological resources, historic and cultural resources, 30 socioeconomics, human health, environmental justice, and waste management. Most 31 site-specific issues (Category 2) have been assigned a significance level of SMALL, 32 MODERATE, or LARGE. For ecological and historic and archaeological resources, the impact 33 significance determination language is specific to the authorizing legislation (e.g., Endangered 34 Species Act of 1973, as amended (16 U.S.C. 1531 et seq.), and National Historic Preservation 35 Act of 1966, as amended (16 U.S.C. 470 et seq.)). The order of presentation of the alternatives 36 is not meant to imply increasing or decreasing level of impact. Nor does it imply that an 37 energy-planning decisionmaker would be more likely to select any given alternative.
38 To ensure that the alternatives analysis is consistent with state or regional energy policies, the 39 NRC reviewed energy-related statutes, regulations, and policies within the LSCS region. As a 40 result, the staff considers alternatives that include wind power or solar photovoltaic (PV) power, 41 as well as a combination that includes both of them.
42 Region of Influence 43 LSCS is owned and operated by Exelon and provides electricity to the region of influence (ROI) 44 through transmission lines owned by Commonwealth Edison (ComEd) (Exelon 2014). ComEd 2-4
 
Alternatives Including the Proposed Action 1 operates under the PJM Interconnection, LLC Alternatives Evaluated in Depth:
2 (PJM), a regional transmission organization 3 that coordinates the movement of wholesale
* new nuclear 4 electricity in 13 states across the Midwest
* coal-integrated gasification combined-cycle 5 and Northeast (Exelon 2014). ComEd
* natural gas combined-cycle 6 provides service to 3.8 million customers
* combination alternative (wind power, natural gas 7 across northern Illinois. Its service territory        combined-cycle, and solar power) 8 borders Iroquois County to the south, the
* purchased power 9 Wisconsin border to the north, the Iowa 10 border to the west, and the Indiana border to Other Alternatives Considered:
11 the east (ComEd 2015). However, electricity 12 consumption in Illinois is not limited to
* energy efficiency and conservation 13 electricity that is generated within the State.
* solar power 14 Although northern Illinois relies on electricity
* wind power 15 from ComEd, the rest of Illinois and
* biomass 16 surrounding states, which are not part of the
* hydroelectric power 17 PJM, are part of the Midcontinent
* wave and ocean energy 18 Independent System Operator, Inc. (MISO)
* fuel cells 19 (see Figure 2-1) (Exelon 2014).
* delayed retirement 20 If renewed licenses were not issued,
* geothermal power 21 replacement power for LSCS would be
* municipal solid waste 22 required in northern Illinois. Electricity could
* petroleum 23 be replaced by generation sources from a
* supercritical pulverized coal 24 variety of locations. Electricity could be 25 transported from within the PJM; however, the PJM in Illinois is geographically distant from the 26 rest of the PJM region (see Figure 2-1). It is also possible that electricity within MISO could be 27 purchased by PJM, and efforts are currently being made to increase coordination and 28 deliverability between the regional transmission organizations (Ott 2013b). In addition, the State 29 of Illinois has a renewable portfolio standard that includes a stipulation that eligible renewable 30 resources must be procured from facilities located in Illinois or the States that adjoin Illinois 31 (Wisconsin, Indiana, Iowa, Kentucky, Michigan, and Missouri) (ILGA 2011). Renewable 32 resources can be obtained only from other regions of the country if they are not available in 33 Illinois or in the adjoining States (ILGA 2011).
34 Because replacement power would be required in northern Illinois, and any renewable energy 35 resources would need to be procured from facilities in Illinois or the adjoining States, the NRC 36 staff evaluated the impacts of locating replacement power facilities within the States of Illinois, 37 Indiana, Iowa, Kentucky, Michigan, Missouri, and Wisconsin. These seven states constitute the 38 ROI for the NRC staffs analysis of alternatives. The NRC assumes that replacement power 39 would either be produced in northern Illinois within the PJM region or would be purchased by 40 PJM from MISO.
41 In 2012, electric generators in the ROI had a net summer generating capacity of approximately 42 179,000 megawatts (MW). This capacity included units fueled by coal (49 percent), natural gas 43 (27 percent), nuclear (11 percent), and wind (6.6 percent) (EIA 2014c).
44 In 2011, the electric industry in the ROI provided approximately 744 million megawatt hours 45 (MWh) of electricity. Electricity produced in the ROI was dominated by coal (67 percent) and 46 nuclear (21 percent). Although natural gas makes up nearly 30 percent of the installed 47 generating capacity in the ROI, it provides only 6 percent of electricity in the region.
48 Nonhydroelectric renewable energy produced 1.3 percent of the electricity in the ROI 49 (EIA 2014b).
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Alternatives Including the Proposed Action 1                      Figure 2-1. Territories of MISO and PJM Interconnection 2                                    Source: MISO-PJM undated 3 Renewable Energy Legislation in the Region of Influence 4 Renewable energy legislation in Illinois allows the purchase of electricity generation in adjoining 5 States; therefore, any legislation targeting renewable energy in these States could impact a 6 States incentive to develop renewable resources. Five States in the ROI (Illinois, Iowa, 7 Missouri, Wisconsin, and Michigan) have legally mandated renewable energy programs. The 8 State of Indiana has a voluntary program, and State of Kentucky does not have any renewable 9 energy requirements. The paragraphs below briefly outline each States program, including 10 renewable energy goals and benchmarks.
11 In August 2007, Illinois adopted a renewable portfolio standard that requires the States utilities 12 to produce at least 25 percent of their power from renewable sources by 2025, 75 percent of 13 which must come from wind. Solar PV must comprise 6 percent of the annual requirement for 14 calendar year 2015 and thereafter. Other eligible sources include biomass and existing 15 hydroelectric power (DSIRE 2015a). The law also includes an energy efficiency standard that 16 requires utilities to implement cost-effective energy efficiency measures to meet energy savings 17 of 1 percent by calendar year 2016 and thereafter (ILGA 2011). For electric utilities (including 18 ComEd), eligible resources must be located in Illinois; resources can be purchased from 19 adjoining States only if there are insufficient in-State resources (ILGA 2011).
20 Iowas Alternative Energy Production Law requires the States two investor-owned utilities to 21 generate a combined total of 105 MW of their generating capacity from renewable energy 22 sources. A 2007 order allows the utilities to participate in renewable energy credit trading 23 programs by distinguishing between renewable electricity production capacity used to comply 24 with Iowa law and that which can be used to satisfy other states renewable portfolio standards 25 (DSIRE 2014).
26 Missouri adopted a renewable portfolio standard that requires investor-owned utilities to 27 increase their use of renewable sources by 15 percent by 2021 and includes a provision 28 specifying that 2 percent of the renewable portfolio standard requirement must be met by solar 29 energy. Resources can be purchased from outside Missouri, but renewable energy generated 30 in-State receives a multiplier of 1.25 compared to out-of-State generation (DSIRE 2015b).
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Alternatives Including the Proposed Action 1 Wisconsins renewable portfolio standard requires utilities to produce 10 percent of their 2 electricity from renewable sources by 2015. Included in the renewable portfolio standard is a 3 provision that allows electricity providers to create and sell or transfer renewable resource 4 credits and renewable energy certificates. Renewable energy generated outside Wisconsin is 5 eligible, provided that the electricity is distributed to Wisconsin customers (DSIRE 2015c).
6 Michigan enacted a Renewable Energy Standard in 2008 that requires utilities to generate 7 10 percent of their retail electricity sales from renewable energy resources by 2015.
8 The standard also allows energy efficiency and advanced cleaner energy systems to meet part 9 of the requirement. Renewable energy credits can be purchased from in-State or out-of-State 10 facilities, provided that the facilities are located within the retail electric service territory of a 11 utility that is recognized by the Michigan Public Service Commission (DSIRE 2015d).
12 Indiana does not have a mandatory renewable or alternative energy portfolio standard. On 13 July 9, 2012, Indiana adopted a Clean Energy Portfolio Standard, which sets a voluntary goal of 14 10 percent clean energy by 2025, based on the amount of electricity supplied by the utility in 15 2010. Unlike many of the other ROI states, up to 30 percent of the goal may be met with clean 16 coal technology, nuclear energy, combined heat and power systems, natural gas that displaces 17 electricity from coal, and net-metered distributed generation facilities. Fifty percent of qualifying 18 energy must come from within the State. Utilities that participate in the program and meet the 19 program goals are eligible for incentives that are used to pay for the compliance projects 20 (DSIRE 2015e).
21 Kentucky is the only State in the ROI that does not have mandatory or voluntary renewable 22 energy requirements.
23 Given known technological and demographic trends, the EIA predicts that 34 percent of 24 electricity in the United States will be generated by coal in 2040 (EIA 2015). Natural gas 25 generation rose from 16 percent in 2000 to 27 percent in 2013 and is projected to increase to 26 31 percent in 2040 (EIA 2013a, 2015). Electricity generation from renewable energy is 27 expected to grow from 13 percent of total generation in 2013 to 18 percent in 2040 (EIA 2015).
28 However, there are uncertainties that could affect this forecast, particularly the implementation 29 of policies aimed at reducing greenhouse gas emissions, which would have a direct effect on 30 fossil fuel-based generation technologies.
31 The remainder of this section describes replacement power alternatives to license renewal 32 considered in depth. These include a new nuclear alternative in Section 2.2.2.1; a 33 coal-integrated gasification combined-cycle (IGCC) alternative in Section 2.2.2.2; a natural gas 34 combined-cycle (NGCC) alternative in Section 2.2.2.3; a combination natural gas, wind, and 35 solar power alternative in Section 2.2.2.4; and a purchased power alternative in Section 2.2.2.5.
36 Table 2-1 summarizes key design characteristics of the alternative technologies evaluated in 37 depth. The environmental impacts of these alternatives are evaluated in Chapter 4.
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Alternatives Including the Proposed Action 1      Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 2                                          Considered in Depth(a)
New Nuclear                                                              Combination Alternative              IGCC Alternative          NGCC Alternative      Alternative Summary of    Two-unit nuclear          Four 618-MWe units, Five 560-MWe                One 360 MWe Alternative    plant, each with          for a total of            units, for a total of NGCC unit; a 1,120 MWe, for a total 2,472 MWe                    2,800 MWe            1,813 MWe wind of 2,240 MWe                                                              farm; and a 227 MWe installed solar PV facility, for a total of 2,400 MWe Location      An existing nuclear      On the LSCS site or      On the LSCS site. The NGCC plant site or retired    at another existing      New transmission      component would coal plant site outside  power plant site.        line(s) and other    be located on the Illinois. New            New transmission          infrastructure        LSCS site. The transmission line(s)      line(s) and other        upgrades may be      wind and solar and other                infrastructure            required; would      components would infrastructure            upgrades may be          require construction  be spread across upgrades may be          required. Some            of a new or          multiple sites required. Some            facilities (e.g., support upgraded pipeline. throughout the ROI.
facilities (e.g., support buildings, potable        Some facilities buildings, potable        water supply, and        (e.g., support water supply, and        sanitary discharge        buildings, potable sanitary discharge        structures) could be      water supply, and structures) could be      shared with existing      sanitary discharge shared with existing      plant.                    structures) could be plant.                                              shared with existing plant.
Cooling        Closed-cycle with        Closed-cycle with        Closed-cycle with    For the NGCC System        natural draft cooling    mechanical draft          mechanical draft      portion, towers. Cooling          cooling towers.          cooling towers.      closed-cycle with water withdrawal        Cooling water            Cooling water        mechanical draft 56 mgd; consumptive      withdrawal25 mgd;        withdrawal          cooling towers.
water use42 mgd          consumptive water        17 mgd;              Cooling water (NRC 2008).              use20 mgd                consumptive water    would be 15% of (NETL 2013a).            use13 mgd            that required for (NETL 2013a).        NGCC alternative.
Minimal water use for wind and solar.
Land          556 ac (225 ha)          2,000 ac (800 ha) for    94 ac (38 ha) for the Wind farms would Require-      (NRC 2008); 520 ac        the major permanent      plant, including      require 3,376 ac ments          (210 ha) for uranium      facilities; 1,100 ac      pipelines            (1,366 ha) to mining and                (450 ha) per year for    (Exelon 2014);        10,127 ac processing(b)            mining (DOE 2010a)        10,080 ac            (4,098 ha) (WAPA (NRC 2013)                                          (4,079 ha) for gas    and FWS 2013);
extraction and        solar PV facilities collection            would require (NRC 1996)            6,749 ac (2,731 ha)
(Ong et al. 2013).
For the NGCC portion, land use would remain the 2-8
 
Alternatives Including the Proposed Action New Nuclear                                                                    Combination Alternative                IGCC Alternative        NGCC Alternative          Alternative same at 94 ac (38 ha)
(Exelon 2014).
Work Force          3,500 workers during        4,600 workers during    1,783 workers            Solar PV peak construction;          peak construction;      during peak              600 workers during 812 workers during          420 workers during      construction;            peak construction, operations                  operations              94 workers during        60 workers during (NRC 2008)                  (DOE 2010a)              operations                operations (Exelon 2014)            (DOE 2010b).
Wind931 workers during construction, 566 workers during operations (DOE 2008).
NGCCnumber of construction and operations workers would be less than the NGCC alternative but would not be a linear reduction because of the need for a minimum number of workers regardless of the size of the plant.
Key: ac = acres, ha = hectares, IGCC = coal-integrated gasification combined-cycle (alternative), mgd = million gallons per day, MWe = megawatts electric, NGCC = natural gas combined-cycle (alternative), PV = photovoltaic, and ROI = region of influence.
(a) Because  of the speculative nature of using purchased power to replace LSCS capacity and because of the inherent variability of characteristics associated with such an approach, this table does not include the purchased power alternative.
(b) This is normalized to model the light water reactor annual fuel requirement. Forty-two percent of this land requirement is temporarily committed land.
Sources: DOE 2008, 2010a, 2010b; Exelon 2014; NETL 2013a; NRC 1996, 2008, 2013; Ong et al. 2013; WAPA and FWS 2013 1 2.2.2.1        New Nuclear Alternative 2 In this section, the NRC staff describes the new nuclear alternative. The NRC staff evaluates 3 the environmental impacts from this alternative in Chapter 4.
4 The NRC staff considered the construction of a new nuclear plant to be a reasonable alternative 5 to license renewal. For example, nuclear generation currently provides 21 percent of electricity 6 generation in the ROI (EIA 2014b). Twelve nuclear power plants operate in the ROI; 7 eight applicants have received renewed licenses, and three additional applicants have applied 8 for renewed licenses from the NRC (including LSCS) (NRC 2015). In addition, there is interest 9 in new nuclear power plant development in the region; combined operating license (COL) 10 applications have been filed for two new nuclear power plants in the ROI. On July 24, 2008, 2-9
 
Alternatives Including the Proposed Action 1 Union Electric Company submitted a COL application for Callaway Plant, Unit 2, in Callaway 2 County, Missouri, on the existing Callaway site (AmerenUE 2009). However, Ameren UE has 3 since announced that they are canceling their COL application (Barker 2015). An application 4 was also filed in September 2008 for Enrico Fermi Atomic Power Plant, Unit 3, in Monroe 5 County, Michigan, on the existing Fermi site. On May 1, 2015, the NRC issued a COL 6 authorizing DTE Electric Company to build and operate an economic simplified BWR at the 7 Fermi site (Volume 80 of the Federal Register, 26302 (80 FR 26302)). The NRC staff 8 determined that there may be sufficient time for Exelon to prepare and submit an application, 9 build, and operate two new nuclear units using a certified design before the LSCS licenses 10 expire in April 2022 and December 2023.
11 In evaluating the new nuclear alternative, the NRC staff assumed that two new nuclear reactors 12 would be built on an existing nuclear or coal power plant site, allowing for the maximum use of 13 existing ancillary facilities at those locations, such as support buildings and transmission 14 infrastructure. In 1987, Illinois enacted a moratorium preventing the construction of new nuclear 15 power plants within the State. Until the moratorium is lifted, a new nuclear alternative would 16 require siting elsewhere in the ROI. For the purposes of this analysis, the NRC relied on the 17 Vogtle Electric Generating Plant (Vogtle), Units 3 and 4 (located in Waynesboro, Georgia), COL 18 environmental impact statement for technological parameters for the new nuclear alternative 19 because the Vogtle, Units 3 and 4, COL considers two new nuclear reactor units with a similar 20 output as LSCS and is representative of the reactors that could be constructed in the ROI 21 before LSCSs licenses expire (NRC 2011). As such, the NRC staff assumed 22 two Westinghouse AP1000 reactors with a net electrical output of 2,240 MWe would replace 23 LSCSs current reactors for this alternative. The NRC staff estimated that 324 ac (131 ha) of 24 land would be required on a long-term basis because of permanent facilities, and an additional 25 232 ac (94 ha) would be disturbed for temporary facilities, a laydown area, and storage of 26 dredge material (NRC 2008).
27 The heat rejection demands of a new nuclear alternative would be similar to those of LSCS.
28 The new reactors may require a new cooling system (including natural draft cooling towers and 29 intake and discharge structures). The NRC staff assumes that water requirements for the new 30 nuclear alternative would be similar to current water use at LSCS. A new onsite transmission 31 line and drinking water wells may be required if insufficient infrastructure occurs on the site.
32 Construction materials would be delivered by a combination of rail spur, truck, and barge, 33 depending on the specific site location. It is possible that modifications would be required to 34 deliver such materials, depending on the existing infrastructure at the site; modifications could 35 include new rail lines or access roads.
36 The NRC staff also considered the installation of multiple small modular reactors as an 37 alternative to renewing the LSCS licenses. The NRC established the Advanced Reactor 38 Program in the Office of New Reactors because of considerable interest in small modular 39 reactors along with anticipated license applications by vendors. Small modular reactors are 40 approximately 300 MW or less, would have lower initial capacity than that of large-scale units, 41 and would have siting flexibility for locations that are not large enough to accommodate 42 traditional nuclear reactors (DOE undated). As of October 2015, no applications for small 43 modular reactors have been submitted to the NRC. The DOE has estimated that the technology 44 may achieve commercial operation by 2021 to 2025 (DOE undated). Because small modular 45 reactors are not expected to be operational at a commercial scale until near the time LSCSs 46 licenses expire, it is unlikely that eight new small modular reactors (the number of units required 47 to replace LSCSs current output) could be constructed in the ROI; therefore, this analysis 48 focuses on nuclear generation by larger nuclear units.
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Alternatives Including the Proposed Action 1 2.2.2.2      IGCC Alternative 2 In this section, the NRC staff describes the IGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4.
4 Coal provides the greatest share of electrical power in the ROI, and in 2010, coal represented 5 49 percent of installed generation capacity and accounted for 67 percent of all electricity 6 generated in the ROI (EIA 2014b). IGCC is a technology that generates electricity from coal 7 and combines modern coal gasification technology with both gas-turbine and steam-turbine 8 power generation. The technology is cleaner than conventional pulverized coal plants because 9 some of the major pollutants are removed from the gas stream before combustion. An IGCC 10 power plant consists of coal gasification and combined-cycle power generation. Coal gasifiers 11 convert coal into a gas (synthesis gas, also referred to as syngas), which fuels the 12 combined-cycle power generating units. The combined-cycle system for a 618-MWe IGCC 13 power plant includes two combustion turbines, two heat recovery steam generators, and a 14 steam turbine. The combined-cycle units combust gas in one or more combustion turbines, and 15 the resulting hot exhaust gas is then used to heat water into steam to drive a steam turbine.
16 The steam turbine then uses the heat from the gas turbines exhaust through a heat recovery 17 steam generator to produce additional electricity (DOE 2010a). This two-cycle process has a 18 high rate of efficiency because the exhaust heat that would otherwise be lost is captured and 19 reused. In addition, the power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and 20 particulate emissions by removing constituents from the syngas before combustion. Nearly 21 100 percent of the nitrogen from the syngas would be removed before combustion in the gas 22 turbines and would result in lower nitrogen oxide emissions compared to conventional coal-fired 23 power plants (DOE 2010a).
24 IGCC power plants have been in operation since the mid-1990s; the Wabash Rice IGCC 25 repowering project in Indiana and the Polk Power Station in Florida are two examples of 26 operating IGCC plants. Recently, there has been an increased interest in new IGCC projects, 27 and multiple new projects have been proposed or have recently begun operations in the 28 United States. The Duke Energy Edwardsport Generation Station (Edwardsport) in Indiana is a 29 618-MWe IGCC power plant in the ROI that began commercial operation in June 2013. Duke 30 Energy estimates that the IGCC plant will produce 10 times as much power as the retired coal 31 plant it replaced with 70 percent fewer emissions of sulfur dioxide, nitrogen oxides, and 32 particulates. The IGCC plant will reduce carbon emissions per megawatt hour by nearly half 33 compared to conventional coal-fired plants (Duke Energy 2013). In addition, Edwardsport has 34 the potential for carbon capture and geologic sequestration. Space has been reserved at the 35 site for carbon dioxide capture equipment (NETL 2013b).
36 Many IGCC power plants have been designed with carbon capture and storage (CCS) to further 37 reduce carbon dioxide emissions. The Kemper County IGCC project in east-central Mississippi 38 proposes to use CCS to reduce carbon dioxide emissions by almost 70 percent by removing 39 carbon from the syngas post-gasification (DOE 2010a). According to a 2013 National Energy 40 Technology Laboratory (NETL) report, nine IGCC projects totaling over 4,000 MW are currently 41 active; these projects are in the planning stages, or they have begun construction.
42 Thirteen projects have been proposed and subsequently canceled for a variety of reasons, 43 including air quality issues, state laws and regulations, redirected focus on gas-fired generation 44 and renewables, and unanticipated rising costs (NETL 2013c).
45 IGCC technology and proposed projects have experienced a number of setbacks and 46 opposition, hindering IGCCs ability to fully integrate into the energy market. The most 47 significant roadblock is IGCCs high capital cost compared to conventional coal-fired power 48 plants. Cost overruns have been experienced at both the Edwardsport IGCC project and the 2-11
 
Alternatives Including the Proposed Action 1 Kemper County IGCC project. FutureGen, an IGCC plant featuring CCS, lost DOE financial 2 support because of escalating cost estimates (Reuters 2012). Other issues include construction 3 timeline overruns, a limited track record for reliable performance, and opposition from an 4 environmental perspective.
5 Despite some of the current setbacks and concerns associated with IGCC projects, the NRC 6 staff considers IGCC technology to be a reasonable source of baseload power to replace LSCS 7 by the time its licenses expire in 2022 and 2023 because of the current regulatory framework 8 and the number of active IGCC plants within the ROI. On August 3, 2015, EPA signed a final 9 rule for carbon pollution that would apply to new fossil fuel-fired power plants 10 (80 FR 64661-65120). The action establishes performance standards for utility boilers and 11 IGCC units based on partial implementation of a CCS system as a method of emission 12 reduction. The emission limit for these sources is 1,305 lb carbon dioxide per megawatt hour 13 (CO2/MWh), and any new coal-fired power plants could require CCS in order to achieve this 14 emission limit.
15 Overall, the NRC staff considers IGCC power plants as an alternative to LSCS because the 16 Edwardsport IGCC project in Indiana is currently in operation and because the Kemper County 17 IGCC project in Mississippi is under construction. The technology parameters for these plants 18 are considered the current state of technology and are used here to describe a hypothetical 19 IGCC power plant located on an existing power plant site within the ROI.
20 To replace the electricity that LSCS generates, the NRC staff considered four IGCC units, each 21 with a net capacity of 618 MWe. Various coal sources are available to coal-fired power plants in 22 the ROI. For the purpose of this evaluation, the NRC staff assumes that the IGCC alternative 23 would burn a sub-bituminous coal based on the type of coal used in electric plants in Illinois.
24 The NRC staff presumes that coal burned in Illinois will be representative of coal that would be 25 burned in an IGCC alternative regardless of where it may be located (EIA 2012). The IGCC 26 units would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 27 removing constituents from the syngas. In addition, the units would be designed with the 28 potential to add CCS later. Using CCS, carbon dioxide emission would be compressed and 29 piped off site where it could be sold for beneficial use or geologic storage.
30 The IGCC alternative would be located at an existing site (such as an existing power plant site) 31 to maximize availability of infrastructure and to reduce other environmental impacts. Depending 32 on the specific site location, there might be a need to construct new intake and discharge 33 facilities and a new cooling system. The IGCC alternative would use about the same amount of 34 water as LSCS and a similar amount as the Edwardsport IGCC plant. The NRC staff assumes 35 that the cooling system would use a closed-cycle system with mechanical draft cooling towers.
36 This system would withdraw 25 million gallons per day (gpd) (95 million liters per day (Lpd)) of 37 water and would consume 20 million gpd (76 million Lpd). Onsite visible structures could 38 include the boilers, exhaust stacks, intake and discharge structures, mechanical draft cooling 39 towers, transmission lines, and an electrical switchyard. Construction materials would be 40 delivered by a combination of rail spur, truck, and barge, depending on the specific site location.
41 Modifications may be required to deliver such materials; modifications could include new rail 42 lines or access roads.
43 The NRC staff also considered supercritical pulverized coal (SCPC) as an alternative to 44 renewing the LSCS licenses. SCPC was dismissed as the coal alternative because of new 45 regulations aimed at limiting the environmental impacts from conventional pulverized coal 46 plants. The presence of active IGCC plants in the ROI also contributed to the selection of IGCC 47 for analysis.
2-12
 
Alternatives Including the Proposed Action 1 2.2.2.3      NGCC Alternative 2 In this section, the NRC staff describes the NGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4.
4 Natural gas represents nearly 30 percent of installed generation capacity in the ROI but 5 provides only 6 percent of all electrical power in the ROI (EIA 2014b, 2014c). Nationwide, the 6 percentage of power generated by natural gas is expected to rise through 2040, although the 7 actual rise in natural gas generation will depend on future natural gas prices (EIA 2013a). The 8 NRC staff considers the construction of an NGCC power plant to be a reasonable alternative to 9 license renewal because it is a feasible, commercially available option for providing electrical 10 generating capacity beyond the expiration of LSCSs current licenses.
11 Baseload NGCC power plants have proven their reliability and can have capacity factors as high 12 as 85 percent. In an NGCC system, electricity is generated using a gas turbine that burns 13 natural gas. A steam turbine uses the heat from gas turbine exhaust through a heat recovery 14 steam generator to produce additional electricity. This two-cycle process has a high rate of 15 efficiency because the exhaust heat that would otherwise be lost is captured and reused. Like 16 other fossil fuel sources, NGCC power plants are a source of greenhouse gases, including 17 carbon dioxide. An NGCC power plant, however, produces significantly fewer greenhouse 18 gases per unit of electrical output than conventional coal-powered plants.
19 To replace the electricity that LSCS generates, the NRC staff considered five NGCC units, each 20 with a net capacity of 560 MWe (NETL 2007). The NRC staff assumes that each plant 21 configuration consists of two combustion turbine generators, two heat recovery steam 22 generators, and one steam turbine generator with mechanical draft cooling towers for heat 23 rejection. The power plant is assumed to incorporate a selective catalytic reduction system to 24 minimize the plants nitrogen oxide emissions (NETL 2007).
25 This 2,800-MWe NGCC plant would consume 124 billion cubic feet (3,500 million cubic meters) 26 of natural gas annually, assuming an average heat content of 1,021 British thermal units per 27 cubic foot (EIA 2013c). Natural gas would be extracted from the ground through wells, and then 28 it would be treated to remove impurities and blended to meet pipeline gas standards before 29 being piped through the State pipeline system to the plant site. This NGCC alternative would 30 produce relatively little waste, primarily in the form of spent catalysts used for control of nitrogen 31 oxide emissions.
32 The NGCC alternative would be located on undeveloped land at LSCS to maximize availability 33 of infrastructure and to reduce other environmental impacts. Depending on the specific site 34 location, there might be a need to construct new intake and discharge facilities and a new 35 cooling system. Because NGCC power plants generate much of their power from a gas-turbine 36 combined-cycle plant and because the overall thermal efficiency of this type of plant is high, an 37 NGCC alternative would require less cooling water than LSCS would. This system would 38 withdraw 17 million gpd (64 million Lpd) of water and would consume 13 million gpd 39 (49 million Lpd). The NRC staff assumes that the cooling system would use a closed-cycle 40 system with mechanical draft cooling towers. Onsite visible structures could include the cooling 41 towers, exhaust stacks, intake and discharge structures, transmission lines, natural gas 42 pipelines, and an electrical switchyard. Construction materials could be delivered by a 43 combination of rail spur, truck, and barge. Modifications may be required to deliver such 44 materials; modifications could include new rail lines or access roads.
45 2.2.2.4      Combination Alternative (NGCC, Wind, and Solar) 46 In this section, the NRC staff describes the combination alternative to the continued operation of 47 LSCS consisting of an NGCC facility constructed at an existing power plant site and operating in 2-13
 
Alternatives Including the Proposed Action 1 conjunction with land-based wind farms and solar energy facilities, all of which would be located 2 within the ROI. The NRC staff evaluates the environmental impacts from this alternative in 3 Chapter 4.
4 To serve as an effective baseload power alternative to the LSCS reactors, this combination 5 alternative must be capable of providing an equivalent amount of baseload power. For the 6 purpose of this evaluation, the NRC staff presumes that NGCC, wind farms, and solar PV 7 facilities would comprise the combination alternative.
8 NGCC Portion of the Combination Alternative 9 To produce its required share of power (360 MWe), the NGCC portion, operating at an expected 10 capacity factor of 85 percent (NETL 2007), would need to have a nameplate rating of 11 approximately 425 MWe.
12 In 2013, the EIA reported that natural gas-fired power plants are generally used infrequently for 13 shorter periods to meet peak demand. Capacity factors for natural gas plants averaged less 14 than 5 percent during off-peak demand hours for most regions of the country. Natural gas is 15 used for these peaker plants because natural gas combustion turbines can respond quickly; 16 therefore, they tend to be used to meet short-term increases in electricity demand (EIA 2013d).
17 A report prepared by CITI Research stated that gas-fired power plants can help overcome the 18 intermittent nature of renewable energy (Channell et al. 2012). The peaking aspect of natural 19 gas-fired power plants makes natural gas an ideal addition to an otherwise renewable energy 20 combination alternative.
21 The NRC staff assumed that one new NGCC unit of the type described in Section 2.2.2.3 would 22 be constructed and installed at LSCS with a total net capacity of 360 MWe. The appearance of 23 an NGCC unit would be similar to that of the full NGCC alternative considered in 24 Section 2.2.2.3, although only one unit would be constructed. The NRC staff assumes that the 25 NGCC portion of this alternative, which is assumed to be located at LSCS, would use existing 26 electrical switchyards, substations, and transmission lines. Depending on the existing site 27 conditions, it is possible that intake and discharge structures of the existing cooling system 28 could continue in service but would be connected to a new closed-cycle cooling system. For the 29 purposes of this analysis, the NRC staff assumes that the NGCC portion of the combination 30 would use mechanical draft cooling towers.
31 Wind Portion of the Combination Alternative 32 The NRC staff assumes that the wind-generated power from this combination alternative would 33 come from land-based wind farms, which would be located in the ROI within the States of 34 Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, or Wisconsin. The wind portion, assuming 35 a capacity factor of 30 percent, would require a nameplate capacity of 6,042 MWe (WAPA and 36 FWS 2013).
37 The American Wind Energy Association reports a total of more than 67,000 MW of installed 38 wind energy capacity nationwide as of June 30, 2015 (DOE 2015). As of June 2015, Texas is 39 by far the leader in installed land-based capacity with 15,635 MW. Two States in the ROI have 40 the third and fifth largest installed capacity: Iowa with 5,708 MW, followed by Illinois with 41 3,667 MW (DOE 2015). The installed wind capacity in the ROI has been increasing annually by 42 1,000 MWe to 2,500 MWe in each of the past 8 years, for a total of over 13,000 MWe of 43 additional wind capacity from 2007 to 2014 (DOE 2015). Therefore, the NRC staff considers 44 6,042 MW of wind energy to be a reasonable amount by the time the LSCS licenses expire in 45 2022 and 2023. As is the case with other renewable energy sources, the feasibility of wind 46 resources serving as alternative baseload power is dependent on the location (relative to 47 expected load centers), value, accessibility, and constancy of the resource. Wind energy must 2-14
 
Alternatives Including the Proposed Action 1 be converted to electricity at or near the point where it is extracted, and there are limited energy 2 storage opportunities available to overcome the intermittency and variability of wind resources.
3 At the current stage of wind energy technology development, wind resources in wind power 4 class 3 and higher are suitable for most utility scale applications (NREL 2014a). Wind power 5 class 3 is defined as having a wind speed of 15.7 miles per hour (7.0 meters per second) and a 6 wind density of 500 watts per square meter at 164 ft (50 m) (NREL 2014a). Each State in the 7 ROI, other than Kentucky, has wind resources meeting this power class, with the highest 8 concentrations occurring in Iowa and Illinois (NREL 2015a).
9 Individual wind turbine capacity increased from 0.71 MW in 1999 to 1.79 MW in 2010. The size 10 of turbine most frequently installed in the United States in recent years is the 1.5-MW turbine 11 (WAPA and FWS 2013). For the purposes of this analysis, the NRC staff assumes wind 12 turbines with a capacity of 1.79 MW. The capacity factors of land-based wind farms are lower 13 than offshore wind farms (WAPA and FWS 2013). For the wind portion of the combination 14 alternative, the NRC staff assumed a capacity factor of 30 percent, resulting in an estimated 15 total net capacity of 1,813 MWe. Wind turbines must be well separated from each other to 16 avoid interferences to wind flowing through the wind farm, resulting in wind farms requiring 17 substantial amounts of land. Wind turbines may require as much as 1 to 3 ac (0.4 to 1.2 ha) of 18 land for each turbine (WAPA and FWS 2013). Based on the size of the turbines and amount of 19 land required between each turbine, approximately 3,376 turbines and 3,376 to 10,127 ac 20 (1,366 to 4,098 ha) would be required for the wind portion of the combination alternative.
21 Wind energys intermittency affects its viability and value as a baseload power source.
22 However, the variability of wind-generated electricity can be lessened if the proposed wind 23 farms were located at a large distance from one another and were operated as interconnected 24 wind farms, an aggregate controlled from a central point. Distance separation ensures that the 25 two wind farms will not simultaneously experience the same climate, and power will likely be 26 produced at some of the wind farms at any given time (Archer and Jacobson 2007).
27 Solar Photovoltaic Portion of the Combination Alternative 28 The solar portion of the combination alternative would be generated through one or more solar 29 PV energy facilities located in the ROI. Assuming a capacity factor of 19 percent, the solar 30 energy facilities would need a collective nameplate rating of 1,193 MWe. Solar PV technologies 31 could be installed on building roofs at existing residential, commercial, or industrial sites or at 32 larger standalone solar facilities.
33 Nationwide, growth in large solar PV facilities (greater than 5 MW) has resulted in an increase 34 from 70 MW in 2009 to over 700 MW installed capacity in 2011. As of January 2012, it is 35 estimated that more than 11,000 MW of large solar PV projects have signed power purchase 36 agreements (Mendelsohn et al. 2012). Over 9,000 MW of those solar projects are 50 MW or 37 greater, although most are located in the southwestern United States (Mendelsohn et al. 2012).
38 As described in Section 2.2.2, two States in the ROI (Missouri and Illinois) have renewable 39 energy legislation that includes requirements for solar PV technology. Missouris renewable 40 portfolio standard includes a provision specifying that 2 percent of the renewable portfolio 41 standard requirement must be met by solar energy by 2021. Illinois renewable portfolio 42 standard specifies that solar PV must comprise 6 percent of the annual requirement for 43 compliance year 2015-2016 and thereafter. As of 2012, only 33 MW of solar energy capacity 44 had been installed in the ROI (EIA 2014c).
45 Solar PV resources in the ROI range from 4.0 to 5.0 kilowatt hours per square meter per day 46 (kWh/m2/day). The most viable solar resources are located in Missouri, Iowa, and southern 47 Illinois and Indiana (NREL 2015b). Economically viable solar resources are considered to be 48 6.75 kWh/m2/day and greater (BLM and DOE 2010). As is the case with wind energy sources, 2-15
 
Alternatives Including the Proposed Action 1 the feasibility of solar energy resources serving as alternative baseload power is dependent on 2 the location, value, accessibility, and constancy of the resource. Solar PV uses solar panels to 3 convert solar radiation into usable electricity. Solar cells are formed into solar panels that can 4 then be linked into PV arrays to generate electricity. The electricity generated can be stored, 5 used directly, fed into a large electricity grid, or combined with other electricity generators as a 6 hybrid plant. Solar PV can generate electricity whenever there is sunlight, regardless of 7 whether the sun is directly shining on solar panels. Therefore, solar PV technologies do not 8 need to directly face and track the sun, which has allowed solar PV systems to have broader 9 geographical use than concentrated solar power (Ardani and Margolis 2011). Because the ROI 10 contains average solar PV resources and because solar PV is a commercially available option 11 for providing electrical generating capacity, the NRC staff considers the construction of solar PV 12 facilities to be a reasonable alternative to license renewal when combined with wind and NGCC.
13 For the purposes of this analysis, the NRC staff assumes solar PV facilities with a capacity 14 factor of 19 percent (Ardani and Margolis 2011). Solar PV facilities may require 6.2 ac (2.5 ha) 15 of land per megawatt (NRC 2013). Although not all of this land would be cleared of vegetation 16 and permanently impacted, it represents the land enclosed in the total site boundary of the solar 17 facility (Ong et al. 2013). For the solar portion of this combination alternative, approximately 18 7,397 ac (2,993 ha) would be required to support an installed net capacity of 227 MWe. In this 19 analysis, the NRC staff does not speculate on the number and size of individual solar facilities, 20 nor their locations within the ROI. However, as stated above, some of the output could be 21 realized by solar PV installations on building roofs at existing residential, commercial, or 22 industrial sites or at larger standalone solar facilities. To the extent that rooftop or 23 building-integrated solar PV installations remain popular, land impacts would be relatively minor.
24 Solar PV systems do not require water for cooling purposes, but a small amount of water is 25 needed to clean the panels and for potable water for the workforce. Impacts identified in the 26 U.S. Department of the Interior Bureau of Land Management (BLM) and DOEs Solar Energy 27 Programmatic Environmental Impact Statement (PEIS) (BLM and DOE 2010, 2012) provide 28 information used in the analyses presented in the impact sections in Chapter 4.
29 2.2.2.5      Purchased Power Alternative 30 In this section, the NRC staff describes purchased power as an alternative to the continued 31 operation of LSCS.
32 The impacts from purchased power would depend substantially on the generation technologies 33 used to supply the purchased power. Impacts from operation of other electricity generators 34 would likely occur in the ROI. As discussed in Section 2.2.1, replacement power for LSCS 35 would be required in northern Illinois and could come from anywhere within Illinois or adjoining 36 states in either the PJM or MISO Regional Transmission Organizations (RTOs). Given the large 37 geographic area, multiple RTOs within the ROI, and wide-ranging generating facilities, the NRC 38 staff considers purchased power to be a feasible source of baseload power to replace LSCS by 39 the time the licenses expire in 2022 and 2023.
40 Purchased power would likely come from the most common types of electricity generation within 41 the ROI: coal, natural gas, nuclear, and wind. All these power sources are discussed as 42 alternatives to license renewal of LSCS and are identified in Sections 2.2.2.2 to 2.2.2.4.
43 Construction and operational impacts from these sources of electricity generation are 44 considered in Chapter 4. Purchased power may require new transmission lines (which may 45 require new construction) and may also rely on older and less-efficient power plants operating at 46 higher capacities than they currently operate or on new facilities that would be constructed.
47 During operations, impacts from nuclear, coal-fired, and natural gas-fired plants and from wind 2-16
 
Alternatives Including the Proposed Action 1 and solar energy projects would be similar to those described under the new nuclear, coal, 2 natural gas, and combination alternatives described in Chapter 4 for all resource areas.
3 2.3      Alternatives Considered but Dismissed 4 Alternatives to LSCS license renewal that were considered and eliminated from detailed study 5 are presented in this section. These alternatives were eliminated because of technical resource 6 availability or current commercial limitations. Many of these limitations would continue to exist 7 when the current LSCS licenses expire.
8 2.3.1      Energy Conservation and Energy Efficiency 9 Energy conservation can include reducing energy demand through behavioral changes or 10 altering the shape of the electricity load and usually does not require the addition of new 11 generating capacity. Conservation and energy efficiency programs are more broadly referred to 12 as demand-side management.
13 Conservation and energy efficiency programs can be initiated by a utility, transmission 14 operators, the state, or other load-serving entities. The State of Illinois renewable portfolio 15 standard includes an energy efficiency portfolio standard that requires utilities to reduce electric 16 usage by 2 percent of demand by 2015 (DSIRE 2015a), which is equivalent to 4 million MWh, 17 only 20 percent of the amount that would be required to offset LSCSs current electrical 18 generation.
19 In general, residential electricity consumers have been responsible for the majority of peak load 20 reductions, and participation in most programs is voluntary. Therefore, the existence of a 21 program does not guarantee that reductions in electricity demand would occur. The GEIS 22 concludes that, although the energy conservation or energy efficiency potential in the 23 United States is substantial, there are likely no cases where an energy efficiency or 24 conservation program has been implemented expressly to replace or offset a large baseload 25 generation station (NRC 2013). Although significant energy savings are possible in the ROI 26 through demand-side management and energy efficiency programs, conservation and energy 27 efficiency programs are not likely to replace LSCS as a standalone alternative; therefore, the 28 NRC staff does not consider conservation and energy efficiency to be a reasonable alternative 29 to license renewal.
30 2.3.2      Solar 31 Solar power, including solar PV and concentrated solar power technologies, produce power 32 generated from sunlight. PVs convert sunlight directly into electricity using solar cells made 33 from silicon or cadmium telluride. Concentrating solar power uses heat from the sun to boil 34 water and produce steam to drive a turbine connected to a generator to produce electricity 35 (NREL 2014b). To be considered a viable alternative, a solar alternative must replace the 36 amount of electricity LSCS provides. Assuming a capacity factor of 19 percent (Ardani and 37 Margolis 2011), approximately 12,400 MWe of electricity would need to be generated by solar 38 energy facilities in the seven-State ROI.
39 In 2012, 33 MW of solar energy capacity was installed in the ROI (EIA 2014c). The DOEs 40 National Renewable Energy Laboratory (NREL) reports that the States in the ROI receive solar 41 insolation of 4.0 to 5.0 kWh/m2/day, which is considered low to average (NREL 2015b). For 42 utility-scale development, insolation levels below 6.5 kWh/m2/day are not considered 43 economically viable given current technologies (BLM and DOE 2010). There is more potential 44 for solar development using local PV applications, such as rooftop solar panels, than through 2-17
 
Alternatives Including the Proposed Action 1 utility-scale solar facilities. In addition, a solar facility can only generate electricity when the sun 2 is shining. Energy storage can be used to overcome intermittency for concentrating solar power 3 facilities; however, current and foreseeable storage technologies that have been paired with 4 solar power facilities have a much smaller capacity than would be necessary to replace LSCS.
5 Taking all of the factors above into account, it is unlikely that solar PV or concentrated solar 6 power technologies could serve as baseload power in the ROI to replace LSCSs current 7 electricity output. Given the modest levels of solar energy available throughout the ROI, the 8 lack of substantial installed solar capacity in the ROI and the weather-dependent intermittency 9 of solar power, the NRC staff concludes that a solar power energy facility in the ROI would not 10 be a reasonable alternative to license renewal. The NRC staff described an alternative of solar 11 power in combination with wind and an NGCC plant in Section 2.2.2.4.
12 2.3.3      Wind 13 Two States in the ROI have the third and fifth largest installed capacity in the Nation: Iowa with 14 5,708 MW, followed by Illinois with 3,667 MW (DOE 2015). The installed wind capacity in the 15 ROI has been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 8 years, for 16 a total of over 13,000 MWe of additional wind capacity from 2007 to 2014 (DOE 2015). All of 17 the wind energy facilities and the electricity generation from wind currently being produced in 18 the ROI are land based. To be considered a viable alternative, a wind alternative must replace 19 the amount of electricity LSCS provides. Assuming a capacity factor of 30 percent for 20 land-based wind and 40 percent for offshore wind, a range of 5,665 to 7,553 MWe of electricity 21 would need to be generated by some combination of land-based and offshore wind energy 22 facilities in the seven-State ROI.
23 As is the case with other renewable energy sources, the feasibility of wind resources serving as 24 alternative baseload power is dependent on the location (relative to expected load centers),
25 value, accessibility, and constancy of the resource. Wind energy must be converted to 26 electricity at or near the point where it is extracted, and there are limited energy storage 27 opportunities available to overcome the intermittency and variability of wind resource availability.
28 Although wind power is intermittent and although individual facilities are unable to provide 29 baseload power, it has been proposed that multiple interconnected wind installations separated 30 by long distances could theoretically function as a virtual power plant and could provide 31 baseload power since individual facilities would be exposed to different weather and wind 32 conditions. To date, however, no states or utilities operate arrays of wind installations as virtual 33 power plants.
34 Given the amount of wind capacity necessary to replace LSCS and the intermittency of wind 35 power, the NRC staff finds a completely wind-based alternative to be unreasonable. However, 36 the NRC staff also concludes that, when used in combination with other technologies with 37 inherently higher capacity factors, wind energy can provide a viable alternative. The NRC staff 38 described such a possible combination alternative in Section 2.2.2.4.
39 2.3.3.1      Offshore Wind 40 The United States does not have any offshore wind farms in operation; however, approximately 41 20 projects representing more than 2,000 MW of capacity are in the planning and permitting 42 process as of 2010 (Musial and Ram 2010). Offshore wind projects have been developed in 43 Europe, most of which are located close to shore and in shallow water less than 98.4 ft (30 m) in 44 depth. Total worldwide installed capacity has been estimated at 2,377 MW (Musial and 45 Ram 2010).
46 Although wind data suggest a potential for offshore wind farms in the Great Lakes, project costs 47 likely will limit the future potential of large-scale projects (Tidball et al. 2010). NREL 2-18
 
Alternatives Including the Proposed Action 1 (Tidball et al. 2010) estimated that offshore project costs would run approximately 200 to 2 300 percent higher than land-based systems. In addition, based on current prices for wind 3 turbines, the 20-year levelized cost of electricity produced from an offshore wind farm would be 4 above the current production costs from existing power generation facilities. In addition to cost, 5 other barriers include the immature status of the technology, limited resource area, and high 6 risks and uncertainty (Tidball et al. 2010). Because no offshore wind capacity yet exists in 7 either the Great Lakes or on the Atlantic Coast and because none appears likely to exist on a 8 large commercial scale in the Great Lakes by 2022 (given the current state of development), the 9 NRC staff finds that offshore wind will not be a reasonable alternative to LSCS.
10 2.3.3.2      Wind Power with Storage 11 Energy storage is one possible way to overcome intermittency. Besides pumped hydroelectric 12 facilities, compressed air energy storage (CAES) is the technology most suited for storage of 13 large amounts of energy. In CAES systems, electricity generated during low-demand periods 14 can be stored by using a compressor to pressurize and store air; during high-demand periods, 15 the compressed air can be used to drive a turbine to generate electricity. A 2011 DOE report 16 analyzed various power-generation sources, including wind, coupled with CAES systems 17 (Ilic et al. 2011). The report considered siting criteria, using (1) proximity to natural gas lines, 18 high voltage transmission, and a market for wholesale electric power and (2) availability of 19 geology and wind resources. The results show that, within the ROI, the potential exists for 20 one CAES site in northwestern Iowa. Without detailed wind-speed data, specific site 21 information, and detailed information on the energy-storage capacity of the potential CAES site, 22 estimating how much wind capacity would be necessary and determining whether it could 23 provide for an all-wind alternative would be difficult. Furthermore, the NRC staff is not aware of 24 a CAES project coupled with wind generation that is providing baseload power. Therefore, the 25 NRC staff concludes that the use of CAES in combination with wind turbines to replace the 26 LSCS power plant is unlikely.
27 2.3.3.3      Conclusion 28 Despite the relatively high reliability demonstrated by modern turbines, the recent technological 29 advancements in turbine design and wind farm operation, and wind energys dramatic market 30 penetrations of recent years, empirical data on wind farm capacity factors and wind energys 31 limited ability to store power for delayed production of electricity cause the NRC staff to 32 conclude that wind energyon shore, off shore, or a combination thereofcould not serve as a 33 discrete alternative to the baseload power supplied by the LSCS reactors. However, the NRC 34 staff also concludes that, when used in combination with other technologies with inherently 35 higher capacity factors, wind energy can provide a viable alternative. The NRC staff described 36 such a possible combination alternative in Section 2.2.2.4.
37 2.3.4      Biomass 38 Biomass resources used for biomass-fired generation include agricultural residues, animal 39 manure, wood wastes from forestry and industry, residues from food and paper industries, 40 municipal green wastes, dedicated energy crop, and methane from landfills (IEA 2007). Using 41 biomass-fired generation for baseload power depends on the geographic distribution, available 42 quantities, constancy of supply, and energy content of biomass resources. For this analysis, the 43 NRC staff assumed that biomass would be combusted for power generation in the electricity 44 sector. Biomass is also used for space heating in residential and commercial buildings and can 45 be converted to a liquid form for use in transportation fuels (Haq undated).
46 In the GEIS, the NRC staff indicated a wood waste facility could provide baseload power and 47 could operate with capacity factors between 70 and 80 percent (NRC 2013). Although the ROI 2-19
 
Alternatives Including the Proposed Action 1 currently produces electricity from biomass fuels, the plants operating within the ROI generated 2 less than 1 percent of the total power generation in 2011 (EIA 2014b). Based on the relatively 3 low electricity generation currently produced at biomass plants, it is unlikely that these plants, or 4 the construction of several new biomass plants, could increase capacity by adding 2,327 MWe 5 of electricity from biomass-fired generation by the time LSCSs licenses expire in 2022 and 6 2023.
7 For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 8 used for biomass conversion would be similar to fossil fuel plants, including the direct 9 combustion of biomass in a boiler to produce steam (NRC 2013). Biomass generation is 10 generally more cost-effective when co-fired with coal plants (IEA 2007). Biomass-fired 11 generation plants generally are small and can reach capacities of 50 MWe, which means that 12 more than 40 new facilities would be required before the LSCS licenses expire. After 13 reevaluating current technologies, the NRC staff finds biomass-fired alternatives as still unable 14 to reliably replace the LSCS capacity. For this reason, the NRC staff does not consider 15 biomass to be a reasonable alternative to LSCS license renewal.
16 2.3.5      Hydroelectric 17 Hydroelectric power uses the force of water to turn turbines that spin a generator to produce 18 electricity. In a run-of-the-river system, the force of a river current provides the force to create 19 the needed pressure for the turbine. In a storage system, water is accumulated in reservoirs 20 created by dams and is released as needed to generate electricity.
21 The DOEs Idaho National Environmental Engineering Laboratory (now Idaho National 22 Laboratory) completed a comprehensive survey of hydropower resources in 1997. The ROI has 23 hydroelectric generating potential of 1,954 MW, adjusting for environmental, legal, and 24 institutional constraints (Conner et al. 1998). These constraints could include (1) scenic, 25 cultural, historical, and geological values, (2) Federal and state land use, and (3) legal 26 protection issues, such as wild and scenic legislation and threatened or endangered fish and 27 wildlife legislative protection. A separate assessment by DOE of nonpowered dams (dams that 28 do not produce electricity) concluded that there is potential for 4,185 MW of electricity in the ROI 29 (ORNL 2012). These nonpowered dams serve various purposes, such as providing water 30 supply to inland navigation.
31 The EIA reported that the States comprising the ROI generated 2,262 MW of electricity from 32 hydroelectric power in 2012 (EIA 2014c). In order to replace LSCSs current output, 33 hydroelectric generation across the ROI would need to double by 2022. Although there is 34 potential for anywhere between 1,954 MW and 4,185 MW of hydroelectric power, it is unlikely 35 that the maximum levels of development would occur across the entire ROI by the time LSCSs 36 licenses expire in 2022 and 2023 because the generating capacity of hydroelectric power is 37 projected to continue to decrease through 2040 (EIA 2013b). Given the decrease in projected 38 power generation from hydroelectric facilities, the NRC staff does not consider hydroelectric 39 power to be a reasonable alternative to license renewal.
40 2.3.6      Wave and Ocean Energy 41 Waves, currents, and tides are often predictable and reliable, making them attractive candidates 42 for potential renewable energy generation. Four major technologies may be suitable to harness 43 wave energy: terminator devices that range from 500 kilowatts to 2 MW, attenuators, point 44 absorbers, and overtopping devices (BOEM undated). Point absorbers and attenuators use 45 floating buoys to convert wave motion into mechanical energy, driving a generator to produce 46 electricity. Overtopping devices trap a portion of a wave at a higher elevation than the sea 2-20
 
Alternatives Including the Proposed Action 1 surface; waves then enter a tube and compress air that is used to drive a generator that 2 produces electricity (NRC 2013). Some designs are undergoing demonstration testing at 3 commercial scales, but none are currently used to provide baseload power (BOEM undated).
4 The Great Lakes do not experience large tides, and there is limited energy output for wave 5 technologies in the Great Lakes. The Electric Power Research Institute (EPRI) published a 6 document that assessed ocean wave energy resources in the United States. The Great Lakes 7 were not included in the analysis, suggesting that the resource potential is not great enough to 8 use on a commercial scale (EPRI 2011). Consequently, the limited resource availability and 9 infancy of the technologies in the Great Lakes support the NRC staffs conclusion that wave and 10 ocean energy technologies are not feasible substitutes for LSCS.
11 2.3.7      Fuel Cells 12 Fuel cells oxidize fuels without combustion and its environmental side effects. Fuel cells use a 13 fuel (e.g., hydrogen) and oxygen to create electricity through an electrochemical process. The 14 only byproducts (depending on fuel characteristics) are heat, water, and carbon dioxide 15 (depending on hydrogen fuel type) (DOE 2013a). Hydrogen fuel can come from a variety of 16 hydrocarbon resources. Natural gas is a typical hydrogen source.
17 Fuel cells are not economically or technologically competitive with other alternatives for 18 electricity generation. EIA projects that fuel cells may cost $6,835 per installed kilowatt (total 19 overnight capital costs, 2010 dollars), which is high compared to other alternative technologies 20 analyzed in this section (EIA 2010). More importantly, fuel cell units are likely to be small in size 21 (approximately 10 MWe). Replacing the power LSCS provides would be extremely costly; it 22 would require the construction of approximately 230 units and modifications to the existing 23 transmission system. Given the immature status of fuel cell technology and high cost, the NRC 24 staff does not consider fuel cells to be a reasonable alternative to LSCS license renewal.
25 2.3.8      Delayed Retirement 26 A delayed retirement alternative would consider deferring the retirement of generating facilities 27 in Illinois and its six adjoining states that include MISO and PJM RTOs.
28 To maintain reliable operations, electric systems must be able to meet peak load requirements.
29 To ensure sufficient capacity, this must also include a planning reserve margin (FERC 2013).
30 The projected MISO reserve margin for 2021 is 18.6 percent, which exceeds the reserve margin 31 requirement of 17.4 percent. However, recent EPA regulations may lead to increased coal plant 32 retirements at a faster pace than projected. In that case, 3,000 MW to 12,600 MW of plant 33 retirements could decrease the projected reserves anywhere from 16.22 to 6.9 percent, well 34 below the reserve margin requirement (MISO 2011).
35 PJM is facing similar constraints due, in large part, to retirements of coal plants given air quality 36 regulations (Ott 2013a). This indicates an emerging reliability problem potentially affecting 37 major population centers within the PJM region in the near future (Ott 2013a). Because the 38 current generation mix has not resulted in the long-term commitment of generation needed for 39 reliability, generation retirements that have occurred with short notice have created 40 unanticipated reliability problems for PJM (Ott 2013a).
41 The EIA expects that more coal plant retirements will occur before 2016 than those previously 42 predicted. These accelerated retirements are driven by low natural gas prices, slow growth in 43 electricity demand, and the requirements of the Mercury and Air Toxics Standards that will 44 require significant reductions in plant emissions (EIA 2014a, EPA 2015). Exelon also expects 45 increased generation retirements for a variety of reasons, including increased operating costs 2-21
 
Alternatives Including the Proposed Action 1 for older facilities, increased environmental regulations and competition, and decreased load 2 (Exelon undated). As generators are required to adhere to future regulations, some power 3 plants may opt for early retirement of older units rather than incur the cost for compliance.
4 Exelon has further stated that some of their nuclear fleet may be retired early because of low 5 wholesale energy prices and current energy policy (Associated Press 2015). Because of the 6 uncertain regulatory environment and concerns expressed by MISO and PJM concerning the 7 retirement pace of coal power plants, the NRC staff does not consider delayed retirement to be 8 a reasonable alternative to LSCS license renewal.
9 2.3.9    Geothermal 10 Geothermal technologies extract the heat contained in geologic formations to produce steam to 11 drive a conventional steam turbine generator. Facilities producing electricity from geothermal 12 energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 13 a potential source of baseload electric power. However, the feasibility of geothermal power 14 generation to provide baseload power depends on the regional quality and accessibility of 15 geothermal resources. Utility-scale geothermal energy generation requires geothermal 16 reservoirs with a temperature above 200 &deg;F (93 &deg;C). Utility-scale power plants range from small 17 300 kilowatts electric to 50 MWe and greater (TEEIC undated). Geothermal resources are 18 concentrated in the western United States. Specifically, these resources are found in Alaska, 19 Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, 20 Washington, and Wyoming. In general, most assessments of geothermal resources have been 21 concentrated on these western states (DOE 2013b; USGS 2008). Geothermal resources are 22 used in the ROI for heating and cooling purposes, but no electricity is currently being produced 23 from geothermal resources in the ROI (EIA 2014c). Given the low resource potential in the ROI, 24 the NRC staff does not consider geothermal to be a reasonable alternative to license renewal.
25 2.3.10    Municipal Solid Waste 26 Energy recovery from municipal solid waste converts nonrecyclable waste materials into usable 27 heat, electricity, or fuel through combustion (EPA 2014b). The three types of combustion 28 technologies include mass burning, modular systems, and refuse-derived fuel systems 29 (EPA 2014a). Mass burning is the method used most frequently in the United States. The heat 30 released from combustion is used to convert water to steam, which is used to drive a turbine 31 generator to produce electricity. Ash is collected and taken to a landfill, and particulates are 32 captured through a filtering system (EPA 2014a). As of 2010, approximately 33 86 waste-to-energy plants are in operation in 25 states, processing more than 28 million tons of 34 waste per year (EPA 2014b). These waste-to-energy plants have an aggregate capacity of 35 2,720 MWe, and although some plants have expanded to handle additional waste and produce 36 more energy, no new plants have been built in the United States since 1995 (EPA 2014b). The 37 average waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can 38 operate at capacity factors greater than 90 percent (Michaels 2010). Indiana has one waste 39 recovery facility that produces steam; Iowa has one waste-to-energy facility that produces 40 10 MW of electricity; Michigan has three facilities that produce 89.7 MW of electricity; and 41 Wisconsin has two facilities that generate 32.3 MW of electricity (Michaels 2010). In total, as of 42 2010, the ROI had a municipal solid waste generating capacity of 132 MW. More than 43 46 average-sized plants would be necessary to provide the same level of output as LSCS, 44 almost doubling the national waste-to-energy generation.
45 The decision to burn municipal waste to generate energy is usually driven by the need for an 46 alternative to landfills rather than energy considerations. Given the improbability that additional 47 stable supplies of municipal solid waste would be available to support approximately 46 new 2-22
 
Alternatives Including the Proposed Action 1 facilities and that so few existing plants operate in the ROI, the NRC staff does not consider 2 municipal solid waste combustion to be a reasonable alternative to LSCS license renewal.
3 2.3.11    Petroleum 4 In the ROI, oil-fired generation in 2012 had a generating capacity of 4,986 MW (EIA 2014c).
5 The variable costs of oil-fired generation tend to be greater than those of the nuclear or 6 coal-fired operations, and oil-fired generation tends to have greater environmental impacts than 7 natural gas-fired generation. The high cost of oil has resulted in a steady decline in its use for 8 electricity generation (EIA 2013a). Given the high cost of oil and the small generating capacity 9 from oil-fired power plants in the ROI, the NRC staff does not consider oil-fired generation a 10 reasonable alternative to LSCS license renewal.
11 2.3.12    Supercritical Pulverized Coal 12 In general, SCPC power plants are feasible, commercially available options for providing 13 electrical generating capacity. Baseload coal units have proven their reliability and can sustain 14 capacity factors as high as 79 percent. Pulverized coal power generation uses crushed coal 15 that is fed into a boiler where it is burned to create heat. The heat produces steam that is used 16 to spin one or more turbines to generate electricity. Among the technologies available, 17 pulverized coal boilers producing supercritical steam (SCPC boilers) are increasingly common 18 for new coal-fired plants given their high operating temperatures and pressures that increase 19 thermal efficiencies and overall reliability. SCPC facilities consume less fuel per unit output, 20 reducing environmental impacts (NETL undated).
21 As described in Section 2.2.3, EPA has signed a final rule for carbon pollution that would apply 22 to new fossil fuel-fired power plants, including SCPC facilities (80 FR 64661-65120). The 23 action establishes performance standards and has identified a CCS system as a method of 24 emission reduction. The emission limit for these sources of 1,305 lb CO2/MWh, and any new 25 coal-fired power plants could require CCS in order to achieve this emission limit.
26 In addition, given known technology and technological and demographic trends, EIA predicts 27 that by 2040 natural gas will surpass coal as the largest share of U.S. electric power generation 28 (EIA 2013a). This does not consider the EPA rule described above but indicates a general 29 trend away from coal-fired facilities in favor of natural gas-fired power plants due to falling 30 natural gas prices. MISO projected that the EPA regulations could lead to increased coal plant 31 retirements and estimated retirements between 3,000 MW to 12,600 MW, which could have a 32 large impact on MISOs reserve margin in the future (MISO 2011).
33 Although SCPC plants are currently the most widely used source of electricity generation within 34 the ROI, given the potential for stringent air quality regulations and trends toward natural 35 gas-fired power plants, the NRC staff does not consider SCPC to be a reasonable alternative to 36 LSCS license renewal. Instead, the NRC staff describes an IGCC plant under the coal 37 alternative in Section 2.2.2.2.
38 2.4      Comparison of Alternatives 39 In this chapter, the NRC staff considered the following alternatives to LSCS license renewal:
40 new nuclear generation; IGCC generation; NGCC generation; a combination alternative of 41 natural gas, wind, and solar; and purchased power. The NRC also considered the no-action 42 alternative and its effects. The impacts for all alternatives to LSCS license renewal are 43 discussed in Chapter 4 and summarized in Table 2-2 below.
2-23
 
Alternatives Including the Proposed Action 1 The environmental impacts of the proposed action (issuing renewed LSCS operating licenses) 2 would be SMALL for all impact categories. The environmental impacts from all other 3 alternatives would be larger than the proposed license renewal, as shown in Table 2-2.
4 In conclusion, the environmentally preferred alternative is the granting of renewed licenses for 5 LSCS. All other alternatives capable of meeting the needs currently served by LSCS entail 6 potentially greater impacts than those of the proposed action of renewing the license for LSCS.
7 To make up the lost power generation if a renewed license is not issued (the no-action 8 alternative), one or a combination of alternatives would be implemented, all of which have 9 greater impacts than the proposed action. Hence, the NRC staff concludes that the no-action 10 alternative will have environmental impacts greater than or equal to those of the proposed 11 license renewal action.
2-24
 
1                            Table 2-2. Summary of Environmental Impacts of Proposed Action and Alternatives LSCS License                                                          Combination Renewal                                                              Alternative Impact Area              (Proposed                New Nuclear    IGCC          NGCC          (NGCC, Wind,  Purchased (Resource)                Action)      No-Action    Alternative    Alternative  Alternative    and Solar)    Power Land Use and Visual Resources SMALL TO      SMALL TO      SMALL TO      SMALL TO Land Use                SMALL        SMALL                                                                  SMALL MODERATE      LARGE        MODERATE      MODERATE SMALL TO                                    SMALL TO Visual Resources        SMALL        SMALL                      SMALL        SMALL                        SMALL MODERATE                                    LARGE Air Quality and Noise SMALL TO Air Quality              SMALL        SMALL      SMALL          MODERATE      MODERATE      SMALL MODERATE SMALL TO                    SMALL TO      SMALL TO Noise                    SMALL        SMALL      SMALL                        SMALL MODERATE                    MODERATE      MODERATE Geologic Environment      SMALL        SMALL      SMALL          SMALL        SMALL          SMALL          SMALL 2-25  Water Resources Surface Water                                      SMALL TO      SMALL TO                                    SMALL TO SMALL        SMALL                                    SMALL          SMALL Resources                                          MODERATE      MODERATE                                    MODERATE Groundwater SMALL        SMALL      SMALL          SMALL        SMALL          SMALL          SMALL Resources SMALL TO      MODERATE      SMALL TO      SMALL TO Terrestrial Resources    SMALL        SMALL                                                                  SMALL MODERATE      TO LARGE      MODERATE      MODERATE SMALL to                                SMALL to Aquatic Resources                      SMALL      SMALL                        SMALL          SMALL          SMALL MODERATE1                                MODERATE Special Status Species NO EFFECT    SEE NOTE2  SEE NOTE2      SEE NOTE2    SEE NOTE2      SEE NOTE2      SEE NOTE2
      & Habitats Historic and                                                                                    SMALL TO      SMALL TO SEE NOTE3    SMALL      SMALL          SMALL        SMALL Cultural Resources                                                                              LARGE          LARGE Socioeconomics SMALL TO    SMALL TO      SMALL TO      SMALL TO                      SMALL TO Socioeconomics          SMALL                                                                SMALL LARGE      LARGE          LARGE        LARGE                        LARGE Alternatives including the Proposed Action
 
LSCS License                                                                                    Combination Renewal                                                                                          Alternative Impact Area                (Proposed                          New Nuclear          IGCC                NGCC                (NGCC, Wind,        Purchased (Resource)                  Action)      No-Action            Alternative          Alternative        Alternative          and Solar)          Power SMALL TO            SMALL TO            SMALL TO            SMALL TO            SMALL TO Transportation            SMALL              SMALL LARGE                LARGE              LARGE                MODERATE            LARGE Human Health                SMALL              SMALL          SMALL                SMALL              SMALL                SMALL                SMALL Environmental Justice      SEE  NOTE4        SEE  NOTE5    SEE  NOTE6          SEE  NOTE6        SEE  NOTE6          SEE  NOTE6          SEE NOTE6 Waste Management SMALL TO                                                      SMALL TO and Pollution              SMALL              SMALL          SMALL                                    SMALL                SMALL MODERATE                                                      MODERATE Prevention Key: IGCC = coal-integrated gasification combined-cycle (alternative), NGCC = natural gas combined-cycle (alternative), NRHP = National Register of Historic Places, APE = area of potential effect, CRMP = Cultural Response Management Plan, and IHPA = Illinois Historic Preservation Agency.
(1) Thermal  impacts would be SMALL for aquatic resources in the Illinois River and SMALL to MODERATE for aquatic resources in the cooling pond.
Alternatives including the Proposed Action MODERATE thermal impacts would primarily be experienced by gizzard and threadfin shad in the cooling pond.
(2) The magnitude of impacts could vary widely based on site selection and the presence or absence of special status species and habitats when the alternative is implemented; therefore, the NRC staff cannot forecast a level of impact for this alternative.
2-26  (3) Based on (1) there being currently no NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelons draft CRMP, (4) the fact that no license renewal-related physical changes or ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource assessment, license renewal would not affect any known historic properties (36 CFR 800.4(d)(1)).
(4) Continued operation of LSCS would not have disproportionately high and adverse human health and environmental effects on minority and low-income populations.
(5) The no-action alternative could disproportionately affect minority and low-income populations.
(6) Based on this information and the analysis of human health and environmental impacts presented in this SEIS, it is not likely that this alternative would have disproportionately high and adverse human health and environmental effects on minority and low-income populations. However, this determination would depend on the location, plant design, and operational characteristics of the alternative. Therefore, the NRC staff cannot determine whether this alternative would result in disproportionately high and adverse human health and environmental effects on minority and low-income populations.
 
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1                              3.0 AFFECTED ENVIRONMENT 2 In this supplemental environmental impact statement (SEIS), the affected environment is the 3 environment that currently exists at and around LaSalle County Station, Units 1 and 2 (LSCS).
4 Because existing conditions are at least partially the result of past construction and operation at 5 the plant, the impacts of these past and ongoing actions and a discussion on how they have 6 shaped the environment are presented here. The facility and its operation are described in 7 Section 3.1. The affected environment is presented in Sections 3.2 to 3.13.
8 3.1      Description of Nuclear Power Plant Facility and Operation 9 LSCS is a two unit nuclear power plant located in LaSalle County, Illinois. It began commercial 10 operation in January 1984 (Unit 1) and October 1984 (Unit 2). Generally, the U.S. Nuclear 11 Regulatory Commission (NRC) staff drew information about LSCSs facilities and operation from 12 the Exelon Generation Company, LLC (Exelon), Environmental Report (ER) (Exelon 2014a).
13 3.1.1      External Appearance and Setting 14 The LSCS site is approximately 82 driving miles (mi) (132 kilometers (km)) southwest of OHare 15 International Airport in Chicago, Illinois, and approximately 26 mi (42 km) west of Exelons 16 Braidwood Generating Station in Braceville, Illinois. Interstate Highway 80 is 8 mi (13 km) north 17 of the site. Figure 3-1 presents the 50-mi (80-km) area around LSCS.
18 The LSCS site is located in a rural and agricultural setting. However, the surroundings are 19 dominated by many wind turbines. Each wind turbine is 389 feet (ft) (119 meters (m)) tall (which 20 includes the length of one of its three 126.5-ft (38.5-m) rotator blades). The town of Seneca lies 21 6 mi (10 km) northeast of LSCS. The town of Marseilles lies 7 mi (11 km) north-northwest of 22 LSCS. The Illinois River is 5 mi (8 km) north of LSCS. The Chicago, Rock Island and Pacific 23 Railroad, which runs parallel to, and slightly north of, the Illinois River, is the closest railroad line 24 in this area. A 6-mi (10-km) rail spur connects LSCS to the Atchison, Topeka, and Santa Fe 25 Railroad south of the site (Exelon 2014a). Figure 3-2 presents the 6-mi (10-km) area around 26 LSCS.
27 The LSCS site is approximately 3,776 acres (ac) (1,528 hectares (ha)) of which approximately 28 2,058 ac (833 ha) are the cooling pond. Underground pipelines approximately 3.5 mi (5.6 km) 29 long connect the cooling pond to the Illinois River, which is the source of the plants makeup 30 water and the receiving body of water for plant discharges. This pipeline corridor right-of-way 31 intersects the eastern portion of the Marseilles State Fish and Wildlife Area, which is managed 32 by the Illinois Department of Natural Resources (IDNR) for hunting and wildlife habitat. Country 33 Road 6 (also known as North 21st Road) provides access to LSCS and runs along the sites 34 southern boundary (Exelon 2014a). Figure 3-3 presents the LSCS site layout.
35 The LSCS sites main structures include two reactor buildings, an auxiliary building (which 36 houses the control room), a turbine building, a diesel generator building, a switchyard, a training 37 building, an interim radioactive waste (radwaste) storage facility, a radwaste building, sewage 38 and wastewater treatment facilities, and an independent spent fuel storage installation (ISFSI).
39 The sites tallest structure is a 400-ft (122-m) meteorological tower. The area of the LSCS site 40 that is completely enclosed by physical barriers and that allows access only at designated 41 control points is called the protected area. A physical protection program at the LSCS site 42 includes surveillance, observation, and monitoring within the protected area (Exelon 2014a).
43 Figure 3-4 presents the LSCS plant features.
3-1
 
Affected Environment 1                      Figure 3-1. LSCS 50-mi (80-km) Radius Map 2                                Source: Exelon 2014a 3-2
 
Affected Environment 1 Figure 3-2. LSCS 6-mi (10-km) Radius Map 2          Source: Exelon 2014a 3-3
 
Affected Environment 1                      Figure 3-3. LSCS Site Layout 2                          Source: Exelon 2014a 3-4
 
Affected Environment 1 Figure 3-4. LSCS Plant Features 2      Source: Exelon 2014a 3-5
 
Affected Environment 1 3.1.2    Nuclear Reactor Systems 2 The nuclear reactor for each of the two LSCS units is a General Electric boiling water reactor 3 (BWR/5) with Mark II containment. Each LSCS reactor is licensed to produce core power of 4 3,546 megawatts thermal. The annual mean net electrical power capacity for LSCS is 5 2,327 megawatts electric. LSCS uses a 2,058-ac (833-ha) diked cooling pond for core cooling 6 and withdraws makeup water from, and discharges to, the Illinois River (Exelon 2014a).
7 LSCS operates using low-enriched uranium dioxide fuel with enrichment not exceeding a 8 nominal 5.0 percent by weight of uranium-235 and has been historically operated within a 9 maximum analyzed fuel burnup rate of 62,000 megawatt-days per metric ton of 10 uranium (MWd/MTU). In its ER, Exelon stated that, during some future fuel cycles, it expects 11 the peak fuel burnup rate to exceed 62,000 MWd/MTU in some part-length fuel rods.
12 Addendum 1 to Volume 1 of NUREG-1437, Generic Environmental Impact Statement for 13 License Renewal of Nuclear Power Plants (GEIS) (NRC 1999), states that the environmental 14 impacts would be small for transporting spent fuel enriched with up to 5-percent uranium-235 15 with an average burnup for the peak rod of up to 62,000 MWd/MTU. It also states that, if peak 16 fuel burnup is projected to exceed 62,000 MWd/MTU, license renewal applicants must submit 17 an assessment of the implications for the environmental impacts. Exelon submitted an 18 assessment of the environmental impacts of transporting spent fuel enriched with an average 19 burnup for the peak rod exceeding 62,000 MWd/MTU in Section 4.13 of its ER. Appendix G of 20 this document provides the NRC staffs analysis of these projected environmental impacts.
21 Refueling outages for LSCS, Units 1 and 2, are on a staggered 24-month schedule 22 (Exelon 2014a).
23 3.1.3    Cooling and Auxiliary Water Systems 24 LSCS uses a closed-cycle, recirculating cooling system that includes an artificial cooling pond 25 for heat dissipation. In this type of closed-cycle system, the cooling pond serves as the primary 26 source of water to cool plant components and as the primary receiving body for excess heat.
27 In BWRs like those used at LSCS, steam is produced directly in each reactor vessel. The 28 steam passes through moisture separators and steam dryers and then flows to the turbine.
29 Such systems contain only two heat transfer (exchange) loops. The primary loop transports the 30 steam from the reactor vessel directly to the turbine, which generates electricity. The secondary 31 cooling loop removes excess heat from the primary loop in the main condenser. From the 32 condenser, the primary condensate is returned as feedwater to the reactor, and the secondary 33 cooling loop removes the excess heat (NRC 2013). At LSCS, condenser cooling water is 34 discharged directly to the cooling pond, where the heat is dissipated through mixing and 35 evaporation (Exelon 2014a).
36 Cooling water that is not otherwise lost from the pond through evaporation or seepage or that is 37 consumed in the process is recirculated from the cooling pond through the condenser systems 38 in a continuous loop. In addition, a portion of the water in the cooling pond is discharged as 39 blowdown on a near continuously basis under normal conditions. (Blowdown is water that is 40 rinsed from the cooling system (i.e., cooling pond) to remove impurities that may degrade plant 41 performance.) Total dissolved solids are the primary constituents of concern to prevent scale 42 buildup on plant components.
43 All water lost from the recirculating system must be replaced with fresh water; this water is 44 referred to as makeup water (Exelon 2014a; NRC 2013). Makeup water for the onsite cooling 45 pond is withdrawn from, and blowdown is discharged to, the Illinois River, which lies 3.5 mi 46 (5.6 km) north of LSCSs cooling pond. The intake and blowdown pipelines are routed through 3-6
 
Affected Environment 1 a common right-of-way corridor. Figure 3-5 provides a basic schematic diagram of a 2 closed-cycle, recirculating cooling system that uses a cooling pond.
3                  Figure 3-5. Closed-Cycle Cooling System with Cooling Pond 4                              Source: Modified from NRC 2013, Figure 3.1-4 5 Groundwater is also used by LSCS for potable water, sanitary water, and demineralized water 6 makeup systems.
7 Unless otherwise cited, the NRC primarily drew information about LSCSs cooling and auxiliary 8 water systems from Exelons ER (Exelon 2014a, 2015b) and its Updated Final Safety Analysis 9 Report (UFSAR) (Exelon 2014b). The NRC staff visited the facilities cited herein during the 10 May 2015 environmental site audit (NRC 2015b). Descriptions of the individual plant cooling 11 and auxiliary systems and components that interact with the environment are provided below.
12 Cooling Pond and Ultimate Heat Sink. Water for the circulating water system (CWS) for 13 condenser cooling water and for the plant service water system are supplied directly from the 14 cooling pond.
15 The LSCS cooling pond is an engineered impoundment encompassing 2,058 ac (833 ha) with 16 an average depth of 15 ft (4.7 m) (NRC 1978) (Figure 3-6). The pond has an elevation of 700 ft 17 (213 m) above mean sea level (MSL) at normal pool elevation. At this water elevation, the 18 cooling pond has a storage capacity of 31,706 acre-feet (39 million cubic meters (m3)) of water.
19 This impoundment was formed by constructing earthen dikes to enclose the north, east, and 20 south sides of the pond; the natural levee of the Illinois River forms the fourth side. Engineered 21 fill consisting of silty-clay, taken from borrow areas within the pond basin, was used in the 22 construction of these peripheral dikes. A perimeter drainage ditch designed to intercept runoff 23 and to capture and direct seepage toward surface drainages and away from the dikes flanks the 24 ponds dikes (Exelon 2014b).
25 Integral to the ponds construction are three internal baffle or finger dikes (i.e., earthen berms),
26 that total 22,623 ft (6,895 m) in length. These structures direct the flow of water from the 27 discharge canal and through the pond to ensure that the coolest water is available for use by 28 LSCS (Exelon 2014b) (Figure 3-6). The average residence time for water in the cooling pond is 29 5.5 days (NRC 1978).
3-7
 
Affected Environment 1 The peripheral dike system that encloses the cooling pond includes a 300-ft- (91-m)-wide 2 auxiliary spillway structure. The spillway is located northwest of the main plant complex and is 3 adjacent to the discharge canal. The structure is capable of passing a volume of 4 1,069,000 gallons per minute (gpm) (2,380 cubic feet per second (cfs) or 67.2 meters per 5 second (m/s)) of water associated with the probable maximum water level. Discharge from the 6 structure flows north to South Kickapoo Creek, a tributary to the Illinois River (Exelon 2014b).
7 A dedicated portion of the cooling pond located immediately adjacent to the LSCS intake canal 8 serves as the plants ultimate heat sink (UHS). It is also known as the core standby cooling 9 system (CSCS) pond and directly supplies the CSCS equipment cooling water system, as 10 discussed below. This excavated area comprises 83 ac (34 ha) in size and is 5 ft (1.5 m) deep 11 below grade. It can hold 460 acre-feet (567,000 m3) of water. This volume of water is sufficient 12 to supply 30 days of cooling water following safe shutdown from normal operating or accident 13 conditions. The CSCS pond can function even if the perimeter dikes of the cooling pond are 14 breached (Exelon 2014b).
15 Illinois River Water Makeup System. Cooling pond makeup water is withdrawn via the river 16 screen house located on the south bank of the Illinois River at Illinois River Mile (RM) 249.5 17 (River Kilometer (RKm) 401.5) (Figure 3-6). The river screen house is situated approximately 18 3.5 mi (5.6 km) north of the cooling pond. The structure is designed to withstand the 100-year 19 flood of the Illinois River (Exelon 2014b).
20 The river screen house contains three makeup water pumps, each with a capacity of 21 30,000 gpm (67 cfs or 1.9 cubic meters per second (m3/s)). Two pumps are normally operated 22 at all times to meet cooling pond makeup demands, with the third serving as a backup.
23 However, when reduced evaporation demands allow (winter months), the pump discharge ball 24 valves are closed to 30 degrees (one-third open) (Exelon 2015c).
25 River water is first drawn through an intake flume in the bottom of the river and then into a 26 72-ft-- (22-m)-wide funnel inlet basin with concrete dam located 24 ft (7 m) from the shoreline 27 frontage of the river screen house. The inlet is protected by a floating log boom to deflect river 28 debris. From the inlet, water then enters the intake forebay of the screen house and passes first 29 through two adjacent bar grills and then through vertical traveling screens with 3/8-inch (in.)
30 (0.95-centimeter (cm)) openings before entering the pumps (Exelon 2014a, 2015a). The bar 31 grills are galvanized steel and measure 3/8 in. (0.95 cm) thick and 4 in. (10 cm) wide. The 32 narrow dimension of each bar is oriented perpendicular to the incoming water flow, and the 33 centerlines of the narrow dimension of adjacent bars are spaced 3 in. (7.6 cm) apart 34 (Exelon 2015c).
35 Water velocity in the river intake channel is reported as ranging from 0.3 to 0.5 feet per second 36 (fps) (0.10 to 0.15 m/s) with one pump operating and 0.6 to 1.0 fps (0.2 to 0.3 m/s) with two 37 pumps operating. Flow velocity at the travelling screens ranges from about 0.5 to 0.9 fps 38 (0.15 to 0.3 m/s) with one and two makeup pumps in full operation, respectively (NRC 1978; 39 Exelon 2014a). In NRCs Final Environmental Statement for the operating license of LSCS, the 40 NRC staff estimated that the intake velocity at the face of the traveling screens would be 0.5 fps 41 (0.2 m/s) 93 percent of the time and 1.0 fps (0.3 m/s) the remaining 7 percent of the time 42 (NRC 1978). Exelon has not performed any operational studies to further characterize intake 43 flow velocities (Exelon 2015c). Based on the assessment the NRC performed for LSCSs 44 operating license (NRC 1978), the velocity at the face of the traveling screens would typically be 45 within the 0.5fps (0.15m/s) intake velocity now recommended by the U.S. Environmental 46 Protection Agency (EPA) for protection of aquatic organisms (Volume 69 of the Federal 47 Register, page 41576 (69 FR 41576)), although the velocity may be closer to 1.0 fps (0.3m/s) 48 during certain periods during operations.
3-8
 
Affected Environment 1 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities 2            Sources: Modified from Exelon 2014a, 2015b 3-9
 
Affected Environment 1 A backwash system removes debris from the river intake traveling screens, and trash rakes 2 remove debris from bar grills. The backwash system can be set to operate in automatic or 3 manual mode, but the system is normally left in automatic mode unless high debris loading 4 requires manual cleaning. In automatic mode, cleaning is initiated when the measured 5 differential water level across the screens reaches 4 in. (10 cm). With a differential water level 6 of 6 in. (15 cm), the system switches to fast speed. A differential level in excess of 16 in.
7 (40 cm) for at least 15 seconds will cause the associated makeup pumps to trip to prevent 8 cavitation damage. Manual mode with either a slow or fast speed setting may be used during 9 periods of high debris loading (Exelon 2015c).
10 Collected debris, including any impinged biota, is deposited in a trash basket located outside the 11 river screen house, with the debris ultimately disposed of in an offsite permitted landfill. The 12 river screen house is not equipped with a fish return system. Screen backwash and other 13 intermittent discharges from the screen house are discharged to the Illinois River through a 14 National Pollutant Discharge Elimination System (NPDES)-permitted outfall (Outfall 002). The 15 intake forebay of the facility has a floating oil boom to prevent any oil leaks from the screen 16 house from entering the river. Section 3.5.1.3 of this SEIS presents additional information on 17 water quality and LSCSs NPDES permit.
18 With all three river makeup water pumps in operation, LSCSs maximum surface water makeup 19 supply capacity is 90,000 gpm (200 cfs or 5.66 m3/s), which is equivalent to 129.6 million 20 gallons per day (mgd) (491,000 cubic meters per day (m3/day)). Normal peak makeup 21 withdrawal from the Illinois River, with two pumps operating, is 60,000 gpm (134 cfs or 22 3.77 m3/s) or 86.4 mgd (327,000 m3/day). Surface water use is detailed in Section 3.5.1.2.
23 From the river screen house, intake water is pumped south to the northern end of the LSCS 24 cooling pond through a 60-in. (152-cm) pipeline. Upon reaching the pond, the water is 25 conveyed into the pond through a reinforced concrete discharge structure located on the north 26 side of the ponds discharge canal. The structure is designed to prevent erosion of the cooling 27 pond dike (Exelon 2014b) (see Figure 3-6).
28 The river intake pipeline is equipped with air and vacuum relief valves along its course to help 29 guard against pressure surges and other conditions that sometimes occur due to elevation 30 changes along its routing. Nevertheless, the makeup pipeline, which is not a safety-related 31 structure, has experienced a number of breaks resulting in flooding and erosion of areas 32 surrounding the break. The most recent such break occurred on January 23, 2014. Exelon 33 reported the break to both the Illinois Environmental Protection Agency (IEPA) and EPA 34 Region V in accordance with the reporting provisions of Exelons NPDES permit 35 (Exelon 2015c).
36 To address issues associated with pipeline breaks, Exelon has performed maintenance, 37 including replacing relief valves, and has installed instrumentation on the intake traveling 38 screens to alert the LSCS control room operators to abnormal conditions. Exelon has also 39 modified operating and response procedures and has implemented plans and procedures to 40 prevent and quickly respond to any breaks. For example, operational procedures have been 41 modified to include checks on pipeline integrity and to ensure necessary parts are maintained to 42 replace a section of pipeline should a break occur (Exelon 2014a, 2015a).
43 CWS and Blowdown Discharge. The CWS provides cooling water to the main condensers. In 44 addition to the condensers, the system includes the cooling pond, lake screen house, circulating 45 water pumps, piping, valves, and related equipment. The system normally supplies water to the 46 main condensers at temperatures ranging from 32 &deg;F to a maximum of 100 &deg;F (0 to 37.8 &deg;C).
47 However, operating license technical specifications (TS) limit the temperature of the cooling 3-10
 
Affected Environment 1 water supplied to the facility from the UHS portion of the cooling pond to 101.25 &deg;F (38.5 &deg;C) 2 (Exelon 2014b).
3 The main condenser of each unit requires 616,500 gpm (1,373 cfs or 38.8 m3/s), or 888 mgd 4 (3.36 million m3) of circulating water flow to remove waste heat at 100-percent load. Cooling 5 water is withdrawn from the cooling pond through the lake screen house, which is located at the 6 west end of the intake canal (Figure 3-6). The lake screen house contains six circulating water 7 pumps (three for each unit) that take suction from the service water tunnel (Exelon 2014a).
8 Each pump has a capacity of 205,500 gpm (457.7 cfs or 12.9 m3/s) (Exelon 2015c), with two 9 pumps normally in operation per unit to supply water to the condensers. Water first enters the 10 intake forebays after passing through bar grills and traveling screens with 3/8-in. (0.95-cm) 11 openings. Trash rakes prevent larger debris and aquatic biota from entering the system. The 12 design water intake velocity at the screens is approximately 2.2 fps (0.7 m/s), assuming clean 13 screens. Debris removed from the traveling screens by the screen backwash system and from 14 the bar grills by trash rakes is collected in a trash basket and disposed of in an offsite permitted 15 landfill. Similar to the river intake backwash system, the circulating water backwash system can 16 be operated in either automatic or manual mode. When in automatic mode with a differential 17 water level across the screens ranging between 0 and 6 in. (0 to 15 cm), a timer initiates a 18 3-minute wash cycle every 12 to [[estimated NRC review hours::14 hours]]. With a differential level rising to between 6 and 19 10 in. (15 to 25 cm), a continuous backwash cycle starts at slow speed. The fast setting is 20 triggered with a differential water level exceeding 10 in. (25 cm). Manual mode may be used 21 during fish runs or other periods of high debris intake (Exelon 2015c). Like the river screen 22 house, the lake screen house has no fish return system (Exelon 2014a, 2014b).
23 From the lake screen house, water is pumped through the main condenser of each unit.
24 A chemical feed system, located in facilities adjacent to the lake screen house, injects biocide 25 and other chemical treatments to reduce biofouling, silting, and scale buildup in the condenser 26 systems. After passing through the unit condensers, heated circulating water is returned to the 27 cooling pond through the discharge canal. The nominal (design) temperature rise in the 28 circulating water passing through the main condensers is approximately 26.7 &deg;F (10 &deg;C) 29 (Exelon 2014b).
30 As previously stated, a series of parallel dikes in the cooling pond direct and slow the rate of 31 movement of the returned cooling water through the pond to facilitate residence time cooling 32 processes so that the coolest water is available for uptake again at the lake screen house.
33 This heat dissipation is necessary so that cooling pond blowdown to the Illinois River meets 34 temperature limitations and mixing zone requirements under the Illinois thermal water quality 35 standards (35 IAC 302) and Special Condition 3 of Exelons NPDES Permit No. IL0048151 36 (IEPA 2013). The permit also authorizes the discharge of various other effluent streams to the 37 cooling pond in addition to condenser cooling water, as further described in Section 3.5.1.3 of 38 this SEIS.
39 Blowdown combined with other comingled effluent streams flows through an open channel 40 originating at the west shore of the cooling pond (UHS portion) and then northwest to a spillway 41 adjacent to the LSCS discharge canal. This combined effluent stream can include processed 42 liquid radioactive waste (radwaste), which may be discharged on a batch basis directly into the 43 cooling pond blowdown line at a maximum rate of 45 gpm (0.17 cubic meters per minute), as 44 further described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Nevertheless, the blowdown 45 line is equipped with a radiation monitor that will automatically isolate the radwaste discharge 46 line in the event of a high-radiation signal (Exelon 2014b).
47 The blowdown spillway connects to a 66-in. (168-cm) diameter pipeline through which the 48 collected blowdown travels underground via gravity flow. The pipeline discharges into an 3-11
 
Affected Environment 1 approximately 500-ft- (150-m)-long discharge structure consisting of a plunge pool and rip-raped 2 lined swale that connects with the Illinois River at RM 249.4 (RKm 401) and just upstream of the 3 LSCS river screen house (see Figure 3-6). The maximum blowdown rate of the system is 4 equal to the maximum intake rate of 90,000 gpm (200 cfs or 5.66 m3/s). However, 5 motor-operated values at both the river and lake ends of the discharge line can be used to 6 isolate the pipeline for maintenance and are used to adjust the blowdown to an average of 7 58,000 gpm (129 cfs or 3.65 m3/s) or less with a target annual average of 30,000 gpm (67 cfs or 8 1.89 m3/s) (Exelon 2014a, 2014b). The blowdown discharge point is regulated under LSCSs 9 NPDES permit as Outfall 001 (see Section 3.5.1.3).
10 Because the blowdown pipeline functions under gravity flow, it is less susceptible to surges and 11 breakage than the river intake pipeline. It is also equipped with air and vacuum relief valves.
12 Nevertheless, breaks do occur. The most recent such break occurred on July 13, 2012. Exelon 13 reported the break to both the IEPA and EPA Region V. As discussed above for the makeup 14 pipeline, Exelon has implemented a program to reduce the frequency of breaks and their 15 impacts on operations and the environment (Exelon 2015c).
16 Plant Service Water System. The service water system provides cooling water for various 17 nonsafety-related auxiliary systems and components, including cooling water for the turbine 18 generator; various air conditioning condensers; and the fuel pool, turbine building, and reactor 19 building heat exchangers. It also supplies water for the lake screen house traveling screen 20 backwash system and the radwaste system, and it is used to fill the fire protection system and 21 serves as a backup fire water supply. Service water is normally supplied by four pumps, with a 22 fifth pump serving as a backup, located in the lake screen house. Each pump has a capacity of 23 16,000 gpm (35.6 cfs or 1.01 m3/s). The pumps take suction from the lake screen house intake 24 service water tunnel and discharge into a common header. Automatic backwash strainers 25 remove any debris that might be passed through the circulating water screens. In addition, the 26 system has two jockey pumps rated at 5,000 gpm (11.1 cfs or 0.31 m3/s). These pumps are 27 powered by an emergency diesel generator and are used to meet minimum flow requirements 28 during a loss of offsite power. The service water is also treated by the chemical feed system to 29 guard against biofouling, scale buildup, corrosion, and silting. Chemical injection occurs directly 30 to the service water tunnel feed lines. All service water return flows are discharged back to the 31 cooling pond (Exelon 2014a, 2014b).
32 Fire Protection Water System. The cooling pond is the source of fire protection water for the 33 LSCS fire hydrants, the water sprinkler and deluge systems, and the hose valve stations.
34 One of two 75-gpm (0.17-cfs or 0.005-m3/s) jockey pumps normally keep the system 35 pressurized. If a system demand occurs, a 225-gpm (0.50-cfs or 0.014-m3/s) intermediate 36 pump is activated. If the demands of the intermediate pump are exceeded, the first of two 37 diesel-driven pumps are automatically engaged. These pumps, each with a capacity of 38 2,500 gpm (51 cfs or 1.44 m3/s), are located in the lake screen house and take suction directly 39 from the service water tunnel (Exelon 2014b).
40 Core Standby Cooling System. This system is equivalent in purpose to the essential service 41 water systems at other nuclear power plants and provides cooling water for the purpose of 42 cooling safety-related equipment necessary for safe shutdown of the reactors. This equipment 43 includes the residual heat removal heat exchangers, pump seal coolers, and emergency diesel 44 generators; the system also provides emergency spent fuel pool makeup water and a source of 45 water for containment flooding for post-accident recovery. The CSCS withdraws cooling pond 46 water from the UHS portion of the cooling pond (as discussed earlier) via the lake screen house 47 service water tunnel. The water is chemically treated by the chemical feed system as previously 48 described. As a safeguard against blockage of the traveling screens ahead of the service water 49 channel, the system has a 54-in. (137-cm) bypass line that can be opened to directly supply 3-12
 
Affected Environment 1 CSCS water. All pumps and strainers for conveying emergency cooling water are located in 2 watertight spaces within the basements of the various plant buildings (Exelon 2014a, 2014b).
3 Potable Water System. LSCS uses groundwater from two deep wells (Nos. 1 and 2) to supply 4 potable (drinking) water, sanitary water, and raw makeup water for the demineralized water 5 system. The wells were installed during plant construction with completion depths of 1,629 ft 6 (497 m) and 1,620 ft (494 m), respectively (Exelon 2014a). Each well has a pump capacity of 7 300 gpm (1.14 cubic meters per minute) (Exelon 2014b). Water is stored in a 350,000-gallon 8 (gal) (1,325-m3) storage tank before distribution. The plant supply wells and LSCSs 9 groundwater use are further discussed in Section 3.5.2.2.
10 3.1.4    Radioactive Waste Management Systems 11 As part of normal operations and as a result of equipment repairs and replacements due to 12 normal maintenance activities, nuclear power plants routinely generate both radioactive and 13 nonradioactive wastes. Nonradioactive wastes include hazardous and nonhazardous wastes.
14 There is also a class of waste, called mixed waste that is both radioactive and hazardous. The 15 systems used to manage (i.e., treat, store, and dispose of) these wastes are described in this 16 section. Waste minimization and pollution prevention measures commonly employed at nuclear 17 power plants are also discussed in this section.
18 All nuclear plants were licensed with the expectation that they would release very limited 19 quantities of radioactive material to both the air and water during normal operation. However, 20 NRC regulations require that gaseous and liquid radioactive releases from nuclear power plants 21 must meet radiation dose-based limits specified in Title 10 of the Code of Federal Regulations 22 (10 CFR) Part 20, and the as low as is reasonably achievable (ALARA) criteria in Appendix I to 23 10 CFR Part 50. Regulatory limits are placed on the radiation dose that members of the public 24 can receive from radioactive effluents released by a nuclear power plant. All nuclear power 25 plants use radioactive waste management systems to control and monitor radioactive wastes.
26 LSCS uses liquid, gaseous, and solid waste processing systems to collect and process, as 27 needed, radioactive materials produced as a by-product of plant operations. The liquid and 28 gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 29 discharge into the environment. This is to ensure that the dose to members of the public from 30 radioactive effluents is reduced to levels that are ALARA in accordance with NRCs regulations.
31 The radioactive material removed from the effluents is converted into a solid form for eventual 32 disposal at a licensed radioactive disposal facility.
33 Exelon has a radiological environmental monitoring program (REMP) to assess the radiological 34 impact, if any, to the public and the environment from radioactive effluents released during 35 operations at LSCS. The REMP measures the aquatic, terrestrial, and atmospheric 36 environment for radioactivity, as well as the ambient radiation. In addition, the REMP measures 37 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 38 material, including radon) (Teledyne 2015).
39 LSCS has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 40 parameters used to calculate offsite doses resulting from liquid and gaseous radioactive 41 effluents. These methods are used to ensure that radioactive material discharges from the plant 42 meet NRC and EPA regulatory dose standards. The ODCM also contains the requirements for 43 the REMP (Exelon 2013d).
44 3.1.4.1    Radioactive Liquid Waste Management 45 LSCS Units 1 and 2 share a common liquid radioactive waste system (LRWS). The LRWS 46 collects, monitors, and processes any potentially radioactive liquid wastes produced in the plant.
3-13
 
Affected Environment 1 The LRWS also recycles as much processed liquid waste as can be accommodated within the 2 LSCS water balance. Although LSCS tries to limit any radioactive releases via the liquid 3 pathway, discharges from the system are authorized and may occur if treated waste water is not 4 needed for other plant uses. The LRWS is designed so that any liquid radioactive waste 5 discharged from the site will have radioactive nuclide concentrations below the limits specified in 6 10 CFR Part 20 and Appendix I to10 CFR Part 50.
7 Processing of liquids in the LRWS results in a clean product stream and a reject stream. The 8 clean product stream returns water for use by the main plant systems via the condensate 9 storage tanks if the water quality is found acceptable and if the plant has the need for the 10 makeup water. Water in the reject stream is processed for disposal in the solid radioactive 11 waste system. Unused treated waste water can be sent to a discharge tank and held until a 12 discharge batch accumulates. Before any release of a discharge batch, it would be sampled 13 and treated if necessary to ensure radionuclide concentrations and resulting radiation doses to 14 LSCS personnel and the general public comply with NRC regulations in 10 CFR Part 20 and 15 Appendix I to 10 CFR Part 50. The LWRS sends discharge batches directly into the cooling 16 pond blowdown line.
17 The LRWS consists of a waste processing subsystem, a floor drain processing subsystem, a 18 chemical waste subsystem, and a sludge subsystem. All subsystems are shared by LSCS 19 Units 1 and 2. A vendor-provided liquid waste treatment system is also available to supplement 20 the LRWS if needed.
21 The waste processing subsystem collects and processes water from sources such as 22 equipment drains. This water is treated by settling, filtration, and demineralization. After 23 treatment and sampling, the water is returned for reuse through the condensate storage tanks.
24 The floor drain processing subsystem collects and processes water from the floor drain 25 systems. After treatment and sampling, the water is returned for reuse through the condensate 26 storage tanks. The chemical waste subsystem collects and processes water from areas like the 27 laboratory drains and the radwaste building sump. After treatment and sampling, plant 28 procedures are used to determine where the processed water goes, which may include 29 discharge. The sludge subsystem is not a processing stream, but rather a group of tanks and 30 associated pumps that serve as an interface between the LRWS and the solid radioactive waste 31 handling system. After radioactive contaminants have been removed from the LRWS, 32 concentrated, and treated or held up to allow radioactive decay if necessary, they are 33 transferred to the solid radioactive waste system for processing, temporary storage, and 34 shipment for disposal.
35 The use of these radioactive waste systems and the procedural requirements in the ODCM 36 ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 37 dose standards.
38 Dose estimates for members of the public are calculated based on radioactive liquid effluent 39 release data and aquatic transport models. Exelons annual radiological effluent release report 40 contains the radioactive liquid effluents release data from LSCS and the resultant calculated 41 doses. The NRC staff reviewed 5 years of radioactive effluent release data: 2010 through 2014 42 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year period provides a data set that covers a 43 broad range of activities that occur at a nuclear power plant, such as refueling outages, routine 44 operation, and maintenance activities that can affect the generation of radioactive effluents.
45 LSCS did not have any radioactive liquid effluent releases over the period of 2010 through 46 2014.
47 Since LSCS had no radioactive liquid effluent releases for the period of 2010 through 2014, its 48 radioactive liquid effluent control program showed that radiation doses to members of the public 3-14
 
Affected Environment 1 were controlled within the NRCs and EPAs radiation protection standards contained in 2 Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR Part 190. Also, since LSCS had no 3 radioactive liquid effluent releases for the period of 2010 through 2014, no adverse trends were 4 observed in the dose levels.
5 Routine plant refueling and maintenance activities currently performed will continue during the 6 license renewal term. Based on the past performance of the radioactive waste system to 7 maintain doses from radioactive liquid effluents to be ALARA, similar performance is expected 8 during the license renewal term.
9 3.1.4.2      Radioactive Gaseous Waste Management 10 LSCS Units 1 and 2 share a common gaseous radioactive waste system (GRWS) with a 11 common vent stack located on the roof of the containment building between the two units. The 12 GRWS is designed to process and control radioactive gases and minimize the amount of 13 radioactive gaseous material released into the environment. The gaseous radioactive wastes 14 released consist primarily of xenon, argon, iodine, tritium, and carbon. The steam in a BWR 15 plant such as LSCS contains impurities in the form of radioactive gases that are continuously 16 removed during plant operation from the main condenser by an air ejector. This process is the 17 major source of radioactive gases generated by LSCS (Exelon 2014a). The GRWS removes 18 some radioactive gases and delays the release of other radioactive gases by adsorption on 19 charcoal beds to allow time for radioactive decay. As a final step, the gaseous waste stream 20 passes through a high efficiency particulate air filter, and is discharged through the common 21 vent stack. Other plant facilities that are potential sources of radioactive gas emissions include 22 the primary containment, the secondary containments (reactor buildings), the turbine buildings, 23 and the radwaste building. The ventilation systems in each of these facilities have filtration and 24 treatment systems that the air passes through before being discharged through the vent stack 25 (Exelon 2014a).
26 The use of these radioactive waste systems and the procedural requirements in the ODCM 27 ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 28 dose standards.
29 Dose estimates for members of the public are calculated based on radioactive gaseous effluent 30 release data and atmospheric transport models. Exelons annual radioactive effluent release 31 report contains a detailed presentation of the radioactive gaseous effluents released from LSCS 32 and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 33 release data: 2010 through 2014 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year 34 period provides a data set that covers a broad range of activities that occur at a nuclear power 35 plant, such as refueling outages, nonrefueling outage years, routine operation, and maintenance 36 activities that can affect the generation of radioactive effluents. The NRC staff compared the 37 data against NRC dose limits and looked for indication of adverse trends (i.e., increasing dose 38 levels) over the period of 2010 through 2014. Since the radioactive gaseous effluents are 39 released from a common vent stack shared by both Unit 1 and Unit 2, the resultant calculated 40 doses presented in the effluent release are divided in half to evaluate compliance with the 41 Appendix I to 10 CFR Part 50 dose criteria. The following summarizes the calculated doses 42 from radioactive gaseous effluents released from LSCS Units 1 and 2 during 2014:
43 Unit 1 44
* The air dose at the site boundary from gamma radiation in gaseous effluents from 45              LSCS was 2.36x102 millirad (mrad) (2.36x104 milligray (mGy), which is well below 46              the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.
3-15
 
Affected Environment 1
* The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 2            was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 3            dose criterion in Appendix I to 10 CFR Part 50.
4
* The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 5            carbon-14 from LSCS was 4.56x101 millirem (mrem) (4.56x103 millisievert (mSv)),
6            which is well below the 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR 7            Part 50.
8 Unit 2 9
* The air dose at the site boundary from gamma radiation in gaseous effluents from 10            LSCS was 2.36x102 mrad (2.36x104 mGy), which is well below the 10 mrad 11            (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.
12
* The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 13            was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 14            dose criterion in Appendix I to 10 CFR Part 50.
15
* The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 16            carbon-14 from LSCS was 4.56x101 mrem (4.56x103 mSv), which is well below the 17            15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50.
18 The NRC staffs review of LSCSs radioactive gaseous effluent control program showed that 19 radiation doses to members of the public were controlled within NRCs and EPAs radiation 20 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 21 40 CFR Part 190. No adverse trends were observed in the dose levels.
22 Routine plant refueling and maintenance activities currently performed will continue during the 23 license renewal term. Based on the past performance of the radioactive waste system to 24 maintain doses from radioactive gaseous effluents to be ALARA, similar performance is 25 expected during the license renewal term.
26 3.1.4.3    Radioactive Solid Waste Management 27 LSCS Units 1 and 2 share a common solid radioactive waste system (SRWS). The SRWS 28 receives, dewaters, solidifies, packages, handles, and provides temporary storage facilities for 29 all radioactive wet solid wastes prior to offsite shipment and disposal in accordance with NRC 30 regulations in 10 CFR Parts 61 and 71. It also receives, decontaminates, compacts 31 (as necessary), and provides temporary storage facilities for all radioactive dry wastes prior to 32 offsite shipment and disposal (Exelon 2014a). Transportation of the radioactive solid waste is 33 governed by the U.S. Department of Transportation regulations in 49 CFR Parts 171 to 178.
34 LSCS disposes of solid radioactive waste at facilities in Utah and Texas. LSCS also utilizes 35 offsite vendor services in Tennessee for dry active waste processing, including compaction, 36 incineration, thermal processing, and sorting of the dry active waste.
37 LSCS Units 1 and 2 have a shared Interim Radwaste Storage Facility (IRSF) with the capacity 38 to hold 270 containers of Class B and Class C (Class B/C) low-level radioactive wastes in two 39 layers of 135 spots each. In 2011, LSCS Units 1 and 2 both received license amendments to 40 allow their IRSF to store Class B/C waste from Braidwood, Byron, and Clinton Stations in 41 addition to the wastes generated at LSCS. Exelon states that LSCS has sufficient excess 42 storage capacity to accommodate extended storage of the Class B/C wastes generated by all 43 four Exelon stations. Also, LSCS can ship Class B/C wastes for treatment and disposal to the 44 Waste Control Specialists facility in Texas to reduce the demand for any extended onsite 3-16
 
Affected Environment 1 storage of those wastes. Therefore, storage capacity for low-level radioactive wastes should be 2 sufficient for the length of the license renewal term. (Exelon 2014a) 3 LSCS infrequently generates small quantities of mixed waste (waste having both a hazardous 4 component and radioactive component). The IEPA regulates the hazardous component of the 5 waste and the Illinois Emergency Management Agency Division of Nuclear Safety and the NRC 6 regulate the radioactive component. When generated, mixed wastes are accumulated in the 7 Mixed Waste Storage Building before transport to a licensed offsite facility for treatment and 8 disposal (Exelon 2014a).
9 LSCS has contracts to send its low-level waste (LLW) to two licensed LLW disposal sites:
10 EnergySolutions in Clive, Utah, and Waste Control Specialists in Andrews, Texas. LSCS also 11 sends certain wastes to Toxco Materials Management Center in Oak Ridge, Tennessee, and 12 EnergySolutions in Oak Ridge, Tennessee for processing before disposal.
13 In 2014, 30 LLW shipments were made from LSCS for processing and disposal to the 14 EnergySolutions Clive facility in Clive, Utah, the EnergySolutions Bear Creek facility in Oak 15 Ridge, Tennessee, and the Toxco Materials Management Center in Oak Ridge, Tennessee.
16 The total volume and radioactivity of LLW shipped offsite in 2014 was 1.23x103 m3 17 (4.34x104 cubic feet and 1.34x101 curies (4.95x105 megabecquerels)), respectively 18 (Exelon 2015b). Routine plant operation, refueling outages, and maintenance activities that 19 generate radioactive solid waste will continue during the license renewal term. Radioactive 20 solid waste is expected to be generated and shipped off site for disposal during the license 21 renewal term.
22 3.1.4.4      Radioactive Waste Storage 23 Low-level radioactive waste (LLRW) is stored temporarily onsite before being shipped offsite for 24 disposal at a licensed LLRW disposal facility. Exelon (2014a) stated that LSCS has sufficient 25 capability to store Class B/C LLRW from Braidwood, Byron, and Clinton Stations in addition to 26 LSCS Class B/C waste in the IRSF (Exelon 2014a).
27 LSCS stores its spent fuel in a spent fuel pool and also in an onsite independent spent fuel 28 storage installation (ISFSI). The ISFSI is used to safely store spent fuel in licensed and 29 approved dry cask storage containers onsite. The installation and monitoring of this facility is 30 governed by NRC requirements in 10 CFR Part 72, Licensing requirements for the independent 31 storage of spent nuclear fuel, high-level radioactive waste, and reactor-related Greater than 32 class C waste. The LSCS ISFSI will remain in place until the U.S. Department of Energy takes 33 possession of the spent fuel and removes it from the site for permanent disposal or processing.
34 Spent fuel transfers to the ISFSI began in 2010 when fuel from the spent fuel pool was placed 35 in casks and transferred to the ISFSI storage pad. As of December 2014, there are 16 dry 36 casks containing spent fuel on the ISFSI storage pad (Exelon 2015b).
37 3.1.4.5      Radiological Environmental Monitoring Program 38 Exelon conducts a REMP to assess the radiological impact, if any, to the public and the 39 environment from operations at LSCS.
40 The REMP measures the aquatic, terrestrial, and atmospheric environment for ambient 41 radiation and radioactivity. Monitoring is conducted for the following: direct radiation, air, water, 42 groundwater, milk, local agricultural crops, fish, and sediment. The REMP also measures 43 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 44 material, including radon).
45 In addition to the REMP, LSCS has an onsite ground water protection program designed to 46 monitor the onsite plant environment for detection of leaks from plant systems and pipes 3-17
 
Affected Environment 1 containing radioactive liquid (Teledyne 2015). Information on the groundwater protection 2 program is contained in Section 3.5.2 of this document.
3 The NRC staff reviewed 5 years of annual radiological environmental monitoring data:
4 2010 through 2014 (Teledyne 2011, 2012, 2013, 2014, 2015). A 5-year period provides a data 5 set that covers a broad range of activities that occur at a nuclear power plant, such as refueling 6 outages, routine operation, and maintenance activities that can affect the generation and 7 release of radioactive effluents into the environment. The NRC staff looked for indication of 8 adverse trends (i.e., buildup of radioactivity levels) over the period of 2010 through 2014.
9 The NRC staffs review of Exelons data showed no indication of an adverse trend in 10 radioactivity levels in the environment. The data showed that there was no measurable impact 11 to the environment from operations at LSCS.
12 3.1.5    Nonradioactive Waste Management Systems 13 Like any other industrial facility, nuclear power plants generate wastes that are not 14 contaminated with either radionuclides or hazardous chemicals.
15 LSCS has a nonradioactive waste management program to handle its nonradioactive hazardous 16 and nonhazardous wastes. The waste is managed in accordance with Exelons procedures.
17 Listed below is a summary of the types of waste materials generated and managed at LSCS.
18
* LSCS is a small quantity hazardous waste generator; however, hazardous wastes 19              are managed according to large quantity generator standards. LSCS has contracts 20              in place to transfer hazardous waste to licensed offsite treatment and disposal 21              facilities.
22
* LSCSs nonhazardous wastes include potentially infectious medical waste (PIMW),
23              waste/used oil, grease, antifreeze, adhesives, and other petroleum-based liquids.
24              PIMW is generated at a health facility onsite and can include used and unused 25              hypodermic needles and syringes, as well as items contaminated with human blood.
26              PIMW is considered a unique special waste category in Illinois and transportation 27              and disposal of this waste is regulated under the Illinois Administrative Code (IAC) 28              Title 35, Sections 1420 through 1422 and 1450, (35 IAC 1420-1422, 1450).
29
* Universal wastes, such as batteries and mercury-containing lamps are managed in 30              accordance with 35 IAC 733 standards. Other wastes, such as, oils, metals, paper, 31              and other recyclables are managed according to Exelon procedures and Illinois 32              regulations.
33 Exelon operates an onsite sewage treatment plant. Sewage treatment effluent is discharged to 34 the LSCS cooling pond. Nonradioactive industrial wastewater is also processed at the 35 treatment plant and the treated effluent is discharged into the cooling pond. Cooling pond 36 blowdown is discharged to the Illinois River under NPDES permit IL0048151 (Exelon 2014a).
37 3.1.6    Utility and Transportation Infrastructure 38 The utility and transportation infrastructure at nuclear power plants typically interfaces with 39 public infrastructure systems available in the region. Such infrastructure includes utilities, 40 including suppliers of electricity, fuel, and water, as well as roads and railroads that provide 41 access to the site. The following sections briefly describe the existing utility and transportation 42 infrastructure at LSCS.
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Affected Environment 1 3.1.6.1      Electricity 2 Nuclear power plants generate electricity for other users; however, they also use electricity to 3 operate. Offsite power sources provide power to engineered safety features and emergency 4 equipment in the event of a malfunction or interruption of power generation at the plant.
5 Independent backup power sources provide power in the event that power is interrupted from 6 both the plant and offsite power sources.
7 At LSCS, connections to the Commonwealth Edison Company (ComEd) 345-kilovolt (kV) 8 system at the onsite switchyard provide offsite power sources for essential safety systems and 9 emergency equipment (Exelon 2014g). The switchyard is arranged in a double ring bus such 10 that offsite power to both units cannot be lost due to any single failure (Exelon 2014g). In the 11 event of total loss of auxiliary power from offsite sources, onsite diesel generators serve as an 12 independent source of power for safe shutdown (Exelon 2014g). LSCS has six diesel 13 generators (three for each nuclear unit) that can each provide up to 4.16 kV of power, which is 14 ample capacity to supply all power required for the safe shutdown of both units in the event of a 15 total loss of offsite power (Exelon 2014g).
16 3.1.6.2      Fuel 17 The LSCS nuclear units are operated using low-enriched uranium dioxide fuel with enrichment 18 not exceeding 5 percent by weight of uranium-235. At any given time, the LSCS units contain 19 approximately 140 metric tons (MT) (308,600 pounds) of uranium fuel (Exelon 2015e). Exelon 20 replaces about 36 percent of that fuel at each refueling, which occurs on a staggered 24-month 21 cycle (Exelon 2014a). Fresh (i.e., unirradiated) fuel is brought to the site and stored onsite in 22 the LSCS new fuel storage facility prior to installation in the reactor cores (Exelon 2014g).
23 Exelon stores spent fuel in a spent fuel pool and an ISFSI. Nuclear fuel and radioactive waste 24 systems are further described in Section 3.1.4.
25 In addition to nuclear fuel, LSCS requires diesel fuel to operate the emergency diesel power 26 generators. To meet emergency demands, Exelon stockpiles diesel fuel and gasoline on the 27 site. In total, Exelon stores 204,080 gal (772,530 liters) of diesel fuel and gasoline for a variety 28 of uses, including emergency diesel generators, diesel fire pumps, and plant vehicles 29 (Exelon 2015e).
30 3.1.6.3      Water 31 In addition to cooling and auxiliary water (described in Section 3.1.3), nuclear power plants 32 require potable water for sanitary and everyday uses by personnel (e.g., drinking, showering, 33 cleaning, laundry, toilets, and eye washes). At LSCS, two deep wells supply the site with 34 potable water. Water pumped from the wells is routed to an onsite vendor trailer, which 35 deionizes the water and routes the water to a 1.3-million-liter (350,000-gal) storage tank. Water 36 drawn from the storage tank may be used in either the demineralized water makeup system or 37 the potable and sanitary water system. Water withdrawn for use in the potable water system 38 undergoes chlorination prior to entering the system. LSCS withdraws approximately 98 liters 39 per minute (L/min) (26 gpm) from the wells for potable water uses. (Exelon 2014a) 40 3.1.6.4      Transportation Systems 41 All nuclear power plants are served by controlled access roads. In addition to roads, many 42 plants also have railroad connections for moving heavy equipment and other materials. Some 43 plants that are located on navigable waters, such as rivers, Great Lakes, or oceans, have 44 facilities to receive and ship loads on barges.
45 At LSCS, County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, 46 provides access to the site from the southern boundary. Major roads in the area include State 3-19
 
Affected Environment 1 Route 170 (SR-170), which lies 0.8 km (0.5 mi) east of the site, and Interstate 80 (I-80), which 2 lies 13 km (8 mi) north of the site. Section 3.10.6 describes local transportation systems, 3 including roadway access, in more detail.
4 Two major railway systems provide service near the LSCS site: the CSX Railroad runs parallel 5 to and slightly north of the Illinois River, and a 10-km (6-mi) rail spur connects LSCS to the 6 Atchison, Topeka, and Santa Fe Railroad south of the site. Exelon uses a portion of the onsite 7 rail spur to transport spent fuel casks to the onsite storage area, but the spur has not been used 8 to deliver equipment or materials to the site from external sources in many years.
9 (Exelon 2015f) 10 LSCS lies south of the Marseilles Pool in the reach of the Illinois River between the Marseilles 11 Lock and Dam at Marseilles, Illinois, and the Dresden Lock and Dam south of Channahon, 12 Illinois (Exelon 2014a). These lock and dam sites are part of the Illinois Waterway, which flows 13 from Chicago, Illinois, to St. Louis, Missouri, and is composed of seven water systems: Illinois 14 River, Des Plaines River, Chicago Sanitary and Shipping Canal, South Branch Chicago River, 15 Cal-Sag Channel, Little Calumet River, and the Calumet River (USACE 2012). Much of the 16 barge traffic in this area is dominated by transportation of agricultural products (grains, corn, 17 and soybeans) and other commodities, such as cement and concrete (USACE 2012).
18 Exelon (2015g) does not own or maintain a barge slip for LSCS and does not otherwise receive 19 or ship equipment for LSCS by barge.
20 Major airports in the vicinity of LSCS include Chicago Midway International Airport, Chicago 21 OHare International Airport, and Central Illinois Regional Airport, which lie approximately 93 km 22 (58 mi) northeast, 100 km (60 mi) north-northeast, and 110 km (70 mi) south of the site, 23 respectively. Additionally, Illinois Valley Regional Airport in Peru, Illinois, serves LaSalle 24 County, and eight private airports in the county accommodate smaller cargo, passenger, and 25 private aircraft (LaSalle County 2014).
26 3.1.6.5      Power Transmission Systems 27 ComEd owns and operates the 345-kV onsite switchyard that connects LSCS with the regional 28 electric grid. From the switchyard, a total of six transmission lines extend to four substations.
29 Two 345-kV lines travel 66 km (41 mi) north from the site to the Plano substation east of Plano, 30 Illinois. Two 345-kV lines travel 100 km (62 mi) northeast to Braidwood Station, Units 1 and 2, 31 in Braceville, Illinois. Two 138-kV lines are connected to the switchyard through a 345/138-kV 32 transformer. One of the 138-kV line extends 27 km (17 mi) to Mazon, Illinois, and the other 33 138-kV line extends 40 km (25 mi) to Streator, Illinois (AEC 1973; NRC 1978; Exelon 2015h).
34 For license renewal, the NRC (2013) evaluates as part of the proposed action the continued 35 operation of those transmission lines that connect the nuclear power plant to the substation 36 where electricity is fed into the regional power distribution system and transmission lines that 37 supply power to the nuclear plant from the grid. Exelon (2015h) has determined that the four 38 electrical connections between the main plant and the LSCS switchyard are in scope for the 39 license renewal environmental review. These connections extend a distance of 1,300 ft (400 m) 40 across flat, primarily gravel laydown areas and paved roads (Exelon 2015h). Because 41 redundant offsite power is provided to LSCS through the LSCS substation, no offsite 42 transmission lines supply power to the nuclear plant from the grid (Exelon 2015h). All of the 43 in-scope transmission lines lie within the owner-controlled and industrial-use area of the site.
44 3.1.7      Nuclear Power Plant Operations and Maintenance 45 Maintenance activities conducted at LSCS include inspection, testing, and surveillance to 46 maintain the current licensing basis of the facility and to ensure compliance with environmental 3-20
 
Affected Environment 1 and safety requirements. Various programs and activities currently exist at LSCS to maintain, 2 inspect, test, and monitor the performance of facility equipment. These maintenance activities 3 include inspection requirements for reactor vessel materials, boiler and pressure vessel 4 inservice inspection and testing, and maintenance of water chemistry.
5 Additional programs include those carried out to meet TS surveillance requirements, those 6 implemented in response to the NRC generic communications, and various periodic 7 maintenance, testing, and inspection procedures. LSCS must periodically discontinue the 8 production of electricity for outages supporting refueling, periodic in-service inspection and 9 testing, and maintenance activities. The LSCS reactor units are on staggered 24-month 10 refueling cycles (Exelon 2014a).
11 3.2      Land Use and Visual Resources 12 3.2.1      Land Use 13 3.2.1.1      Onsite Land Use 14 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 15 Illinois (Exelon 2015p). The site lies 8 km (5 mi) south of the Illinois River, about 10 km (6 mi) 16 southwest of Seneca, Illinois, and 120 km (75 mi) southwest of downtown Chicago.
17 (Exelon 2014a) 18 A cooling pond occupies the western side of the site and accounts for about half of the site area.
19 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 20 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac). This 21 industrial area is surrounded by about 142 ha (350 ac) of undeveloped natural areas, including 22 grassland, old field, scrub-scrub, and small forested fragments (Exelon 2015p).
23 On the southwest shore of the cooling pond, the IDNR operates the LaSalle Fish Hatchery 24 under a lease agreement with Exelon. The hatchery encompasses approximately 18 ha (45 ac) 25 and includes several small buildings and 16 fish-rearing pools (Exelon 2014a).
26 A 5.6-km (3.5-mi) corridor for the makeup and blowdown pipelineswhich travel underground 27 from the Illinois River screen house south to the cooling pondcontains woodlands, pastures, 28 and wetlands as well as mowed and maintained right-of-way for a portion of the 29 LaSalle-to-Plano 345-kV transmission line (Exelon 2014a).
30 Table 3-1 lists site land uses, and Figure 3-3 depicts the site layout. Sections 3.1 and 3.6 31 describe the developed and natural areas of the site in more detail, respectively.
32                              Table 3-1. LSCS Site Land Uses by Area Land Use                                              Area (in acres)(a)          Percent Open Water                                                  1,976(b)                52.3 Developed, Open Space                                        120                    3.2 Developed, Low Intensity                                      218                    5.8 Developed, Medium Intensity                                    73                  1.9 Developed, High Intensity                                      90                  2.4 Barren Land                                                      5                  0.1 Deciduous Forest                                              386                  10.2 Shrub/Scrub                                                    17                  0.5 3-21
 
Affected Environment Land Use                                                          Area (in acres)(a)              Percent Grassland/Herbaceous                                                        473                      12.5 Pasture/Hay                                                                  11                      0.3 Cultivated Crops                                                            346                      9.2 Woody Wetlands                                                                58                      1.5 Emergent Herbaceous Wetlands                                                  2                      0.1 Total                                                                    3,776                    100.0 (a) To  convert acres to hectares, divide by 2.4711.
(b) Exelon  used the 2011 National Land Cover Database (NLCD) to estimate acreage of site land uses. Of the 3,776-acre site, the 2011 NLCD identified 1,976 acres as open water, most of which consists of the cooling pond. This number of acres is inconsistent with the 2,058 acres reported in ComEds Environmental Report that evaluated the operation of LSCS (ComEd 1977). However, because the methodologies used to estimate land use acreages are different between these documents and the NLCD, and because both methodologies are inherently uncertain, Exelon was unable to resolve the discrepancy between the cooling pond acreage estimates. It is possible that, in the 1977 Environmental Report, features such as dikes, screen house, discharge canals, and storm water ponds were included in the cooling pond acreage estimate. Accordingly, all estimates should be considered approximate.
Source: Exelon 2015d 1 3.2.1.2          Coastal Zone 2 In 1972, Congress promulgated the Coastal Zone Management Act (16 USC 1451 et seq.;
3 CZMA) to encourage and assist States and territories in developing management programs that 4 preserve, protect, develop, and, where possible, restore the resources of the coastal zone 5 (i.e., the coastal waters and the adjacent shore lands strongly influenced by one another, which 6 may include islands, transitional and intertidal areas, salt marshes, wetlands, beaches, and 7 Great Lakes waters). Individual states are responsible for developing a Federally approved 8 Coastal Management Plan and implementing a coastal management program in accordance 9 with such a plan. In Illinois, the IDNR administers the coastal management program.
10 Section 307(c)(3)(A) of the CZMA requires that applicants for Federal permits whose proposed 11 activities could reasonably affect coastal zones certify to the licensing agency (here, the NRC) 12 that the proposed activity would be consistent with the states coastal management program.
13 The regulations that implement the CZMA indicate that this requirement is applicable to renewal 14 of Federal licenses for actions not previously reviewed by the state (15 CFR 930.51(b)(1)).
15 LSCS is outside of the boundary of the Illinois coastal zone (IDNR 2011b, 2015c). Accordingly, 16 a consistency determination is not required for the proposed LSCS license renewal.
17 3.2.1.3          Offsite Land Use 18 Within a 10-km (6mi) radius of the LSCS site, most lands are contained within LaSalle County; 19 however, this radius also includes a small area of land in Grundy County to the east. Land use 20 in this area is primarily agricultural. Cropland or pastures border the LSCS site to the east, 21 south, and west. The Illinois River lies to the north of the site, and the bluffs overlooking the 22 Illinois River are mostly forested. The rivers south bank floodplain includes agricultural fields 23 and woodlots, while the north bank is more developed and includes parts of the incorporated 24 towns of Seneca and Marseilles. The majority of land cover (about 70 percent) within 10 km 25 (6 mi) is used for crop cultivation. Deciduous forest accounts for about 12 percent of land cover, 26 and the remaining 18 percent is composed of various land cover types, including open water, 3-22
 
Affected Environment 1 developed land, wetlands, and grasslands. Table 3-2 characterizes the land uses within a 2 10-km (6-mi) radius of LSCS.
3                    Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS Area Land Use                                          (in acres)(a) Percent Open Water                                          2,915        4.0 Developed, Open Space                                3,124        4.3 Developed, Low Intensity                            2,676        3.7 Developed, Medium Intensity                            451        0.6 Developed, High Intensity                              256        0.4 Barren Land                                            84        0.1 Deciduous Forest                                    8,479      11.7 Evergreen Forest                                        4        0.0 Shrub/Scrub                                            43        0.1 Grassland/Herbaceous                                2,165        3.0 Pasture/Hay                                            966        1.3 Cultivated Crops                                    50,755      70.2 Woody Wetlands                                        425        0.6 Emergent Herbaceous Wetlands                            8        0.0 Total                                              72,351      100.0 (a) To convert acres to hectares, divide by 2.4711.
Source: Exelon 2015i 4 The IDNR manages three areas for public use and recreation within 10 km (6 mi) of LSCS. The 5 LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling pond that is 6 managed by the IDNR and open to the public for fishing and other recreational purposes 7 (Exelon 2014a). The Marseilles State Fish & Wildlife Area is approximately 2.4 km (1.5 mi) 8 north of the LSCS site. The IDNR (2015e) manages this 1,032-ha (2,550-acre) tract of 9 predominantly wooded land for wildlife habitat and hunting. Illini State Park lies approximately 10 10 km (6 mi) northwest of LSCS on the south bank of the Illinois River and encompasses 11 206 ha (510 ac) (Exelon 2014a).
12 LaSalle County, in which LSCS is located, is a predominantly agricultural county; 85 percent of 13 the countys 1,135 square miles (m2) (294,000 ha or 726,400 ac) are in agricultural production 14 (LaSalle County 2014). Much of the countys agricultural lands were formerly prairie. LaSalle 15 Countys major agricultural crops include corn, soybeans, and its major livestock commodities 16 include cattle and calves, hogs and pigs, and sheep and lambs (LaSalle County 2014). The 17 LaSalle County Comprehensive Plan (LaSalle County 2014) anticipates that the county will 18 experience a slight (4 percent) increase in population over the next 15 years and reach an 19 estimated 141,615 people by 2030. The county plans to manage its land resources in a manner 20 that will preserve prime farmland and to encourage continued urban growth in areas where 21 public infrastructure and services already exist so that farmland, open spaces, and natural and 22 cultural resources are preserved.
3-23
 
Affected Environment 1 3.2.2      Visual Resources 2 As described in the previous section, the LSCS site is located in a predominantly agricultural 3 region. The sites grade elevation is approximately 216 m (710 ft) above MSL, which is the 4 highest point within a 3-km (5-mi) radius. The sites generating facilities were built 60 m (200 ft) 5 above the Illinois River floodplain elevation, which ranges from 152 to 155 m (500 to 510 ft) 6 above mean sea level. The tallest structures on the LSCS site are the meteorological tower and 7 the station vent stack, which are 122 m (400 ft) tall and 113 m (370 ft) tall, respectively. The 8 vent stack is painted with thick white and red horizontal stripes. The largest and most visible 9 buildings on the site are the reactor and turbine buildings, which are 56 m (185 ft) and 41 m 10 (134 ft) tall, respectively (Exelon 2014a).
11 To the west and the southwest, the Grand Ridge Energy Center wind farm is situated on slightly 12 higher ground (221 to 227 m (725 to 750 ft) above MSL) on a north-south ridgeline. A second 13 wind farm, Top Crop I, is sited south and east of the Grand Ridge Energy Center. Wind turbines 14 at these facilities stand 118.5 m (389 ft) tall and have rotor blades that are 38.5 m (126.5 ft) 15 long. These two facilities 134 wind turbines dominate the viewscape in the vicinity of LSCS.
16 (Exelon 2014a) 17 From most vantage points, the wind turbines are more noticeable than the LSCS buildings or 18 facilities. A motorist travelling north on Highway 170 from Ranson, Illinois, to Seneca, Illinois, 19 would see wind turbines to the west, south, and east until the motorist crested the bluffs of the 20 Illinois River at an elevation of about 200 m (650 ft) above MSL. The motorist would then lose 21 sight of the turbines at the highway bridge that crosses the Illinois River, at which point the 22 roads elevation descends to approximately 152 m (500 ft) (Exelon 2014a).
23 3.3      Meteorology, Air Quality, and Noise 24 3.3.1      Meteorology and Climatology 25 LSCS is located in LaSalle County in northeastern Illinois, approximately 70 mi (113 km) 26 southwest of Chicago and 35 mi (56 km) southwest of Joliet, Illinois. The regional climate is 27 continental with cold winters; warm summers; and frequent short fluctuations in temperature, 28 humidity, cloudiness, and wind direction (NCDC 2004). During fall, winter, and spring, the polar 29 jet stream is located near or over northeastern Illinois, which causes large-scale synoptic storms 30 to move through the area bringing precipitation, winds, and often dramatic temperature changes 31 (NCDC 2004). Temperature and precipitation conditions vary widely throughout Illinois and 32 between years. A wide range of temperature extremes is common in this region 33 (NCDC 2015a). Tornadoes, thunderstorms, hail, and heat and cold waves are common in the 34 State, and flooding is the most damaging weather-related hazard in Illinois (NCDC 2004).
35 The NRC staff obtained climatological data collected at the Peoria, Illinois, airport station 36 (KPIA), which is located approximately 62 mi (100 km) from LSCS. Additionally, LSCS 37 maintains a meteorological monitoring program that includes a 400-ft (122-m) meteorological 38 tower located approximately 0.5 mi (0.8 km) southeast of the reactor buildings. The tower 39 measures wind direction, wind speed, temperature, and precipitation. Data from these stations 40 were used to characterize the regions climate and are presented below.
41 The prevailing wind direction, for the 1981 through 2010 timeframe, at the KPIA station was 42 from the south-southwest (NCDC 2015a). The mean annual wind speed for the 1981 through 43 2010 timeframe is 8.4 miles per hour (mph) (13.5 kilometers per hour (kph)), and the mean 44 monthly wind speed ranges from 6.0 mph (9.7 kph) in August to 10.2 mph (16.4 kph) in March.
45 The annual predominant wind direction from the meteorological tower at LSCS for the 3-24
 
Affected Environment 1 2010 through 2014 timeframe was from the south-southwest direction (for 2011 and 2012) and 2 from the west-northwest direction (for 2010, 2013, and 2014) (Exelon 2015j). The mean annual 3 wind speed at LSCS for the 2010 through 2014 timeframe is 10.4 mph (16.7 kph) 4 (Exelon 2015j).
5 The mean annual temperature for the 1985 through 2014 period of record at the KPIA station is 6 51.9 &deg;F (11.1 &deg;C), with a mean monthly temperature ranging from a low of 25.2 &deg;F (-3.7 &deg;C) in 7 January to a high of 75.8 &deg;F (24.3 &deg;C) in July (NCDC 2015a). The hottest year over the period 8 of record was in 2012, and coolest was in 1996. The mean annual temperature for the 2010 9 through 2014 timeframe at LSCS is 50.7 &deg;F (10.3 &deg;C), with a mean monthly temperature ranging 10 from a low of 22.5 &deg;F (-5.3 &deg;C) in January to a high of 75.4 &deg;F (24.1 &deg;C) in July (Exelon 2015j).
11 The mean total annual liquid precipitation for the 1985 through 2014 period of record measured 12 at the KPIA station is 35.9 in. (91.2 cm). The wettest year for the period of record is 55.35 in.
13 (140.6 cm) in 1990 (NCDC 2015a); the driest year from the same period is 22.16 in. (56.2 cm) in 14 1988 (NCDC 2015a). Monthly precipitation amounts tend to be evenly distributed throughout 15 the year and range from an average of 1.9 in. (4.8 cm) in January to 4.3 in. (10.9 cm) in May 16 (NCDC 2015a). The mean total annual precipitation measurements taken at LSCSs 17 meteorological tower for the 2010 through 2014 timeframe is 29.83 in. (75.8 cm). Average 18 monthly precipitation ranges from a low of 0.93 in. (2.4 cm) in January to a high of 5.89 in.
19 (14.9 cm) in June (Exelon 2015j).
20 LaSalle County, where LSCS is located, experiences severe weather events, such as 21 tornadoes, floods, and hail. For the 1950 through 2014 period of record, the following events 22 have been recorded (NCDC 2015b):
23
* 40 tornado events, 24
* 26 flash floods events, 25
* 131 hail events, and 26
* 4 blizzard events.
27 3.3.2    Air Quality 28 Under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.), EPA has set 29 primary and secondary National Ambient Air Quality Standards (NAAQS) (40 CFR Part 50) for 30 six common criteria pollutants to protect sensitive populations and the environment. Primary 31 standards specify maximum ambient concentration levels of the criteria pollutants aimed at 32 providing public health protection, including protecting the health of sensitive populations, such 33 as asthmatics, children, and the elderly. Secondary standards specify maximum ambient 34 concentration levels of the criteria pollutants aimed at providing public welfare protection, 35 including protection against decreased visibility and damage to animals, crops, vegetation, and 36 buildings. The NAAQS criteria pollutants include carbon monoxide (CO), lead (Pb), nitrogen 37 dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). Particulate matter 38 is further categorized by sizePM10 (aerodynamic diameter of 10 micrometers (&#xb5;m) or less) 39 and PM2.5 (aerodynamic diameter of 2.5 &#xb5;m or less). Table 3-3 identifies the NAAQS for the six 40 common criteria pollutants.
3-25
 
Affected Environment 1                            Table 3-3. National Ambient Air Quality Standards Primary/Secondary Pollutant                        Standard                      Averaging Time              Level Carbon Monoxide (CO)              Primary                      8 hour                      9 ppm 1 hour                      35 ppm Lead (Pb)                        Primary and Secondary        Rolling 3-month average 0.15 &#xb5;g/m3 Nitrogen Dioxide (NO2)            Primary                      1 hour                      100 ppb Primary and Secondary        Annual                      53 ppb Ozone (O3)                        Primary and Secondary        8 hour                      0.075 ppm Particulate matter less than      Primary                      Annual                      12 &#xb5;g/m3 2.5 &#xb5;m (PM2.5)
Secondary                    Annual                      15 &#xb5;g/m3 Primary and Secondary        24 hour                      35 &#xb5;g/m3 Particulate matter less than      Primary and Secondary        2 hour                      150 &#xb5;g/m3 10 &#xb5;m (PM10)
Sulfur Dioxide (SO2)              Primary                      1 hour                      75 ppb Secondary                    3 hour                      0.5 ppm Key: ppb = parts per billion, ppm = parts per million, &#xb5;g/m3 = micrograms per cubic meter, and &#xb5;m = micrometers.
Source: EPA 2015d 2 EPA designates areas of attainment and nonattainment with respect to the NAAQS. Areas 3 that have insufficient data to determine designation status are denoted as unclassifiable.
4 Areas that were once in nonattainment, but are now in attainment, are called maintenance 5 areas; these areas are under a 10-year monitoring plan to maintain the attainment designation 6 status. States have primary responsibility for ensuring attainment and maintenance of the 7 NAAQS. Under Section 110 of the CAA and related provisions, states are to submit, for EPA 8 approval, State Implementation Plans that provide for the timely attainment and maintenance of 9 the NAAQS.
10 Air quality designations are generally made at the county level. For the purpose of planning and 11 maintaining ambient air quality with respect to the NAAQS, EPA has developed air quality 12 control regions (AQCRs), which are intrastate or interstate areas that share a common airshed 13 (40 CFR Part 81). LSCS is located in LaSalle County, Illinois. This County, along with an 14 additional five neighboring Counties (Bureau, Lee, Marshall, Putnam, and Stark Counties) in 15 Illinois compose the North Central Illinois Intrastate AQCR (40 CFR 81.262). With regard to the 16 NAAQS criteria pollutants, LaSalle County is designated as an attainment area for all NAAQS 17 (40 CFR 81.314). The nearest designated nonattainment area is Grundy County, for the 8-hour 18 ozone 2008 standard. The nearest designated maintenance area is Grundy County for the 19 PM2.5 1997 standard. Grundy County is adjacent to LaSalle County, approximately 4 mi (6 km) 20 from LSCS. Although Grundy County is adjacent to LaSalle County, it is not part of the same 21 AQCR that LaSalle County belongs to.
22 Illinois air pollution control rules are issued under Title 35 of the IAC. Air emission sources at 23 LSCS are regulated under a Federally Enforceable State Operating Permit (FESOP) (Permit 24 No. 099802AAA, issued in December 2000) issued by the IEPA (IEPA 2000). A source is 3-26
 
Affected Environment 1 eligible for a FESOP (also known as synthetic minor air permit) if the potential to emit from the 2 source triggers CAA permit program requirements but if maximum actual emissions are below, 3 or can be restricted to remain below, major source thresholds. LSCSs FESOP permit was 4 issued in December 2000, and expired in December 2005. In accordance with 35 IAC Part 201 5 and the Illinois Environmental Protection Act of 1970 (415 Illinois Compiled Statute (ILCS) 5/39),
6 Exelon submitted a renewal application for the FESOP permit (on July 15, 2005) to the IEPA 7 90 days before the expiration of the permit; therefore, the conditions of the FESOP are 8 administratively extended. On April 7, 2015, the IEPA issued a draft FESOP permit for LSCS 9 for public review and comment (IEPA 2015).
10 Permitted sources at LSCS include five diesel-fired generators, a gasoline storage tank, and 11 gasoline dispensing facilities. The LSCS FESOP permit limits nitrogen oxides, carbon 12 monoxide, particulate matter, volatile organic compounds, and/or the sulfur dioxide emissions 13 from the diesel generators and storage tank, as well as the fuel consumption of the diesel 14 generators and gasoline of the fuel storage tank. LSCS has been in compliance with the 15 requirements established in its FESOP permit, and there have been no reported violations in the 16 past 5 years (Exelon 2015k; EPA 2015b). Emissions from permitted sources at LSCS are 17 presented in Table 3-4. LSCS also has additional air emission sources that are exempt from 18 permitting requirements, but it must still comply with applicable environmental laws and 19 regulations. These air emission sources include diesel pumps and generators that are less than 20 600 horsepower and that are intended to be used during emergency circumstances and only 21 operated during routine surveillance and testing (Exelon 2015j). Air emissions for LaSalle 22 County in 2011 for carbon monoxide, nitrogen oxides, sulfur dioxide, particulate matter less than 23 10 &#xb5;m, and particulate matter less than 2.5 &#xb5;m were 1,213 tons, 2,308 tons, 611 tons, 832 tons, 24 and 483 tons, respectively (EPA 2011). LSCS permitted annual emissions are less than 25 1 percent of the total 2011 emissions for LaSalle County.
26                                Table 3-4. LSCS Air Emissions (MT/year)(a)
Pollutant                2008            2009            2010            2011            2012          2013 CO                        1.10            1.76            1.65            1.52            2.01          1.9 SO2                      0.0042          0.0017          0.0021          0.0017          0.0021        0.001 NOx                      4.18            6.62            6.21            5.73            7.58          6.0 PM10                      0.075            0.12            0.11            0.10            0.14          0.11 PM2.5                    0.075            0.12            0.11            0.10            0.14          0.11 VOC                      0.25            0.33            0.32            0.30            0.35          0.30 CO2                    -(b)            -(b)          315.79            295.46        390.91        308.3 Key: CO = carbon monoxide, NOx = nitrogen oxides, SO2 = sulfur dioxide, PM10 = particulate matter less than 10 micrometers, PM2.5 = particulate matter less than 2.5 micrometers, and VOC = volatile organic compounds.
(a) To convert metric tons (MT) per year to tons per year, multiply by 1.1023.
(b) Carbon dioxide emissions reporting commenced in 2010; therefore, prior year emissions are not available.
Sources: Exelon 2014, 2015k 27 On October 30, 2009, EPA published a rule for the mandatory reporting of greenhouse gases 28 (GHGs) from sources that in general emit 25,000 MT or more of carbon dioxide equivalent 29 (CO2e) per year in the United States (74 FR 56260). Most small facilities across all sectors of 30 the economy fall below the 25,000-MT threshold and are not required to report GHG emissions 31 to EPA. On June 3, 2010, EPA issued the Prevention of Significant Deterioration (PSD) and 3-27
 
Affected Environment 1 Title V GHG Tailoring Rule (75 FR 31514). Beginning January 2, 2011, operating permits 2 issued to major sources of GHGs under the PSD or Title V Federal permit programs must 3 contain provisions requiring the use of best available control technology to limit the emissions of 4 GHGs if those sources would be subject to PSD or Title V permitting requirements because of 5 their non-GHG pollutant emission potentials and because their estimated GHG emissions are at 6 least 75,000 tons per year of CO2e. As discussed above, LSCS is a synthetic minor source, 7 and, as shown in Table 3-4, GHG emissions from sources at LSCS are below the GHG 8 Mandatory Reporting (40 CFR Part 98) and Tailoring Rule thresholds. Section 4.15 of this SEIS 9 further discusses GHG emissions.
10 EPA issued the Regional Haze Rule (RHR) to improve and protect visibility in national parks 11 and wilderness areas from haze, which is caused by numerous, diverse sources located across 12 a broad region (40 CFR 51.308-309). Specifically, Subpart D of 40 CFR Part 81 lists mandatory 13 Class I Federal Areas where visibility is an important value. The Regional Haze Rule requires 14 states to develop State Implementation Plans to reduce visibility impairment at Class I Federal 15 areas. The nearest Class I Federal area for visibility protection is the Mingo National Wildlife 16 Refuge, which is approximately 306 mi (492 km) southwest of the LSCS site. EPA recommends 17 that emission sources located within 62 mi (100 km) of a Class I area be modeled to consider 18 adverse impacts (EPA 1992). Considering the distance to the nearest Class I area and the 19 minor nature of air emissions from the site, there is little likelihood that ongoing activities at 20 LSCS adversely affect air quality and air quality-related values (e.g., visibility or acid deposition) 21 in any of the Class I areas.
22 3.3.3    Noise 23 Noise is unwanted sound and can be generated by many sources. Sound intensity is measured 24 in logarithmic units called decibels (dB). A dB is the ratio of the measured sound pressure level 25 to a reference level equal to a normal persons threshold of hearing. Most people barely notice 26 a difference of 3 dB or less (FHA 2011). Another characteristic of sound is frequency or pitch.
27 Noise may be composed of many frequencies, but the human ear does not hear very low or 28 very high frequencies. To represent noise as closely as possible to the noise levels people 29 experience, sounds are measured using a frequency weighting scheme known as the A scale.
30 Sound levels measured on this A scale are given in units of A-weighted decibels (dBA). Table 31 3-5 presents common noise sources and their respective noise levels. Noise levels can 32 become annoying at 80 dBA and very annoying at 90 dBA. To the human ear, each increase of 33 10 dBA sounds twice as loud (EPA 1981).
34                      Table 3-5. Common Noise Sources and Noise Levels Noise Source                                          Noise Level (dBA)
Human hearing threshold                                          0 Soft whisper                                                    30 Quiet residential area                                          40 Dishwasher                                                    55-70 Lawn mower                                                    65-95 Blender                                                        80-90 Ambulance siren, jet plane                                      120 Source: CHC undated 3-28
 
Affected Environment 1 Several different terms are commonly used to describe sounds that vary in intensity over time.
2 The equivalent sound intensity level (Leq) represents the average sound intensity level over a 3 specified interval, often 1 hour. The day-night average sound intensity level (LDN) is a single 4 value calculated from an hourly Leq over a 24-hour period, with the addition of 10 dBA to sound 5 levels from 10 p.m. to 7 a.m. This addition accounts for the greater sensitivity of most people to 6 nighttime noise. Statistical sound level (Ln) is the sound level that is exceeded n percent of the 7 time during a given period. For example, L90, is the sound level exceeded 90 percent of the 8 time and is considered the background level.
9 There are no Federal regulations1 for public exposures to noise (EPA 2015c). The EPA 10 recommends day-night average sounds levels (LDN) of 55 dBA as guidelines or goals for 11 outdoors in residential areas (EPA 1974). However, these are not standards. The Federal 12 Housing Administration has established noise assessment guidelines for housing projects and 13 finds that day-night average sound levels (LDN) of 65 dBA or less are acceptable (HUD 2014).
14 Sections 25 and 27 of the Illinois Environmental Protection Act of 1970 (Chapter 415) 15 established the authority to create noise regulations. The actual noise regulations are found in 16 the IAC (Title 35, Subtitle H). These noise regulations have allowable octave-band sound levels 17 according to emitting and receiving land class (Class A, B, and C) and time of day.
18 Major offsite noise sources in the vicinity of LSCS include vehicles, wind turbines, and 19 agricultural equipment/machinery (Exelon 2015l). Common noise sources from nuclear power 20 plant operations include transformers, loudspeakers, cooling towers, auxiliary equipment, and 21 worker vehicles (NRC 2013). Major noise sources at LSCS include pumps, turbine building 22 supply and exhaust fans, sirens, generators, transformers, and loudspeakers (Exelon 2015m).
23 However, most of these noise sources are inside buildings, at approximately a 980-ft (300-m) 24 distance from the site boundary, and/or are intermittent. The nearest resident is approximately 25 0.7 mi (1.1 km) from the reactor buildings (Exelon 2014a). Exelon has not received any noise 26 complaints from residents in the vicinity of LSCS (Exelon 2014a). Additional noise sensitive 27 receptors nearby include the LaSalle Lake State Fish and Wildlife Area and Marseilles State 28 Fish and Wildlife Area. LSCS is subject to, and in compliance with, Illinois noise pollution 29 control regulations (Exelon 2015c, 2015m).
30 3.4      Geologic Environment 31 This section describes the current geologic environment of the LSCS site and vicinity, including 32 landforms, geology, soils, and seismic conditions.
33 3.4.1      Physiography and Geology 34 The site is located in an area that contains glacially deposited sediments overlying a bedrock 35 surface. These deposits formed during successive periods of glaciation. The power block and 36 the cooling pond are located on a glacial moraine (a depositional landform directly deposited by 37 a glacier). This area has a flat gently rolling topography. The river screen house is located 38 north of both the power block and cooling pond on the flat-lying river valley of the Illinois River.
39 The river valley is approximately 3.5 mi (5.6 km) north of the site and is topographically 40 separated from the glacial moraine by the bluffs along the Illinois River. The bluffs along the 41 Illinois River are dissected by stream valleys that cut into the glacial sediments and drain north 1  In 1972, Congress passed the Noise Control Act of 1972 (42 U.S.C. 4901 et seq.) establishing a national policy to promote an environment free of noise that impacts the health and welfare of the public. However, in 1982, there was a shift in Federal noise control policy to transfer the responsibility of regulation noise to state and local governments. The Noise Control Act of 1972 was never rescinded by Congress, but it remains unfunded (EPA 2015c).
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Affected Environment 1 to the Illinois River. The maximum topographic relief between the site and the river is 2 approximately 255 ft (78 m) (Exelon 2014a; USDA 2008) (Figure 3-7).
3 In the area of the power block and the cooling pond, the land is covered by a 4- to 8-ft (1.2- to 4 2.4-m) layer of Richland Loess. The loess consists of windblown silt that has been weathered 5 to slightly clayey silt. The Richland Loess is underlain by the Wedron Silty-Clay Till. The till was 6 directly deposited by glacial activity. It consists of unsorted silt and clay sedimentary deposits.
7 In localized areas, the till also contains scattered, disconnected bodies of sand and gravel. In 8 the area of the plant buildings and cooling pond, the Wedron Silty-Clay Till ranges in thickness 9 from 120 to 140 ft (37 to 43 m). Moving north from the plant buildings and the cooling pond to 10 the river, the Wedron Silty-Clay Till decreases in thickness until it disappears near the Illinois 11 River (Figure 3-8) (Exelon 2014a).
12 Below the LSCS site, the Wedron Silty-Clay Till is underlain by bedrock. The topography of the 13 bedrock reflects the surface of the land before glaciation. This topography is now buried by 14 glacially deposited sediments. The site is located between two bedrock valleys that are filled 15 with the Wedron Silty-Clay Till and some alluvial sand and gravel deposits from ancient streams 16 that flowed through the bedrock valleys before they were completely buried. One alluvium-filled 17 buried valley runs east-west and is located between the plant facility and the Illinois River Bluff, 18 and one valley is located south of the plant facility and trends northwest and southeast 19 (Exelon 2014a, 2014c) (Figure 3-9).
20 The underlying bedrock consists of 4,500 ft (1,371 m) of dolomite, sandstone, and shale rock.
21 In turn, these rocks are underlain by granites and metamorphic rocks to a great depth. The 22 Pennsylvanian aged Carbondale Formation forms the top of the bedrock surface over most of 23 the site area. It is composed of alternating strata of shale, sandstone, clay, coal, limestone, and 24 siltstone (Exelon 2014a).
25 LaSalle County contains a number of geologic resources of economic importance. The County 26 is one of a handful of locations that can easily access the St. Peter Sandstone Formation. The 27 unique characteristics of this sandstone make it valuable for a number of commercial uses, 28 including glass, sand filters, sand molding, and abrasives. It is also in high demand for the 29 extraction of oil and gas using conventional horizontal drilling and shale fracking techniques.
30 LaSalle County also contains commercial deposits of gravel and limestone. Limestone and 31 gravel are used in concrete, agricultural limestone, and road surfaces. Clay is mined in the 32 county to manufacture bricks, drain tile, and dinnerware. Coal is no longer mined in the County 33 but historically was mined in bluffs along the Illinois River and around Streator, Illinois 34 (Ataner and Butler 2013; LaSalle County 2014; USDA 2008).
35 The LSCS site is underlain by coal seams, limestone beds, and the St. Peter Sandstone.
36 However, they lie too deep beneath the land surface to be economically accessed. No oil and 37 gas deposits have been identified beneath the site.
38 3.4.2      Soils 39 Eighty-five percent of the soil in LaSalle County is designated as prime farmland, and 9 percent 40 is farmland of State importance (Exelon 2014a). Within the site boundary, almost all the soil is 41 either silty loam or silty clay loam and is designated as prime farmland or farmland of State 42 importance (Exelon 2014a; USDA 2008, 2015b).
43 Following initial construction of the facility, areas surrounding LSCS were graded to control 44 runoff and to minimize erosion. Many areas were revegetated to support this effort 45 (Exelon 2014a).
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Affected Environment 1 Figure 3-7. Site Physiography, LSCS Vicinity 2          Source: NRC Generated 3-31
 
Affected Environment 1              Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity 2                                  (Elevation Exaggerated) 3                            Source: Modified from Exelon 2014a 3-32
 
Affected Environment 1 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity 2                Source: Modified from Exelon 2014e 3-33
 
Affected Environment 1 3.4.3      Seismic Setting 2 The site is located in an area of Illinois that might experience slight damage from earthquakes 3 (FEMA 2015; Mid-America Earthquake Center 2009). A number of earthquakes (USGS 2013a, 4 2013b, 2013c) have originated within Illinois, including the following:
5
* On May 26, 1909, a large earthquake knocked over many chimneys in Aurora and 6              swayed buildings in Chicago.
7
* On July 18, 1909, an earthquake knocked down chimneys in Petersburg.
8
* On August 14, 1965, a sharp local earthquake knocked down chimneys in Elco, 9              Unity, Olive Branch, and Olmstead.
10
* On November 9, 1968, a magnitude 5.3 earthquake was felt over the entire State of 11              Illinois and in 22 other states.
12 Dozens of earthquakes originating outside Illinois have been felt inside the State without 13 causing damage. These earthquakes originated in Missouri, Arkansas, Kansas, Nebraska, 14 Tennessee, Indiana, Ohio, Michigan, Kentucky, and Canada. Illinois can be affected by two 15 major seismic zones, the Wabash Valley Seismic Zone and the New Madrid Seismic Zone. The 16 Wabash Valley Zone lies between southeastern Illinois and southwestern Indiana about 322 mi 17 (518 km) from the site. The New Madrid Seismic Zone is about 300 mi (483 km) from the site in 18 southern Illinois, Missouri, Kentucky, and Tennessee. Of these two seismic zones, the New 19 Madrid Seismic Zone is capable of producing very powerful earthquakes. If a large magnitude 20 earthquake occurs in the New Madrid Seismic Zone, major damage could be experienced in 21 southern Illinois (Missouri Department of Natural Resources 2013; USGS 2009).
22 The NRC requires every nuclear power plant to be designed for site-specific ground motions 23 that are appropriate for its location. Nuclear power plants, including LSCS, Units 1 and 2, are 24 designed and built to withstand site-specific ground motion based on their location and nearby 25 earthquake activity. For LSCS, this includes earthquakes originating in either the Wabash 26 Valley Zone or the New Madrid Seismic Zone (Exelon 2014a). The seismic design basis is 27 established during the initial siting process using site-specific seismic hazard assessments. For 28 each nuclear power plant site, applicants estimate a design-basis ground motion based on 29 earthquake sources, wave propagations, and site responses; this estimate is then accounted for 30 in the design of the plant. In this way, nuclear power plants are designed to withstand the 31 maximum credible earthquake for a given site. Because methods of assessing seismic hazards 32 evolve over time and the scientific understanding of earthquake hazards improve (NRC 2014c),
33 the NRCs understanding of the seismic hazard for a given nuclear power plant may change 34 over time. As new seismic information becomes available, the NRC evaluates the new 35 information to determine whether changes are needed at existing plants or to NRC regulations.
36 The NRCs evaluation of the impact of seismic activity on a nuclear power plant is an ongoing 37 process that is separate from the license renewal process.
38 On December 23, 2011, the Consolidated Appropriations Act (Public Law 112-074) was signed 39 into law. Section 402 of the law directs the NRC to require reactor licensees to re-evaluate the 40 seismic hazard at their sites against current applicable Commission requirements and 41 thereafter, when appropriate, as determined by the Commission (NRC 2012). In 2012, the NRC 42 required all licensees to re-evaluate the seismic hazards at their sites using updated seismic 43 information and present-day regulatory guidance and methodologies (NRC 2012). The purpose 44 of that request was to gather information to update the seismic hazards analysis to enable the 45 NRC staff to determine whether individual site licenses should be modified, suspended, or 46 revoked (NRC 2014a). On March 31, 2014, Exelon responded to this request and provided its 3-34
 
Affected Environment 1 Seismic Hazard and Screening Report (SHSR) for LSCS (Exelon 2014d). On April 21, 2015, 2 the NRC staff issued an assessment (NRC 2015a) documenting its review of the Seismic 3 Hazard and Screening Report. The NRC staff concluded that Exelon met the intent of the 4 guidance for determining the re-evaluated seismic hazard and that it had provided an 5 acceptable response to the request. In addition, the NRC staff directed Exelon to perform 6 further seismic evaluations for NRC review.
7 3.5      Water Resources 8 3.5.1      Surface Water Resources 9 This section describes the current surface water resources within and near LSCS.
10 NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants 11 (GEIS) (NRC 2013), states that surface water encompasses all water bodies that occur above 12 the ground surface, including rivers, streams, lakes, ponds, and man-made reservoirs or 13 impoundments.
14 3.5.1.1      Surface Water Hydrology 15 The major surface water body in the region is the Illinois River, located approximately 4 mi 16 (6.4 km) to the north of the LSCS main plant complex (see Figure 3-2). The LSCS site is 17 situated within the lowermost portion of the Upper Illinois River Basin, which includes the 18 10,949- mi2 (28,369-square-kilometer (km2)) drainage area upstream from Ottawa, Illinois 19 (Figure 3-10). The Illinois River is formed from the confluence of the Kankakee and Des 20 Plaines Rivers at a point approximately 10 mi (16 km) east of Morris, Illinois. The main stem of 21 the Illinois River is joined by the Fox River at Ottawa (Arnold et al. 1999; USGS 1998).
22 The Illinois River is also central to the Illinois Waterway, which provides for navigation from Lake 23 Michigan to the Mississippi River and on to the Gulf of Mexico. The origins of this waterway 24 began with the construction of canals from the lake to the Chicago and Illinois Rivers, beginning 25 in the 1830s. Construction of the formal Illinois Waterway began in 1919 with the State of 26 Illinois leading efforts in the upper part of the river basin and the U.S. Army Corps of Engineers 27 (USACE) in the lower part. Today, the Illinois Waterway includes part of the Chicago River, the 28 Chicago Sanitary and Ship Canal, the Des Plaines River, and the Illinois River. Navigation is 29 made possible by a series of eight major locks and dams and associated navigation pools along 30 the Illinois River and its tributaries. Each pool is named for the dam downstream of each pool 31 (Exelon 2014a; Talkington 1991). Along its length, the waterway contains a navigation channel 32 at least 9 ft (2.7 m) deep and 300 ft (91 m) wide (Talkington 1991). In the vicinity of LSCS, at 33 normal pool elevation, the river has a depth of 12 ft (3.7 m) and a width of 800 ft (244 m) 34 (Exelon 2014a).
35 LSCS is located along the Marseilles Pool portion of the Illinois River. The Marseilles Lock and 36 Dam at Illinois RM 247 (RKm 397.5) is approximately 2.4 mi (3.9 km) downstream of the LSCS 37 intake and discharge structures near RM 249.5 (RKm 401.5) (see Section 3.1.3). However, the 38 lock itself is located a further 2.5 mi (4.0 km) downstream of the dam on a bypass canal 39 (Marseilles Canal) (USACE 2014). The Dresden Island Lock and Dam is 22 mi (35 km) 40 upstream of the LSCS intake structure at RM 271.5 (RKm 437) (Exelon 2014a). The Marseilles 41 Dam is 24 ft (7.3 m) high, and the Dresden Dam is 22 ft (6.7 m) high (Talkington 1991).
42 In total, the main stem of the Illinois River flows for approximately 270 mi (439 km) through 43 Illinois and ultimately discharges into the Mississippi River at Grafton, Illinois (Exelon 2014a; 44 USGS 1994; Talkington 1991). However, when accounting for the other components of the 45 Illinois Waterway, the total length of the river system is 327 mi (526 km) (Talkington 1991).
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Affected Environment 1 The U.S. Geological Survey (USGS) maintains a gaging station on the Illinois River at 2 Marseilles, Illinois (Station 05543500) and RM 246.5 (RKm 396.7). This station is 3 approximately 3 mi (4.8 km) downstream from the LSCS river screen house intake and nearby 4 discharge structure near RM 249.4 (RKm 401). The gaging station is also 0.5 mi (0.8 km) 5 downstream of the Marseilles Dam and 6.9 mi (11 km) upstream from the confluence of the Fox 6 River with the main stem of the Illinois River (Exelon 2014a; USGS 1999b, USGS 2015).
7 The mean annual discharge measured at the USGS gage at Marseilles for water years 1920 8 through 2014 is 10,750 cfs (304 m3/s). For water year 2014, the mean discharge was 9 11,190 cfs (316 m3/s). The mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the 10 period of record (USGS 2015). The 90 percent exceedance flow is an indicator value of 11 hydrologic drought. It signifies a rate of streamflow that is equaled or exceeded 90 percent of 12 the time, as compared to the average flow for the period of record. Based on average monthly 13 flow over the period of record at the station, November is the low-flow month, and April is the 14 high-flow month for the Marseilles Pool (USGS 2015).
15 Tributaries to the Illinois River in the immediate vicinity of LSCS include South Kickapoo Creek, 16 Spring Brook, Deadly Run, Armstrong Run, and Hog Run (Figure 3-11). These headwater 17 streams and manmade ditches drain the glacial upland on which LSCS is located and generally 18 flow north toward the dissected bluffs of the river and across the river valley and into the Illinois 19 River. The most extensive of these nearby tributaries is South Kickapoo Creek. With its 20 headwaters on the northwest side of the LSCS property, this stream receives stormwater runoff, 21 cooling pond dike seepage collected by the LSCS perimeter drainage ditch, and overflow from 22 the cooling pond auxiliary spillway (see Figures 3-3 and 3-5). The main channel of South 23 Kickapoo Creek flows north to northwest from LSCS, with the main channel discharging to the 24 Illinois River at a point approximately 3.5 mi (5.6 km) northwest of the LSCS cooling pond and 25 approximately 0.4 mi (0.6 km) downstream of the LSCS blowdown discharge structure 26 (Exelon 2014a).
27 On the northeast perimeter of the cooling pond is Armstrong Run. Armstrong Run previously 28 drained much of the area that is now occupied by LSCS before plant construction. Like many of 29 the manmade drainage channels (called runs) in the region, it was constructed to convey 30 drainage collected by agricultural drain tile systems (NRC 1978). Armstrong Run now receives 31 runoff and seepage collected from the northeast end of the peripheral dike drainage ditch.
32 It discharges to the Illinois River at a point approximately 3.2 RM (5.1 RKm) northeast of the 33 cooling pond and about 4.5 RM (7.2 RKm) upstream of the river screen house (Exelon 2014a).
34 As further described in Section 3.1.3, the dominant surface water feature within the LSCS site 35 and vicinity is the 2,058- ac (833- ha) cooling pond (Figure 3-5). Other surface water features 36 on the LSCS plant site include two stormwater management ponds (North and South Storm 37 Water Ponds), two sewage treatment lagoons, and a collection of hatchery ponds as 38 summarized below. The NRC staff visited the facilities cited herein during the May 2015 39 environmental site audit (NRC 2015b).
40 The North and South Storm Water Ponds are located west of the LSCS main plant complex and 41 receive stormwater runoff from the protected area, serving the north and south zones of the 42 plant, respectively. Within the site, a system of ditches, storm drains, culverts, and underground 43 storm sewers collect runoff and drainage from the protected area and convey much of it to 44 either of the two ponds. Uncontaminated runoff from the north zone of the plant is conveyed to 45 the North Storm Water Pond, with some runoff sources first passing through the Unit 2 oil-water 46 separator. A portion of the switchyard also drains toward the north zone, although most of the 47 switchyard drains east to the cooling pond.
3-36
 
Affected Environment 1 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries 2                  Source: Modified from Arnold et al. 1999 3-37
 
Affected Environment 1          Figure 3-11. LSCS Surface Water and Related Water Resource Features 2                        Source: Modified from Exelon 2014a, 2015b 3-38
 
Affected Environment 1 Most runoff from the south zone enters the smaller South Storm Water Pond; this pond then 2 discharges to the cooling pond discharge canal through internal Outfall H01. Before entering 3 the pond, some flows first pass through the Unit 1 oil-water separator. The south pond also 4 receives runoff from the firing range. Areas of the plant site to the northwest and south of the 5 developed plant complex do not drain to the ponds but instead are drained by existing surface 6 stream segments and ditches (Exelon 2014a, 2014c).
7 Stormwater management and pollution control at LSCS is subject to Exelons Storm Water 8 Pollution Prevention Plan (SWPPP) (Exelon 2013e), which Exelon has implemented in 9 accordance with Special Condition 8 of the sites NPDES permit (IEPA 2013). The SWPPP 10 applies to industrial stormwater runoff from the site, which is not otherwise process-related and 11 not captured and processed by LSCSs wastewater treatment facilities. It describes the best 12 management practices, controls, inspection, and monitoring requirements, and the associated 13 implementing procedures and personnel responsibilities for reducing pollutants in stormwater 14 discharge and for ensuring compliance with the terms and conditions of the site NPDES permit 15 (Exelon 2013e).
16 Two open sewage treatment lagoons provide primary and secondary treatment for LSCSs 17 sanitary effluent. These lagoons are geotextile-lined impoundments and are located to the north 18 of the main plant complex adjacent to LSCSs sewage treatment plant (as shown in 19 Figure 3-3). Together, the NRC staff estimates the two impoundments cover an area of about 20 1.6 ac (0.65 ha). After filtration and final disinfection in the sewage treatment plant, the final 21 effluent from the treatment system is discharged into the cooling pond via NPDES internal 22 Outfall B01 (Exelon 2014a, 2014c).
23 A cluster of 16 small fish-rearing ponds is located on the southwest shore of the cooling pond 24 (see Figures 3-3 and 3-5). The NRC staff estimates that the ponds total approximately 29 ac 25 (12 ha) of open water. These ponds comprise the LaSalle Fish Hatchery operated by the IDNR 26 on plant property and subject to a lease agreement with Exelon. The hatchery uses the cooling 27 pond as a makeup water source. Runoff and drainage from the hatchery ponds flow back to the 28 cooling pond and are ultimately subject to LSCSs NPDES permit provisions 29 (Exelon 2014a, 2014c). The LSCS sites NPDES permit is further discussed in Section 3.5.1.3.
30 LSCS is not susceptible to riverine flooding because it is located upland and away from the 31 Illinois River.
32 The grade elevation at the plant site is 710 ft (216 m) above MSL, and the floor elevation of the 33 LSCS facilities is 710.5 ft (217 m) above MSL. The plant floor lies at an elevation that is 188 ft 34 (57 m) above the level of a postulated probable maximum flood on the Illinois River 35 (Exelon 2014a, 2014g). Although the river screen house is not a safety-related structure, it is 36 designed to withstand the 100-year flood on the Illinois River. Its loss would not impact the 37 ability to safely shut down the plant as water could still be drawn from the cooling pond and from 38 the UHS portion of the cooling pond, as described in Section 3.1.3 of the SEIS (Exelon 2014a, 39 2014g).
40 Furthermore, a failure of the peripheral dike system enclosing the cooling pond would not flood 41 the power plant area because the onsite topography would cause cooling pond water to flow 42 north and away from the plant following the existing drainage network (Exelon 2014a, 2014g).
43 3.5.1.2      Surface Water Use 44 LSCS withdraws surface water from the Illinois River as makeup water for the plants cooling 45 pond. The cooling pond provides water for the plants circulating water, service water, and 46 essential cooling water systems. Cooling tower blowdown and other permitted effluent streams 47 are discharged back to the Illinois River via the plants primary NPDES outfall (Outfall 001) at a 3-39
 
Affected Environment 1 point located about 900 ft (270 m) downstream from LSCSs river intake structure and 2 associated river screen house.
3 The maximum (nominal) surface water withdrawal rate for LSCS, Units 1 and 2, is 90,000 gpm 4 (200 cfs or 5.66 m3/s). This is equivalent to 129.6 million gallons per day (mgd) 5 (491,000 m3/day). However, Exelon reports in its ER that LSCSs normal peak makeup 6 withdrawal rate from the Illinois River is 60,000 gpm (134 cfs or 3.77 m3/s) or 86.4 mgd 7 (327,000 m3/day). This rate assumes a two-pump operation with valves open at 100 percent.
8 The third makeup pump located in the river screen house normally serves as a backup 9 (see Section 3.1.3).
10 The NRC staff reviewed submittals by Exelon to the Illinois State Water Survey that document 11 the volume of surface water withdrawn from, and discharged back to, the Illinois River during 12 the period 2009 to 2013 (Table 3-6). Based on these data, LSCS surface water withdrawals 13 have averaged 24,745 million gallons per year (mgy) (93.7 million cubic meters per year 14 (m3/yr)). This is equivalent to an average withdrawal rate of approximately 105 cfs (2.96 m3/s or 15 67.8 mgd). Return discharges (blowdown) to the Illinois River have averaged 13,046 mgy 16 (49.4 million m3/yr), which is equivalent to an average discharge rate of about 55.3 cfs 17 (1.56 m3/s or 35.7 mgd). The difference between withdraw and discharge (i.e., approximately 18 49.7 cfs (1.40 m3/s)) generally reflects process consumptive use or other losses, evaporative 19 losses, and presumably seepage from the cooling pond. In total, these data indicate a 20 consumptive use rate averaging 47 percent.
21    Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, LSCS Withdrawals                                      Discharges Year              (mgy)          mgd            cfs            (mgy)              mgd              cfs 2009            28,598.4          78.5            121          19,405.0              53.2            82.2 2010            25,876.8          70.9            110          13,686.0              37.5            58.0 2011            23,328.0          63.9            98.9        11,961.1              32.8            50.7 2012            28,857.6          79.1            122          14,005.7              38.4            59.4 2013            17,064.0          46.7            72.3          6,173.0              16.9            26.2 Average            24,745.0          67.8            105          13,046.1              35.7            55.3 Note: Reported and calculated values are rounded. To convert million gallons per year (mgy) to million cubic meters (m3), divide by 264.2. To convert, million gallons per day (mgd) to cubic feet per second (cfs), multiply by 1.547.
Sources: Exelon 2011a, 2012a, 2013a, 2014a, 2014d 22 LSCSs surface water withdrawals and consumptive water use are not subject to any water 23 allocation or related permitting requirements at the present time. In 2006, the Governor of 24 Illinois issued an executive order establishing a Statewide program for State and regional water 25 supply planning and management, which included the development and approval of regional 26 plans in designated Priority Water Quantity Planning Areas (State of Illinois 2006). LaSalle 27 County, where LSCS is located, is not included within any of the three designated planning 28 areas (Exelon 2014a; ISWS 2015a). Nevertheless, as referenced above, Exelon reports its 29 surface water withdrawals to the State of Illinois under the State Illinois Water Inventory 30 Program (Exelon 2014a; ISWS 2015b). Reporting is required in accordance with the Illinois 31 Water Use Act of 1983 (525 ILCS 45) and its 2010 amendments. The general purpose and 32 intent of the Act is to establish a means of reviewing potential water conflicts before damage to 3-40
 
Affected Environment 1 any person is incurred and to establish a rule for mitigating water shortage conflicts. The 2 2010 amendments to the Illinois Water Use Act added high-capacity intakes as subject to the 3 Acts water use reporting provisions. Such intakes are surface water intakes on a property in 4 which the rate or capacity of water withdrawal of all intakes for the property is equal to, or in 5 excess of, 100,000 gal (380 m3) during any 24-hour period (525 ILCS 45).
6 Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and 7 cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat 8 Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan 9 and associated procedures to mitigate the impacts of summer drought and/or high river 10 temperature and river low-flow conditions. Depending on predefined conditions set forth in the 11 plan and implementing procedures, such actions may include a combination of monitoring and 12 modeling of river intake and mixing zone temperatures; manipulation of the water level of the 13 cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the 14 cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the TS 15 limits on condenser inlet temperature from the cooling pond (Exelon 2014a, 2015c).
16 Two other industrial facilities withdraw water from the Marseilles Pool of the Illinois River in the 17 vicinity of LSCS (Figure 3-5) and are listed in the Illinois Water Inventory Program. These are 18 Agrium U.S., Inc., and PCE Phosphate, Marseilles Operation. The volume of water withdrawn 19 by these commercial facilities is not publicly available (Exelon 2014a). Because they are 20 included in the States inventory, the NRC staff presumes that each facility withdraws in excess 21 of 100,000 gpd (380 m3). Both are also currently subject to NPDES individual permits 22 (i.e., Permits IL0001708 and IL0036463). Based on reported return discharges to the Illinois 23 River, it is estimated that Agriums surface water withdrawals are on the order of 5 mgd 24 (18,900 m3) (EPA 2015a).
25 The public water supply systems in the vicinity of LSCS (i.e., the city of Marseilles and the 26 village of Seneca) do not withdraw water from the Illinois River but instead rely upon 27 groundwater-supplied systems (Exelon 2014a) (see Section 3.5.2.2).
28 Surface water withdrawals within the Marseilles Pool have shown no significant effects on water 29 availability to date (Exelon 2014a).
30 3.5.1.3      Surface Water Quality and Effluents 31 The Illinois Pollution Control Board (IPCB), a sister agency to the IEPA, promulgates water 32 quality standards in the State. Two Sections of Title 35 of the IAC (35 IAC 302 and 35 IAC 303) 33 contain the standards applicable to lakes and streams. Procedures that must be followed in 34 using water quality standards to set NPDES permit limits appear in Section 309 (35 IAC 309).
35 Designated uses prescribed by 35 IAC 303 are those uses specified in water quality standards 36 for each lake, river, stream, and groundwater resource. In designating uses for a waterbody, 37 the IPCB considers the use and value of the waterbody for public water supply; propagation of 38 fish, shellfish, and wildlife; and recreational, agricultural, industrial, and navigational purposes.
39 The main stem of the Illinois River is designated a general use water by the IPCB. Waters in 40 the general use category must meet water quality standards protective of aquatic life, wildlife, 41 agricultural use, and secondary contact use, as well as most industrial uses and aesthetic 42 quality (35 IAC 303.201). These standards pertain to pH; phosphorus; dissolved oxygen; 43 radioactivity (gross beta, strontium-90, and radium-226 and -228); various chemical constituents 44 (metals and organic compounds); fecal coliform; and other toxic substances. In addition, a 45 segment of the main stem of the Illinois River within LaSalle and Grundy Counties, and 46 encompassing the entire Marseilles Pool on which LSCS is located, is afforded enhanced 47 dissolved oxygen protection. Dissolved oxygen levels must be not less than 5.0 milligrams per 3-41
 
Affected Environment 1 liter at any time during March through July and not less than 4.0 milligrams per liter at any time 2 during August through February (35 IAC 302.206).
3 Over the last 150 years, water quality within the whole of the Illinois River Basin has historically 4 suffered from rapid population growth; urbanization; and industrial development, including the 5 conversion of prairie, wetlands, and forests. This change resulted in the discharge of untreated 6 and inadequately treated sewage, the discharge of industrial pollutants and refuse, runoff of 7 agricultural chemicals and sediments, and the alteration of the natural river hydrology due to 8 navigation and flood control projects (Exelon 2014a; Talkington 1991).
9 Over the last 50 years, substantial improvements in water quality have occurred because of 10 municipal and industrial waste treatment and management efforts to address both point and 11 nonpoint pollutant sources. Ongoing water quality concerns within the upper Illinois River Basin 12 include the atmospheric deposition of pesticides and trace metals; endocrine disrupting 13 compounds in surface and groundwater; nutrient enrichment of surface and groundwater; the 14 transport and fate of pesticides, trace elements, and volatile organic compounds in surface and 15 ground water; and the effects of urbanization on biodiversity, habitat, and water quality 16 (USGS 1998).
17 Section 303(d) of the Federal Water Pollution Control Act (i.e., Clean Water Act of 1977, as 18 amended (CWA) (33 U.S.C. 1251 et seq.)) requires the State of Illinois and other states to 19 identify all impaired waters for which effluent limitations and pollution control activities are not 20 sufficient to attain water quality standards in such waters. The Section 303(d) list includes those 21 water quality-limited stream segments that require the development of total maximum daily 22 loads (TMDLs) to ensure future compliance with water quality standards. The TMDLs specify 23 the maximum amount of a pollutant that a waterbody can receive and still meet water quality 24 standards. Once established, TMDLs are typically implemented through watershed-based 25 programs administered by the State, primarily through the NPDES permit program and 26 associated point and nonpoint source water quality improvement plans and associated best 27 management practices. The IEPA has classified a 30.1-mi- (48.4-km)-long segment (IL_D-23) 28 of the Illinois River between Morris and Ottawa, Illinois, that includes the LSCS site as impaired.
29 This segment is listed as impaired because it does not meet designated uses for fish 30 consumption due to polychlorinated biphenyls (PCBs) and mercury contamination. It is also 31 impaired for primary contact recreation use due to fecal coliform bacteria (IEPA 2014b). Special 32 Condition 13 of the NPDES permit for LSCS prohibits the discharge of PCBs in plant effluents 33 (IEPA 2013). The river segment is classified as fully supporting its designated use for aquatic 34 life. IEPA has assigned a medium priority for the development of TMDLs for segment IL_D-23 35 (IEPA 2014b).
36 As for other streams and runs in the vicinity of LSCS, IEPA (2014b) designates them as 37 Category 3, which are waters for which no use-support determination can be made due to 38 insufficient available data and/or information.
39 The LSCS cooling pond is included in the IEPAs CWA Section 314 inventory of lakes and has 40 also been designated as Category 3 (IEPA 2014b). However, LSCSs cooling pond is defined 41 by the State of Illinois as a wastewater treatment works pursuant to 35 IAC 301.415. Under this 42 definition, the cooling pond is not waters of the State under 35 IAC 301.440. Likewise, as 43 defined in 40 CFR 230.3, pursuant to the Federal CWA, waste treatment systems, including 44 treatment ponds or lagoons designed to meet the requirements of the Clean Water Act are 45 explicitly excluded from the definition of waters of the United States. Therefore, the cooling 46 pond is not subject to State or Federal water quality standards.
47 To operate a nuclear power plant, licensees must comply with the CWA, including associated 48 requirements imposed by EPA or the state as part of the NPDES permitting system under 3-42
 
Affected Environment 1 Section 402 of the CWA, as well as state water quality certification requirements under 2 Section 401 of the CWA. The EPA or the state, not the NRC, sets the limits for effluents and 3 operational parameters in plant-specific NPDES permits. Nuclear power plants cannot operate 4 without a valid NPDES permit and a current CWA Section 401 Water Quality Certification. The 5 EPA has delegated responsibility to the State of Illinois for the administration of the NPDES 6 program in Illinois. NPDES permits are issued by the IEPA on a 5-year cycle.
7 LSCS is authorized to discharge various wastewater (effluent) streams, including cooling pond 8 blowdown and stormwater under NPDES Permit IL0048151, reissued on July 5, 2013; the 9 current permit expires on July 31, 2018 (Exelon 2014a; IEPA 2013). The permit specifies the 10 discharge standards and monitoring requirements for effluent chemical and thermal quality 11 through the plants outfalls to the Illinois River, as summarized in Figure 3-7. The location of 12 the LSCSs primary outfall (001) to the Illinois River is shown in Figure 3-5.
13                          Table 3-7. National Pollutant Discharge Elimination 14                                    System-Permitted Outfalls, LSCS Average Flow Outfall        Rate (mgd)(a)    Description 001(b,c,d,e)  34.9              Cooling Pond Blowdown; includes effluents from internal Outfalls A01 through H01, as well as IDNR fish hatchery effluents; discharge to the Illinois River A01(b,f,g)    Intermittent      Demineralizer Regenerant Wastes; includes makeup demineralizer regenerant wastes, off-specification demineralized water, makeup demineralizer maintenance wastewater, unit waterbox vacuum pump condensate, and radioactive waste (radwaste) treatment acid/caustic system drains discharges B01(b,c,f,g,h) 0.06              Sewage Treatment Plant Effluent; includes sanitary wastewater and eyewash station wastewater C01(b,c,f,g,i) 0.044            Wastewater Treatment System Effluent; includes nonsanitary drains composed of turbine building fire and miscellaneous nonradioactive wastewater sump, greensand filter backwash, diesel fuel storage and service water building sump, auxiliary boiler blowdown, water softener regenerant waste, demineralizer regenerant wastes, heat bay building roof area, fire protection system flushing and maintenance, service water system flushing and maintenance, domestic water system flushing and maintenance, clean condensate system flushing and maintenance, laboratory liquid wastes, station heat system condensate, diesel generator cooling water, standby liquid control test skid flush water, and groundwater D01(f)        Intermittent      Cooling Water Intake Screen Backwash E01(b,f g,i)  Intermittent      Unit 1 and 2 Radwaste Treatment System Effluent; includes equipment and floor drains in the turbine, auxiliary, and reactor buildings, as well as condensate polisher waste from the turbine building and decontamination and laundry waste F01(f)        Intermittent      Auxiliary Reactor Equipment Cooling and Flushing Water G01(f,j)      Intermittent      North Site Stormwater Runoff H01(f,j)      Intermittent      South Site Stormwater Runoff I01(b,f,g)    Intermittent      Reverse Osmosis System Reject Water and Greensand Filter Backwash 3-43
 
Affected Environment Average Flow Outfall          Rate (mgd)(a)          Description 002(k)            Intermittent          Illinois River Makeup Water Intake Screen Backwash; includes river intake screen backwash; trench wash water; process sampling discharge; lake makeup pump gland leakoff; coolers/reliefs flow; lake makeup pump strainer backwash; air compressor receiver and prefilter drainage; dewatering pump discharge; fire protection water; and river screen house switchyard stormwater runoff, floor drains, and roof drains; discharge to the Illinois River at the river screen house (a) To  convert million gallons per day (mgd) to million cubic meters (m3), divide by 264.2.
(b) Flow  is subject to monitoring and reporting in units of mgd as a monthly average and as a daily maximum on Discharge Monitoring Report (DMR) (NPDES permit Special Condition 1).
(c) pH is subject to limit of 6.0 to 9.0 (NPDES permit Special Condition 2).
(d) Temperature is subject to continuous monitoring and DMR reporting of maximum monthly, as well as with temperature limits and mixing zone criteria (NPDES permit Special Condition 3). The calculated temperature at the edge of the mixing zone is limited to no more than 5 &deg;F (2.8 &deg;C) higher than ambient river temperature. The temperature beyond the mixing zone cannot exceed specified monthly limits for longer than 1 percent (i.e., 87.[[estimated NRC review hours::6 hours]]) of any 12-month period and cannot at any time exceed the specified monthly limit by more than 1.7 &deg;C (3 &deg;F). During the months of April through November, the calculated temperature outside the mixing cannot exceed 93 &deg;F (34 &deg;C).
(e) Total residual chlorine is subject to a limit of 0.05 milligrams per liter (NPDES permit Special Conditions 4 and 16).
(f) This outfall is the NPDES permit internal monitoring point before the numbered point source outfall.
(g) Total suspended solids are subject to specified limits and monitoring.
(h) Carbonaceous biochemical oxygen demand is subject to specified limits and monitoring.
(i) Oil and grease are subject to specified limits and monitoring.
(j) Stormwater is subject to requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8).
(k) Adequate maintenance of intake screen system is required to prevent discharge of floating debris back to the river. The stormwater portion is subject to the requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8).
Note: The release of complex metal-bearing waste streams and polychlorinated biphenyls (PCBs) from all outfalls is prohibited by NPDES permit Special Conditions 5 and 13, respectively. Special Condition 9 authorizes the use of water treatment additives that were requested by Exelon as part of the renewed NPDES permit application.
Source: IEPA 2013 1 As indicated in Table 3-7, the NPDES permit for LSCS requires Exelon to monitor and sample 2 site effluents for various parameters in accordance with applicable effluent limits. Monitoring 3 results are reported in monthly Discharge Monitoring Reports (DMRs) submitted to the State.
4 The NRC staff reviewed the DMRs submitted by Exelon to the IEPA for the period 2010 through 5 2014. This review encompassed the results of recorded maximum cooling pond blowdown 6 temperatures to the Illinois River and associated calculations of river mixing zone temperatures 7 as reported in the DMRs for the past 5 years (2010 through 2014) and as compiled by Exelon 8 (Exelon 2015c). Based on the NRCs staff review and Exelons responses to the NRCs 9 requests for additional information, LSCS has received no notices of violation associated with 10 NPDES permitted discharges during the 2010 through 2014 time period. Nonetheless, Exelon 11 recorded several unusual occurrences in its DMR reports. These included reports of a makeup 12 pipeline line failure on January 29, 2010; a blowdown line failure on July 13, 2012; a makeup 13 pipeline line failure on January 25, 2013; a blowdown line air release valve failure on 3-44
 
Affected Environment 1 February 8, 2013; a makeup pipeline failure on May 21, 2013; and a makeup pipeline failure on 2 January 23, 2014 (Exelon 2015c).
3 The DMR submittals also document actions taken to comply with provisional variances granted 4 by the IEPA to Exelon with respect to LSCSs effluent discharges to the Illinois River and 5 associated river mixing zone temperature limits. Specifically, these variances 6 (IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in 7 March, July, and August 2012, respectively, due to unusual weather conditions and associated 8 high ambient river water temperatures that impacted the ability for LSCS thermal discharges to 9 meet the requirements of Special Condition 3 of LSCSs NPDES permit. This limits the number 10 of temperature excursion hours to 1 percent (87.[[estimated NRC review hours::6 hours]]) of the hours in a 12-month period, 11 ending with any month (see footnote d in Table 3-7). During the variance period(s), Exelon was 12 required, in part, to continuously monitor both the discharge and receiving water temperatures 13 and visually inspect all discharge areas at least three times each day to assess the impact on 14 aquatic life. These thermal discharge excursions were not found to have any impact on aquatic 15 life (Exelon 2015c).
16 An applicant (in this case, Exelon) for a Federal license to conduct activities that may cause a 17 discharge of regulated pollutants into navigable waters of the United States is required by 18 Section 401 of the CWA to provide the licensing agency (in this case, the NRC) with water 19 quality certification from the state (in this case, the State of Illinois). This certification implies 20 that discharges from the project or facility to be licensed will comply with CWA requirements and 21 will not cause or contribute to a violation of state water quality standards. If the applicant has 22 not received Section 401 certification, the NRC cannot issue a renewed license unless that state 23 has waived the requirement. The NRC recognizes that some NPDES-delegated states explicitly 24 integrate their 401 certification process with NPDES permit issuance. However, LSCSs 25 NPDES permit does not explicitly convey water quality certification under CWA Section 401.
26 By letter dated February 4, 2014, Exelon submitted an application to the IEPA Bureau of Water 27 that requested certification from the IEPA that renewal of Exelons NRC operating licenses for 28 LSCS would not violate State water quality standards (Exelon 2014h). The IEPA Division of 29 Water Pollution Control issued a letter to the NRC, and copied Exelon, which provides 30 Section 401 water quality certification for renewal of the operating licenses for LSCS. The 31 certification was issued with the condition that Exelon shall be responsible for obtaining NPDES 32 permits required for wastewater or stormwater discharges to waters of the State (IEPA 2014c).
33 As previously stated in this section, NRC licensees must comply with the CWA, including 34 associated requirements imposed by EPA or the state, as part of the NPDES permitting system 35 under CWA Section 402. The NRC staff concludes that the IEPAs response provides the 36 necessary certification pursuant to CWA Section 401.
37 To maintain LSCSs surface water intake system on Marseilles Pool of the Illinois River, Exelon 38 conducts occasional maintenance dredging at the river screen house (Exelon 2014a). The 39 need for maintenance dredging at the river screen house forebay is periodically evaluated in 40 accordance with an Exelon operating procedure. Currently, needed dredging is conducted 41 under a USACE Section 10 permit, which is issued pursuant to the Rivers and Harbors 42 Appropriation Act of 1899 (33 U.S.C. 403) (USACE 2006). Dredging was most recently 43 conducted in October 2013 in compliance with the provisions of the permit. Less than 100 cubic 44 yards (76 m3) of sediment was removed, and the material was dewatered and placed out of the 45 floodplain near the screen house. Future maintenance dredging will be conducted as needed 46 and with the necessary permits. Exelon does not expect to perform any dredging in the vicinity 47 of the LSCS discharge channel during the license renewal term and does not anticipate the 48 need to conduct any fill activities (Exelon 2015c).
3-45
 
Affected Environment 1 3.5.2      Groundwater Resources 2 This section describes the current groundwater resources at the LSCS site and in the vicinity.
3 3.5.2.1      Site Description and Hydrogeology 4 The site is characterized by five hydrogeologic units. By increasing depth, they are as follows:
5
* the Alluvial Aquifer, 6
* the Glacial Drift Aquitard, 7
* the Buried Bedrock Valley Aquifers, 8
* the Pennsylvanian Aquitard, and 9
* the Cambrian-Ordovician Aquifer System.
10 The hydrogeologic characteristics of these units are summarized in Figure 3-12.
11 Alluvial (stream) deposits are found beneath, and extend along each side of, the Illinois River.
12 These deposits form the Alluvial Aquifer that lays on top of the bedrock (the Pennsylvanian 13 Aquitard) (Figure 3-8). The river functions as a hydrologic boundary, which prevents 14 groundwater within the Alluvial Aquifer from flowing from one side of the river to the other. The 15 Alluvial Aquifer is generally 2 to 4 ft (0.6 to 1.2 m) thick, is located in the vicinity of the river 16 screen house, and ranges from 3,500 to 4,800 ft (1,067 to 1,463 m) in width. Yields in the 17 Alluvial Aquifer are restricted by the limited areal extent and thickness of the sand and gravel 18 deposits that make up the aquifer. Small dependable yields suitable for domestic purposes are 19 only locally available. The aquifer receives recharge primarily by precipitation and from the 20 river. Well yields from the Alluvial Aquifer in the vicinity of the river screen house are most likely 21 adequate only for domestic use (Exelon 2014a).
22 The Glacial Drift Aquitard is made up of the Richland Loess and the Wedron Silty-Clay Till 23 (see Section 3.4.1). The aquitard largely consists of silty-clay till (unsorted sediment containing 24 a range of grain sizes) with very low permeability. In the area of the plant buildings, the Glacial 25 Drift Aquitard is over 200 ft (61 m) thick (CRA 2006). Any extractable groundwater in this 26 aquitard is produced from thin discontinuous sand and gravel pockets that are recharged by the 27 slow infiltration of precipitation through the silty-clay till. The volume of groundwater produced 28 from these pockets is limited so that it is primarily used as a source of water for domestic or 29 farm activities (Exelon 2014a).
30 As discussed in Section 3.4.1, the site is located between two buried bedrock valleys that 31 contain alluvial deposits of sandy gravels and gravelly sands with lesser amounts of silt and clay 32 in scattered thin layers. These alluvial deposits are overlain and merge with the Wedron 33 Silty-Clay Till. They are recharged by the slow infiltration of precipitation through the thick 34 overlying Glacial Drift Aquitard. Therefore, the volume of groundwater that can be produced 35 from the Buried Bedrock Valley Aquifers is limited to supplying water for domestic or farm 36 activities (Exelon 2014a).
37 The Pennsylvanian Aquitard forms the bedrock. It consists of alternating beds of shale, 38 siltstone, underclay, sandstone, limestone, coal, and many gradational layers. Low permeability 39 shale and siltstone comprise more than 90 percent of the aquitard. In the area of the plant 40 buildings, the Pennsylvanian Aquitard is approximately 176 ft (54 m) thick. Groundwater in the 41 aquitard occurs under artesian conditions. Wells finished in the aquitard get water primarily 42 from thin sandstone and limestone beds within the aquitard, which are recharged by seepage 43 through the overlying shales and through the silty-clay till of the Glacial Drift Aquitard. In 44 general, the sandstone and limestone beds within the aquitard can only supply enough water for 3-46
 
Affected Environment 1 domestic or farm use because well yields are commonly less than 36 L/min (10 gpm) 2 (Exelon 2014a).
3                        Figure 3-12. LSCS Site Hydrogeologic Units 4                            Source: Modified from Exelon 2014a 3-47
 
Affected Environment 1 The Pennsylvanian Aquitard is underlain by the Cambrian-Ordovician Aquifer, which is an 2 important aquifer in the region. Beneath the site, this aquifer is composed of the following strata 3 (listed from shallowest to deepest):
4
* Platteville Group, 5
* GlenwoodSt. Peter Sandstone, 6
* Potosi Dolomite, 7
* Franconia Formation, 8
* Ironton Sandstone, and 9
* Galesville Sandstone.
10 At the site, the Cambrian-Ordovician Aquifer is approximately 1,090 ft (469 m) thick. Although 11 numerous alternating layers of sandstones, limestone, and dolomites impart a heterogeneous 12 character to the system, these units are hydraulically connected and behave as a single aquifer 13 (Exelon 2014a). The Cambrian-Ordovician Aquifer is the most important supplier of public 14 water in the region.
15 The Cambrian-Ordovician Aquifer is underlain by 450 ft (137 m) of the Eau Claire Formation 16 Aquitard, which is underlain by 2,500 ft (762 m) of the Mt. Simon Aquifer. The Mt. Simon 17 Aquifer is underlain by granitic and metamorphic rock.
18 In addition to the hydrogeologic units previously described, the plant area is directly underlain by 19 engineered granular fill that has been placed on top of the Wedron Silty-Clay Till. The 20 engineered granular fill underlies and surrounds the plant buildings and structures. It is 21 composed of sand and gravel and silty clay and contains groundwater that is recharged by local 22 precipitation. Because the underlying Wedron Silty-Clay Till has a very low permeability, 23 groundwater in the granular fill flows laterally eastward until it discharges into the intake canal, 24 or it flows laterally and discharges to the stormwater ponds and the discharge canal to the west 25 (CRA 2006) (Figures 3-12 and 3-13).
26 3.5.2.2      Groundwater Use 27 LaSalle County has an adequate supply of groundwater to meet current needs for industrial, 28 municipal, and domestic purposes. Regionally, the most abundant groundwater supplies are 29 obtained from the Cambrian-Ordovician Aquifer (LaSalle County 2014).
30 At the site, water for potable usage is obtained from two cased onsite wells completed into the 31 Cambrian-Ordovician Aquifer. These wells were installed in 1972 and 1974 in the area of the 32 plant buildings. They were drilled to a depth of 1,620 and 1,629 ft (494 and 496 m) and cased 33 to a depth of 921 and 989 ft (281 and 301 m) (Exelon 2014a, 2014f; ISGS 2015). Together the 34 two wells withdraw groundwater at an average rate of 26.1 gpm (98.7 L/min) (Exelon 2014a).
3-48
 
Affected Environment 1 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill 2                Source: Modified from Exelon 2014a 3-49
 
Affected Environment 1                      Figure 3-14. LSCS Hydrogeologic Cross-Section 2                                  (Elevation Exaggerated) 3                              Source: Modified from CRA 2006 3-50
 
Affected Environment 1 Within 10 mi (16 km) of the LSCS site, almost all water used for public water supplies is 2 obtained from the Cambrian-Ordovician Aquifer. However, the Village of Ransom withdraws 3 water from both the Cambrian-Ordovician Aquifer and from permeable zones in the 4 Pennsylvanian Aquitard, and the Village of Grand Ridge obtains water from the Buried Bedrock 5 Valley Aquifers. People in small communities within 10 mi (16 km) of the LSCS site that are not 6 served by a public water supply system obtain water from individual wells in the glacial drift, the 7 Pennsylvanian strata, or the upper portion of the Cambrian-Ordovician Aquifer (Exelon 2014a).
8 3.5.2.3      Groundwater Quality 9 In general, the quality of groundwater in the Alluvial Aquifer, the Glacial Drift Aquitard, the 10 Buried Bedrock Valley Aquifers, the Pennsylvanian Aquitard, and the Cambrian-Ordovician 11 Aquifer is suitable for public use and consumption. A search of Illinois State Geological Survey 12 water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant 13 buildings. With the exception of one well completed in the Pennsylvanian Aquitard, all these 14 wells withdraw water from the Cambrian-Ordovician Aquifer (ISGS 2015).
15 In 1985, a condensate line broke in the area east-southeast of the LSCS reactor building.
16 Tritium was detected near the broken line in groundwater near the surface. The line was 17 repaired soon after it broke. In 1986, the highest tritium concentrations detected in the 18 groundwater was approximately 11,000 picocuries per liter (pCi/L). Tritium concentrations in the 19 groundwater near the broken line have declined to the point that, since 2007, tritium 20 concentrations in the groundwater have been below the lower limit of detection (Exelon 2014a; 21 Exelon Nuclear 2008, 2009, 2010, 2011, 2012, 2013, 2014, 2015).
22 In September 2001, a spill of water from a recycled condensate storage tank resulted in tritium 23 contamination into groundwater near the land surface. Tritium concentrations in the 24 groundwater ranged from 766 to 1,280 pCi/L in 2006 (Exelon 2014a; Exelon Nuclear 2007).
25 These concentrations are well below the EPA Maximum Contaminant Level for tritium of 26 20,000 pCi/L. In 2014, tritium concentrations in the groundwater had further decreased below 27 the lower limit of detection (Exelon Nuclear 2015).
28 Another leak from a recycled condensate tank was identified in 2010. The tank is located near 29 the plant buildings and is underlain by 10 ft (3 m) of engineered granular fill. In turn, the fill is 30 underlain by the Wedron Silty-Clay Till. Soon after the leak was detected, the tank was drained 31 and repaired. The leak contaminated groundwater in engineered granular fill with condensate 32 water that contained tritium. Contamination in the engineered granular fill is being addressed 33 through natural monitored attenuation and by active remediation. Exelon is pumping 34 contaminated groundwater from both a well and a French drain installed in the engineered 35 granular fill and then discharging the recovered water into the cooling pond where it is greatly 36 diluted to below the lower limit of detection (Exelon 2014a). Exelon has been monitoring the 37 cleanup of the engineered granular fill using monitor wells. In June 2015, samples from all of 38 the monitor wells recorded tritium concentrations below the EPA Maximum Contaminant Level 39 for tritium of 20,000 pCi/L (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015; Exelon 2015a, 40 2015c). Although the engineered granular fill has been contaminated with tritium and is being 41 cleaned up, it is not an aquifer. No aquifers are known to have been contaminated by 42 inadvertent releases of radionuclides to groundwater.
43 One nonradiological release to groundwater occurred in 1999 when an oil tank was discovered 44 to have leaked. The spill was remediated, and on February 9, 2005, IEPA issued a letter of No 45 Further Remediation for the cleanup activities (Exelon 2014a).
3-51
 
Affected Environment 1 3.6      Terrestrial Resources 2 3.6.1      LSCS Ecoregion 3 LSCS lies within the Illinois/Indiana Prairies Level IV Ecoregion. This ecoregion encompasses 4 19,557 mi2 (50,652 km2) in eastern and central Illinois and western Indiana (Woods et al. 2006).
5 It is composed of vast glaciated, flat to rolling plains with terminal and recessional moraines, 6 prairie potholes, and old lake beds. Historically, tallgrass prairie covered the majority of the land 7 surface. Oak-hickory forests were common on moraines and floodplains, and marshes and wet 8 prairies occurred in poorly drained areas. Beginning in the 19th century, agricultural land began 9 to replace the natural vegetation, and it is now the dominant land type (Woods et al. 2006).
10 Prairie remnants lack many natural ecosystem functions due to their small size, and areas of 11 prairie restoration often lack forbs (broad-leaved herbs other than grass) or are overly 12 dominated by big bluestem (Andropogon gerardii) (a grass) or Indiangrass (Sorghastrum 13 nutans) (IDNR 2005). Historically, forests were dominated by oak (Quercus spp.), hickory 14 (Carya spp.), elm (Ulmus spp.), ash (Fraxinus spp.), beech (Fagus spp.), and maple (Acer spp.)
15 species (CEC 2008). Remaining forests are highly fragmented and are experiencing species 16 composition shifts to sugar maple (A. saccharum) and other mesophytic species (IDNR 2005).
17 This shift is in part due to fire suppression, which has favored species that do not rely on 18 periodic fires as part of their life cycle (IDNR 2005). Many wetland areas have been drained for 19 row crops, and agriculture now accounts for over 75 percent of land use within this ecoregion 20 (IDNR 2005).
21 Table 3-8 lists representative wildlife for this ecoregion, as well as species that the Illinois 22 Department of Natural Resources (IDNR) considers to be critical to the conservation and 23 restoration of the regions native habitats; species that are indicative of ecosystem health 24 (known as indicator species); and species that are native to the region, but are now extirpated 25 or imperiled.
26 The IDNR maintains the Illinois Wildlife Action Plan (IDNR 2005), which addresses native 27 habitat and species decline and contains a statewide conservation plan.
28              Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion Wildlife representative of the ecoregion American black bear                eastern bluebird                  North American porcupine (Ursus americanus)                (Sialia sialis)                  (Erethizon dorsatum)
American redstart                  eastern chipmunk                  raccoon (Setophaga ruticilla)              (Tamias striatus)                (Procyon lotor) bobcat                            eastern gray squirrel            tree sparrow (Lynx rufus)                      (Sciurus carolinensis)            (Passer montanus)
Canada warbler                    gray fox                          white-footed mouse (Cardellina canadensis)            (Urocyon cinereoargenteus)        (Peromyscus leucopus) coyote                            indigo bunting                    white-tailed deer (Canis latrans)                    (Passerina cyanea)                (Odocoileus virginianus) 3-52
 
Affected Environment Wildlife critical to the conservation and restoration of the ecoregions native habitats American badger                          Henslows sparrow                        northern harrier (Taxidea taxus)                          (Ammodramus henslowii)                  (Circus cyaneus) eastern massasauga(a)                    Illinois chorus frog                    ornate box turtle (Sistrurus catenatus)                    (Pseudacris streckeri illinoensis)      (Terrapene ornata ornata) four-toed salamander                    Indiana bat(b)                          red squirrel (Hemidactylium scutatum)                (Myotis sodalis)                        (Sciurus vulgaris) gray bat(a)                              Kirtlands snake                        short-eared owl (Myotis grisescens)                      (Clonophis kirtlandii)                  (Asio flammeus)
Wildlife indicative of ecosystem health (indicator species) black rat snake                          eastern meadowlark                      prairie vole (Elaphe obsoleta obsoleta)              (Sturnella magna)                        (Microtus ochrogaster) black-capped chickadee                  great blue heron                        red-headed woodpecker (Poecile atricapillus)                  (Ardea herodias)                        (Melanerpes erythrocephalus) eastern box turtle                      horned lark                              red-tailed hawk (Terrapene carolina carolina)            (Eremophila alpestris)                  (Buteo jamaicensis) eastern kingbird                        prairie king snake                      tufted titmouse (Tyrannus tyrannus)                      (Lampropeltis calligaster                (Baeolophus bicolor) calligaster)
Extirpated or imperiled wildlife American bison                          Blandings turtle                        Franklins ground-squirrel (Bison bison)                            (Emys blandingii)                        (Poliocitellus franklinii)
(a) The  eastern massasauga is a candidate for listing under the Endangered Species Act of 1973, as amended (ESA), and the gray bat is listed as endangered under the ESA. While these species occur within the Illinois/Indiana Prairies Level IV Ecoregion, the FWS (2015d) indicates that they do not occur within the area that would be affected by the proposed LSCS license renewal.
(b) The Indiana bat is Federally listed as endangered under the ESA and is discussed in detail in Section 3.8.
Sources: CEC 1997; IDNR 2005; WIken et al. 2011 1 3.6.2          LSCS Site Surveys, Studies, and Reports 2 A number of vegetation and wildlife surveys have been conducted on the LSCS site beginning 3 with baseline surveys prior to LSCS construction in the early 1970s. This section summarizes 4 these surveys in chronological order.
5 Baseline Terrestrial Surveys (1971-1972) 6 In July and December 1971, and April, July, and October 1972, baseline ecological studies were 7 conducted at the LSCS site. The 1971 studies were primarily qualitative, and the 1972 studies 8 gathered quantitative data on vegetation, mammals, birds, reptiles, and invertebrates present on 9 the LSCS site. The ER for operation of LSCS (ComEd 1977) describes these studies and the 10 associated results in detail.
11 Final Environmental Statement for Construction (1973) 12 In February 1973, the U.S. Atomic Energy Commission (AEC), the NRCs predecessor agency, 13 issued a Final Environmental Statement that evaluated the construction of LSCS (FES-C) 14 (AEC 1973). Although no specific studies were conducted to support the preparation of the 3-53
 
Affected Environment 1 FESC, the report briefly summarizes the terrestrial wildlife and habitats on the site, including 2 those that were altered or destroyed during the construction of the cooling pond.
3 Terrestrial Monitoring during LSCS Construction (1974-1978) 4 Following the commencement of LSCS construction, ComEd commissioned NALCO 5 Environmental Sciences to conduct a 5-year monitoring program to evaluate the effects of 6 temporary and permanent ecological disturbances related to construction from 1974 7 through 1978. The ER for operation of LSCS (ComEd 1977) describes the results of the first 8 2 years of this monitoring.
9 Final Environmental Statement for Operation (1978) 10 In November 1978, the NRC issued a Final Environmental Statement that evaluated the 11 operation of LSCS (FES-O) (NRC 1978). The report includes updates to the terrestrial habitat 12 and wildlife information presented in the FES-C based on the 5 years of terrestrial monitoring 13 conducted during LSCS construction.
14 Wildlife Habitat Council Vegetation and Wildlife Surveys (2007) 15 In September 2007, Wildlife Habitat Council (WHC) biologists performed a baseline habitat 16 survey for the Wildlife at Work program. The survey results are documented in the LSCS 17 Wildlife Management Plan (Exelon 2013b).
18 LSCS Wildlife Habitat Team Monitoring (Ongoing) 19 The LSCS Wildlife Habitat Team conducts periodic wildlife surveys of the site in the spring 20 (April), summer (July), and fall (September) to monitor changes in wildlife communities and to 21 document any new species found on the site. Results of periodic surveys are collected in 22 Exelons Wildlife Management Plan (Exelon 2013b).
23 3.6.3      LSCS Site 24 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 25 Illinois. The cooling pond, generating facilities and associated infrastructure, and LaSalle Fish 26 Hatchery occupy the majority (66 percent) of the site. The remaining areas are undeveloped 27 and include the following terrestrial communities: forest, shrub-scrub, grassland, old-field, and 28 wetlands.
29 A cooling pond occupies the western side of the site and accounts for about half of the site area.
30 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 31 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac) 32 (Exelon 2015p). This industrial area is surrounded by about 142 ha (350 ac) of undeveloped 33 natural areas, including grassland, old field, schub-scrub, and small forested fragments 34 (Exelon 2015p).
35 3.6.3.1      Vegetation 36 Because the majority of the LSCS site is developed or occupied by the cooling pond, only small 37 areas of terrestrial habitat occur on the site. An open grassy area lies between the cooling pond 38 and the sites industrial area. This area is bounded on the north by the discharge canal and on 39 the south by the property boundary. Another grassy area lies to the southwest of the industrial 40 area. These two areas have a few scattered trees (Exelon 2014a).
41 The makeup and blowdown pipeline corridor extends north from the cooling pond to the Illinois 42 River and supports upland habitats, including shrub-scrub, forest, grassland, and old-fields, and 43 scattered wetlands. Common tree species in the upland forest areas, which comprise the 3-54
 
Affected Environment 1 majority of the corridor, include white oak (Quercus alba), red oak (Q. rubra), shagbark hickory 2 (Carya ovata), sugar maple, hop hornbeam (Ostrya virginiana), hawthorn (Crataegus spp.),
3 black cherry (Prunus serotina), and American elm (Ulmus americana) (Exelon 2014a). The 4 corridor widens as it approaches the Illinois River where it contains several small freshwater 5 emergent and freshwater forested/scrub wetlands. These wetlands are discussed in 6 Section 3.6.5.2.
7 3.6.3.2      Wildlife 8 Mammals 9 During the baseline terrestrial surveys in 1971 and 1972, 29 species of mammals were recorded 10 on the LSCS site. The most commonly observed mammals included raccoon (Procyon lotor),
11 mink (Mustela vison), red fox (Vulpes fulva), gray fox (Urocyon cinereoargenteus), gray squirrel 12 (Sciurus carolinensis), fox squirrel (Sciurus niger), beaver (Castor canadensis), muskrat 13 (Ondatra zibethicus), eastern cottontail (Sylvilagus floridanus), and white-tailed deer 14 (ComEd 1977). During the 2007 WHC baseline inventory of the LSCS site, coyote (Canis 15 latrans), beaver, opossum (Didelphis virginiana), groundhog (Marmota monax), striped skunk 16 (Mephitis mephitis), white-tailed deer, and gray squirrel were observed on the site (Exelon 17 2013b).
18 Birds 19 During the baseline terrestrial surveys in 1971 and 1972, 129 species of birds were recorded on 20 or near the LSCS site. Of these, 41 are considered permanent residents, 45 are summer 21 residents, 13 are winter residents, and 21 are transients (ComEd 1977). Permanent residents 22 included mallard (Anas platyrhynchos), black duck (A. rubripes), red-tailed hawk (Buteo 23 jamaicensis), red-shouldered hawk (Buteo lineatus), bald eagle (Haliaeetus leucocephalus),
24 bobwhite (Colinus virginianus), ring-necked pheasant (Phasianus colchicus), killdeer 25 (Charadrius vociferus), rock dove (Columba livia), mourning dove (Zenaida macroura), great 26 horned owl (Bubo virginianus), short-eared owl (Asio flammeus), saw-whet owl (Aegolius 27 acadicus), northern flicker (Colaptes auratus), red-bellied woodpecker (Melanerpes carolinus),
28 red-headed woodpecker (M. erythrocephalus), horned lark (Eremophila alpestris), blue jay 29 (Cyanocitta cristata), American crow (Corvus brachyrhynchos), black-capped chickadee 30 (Poecile atricapillus), northern mockingbird (Mimus polyglottos), eastern bluebird (Sialia sialis),
31 cedar waxwing (Bombycilla cedrorum), loggerhead shrike (Lanius ludovicianus), starling 32 (Sturnus vulgaris), and house sparrow (Passer domesticus) (ComEd 1977). During the 2007 33 WHC baseline inventory of the LSCS site, 15 species of birds were observed, all of which had 34 been previously recorded as occurring on the site during baseline surveys (Exelon 2013b).
35 Reptiles and Amphibians 36 No reptiles or amphibians were collected on the LSCS site in the 1971 baseline surveys 37 (ComEd 1977). In 1972, two Eastern plains garter snakes (Thamnophis radix radix) were 38 observed in pastureland near an intermittent stream (ComEd 1977). The 2007 WHC baseline 39 inventory did not include reptiles or amphibians.
40 3.6.4    LSCS Wildlife Management Plan 41 The LSCS Wildlife Management Plan (Exelon 2013b) outlines the goals and projects of LSCSs 42 Wildlife at Work program. Some of the plans past and planned wildlife habitat enhancement 43 and conservation activities at the LSCS site include:
44
* planting native vegetation, including swamp white oak (Quercus bicolor) near the 45            cooling pond, 3-55
 
Affected Environment 1
* controlling invasive common reed (Phragmites australis) near the cooling pond, 2
* enhancing existing habitat for grassland nesting birds through seeding, mowing, and 3              controlled burns, 4
* maintaining nesting boxes for eastern bluebirds, and 5
* installing osprey (Pandion haliaetus) platforms near the cooling pond 6              (Exelon 2014a).
7 Exelon (2015n), as a corporation, has been a member of the WHC since 2005, and Exelon first 8 received WHC certification for its Wildlife at Work program at LSCS in November 2011.
9 3.6.5      Important Species and Habitats 10 3.6.5.1      Important Species 11 State-Listed Species 12 The Illinois Endangered Species Protection Act of 1972, as amended, makes illegal the transfer, 13 sale, and possession of species (including skins and products) listed by the State as 14 endangered or threatened. The Act establishes an Endangered Species Protection Board, 15 which maintains a list of endangered and threatened species and advises the IDNR on the 16 conservation of those species.
17 Within LaSalle County, the IDNRs (2014b) Natural Heritage Database indicates that 18 28 State-listed terrestrial species (19 plants, 3 birds, 2 reptiles, 2 mammals, 1 insect, and 19 1 amphibian) occur in the county (see Table 3-9). In September 2013, Exelon generated an 20 IDNR Ecological Compliance Assessment Tool (EcoCAT) report that used Illinois Natural 21 Heritage Database information to further refine the list of State-listed species that could occur 22 on the LaSalle site and that could potentially be affected by the proposed license renewal. The 23 EcoCAT report is included in Appendix C of the applicants ER (Exelon 2014a). The report 24 indicates that there are no terrestrial State-listed species on or near the LSCS site that may be 25 affected by the proposed license renewal. In a May 2014 letter to Exelon, the IDNR (2014c) 26 confirmed that the EcoCAT report was accurate, and in its letter, the IDNR mentioned no 27 records of State-listed terrestrial species on or near the site. Federally protected species are 28 discussed in Section 3.8.
29                          Table 3-9. State-Listed Species in LaSalle County Common Name            Species Name                        Status(a)
Amphibians four-toed salamander    Hemidactylium scutatum                ST Birds cerulean warbler        Dendroica cerulea                      ST loggerhead shrike      Lanius ludovicianus                  SE upland sandpiper        Bartramia longicauda                  SE Insects regal fritillary        Speyeria idalia                        ST 3-56
 
Affected Environment Common Name                Species Name                                Status(a)
Mammals gray bat(b)                Myotis grisescens                              SE Indiana bat(b)              Myotis sodalis                                SE Plants American brooklime          Veronica americana                            SE bunchberry                  Cornus canadensis                              SE cliff goldenrod            Solidago sciaphila                              ST decurrent false aster(b)    Boltonia decurrens                              ST fibrous-rooted sedge        Carex communis                                  ST forked aster                Aster furcatus                                  ST golden corydalis            Corydalis aurea                                SE hairy woodrush              Luzula acuminata                              SE hemlock panic grass        Dichanthelium portoricense                    SE long beech fern            Phegopteris connectilis                        SE pink corydalis              Corydalis sempervirens                        SE plantain-leaved sedge      Carex plantaginea                              SE queen-of-the-prairie        Filipendula rubra                              SE red pine                    Pinus resinosa                                SE red-berried elder          Sambucus racemosa ssp. pubens                  SE shadbush                    Amelanchier sanguinea                          SE snowberry                  Symphoricarpos albus var. albus                SE spike                      Elliptio dilatata                              ST weak bluegrass              Poa languida                                  SE Reptiles blanding's turtle          Emydoidea blandingii                          SE timber rattlesnake          Crotalus horridus                              ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) These species are also Federally listed under the Endangered Species Act of 1973, as amended (ESA) and are discussed in detail in Section 3.8.
Source: IDNR 2014b 1 Although not listed as occurring in LaSalle County by the IDNR, Exelon (2014a) reports that it 2 has observed the State-threatened peregrine falcon (Falco peregrinus) on the LSCS site. A pair 3 of peregrine falcons nested on the roof of the auxiliary building several years ago. Exelon 4 (2014a) personnel have not observed peregrine falcon nesting in recent years, but personnel 3-57
 
Affected Environment 1 occasionally observe peregrines in flight on the site. The FES-O (NRC 1978) notes the 2 observance of a single peregrine falcon in November 1972 in an offsite woodland.
3 Bald Eagles 4 The bald eagle is protected under the Bald and Golden Eagle Protection Act (16 USC 668 5 et seq.). This Federal act prohibits anyone from taking or disturbing bald eagles or golden 6 eagles (Aquila chrysaetos), including their nests or eggs, without a U.S. Fish and Wildlife 7 Service (FWS)-issued permit. The bald eagle was observed near the LSCS site in April 1972, 8 on the rivers north-facing bluffs (ComEd 1977; NRC 1978). However, Exelon (2014a) is not 9 aware of bald eagle observations at the site in recent years.
10 3.6.5.2      Important Habitats 11 Illinois Natural Areas Inventory Sites 12 In its Illinois Natural Areas Inventory (INAI), the IDNR (2014a) identifies 28 LaSalle County sites 13 as Category I (high quality natural community and natural community restorations), Category II 14 (specific suitable habitat for state-listed species or state-listed species relocations),
15 Category III (State-dedicated Nature Preserves, Land and Water Reserves, & Natural Heritage 16 Landmarks), or a combination of the three categories. The 2013 EcoCAT report (contained in 17 Appendix D of the applicants ER (Exelon 2014a)) indicates that one of these sites with 18 terrestrial habitat lies near the LSCS site: Marseilles Hill Prairie.
19 The Marseilles Hill Prairie (INAI Site No. 1520) lies 3 mi (4.8 km) north of the LSCS main site 20 boundary (Exelon 2015o). It is 39.71 ac (16.07 ha) in size and managed by the IDNR (2014a) 21 to conserve prairie habitat. The IDNR (2014a) designates this INAI site as Category I.
22 State Parks and Wildlife Areas 23 The IDNR manages three areas for State parks or wildlife areas within 10 km (6 mi) of LSCS:
24 LaSalle Lake State Fish & Wildlife Area, Marseilles State Fish & Wildlife Area, and Illini State 25 Park. The LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling 26 pond that is managed by the IDNR and open to the public for fishing and other recreational 27 purposes (Exelon 2014a). The Marseilles State Fish & Wildlife Area is open to seasonal 28 hunting of turkey (Meleagris gallopavo), pheasant, quail, dove, deer, rabbit, squirrel, and coyote 29 (IDNR 2015e). Illini State Park provides habitat for a number deciduous trees, including hickory, 30 ash (Fraxinus spp.), walnut (Juglans spp.), elm, cottonwood (Populus deltoids), oak, and maple, 31 as well as white-tailed deer, eastern gray squirrels, opossums, beavers, raccoon, groundhogs, 32 and a variety of waterfowl and songbirds (IDNR 2015b).
33 Wetlands 34 The National Wetlands Inventory Wetlands Mapper identifies eight small areas of freshwater 35 emergent wetland and freshwater forested/scrub wetland on the LSCS site near the Illinois 36 River that total about 10 ac (4 ha) (FWS 2015e). Common tree species in the freshwater 37 forested/scrub wetland include American elm, black cherry, white oak, red oak, black oak, 38 shagbark hickory, bitternut hickory (Carya cordiformis), hackberry (Celtis occidentalis), elm, 39 willow (Salix spp.), and sycamore (Platanus occidentalis) (Exelon 2014a). The freshwater 40 emergent wetlands contain cattail (Typha spp.), horsetail (Equisetum spp.), and other 41 herbaceous vegetation (Exelon 2014a).
42 Managed Prairie Habitat 43 In partnership with Pheasants Forever, Inc., Exelon (2014a) actively manages 4 ha (10 ac) of 44 native prairie to the west of the cooling pond.
3-58
 
Affected Environment 1 3.6.6      Invasive and Non-Native Species 2 The invasive common reed inhabits parts of the cooling pond, particularly along the ponds 3 western edge. In 2007, as part of its Wildlife at Work program, Exelon (2014a) began an effort 4 to eradicate the species through mechanical harvesting and application of aquatic-safe 5 herbicides.
6 3.7      Aquatic Resources 7 The aquatic communities of interest for the LSCS site occur in the Illinois River and in the sites 8 artificial cooling pond. The Illinois River lies 5 mi (8 km) north of the site. It supplies makeup 9 water to LSCSs cooling system and receives cooling system blowdown. The cooling pond is 10 the sites main source of cooling water and is the plants UHS. Section 3.1.3 describes the 11 cooling system in detail, and Section 3.5.1 describes the surface water characteristics of the 12 Illinois River and the cooling pond.
13 The sections below describe the two main aquatic ecosystems at the LSCS site, the Illinois 14 River and the LSCS cooling pond (see Sections 3.7.1 and 3.7.2, respectively). In addition, 15 Section 3.7.3 describes State-listed species and important habitats and Section 3.7.4 describes 16 non-native species.
17 3.7.1      Illinois River 18 The Illinois River begins southwest of Chicago, at the confluence of the Des Plaines and 19 Kankakee Rivers. It flows south until it reaches the Mississippi River north of St. Louis, 20 Missouri. The total length of the Illinois River is approximately 322 mi (518 km) (IDNR 2011a).
21 The Illinois Rivers watershed drains a total of 29,010 mi2 (75,136 km2) from Illinois, Wisconsin, 22 and Indiana (IDNR 2011a). Major tributaries include the Des Plaines, Fox, Kankakee, 23 Vermilion, Mackinaw, Sangamon, Spoon, and La Moine rivers.
24 Prior to the 1800s, the Illinois River Basin was comprised of prairie savannas and oak-hickory 25 forests. The river provided diverse aquatic habitats including backwater lakes, side channels, 26 and a narrow main channel (USGS 1999a). The rapid expansion of agricultural activities 27 throughout the 1800s and early 1900s converted wet and mesic (relatively well drained) 28 floodplain prairies to crop lands. This land use conversion resulted in increased erosion, 29 sediment loading, and nutrient and herbicide transport to the Illinois River. Beginning in the 30 1900s, several efforts occurred to divert water from Lake Michigan and construct navigation 31 dams or levees to increase the navigability of the Illinois River to the Mississippi River and 32 provide a navigable passage from Chicago (Lake Michigan) to the Gulf of Mexico (USGS 33 1999a). As the population in Chicago continued to grow, sewage disposal and toxic waste 34 disposal further contributed to the degradation of aquatic habitat in the Illinois River (Parker 35 2014). By the 1960s, the biodiversity of fish within the upper Illinois River was low and 36 freshwater mussels were nearly absent (Sietman et al. 2001). Pollution tolerant, non-native 37 common carp (Cyprinus carpio) and goldfish (Carassius auratus) dominated fish populations 38 (Parker 2014). Since the passage of the CWA in 1974, water quality within the Illinois River has 39 improved and more diverse fish assemblages inhabit the upper Illinois River (Parker 2014).
40 Similarly, freshwater mussels have recolonized portions of the upper Illinois River since the 41 1980s (Sietman et al. 2001).
42 Currently, a series of locks and dams along the Illinois River continue to limit habitat connectivity 43 and fish passage along the Illinois River. Four of the locks and dams (Thomas J. OBrien, 44 Lockport, Brandon Road, and Dresden Island) are upstream of LSCS and four (Marseilles, 45 Starved Rock, Peoria, and LaGrange) are downstream (USACE 1998). The closest locks and 3-59
 
Affected Environment 1 dams to LSCS include the Dresden Island Lock and Dam, 22 mi (26 km) upstream of the LSCS 2 intake, and the Marseilles Lock and Dam, 2.4 mi (3.5 km) downstream of the LSCS discharge 3 (USACE 1998; Exelon 2015c).
4 In 2005, IEPA most recently classified the water quality within the Illinois River as fair, which 5 means that the water quality has been impaired, and the water body meets the needs of a 6 designated use most of the time (IDNR 2011a). Current factors that continue to contribute to 7 the degradation of the Illinois River include the increase in invasive fish, accumulated 8 sediments, continued sedimentation, and agricultural chemical runoff (USGS 1999a; 9 Parker et al. 2005).
10 3.7.1.1      Aquatic Communities in the Illinois River 11 Plankton 12 Plankton are small organisms that float or drift in rivers and other water bodies. Plankton is a 13 primary food source for many whales, fish, and other animals, and consists of bacteria, 14 protozoans, certain algae, tiny crustaceans such as copepods, and many other organisms.
15 ComEd, the previous owner of LSCS, conducted surveys for plankton within the Illinois River 16 both upstream and downstream of the LSCS discharge and river intake structures. ComEd 17 initially sampled plankton prior to operations, from August 1972 through January 1973, and 18 again during construction, from February 1974 through November 1976. These studies are 19 summarized in the Final Environmental Statement for Operations of LSCS (NRC 1978).
20 Phytoplankton. Phytoplankton are microscopic floating photosynthetic organisms that form 21 one base of aquatic food webs by producing biomass from inorganic compounds and sunlight.
22 As primary producers, phytoplankton play key ecosystem roles in the distribution, transfer, and 23 recycling of nutrients and minerals.
24 Diatoms were the most abundant phytoplankton in the Illinois River near LSCS in the 1970s, 25 and reached peak densities in August (NRC 1978). The most common diatom genera included 26 Cyclotella, Melosira, and Stephanodiscus. The NRC staff noted that many of the diatoms 27 collected in preoperational studies were pollution tolerant (NRC 1978). Other phytoplankton 28 followed similar trends with primary production peaking in August and dipping in winter months.
29 The NRC staff is not aware of any additional phytoplankton surveys that have been conducted 30 in the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.
31 Periphyton. Periphyton includes a mixture of algae, cyanobacteria (in the past often called 32 blue-green algae), heterotrophic microbes, other small organisms, and detritus that attach to 33 submerged surfaces. Like phytoplankton, periphyton are primary producers and provide a 34 source of nutrients to many bottom-feeding organisms.
35 During ComEds initial study prior to construction, diatom densities upstream of the LSCS 36 discharge and intake areas accounted for 75 percent of the total periphyton density in 37 August 1972 and 100 percent in January 1973. The next dominant taxa was green algae, which 38 accounted for 7 percent of the total periphyton density in 1972 and none of the total periphyton 39 density in 1973. Downstream of the LSCS discharge and intake, diatom densities accounted for 40 94 percent of the total periphyton density in August 1972 and 92 percent in January 1973, while 41 the green algae accounted for 1 percent in 1972 and none in 1973 (NRC 1978). Diatoms were 42 the dominant periphyton group during the warmer months (May, August, and November),
43 whereas green algae was dominant during February from 1974 to 1976 (NRC 1978). Dominant 44 diatom genera included Cyclotella, Navicula, and Nitzschia; dominant green algae genera 45 included Stigeoclonium, Cladophora, Rhizoclonium, and Ulothrix (NRC 1978).
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Affected Environment 1 The NRC staff is not aware of any additional periphyton surveys that have been conducted in 2 the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2.
3 Zooplankton. Zooplankton are small animals that float, drift, or weakly swim in the water column 4 and include ichthyoplankton (fish eggs and larvae) with no or limited swimming ability and larvae 5 of benthic invertebrates. Zooplankton are important trophic links between primary producers 6 (e.g., phytoplankton and periphyton) and carnivores (e.g., fish).
7 During preoperational studies, copepods and rotifers dominated zooplankton samples both prior 8 to and during construction (NRC 1978). Dominant copepod genera included Cyclops and 9 Eucyclops, and dominant rotifer genera included Asplanchna, Brachionus, Filinia, Notholca, 10 Polyarthra, and Synchaeta (NRC 1978). Peak densities for both copepods and rotifers 11 generally occurred in August, and minimum densities generally occurred in February.
12 In 2014, EA Engineering, Science, and Technology, Inc. (EA) (2015) collected icthyoplankton 13 samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected 14 samples using 0.5-m (1.6-ft) conical plankton nets with 505-&#xb5;m mesh suspended from the 15 forebay bridge in front of the river intake (see Figure 3-15). EA (2015) collected samples during 16 the 2014 spawning season, from late April through August, when icthyoplankton densities would 17 likely be highest.
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Affected Environment 1      Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure 2                  Key: LSCS: LaSalle County Station; RSH: River Screen House 3                                          Source: EA (2015) 4 EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 5 27 distinct taxa. The most common taxa included carps, minnows, and suckers, which 6 combined comprised 79 percent of the number of organisms within ichthyoplankton sample.
7 EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was 8 not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles.
9 The most common taxa by life stage included Ictiobinae (buffalo fish) yolk-sac larvae 10 (24 percent), cyprinidae (carps and minnows) yolk-sac larvae (23 percent), and common carp 11 yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent 12 of the icthyoplankton samples (EA 2015).
13 Benthic Macroinvertebrates 14 Benthic macroinvertebrates include aquatic annelids (e.g., aquatic worms or oligochaetes, 15 leeches), mollusks, crustaceans, and insect larvae that inhabit aquatic sediments and 16 submerged surfaces. They accelerate detrital decomposition and nutrient cycling, and serve as 3-62
 
Affected Environment 1 a food source for fish and other aquatic biota. ComEd, Exelon, and their contractors sampled 2 benthic invertebrates during three time periods: preoperational studies from February through 3 November, 1972 through 1976 (as summarized in NRC 1978); a 1999 study in response to low 4 flow and high air temperatures (EA 2000); and a 2013 study in preparation for Exelons license 5 renewal application (EA 2014).
6 During the preoperational and the 2013 study, ComEd and Exelon sampled benthic 7 macroinvertebrates at one location upstream of the river intake and blowdown discharge 8 (location 1), at one location immediately downstream of the blowdown discharge (location 2),
9 and at two locations further downstream of the blowdown discharge (locations 3 and 4) (Figure 10 3-16). ComEd and Exelon sampled each location with a Hester-Dendy artificial substrate 11 sampler and a Ponar grab sampler (NRC 1978; EA 2014).
12 In 1999, Exelon also collected benthos using a Ponar grab at one site upstream and one site 13 downstream of the blowdown discharge, similar to the sampling sites for the preoperational and 14 2013 study. In addition, EA collected benthos using a Ponar grab at a second downstream site 15 that was further downstream than South Kickapoo Creek (EA 2000).
16                  Figure 3-16. Sampling Locations in LSCS Aquatic Surveys 17                                          Source: EA 2014 18 Collections during preoperational studies resulted in the identification of 143 taxa (NRC 1978).
19 Chironomidae and Oligochaeta were the most dominant groups. The most common 20 oligochaete genera were Limnodrilus and Nais. The most abundant chironomid genera 21 included Cryptochironomous, Dicrotendipes, Procladius, Cricotopus, and Orthocladius.
22 EA (2000) collected a total of 34 taxa from Ponar grab samples. Chironomidae and Oligochaeta 23 were the most taxa-rich groups, with 12 taxa each. EA (2000) determined that the dominant 24 taxa at all sampling sites are considered tolerant to poor water quality. Both total richness and 25 the number of Ephemeroptera, Plecoptera, and Trichoptera species, which are considered 26 intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) 27 compared to upstream (location 1) of the intake and discharge structures.
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Affected Environment 1 EA (2014) collected a total of 61 taxa from the Hester-Dendy artificial substrate collections.
2 Chironomidae was the most taxa rich group with 21 taxa followed by Ephemeroptera and Bivalvia, 3 with 8 taxa each. The dominant taxa from the Hester-Dendy collections included the following 4 insect larvae: Dicrotendipes modestus (a non-biting midge), Maccaffertium integrum (a mayfly),
5 Cyrnellus fraternus (a caddisfly), and Dicrotendipes neomodestus. Among the 10 most dominant 6 taxa for the Hester-Dendy artificial substrate samples, only one taxon is considered tolerant of 7 environmental degradation, Glyptotendipes (IEPA 1987; EA 2014). The remaining taxa are 8 considered facultative to slightly intolerant to poor water quality (IEPA 1987; EA 2014).
9 For the Ponar grab samples, Chironomidae was the most taxa rich group with 15 taxa, followed 10 by 8 Bivalvia and 4 Ephemeroptera taxa. EA (2014) observed the highest taxa richness at 11 locations 1 and 3 (20 to 29 taxa) as compared to locations 2 and 4 (16 to 27 taxa). Species 12 richness among pollution sensitive Ephemeroptera, Plecoptera, and Trichoptera was similar 13 among all locations, ranging from three to five taxa (EA 2014). At all sampling sites, EA (2014) 14 observed dominant taxa that were relatively tolerant to poor water quality as well as dominant 15 taxa that were relatively intolerant or facultative to poor water quality.
16 Fish 17 ComEd, Exelon, and their contractors sampled fish near LSCS during three time periods:
18 preoperational studies from May through November, 1972 through 1976 (as summarized in 19 NRC 1978); a post-operational study in response to low flow and high air temperatures in July 20 through October, 1999 (EA 2000); and a post-operational study in August 2013 in preparation 21 for Exelons license renewal application (EA 2014).
22 During both the preoperational and 2013 study, Exelon sampled fish at one location upstream of 23 the river intake and blowdown discharge (location 1) and at two locations downstream of the 24 blowdown discharge (locations 2 and 5), one of which was South Kickapoo Creek 25 (Figure 3-16). Exelon sampled fish at each sampling site by electrofishing in a downstream 26 direction for 500 m (1,640 ft). In addition, Exelon seined for fish along the shoreline at all three 27 locations using a 25-ft (8-m) long by 6-ft (2-m) deep seine with 0.19- in. (0.48-cm) mesh.
28 Exelon hauled the seine along 15 m (49 ft) of shoreline in a downstream direction.
29 In 1999, EA also electrofished at one site upstream and one site downstream of the blowdown 30 discharge, similar to the sampling sites for the preoperational and 2013 study. In addition, EA 31 electrofished at second downstream site that was further downstream than South Kickapoo 32 Creek (EA 2000).
33 All three studies looked for external parasites or other abnormalities. EA (2000 and 2014) 34 specifically examined all fish for external DELT (deformities, erosions, lesions, or tumors) 35 anomalies.
36 During the preoperational monitoring period, NRC (1978) determined that the most dominant 37 species included emerald shiner (Notropis atherinoides), gizzard shad (Dorosoma cepedianum),
38 common carp, green sunfish (Lepomis cyanellus), bluntnose minnow (Pimephales notatus), and 39 white sucker (Catostomus commersonii) (see Table 3-10). Prior to operations, downstream 40 collection stations generally had lower species abundance and higher species diversity than 41 upstream stations (NRC 1978). The NRC (1978) concluded that the low species abundance 42 and diversity, low condition factors, and the degree of external parasitism and physical damage 43 of the fishes in this area of the Illinois River were indicative of a poor quality aquatic 44 environment. Barge traffic, habitat alteration, and heavy pollution loads contributed significantly 45 to the poor water quality in the Illinois River near LSCS, which primarily supported populations 46 of pollution-tolerant fish in the 1970s (NRC 1978).
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Affected Environment 1 During the 1999 survey, EA (2000) collected 27 species and 1 hybrid for a total of 960 fish. The 2 most commonly collected fish species included gizzard shad (24 percent), smallmouth buffalo 3 (Ictiobus bubalus) (12 percent), spotfin shiner (Cyprinella spiloptera) (10 percent), green sunfish 4 (9 percent) and bluegill (Lepomis macrochirus) (8 percent) (Table 3-10). EA (2000) observed a 5 total of 63 fish (6.6 percent of the catch) with DELT anomalies. Channel catfish (Ictalurus 6 punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest 7 DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin 8 erosion (52 percent) and deformities (38 percent).
9 During the 2013 study, EA (2014) collected 12 fish species for a total of 1,295 fish. The most 10 commonly collected species during electrofishing included gizzard shad (48 percent), spotfin 11 shiner (16.5 percent), smallmouth buffalo (6 percent), golden redhorse (Moxostoma erythrurum) 12 (5 percent), smallmouth bass (Micropterus dolomieu) (4 percent), and freshwater drum 13 (4 percent; EA 2014) (Table 3-10). Gizzard shad dominated samples both upstream and 14 downstream of the intake and discharge (EA 2014). The most commonly collected species 15 during seining surveys included emerald shiner (83 percent), spotfin shiner (9.5 percent),
16 bluntnose minnow (2 percent), and sand shiner (Notropis stramineus) (2 percent) (EA 2014) 17 (Table 3-10). Emerald shiner dominated samples both upstream and downstream of the intake 18 and discharge (EA 2014). EA (2014) observed DELT anomalies on 2 of the 1,295 fish collected 19 (0.2 percent), both of which were eroded fins on freshwater drum. EA (2014) did not observe 20 any external parasites or other abnormalities.
21        Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River Commonly Collected Species(d)
Species                    Common Name                1974-1976(a)    1999(b)        2013(c)
Cyprinidae Cyprinella spiloptera      spotfin (spottail) shiner      X          X                X Cyprinus carpio            common carp                    X Notropis atherinoides      emerald shiner                  X          X                X Notropis stramineus        sand shiner                                                  X Pimephales notatus          bluntnose minnow                X                            X Pimephales vigilax          bullhead minnow                X                            X Centrarchidae Lepomis cyanellus          green sunfish                  X          X Lepomis macrochirus        bluegill                                    X Catostomidae Catostomus commersoni      white sucker                    X Ictiobus bubalus            smallmouth buffalo                          X                X Micropterus dolomieu        smallmouth bass                                              X Moxostoma erythrurum        golden redhorse                                              X Atherinopsidae Labidesthes sicculus        brook silverside                                              X Clupeidae Dorosoma cepedianum        gizzard shad                    X          X                X 3-65
 
Affected Environment Commonly Collected Species(d)
Species                          Common Name                      1974-1976(a)        1999(b)            2013(c)
Sciaenidae Aplodinotus grunniens            freshwater drum                                                            X (a) NRC 1978 (b) EA 2000 (c) EA 2014 (d) X= one of the sixth most commonly collected species, based on the number of individuals collected during electrofishing or seining sampling within a single time period. Note that a species may still have been observed during the collection period even if it was not one of the sixth most commonly collected species.
Sources: NRC 1978; EA 2000, 2014 1 Common carp and white sucker were commonly collected during preoperational studies but 2 were not commonly collected during the 1999 or 2013 study. Ohio EPA (1987) classifies both of 3 these species as pollution tolerant. Brook silverside (Labidesthes sicculus), freshwater drum, 4 sand shiner, smallmouth bass, smallmouth buffalo, golden redhorse, and bluegill were among 5 the commonly collected species in the 1999 or 2013 studies but were not commonly collected in 6 the preoperational studies. Five of these seven species (brook silverside, sand shiner, 7 smallmouth bass, golden redhorse, and bluegill) are native species that are sensitive to declines 8 in water quality or habitat degradation (Lerczak 1996; Smith 2002).
9 These results are consistent with other fish surveys (Lerczak 1996; McClelland et al. 2012) 10 within the upper Illinois River that since the mid-1950s through 1990s and the 2000s, show a 11 decline in fish species that are tolerant of poor water quality and an increase in fish species that 12 are sensitive to habitat degradation. For example, Lerczak (1996) examined fish population 13 data from the Illinois Natural History Survey (INHS), which began monitoring fish populations in 14 the Illinois River in 1957. Since 1957, INHS conducted annual electrofishing surveys at set 15 locations throughout the entire Illinois River, including sampling locations approximately 1 RM 16 downstream of the LSCS river intake, within the vicinity of the LSCS river intake, and 11 RM 17 upstream of the LSCS river intake. Within the upper 50 mi (80 km) of the Illinois River, which 18 includes LSCS, Lerczak (1996) concluded that common carp, which is pollution tolerant, has 19 become less common while bluegill, which is intolerant to degraded habitats, has become more 20 common. For example, in the 1960s, INHS captured an average of 35 common carp per hour 21 as compared to 6 common carp per hour in the 1990s. Bluegill increased from averages of less 22 than 1 per hour in the 1960s to 12 per hour in the 1990s. Lerczak (1996) also noted that in the 23 1990s, fish communities were more evenly distributed among a greater number of species than 24 in the 1960s. For example, in 1962 and 1963, four species comprised 95 percent of all catches:
25 gizzard shad, emerald shiner, common carp, and goldfisha species with pollution tolerance 26 similar to common carp. In 1995, 10 species comprised 95 percent of all catches including 27 several species that are sensitive to habitat degradation, such as the bluegill, largemouth bass 28 (Micropterus salmoides), and several species of small minnows.
29 McClellan et al. (2012) also examined fish populations during three time periods from 1957 30 through 2009 based on INHS data. Table 3-11 describes the species that contributed to 31 approximately 90 percent of all electrofishing catches in the Illinois River (McClelland 32 et al. 2012). The NRC staff further classified fish as either pollution tolerant or intolerant. In 33 addition, the NRC staff determined whether McClelland reported increases or decreases in the 34 relative abundance of each species over time. The NRC staff notes that these general trends 35 were not assessed using regression analyses or other statistical analyses. The most common 3-66
 
Affected Environment 1  species during the 1957 through 1969 surveys (common carp, gizzard shad, emerald shiner, 2  and goldfish) are considered pollution tolerant species and the relative abundance of these 3  species has generally declined over time. All pollution intolerant species listed in 4  Table 3-11 have generally increased overtime. These data suggest that water quality within the 5  Illinois River has improved over time, allowing species that are pollution sensitive to increase in 6  relative abundance.
7    Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural History 8                                Electrofishing Surveys from 1957 through 2009 Species(a)                      Common Name                  1957-1969        1970-1989        1990-2009        Trend(c)
Pollution Tolerant Species(b)                                                      Percent of Catch Cyprinus carpio                  common carp                      24.9              16.4              7.6 Dorosoma cepedianum gizzard shad                                  20.4              23.0            16.2 Notropis atherinoides            emerald shiner                  19.3              10.7            10.6 Carassius auratus                goldfish                          6.6              2.2              -
Cyprinus carpio x                common carp x goldfish            3.0              -                -
Carassius auratus Lepomis cyanellus                green sunfish                      2.4              6.3              5.3 Ictiobus cyprinellus            bigmouth buffalo                  1.8              1.8              1.3 Ameiurus melas                  black bullhead                    1.4              -                -
Pimephales vigilax              bullhead minnow                    -                -                2.9 Pimephales notatus              bluntnose minnow                    -                -                2.3 Lepomis humilis                  orangespotted sunfish              -                -                1.2 Aplodinotus grunniens            freshwater drum                    -              3.8              4.8 Pollution Intolerant Species(b)                                                    Percent of Catch Lepomis macrochirus              bluegill                          2.8              6.2            13.1 Micropterus salmoides            largemouth bass                    2.2              5.1              6.4 Pomoxis nigromaculatus          black crappie                      1.8              4.2              2.9 Ictalurus punctatus              channel catfish                    -                3.5              5.6 Morone chrysops                  white bass                          -                2.9              2.8 Micropterus dolomieu            smallmouth bass                    -                -                1.4 Notes: (-) = Fish species not part of 90 percent of the catch during specified time period (a) Species ordered by decreasing relative abundance based on McClelland et al 2012; species contributed to approximately 90 percent of all electrofishing catches in the Illinois River and could be classified as either pollution tolerant or intolerant.
(b) Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015.
(c) Inclines or declines in the relative abundance of each species are general trends; the NRC staff did not evaluate these trends using regression analyses or other statistical analyses.
Sources: Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015; McClelland et al. 2012 9  3.7.2        LSCS Cooling Pond 10  As described in Section 3.5, the 2,058-ac (833-ha) cooling pond was created in 1978 by 11  pumping water from the Illinois River into the excavated pond. Exelon leases a large portion of 12  the LSCS cooling pond to the IDNR, which maintains the LSCS cooling pond as an outdoor 3-67
 
Affected Environment 1 recreation area for public use and fishing. IDNR has actively managed the LSCS cooling pond 2 since 1984 (Exelon 2014a). For example, IDNR surveys the cooling pond each year and 3 determines which fish to stock based on fishermen preferences, fish abundance, different 4 species tolerance to warm waters, predator and prey dynamics, and other factors (Exelon 2002, 5 2014a, 2015a). The cooling pond can be characterized as a highly managed ecosystem in 6 which IDNR fish stocking and other human activities primarily influence the species composition 7 and population dynamics.
8 3.7.2.1        Aquatic Community in the Cooling Pond 9 IDNR stocks the LSCS cooling pond each year. In 1981, IDNRs fish hatchery located adjacent 10 to the cooling pond started operations, at which point IDNR started stocking the cooling pond 11 with species from the hatchery (EA 2002). Initially, IDNR stocked the LSCS cooling pond with 12 largemouth bass and bluegill (EA 2002).
13 Currently, commonly stocked species include largemouth bass, smallmouth bass, black crappie 14 (Pomoxis nigromaculatus), white crappie (Pomoxis annularis), channel catfish, blue catfish 15 (Ictalurus furcatus), striped bass hybrid (Morone saxatilis x M. chrysops), walleye (Sander 16 vitreus), and bluegill (See Table 3-12; Exelon 2002 and 2015a). Because of the high water 17 temperatures experienced in the summer months, introductions of warm-water species, such as 18 largemouth bass and blue catfish, have been more successful than introductions of cool-water 19 species, such as walleye and tiger muskellunge.
20 In addition to the stocked species, gizzard shad and threadfin shad (Dorosoma petenense) 21 together called shadalso occur in the cooling pond. Shad are not recreationally fished, and 22 IDNR does not currently stock these fish. IDNR stocks some recreationally fished species that 23 consume shad (e.g., catfish and striped bass) in part to limit the size of shad populations 24 (Exelon 2002).
25                  Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 Common                                                              Annual Species(a)          Name            2008  2009    2010      2011  2012  2013    2014  Average Percent Lepomis            bluegill      55,466 11,740 84,661 364,731 73,681    25,031 100,130 102,206  40%
macrochirus Micropterus        largemouth 66,395 51,207 50,434 30,470 84,166        48,753  2,660  47,726  19%
salmoides          bass Morone saxatilis striped          80,889 68,404 41,284 52,642        0  20,580 26,047  48,308  19%
hybrid              bass hybrid Ictalurus          blue catfish 18,560 34,452 19,800 23,368          0    0    18,200  22,876  9%
furcatus Micropterus        smallmouth 25,365 21,155 21,118 22,733 20,683        22,354 20,582  21,999  9%
dolomieu            bass Lepomis            redear        34,151    0    4,830      4,830  0    0          0 14,604  6%
microlophus        sunfish (a) Species are ordered by relative abundance (highest to lowest).
Sources: Exelon 2014a; IDNR and Exelon 2014 and 2015 3-68
 
Affected Environment 1 3.7.2.2      Cooling Pond Fish Kill Events 2 LSCS has had four reportable fish kills in the cooling pond since 2001, including fish kills in 3 July 2001, June 2005, June 2009, and August 2010 (Exelon 2014a, 2015a). The temperature in 4 the cooling pond during these events ranged from 93 &deg;F (33.9 &deg;C) to 101&deg;F (38.3 &deg;C) 5 (Exelon 2001, 2009, 2010). In addition, several smaller non-reportable fish kills have occurred 6 when the cooling pond was 95 &deg;F (35 &deg;C) or above (Exelon 2015c). Exelon attributes these fish 7 kills to high cooling pond temperatures as a result of high summer temperatures combined with 8 low winds and high humidity, as described below (Exelon 2001, 2009, 2010).
9 The largest fish kill occurred in July 2001 when IDNR reported approximately 94,500 dead fish 10 due to high temperatures that peaked at 98.2 &deg;F (36.9 &deg;C) (Exelon 2001). IDNR found the 11 maximum temperature in the cooling pond discharge canal to be 120 &deg;F (48.9 &deg;C) and dissolved 12 oxygen levels to range from 6.2 to 18.8 parts per million. The majority of dead fish (96 percent) 13 were gizzard shad (90,800) (Exelon 2001). IDNR identified other dead fish to include 14 1,279 carp, 1,143 smallmouth buffalo, 610 freshwater drum, 345 channel catfish, 238 striped 15 bass hybrid, 93 smallmouth bass, 24 walleye, 13 bluegill, 12 white bass (Morone chrysops),
16 6 yellow bullhead catfish (Ameiurus natalis), and 4 yellow bass (M. mississippiensis) 17 (Exelon 2001).
18 In a June 2005 fish kill, IDNR counted 1,515 dead fish, including 1,439 striped bass hybrids 19 (95 percent), 36 smallmouth bass (2 percent), 20 walleye (1 percent),11 channel catfish (less 20 than 1 percent), 4 blue catfish (less than 1 percent), 3 yellow bass (less than 1 percent), and 21 2 sauger (less than 1 percent) (Exelon 2015c). The LSCS cooling pond peaked at 95 &deg;F (35 &deg;C) 22 during the fish kill (Exelon 2015c).
23 In the June 2009 fish kill, 3,000 to 4,000 gizzard shad comprised 99 percent of the dead fish 24 shad (Exelon 2009). Exelon (2009) also observed 26 smallmouth bass, 4 striped bass, and 25 4 walleye. Immediately prior to and during the fish kill, the LSCS cooling pond increased 10 &deg;F 26 from 83 &deg;F (28 &deg;C) on June 20 to 93 &deg;F (34 &deg;C) on June 23.
27 In the August 2010 fish kill, IDNR concluded that over 90 percent of the dead fish were small 28 threadfin and gizzard shad less than 3 in. (8 cm) long (Exelon 2010). IDNR also observed dead 29 carp, striped bass hybrids, walleye, and smallmouth bass (Exelon 2010). The LSCS cooling 30 pond peaked at 101.3 &deg;F (38.5 &deg;C) the day before the fish kill.
31 3.7.3      Important Species and Habitats 32 3.7.3.1      State-Listed Species 33 IDNR lists 35 fish and 26 mussel species as State-endangered or threatened (IDNR 2015a). Of 34 these, IDNR (2014b) indicates that 7 species (5 fish, 2 mussels) occur in LaSalle County (see 35 Table 3-13).
3-69
 
Affected Environment 1    Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle County Recorded Occurrences Near LSCS LSCS River Intake(d)
Starved Rock or Preoperational Studies (b)      Marseilles Pool(c)
Species                                  Common Name                      State Status(a)
Fish Fundulus diaphanous                      banded killifish                        ST                                  x                  x Moxostoma carinatum                      river redhorse                          ST Moxostoma valenciennesi                  greater redhorse                        SE Notropis heterolepis                    blacknose shiner                        SE Notropis texanus                        weed shiner                            SE Mussels Alasmidonta viridis                      slippershell                            ST Elliptio dilatata                        spike                                  ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) NRC  1978 (c) McClelland and Sass 2007; Fritts 2013 (d) EA 2014, 2015; Exelon 2015c, 2015p Sources: NRC 1978; IDNR 2014b; McClelland and Sass 2007; Fritts 2013; EA 2014, 2015; Exelon 2014a, 2015a 2  Banded killifish. Banded killifish occur in clear glacial lakes, streams, or tributaries, often near 3  vegetation (Nyboer et al. 2006). This fish forms small schools near the surface of weedy lakes 4  (Nyboer et al. 2006). In recent years, this species has been documented in the Illinois River 5  (McClelland and Sass 2007; McClelland et al. 2012). In 2006, the INHS collected two banded 6  killifish at RM 241.5 in the Starved Rock Pool sampling area, approximately 8 RM (13 Rkm) 7  downstream of the LSCS river intake (McClelland and Sass 2007). However, from 1993 8  through 2012, the INHS did not observe banded killifish in the Marseilles Pool sampling area, 9  which included sampling locations approximately 1 RM (1.6 Rkm) downstream of the LSCS river 10  intake, within the vicinity of the LSCS river intake, and 11 RM (18 Rkm) upstream of the LSCS 11  river intake (Fritts 2013).
12  In 2014, EA (2015) collected a juvenile banded killifish during an impingement and entrainment 13  study at the LSCS river intake. In response to this collection, Exelon noted that EA Engineering 14  intends to request a scientific collectors permit report from IDNR. This species was not 15  collected during preoperational surveys (NRC 1978) or during operational studies in 1999 and 16  2013 (EA 2000, 2014).
17  River Redhorse. The river redhorse inhabits large river systems, including impoundments and 18  pools, in areas of moderate to swift current and clean gravel substrate (NatureServe 2014a).
19  Barbour et al. (1999) classify this species as an insectivore that is intolerant of pollution and 20  other environmental stressors. INHS electrofishing surveys that began in 1957 have 21  documented this species in the Illinois River (McClelland and Sass 2007). However, from 1993 3-70
 
Affected Environment 1 through 2012, INHS did not observe river redhorse in the Marseilles Pool sampling area, which 2 included sampling locations approximately 1 RM (1.6 RKm) downstream of the LSCS river 3 intake, within the vicinity of the LSCS river intake, and 11 RM (18 RKm) upstream of the LSCS 4 river intake (Fritts 2013). The river redhorse was not collected during preoperational surveys 5 (NRC 1978) or operational surveys in 1999 and 2013 (EA 2000, 2014). From 2013 through 6 2015, EA (2015) conducted an impingement and entrainment study near the LSCS river intake.
7 Although EA (2015) collected several Moxostoma fish that were not identified to species, EA 8 (2015) concluded that these species were most likely the more common Moxostoma spp., such 9 as shorthead, golden, silver, and black redhorse, given that these common species were 10 conclusively identified during the study.
11 Greater Redhorse. The greater redhorse inhabits lakes and large rivers with sandy to rocky 12 pools (Nyboer et al. 2006). This fish was considered extirpated in Illinois until it was observed in 13 the upper Illinois River basin in 1985 (Nyboer et al. 2006). IDNR (2014) recorded three 14 observations of this species in LaSalle County, most recently in July 2004. This species is rare 15 in the Illinois River, and INHS did not observe this species from 1957 through 2006 at any 16 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 17 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 18 (EA 2000, 2014), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 19 1993 through 2012 (Fritts 2013). From 2013 through 2015, EA (2015) conducted an 20 impingement and entrainment study near the LSCS river intake. Although EA (2015) collected 21 several Moxostoma fish that were not identified to species, EA (2015) concluded that these 22 species were most likely the more common Moxostoma spp., such as shorthead, golden, silver, 23 and black redhorse given that these common species were conclusively identified during the 24 study.
25 Blacknose shiner. The blacknose shiner inhabits clear vegetated lakes, and pools and runs of 26 clear streams (Nyboer et al. 2006). Increased turbidity and decreases in aquatic vegetation 27 have contributed to the decline of this species (Nyboer et al. 2006). IDNR (2014) recorded two 28 observations of this species in LaSalle County, most recently in October 2013. This species is 29 rare in the Illinois River and INHS did not observe this species from 1957 through 2006 at any 30 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 31 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 32 (EA 2000, 2014), an impingement and entrainment study at the LSCS river intake from 2013 33 through 2015 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling 34 area from 1993 through 2012 (Fritts 2013).
35 Weed shiner. In Illinois, the weed shiner inhabits clear sand-bottom creeks with some 36 submerged vegetation (Nyboer et al. 2006). IDNR (2014) recorded one observation of this 37 species in LaSalle County, most recently in October 2013. This species is rare in the Illinois 38 River and INHS did not observe this species from 1957 through 2006 at any sampling station in 39 the Illinois River (McClelland and Sass 2007). This species was not collected during 40 preoperational surveys (NRC 1978), operational studies in 1999 and 2013 (EA 2000, 2014), an 41 impingement and entrainment study at the LSCS river intake from 2013 through 2015 42 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 1993 43 through 2012 (Fritts 2013).
44 Slippershell. The slippershell is a freshwater mussel that inhabits small to medium sized 45 streams where it is usually found buried in sandy substrates in shallow water 46 (Nyboer et al. 2006). IDNR (2014) recorded five observations of this species in LaSalle County, 47 most recently in October 2013. In 1994, 1995, and 1999, Sietman et al. (2001) conducted 48 freshwater mussel surveys in the Illinois River from RM 232.0 to 271.2 (RKm 373 to 436),
49 including the Starved Rock and Marseilles Pools sampling areas. Sietman et al. (2001) did not 3-71
 
Affected Environment 1 collect this species during the surveys. Similarly, this species was not observed in 2013 when 2 IDNR collected 14,850 live mussels, representing 23 species, near the Marseilles Dam after a 3 boating accident (Kanter 2013). This species was not collected during LSCS preoperational 4 surveys (NRC 1978), operational studies in 2013 (EA 2014), or during impingement and 5 entrainment studies at the LSCS river intake from 2013 through 2015 (EA 2015).
6 Spike. The spike is a freshwater mussel that inhabits shoals of medium streams to large 7 rivers, reservoirs, and lakes with sand and gravel substrates (Minnesota DNR 2014). It is 8 distributed throughout the eastern United States, the Mississippi River system, and portions of 9 the Great Lakes (NatureServe 2014b). IDNR (2014) recorded one observation of this species in 10 LaSalle County in August 2010. This species was not collected during LSCS preoperational 11 surveys (NRC 1978); the freshwater mussel survey from RM 232.0 to 271.2 in 1994, 1995, and 12 1999 (Sietman et al. 2001); IDNRs collection of mussels near the Marseilles Dam in 2013 13 (Kanter 2013); operational studies in 2013 (EA 2014); or during impingement and entrainment 14 studies at the LSCS river intake from 2013 through 2015 (EA 2015).
15 3.7.3.2      Important Habitats 16 LaSalle Lake State Fish and Wildlife Area is part of the 2,058 ac (833 ha) cooling pond. As 17 described above in Section 3.7.2, IDNR manages this area for public boating and fishing.
18 The Marseilles State Fish and Wildlife Area occurs approximately 1.5 mi (2.4 km) north of the 19 LSCS site and the makeup and blowdown pipeline corridor right-of-way crosses the eastern 20 portion of the area. The Marseilles State Fish and Wildlife Area is a 1,032-ha (2,550-ac) area 21 managed by IDNR for hunting and wildlife habitat (IDNR 2015d). It is a joint-use area with the 22 Illinois Department of Military Affairs, and periodically used by the Illinois National Guard for 23 training (IDNR 2015d).
24 3.7.4    Non-Native Species 25 Several non-native species, including the common carp, goldfish, and Asian carps 26 (Hypophthalmichthys spp.), have been introduced into the Illinois River (McClelland et al. 2012).
27 Common carp and goldfish have been present in the vicinity of LSCS prior to operations 28 (McClelland et al. 2012; Exelon 2014a). Both species dominated non-native fish collections in 29 INHSs long term monitoring surveys from 1957 and 1985 (McClelland et al. 2012). Common 30 carp and goldfish are tolerant of degraded aquatic habitats and can tolerate low levels of 31 dissolved oxygen and high water turbidity.
32 Beginning in 1985, the number of non-native fish observed in the Illinois River increased 33 (McClelland et al. 2012). Species documented in the Illinois River since 1985 include grass 34 carp (Ctenopharyngodon idella), bighead carp (Hypophthalmycthys nobilis), silver carp 35 (Hypophthalmycthys molitrix), round goby (Neogobius melanostomus), white perch (Morone 36 americana), and the white perch-yellow bass hybrid (M. americana x M. mississippiensis) 37 (McClelland et al. 2012).
38 In addition to fish, Exelon has documented the occurrence of invertebrate non-native species 39 near the river intake, the cooling pond intake, and within the cooling system. Bryozoans are 40 aquatic invertebrates that grow into large sessile colonies. Zebra mussels are native to the 41 Black and Caspian Seas, and have invaded Europe and North America. These organisms can 42 cause biofouling of LSCSs underwater piping systems or water intakes. In 1996, Exelon 43 discovered bryozoans at the cooling pond screen house and removed the colony by using a 44 continuous chlorination treatment. In 2010, Exelon observed the bryozoan Plumatella reticulata 45 in the Unit 1 cooling water system and unidentified bryozoans at the river intake and in the 46 cooling pond (HDR 2011). Within the past 5 years, Exelon has continued to regularly observe 3-72
 
Affected Environment 1 bryozoan colonies and zebra mussels at both the river intake and the cooling pond intake, and 2 limits the growth of these organisms by using biocides (HDR 2012, 2013, 2014; Exelon 2014a).
3 When necessary, Exelon also follows procedures to remove zebra mussels manually.
4 3.8      Federally Protected Species and Habitats 5 Because NRCs issuance of a renewed license for power plants is a Federal action, the NRCs 6 National Environmental Policy Act (NEPA) process considers species and habitats that are 7 protected under Federal acts and possibly affected by license renewal. Federal acts that 8 protect species and habitats possibly affected by the renewal of a nuclear plant license include 9 the Endangered Species Act of 1973, as amended (ESA); the Bald and Golden Eagle 10 Protection Act of 1940, as amended; the Migratory Bird Treaty Act of 1918, as amended; the 11 Magnuson-Stevens Fishery Conservation and Management Act, as amended (MSA); and the 12 Marine Mammal Protection Act of 1972, as amended. Of these, the NRC has direct 13 responsibilities only under the ESA and MSA. No species protected under the MSA, which 14 protects habitat for certain marine and anadromous fish species, occur near LSCS. Species 15 protected under the ESA are discussed in this section, and species protected under other 16 Federal acts where the NRC has no direct responsibilities and under}}

Latest revision as of 02:15, 31 October 2019

NUREG-1437 Dfc, Supp 57, Generic Environmental Impact Statement for License Renewal of Nuclear Plants Regarding LaSalle County Station, Units 1 and 2.
ML16033A103
Person / Time
Site: LaSalle  Constellation icon.png
Issue date: 02/29/2016
From: David Drucker
Office of Nuclear Reactor Regulation
To:
Meyd, Donald
References
NUREG-1437 DFC S57
Download: ML16033A103 (481)
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Address: U.S. Nuclear Regulatory Commission The NUREG series comprises (1) technical and adminis-Office of Administration trative reports and books prepared by the staff (NUREG-XXXX) or agency contractors (NUREG/CR-XXXX), (2) Publications Branch proceedings of conferences (NUREG/CP-XXXX), (3) reports Washington, DC 20555-0001 resulting from international agreements (NUREG/IA-XXXX), E-mail: distribution.resource@nrc.gov (4) brochures (NUREG/BR-XXXX), and (5) compilations of Facsimile: (301) 415-2289 legal decisions and orders of the Commission and Atomic and Safety Licensing Boards and of Directors decisions Some publications in the NUREG series that are posted under Section 2.206 of NRCs regulations (NUREG-0750). at NRCs Web site address www.nrc.gov/reading-rm/ DISCLAIMER: This report was prepared as an account doc-collections/nuregs are updated periodically and may of work sponsored by an agency of the U.S. Government. differ from the last printed version. Although references to Neither the U.S. Government nor any agency thereof, nor any employee, makes any warranty, expressed or implied, material found on a Web site bear the date the material or assumes any legal liability or responsibility for any third was accessed, the material available on the date cited partys use, or the results of such use, of any information, may subsequently be removed from the site. apparatus, product, or process disclosed in this publication, or represents that its use by such third party would not infringe privately owned rights.

NUREG-1437 Supplement 57 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft Report for Comment Manuscript Completed: February 2016 Date Published: February 2016 Office of Nuclear Reactor Regulation

1 Proposed Action Issuance of renewed operating licenses NPF-11 and NPF-18 for LaSalle 2 County Station, Units 1 and 2 (LSCS), in LaSalle County, Illinois 3 Type of Statement Draft Supplemental Environmental Impact Statement 4 Agency Contact Mr. David Drucker 5 U.S. Nuclear Regulatory Commission (NRC) 6 Office of Nuclear Reactor Regulation 7 Mail Stop O-11F1 8 Washington, DC 20555-0001 9 Phone: 1-800-368-5642, extension 6223 10 E-mail: david.drucker@nrc.gov 11 Comments Any interested party may submit comments on this draft supplemental 12 environmental impact statement. Please specify NUREG-1437, 13 Supplement 57, draft, in your comments, and send them by the end of the 14 comment period specified in the Federal Register notice announcing the 15 availability of this report. Comments may be submitted electronically by 16 searching for docket ID NRC-2014-0268 at the Federal rulemaking Web 17 site, http://www.regulations.gov. Comments also may be mailed to the 18 following address: 19 Chief, Rules, Announcements, and Directives Branch 20 Division of Administrative Services 21 Office of Administration 22 Mail Stop: OWFN-12 H08 23 U.S. Nuclear Regulatory Commission 24 Washington, DC 20555-0001 25 Please be aware that any comments that you submit to the NRC will be 26 considered a public record and entered into the Agencywide Documents 27 Access and Management System. Do not provide information you would 28 not want to be publicly available.

1 COVER SHEET 2 Responsible Agency: U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor 3 Regulation. There are no cooperating agencies involved in the preparation of this document. 4 Title: Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 5 Supplement 57, Regarding LaSalle County Station, Units 1 and 2, Draft Report for Comment 6 (NUREG-1437). LaSalle County Station is located in LaSalle County, Illinois. 7 For additional information or copies of this document contact: 8 Division of License Renewal 9 U.S. Nuclear Regulatory Commission 10 Office of Nuclear Reactor Regulation 11 Mail Stop O-11F1 12 11555 Rockville Pike 13 Rockville, Maryland 20852 14 Phone: 1-800-368-5642, extension 6223 15 Email: david.drucker@nrc.gov 16 ABSTRACT 17 This supplemental environmental impact statement (SEIS) has been prepared in response to an 18 application submitted by Exelon Generation Company, LLC (Exelon), to renew the operating 19 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years. 20 This SEIS includes the preliminary analysis that evaluates the environmental impacts of the 21 proposed action and alternatives to the proposed action. Alternatives considered include: 22 (1) new nuclear power generation, (2) coal-integrated gasification combined-cycle, (3) natural 23 gas combined-cycle (NGCC), (4) a combination of NGCC, wind, and solar generation, 24 (5) purchased power, and (6) the no-action alternative (i.e., no renewal of the license). 25 The U.S. Nuclear Regulatory Commission (NRC) staffs preliminary recommendation is that the 26 adverse environmental impacts of license renewal for LSCS are not so great that preserving the 27 option of license renewal for energy-planning decisionmakers would be unreasonable. The 28 NRC staff based its recommendation on the following factors: 29

  • the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic Environmental 30 Impact Statement for License Renewal of Nuclear Plants; 31
  • the Environmental Report submitted by Exelon; 32
  • the NRC staffs consultation with Federal, State, local, and Tribal Government 33 agencies; 34
  • the NRC staffs independent environmental review; and 35
  • the NRC staffs consideration of public comments received during the scoping 36 process.

iii

1 TABLE OF CONTENTS 2 ABSTRACT .............................................................................................................................. iii 3 TABLE OF CONTENTS ............................................................................................................ v 4 FIGURES ................................................................................................................................. xv 5 TABLES ................................................................................................................................ xvii 6 EXECUTIVE

SUMMARY

........................................................................................................ xxi 7 ABBREVIATIONS AND ACRONYMS ..................................................................................xxvii 8

1.0 INTRODUCTION

.......................................................................................................... 1-1 9       1.1      Proposed Federal Action.................................................................................. 1-1 10       1.2      Purpose and Need for Proposed Federal Action .............................................. 1-1 11       1.3      Major Environmental Review Milestones .......................................................... 1-1 12       1.4      Generic Environmental Impact Statement ........................................................ 1-2 13       1.5      Supplemental Environmental Impact Statement ............................................... 1-4 14       1.6      Decisions to Be Supported by the SEIS ........................................................... 1-5 15       1.7      Cooperating Agencies ...................................................................................... 1-5 16       1.8      Consultations ................................................................................................... 1-5 17       1.9      Correspondence .............................................................................................. 1-6 18       1.10     Status of Compliance ....................................................................................... 1-6 19       1.11     Related Federal and State Activities ................................................................ 1-6 20       1.12     References ...................................................................................................... 1-7 21 2.0  ALTERNATIVES INCLUDING THE PROPOSED ACTION .......................................... 2-1 22       2.1      Proposed Action .............................................................................................. 2-1 23                2.1.1           Plant Operations during the License Renewal Term......................... 2-1 24                2.1.2           Refurbishment and Other Activities Associated with License 25                                Renewal ........................................................................................... 2-2 26                2.1.3           Termination of Nuclear Power Plant Operations and 27                                Decommissioning after the License Renewal Term .......................... 2-2 28       2.2      Alternatives ...................................................................................................... 2-3 29                2.2.1           No-Action Alternative ....................................................................... 2-3 30                2.2.2           Replacement Power Alternatives ..................................................... 2-4 31                                2.2.2.1            New Nuclear Alternative ................................................ 2-9 32                                2.2.2.2            IGCC Alternative ......................................................... 2-11 33                                2.2.2.3            NGCC Alternative ........................................................ 2-13 34                                2.2.2.4            Combination Alternative (NGCC, Wind, and Solar)...... 2-13 35                                2.2.2.5            Purchased Power Alternative ...................................... 2-16 36       2.3      Alternatives Considered but Dismissed .......................................................... 2-17 37                2.3.1           Energy Conservation and Energy Efficiency .................................. 2-17 38                2.3.2           Solar .............................................................................................. 2-17 v

Table of Contents 1 2.3.3 Wind .............................................................................................. 2-18 2 2.3.3.1 Offshore Wind ............................................................. 2-18 3 2.3.3.2 Wind Power with Storage ............................................ 2-19 4 2.3.3.3 Conclusion .................................................................. 2-19 5 2.3.4 Biomass ......................................................................................... 2-19 6 2.3.5 Hydroelectric .................................................................................. 2-20 7 2.3.6 Wave and Ocean Energy ............................................................... 2-20 8 2.3.7 Fuel Cells ....................................................................................... 2-21 9 2.3.8 Delayed Retirement ....................................................................... 2-21 10 2.3.9 Geothermal .................................................................................... 2-22 11 2.3.10 Municipal Solid Waste .................................................................... 2-22 12 2.3.11 Petroleum ...................................................................................... 2-23 13 2.3.12 Supercritical Pulverized Coal ......................................................... 2-23 14 2.4 Comparison of Alternatives ............................................................................ 2-23 15 2.5 References .................................................................................................... 2-27 16 3.0 AFFECTED ENVIRONMENT ....................................................................................... 3-1 17 3.1 Description of Nuclear Power Plant Facility and Operation .............................. 3-1 18 3.1.1 External Appearance and Setting ..................................................... 3-1 19 3.1.2 Nuclear Reactor Systems................................................................. 3-6 20 3.1.3 Cooling and Auxiliary Water Systems .............................................. 3-6 21 3.1.4 Radioactive Waste Management Systems ..................................... 3-13 22 3.1.4.1 Radioactive Liquid Waste Management ...................... 3-13 23 3.1.4.2 Radioactive Gaseous Waste Management .................. 3-15 24 3.1.4.3 Radioactive Solid Waste Management ........................ 3-16 25 3.1.4.4 Radioactive Waste Storage ......................................... 3-17 26 3.1.4.5 Radiological Environmental Monitoring Program ......... 3-17 27 3.1.5 Nonradioactive Waste Management Systems ................................ 3-18 28 3.1.6 Utility and Transportation Infrastructure.......................................... 3-18 29 3.1.6.1 Electricity ..................................................................... 3-19 30 3.1.6.2 Fuel ............................................................................. 3-19 31 3.1.6.3 Water .......................................................................... 3-19 32 3.1.6.4 Transportation Systems............................................... 3-19 33 3.1.6.5 Power Transmission Systems ..................................... 3-20 34 3.1.7 Nuclear Power Plant Operations and Maintenance ........................ 3-20 35 3.2 Land Use and Visual Resources .................................................................... 3-21 36 3.2.1 Land Use ....................................................................................... 3-21 37 3.2.1.1 Onsite Land Use ......................................................... 3-21 38 3.2.1.2 Coastal Zone ............................................................... 3-22 39 3.2.1.3 Offsite Land Use ......................................................... 3-22 40 3.2.2 Visual Resources ........................................................................... 3-24 41 3.3 Meteorology, Air Quality, and Noise ............................................................... 3-24 vi

Table of Contents 1 3.3.1 Meteorology and Climatology ......................................................... 3-24 2 3.3.2 Air Quality ...................................................................................... 3-25 3 3.3.3 Noise ............................................................................................. 3-28 4 3.4 Geologic Environment .................................................................................... 3-29 5 3.4.1 Physiography and Geology ............................................................ 3-29 6 3.4.2 Soils ............................................................................................... 3-30 7 3.4.3 Seismic Setting .............................................................................. 3-34 8 3.5 Water Resources ........................................................................................... 3-35 9 3.5.1 Surface Water Resources .............................................................. 3-35 10 3.5.1.1 Surface Water Hydrology ............................................ 3-35 11 3.5.1.2 Surface Water Use ...................................................... 3-39 12 3.5.1.3 Surface Water Quality and Effluents ............................ 3-41 13 3.5.2 Groundwater Resources ................................................................ 3-46 14 3.5.2.1 Site Description and Hydrogeology ............................. 3-46 15 3.5.2.2 Groundwater Use ........................................................ 3-48 16 3.5.2.3 Groundwater Quality ................................................... 3-51 17 3.6 Terrestrial Resources ..................................................................................... 3-52 18 3.6.1 LSCS Ecoregion ............................................................................ 3-52 19 3.6.2 LSCS Site Surveys, Studies, and Reports...................................... 3-53 20 3.6.3 LSCS Site ...................................................................................... 3-54 21 3.6.3.1 Vegetation ................................................................... 3-54 22 3.6.3.2 Wildlife ........................................................................ 3-55 23 3.6.4 LSCS Wildlife Management Plan ................................................... 3-55 24 3.6.5 Important Species and Habitats ..................................................... 3-56 25 3.6.5.1 Important Species ....................................................... 3-56 26 3.6.5.2 Important Habitats ....................................................... 3-58 27 3.6.6 Invasive and Non-Native Species................................................... 3-59 28 3.7 Aquatic Resources ......................................................................................... 3-59 29 3.7.1 Illinois River ................................................................................... 3-59 30 3.7.1.1 Aquatic Communities in the Illinois River ..................... 3-60 31 3.7.2 LSCS Cooling Pond ....................................................................... 3-67 32 3.7.2.1 Aquatic Community in the Cooling Pond ..................... 3-68 33 3.7.2.2 Cooling Pond Fish Kill Events...................................... 3-69 34 3.7.3 Important Species and Habitats ..................................................... 3-69 35 3.7.3.1 State-Listed Species ................................................... 3-69 36 3.7.3.2 Important Habitats ....................................................... 3-72 37 3.7.4 Non-Native Species ....................................................................... 3-72 38 3.8 Federally Protected Species and Habitats...................................................... 3-73 39 3.8.1 Action Area .................................................................................... 3-73 40 3.8.2 Federally Protected Species and Habitats Considered................... 3-74 41 3.9 Historic and Cultural Resources ..................................................................... 3-79 vii

Table of Contents 1 3.9.1 Cultural Background....................................................................... 3-80 2 3.9.2 Historic and Cultural Resources ..................................................... 3-82 3 3.10 Socioeconomics ............................................................................................. 3-82 4 3.10.1 Power Plant Employment and Expenditures .................................. 3-83 5 3.10.2 Regional Economic Characteristics ................................................ 3-83 6 3.10.2.1 Employment and Income ............................................. 3-84 7 3.10.2.2 Unemployment ............................................................ 3-86 8 3.10.3 Demographic Characteristics ......................................................... 3-86 9 3.10.3.1 Transient Population ................................................... 3-88 10 3.10.3.2 Migrant Farm Workers ................................................. 3-89 11 3.10.4 Housing and Community Services ................................................. 3-90 12 3.10.4.1 Housing ....................................................................... 3-91 13 3.10.4.2 Education .................................................................... 3-91 14 3.10.4.3 Public Water Supply .................................................... 3-91 15 3.10.5 Tax Revenues ................................................................................ 3-93 16 3.10.6 Local Transportation ...................................................................... 3-95 17 3.11 Human Health ................................................................................................ 3-96 18 3.11.1 Radiological Exposure and Risk ..................................................... 3-96 19 3.11.2 Chemical Hazards .......................................................................... 3-97 20 3.11.3 Microbiological Hazards ................................................................. 3-97 21 3.11.3.1 Thermophilic Microorganisms of Concern ................... 3-98 22 3.11.3.2 Prevalence of Waterborne Diseases Associated 23 with Recreational Waters............................................. 3-99 24 3.11.4 Electromagnetic Fields ................................................................... 3-99 25 3.11.5 Other Hazards.............................................................................. 3-100 26 3.12 Environmental Justice .................................................................................. 3-101 27 3.12.1 Minority Population ...................................................................... 3-102 28 3.12.2 Low-Income Population................................................................ 3-102 29 3.13 Waste Management and Pollution Prevention.............................................. 3-106 30 3.13.1 Radioactive Waste ....................................................................... 3-106 31 3.13.2 Nonradioactive Waste .................................................................. 3-106 32 3.14 References .................................................................................................. 3-106 33 4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS ........................ 4-1 34 4.1 Introduction ...................................................................................................... 4-1 35 4.2 Land Use and Visual Resources ...................................................................... 4-1 36 4.2.1 Proposed Action............................................................................... 4-1 37 4.2.2 No-Action Alternative ....................................................................... 4-2 38 4.2.2.1 Land Use ....................................................................... 4-2 39 4.2.2.2 Visual Resources .......................................................... 4-2 40 4.2.3 New Nuclear Alternative ................................................................... 4-3 41 4.2.3.1 Land Use ....................................................................... 4-3 viii

Table of Contents 1 4.2.3.2 Visual Resources .......................................................... 4-3 2 4.2.4 IGCC Alternative .............................................................................. 4-3 3 4.2.4.1 Land Use ....................................................................... 4-3 4 4.2.4.2 Visual Resources .......................................................... 4-4 5 4.2.5 Natural Gas Combined-Cycle Alternative ......................................... 4-4 6 4.2.5.1 Land Use ....................................................................... 4-4 7 4.2.5.2 Visual Resources .......................................................... 4-4 8 4.2.6 Combination Alternative (NGCC, Wind, Solar) ................................. 4-5 9 4.2.6.1 Land Use ....................................................................... 4-5 10 4.2.6.2 Visual Resources .......................................................... 4-5 11 4.2.7 Purchased Power Alternative ........................................................... 4-6 12 4.2.7.1 Land Use ....................................................................... 4-6 13 4.2.7.2 Visual Resources .......................................................... 4-6 14 4.3 Air Quality and Noise ....................................................................................... 4-6 15 4.3.1 Proposed Action............................................................................... 4-6 16 4.3.1.1 Air Quality ..................................................................... 4-6 17 4.3.1.2 Noise ............................................................................. 4-7 18 4.3.2 No-Action Alternative ....................................................................... 4-7 19 4.3.2.1 Air Quality ..................................................................... 4-7 20 4.3.2.2 Noise ............................................................................. 4-7 21 4.3.3 New Nuclear Alternative ................................................................... 4-7 22 4.3.3.1 Air Quality ..................................................................... 4-7 23 4.3.3.2 Noise ............................................................................. 4-9 24 4.3.4 IGCC Alternative ............................................................................ 4-10 25 4.3.4.1 Air Quality ................................................................... 4-10 26 4.3.4.2 Noise ........................................................................... 4-13 27 4.3.5 NGCC Alternative .......................................................................... 4-13 28 4.3.5.1 Air Quality ................................................................... 4-13 29 4.3.5.2 Noise ........................................................................... 4-15 30 4.3.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-16 31 4.3.6.1 Air Quality ................................................................... 4-16 32 4.3.6.2 Noise ........................................................................... 4-18 33 4.3.7 Purchased Power Alternative ......................................................... 4-19 34 4.3.7.1 Air Quality ................................................................... 4-19 35 4.3.7.2 Noise ........................................................................... 4-19 36 4.4 Geologic Environment .................................................................................... 4-20 37 4.4.1 Proposed Action............................................................................. 4-20 38 4.4.2 No-Action Alternative ..................................................................... 4-20 39 4.4.3 New Nuclear Alternative ................................................................. 4-20 40 4.4.4 IGCC Alternative ............................................................................ 4-21 41 4.4.5 NGCC Alternative .......................................................................... 4-21 ix

Table of Contents 1 4.4.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-21 2 4.4.7 Purchased Power Alternative ......................................................... 4-21 3 4.5 Water Resources ........................................................................................... 4-21 4 4.5.1 Proposed Action............................................................................. 4-22 5 4.5.1.1 Surface Water Resources ........................................... 4-22 6 4.5.1.2 Groundwater Resources.............................................. 4-24 7 4.5.2 No-Action Alternative ..................................................................... 4-26 8 4.5.2.1 Surface Water Resources ........................................... 4-26 9 4.5.2.2 Groundwater Resources.............................................. 4-26 10 4.5.3 New Nuclear Alternative ................................................................. 4-26 11 4.5.3.1 Surface Water Resources ........................................... 4-26 12 4.5.3.2 Groundwater Resources.............................................. 4-27 13 4.5.4 IGCC Alternative ............................................................................ 4-27 14 4.5.4.1 Surface Water Resources ........................................... 4-27 15 4.5.4.2 Groundwater Resources.............................................. 4-28 16 4.5.5 NGCC Alternative .......................................................................... 4-28 17 4.5.5.1 Surface Water Resources ........................................... 4-28 18 4.5.5.2 Groundwater Resources.............................................. 4-29 19 4.5.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-29 20 4.5.6.1 Surface Water Resources ........................................... 4-29 21 4.5.6.2 Groundwater Resources.............................................. 4-30 22 4.5.7 Purchased Power Alternative ......................................................... 4-30 23 4.5.7.1 Surface Water Resources ........................................... 4-30 24 4.5.7.2 Groundwater Resources.............................................. 4-30 25 4.6 Terrestrial Resources ..................................................................................... 4-30 26 4.6.1 Proposed Action............................................................................. 4-31 27 4.6.1.1 Generic GEIS Issues ................................................... 4-31 28 4.6.1.2 Effects on Terrestrial Resources (Non-Cooling 29 System Impacts) ......................................................... 4-31 30 4.6.1.3 Water Use Conflicts with Terrestrial Resources ........... 4-33 31 4.6.2 No-Action Alternative ..................................................................... 4-34 32 4.6.3 New Nuclear Alternative ................................................................. 4-34 33 4.6.4 IGCC Alternative ............................................................................ 4-35 34 4.6.5 NGCC Alternative .......................................................................... 4-35 35 4.6.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-36 36 4.6.7 Purchased Power Alternative ......................................................... 4-37 37 4.7 Aquatic Resources ......................................................................................... 4-37 38 4.7.1 Proposed Action............................................................................. 4-37 39 4.7.1.1 GEIS Category 1 Issues .............................................. 4-38 40 4.7.1.2 Impingement and Entrainment of Aquatic 41 Organisms ................................................................... 4-38 x

Table of Contents 1 4.7.1.3 Thermal Impacts on Aquatic Organisms ...................... 4-45 2 4.7.1.4 Water Use Conflicts with Aquatic Resources ............... 4-52 3 4.7.2 No-Action Alternative ..................................................................... 4-52 4 4.7.3 New Nuclear Alternative ................................................................. 4-53 5 4.7.4 IGCC Alternative ............................................................................ 4-53 6 4.7.5 NGCC Alternative .......................................................................... 4-54 7 4.7.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-54 8 4.7.7 Purchased Power Alternative ......................................................... 4-54 9 4.8 Special Status Species and Habitats.............................................................. 4-55 10 4.8.1 Proposed Action............................................................................. 4-55 11 4.8.2 No-Action Alternative ..................................................................... 4-57 12 4.8.3 New Nuclear Alternative ................................................................. 4-57 13 4.8.4 IGCC Alternative ............................................................................ 4-58 14 4.8.5 NGCC Alternative .......................................................................... 4-58 15 4.8.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-59 16 4.8.7 Purchased Power Alternative ......................................................... 4-59 17 4.9 Historic and Cultural Resources ..................................................................... 4-59 18 4.9.1 Proposed Action............................................................................. 4-60 19 4.9.2 No-Action Alternative ..................................................................... 4-62 20 4.9.3 New Nuclear Alternative ................................................................. 4-62 21 4.9.4 IGCC Alternative ............................................................................ 4-62 22 4.9.5 NGCC Alternative .......................................................................... 4-63 23 4.9.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-63 24 4.9.7 Purchased Power Alternative ......................................................... 4-64 25 4.10 Socioeconomics ............................................................................................. 4-64 26 4.10.1 Proposed Action............................................................................. 4-65 27 4.10.2 No-Action Alternative ..................................................................... 4-65 28 4.10.2.1 Socioeconomics .......................................................... 4-65 29 4.10.2.2 Transportation ............................................................. 4-66 30 4.10.3 New Nuclear Alternative ................................................................. 4-66 31 4.10.3.1 Socioeconomics .......................................................... 4-66 32 4.10.3.2 Transportation ............................................................. 4-67 33 4.10.4 IGCC Alternative ............................................................................ 4-67 34 4.10.4.1 Socioeconomics .......................................................... 4-67 35 4.10.4.2 Transportation ............................................................. 4-68 36 4.10.5 NGCC Alternative .......................................................................... 4-69 37 4.10.5.1 Socioeconomics .......................................................... 4-69 38 4.10.5.2 Transportation ............................................................. 4-69 39 4.10.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-70 40 4.10.6.1 Socioeconomics .......................................................... 4-70 41 4.10.6.2 Transportation ............................................................. 4-71 xi

Table of Contents 1 4.10.7 Purchased Power Alternative ......................................................... 4-71 2 4.10.7.1 Socioeconomics .......................................................... 4-71 3 4.10.7.2 Transportation ............................................................. 4-71 4 4.11 Human Health ................................................................................................ 4-72 5 4.11.1 Proposed Action............................................................................. 4-72 6 4.11.1.1 Normal Operating Conditions ...................................... 4-72 7 4.11.1.2 Environmental Impacts of Postulated Accidents .......... 4-75 8 4.11.2 No-Action Alternative ..................................................................... 4-88 9 4.11.3 New Nuclear Alternative ................................................................. 4-89 10 4.11.4 IGCC Alternative ............................................................................ 4-89 11 4.11.5 NGCC Alternative .......................................................................... 4-90 12 4.11.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-90 13 4.11.7 Purchased Power Alternative ......................................................... 4-90 14 4.12 Environmental Justice .................................................................................... 4-91 15 4.12.1 Proposed Action............................................................................. 4-91 16 4.12.2 No-Action Alternative ..................................................................... 4-93 17 4.12.3 New Nuclear Alternative ................................................................. 4-93 18 4.12.4 IGCC Alternative ............................................................................ 4-94 19 4.12.5 NGCC Alternative .......................................................................... 4-95 20 4.12.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-95 21 4.12.7 Purchased Power Alternative ......................................................... 4-96 22 4.13 Waste Management ....................................................................................... 4-97 23 4.13.1 Proposed Action............................................................................. 4-97 24 4.13.2 No-Action Alternative ..................................................................... 4-98 25 4.13.3 New Nuclear Alternative ................................................................. 4-98 26 4.13.4 IGCC Alternative ............................................................................ 4-98 27 4.13.5 NGCC Alternative .......................................................................... 4-99 28 4.13.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-99 29 4.13.7 Purchased Power Alternative ......................................................... 4-99 30 4.14 Evaluation of New and Potentially Significant Information .............................. 4-99 31 4.15 Impacts Common to All Alternatives............................................................. 4-100 32 4.15.1 Fuel Cycles .................................................................................. 4-100 33 4.15.1.1 Uranium Fuel Cycle ................................................... 4-101 34 4.15.1.2 Replacement Power Plant Fuel Cycles...................... 4-102 35 4.15.2 Terminating Power Plant Operations and Decommissioning ........ 4-102 36 4.15.2.1 Existing Nuclear Power Plant .................................... 4-103 37 4.15.2.2 Replacement Power Plants ....................................... 4-103 38 4.15.3 Greenhouse Gas Emissions and Climate Change ....................... 4-104 39 4.15.3.1 Greenhouse Gas Emissions from the Proposed 40 Project and Alternatives............................................. 4-104 41 4.15.3.2 Climate Change Impacts to Resource Areas ............. 4-107 xii

Table of Contents 1 4.16 Cumulative Impacts of the Proposed Action ................................................. 4-113 2 4.16.1 Air Quality and Noise ................................................................... 4-113 3 4.16.1.1 Air Quality ................................................................. 4-114 4 4.16.1.2 Noise ......................................................................... 4-115 5 4.16.2 Geology and Soils ........................................................................ 4-115 6 4.16.3 Water Resources ......................................................................... 4-116 7 4.16.3.1 Surface Water Resources ......................................... 4-116 8 4.16.3.2 Groundwater Resources............................................ 4-120 9 4.16.4 Terrestrial Resources ................................................................... 4-121 10 4.16.5 Aquatic Resources ....................................................................... 4-124 11 4.16.5.1 Energy Development ................................................. 4-124 12 4.16.5.2 Future Urbanization and Transportation 13 Development ............................................................. 4-125 14 4.16.5.3 Wildlife Preserves, Parks, and Recreational Areas .... 4-125 15 4.16.5.4 Illinois Wildlife Conservation Plan .............................. 4-125 16 4.16.5.5 Conclusion ................................................................ 4-125 17 4.16.6 Historic and Cultural Resources ................................................... 4-126 18 4.16.7 Socioeconomics ........................................................................... 4-126 19 4.16.8 Human Health .............................................................................. 4-127 20 4.16.9 Environmental Justice .................................................................. 4-127 21 4.16.10 Waste Management ..................................................................... 4-128 22 4.16.11 Global Climate Change ................................................................ 4-129 23 4.16.12 Summary of Cumulative Impacts.................................................. 4-130 24 4.17 Resource Commitments............................................................................... 4-132 25 4.17.1 Unavoidable Adverse Environmental Impacts .............................. 4-132 26 4.17.2 Short-Term Versus Long-Term Productivity ................................. 4-133 27 4.17.3 Irreversible and Irretrievable Commitments of Resources ............ 4-133 28 4.18 References .................................................................................................. 4-134 29

5.0 CONCLUSION

............................................................................................................. 5-1 30      5.1   Environmental Impacts of License Renewal ..................................................... 5-1 31      5.2   Comparison of Alternatives .............................................................................. 5-1 32      5.3   Recommendation ............................................................................................. 5-1 33 6.0 LIST OF PREPARERS ................................................................................................ 6-1 34 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES 35      OF THIS SEIS ARE SENT .......................................................................................... 7-1 36 8.0 INDEX .......................................................................................................................... 8-1 37 APPENDIX A    COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW ...... A-1 38 APPENDIX B    APPLICABLE LAWS, REGULATIONS, AND OTHER 39               REQUIREMENTS ......................................................................................... B-1 40 APPENDIX C    CONSULTATION CORRESPONDENCE ..................................................... C-1 xiii

Table of Contents 1 APPENDIX D CHRONOLOGY OF ENVIRONMENTAL REVIEW 2 CORRESPONDENCE .................................................................................. D-1 3 APPENDIX E PROJECTS AND ACTIONS CONSIDERED IN CUMULATIVE IMPACTS 4 ANALYSIS.................................................................................................... E-1 5 APPENDIX F U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 6 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 7 LASALLE COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF 8 LICENSE RENEWAL APPLICATION REVIEW............................................ F-1 9 APPENDIX G TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL ................G-1 xiv

1 FIGURES 2 Figure 1-1. Environmental Review Process........................................................................ 1-2 3 Figure 1-2. Environmental Issues Evaluated for License Renewal ..................................... 1-4 4 Figure 2-1. Territories of MISO and PJM Interconnection................................................... 2-6 5 Figure 3-1. LSCS 50-mi (80-km) Radius Map .................................................................... 3-2 6 Figure 3-2. LSCS 6-mi (10-km) Radius Map ...................................................................... 3-3 7 Figure 3-3. LSCS Site Layout............................................................................................. 3-4 8 Figure 3-4. LSCS Plant Features ....................................................................................... 3-5 9 Figure 3-5. Closed-Cycle Cooling System with Cooling Pond ............................................ 3-7 10 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities ...................................... 3-9 11 Figure 3-7. Site Physiography, LSCS Vicinity ................................................................... 3-31 12 Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity ...................................... 3-32 13 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity ................................ 3-33 14 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries ..................... 3-37 15 Figure 3-11. LSCS Surface Water and Related Water Resource Features ........................ 3-38 16 Figure 3-12. LSCS Site Hydrogeologic Units...................................................................... 3-47 17 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill .................................... 3-49 18 Figure 3-14. LSCS Hydrogeologic Cross-Section............................................................... 3-50 19 Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure........... 3-62 20 Figure 3-16. Sampling Locations in LSCS Aquatic Surveys ............................................... 3-63 21 Figure 3-17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS .................... 3-104 22 Figure 3-18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS ............. 3-105 23 Figure G-1. Illustration of Truck Stop Model ....................................................................... G-6 xv

1 TABLES 2 Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 3 License Renewal............................................................................................. xxiii 4 Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 5 Considered in Depth ........................................................................................ 2-8 6 Table 2-2. Summary of Environmental Impacts of Proposed Action and 7 Alternatives .................................................................................................... 2-25 8 Table 3-1. LSCS Site Land Uses by Area ....................................................................... 3-21 9 Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS ........................................... 3-23 10 Table 3-3. National Ambient Air Quality Standards ......................................................... 3-26 11 Table 3-4. LSCS Air Emissions (MT/year)....................................................................... 3-27 12 Table 3-5. Common Noise Sources and Noise Levels .................................................... 3-28 13 Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, 14 LSCS ............................................................................................................. 3-40 15 Table 3-7. National Pollutant Discharge Elimination System-Permitted Outfalls, 16 LSCS ............................................................................................................. 3-43 17 Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion............................... 3-52 18 Table 3-9. State-Listed Species in LaSalle County ......................................................... 3-56 19 Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River ............ 3-65 20 Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural 21 History Electrofishing Surveys from 1957 through 2009 ................................. 3-67 22 Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 ................................... 3-68 23 Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle 24 County ........................................................................................................... 3-70 25 Table 3-14. Federally Listed Species and Designated Habitat in La Salle County, 26 Illinois............................................................................................................. 3-75 27 Table 3-15. LSCS Employees Residence by County ........................................................ 3-83 28 Table 3-16. Employment by Industry in the LSCS ROI (2014, 1-year estimates and 29 2009-2013, 5-year estimates) ........................................................................ 3-84 30 Table 3-17. Major Employers in LaSalle County in 2009 ................................................... 3-85 31 Table 3-18. Estimated Income Information for the LSCS ROI (2014 estimates, 32 unless otherwise indicated) ............................................................................ 3-85 33 Table 3-19. Population and Percent Growth in LSCS ROI Counties 1980-2010, 34 2014 (estimated), and Projected for 2020-2060 ............................................ 3-86 35 Table 3-20. Demographic Profile of the Population in the LSCS ROI in 2010 ................... 3-87 36 Table 3-21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County) ................... 3-87 37 Table 3-22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of 38 LSCS ............................................................................................................. 3-88 39 Table 3-23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 40 within 50 mi (80 km) of LSCS (2012).............................................................. 3-90 41 Table 3-24. Housing in the LSCS ROI (2014 estimate) ..................................................... 3-91 42 Table 3-25. Local Public Water Supply Systems ............................................................... 3-92 xvii

1 Table 3-26. LSCS Power Block Tax Payments and Valuations 2007-2014 (in 2 dollars) ........................................................................................................... 3-93 3 Table 3-27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total 4 Levy ............................................................................................................... 3-94 5 Table 3-28. Annual Payments to Illinois Emergency Management Agency 2009-6 2014............................................................................................................... 3-95 7 Table 3-29. Major Commuting Routes in the Vicinity of LSCS: 2013-2014 Average 8 Annual Daily Traffic Count ............................................................................. 3-95 9 Table 4-1. Land Use and Visual Resource Issues............................................................. 4-2 10 Table 4-2. Air Quality and Noise ....................................................................................... 4-7 11 Table 4-3. Geology and Soils Issues............................................................................... 4-20 12 Table 4-4. Surface Water Resources Issues ................................................................... 4-22 13 Table 4-5. Groundwater Issues ....................................................................................... 4-24 14 Table 4-6. Terrestrial Resource Issues ........................................................................... 4-31 15 Table 4-7. Aquatic Resource Issues ............................................................................... 4-37 16 Table 4-8. Special Status Species and Habitat Issues .................................................... 4-55 17 Table 4-9. Federally Listed Species and Designated Habitat in LaSalle County, 18 Illinois, and NRC Effect Determinations for Proposed LSCS License 19 Renewal ......................................................................................................... 4-56 20 Table 4-10. Historic and Cultural Resources Issue ........................................................... 4-60 21 Table 4-11. Socioeconomic NEPA Issues Affected by License Renewal .......................... 4-65 22 Table 4-12. Human Health Issues ..................................................................................... 4-72 23 Table 4-13. Issues Related to Postulated Accidents ......................................................... 4-76 24 Table 4-14. LSCS CDF for Internal Events ....................................................................... 4-79 25 Table 4-15. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 26 for Internal Events .......................................................................................... 4-81 27 Table 4-16. LSCS Potentially Cost-Beneficial SAMAs ...................................................... 4-84 28 Table 4-17. Environmental Justice NEPA Issue ................................................................ 4-91 29 Table 4-18. Waste Management Issues ............................................................................ 4-97 30 Table 4-19. Issues Related to the Uranium Fuel Cycle ................................................... 4-101 31 Table 4-20. Issues Related to Decommissioning ............................................................ 4-103 32 Table 4-21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)......... 4-105 33 Table 4-22. Direct GHG Emissions from Operation of the Proposed Action and 34 Alternatives .................................................................................................. 4-107 35 Table 4-23. Comparison of GHG Emission Inventories ................................................... 4-130 36 Table 4-24. Summary of Cumulative Impacts on Resource Areas .................................. 4-131 37 Table 6-1. List of Preparers .............................................................................................. 6-1 38 Table B-1. Federal and State Requirements ..................................................................... B-2 39 Table B-2. Licenses and Permits ....................................................................................... B-7 40 Table C-1. ESA Section 7 Consultation Correspondence ..................................................C-2 41 Table C-2. NHPA Correspondence....................................................................................C-3 42 Table D-1. Environmental Review Correspondence ..........................................................D-1 43 Table E-1. Projects and Actions Considered in Cumulative Impact Analysis ..................... E-1

Tables 1 Table F-1. LaSalle County Station CDF for Internal Events ............................................... F-3 2 Table F-2. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 3 for Internal Events ............................................................................................ F-4 4 Table F-3. Summary of Major PRA Models and Corresponding CDF and LERF 5 Results............................................................................................................. F-7 6 Table F-4. Dominant LSCS Contributors to Seismic CDF ............................................... F-12 7 Table F-5(a). Dominant LSCS Unit 1 Fire Zone Contributors to Fire CDF of 8.9x10-6 8 per year ......................................................................................................... F-14 9 Table F-5(b). Dominant LSCS Unit 2 Fire Zone Contributors to Fire CDF of 9.4x10-6 10 per year ......................................................................................................... F-14 11 Table F-6. SAMA Cost-Benefit Screening Analysis for LSCS Station .............................. F-33 12 Table G-1. Transportation Route Information for Shipments from LSCS to the 13 Proposed Yucca Mountain Repository Site ..................................................... G-4 14 Table G-2. RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters ....................... G-5 15 Table G-3. Annual Normal (Incident-Free) Radiation Doses to Transport Workers 16 and the Public from Shipping Spent Fuel from LSCS to the Proposed 17 Yucca Mountain Repository Site, Normalized to Reference 18 LWR (880 MWe (net)) ..................................................................................... G-6 19 Table G-4. Radionuclide Inventories Used in Transportation Accident Risk 20 Calculations for the LSCS Reactors ...............................................................G-10 21 Table G-5. Annual Spent Fuel Transportation Accident Impacts from Shipping 22 Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 23 Site, Normalized to Reference LWR Reactor (880 MWe (net)).......................G-11 xix

1 EXECUTIVE

SUMMARY

2 BACKGROUND 3 By letter dated December 9, 2014, Exelon Generation Company, LLC (Exelon) submitted an 4 application to the U.S. Nuclear Regulatory Commission (NRC) to issue renewed operating 5 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20-year period. 6 Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 51.20(b)(2), the renewal of a 7 power reactor operating license requires preparation of an environmental impact statement 8 (EIS) or a supplement to an existing EIS. In addition, 10 CFR 51.95(c) states that, in connection 9 with the renewal of an operating license, the NRC shall prepare an EIS, which is a supplement 10 to the Commissions NUREG-1437, Generic Environmental Impact Statement (GEIS) for 11 License Renewal of Nuclear Plants. 12 Upon acceptance of Exelons application, the NRC staff began the environmental review 13 process described in 10 CFR Part 51 by publishing a Notice of Intent to prepare a supplemental 14 environmental impact statement (SEIS) and to conduct scoping. In preparation of this SEIS for 15 LSCS, the NRC staff performed the following: 16

  • conducted public scoping meetings on March 10, 2015, in Ottawa, Illinois; 17
  • conducted a site audit at LSCS from May 5-7, 2015; 18
  • reviewed Exelons Environmental Report (ER) and compared it to the GEIS; 19
  • consulted with Federal, State, Tribal, and local agencies; 20
  • conducted a review of the issues following the guidance set forth in 21 Standard Review Plans for Environmental Reviews for Nuclear Power Plants:

22 Environmental Standard Review Plan for Operating License Renewal (NUREG-1555 23 Supplement 1, Revision 1, Final Report); and 24

  • considered public comments received during the scoping process.

25 PROPOSED ACTION 26 Exelon initiated the proposed Federal action (i.e., issuance of renewed power reactor operating 27 licenses) by submitting an application for license renewal of LSCS for which the existing 28 licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023. The NRCs 29 Federal action is to decide whether to renew the licenses for an additional 20 years. The 30 regulation at 10 CFR 2.109 states that, if a licensee of a nuclear power plant files an application 31 to renew an operating license at least 5 years before the expiration date of that license, the 32 existing license will not be deemed to have expired until the safety and environmental reviews 33 are completed and until the NRC has made a final decision on whether to issue a renewed 34 license for the additional 20 years. 35 PURPOSE AND NEED FOR ACTION 36 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 37 option that allows for power generation capability beyond the term of the current nuclear power 38 plant operating licenses to meet future system generating needs. Such needs may be 39 determined by other energy-planning decisionmakers, such as states, operators, and, where 40 authorized, Federal agencies (other than the NRC). This definition of purpose and need reflects xxi

Executive Summary 1 the NRCs recognition that, unless there are findings in the safety review required by the Atomic 2 Energy Act of 1954, as amended, or findings in the National Environmental Policy Act of 1969, 3 as amended, environmental analysis that would lead the NRC to reject a license renewal 4 application, the NRC does not have a role in the energy-planning decisions as to whether a 5 particular nuclear power plant should continue to operate. 6 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL 7 The SEIS evaluates the potential environmental impacts of the proposed action. The 8 environmental impacts from the proposed action are designated as SMALL, MODERATE, or 9 LARGE. As established in the GEIS, Category 1 issues are those that meet all of the following 10 criteria: 11

  • The environmental impacts associated with the issue SMALL: Environmental 12 are determined to apply either to all plants or, for some effects are not detectable or 13 issues, to plants having a specific type of cooling are so minor that they will 14 system or other specified plant or site characteristics. neither destabilize nor noticeably alter any important 15
  • A single significance level (i.e., SMALL, MODERATE, attribute of the resource.

16 or LARGE) has been assigned to the impacts except MODERATE: 17 for collective offsite radiological impacts from the fuel Environmental effects are 18 cycle and from high-level waste and spent fuel sufficient to alter noticeably, but not to destabilize, 19 disposal. important attributes of the 20

  • Mitigation of adverse impacts associated with the issue resource.

21 is considered in the analysis, and it has been LARGE: Environmental 22 determined that additional plant-specific mitigation effects are clearly noticeable and are sufficient to 23 measures are likely not to be sufficiently beneficial to destabilize important 24 warrant implementation. attributes of the resource. 25 For Category 1 issues, no additional site-specific analysis is 26 required in this SEIS unless new and significant information is identified. Chapter 4 of this SEIS 27 presents the process for identifying new and significant information. Site-specific issues 28 (Category 2) are those that do not meet one or more of the criteria for Category 1 issues; 29 therefore, an additional site-specific review for these non-generic issues is required, and the 30 results are documented in the SEIS. 31 Neither Exelon nor the NRC identified information that is both new and significant related to 32 Category 1 issues that would call into question the conclusions in the GEIS. This conclusion is 33 supported by the NRC staffs review of the applicants ER and other documentation relevant to 34 the applicants activities, the public scoping process, and the findings from the environmental 35 site audit conducted by the NRC staff. Therefore, the NRC staff relied upon the conclusions of 36 the GEIS for all Category 1 issues applicable to LSCS. 37 The NRC staff did find new information regarding the Category 1 a uranium fuel cycle issue 38 (Transportation), but this new information was not considered significant and therefore did not 39 affect the conclusions for these issues presented in the GEIS. This new information is 40 discussed in Section 4.15.1 and Appendix G of this SEIS. 41 Table ES-1 summarizes the Category 2 issues relevant to LSCS and the NRC staffs findings 42 related to those issues. If the NRC staff determined that there were no Category 2 issues 43 applicable for a particular resource area, the findings of the GEIS, as documented in 44 Appendix B to Subpart A of 10 CFR Part 51, are incorporated for that resource area. xxii

Executive Summary 1 Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 2 License Renewal Resource Area Relevant Category 2 Issues Impacts Surface Water Resources Surface water use conflicts SMALL Groundwater Resources Groundwater Use Conflicts SMALL Groundwater Quality Degradation SMALL Radionuclides released to groundwater SMALL Terrestrial Resources Effects on terrestrial resources (non-cooling SMALL system impacts) Water use conflicts with terrestrial resources SMALL Aquatic Resources Impingement and entrainment of aquatic SMALL organisms Thermal impacts on aquatic organisms SMALL to MODERATE(a) Water use conflicts with aquatic resources SMALL Special Status Species and Threatened, endangered, and species and No effect (b) Habitats essential fish habitat Historic and Cultural Historic and cultural resources No adverse effect (c) Resources Human Health Microbiological hazards to the public SMALL Electric shock hazards SMALL Environmental Justice Minority and low-income populations See note below (d) Cumulative Impacts Terrestrial Ecology MODERATE to LARGE Aquatic Resources MODERATE Socioeconomic See note below (e) Environmental Justice See note below (d) Global Climate Change MODERATE All other resource areas SMALL (a) Thermal impacts would be SMALL for all aquatic resources in the Illinois River and SMALL for aquatic resources in the cooling pond, except for gizzard shad and threadfin shad. Gizzard shad and threadfin shad would experience MODERATE thermal impacts in the cooling pond. (b) For Federally protected species, the NRC reports the effects from continued operation of LSCS during the license renewal period in terms of its Endangered Species Act of 1973, as amended, findings of no effect, may effect, but not likely to adversely effect, or may affect, and is likely to adversely affect. (c) The National Historic Preservation Act of 1966, as amended, requires Federal agencies to consider the effects of their undertakings on historic properties. (d) There would be no disproportionately high and adverse impacts to minority and low-income populations. (e) The contributory effects from the continued operation of LSCS during the license renewal period would have no new or increased impact on socioeconomic conditions beyond what is currently being experienced. 3 SEVERE ACCIDENT MITIGATION ALTERNATIVES 4 Since severe accident mitigation alternatives (SAMAs) have not been previously considered in 5 an environmental impact statement or environmental assessment for LSCS, xxiii

Executive Summary 1 10 CFR 51.53(c)(3)(ii)(L) requires Exelon to submit, with the ER, a consideration of alternatives 2 to mitigate severe accidents. SAMAs are potential ways to reduce the risk or potential impacts 3 of uncommon, but potentially severe accidents. SAMAs may include changes to plant 4 components, systems, procedures, and training. 5 The NRC staff reviewed Exelons ER evaluation of potential SAMAs and concluded that none of 6 the potentially cost-beneficial SAMAs relate to adequately managing the effects of aging during 7 the extended period of operation. Therefore, the potentially cost-beneficial SAMAs identified 8 need not be implemented as part of the license renewal, pursuant to 10 CFR Part 54. 9 ALTERNATIVES 10 The NRC staff considered the environmental impacts associated with alternatives to license 11 renewal. These alternatives include other methods of power generation, as well as not 12 renewing the LSCS operating licenses (the no-action alternative). The NRC staff considered 13 the following feasible and commercially viable replacement power alternatives: 14

  • new nuclear power; 15
  • coal-integrated gasification combined-cycle; 16
  • natural gas combined-cycle (NGCC); and 17
  • combination alternative (NGCC, wind, and solar power), and 18
  • purchased power.

19 The NRC staff initially considered a number of additional alternatives for analysis as alternatives 20 to the license renewal of LSCS. The NRC staff later dismissed these alternatives because of 21 technical, resource availability, or commercial limitations that currently exist and that the NRC 22 staff believes are likely to continue to exist when the current LSCS licenses expire. The 23 no-action alternative and the effects it would have were also considered by the NRC staff. 24 Where possible, the NRC staff evaluated potential environmental impacts for these alternatives 25 located at both the LSCS site and some other unspecified alternate location. The NRC staff 26 considered the following alternatives, but dismissed them: 27

  • energy conservation and energy efficiency, 28
  • solar power, 29
  • wind power, 30
  • biomass, 31
  • hydroelectric power, 32
  • wave and ocean energy, 33
  • fuel cells, 34
  • delayed retirement, 35
  • geothermal power, 36
  • municipal solid waste, 37
  • oil-fired power, and 38
  • supercritical pulverized coal.

xxiv

Executive Summary 1 The NRC staff evaluated each alternative using the same resource areas that were used in 2 evaluating impacts from license renewal. 3 PRELIMINARY RECOMMENDATION 4 The NRC staffs preliminary recommendation is that the adverse environmental impacts of 5 license renewal for LSCS are not so great that preserving the option of license renewal for 6 energy-planning decisionmakers would be unreasonable. The NRC staff based its 7 recommendation on the following: 8

  • the analyses and findings in the GEIS; 9
  • the ER submitted by Exelon; 10
  • the NRC staffs consultation with Federal, State, local, and Tribal Government 11 agencies; 12
  • the NRC staffs independent environmental review; and 13
  • the NRC staffs consideration of public comments received during the scoping 14 process.

xxv

Abbreviations and Acronyms 1 ABBREVIATIONS AND ACRONYMS 2 ac acre(s) 3 AC alternating current 4 ACC averted cleanup and decontamination costs 5 ACHP Advisory Council on Historic Preservation 6 ADAMS Agencywide Documents Access and Management System 7 AEA Atomic Energy Act of 1954 (as amended) 8 AFW auxiliary feedwater 9 AMSAC ATWS mitigating system actuation circuitry 10 ANL Argonne National Laboratory 11 ANS American Nuclear Society 12 AOC averted offsite property damage costs 13 AOE averted occupational exposure 14 AOSC averted onsite costs 15 AP auxiliary power 16 APE averted public exposure 17 ASLB Atomic Safety and Licensing Board (NRC) 18 ASME American Society of Mechanical Engineers 19 ATWS anticipated transient(s) without scram 20 AWEA American Wind Energy Association 21 BEA Bureau of Economic Analysis 22 BLM Bureau of Land Management 23 BLS Bureau of Labor Statistics 24 BOEM Bureau of Ocean Energy Management 25 BTU/ft3 British thermal unit(s) per cubic foot 26 CAA Clean Air Act 27 CAES compressed air energy storage 28 CCS carbon capture and storage 29 CCW component cooling water 30 CDF core damage frequency 31 CEQ Council on Environmental Quality 32 CET containment event tree 33 CFE early containment failure 34 CFR Code of Federal Regulations xxvii

Abbreviations and Acronyms 1 cfs cubic foot (feet) per second 2 CLB current licensing basis/bases 3 CO carbon monoxide 4 CO2 carbon dioxide 5 CO2/MWh carbon dioxide per megawatt hour 6 COL combined license 7 CVCS chemical and volume control system 8 CWA Clean Water Act 9 div. Division 10 DLOOP dual unit loss(es) of offsite power 11 DMS Diverse Mitigation System 12 DOE U.S. Department of Energy 13 DSIRE Database of State Incentives for Renewables and Efficiency 14 DSM demand-side management 15 ECCS emergency core cooling system 16 EFH essential fish habitat 17 EIA Energy Information Administration 18 EIS environmental impact statement 19 ELPC Environmental Law and Policy Center 20 Elv. elevation 21 EMF electromagnetic field 22 EPA U.S. Environmental Protection Agency 23 EPRI Electric Power Research Institute 24 EPZ emergency planning zone 25 ER Environmental Report 26 ERC Energy Recovery Council 27 ES Environmental Services 28 ESA Endangered Species Act of 1973, as amended 29 ESF engineered safety feature 30 ESFAS engineered safety features actuation system 31 ESP early site permit 32 ESW emergency service water 33 Exelon Exelon Generation Company, LLC 34 FEIS final environmental impact statement 35 FERC Federal Energy Regulatory Commission xxviii

Abbreviations and Acronyms 1 FESOP Federally Enforceable State Operating Permit 2 FIVE fire-induced vulnerability evaluation 3 FR Federal Register 4 FRN Federal Register notice 5 ft3 cubic foot (feet) 6 FW feedwater 7 FWCA Fish and Wildlife Coordination Act of 1934, as amended 8 FWS U.S. Fish and Wildlife Service 9 GEIS generic environmental impact statement 10 GI generic issue 11 GL generic letter 12 gpd gallon(s) per day 13 gpm gallon(s) per minute 14 ha hectare(s) 15 HCLPF high confidence in low probability of failure 16 HEP human error probability 17 HFE human failure event 18 HFO high winds, floods, and other 19 HRA human reliability analysis 20 HX heat exchanger 21 IDNR Illinois Department of Natural Resources 22 IDOT Illinois Department of Transportation 23 IDPH Illinois Department of Public Health 24 IEA International Energy Agency 25 IEPA Illinois Environmental Protection Agency 26 IGCC integrated gasification combined-cycle 27 IHPA Illinois Historic Preservation Agency 28 ILCS Illinois Compiled Statutes 29 INEEL Idaho National Engineering and Environmental Laboratory 30 IPE individual plant examination 31 IPEEE individual plant examination(s) of external events 32 ISLOCA interfacing-systems loss-of-coolant accident 33 JHEP joint human error probability 34 km kilometer(s) 35 kW kilowatt(s) xxix

Abbreviations and Acronyms 1 kWe kilowatt(s) electric 2 kWh/m2/d kilowatt hours per square meter per day 3 lb pound(s) 4 LER large early release 5 LERF large early release frequency 6 LMFW loss of main feedwater 7 LOCA loss-of-coolant accident 8 LOOP loss(es) of offsite power 9 Lpd liters per day 10 LRA license renewal application 11 LSCS LaSalle County Station, Units 1 and 2 12 m/s meter(s) per second 13 m3 cubic meter(s) 14 MAAP Modular Accident Analysis Program 15 MACCS2 MELCOR Accident Consequence Code System 2 16 MACR maximum averted cost risk 17 MATS Mercury and Air Toxics Standards 18 MCR main control room 19 mgd million gallons per day 20 mi mile(s) 21 MISO Midcontinent Independent System Operator 22 MMPA Marine Mammal Protection Act 23 MOV motor-operated valve 24 mph mile(s) per hour 25 MSA Magnuson-Stevens Fishery Conservation and Management Act, 26 as amended through 2006 27 MUR measurement uncertainty recapture 28 MW megawatt(s) 29 MWe megawatt(s) electric 30 MWh megawatt hour(s) 31 MWt megawatt(s) thermal 32 NEIS National Energy Information Service 33 NEPA National Environmental Policy Act of 1969, as amended 34 NETL National Energy Technology Laboratory 35 NGCC natural gas combined-cycle xxx

Abbreviations and Acronyms 1 NHPA National Historic Preservation Act of 1966, as amended 2 NMFS National Marine Fisheries Service (of the National Oceanic and 3 Atmospheric Administration) 4 NO2 nitrogen dioxide 5 NOx nitrogen oxide(s) 6 NPDES National Pollutant Discharge Elimination System 7 NRC U.S. Nuclear Regulatory Commission 8 NREL National Renewable Energy Laboratory 9 NRR Nuclear Reactor Regulation, Office of (NRC) 10 O3 ozone 11 OECR offsite economic cost risk 12 ORNL Oak Ridge National Laboratory 13 Pb lead 14 PDR population dose risk 15 PDS plant damage state 16 PEIS programmatic environmental impact statement 17 PL public law 18 PNNL Pacific Northwest National Laboratory 19 PORV power-operated relief valve 20 PRA probabilistic risk assessment 21 PV photovoltaic 22 PWR pressurized water reactor 23 RAI request(s) for additional information 24 RCP reactor coolant pump 25 RCRA Resource Conservation and Recovery Act of 1976, as amended 26 rem roentgen equivalent(s) man 27 RHR residual heat removal 28 ROI region(s) of influence 29 RPC replacement power cost 30 RPS reactor protection system 31 RPV reactor pressure vessel 32 RRW risk reduction worth 33 RTO Regional Transmission Organization 34 RWST refueling water storage tank 35 SAMA severe accident mitigation alternative xxxi

Abbreviations and Acronyms 1 SAT system auxiliary transformer 2 SBO station blackout 3 SCPC supercritical pulverized coal 4 SEIS supplemental environmental impact statement 5 SER safety evaluation report 6 SG steam generator 7 SGTR steam generator tube rupture 8 SI safety injection 9 SMA seismic margin assessment 10 SO2 sulfur dioxide 11 SR supporting requirement 12 SSC structure, system, and component 13 SSEL Safe Shutdown Equipment List 14 Sv sievert(s) 15 SW service water 16 SX essential service water 17 syngas synthesis gas 18 TAC technical assignment control 19 TEEIC Tribal Energy and Environmental Information Clearinghouse 20 TS technical specification 21 U.S. United States 22 U.S.C. United States Code 23 UAT unit auxiliary transformer 24 UFSAR updated final safety analysis report 25 USDA U.S. Department of Agriculture 26 USGS U.S. Geological Survey 27 yd 3 cubic yard(s) 28 W/m2 watt(s) per square meter xxxii

1

1.0 INTRODUCTION

2 Under the U.S. Nuclear Regulatory Commissions (NRCs) environmental protection regulations 3 in Part 51 of Title 10 of the Code of Federal Regulations (10 CFR Part 51)which implement 4 the National Environmental Policy Act (NEPA)the issuance or renewal of a nuclear power 5 plant operating license requires the preparation of an environmental impact statement (EIS). 6 The Atomic Energy Act of 1954 (AEA) specified that licenses for commercial power reactors can 7 be granted for up to 40 years. NRC regulations (10 CFR 54.31) allow for an option to renew a 8 license for up to an additional 20 years. The initial 40-year licensing period was based on 9 economic and antitrust considerations rather than on technical limitations of the nuclear facility. 10 The decision to seek a license renewal rests entirely with nuclear power facility owners and, 11 typically, is based on the facilitys economic viability and the investment necessary to continue 12 to meet NRC safety and environmental requirements. The NRC makes the decision to grant or 13 deny license renewal based on whether the applicant has demonstrated that the environmental 14 and safety requirements in the agencys regulations can be met during the period of extended 15 operation. 16 1.1 Proposed Federal Action 17 Exelon Generation Company, LLC (Exelon), initiated the proposed Federal action by submitting 18 an application for license renewal of LaSalle County Station, Units 1 and 2 (LSCS), for which 19 the existing licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023. 20 The NRCs Federal action is to decide whether to renew the licenses for an additional 20 years. 21 1.2 Purpose and Need for Proposed Federal Action 22 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 23 option that allows for power generation capability beyond the term of a current nuclear power 24 plant operating license to meet future system generating needs, as such needs may be 25 determined by other energy-planning decisionmakers. This definition of purpose and need 26 reflects the NRCs recognition that, unless there are findings in the safety review required by the 27 AEA or findings in the NEPA environmental analysis that would lead the NRC to reject a license 28 renewal application (LRA), the NRC does not have a role in the energy-planning decisions of 29 state regulators and utility officials as to whether a particular nuclear power plant should 30 continue to operate. 31 1.3 Major Environmental Review Milestones 32 Exelon submitted an Environmental Report (ER) (Exelon 2014a) as part of its 33 LRA (Exelon 2014b) in December 2014. After reviewing the LRA and ER for sufficiency, the 34 NRC staff published a Federal Register Notice of Acceptability and Opportunity for Hearing 35 (Volume 80 of the Federal Register (FR), page 5822 (80 FR 5822)) on February 3, 2015. Also, 36 on February 3, 2015, the NRC published another notice in the Federal Register (80 FR 5793) on 37 the intent to conduct scoping, thereby beginning the 60-day scoping period. 38 The NRC staff held two public scoping meetings on March 10, 2015, in Ottawa, Illinois. In a 39 letter dated July 2, 2015, the NRC issued a report entitled, Environmental Impact Statement 40 Scoping Process Summary Report, LaSalle County Station, Units 1 and 2, Brookfield Township, 1-1

Introduction 1 LaSalle County, IL, which includes both the comments received during the scoping process 2 and the NRC staffs responses to those comments (NRC 2015a). 3 In order to independently verify information provided in the ER, the NRC staff conducted a site 4 audit at LSCS in May 2015. During the site audit, the NRC staff met with plant personnel, 5 reviewed specific documentation, toured the facility, and met with interested local agencies. In 6 a letter dated May 20, 2015, the NRC summarized that site audit and listed the attendees 7 (NRC 2015b). 8 Upon completion of the scoping period and site audit, the NRC staff compiled its findings in a 9 draft supplemental environmental impact statement (SEIS). This document is made available 10 for public comment for 45 days. During this time, the NRC staff will host public meetings and 11 collect public comments. Based on the information gathered, the NRC staff will amend the draft 12 SEIS findings, as necessary, and will publish the final SEIS. Figure 1-1 shows the major 13 milestones of the NRCs LRA environmental review process. 14 Figure 1-1. Environmental Review Process 15 16 The NRC has established a license renewal process that can be completed in a reasonable 17 period of time with clear requirements to ensure safe plant operation for up to an additional 18 20 years of plant life. The NRC staff conducts the safety review simultaneously with the 19 environmental review. The NRC staff documents the findings of the safety review in a safety 20 evaluation report (SER). The findings in the SEIS and the SER are both factors in the NRCs 21 decision to either grant or deny the issuance of a renewed license. 22 1.4 Generic Environmental Impact Statement 23 The NRC staff performed a generic assessment of the environmental impacts associated with 24 license renewal to improve the efficiency of its license renewal review. NUREG-1437, Generic 25 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) 1-2

Introduction 1 (NRC 1996, 1999, 2013), documents the results of the NRC staffs systematic approach to 2 evaluate the environmental consequences of renewing the licenses of individual nuclear power 3 plants and operating them for an additional 20 years. The NRC staff analyzed in detail, and 4 resolved, those environmental issues that could be resolved generically in the GEIS. The NRC 5 originally issued the GEIS in 1996, issued Addendum 1 to the GEIS in 1999, and issued 6 Revision 1 to the GEIS in 2013. Unless otherwise noted, all references to the GEIS include 7 Addendum 1 and Revision 1 to the GEIS. 8 The GEIS establishes separate environmental impact issues for the NRC staff to independently 9 verify. Of these issues, the NRC staff determined that some generic issues are generic to all 10 plants (Category 1). Other issues do not lend themselves to generic consideration (Category 2 11 or uncategorized). The NRC staff evaluated these issues on a site-specific basis in the SEIS. 12 Appendix B to Subpart A of 10 CFR Part 51 summarizes the NRC staffs findings in the GEIS. 13 For each potential environmental issue, the NRC staff does the following in the GEIS: 14

  • describes the activity that affects the environment, 15
  • identifies the population or resource that is affected, 16
  • assesses the nature and magnitude of the impact on the affected population or 17 resource, 18
  • characterizes the significance of the effect for both beneficial and adverse effects, 19
  • determines whether the results of the analysis apply to all plants, and 20
  • considers whether additional mitigation measures would be warranted for impacts 21 that would have the same significance level for all plants.

22 The NRC established its standard of significance for impacts using the Council on 23 Environmental Quality terminology for significant. The NRC established three levels of 24 significance for potential impactsSMALL, MODERATE, and LARGE, as defined below. 25 SMALL: Environmental effects are not 26 detectable or are so minor that they will neither Significance indicates the importance of likely environmental impacts and is determined by 27 destabilize nor noticeably alter any important considering two variables: context and intensity. 28 attribute of the resource. Context is the geographic, biophysical, and social 29 MODERATE: Environmental effects are context in which the effects will occur. 30 sufficient to alter noticeably, but not to Intensity refers to the severity of the impact in 31 destabilize, important attributes of the resource. whatever context it occurs. 32 LARGE: Environmental effects are clearly 33 noticeable and are sufficient to destabilize important attributes of the resource. 34 The GEIS includes a determination of whether the analysis of the environmental issue could be 35 applied to all plants and whether additional mitigation measures would be warranted. Issues 36 are assigned a Category 1 or a Category 2 designation. As set forth in the GEIS, Category 1 37 issues are those that meet the following criteria: 38

  • The environmental impacts associated with the issue have been determined to apply 39 either to all plants or, for some issues, to plants having a specific type of cooling 40 system or other specified plant or site characteristics.

41

  • A single significance level (i.e., SMALL, MODERATE, or LARGE) has been assigned 42 to the impacts (except for collective offsite radiological impacts from the fuel cycle 43 and from high-level waste and spent fuel disposal).

1-3

Introduction 1

  • Mitigation of adverse impacts associated with the issue has been considered in the 2 analysis, and it has been determined that additional plant-specific mitigation 3 measures are likely not to be sufficiently beneficial to warrant implementation.

4 For generic issues (Category 1), no additional site-specific analysis is required in the SEIS 5 unless new and significant information is identified. The process for identifying new and 6 significant information for site-specific analysis is presented in Chapter 4. Site-specific issues 7 (Category 2) are those that do not meet one or more of the criteria of Category 1 issues; 8 therefore, additional site-specific review for these issues is required. A site-specific analysis is 9 required for 17 of those 78 issues evaluated in the GEIS. Figure 1-2 illustrates this process. 10 The results of that site-specific review are documented in the SEIS. 11 Figure 1-2. Environmental Issues Evaluated for License Renewal 12 1.5 Supplemental Environmental Impact Statement 13 The SEIS presents an analysis that considers the environmental effects of the continued 14 operation of LSCS, alternatives to license renewal, and mitigation measures for minimizing 15 adverse environmental impacts. Chapter 4 contains analysis and comparison of the potential 16 environmental impacts from alternatives. Chapter 5 presents the NRCs recommendation on 17 whether the environmental impacts of license renewal are so great that preserving the option of 1-4

Introduction 1 license renewal would be unreasonable. The NRC will make its final recommendation after 2 considering comments received on the draft SEIS during the public comment period. 3 In the preparation of the SEIS for LSCS, the NRC staff carried out the following activities: 4

  • reviewed the information provided in Exelons ER; 5
  • consulted with Federal, state, and local agencies, and tribal nations; 6
  • conducted an independent review of the issues during site audit; and 7
  • considered the public comments received for the review (during the scoping 8 process).

9 New information can be identified from many 10 sources, including the applicant, the NRC, other New and significant information. To merit 11 agencies, or public comments. If a new issue is additional review, information must be both new and bear on the proposed action or its impacts, 12 revealed, it is first analyzed to determine whether presenting a seriously different picture of the 13 it is within the scope of the license renewal impacts from those envisioned in the GEIS. 14 environmental evaluation. If the new issue is not 15 addressed in the GEIS, the NRC staff would determine the significance of the issue and 16 document the analysis in the SEIS. 17 1.6 Decisions to Be Supported by the SEIS 18 The decision to be supported by the SEIS is whether to renew the operating licenses for LSCS 19 for an additional 20 years. The NRC decision standard is specified in 10 CFR 51.103(a)(5), as 20 follows: 21 In making a final decision on a license renewal action pursuant to Part 54 22 of this chapter, the Commission shall determine whether or not the 23 adverse environmental impacts of license renewal are so great that 24 preserving the option of license renewal for energy planning 25 decisionmakers would be unreasonable. 26 There are many factors that the NRC takes into consideration when deciding whether to renew 27 the operating license of a nuclear power plant. The analyses of environmental impacts 28 evaluated in this GEIS will provide the NRCs decisionmaker (in this case, the Commission) with 29 important environmental information for use in the overall decisionmaking process. There are 30 also decisions outside the regulatory scope of license renewal that cannot be made on the basis 31 of the GEIS analysis. These decisions include the following issues: changes to plant cooling 32 systems, disposition of spent nuclear fuel, emergency preparedness, safeguards and security, 33 need for power, and seismicity and flooding (NRC 2013). 34 1.7 Cooperating Agencies 35 During the scoping process, no Federal, state, or local agencies were identified as cooperating 36 agencies in the preparation of this SEIS. 37 1.8 Consultations 38 The Endangered Species Act of 1973, as amended (ESA) (16 U.S.C. 1531 et seq.); the 39 Magnuson-Stevens Fisheries Conservation and Management Act of 1996, as amended (MSA) 40 (16 U.S.C. 1801 et seq.); and the National Historic Preservation Act of 1966, as amended 41 (NHPA) (16 U.S.C. 470 et seq.), require Federal agencies to consult with applicable state and 1-5

Introduction 1 Federal agencies and groups before taking action that may affect endangered species, 2 fisheries, or historic and archaeological resources, respectively. The NRC consulted with the 3 following agencies and groups; Appendix C provides a discussion of the consultation 4 documents: 5

  • U.S. Fish and Wildlife Service (FWS);

6

  • Illinois Historic Preservation Agency; 7
  • Advisory Council on Historic Preservation; 8
  • Ho-Chunk Nation; 9
  • Miami Tribe of Oklahoma; 10
  • Peoria Tribe of Indians of Oklahoma; 11
  • Citizen Potawatomi Nation; 12
  • Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki Nation; 13
  • Sac and Fox Nation of Missouri in Kansas and Nebraska; 14
  • Sac and Fox Nation; 15
  • Pokagon Band of Potawatomi; 16
  • Forest County Potawatomi; 17
  • Hannahville Indian Community, Band of Potawatomi; 18
  • Prairie Band Potawatomi Nation; 19
  • Winnebago Tribe of Nebraska; 20
  • Kickapoo Tribe in Kansas; and 21
  • Kickapoo Tribe of Oklahoma.

22 1.9 Correspondence 23 During the course of the environmental review, the NRC staff contacted Federal, state, regional, 24 local, and tribal agencies listed in Section 1.8. Appendix C lists the correspondence associated 25 with the ESA, MSA, and NHPA. Appendix D lists all other correspondence. 26 1.10 Status of Compliance 27 Exelon is responsible for complying with all NRC regulations and other applicable Federal, 28 state, and local requirements. Appendix F of the GEIS describes some of the major applicable 29 Federal statutes. There are numerous permits and licenses issued by Federal, state, and local 30 authorities for activities at LSCS. Appendix B contains further information about LSCSs status 31 of compliance. 32 1.11 Related Federal and State Activities 33 The NRC reviewed the possibility that activities of other Federal agencies might impact the 34 renewal of the operating licenses for LSCS. There are no Federal projects that would make it 35 necessary for another Federal agency to become a cooperating agency in the preparation of 36 this SEIS. 1-6

Introduction 1 There are no known American Indian lands within 50 miles (mi) (80 kilometers (km)) of the 2 LSCS. There are three Federally owned facilities within 50 mi (80 km) of the LSCS: (1) Fermi 3 National Accelerator Laboratory, (2) Argonne National Laboratory, and (3) Joliet Army 4 Ammunition Plant. 5 Section 102(2)(C) of NEPA requires the NRC to consult with, and obtain comments from, any 6 Federal agency that has jurisdiction by law or special expertise with respect to any 7 environmental impact involved in the subject matter of the SEIS. For example, during the 8 course of preparing the SEIS, the NRC consulted with the FWS. Appendix C lists all 9 consultation correspondences. 10 1.12 References 11 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 12 protection regulations for domestic licensing and related regulatory functions. 13 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 14 renewal of operating licenses for nuclear power plants. 15 80 FR 5793. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 16 notice of intent to prepare an environmental impact statement and conduct the scoping process; 17 public meetings and request for comment. Federal Register 80(22):5793-5795. 18 February 3, 2015. 19 80 FR 5822. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 20 license renewal application; opportunity to request a hearing and to petition for leave to 21 intervene. Federal Register 80(22):5822-5825. February 3, 2015. 22 Atomic Energy Act of 1954, as amended. 42 U.S.C. §2011 et seq. 23 Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 24 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 25 Operating License Renewal Stage, LaSalle County Station. Exelon. December 9, 2014. 26 Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 27 ML14343A897. 28 [Exelon] Exelon Generation Company, LLC. 2014b. License Renewal Application, LaSalle 29 County Station, Units 1 and 2. Exelon. December 9, 2014. ADAMS No. ML14343A849. 30 Magnuson-Stevens Fishery Conservation and Management Act of 1996, as amended. 31 16 U.S.C. §1801 et seq. 32 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 33 National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq. 34 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement 35 for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG-1437, 36 Volumes 1 and 2. May 31, 1996. ADAMS Nos. ML040690705 and ML040690738. 37 [NRC] U.S. Nuclear Regulatory Commission. 1999. Section 6.3Transportation, Table 9.1, 38 Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants. 39 In: Generic Environmental Impact Statement for License Renewal of Nuclear Plants. 40 Washington, DC: NRC. NUREG-1437, Volume 1, Addendum 1. August 1999. ADAMS 41 No. ML040690720. 1-7

Introduction 1 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 2 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Revision 1, 3 Volumes 1, 2, and 3. June 19, 2013. ADAMS No. ML13107A023. 4 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Letter from BD Wittick (NRC), Branch 5 Chief, to MP Gallagher (Exelon).

Subject:

Issuance of Scoping Summary Report Associated 6 with the LaSalle County Station, Units 1 and 2, License Renewal Application Environmental 7 Review (TAC Nos. MF5567 and MF5568). July 2, 2015. ADAMS No. ML15147A380. 8 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Letter from BD Wittick (NRC), Branch 9 Chief, to MP Gallagher (Exelon).

Subject:

Summary of the License Renewal Environmental 10 Audit for LaSalle County Station, Units 1 and 2 (TAC Nos. MF5567 and MF5568). 11 May 20, 2015. ADAMS No. ML15132A674. 1-8

1 2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION 2 Although the U.S. Nuclear Regulatory Commissions (NRCs) decisionmaking authority in 3 license renewal is limited to deciding whether or not to renew a nuclear power plants operating 4 license, the NRCs implementation of the National Environmental Policy Act of 1969 (NEPA), as 5 amended (42 U.S.C. 4321 et seq.), requires consideration of the environmental impacts of 6 potential alternatives to renewing a plants operating license. While the ultimate decision about 7 which alternative (or the proposed action) to carry out falls to operator, state, or other non-NRC 8 Federal officials, comparing the impacts of renewing the operating license to the environmental 9 impacts of alternatives allows the NRC to determine whether the environmental impacts of 10 license renewal are so great that preserving the option of license renewal for energy-planning 11 decisionmakers would be unreasonable (Title 10 of the Code of Federal Regulations 12 (10 CFR) 51.95(c)(4)). 13 Energy-planning decisionmakers and owners of the nuclear power plant ultimately decide 14 whether the plant will continue to operate, and economic and environmental considerations play 15 important roles in this decision. In general, the NRCs responsibility is to ensure the safe 16 operation of nuclear power facilities and not to formulate energy policy or encourage or 17 discourage the development of alternative power generation. The NRC does not engage in 18 energy-planning decisions and makes no judgment as to which energy alternatives evaluated 19 would be the most likely alternative in any given case. 20 The remainder of this chapter provides (1) a description of the proposed action, (2) a description 21 of alternatives to the proposed action (including the no-action alternative), and (3) alternatives to 22 LaSalle County Station, Units 1 and 2 (LSCS) license renewal that were considered and 23 eliminated from detailed study. Chapter 4 of this plant-specific supplemental environmental 24 impact statement (SEIS) compares the impacts of renewing the operating licenses of LSCS and 25 continued plant operations to the environmental impacts of alternatives. 26 2.1 Proposed Action 27 As stated in Section 1.1 of this document, the NRCs proposed Federal action is the decision of 28 whether to renew the LSCS operating licenses for an additional 20 years. For the NRC to 29 determine the impacts from continued operation of LSCS, an understanding of that operation is 30 needed. Section 2.1.1 describes normal power plant operations during the license renewal 31 term. LSCS is a two-unit, nuclear-powered steam-electric generating facility that began 32 commercial operation in January 1984 (Unit 1) and October 1984 (Unit 2). The nuclear reactors 33 at both units are General Electric boiling water reactors (BWRs), and together they produce an 34 annual average net output of 2,327 megawatts electric (MWe) (Exelon 2014). 35 2.1.1 Plant Operations during the License Renewal Term 36 Most plant operation activities during license renewal would be the same as, or similar to, those 37 occurring during the current license term (NRC 2013). Section 2.1.1 of NUREG-1437, Generic 38 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS), 39 Revision 1 (NRC 2013), describes the general types of activities that are carried out during the 40 operation of a nuclear power plant, such as LSCS, as follows: 41

  • reactor operation; 42
  • waste management; 2-1

Alternatives Including the Proposed Action 1

  • security; 2
  • office and clerical work; 3
  • surveillance, monitoring, and maintenance; and 4
  • refueling and other outages.

5 As stated in the Exelon Generation Company, LLCs (Exelons) Environmental Report (ER) 6 (Exelon 2014), LSCS will continue to operate during the license renewal term in the same 7 manner as it does during the current license term except for, as appropriate, additional aging 8 management programs to address structure and component aging in accordance with 9 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants. 10 2.1.2 Refurbishment and Other Activities Associated with License Renewal 11 Refurbishment activities include replacement and repair of major systems, structures, and 12 components. For example, replacement activities may include replacement of recirculation 13 piping systems for BWRs. The intent of the major refurbishment class of activities characterized 14 in the GEIS (NRC 2013) is to encompass actions that typically take place only once in the life of 15 a nuclear plant, if at all. Refurbishment activities may have an impact on the environment 16 beyond those that occur during normal operations and may require evaluation depending on the 17 type of action and the plant-specific design. 18 In preparation for its license renewal application, Exelon performed an evaluation of LSCS 19 structures, systems, and components in accordance with 10 CFR 54.21, Contents of 20 applicationtechnical information, to identify whether any major refurbishment activities would 21 be necessary to support the continued operation of LSCS during the proposed 20-year period of 22 extended operation (Exelon 2014). 23 Exelon did not identify any major refurbishment or replacement activities needed to support the 24 continued operation of LSCS beyond the existing operating license term (Exelon 2014). 25 Therefore, these activities are not discussed under the proposed action in Chapter 4. 26 2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning after the 27 License Renewal Term 28 NUREG-0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear 29 Facilities: Supplement 1, Regarding the Decommissioning of Nuclear Power Reactors, 30 describes the impacts of decommissioning (NRC 2002). Most activities associated with plant 31 operations would cease with reactor shutdown. Some activities (e.g., security and oversight of 32 spent nuclear fuel) would remain unchanged, whereas others (e.g., waste management; office 33 and clerical work; laboratory analysis; and surveillance, monitoring, and maintenance) would 34 continue at reduced or altered levels. Systems dedicated to reactor operations would cease 35 operations; however, impacts from their physical presence may continue if they are not removed 36 after reactor shutdown. For multiple-unit sites, such as LSCS, shared systems may operate at 37 reduced capacities. Impacts associated with dedicated systems that remain in place or shared 38 systems that continue to operate at normal capacities would remain unchanged. 39 Decommissioning will occur whether LSCS is shut down at the end of its current operating 40 license term or at the end of the period of extended operation. There are no site-specific issues 41 related to decommissioning. The license renewal GEIS concludes that license renewal would 42 have a negligible (SMALL) effect on the impacts of terminating operations and decommissioning 43 on all resources. 2-2

Alternatives Including the Proposed Action 1 2.2 Alternatives 2 As stated above, the NRC has the obligation to consider reasonable alternatives to the 3 proposed action of renewing the licenses for the nuclear reactors at LSCS. To be reasonable, a 4 replacement power alternative must be commercially viable on a utility scale and operational 5 prior to the expiration of the reactors operating licenses, or expected to become commercially 6 viable on a utility scale and operational prior to the expiration of the reactors operating licenses 7 (NRC 2013). The 2013 GEIS update incorporated the latest information on replacement power 8 alternatives; however, rapidly evolving technologies are likely to outpace the information 9 presented in the GEIS. As such, a site-specific analysis of alternatives must be performed for 10 each SEIS, taking into account changes in technology and science since the preparation of the 11 GEIS. 12 Section 2.2.1 below describes the no-action alternative (i.e., the NRC takes no action and does 13 not issue renewed licenses for LSCS). Sections 2.2.2.1-2.2.2.5 describe the characteristics of 14 replacement power alternatives for LSCS. 15 2.2.1 No-Action Alternative 16 At some point, operating nuclear power plants will terminate operations and undergo 17 decommissioning. The no-action alternative represents a decision by the NRC not to renew the 18 operating license of a nuclear power plant beyond the current operating license term. Under the 19 no-action alternative, the NRC does not renew the operating licenses, and the LSCS plant shuts 20 down at or before the end of the current licenses in 2022 and 2023. After shutdown, plant 21 operators will initiate decommissioning in accordance with 10 CFR 50.82, Termination of 22 License. 23 Only those impacts that arise directly as a result of plant shutdown will be addressed in this 24 SEIS. The environmental impacts from decommissioning and related activities are addressed in 25 several other documents, including the decommissioning GEIS (NRC 2002); the license renewal 26 GEIS, Chapter 4 (NRC 2013); and Chapter 4 of this SEIS. These analyses either directly 27 address or bound the environmental impacts of decommissioning whenever Exelon ceases to 28 operate LSCS. 29 Even with renewed operating licenses, LSCS will eventually shut down, and the 30 environmental impacts addressed later in Chapter 4 of this SEIS will occur at that time. 31 As with decommissioning impacts, shutdown impacts are expected to be similar whether they 32 occur at the end of the current license term or at the end of a renewed license term. 33 Termination of operations at LSCS would result in the total cessation of electrical power 34 production. Unlike the alternatives described in Section 2.2.2, the no-action alternative does not 35 meet the purpose and need of the proposed action because it does not provide a means of 36 delivering baseload power to meet future electric system needs. Given the current need for the 37 power generated by LSCS, the no-action alternative would likely create a need for a 38 replacement power alternative. A full range of replacement power alternatives (including new 39 nuclear, fossil fuels, and renewable energy sources) are described in the following section, and 40 their potential impacts are assessed in Chapter 4. Although the NRCs authority only extends to 41 the decision of whether to renew the LSCS operating licenses, the replacement power 42 alternatives described in the following sections represent possible options for energy-planning 43 decisionmakers should the NRC choose not to renew the LSCS operating licenses. 2-3

Alternatives Including the Proposed Action 1 2.2.2 Replacement Power Alternatives 2 In evaluating alternatives to license renewal, the NRC considered energy technologies or 3 options currently in commercial operation, as well as technologies not currently in commercial 4 operation but likely to be commercially available by the time the current LSCS operating 5 licenses expire. The current operating licenses for the LSCS, Units 1 and 2, expire on 6 April 17, 2022, and December 16, 2023, respectively. Alternatives that are not likely to be 7 constructed, permitted, and connected to the grid by the time the LSCS licenses expire were 8 eliminated from detailed consideration. 9 Alternatives that cannot provide the equivalent of LSCSs current generating capacity and, in 10 some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 11 reasonable alternatives, were not considered in detail. Each alternative eliminated is briefly 12 discussed, and the basis for its elimination is provided in Section 2.3. In total, 17 alternatives to 13 the proposed action were considered (see text box) and then narrowed to the 5 alternatives 14 considered in Sections 2.2.2.1-2.2.2.5. The NRC staff evaluated the environmental impacts of 15 these five alternatives and the no-action alternative. They are discussed in depth in Chapter 4 16 of this SEIS. 17 The GEIS presents an overview of some energy technologies but does not reach conclusions 18 about which alternatives are most appropriate. Because many energy technologies are 19 continually evolving in capability and cost and because regulatory structures have changed to 20 either promote or impede development of particular alternatives, the analyses in this chapter 21 may include updated information from the following sources: 22

  • U.S. Department of Energy (DOE), U.S. Energy Information Administration (EIA),

23

  • other offices within the DOE, 24
  • U.S. Environmental Protection Agency (EPA),

25

  • industry sources and publications, and 26
  • information submitted by Exelon in its ER.

27 The evaluation of each alternative in Chapter 4 of this SEIS considers the environmental 28 impacts across several impact categories: land use and visual resources, air quality and noise, 29 geologic environment, water resources, ecological resources, historic and cultural resources, 30 socioeconomics, human health, environmental justice, and waste management. Most 31 site-specific issues (Category 2) have been assigned a significance level of SMALL, 32 MODERATE, or LARGE. For ecological and historic and archaeological resources, the impact 33 significance determination language is specific to the authorizing legislation (e.g., Endangered 34 Species Act of 1973, as amended (16 U.S.C. 1531 et seq.), and National Historic Preservation 35 Act of 1966, as amended (16 U.S.C. 470 et seq.)). The order of presentation of the alternatives 36 is not meant to imply increasing or decreasing level of impact. Nor does it imply that an 37 energy-planning decisionmaker would be more likely to select any given alternative. 38 To ensure that the alternatives analysis is consistent with state or regional energy policies, the 39 NRC reviewed energy-related statutes, regulations, and policies within the LSCS region. As a 40 result, the staff considers alternatives that include wind power or solar photovoltaic (PV) power, 41 as well as a combination that includes both of them. 42 Region of Influence 43 LSCS is owned and operated by Exelon and provides electricity to the region of influence (ROI) 44 through transmission lines owned by Commonwealth Edison (ComEd) (Exelon 2014). ComEd 2-4

Alternatives Including the Proposed Action 1 operates under the PJM Interconnection, LLC Alternatives Evaluated in Depth: 2 (PJM), a regional transmission organization 3 that coordinates the movement of wholesale

  • new nuclear 4 electricity in 13 states across the Midwest
  • coal-integrated gasification combined-cycle 5 and Northeast (Exelon 2014). ComEd
  • natural gas combined-cycle 6 provides service to 3.8 million customers
  • combination alternative (wind power, natural gas 7 across northern Illinois. Its service territory combined-cycle, and solar power) 8 borders Iroquois County to the south, the
  • purchased power 9 Wisconsin border to the north, the Iowa 10 border to the west, and the Indiana border to Other Alternatives Considered:

11 the east (ComEd 2015). However, electricity 12 consumption in Illinois is not limited to

  • energy efficiency and conservation 13 electricity that is generated within the State.
  • solar power 14 Although northern Illinois relies on electricity
  • wind power 15 from ComEd, the rest of Illinois and
  • biomass 16 surrounding states, which are not part of the
  • hydroelectric power 17 PJM, are part of the Midcontinent
  • wave and ocean energy 18 Independent System Operator, Inc. (MISO)
  • fuel cells 19 (see Figure 2-1) (Exelon 2014).
  • delayed retirement 20 If renewed licenses were not issued,
  • geothermal power 21 replacement power for LSCS would be
  • municipal solid waste 22 required in northern Illinois. Electricity could
  • petroleum 23 be replaced by generation sources from a
  • supercritical pulverized coal 24 variety of locations. Electricity could be 25 transported from within the PJM; however, the PJM in Illinois is geographically distant from the 26 rest of the PJM region (see Figure 2-1). It is also possible that electricity within MISO could be 27 purchased by PJM, and efforts are currently being made to increase coordination and 28 deliverability between the regional transmission organizations (Ott 2013b). In addition, the State 29 of Illinois has a renewable portfolio standard that includes a stipulation that eligible renewable 30 resources must be procured from facilities located in Illinois or the States that adjoin Illinois 31 (Wisconsin, Indiana, Iowa, Kentucky, Michigan, and Missouri) (ILGA 2011). Renewable 32 resources can be obtained only from other regions of the country if they are not available in 33 Illinois or in the adjoining States (ILGA 2011).

34 Because replacement power would be required in northern Illinois, and any renewable energy 35 resources would need to be procured from facilities in Illinois or the adjoining States, the NRC 36 staff evaluated the impacts of locating replacement power facilities within the States of Illinois, 37 Indiana, Iowa, Kentucky, Michigan, Missouri, and Wisconsin. These seven states constitute the 38 ROI for the NRC staffs analysis of alternatives. The NRC assumes that replacement power 39 would either be produced in northern Illinois within the PJM region or would be purchased by 40 PJM from MISO. 41 In 2012, electric generators in the ROI had a net summer generating capacity of approximately 42 179,000 megawatts (MW). This capacity included units fueled by coal (49 percent), natural gas 43 (27 percent), nuclear (11 percent), and wind (6.6 percent) (EIA 2014c). 44 In 2011, the electric industry in the ROI provided approximately 744 million megawatt hours 45 (MWh) of electricity. Electricity produced in the ROI was dominated by coal (67 percent) and 46 nuclear (21 percent). Although natural gas makes up nearly 30 percent of the installed 47 generating capacity in the ROI, it provides only 6 percent of electricity in the region. 48 Nonhydroelectric renewable energy produced 1.3 percent of the electricity in the ROI 49 (EIA 2014b). 2-5

Alternatives Including the Proposed Action 1 Figure 2-1. Territories of MISO and PJM Interconnection 2 Source: MISO-PJM undated 3 Renewable Energy Legislation in the Region of Influence 4 Renewable energy legislation in Illinois allows the purchase of electricity generation in adjoining 5 States; therefore, any legislation targeting renewable energy in these States could impact a 6 States incentive to develop renewable resources. Five States in the ROI (Illinois, Iowa, 7 Missouri, Wisconsin, and Michigan) have legally mandated renewable energy programs. The 8 State of Indiana has a voluntary program, and State of Kentucky does not have any renewable 9 energy requirements. The paragraphs below briefly outline each States program, including 10 renewable energy goals and benchmarks. 11 In August 2007, Illinois adopted a renewable portfolio standard that requires the States utilities 12 to produce at least 25 percent of their power from renewable sources by 2025, 75 percent of 13 which must come from wind. Solar PV must comprise 6 percent of the annual requirement for 14 calendar year 2015 and thereafter. Other eligible sources include biomass and existing 15 hydroelectric power (DSIRE 2015a). The law also includes an energy efficiency standard that 16 requires utilities to implement cost-effective energy efficiency measures to meet energy savings 17 of 1 percent by calendar year 2016 and thereafter (ILGA 2011). For electric utilities (including 18 ComEd), eligible resources must be located in Illinois; resources can be purchased from 19 adjoining States only if there are insufficient in-State resources (ILGA 2011). 20 Iowas Alternative Energy Production Law requires the States two investor-owned utilities to 21 generate a combined total of 105 MW of their generating capacity from renewable energy 22 sources. A 2007 order allows the utilities to participate in renewable energy credit trading 23 programs by distinguishing between renewable electricity production capacity used to comply 24 with Iowa law and that which can be used to satisfy other states renewable portfolio standards 25 (DSIRE 2014). 26 Missouri adopted a renewable portfolio standard that requires investor-owned utilities to 27 increase their use of renewable sources by 15 percent by 2021 and includes a provision 28 specifying that 2 percent of the renewable portfolio standard requirement must be met by solar 29 energy. Resources can be purchased from outside Missouri, but renewable energy generated 30 in-State receives a multiplier of 1.25 compared to out-of-State generation (DSIRE 2015b). 2-6

Alternatives Including the Proposed Action 1 Wisconsins renewable portfolio standard requires utilities to produce 10 percent of their 2 electricity from renewable sources by 2015. Included in the renewable portfolio standard is a 3 provision that allows electricity providers to create and sell or transfer renewable resource 4 credits and renewable energy certificates. Renewable energy generated outside Wisconsin is 5 eligible, provided that the electricity is distributed to Wisconsin customers (DSIRE 2015c). 6 Michigan enacted a Renewable Energy Standard in 2008 that requires utilities to generate 7 10 percent of their retail electricity sales from renewable energy resources by 2015. 8 The standard also allows energy efficiency and advanced cleaner energy systems to meet part 9 of the requirement. Renewable energy credits can be purchased from in-State or out-of-State 10 facilities, provided that the facilities are located within the retail electric service territory of a 11 utility that is recognized by the Michigan Public Service Commission (DSIRE 2015d). 12 Indiana does not have a mandatory renewable or alternative energy portfolio standard. On 13 July 9, 2012, Indiana adopted a Clean Energy Portfolio Standard, which sets a voluntary goal of 14 10 percent clean energy by 2025, based on the amount of electricity supplied by the utility in 15 2010. Unlike many of the other ROI states, up to 30 percent of the goal may be met with clean 16 coal technology, nuclear energy, combined heat and power systems, natural gas that displaces 17 electricity from coal, and net-metered distributed generation facilities. Fifty percent of qualifying 18 energy must come from within the State. Utilities that participate in the program and meet the 19 program goals are eligible for incentives that are used to pay for the compliance projects 20 (DSIRE 2015e). 21 Kentucky is the only State in the ROI that does not have mandatory or voluntary renewable 22 energy requirements. 23 Given known technological and demographic trends, the EIA predicts that 34 percent of 24 electricity in the United States will be generated by coal in 2040 (EIA 2015). Natural gas 25 generation rose from 16 percent in 2000 to 27 percent in 2013 and is projected to increase to 26 31 percent in 2040 (EIA 2013a, 2015). Electricity generation from renewable energy is 27 expected to grow from 13 percent of total generation in 2013 to 18 percent in 2040 (EIA 2015). 28 However, there are uncertainties that could affect this forecast, particularly the implementation 29 of policies aimed at reducing greenhouse gas emissions, which would have a direct effect on 30 fossil fuel-based generation technologies. 31 The remainder of this section describes replacement power alternatives to license renewal 32 considered in depth. These include a new nuclear alternative in Section 2.2.2.1; a 33 coal-integrated gasification combined-cycle (IGCC) alternative in Section 2.2.2.2; a natural gas 34 combined-cycle (NGCC) alternative in Section 2.2.2.3; a combination natural gas, wind, and 35 solar power alternative in Section 2.2.2.4; and a purchased power alternative in Section 2.2.2.5. 36 Table 2-1 summarizes key design characteristics of the alternative technologies evaluated in 37 depth. The environmental impacts of these alternatives are evaluated in Chapter 4. 2-7

Alternatives Including the Proposed Action 1 Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 2 Considered in Depth(a) New Nuclear Combination Alternative IGCC Alternative NGCC Alternative Alternative Summary of Two-unit nuclear Four 618-MWe units, Five 560-MWe One 360 MWe Alternative plant, each with for a total of units, for a total of NGCC unit; a 1,120 MWe, for a total 2,472 MWe 2,800 MWe 1,813 MWe wind of 2,240 MWe farm; and a 227 MWe installed solar PV facility, for a total of 2,400 MWe Location An existing nuclear On the LSCS site or On the LSCS site. The NGCC plant site or retired at another existing New transmission component would coal plant site outside power plant site. line(s) and other be located on the Illinois. New New transmission infrastructure LSCS site. The transmission line(s) line(s) and other upgrades may be wind and solar and other infrastructure required; would components would infrastructure upgrades may be require construction be spread across upgrades may be required. Some of a new or multiple sites required. Some facilities (e.g., support upgraded pipeline. throughout the ROI. facilities (e.g., support buildings, potable Some facilities buildings, potable water supply, and (e.g., support water supply, and sanitary discharge buildings, potable sanitary discharge structures) could be water supply, and structures) could be shared with existing sanitary discharge shared with existing plant. structures) could be plant. shared with existing plant. Cooling Closed-cycle with Closed-cycle with Closed-cycle with For the NGCC System natural draft cooling mechanical draft mechanical draft portion, towers. Cooling cooling towers. cooling towers. closed-cycle with water withdrawal Cooling water Cooling water mechanical draft 56 mgd; consumptive withdrawal25 mgd; withdrawal cooling towers. water use42 mgd consumptive water 17 mgd; Cooling water (NRC 2008). use20 mgd consumptive water would be 15% of (NETL 2013a). use13 mgd that required for (NETL 2013a). NGCC alternative. Minimal water use for wind and solar. Land 556 ac (225 ha) 2,000 ac (800 ha) for 94 ac (38 ha) for the Wind farms would Require- (NRC 2008); 520 ac the major permanent plant, including require 3,376 ac ments (210 ha) for uranium facilities; 1,100 ac pipelines (1,366 ha) to mining and (450 ha) per year for (Exelon 2014); 10,127 ac processing(b) mining (DOE 2010a) 10,080 ac (4,098 ha) (WAPA (NRC 2013) (4,079 ha) for gas and FWS 2013); extraction and solar PV facilities collection would require (NRC 1996) 6,749 ac (2,731 ha) (Ong et al. 2013). For the NGCC portion, land use would remain the 2-8

Alternatives Including the Proposed Action New Nuclear Combination Alternative IGCC Alternative NGCC Alternative Alternative same at 94 ac (38 ha) (Exelon 2014). Work Force 3,500 workers during 4,600 workers during 1,783 workers Solar PV peak construction; peak construction; during peak 600 workers during 812 workers during 420 workers during construction; peak construction, operations operations 94 workers during 60 workers during (NRC 2008) (DOE 2010a) operations operations (Exelon 2014) (DOE 2010b). Wind931 workers during construction, 566 workers during operations (DOE 2008). NGCCnumber of construction and operations workers would be less than the NGCC alternative but would not be a linear reduction because of the need for a minimum number of workers regardless of the size of the plant. Key: ac = acres, ha = hectares, IGCC = coal-integrated gasification combined-cycle (alternative), mgd = million gallons per day, MWe = megawatts electric, NGCC = natural gas combined-cycle (alternative), PV = photovoltaic, and ROI = region of influence. (a) Because of the speculative nature of using purchased power to replace LSCS capacity and because of the inherent variability of characteristics associated with such an approach, this table does not include the purchased power alternative. (b) This is normalized to model the light water reactor annual fuel requirement. Forty-two percent of this land requirement is temporarily committed land. Sources: DOE 2008, 2010a, 2010b; Exelon 2014; NETL 2013a; NRC 1996, 2008, 2013; Ong et al. 2013; WAPA and FWS 2013 1 2.2.2.1 New Nuclear Alternative 2 In this section, the NRC staff describes the new nuclear alternative. The NRC staff evaluates 3 the environmental impacts from this alternative in Chapter 4. 4 The NRC staff considered the construction of a new nuclear plant to be a reasonable alternative 5 to license renewal. For example, nuclear generation currently provides 21 percent of electricity 6 generation in the ROI (EIA 2014b). Twelve nuclear power plants operate in the ROI; 7 eight applicants have received renewed licenses, and three additional applicants have applied 8 for renewed licenses from the NRC (including LSCS) (NRC 2015). In addition, there is interest 9 in new nuclear power plant development in the region; combined operating license (COL) 10 applications have been filed for two new nuclear power plants in the ROI. On July 24, 2008, 2-9

Alternatives Including the Proposed Action 1 Union Electric Company submitted a COL application for Callaway Plant, Unit 2, in Callaway 2 County, Missouri, on the existing Callaway site (AmerenUE 2009). However, Ameren UE has 3 since announced that they are canceling their COL application (Barker 2015). An application 4 was also filed in September 2008 for Enrico Fermi Atomic Power Plant, Unit 3, in Monroe 5 County, Michigan, on the existing Fermi site. On May 1, 2015, the NRC issued a COL 6 authorizing DTE Electric Company to build and operate an economic simplified BWR at the 7 Fermi site (Volume 80 of the Federal Register, 26302 (80 FR 26302)). The NRC staff 8 determined that there may be sufficient time for Exelon to prepare and submit an application, 9 build, and operate two new nuclear units using a certified design before the LSCS licenses 10 expire in April 2022 and December 2023. 11 In evaluating the new nuclear alternative, the NRC staff assumed that two new nuclear reactors 12 would be built on an existing nuclear or coal power plant site, allowing for the maximum use of 13 existing ancillary facilities at those locations, such as support buildings and transmission 14 infrastructure. In 1987, Illinois enacted a moratorium preventing the construction of new nuclear 15 power plants within the State. Until the moratorium is lifted, a new nuclear alternative would 16 require siting elsewhere in the ROI. For the purposes of this analysis, the NRC relied on the 17 Vogtle Electric Generating Plant (Vogtle), Units 3 and 4 (located in Waynesboro, Georgia), COL 18 environmental impact statement for technological parameters for the new nuclear alternative 19 because the Vogtle, Units 3 and 4, COL considers two new nuclear reactor units with a similar 20 output as LSCS and is representative of the reactors that could be constructed in the ROI 21 before LSCSs licenses expire (NRC 2011). As such, the NRC staff assumed 22 two Westinghouse AP1000 reactors with a net electrical output of 2,240 MWe would replace 23 LSCSs current reactors for this alternative. The NRC staff estimated that 324 ac (131 ha) of 24 land would be required on a long-term basis because of permanent facilities, and an additional 25 232 ac (94 ha) would be disturbed for temporary facilities, a laydown area, and storage of 26 dredge material (NRC 2008). 27 The heat rejection demands of a new nuclear alternative would be similar to those of LSCS. 28 The new reactors may require a new cooling system (including natural draft cooling towers and 29 intake and discharge structures). The NRC staff assumes that water requirements for the new 30 nuclear alternative would be similar to current water use at LSCS. A new onsite transmission 31 line and drinking water wells may be required if insufficient infrastructure occurs on the site. 32 Construction materials would be delivered by a combination of rail spur, truck, and barge, 33 depending on the specific site location. It is possible that modifications would be required to 34 deliver such materials, depending on the existing infrastructure at the site; modifications could 35 include new rail lines or access roads. 36 The NRC staff also considered the installation of multiple small modular reactors as an 37 alternative to renewing the LSCS licenses. The NRC established the Advanced Reactor 38 Program in the Office of New Reactors because of considerable interest in small modular 39 reactors along with anticipated license applications by vendors. Small modular reactors are 40 approximately 300 MW or less, would have lower initial capacity than that of large-scale units, 41 and would have siting flexibility for locations that are not large enough to accommodate 42 traditional nuclear reactors (DOE undated). As of October 2015, no applications for small 43 modular reactors have been submitted to the NRC. The DOE has estimated that the technology 44 may achieve commercial operation by 2021 to 2025 (DOE undated). Because small modular 45 reactors are not expected to be operational at a commercial scale until near the time LSCSs 46 licenses expire, it is unlikely that eight new small modular reactors (the number of units required 47 to replace LSCSs current output) could be constructed in the ROI; therefore, this analysis 48 focuses on nuclear generation by larger nuclear units. 2-10

Alternatives Including the Proposed Action 1 2.2.2.2 IGCC Alternative 2 In this section, the NRC staff describes the IGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4. 4 Coal provides the greatest share of electrical power in the ROI, and in 2010, coal represented 5 49 percent of installed generation capacity and accounted for 67 percent of all electricity 6 generated in the ROI (EIA 2014b). IGCC is a technology that generates electricity from coal 7 and combines modern coal gasification technology with both gas-turbine and steam-turbine 8 power generation. The technology is cleaner than conventional pulverized coal plants because 9 some of the major pollutants are removed from the gas stream before combustion. An IGCC 10 power plant consists of coal gasification and combined-cycle power generation. Coal gasifiers 11 convert coal into a gas (synthesis gas, also referred to as syngas), which fuels the 12 combined-cycle power generating units. The combined-cycle system for a 618-MWe IGCC 13 power plant includes two combustion turbines, two heat recovery steam generators, and a 14 steam turbine. The combined-cycle units combust gas in one or more combustion turbines, and 15 the resulting hot exhaust gas is then used to heat water into steam to drive a steam turbine. 16 The steam turbine then uses the heat from the gas turbines exhaust through a heat recovery 17 steam generator to produce additional electricity (DOE 2010a). This two-cycle process has a 18 high rate of efficiency because the exhaust heat that would otherwise be lost is captured and 19 reused. In addition, the power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and 20 particulate emissions by removing constituents from the syngas before combustion. Nearly 21 100 percent of the nitrogen from the syngas would be removed before combustion in the gas 22 turbines and would result in lower nitrogen oxide emissions compared to conventional coal-fired 23 power plants (DOE 2010a). 24 IGCC power plants have been in operation since the mid-1990s; the Wabash Rice IGCC 25 repowering project in Indiana and the Polk Power Station in Florida are two examples of 26 operating IGCC plants. Recently, there has been an increased interest in new IGCC projects, 27 and multiple new projects have been proposed or have recently begun operations in the 28 United States. The Duke Energy Edwardsport Generation Station (Edwardsport) in Indiana is a 29 618-MWe IGCC power plant in the ROI that began commercial operation in June 2013. Duke 30 Energy estimates that the IGCC plant will produce 10 times as much power as the retired coal 31 plant it replaced with 70 percent fewer emissions of sulfur dioxide, nitrogen oxides, and 32 particulates. The IGCC plant will reduce carbon emissions per megawatt hour by nearly half 33 compared to conventional coal-fired plants (Duke Energy 2013). In addition, Edwardsport has 34 the potential for carbon capture and geologic sequestration. Space has been reserved at the 35 site for carbon dioxide capture equipment (NETL 2013b). 36 Many IGCC power plants have been designed with carbon capture and storage (CCS) to further 37 reduce carbon dioxide emissions. The Kemper County IGCC project in east-central Mississippi 38 proposes to use CCS to reduce carbon dioxide emissions by almost 70 percent by removing 39 carbon from the syngas post-gasification (DOE 2010a). According to a 2013 National Energy 40 Technology Laboratory (NETL) report, nine IGCC projects totaling over 4,000 MW are currently 41 active; these projects are in the planning stages, or they have begun construction. 42 Thirteen projects have been proposed and subsequently canceled for a variety of reasons, 43 including air quality issues, state laws and regulations, redirected focus on gas-fired generation 44 and renewables, and unanticipated rising costs (NETL 2013c). 45 IGCC technology and proposed projects have experienced a number of setbacks and 46 opposition, hindering IGCCs ability to fully integrate into the energy market. The most 47 significant roadblock is IGCCs high capital cost compared to conventional coal-fired power 48 plants. Cost overruns have been experienced at both the Edwardsport IGCC project and the 2-11

Alternatives Including the Proposed Action 1 Kemper County IGCC project. FutureGen, an IGCC plant featuring CCS, lost DOE financial 2 support because of escalating cost estimates (Reuters 2012). Other issues include construction 3 timeline overruns, a limited track record for reliable performance, and opposition from an 4 environmental perspective. 5 Despite some of the current setbacks and concerns associated with IGCC projects, the NRC 6 staff considers IGCC technology to be a reasonable source of baseload power to replace LSCS 7 by the time its licenses expire in 2022 and 2023 because of the current regulatory framework 8 and the number of active IGCC plants within the ROI. On August 3, 2015, EPA signed a final 9 rule for carbon pollution that would apply to new fossil fuel-fired power plants 10 (80 FR 64661-65120). The action establishes performance standards for utility boilers and 11 IGCC units based on partial implementation of a CCS system as a method of emission 12 reduction. The emission limit for these sources is 1,305 lb carbon dioxide per megawatt hour 13 (CO2/MWh), and any new coal-fired power plants could require CCS in order to achieve this 14 emission limit. 15 Overall, the NRC staff considers IGCC power plants as an alternative to LSCS because the 16 Edwardsport IGCC project in Indiana is currently in operation and because the Kemper County 17 IGCC project in Mississippi is under construction. The technology parameters for these plants 18 are considered the current state of technology and are used here to describe a hypothetical 19 IGCC power plant located on an existing power plant site within the ROI. 20 To replace the electricity that LSCS generates, the NRC staff considered four IGCC units, each 21 with a net capacity of 618 MWe. Various coal sources are available to coal-fired power plants in 22 the ROI. For the purpose of this evaluation, the NRC staff assumes that the IGCC alternative 23 would burn a sub-bituminous coal based on the type of coal used in electric plants in Illinois. 24 The NRC staff presumes that coal burned in Illinois will be representative of coal that would be 25 burned in an IGCC alternative regardless of where it may be located (EIA 2012). The IGCC 26 units would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 27 removing constituents from the syngas. In addition, the units would be designed with the 28 potential to add CCS later. Using CCS, carbon dioxide emission would be compressed and 29 piped off site where it could be sold for beneficial use or geologic storage. 30 The IGCC alternative would be located at an existing site (such as an existing power plant site) 31 to maximize availability of infrastructure and to reduce other environmental impacts. Depending 32 on the specific site location, there might be a need to construct new intake and discharge 33 facilities and a new cooling system. The IGCC alternative would use about the same amount of 34 water as LSCS and a similar amount as the Edwardsport IGCC plant. The NRC staff assumes 35 that the cooling system would use a closed-cycle system with mechanical draft cooling towers. 36 This system would withdraw 25 million gallons per day (gpd) (95 million liters per day (Lpd)) of 37 water and would consume 20 million gpd (76 million Lpd). Onsite visible structures could 38 include the boilers, exhaust stacks, intake and discharge structures, mechanical draft cooling 39 towers, transmission lines, and an electrical switchyard. Construction materials would be 40 delivered by a combination of rail spur, truck, and barge, depending on the specific site location. 41 Modifications may be required to deliver such materials; modifications could include new rail 42 lines or access roads. 43 The NRC staff also considered supercritical pulverized coal (SCPC) as an alternative to 44 renewing the LSCS licenses. SCPC was dismissed as the coal alternative because of new 45 regulations aimed at limiting the environmental impacts from conventional pulverized coal 46 plants. The presence of active IGCC plants in the ROI also contributed to the selection of IGCC 47 for analysis. 2-12

Alternatives Including the Proposed Action 1 2.2.2.3 NGCC Alternative 2 In this section, the NRC staff describes the NGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4. 4 Natural gas represents nearly 30 percent of installed generation capacity in the ROI but 5 provides only 6 percent of all electrical power in the ROI (EIA 2014b, 2014c). Nationwide, the 6 percentage of power generated by natural gas is expected to rise through 2040, although the 7 actual rise in natural gas generation will depend on future natural gas prices (EIA 2013a). The 8 NRC staff considers the construction of an NGCC power plant to be a reasonable alternative to 9 license renewal because it is a feasible, commercially available option for providing electrical 10 generating capacity beyond the expiration of LSCSs current licenses. 11 Baseload NGCC power plants have proven their reliability and can have capacity factors as high 12 as 85 percent. In an NGCC system, electricity is generated using a gas turbine that burns 13 natural gas. A steam turbine uses the heat from gas turbine exhaust through a heat recovery 14 steam generator to produce additional electricity. This two-cycle process has a high rate of 15 efficiency because the exhaust heat that would otherwise be lost is captured and reused. Like 16 other fossil fuel sources, NGCC power plants are a source of greenhouse gases, including 17 carbon dioxide. An NGCC power plant, however, produces significantly fewer greenhouse 18 gases per unit of electrical output than conventional coal-powered plants. 19 To replace the electricity that LSCS generates, the NRC staff considered five NGCC units, each 20 with a net capacity of 560 MWe (NETL 2007). The NRC staff assumes that each plant 21 configuration consists of two combustion turbine generators, two heat recovery steam 22 generators, and one steam turbine generator with mechanical draft cooling towers for heat 23 rejection. The power plant is assumed to incorporate a selective catalytic reduction system to 24 minimize the plants nitrogen oxide emissions (NETL 2007). 25 This 2,800-MWe NGCC plant would consume 124 billion cubic feet (3,500 million cubic meters) 26 of natural gas annually, assuming an average heat content of 1,021 British thermal units per 27 cubic foot (EIA 2013c). Natural gas would be extracted from the ground through wells, and then 28 it would be treated to remove impurities and blended to meet pipeline gas standards before 29 being piped through the State pipeline system to the plant site. This NGCC alternative would 30 produce relatively little waste, primarily in the form of spent catalysts used for control of nitrogen 31 oxide emissions. 32 The NGCC alternative would be located on undeveloped land at LSCS to maximize availability 33 of infrastructure and to reduce other environmental impacts. Depending on the specific site 34 location, there might be a need to construct new intake and discharge facilities and a new 35 cooling system. Because NGCC power plants generate much of their power from a gas-turbine 36 combined-cycle plant and because the overall thermal efficiency of this type of plant is high, an 37 NGCC alternative would require less cooling water than LSCS would. This system would 38 withdraw 17 million gpd (64 million Lpd) of water and would consume 13 million gpd 39 (49 million Lpd). The NRC staff assumes that the cooling system would use a closed-cycle 40 system with mechanical draft cooling towers. Onsite visible structures could include the cooling 41 towers, exhaust stacks, intake and discharge structures, transmission lines, natural gas 42 pipelines, and an electrical switchyard. Construction materials could be delivered by a 43 combination of rail spur, truck, and barge. Modifications may be required to deliver such 44 materials; modifications could include new rail lines or access roads. 45 2.2.2.4 Combination Alternative (NGCC, Wind, and Solar) 46 In this section, the NRC staff describes the combination alternative to the continued operation of 47 LSCS consisting of an NGCC facility constructed at an existing power plant site and operating in 2-13

Alternatives Including the Proposed Action 1 conjunction with land-based wind farms and solar energy facilities, all of which would be located 2 within the ROI. The NRC staff evaluates the environmental impacts from this alternative in 3 Chapter 4. 4 To serve as an effective baseload power alternative to the LSCS reactors, this combination 5 alternative must be capable of providing an equivalent amount of baseload power. For the 6 purpose of this evaluation, the NRC staff presumes that NGCC, wind farms, and solar PV 7 facilities would comprise the combination alternative. 8 NGCC Portion of the Combination Alternative 9 To produce its required share of power (360 MWe), the NGCC portion, operating at an expected 10 capacity factor of 85 percent (NETL 2007), would need to have a nameplate rating of 11 approximately 425 MWe. 12 In 2013, the EIA reported that natural gas-fired power plants are generally used infrequently for 13 shorter periods to meet peak demand. Capacity factors for natural gas plants averaged less 14 than 5 percent during off-peak demand hours for most regions of the country. Natural gas is 15 used for these peaker plants because natural gas combustion turbines can respond quickly; 16 therefore, they tend to be used to meet short-term increases in electricity demand (EIA 2013d). 17 A report prepared by CITI Research stated that gas-fired power plants can help overcome the 18 intermittent nature of renewable energy (Channell et al. 2012). The peaking aspect of natural 19 gas-fired power plants makes natural gas an ideal addition to an otherwise renewable energy 20 combination alternative. 21 The NRC staff assumed that one new NGCC unit of the type described in Section 2.2.2.3 would 22 be constructed and installed at LSCS with a total net capacity of 360 MWe. The appearance of 23 an NGCC unit would be similar to that of the full NGCC alternative considered in 24 Section 2.2.2.3, although only one unit would be constructed. The NRC staff assumes that the 25 NGCC portion of this alternative, which is assumed to be located at LSCS, would use existing 26 electrical switchyards, substations, and transmission lines. Depending on the existing site 27 conditions, it is possible that intake and discharge structures of the existing cooling system 28 could continue in service but would be connected to a new closed-cycle cooling system. For the 29 purposes of this analysis, the NRC staff assumes that the NGCC portion of the combination 30 would use mechanical draft cooling towers. 31 Wind Portion of the Combination Alternative 32 The NRC staff assumes that the wind-generated power from this combination alternative would 33 come from land-based wind farms, which would be located in the ROI within the States of 34 Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, or Wisconsin. The wind portion, assuming 35 a capacity factor of 30 percent, would require a nameplate capacity of 6,042 MWe (WAPA and 36 FWS 2013). 37 The American Wind Energy Association reports a total of more than 67,000 MW of installed 38 wind energy capacity nationwide as of June 30, 2015 (DOE 2015). As of June 2015, Texas is 39 by far the leader in installed land-based capacity with 15,635 MW. Two States in the ROI have 40 the third and fifth largest installed capacity: Iowa with 5,708 MW, followed by Illinois with 41 3,667 MW (DOE 2015). The installed wind capacity in the ROI has been increasing annually by 42 1,000 MWe to 2,500 MWe in each of the past 8 years, for a total of over 13,000 MWe of 43 additional wind capacity from 2007 to 2014 (DOE 2015). Therefore, the NRC staff considers 44 6,042 MW of wind energy to be a reasonable amount by the time the LSCS licenses expire in 45 2022 and 2023. As is the case with other renewable energy sources, the feasibility of wind 46 resources serving as alternative baseload power is dependent on the location (relative to 47 expected load centers), value, accessibility, and constancy of the resource. Wind energy must 2-14

Alternatives Including the Proposed Action 1 be converted to electricity at or near the point where it is extracted, and there are limited energy 2 storage opportunities available to overcome the intermittency and variability of wind resources. 3 At the current stage of wind energy technology development, wind resources in wind power 4 class 3 and higher are suitable for most utility scale applications (NREL 2014a). Wind power 5 class 3 is defined as having a wind speed of 15.7 miles per hour (7.0 meters per second) and a 6 wind density of 500 watts per square meter at 164 ft (50 m) (NREL 2014a). Each State in the 7 ROI, other than Kentucky, has wind resources meeting this power class, with the highest 8 concentrations occurring in Iowa and Illinois (NREL 2015a). 9 Individual wind turbine capacity increased from 0.71 MW in 1999 to 1.79 MW in 2010. The size 10 of turbine most frequently installed in the United States in recent years is the 1.5-MW turbine 11 (WAPA and FWS 2013). For the purposes of this analysis, the NRC staff assumes wind 12 turbines with a capacity of 1.79 MW. The capacity factors of land-based wind farms are lower 13 than offshore wind farms (WAPA and FWS 2013). For the wind portion of the combination 14 alternative, the NRC staff assumed a capacity factor of 30 percent, resulting in an estimated 15 total net capacity of 1,813 MWe. Wind turbines must be well separated from each other to 16 avoid interferences to wind flowing through the wind farm, resulting in wind farms requiring 17 substantial amounts of land. Wind turbines may require as much as 1 to 3 ac (0.4 to 1.2 ha) of 18 land for each turbine (WAPA and FWS 2013). Based on the size of the turbines and amount of 19 land required between each turbine, approximately 3,376 turbines and 3,376 to 10,127 ac 20 (1,366 to 4,098 ha) would be required for the wind portion of the combination alternative. 21 Wind energys intermittency affects its viability and value as a baseload power source. 22 However, the variability of wind-generated electricity can be lessened if the proposed wind 23 farms were located at a large distance from one another and were operated as interconnected 24 wind farms, an aggregate controlled from a central point. Distance separation ensures that the 25 two wind farms will not simultaneously experience the same climate, and power will likely be 26 produced at some of the wind farms at any given time (Archer and Jacobson 2007). 27 Solar Photovoltaic Portion of the Combination Alternative 28 The solar portion of the combination alternative would be generated through one or more solar 29 PV energy facilities located in the ROI. Assuming a capacity factor of 19 percent, the solar 30 energy facilities would need a collective nameplate rating of 1,193 MWe. Solar PV technologies 31 could be installed on building roofs at existing residential, commercial, or industrial sites or at 32 larger standalone solar facilities. 33 Nationwide, growth in large solar PV facilities (greater than 5 MW) has resulted in an increase 34 from 70 MW in 2009 to over 700 MW installed capacity in 2011. As of January 2012, it is 35 estimated that more than 11,000 MW of large solar PV projects have signed power purchase 36 agreements (Mendelsohn et al. 2012). Over 9,000 MW of those solar projects are 50 MW or 37 greater, although most are located in the southwestern United States (Mendelsohn et al. 2012). 38 As described in Section 2.2.2, two States in the ROI (Missouri and Illinois) have renewable 39 energy legislation that includes requirements for solar PV technology. Missouris renewable 40 portfolio standard includes a provision specifying that 2 percent of the renewable portfolio 41 standard requirement must be met by solar energy by 2021. Illinois renewable portfolio 42 standard specifies that solar PV must comprise 6 percent of the annual requirement for 43 compliance year 2015-2016 and thereafter. As of 2012, only 33 MW of solar energy capacity 44 had been installed in the ROI (EIA 2014c). 45 Solar PV resources in the ROI range from 4.0 to 5.0 kilowatt hours per square meter per day 46 (kWh/m2/day). The most viable solar resources are located in Missouri, Iowa, and southern 47 Illinois and Indiana (NREL 2015b). Economically viable solar resources are considered to be 48 6.75 kWh/m2/day and greater (BLM and DOE 2010). As is the case with wind energy sources, 2-15

Alternatives Including the Proposed Action 1 the feasibility of solar energy resources serving as alternative baseload power is dependent on 2 the location, value, accessibility, and constancy of the resource. Solar PV uses solar panels to 3 convert solar radiation into usable electricity. Solar cells are formed into solar panels that can 4 then be linked into PV arrays to generate electricity. The electricity generated can be stored, 5 used directly, fed into a large electricity grid, or combined with other electricity generators as a 6 hybrid plant. Solar PV can generate electricity whenever there is sunlight, regardless of 7 whether the sun is directly shining on solar panels. Therefore, solar PV technologies do not 8 need to directly face and track the sun, which has allowed solar PV systems to have broader 9 geographical use than concentrated solar power (Ardani and Margolis 2011). Because the ROI 10 contains average solar PV resources and because solar PV is a commercially available option 11 for providing electrical generating capacity, the NRC staff considers the construction of solar PV 12 facilities to be a reasonable alternative to license renewal when combined with wind and NGCC. 13 For the purposes of this analysis, the NRC staff assumes solar PV facilities with a capacity 14 factor of 19 percent (Ardani and Margolis 2011). Solar PV facilities may require 6.2 ac (2.5 ha) 15 of land per megawatt (NRC 2013). Although not all of this land would be cleared of vegetation 16 and permanently impacted, it represents the land enclosed in the total site boundary of the solar 17 facility (Ong et al. 2013). For the solar portion of this combination alternative, approximately 18 7,397 ac (2,993 ha) would be required to support an installed net capacity of 227 MWe. In this 19 analysis, the NRC staff does not speculate on the number and size of individual solar facilities, 20 nor their locations within the ROI. However, as stated above, some of the output could be 21 realized by solar PV installations on building roofs at existing residential, commercial, or 22 industrial sites or at larger standalone solar facilities. To the extent that rooftop or 23 building-integrated solar PV installations remain popular, land impacts would be relatively minor. 24 Solar PV systems do not require water for cooling purposes, but a small amount of water is 25 needed to clean the panels and for potable water for the workforce. Impacts identified in the 26 U.S. Department of the Interior Bureau of Land Management (BLM) and DOEs Solar Energy 27 Programmatic Environmental Impact Statement (PEIS) (BLM and DOE 2010, 2012) provide 28 information used in the analyses presented in the impact sections in Chapter 4. 29 2.2.2.5 Purchased Power Alternative 30 In this section, the NRC staff describes purchased power as an alternative to the continued 31 operation of LSCS. 32 The impacts from purchased power would depend substantially on the generation technologies 33 used to supply the purchased power. Impacts from operation of other electricity generators 34 would likely occur in the ROI. As discussed in Section 2.2.1, replacement power for LSCS 35 would be required in northern Illinois and could come from anywhere within Illinois or adjoining 36 states in either the PJM or MISO Regional Transmission Organizations (RTOs). Given the large 37 geographic area, multiple RTOs within the ROI, and wide-ranging generating facilities, the NRC 38 staff considers purchased power to be a feasible source of baseload power to replace LSCS by 39 the time the licenses expire in 2022 and 2023. 40 Purchased power would likely come from the most common types of electricity generation within 41 the ROI: coal, natural gas, nuclear, and wind. All these power sources are discussed as 42 alternatives to license renewal of LSCS and are identified in Sections 2.2.2.2 to 2.2.2.4. 43 Construction and operational impacts from these sources of electricity generation are 44 considered in Chapter 4. Purchased power may require new transmission lines (which may 45 require new construction) and may also rely on older and less-efficient power plants operating at 46 higher capacities than they currently operate or on new facilities that would be constructed. 47 During operations, impacts from nuclear, coal-fired, and natural gas-fired plants and from wind 2-16

Alternatives Including the Proposed Action 1 and solar energy projects would be similar to those described under the new nuclear, coal, 2 natural gas, and combination alternatives described in Chapter 4 for all resource areas. 3 2.3 Alternatives Considered but Dismissed 4 Alternatives to LSCS license renewal that were considered and eliminated from detailed study 5 are presented in this section. These alternatives were eliminated because of technical resource 6 availability or current commercial limitations. Many of these limitations would continue to exist 7 when the current LSCS licenses expire. 8 2.3.1 Energy Conservation and Energy Efficiency 9 Energy conservation can include reducing energy demand through behavioral changes or 10 altering the shape of the electricity load and usually does not require the addition of new 11 generating capacity. Conservation and energy efficiency programs are more broadly referred to 12 as demand-side management. 13 Conservation and energy efficiency programs can be initiated by a utility, transmission 14 operators, the state, or other load-serving entities. The State of Illinois renewable portfolio 15 standard includes an energy efficiency portfolio standard that requires utilities to reduce electric 16 usage by 2 percent of demand by 2015 (DSIRE 2015a), which is equivalent to 4 million MWh, 17 only 20 percent of the amount that would be required to offset LSCSs current electrical 18 generation. 19 In general, residential electricity consumers have been responsible for the majority of peak load 20 reductions, and participation in most programs is voluntary. Therefore, the existence of a 21 program does not guarantee that reductions in electricity demand would occur. The GEIS 22 concludes that, although the energy conservation or energy efficiency potential in the 23 United States is substantial, there are likely no cases where an energy efficiency or 24 conservation program has been implemented expressly to replace or offset a large baseload 25 generation station (NRC 2013). Although significant energy savings are possible in the ROI 26 through demand-side management and energy efficiency programs, conservation and energy 27 efficiency programs are not likely to replace LSCS as a standalone alternative; therefore, the 28 NRC staff does not consider conservation and energy efficiency to be a reasonable alternative 29 to license renewal. 30 2.3.2 Solar 31 Solar power, including solar PV and concentrated solar power technologies, produce power 32 generated from sunlight. PVs convert sunlight directly into electricity using solar cells made 33 from silicon or cadmium telluride. Concentrating solar power uses heat from the sun to boil 34 water and produce steam to drive a turbine connected to a generator to produce electricity 35 (NREL 2014b). To be considered a viable alternative, a solar alternative must replace the 36 amount of electricity LSCS provides. Assuming a capacity factor of 19 percent (Ardani and 37 Margolis 2011), approximately 12,400 MWe of electricity would need to be generated by solar 38 energy facilities in the seven-State ROI. 39 In 2012, 33 MW of solar energy capacity was installed in the ROI (EIA 2014c). The DOEs 40 National Renewable Energy Laboratory (NREL) reports that the States in the ROI receive solar 41 insolation of 4.0 to 5.0 kWh/m2/day, which is considered low to average (NREL 2015b). For 42 utility-scale development, insolation levels below 6.5 kWh/m2/day are not considered 43 economically viable given current technologies (BLM and DOE 2010). There is more potential 44 for solar development using local PV applications, such as rooftop solar panels, than through 2-17

Alternatives Including the Proposed Action 1 utility-scale solar facilities. In addition, a solar facility can only generate electricity when the sun 2 is shining. Energy storage can be used to overcome intermittency for concentrating solar power 3 facilities; however, current and foreseeable storage technologies that have been paired with 4 solar power facilities have a much smaller capacity than would be necessary to replace LSCS. 5 Taking all of the factors above into account, it is unlikely that solar PV or concentrated solar 6 power technologies could serve as baseload power in the ROI to replace LSCSs current 7 electricity output. Given the modest levels of solar energy available throughout the ROI, the 8 lack of substantial installed solar capacity in the ROI and the weather-dependent intermittency 9 of solar power, the NRC staff concludes that a solar power energy facility in the ROI would not 10 be a reasonable alternative to license renewal. The NRC staff described an alternative of solar 11 power in combination with wind and an NGCC plant in Section 2.2.2.4. 12 2.3.3 Wind 13 Two States in the ROI have the third and fifth largest installed capacity in the Nation: Iowa with 14 5,708 MW, followed by Illinois with 3,667 MW (DOE 2015). The installed wind capacity in the 15 ROI has been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 8 years, for 16 a total of over 13,000 MWe of additional wind capacity from 2007 to 2014 (DOE 2015). All of 17 the wind energy facilities and the electricity generation from wind currently being produced in 18 the ROI are land based. To be considered a viable alternative, a wind alternative must replace 19 the amount of electricity LSCS provides. Assuming a capacity factor of 30 percent for 20 land-based wind and 40 percent for offshore wind, a range of 5,665 to 7,553 MWe of electricity 21 would need to be generated by some combination of land-based and offshore wind energy 22 facilities in the seven-State ROI. 23 As is the case with other renewable energy sources, the feasibility of wind resources serving as 24 alternative baseload power is dependent on the location (relative to expected load centers), 25 value, accessibility, and constancy of the resource. Wind energy must be converted to 26 electricity at or near the point where it is extracted, and there are limited energy storage 27 opportunities available to overcome the intermittency and variability of wind resource availability. 28 Although wind power is intermittent and although individual facilities are unable to provide 29 baseload power, it has been proposed that multiple interconnected wind installations separated 30 by long distances could theoretically function as a virtual power plant and could provide 31 baseload power since individual facilities would be exposed to different weather and wind 32 conditions. To date, however, no states or utilities operate arrays of wind installations as virtual 33 power plants. 34 Given the amount of wind capacity necessary to replace LSCS and the intermittency of wind 35 power, the NRC staff finds a completely wind-based alternative to be unreasonable. However, 36 the NRC staff also concludes that, when used in combination with other technologies with 37 inherently higher capacity factors, wind energy can provide a viable alternative. The NRC staff 38 described such a possible combination alternative in Section 2.2.2.4. 39 2.3.3.1 Offshore Wind 40 The United States does not have any offshore wind farms in operation; however, approximately 41 20 projects representing more than 2,000 MW of capacity are in the planning and permitting 42 process as of 2010 (Musial and Ram 2010). Offshore wind projects have been developed in 43 Europe, most of which are located close to shore and in shallow water less than 98.4 ft (30 m) in 44 depth. Total worldwide installed capacity has been estimated at 2,377 MW (Musial and 45 Ram 2010). 46 Although wind data suggest a potential for offshore wind farms in the Great Lakes, project costs 47 likely will limit the future potential of large-scale projects (Tidball et al. 2010). NREL 2-18

Alternatives Including the Proposed Action 1 (Tidball et al. 2010) estimated that offshore project costs would run approximately 200 to 2 300 percent higher than land-based systems. In addition, based on current prices for wind 3 turbines, the 20-year levelized cost of electricity produced from an offshore wind farm would be 4 above the current production costs from existing power generation facilities. In addition to cost, 5 other barriers include the immature status of the technology, limited resource area, and high 6 risks and uncertainty (Tidball et al. 2010). Because no offshore wind capacity yet exists in 7 either the Great Lakes or on the Atlantic Coast and because none appears likely to exist on a 8 large commercial scale in the Great Lakes by 2022 (given the current state of development), the 9 NRC staff finds that offshore wind will not be a reasonable alternative to LSCS. 10 2.3.3.2 Wind Power with Storage 11 Energy storage is one possible way to overcome intermittency. Besides pumped hydroelectric 12 facilities, compressed air energy storage (CAES) is the technology most suited for storage of 13 large amounts of energy. In CAES systems, electricity generated during low-demand periods 14 can be stored by using a compressor to pressurize and store air; during high-demand periods, 15 the compressed air can be used to drive a turbine to generate electricity. A 2011 DOE report 16 analyzed various power-generation sources, including wind, coupled with CAES systems 17 (Ilic et al. 2011). The report considered siting criteria, using (1) proximity to natural gas lines, 18 high voltage transmission, and a market for wholesale electric power and (2) availability of 19 geology and wind resources. The results show that, within the ROI, the potential exists for 20 one CAES site in northwestern Iowa. Without detailed wind-speed data, specific site 21 information, and detailed information on the energy-storage capacity of the potential CAES site, 22 estimating how much wind capacity would be necessary and determining whether it could 23 provide for an all-wind alternative would be difficult. Furthermore, the NRC staff is not aware of 24 a CAES project coupled with wind generation that is providing baseload power. Therefore, the 25 NRC staff concludes that the use of CAES in combination with wind turbines to replace the 26 LSCS power plant is unlikely. 27 2.3.3.3 Conclusion 28 Despite the relatively high reliability demonstrated by modern turbines, the recent technological 29 advancements in turbine design and wind farm operation, and wind energys dramatic market 30 penetrations of recent years, empirical data on wind farm capacity factors and wind energys 31 limited ability to store power for delayed production of electricity cause the NRC staff to 32 conclude that wind energyon shore, off shore, or a combination thereofcould not serve as a 33 discrete alternative to the baseload power supplied by the LSCS reactors. However, the NRC 34 staff also concludes that, when used in combination with other technologies with inherently 35 higher capacity factors, wind energy can provide a viable alternative. The NRC staff described 36 such a possible combination alternative in Section 2.2.2.4. 37 2.3.4 Biomass 38 Biomass resources used for biomass-fired generation include agricultural residues, animal 39 manure, wood wastes from forestry and industry, residues from food and paper industries, 40 municipal green wastes, dedicated energy crop, and methane from landfills (IEA 2007). Using 41 biomass-fired generation for baseload power depends on the geographic distribution, available 42 quantities, constancy of supply, and energy content of biomass resources. For this analysis, the 43 NRC staff assumed that biomass would be combusted for power generation in the electricity 44 sector. Biomass is also used for space heating in residential and commercial buildings and can 45 be converted to a liquid form for use in transportation fuels (Haq undated). 46 In the GEIS, the NRC staff indicated a wood waste facility could provide baseload power and 47 could operate with capacity factors between 70 and 80 percent (NRC 2013). Although the ROI 2-19

Alternatives Including the Proposed Action 1 currently produces electricity from biomass fuels, the plants operating within the ROI generated 2 less than 1 percent of the total power generation in 2011 (EIA 2014b). Based on the relatively 3 low electricity generation currently produced at biomass plants, it is unlikely that these plants, or 4 the construction of several new biomass plants, could increase capacity by adding 2,327 MWe 5 of electricity from biomass-fired generation by the time LSCSs licenses expire in 2022 and 6 2023. 7 For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 8 used for biomass conversion would be similar to fossil fuel plants, including the direct 9 combustion of biomass in a boiler to produce steam (NRC 2013). Biomass generation is 10 generally more cost-effective when co-fired with coal plants (IEA 2007). Biomass-fired 11 generation plants generally are small and can reach capacities of 50 MWe, which means that 12 more than 40 new facilities would be required before the LSCS licenses expire. After 13 reevaluating current technologies, the NRC staff finds biomass-fired alternatives as still unable 14 to reliably replace the LSCS capacity. For this reason, the NRC staff does not consider 15 biomass to be a reasonable alternative to LSCS license renewal. 16 2.3.5 Hydroelectric 17 Hydroelectric power uses the force of water to turn turbines that spin a generator to produce 18 electricity. In a run-of-the-river system, the force of a river current provides the force to create 19 the needed pressure for the turbine. In a storage system, water is accumulated in reservoirs 20 created by dams and is released as needed to generate electricity. 21 The DOEs Idaho National Environmental Engineering Laboratory (now Idaho National 22 Laboratory) completed a comprehensive survey of hydropower resources in 1997. The ROI has 23 hydroelectric generating potential of 1,954 MW, adjusting for environmental, legal, and 24 institutional constraints (Conner et al. 1998). These constraints could include (1) scenic, 25 cultural, historical, and geological values, (2) Federal and state land use, and (3) legal 26 protection issues, such as wild and scenic legislation and threatened or endangered fish and 27 wildlife legislative protection. A separate assessment by DOE of nonpowered dams (dams that 28 do not produce electricity) concluded that there is potential for 4,185 MW of electricity in the ROI 29 (ORNL 2012). These nonpowered dams serve various purposes, such as providing water 30 supply to inland navigation. 31 The EIA reported that the States comprising the ROI generated 2,262 MW of electricity from 32 hydroelectric power in 2012 (EIA 2014c). In order to replace LSCSs current output, 33 hydroelectric generation across the ROI would need to double by 2022. Although there is 34 potential for anywhere between 1,954 MW and 4,185 MW of hydroelectric power, it is unlikely 35 that the maximum levels of development would occur across the entire ROI by the time LSCSs 36 licenses expire in 2022 and 2023 because the generating capacity of hydroelectric power is 37 projected to continue to decrease through 2040 (EIA 2013b). Given the decrease in projected 38 power generation from hydroelectric facilities, the NRC staff does not consider hydroelectric 39 power to be a reasonable alternative to license renewal. 40 2.3.6 Wave and Ocean Energy 41 Waves, currents, and tides are often predictable and reliable, making them attractive candidates 42 for potential renewable energy generation. Four major technologies may be suitable to harness 43 wave energy: terminator devices that range from 500 kilowatts to 2 MW, attenuators, point 44 absorbers, and overtopping devices (BOEM undated). Point absorbers and attenuators use 45 floating buoys to convert wave motion into mechanical energy, driving a generator to produce 46 electricity. Overtopping devices trap a portion of a wave at a higher elevation than the sea 2-20

Alternatives Including the Proposed Action 1 surface; waves then enter a tube and compress air that is used to drive a generator that 2 produces electricity (NRC 2013). Some designs are undergoing demonstration testing at 3 commercial scales, but none are currently used to provide baseload power (BOEM undated). 4 The Great Lakes do not experience large tides, and there is limited energy output for wave 5 technologies in the Great Lakes. The Electric Power Research Institute (EPRI) published a 6 document that assessed ocean wave energy resources in the United States. The Great Lakes 7 were not included in the analysis, suggesting that the resource potential is not great enough to 8 use on a commercial scale (EPRI 2011). Consequently, the limited resource availability and 9 infancy of the technologies in the Great Lakes support the NRC staffs conclusion that wave and 10 ocean energy technologies are not feasible substitutes for LSCS. 11 2.3.7 Fuel Cells 12 Fuel cells oxidize fuels without combustion and its environmental side effects. Fuel cells use a 13 fuel (e.g., hydrogen) and oxygen to create electricity through an electrochemical process. The 14 only byproducts (depending on fuel characteristics) are heat, water, and carbon dioxide 15 (depending on hydrogen fuel type) (DOE 2013a). Hydrogen fuel can come from a variety of 16 hydrocarbon resources. Natural gas is a typical hydrogen source. 17 Fuel cells are not economically or technologically competitive with other alternatives for 18 electricity generation. EIA projects that fuel cells may cost $6,835 per installed kilowatt (total 19 overnight capital costs, 2010 dollars), which is high compared to other alternative technologies 20 analyzed in this section (EIA 2010). More importantly, fuel cell units are likely to be small in size 21 (approximately 10 MWe). Replacing the power LSCS provides would be extremely costly; it 22 would require the construction of approximately 230 units and modifications to the existing 23 transmission system. Given the immature status of fuel cell technology and high cost, the NRC 24 staff does not consider fuel cells to be a reasonable alternative to LSCS license renewal. 25 2.3.8 Delayed Retirement 26 A delayed retirement alternative would consider deferring the retirement of generating facilities 27 in Illinois and its six adjoining states that include MISO and PJM RTOs. 28 To maintain reliable operations, electric systems must be able to meet peak load requirements. 29 To ensure sufficient capacity, this must also include a planning reserve margin (FERC 2013). 30 The projected MISO reserve margin for 2021 is 18.6 percent, which exceeds the reserve margin 31 requirement of 17.4 percent. However, recent EPA regulations may lead to increased coal plant 32 retirements at a faster pace than projected. In that case, 3,000 MW to 12,600 MW of plant 33 retirements could decrease the projected reserves anywhere from 16.22 to 6.9 percent, well 34 below the reserve margin requirement (MISO 2011). 35 PJM is facing similar constraints due, in large part, to retirements of coal plants given air quality 36 regulations (Ott 2013a). This indicates an emerging reliability problem potentially affecting 37 major population centers within the PJM region in the near future (Ott 2013a). Because the 38 current generation mix has not resulted in the long-term commitment of generation needed for 39 reliability, generation retirements that have occurred with short notice have created 40 unanticipated reliability problems for PJM (Ott 2013a). 41 The EIA expects that more coal plant retirements will occur before 2016 than those previously 42 predicted. These accelerated retirements are driven by low natural gas prices, slow growth in 43 electricity demand, and the requirements of the Mercury and Air Toxics Standards that will 44 require significant reductions in plant emissions (EIA 2014a, EPA 2015). Exelon also expects 45 increased generation retirements for a variety of reasons, including increased operating costs 2-21

Alternatives Including the Proposed Action 1 for older facilities, increased environmental regulations and competition, and decreased load 2 (Exelon undated). As generators are required to adhere to future regulations, some power 3 plants may opt for early retirement of older units rather than incur the cost for compliance. 4 Exelon has further stated that some of their nuclear fleet may be retired early because of low 5 wholesale energy prices and current energy policy (Associated Press 2015). Because of the 6 uncertain regulatory environment and concerns expressed by MISO and PJM concerning the 7 retirement pace of coal power plants, the NRC staff does not consider delayed retirement to be 8 a reasonable alternative to LSCS license renewal. 9 2.3.9 Geothermal 10 Geothermal technologies extract the heat contained in geologic formations to produce steam to 11 drive a conventional steam turbine generator. Facilities producing electricity from geothermal 12 energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 13 a potential source of baseload electric power. However, the feasibility of geothermal power 14 generation to provide baseload power depends on the regional quality and accessibility of 15 geothermal resources. Utility-scale geothermal energy generation requires geothermal 16 reservoirs with a temperature above 200 °F (93 °C). Utility-scale power plants range from small 17 300 kilowatts electric to 50 MWe and greater (TEEIC undated). Geothermal resources are 18 concentrated in the western United States. Specifically, these resources are found in Alaska, 19 Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, 20 Washington, and Wyoming. In general, most assessments of geothermal resources have been 21 concentrated on these western states (DOE 2013b; USGS 2008). Geothermal resources are 22 used in the ROI for heating and cooling purposes, but no electricity is currently being produced 23 from geothermal resources in the ROI (EIA 2014c). Given the low resource potential in the ROI, 24 the NRC staff does not consider geothermal to be a reasonable alternative to license renewal. 25 2.3.10 Municipal Solid Waste 26 Energy recovery from municipal solid waste converts nonrecyclable waste materials into usable 27 heat, electricity, or fuel through combustion (EPA 2014b). The three types of combustion 28 technologies include mass burning, modular systems, and refuse-derived fuel systems 29 (EPA 2014a). Mass burning is the method used most frequently in the United States. The heat 30 released from combustion is used to convert water to steam, which is used to drive a turbine 31 generator to produce electricity. Ash is collected and taken to a landfill, and particulates are 32 captured through a filtering system (EPA 2014a). As of 2010, approximately 33 86 waste-to-energy plants are in operation in 25 states, processing more than 28 million tons of 34 waste per year (EPA 2014b). These waste-to-energy plants have an aggregate capacity of 35 2,720 MWe, and although some plants have expanded to handle additional waste and produce 36 more energy, no new plants have been built in the United States since 1995 (EPA 2014b). The 37 average waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can 38 operate at capacity factors greater than 90 percent (Michaels 2010). Indiana has one waste 39 recovery facility that produces steam; Iowa has one waste-to-energy facility that produces 40 10 MW of electricity; Michigan has three facilities that produce 89.7 MW of electricity; and 41 Wisconsin has two facilities that generate 32.3 MW of electricity (Michaels 2010). In total, as of 42 2010, the ROI had a municipal solid waste generating capacity of 132 MW. More than 43 46 average-sized plants would be necessary to provide the same level of output as LSCS, 44 almost doubling the national waste-to-energy generation. 45 The decision to burn municipal waste to generate energy is usually driven by the need for an 46 alternative to landfills rather than energy considerations. Given the improbability that additional 47 stable supplies of municipal solid waste would be available to support approximately 46 new 2-22

Alternatives Including the Proposed Action 1 facilities and that so few existing plants operate in the ROI, the NRC staff does not consider 2 municipal solid waste combustion to be a reasonable alternative to LSCS license renewal. 3 2.3.11 Petroleum 4 In the ROI, oil-fired generation in 2012 had a generating capacity of 4,986 MW (EIA 2014c). 5 The variable costs of oil-fired generation tend to be greater than those of the nuclear or 6 coal-fired operations, and oil-fired generation tends to have greater environmental impacts than 7 natural gas-fired generation. The high cost of oil has resulted in a steady decline in its use for 8 electricity generation (EIA 2013a). Given the high cost of oil and the small generating capacity 9 from oil-fired power plants in the ROI, the NRC staff does not consider oil-fired generation a 10 reasonable alternative to LSCS license renewal. 11 2.3.12 Supercritical Pulverized Coal 12 In general, SCPC power plants are feasible, commercially available options for providing 13 electrical generating capacity. Baseload coal units have proven their reliability and can sustain 14 capacity factors as high as 79 percent. Pulverized coal power generation uses crushed coal 15 that is fed into a boiler where it is burned to create heat. The heat produces steam that is used 16 to spin one or more turbines to generate electricity. Among the technologies available, 17 pulverized coal boilers producing supercritical steam (SCPC boilers) are increasingly common 18 for new coal-fired plants given their high operating temperatures and pressures that increase 19 thermal efficiencies and overall reliability. SCPC facilities consume less fuel per unit output, 20 reducing environmental impacts (NETL undated). 21 As described in Section 2.2.3, EPA has signed a final rule for carbon pollution that would apply 22 to new fossil fuel-fired power plants, including SCPC facilities (80 FR 64661-65120). The 23 action establishes performance standards and has identified a CCS system as a method of 24 emission reduction. The emission limit for these sources of 1,305 lb CO2/MWh, and any new 25 coal-fired power plants could require CCS in order to achieve this emission limit. 26 In addition, given known technology and technological and demographic trends, EIA predicts 27 that by 2040 natural gas will surpass coal as the largest share of U.S. electric power generation 28 (EIA 2013a). This does not consider the EPA rule described above but indicates a general 29 trend away from coal-fired facilities in favor of natural gas-fired power plants due to falling 30 natural gas prices. MISO projected that the EPA regulations could lead to increased coal plant 31 retirements and estimated retirements between 3,000 MW to 12,600 MW, which could have a 32 large impact on MISOs reserve margin in the future (MISO 2011). 33 Although SCPC plants are currently the most widely used source of electricity generation within 34 the ROI, given the potential for stringent air quality regulations and trends toward natural 35 gas-fired power plants, the NRC staff does not consider SCPC to be a reasonable alternative to 36 LSCS license renewal. Instead, the NRC staff describes an IGCC plant under the coal 37 alternative in Section 2.2.2.2. 38 2.4 Comparison of Alternatives 39 In this chapter, the NRC staff considered the following alternatives to LSCS license renewal: 40 new nuclear generation; IGCC generation; NGCC generation; a combination alternative of 41 natural gas, wind, and solar; and purchased power. The NRC also considered the no-action 42 alternative and its effects. The impacts for all alternatives to LSCS license renewal are 43 discussed in Chapter 4 and summarized in Table 2-2 below. 2-23

Alternatives Including the Proposed Action 1 The environmental impacts of the proposed action (issuing renewed LSCS operating licenses) 2 would be SMALL for all impact categories. The environmental impacts from all other 3 alternatives would be larger than the proposed license renewal, as shown in Table 2-2. 4 In conclusion, the environmentally preferred alternative is the granting of renewed licenses for 5 LSCS. All other alternatives capable of meeting the needs currently served by LSCS entail 6 potentially greater impacts than those of the proposed action of renewing the license for LSCS. 7 To make up the lost power generation if a renewed license is not issued (the no-action 8 alternative), one or a combination of alternatives would be implemented, all of which have 9 greater impacts than the proposed action. Hence, the NRC staff concludes that the no-action 10 alternative will have environmental impacts greater than or equal to those of the proposed 11 license renewal action. 2-24

1 Table 2-2. Summary of Environmental Impacts of Proposed Action and Alternatives LSCS License Combination Renewal Alternative Impact Area (Proposed New Nuclear IGCC NGCC (NGCC, Wind, Purchased (Resource) Action) No-Action Alternative Alternative Alternative and Solar) Power Land Use and Visual Resources SMALL TO SMALL TO SMALL TO SMALL TO Land Use SMALL SMALL SMALL MODERATE LARGE MODERATE MODERATE SMALL TO SMALL TO Visual Resources SMALL SMALL SMALL SMALL SMALL MODERATE LARGE Air Quality and Noise SMALL TO Air Quality SMALL SMALL SMALL MODERATE MODERATE SMALL MODERATE SMALL TO SMALL TO SMALL TO Noise SMALL SMALL SMALL SMALL MODERATE MODERATE MODERATE Geologic Environment SMALL SMALL SMALL SMALL SMALL SMALL SMALL 2-25 Water Resources Surface Water SMALL TO SMALL TO SMALL TO SMALL SMALL SMALL SMALL Resources MODERATE MODERATE MODERATE Groundwater SMALL SMALL SMALL SMALL SMALL SMALL SMALL Resources SMALL TO MODERATE SMALL TO SMALL TO Terrestrial Resources SMALL SMALL SMALL MODERATE TO LARGE MODERATE MODERATE SMALL to SMALL to Aquatic Resources SMALL SMALL SMALL SMALL SMALL MODERATE1 MODERATE Special Status Species NO EFFECT SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 

      & Habitats Historic and                                                                                    SMALL TO       SMALL TO SEE NOTE3     SMALL       SMALL          SMALL         SMALL Cultural Resources                                                                              LARGE          LARGE Socioeconomics SMALL TO    SMALL TO       SMALL TO      SMALL TO                      SMALL TO Socioeconomics           SMALL                                                                 SMALL LARGE       LARGE          LARGE         LARGE                         LARGE Alternatives including the Proposed Action

LSCS License Combination Renewal Alternative Impact Area (Proposed New Nuclear IGCC NGCC (NGCC, Wind, Purchased (Resource) Action) No-Action Alternative Alternative Alternative and Solar) Power SMALL TO SMALL TO SMALL TO SMALL TO SMALL TO Transportation SMALL SMALL LARGE LARGE LARGE MODERATE LARGE Human Health SMALL SMALL SMALL SMALL SMALL SMALL SMALL Environmental Justice SEE NOTE4 SEE NOTE5 SEE NOTE6 SEE NOTE6 SEE NOTE6 SEE NOTE6 SEE NOTE6 Waste Management SMALL TO SMALL TO and Pollution SMALL SMALL SMALL SMALL SMALL MODERATE MODERATE Prevention Key: IGCC = coal-integrated gasification combined-cycle (alternative), NGCC = natural gas combined-cycle (alternative), NRHP = National Register of Historic Places, APE = area of potential effect, CRMP = Cultural Response Management Plan, and IHPA = Illinois Historic Preservation Agency. (1) Thermal impacts would be SMALL for aquatic resources in the Illinois River and SMALL to MODERATE for aquatic resources in the cooling pond. Alternatives including the Proposed Action MODERATE thermal impacts would primarily be experienced by gizzard and threadfin shad in the cooling pond. (2) The magnitude of impacts could vary widely based on site selection and the presence or absence of special status species and habitats when the alternative is implemented; therefore, the NRC staff cannot forecast a level of impact for this alternative. 2-26 (3) Based on (1) there being currently no NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelons draft CRMP, (4) the fact that no license renewal-related physical changes or ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource assessment, license renewal would not affect any known historic properties (36 CFR 800.4(d)(1)). (4) Continued operation of LSCS would not have disproportionately high and adverse human health and environmental effects on minority and low-income populations. (5) The no-action alternative could disproportionately affect minority and low-income populations. (6) Based on this information and the analysis of human health and environmental impacts presented in this SEIS, it is not likely that this alternative would have disproportionately high and adverse human health and environmental effects on minority and low-income populations. However, this determination would depend on the location, plant design, and operational characteristics of the alternative. Therefore, the NRC staff cannot determine whether this alternative would result in disproportionately high and adverse human health and environmental effects on minority and low-income populations.

Alternatives Including the Proposed Action 1 2.5 References 2 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 3 production and utilization facilities. 4 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 5 protection regulations for domestic licensing and related regulatory functions. 6 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 7 renewal of operating licenses for nuclear power plants. 8 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forest, and Public Property, 9 Part 800, Protection of historic properties. 10 80 FR 26302. U.S. Nuclear Regulatory Commission. DTE Electric Company: Fermi 3. 11 Combined license and record of decision: Issuance. Federal Register 80:26302-26303. 12 May 7, 2015. 13 AmerenUE. 2009. Callaway Plant Unit 2 Combined License Application Part 3: Environmental 14 Report. Revision 1. February 2009. 1,444 p. Agencywide Documents Access and 15 Management System (ADAMS) No. ML090710402. 16 Archer CL, Jacobson MZ. 2007. Supplying baseload power and reducing transmission 17 requirements by interconnecting wind farms. Journal of Applied Meteorology and 18 Climatology 46(11):1701-1717. Available at 19 <http://www.stanford.edu/group/efmh/winds/aj07_jamc.pdf> (accessed 28 August 2015). 20 Ardani K, Margolis R. 2011. 2010 Solar Technologies Market Report. Golden, Colorado: 21 National Renewable Energy Laboratory. November 2011. 136 p. Available at 22 <http://www.nrel.gov/docs/fy12osti/51847.pdf> (accessed 28 August 2015). 23 Associated Press. 2015. Nuclear plants in Illinois could be shuttered if they dont get a break 24 from state, Exelon says. Chicago Sun-Times. March 28, 2015. Available at 25 <http://chicago.suntimes.com/business/7/71/477077/nuclear-plants-illinois-shuttered-dont-get-26 break-state-exelon-says> (accessed 28 August 2015). 27 Barker, J. 2015. Ameren officially pulls plug on new Callaway nuke. St. Louis Post-Dispatch. 28 July 31, 2015. Available at <http://www.stltoday.com/business/local/ameren-officially-pulls-plug-29 on-new-callaway-nuke/article_c4202562-c6c3-5b93-95ee-f45dd8778378.html> (accessed 30 2 September 2015). 31 [BLM and DOE] U.S. Department of the Interior Bureau of Land Management and 32 U.S. Department of Energy. 2010. Draft Programmatic Environmental Impact Statement for 33 Solar Energy Development in Six Southwestern States. DES 10-59, DOE/EIS-0403, Volumes 1 34 to 8. December 2010. 11,145 p. Available at 35 <http://www.solareis.anl.gov/documents/dpeis/index.cfm> (accessed 4 September 2015). 36 [BLM and DOE] U.S. Department of the Interior Bureau of Land Management and 37 U.S. Department of Energy. 2012. Final Programmatic Environmental Impact Statement 38 (PEIS) for Solar Energy Development in Six Southwestern States. FES 12-24, DOE/EIS-0403, 39 Volumes 1 to 7. July 2012. 3,596 p. Available at 40 <http://www.solareis.anl.gov/documents/fpeis/index.cfm> (accessed 28 August 2015). 41 [BOEM] Bureau of Ocean Energy Management. undated. Ocean Wave Energy. Available at 42 <http://www.boem.gov/Renewable-Energy-Program/Renewable-Energy-Guide/ 43 Ocean-Wave-Energy.aspx> (accessed 28 August 2015). 2-27

Alternatives Including the Proposed Action 1 Channell J, Lam T, Pourreza S. 2012. Shale & renewables: A symbiotic relationship. 2 CITI Research. September 12, 2012. 88 p. Available at <http://www.ourenergypolicy.org/ 3 wp-content/uploads/2013/04/citigroup-renewables-and-natgas-report.pdf> (accessed 4 28 August 2015). 5 [ComEd] Commonwealth Edison Company. 2015. ComEdAn Exelon Company: 6 Company Profile. Available at <https://www.comed.com/about-us/company-7 information/Pages/profile.aspx> (accessed 28 August 2015). 8 Conner AM, Francfort JE, Rinehart BN. 1998. U.S. Hydropower Resource Assessment, Final 9 Report. Idaho Falls, Idaho. Idaho National Engineering and Environmental Laboratory. 10 DOE/ID-10430.2. December 1998. 49 p. Available at 11 <http://hydropower.inl.gov/resourceassessment/pdfs/doeid-10430.pdf> (accessed 12 28 August 2015). 13 [DOE] U.S. Department of Energy. 2008. 20% Wind Energy by 2030Increasing Wind 14 Energys Contribution to U.S. Electricity Supply. DOE/GO-102008-2567. July 2008. 228 p. 15 Available at <http://www.nrel.gov/docs/fy08osti/41869.pdf> (accessed 10 September 2015). 16 [DOE] U.S. Department of Energy. 2010a. Kemper County Integrated Gasification 17 Combined-Cycle (IGCC) Project, Final Environmental Impact Statement (EIS). 18 Washington, DC: DOE. DOE/EIS-0409, Volume 1. May 2010. 671 p. Available at 19 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/ 20 EIS-0409-FEIS-01-2010.pdf> (accessed 28 August 2015). 21 [DOE] U.S. Department of Energy. 2010b. Final Environmental Assessment for Department of 22 Energy Loan Guarantee for the Agua Caliente Solar Project in Yuma County, Arizona. 23 DOE/EA-1797. November 2010. Available at 24 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/EA-1797-FEA-2010.pdf> 25 (accessed 28 August 2015). 26 [DOE] U.S. Department of Energy. 2015. WINDExchange: U.S. Installed Wind Capacity. 27 Available at <http://www.windpoweringamerica.gov/wind_installed_capacity.asp> (accessed 28 28 August 2015). 29 [DOE] U.S. Department of Energy. 2013a. Fuel CellBasics. August 14, 2013. Available at 30 <http://energy.gov/eere/energybasics/articles/fuel-cell-basics> (accessed 31 August 2015). 31 [DOE] U.S. Department of Energy. 2013b. Geothermal Resource Basics. August 14, 2013. 32 Available at <http://energy.gov/eere/energybasics/articles/geothermal-resource-basics> 33 (accessed 31 August 2015). 34 [DOE] U.S. Department of Energy. undated. Small Modular Nuclear Reactors. Available at 35 <http://energy.gov/ne/nuclear-reactor-technologies/small-modular-nuclear-reactors> (accessed 36 28 August 2015). 37 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2014. Iowa Alternative 38 Energy Law. October 31, 2014. Available at 39 <http://programs.dsireusa.org/system/program/detail/265> (accessed 31 August 2015). 40 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015a. Illinois Renewable 41 Portfolio Standard. June 26, 2015. Available at 42 <http://programs.dsireusa.org/system/program/detail/584> (accessed 31 August 2015). 43 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015b. Missouri 44 Renewable Electricity Standard. May 18, 2015. Available at 45 <http://programs.dsireusa.org/system/program/detail/2622> (accessed 31 August 2015). 2-28

Alternatives Including the Proposed Action 1 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015c. Wisconsin 2 Renewable Portfolio Standard. May 6, 2015. Available at 3 <http://programs.dsireusa.org/system/program/detail/190> (accessed 31 August 2015). 4 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015d. Michigan 5 Renewable Energy Standard. June 25, 2015. Available at 6 <http://programs.dsireusa.org/system/program/detail/3094> (accessed 31 August 2015). 7 [DSIRE] Database of State Incentives for Renewable Energy. 2015e. Indiana Clean Energy 8 Portfolio Goal. May 12, 2015. Available at 9 <http://programs.dsireusa.org/system/program/detail/4832> (accessed 31 August 2015). 10 Duke Energy. 2013. Project Overview. Available at <http://www.duke-energy.com/ 11 about-us/edwardsport-overview.asp> (accessed 31 August 2015). 12 [EIA] U.S. Energy Information Administration. 2010. Updated Capital Cost Estimates for 13 Electricity Generation Plants. November 2010. Available at 14 <http://www.eia.gov/oiaf/beck_plantcosts/index.html> (accessed 31 August 2015). 15 [EIA] U.S. Energy Information Administration. 2012. Voluntary Reporting of Greenhouse 16 Gases ProgramEmission Factors and Global Warming. Available at 17 <http://www.eia.gov/oiaf/1605/emission_factors.html> (accessed 31 August 2015). 18 [EIA] U.S. Energy Information Administration. 2013a. Annual Energy Outlook 2013 with 19 Projections to 2040. DOE/EIA 0383 (2013). Washington, DC: EIA. April 26, 2013. 244 p. 20 Available at <http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf> (accessed 28 August 2015). 21 [EIA] U.S. Energy Information Administration. 2013b. Annual Energy Outlook 2014 Early 22 Release. December 16, 2013. Available at <http://www.eia.gov/forecasts/archive/ 23 aeo14/er/pdf/0383er(2014).pdf> (accessed 28 August 2015). 24 [EIA] U.S. Energy Information Administration. 2013c. U.S. Energy Information Administration 25 Frequently Asked Questions. How much coal, natural gas, or petroleum is used to generate a 26 kilowatthour of electricity? Available at <http://www.eia.gov/tools/faqs/faq.cfm?id=667&t=2> 27 (accessed 31 August 2015). 28 [EIA] U.S. Energy Information Administration. 2013d. U.S. Energy Information Administration 29 Today in Energy. Natural gas-fired combustion turbines are generally used to meet peak 30 electricity load. October 1, 2013. Available at 31 <http://www.eia.gov/todayinenergy/detail.cfm?id=13191> (accessed 31 August 2015). 32 [EIA] U.S. Energy Information Administration. 2014a. U.S. Energy Information 33 AdministrationToday in Energy. AEO2014 projects more coal-fired power plant retirements 34 by 2016 than have been scheduled. February 14, 2014. Available at 35 <http://www.eia.gov/todayinenergy/detail.cfm?id=15031&src=email> (accessed 36 31 August 2015). 37 [EIA] U.S. Energy Information Administration. 2014b. State Electricity Profiles 2011. 38 Washington, DC: EIA. Available at <http://www.eia.gov/electricity/state/archive/sep2011.pdf> 39 (accessed 31 August 2015). 40 [EIA] U.S. Energy Information Administration. 2014c. State Electricity Profiles 2012. 41 Washington, DC: EIA. Available at <http://www.eia.gov/electricity/state/archive/2012/> 42 (accessed 1 September 2015). 2-29

Alternatives Including the Proposed Action 1 [EIA] U.S. Energy Information Administration. 2015. Annual Energy Outlook 2015 with 2 Projections to 2040. DOE/EIA 0383 (2015). Washington, DC: EIA. April 14, 2015. 154 p. 3 Available at <http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf> (accessed 4 2 September 2015). 5 Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 6 [EPA] U.S. Environmental Protection Agency. 2014a. Municipal Solid Waste: Basic 7 Information about Energy Recovery from Waste. Available at 8 <http://www.epa.gov/osw/nonhaz/municipal/wte/basic.htm> (accessed 31 August 2015). 9 [EPA] U.S. Environmental Protection Agency. 2014b. Municipal Solid Waste: Energy 10 Recovery from Waste. Available at <http://www.epa.gov/osw/nonhaz/municipal/wte/> 11 (accessed 31 August 2015). 12 [EPA] U.S. Environmental Protection Agency. 2015. Mercury and Air Toxics Standards. 13 Available at <http://www3.epa.gov/mats/> (accessed 13 October 2015). 14 [EPRI] Electric Power Research Institute. 2011. Mapping and Assessment of the United States 15 Ocean Wave Energy Resource. Palo Alto, California: EPRI. 1024637. December 2011. 16 176 p. Available at <http://www1.eere.energy.gov/water//pdfs/mappingandassessment.pdf> 17 (accessed 31 August 2015). 18 [Exelon] Exelon Generation Company, LLC. 2014. Applicants Environmental Report 19 Operating License Renewal Stage, LaSalle County Station, Units 1 and 2, License Renewal 20 Application. Kennett Square, Pennsylvania: Exelon. December 9, 2014. ADAMS 21 No. ML14343A883. 22 [Exelon] Exelon Generation Company, LLC. undated. PJM TOA-AC July Meeting, At-Risk 23 Generation Retirement. 6 p. Available at <http://www.pjm.com/~/media/committees-24 groups/committees/toa-ac/20100715/20100715-item-04-generation-retirements.ashx> 25 (accessed 31 August 2015). 26 [FERC] Federal Energy Regulatory Commission. 2013. Centralized Capacity Market Design 27 Elements. Commission Staff Report AD13-7-000. August 23, 2013. 34 p. Available at 28 <http://www.ferc.gov/CalendarFiles/20130826142258-Staff%20Paper.pdf> (accessed 29 31 August 2015). 30 Haq Z. undated. Biomass for Electricity Generation. U.S. Energy Information Administration. 31 18 p. Available at <http://www.eia.gov/oiaf/analysispaper/biomass/pdf/biomass.pdf> (accessed 32 31 August 2015). 33 [IEA] International Energy Agency. 2007. Biomass for Power Generation and CHP. IEA 34 Energy Technology Essentials ETE03. Available at 35 <https://www.iea.org/publications/freepublications/publication/essentials3.pdf> (accessed 36 4 September 2015). 37 [ILGA] Illinois General Assembly. 2011. Illinois Senate Bill 1652, Section 5, Illinois Power 38 Agency Act. Available at <http://www.ilga.gov/legislation/97/SB/09700SB1652enr.htm> 39 (accessed 31 August 2015). 40 Ilic J, Prica M, Rabiei S, Goellner J, Wilson D, Shih C (Booz Allen Hamilton, Inc.). 2011. 41 Technical and Economic Analysis of Various Power Generation Resources Coupled with CAES 42 Systems. National Energy Technology Laboratory. May 17, 2011. DOE/NETL-2011/1472. 43 96 p. Available at <http://www.netl.doe.gov/File%20Library/Research/ 44 Energy%20Analysis/Publications/HybridGeneration05242011.pdf> (accessed 31 August 2015). 2-30

Alternatives Including the Proposed Action 1 Mendelsohn M, Lowder T, Canavan B. 2012. Utility-Scale Concentrating Solar Power and 2 Photovoltaics Projects: A Technology and Market Overview. Golden, Colorado: National 3 Renewable Energy Laboratory. NREL/TP-6A20-51137. April 2012. 65 p. Available at 4 <http://www.nrel.gov/docs/fy12osti/51137.pdf> (accessed 31 August 2015). 5 Michaels T. 2010. The 2010 ERC Directory of Waste-to-Energy Plants. Washington, DC: 6 Energy Recovery Council. November 12, 2010. 32 p. Available at 7 <http://www.energyrecoverycouncil.org/userfiles/file/ERC_2010_Directory.pdf> (accessed 8 31 August 2015). 9 [MISO] Midcontinent Independent System Operator, Inc. 2011. 2011 Long Term Resource 10 Assessment. 34 p. Available at 11 <https://www.misoenergy.org/Library/Repository/Study/Seasonal%20Assessments/ 12 2011%20Long-Term%20Resource%20Assessment.pdf> (accessed 31 August 2015). 13 [MISO-PJM] Midcontinent Independent System Operator, Inc., and PJM Interconnection. 14 undated. Joint and Common Market. Available at <http://www.miso-pjm.com/> (accessed 15 31 August 2015). 16 Musial W (NREL), Ram B (Energetics). 2010. Large-Scale Offshore Wind Power in the 17 United States: Assessment of Opportunities and Barriers. Golden, Colorado: NREL. 18 NREL/TP-500-40745. September 2010. 240 p. Available at 19 <http://www.nrel.gov/docs/fy10osti/40745.pdf> (accessed 31 August 2015). 20 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 21 National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq. 22 [NETL] National Energy Technology Laboratory. 2007. Natural Gas Combined-Cycle Plant. 23 4 p. Available at 24 <http://www.netl.doe.gov/KMD/cds/disk50/NGCC%20Plant%20Case_FClass_051607.pdf> 25 (accessed 31 August 2015). 26 [NETL] National Energy Technology Laboratory. 2013a. Cost and Performance Baseline for 27 Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity. Revision 2a. 28 DOE/NETL-2010/1397, September 2013. 626 p. Available at 29 <http://www.netl.doe.gov/File%20Library/research/energy%20analysis/publications/ 30 BitBase_FinRep_Rev2.pdf> (accessed 31 August 2015). 31 [NETL] National Energy Technology Laboratory. 2013b. IGCC Project Examples. Available 32 at <http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/ 33 project-examples> (accessed 31 August 2015). 34 [NETL] National Energy Technology Laboratory. 2013c. Gasification Database: Proposed 35 U.S. Projects Having Commercial Potential. October 2013. Available at 36 <http://www.netl.doe.gov/File%20Library/research/coal/energy%20systems/gasification/ 37 worldwide%20database/US-Gasification-Database.xlsx> (accessed 31 August 2015). 38 [NETL] National Energy Technology Laboratory. undated. Supercritical Pulverized Bituminous 39 Coal Plant. 4 p. Available at <http://www.netl.doe.gov/KMD/cds/disk50/ 40 PC%20Plant%20Case_Supercritical_051507.pdf> (accessed 31 August 2015). 41 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement 42 for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG-1437, 43 Volumes 1 and 2. May 31, 1996. 1,204 p. ADAMS Nos. ML040690705 and ML040690738. 2-31

Alternatives Including the Proposed Action 1 [NRC] U.S. Nuclear Regulatory Commission. 2002. Final Generic Environmental Impact 2 Statement on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the 3 Decommissioning of Nuclear Power Reactors. NUREG-0586, Volumes 1 and 2. 4 Washington, DC: NRC. November 30, 2002. 516 p. ADAMS Nos. ML023470327, 5 ML023500228, and ML023500295. 6 [NRC] U.S. Nuclear Regulatory Commission. 2008. Final Environmental Impact Statement for 7 an Early Site Permit (ESP) at the Vogtle Electric Generating Plant Site. Washington, DC: NRC. 8 NUREG-1872, Volumes 1 and 2. August 2008. 1,242 p. Available at 9 <http://www.nrc.gov/reading-rm/doc-collections/nuregs/staff/sr1872/index.html> (accessed 10 31 August 2015). 11 [NRC] U.S. Nuclear Regulatory Commission. 2009. Frequently Asked Questions about License 12 Applications for New Nuclear Power Reactors. NUREG/BR-0468. December 2009. 110 p. 13 Available at <http://www.nrc.gov/reading-rm/doc-collections/nuregs/brochures/br0468/> 14 (accessed 31 August 2015). 15 [NRC] U.S. Nuclear Regulatory Commission. 2011. Final Supplemental Environmental Impact 16 Statement for Combined Licenses (COLs) for Vogtle Electric Generating Plant, Units 3 and 4, 17 Final Report. Washington, DC: NRC. NUREG-1947. March 2011. 568 p. ADAMS 18 No. ML11076A010. 19 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 20 for License Renewal of Nuclear Plants. Revision 1. Washington, DC: NRC. NUREG-1437, 21 Volumes 1, 2, and 3. June 30, 2013. 1,535 p. ADAMS Nos. ML13106A241, ML13106A242, 22 and ML13106A244. 23 [NRC] U.S. Nuclear Regulatory Commission. 2015. Status of License Renewal Applications 24 and Industry Activities. Available at <http://www.nrc.gov/reactors/operating/licensing/ 25 renewal/applications.html> (accessed 31 August 2015). 26 [NREL] National Renewable Energy Laboratory. 2014a. Dynamic Maps, GIS Data, and 27 AnalysisWind Data Details. February 6, 2014. Available at 28 <http://www.nrel.gov/gis/wind_detail.html> (accessed 4 September 2015). 29 [NREL] National Renewable Energy Laboratory. 2014b. Learning about Renewable Energy 30 Solar Energy Basics. July 25, 2014. Available at <http://www.nrel.gov/learning/re_solar.html> 31 (accessed 31 August 2015). 32 [NREL] National Renewable Energy Laboratory. 2015a. Dynamic Maps, GIS Data, and 33 Analysis ToolsWind Data. April 15, 2015. Available at 34 <http://www.nrel.gov/gis/data_wind.html> (accessed 4 September 2015). 35 [NREL] National Renewable Energy Laboratory. 2015b. Dynamic Maps, GIS Data, and 36 Analysis ToolsSolar Maps. February 2, 2015. Available at 37 <http://www.nrel.gov/gis/solar.html> (accessed 4 September 2015). 38 Ong S, Campbell C, Denholm P, Margolis R, Heath G. 2013. Land-Use Requirements for Solar 39 Power Plants in the United States. Golden, Colorado: National Renewable Energy Laboratory. 40 NREL/TP-6A20-56290. June 2013. 47 p. Available at 41 <http://www.nrel.gov/docs/fy13osti/56290.pdf> (accessed 31 August 2015). 42 [ORNL] Oak Ridge National Laboratory. 2012. An Assessment of Energy Potential at 43 Non-Powered Dams in the United States. Oak Ridge, Tennessee: ORNL. April 2012. 44 p. 44 Available at <http://www1.eere.energy.gov/water/pdfs/npd_report.pdf> (accessed 45 31 August 2015). 2-32

Alternatives Including the Proposed Action 1 Ott A. 2013a. Centralized Capacity Markets in Regional Transmission Organizations and 2 Independent System Operators. Norristown, Pennsylvania: PJM Interconnection, LLC. 3 October 3, 2013. 33 p. Available at <http://www.pjm.com/~/media/about-pjm/who-we-4 are/public-disclosures/20131004-board-response-to-chairman-powelson-regarding-generation-5 retirements.ashx> (accessed 31 August 2015). 6 Ott A. 2013b. PJM/MISO Seams Coordination and Capacity Deliverability. Norristown, 7 Pennsylvania: PJM Interconnection, LLC. June 20, 2013. 9 p. Available at 8 <http://www.ferc.gov/industries/electric/indus-act/rto/pjm.pdf> (accessed 31 August 2015). 9 [Reuters] Thomson Reuters. 2012. Southern, Duke push US coal gasification; others quit. 10 June 12, 2012. Available at <http://www.reuters.com/article/2012/06/12/ 11 utilities-coal-gasification-idUSL1E8H78P420120612> (accessed 31 August 2015). 12 [TEEIC] Tribal Energy and Environmental Information Clearinghouse. undated. Utility-Scale 13 and Direct Use Geothermal Energy Generation. Available at 14 <http://teeic.indianaffairs.gov/er/geothermal/restech/scale/index.htm> (accessed 15 31 August 2015). 16 Tidball R, Bluestein J, Rodriguez N, Knoke S (ICF International). 2010. Cost and Performance 17 Assumptions for Modeling Electricity Generation Technologies. Golden, Colorado: National 18 Renewable Energy Laboratory. NREL/SR-6A20-48595. November 2010. 211 p. Available at 19 <http://www.nrel.gov/docs/fy11osti/48595.pdf> (accessed 31 August 2015). 20 [USGS] U.S. Geological Survey. 2008. Assessment of Moderate- and High-Temperature 21 Geothermal Resources of the United States. Menlo Park, California: USGS. Fact 22 Sheet 2008-3082. 4 p. Available at <http://pubs.usgs.gov/fs/2008/3082/pdf/fs2008-3082.pdf> 23 (accessed 31 August 2015). 24 [WAPA and FWS] Western Area Power Administration and U.S. Fish and Wildlife Service. 25 2013. Upper Great Plains Wind Energy Programmatic Environmental Impact Statement, Draft. 26 DOE/EIS-0408. March 2013. 938 p. Available at 27 <http://plainswindeis.anl.gov/documents/dpeis/Draft_UGP_Wind_Energy_PEIS.pdf> (accessed 28 31 August 2015). 2-33

1 3.0 AFFECTED ENVIRONMENT 2 In this supplemental environmental impact statement (SEIS), the affected environment is the 3 environment that currently exists at and around LaSalle County Station, Units 1 and 2 (LSCS). 4 Because existing conditions are at least partially the result of past construction and operation at 5 the plant, the impacts of these past and ongoing actions and a discussion on how they have 6 shaped the environment are presented here. The facility and its operation are described in 7 Section 3.1. The affected environment is presented in Sections 3.2 to 3.13. 8 3.1 Description of Nuclear Power Plant Facility and Operation 9 LSCS is a two unit nuclear power plant located in LaSalle County, Illinois. It began commercial 10 operation in January 1984 (Unit 1) and October 1984 (Unit 2). Generally, the U.S. Nuclear 11 Regulatory Commission (NRC) staff drew information about LSCSs facilities and operation from 12 the Exelon Generation Company, LLC (Exelon), Environmental Report (ER) (Exelon 2014a). 13 3.1.1 External Appearance and Setting 14 The LSCS site is approximately 82 driving miles (mi) (132 kilometers (km)) southwest of OHare 15 International Airport in Chicago, Illinois, and approximately 26 mi (42 km) west of Exelons 16 Braidwood Generating Station in Braceville, Illinois. Interstate Highway 80 is 8 mi (13 km) north 17 of the site. Figure 3-1 presents the 50-mi (80-km) area around LSCS. 18 The LSCS site is located in a rural and agricultural setting. However, the surroundings are 19 dominated by many wind turbines. Each wind turbine is 389 feet (ft) (119 meters (m)) tall (which 20 includes the length of one of its three 126.5-ft (38.5-m) rotator blades). The town of Seneca lies 21 6 mi (10 km) northeast of LSCS. The town of Marseilles lies 7 mi (11 km) north-northwest of 22 LSCS. The Illinois River is 5 mi (8 km) north of LSCS. The Chicago, Rock Island and Pacific 23 Railroad, which runs parallel to, and slightly north of, the Illinois River, is the closest railroad line 24 in this area. A 6-mi (10-km) rail spur connects LSCS to the Atchison, Topeka, and Santa Fe 25 Railroad south of the site (Exelon 2014a). Figure 3-2 presents the 6-mi (10-km) area around 26 LSCS. 27 The LSCS site is approximately 3,776 acres (ac) (1,528 hectares (ha)) of which approximately 28 2,058 ac (833 ha) are the cooling pond. Underground pipelines approximately 3.5 mi (5.6 km) 29 long connect the cooling pond to the Illinois River, which is the source of the plants makeup 30 water and the receiving body of water for plant discharges. This pipeline corridor right-of-way 31 intersects the eastern portion of the Marseilles State Fish and Wildlife Area, which is managed 32 by the Illinois Department of Natural Resources (IDNR) for hunting and wildlife habitat. Country 33 Road 6 (also known as North 21st Road) provides access to LSCS and runs along the sites 34 southern boundary (Exelon 2014a). Figure 3-3 presents the LSCS site layout. 35 The LSCS sites main structures include two reactor buildings, an auxiliary building (which 36 houses the control room), a turbine building, a diesel generator building, a switchyard, a training 37 building, an interim radioactive waste (radwaste) storage facility, a radwaste building, sewage 38 and wastewater treatment facilities, and an independent spent fuel storage installation (ISFSI). 39 The sites tallest structure is a 400-ft (122-m) meteorological tower. The area of the LSCS site 40 that is completely enclosed by physical barriers and that allows access only at designated 41 control points is called the protected area. A physical protection program at the LSCS site 42 includes surveillance, observation, and monitoring within the protected area (Exelon 2014a). 43 Figure 3-4 presents the LSCS plant features. 3-1

Affected Environment 1 Figure 3-1. LSCS 50-mi (80-km) Radius Map 2 Source: Exelon 2014a 3-2

Affected Environment 1 Figure 3-2. LSCS 6-mi (10-km) Radius Map 2 Source: Exelon 2014a 3-3

Affected Environment 1 Figure 3-3. LSCS Site Layout 2 Source: Exelon 2014a 3-4

Affected Environment 1 Figure 3-4. LSCS Plant Features 2 Source: Exelon 2014a 3-5

Affected Environment 1 3.1.2 Nuclear Reactor Systems 2 The nuclear reactor for each of the two LSCS units is a General Electric boiling water reactor 3 (BWR/5) with Mark II containment. Each LSCS reactor is licensed to produce core power of 4 3,546 megawatts thermal. The annual mean net electrical power capacity for LSCS is 5 2,327 megawatts electric. LSCS uses a 2,058-ac (833-ha) diked cooling pond for core cooling 6 and withdraws makeup water from, and discharges to, the Illinois River (Exelon 2014a). 7 LSCS operates using low-enriched uranium dioxide fuel with enrichment not exceeding a 8 nominal 5.0 percent by weight of uranium-235 and has been historically operated within a 9 maximum analyzed fuel burnup rate of 62,000 megawatt-days per metric ton of 10 uranium (MWd/MTU). In its ER, Exelon stated that, during some future fuel cycles, it expects 11 the peak fuel burnup rate to exceed 62,000 MWd/MTU in some part-length fuel rods. 12 Addendum 1 to Volume 1 of NUREG-1437, Generic Environmental Impact Statement for 13 License Renewal of Nuclear Power Plants (GEIS) (NRC 1999), states that the environmental 14 impacts would be small for transporting spent fuel enriched with up to 5-percent uranium-235 15 with an average burnup for the peak rod of up to 62,000 MWd/MTU. It also states that, if peak 16 fuel burnup is projected to exceed 62,000 MWd/MTU, license renewal applicants must submit 17 an assessment of the implications for the environmental impacts. Exelon submitted an 18 assessment of the environmental impacts of transporting spent fuel enriched with an average 19 burnup for the peak rod exceeding 62,000 MWd/MTU in Section 4.13 of its ER. Appendix G of 20 this document provides the NRC staffs analysis of these projected environmental impacts. 21 Refueling outages for LSCS, Units 1 and 2, are on a staggered 24-month schedule 22 (Exelon 2014a). 23 3.1.3 Cooling and Auxiliary Water Systems 24 LSCS uses a closed-cycle, recirculating cooling system that includes an artificial cooling pond 25 for heat dissipation. In this type of closed-cycle system, the cooling pond serves as the primary 26 source of water to cool plant components and as the primary receiving body for excess heat. 27 In BWRs like those used at LSCS, steam is produced directly in each reactor vessel. The 28 steam passes through moisture separators and steam dryers and then flows to the turbine. 29 Such systems contain only two heat transfer (exchange) loops. The primary loop transports the 30 steam from the reactor vessel directly to the turbine, which generates electricity. The secondary 31 cooling loop removes excess heat from the primary loop in the main condenser. From the 32 condenser, the primary condensate is returned as feedwater to the reactor, and the secondary 33 cooling loop removes the excess heat (NRC 2013). At LSCS, condenser cooling water is 34 discharged directly to the cooling pond, where the heat is dissipated through mixing and 35 evaporation (Exelon 2014a). 36 Cooling water that is not otherwise lost from the pond through evaporation or seepage or that is 37 consumed in the process is recirculated from the cooling pond through the condenser systems 38 in a continuous loop. In addition, a portion of the water in the cooling pond is discharged as 39 blowdown on a near continuously basis under normal conditions. (Blowdown is water that is 40 rinsed from the cooling system (i.e., cooling pond) to remove impurities that may degrade plant 41 performance.) Total dissolved solids are the primary constituents of concern to prevent scale 42 buildup on plant components. 43 All water lost from the recirculating system must be replaced with fresh water; this water is 44 referred to as makeup water (Exelon 2014a; NRC 2013). Makeup water for the onsite cooling 45 pond is withdrawn from, and blowdown is discharged to, the Illinois River, which lies 3.5 mi 46 (5.6 km) north of LSCSs cooling pond. The intake and blowdown pipelines are routed through 3-6

Affected Environment 1 a common right-of-way corridor. Figure 3-5 provides a basic schematic diagram of a 2 closed-cycle, recirculating cooling system that uses a cooling pond. 3 Figure 3-5. Closed-Cycle Cooling System with Cooling Pond 4 Source: Modified from NRC 2013, Figure 3.1-4 5 Groundwater is also used by LSCS for potable water, sanitary water, and demineralized water 6 makeup systems. 7 Unless otherwise cited, the NRC primarily drew information about LSCSs cooling and auxiliary 8 water systems from Exelons ER (Exelon 2014a, 2015b) and its Updated Final Safety Analysis 9 Report (UFSAR) (Exelon 2014b). The NRC staff visited the facilities cited herein during the 10 May 2015 environmental site audit (NRC 2015b). Descriptions of the individual plant cooling 11 and auxiliary systems and components that interact with the environment are provided below. 12 Cooling Pond and Ultimate Heat Sink. Water for the circulating water system (CWS) for 13 condenser cooling water and for the plant service water system are supplied directly from the 14 cooling pond. 15 The LSCS cooling pond is an engineered impoundment encompassing 2,058 ac (833 ha) with 16 an average depth of 15 ft (4.7 m) (NRC 1978) (Figure 3-6). The pond has an elevation of 700 ft 17 (213 m) above mean sea level (MSL) at normal pool elevation. At this water elevation, the 18 cooling pond has a storage capacity of 31,706 acre-feet (39 million cubic meters (m3)) of water. 19 This impoundment was formed by constructing earthen dikes to enclose the north, east, and 20 south sides of the pond; the natural levee of the Illinois River forms the fourth side. Engineered 21 fill consisting of silty-clay, taken from borrow areas within the pond basin, was used in the 22 construction of these peripheral dikes. A perimeter drainage ditch designed to intercept runoff 23 and to capture and direct seepage toward surface drainages and away from the dikes flanks the 24 ponds dikes (Exelon 2014b). 25 Integral to the ponds construction are three internal baffle or finger dikes (i.e., earthen berms), 26 that total 22,623 ft (6,895 m) in length. These structures direct the flow of water from the 27 discharge canal and through the pond to ensure that the coolest water is available for use by 28 LSCS (Exelon 2014b) (Figure 3-6). The average residence time for water in the cooling pond is 29 5.5 days (NRC 1978). 3-7

Affected Environment 1 The peripheral dike system that encloses the cooling pond includes a 300-ft- (91-m)-wide 2 auxiliary spillway structure. The spillway is located northwest of the main plant complex and is 3 adjacent to the discharge canal. The structure is capable of passing a volume of 4 1,069,000 gallons per minute (gpm) (2,380 cubic feet per second (cfs) or 67.2 meters per 5 second (m/s)) of water associated with the probable maximum water level. Discharge from the 6 structure flows north to South Kickapoo Creek, a tributary to the Illinois River (Exelon 2014b). 7 A dedicated portion of the cooling pond located immediately adjacent to the LSCS intake canal 8 serves as the plants ultimate heat sink (UHS). It is also known as the core standby cooling 9 system (CSCS) pond and directly supplies the CSCS equipment cooling water system, as 10 discussed below. This excavated area comprises 83 ac (34 ha) in size and is 5 ft (1.5 m) deep 11 below grade. It can hold 460 acre-feet (567,000 m3) of water. This volume of water is sufficient 12 to supply 30 days of cooling water following safe shutdown from normal operating or accident 13 conditions. The CSCS pond can function even if the perimeter dikes of the cooling pond are 14 breached (Exelon 2014b). 15 Illinois River Water Makeup System. Cooling pond makeup water is withdrawn via the river 16 screen house located on the south bank of the Illinois River at Illinois River Mile (RM) 249.5 17 (River Kilometer (RKm) 401.5) (Figure 3-6). The river screen house is situated approximately 18 3.5 mi (5.6 km) north of the cooling pond. The structure is designed to withstand the 100-year 19 flood of the Illinois River (Exelon 2014b). 20 The river screen house contains three makeup water pumps, each with a capacity of 21 30,000 gpm (67 cfs or 1.9 cubic meters per second (m3/s)). Two pumps are normally operated 22 at all times to meet cooling pond makeup demands, with the third serving as a backup. 23 However, when reduced evaporation demands allow (winter months), the pump discharge ball 24 valves are closed to 30 degrees (one-third open) (Exelon 2015c). 25 River water is first drawn through an intake flume in the bottom of the river and then into a 26 72-ft-- (22-m)-wide funnel inlet basin with concrete dam located 24 ft (7 m) from the shoreline 27 frontage of the river screen house. The inlet is protected by a floating log boom to deflect river 28 debris. From the inlet, water then enters the intake forebay of the screen house and passes first 29 through two adjacent bar grills and then through vertical traveling screens with 3/8-inch (in.) 30 (0.95-centimeter (cm)) openings before entering the pumps (Exelon 2014a, 2015a). The bar 31 grills are galvanized steel and measure 3/8 in. (0.95 cm) thick and 4 in. (10 cm) wide. The 32 narrow dimension of each bar is oriented perpendicular to the incoming water flow, and the 33 centerlines of the narrow dimension of adjacent bars are spaced 3 in. (7.6 cm) apart 34 (Exelon 2015c). 35 Water velocity in the river intake channel is reported as ranging from 0.3 to 0.5 feet per second 36 (fps) (0.10 to 0.15 m/s) with one pump operating and 0.6 to 1.0 fps (0.2 to 0.3 m/s) with two 37 pumps operating. Flow velocity at the travelling screens ranges from about 0.5 to 0.9 fps 38 (0.15 to 0.3 m/s) with one and two makeup pumps in full operation, respectively (NRC 1978; 39 Exelon 2014a). In NRCs Final Environmental Statement for the operating license of LSCS, the 40 NRC staff estimated that the intake velocity at the face of the traveling screens would be 0.5 fps 41 (0.2 m/s) 93 percent of the time and 1.0 fps (0.3 m/s) the remaining 7 percent of the time 42 (NRC 1978). Exelon has not performed any operational studies to further characterize intake 43 flow velocities (Exelon 2015c). Based on the assessment the NRC performed for LSCSs 44 operating license (NRC 1978), the velocity at the face of the traveling screens would typically be 45 within the 0.5fps (0.15m/s) intake velocity now recommended by the U.S. Environmental 46 Protection Agency (EPA) for protection of aquatic organisms (Volume 69 of the Federal 47 Register, page 41576 (69 FR 41576)), although the velocity may be closer to 1.0 fps (0.3m/s) 48 during certain periods during operations. 3-8

Affected Environment 1 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities 2 Sources: Modified from Exelon 2014a, 2015b 3-9

Affected Environment 1 A backwash system removes debris from the river intake traveling screens, and trash rakes 2 remove debris from bar grills. The backwash system can be set to operate in automatic or 3 manual mode, but the system is normally left in automatic mode unless high debris loading 4 requires manual cleaning. In automatic mode, cleaning is initiated when the measured 5 differential water level across the screens reaches 4 in. (10 cm). With a differential water level 6 of 6 in. (15 cm), the system switches to fast speed. A differential level in excess of 16 in. 7 (40 cm) for at least 15 seconds will cause the associated makeup pumps to trip to prevent 8 cavitation damage. Manual mode with either a slow or fast speed setting may be used during 9 periods of high debris loading (Exelon 2015c). 10 Collected debris, including any impinged biota, is deposited in a trash basket located outside the 11 river screen house, with the debris ultimately disposed of in an offsite permitted landfill. The 12 river screen house is not equipped with a fish return system. Screen backwash and other 13 intermittent discharges from the screen house are discharged to the Illinois River through a 14 National Pollutant Discharge Elimination System (NPDES)-permitted outfall (Outfall 002). The 15 intake forebay of the facility has a floating oil boom to prevent any oil leaks from the screen 16 house from entering the river. Section 3.5.1.3 of this SEIS presents additional information on 17 water quality and LSCSs NPDES permit. 18 With all three river makeup water pumps in operation, LSCSs maximum surface water makeup 19 supply capacity is 90,000 gpm (200 cfs or 5.66 m3/s), which is equivalent to 129.6 million 20 gallons per day (mgd) (491,000 cubic meters per day (m3/day)). Normal peak makeup 21 withdrawal from the Illinois River, with two pumps operating, is 60,000 gpm (134 cfs or 22 3.77 m3/s) or 86.4 mgd (327,000 m3/day). Surface water use is detailed in Section 3.5.1.2. 23 From the river screen house, intake water is pumped south to the northern end of the LSCS 24 cooling pond through a 60-in. (152-cm) pipeline. Upon reaching the pond, the water is 25 conveyed into the pond through a reinforced concrete discharge structure located on the north 26 side of the ponds discharge canal. The structure is designed to prevent erosion of the cooling 27 pond dike (Exelon 2014b) (see Figure 3-6). 28 The river intake pipeline is equipped with air and vacuum relief valves along its course to help 29 guard against pressure surges and other conditions that sometimes occur due to elevation 30 changes along its routing. Nevertheless, the makeup pipeline, which is not a safety-related 31 structure, has experienced a number of breaks resulting in flooding and erosion of areas 32 surrounding the break. The most recent such break occurred on January 23, 2014. Exelon 33 reported the break to both the Illinois Environmental Protection Agency (IEPA) and EPA 34 Region V in accordance with the reporting provisions of Exelons NPDES permit 35 (Exelon 2015c). 36 To address issues associated with pipeline breaks, Exelon has performed maintenance, 37 including replacing relief valves, and has installed instrumentation on the intake traveling 38 screens to alert the LSCS control room operators to abnormal conditions. Exelon has also 39 modified operating and response procedures and has implemented plans and procedures to 40 prevent and quickly respond to any breaks. For example, operational procedures have been 41 modified to include checks on pipeline integrity and to ensure necessary parts are maintained to 42 replace a section of pipeline should a break occur (Exelon 2014a, 2015a). 43 CWS and Blowdown Discharge. The CWS provides cooling water to the main condensers. In 44 addition to the condensers, the system includes the cooling pond, lake screen house, circulating 45 water pumps, piping, valves, and related equipment. The system normally supplies water to the 46 main condensers at temperatures ranging from 32 °F to a maximum of 100 °F (0 to 37.8 °C). 47 However, operating license technical specifications (TS) limit the temperature of the cooling 3-10

Affected Environment 1 water supplied to the facility from the UHS portion of the cooling pond to 101.25 °F (38.5 °C) 2 (Exelon 2014b). 3 The main condenser of each unit requires 616,500 gpm (1,373 cfs or 38.8 m3/s), or 888 mgd 4 (3.36 million m3) of circulating water flow to remove waste heat at 100-percent load. Cooling 5 water is withdrawn from the cooling pond through the lake screen house, which is located at the 6 west end of the intake canal (Figure 3-6). The lake screen house contains six circulating water 7 pumps (three for each unit) that take suction from the service water tunnel (Exelon 2014a). 8 Each pump has a capacity of 205,500 gpm (457.7 cfs or 12.9 m3/s) (Exelon 2015c), with two 9 pumps normally in operation per unit to supply water to the condensers. Water first enters the 10 intake forebays after passing through bar grills and traveling screens with 3/8-in. (0.95-cm) 11 openings. Trash rakes prevent larger debris and aquatic biota from entering the system. The 12 design water intake velocity at the screens is approximately 2.2 fps (0.7 m/s), assuming clean 13 screens. Debris removed from the traveling screens by the screen backwash system and from 14 the bar grills by trash rakes is collected in a trash basket and disposed of in an offsite permitted 15 landfill. Similar to the river intake backwash system, the circulating water backwash system can 16 be operated in either automatic or manual mode. When in automatic mode with a differential 17 water level across the screens ranging between 0 and 6 in. (0 to 15 cm), a timer initiates a 18 3-minute wash cycle every 12 to 14 hours0.583 days <br />0.0833 weeks <br />0.0192 months <br />. With a differential level rising to between 6 and 19 10 in. (15 to 25 cm), a continuous backwash cycle starts at slow speed. The fast setting is 20 triggered with a differential water level exceeding 10 in. (25 cm). Manual mode may be used 21 during fish runs or other periods of high debris intake (Exelon 2015c). Like the river screen 22 house, the lake screen house has no fish return system (Exelon 2014a, 2014b). 23 From the lake screen house, water is pumped through the main condenser of each unit. 24 A chemical feed system, located in facilities adjacent to the lake screen house, injects biocide 25 and other chemical treatments to reduce biofouling, silting, and scale buildup in the condenser 26 systems. After passing through the unit condensers, heated circulating water is returned to the 27 cooling pond through the discharge canal. The nominal (design) temperature rise in the 28 circulating water passing through the main condensers is approximately 26.7 °F (10 °C) 29 (Exelon 2014b). 30 As previously stated, a series of parallel dikes in the cooling pond direct and slow the rate of 31 movement of the returned cooling water through the pond to facilitate residence time cooling 32 processes so that the coolest water is available for uptake again at the lake screen house. 33 This heat dissipation is necessary so that cooling pond blowdown to the Illinois River meets 34 temperature limitations and mixing zone requirements under the Illinois thermal water quality 35 standards (35 IAC 302) and Special Condition 3 of Exelons NPDES Permit No. IL0048151 36 (IEPA 2013). The permit also authorizes the discharge of various other effluent streams to the 37 cooling pond in addition to condenser cooling water, as further described in Section 3.5.1.3 of 38 this SEIS. 39 Blowdown combined with other comingled effluent streams flows through an open channel 40 originating at the west shore of the cooling pond (UHS portion) and then northwest to a spillway 41 adjacent to the LSCS discharge canal. This combined effluent stream can include processed 42 liquid radioactive waste (radwaste), which may be discharged on a batch basis directly into the 43 cooling pond blowdown line at a maximum rate of 45 gpm (0.17 cubic meters per minute), as 44 further described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Nevertheless, the blowdown 45 line is equipped with a radiation monitor that will automatically isolate the radwaste discharge 46 line in the event of a high-radiation signal (Exelon 2014b). 47 The blowdown spillway connects to a 66-in. (168-cm) diameter pipeline through which the 48 collected blowdown travels underground via gravity flow. The pipeline discharges into an 3-11

Affected Environment 1 approximately 500-ft- (150-m)-long discharge structure consisting of a plunge pool and rip-raped 2 lined swale that connects with the Illinois River at RM 249.4 (RKm 401) and just upstream of the 3 LSCS river screen house (see Figure 3-6). The maximum blowdown rate of the system is 4 equal to the maximum intake rate of 90,000 gpm (200 cfs or 5.66 m3/s). However, 5 motor-operated values at both the river and lake ends of the discharge line can be used to 6 isolate the pipeline for maintenance and are used to adjust the blowdown to an average of 7 58,000 gpm (129 cfs or 3.65 m3/s) or less with a target annual average of 30,000 gpm (67 cfs or 8 1.89 m3/s) (Exelon 2014a, 2014b). The blowdown discharge point is regulated under LSCSs 9 NPDES permit as Outfall 001 (see Section 3.5.1.3). 10 Because the blowdown pipeline functions under gravity flow, it is less susceptible to surges and 11 breakage than the river intake pipeline. It is also equipped with air and vacuum relief valves. 12 Nevertheless, breaks do occur. The most recent such break occurred on July 13, 2012. Exelon 13 reported the break to both the IEPA and EPA Region V. As discussed above for the makeup 14 pipeline, Exelon has implemented a program to reduce the frequency of breaks and their 15 impacts on operations and the environment (Exelon 2015c). 16 Plant Service Water System. The service water system provides cooling water for various 17 nonsafety-related auxiliary systems and components, including cooling water for the turbine 18 generator; various air conditioning condensers; and the fuel pool, turbine building, and reactor 19 building heat exchangers. It also supplies water for the lake screen house traveling screen 20 backwash system and the radwaste system, and it is used to fill the fire protection system and 21 serves as a backup fire water supply. Service water is normally supplied by four pumps, with a 22 fifth pump serving as a backup, located in the lake screen house. Each pump has a capacity of 23 16,000 gpm (35.6 cfs or 1.01 m3/s). The pumps take suction from the lake screen house intake 24 service water tunnel and discharge into a common header. Automatic backwash strainers 25 remove any debris that might be passed through the circulating water screens. In addition, the 26 system has two jockey pumps rated at 5,000 gpm (11.1 cfs or 0.31 m3/s). These pumps are 27 powered by an emergency diesel generator and are used to meet minimum flow requirements 28 during a loss of offsite power. The service water is also treated by the chemical feed system to 29 guard against biofouling, scale buildup, corrosion, and silting. Chemical injection occurs directly 30 to the service water tunnel feed lines. All service water return flows are discharged back to the 31 cooling pond (Exelon 2014a, 2014b). 32 Fire Protection Water System. The cooling pond is the source of fire protection water for the 33 LSCS fire hydrants, the water sprinkler and deluge systems, and the hose valve stations. 34 One of two 75-gpm (0.17-cfs or 0.005-m3/s) jockey pumps normally keep the system 35 pressurized. If a system demand occurs, a 225-gpm (0.50-cfs or 0.014-m3/s) intermediate 36 pump is activated. If the demands of the intermediate pump are exceeded, the first of two 37 diesel-driven pumps are automatically engaged. These pumps, each with a capacity of 38 2,500 gpm (51 cfs or 1.44 m3/s), are located in the lake screen house and take suction directly 39 from the service water tunnel (Exelon 2014b). 40 Core Standby Cooling System. This system is equivalent in purpose to the essential service 41 water systems at other nuclear power plants and provides cooling water for the purpose of 42 cooling safety-related equipment necessary for safe shutdown of the reactors. This equipment 43 includes the residual heat removal heat exchangers, pump seal coolers, and emergency diesel 44 generators; the system also provides emergency spent fuel pool makeup water and a source of 45 water for containment flooding for post-accident recovery. The CSCS withdraws cooling pond 46 water from the UHS portion of the cooling pond (as discussed earlier) via the lake screen house 47 service water tunnel. The water is chemically treated by the chemical feed system as previously 48 described. As a safeguard against blockage of the traveling screens ahead of the service water 49 channel, the system has a 54-in. (137-cm) bypass line that can be opened to directly supply 3-12

Affected Environment 1 CSCS water. All pumps and strainers for conveying emergency cooling water are located in 2 watertight spaces within the basements of the various plant buildings (Exelon 2014a, 2014b). 3 Potable Water System. LSCS uses groundwater from two deep wells (Nos. 1 and 2) to supply 4 potable (drinking) water, sanitary water, and raw makeup water for the demineralized water 5 system. The wells were installed during plant construction with completion depths of 1,629 ft 6 (497 m) and 1,620 ft (494 m), respectively (Exelon 2014a). Each well has a pump capacity of 7 300 gpm (1.14 cubic meters per minute) (Exelon 2014b). Water is stored in a 350,000-gallon 8 (gal) (1,325-m3) storage tank before distribution. The plant supply wells and LSCSs 9 groundwater use are further discussed in Section 3.5.2.2. 10 3.1.4 Radioactive Waste Management Systems 11 As part of normal operations and as a result of equipment repairs and replacements due to 12 normal maintenance activities, nuclear power plants routinely generate both radioactive and 13 nonradioactive wastes. Nonradioactive wastes include hazardous and nonhazardous wastes. 14 There is also a class of waste, called mixed waste that is both radioactive and hazardous. The 15 systems used to manage (i.e., treat, store, and dispose of) these wastes are described in this 16 section. Waste minimization and pollution prevention measures commonly employed at nuclear 17 power plants are also discussed in this section. 18 All nuclear plants were licensed with the expectation that they would release very limited 19 quantities of radioactive material to both the air and water during normal operation. However, 20 NRC regulations require that gaseous and liquid radioactive releases from nuclear power plants 21 must meet radiation dose-based limits specified in Title 10 of the Code of Federal Regulations 22 (10 CFR) Part 20, and the as low as is reasonably achievable (ALARA) criteria in Appendix I to 23 10 CFR Part 50. Regulatory limits are placed on the radiation dose that members of the public 24 can receive from radioactive effluents released by a nuclear power plant. All nuclear power 25 plants use radioactive waste management systems to control and monitor radioactive wastes. 26 LSCS uses liquid, gaseous, and solid waste processing systems to collect and process, as 27 needed, radioactive materials produced as a by-product of plant operations. The liquid and 28 gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 29 discharge into the environment. This is to ensure that the dose to members of the public from 30 radioactive effluents is reduced to levels that are ALARA in accordance with NRCs regulations. 31 The radioactive material removed from the effluents is converted into a solid form for eventual 32 disposal at a licensed radioactive disposal facility. 33 Exelon has a radiological environmental monitoring program (REMP) to assess the radiological 34 impact, if any, to the public and the environment from radioactive effluents released during 35 operations at LSCS. The REMP measures the aquatic, terrestrial, and atmospheric 36 environment for radioactivity, as well as the ambient radiation. In addition, the REMP measures 37 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 38 material, including radon) (Teledyne 2015). 39 LSCS has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 40 parameters used to calculate offsite doses resulting from liquid and gaseous radioactive 41 effluents. These methods are used to ensure that radioactive material discharges from the plant 42 meet NRC and EPA regulatory dose standards. The ODCM also contains the requirements for 43 the REMP (Exelon 2013d). 44 3.1.4.1 Radioactive Liquid Waste Management 45 LSCS Units 1 and 2 share a common liquid radioactive waste system (LRWS). The LRWS 46 collects, monitors, and processes any potentially radioactive liquid wastes produced in the plant. 3-13

Affected Environment 1 The LRWS also recycles as much processed liquid waste as can be accommodated within the 2 LSCS water balance. Although LSCS tries to limit any radioactive releases via the liquid 3 pathway, discharges from the system are authorized and may occur if treated waste water is not 4 needed for other plant uses. The LRWS is designed so that any liquid radioactive waste 5 discharged from the site will have radioactive nuclide concentrations below the limits specified in 6 10 CFR Part 20 and Appendix I to10 CFR Part 50. 7 Processing of liquids in the LRWS results in a clean product stream and a reject stream. The 8 clean product stream returns water for use by the main plant systems via the condensate 9 storage tanks if the water quality is found acceptable and if the plant has the need for the 10 makeup water. Water in the reject stream is processed for disposal in the solid radioactive 11 waste system. Unused treated waste water can be sent to a discharge tank and held until a 12 discharge batch accumulates. Before any release of a discharge batch, it would be sampled 13 and treated if necessary to ensure radionuclide concentrations and resulting radiation doses to 14 LSCS personnel and the general public comply with NRC regulations in 10 CFR Part 20 and 15 Appendix I to 10 CFR Part 50. The LWRS sends discharge batches directly into the cooling 16 pond blowdown line. 17 The LRWS consists of a waste processing subsystem, a floor drain processing subsystem, a 18 chemical waste subsystem, and a sludge subsystem. All subsystems are shared by LSCS 19 Units 1 and 2. A vendor-provided liquid waste treatment system is also available to supplement 20 the LRWS if needed. 21 The waste processing subsystem collects and processes water from sources such as 22 equipment drains. This water is treated by settling, filtration, and demineralization. After 23 treatment and sampling, the water is returned for reuse through the condensate storage tanks. 24 The floor drain processing subsystem collects and processes water from the floor drain 25 systems. After treatment and sampling, the water is returned for reuse through the condensate 26 storage tanks. The chemical waste subsystem collects and processes water from areas like the 27 laboratory drains and the radwaste building sump. After treatment and sampling, plant 28 procedures are used to determine where the processed water goes, which may include 29 discharge. The sludge subsystem is not a processing stream, but rather a group of tanks and 30 associated pumps that serve as an interface between the LRWS and the solid radioactive waste 31 handling system. After radioactive contaminants have been removed from the LRWS, 32 concentrated, and treated or held up to allow radioactive decay if necessary, they are 33 transferred to the solid radioactive waste system for processing, temporary storage, and 34 shipment for disposal. 35 The use of these radioactive waste systems and the procedural requirements in the ODCM 36 ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 37 dose standards. 38 Dose estimates for members of the public are calculated based on radioactive liquid effluent 39 release data and aquatic transport models. Exelons annual radiological effluent release report 40 contains the radioactive liquid effluents release data from LSCS and the resultant calculated 41 doses. The NRC staff reviewed 5 years of radioactive effluent release data: 2010 through 2014 42 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year period provides a data set that covers a 43 broad range of activities that occur at a nuclear power plant, such as refueling outages, routine 44 operation, and maintenance activities that can affect the generation of radioactive effluents. 45 LSCS did not have any radioactive liquid effluent releases over the period of 2010 through 46 2014. 47 Since LSCS had no radioactive liquid effluent releases for the period of 2010 through 2014, its 48 radioactive liquid effluent control program showed that radiation doses to members of the public 3-14

Affected Environment 1 were controlled within the NRCs and EPAs radiation protection standards contained in 2 Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR Part 190. Also, since LSCS had no 3 radioactive liquid effluent releases for the period of 2010 through 2014, no adverse trends were 4 observed in the dose levels. 5 Routine plant refueling and maintenance activities currently performed will continue during the 6 license renewal term. Based on the past performance of the radioactive waste system to 7 maintain doses from radioactive liquid effluents to be ALARA, similar performance is expected 8 during the license renewal term. 9 3.1.4.2 Radioactive Gaseous Waste Management 10 LSCS Units 1 and 2 share a common gaseous radioactive waste system (GRWS) with a 11 common vent stack located on the roof of the containment building between the two units. The 12 GRWS is designed to process and control radioactive gases and minimize the amount of 13 radioactive gaseous material released into the environment. The gaseous radioactive wastes 14 released consist primarily of xenon, argon, iodine, tritium, and carbon. The steam in a BWR 15 plant such as LSCS contains impurities in the form of radioactive gases that are continuously 16 removed during plant operation from the main condenser by an air ejector. This process is the 17 major source of radioactive gases generated by LSCS (Exelon 2014a). The GRWS removes 18 some radioactive gases and delays the release of other radioactive gases by adsorption on 19 charcoal beds to allow time for radioactive decay. As a final step, the gaseous waste stream 20 passes through a high efficiency particulate air filter, and is discharged through the common 21 vent stack. Other plant facilities that are potential sources of radioactive gas emissions include 22 the primary containment, the secondary containments (reactor buildings), the turbine buildings, 23 and the radwaste building. The ventilation systems in each of these facilities have filtration and 24 treatment systems that the air passes through before being discharged through the vent stack 25 (Exelon 2014a). 26 The use of these radioactive waste systems and the procedural requirements in the ODCM 27 ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 28 dose standards. 29 Dose estimates for members of the public are calculated based on radioactive gaseous effluent 30 release data and atmospheric transport models. Exelons annual radioactive effluent release 31 report contains a detailed presentation of the radioactive gaseous effluents released from LSCS 32 and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 33 release data: 2010 through 2014 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year 34 period provides a data set that covers a broad range of activities that occur at a nuclear power 35 plant, such as refueling outages, nonrefueling outage years, routine operation, and maintenance 36 activities that can affect the generation of radioactive effluents. The NRC staff compared the 37 data against NRC dose limits and looked for indication of adverse trends (i.e., increasing dose 38 levels) over the period of 2010 through 2014. Since the radioactive gaseous effluents are 39 released from a common vent stack shared by both Unit 1 and Unit 2, the resultant calculated 40 doses presented in the effluent release are divided in half to evaluate compliance with the 41 Appendix I to 10 CFR Part 50 dose criteria. The following summarizes the calculated doses 42 from radioactive gaseous effluents released from LSCS Units 1 and 2 during 2014: 43 Unit 1 44

  • The air dose at the site boundary from gamma radiation in gaseous effluents from 45 LSCS was 2.36x102 millirad (mrad) (2.36x104 milligray (mGy), which is well below 46 the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

3-15

Affected Environment 1

  • The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 2 was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 3 dose criterion in Appendix I to 10 CFR Part 50.

4

  • The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 5 carbon-14 from LSCS was 4.56x101 millirem (mrem) (4.56x103 millisievert (mSv)),

6 which is well below the 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR 7 Part 50. 8 Unit 2 9

  • The air dose at the site boundary from gamma radiation in gaseous effluents from 10 LSCS was 2.36x102 mrad (2.36x104 mGy), which is well below the 10 mrad 11 (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

12

  • The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 13 was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 14 dose criterion in Appendix I to 10 CFR Part 50.

15

  • The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 16 carbon-14 from LSCS was 4.56x101 mrem (4.56x103 mSv), which is well below the 17 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50.

18 The NRC staffs review of LSCSs radioactive gaseous effluent control program showed that 19 radiation doses to members of the public were controlled within NRCs and EPAs radiation 20 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 21 40 CFR Part 190. No adverse trends were observed in the dose levels. 22 Routine plant refueling and maintenance activities currently performed will continue during the 23 license renewal term. Based on the past performance of the radioactive waste system to 24 maintain doses from radioactive gaseous effluents to be ALARA, similar performance is 25 expected during the license renewal term. 26 3.1.4.3 Radioactive Solid Waste Management 27 LSCS Units 1 and 2 share a common solid radioactive waste system (SRWS). The SRWS 28 receives, dewaters, solidifies, packages, handles, and provides temporary storage facilities for 29 all radioactive wet solid wastes prior to offsite shipment and disposal in accordance with NRC 30 regulations in 10 CFR Parts 61 and 71. It also receives, decontaminates, compacts 31 (as necessary), and provides temporary storage facilities for all radioactive dry wastes prior to 32 offsite shipment and disposal (Exelon 2014a). Transportation of the radioactive solid waste is 33 governed by the U.S. Department of Transportation regulations in 49 CFR Parts 171 to 178. 34 LSCS disposes of solid radioactive waste at facilities in Utah and Texas. LSCS also utilizes 35 offsite vendor services in Tennessee for dry active waste processing, including compaction, 36 incineration, thermal processing, and sorting of the dry active waste. 37 LSCS Units 1 and 2 have a shared Interim Radwaste Storage Facility (IRSF) with the capacity 38 to hold 270 containers of Class B and Class C (Class B/C) low-level radioactive wastes in two 39 layers of 135 spots each. In 2011, LSCS Units 1 and 2 both received license amendments to 40 allow their IRSF to store Class B/C waste from Braidwood, Byron, and Clinton Stations in 41 addition to the wastes generated at LSCS. Exelon states that LSCS has sufficient excess 42 storage capacity to accommodate extended storage of the Class B/C wastes generated by all 43 four Exelon stations. Also, LSCS can ship Class B/C wastes for treatment and disposal to the 44 Waste Control Specialists facility in Texas to reduce the demand for any extended onsite 3-16

Affected Environment 1 storage of those wastes. Therefore, storage capacity for low-level radioactive wastes should be 2 sufficient for the length of the license renewal term. (Exelon 2014a) 3 LSCS infrequently generates small quantities of mixed waste (waste having both a hazardous 4 component and radioactive component). The IEPA regulates the hazardous component of the 5 waste and the Illinois Emergency Management Agency Division of Nuclear Safety and the NRC 6 regulate the radioactive component. When generated, mixed wastes are accumulated in the 7 Mixed Waste Storage Building before transport to a licensed offsite facility for treatment and 8 disposal (Exelon 2014a). 9 LSCS has contracts to send its low-level waste (LLW) to two licensed LLW disposal sites: 10 EnergySolutions in Clive, Utah, and Waste Control Specialists in Andrews, Texas. LSCS also 11 sends certain wastes to Toxco Materials Management Center in Oak Ridge, Tennessee, and 12 EnergySolutions in Oak Ridge, Tennessee for processing before disposal. 13 In 2014, 30 LLW shipments were made from LSCS for processing and disposal to the 14 EnergySolutions Clive facility in Clive, Utah, the EnergySolutions Bear Creek facility in Oak 15 Ridge, Tennessee, and the Toxco Materials Management Center in Oak Ridge, Tennessee. 16 The total volume and radioactivity of LLW shipped offsite in 2014 was 1.23x103 m3 17 (4.34x104 cubic feet and 1.34x101 curies (4.95x105 megabecquerels)), respectively 18 (Exelon 2015b). Routine plant operation, refueling outages, and maintenance activities that 19 generate radioactive solid waste will continue during the license renewal term. Radioactive 20 solid waste is expected to be generated and shipped off site for disposal during the license 21 renewal term. 22 3.1.4.4 Radioactive Waste Storage 23 Low-level radioactive waste (LLRW) is stored temporarily onsite before being shipped offsite for 24 disposal at a licensed LLRW disposal facility. Exelon (2014a) stated that LSCS has sufficient 25 capability to store Class B/C LLRW from Braidwood, Byron, and Clinton Stations in addition to 26 LSCS Class B/C waste in the IRSF (Exelon 2014a). 27 LSCS stores its spent fuel in a spent fuel pool and also in an onsite independent spent fuel 28 storage installation (ISFSI). The ISFSI is used to safely store spent fuel in licensed and 29 approved dry cask storage containers onsite. The installation and monitoring of this facility is 30 governed by NRC requirements in 10 CFR Part 72, Licensing requirements for the independent 31 storage of spent nuclear fuel, high-level radioactive waste, and reactor-related Greater than 32 class C waste. The LSCS ISFSI will remain in place until the U.S. Department of Energy takes 33 possession of the spent fuel and removes it from the site for permanent disposal or processing. 34 Spent fuel transfers to the ISFSI began in 2010 when fuel from the spent fuel pool was placed 35 in casks and transferred to the ISFSI storage pad. As of December 2014, there are 16 dry 36 casks containing spent fuel on the ISFSI storage pad (Exelon 2015b). 37 3.1.4.5 Radiological Environmental Monitoring Program 38 Exelon conducts a REMP to assess the radiological impact, if any, to the public and the 39 environment from operations at LSCS. 40 The REMP measures the aquatic, terrestrial, and atmospheric environment for ambient 41 radiation and radioactivity. Monitoring is conducted for the following: direct radiation, air, water, 42 groundwater, milk, local agricultural crops, fish, and sediment. The REMP also measures 43 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 44 material, including radon). 45 In addition to the REMP, LSCS has an onsite ground water protection program designed to 46 monitor the onsite plant environment for detection of leaks from plant systems and pipes 3-17

Affected Environment 1 containing radioactive liquid (Teledyne 2015). Information on the groundwater protection 2 program is contained in Section 3.5.2 of this document. 3 The NRC staff reviewed 5 years of annual radiological environmental monitoring data: 4 2010 through 2014 (Teledyne 2011, 2012, 2013, 2014, 2015). A 5-year period provides a data 5 set that covers a broad range of activities that occur at a nuclear power plant, such as refueling 6 outages, routine operation, and maintenance activities that can affect the generation and 7 release of radioactive effluents into the environment. The NRC staff looked for indication of 8 adverse trends (i.e., buildup of radioactivity levels) over the period of 2010 through 2014. 9 The NRC staffs review of Exelons data showed no indication of an adverse trend in 10 radioactivity levels in the environment. The data showed that there was no measurable impact 11 to the environment from operations at LSCS. 12 3.1.5 Nonradioactive Waste Management Systems 13 Like any other industrial facility, nuclear power plants generate wastes that are not 14 contaminated with either radionuclides or hazardous chemicals. 15 LSCS has a nonradioactive waste management program to handle its nonradioactive hazardous 16 and nonhazardous wastes. The waste is managed in accordance with Exelons procedures. 17 Listed below is a summary of the types of waste materials generated and managed at LSCS. 18

  • LSCS is a small quantity hazardous waste generator; however, hazardous wastes 19 are managed according to large quantity generator standards. LSCS has contracts 20 in place to transfer hazardous waste to licensed offsite treatment and disposal 21 facilities.

22

  • LSCSs nonhazardous wastes include potentially infectious medical waste (PIMW),

23 waste/used oil, grease, antifreeze, adhesives, and other petroleum-based liquids. 24 PIMW is generated at a health facility onsite and can include used and unused 25 hypodermic needles and syringes, as well as items contaminated with human blood. 26 PIMW is considered a unique special waste category in Illinois and transportation 27 and disposal of this waste is regulated under the Illinois Administrative Code (IAC) 28 Title 35, Sections 1420 through 1422 and 1450, (35 IAC 1420-1422, 1450). 29

  • Universal wastes, such as batteries and mercury-containing lamps are managed in 30 accordance with 35 IAC 733 standards. Other wastes, such as, oils, metals, paper, 31 and other recyclables are managed according to Exelon procedures and Illinois 32 regulations.

33 Exelon operates an onsite sewage treatment plant. Sewage treatment effluent is discharged to 34 the LSCS cooling pond. Nonradioactive industrial wastewater is also processed at the 35 treatment plant and the treated effluent is discharged into the cooling pond. Cooling pond 36 blowdown is discharged to the Illinois River under NPDES permit IL0048151 (Exelon 2014a). 37 3.1.6 Utility and Transportation Infrastructure 38 The utility and transportation infrastructure at nuclear power plants typically interfaces with 39 public infrastructure systems available in the region. Such infrastructure includes utilities, 40 including suppliers of electricity, fuel, and water, as well as roads and railroads that provide 41 access to the site. The following sections briefly describe the existing utility and transportation 42 infrastructure at LSCS. 3-18

Affected Environment 1 3.1.6.1 Electricity 2 Nuclear power plants generate electricity for other users; however, they also use electricity to 3 operate. Offsite power sources provide power to engineered safety features and emergency 4 equipment in the event of a malfunction or interruption of power generation at the plant. 5 Independent backup power sources provide power in the event that power is interrupted from 6 both the plant and offsite power sources. 7 At LSCS, connections to the Commonwealth Edison Company (ComEd) 345-kilovolt (kV) 8 system at the onsite switchyard provide offsite power sources for essential safety systems and 9 emergency equipment (Exelon 2014g). The switchyard is arranged in a double ring bus such 10 that offsite power to both units cannot be lost due to any single failure (Exelon 2014g). In the 11 event of total loss of auxiliary power from offsite sources, onsite diesel generators serve as an 12 independent source of power for safe shutdown (Exelon 2014g). LSCS has six diesel 13 generators (three for each nuclear unit) that can each provide up to 4.16 kV of power, which is 14 ample capacity to supply all power required for the safe shutdown of both units in the event of a 15 total loss of offsite power (Exelon 2014g). 16 3.1.6.2 Fuel 17 The LSCS nuclear units are operated using low-enriched uranium dioxide fuel with enrichment 18 not exceeding 5 percent by weight of uranium-235. At any given time, the LSCS units contain 19 approximately 140 metric tons (MT) (308,600 pounds) of uranium fuel (Exelon 2015e). Exelon 20 replaces about 36 percent of that fuel at each refueling, which occurs on a staggered 24-month 21 cycle (Exelon 2014a). Fresh (i.e., unirradiated) fuel is brought to the site and stored onsite in 22 the LSCS new fuel storage facility prior to installation in the reactor cores (Exelon 2014g). 23 Exelon stores spent fuel in a spent fuel pool and an ISFSI. Nuclear fuel and radioactive waste 24 systems are further described in Section 3.1.4. 25 In addition to nuclear fuel, LSCS requires diesel fuel to operate the emergency diesel power 26 generators. To meet emergency demands, Exelon stockpiles diesel fuel and gasoline on the 27 site. In total, Exelon stores 204,080 gal (772,530 liters) of diesel fuel and gasoline for a variety 28 of uses, including emergency diesel generators, diesel fire pumps, and plant vehicles 29 (Exelon 2015e). 30 3.1.6.3 Water 31 In addition to cooling and auxiliary water (described in Section 3.1.3), nuclear power plants 32 require potable water for sanitary and everyday uses by personnel (e.g., drinking, showering, 33 cleaning, laundry, toilets, and eye washes). At LSCS, two deep wells supply the site with 34 potable water. Water pumped from the wells is routed to an onsite vendor trailer, which 35 deionizes the water and routes the water to a 1.3-million-liter (350,000-gal) storage tank. Water 36 drawn from the storage tank may be used in either the demineralized water makeup system or 37 the potable and sanitary water system. Water withdrawn for use in the potable water system 38 undergoes chlorination prior to entering the system. LSCS withdraws approximately 98 liters 39 per minute (L/min) (26 gpm) from the wells for potable water uses. (Exelon 2014a) 40 3.1.6.4 Transportation Systems 41 All nuclear power plants are served by controlled access roads. In addition to roads, many 42 plants also have railroad connections for moving heavy equipment and other materials. Some 43 plants that are located on navigable waters, such as rivers, Great Lakes, or oceans, have 44 facilities to receive and ship loads on barges. 45 At LSCS, County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, 46 provides access to the site from the southern boundary. Major roads in the area include State 3-19

Affected Environment 1 Route 170 (SR-170), which lies 0.8 km (0.5 mi) east of the site, and Interstate 80 (I-80), which 2 lies 13 km (8 mi) north of the site. Section 3.10.6 describes local transportation systems, 3 including roadway access, in more detail. 4 Two major railway systems provide service near the LSCS site: the CSX Railroad runs parallel 5 to and slightly north of the Illinois River, and a 10-km (6-mi) rail spur connects LSCS to the 6 Atchison, Topeka, and Santa Fe Railroad south of the site. Exelon uses a portion of the onsite 7 rail spur to transport spent fuel casks to the onsite storage area, but the spur has not been used 8 to deliver equipment or materials to the site from external sources in many years. 9 (Exelon 2015f) 10 LSCS lies south of the Marseilles Pool in the reach of the Illinois River between the Marseilles 11 Lock and Dam at Marseilles, Illinois, and the Dresden Lock and Dam south of Channahon, 12 Illinois (Exelon 2014a). These lock and dam sites are part of the Illinois Waterway, which flows 13 from Chicago, Illinois, to St. Louis, Missouri, and is composed of seven water systems: Illinois 14 River, Des Plaines River, Chicago Sanitary and Shipping Canal, South Branch Chicago River, 15 Cal-Sag Channel, Little Calumet River, and the Calumet River (USACE 2012). Much of the 16 barge traffic in this area is dominated by transportation of agricultural products (grains, corn, 17 and soybeans) and other commodities, such as cement and concrete (USACE 2012). 18 Exelon (2015g) does not own or maintain a barge slip for LSCS and does not otherwise receive 19 or ship equipment for LSCS by barge. 20 Major airports in the vicinity of LSCS include Chicago Midway International Airport, Chicago 21 OHare International Airport, and Central Illinois Regional Airport, which lie approximately 93 km 22 (58 mi) northeast, 100 km (60 mi) north-northeast, and 110 km (70 mi) south of the site, 23 respectively. Additionally, Illinois Valley Regional Airport in Peru, Illinois, serves LaSalle 24 County, and eight private airports in the county accommodate smaller cargo, passenger, and 25 private aircraft (LaSalle County 2014). 26 3.1.6.5 Power Transmission Systems 27 ComEd owns and operates the 345-kV onsite switchyard that connects LSCS with the regional 28 electric grid. From the switchyard, a total of six transmission lines extend to four substations. 29 Two 345-kV lines travel 66 km (41 mi) north from the site to the Plano substation east of Plano, 30 Illinois. Two 345-kV lines travel 100 km (62 mi) northeast to Braidwood Station, Units 1 and 2, 31 in Braceville, Illinois. Two 138-kV lines are connected to the switchyard through a 345/138-kV 32 transformer. One of the 138-kV line extends 27 km (17 mi) to Mazon, Illinois, and the other 33 138-kV line extends 40 km (25 mi) to Streator, Illinois (AEC 1973; NRC 1978; Exelon 2015h). 34 For license renewal, the NRC (2013) evaluates as part of the proposed action the continued 35 operation of those transmission lines that connect the nuclear power plant to the substation 36 where electricity is fed into the regional power distribution system and transmission lines that 37 supply power to the nuclear plant from the grid. Exelon (2015h) has determined that the four 38 electrical connections between the main plant and the LSCS switchyard are in scope for the 39 license renewal environmental review. These connections extend a distance of 1,300 ft (400 m) 40 across flat, primarily gravel laydown areas and paved roads (Exelon 2015h). Because 41 redundant offsite power is provided to LSCS through the LSCS substation, no offsite 42 transmission lines supply power to the nuclear plant from the grid (Exelon 2015h). All of the 43 in-scope transmission lines lie within the owner-controlled and industrial-use area of the site. 44 3.1.7 Nuclear Power Plant Operations and Maintenance 45 Maintenance activities conducted at LSCS include inspection, testing, and surveillance to 46 maintain the current licensing basis of the facility and to ensure compliance with environmental 3-20

Affected Environment 1 and safety requirements. Various programs and activities currently exist at LSCS to maintain, 2 inspect, test, and monitor the performance of facility equipment. These maintenance activities 3 include inspection requirements for reactor vessel materials, boiler and pressure vessel 4 inservice inspection and testing, and maintenance of water chemistry. 5 Additional programs include those carried out to meet TS surveillance requirements, those 6 implemented in response to the NRC generic communications, and various periodic 7 maintenance, testing, and inspection procedures. LSCS must periodically discontinue the 8 production of electricity for outages supporting refueling, periodic in-service inspection and 9 testing, and maintenance activities. The LSCS reactor units are on staggered 24-month 10 refueling cycles (Exelon 2014a). 11 3.2 Land Use and Visual Resources 12 3.2.1 Land Use 13 3.2.1.1 Onsite Land Use 14 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 15 Illinois (Exelon 2015p). The site lies 8 km (5 mi) south of the Illinois River, about 10 km (6 mi) 16 southwest of Seneca, Illinois, and 120 km (75 mi) southwest of downtown Chicago. 17 (Exelon 2014a) 18 A cooling pond occupies the western side of the site and accounts for about half of the site area. 19 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 20 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac). This 21 industrial area is surrounded by about 142 ha (350 ac) of undeveloped natural areas, including 22 grassland, old field, scrub-scrub, and small forested fragments (Exelon 2015p). 23 On the southwest shore of the cooling pond, the IDNR operates the LaSalle Fish Hatchery 24 under a lease agreement with Exelon. The hatchery encompasses approximately 18 ha (45 ac) 25 and includes several small buildings and 16 fish-rearing pools (Exelon 2014a). 26 A 5.6-km (3.5-mi) corridor for the makeup and blowdown pipelineswhich travel underground 27 from the Illinois River screen house south to the cooling pondcontains woodlands, pastures, 28 and wetlands as well as mowed and maintained right-of-way for a portion of the 29 LaSalle-to-Plano 345-kV transmission line (Exelon 2014a). 30 Table 3-1 lists site land uses, and Figure 3-3 depicts the site layout. Sections 3.1 and 3.6 31 describe the developed and natural areas of the site in more detail, respectively. 32 Table 3-1. LSCS Site Land Uses by Area Land Use Area (in acres)(a) Percent Open Water 1,976(b) 52.3 Developed, Open Space 120 3.2 Developed, Low Intensity 218 5.8 Developed, Medium Intensity 73 1.9 Developed, High Intensity 90 2.4 Barren Land 5 0.1 Deciduous Forest 386 10.2 Shrub/Scrub 17 0.5 3-21

Affected Environment Land Use Area (in acres)(a) Percent Grassland/Herbaceous 473 12.5 Pasture/Hay 11 0.3 Cultivated Crops 346 9.2 Woody Wetlands 58 1.5 Emergent Herbaceous Wetlands 2 0.1 Total 3,776 100.0 (a) To convert acres to hectares, divide by 2.4711. (b) Exelon used the 2011 National Land Cover Database (NLCD) to estimate acreage of site land uses. Of the 3,776-acre site, the 2011 NLCD identified 1,976 acres as open water, most of which consists of the cooling pond. This number of acres is inconsistent with the 2,058 acres reported in ComEds Environmental Report that evaluated the operation of LSCS (ComEd 1977). However, because the methodologies used to estimate land use acreages are different between these documents and the NLCD, and because both methodologies are inherently uncertain, Exelon was unable to resolve the discrepancy between the cooling pond acreage estimates. It is possible that, in the 1977 Environmental Report, features such as dikes, screen house, discharge canals, and storm water ponds were included in the cooling pond acreage estimate. Accordingly, all estimates should be considered approximate. Source: Exelon 2015d 1 3.2.1.2 Coastal Zone 2 In 1972, Congress promulgated the Coastal Zone Management Act (16 USC 1451 et seq.; 3 CZMA) to encourage and assist States and territories in developing management programs that 4 preserve, protect, develop, and, where possible, restore the resources of the coastal zone 5 (i.e., the coastal waters and the adjacent shore lands strongly influenced by one another, which 6 may include islands, transitional and intertidal areas, salt marshes, wetlands, beaches, and 7 Great Lakes waters). Individual states are responsible for developing a Federally approved 8 Coastal Management Plan and implementing a coastal management program in accordance 9 with such a plan. In Illinois, the IDNR administers the coastal management program. 10 Section 307(c)(3)(A) of the CZMA requires that applicants for Federal permits whose proposed 11 activities could reasonably affect coastal zones certify to the licensing agency (here, the NRC) 12 that the proposed activity would be consistent with the states coastal management program. 13 The regulations that implement the CZMA indicate that this requirement is applicable to renewal 14 of Federal licenses for actions not previously reviewed by the state (15 CFR 930.51(b)(1)). 15 LSCS is outside of the boundary of the Illinois coastal zone (IDNR 2011b, 2015c). Accordingly, 16 a consistency determination is not required for the proposed LSCS license renewal. 17 3.2.1.3 Offsite Land Use 18 Within a 10-km (6mi) radius of the LSCS site, most lands are contained within LaSalle County; 19 however, this radius also includes a small area of land in Grundy County to the east. Land use 20 in this area is primarily agricultural. Cropland or pastures border the LSCS site to the east, 21 south, and west. The Illinois River lies to the north of the site, and the bluffs overlooking the 22 Illinois River are mostly forested. The rivers south bank floodplain includes agricultural fields 23 and woodlots, while the north bank is more developed and includes parts of the incorporated 24 towns of Seneca and Marseilles. The majority of land cover (about 70 percent) within 10 km 25 (6 mi) is used for crop cultivation. Deciduous forest accounts for about 12 percent of land cover, 26 and the remaining 18 percent is composed of various land cover types, including open water, 3-22

Affected Environment 1 developed land, wetlands, and grasslands. Table 3-2 characterizes the land uses within a 2 10-km (6-mi) radius of LSCS. 3 Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS Area Land Use (in acres)(a) Percent Open Water 2,915 4.0 Developed, Open Space 3,124 4.3 Developed, Low Intensity 2,676 3.7 Developed, Medium Intensity 451 0.6 Developed, High Intensity 256 0.4 Barren Land 84 0.1 Deciduous Forest 8,479 11.7 Evergreen Forest 4 0.0 Shrub/Scrub 43 0.1 Grassland/Herbaceous 2,165 3.0 Pasture/Hay 966 1.3 Cultivated Crops 50,755 70.2 Woody Wetlands 425 0.6 Emergent Herbaceous Wetlands 8 0.0 Total 72,351 100.0 (a) To convert acres to hectares, divide by 2.4711. Source: Exelon 2015i 4 The IDNR manages three areas for public use and recreation within 10 km (6 mi) of LSCS. The 5 LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling pond that is 6 managed by the IDNR and open to the public for fishing and other recreational purposes 7 (Exelon 2014a). The Marseilles State Fish & Wildlife Area is approximately 2.4 km (1.5 mi) 8 north of the LSCS site. The IDNR (2015e) manages this 1,032-ha (2,550-acre) tract of 9 predominantly wooded land for wildlife habitat and hunting. Illini State Park lies approximately 10 10 km (6 mi) northwest of LSCS on the south bank of the Illinois River and encompasses 11 206 ha (510 ac) (Exelon 2014a). 12 LaSalle County, in which LSCS is located, is a predominantly agricultural county; 85 percent of 13 the countys 1,135 square miles (m2) (294,000 ha or 726,400 ac) are in agricultural production 14 (LaSalle County 2014). Much of the countys agricultural lands were formerly prairie. LaSalle 15 Countys major agricultural crops include corn, soybeans, and its major livestock commodities 16 include cattle and calves, hogs and pigs, and sheep and lambs (LaSalle County 2014). The 17 LaSalle County Comprehensive Plan (LaSalle County 2014) anticipates that the county will 18 experience a slight (4 percent) increase in population over the next 15 years and reach an 19 estimated 141,615 people by 2030. The county plans to manage its land resources in a manner 20 that will preserve prime farmland and to encourage continued urban growth in areas where 21 public infrastructure and services already exist so that farmland, open spaces, and natural and 22 cultural resources are preserved. 3-23

Affected Environment 1 3.2.2 Visual Resources 2 As described in the previous section, the LSCS site is located in a predominantly agricultural 3 region. The sites grade elevation is approximately 216 m (710 ft) above MSL, which is the 4 highest point within a 3-km (5-mi) radius. The sites generating facilities were built 60 m (200 ft) 5 above the Illinois River floodplain elevation, which ranges from 152 to 155 m (500 to 510 ft) 6 above mean sea level. The tallest structures on the LSCS site are the meteorological tower and 7 the station vent stack, which are 122 m (400 ft) tall and 113 m (370 ft) tall, respectively. The 8 vent stack is painted with thick white and red horizontal stripes. The largest and most visible 9 buildings on the site are the reactor and turbine buildings, which are 56 m (185 ft) and 41 m 10 (134 ft) tall, respectively (Exelon 2014a). 11 To the west and the southwest, the Grand Ridge Energy Center wind farm is situated on slightly 12 higher ground (221 to 227 m (725 to 750 ft) above MSL) on a north-south ridgeline. A second 13 wind farm, Top Crop I, is sited south and east of the Grand Ridge Energy Center. Wind turbines 14 at these facilities stand 118.5 m (389 ft) tall and have rotor blades that are 38.5 m (126.5 ft) 15 long. These two facilities 134 wind turbines dominate the viewscape in the vicinity of LSCS. 16 (Exelon 2014a) 17 From most vantage points, the wind turbines are more noticeable than the LSCS buildings or 18 facilities. A motorist travelling north on Highway 170 from Ranson, Illinois, to Seneca, Illinois, 19 would see wind turbines to the west, south, and east until the motorist crested the bluffs of the 20 Illinois River at an elevation of about 200 m (650 ft) above MSL. The motorist would then lose 21 sight of the turbines at the highway bridge that crosses the Illinois River, at which point the 22 roads elevation descends to approximately 152 m (500 ft) (Exelon 2014a). 23 3.3 Meteorology, Air Quality, and Noise 24 3.3.1 Meteorology and Climatology 25 LSCS is located in LaSalle County in northeastern Illinois, approximately 70 mi (113 km) 26 southwest of Chicago and 35 mi (56 km) southwest of Joliet, Illinois. The regional climate is 27 continental with cold winters; warm summers; and frequent short fluctuations in temperature, 28 humidity, cloudiness, and wind direction (NCDC 2004). During fall, winter, and spring, the polar 29 jet stream is located near or over northeastern Illinois, which causes large-scale synoptic storms 30 to move through the area bringing precipitation, winds, and often dramatic temperature changes 31 (NCDC 2004). Temperature and precipitation conditions vary widely throughout Illinois and 32 between years. A wide range of temperature extremes is common in this region 33 (NCDC 2015a). Tornadoes, thunderstorms, hail, and heat and cold waves are common in the 34 State, and flooding is the most damaging weather-related hazard in Illinois (NCDC 2004). 35 The NRC staff obtained climatological data collected at the Peoria, Illinois, airport station 36 (KPIA), which is located approximately 62 mi (100 km) from LSCS. Additionally, LSCS 37 maintains a meteorological monitoring program that includes a 400-ft (122-m) meteorological 38 tower located approximately 0.5 mi (0.8 km) southeast of the reactor buildings. The tower 39 measures wind direction, wind speed, temperature, and precipitation. Data from these stations 40 were used to characterize the regions climate and are presented below. 41 The prevailing wind direction, for the 1981 through 2010 timeframe, at the KPIA station was 42 from the south-southwest (NCDC 2015a). The mean annual wind speed for the 1981 through 43 2010 timeframe is 8.4 miles per hour (mph) (13.5 kilometers per hour (kph)), and the mean 44 monthly wind speed ranges from 6.0 mph (9.7 kph) in August to 10.2 mph (16.4 kph) in March. 45 The annual predominant wind direction from the meteorological tower at LSCS for the 3-24

Affected Environment 1 2010 through 2014 timeframe was from the south-southwest direction (for 2011 and 2012) and 2 from the west-northwest direction (for 2010, 2013, and 2014) (Exelon 2015j). The mean annual 3 wind speed at LSCS for the 2010 through 2014 timeframe is 10.4 mph (16.7 kph) 4 (Exelon 2015j). 5 The mean annual temperature for the 1985 through 2014 period of record at the KPIA station is 6 51.9 °F (11.1 °C), with a mean monthly temperature ranging from a low of 25.2 °F (-3.7 °C) in 7 January to a high of 75.8 °F (24.3 °C) in July (NCDC 2015a). The hottest year over the period 8 of record was in 2012, and coolest was in 1996. The mean annual temperature for the 2010 9 through 2014 timeframe at LSCS is 50.7 °F (10.3 °C), with a mean monthly temperature ranging 10 from a low of 22.5 °F (-5.3 °C) in January to a high of 75.4 °F (24.1 °C) in July (Exelon 2015j). 11 The mean total annual liquid precipitation for the 1985 through 2014 period of record measured 12 at the KPIA station is 35.9 in. (91.2 cm). The wettest year for the period of record is 55.35 in. 13 (140.6 cm) in 1990 (NCDC 2015a); the driest year from the same period is 22.16 in. (56.2 cm) in 14 1988 (NCDC 2015a). Monthly precipitation amounts tend to be evenly distributed throughout 15 the year and range from an average of 1.9 in. (4.8 cm) in January to 4.3 in. (10.9 cm) in May 16 (NCDC 2015a). The mean total annual precipitation measurements taken at LSCSs 17 meteorological tower for the 2010 through 2014 timeframe is 29.83 in. (75.8 cm). Average 18 monthly precipitation ranges from a low of 0.93 in. (2.4 cm) in January to a high of 5.89 in. 19 (14.9 cm) in June (Exelon 2015j). 20 LaSalle County, where LSCS is located, experiences severe weather events, such as 21 tornadoes, floods, and hail. For the 1950 through 2014 period of record, the following events 22 have been recorded (NCDC 2015b): 23

  • 40 tornado events, 24
  • 26 flash floods events, 25
  • 131 hail events, and 26
  • 4 blizzard events.

27 3.3.2 Air Quality 28 Under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.), EPA has set 29 primary and secondary National Ambient Air Quality Standards (NAAQS) (40 CFR Part 50) for 30 six common criteria pollutants to protect sensitive populations and the environment. Primary 31 standards specify maximum ambient concentration levels of the criteria pollutants aimed at 32 providing public health protection, including protecting the health of sensitive populations, such 33 as asthmatics, children, and the elderly. Secondary standards specify maximum ambient 34 concentration levels of the criteria pollutants aimed at providing public welfare protection, 35 including protection against decreased visibility and damage to animals, crops, vegetation, and 36 buildings. The NAAQS criteria pollutants include carbon monoxide (CO), lead (Pb), nitrogen 37 dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). Particulate matter 38 is further categorized by sizePM10 (aerodynamic diameter of 10 micrometers (µm) or less) 39 and PM2.5 (aerodynamic diameter of 2.5 µm or less). Table 3-3 identifies the NAAQS for the six 40 common criteria pollutants. 3-25

Affected Environment 1 Table 3-3. National Ambient Air Quality Standards Primary/Secondary Pollutant Standard Averaging Time Level Carbon Monoxide (CO) Primary 8 hour 9 ppm 1 hour 35 ppm Lead (Pb) Primary and Secondary Rolling 3-month average 0.15 µg/m3 Nitrogen Dioxide (NO2) Primary 1 hour 100 ppb Primary and Secondary Annual 53 ppb Ozone (O3) Primary and Secondary 8 hour 0.075 ppm Particulate matter less than Primary Annual 12 µg/m3 2.5 µm (PM2.5) Secondary Annual 15 µg/m3 Primary and Secondary 24 hour 35 µg/m3 Particulate matter less than Primary and Secondary 2 hour 150 µg/m3 10 µm (PM10) Sulfur Dioxide (SO2) Primary 1 hour 75 ppb Secondary 3 hour 0.5 ppm Key: ppb = parts per billion, ppm = parts per million, µg/m3 = micrograms per cubic meter, and µm = micrometers. Source: EPA 2015d 2 EPA designates areas of attainment and nonattainment with respect to the NAAQS. Areas 3 that have insufficient data to determine designation status are denoted as unclassifiable. 4 Areas that were once in nonattainment, but are now in attainment, are called maintenance 5 areas; these areas are under a 10-year monitoring plan to maintain the attainment designation 6 status. States have primary responsibility for ensuring attainment and maintenance of the 7 NAAQS. Under Section 110 of the CAA and related provisions, states are to submit, for EPA 8 approval, State Implementation Plans that provide for the timely attainment and maintenance of 9 the NAAQS. 10 Air quality designations are generally made at the county level. For the purpose of planning and 11 maintaining ambient air quality with respect to the NAAQS, EPA has developed air quality 12 control regions (AQCRs), which are intrastate or interstate areas that share a common airshed 13 (40 CFR Part 81). LSCS is located in LaSalle County, Illinois. This County, along with an 14 additional five neighboring Counties (Bureau, Lee, Marshall, Putnam, and Stark Counties) in 15 Illinois compose the North Central Illinois Intrastate AQCR (40 CFR 81.262). With regard to the 16 NAAQS criteria pollutants, LaSalle County is designated as an attainment area for all NAAQS 17 (40 CFR 81.314). The nearest designated nonattainment area is Grundy County, for the 8-hour 18 ozone 2008 standard. The nearest designated maintenance area is Grundy County for the 19 PM2.5 1997 standard. Grundy County is adjacent to LaSalle County, approximately 4 mi (6 km) 20 from LSCS. Although Grundy County is adjacent to LaSalle County, it is not part of the same 21 AQCR that LaSalle County belongs to. 22 Illinois air pollution control rules are issued under Title 35 of the IAC. Air emission sources at 23 LSCS are regulated under a Federally Enforceable State Operating Permit (FESOP) (Permit 24 No. 099802AAA, issued in December 2000) issued by the IEPA (IEPA 2000). A source is 3-26

Affected Environment 1 eligible for a FESOP (also known as synthetic minor air permit) if the potential to emit from the 2 source triggers CAA permit program requirements but if maximum actual emissions are below, 3 or can be restricted to remain below, major source thresholds. LSCSs FESOP permit was 4 issued in December 2000, and expired in December 2005. In accordance with 35 IAC Part 201 5 and the Illinois Environmental Protection Act of 1970 (415 Illinois Compiled Statute (ILCS) 5/39), 6 Exelon submitted a renewal application for the FESOP permit (on July 15, 2005) to the IEPA 7 90 days before the expiration of the permit; therefore, the conditions of the FESOP are 8 administratively extended. On April 7, 2015, the IEPA issued a draft FESOP permit for LSCS 9 for public review and comment (IEPA 2015). 10 Permitted sources at LSCS include five diesel-fired generators, a gasoline storage tank, and 11 gasoline dispensing facilities. The LSCS FESOP permit limits nitrogen oxides, carbon 12 monoxide, particulate matter, volatile organic compounds, and/or the sulfur dioxide emissions 13 from the diesel generators and storage tank, as well as the fuel consumption of the diesel 14 generators and gasoline of the fuel storage tank. LSCS has been in compliance with the 15 requirements established in its FESOP permit, and there have been no reported violations in the 16 past 5 years (Exelon 2015k; EPA 2015b). Emissions from permitted sources at LSCS are 17 presented in Table 3-4. LSCS also has additional air emission sources that are exempt from 18 permitting requirements, but it must still comply with applicable environmental laws and 19 regulations. These air emission sources include diesel pumps and generators that are less than 20 600 horsepower and that are intended to be used during emergency circumstances and only 21 operated during routine surveillance and testing (Exelon 2015j). Air emissions for LaSalle 22 County in 2011 for carbon monoxide, nitrogen oxides, sulfur dioxide, particulate matter less than 23 10 µm, and particulate matter less than 2.5 µm were 1,213 tons, 2,308 tons, 611 tons, 832 tons, 24 and 483 tons, respectively (EPA 2011). LSCS permitted annual emissions are less than 25 1 percent of the total 2011 emissions for LaSalle County. 26 Table 3-4. LSCS Air Emissions (MT/year)(a) Pollutant 2008 2009 2010 2011 2012 2013 CO 1.10 1.76 1.65 1.52 2.01 1.9 SO2 0.0042 0.0017 0.0021 0.0017 0.0021 0.001 NOx 4.18 6.62 6.21 5.73 7.58 6.0 PM10 0.075 0.12 0.11 0.10 0.14 0.11 PM2.5 0.075 0.12 0.11 0.10 0.14 0.11 VOC 0.25 0.33 0.32 0.30 0.35 0.30 CO2 -(b) -(b) 315.79 295.46 390.91 308.3 Key: CO = carbon monoxide, NOx = nitrogen oxides, SO2 = sulfur dioxide, PM10 = particulate matter less than 10 micrometers, PM2.5 = particulate matter less than 2.5 micrometers, and VOC = volatile organic compounds. (a) To convert metric tons (MT) per year to tons per year, multiply by 1.1023. (b) Carbon dioxide emissions reporting commenced in 2010; therefore, prior year emissions are not available. Sources: Exelon 2014, 2015k 27 On October 30, 2009, EPA published a rule for the mandatory reporting of greenhouse gases 28 (GHGs) from sources that in general emit 25,000 MT or more of carbon dioxide equivalent 29 (CO2e) per year in the United States (74 FR 56260). Most small facilities across all sectors of 30 the economy fall below the 25,000-MT threshold and are not required to report GHG emissions 31 to EPA. On June 3, 2010, EPA issued the Prevention of Significant Deterioration (PSD) and 3-27

Affected Environment 1 Title V GHG Tailoring Rule (75 FR 31514). Beginning January 2, 2011, operating permits 2 issued to major sources of GHGs under the PSD or Title V Federal permit programs must 3 contain provisions requiring the use of best available control technology to limit the emissions of 4 GHGs if those sources would be subject to PSD or Title V permitting requirements because of 5 their non-GHG pollutant emission potentials and because their estimated GHG emissions are at 6 least 75,000 tons per year of CO2e. As discussed above, LSCS is a synthetic minor source, 7 and, as shown in Table 3-4, GHG emissions from sources at LSCS are below the GHG 8 Mandatory Reporting (40 CFR Part 98) and Tailoring Rule thresholds. Section 4.15 of this SEIS 9 further discusses GHG emissions. 10 EPA issued the Regional Haze Rule (RHR) to improve and protect visibility in national parks 11 and wilderness areas from haze, which is caused by numerous, diverse sources located across 12 a broad region (40 CFR 51.308-309). Specifically, Subpart D of 40 CFR Part 81 lists mandatory 13 Class I Federal Areas where visibility is an important value. The Regional Haze Rule requires 14 states to develop State Implementation Plans to reduce visibility impairment at Class I Federal 15 areas. The nearest Class I Federal area for visibility protection is the Mingo National Wildlife 16 Refuge, which is approximately 306 mi (492 km) southwest of the LSCS site. EPA recommends 17 that emission sources located within 62 mi (100 km) of a Class I area be modeled to consider 18 adverse impacts (EPA 1992). Considering the distance to the nearest Class I area and the 19 minor nature of air emissions from the site, there is little likelihood that ongoing activities at 20 LSCS adversely affect air quality and air quality-related values (e.g., visibility or acid deposition) 21 in any of the Class I areas. 22 3.3.3 Noise 23 Noise is unwanted sound and can be generated by many sources. Sound intensity is measured 24 in logarithmic units called decibels (dB). A dB is the ratio of the measured sound pressure level 25 to a reference level equal to a normal persons threshold of hearing. Most people barely notice 26 a difference of 3 dB or less (FHA 2011). Another characteristic of sound is frequency or pitch. 27 Noise may be composed of many frequencies, but the human ear does not hear very low or 28 very high frequencies. To represent noise as closely as possible to the noise levels people 29 experience, sounds are measured using a frequency weighting scheme known as the A scale. 30 Sound levels measured on this A scale are given in units of A-weighted decibels (dBA). Table 31 3-5 presents common noise sources and their respective noise levels. Noise levels can 32 become annoying at 80 dBA and very annoying at 90 dBA. To the human ear, each increase of 33 10 dBA sounds twice as loud (EPA 1981). 34 Table 3-5. Common Noise Sources and Noise Levels Noise Source Noise Level (dBA) Human hearing threshold 0 Soft whisper 30 Quiet residential area 40 Dishwasher 55-70 Lawn mower 65-95 Blender 80-90 Ambulance siren, jet plane 120 Source: CHC undated 3-28

Affected Environment 1 Several different terms are commonly used to describe sounds that vary in intensity over time. 2 The equivalent sound intensity level (Leq) represents the average sound intensity level over a 3 specified interval, often 1 hour. The day-night average sound intensity level (LDN) is a single 4 value calculated from an hourly Leq over a 24-hour period, with the addition of 10 dBA to sound 5 levels from 10 p.m. to 7 a.m. This addition accounts for the greater sensitivity of most people to 6 nighttime noise. Statistical sound level (Ln) is the sound level that is exceeded n percent of the 7 time during a given period. For example, L90, is the sound level exceeded 90 percent of the 8 time and is considered the background level. 9 There are no Federal regulations1 for public exposures to noise (EPA 2015c). The EPA 10 recommends day-night average sounds levels (LDN) of 55 dBA as guidelines or goals for 11 outdoors in residential areas (EPA 1974). However, these are not standards. The Federal 12 Housing Administration has established noise assessment guidelines for housing projects and 13 finds that day-night average sound levels (LDN) of 65 dBA or less are acceptable (HUD 2014). 14 Sections 25 and 27 of the Illinois Environmental Protection Act of 1970 (Chapter 415) 15 established the authority to create noise regulations. The actual noise regulations are found in 16 the IAC (Title 35, Subtitle H). These noise regulations have allowable octave-band sound levels 17 according to emitting and receiving land class (Class A, B, and C) and time of day. 18 Major offsite noise sources in the vicinity of LSCS include vehicles, wind turbines, and 19 agricultural equipment/machinery (Exelon 2015l). Common noise sources from nuclear power 20 plant operations include transformers, loudspeakers, cooling towers, auxiliary equipment, and 21 worker vehicles (NRC 2013). Major noise sources at LSCS include pumps, turbine building 22 supply and exhaust fans, sirens, generators, transformers, and loudspeakers (Exelon 2015m). 23 However, most of these noise sources are inside buildings, at approximately a 980-ft (300-m) 24 distance from the site boundary, and/or are intermittent. The nearest resident is approximately 25 0.7 mi (1.1 km) from the reactor buildings (Exelon 2014a). Exelon has not received any noise 26 complaints from residents in the vicinity of LSCS (Exelon 2014a). Additional noise sensitive 27 receptors nearby include the LaSalle Lake State Fish and Wildlife Area and Marseilles State 28 Fish and Wildlife Area. LSCS is subject to, and in compliance with, Illinois noise pollution 29 control regulations (Exelon 2015c, 2015m). 30 3.4 Geologic Environment 31 This section describes the current geologic environment of the LSCS site and vicinity, including 32 landforms, geology, soils, and seismic conditions. 33 3.4.1 Physiography and Geology 34 The site is located in an area that contains glacially deposited sediments overlying a bedrock 35 surface. These deposits formed during successive periods of glaciation. The power block and 36 the cooling pond are located on a glacial moraine (a depositional landform directly deposited by 37 a glacier). This area has a flat gently rolling topography. The river screen house is located 38 north of both the power block and cooling pond on the flat-lying river valley of the Illinois River. 39 The river valley is approximately 3.5 mi (5.6 km) north of the site and is topographically 40 separated from the glacial moraine by the bluffs along the Illinois River. The bluffs along the 41 Illinois River are dissected by stream valleys that cut into the glacial sediments and drain north 1 In 1972, Congress passed the Noise Control Act of 1972 (42 U.S.C. 4901 et seq.) establishing a national policy to promote an environment free of noise that impacts the health and welfare of the public. However, in 1982, there was a shift in Federal noise control policy to transfer the responsibility of regulation noise to state and local governments. The Noise Control Act of 1972 was never rescinded by Congress, but it remains unfunded (EPA 2015c). 3-29

Affected Environment 1 to the Illinois River. The maximum topographic relief between the site and the river is 2 approximately 255 ft (78 m) (Exelon 2014a; USDA 2008) (Figure 3-7). 3 In the area of the power block and the cooling pond, the land is covered by a 4- to 8-ft (1.2- to 4 2.4-m) layer of Richland Loess. The loess consists of windblown silt that has been weathered 5 to slightly clayey silt. The Richland Loess is underlain by the Wedron Silty-Clay Till. The till was 6 directly deposited by glacial activity. It consists of unsorted silt and clay sedimentary deposits. 7 In localized areas, the till also contains scattered, disconnected bodies of sand and gravel. In 8 the area of the plant buildings and cooling pond, the Wedron Silty-Clay Till ranges in thickness 9 from 120 to 140 ft (37 to 43 m). Moving north from the plant buildings and the cooling pond to 10 the river, the Wedron Silty-Clay Till decreases in thickness until it disappears near the Illinois 11 River (Figure 3-8) (Exelon 2014a). 12 Below the LSCS site, the Wedron Silty-Clay Till is underlain by bedrock. The topography of the 13 bedrock reflects the surface of the land before glaciation. This topography is now buried by 14 glacially deposited sediments. The site is located between two bedrock valleys that are filled 15 with the Wedron Silty-Clay Till and some alluvial sand and gravel deposits from ancient streams 16 that flowed through the bedrock valleys before they were completely buried. One alluvium-filled 17 buried valley runs east-west and is located between the plant facility and the Illinois River Bluff, 18 and one valley is located south of the plant facility and trends northwest and southeast 19 (Exelon 2014a, 2014c) (Figure 3-9). 20 The underlying bedrock consists of 4,500 ft (1,371 m) of dolomite, sandstone, and shale rock. 21 In turn, these rocks are underlain by granites and metamorphic rocks to a great depth. The 22 Pennsylvanian aged Carbondale Formation forms the top of the bedrock surface over most of 23 the site area. It is composed of alternating strata of shale, sandstone, clay, coal, limestone, and 24 siltstone (Exelon 2014a). 25 LaSalle County contains a number of geologic resources of economic importance. The County 26 is one of a handful of locations that can easily access the St. Peter Sandstone Formation. The 27 unique characteristics of this sandstone make it valuable for a number of commercial uses, 28 including glass, sand filters, sand molding, and abrasives. It is also in high demand for the 29 extraction of oil and gas using conventional horizontal drilling and shale fracking techniques. 30 LaSalle County also contains commercial deposits of gravel and limestone. Limestone and 31 gravel are used in concrete, agricultural limestone, and road surfaces. Clay is mined in the 32 county to manufacture bricks, drain tile, and dinnerware. Coal is no longer mined in the County 33 but historically was mined in bluffs along the Illinois River and around Streator, Illinois 34 (Ataner and Butler 2013; LaSalle County 2014; USDA 2008). 35 The LSCS site is underlain by coal seams, limestone beds, and the St. Peter Sandstone. 36 However, they lie too deep beneath the land surface to be economically accessed. No oil and 37 gas deposits have been identified beneath the site. 38 3.4.2 Soils 39 Eighty-five percent of the soil in LaSalle County is designated as prime farmland, and 9 percent 40 is farmland of State importance (Exelon 2014a). Within the site boundary, almost all the soil is 41 either silty loam or silty clay loam and is designated as prime farmland or farmland of State 42 importance (Exelon 2014a; USDA 2008, 2015b). 43 Following initial construction of the facility, areas surrounding LSCS were graded to control 44 runoff and to minimize erosion. Many areas were revegetated to support this effort 45 (Exelon 2014a). 3-30

Affected Environment 1 Figure 3-7. Site Physiography, LSCS Vicinity 2 Source: NRC Generated 3-31

Affected Environment 1 Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity 2 (Elevation Exaggerated) 3 Source: Modified from Exelon 2014a 3-32

Affected Environment 1 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity 2 Source: Modified from Exelon 2014e 3-33

Affected Environment 1 3.4.3 Seismic Setting 2 The site is located in an area of Illinois that might experience slight damage from earthquakes 3 (FEMA 2015; Mid-America Earthquake Center 2009). A number of earthquakes (USGS 2013a, 4 2013b, 2013c) have originated within Illinois, including the following: 5

  • On May 26, 1909, a large earthquake knocked over many chimneys in Aurora and 6 swayed buildings in Chicago.

7

  • On July 18, 1909, an earthquake knocked down chimneys in Petersburg.

8

  • On August 14, 1965, a sharp local earthquake knocked down chimneys in Elco, 9 Unity, Olive Branch, and Olmstead.

10

  • On November 9, 1968, a magnitude 5.3 earthquake was felt over the entire State of 11 Illinois and in 22 other states.

12 Dozens of earthquakes originating outside Illinois have been felt inside the State without 13 causing damage. These earthquakes originated in Missouri, Arkansas, Kansas, Nebraska, 14 Tennessee, Indiana, Ohio, Michigan, Kentucky, and Canada. Illinois can be affected by two 15 major seismic zones, the Wabash Valley Seismic Zone and the New Madrid Seismic Zone. The 16 Wabash Valley Zone lies between southeastern Illinois and southwestern Indiana about 322 mi 17 (518 km) from the site. The New Madrid Seismic Zone is about 300 mi (483 km) from the site in 18 southern Illinois, Missouri, Kentucky, and Tennessee. Of these two seismic zones, the New 19 Madrid Seismic Zone is capable of producing very powerful earthquakes. If a large magnitude 20 earthquake occurs in the New Madrid Seismic Zone, major damage could be experienced in 21 southern Illinois (Missouri Department of Natural Resources 2013; USGS 2009). 22 The NRC requires every nuclear power plant to be designed for site-specific ground motions 23 that are appropriate for its location. Nuclear power plants, including LSCS, Units 1 and 2, are 24 designed and built to withstand site-specific ground motion based on their location and nearby 25 earthquake activity. For LSCS, this includes earthquakes originating in either the Wabash 26 Valley Zone or the New Madrid Seismic Zone (Exelon 2014a). The seismic design basis is 27 established during the initial siting process using site-specific seismic hazard assessments. For 28 each nuclear power plant site, applicants estimate a design-basis ground motion based on 29 earthquake sources, wave propagations, and site responses; this estimate is then accounted for 30 in the design of the plant. In this way, nuclear power plants are designed to withstand the 31 maximum credible earthquake for a given site. Because methods of assessing seismic hazards 32 evolve over time and the scientific understanding of earthquake hazards improve (NRC 2014c), 33 the NRCs understanding of the seismic hazard for a given nuclear power plant may change 34 over time. As new seismic information becomes available, the NRC evaluates the new 35 information to determine whether changes are needed at existing plants or to NRC regulations. 36 The NRCs evaluation of the impact of seismic activity on a nuclear power plant is an ongoing 37 process that is separate from the license renewal process. 38 On December 23, 2011, the Consolidated Appropriations Act (Public Law 112-074) was signed 39 into law. Section 402 of the law directs the NRC to require reactor licensees to re-evaluate the 40 seismic hazard at their sites against current applicable Commission requirements and 41 thereafter, when appropriate, as determined by the Commission (NRC 2012). In 2012, the NRC 42 required all licensees to re-evaluate the seismic hazards at their sites using updated seismic 43 information and present-day regulatory guidance and methodologies (NRC 2012). The purpose 44 of that request was to gather information to update the seismic hazards analysis to enable the 45 NRC staff to determine whether individual site licenses should be modified, suspended, or 46 revoked (NRC 2014a). On March 31, 2014, Exelon responded to this request and provided its 3-34

Affected Environment 1 Seismic Hazard and Screening Report (SHSR) for LSCS (Exelon 2014d). On April 21, 2015, 2 the NRC staff issued an assessment (NRC 2015a) documenting its review of the Seismic 3 Hazard and Screening Report. The NRC staff concluded that Exelon met the intent of the 4 guidance for determining the re-evaluated seismic hazard and that it had provided an 5 acceptable response to the request. In addition, the NRC staff directed Exelon to perform 6 further seismic evaluations for NRC review. 7 3.5 Water Resources 8 3.5.1 Surface Water Resources 9 This section describes the current surface water resources within and near LSCS. 10 NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants 11 (GEIS) (NRC 2013), states that surface water encompasses all water bodies that occur above 12 the ground surface, including rivers, streams, lakes, ponds, and man-made reservoirs or 13 impoundments. 14 3.5.1.1 Surface Water Hydrology 15 The major surface water body in the region is the Illinois River, located approximately 4 mi 16 (6.4 km) to the north of the LSCS main plant complex (see Figure 3-2). The LSCS site is 17 situated within the lowermost portion of the Upper Illinois River Basin, which includes the 18 10,949- mi2 (28,369-square-kilometer (km2)) drainage area upstream from Ottawa, Illinois 19 (Figure 3-10). The Illinois River is formed from the confluence of the Kankakee and Des 20 Plaines Rivers at a point approximately 10 mi (16 km) east of Morris, Illinois. The main stem of 21 the Illinois River is joined by the Fox River at Ottawa (Arnold et al. 1999; USGS 1998). 22 The Illinois River is also central to the Illinois Waterway, which provides for navigation from Lake 23 Michigan to the Mississippi River and on to the Gulf of Mexico. The origins of this waterway 24 began with the construction of canals from the lake to the Chicago and Illinois Rivers, beginning 25 in the 1830s. Construction of the formal Illinois Waterway began in 1919 with the State of 26 Illinois leading efforts in the upper part of the river basin and the U.S. Army Corps of Engineers 27 (USACE) in the lower part. Today, the Illinois Waterway includes part of the Chicago River, the 28 Chicago Sanitary and Ship Canal, the Des Plaines River, and the Illinois River. Navigation is 29 made possible by a series of eight major locks and dams and associated navigation pools along 30 the Illinois River and its tributaries. Each pool is named for the dam downstream of each pool 31 (Exelon 2014a; Talkington 1991). Along its length, the waterway contains a navigation channel 32 at least 9 ft (2.7 m) deep and 300 ft (91 m) wide (Talkington 1991). In the vicinity of LSCS, at 33 normal pool elevation, the river has a depth of 12 ft (3.7 m) and a width of 800 ft (244 m) 34 (Exelon 2014a). 35 LSCS is located along the Marseilles Pool portion of the Illinois River. The Marseilles Lock and 36 Dam at Illinois RM 247 (RKm 397.5) is approximately 2.4 mi (3.9 km) downstream of the LSCS 37 intake and discharge structures near RM 249.5 (RKm 401.5) (see Section 3.1.3). However, the 38 lock itself is located a further 2.5 mi (4.0 km) downstream of the dam on a bypass canal 39 (Marseilles Canal) (USACE 2014). The Dresden Island Lock and Dam is 22 mi (35 km) 40 upstream of the LSCS intake structure at RM 271.5 (RKm 437) (Exelon 2014a). The Marseilles 41 Dam is 24 ft (7.3 m) high, and the Dresden Dam is 22 ft (6.7 m) high (Talkington 1991). 42 In total, the main stem of the Illinois River flows for approximately 270 mi (439 km) through 43 Illinois and ultimately discharges into the Mississippi River at Grafton, Illinois (Exelon 2014a; 44 USGS 1994; Talkington 1991). However, when accounting for the other components of the 45 Illinois Waterway, the total length of the river system is 327 mi (526 km) (Talkington 1991). 3-35

Affected Environment 1 The U.S. Geological Survey (USGS) maintains a gaging station on the Illinois River at 2 Marseilles, Illinois (Station 05543500) and RM 246.5 (RKm 396.7). This station is 3 approximately 3 mi (4.8 km) downstream from the LSCS river screen house intake and nearby 4 discharge structure near RM 249.4 (RKm 401). The gaging station is also 0.5 mi (0.8 km) 5 downstream of the Marseilles Dam and 6.9 mi (11 km) upstream from the confluence of the Fox 6 River with the main stem of the Illinois River (Exelon 2014a; USGS 1999b, USGS 2015). 7 The mean annual discharge measured at the USGS gage at Marseilles for water years 1920 8 through 2014 is 10,750 cfs (304 m3/s). For water year 2014, the mean discharge was 9 11,190 cfs (316 m3/s). The mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the 10 period of record (USGS 2015). The 90 percent exceedance flow is an indicator value of 11 hydrologic drought. It signifies a rate of streamflow that is equaled or exceeded 90 percent of 12 the time, as compared to the average flow for the period of record. Based on average monthly 13 flow over the period of record at the station, November is the low-flow month, and April is the 14 high-flow month for the Marseilles Pool (USGS 2015). 15 Tributaries to the Illinois River in the immediate vicinity of LSCS include South Kickapoo Creek, 16 Spring Brook, Deadly Run, Armstrong Run, and Hog Run (Figure 3-11). These headwater 17 streams and manmade ditches drain the glacial upland on which LSCS is located and generally 18 flow north toward the dissected bluffs of the river and across the river valley and into the Illinois 19 River. The most extensive of these nearby tributaries is South Kickapoo Creek. With its 20 headwaters on the northwest side of the LSCS property, this stream receives stormwater runoff, 21 cooling pond dike seepage collected by the LSCS perimeter drainage ditch, and overflow from 22 the cooling pond auxiliary spillway (see Figures 3-3 and 3-5). The main channel of South 23 Kickapoo Creek flows north to northwest from LSCS, with the main channel discharging to the 24 Illinois River at a point approximately 3.5 mi (5.6 km) northwest of the LSCS cooling pond and 25 approximately 0.4 mi (0.6 km) downstream of the LSCS blowdown discharge structure 26 (Exelon 2014a). 27 On the northeast perimeter of the cooling pond is Armstrong Run. Armstrong Run previously 28 drained much of the area that is now occupied by LSCS before plant construction. Like many of 29 the manmade drainage channels (called runs) in the region, it was constructed to convey 30 drainage collected by agricultural drain tile systems (NRC 1978). Armstrong Run now receives 31 runoff and seepage collected from the northeast end of the peripheral dike drainage ditch. 32 It discharges to the Illinois River at a point approximately 3.2 RM (5.1 RKm) northeast of the 33 cooling pond and about 4.5 RM (7.2 RKm) upstream of the river screen house (Exelon 2014a). 34 As further described in Section 3.1.3, the dominant surface water feature within the LSCS site 35 and vicinity is the 2,058- ac (833- ha) cooling pond (Figure 3-5). Other surface water features 36 on the LSCS plant site include two stormwater management ponds (North and South Storm 37 Water Ponds), two sewage treatment lagoons, and a collection of hatchery ponds as 38 summarized below. The NRC staff visited the facilities cited herein during the May 2015 39 environmental site audit (NRC 2015b). 40 The North and South Storm Water Ponds are located west of the LSCS main plant complex and 41 receive stormwater runoff from the protected area, serving the north and south zones of the 42 plant, respectively. Within the site, a system of ditches, storm drains, culverts, and underground 43 storm sewers collect runoff and drainage from the protected area and convey much of it to 44 either of the two ponds. Uncontaminated runoff from the north zone of the plant is conveyed to 45 the North Storm Water Pond, with some runoff sources first passing through the Unit 2 oil-water 46 separator. A portion of the switchyard also drains toward the north zone, although most of the 47 switchyard drains east to the cooling pond. 3-36

Affected Environment 1 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries 2 Source: Modified from Arnold et al. 1999 3-37

Affected Environment 1 Figure 3-11. LSCS Surface Water and Related Water Resource Features 2 Source: Modified from Exelon 2014a, 2015b 3-38

Affected Environment 1 Most runoff from the south zone enters the smaller South Storm Water Pond; this pond then 2 discharges to the cooling pond discharge canal through internal Outfall H01. Before entering 3 the pond, some flows first pass through the Unit 1 oil-water separator. The south pond also 4 receives runoff from the firing range. Areas of the plant site to the northwest and south of the 5 developed plant complex do not drain to the ponds but instead are drained by existing surface 6 stream segments and ditches (Exelon 2014a, 2014c). 7 Stormwater management and pollution control at LSCS is subject to Exelons Storm Water 8 Pollution Prevention Plan (SWPPP) (Exelon 2013e), which Exelon has implemented in 9 accordance with Special Condition 8 of the sites NPDES permit (IEPA 2013). The SWPPP 10 applies to industrial stormwater runoff from the site, which is not otherwise process-related and 11 not captured and processed by LSCSs wastewater treatment facilities. It describes the best 12 management practices, controls, inspection, and monitoring requirements, and the associated 13 implementing procedures and personnel responsibilities for reducing pollutants in stormwater 14 discharge and for ensuring compliance with the terms and conditions of the site NPDES permit 15 (Exelon 2013e). 16 Two open sewage treatment lagoons provide primary and secondary treatment for LSCSs 17 sanitary effluent. These lagoons are geotextile-lined impoundments and are located to the north 18 of the main plant complex adjacent to LSCSs sewage treatment plant (as shown in 19 Figure 3-3). Together, the NRC staff estimates the two impoundments cover an area of about 20 1.6 ac (0.65 ha). After filtration and final disinfection in the sewage treatment plant, the final 21 effluent from the treatment system is discharged into the cooling pond via NPDES internal 22 Outfall B01 (Exelon 2014a, 2014c). 23 A cluster of 16 small fish-rearing ponds is located on the southwest shore of the cooling pond 24 (see Figures 3-3 and 3-5). The NRC staff estimates that the ponds total approximately 29 ac 25 (12 ha) of open water. These ponds comprise the LaSalle Fish Hatchery operated by the IDNR 26 on plant property and subject to a lease agreement with Exelon. The hatchery uses the cooling 27 pond as a makeup water source. Runoff and drainage from the hatchery ponds flow back to the 28 cooling pond and are ultimately subject to LSCSs NPDES permit provisions 29 (Exelon 2014a, 2014c). The LSCS sites NPDES permit is further discussed in Section 3.5.1.3. 30 LSCS is not susceptible to riverine flooding because it is located upland and away from the 31 Illinois River. 32 The grade elevation at the plant site is 710 ft (216 m) above MSL, and the floor elevation of the 33 LSCS facilities is 710.5 ft (217 m) above MSL. The plant floor lies at an elevation that is 188 ft 34 (57 m) above the level of a postulated probable maximum flood on the Illinois River 35 (Exelon 2014a, 2014g). Although the river screen house is not a safety-related structure, it is 36 designed to withstand the 100-year flood on the Illinois River. Its loss would not impact the 37 ability to safely shut down the plant as water could still be drawn from the cooling pond and from 38 the UHS portion of the cooling pond, as described in Section 3.1.3 of the SEIS (Exelon 2014a, 39 2014g). 40 Furthermore, a failure of the peripheral dike system enclosing the cooling pond would not flood 41 the power plant area because the onsite topography would cause cooling pond water to flow 42 north and away from the plant following the existing drainage network (Exelon 2014a, 2014g). 43 3.5.1.2 Surface Water Use 44 LSCS withdraws surface water from the Illinois River as makeup water for the plants cooling 45 pond. The cooling pond provides water for the plants circulating water, service water, and 46 essential cooling water systems. Cooling tower blowdown and other permitted effluent streams 47 are discharged back to the Illinois River via the plants primary NPDES outfall (Outfall 001) at a 3-39

Affected Environment 1 point located about 900 ft (270 m) downstream from LSCSs river intake structure and 2 associated river screen house. 3 The maximum (nominal) surface water withdrawal rate for LSCS, Units 1 and 2, is 90,000 gpm 4 (200 cfs or 5.66 m3/s). This is equivalent to 129.6 million gallons per day (mgd) 5 (491,000 m3/day). However, Exelon reports in its ER that LSCSs normal peak makeup 6 withdrawal rate from the Illinois River is 60,000 gpm (134 cfs or 3.77 m3/s) or 86.4 mgd 7 (327,000 m3/day). This rate assumes a two-pump operation with valves open at 100 percent. 8 The third makeup pump located in the river screen house normally serves as a backup 9 (see Section 3.1.3). 10 The NRC staff reviewed submittals by Exelon to the Illinois State Water Survey that document 11 the volume of surface water withdrawn from, and discharged back to, the Illinois River during 12 the period 2009 to 2013 (Table 3-6). Based on these data, LSCS surface water withdrawals 13 have averaged 24,745 million gallons per year (mgy) (93.7 million cubic meters per year 14 (m3/yr)). This is equivalent to an average withdrawal rate of approximately 105 cfs (2.96 m3/s or 15 67.8 mgd). Return discharges (blowdown) to the Illinois River have averaged 13,046 mgy 16 (49.4 million m3/yr), which is equivalent to an average discharge rate of about 55.3 cfs 17 (1.56 m3/s or 35.7 mgd). The difference between withdraw and discharge (i.e., approximately 18 49.7 cfs (1.40 m3/s)) generally reflects process consumptive use or other losses, evaporative 19 losses, and presumably seepage from the cooling pond. In total, these data indicate a 20 consumptive use rate averaging 47 percent. 21 Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, LSCS Withdrawals Discharges Year (mgy) mgd cfs (mgy) mgd cfs 2009 28,598.4 78.5 121 19,405.0 53.2 82.2 2010 25,876.8 70.9 110 13,686.0 37.5 58.0 2011 23,328.0 63.9 98.9 11,961.1 32.8 50.7 2012 28,857.6 79.1 122 14,005.7 38.4 59.4 2013 17,064.0 46.7 72.3 6,173.0 16.9 26.2 Average 24,745.0 67.8 105 13,046.1 35.7 55.3 Note: Reported and calculated values are rounded. To convert million gallons per year (mgy) to million cubic meters (m3), divide by 264.2. To convert, million gallons per day (mgd) to cubic feet per second (cfs), multiply by 1.547. Sources: Exelon 2011a, 2012a, 2013a, 2014a, 2014d 22 LSCSs surface water withdrawals and consumptive water use are not subject to any water 23 allocation or related permitting requirements at the present time. In 2006, the Governor of 24 Illinois issued an executive order establishing a Statewide program for State and regional water 25 supply planning and management, which included the development and approval of regional 26 plans in designated Priority Water Quantity Planning Areas (State of Illinois 2006). LaSalle 27 County, where LSCS is located, is not included within any of the three designated planning 28 areas (Exelon 2014a; ISWS 2015a). Nevertheless, as referenced above, Exelon reports its 29 surface water withdrawals to the State of Illinois under the State Illinois Water Inventory 30 Program (Exelon 2014a; ISWS 2015b). Reporting is required in accordance with the Illinois 31 Water Use Act of 1983 (525 ILCS 45) and its 2010 amendments. The general purpose and 32 intent of the Act is to establish a means of reviewing potential water conflicts before damage to 3-40

Affected Environment 1 any person is incurred and to establish a rule for mitigating water shortage conflicts. The 2 2010 amendments to the Illinois Water Use Act added high-capacity intakes as subject to the 3 Acts water use reporting provisions. Such intakes are surface water intakes on a property in 4 which the rate or capacity of water withdrawal of all intakes for the property is equal to, or in 5 excess of, 100,000 gal (380 m3) during any 24-hour period (525 ILCS 45). 6 Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and 7 cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat 8 Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan 9 and associated procedures to mitigate the impacts of summer drought and/or high river 10 temperature and river low-flow conditions. Depending on predefined conditions set forth in the 11 plan and implementing procedures, such actions may include a combination of monitoring and 12 modeling of river intake and mixing zone temperatures; manipulation of the water level of the 13 cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the 14 cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the TS 15 limits on condenser inlet temperature from the cooling pond (Exelon 2014a, 2015c). 16 Two other industrial facilities withdraw water from the Marseilles Pool of the Illinois River in the 17 vicinity of LSCS (Figure 3-5) and are listed in the Illinois Water Inventory Program. These are 18 Agrium U.S., Inc., and PCE Phosphate, Marseilles Operation. The volume of water withdrawn 19 by these commercial facilities is not publicly available (Exelon 2014a). Because they are 20 included in the States inventory, the NRC staff presumes that each facility withdraws in excess 21 of 100,000 gpd (380 m3). Both are also currently subject to NPDES individual permits 22 (i.e., Permits IL0001708 and IL0036463). Based on reported return discharges to the Illinois 23 River, it is estimated that Agriums surface water withdrawals are on the order of 5 mgd 24 (18,900 m3) (EPA 2015a). 25 The public water supply systems in the vicinity of LSCS (i.e., the city of Marseilles and the 26 village of Seneca) do not withdraw water from the Illinois River but instead rely upon 27 groundwater-supplied systems (Exelon 2014a) (see Section 3.5.2.2). 28 Surface water withdrawals within the Marseilles Pool have shown no significant effects on water 29 availability to date (Exelon 2014a). 30 3.5.1.3 Surface Water Quality and Effluents 31 The Illinois Pollution Control Board (IPCB), a sister agency to the IEPA, promulgates water 32 quality standards in the State. Two Sections of Title 35 of the IAC (35 IAC 302 and 35 IAC 303) 33 contain the standards applicable to lakes and streams. Procedures that must be followed in 34 using water quality standards to set NPDES permit limits appear in Section 309 (35 IAC 309). 35 Designated uses prescribed by 35 IAC 303 are those uses specified in water quality standards 36 for each lake, river, stream, and groundwater resource. In designating uses for a waterbody, 37 the IPCB considers the use and value of the waterbody for public water supply; propagation of 38 fish, shellfish, and wildlife; and recreational, agricultural, industrial, and navigational purposes. 39 The main stem of the Illinois River is designated a general use water by the IPCB. Waters in 40 the general use category must meet water quality standards protective of aquatic life, wildlife, 41 agricultural use, and secondary contact use, as well as most industrial uses and aesthetic 42 quality (35 IAC 303.201). These standards pertain to pH; phosphorus; dissolved oxygen; 43 radioactivity (gross beta, strontium-90, and radium-226 and -228); various chemical constituents 44 (metals and organic compounds); fecal coliform; and other toxic substances. In addition, a 45 segment of the main stem of the Illinois River within LaSalle and Grundy Counties, and 46 encompassing the entire Marseilles Pool on which LSCS is located, is afforded enhanced 47 dissolved oxygen protection. Dissolved oxygen levels must be not less than 5.0 milligrams per 3-41

Affected Environment 1 liter at any time during March through July and not less than 4.0 milligrams per liter at any time 2 during August through February (35 IAC 302.206). 3 Over the last 150 years, water quality within the whole of the Illinois River Basin has historically 4 suffered from rapid population growth; urbanization; and industrial development, including the 5 conversion of prairie, wetlands, and forests. This change resulted in the discharge of untreated 6 and inadequately treated sewage, the discharge of industrial pollutants and refuse, runoff of 7 agricultural chemicals and sediments, and the alteration of the natural river hydrology due to 8 navigation and flood control projects (Exelon 2014a; Talkington 1991). 9 Over the last 50 years, substantial improvements in water quality have occurred because of 10 municipal and industrial waste treatment and management efforts to address both point and 11 nonpoint pollutant sources. Ongoing water quality concerns within the upper Illinois River Basin 12 include the atmospheric deposition of pesticides and trace metals; endocrine disrupting 13 compounds in surface and groundwater; nutrient enrichment of surface and groundwater; the 14 transport and fate of pesticides, trace elements, and volatile organic compounds in surface and 15 ground water; and the effects of urbanization on biodiversity, habitat, and water quality 16 (USGS 1998). 17 Section 303(d) of the Federal Water Pollution Control Act (i.e., Clean Water Act of 1977, as 18 amended (CWA) (33 U.S.C. 1251 et seq.)) requires the State of Illinois and other states to 19 identify all impaired waters for which effluent limitations and pollution control activities are not 20 sufficient to attain water quality standards in such waters. The Section 303(d) list includes those 21 water quality-limited stream segments that require the development of total maximum daily 22 loads (TMDLs) to ensure future compliance with water quality standards. The TMDLs specify 23 the maximum amount of a pollutant that a waterbody can receive and still meet water quality 24 standards. Once established, TMDLs are typically implemented through watershed-based 25 programs administered by the State, primarily through the NPDES permit program and 26 associated point and nonpoint source water quality improvement plans and associated best 27 management practices. The IEPA has classified a 30.1-mi- (48.4-km)-long segment (IL_D-23) 28 of the Illinois River between Morris and Ottawa, Illinois, that includes the LSCS site as impaired. 29 This segment is listed as impaired because it does not meet designated uses for fish 30 consumption due to polychlorinated biphenyls (PCBs) and mercury contamination. It is also 31 impaired for primary contact recreation use due to fecal coliform bacteria (IEPA 2014b). Special 32 Condition 13 of the NPDES permit for LSCS prohibits the discharge of PCBs in plant effluents 33 (IEPA 2013). The river segment is classified as fully supporting its designated use for aquatic 34 life. IEPA has assigned a medium priority for the development of TMDLs for segment IL_D-23 35 (IEPA 2014b). 36 As for other streams and runs in the vicinity of LSCS, IEPA (2014b) designates them as 37 Category 3, which are waters for which no use-support determination can be made due to 38 insufficient available data and/or information. 39 The LSCS cooling pond is included in the IEPAs CWA Section 314 inventory of lakes and has 40 also been designated as Category 3 (IEPA 2014b). However, LSCSs cooling pond is defined 41 by the State of Illinois as a wastewater treatment works pursuant to 35 IAC 301.415. Under this 42 definition, the cooling pond is not waters of the State under 35 IAC 301.440. Likewise, as 43 defined in 40 CFR 230.3, pursuant to the Federal CWA, waste treatment systems, including 44 treatment ponds or lagoons designed to meet the requirements of the Clean Water Act are 45 explicitly excluded from the definition of waters of the United States. Therefore, the cooling 46 pond is not subject to State or Federal water quality standards. 47 To operate a nuclear power plant, licensees must comply with the CWA, including associated 48 requirements imposed by EPA or the state as part of the NPDES permitting system under 3-42

Affected Environment 1 Section 402 of the CWA, as well as state water quality certification requirements under 2 Section 401 of the CWA. The EPA or the state, not the NRC, sets the limits for effluents and 3 operational parameters in plant-specific NPDES permits. Nuclear power plants cannot operate 4 without a valid NPDES permit and a current CWA Section 401 Water Quality Certification. The 5 EPA has delegated responsibility to the State of Illinois for the administration of the NPDES 6 program in Illinois. NPDES permits are issued by the IEPA on a 5-year cycle. 7 LSCS is authorized to discharge various wastewater (effluent) streams, including cooling pond 8 blowdown and stormwater under NPDES Permit IL0048151, reissued on July 5, 2013; the 9 current permit expires on July 31, 2018 (Exelon 2014a; IEPA 2013). The permit specifies the 10 discharge standards and monitoring requirements for effluent chemical and thermal quality 11 through the plants outfalls to the Illinois River, as summarized in Figure 3-7. The location of 12 the LSCSs primary outfall (001) to the Illinois River is shown in Figure 3-5. 13 Table 3-7. National Pollutant Discharge Elimination 14 System-Permitted Outfalls, LSCS Average Flow Outfall Rate (mgd)(a) Description 001(b,c,d,e) 34.9 Cooling Pond Blowdown; includes effluents from internal Outfalls A01 through H01, as well as IDNR fish hatchery effluents; discharge to the Illinois River A01(b,f,g) Intermittent Demineralizer Regenerant Wastes; includes makeup demineralizer regenerant wastes, off-specification demineralized water, makeup demineralizer maintenance wastewater, unit waterbox vacuum pump condensate, and radioactive waste (radwaste) treatment acid/caustic system drains discharges B01(b,c,f,g,h) 0.06 Sewage Treatment Plant Effluent; includes sanitary wastewater and eyewash station wastewater C01(b,c,f,g,i) 0.044 Wastewater Treatment System Effluent; includes nonsanitary drains composed of turbine building fire and miscellaneous nonradioactive wastewater sump, greensand filter backwash, diesel fuel storage and service water building sump, auxiliary boiler blowdown, water softener regenerant waste, demineralizer regenerant wastes, heat bay building roof area, fire protection system flushing and maintenance, service water system flushing and maintenance, domestic water system flushing and maintenance, clean condensate system flushing and maintenance, laboratory liquid wastes, station heat system condensate, diesel generator cooling water, standby liquid control test skid flush water, and groundwater D01(f) Intermittent Cooling Water Intake Screen Backwash E01(b,f g,i) Intermittent Unit 1 and 2 Radwaste Treatment System Effluent; includes equipment and floor drains in the turbine, auxiliary, and reactor buildings, as well as condensate polisher waste from the turbine building and decontamination and laundry waste F01(f) Intermittent Auxiliary Reactor Equipment Cooling and Flushing Water G01(f,j) Intermittent North Site Stormwater Runoff H01(f,j) Intermittent South Site Stormwater Runoff I01(b,f,g) Intermittent Reverse Osmosis System Reject Water and Greensand Filter Backwash 3-43

Affected Environment Average Flow Outfall Rate (mgd)(a) Description 002(k) Intermittent Illinois River Makeup Water Intake Screen Backwash; includes river intake screen backwash; trench wash water; process sampling discharge; lake makeup pump gland leakoff; coolers/reliefs flow; lake makeup pump strainer backwash; air compressor receiver and prefilter drainage; dewatering pump discharge; fire protection water; and river screen house switchyard stormwater runoff, floor drains, and roof drains; discharge to the Illinois River at the river screen house (a) To convert million gallons per day (mgd) to million cubic meters (m3), divide by 264.2. (b) Flow is subject to monitoring and reporting in units of mgd as a monthly average and as a daily maximum on Discharge Monitoring Report (DMR) (NPDES permit Special Condition 1). (c) pH is subject to limit of 6.0 to 9.0 (NPDES permit Special Condition 2). (d) Temperature is subject to continuous monitoring and DMR reporting of maximum monthly, as well as with temperature limits and mixing zone criteria (NPDES permit Special Condition 3). The calculated temperature at the edge of the mixing zone is limited to no more than 5 °F (2.8 °C) higher than ambient river temperature. The temperature beyond the mixing zone cannot exceed specified monthly limits for longer than 1 percent (i.e., 87.6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />) of any 12-month period and cannot at any time exceed the specified monthly limit by more than 1.7 °C (3 °F). During the months of April through November, the calculated temperature outside the mixing cannot exceed 93 °F (34 °C). (e) Total residual chlorine is subject to a limit of 0.05 milligrams per liter (NPDES permit Special Conditions 4 and 16). (f) This outfall is the NPDES permit internal monitoring point before the numbered point source outfall. (g) Total suspended solids are subject to specified limits and monitoring. (h) Carbonaceous biochemical oxygen demand is subject to specified limits and monitoring. (i) Oil and grease are subject to specified limits and monitoring. (j) Stormwater is subject to requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8). (k) Adequate maintenance of intake screen system is required to prevent discharge of floating debris back to the river. The stormwater portion is subject to the requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8). Note: The release of complex metal-bearing waste streams and polychlorinated biphenyls (PCBs) from all outfalls is prohibited by NPDES permit Special Conditions 5 and 13, respectively. Special Condition 9 authorizes the use of water treatment additives that were requested by Exelon as part of the renewed NPDES permit application. Source: IEPA 2013 1 As indicated in Table 3-7, the NPDES permit for LSCS requires Exelon to monitor and sample 2 site effluents for various parameters in accordance with applicable effluent limits. Monitoring 3 results are reported in monthly Discharge Monitoring Reports (DMRs) submitted to the State. 4 The NRC staff reviewed the DMRs submitted by Exelon to the IEPA for the period 2010 through 5 2014. This review encompassed the results of recorded maximum cooling pond blowdown 6 temperatures to the Illinois River and associated calculations of river mixing zone temperatures 7 as reported in the DMRs for the past 5 years (2010 through 2014) and as compiled by Exelon 8 (Exelon 2015c). Based on the NRCs staff review and Exelons responses to the NRCs 9 requests for additional information, LSCS has received no notices of violation associated with 10 NPDES permitted discharges during the 2010 through 2014 time period. Nonetheless, Exelon 11 recorded several unusual occurrences in its DMR reports. These included reports of a makeup 12 pipeline line failure on January 29, 2010; a blowdown line failure on July 13, 2012; a makeup 13 pipeline line failure on January 25, 2013; a blowdown line air release valve failure on 3-44

Affected Environment 1 February 8, 2013; a makeup pipeline failure on May 21, 2013; and a makeup pipeline failure on 2 January 23, 2014 (Exelon 2015c). 3 The DMR submittals also document actions taken to comply with provisional variances granted 4 by the IEPA to Exelon with respect to LSCSs effluent discharges to the Illinois River and 5 associated river mixing zone temperature limits. Specifically, these variances 6 (IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in 7 March, July, and August 2012, respectively, due to unusual weather conditions and associated 8 high ambient river water temperatures that impacted the ability for LSCS thermal discharges to 9 meet the requirements of Special Condition 3 of LSCSs NPDES permit. This limits the number 10 of temperature excursion hours to 1 percent (87.6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />) of the hours in a 12-month period, 11 ending with any month (see footnote d in Table 3-7). During the variance period(s), Exelon was 12 required, in part, to continuously monitor both the discharge and receiving water temperatures 13 and visually inspect all discharge areas at least three times each day to assess the impact on 14 aquatic life. These thermal discharge excursions were not found to have any impact on aquatic 15 life (Exelon 2015c). 16 An applicant (in this case, Exelon) for a Federal license to conduct activities that may cause a 17 discharge of regulated pollutants into navigable waters of the United States is required by 18 Section 401 of the CWA to provide the licensing agency (in this case, the NRC) with water 19 quality certification from the state (in this case, the State of Illinois). This certification implies 20 that discharges from the project or facility to be licensed will comply with CWA requirements and 21 will not cause or contribute to a violation of state water quality standards. If the applicant has 22 not received Section 401 certification, the NRC cannot issue a renewed license unless that state 23 has waived the requirement. The NRC recognizes that some NPDES-delegated states explicitly 24 integrate their 401 certification process with NPDES permit issuance. However, LSCSs 25 NPDES permit does not explicitly convey water quality certification under CWA Section 401. 26 By letter dated February 4, 2014, Exelon submitted an application to the IEPA Bureau of Water 27 that requested certification from the IEPA that renewal of Exelons NRC operating licenses for 28 LSCS would not violate State water quality standards (Exelon 2014h). The IEPA Division of 29 Water Pollution Control issued a letter to the NRC, and copied Exelon, which provides 30 Section 401 water quality certification for renewal of the operating licenses for LSCS. The 31 certification was issued with the condition that Exelon shall be responsible for obtaining NPDES 32 permits required for wastewater or stormwater discharges to waters of the State (IEPA 2014c). 33 As previously stated in this section, NRC licensees must comply with the CWA, including 34 associated requirements imposed by EPA or the state, as part of the NPDES permitting system 35 under CWA Section 402. The NRC staff concludes that the IEPAs response provides the 36 necessary certification pursuant to CWA Section 401. 37 To maintain LSCSs surface water intake system on Marseilles Pool of the Illinois River, Exelon 38 conducts occasional maintenance dredging at the river screen house (Exelon 2014a). The 39 need for maintenance dredging at the river screen house forebay is periodically evaluated in 40 accordance with an Exelon operating procedure. Currently, needed dredging is conducted 41 under a USACE Section 10 permit, which is issued pursuant to the Rivers and Harbors 42 Appropriation Act of 1899 (33 U.S.C. 403) (USACE 2006). Dredging was most recently 43 conducted in October 2013 in compliance with the provisions of the permit. Less than 100 cubic 44 yards (76 m3) of sediment was removed, and the material was dewatered and placed out of the 45 floodplain near the screen house. Future maintenance dredging will be conducted as needed 46 and with the necessary permits. Exelon does not expect to perform any dredging in the vicinity 47 of the LSCS discharge channel during the license renewal term and does not anticipate the 48 need to conduct any fill activities (Exelon 2015c). 3-45

Affected Environment 1 3.5.2 Groundwater Resources 2 This section describes the current groundwater resources at the LSCS site and in the vicinity. 3 3.5.2.1 Site Description and Hydrogeology 4 The site is characterized by five hydrogeologic units. By increasing depth, they are as follows: 5

  • the Alluvial Aquifer, 6
  • the Glacial Drift Aquitard, 7
  • the Buried Bedrock Valley Aquifers, 8
  • the Pennsylvanian Aquitard, and 9
  • the Cambrian-Ordovician Aquifer System.

10 The hydrogeologic characteristics of these units are summarized in Figure 3-12. 11 Alluvial (stream) deposits are found beneath, and extend along each side of, the Illinois River. 12 These deposits form the Alluvial Aquifer that lays on top of the bedrock (the Pennsylvanian 13 Aquitard) (Figure 3-8). The river functions as a hydrologic boundary, which prevents 14 groundwater within the Alluvial Aquifer from flowing from one side of the river to the other. The 15 Alluvial Aquifer is generally 2 to 4 ft (0.6 to 1.2 m) thick, is located in the vicinity of the river 16 screen house, and ranges from 3,500 to 4,800 ft (1,067 to 1,463 m) in width. Yields in the 17 Alluvial Aquifer are restricted by the limited areal extent and thickness of the sand and gravel 18 deposits that make up the aquifer. Small dependable yields suitable for domestic purposes are 19 only locally available. The aquifer receives recharge primarily by precipitation and from the 20 river. Well yields from the Alluvial Aquifer in the vicinity of the river screen house are most likely 21 adequate only for domestic use (Exelon 2014a). 22 The Glacial Drift Aquitard is made up of the Richland Loess and the Wedron Silty-Clay Till 23 (see Section 3.4.1). The aquitard largely consists of silty-clay till (unsorted sediment containing 24 a range of grain sizes) with very low permeability. In the area of the plant buildings, the Glacial 25 Drift Aquitard is over 200 ft (61 m) thick (CRA 2006). Any extractable groundwater in this 26 aquitard is produced from thin discontinuous sand and gravel pockets that are recharged by the 27 slow infiltration of precipitation through the silty-clay till. The volume of groundwater produced 28 from these pockets is limited so that it is primarily used as a source of water for domestic or 29 farm activities (Exelon 2014a). 30 As discussed in Section 3.4.1, the site is located between two buried bedrock valleys that 31 contain alluvial deposits of sandy gravels and gravelly sands with lesser amounts of silt and clay 32 in scattered thin layers. These alluvial deposits are overlain and merge with the Wedron 33 Silty-Clay Till. They are recharged by the slow infiltration of precipitation through the thick 34 overlying Glacial Drift Aquitard. Therefore, the volume of groundwater that can be produced 35 from the Buried Bedrock Valley Aquifers is limited to supplying water for domestic or farm 36 activities (Exelon 2014a). 37 The Pennsylvanian Aquitard forms the bedrock. It consists of alternating beds of shale, 38 siltstone, underclay, sandstone, limestone, coal, and many gradational layers. Low permeability 39 shale and siltstone comprise more than 90 percent of the aquitard. In the area of the plant 40 buildings, the Pennsylvanian Aquitard is approximately 176 ft (54 m) thick. Groundwater in the 41 aquitard occurs under artesian conditions. Wells finished in the aquitard get water primarily 42 from thin sandstone and limestone beds within the aquitard, which are recharged by seepage 43 through the overlying shales and through the silty-clay till of the Glacial Drift Aquitard. In 44 general, the sandstone and limestone beds within the aquitard can only supply enough water for 3-46

Affected Environment 1 domestic or farm use because well yields are commonly less than 36 L/min (10 gpm) 2 (Exelon 2014a). 3 Figure 3-12. LSCS Site Hydrogeologic Units 4 Source: Modified from Exelon 2014a 3-47

Affected Environment 1 The Pennsylvanian Aquitard is underlain by the Cambrian-Ordovician Aquifer, which is an 2 important aquifer in the region. Beneath the site, this aquifer is composed of the following strata 3 (listed from shallowest to deepest): 4

  • Platteville Group, 5
  • GlenwoodSt. Peter Sandstone, 6
  • Potosi Dolomite, 7
  • Franconia Formation, 8
  • Ironton Sandstone, and 9
  • Galesville Sandstone.

10 At the site, the Cambrian-Ordovician Aquifer is approximately 1,090 ft (469 m) thick. Although 11 numerous alternating layers of sandstones, limestone, and dolomites impart a heterogeneous 12 character to the system, these units are hydraulically connected and behave as a single aquifer 13 (Exelon 2014a). The Cambrian-Ordovician Aquifer is the most important supplier of public 14 water in the region. 15 The Cambrian-Ordovician Aquifer is underlain by 450 ft (137 m) of the Eau Claire Formation 16 Aquitard, which is underlain by 2,500 ft (762 m) of the Mt. Simon Aquifer. The Mt. Simon 17 Aquifer is underlain by granitic and metamorphic rock. 18 In addition to the hydrogeologic units previously described, the plant area is directly underlain by 19 engineered granular fill that has been placed on top of the Wedron Silty-Clay Till. The 20 engineered granular fill underlies and surrounds the plant buildings and structures. It is 21 composed of sand and gravel and silty clay and contains groundwater that is recharged by local 22 precipitation. Because the underlying Wedron Silty-Clay Till has a very low permeability, 23 groundwater in the granular fill flows laterally eastward until it discharges into the intake canal, 24 or it flows laterally and discharges to the stormwater ponds and the discharge canal to the west 25 (CRA 2006) (Figures 3-12 and 3-13). 26 3.5.2.2 Groundwater Use 27 LaSalle County has an adequate supply of groundwater to meet current needs for industrial, 28 municipal, and domestic purposes. Regionally, the most abundant groundwater supplies are 29 obtained from the Cambrian-Ordovician Aquifer (LaSalle County 2014). 30 At the site, water for potable usage is obtained from two cased onsite wells completed into the 31 Cambrian-Ordovician Aquifer. These wells were installed in 1972 and 1974 in the area of the 32 plant buildings. They were drilled to a depth of 1,620 and 1,629 ft (494 and 496 m) and cased 33 to a depth of 921 and 989 ft (281 and 301 m) (Exelon 2014a, 2014f; ISGS 2015). Together the 34 two wells withdraw groundwater at an average rate of 26.1 gpm (98.7 L/min) (Exelon 2014a). 3-48

Affected Environment 1 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill 2 Source: Modified from Exelon 2014a 3-49

Affected Environment 1 Figure 3-14. LSCS Hydrogeologic Cross-Section 2 (Elevation Exaggerated) 3 Source: Modified from CRA 2006 3-50

Affected Environment 1 Within 10 mi (16 km) of the LSCS site, almost all water used for public water supplies is 2 obtained from the Cambrian-Ordovician Aquifer. However, the Village of Ransom withdraws 3 water from both the Cambrian-Ordovician Aquifer and from permeable zones in the 4 Pennsylvanian Aquitard, and the Village of Grand Ridge obtains water from the Buried Bedrock 5 Valley Aquifers. People in small communities within 10 mi (16 km) of the LSCS site that are not 6 served by a public water supply system obtain water from individual wells in the glacial drift, the 7 Pennsylvanian strata, or the upper portion of the Cambrian-Ordovician Aquifer (Exelon 2014a). 8 3.5.2.3 Groundwater Quality 9 In general, the quality of groundwater in the Alluvial Aquifer, the Glacial Drift Aquitard, the 10 Buried Bedrock Valley Aquifers, the Pennsylvanian Aquitard, and the Cambrian-Ordovician 11 Aquifer is suitable for public use and consumption. A search of Illinois State Geological Survey 12 water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant 13 buildings. With the exception of one well completed in the Pennsylvanian Aquitard, all these 14 wells withdraw water from the Cambrian-Ordovician Aquifer (ISGS 2015). 15 In 1985, a condensate line broke in the area east-southeast of the LSCS reactor building. 16 Tritium was detected near the broken line in groundwater near the surface. The line was 17 repaired soon after it broke. In 1986, the highest tritium concentrations detected in the 18 groundwater was approximately 11,000 picocuries per liter (pCi/L). Tritium concentrations in the 19 groundwater near the broken line have declined to the point that, since 2007, tritium 20 concentrations in the groundwater have been below the lower limit of detection (Exelon 2014a; 21 Exelon Nuclear 2008, 2009, 2010, 2011, 2012, 2013, 2014, 2015). 22 In September 2001, a spill of water from a recycled condensate storage tank resulted in tritium 23 contamination into groundwater near the land surface. Tritium concentrations in the 24 groundwater ranged from 766 to 1,280 pCi/L in 2006 (Exelon 2014a; Exelon Nuclear 2007). 25 These concentrations are well below the EPA Maximum Contaminant Level for tritium of 26 20,000 pCi/L. In 2014, tritium concentrations in the groundwater had further decreased below 27 the lower limit of detection (Exelon Nuclear 2015). 28 Another leak from a recycled condensate tank was identified in 2010. The tank is located near 29 the plant buildings and is underlain by 10 ft (3 m) of engineered granular fill. In turn, the fill is 30 underlain by the Wedron Silty-Clay Till. Soon after the leak was detected, the tank was drained 31 and repaired. The leak contaminated groundwater in engineered granular fill with condensate 32 water that contained tritium. Contamination in the engineered granular fill is being addressed 33 through natural monitored attenuation and by active remediation. Exelon is pumping 34 contaminated groundwater from both a well and a French drain installed in the engineered 35 granular fill and then discharging the recovered water into the cooling pond where it is greatly 36 diluted to below the lower limit of detection (Exelon 2014a). Exelon has been monitoring the 37 cleanup of the engineered granular fill using monitor wells. In June 2015, samples from all of 38 the monitor wells recorded tritium concentrations below the EPA Maximum Contaminant Level 39 for tritium of 20,000 pCi/L (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015; Exelon 2015a, 40 2015c). Although the engineered granular fill has been contaminated with tritium and is being 41 cleaned up, it is not an aquifer. No aquifers are known to have been contaminated by 42 inadvertent releases of radionuclides to groundwater. 43 One nonradiological release to groundwater occurred in 1999 when an oil tank was discovered 44 to have leaked. The spill was remediated, and on February 9, 2005, IEPA issued a letter of No 45 Further Remediation for the cleanup activities (Exelon 2014a). 3-51

Affected Environment 1 3.6 Terrestrial Resources 2 3.6.1 LSCS Ecoregion 3 LSCS lies within the Illinois/Indiana Prairies Level IV Ecoregion. This ecoregion encompasses 4 19,557 mi2 (50,652 km2) in eastern and central Illinois and western Indiana (Woods et al. 2006). 5 It is composed of vast glaciated, flat to rolling plains with terminal and recessional moraines, 6 prairie potholes, and old lake beds. Historically, tallgrass prairie covered the majority of the land 7 surface. Oak-hickory forests were common on moraines and floodplains, and marshes and wet 8 prairies occurred in poorly drained areas. Beginning in the 19th century, agricultural land began 9 to replace the natural vegetation, and it is now the dominant land type (Woods et al. 2006). 10 Prairie remnants lack many natural ecosystem functions due to their small size, and areas of 11 prairie restoration often lack forbs (broad-leaved herbs other than grass) or are overly 12 dominated by big bluestem (Andropogon gerardii) (a grass) or Indiangrass (Sorghastrum 13 nutans) (IDNR 2005). Historically, forests were dominated by oak (Quercus spp.), hickory 14 (Carya spp.), elm (Ulmus spp.), ash (Fraxinus spp.), beech (Fagus spp.), and maple (Acer spp.) 15 species (CEC 2008). Remaining forests are highly fragmented and are experiencing species 16 composition shifts to sugar maple (A. saccharum) and other mesophytic species (IDNR 2005). 17 This shift is in part due to fire suppression, which has favored species that do not rely on 18 periodic fires as part of their life cycle (IDNR 2005). Many wetland areas have been drained for 19 row crops, and agriculture now accounts for over 75 percent of land use within this ecoregion 20 (IDNR 2005). 21 Table 3-8 lists representative wildlife for this ecoregion, as well as species that the Illinois 22 Department of Natural Resources (IDNR) considers to be critical to the conservation and 23 restoration of the regions native habitats; species that are indicative of ecosystem health 24 (known as indicator species); and species that are native to the region, but are now extirpated 25 or imperiled. 26 The IDNR maintains the Illinois Wildlife Action Plan (IDNR 2005), which addresses native 27 habitat and species decline and contains a statewide conservation plan. 28 Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion Wildlife representative of the ecoregion American black bear eastern bluebird North American porcupine (Ursus americanus) (Sialia sialis) (Erethizon dorsatum) American redstart eastern chipmunk raccoon (Setophaga ruticilla) (Tamias striatus) (Procyon lotor) bobcat eastern gray squirrel tree sparrow (Lynx rufus) (Sciurus carolinensis) (Passer montanus) Canada warbler gray fox white-footed mouse (Cardellina canadensis) (Urocyon cinereoargenteus) (Peromyscus leucopus) coyote indigo bunting white-tailed deer (Canis latrans) (Passerina cyanea) (Odocoileus virginianus) 3-52

Affected Environment Wildlife critical to the conservation and restoration of the ecoregions native habitats American badger Henslows sparrow northern harrier (Taxidea taxus) (Ammodramus henslowii) (Circus cyaneus) eastern massasauga(a) Illinois chorus frog ornate box turtle (Sistrurus catenatus) (Pseudacris streckeri illinoensis) (Terrapene ornata ornata) four-toed salamander Indiana bat(b) red squirrel (Hemidactylium scutatum) (Myotis sodalis) (Sciurus vulgaris) gray bat(a) Kirtlands snake short-eared owl (Myotis grisescens) (Clonophis kirtlandii) (Asio flammeus) Wildlife indicative of ecosystem health (indicator species) black rat snake eastern meadowlark prairie vole (Elaphe obsoleta obsoleta) (Sturnella magna) (Microtus ochrogaster) black-capped chickadee great blue heron red-headed woodpecker (Poecile atricapillus) (Ardea herodias) (Melanerpes erythrocephalus) eastern box turtle horned lark red-tailed hawk (Terrapene carolina carolina) (Eremophila alpestris) (Buteo jamaicensis) eastern kingbird prairie king snake tufted titmouse (Tyrannus tyrannus) (Lampropeltis calligaster (Baeolophus bicolor) calligaster) Extirpated or imperiled wildlife American bison Blandings turtle Franklins ground-squirrel (Bison bison) (Emys blandingii) (Poliocitellus franklinii) (a) The eastern massasauga is a candidate for listing under the Endangered Species Act of 1973, as amended (ESA), and the gray bat is listed as endangered under the ESA. While these species occur within the Illinois/Indiana Prairies Level IV Ecoregion, the FWS (2015d) indicates that they do not occur within the area that would be affected by the proposed LSCS license renewal. (b) The Indiana bat is Federally listed as endangered under the ESA and is discussed in detail in Section 3.8. Sources: CEC 1997; IDNR 2005; WIken et al. 2011 1 3.6.2 LSCS Site Surveys, Studies, and Reports 2 A number of vegetation and wildlife surveys have been conducted on the LSCS site beginning 3 with baseline surveys prior to LSCS construction in the early 1970s. This section summarizes 4 these surveys in chronological order. 5 Baseline Terrestrial Surveys (1971-1972) 6 In July and December 1971, and April, July, and October 1972, baseline ecological studies were 7 conducted at the LSCS site. The 1971 studies were primarily qualitative, and the 1972 studies 8 gathered quantitative data on vegetation, mammals, birds, reptiles, and invertebrates present on 9 the LSCS site. The ER for operation of LSCS (ComEd 1977) describes these studies and the 10 associated results in detail. 11 Final Environmental Statement for Construction (1973) 12 In February 1973, the U.S. Atomic Energy Commission (AEC), the NRCs predecessor agency, 13 issued a Final Environmental Statement that evaluated the construction of LSCS (FES-C) 14 (AEC 1973). Although no specific studies were conducted to support the preparation of the 3-53

Affected Environment 1 FESC, the report briefly summarizes the terrestrial wildlife and habitats on the site, including 2 those that were altered or destroyed during the construction of the cooling pond. 3 Terrestrial Monitoring during LSCS Construction (1974-1978) 4 Following the commencement of LSCS construction, ComEd commissioned NALCO 5 Environmental Sciences to conduct a 5-year monitoring program to evaluate the effects of 6 temporary and permanent ecological disturbances related to construction from 1974 7 through 1978. The ER for operation of LSCS (ComEd 1977) describes the results of the first 8 2 years of this monitoring. 9 Final Environmental Statement for Operation (1978) 10 In November 1978, the NRC issued a Final Environmental Statement that evaluated the 11 operation of LSCS (FES-O) (NRC 1978). The report includes updates to the terrestrial habitat 12 and wildlife information presented in the FES-C based on the 5 years of terrestrial monitoring 13 conducted during LSCS construction. 14 Wildlife Habitat Council Vegetation and Wildlife Surveys (2007) 15 In September 2007, Wildlife Habitat Council (WHC) biologists performed a baseline habitat 16 survey for the Wildlife at Work program. The survey results are documented in the LSCS 17 Wildlife Management Plan (Exelon 2013b). 18 LSCS Wildlife Habitat Team Monitoring (Ongoing) 19 The LSCS Wildlife Habitat Team conducts periodic wildlife surveys of the site in the spring 20 (April), summer (July), and fall (September) to monitor changes in wildlife communities and to 21 document any new species found on the site. Results of periodic surveys are collected in 22 Exelons Wildlife Management Plan (Exelon 2013b). 23 3.6.3 LSCS Site 24 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 25 Illinois. The cooling pond, generating facilities and associated infrastructure, and LaSalle Fish 26 Hatchery occupy the majority (66 percent) of the site. The remaining areas are undeveloped 27 and include the following terrestrial communities: forest, shrub-scrub, grassland, old-field, and 28 wetlands. 29 A cooling pond occupies the western side of the site and accounts for about half of the site area. 30 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 31 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac) 32 (Exelon 2015p). This industrial area is surrounded by about 142 ha (350 ac) of undeveloped 33 natural areas, including grassland, old field, schub-scrub, and small forested fragments 34 (Exelon 2015p). 35 3.6.3.1 Vegetation 36 Because the majority of the LSCS site is developed or occupied by the cooling pond, only small 37 areas of terrestrial habitat occur on the site. An open grassy area lies between the cooling pond 38 and the sites industrial area. This area is bounded on the north by the discharge canal and on 39 the south by the property boundary. Another grassy area lies to the southwest of the industrial 40 area. These two areas have a few scattered trees (Exelon 2014a). 41 The makeup and blowdown pipeline corridor extends north from the cooling pond to the Illinois 42 River and supports upland habitats, including shrub-scrub, forest, grassland, and old-fields, and 43 scattered wetlands. Common tree species in the upland forest areas, which comprise the 3-54

Affected Environment 1 majority of the corridor, include white oak (Quercus alba), red oak (Q. rubra), shagbark hickory 2 (Carya ovata), sugar maple, hop hornbeam (Ostrya virginiana), hawthorn (Crataegus spp.), 3 black cherry (Prunus serotina), and American elm (Ulmus americana) (Exelon 2014a). The 4 corridor widens as it approaches the Illinois River where it contains several small freshwater 5 emergent and freshwater forested/scrub wetlands. These wetlands are discussed in 6 Section 3.6.5.2. 7 3.6.3.2 Wildlife 8 Mammals 9 During the baseline terrestrial surveys in 1971 and 1972, 29 species of mammals were recorded 10 on the LSCS site. The most commonly observed mammals included raccoon (Procyon lotor), 11 mink (Mustela vison), red fox (Vulpes fulva), gray fox (Urocyon cinereoargenteus), gray squirrel 12 (Sciurus carolinensis), fox squirrel (Sciurus niger), beaver (Castor canadensis), muskrat 13 (Ondatra zibethicus), eastern cottontail (Sylvilagus floridanus), and white-tailed deer 14 (ComEd 1977). During the 2007 WHC baseline inventory of the LSCS site, coyote (Canis 15 latrans), beaver, opossum (Didelphis virginiana), groundhog (Marmota monax), striped skunk 16 (Mephitis mephitis), white-tailed deer, and gray squirrel were observed on the site (Exelon 17 2013b). 18 Birds 19 During the baseline terrestrial surveys in 1971 and 1972, 129 species of birds were recorded on 20 or near the LSCS site. Of these, 41 are considered permanent residents, 45 are summer 21 residents, 13 are winter residents, and 21 are transients (ComEd 1977). Permanent residents 22 included mallard (Anas platyrhynchos), black duck (A. rubripes), red-tailed hawk (Buteo 23 jamaicensis), red-shouldered hawk (Buteo lineatus), bald eagle (Haliaeetus leucocephalus), 24 bobwhite (Colinus virginianus), ring-necked pheasant (Phasianus colchicus), killdeer 25 (Charadrius vociferus), rock dove (Columba livia), mourning dove (Zenaida macroura), great 26 horned owl (Bubo virginianus), short-eared owl (Asio flammeus), saw-whet owl (Aegolius 27 acadicus), northern flicker (Colaptes auratus), red-bellied woodpecker (Melanerpes carolinus), 28 red-headed woodpecker (M. erythrocephalus), horned lark (Eremophila alpestris), blue jay 29 (Cyanocitta cristata), American crow (Corvus brachyrhynchos), black-capped chickadee 30 (Poecile atricapillus), northern mockingbird (Mimus polyglottos), eastern bluebird (Sialia sialis), 31 cedar waxwing (Bombycilla cedrorum), loggerhead shrike (Lanius ludovicianus), starling 32 (Sturnus vulgaris), and house sparrow (Passer domesticus) (ComEd 1977). During the 2007 33 WHC baseline inventory of the LSCS site, 15 species of birds were observed, all of which had 34 been previously recorded as occurring on the site during baseline surveys (Exelon 2013b). 35 Reptiles and Amphibians 36 No reptiles or amphibians were collected on the LSCS site in the 1971 baseline surveys 37 (ComEd 1977). In 1972, two Eastern plains garter snakes (Thamnophis radix radix) were 38 observed in pastureland near an intermittent stream (ComEd 1977). The 2007 WHC baseline 39 inventory did not include reptiles or amphibians. 40 3.6.4 LSCS Wildlife Management Plan 41 The LSCS Wildlife Management Plan (Exelon 2013b) outlines the goals and projects of LSCSs 42 Wildlife at Work program. Some of the plans past and planned wildlife habitat enhancement 43 and conservation activities at the LSCS site include: 44

  • planting native vegetation, including swamp white oak (Quercus bicolor) near the 45 cooling pond, 3-55

Affected Environment 1

  • controlling invasive common reed (Phragmites australis) near the cooling pond, 2
  • enhancing existing habitat for grassland nesting birds through seeding, mowing, and 3 controlled burns, 4
  • maintaining nesting boxes for eastern bluebirds, and 5
  • installing osprey (Pandion haliaetus) platforms near the cooling pond 6 (Exelon 2014a).

7 Exelon (2015n), as a corporation, has been a member of the WHC since 2005, and Exelon first 8 received WHC certification for its Wildlife at Work program at LSCS in November 2011. 9 3.6.5 Important Species and Habitats 10 3.6.5.1 Important Species 11 State-Listed Species 12 The Illinois Endangered Species Protection Act of 1972, as amended, makes illegal the transfer, 13 sale, and possession of species (including skins and products) listed by the State as 14 endangered or threatened. The Act establishes an Endangered Species Protection Board, 15 which maintains a list of endangered and threatened species and advises the IDNR on the 16 conservation of those species. 17 Within LaSalle County, the IDNRs (2014b) Natural Heritage Database indicates that 18 28 State-listed terrestrial species (19 plants, 3 birds, 2 reptiles, 2 mammals, 1 insect, and 19 1 amphibian) occur in the county (see Table 3-9). In September 2013, Exelon generated an 20 IDNR Ecological Compliance Assessment Tool (EcoCAT) report that used Illinois Natural 21 Heritage Database information to further refine the list of State-listed species that could occur 22 on the LaSalle site and that could potentially be affected by the proposed license renewal. The 23 EcoCAT report is included in Appendix C of the applicants ER (Exelon 2014a). The report 24 indicates that there are no terrestrial State-listed species on or near the LSCS site that may be 25 affected by the proposed license renewal. In a May 2014 letter to Exelon, the IDNR (2014c) 26 confirmed that the EcoCAT report was accurate, and in its letter, the IDNR mentioned no 27 records of State-listed terrestrial species on or near the site. Federally protected species are 28 discussed in Section 3.8. 29 Table 3-9. State-Listed Species in LaSalle County Common Name Species Name Status(a) Amphibians four-toed salamander Hemidactylium scutatum ST Birds cerulean warbler Dendroica cerulea ST loggerhead shrike Lanius ludovicianus SE upland sandpiper Bartramia longicauda SE Insects regal fritillary Speyeria idalia ST 3-56

Affected Environment Common Name Species Name Status(a) Mammals gray bat(b) Myotis grisescens SE Indiana bat(b) Myotis sodalis SE Plants American brooklime Veronica americana SE bunchberry Cornus canadensis SE cliff goldenrod Solidago sciaphila ST decurrent false aster(b) Boltonia decurrens ST fibrous-rooted sedge Carex communis ST forked aster Aster furcatus ST golden corydalis Corydalis aurea SE hairy woodrush Luzula acuminata SE hemlock panic grass Dichanthelium portoricense SE long beech fern Phegopteris connectilis SE pink corydalis Corydalis sempervirens SE plantain-leaved sedge Carex plantaginea SE queen-of-the-prairie Filipendula rubra SE red pine Pinus resinosa SE red-berried elder Sambucus racemosa ssp. pubens SE shadbush Amelanchier sanguinea SE snowberry Symphoricarpos albus var. albus SE spike Elliptio dilatata ST weak bluegrass Poa languida SE Reptiles blanding's turtle Emydoidea blandingii SE timber rattlesnake Crotalus horridus ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) These species are also Federally listed under the Endangered Species Act of 1973, as amended (ESA) and are discussed in detail in Section 3.8. Source: IDNR 2014b 1 Although not listed as occurring in LaSalle County by the IDNR, Exelon (2014a) reports that it 2 has observed the State-threatened peregrine falcon (Falco peregrinus) on the LSCS site. A pair 3 of peregrine falcons nested on the roof of the auxiliary building several years ago. Exelon 4 (2014a) personnel have not observed peregrine falcon nesting in recent years, but personnel 3-57

Affected Environment 1 occasionally observe peregrines in flight on the site. The FES-O (NRC 1978) notes the 2 observance of a single peregrine falcon in November 1972 in an offsite woodland. 3 Bald Eagles 4 The bald eagle is protected under the Bald and Golden Eagle Protection Act (16 USC 668 5 et seq.). This Federal act prohibits anyone from taking or disturbing bald eagles or golden 6 eagles (Aquila chrysaetos), including their nests or eggs, without a U.S. Fish and Wildlife 7 Service (FWS)-issued permit. The bald eagle was observed near the LSCS site in April 1972, 8 on the rivers north-facing bluffs (ComEd 1977; NRC 1978). However, Exelon (2014a) is not 9 aware of bald eagle observations at the site in recent years. 10 3.6.5.2 Important Habitats 11 Illinois Natural Areas Inventory Sites 12 In its Illinois Natural Areas Inventory (INAI), the IDNR (2014a) identifies 28 LaSalle County sites 13 as Category I (high quality natural community and natural community restorations), Category II 14 (specific suitable habitat for state-listed species or state-listed species relocations), 15 Category III (State-dedicated Nature Preserves, Land and Water Reserves, & Natural Heritage 16 Landmarks), or a combination of the three categories. The 2013 EcoCAT report (contained in 17 Appendix D of the applicants ER (Exelon 2014a)) indicates that one of these sites with 18 terrestrial habitat lies near the LSCS site: Marseilles Hill Prairie. 19 The Marseilles Hill Prairie (INAI Site No. 1520) lies 3 mi (4.8 km) north of the LSCS main site 20 boundary (Exelon 2015o). It is 39.71 ac (16.07 ha) in size and managed by the IDNR (2014a) 21 to conserve prairie habitat. The IDNR (2014a) designates this INAI site as Category I. 22 State Parks and Wildlife Areas 23 The IDNR manages three areas for State parks or wildlife areas within 10 km (6 mi) of LSCS: 24 LaSalle Lake State Fish & Wildlife Area, Marseilles State Fish & Wildlife Area, and Illini State 25 Park. The LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling 26 pond that is managed by the IDNR and open to the public for fishing and other recreational 27 purposes (Exelon 2014a). The Marseilles State Fish & Wildlife Area is open to seasonal 28 hunting of turkey (Meleagris gallopavo), pheasant, quail, dove, deer, rabbit, squirrel, and coyote 29 (IDNR 2015e). Illini State Park provides habitat for a number deciduous trees, including hickory, 30 ash (Fraxinus spp.), walnut (Juglans spp.), elm, cottonwood (Populus deltoids), oak, and maple, 31 as well as white-tailed deer, eastern gray squirrels, opossums, beavers, raccoon, groundhogs, 32 and a variety of waterfowl and songbirds (IDNR 2015b). 33 Wetlands 34 The National Wetlands Inventory Wetlands Mapper identifies eight small areas of freshwater 35 emergent wetland and freshwater forested/scrub wetland on the LSCS site near the Illinois 36 River that total about 10 ac (4 ha) (FWS 2015e). Common tree species in the freshwater 37 forested/scrub wetland include American elm, black cherry, white oak, red oak, black oak, 38 shagbark hickory, bitternut hickory (Carya cordiformis), hackberry (Celtis occidentalis), elm, 39 willow (Salix spp.), and sycamore (Platanus occidentalis) (Exelon 2014a). The freshwater 40 emergent wetlands contain cattail (Typha spp.), horsetail (Equisetum spp.), and other 41 herbaceous vegetation (Exelon 2014a). 42 Managed Prairie Habitat 43 In partnership with Pheasants Forever, Inc., Exelon (2014a) actively manages 4 ha (10 ac) of 44 native prairie to the west of the cooling pond. 3-58

Affected Environment 1 3.6.6 Invasive and Non-Native Species 2 The invasive common reed inhabits parts of the cooling pond, particularly along the ponds 3 western edge. In 2007, as part of its Wildlife at Work program, Exelon (2014a) began an effort 4 to eradicate the species through mechanical harvesting and application of aquatic-safe 5 herbicides. 6 3.7 Aquatic Resources 7 The aquatic communities of interest for the LSCS site occur in the Illinois River and in the sites 8 artificial cooling pond. The Illinois River lies 5 mi (8 km) north of the site. It supplies makeup 9 water to LSCSs cooling system and receives cooling system blowdown. The cooling pond is 10 the sites main source of cooling water and is the plants UHS. Section 3.1.3 describes the 11 cooling system in detail, and Section 3.5.1 describes the surface water characteristics of the 12 Illinois River and the cooling pond. 13 The sections below describe the two main aquatic ecosystems at the LSCS site, the Illinois 14 River and the LSCS cooling pond (see Sections 3.7.1 and 3.7.2, respectively). In addition, 15 Section 3.7.3 describes State-listed species and important habitats and Section 3.7.4 describes 16 non-native species. 17 3.7.1 Illinois River 18 The Illinois River begins southwest of Chicago, at the confluence of the Des Plaines and 19 Kankakee Rivers. It flows south until it reaches the Mississippi River north of St. Louis, 20 Missouri. The total length of the Illinois River is approximately 322 mi (518 km) (IDNR 2011a). 21 The Illinois Rivers watershed drains a total of 29,010 mi2 (75,136 km2) from Illinois, Wisconsin, 22 and Indiana (IDNR 2011a). Major tributaries include the Des Plaines, Fox, Kankakee, 23 Vermilion, Mackinaw, Sangamon, Spoon, and La Moine rivers. 24 Prior to the 1800s, the Illinois River Basin was comprised of prairie savannas and oak-hickory 25 forests. The river provided diverse aquatic habitats including backwater lakes, side channels, 26 and a narrow main channel (USGS 1999a). The rapid expansion of agricultural activities 27 throughout the 1800s and early 1900s converted wet and mesic (relatively well drained) 28 floodplain prairies to crop lands. This land use conversion resulted in increased erosion, 29 sediment loading, and nutrient and herbicide transport to the Illinois River. Beginning in the 30 1900s, several efforts occurred to divert water from Lake Michigan and construct navigation 31 dams or levees to increase the navigability of the Illinois River to the Mississippi River and 32 provide a navigable passage from Chicago (Lake Michigan) to the Gulf of Mexico (USGS 33 1999a). As the population in Chicago continued to grow, sewage disposal and toxic waste 34 disposal further contributed to the degradation of aquatic habitat in the Illinois River (Parker 35 2014). By the 1960s, the biodiversity of fish within the upper Illinois River was low and 36 freshwater mussels were nearly absent (Sietman et al. 2001). Pollution tolerant, non-native 37 common carp (Cyprinus carpio) and goldfish (Carassius auratus) dominated fish populations 38 (Parker 2014). Since the passage of the CWA in 1974, water quality within the Illinois River has 39 improved and more diverse fish assemblages inhabit the upper Illinois River (Parker 2014). 40 Similarly, freshwater mussels have recolonized portions of the upper Illinois River since the 41 1980s (Sietman et al. 2001). 42 Currently, a series of locks and dams along the Illinois River continue to limit habitat connectivity 43 and fish passage along the Illinois River. Four of the locks and dams (Thomas J. OBrien, 44 Lockport, Brandon Road, and Dresden Island) are upstream of LSCS and four (Marseilles, 45 Starved Rock, Peoria, and LaGrange) are downstream (USACE 1998). The closest locks and 3-59

Affected Environment 1 dams to LSCS include the Dresden Island Lock and Dam, 22 mi (26 km) upstream of the LSCS 2 intake, and the Marseilles Lock and Dam, 2.4 mi (3.5 km) downstream of the LSCS discharge 3 (USACE 1998; Exelon 2015c). 4 In 2005, IEPA most recently classified the water quality within the Illinois River as fair, which 5 means that the water quality has been impaired, and the water body meets the needs of a 6 designated use most of the time (IDNR 2011a). Current factors that continue to contribute to 7 the degradation of the Illinois River include the increase in invasive fish, accumulated 8 sediments, continued sedimentation, and agricultural chemical runoff (USGS 1999a; 9 Parker et al. 2005). 10 3.7.1.1 Aquatic Communities in the Illinois River 11 Plankton 12 Plankton are small organisms that float or drift in rivers and other water bodies. Plankton is a 13 primary food source for many whales, fish, and other animals, and consists of bacteria, 14 protozoans, certain algae, tiny crustaceans such as copepods, and many other organisms. 15 ComEd, the previous owner of LSCS, conducted surveys for plankton within the Illinois River 16 both upstream and downstream of the LSCS discharge and river intake structures. ComEd 17 initially sampled plankton prior to operations, from August 1972 through January 1973, and 18 again during construction, from February 1974 through November 1976. These studies are 19 summarized in the Final Environmental Statement for Operations of LSCS (NRC 1978). 20 Phytoplankton. Phytoplankton are microscopic floating photosynthetic organisms that form 21 one base of aquatic food webs by producing biomass from inorganic compounds and sunlight. 22 As primary producers, phytoplankton play key ecosystem roles in the distribution, transfer, and 23 recycling of nutrients and minerals. 24 Diatoms were the most abundant phytoplankton in the Illinois River near LSCS in the 1970s, 25 and reached peak densities in August (NRC 1978). The most common diatom genera included 26 Cyclotella, Melosira, and Stephanodiscus. The NRC staff noted that many of the diatoms 27 collected in preoperational studies were pollution tolerant (NRC 1978). Other phytoplankton 28 followed similar trends with primary production peaking in August and dipping in winter months. 29 The NRC staff is not aware of any additional phytoplankton surveys that have been conducted 30 in the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2. 31 Periphyton. Periphyton includes a mixture of algae, cyanobacteria (in the past often called 32 blue-green algae), heterotrophic microbes, other small organisms, and detritus that attach to 33 submerged surfaces. Like phytoplankton, periphyton are primary producers and provide a 34 source of nutrients to many bottom-feeding organisms. 35 During ComEds initial study prior to construction, diatom densities upstream of the LSCS 36 discharge and intake areas accounted for 75 percent of the total periphyton density in 37 August 1972 and 100 percent in January 1973. The next dominant taxa was green algae, which 38 accounted for 7 percent of the total periphyton density in 1972 and none of the total periphyton 39 density in 1973. Downstream of the LSCS discharge and intake, diatom densities accounted for 40 94 percent of the total periphyton density in August 1972 and 92 percent in January 1973, while 41 the green algae accounted for 1 percent in 1972 and none in 1973 (NRC 1978). Diatoms were 42 the dominant periphyton group during the warmer months (May, August, and November), 43 whereas green algae was dominant during February from 1974 to 1976 (NRC 1978). Dominant 44 diatom genera included Cyclotella, Navicula, and Nitzschia; dominant green algae genera 45 included Stigeoclonium, Cladophora, Rhizoclonium, and Ulothrix (NRC 1978). 3-60

Affected Environment 1 The NRC staff is not aware of any additional periphyton surveys that have been conducted in 2 the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2. 3 Zooplankton. Zooplankton are small animals that float, drift, or weakly swim in the water column 4 and include ichthyoplankton (fish eggs and larvae) with no or limited swimming ability and larvae 5 of benthic invertebrates. Zooplankton are important trophic links between primary producers 6 (e.g., phytoplankton and periphyton) and carnivores (e.g., fish). 7 During preoperational studies, copepods and rotifers dominated zooplankton samples both prior 8 to and during construction (NRC 1978). Dominant copepod genera included Cyclops and 9 Eucyclops, and dominant rotifer genera included Asplanchna, Brachionus, Filinia, Notholca, 10 Polyarthra, and Synchaeta (NRC 1978). Peak densities for both copepods and rotifers 11 generally occurred in August, and minimum densities generally occurred in February. 12 In 2014, EA Engineering, Science, and Technology, Inc. (EA) (2015) collected icthyoplankton 13 samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected 14 samples using 0.5-m (1.6-ft) conical plankton nets with 505-µm mesh suspended from the 15 forebay bridge in front of the river intake (see Figure 3-15). EA (2015) collected samples during 16 the 2014 spawning season, from late April through August, when icthyoplankton densities would 17 likely be highest. 3-61

Affected Environment 1 Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure 2 Key: LSCS: LaSalle County Station; RSH: River Screen House 3 Source: EA (2015) 4 EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 5 27 distinct taxa. The most common taxa included carps, minnows, and suckers, which 6 combined comprised 79 percent of the number of organisms within ichthyoplankton sample. 7 EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was 8 not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles. 9 The most common taxa by life stage included Ictiobinae (buffalo fish) yolk-sac larvae 10 (24 percent), cyprinidae (carps and minnows) yolk-sac larvae (23 percent), and common carp 11 yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent 12 of the icthyoplankton samples (EA 2015). 13 Benthic Macroinvertebrates 14 Benthic macroinvertebrates include aquatic annelids (e.g., aquatic worms or oligochaetes, 15 leeches), mollusks, crustaceans, and insect larvae that inhabit aquatic sediments and 16 submerged surfaces. They accelerate detrital decomposition and nutrient cycling, and serve as 3-62

Affected Environment 1 a food source for fish and other aquatic biota. ComEd, Exelon, and their contractors sampled 2 benthic invertebrates during three time periods: preoperational studies from February through 3 November, 1972 through 1976 (as summarized in NRC 1978); a 1999 study in response to low 4 flow and high air temperatures (EA 2000); and a 2013 study in preparation for Exelons license 5 renewal application (EA 2014). 6 During the preoperational and the 2013 study, ComEd and Exelon sampled benthic 7 macroinvertebrates at one location upstream of the river intake and blowdown discharge 8 (location 1), at one location immediately downstream of the blowdown discharge (location 2), 9 and at two locations further downstream of the blowdown discharge (locations 3 and 4) (Figure 10 3-16). ComEd and Exelon sampled each location with a Hester-Dendy artificial substrate 11 sampler and a Ponar grab sampler (NRC 1978; EA 2014). 12 In 1999, Exelon also collected benthos using a Ponar grab at one site upstream and one site 13 downstream of the blowdown discharge, similar to the sampling sites for the preoperational and 14 2013 study. In addition, EA collected benthos using a Ponar grab at a second downstream site 15 that was further downstream than South Kickapoo Creek (EA 2000). 16 Figure 3-16. Sampling Locations in LSCS Aquatic Surveys 17 Source: EA 2014 18 Collections during preoperational studies resulted in the identification of 143 taxa (NRC 1978). 19 Chironomidae and Oligochaeta were the most dominant groups. The most common 20 oligochaete genera were Limnodrilus and Nais. The most abundant chironomid genera 21 included Cryptochironomous, Dicrotendipes, Procladius, Cricotopus, and Orthocladius. 22 EA (2000) collected a total of 34 taxa from Ponar grab samples. Chironomidae and Oligochaeta 23 were the most taxa-rich groups, with 12 taxa each. EA (2000) determined that the dominant 24 taxa at all sampling sites are considered tolerant to poor water quality. Both total richness and 25 the number of Ephemeroptera, Plecoptera, and Trichoptera species, which are considered 26 intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) 27 compared to upstream (location 1) of the intake and discharge structures. 3-63

Affected Environment 1 EA (2014) collected a total of 61 taxa from the Hester-Dendy artificial substrate collections. 2 Chironomidae was the most taxa rich group with 21 taxa followed by Ephemeroptera and Bivalvia, 3 with 8 taxa each. The dominant taxa from the Hester-Dendy collections included the following 4 insect larvae: Dicrotendipes modestus (a non-biting midge), Maccaffertium integrum (a mayfly), 5 Cyrnellus fraternus (a caddisfly), and Dicrotendipes neomodestus. Among the 10 most dominant 6 taxa for the Hester-Dendy artificial substrate samples, only one taxon is considered tolerant of 7 environmental degradation, Glyptotendipes (IEPA 1987; EA 2014). The remaining taxa are 8 considered facultative to slightly intolerant to poor water quality (IEPA 1987; EA 2014). 9 For the Ponar grab samples, Chironomidae was the most taxa rich group with 15 taxa, followed 10 by 8 Bivalvia and 4 Ephemeroptera taxa. EA (2014) observed the highest taxa richness at 11 locations 1 and 3 (20 to 29 taxa) as compared to locations 2 and 4 (16 to 27 taxa). Species 12 richness among pollution sensitive Ephemeroptera, Plecoptera, and Trichoptera was similar 13 among all locations, ranging from three to five taxa (EA 2014). At all sampling sites, EA (2014) 14 observed dominant taxa that were relatively tolerant to poor water quality as well as dominant 15 taxa that were relatively intolerant or facultative to poor water quality. 16 Fish 17 ComEd, Exelon, and their contractors sampled fish near LSCS during three time periods: 18 preoperational studies from May through November, 1972 through 1976 (as summarized in 19 NRC 1978); a post-operational study in response to low flow and high air temperatures in July 20 through October, 1999 (EA 2000); and a post-operational study in August 2013 in preparation 21 for Exelons license renewal application (EA 2014). 22 During both the preoperational and 2013 study, Exelon sampled fish at one location upstream of 23 the river intake and blowdown discharge (location 1) and at two locations downstream of the 24 blowdown discharge (locations 2 and 5), one of which was South Kickapoo Creek 25 (Figure 3-16). Exelon sampled fish at each sampling site by electrofishing in a downstream 26 direction for 500 m (1,640 ft). In addition, Exelon seined for fish along the shoreline at all three 27 locations using a 25-ft (8-m) long by 6-ft (2-m) deep seine with 0.19- in. (0.48-cm) mesh. 28 Exelon hauled the seine along 15 m (49 ft) of shoreline in a downstream direction. 29 In 1999, EA also electrofished at one site upstream and one site downstream of the blowdown 30 discharge, similar to the sampling sites for the preoperational and 2013 study. In addition, EA 31 electrofished at second downstream site that was further downstream than South Kickapoo 32 Creek (EA 2000). 33 All three studies looked for external parasites or other abnormalities. EA (2000 and 2014) 34 specifically examined all fish for external DELT (deformities, erosions, lesions, or tumors) 35 anomalies. 36 During the preoperational monitoring period, NRC (1978) determined that the most dominant 37 species included emerald shiner (Notropis atherinoides), gizzard shad (Dorosoma cepedianum), 38 common carp, green sunfish (Lepomis cyanellus), bluntnose minnow (Pimephales notatus), and 39 white sucker (Catostomus commersonii) (see Table 3-10). Prior to operations, downstream 40 collection stations generally had lower species abundance and higher species diversity than 41 upstream stations (NRC 1978). The NRC (1978) concluded that the low species abundance 42 and diversity, low condition factors, and the degree of external parasitism and physical damage 43 of the fishes in this area of the Illinois River were indicative of a poor quality aquatic 44 environment. Barge traffic, habitat alteration, and heavy pollution loads contributed significantly 45 to the poor water quality in the Illinois River near LSCS, which primarily supported populations 46 of pollution-tolerant fish in the 1970s (NRC 1978). 3-64

Affected Environment 1 During the 1999 survey, EA (2000) collected 27 species and 1 hybrid for a total of 960 fish. The 2 most commonly collected fish species included gizzard shad (24 percent), smallmouth buffalo 3 (Ictiobus bubalus) (12 percent), spotfin shiner (Cyprinella spiloptera) (10 percent), green sunfish 4 (9 percent) and bluegill (Lepomis macrochirus) (8 percent) (Table 3-10). EA (2000) observed a 5 total of 63 fish (6.6 percent of the catch) with DELT anomalies. Channel catfish (Ictalurus 6 punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest 7 DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin 8 erosion (52 percent) and deformities (38 percent). 9 During the 2013 study, EA (2014) collected 12 fish species for a total of 1,295 fish. The most 10 commonly collected species during electrofishing included gizzard shad (48 percent), spotfin 11 shiner (16.5 percent), smallmouth buffalo (6 percent), golden redhorse (Moxostoma erythrurum) 12 (5 percent), smallmouth bass (Micropterus dolomieu) (4 percent), and freshwater drum 13 (4 percent; EA 2014) (Table 3-10). Gizzard shad dominated samples both upstream and 14 downstream of the intake and discharge (EA 2014). The most commonly collected species 15 during seining surveys included emerald shiner (83 percent), spotfin shiner (9.5 percent), 16 bluntnose minnow (2 percent), and sand shiner (Notropis stramineus) (2 percent) (EA 2014) 17 (Table 3-10). Emerald shiner dominated samples both upstream and downstream of the intake 18 and discharge (EA 2014). EA (2014) observed DELT anomalies on 2 of the 1,295 fish collected 19 (0.2 percent), both of which were eroded fins on freshwater drum. EA (2014) did not observe 20 any external parasites or other abnormalities. 21 Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River Commonly Collected Species(d) Species Common Name 1974-1976(a) 1999(b) 2013(c) Cyprinidae Cyprinella spiloptera spotfin (spottail) shiner X X X Cyprinus carpio common carp X Notropis atherinoides emerald shiner X X X Notropis stramineus sand shiner X Pimephales notatus bluntnose minnow X X Pimephales vigilax bullhead minnow X X Centrarchidae Lepomis cyanellus green sunfish X X Lepomis macrochirus bluegill X Catostomidae Catostomus commersoni white sucker X Ictiobus bubalus smallmouth buffalo X X Micropterus dolomieu smallmouth bass X Moxostoma erythrurum golden redhorse X Atherinopsidae Labidesthes sicculus brook silverside X Clupeidae Dorosoma cepedianum gizzard shad X X X 3-65

Affected Environment Commonly Collected Species(d) Species Common Name 1974-1976(a) 1999(b) 2013(c) Sciaenidae Aplodinotus grunniens freshwater drum X (a) NRC 1978 (b) EA 2000 (c) EA 2014 (d) X= one of the sixth most commonly collected species, based on the number of individuals collected during electrofishing or seining sampling within a single time period. Note that a species may still have been observed during the collection period even if it was not one of the sixth most commonly collected species. Sources: NRC 1978; EA 2000, 2014 1 Common carp and white sucker were commonly collected during preoperational studies but 2 were not commonly collected during the 1999 or 2013 study. Ohio EPA (1987) classifies both of 3 these species as pollution tolerant. Brook silverside (Labidesthes sicculus), freshwater drum, 4 sand shiner, smallmouth bass, smallmouth buffalo, golden redhorse, and bluegill were among 5 the commonly collected species in the 1999 or 2013 studies but were not commonly collected in 6 the preoperational studies. Five of these seven species (brook silverside, sand shiner, 7 smallmouth bass, golden redhorse, and bluegill) are native species that are sensitive to declines 8 in water quality or habitat degradation (Lerczak 1996; Smith 2002). 9 These results are consistent with other fish surveys (Lerczak 1996; McClelland et al. 2012) 10 within the upper Illinois River that since the mid-1950s through 1990s and the 2000s, show a 11 decline in fish species that are tolerant of poor water quality and an increase in fish species that 12 are sensitive to habitat degradation. For example, Lerczak (1996) examined fish population 13 data from the Illinois Natural History Survey (INHS), which began monitoring fish populations in 14 the Illinois River in 1957. Since 1957, INHS conducted annual electrofishing surveys at set 15 locations throughout the entire Illinois River, including sampling locations approximately 1 RM 16 downstream of the LSCS river intake, within the vicinity of the LSCS river intake, and 11 RM 17 upstream of the LSCS river intake. Within the upper 50 mi (80 km) of the Illinois River, which 18 includes LSCS, Lerczak (1996) concluded that common carp, which is pollution tolerant, has 19 become less common while bluegill, which is intolerant to degraded habitats, has become more 20 common. For example, in the 1960s, INHS captured an average of 35 common carp per hour 21 as compared to 6 common carp per hour in the 1990s. Bluegill increased from averages of less 22 than 1 per hour in the 1960s to 12 per hour in the 1990s. Lerczak (1996) also noted that in the 23 1990s, fish communities were more evenly distributed among a greater number of species than 24 in the 1960s. For example, in 1962 and 1963, four species comprised 95 percent of all catches: 25 gizzard shad, emerald shiner, common carp, and goldfisha species with pollution tolerance 26 similar to common carp. In 1995, 10 species comprised 95 percent of all catches including 27 several species that are sensitive to habitat degradation, such as the bluegill, largemouth bass 28 (Micropterus salmoides), and several species of small minnows. 29 McClellan et al. (2012) also examined fish populations during three time periods from 1957 30 through 2009 based on INHS data. Table 3-11 describes the species that contributed to 31 approximately 90 percent of all electrofishing catches in the Illinois River (McClelland 32 et al. 2012). The NRC staff further classified fish as either pollution tolerant or intolerant. In 33 addition, the NRC staff determined whether McClelland reported increases or decreases in the 34 relative abundance of each species over time. The NRC staff notes that these general trends 35 were not assessed using regression analyses or other statistical analyses. The most common 3-66

Affected Environment 1 species during the 1957 through 1969 surveys (common carp, gizzard shad, emerald shiner, 2 and goldfish) are considered pollution tolerant species and the relative abundance of these 3 species has generally declined over time. All pollution intolerant species listed in 4 Table 3-11 have generally increased overtime. These data suggest that water quality within the 5 Illinois River has improved over time, allowing species that are pollution sensitive to increase in 6 relative abundance. 7 Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural History 8 Electrofishing Surveys from 1957 through 2009 Species(a) Common Name 1957-1969 1970-1989 1990-2009 Trend(c) Pollution Tolerant Species(b) Percent of Catch Cyprinus carpio common carp 24.9 16.4 7.6 Dorosoma cepedianum gizzard shad 20.4 23.0 16.2 Notropis atherinoides emerald shiner 19.3 10.7 10.6 Carassius auratus goldfish 6.6 2.2 - Cyprinus carpio x common carp x goldfish 3.0 - - Carassius auratus Lepomis cyanellus green sunfish 2.4 6.3 5.3 Ictiobus cyprinellus bigmouth buffalo 1.8 1.8 1.3 Ameiurus melas black bullhead 1.4 - - Pimephales vigilax bullhead minnow - - 2.9 Pimephales notatus bluntnose minnow - - 2.3 Lepomis humilis orangespotted sunfish - - 1.2 Aplodinotus grunniens freshwater drum - 3.8 4.8 Pollution Intolerant Species(b) Percent of Catch Lepomis macrochirus bluegill 2.8 6.2 13.1 Micropterus salmoides largemouth bass 2.2 5.1 6.4 Pomoxis nigromaculatus black crappie 1.8 4.2 2.9 Ictalurus punctatus channel catfish - 3.5 5.6 Morone chrysops white bass - 2.9 2.8 Micropterus dolomieu smallmouth bass - - 1.4 Notes: (-) = Fish species not part of 90 percent of the catch during specified time period (a) Species ordered by decreasing relative abundance based on McClelland et al 2012; species contributed to approximately 90 percent of all electrofishing catches in the Illinois River and could be classified as either pollution tolerant or intolerant. (b) Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015. (c) Inclines or declines in the relative abundance of each species are general trends; the NRC staff did not evaluate these trends using regression analyses or other statistical analyses. Sources: Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015; McClelland et al. 2012 9 3.7.2 LSCS Cooling Pond 10 As described in Section 3.5, the 2,058-ac (833-ha) cooling pond was created in 1978 by 11 pumping water from the Illinois River into the excavated pond. Exelon leases a large portion of 12 the LSCS cooling pond to the IDNR, which maintains the LSCS cooling pond as an outdoor 3-67

Affected Environment 1 recreation area for public use and fishing. IDNR has actively managed the LSCS cooling pond 2 since 1984 (Exelon 2014a). For example, IDNR surveys the cooling pond each year and 3 determines which fish to stock based on fishermen preferences, fish abundance, different 4 species tolerance to warm waters, predator and prey dynamics, and other factors (Exelon 2002, 5 2014a, 2015a). The cooling pond can be characterized as a highly managed ecosystem in 6 which IDNR fish stocking and other human activities primarily influence the species composition 7 and population dynamics. 8 3.7.2.1 Aquatic Community in the Cooling Pond 9 IDNR stocks the LSCS cooling pond each year. In 1981, IDNRs fish hatchery located adjacent 10 to the cooling pond started operations, at which point IDNR started stocking the cooling pond 11 with species from the hatchery (EA 2002). Initially, IDNR stocked the LSCS cooling pond with 12 largemouth bass and bluegill (EA 2002). 13 Currently, commonly stocked species include largemouth bass, smallmouth bass, black crappie 14 (Pomoxis nigromaculatus), white crappie (Pomoxis annularis), channel catfish, blue catfish 15 (Ictalurus furcatus), striped bass hybrid (Morone saxatilis x M. chrysops), walleye (Sander 16 vitreus), and bluegill (See Table 3-12; Exelon 2002 and 2015a). Because of the high water 17 temperatures experienced in the summer months, introductions of warm-water species, such as 18 largemouth bass and blue catfish, have been more successful than introductions of cool-water 19 species, such as walleye and tiger muskellunge. 20 In addition to the stocked species, gizzard shad and threadfin shad (Dorosoma petenense) 21 together called shadalso occur in the cooling pond. Shad are not recreationally fished, and 22 IDNR does not currently stock these fish. IDNR stocks some recreationally fished species that 23 consume shad (e.g., catfish and striped bass) in part to limit the size of shad populations 24 (Exelon 2002). 25 Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 Common Annual Species(a) Name 2008 2009 2010 2011 2012 2013 2014 Average Percent Lepomis bluegill 55,466 11,740 84,661 364,731 73,681 25,031 100,130 102,206 40% macrochirus Micropterus largemouth 66,395 51,207 50,434 30,470 84,166 48,753 2,660 47,726 19% salmoides bass Morone saxatilis striped 80,889 68,404 41,284 52,642 0 20,580 26,047 48,308 19% hybrid bass hybrid Ictalurus blue catfish 18,560 34,452 19,800 23,368 0 0 18,200 22,876 9% furcatus Micropterus smallmouth 25,365 21,155 21,118 22,733 20,683 22,354 20,582 21,999 9% dolomieu bass Lepomis redear 34,151 0 4,830 4,830 0 0 0 14,604 6% microlophus sunfish (a) Species are ordered by relative abundance (highest to lowest). Sources: Exelon 2014a; IDNR and Exelon 2014 and 2015 3-68

Affected Environment 1 3.7.2.2 Cooling Pond Fish Kill Events 2 LSCS has had four reportable fish kills in the cooling pond since 2001, including fish kills in 3 July 2001, June 2005, June 2009, and August 2010 (Exelon 2014a, 2015a). The temperature in 4 the cooling pond during these events ranged from 93 °F (33.9 °C) to 101°F (38.3 °C) 5 (Exelon 2001, 2009, 2010). In addition, several smaller non-reportable fish kills have occurred 6 when the cooling pond was 95 °F (35 °C) or above (Exelon 2015c). Exelon attributes these fish 7 kills to high cooling pond temperatures as a result of high summer temperatures combined with 8 low winds and high humidity, as described below (Exelon 2001, 2009, 2010). 9 The largest fish kill occurred in July 2001 when IDNR reported approximately 94,500 dead fish 10 due to high temperatures that peaked at 98.2 °F (36.9 °C) (Exelon 2001). IDNR found the 11 maximum temperature in the cooling pond discharge canal to be 120 °F (48.9 °C) and dissolved 12 oxygen levels to range from 6.2 to 18.8 parts per million. The majority of dead fish (96 percent) 13 were gizzard shad (90,800) (Exelon 2001). IDNR identified other dead fish to include 14 1,279 carp, 1,143 smallmouth buffalo, 610 freshwater drum, 345 channel catfish, 238 striped 15 bass hybrid, 93 smallmouth bass, 24 walleye, 13 bluegill, 12 white bass (Morone chrysops), 16 6 yellow bullhead catfish (Ameiurus natalis), and 4 yellow bass (M. mississippiensis) 17 (Exelon 2001). 18 In a June 2005 fish kill, IDNR counted 1,515 dead fish, including 1,439 striped bass hybrids 19 (95 percent), 36 smallmouth bass (2 percent), 20 walleye (1 percent),11 channel catfish (less 20 than 1 percent), 4 blue catfish (less than 1 percent), 3 yellow bass (less than 1 percent), and 21 2 sauger (less than 1 percent) (Exelon 2015c). The LSCS cooling pond peaked at 95 °F (35 °C) 22 during the fish kill (Exelon 2015c). 23 In the June 2009 fish kill, 3,000 to 4,000 gizzard shad comprised 99 percent of the dead fish 24 shad (Exelon 2009). Exelon (2009) also observed 26 smallmouth bass, 4 striped bass, and 25 4 walleye. Immediately prior to and during the fish kill, the LSCS cooling pond increased 10 °F 26 from 83 °F (28 °C) on June 20 to 93 °F (34 °C) on June 23. 27 In the August 2010 fish kill, IDNR concluded that over 90 percent of the dead fish were small 28 threadfin and gizzard shad less than 3 in. (8 cm) long (Exelon 2010). IDNR also observed dead 29 carp, striped bass hybrids, walleye, and smallmouth bass (Exelon 2010). The LSCS cooling 30 pond peaked at 101.3 °F (38.5 °C) the day before the fish kill. 31 3.7.3 Important Species and Habitats 32 3.7.3.1 State-Listed Species 33 IDNR lists 35 fish and 26 mussel species as State-endangered or threatened (IDNR 2015a). Of 34 these, IDNR (2014b) indicates that 7 species (5 fish, 2 mussels) occur in LaSalle County (see 35 Table 3-13). 3-69

Affected Environment 1 Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle County Recorded Occurrences Near LSCS LSCS River Intake(d) Starved Rock or Preoperational Studies (b) Marseilles Pool(c) Species Common Name State Status(a) Fish Fundulus diaphanous banded killifish ST x x Moxostoma carinatum river redhorse ST Moxostoma valenciennesi greater redhorse SE Notropis heterolepis blacknose shiner SE Notropis texanus weed shiner SE Mussels Alasmidonta viridis slippershell ST Elliptio dilatata spike ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) NRC 1978 (c) McClelland and Sass 2007; Fritts 2013 (d) EA 2014, 2015; Exelon 2015c, 2015p Sources: NRC 1978; IDNR 2014b; McClelland and Sass 2007; Fritts 2013; EA 2014, 2015; Exelon 2014a, 2015a 2 Banded killifish. Banded killifish occur in clear glacial lakes, streams, or tributaries, often near 3 vegetation (Nyboer et al. 2006). This fish forms small schools near the surface of weedy lakes 4 (Nyboer et al. 2006). In recent years, this species has been documented in the Illinois River 5 (McClelland and Sass 2007; McClelland et al. 2012). In 2006, the INHS collected two banded 6 killifish at RM 241.5 in the Starved Rock Pool sampling area, approximately 8 RM (13 Rkm) 7 downstream of the LSCS river intake (McClelland and Sass 2007). However, from 1993 8 through 2012, the INHS did not observe banded killifish in the Marseilles Pool sampling area, 9 which included sampling locations approximately 1 RM (1.6 Rkm) downstream of the LSCS river 10 intake, within the vicinity of the LSCS river intake, and 11 RM (18 Rkm) upstream of the LSCS 11 river intake (Fritts 2013). 12 In 2014, EA (2015) collected a juvenile banded killifish during an impingement and entrainment 13 study at the LSCS river intake. In response to this collection, Exelon noted that EA Engineering 14 intends to request a scientific collectors permit report from IDNR. This species was not 15 collected during preoperational surveys (NRC 1978) or during operational studies in 1999 and 16 2013 (EA 2000, 2014). 17 River Redhorse. The river redhorse inhabits large river systems, including impoundments and 18 pools, in areas of moderate to swift current and clean gravel substrate (NatureServe 2014a). 19 Barbour et al. (1999) classify this species as an insectivore that is intolerant of pollution and 20 other environmental stressors. INHS electrofishing surveys that began in 1957 have 21 documented this species in the Illinois River (McClelland and Sass 2007). However, from 1993 3-70

Affected Environment 1 through 2012, INHS did not observe river redhorse in the Marseilles Pool sampling area, which 2 included sampling locations approximately 1 RM (1.6 RKm) downstream of the LSCS river 3 intake, within the vicinity of the LSCS river intake, and 11 RM (18 RKm) upstream of the LSCS 4 river intake (Fritts 2013). The river redhorse was not collected during preoperational surveys 5 (NRC 1978) or operational surveys in 1999 and 2013 (EA 2000, 2014). From 2013 through 6 2015, EA (2015) conducted an impingement and entrainment study near the LSCS river intake. 7 Although EA (2015) collected several Moxostoma fish that were not identified to species, EA 8 (2015) concluded that these species were most likely the more common Moxostoma spp., such 9 as shorthead, golden, silver, and black redhorse, given that these common species were 10 conclusively identified during the study. 11 Greater Redhorse. The greater redhorse inhabits lakes and large rivers with sandy to rocky 12 pools (Nyboer et al. 2006). This fish was considered extirpated in Illinois until it was observed in 13 the upper Illinois River basin in 1985 (Nyboer et al. 2006). IDNR (2014) recorded three 14 observations of this species in LaSalle County, most recently in July 2004. This species is rare 15 in the Illinois River, and INHS did not observe this species from 1957 through 2006 at any 16 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 17 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 18 (EA 2000, 2014), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 19 1993 through 2012 (Fritts 2013). From 2013 through 2015, EA (2015) conducted an 20 impingement and entrainment study near the LSCS river intake. Although EA (2015) collected 21 several Moxostoma fish that were not identified to species, EA (2015) concluded that these 22 species were most likely the more common Moxostoma spp., such as shorthead, golden, silver, 23 and black redhorse given that these common species were conclusively identified during the 24 study. 25 Blacknose shiner. The blacknose shiner inhabits clear vegetated lakes, and pools and runs of 26 clear streams (Nyboer et al. 2006). Increased turbidity and decreases in aquatic vegetation 27 have contributed to the decline of this species (Nyboer et al. 2006). IDNR (2014) recorded two 28 observations of this species in LaSalle County, most recently in October 2013. This species is 29 rare in the Illinois River and INHS did not observe this species from 1957 through 2006 at any 30 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 31 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 32 (EA 2000, 2014), an impingement and entrainment study at the LSCS river intake from 2013 33 through 2015 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling 34 area from 1993 through 2012 (Fritts 2013). 35 Weed shiner. In Illinois, the weed shiner inhabits clear sand-bottom creeks with some 36 submerged vegetation (Nyboer et al. 2006). IDNR (2014) recorded one observation of this 37 species in LaSalle County, most recently in October 2013. This species is rare in the Illinois 38 River and INHS did not observe this species from 1957 through 2006 at any sampling station in 39 the Illinois River (McClelland and Sass 2007). This species was not collected during 40 preoperational surveys (NRC 1978), operational studies in 1999 and 2013 (EA 2000, 2014), an 41 impingement and entrainment study at the LSCS river intake from 2013 through 2015 42 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 1993 43 through 2012 (Fritts 2013). 44 Slippershell. The slippershell is a freshwater mussel that inhabits small to medium sized 45 streams where it is usually found buried in sandy substrates in shallow water 46 (Nyboer et al. 2006). IDNR (2014) recorded five observations of this species in LaSalle County, 47 most recently in October 2013. In 1994, 1995, and 1999, Sietman et al. (2001) conducted 48 freshwater mussel surveys in the Illinois River from RM 232.0 to 271.2 (RKm 373 to 436), 49 including the Starved Rock and Marseilles Pools sampling areas. Sietman et al. (2001) did not 3-71

Affected Environment 1 collect this species during the surveys. Similarly, this species was not observed in 2013 when 2 IDNR collected 14,850 live mussels, representing 23 species, near the Marseilles Dam after a 3 boating accident (Kanter 2013). This species was not collected during LSCS preoperational 4 surveys (NRC 1978), operational studies in 2013 (EA 2014), or during impingement and 5 entrainment studies at the LSCS river intake from 2013 through 2015 (EA 2015). 6 Spike. The spike is a freshwater mussel that inhabits shoals of medium streams to large 7 rivers, reservoirs, and lakes with sand and gravel substrates (Minnesota DNR 2014). It is 8 distributed throughout the eastern United States, the Mississippi River system, and portions of 9 the Great Lakes (NatureServe 2014b). IDNR (2014) recorded one observation of this species in 10 LaSalle County in August 2010. This species was not collected during LSCS preoperational 11 surveys (NRC 1978); the freshwater mussel survey from RM 232.0 to 271.2 in 1994, 1995, and 12 1999 (Sietman et al. 2001); IDNRs collection of mussels near the Marseilles Dam in 2013 13 (Kanter 2013); operational studies in 2013 (EA 2014); or during impingement and entrainment 14 studies at the LSCS river intake from 2013 through 2015 (EA 2015). 15 3.7.3.2 Important Habitats 16 LaSalle Lake State Fish and Wildlife Area is part of the 2,058 ac (833 ha) cooling pond. As 17 described above in Section 3.7.2, IDNR manages this area for public boating and fishing. 18 The Marseilles State Fish and Wildlife Area occurs approximately 1.5 mi (2.4 km) north of the 19 LSCS site and the makeup and blowdown pipeline corridor right-of-way crosses the eastern 20 portion of the area. The Marseilles State Fish and Wildlife Area is a 1,032-ha (2,550-ac) area 21 managed by IDNR for hunting and wildlife habitat (IDNR 2015d). It is a joint-use area with the 22 Illinois Department of Military Affairs, and periodically used by the Illinois National Guard for 23 training (IDNR 2015d). 24 3.7.4 Non-Native Species 25 Several non-native species, including the common carp, goldfish, and Asian carps 26 (Hypophthalmichthys spp.), have been introduced into the Illinois River (McClelland et al. 2012). 27 Common carp and goldfish have been present in the vicinity of LSCS prior to operations 28 (McClelland et al. 2012; Exelon 2014a). Both species dominated non-native fish collections in 29 INHSs long term monitoring surveys from 1957 and 1985 (McClelland et al. 2012). Common 30 carp and goldfish are tolerant of degraded aquatic habitats and can tolerate low levels of 31 dissolved oxygen and high water turbidity. 32 Beginning in 1985, the number of non-native fish observed in the Illinois River increased 33 (McClelland et al. 2012). Species documented in the Illinois River since 1985 include grass 34 carp (Ctenopharyngodon idella), bighead carp (Hypophthalmycthys nobilis), silver carp 35 (Hypophthalmycthys molitrix), round goby (Neogobius melanostomus), white perch (Morone 36 americana), and the white perch-yellow bass hybrid (M. americana x M. mississippiensis) 37 (McClelland et al. 2012). 38 In addition to fish, Exelon has documented the occurrence of invertebrate non-native species 39 near the river intake, the cooling pond intake, and within the cooling system. Bryozoans are 40 aquatic invertebrates that grow into large sessile colonies. Zebra mussels are native to the 41 Black and Caspian Seas, and have invaded Europe and North America. These organisms can 42 cause biofouling of LSCSs underwater piping systems or water intakes. In 1996, Exelon 43 discovered bryozoans at the cooling pond screen house and removed the colony by using a 44 continuous chlorination treatment. In 2010, Exelon observed the bryozoan Plumatella reticulata 45 in the Unit 1 cooling water system and unidentified bryozoans at the river intake and in the 46 cooling pond (HDR 2011). Within the past 5 years, Exelon has continued to regularly observe 3-72

Affected Environment 1 bryozoan colonies and zebra mussels at both the river intake and the cooling pond intake, and 2 limits the growth of these organisms by using biocides (HDR 2012, 2013, 2014; Exelon 2014a). 3 When necessary, Exelon also follows procedures to remove zebra mussels manually. 4 3.8 Federally Protected Species and Habitats 5 Because NRCs issuance of a renewed license for power plants is a Federal action, the NRCs 6 National Environmental Policy Act (NEPA) process considers species and habitats that are 7 protected under Federal acts and possibly affected by license renewal. Federal acts that 8 protect species and habitats possibly affected by the renewal of a nuclear plant license include 9 the Endangered Species Act of 1973, as amended (ESA); the Bald and Golden Eagle 10 Protection Act of 1940, as amended; the Migratory Bird Treaty Act of 1918, as amended; the 11 Magnuson-Stevens Fishery Conservation and Management Act, as amended (MSA); and the 12 Marine Mammal Protection Act of 1972, as amended. Of these, the NRC has direct 13 responsibilities only under the ESA and MSA. No species protected under the MSA, which 14 protects habitat for certain marine and anadromous fish species, occur near LSCS. Species 15 protected under the ESA are discussed in this section, and species protected under other 16 Federal acts where the NRC has no direct responsibilities and under State acts are discussed in 17 Section 3.6 for terrestrial resources and Section 3.7 for aquatic resources. 18 Section 7(a)(2) of the ESA states that each Federal agency shall, in consultation with the 19 Secretary (Secretary of Commerce or Secretary of the Interior), insure that any action 20 authorized, funded, or carried out by that agency is not likely to jeopardize the continued 21 existence of a listed species or result in the destruction or adverse modification of designated 22 critical habitat. In fulfilling these requirements, each agency is to use the best scientific and 23 commercial data available. Section 7 of the ESA sets out the consultation process, which is 24 further implemented by regulation (50 CFR Part 402). The ESA makes it unlawful for a person 25 to take a listed animal without a permit, where take under the ESA is defined as to harass, 26 harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such 27 conduct. Through regulations, the term harm is defined as an act which actually kills or 28 injures wildlife. Such an act may include significant habitat modification or degradation where it 29 actually kills or injures wildlife by significantly impairing essential behavioral patterns, including 30 breeding, feeding or sheltering (50 CFR 17.3). Listed plants are not protected from take, 31 although collecting or maliciously harming them on Federal land is illegal. 32 The FWS and the National Marine Fisheries Service jointly administer the ESA. The FWS 33 manages the protection of and recovery efforts for listed terrestrial and freshwater species, and 34 the National Marine Fisheries Service manages the protection of and recovery efforts for listed 35 marine and anadromous species, of which none occur in the Illinois River near LSCS. 36 3.8.1 Action Area 37 The ESA regulations at 50 CFR 402.02 define action area to mean all areas to be affected 38 directly or indirectly by the Federal action and not merely the immediate area involved in the 39 action. The action area essentially bounds the analysis of ESA-protected species because 40 species that occur within the action area may be affected by the Federal action, while species 41 that do not occur within the action area would likely not be affected by the Federal action. The 42 NRC staff recognizes that, although the action area is stationary, Federally listed species can 43 move in and out of the action area. For instance, a migratory fish species could occur in the 44 action area periodically and then travel to freshwater streams to spawn. Similarly, a flowering 45 plant known to occur near, but outside of, the action area could appear within the action area 46 over time if its seeds are carried into the action area by wind, water, or animals. Thus, in its 3-73

Affected Environment 1 analysis, the NRC staff considers not only those species known to occur directly within the 2 action area but also those species that may passively or actively move into the action area. The 3 NRC staff then considers whether the life history of each species makes the species likely to 4 move into the action area where it could be affected by the proposed LSCS license renewal. 5 Depending on habitat requirements, migration patterns, or other biological or physical 6 requirements, different species may require different action areas. 7 The LSCS site occupies about 1,528 ha (3,776 ac) in Marseilles, La Salle County, Illinois 8 (Exelon 2015p), about 8 km (5 mi) south of the Illinois River (Exelon 2014a). A cooling pond on 9 the eastern side of the site accounts for about half of the site area. A 5.6-km (3.5-mi) corridor 10 for the makeup and blowdown pipelineswhich travel underground from the Illinois River 11 screen house south to the cooling pondconnects the cooling pond with the Illinois River, from 12 which LSCS withdraws makeup water and discharges blowdown (Exelon 2014a). The intake 13 structure on the Illinois River has bar grills, traveling screens with 3/8 in. (9.5 mm) openings, 14 and no fish return system (Exelon 2014a). 15 For Federally protected terrestrial species, the action area is the site, including the water intake 16 and discharge pipe ROW, and areas immediately around the site that could include natural 17 populations affected by plant operations. Within the action area, Federally listed terrestrial 18 species could experience impacts such as habitat disturbance associated with transmission 19 lines, exposure to radionuclides, and other direct and indirect impacts associated with station, 20 cooling system, and in-scope transmission line operation and maintenance (NRC 2013). 21 For Federally protected aquatic species, the action area is the site and the Illinois River in the 22 area affected by water withdrawal and discharge as well as the range of any species affected by 23 water withdrawal and discharge. The license renewal of nuclear plants action can affect 24 Federally listed aquatic species in several ways, such as impingement or entrainment of 25 individuals into the cooling system, alteration of the riverine environment through water level 26 reductions, changes in dissolved oxygen, gas supersaturation, eutrophication, thermal 27 discharges from cooling system operation, habitat loss or alteration from dredging, and 28 exposure to radionuclides (NRC 2013a). 29 3.8.2 Federally Protected Species and Habitats Considered 30 Exelons ER (2014a) documents correspondence between Exelon and the FWS about the 31 effects of the proposed LSCS license renewal on Federally listed species. In July 2014, the 32 FWS concurred with Exelons March 2014 conclusion that license renewal would not adversely 33 affect any Federally listed species and noted that Exelon should consider an additional species: 34 Northern long-eared bat, a proposed species known to occur in the plant vicinity. In 35 August 2014, Exelon submitted a biological evaluation including the northern long-eared bat, 36 and the FWS concurred with Exelons conclusion that license renewal would not affect any 37 Federally listed species. Exelon (2014a, Appendix D) includes copies of this correspondence. 38 In late February 2015, NRC staff filled in an online form for an updated protected species list for 39 LSCS on FWSs Environmental Conservation Online System, Information for Planning and 40 Conservation. The FWS (2015b) responded with a list of threatened and endangered species 41 that may be affected by the LSCS license renewal. In October 2015, the NRC staff checked the 42 FWS (2015a) online Illinois County distribution of listed species for updates. Exelon (2014a) 43 reports that no federally listed species have been observed on the LSCS property. Terrestrial 44 and wildlife studies conducted by Exelon associated with LSCS that may have discovered and 45 reported Federally listed species are described in Section 3.6.2 of this SEIS. 46 Exelon commissioned several aquatic monitoring studies in the past, and none of them reported 47 Federally listed species in the Illinois River near LSCS. EA (2000) reported the results of a 3-74

Affected Environment 1 1999 monitoring study at three locations in the Illinois River upstream and downstream of the 2 LSCS intake and discharge in late summer. Fish were sampled by electrofishing and seining 3 and benthic macroinvertebrates by Ponar grab. The physical condition of fish put the study area 4 in the poorest category using Ohio criteria, and a benthic macroinvertebrate (macrobenthos) 5 community indicative of poor conditions was present. No Federally listed threatened or 6 endangered species were observed. 7 EA (2014) reported results of fish and macrobenthos monitoring above and below LSCS in 8 summer 2013 and compared results with past studies. Fish were sampled by electrofishing and 9 seining and benthic macroinvertebrates by Ponar grab, kick net samplers, and artificial 10 substrate samplers. No Federally listed threatened or endangered species were observed. 11 EA (2015) reported results of impingement sampling from April 2014 through March 2015 and 12 entrainment sampling in April through August 2014. No Federally listed fish or shellfish species 13 were observed in entrainment or impingement samples. 14 Table 3-14 shows Federally listed species that may occur in LaSalle County near LSCS and 15 habitat notes. Descriptions of the species follow. 16 Table 3-14. Federally Listed Species and Designated Habitat in La Salle County, Illinois Federally Listed Federal Group Species Common Name Status(a) Habitat Mussels Plethobasus sheepnose E Shallow areas in larger rivers and cyphyus mussel streams. Flowering Boltonia decurrent false T Moist, sandy floodplains and prairie Plants decurrens aster wetlands along the Illinois River. Platanthera eastern prairie T Mesic prairie, wetlands, sedge leucophaea fringed orchid meadows, marsh edges, and bogs with full sun and little to no woody encroachment. Delea foliosa leafy prairie- E Prairie remnants on thin soil over clover limestone. Mammals Myotis sodalis Indiana bat E Caves, mines (hibernacula); small stream corridors with well-developed riparian woods; upland forests (foraging). Myotis northern long- T Hibernates in caves and mines - septentrionalis eared bat swarming in surrounding wooded areas in autumn. Roosts and forages in upland forests and woods. Critical Habitat Myotis sodalis Indiana bat Blackball Mine (a) E=endangered; T=threatened Sources: FWS 2015b, 2015a 17 Sheepnose Mussel (Plethobasus cyphyus). The FWS listed the sheepnose mussel (also called 18 just sheepnose) as endangered on March 13, 2012, with an effective date of April 12, 2012, but 19 could not designate critical habitat at that time (77 FR 14914). The sheepnose mussel is a 20 freshwater mussel in the family Unionidae. According to Parmalee and Bogan (1998), adult 3-75

Affected Environment 1 mussels may reach 11 to 12 cm (4.3 to 4.8 in.) in length. Adult mussels are found partially or 2 completely buried in the substrate. They are suspension feeders and eat bacteria, algae, 3 microscopic animals, and detritus (77 FR 14914). Sheepnose is found in large rivers in gravel 4 or mixed sand and gravel (INHS 2013). Further, in unimpounded rivers, sheepnose mussels 5 can be found in less than 0.6 m (2 ft) of water and in relatively fast currents. In reservoirs, 6 sheepnose mussels occupy depths of 3.6 to 4.6 m (12 to 15 ft) (Parmalee and Bogan 1998), 7 though they have also been reported at depths exceeding 6 m (20 ft) (77 FR 14914). 8 Sheepnose mussels are long-lived and can live nearly 100 to 200 years (FWS 2013b). 9 Like other unionids, sheepnose has an unusual life cycle. After fertilization, the eggs live in 10 special gill chambers of the females and develop into microscopic larvae called glochidia. 11 Females brood the glochidia. When the glochidia are ready, the female expels the glochidia, 12 which then must attach to the host fishs gills or fins to complete development by enclosing 13 themselves in a cyst (encysting). They drop off the host fish as newly transformed juveniles. 14 The sauger (Sander canadensis) is the only known natural host for sheepnose mussel 15 glochidia. The FWS (77 FR 14914) reports that in laboratory studies, sheepnose glochidia 16 have successfully transformed on several other species, including fathead minnow (Pimephales 17 promelas), creek chub (Semotilus atromaculatus), central stoneroller (Campostoma anomalum), 18 and brook stickleback (Culaea inconstans), although interactions between these species and 19 sheepnose may be rare and infrequent in nature due to habitat preferences. The FWS (2015c) 20 identifies golden shiner (Notemigonus crysoleucas) as another possible host species. 21 The sheepnose mussel is found across the Southeast and the Midwest, although it has been 22 eliminated from about two-thirds of its range. Today, the sheepnose mussel is found in 23 Alabama, Illinois, Indiana, Iowa, Kentucky, Minnesota, Mississippi, Missouri, Ohio, 24 Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. 25 In a study for Exelon, EA (2014) sampled fish, benthic invertebrates, and physical and chemical 26 parameters during summer 2013 in the Illinois River both upstream and downstream of LSCS 27 and compared the results to past studies for LSCS in 1974 through 1978 and 1999. EA 28 sampled fish using electrofishing and seines and benthic invertebrates using artificial substrate 29 samples and a grab sampler. EA found no threatened or endangered fish or macroinvertebrate 30 species, including endangered mussels, near LSCS in this study or in past studies. 31 Exelon (2014a) reports not observing any Federally listed species at LSCS. 32 Decurrent False Aster (Boltonia decurrens). Decurrent false aster is a flowering perennial plant 33 in the aster family. The aster-like flowers appear from the tall (typically about 1.5 m (60 in.) or 34 more), bushy plants from August to October, and the flower rays range in color from white to 35 pale violet. Decurrent refers to leaf stem bases that run down along the stem where they 36 attach. Decurrent false aster lives in the wet prairies in disturbed alluvial ground and open 37 shores of floodplain forests along the Illinois and Mississippi Rivers, and historically ranged from 38 LaSalle, Illinois, downstream to St. Louis, Missouri, on the Mississippi River. In 1988, the FWS 39 proposed to list the species as threatened (53 FR 5598) because it found only 12 extant 40 populations remaining in 5 Illinois counties and one Missouri County. In addition, destruction 41 and modification of the floodplain forest along the Illinois and Mississippi Rivers due to wetland 42 drainage and agricultural expansion threatened survival of the species. In November 1988, the 43 FWS determined the decurrent false aster to be a threatened species under the ESA but did not 44 designate critical habitat (53 FR 45858). At that time, the FWS thought the species to be 45 extirpated from 13 counties in Illinois and 3 counties in Missouri. Twelve remaining extant 46 populations were located along the Illinois River in Morgan, Schuyler, Fulton, and Marshall 47 Counties; one population along the Mississippi River in St. Clair County; and two populations in 48 St. Charles County, Missouri. It was often found in disturbed alluvial soil where the forest 49 overstory and understory are open due to frequent flooding. It prefers moist, sandy areas 3-76

Affected Environment 1 around natural lakes in the Illinois River floodplain, but these areas now receive 2 or 3 in. (5 to 2 7.5 cm) of silt per year due to extensive row crop agricultural practices and numerous levee 3 systems that increase the amount of silt deposited on river banks during floods, and the silt 4 prevents seed germination. 5 The FWS initiated 5-year status reviews of decurrent false aster in 1990 and 2011, requested 6 new information on the species, and found no reason to change the ESA threatened status. In 7 its Recovery Plan that incorporated new information, FWS (1990) reported 18 known 8 populations for this species in Illinois and 2 in Missouri, although not all were self-sustaining. In 9 its 2012 5-year Review, FWS (2012b) found that research since the Recovery Plan indicated 10 that this species may best be described as a metapopulation (a group of spatially separated 11 populations of the same species that interact at some level) that colonizes and disappears from 12 available habitat patches. In a metapopulation, as local populations fluctuate in size, they 13 become vulnerable to extinction during periods when their numbers are low, and the regional 14 persistence of the species depends on the existence of a metapopulation. Elimination of much 15 of the metapopulation structure can increase the chance of regional extinction of the species. 16 The plants abundance appears to fluctuate widely in response to annual changes in site 17 conditions and the dynamic Illinois River hydrology. In a metapopulation model of decurrent 18 false aster (Smith et al. 2005), flood pulses characterized by spring floods and midsummer 19 periods of low water maintain subpopulations and help establish new sub-populations. The 20 flood pulses provide necessary disturbance and reduce competition to facilitate the colonization 21 of habitats. Impoundment of the Illinois River and periodic prolonged high water events during 22 the growing season have reduced available habitat and contributed to the species decline. The 23 FWS has not reported extant populations in LaSalle County and Exelon (2014a) reports no 24 threatened or endangered species on the LSCS site. 25 Eastern Prairie Fringed Orchid (Platanthera leucophaea). The eastern prairie fringed orchid is 26 1 of at least 200 North American orchid species and is a perennial herb. Plants are about 8 to 27 40 in. (0.2 to 1 m) tall. An upright leafy stem carries a flower cluster called an inflorescence. 28 The 3- to 8-in. (76- to 200-cm) lance-shaped leaves sheath the stem. Each plant has one single 29 flower spike composed of 5 to 40 creamy white flowers, and the blossoms often rise just above 30 the height of the surrounding grasses and sedges. Blooming occurs in late June and early July. 31 Night-flying hawkmoths (family Sphingidae) pollinate the nocturnally fragrant flowers 32 (FWS 2013a). 33 This species typically inhabits tallgrass prairies east of the Mississippi River that have 34 calcareous silt loam soils and calcareous wetlands with open portions of fends, sedge 35 meadows, marshes, and bogs. While once numerous and widespread, populations have 36 declined with the disappearance of eastern prairies by conversion of habitat for crop fields, 37 grazing, intensive and continuous hay mowing, drainage, and related human uses. Other 38 reasons for the decline include succession to woody vegetation, competition from non-native 39 species, and over-collection. Remaining populations tend to be small, unprotected, and 40 unmanaged. The FWS designated the eastern prairie fringed orchid as an endangered species 41 in 1989 (54 FR 39857) and in 2012 initiated a 5-year status review of the listing (77 FR 38762). 42 The FWS did not designate critical habitat for this species. Exelon (2014a) reports not 43 observing any Federally listed species on the LaSalle site. 44 Leafy Prairie-Clover (Delea foliosa). The FWS listed the leafy prairie-clover as endangered 45 throughout its range in 1991 (56 FR 19953), when it was known to be present only in two sites 46 in Alabama, nine sites in Tennessee, and three sites in Illinois. The FWS did not designate 47 critical habitat for leafy prairie-clover. The species is perennial and a member of the pea family 48 (Fabaceae). The plants grow erect stems about 0.5-m (1.5-ft) tall, on the end of which grow 3-77

Affected Environment 1 small purple flowers in dense spikes. Flowering begins in August, and seeds ripen in early 2 October, after which the above-ground portion of the plant dies while the below-ground portion 3 survives the winter (56 FR 19953). 4 This plant is typically found in dry prairies, often in dolomitic soils. In Illinois, leafy prairie-clover 5 was originally known from six counties in the northeastern part of the State, but by 1991 only 6 three populations were known in the State, all in Will County in prairie remnants along the 7 Des Plaines River (56 FR 19953). The U.S. Forest Service (USFS) (undated a) lists the 8 reasons for its decline as plant and habitat loss from inundation by dams, road work, and 9 right-of-way management, including herbicide effects; botanical and horticultural collection; 10 off-road vehicle impacts to plants and habitat; predation by deer and rabbits; encroachment of 11 woody plants; and severe drought. Its habitat is being lost as dolomite prairies are being 12 converted to industrial, commercial, and residential uses (USFS undated b). Recovery efforts 13 by a partnership of the FWS (Chicago Field Office), the USFS, the Forest Preserve District of 14 Will County, the Department of the Army (Joliet Training Area), the IDNR, the Forest Preserve 15 District of Kane County, and Midewin National Tallgrass Prairie are underway in northeastern 16 Illinois (USFS undated b). Exelon (2014a) reports not observing any Federally listed species on 17 the LSCS site. 18 Indiana Bat (Myotis sodalis). The FWS listed the Indiana bat as endangered in 1967 19 (32 FR 4001). The FWS designated critical habitat for the Indiana bat in 1976 (41 FR 41914) to 20 include 11 caves and 2 mines in six states, including a cave in LaSalle County, Illinois. The 21 Indiana bat is an insectivorous, migratory bat that inhabits the central portion of the Eastern 22 United States and hibernates colonially in caves and mines. The decline of Indiana bats is 23 attributed to urban expansion, habitat loss and degradation, human-caused disturbance of 24 caves or mines, insecticide poisoning, and white-nose syndrome (WNS) (FWS 2011; 25 Pruitt and TeWinkel 2007). 26 During summer months, reproductive female bats tend to roost in colonies under slabs of 27 peeling tree bark or cracks within trees in forest fragments, often near agricultural areas 28 (Pruitt and TeWinkel 2007). Colonies may also inhabit closed-canopy, bottomland deciduous 29 forest; riparian habitats; wooded wetlands and floodplains; and upland communities 30 (Pruitt and TeWinkel 2007). Maternity colonies typically consist of 60 to 80 adult females 31 (Whitaker and Brack 2002). Colonies occupy multiple trees for roosting and rearing young 32 (Watrous et al. 2006) and, once established, usually return to the same areas each year 33 (Pruitt and TeWinkel 2007). Nonreproductive females and males do not roost in colonies during 34 the summer; they may remain near the hibernacula or migrate to summer habitat 35 (Pruitt and TeWinkel 2007). A hibernaculum is an area where bats gather and hibernate in 36 winter. High-quality summer habitat includes mature forest stands containing open 37 subcanopies, multiple moderate- to high-quality snags, and trees with exfoliating bark 38 (Farmer et al. 2002). In summer, bats forage for insects along forest edges, riparian areas, and 39 in semi-open forested habitats. In the winter, Indiana bats rely on caves for hibernation. The 40 species prefers hibernacula in areas with karst (limestone, dolomite, and gypsum), although it 41 may also use other cave-like locations, such as mines. 42 The Indiana Bat Recovery Plan (Pruitt and TeWinkel 2007) indicates that Indiana bats are 43 distributed across 36 of the 102 counties in Illinois. Twenty-two winter hibernacula (16 extant, 44 4 of uncertain status, and 2 historic) are located throughout these counties. Additionally, 45 29 extant maternity colonies occur in Illinois, and adult males, nonreproductive females, or both 46 have been captured during summer surveys within 26 of the 36 counties. For 2011, the 47 FWS (2009) estimated that Illinoiss total population of Indiana bats was 54,095 individuals. 48 According to more recent estimates, the Illinois population of Indiana bats has increased by 3-78

Affected Environment 1 almost 2,000 over in 2011 to 55,956 individuals (FWS 2012a). Exelon (2014a) reports not 2 observing any Federally listed species on the LSCS site. 3 Northern Long-Eared Bat (Myotis septentrionalis). In December 2013, the FWS (78 FR 72058) 4 found that listing of the northern long-eared bat as an endangered species under the ESA was 5 warranted. Earlier in October 2013, the FWS (78 FR 61046) had found that it could not 6 determine critical habitat for this species. The FWS listed the northern long-eared bat as 7 threatened throughout its range on April 2, 2015 (80 FR 17974). The following information is 8 from those listing documents. The northern long-eared bat is a medium-sized bat species with 9 average adult body weights of 5 to 8 grams (0.2 to 0.3 ounces), adult body lengths between 10 77 to 95 mm (3.0 to 3.7 in.) and wingspans between 228 and 258 mm (8.9 to 10.2 in.). Adult fur 11 is typically brown, darker on top than below. The range includes much of the eastern and north 12 central United States (it occurs in 39 states) and all Canadian provinces west to the southern 13 Yukon Territory and eastern British Columbia. Throughout the majority of this range, however, it 14 is patchily distributed, and historically it was less common in the southern and western part of its 15 range than in the northern portion. The bats gather and hibernate in winter typically in mines 16 and caves, where they are now usually found only in low numbers. They migrate out of the 17 hibernacula in summer, when they forage at night and roost during daylight in small numbers in 18 live and dead trees and change roosts often. Their diet includes moths, flies, leafhoppers, 19 caddisflies, and beetles, although the diet differs geographically and seasonally, and an 20 individual can consume 3,000 insects each night. Mating occurs in the autumn and birthing in 21 May or June. Mature forests are an important habitat type for northern long-eared bats, 22 although they occasionally act as forager over forest clearings and along roads. The northern 23 long-eared bat has experienced a sharp decline, estimated at approximately 99 percent from 24 hibernaculum data, in the northeastern portion of its range due to the recent emergence of a 25 fungal disease known as WNS (currently called Geomycetes destructans), and the FWS 26 expects similar declines in the western part of its range as this disease spreads. The 27 FWS (2013c) confirmed the existence of WNS in northern long-eared and little brown bats from 28 LaSalle and Monroe Counties, Illinois. Human activities that threaten this species include 29 constructing physical barriers at cave accesses and destruction of habitat through mining, 30 flooding, vandalism, development, timber harvest, and other activities. Exelon (2014a) reports 31 not observing any Federally listed species on the LSCS site. 32 Summary of the Occurrence of Listed Species within the Action Area. The six species listed in 33 Table 3-14 are under the FWSs jurisdiction within LaSalle County, although the information is 34 not specific to the LSCS site. For the six species identified for LaSalle County, the NRC staff 35 did not identify any within the action area after review of the ER (Exelon 2014a), a site visit that 36 included discussions with site staff and review of onsite documents, and published and online 37 sources. Sections 3.6 Terrestrial Resources and 3.7 Aquatic Resources summarize the 38 ecological surveys performed on and near the LSCS site that would detect protected species. 39 Exelon (2014a) reports not observing any Federally listed species on the LSCS site. 40 3.9 Historic and Cultural Resources 41 This section discusses the cultural background and the known historic and cultural resources 42 found on or near LSCS. The discussion is based on a review of historic and cultural resource 43 surveys and other background information on the region surrounding LSCS. In addition, a 44 records search was performed via the Illinois Historic Preservation Agency to obtain the most 45 updated information about historic and cultural resources in the region. 46 The Area of Potential Effect (APE) is the area at the LSCS power plant site, the transmission 47 lines up to the first substation, and immediate environs that may be affected by the license 3-79

Affected Environment 1 renewal decision and land-disturbing activities associated with continued reactor operations. 2 For this analysis, the first substation (345 kV LSCS switchyard) is located on the LSCS site 3 (Exelon 2014a). The APE may extend beyond the immediate environs in instances where 4 land-disturbing maintenance and operations activities during the license renewal term or 5 refurbishment activities could potentially have an effect. In the case of LSCS, the APE includes 6 the corridor between the cooling pond and the Illinois River containing the makeup and 7 blowdown water pipelines within the site boundary. These pipelines traverse a distance of 8 approximately 5.6 km (3.5 mi) from the cooling pond to the Illinois River. See Figure 3-3. 9 3.9.1 Cultural Background 10 Human occupation near the LSCS site is generally characterized according to the following 11 chronological sequence (Pauketat 1993): 12

  • Paleo-Indian Period (12,000 - 10,000 before present (BP)),

13

  • Archaic Period (10,000 - 3,000 BP),

14

  • Woodland Period (3,000 - 1,100 BP),

15

  • Mississippian Period (1,100 - 400 BP (ca. A.D. 900 - 1600)), and 16
  • Protohistoric/Historic Period (400 - present (ca. A.D. 1600 - present)).

17 Paleo-Indian Period (12,000 - 10,000 B.P.). The earliest evidence of people living in Illinois 18 dates to the Paleo-Indian Period. Paleo-Indian sites are generally found upland or on river 19 terraces and are characterized by specific types of projectile points (i.e., fluted Clovis and 20 Folsom points) and stone tools such as gravers, scrapers or large blades. These artifacts often 21 occur in association with mastodon remains, suggesting a reliance on megafauna 22 (e.g., mammoth, ground sloth, and saber-tooth tiger) for subsistence along with plants, small 23 game, birds, and amphibians. Social organization consisted of small, highly nomadic bands of 24 hunter-gathers, leaving Paleo-Indian sites with little detailed archaeological information 25 (Neusius and Gross 2007; Pauketat 1993). 26 Archaic Period (10,000 - 3,000 B.P.). The Archaic Period was a time of major climatic shifts as 27 colder environments transitioned to warmer environments similar to modern conditions. In 28 response to this shift, new technologies and subsistence strategies were developed during this 29 time. The Archaic Period is often divided into early, middle, and late subperiods. The Early 30 Archaic Period is characterized by a shift from nomadic to sedentary settlement patterns, with 31 central base camps located on river terraces and smaller hunting camps located in upland 32 areas. This subperiod also shows an increased reliance on wild plant foods, small game, and 33 aquatic resources. The Middle Archaic Period is characterized by an increased number of 34 settlement sites on high stream terraces, which may reflect population increases. While 35 subsistence and settlement patterns remained fairly similar to the Early Archaic Period, artifact 36 assemblages suggest increased exploitation of aquatic resources as well as new artifacts such 37 as pecked and ground stone tools used for intensive processing of nuts; banner stones that 38 signaled the innovation of a new projectile technology called the atlatl or spear-thrower; and 39 grooved axes. The Late Archaic Period is characterized by an increase in the number and size 40 of settlement sites, which indicates an increase in population and a more sedentary lifestyle. 41 New features of Late Archaic artifact assemblages, such as crude ceramic vessels, represent a 42 shift towards increased reliance on horticulture as a subsistence strategy, although hunting and 43 gathering would have continued (Fagan 2005; Neusius and Gross 2007; Pauketat 1993). 44 Woodland Period (3,000 - 1,100 B.P.). The Woodland Period is also often divided into early, 45 middle, and late periods. However, the distinction between the early and middle period is not 3-80

Affected Environment 1 fixed. The Woodland Period is marked by an increase in more permanent settlements, changes 2 in burial practices, increased cultivation of plants such as sunflowers and cucurbits 3 (e.g., squashes, gourds, melons), and a rise in the manufacture and use of pottery 4 (Fagan 2005). During the Middle Woodland Period, the large and complex Hopewell Culture 5 emerged in the northeastern and Midwestern United States, including Illinois. This culture is 6 characterized by settlement in villages, increased reliance on intensive horticulture, burial 7 mounds, and long distance trade networks. These long distance networks allowed the trade of 8 exotic materials, such as marine shells from the Gulf Coast, obsidian from the Rocky Mountains, 9 copper from Lake Superior, and mica from the Appalachian Mountains far outside their 10 immediate locations. Evidence of the Illinois Hopewell culture is found primarily in the bluffs and 11 floodplains of the Illinois River Valley. The burial mounds of this period often included central 12 features, lined with logs, and filled with grave goods. Different burial treatments within the 13 mounds point to social stratification within society, but through sex and age rather than 14 hereditary lineage (Neusius and Gross 2007). The Late Woodland Period is characterized by 15 an increase in settlement sites, which suggests (a) a rise in population, or (b) a change in 16 settlement patterns from large, centralized village sites to smaller, dispersed habitation sites, or 17 both (Fagan 2005). 18 Mississippian Period (1,100 - 400 B.P. (ca. A.D. 900 - 1600)). The Mississippian Period is 19 characterized by major changes in settlement, subsistence patterns, and social structure. Large 20 highly centralized chiefdoms with permanent settlements sites supported by numerous satellite 21 villages emerged during this period. The platform mound, a new ceremonial earthen mound 22 appeared in association with these permanent settlements. Platform mounds, burial mounds, 23 and defensive structures, such as moats and palisades, were often constructed in clusters in 24 settlements of this period and were common in the larger river valleys of the Midwest. 25 Mississippian Period subsistence relied heavily on maize agriculture, as well as hunting and 26 gathering. Long distance trading increased and craft specialists produced highly specialized 27 lithic and ceramic artifacts, beadwork and shell pendants (Fagan 2005). Examples of 28 Mississippian Period occupation within LaSalle County is the Starved Rock State Park area. 29 Starved Rock is a 1,065 ha (2,632 ac) area along the south bank of the Illinois River between 30 the towns of LaSalle and Ottawa, Illinois. Mississippian period artifacts have been found in 31 some 62 sites in the region surrounding Starved Rock State Park with 16 sites recorded in the 32 park itself (DOI 1998). 33 Protohistoric/Historic Period (A.D. 1600 - Present). The end of the Mississippian Period is 34 characterized by severe social, political, and demographic changes that resulted from indirect 35 and direct contact with Europeans. In particular, it is believed that the introduction of European 36 infectious diseases such as smallpox, typhoid, and influenza severely decimated Native 37 American populations, which had no immunity to these diseases. The spread of these 38 diseases, which were fatal to large numbers of Native Americans, resulted in the widespread 39 abandonment of villages and a concurrent collapse of Native American socioeconomic 40 networks, such that by the time of widespread European contact and settlement, the 41 Mississippian chiefdoms were gone (Fagan 2005). During the historic period, Illinois was 42 primarily populated with a confederation of tribes known as the Illinois, or Illiniwek, and the 43 Miami tribe. During the 1700s and early 1800s, new tribes migrated to Illinois, including the 44 Iroquois, Fox (Mesquakie), Ioway, Kickapoo, Mascouten, Piankashaw, Potawatomi, Sauk, 45 Shawnee, Wea, and Winnebago. Competition for resources led to sporadic war among the 46 Illinois, surrounding tribes, and European immigrants to the area for approximately the next 47 120 years (ISM 2002). In approximately 1673, French explorers traveled along the Mississippi 48 River and up the Illinois River to present-day LaSalle County. Robert Cavalier, also known as 49 Louis de La Salle, made the first European settlement in LaSalle County. French influence in 50 the Illinois territory began to wane by the mid-1700s due to being ejected from the area by the 3-81

Affected Environment 1 British. Illinois became part of the Northwestern Territory at the close of the American 2 Revolution. LaSalle County was organized by the Illinois legislature during the 1830-1831 3 legislative session (Baldwin 1877). The State of Illinois joined the Union in 1818. The area 4 surrounding the LSCS site has principally been used for agriculture and coal mining from this 5 period onward (Exelon 2014a). 6 3.9.2 Historic and Cultural Resources 7 LSCS historic and cultural resources include prehistoric era and historic era archaeological 8 sites, historic districts, and buildings, as well as any site, structure, or object that may be 9 considered eligible for listing on the National Register of Historic Places (NRHP). Historic and 10 cultural resources also include traditional cultural properties that are important to a living 11 community of people for maintaining their culture. Historic property is the legal term for a 12 historic or cultural resource that is eligible for listing on the NRHP. 13 A review of databases maintained by the National Park Service (NPS) indicates that there are 14 31 properties listed in the NRHP within LaSalle County, including three that have been 15 designated as National Historic Landmarks (DOI 2015). These historic properties reflect the 16 historic cultural contexts for the LSCS property and include Starved Rock State Park, and 17 structures and districts dating from the mid-18th through mid-20th centuries. None of the 18 historic properties is located within the boundaries of the LSCS property (DOI 2015). The 19 closest NRHP site is the Illinois and Michigan Canal (NR200462), approximately 5 mi (8 km) to 20 the north of the plant. 21 A number of surveys of the LSCS site were conducted between 1972 and 1994. In 1972, a 22 Phase I archaeological survey was done by the Illinois Archaeological Survey of the LSCS 23 siteoriginally known as the Collins Generating Station. Five sites were discovered on LSCS 24 property. However, these sites were not recorded or evaluated because, in 1972, isolated finds 25 were not recognized as sites and therefore not evaluated. Three of the sites were assigned 26 Illinois Archaeological Survey accession numbersLS00207, LS00208, and LS00209. The 27 1972 survey concluded that construction of the LSCS would not significantly affect 28 archaeological resources (Exelon 2014a). These findings were accepted by the NRC in its Final 29 Environmental Statement for LSCS issued in 1978 (NRC 1978). In 1993, the Illinois 30 Department of Military Affairs did a survey to support the siting of a military training area 31 immediately northwest of LSCS. This survey found 48 archaeological sites, one of which is 32 located on the LSCS siteLS00514. This site was also determined not to be NRHP eligible 33 (Exelon 2014a). 34 The NRC staff searched the Illinois State Archaeological Site Files, a database maintained by 35 the Illinois State Historic Preservation Officer, and identified the LSCS sites listed in the 36 1972 and 1993 surveys as well as one additional siteLS00527which was determined to be 37 NRHP ineligible. No other cultural resources within the current confines of the LSCS site were 38 identified (NRC 2015c). 39 3.10 Socioeconomics 40 This section describes current socioeconomic factors that have the potential to be directly or 41 indirectly affected by changes in operations at LSCS. LSCS, and the communities that support 42 it, can be described as a dynamic socioeconomic system. The communities supply the people, 43 goods, and services required to operate the nuclear power plant. Power plant operations, in 44 turn, supply wages and benefits for people and dollar expenditures for goods and services. The 45 measure of a communitys ability to support LSCS operations depends on its ability to respond 46 to changing environmental, social, economic, and demographic conditions. 3-82

Affected Environment 1 3.10.1 Power Plant Employment and Expenditures 2 The socioeconomics region of influence (ROI) is defined by the areas where LSCS employees 3 and their families reside, spend their income, and use their benefits, thus affecting the economic 4 conditions of the region. Exelon employs a permanent workforce of approximately 5 890 employees and 30 long-term contract employees (Exelon 2014a). Approximately 6 83 percent of LSCS employees reside in a three-county area in northeastern Illinois in Grundy, 7 LaSalle, and Will Counties. Most of the remaining 17 percent of the workforce are spread 8 among 23 other counties in Illinois, with numbers ranging from 1 to 40 employees per county 9 (Exelon 2014a). Given the residential locations of LSCS employees, the most significant effects 10 of plant operations are likely to occur in Grundy, LaSalle, and Will Counties. 11 Table 3-15 summarizes the LSCS workforce geographic distribution. The focus of the 12 socioeconomic impact analysis in this SEIS is, therefore, on the impacts of continued LSCS 13 operations on these three counties, also termed the ROI. 14 Table 3-15. LSCS Employees Residence by County County Number of Employees Percentage of Total Illinois Bureau 12 1 Cook 10 1 Grundy 161 18 Kendall 38 4 LaSalle 490 55 Livingston 40 5 Will 86 10 Other counties 52 6 Total 889 100 Source: Exelon 2014 15 Exelon purchases goods and services to facilitate LSCS operations. While specialized 16 equipment and services are procured from a wider region, some proportion of the goods and 17 services used in plant operations are acquired from within the ROI. These transactions fuel a 18 portion of the local economy, as jobs are provided and additional local purchases are made by 19 plant suppliers. 20 The LSCS units are on staggered 24-month refueling cycles lasting approximately 25 days 21 each. During refueling outages, site employment typically increases by an additional 22 800 temporary workers (Exelon 2014a). Approximately 75 to 80 percent of the outage workers 23 are permanent residents of the ROI. The remaining 20 to 25 percent stay in Morris, Ottawa, or 24 Joliet, Illinois (Exelon 2014a). 25 3.10.2 Regional Economic Characteristics 26 This section presents information on employment and income in the LSCS socioeconomic ROI. 27 Grundy and LaSalle counties are predominantly rural with agricultural and forested land 28 comprising the majority (90 percent) of the land use in the county. Conversely, Will County is 29 more urban with developed land comprising about 34 percent of total land area in the county 30 (USDA 2015a). 3-83

Affected Environment 1 3.10.2.1 Employment and Income 2 From 2010 to 2014, the labor force in the LSCS ROI decreased approximately 0.8 percent to 3 approximately 440,000. However, the number of employed persons increased by about 4 3.4 percent, to approximately 406,000. Consequently, the number of unemployed people in the 5 ROI decreased by 33.6 percent, by approximately 17,000 persons to approximately 33,000, or 6 about 7.6 percent of the current workforcedown from 11.3 percent in 2010 (BLS 2015). 7 According to the U.S. Census Bureaus (USCBs) 2014 American Community Survey 1-Year 8 Estimates for LaSalle and Will Counties and 2009-2013 American Community Survey 5-Year 9 Estimates for Grundy County, the educational, health, and social services industry represented 10 the largest employment sector in the socioeconomic ROI (22.8 percent) followed by 11 manufacturing and retail (both at 12 percent) (USCB 2015a). A list of employment by industry in 12 each county of the ROI is provided in Table 3-16. 13 Table 3-16. Employment by Industry in the LSCS ROI 14 (2014, 1-year estimates and 2009-2013, 5-year estimates) Industry Grundy(a) LaSalle(b) Will(b) Total Percent Total employed civilian workers 22,931 47,159 342,888 412,978 - Agriculture, forestry, fishing, hunting, and mining 334 1,645 1,488 3,467 0.8 Construction 1,920 2,556 21,997 26,473 6.4 Manufacturing 2,872 7,495 39,037 49,404 12.0 Wholesale Trade 760 1,015 10,581 12,356 3.0 Retail Trade 2,677 7,030 40,265 49,972 12.1 Transportation, warehousing, and utilities 2,215 3,157 25,581 30,953 7.5 Information 268 397 7,992 8,657 2.1 Finance, insurance, 1,037 2,348 22,388 25,773 6.2 real estate, rental, and leasing Professional, scientific, management, 1,559 3,081 34,365 39,005 9.4 administrative, and waste management services Educational, health, and social services 4,893 10,252 78,846 93,991 22.8 Arts, entertainment, recreation, accommodation, 2,566 3,737 31,560 37,863 9.2 and food services Other services (except public administration) 936 3,026 16,930 20,892 5.1 Public administration 894 1,420 11,858 14,172 3.4 (a) 2009-2013 American Community Survey 5-Year Estimates. (b) 2014 American Community Survey 1-Year Estimates. Source: USCB 2015a 15 Major employers in LaSalle County, the county in which LSCS is located, are listed in 16 Table 3-17. Exelon is shown as the largest employer in the county. 3-84

Affected Environment 1 Table 3-17. Major Employers in LaSalle County in 2009 Employer Number of Employees Exelon Generation 890 OSF, Saint Elizabeth Medical Center 730 PetSmart 500 Clover Technology Group 450 HR Imaging 425 Office Max 375 SABIC Innovative Plastics 275 Kohls 270 Seattle Sutton Healthy Eating 170 Mitsuboshi Belting 168 Pilkington Industries 157 Tysons 130 U.S. Silica 130 Source: Ottawa Area Chamber of Commerce & Industry, 2009 2 Estimated income information for the LSCS ROI is presented in Table 3-18. According to the 3 USCBs 2014 American Community Survey 1-year estimates, 10.5 percent of families and 4 14.4 percent of individuals in Illinois were living below the Federal poverty threshold and the 5 median household and per capita income for Illinois was $57,444 and $30,417, respectively 6 (USCB 2015b). In the socioeconomic ROI, people living in LaSalle County had median 7 household and per capita incomes below the State average. The median household and per 8 capita income average in LaSalle County was $50,432 and $25,129, respectively, with 9 9.6 percent of families and 13.3 percent of individuals living below the poverty level. 10 Conversely, Will County had a higher median household and per capita income average 11 ($74,828 and $32,148, respectively) and a lower percentage of families (6.3 percent) and 12 individuals (7.9 percent) living below the official poverty level. According to the USCBs 13 2011-2013 American Community Survey 3-Year Estimates, Grundy County also had higher 14 median household and per capita income averages ($63,978 and $28,465, respectively) and 15 lower percentages of families (7.2 percent) and individuals (9.4 percent) living below the poverty 16 level than the State of Illinois and LaSalle County (USCB 2015b). 17 Table 3-18. Estimated Income Information for the LSCS ROI 18 (2014 estimates, unless otherwise indicated) Grundy(b) LaSalle Will Illinois Median household income (dollars)(a) 63,978 50,432 74,828 57,444 Per capita income (dollars)(a) 28,465 25,129 32,148 30,417 Individuals living below the poverty level 9.4 13.3 7.9 14.4 (percent) Families living below the poverty level (percent) 7.2 9.6 6.3 10.5 (a) In 2012 inflation adjusted dollars. (b) 2011-2013 American Community Survey 3-Year Estimates. Source: USCB 2015b. 3-85

Affected Environment 1 3.10.2.2 Unemployment 2 According to the USCBs 2014 American Community Survey estimates, the unemployment 3 rates in LaSalle County and the State of Illinois were 8.1 and 10.5 percent, respectively. 4 Comparatively, the Will County unemployment rate during this same time period was 5 6.0 percent. According to the USCBs 2013 American Community Survey 3-year estimates, the 6 unemployment rates in Grundy County was 9.6 percent (USCB 2015c). 7 3.10.3 Demographic Characteristics 8 According to the 2010 Census, an estimated 103,000 people lived within 20 mi (32 km) of 9 LSCS, which equates to a population density of approximately 81 persons per square mile 10 (persons/mi2) (CAPS 2014). This translates to a Category 3, least sparse population density 11 using the GEIS measure of sparseness (60 to 120 persons/mi2 within 20 mi). An estimated 12 1,926,000 people live within 50 mi (80 km) of LSCS with a population density of approximately 13 245 persons/mi2 (CAPS 2014). This translates to a Category 4 in close proximity population 14 density, using the GEIS measure of proximity (greater than or equal to 190 persons/mi2 within 15 50 mi). Therefore, LSCS is located in a high population area based on the GEIS sparseness 16 and proximity matrix. 17 Table 3-19 shows population projections and percent growth from 1980 to 2060 in the 18 three-county LSCS ROI. The ROI population continues to increase over the past two decades 19 (2000 and 2010). Based on forecasts, the population is expected to continue these trends at 20 moderate to high rates. Population projections for years 2020 and 2040 shown in the table 21 were developed for the Illinois Department of Transportation. 22 Table 3-19. Population and Percent Growth in LSCS ROI Counties 1980-2010, 2014 23 (estimated), and Projected for 2020-2060 Grundy County LaSalle County Will County Percent Percent Percent Year Population change Population change Population change 1980 30,582 - 112,033 - 324,460 - 1990 32,337 5.7 106,913 -4.6 357,313 10.1 2000 37,535 16.1 111,509 4.3 502,266 40.6 2010 50,063 33.4 113,924 2.2 677,560 34.9 2014 50,425 0.7 111,241 -2.4 685,419 1.2 2020 61,265 22.4 118,178 3.7 868,986 28.3 2030 72,463 18.3 121,928 3.2 1,146,722 32.0 2040 83,665 15.5 125,686 3.1 1,366,456 19.2 2050 94,864 13.4 129,439 3.0 1,624,858 18.9 2060 106,064 11.8 133,193 2.9 1,873,593 15.3 Sources: Decennial population data for 1980-2010, and estimated 2014 (USCB 2015d); projections for 2020-2040 Illinois Department of Transportation (IDOT 2012); 2050-2060 calculated. 24 The 2010 Census demographic profile of the three-county ROI population is presented in Table 25 3-20. According to the 2010 Census, minorities (race and ethnicity combined) comprised 26 28.6 percent of the total three-county population. The largest minority populations in the ROI 3-86

Affected Environment 1 were Hispanic or Latino of any race (14.1 percent) and Black or African American (9.2 percent) 2 (USCB 2015e). 3 Table 3-20. Demographic Profile of the Population in the LSCS ROI in 2010 Grundy LaSalle Will ROI Total Population 50,063 113,924 677,560 841,547 Race (percent of total population, Not-Hispanic or Latino) White 88.9 88.3 67.2 71.4 Black or African American 1.2 1.8 11.0 9.2 American Indian & Alaska Native 0.1 0.2 0.1 0.1 Asian 0.6 0.7 4.5 3.7 Native Hawaiian & Other Pacific Islander 0.0 0.0 0.0 0.0 Some other race 0.0 0.0 0.1 0.1 Two or more races 0.9 1.0 1.4 1.3 Ethnicity Hispanic or Latino 4,096 9,135 105,817 119,048 Percent of total population 8.2 8.0 15.6 14.1 Minority population (including Hispanic or Latino ethnicity) Total minority population 5,537 13,379 221,983 240,899 Percent minority 11.1 11.7 32.8 28.6 Source: USCB 2015e 4 According to the USCBs 2014 and 2013 American Community Survey estimates, since 2010 5 minority populations in the ROI were estimated to have increased by approximately 6 17,700 persons and now comprise 30.5 percent of the ROI population (see Table 3-21). The 7 largest increase occurred in the Hispanic or Latino population (nearly 8,900 persons since 2010, 8 an increase of 7.5 percent). The next largest increase in minority population was Asian, an 9 increase of approximately 5,800 persons or 18.5 percent from 2010 (USCB 2015f). 10 Table 3-21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County) Grundy(a) LaSalle Will ROI Total Population 50,425 111,241 685,419 847,085 Race (percent of total population, Not-Hispanic or Latino) White 87.4 86.9 65.3 69.5 Black or African American 1.4 2.1 11.3 9.5 American Indian & Alaska Native 0.1 0.2 0.1 0.1 Asian 0.8 0.9 5.3 4.4 Native Hawaiian & Other Pacific Islander 0.0 0.0 0.0 0.0 Some other race 0.0 0.0 0.0 0.0 Two or more races 1.0 1.0 1.4 1.4 3-87

Affected Environment Grundy(a) LaSalle Will ROI Ethnicity Hispanic or Latino 4,667 9,854 113,470 127,991 Percent of total population 9.3 8.9 16.6 15.1 Minority population (including Hispanic or Latino ethnicity) Total minority population 6,351 14,558 237,731 258,640 Percent minority 12.6 13.1 34.7 30.5 (a) 2011-2013 American Community Survey 3-Year Estimates. Source: USCB 2015f 1 3.10.3.1 Transient Population 2 Within 50 mi (80 km) of LSCS, colleges and recreational opportunities attract daily and seasonal 3 visitors who create a demand for temporary housing and services. In 2015, approximately 4 57,000 students attended colleges and universities within 50 mi (80 km) of LSCS 5 (NCES 2015a). 6 Based on 2009-2013 American Community Survey 5-Year Estimates, approximately 7 23,000 seasonal housing units are located within 50 mi (80 km) of LSCS. Of those, 1,785 were 8 located in the LSCS ROI. Table 3-22 presents information about seasonal housing for the 9 counties located all or partly within 50 mi (80 km) of LSCS. 10 Table 3-22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of LSCS Vacant Housing Units: for Seasonal, Recreational, or County(a) Total Housing Units Occasional Use Percent Illinois Bureau 15,679 216 1.4 Cook 2,176,266 16,059 0.7 DeKalb 40,983 246 0.6 DuPage 356,217 1,125 0.3 Ford 6,259 7 0.1 Grundy 20,027 187 0.9 Iroquois 13,452 200 1.5 Kane 182,145 623 0.3 Kankakee 45,135 436 1.0 Kendall 40,415 35 0.1 LaSalle 49,905 744 1.5 Lee 15,035 313 2.1 Livingston 15,851 55 0.3 McLean 69,979 390 0.6 Marshall 5,905 405 6.9 3-88

Affected Environment Vacant Housing Units: for Seasonal, Recreational, or County(a) Total Housing Units Occasional Use Percent Ogle 22,558 377 1.7 Peoria 83,162 114 0.1 Putnam 3,084 375 12.2 Tazewell 57,608 164 0.3 Will 237,806 854 0.4 Woodford 15,207 109 0.7 Total 3,472,678 23,034 1.6 (a) Counties within 50 mi (80 km) of LSCS with at least one block group located within the 50-mi (80-km) radius. Note: ROI counties are in bold italics. Source: USCB 2015g 1 3.10.3.2 Migrant Farm Workers 2 Migrant farm workers are individuals whose employment requires travel to harvest agricultural 3 crops. These workers may or may not have a permanent residence. Some migrant workers 4 follow the harvesting of crops, particularly fruit, throughout rural areas of the United States. 5 Others may be permanent residents living near LSCS and travel from farm to farm harvesting 6 crops. 7 Migrant workers may be members of minority or low-income populations. Because they travel 8 and can spend a significant amount of time in an area without being actual residents, migrant 9 workers may be unavailable for counting by census takers. If uncounted, these minority and 10 low-income workers would be underrepresented in the decennial Census population counts. 11 In the 2002 Census of Agriculture, farm operators were asked for the first time whether or not 12 they hired migrant workersdefined as a farm worker whose employment required travelto 13 do work that prevented the migrant workers from returning to their permanent place of residence 14 the same day. The Census is conducted every 5 years and results in a comprehensive 15 compilation of agricultural production data for every county in the nation. 16 Information about migrant and temporary labor (working less than 150 days) was collected in 17 the 2012 Census of Agriculture. Table 3-23 supplies information about migrant and temporary 18 farm labor within 50 mi (80 km) of LSCS. According to the 2012 Census, approximately 19 12,000 farm workers were hired to work for less than 150 days and were employed on 20 5,563 farms within 50 mi (80 km) of LSCS. The county with the highest number of temporary 21 farm workers (1,101) on 253 farms was DeKalb County, Illinois (NASS 2015). 3-89

Affected Environment 1 Table 3-23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 2 within 50 mi (80 km) of LSCS (2012) Number of Number of Farms Number of Farm Farms Number of Farms Hiring Workers for Workers Working Reporting with Hired Farm Less Than 150 for Less Than Migrant Farm County(a) Labor(b) Days(b) 150 Days(b) Labor(b) Illinois Bureau 357 308 877 7 Cook 55 32 195 0 DeKalb 338 253 1,101 7 DuPage 38 29 258 3 Ford 175 136 329 4 Grundy 144 119 258 0 Iroquois 482 385 909 2 Kane 220 133 472 3 Kankakee 258 225 837 17 Kendall 127 99 263 2 LaSalle 526 411 933 8 Lee 271 224 506 1 Livingston 459 369 840 3 McLean 565 422 951 2 Marshall 137 110 303 1 Ogle 318 240 534 0 Peoria 199 162 546 4 Putnam 53 44 (D) 0 Tazewell 265 215 735 3 Will 278 212 694 3 Woodford 298 242 685 1 Total 5,563 4,370 12,226 71 (a) Counties within 50 mi of LSCS with at least one block group located within the 50 mi radius. (b) Table 7. Hired farm Labor - Workers and Payroll: 2012. ROI counties are in bold italics. (D) Indicates that data was withheld to avoid disclosing data for individual farms. Source: 2012 Census of Agriculture - County Data (NASS 2015) 3 A total of 71 farms, in the 50-mi (80 km) radius of the LSCS, reported hiring migrant workers in 4 the 2012 Census. Kankakee County, Illinois, reported the most farms with migrant farm labor 5 (17 farms) (NASS 2015). 6 3.10.4 Housing and Community Services 7 This section presents information regarding housing and local public services, including 8 education and water supply. 3-90

Affected Environment 1 3.10.4.1 Housing 2 Table 3-24 lists the total number of occupied and vacant housing units, vacancy rates, and 3 median value in the ROI. Based on USCBs 2014 American Community Survey estimates, 4 there were nearly 310,000 housing units in the ROI, of which nearly 285,000 were occupied. 5 The median values of owner-occupied housing units in the ROI range from $121,700 in LaSalle 6 County to $209,400 in Will County. The vacancy rate also varied considerably between the 7 three counties, from 6.6 percent in Will County to 13.9 percent in LaSalle County 8 (USCB 2015h). 9 Table 3-24. Housing in the LSCS ROI (2014 estimate) Grundy(a) LaSalle Will ROI Total housing units 20,078 49,867 239,857 309,802 Occupied housing units 18,119 42,956 224,012 285,087 Total vacant housing units 1,959 6,911 15,845 24,715 Percent total vacant 9.8 13.9 6.6 8.0 Owner occupied units 13,706 32,020 180,129 225,855 Median value (dollars) 178,200 121,700 209,400 195,073 Owner vacancy rate (percent) 3.2 1.4 0.9 1.1 Renter occupied units 4,413 10,936 43,883 59,232 Median rent (dollars/month) 953 685 1,054 978 Rental vacancy rate (percent) 5.4 11.9 4.4 5.9 (a) 2011-2013 American Community Survey 3-Year Estimates. Source: USCB 2015h 10 3.10.4.2 Education 11 Grundy County has 12 public school districts with 24 public schools and approximately 12 13,000 students during the 2013-2014 school year. LaSalle County, the county in which LSCS 13 is located, has 26 public school districts with 47 public schools and approximately 14 17,000 students during the 2013-2014 school year. Will County has 30 public school districts 15 with 171 public schools and approximately 117,000 students during the 2013-2014 school year 16 (NCES 2015b). 17 3.10.4.3 Public Water Supply 18 The City of LaSalle pumps and treats groundwater. The city's water treatment and distribution 19 system serves the City of LaSalle. The City of LaSalle treatment plant has a treatment capacity 20 of approximately 500,000 gallons per day. Water and wastewater treatment services are 21 provided by a number of townships and municipalities in LaSalle County which service 22 residential, commercial, and industrial customers. Other residents within the county are served 23 by private, onsite well and wastewater disposal systems. 24 Table 3-25 lists the largest public water suppliers in Grundy, LaSalle, and Will Counties and 25 provides water source and population served for those suppliers. Most of the major public water 26 suppliers in Grundy, LaSalle, and Will Counties obtain their supplies from groundwater. 27 Currently, there is excess capacity in every major public water system in the three counties. 3-91

Affected Environment 1 Table 3-25. Local Public Water Supply Systems Public Water System Source Population Served(a) Grundy County Coal City Groundwater 5,587 Diamond Groundwater 2,200 Minooka Groundwater 10,924 Morris Groundwater 12,000 LaSalle County Illinois American-Streator Surface water 19,000 LaSalle Groundwater 9,700 Marseilles Groundwater 4,800 Mandota Groundwater 7,272 Oglesby Groundwater 4,000 Ottawa Groundwater 18,307 Peru Groundwater 11,000 Seneca Groundwater 2,371 Utility Inc. - Lake Holiday Groundwater 6,479 Exelon/LaSalle Groundwater 1,000 Will County Aqua Illinois - University Park Groundwater 6,913 Aqua Illinois - Willowbrook Groundwater 3,422 Breecher Groundwater 4,359 Braidwood Groundwater 6,191 Channahon Groundwater 9,160 Crest Hill Groundwater 20,837 Crete Groundwater 8,259 Elwood Groundwater 2,300 Frankfort Groundwater 24,648 Illinois American - Homer Township Surface water purchased 22,036 Illinois American - West Suburban Surface water purchased 66,429 Joliet Groundwater 147,589 Lockport Groundwater 24,839 Lockport Township Water System Groundwater 2,610 Manhattan Groundwater 6,000 Mokena Surface water purchased 19,500 Monee Groundwater 5,148 New Lenox Surface water purchased 24,394 Peotone Groundwater 4,142 Plainfield Surface water purchased 36,600 Romeoville Groundwater 52,000 3-92

Affected Environment Public Water System Source Population Served(a) Shorewood Groundwater 15,615 Southeast Joliet Groundwater 2,000 Stateville Correctional Center Groundwater purchased 3,500 Wilmington Surface water 5,724 (a) Safe Drinking Water Search for the State of Illinois (EPA 2015e). Source: EPA 2015e 1 3.10.5 Tax Revenues 2 Exelon pays taxes on LSCS property to LaSalle County, public schools, libraries, townships, 3 districts, and other taxing authorities. Property taxes paid by Exelon for LSCS for the years of 4 2007 through 2013 are listed in Table 3-26. As shown in the table, total property tax payments 5 for the reported years fluctuated from year to year. 6 Property taxes paid on LSCS are based partially on settlement agreements for the valuation of 7 the power block, with the remaining land taxed on the assessment of fair market value, as 8 established by Illinois State tax law. Power block tax payments have been approximately 9 98 percent of the total tax payment. Settlement agreements in 1999 and 2006 covered the 10 years 2000 through 2004 and 2005 through 2008, respectively. Negotiations for the next 11 settlement agreement began in 2009 and was not completed until mid-2013. Consequently, 12 without the settlement agreement, the LaSalle County tax assessor increased the assessed 13 value of the LSCS power block, which resulted in sharply increased tax payments by Exelon. 14 As shown in Table 3-26, tax payments more than doubled in 2009 in keeping with the increased 15 assessment of the power block made by the County Assessor, as affirmed or amended on 16 appeal by the LaSalle County Board of Review. Based on independent appraisals, Exelon 17 appealed the assessments for tax years 2009 through 2012 to the Illinois Property Tax Appeal 18 Board because the company did not believe the assessments accurately reflected the value of 19 the LSCS power block. In July 2013, Exelon and all taxing bodies agreed to a new long-term 20 settlement agreement that sets the Equalized Assessed Value of the LSCS power block for the 21 next 7 years, starting with the 2013 tax year. The settlement agreement was fully executed and 22 approved by the Court for the 13th Judicial District in LaSalle County, Illinois, in February 2014. 23 At the request of all parties, the Property Tax Appeal Board dismissed the appeals with 24 prejudice in May 2014 (Exelon 2014a). 25 Exelon intends to negotiate additional tax settlement agreements during the license renewal 26 term, as it helps the company and taxing authorities plan for future income revenue and 27 expenditures (Exelon 2014a). 28 Table 3-26. LSCS Power Block Tax Payments and Valuations 2007-2014 (in dollars) Equalized Assessed Year Value Inferred Fair Market Value Taxes Paid by Exelon 2007 235,000,000(a) 1,566,700,000 12,258,540 2008 235,000,000(a) 1,566,700,000 12,181,812 2009 525,000,000(b) 3,571,500,000 24,595,282 2010 525,000,000(b) 3,571,500,000 24,652,781 3-93

Affected Environment Equalized Assessed Year Value Inferred Fair Market Value Taxes Paid by Exelon 2011 504,000,000(b) 3,360,000,000 23,888,466 2012 488,250,000(b) 3,255,000,000 23,383,171 2013 485,000,000(a) 3,233,333,333 23,749,334 2014 455,000,000(a) 3,033,333,333 22,490,721 (a) Under settlement agreement. (b) Set by Board of Review. NA=Not available. Source: Exelon 2014a, 2015c 1 Taxes paid in 2013 to local taxing bodies constitute between 94 percent and less than 1 percent 2 of the total levy for any individual taxing body, as shown in Table 3-27. Tax payments under 3 any new settlement agreement would likely continue at similar percentages (Exelon 2014a). 4 Table 3-27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total Levy Exelon Payment Total levy Percent of total Taxing Body (dollars) (dollars) levy (%) Brookfield Township 76,547 81,290 94 Brookfield Township Road 409,211 432,957 94 South Prairie Park District 32,009 35,118 91 Allen-Brookfield District 34,719 39,041 89 Seneca Grade School # 170 6,424,862 7,330,695 87 Seneca High School # 160 8,816,393 10,602,732 83 Seneca Library 608,884 731,132 83 Seneca Fire-Ambulance 491,752 633,545 78 Marseilles Fire District 536,095 777,223 69 Illinois Valley Community College # 513 1,790,079 8,027,119 22 LaSalle County 4,772,514 23,342,931 20 Allen Fire District 5,354 151,128 3 Allen Township 2,913 97,044 3 Allen Township Road 3,950 128,063 3 Allen Township School # 65 20,340 1,125,258 2 City of Marseilles 697 963,696 <1 Grand Ridge School # 95 364 2,289,613 <1 Marseilles Library 53 70,300 <1 Ottawa High School # 140 288 12,691,310 <1 Reddick Library 32 2,289,613 <1 Streator High School # 40 3,645 5,512,552 <1 Village of Ransom 136 36,982 <1 Source: Exelon 2014a 3-94

Affected Environment 1 In addition, Exelon makes annual payments to the Illinois Emergency Preparedness Agency for 2 LSCS. These annual payments are listed in Table 3-28. Smaller amounts are paid on an 3 intermittent and voluntary basis to local emergency management agencies and government 4 agencies that participate in emergency management activities. 5 Table 3-28. Annual Payments to Illinois Emergency Management Agency 2009-2014 Year Amount Paid (dollars) 2009 3,356,117 2010 3,575,454 2011 3,790,603 2012 4,084,540 2013 4,084,540 2014 4,014,846 Source: Exelon 2014a 6 Exelon anticipates no change in State or local tax laws, rates or assessments that would result 7 in notable future increases or decreases in property taxes or other payments to State or local 8 governments with respect to LSCS during the license renewal term. However, new property tax 9 settlement agreements could result in higher property tax assessments and higher property tax 10 payments. 11 3.10.6 Local Transportation 12 The region surrounding LSCS has a highly developed roadway network. Interstate 80 (I-80) 13 runs east and west approximately 8 mi (13 km) north of LSCS. Interstate 55 runs northeast to 14 southwest approximately 15 mi (24 km) east of LSCS. US-51/I-39 runs north and south 15 approximately 21 mi (35 km) west of LSCS. Interstate 80 and I-55 provide access to the LSCS 16 site from Chicago to the northeast. 17 County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, runs parallel to 18 LSCSs southern boundary and provides access to the LSCS site. State Highway 170 is 0.5 mi 19 (0.8 km) east of the site and County Road 30, also known as East 25th Road, is slightly west of 20 the site. The Chicago, Rock Island & Pacific Railroad is the closest railroad line to LSCS. It 21 runs parallel to and slightly north of the Illinois River. A 6 mi (10 km) rail spur connects LSCS to 22 the Atchison, Topeka, and Santa Fe Railroad south of the site (Exelon 2014a). 23 Table 3-29 lists commuting routes to the LSCS site and average annual daily traffic volume 24 values. The average annual daily traffic values represent traffic volumes for a 24-hour period 25 factored by both the day of the week and the month of the year. 26 Table 3-29. Major Commuting Routes in the Vicinity of LSCS: 2013-2014 Average 27 Annual Daily Traffic Count Average Annual Daily Roadway and Location Traffic (AADT) County Road 6 (North 21st Road) near LSCS 2,200 County Road 6 (North 21st Road) and Illinois 170 (East 29th Road) 1,800 Illinois 170 (East 29th Road) between River Street and US 6 in Seneca 7,500 3-95

Affected Environment Average Annual Daily Roadway and Location Traffic (AADT) I-80 at US 6 30,200 County Road 30 (East 25th Road) and County Road 6 (North 21st Road) 1,350 County Road 30 (East 25th Road) and County Road 15 (Main Street) 3,800 County Road 15 (Main Street) in Marseilles 6,600 County Road 15 (Rutland Street) 5,200 I-80 at County Road 15 (Rutland Street) 29,100 I-80 at Illinois 23 (Columbus Street) 30,100 Illinois 23 (Columbus Street) south 18,500 Illinois 23/71 (Columbus Street) in Ottawa 12,300 Illinois 23/71 (Columbus Street) over Illinois River 27,500 Illinois 23 (Bloomington Avenue) and County Road 6 (East Main Street) 6,500 County Road 6 (East Main Street) 2,650 Source: Illinois DOT 2015 1 3.11 Human Health 2 3.11.1 Radiological Exposure and Risk 3 As required by NRC regulation 10 CFR 20.1101, Exelon has a radiation protection program 4 designed to protect onsite personnel, including employees, contractor employees, visitors, and 5 offsite members of the public from radiation and radioactive material generated at LSCS. 6 The radiation protection program is extensive and includes, but is not limited to the following: 7

  • Organization and Administration (i.e., a Radiation Protection Manager who is 8 responsible for the program and having trained and qualified workers),

9

  • Implementing procedures, 10
  • ALARA Program to minimize dose to workers and members of the public, 11
  • Dosimetry Program (i.e., measure radiation dose of plant workers),

12

  • Radiological Controls (i.e., protective clothing, shielding, filters, respiratory 13 equipment, and individual work permits with specific radiological requirements),

14

  • Radiation Area Entry and Exit Controls (i.e., locked or barricaded doors, interlocks, 15 local and remote alarms, personnel contamination monitoring stations),

16

  • Posting of Radiation Hazards (i.e., signs and notices alerting plant personnel of 17 potential hazards),

18

  • Record Keeping and Reporting (i.e., documentation of worker dose and radiation 19 survey data),

3-96

Affected Environment 1

  • Radiation Safety Training (i.e., classroom training and use of mockups to simulate 2 complex work assignments),

3

  • Radioactive Effluent Monitoring Management (i.e., control and monitor radioactive 4 liquid and gaseous effluents released into the environment),

5

  • Radioactive Environmental Monitoring (i.e., sampling and analysis of environmental 6 media, such as air, water, vegetation, food crops, direct radiation, and milk to 7 measure the levels of radioactive material in the environment that may impact human 8 health), and 9
  • Radiological Waste Management (i.e., control, monitor, process, and dispose of 10 radioactive solid waste).

11 Regarding the radiation exposure to LSCS personnel, the NRC staff reviewed the data 12 contained in NUREG-0713, Occupational Radiation Exposure at Commercial Nuclear Power 13 Reactors and Other Facilities 2012: Forty-Fifth Annual Report (NUREG-0713, Volume 34) 14 (NRC 2014b). This report, which was the most recent available at the time of this review, 15 summarizes the occupational exposure data through 2012 that are maintained in the NRCs 16 Radiation Exposure Information and Reporting System database. Nuclear power plants are 17 required by 10 CFR 20.2206 to report their occupational exposure data to the NRC annually. 18 NUREG-0713 calculates a 3-year average collective dose per reactor for all nuclear power 19 reactors licensed by the NRC. The 3-year average collective dose is one of the metrics that the 20 NRC uses in the Reactor Oversight Program to evaluate the applicants ALARA program. 21 Collective dose is the sum of the individual doses received by workers at a facility licensed to 22 use radioactive material over a 1-year time period. There are no NRC or EPA standards for 23 collective dose. Based on the data for operating BWRs like those at LSCS, the average annual 24 collective dose per reactor was 133 person-rem. In comparison, LSCS had a reported annual 25 collective dose per reactor of 158 person-rem. 26 In addition, as reported in NUREG-0713, for 2012, no worker at LSCS received an annual dose 27 greater than 2.0 rem (0.02 Sv), which is less than half of the NRC occupational dose limit of 28 5.0 rem (0.05 Sv) in 10 CFR 20.1201. 29 3.11.2 Chemical Hazards 30 The use, storage, and discharge of chemicals, biocides, and sanitary wastes, as well as minor 31 chemical spills are regulated by state and Federal environmental agencies. Chemical hazards 32 to LSCSs workers during the license renewal term are expected to be minimized by 33 implementing good industrial hygiene practices as required by Federal and State regulations. 34 Discharges of chemical and sanitary wastes are monitored and controlled as part of the LSCSs 35 NPDES permit IL0048151 to minimize impacts to the public and the environment 36 (Exelon 2014a). 37 3.11.3 Microbiological Hazards 38 Nuclear plants such as LSCS that discharge thermal effluents to cooling ponds, lakes, canals, 39 or rivers have the potential to promote the increased growth of thermophilic microorganisms, 40 which could result in adverse health effects for plant workers and the public. Microorganisms of 41 particular concern include several types of bacteria (Legionella spp., Salmonella spp., 42 Shigella spp., thermophilic fungi, and Pseudomonas aeruginosa) and the free-living amoeba 43 Naegleria fowleri. 3-97

Affected Environment 1 Nuclear plant workers can be exposed to Legionella spp. when performing maintenance 2 activities on plant cooling systems if workers inhale cooling tower vapors because vapors are 3 often within the optimum temperature range for Legionella growth. Plant personnel most likely 4 to come in contact with Legionella aerosols would be workers who clean biofilms off of 5 condenser tubes, cooling towers, and related system components or equipment. Exposure of 6 the public to Legionella from nuclear plant operations is generally not a concern because 7 Legionella exposure would be confined to a small area of the site within the protected area. 8 LSCS does not have cooling towers so exposure of workers to Legionella is unlikely. 9 The public can be exposed to the thermophilic microorganisms Salmonella, Shigella, 10 P. aeruginosa, and N. fowleri during swimming, boating, or other recreational uses of 11 freshwater. If a nuclear plants thermal effluent enhances the growth of thermophilic 12 microorganisms, recreational users could experience an elevated risk of exposure when using 13 waters near the plants discharge. 14 3.11.3.1 Thermophilic Microorganisms of Concern 15 Legionella is a genus of common warm water bacteria that occurs in lakes, ponds, and other 16 surface waters, as well as some groundwater sources and soils. The bacteria are pathogenic to 17 humans when aerosolized and inhaled into the lungs. Approximately 2 to 5 percent of those 18 exposed in this way to Legionella develop an acute bacterial infection of the lower respiratory 19 tract known as Legionnaires disease (Pearson 2003). Optimal growth occurs in stagnant 20 surface waters with biofilms or slimes that range in temperature from 35 to 45 °C (95 to 113 °F), 21 though the bacteria can persist in waters from 20 to 50 °C (68 to 122 °F) (Pearson 2003). 22 Elderly and immunocompromised individuals are most susceptible to Legionnaires disease 23 (Pearson 2003). According to data from the Centers for Disease Control and Prevention (CDC) 24 (CDC 2011a) from 2000 through 2009, New England and Mid-Atlantic states generally had the 25 highest number of reported legionellosis cases each year. 26 Approximately 2,000 serotypes of Salmonella spp. cause the bacterial infection salmonellosis in 27 humans. Of these, the serotypes Typhimurium and Enteritidis are the most common in the 28 United States (CDC 2010a). Salmonellosis is most common in summer months, and it is 29 transmitted through contact with food, water, or animals contaminated with human or animal 30 feces (CDC 2010a). The bacteria have an optimal growth temperature of 37 °C (98.6 °F) but 31 can grow at temperatures ranging from 6 to 46 °C (43 to 115 °F) (Albrecht 2013a). Studies 32 examining the persistence of Salmonella spp. outside of a host have found that Salmonella can 33 survive for several months in water and in aquatic sediments (Moore et al. 2003). 34 Shigella is a genus of bacteria species that causes shigellosis (i.e., bacterial dysentery), which 35 is spread through consuming fecal-contaminated food or water, by swimming in contaminated 36 water, or by contact with an infected person through contaminated feces and unhygienic 37 handling of food. Its optimum growth temperature is 37 °C (98.6 °F), though it can grow in water 38 temperatures ranging from 10 to 40 °C (50 to 104 °F) (Albrecht 2013b). Shigellosis is most 39 common in summer months and among toddlers age 2 to 4 who are not fully toilet trained and in 40 childcare settings (CDC 2013e). 41 Pseudomonas aeruginosa is a free-living bacterium found in soil, water, sewage, plant surfaces 42 and the skin of healthy individuals. It is most commonly linked to infections transmitted in 43 healthcare settings. However, as a waterborne pathogen, it can cause ear infections 44 (i.e., swimmers ear), eye infections, and skin rashes after exposure to contaminated hot tubs, 45 swimming pools, or other recreational waters (CDC 2013a). Its optimum growth temperature is 46 37 °C (98.6 °F), though it can grow at temperatures as high as 42 °C (107.6 °F) (Todar 2004). 47 P. aeruginosa almost exclusively infects immunocompromised individuals or already injured or 48 inflamed sites on the skin (Todar 2004). 3-98

Affected Environment 1 Naegleria fowleri is a free-living amoeba that occurs in warm lakes, rivers, or hot springs. It is 2 the causative agent of human primary amoebic meningoencephalitis (PAM). Infection occurs 3 when contaminated freshwater enters the nose, and the amoeba migrates to brain tissue; the 4 ensuing illness is usually fatal (CDC 2013b). N. fowleri grows best at higher temperatures up to 5 46 °C (115 °F) (CDC 2013b), though it has also been isolated from thermally altered waters 6 surrounding power plant discharges at temperatures ranging from 35 to 41 °C (95 to 105.8 °F) 7 (Stevens et al. 1977). 8 3.11.3.2 Prevalence of Waterborne Diseases Associated with Recreational Waters 9 From 2002 through 2011, the CDC (2003, 2004a, 2005, 2006a, 2007, 2008a, 2009, 2010b, 10 2011b, 2012) reported an average of 2,774 cases of Legionnaires disease per year, of which 11 between 28 and 151 per year were reported from Illinois. 12 The Illinois Department of Public Health (IDPH) indicates that approximately 1,500 to 13 2,000 cases of salmonellosis are reported in the State each year (IDPH 2009), and the 14 overwhelming majority of salmonellosis cases are foodborne (CDC 2010a). The CDC reports 15 biannually on waterborne disease outbreaks associated with recreational waters. A review of 16 the past 10 available data years (1999 through 2008) of these reports indicates that no 17 outbreaks or cases of waterborne Salmonella infection from recreational waters occurred in the 18 United States during this timeframe (CDC 2002, 2004b, 2006b, 2008b, 2011c). From 2006 to 19 2013, all CDC-reported salmonellosis outbreaks have been caused by contaminated produce, 20 meats, or prepared foods or through contact with contaminated animals (CDC 2013d). 21 Approximately 1,300 confirmed cases of shigellosis are reported in Illinois each year 22 (IDPH 2013). CDC reports (2002, 2004b, 2006b, 2008b, 2011c) indicate that less than a 23 dozen shigellosis outbreaks have been attributed to lakes, reservoirs, and other recreational 24 waters in the past 10 available data years (1999 through 2008). None of these cases was 25 in Illinois. 26 Infections attributed to Pseudomonas aeruginosa are most commonly contracted in pools, spas, 27 and hot tubs. No cases of infection linked to contaminated recreational waters in the 28 United States have been reported within the past 10 available data years (1999 through 2008) 29 (CDC 2002, 2004b, 2006b, 2008b, 2011c). 30 The N. fowleri-caused disease, PAM, is rare in the United States. Since 1962, between zero 31 and eight cases of PAM have been reported to the CDC annually, and no cases have been 32 reported in Illinois (CDC 2013c). 33 3.11.4 Electromagnetic Fields 34 Based on the GEIS, the Commission found that electric shock resulting from direct access to 35 energized conductors or from induced charges in metallic structures has not been found to be a 36 problem at most operating plants and generally is not expected to be a problem during the 37 license renewal term. However, a site-specific review is required to determine the significance 38 of the electric shock potential along the portions of the transmission lines that are within the 39 scope of this SEIS. 40 In the GEIS, the NRC found that without a review of the conformance of each nuclear plant 41 transmission line with National Electrical Safety Code (NESC) criteria, it was not possible to 42 determine the significance of the electric shock potential (IEEE 2002). Evaluation of individual 43 plant transmission lines is necessary because the issue of electric shock safety was not 44 addressed in the licensing process for some plants. For other plants, land use in the vicinity of 45 transmission lines may have changed, or power distribution companies may have chosen to 46 upgrade line voltage. To comply with 10 CFR 51.53(c)(3)(ii)(H), the applicant must provide an 3-99

Affected Environment 1 assessment of the impact of the proposed action on the potential shock hazard from the 2 transmission lines if the transmission lines that were constructed for the specific purpose of 3 connecting the plant to the transmission system do not meet the recommendations of the NESC 4 for preventing electric shock from induced currents. The NRC uses the NESC criteria and the 5 applicants adherence to those criteria during the current operating license as a baseline to 6 assess the potential human health impact of the induced current from an applicants 7 transmission lines. As discussed in the GEIS, the issue of electric shock is of small significance 8 for transmission lines that are operated in adherence with the NESC criteria. 9 As discussed in Section 3.1.6 of this SEIS, transmission lines that are within the scope of the 10 NRCs license renewal environmental review are limited to those transmission lines that connect 11 the nuclear plant to the substation where electricity is fed into the regional distribution system 12 and transmission lines that supply power to the nuclear plant from the grid (NRC 2013). 13 As indicated by Exelon in its ER, no offsite transmission lines are in-scope for the environmental 14 review for license renewal. The only transmission lines that are in scope for license renewal are 15 onsite; the lines from the LSCS power block to the LSCS switchyard (Exelon 2014a). The 16 public does not have access to this area and could not come into contact with these lines. 17 Therefore, there is no potential shock hazard to members of the public from these transmission 18 lines. As discussed in Section 3.11.5 of this SEIS, LSCS maintains an occupational safety 19 program in accordance with the Occupational Safety & Health Administration regulations for its 20 workers, which includes protection from acute electric shock. 21 3.11.5 Other Hazards 22 Two additional human health issues are addressed in this section: physical occupational 23 hazards and electric shock hazards. 24 Nuclear power plants are industrial facilities that have many of the typical occupational hazards 25 found at any other electric power generation facility. Workers at or around nuclear power plants 26 would be involved in some electrical work, electric power line maintenance, repair work, and 27 maintenance activities and exposed to some potentially hazardous physical conditions 28 (e.g., falls, excessive heat, cold, noise, electric shock, and pressure). The issue of physical 29 occupational hazards is generic to all nuclear power plants. 30 The Occupational Safety and Health Administration (OSHA) is responsible for developing and 31 enforcing workplace safety regulations. OSHA was created by the Occupational Safety and 32 Health Act of 1970 (29 USC 651 et seq.), which was enacted to safeguard the health of 33 workers. With specific regard to nuclear power plants, plant conditions that result in an 34 occupational risk, but do not affect the safety of licensed radioactive materials, are under the 35 statutory authority of OSHA rather than the NRC as set forth in a Memorandum of 36 Understanding (53 FR 43950) between the NRC and OSHA. Occupational hazards can be 37 minimized when workers adhere to safety standards and use appropriate protective equipment; 38 however, fatalities and injuries from accidents can still occur. 39 LSCS participates in the OSHA Voluntary Protection Program (VPP) (OSHA 2015a). The VPP 40 recognizes employers and workers in the private industry and federal agencies who have 41 implemented effective safety and health management systems and maintain injury and illness 42 rates below national Bureau of Labor Statistics averages for their respective industries. In the 43 VPP, management, labor, and OSHA establish cooperative relationships at workplaces that 44 have implemented a comprehensive safety and health management system. Approval into VPP 45 is OSHAs official recognition of the outstanding efforts of employers and employees who have 46 achieved exemplary occupational safety and health (OSHA 2015b). LSCS holds the Star 47 rating in the VPP, which indicates participants whose safety and health management systems 3-100

Affected Environment 1 operate in a highly effective, self-sufficient manner and meet all VPP requirements. Star is the 2 highest level of VPP participation (OSHA 2008). 3 3.12 Environmental Justice 4 Under Executive Order (EO) 12898 (59 FR 7629), Federal agencies are responsible for 5 identifying and addressing, as appropriate, disproportionately high and adverse human health 6 and environmental impacts on minority and low-income populations. Independent agencies, 7 such as the NRC, are not bound by the terms of EO 12898 but are, as stated in 8 paragraph 6-604 of the EO, requested to comply with the provisions of [the] order. In 2004, 9 the Commission issued a Policy Statement on the Treatment of Environmental Justice Matters 10 in NRC Regulatory and Licensing Actions (69 FR 52040), which states, The Commission is 11 committed to the general goals set forth in EO 12898, and strives to meet those goals as part of 12 its NEPA review process. 13 The Council on Environmental Quality (CEQ) provides the following information in 14 Environmental Justice: Guidance Under the National Environmental Policy Act (CEQ 1997): 15 Disproportionately High and Adverse Human Health Effects. 16 Adverse health effects are measured in risks and rates that could result in latent 17 cancer fatalities, as well as other fatal or nonfatal adverse impacts on human 18 health. Adverse health effects may include bodily impairment, infirmity, illness, or 19 death. Disproportionately high and adverse human health effects occur when the 20 risk or rate of exposure to an environmental hazard for a minority or low-income 21 population is significant (as employed by NEPA) and appreciably exceeds the 22 risk or exposure rate for the general population or for another appropriate 23 comparison group (CEQ 1997). 24 Disproportionately High and Adverse Environmental Effects. 25 A disproportionately high environmental impact that is significant (as employed 26 by NEPA) refers to an impact or risk of an impact on the natural or physical 27 environment in a low-income or minority community that appreciably exceeds the 28 environmental impact on the larger community. Such effects may include 29 ecological, cultural, human health, economic, or social impacts. An adverse 30 environmental impact is an impact that is determined to be both harmful and 31 significant (as employed by NEPA). In assessing cultural and aesthetic 32 environmental impacts, impacts that uniquely affect geographically dislocated or 33 dispersed minority or low-income populations or American Indian tribes are 34 considered (CEQ 1997). 35 The environmental justice analysis assesses the potential for disproportionately high and 36 adverse human health or environmental effects on minority and low-income populations that 37 could result from the operation of LSCS during the renewal term. In assessing the impacts, the 38 following definitions of minority individuals and populations and low-income population were 39 used (CEQ 1997): 40 Minority individuals 41 Individuals who identify themselves as members of the following population 42 groups: Hispanic or Latino, American Indian or Alaska Native, Asian, Black or 43 African American, Native Hawaiian or Other Pacific Islander, or two or more 44 races, meaning individuals who identified themselves on a Census form as being 45 a member of two or more races, for example, White and Asian. 46 Minority populations 3-101

Affected Environment 1 Minority populations are identified when (1) the minority population of an affected 2 area exceeds 50 percent or (2) the minority population percentage of the affected 3 area is meaningfully greater than the minority population percentage in the 4 general population or other appropriate unit of geographic analysis. 5 Low-income population 6 Low-income populations in an affected area are identified with the annual 7 statistical poverty thresholds from the Census Bureau's Current Population 8 Reports, Series P60, on Income and Poverty. 9 3.12.1 Minority Population 10 According to 2010 Census data, approximately 21 percent of the population residing within a 11 50-mi (80-km) radius of LSCS identified themselves as minority individuals. The largest minority 12 group was Hispanic or Latino (of any race) (9.7 percent), followed by Black or African American 13 (6.4 percent) (USCB 2015e). 14 According to USCBs (USCBs) 2010 Census data, minority populations in the socioeconomic 15 ROI (LaSalle, Grundy, and Will Counties) composed 28.6 percent of the total three-county 16 population (see Table 3-20). Figure 3-17 shows predominantly minority population block 17 groups, using 2010 Census data for race and ethnicity, within a 50-mi (80-km) radius of LSCS. 18 Census block groups were considered minority population block groups if the percentage of the 19 minority population within any block group exceeded 21 percent (the percent of the minority 20 population within the 50-mi radius of LSCS). A minority population exists if the percentage of 21 the minority population within the block group is meaningfully greater than the minority 22 population percentage in the 50-mi (80-km) radius. Approximately 400 of the census block 23 groups located within the 50-mi (80-km) radius of LSCS have meaningfully greater minority 24 populations. 25 As shown in Figure 3-17, minority population block groups (race and ethnicity) are mostly 26 clustered near Chicago, Illinois. None of the block groups near to LSCS have meaningfully 27 greater minority populations. 28 According to the USCBs 2014 American Community Survey 1-Year Estimates, since 2010, 29 minority populations in the ROI increased by approximately 17,700 persons (an increase of 30 7.4 percent) and now comprise 30.5 percent of the ROI population (see Table 2.10.3-3). The 31 largest increases occurred in the Hispanic or Latino population (an increase of approximately 32 8,900 persons or 7.5 percent) and Asian population (an increase of approximately 33 5,800 persons or 18.5 percent) (USCB 2015b). 34 3.12.2 Low-Income Population 35 According to 2010 American Community Survey data, 9 percent of individuals residing within a 36 50-mi (80-km) radius of LSCS were identified as living below the Federal poverty threshold in 37 2010 (USCB 2015e). The 2010 Federal poverty threshold was $22,113 for a family of four. 38 Figure 3-18 shows the location of predominantly low-income population block groups within a 39 50-mi (80 km) radius of LSCS. Census block groups were considered low-income population 40 block groups if the percentage of individuals living below the Federal poverty threshold within 41 any block group exceeded the percent of the individuals living below the Federal poverty 42 threshold within the 50-mi radius of LSCS. Approximately 490 of the 1,269 census block groups 43 located within the 50-mi (80-km) radius of LSCS have meaningfully greater low-income 44 populations. 3-102

Affected Environment 1 As shown in Figure 3-18, low-income population block groups are evenly distributed around 2 LSCS. The LSCS site is not located in a low-income population block group. The nearest 3 low-income population block group is located south and east of the block group containing 4 LSCS. 5 According to the USCBs 2014 American Community Survey 1-Year Estimates, 10.5 percent 6 of families and 14.4 percent of individuals in Illinois were living below the Federal poverty 7 threshold and the median household and per capita incomes for Illinois was $57,444 and 8 $30,417, respectively (USCB 2015b). In the socioeconomic ROI, people living in LaSalle 9 County had median household and per capita incomes below the State average. The median 10 household and per capita income averages in LaSalle County were $50,432 and $25,129, 11 respectively, with 9.6 percent of families and 13.3 percent of individuals living below the poverty 12 level. In comparison to the State of Illinois and LaSalle County, Will County had higher median 13 household and per capita income averages ($74,828 and $32,148, respectively) and lower 14 percentages of families (6.3 percent) and individuals (7.9 percent) living below the poverty level 15 (USCB 2015b). According to the USCBs 2011-2013 American Community Survey 3-Year 16 Estimates, Grundy County also had higher median household and per capita income averages 17 ($63,978 and $28,465, respectively) and lower percentages of families (7.2 percent) and 18 individuals (9.4 percent) living below the poverty level than the State of Illinois and LaSalle 19 County (USCB 2015b). 3-103

Affected Environment 1 Figure 3-17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS 2 Source: USCB 2015e 3-104

Affected Environment 1 Figure 3-18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS 2 Source: USCB 2015e 3-105

Affected Environment 1 3.13 Waste Management and Pollution Prevention 2 3.13.1 Radioactive Waste 3 As discussed in Section 3.1.4 of this SEIS, LSCS uses liquid, gaseous, and solid waste 4 processing systems to collect and treat, as needed, radioactive materials produced as a 5 byproduct of plant operations. Radioactive materials in liquid and gaseous effluents are 6 reduced prior to being released into the environment so that the resultant dose to members of 7 the public from these effluents is well within NRC and EPA dose standards. Radionuclides that 8 can be efficiently removed from the liquid and gaseous effluents prior to release are converted 9 to a solid waste form for disposal in a licensed disposal facility. 10 3.13.2 Nonradioactive Waste 11 Waste minimization and pollution prevention are important elements of operations at all nuclear 12 power plants. Licensees are required to consider pollution prevention measures as dictated by 13 the Pollution Prevention Act (Public Law 101-508) and Resource Conservation and Recovery 14 Act of 1976, as amended (Public Law 94-580) (NRC 2013). 15 As described in Section 3.1.5, LSCS has a nonradioactive waste management program to 16 handle nonradioactive waste in accordance with Federal, State, and corporate regulations and 17 procedures. LSCS has waste minimization measures in place, as verified during the site visit 18 conducted by the NRC staff in May 2015. This program includes appropriate recycling, thereby 19 effecting waste reduction. 20 LSCS has a Storm Water Pollution Prevention Plan (SWPPP) that identifies potential sources of 21 pollution that may affect the quality of storm water discharges from each permitted outfall. The 22 SWPPP also describes practices that are used to reduce pollutants in storm water discharges to 23 assure compliance with the sites NPDES permit. As part of LSCSs Spill Prevention Control 24 and Countermeasure Plan, measures are in place to monitor areas within the site that have the 25 potential for spills of regulated substances, such as oil (Exelon 2014a). 26 3.14 References 27 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, Standards for 28 protection against radiation. 29 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 30 production and utilization facilities. 31 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 32 protection regulations for domestic licensing and related regulatory functions. 33 10 CFR Part 61. Code of Federal Regulations, Title 10, Energy, Part 61, Licensing 34 requirements for land disposal of radioactive waste. 35 10 CFR Part 71. Code of Federal Regulations, Title 10, Energy, Part 71, Packaging and 36 transportation of radioactive material. 37 10 CFR Part 72. Code of Federal Regulations, Title 10, Energy, Part 72, Licensing 38 requirements for the independent storage of spent nuclear fuel, high-level radioactive waste, 39 and reactor-related Greater than Class C waste. 40 15 CFR Part 930. Code of Federal Regulations, Title 15, Commerce and Foreign Trade, 41 Part 930, Federal consistency with approved coastal management programs. 3-106

Affected Environment 1 40 CFR Part 50. Code of Federal Regulations, Title 40, Protection of Environment, Part 50, 2 National primary and secondary ambient air quality standards. 3 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 50, 4 National Primary and Secondary Ambient Air Quality Standards, Washington, DC. 5 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of the Environment, Part 51, 6 Requirements for Preparation, Adoptions, and Submittal of Implementation Plans." 7 Washington, D.C. 8 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 9 "Designation of areas for air quality planning purposes." 10 40 CFR Part 98. Code of Federal Regulations, Title 40, Protection of Environment, Part 98, 11 Mandatory Greenhouse Gas Reporting. 12 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 13 Environmental radiation protection standards for nuclear power operations. 14 40 CFR Part 230. Code of Federal Regulations, Title 40, Protection of Environment, Part 230, 15 Section 404(b)(1) Guidelines for Specification of Disposal Sites for Dredged or Fill Material. 16 49 CFR Parts 171-178. Code of Federal Regulations, Title 49, Transportation, Subchapter C 17 Hazardous Materials Regulations and Specifications for packagings. 18 50 CFR 17.3. U.S. Fish and Wildlife Service. 2006. Endangered and Threatened Wildlife and 19 Plants; Definitions. 20 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 21 Interagency CooperationEndangered Species Act of 1973, as Amended. 22 32 FR 4001. U.S. Fish and Wildlife Service. 1967. Endangered Species. Federal 23 Register 32(48):4001. March 11, 1967. 24 41 FR 41914. U.S. Fish and Wildlife Service. 1976. Endangered and Threatened Wildlife and 25 Plants; Determination of Critical Habitat for American Crocodile, California Condor, Indiana Bat, 26 and Florida Manatee. Federal Register 41(187):41914-41916. September 24, 1976. 27 53 FR 43950. U.S. Department of Labor. Memorandum of Understanding Between the 28 Nuclear Regulatory Commission and the Occupational Safety and Health Administration; 29 Worker Protection at NRC-licensed Facilities. Federal Register 53 (210):43950-43952. 30 October 31, 1988. 31 53 FR 5598. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 32 Plants; Proposal to Determine Boltonia decurrens (Decurrent false aster) to be a Threatened a 33 Threatened Species. Federal Register 53(37):5598-5602. February 25, 1988. 34 53 FR 45858. U.S. Fish and Wildlife Service. 1988. Endangered and Threatened Wildlife and 35 Plants; Determination of Threatened Status for Boltonia decurrens (Decurrent False Aster). 36 Federal Register 53(219):45858-45861. November 14, 1988. 37 54 FR 39857. U.S. Fish and Wildlife Service. 1989. Endangered and Threatened Wildlife and 38 Plants; Determination of Threatened Status for Eastern and Western Prairie Fringed Orchids. 39 Federal Register 54(187):29857-39863. September 28, 1989. 40 56 FR 19953. U.S. Fish and Wildlife Service. 1991. Endangered and Threatened Wildlife and 41 Plants; Dalea foliosa (Leafy Prairie-Clover) Determined to be Endangered. Federal Register 42 56(84):19953-19959. May 1, 1991. 3-107

Affected Environment 1 59 FR 7629. Executive Order No. 12898. Federal actions to address environmental justice in 2 minority populations and low-income populations. Federal Register 59(32):7629-7634. 3 February 16, 1994. 4 69 FR 52040. U.S. Nuclear Regulatory Commission. Policy statement on the treatment of 5 environmental justice matters in NRC regulatory and licensing actions. Federal Register 6 69(163):52040-52048. August 24, 2004. 7 69 FR 41576. U.S. Environmental Protection Agency. National Pollutant Discharge 8 Elimination SystemFinal Regulations to Establish Requirements for Cooling Water Intake 9 Structures at Phase II Existing Facilities. Federal Register 69(131):41576-41693. 10 July 9, 2004. 11 74 FR 56260. Environmental Protection Agency. Mandatory Reporting of Greenhouse 12 Gases. Federal Register 74(209): 56260-56519. October 30, 2009. 13 75 FR 31514. Environmental Protection Agency. Prevention of Significant Deterioration and 14 Title V Greenhouse Gas Tailoring Rule. Federal Register 75(106):31514-31608. 15 77 FR 14914. U.S. Fish and Wildlife Service. Endangered and Threatened Wildlife and Plants: 16 Determination of Endangered Status for the Sheepnose and Spectaclecase Mussels 17 Throughout Their Range. Federal Register 77(49):14914-14949. March 13, 2012. 18 77 FR 38762. U.S. Fish and Wildlife Service. 2012. Endangered and Threatened Wildlife and 19 Plants; 5-Year Status Reviews of Seven Listed Species. Federal Register 20 77(126):38762-38764. June 29, 2012. 21 78 FR 61046. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 22 Plants; 12-Month Finding on a Petition To List the Eastern Small-Footed Bat and the Northern 23 Long-Eared Bat as Endangered or Threatened Species; Listing the Northern Long-Eared Bat as 24 an Endangered Species; Proposed Rule. Federal Register 78(194):61046-61080. 25 October 2, 2013. 26 78 FR 72058. U.S. Fish and Wildlife Service. 2013. Endangered and Threatened Wildlife and 27 Plants; Listing the Northern Long-Eared Bat as an Endangered Species. Federal Register 28 78(231):72058-72059. December 2, 2013. 29 80 FR 17974. U.S. Fish and Wildlife Service. Endangered and Threatened Wildlife and 30 Plants; Threatened Species Status for the Northern Long-Eared Bat with 4(d) Rule. Federal 31 Register 80(63):17974-8033. April 2, 2015. 32 35 IAC 1420.140(a). Illinois Administrative Code, Title 35, Environmental Protection, Part 1420, 33 General Provisions, Section 140, Prohibitions. 34 35 IAC 201. Illinois Administrative Code, Title 35, Environmental Protection, "Subtitle B," Air 35 Pollution Control Board Subchapter a, "Permits and General Provisions," Part 201 Permit and 36 General Provisions. 37 35 IAC 301. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 38 Pollution," Chapter I, "Pollution Control Board," Part 301, Introduction. Illinois Pollution Control 39 Board. Available at <http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulations-40 Title35.aspx> (accessed 21 August 2015). 41 35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, "Water 42 Pollution," Chapter I, "Pollution Control Board," Part 302, Water Quality Standards. Illinois 43 Pollution Control Board. Available at <http://www.ipcb.state.il.us/SLR/IPCBandIEPA 44 EnvironmentalRegulations-Title35.aspx> (accessed 21 August 2015). 3-108

Affected Environment 1 35 IAC 303. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, Water 2 Pollution, Chapter I, Pollution Control Board, Part 303, Water Use Designations and Site 3 Specific Water Quality Standards. Illinois Pollution Control Board. Available at 4 <http://www.ipcb.state.il.us/SLR/IPCBandIEPAEnvironmentalRegulations-Title35.aspx> 5 (accessed 21 August 2015). 6 35 IAC 309. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, Water 7 Pollution, Chapter I, Pollution Control Board, Part 309, Permits, Subpart A, NPDES 8 Permits. Illinois Pollution Control Board. Available at <http://www.ipcb.state.il.us/SLR/ 9 IPCBandIEPAEnvironmentalRegulations-Title35.aspx> (accessed 21 August 2015). 10 35 IAC 733. Illinois Administrative Code, Title 35, Environmental Protection, Part 733, 11 Standards for Universal Waste Management. 12 35 IAC 900, Illinois Administrative Code, Title 35, Environmental Protection, Subtitle H, Noise, 13 Chapter I, "Pollution Control Board." 14 525 ILCS 45. Illinois Compiled Statutes. Chapter 525, Conservation, Act, Water Use 15 Act of 1983, as amended. Available at <http://www.ilga.gov/legislation/ilcs/ 16 ilcs3.asp?ActID=1743&ChapterID=44> (accessed 21 August 2015). 17 [AEC] U.S. Atomic Energy Commission. 1973. Final Environmental Statement Related to the 18 LaSalle County Nuclear Station. February 1972. Washington, DC: AEC. 287 p. ADAMS 19 No. ML15043A501. 20 Albrecht JA. 2013a. University of Nebraska-Lincoln: UNL Food: Bacteria Causing Foodborne 21 Illness: Salmonella. Available at <http://food.unl.edu/web/safety/salmonella> (accessed 22 23 October 2013). 23 Albrecht JA. 2013b. University of Nebraska-Lincoln: UNL Food: Bacteria Causing Foodborne 24 Illness: Shigella. Available at <http://food.unl.edu/web/safety/shigella> (accessed 25 23 October 2013). 26 Arnold TL, Sullivan DJ, Harris MA, Fitzpatrick FA, Scudder BC, Ruhl PM, Hanchar DW, Stewart 27 JS. 1999. Environmental Setting of the Upper Illinois River Basin and Implications for Water 28 Quality. Urbana, IL: U.S. Geological Survey, WRD. Water-Resources Investigations 29 Report 98-4268. Available at <http://il.water.usgs.gov/nawqa/uirb/pubs/reports/WRIR_98-30 4268.pdf> (accessed 21 August 2015). 31 Ataner S, Butler S. 2013. Geologic Field Trip to the Starved Rock State Park Area, LaSalle 32 County, Illinois, Guidebook for the field trip held on October 6, 2013 in conjunction with the 50th 33 Anniversary Annual Meeting of The Clay Minerals Society held at the University of Illinois at 34 Urbana-Champaign. October 6, 2013. Available at 35 <http://www.clays.org/annual%20meeting/50th_annual_meeting_website/docs/CMS13-Fieldtrip-36 Guide-StarvedRock.pdf> (accessed 31 December 2014). 37 Bald and Golden Eagle Protection Act of 1940, as amended. 16 U.S.C. §668-668c. 38 Baldwin, E. 1877. History of LaSalle County Illinois: Its Topography, Geology, Botany, Natural 39 History, History of the Mound Builders, Indian Tribes, French Explorations, and A Sketch of the 40 Pioneer Settlers of Each Town to 1840, with an Appendix, Giving the Present Status of the 41 County, Its Population, Resources, Manufactures, and Institutions. Chicago, IL: Rand McNally 42 and Company, 552 p. 3-109

Affected Environment 1 Barbour MT, Gerritsen J, Snyder BD, Stribling JB. 1999. Rapid Bioassessment Protocols for 2 Use in Streams and Wadeable Rivers: Periphyton, Benthic Macroinvertebrates, and Fish. 3 Second Edition. Appendix C: Tolerance and Trophic Guilds of Selected Fish Species. 4 Washington, DC: U.S. Environmental Protection Agency. EPA 841-B-99-002. Available at 5 <http://water.epa.gov/scitech/monitoring/rsl/bioassessment/index.cfm> (accessed 3 April 2014). 6 [BLS] Bureau of Labor Statistics. 2015. Local Area Unemployment Statistics. July 1, 2015. 7 Available at <http://www.bls.gov/data/> (accessed October 2015). 8 [CAPS] Circular Area Profiles. 2014. Missouri Census Data Center. Circular Area Profiles 9 (CAPS) - Version 10C (Revision 4-24-14) Using Data from Summary File 1, 2010 Census. In a 10 20-mile and 50-mile radius around LSCS (41.24555 Lat., 88.66826 Long). Available at 11 <http://mcdc.missouri.edu/websas/caps10c.html> (accessed October 2015). 12 [CDC] Centers for Disease Control and Prevention. 2002. Surveillance for 13 Waterborne-Disease OutbreaksUnited States, 1999-2000. Morbidity and Mortality Weekly 14 Report 51(8):1-28. November 22, 2002. Available at <http://www.cdc.gov/mmwr/ 15 preview/mmwrhtml/ss5108a1.htm> (accessed 23 October 2013). 16 [CDC] Centers for Disease Control and Prevention. 2003. Summary of Notifiable Diseases 17 United States, 2001. Morbidity and Mortality Weekly Report 50(53). Atlanta, GA: CDC. 18 May 2, 2003. 136 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5053.pdf> (accessed 19 22 October 2013). 20 [CDC] Centers for Disease Control and Prevention. 2004a. Summary of Notifiable Diseases 21 United States, 2002. Morbidity and Mortality Weekly Report 51(53). Atlanta, GA: CDC. 22 April 30, 2004. 88 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5153.pdf> (accessed 23 22 October 2013). 24 [CDC] Centers for Disease Control and Prevention. 2004b. Surveillance for 25 Waterborne-Disease Outbreaks and Other Health Events Associated with Recreational Water 26 United States, 2001-2002. Morbidity and Mortality Weekly Report 53(8):1-22. 27 October 22, 2004. Available at <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5308a1.htm> 28 (accessed 23 October 2013). 29 [CDC] Centers for Disease Control and Prevention. 2005. Summary of Notifiable Diseases 30 United States, 2003. Morbidity and Mortality Weekly Report 52(54). Atlanta, GA: CDC. 31 April 22, 2005. 88 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5254.pdf> (accessed 32 22 October 2013). 33 [CDC] Centers for Disease Control and Prevention. 2006a. Summary of Notifiable Diseases 34 United States, 2004. Morbidity and Mortality Weekly Report 53(53). Atlanta, GA: CDC. 35 June 16, 2006. 84 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5353.pdf> (accessed 36 22 October 2013). 37 [CDC] Centers for Disease Control and Prevention. 2006b. Surveillance for Waterborne 38 Disease and Outbreaks and Other Health Events Associated with Recreational Water 39 United States, 2003-2004. Morbidity and Mortality Weekly Report 55(12):1-24. 40 December 22, 2006. Available at 41 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5512a1.htm> (accessed 23 October 2013). 42 [CDC] Centers for Disease Control and Prevention. 2007. Summary of Notifiable Diseases 43 United States, 2005. Morbidity and Mortality Weekly Report 54(53). Atlanta, GA: CDC. 44 March 30, 2007. 96 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5453.pdf> 45 (accessed 22 October 2013). 3-110

Affected Environment 1 [CDC] Centers for Disease Control and Prevention. 2008a. Summary of Notifiable Diseases 2 United States, 2006. Morbidity and Mortality Weekly Report 55(53). Atlanta, GA: CDC. 3 March 21, 2008. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5553.pdf> 4 (accessed 22 October 2013). 5 [CDC] Centers for Disease Control and Prevention. 2008b. Surveillance for Waterborne 6 Disease and Outbreaks Associated with Recreational Water Use and Other Aquatic 7 Facility-AssociatedUnited States, 2005-2006. Morbidity and Mortality Weekly 8 Report 57(9):1-29. September 9, 2008. Available at 9 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss5709a1.htm> (accessed 23 October 2013). 10 [CDC] Centers for Disease Control and Prevention. 2009. Summary of Notifiable Diseases 11 United States, 2007. Morbidity and Mortality Weekly Report 56(53). Atlanta, GA: CDC. 12 July 9, 2009. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5653.pdf> (accessed 13 22 October 2013). 14 [CDC] Centers for Disease Control and Prevention. 2010a. General Information on 15 Salmonella. April 5, 2012. Available at <http://www.cdc.gov/salmonella/general/> (accessed 16 23 October 2013). 17 [CDC] Centers for Disease Control and Prevention. 2010b. Summary of Notifiable Diseases 18 United States, 2008. Morbidity and Mortality Weekly Report 57(54). Atlanta, GA: CDC. 19 June 25, 2010. 100 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5754.pdf> 20 (accessed 22 October 2013). 21 [CDC] Centers for Disease Control and Prevention. 2011a. LegionellosisUnited States, 22 2000-2009. Morbidity and Mortality Weekly Report 60(32):1083-1086. August 19, 2011. 23 Available at <http://www.cdc.gov/mmwr/preview/mmwrhtml/mm6032a3.htm> (accessed 24 23 October 2013). 25 [CDC] Centers for Disease Control and Prevention. 2011b. Summary of Notifiable Diseases 26 United States, 2009. Morbidity and Mortality Weekly Report 58(53). Atlanta, GA: CDC. 27 May 13, 2011. 104 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5853.pdf> 28 (accessed 22 October 2013). 29 [CDC] Centers for Disease Control and Prevention. 2011c. Surveillance for Waterborne 30 Disease Outbreaks and Other Health Events Associated with Recreational Water 31 United States, 2007-2008. Morbidity and Mortality Weekly Report 60(12):1-32. 32 September 23, 2011. Available at 33 <http://www.cdc.gov/mmwr/preview/mmwrhtml/ss6012a1.htm?s_cid=ss6012a1_w> (accessed 34 23 October 2013). 35 [CDC] Centers for Disease Control and Prevention. 2012. Summary of Notifiable Diseases 36 United States, 2010. Morbidity and Mortality Weekly Report 59(53). Atlanta, GA: CDC. 37 June 1, 2012. 116 p. Available at <http://www.cdc.gov/mmwr/PDF/wk/mm5953.pdf> (accessed 38 22 October 2013). 39 [CDC] Centers for Disease Control and Prevention. 2013a. Pseudomonas aeruginosa in 40 Healthcare SettingsHAI. Available at <http://www.cdc.gov/hai/organisms/ 41 pseudomonas.html> (accessed 23 October 2013). 42 [CDC] Centers for Disease Control and Prevention. 2013b. Naegleria fowleriPrimary 43 Amebic Meningoencephalitis (PAM). Available at <http://www.cdc.gov/parasites/naegleria/> 44 (accessed 23 October 2013). 3-111

Affected Environment 1 [CDC] Centers for Disease Control and Prevention. 2013c. Naegleria fowleriSources of 2 InfectionNumber of Case-reports of Primary Amebic Meningoencephalitis by State of 3 Exposure: United States, 1962-2012. June 6, 2013. Available at 4 <http://www.cdc.gov/parasites/naegleria/state-map.html> (accessed 21 October 2013). 5 [CDC] Centers for Disease Control and Prevention. 2013d. Reports of Selected Salmonella 6 Outbreak Investigations. Available at <http://www.cdc.gov/salmonella/outbreaks.html> 7 (accessed 23 October 2013). 8 [CDC] Centers for Disease Control and Prevention. 2013e. Shigellosis: General 9 InformationNCZVED. May 14, 2013. Available at <http://www.cdc.gov/nczved/divisions/ 10 dfbmd/diseases/shigellosis/> (accessed 23 October 2013). 11 [CEC] Commission for Environmental Cooperation. 1997. Ecological Regions of North 12 America: Toward a Common Perspective. Available at 13 <http://www.cec.org/storage/42/3484_eco-eng_en.pdf> (accessed 5 August 2015). 14 [CEC] Commission for Environmental Cooperation. 2008. Ecoregions of North America-15 Level II. Available at <http://www.eoearth.org/view/article/152145/> (accessed 9 March 2015). 16 [CEQ] Council on Environmental Quality. 1997. Environmental Justice: Guidance under the 17 National Environmental Policy Act. Available at 18 <http://www.epa.gov/oecaerth/environmentaljustice/resources/policy/ej_guidance_nepa_ceq129 19 7.pdf>. 20 [CHC] Center for Hearing and Communication. undated. Common Environmental Noise 21 Levels Factsheet. Available at <http://www.chchearing.org/noise-center-home/facts-22 noise/common-environmental-noise-levels> (accessed 3 August 2015). 23 Clean Air Act of 1970. 42 U.S.C. §7401 et seq. 24 Coastal Zone Management Act of 1972. 16 U.S.C. §1451 et seq. 25 [ComEd] Commonwealth Edison Company. 1977. LaSalle County Station Environmental 26 Report Operating License Stage. Volume 1. May 10, 1977. ADAMS Nos. ML15273A414 and 27 ML15273A415. 28 Consolidated Appropriations Act of 2012. Pub. L. No. 112-74, 402, 125 Stat. 786, 883 (2011), 29 Section 402. 30 [CRA] Conestoga-Rovers & Associates. 2006. Hydrogeologic Investigation Report, Fleetwide 31 Assessment LaSalle Generating Station Marseilles, Illinois, Revision 1. September 2006. 32 ADAMS No. ML062760008. 33 [DOI] U.S. Department of the Interior, National Park Service. 1998. National Register of 34 Historic Places, Multiple Property Documentation Form, Archaeological Sites of Starved Rock 35 State Park (9,000-150 B.P.). Available at 36 http://pdfhost.focus.nps.gov/docs/NRHP/Text/64500198.pdf (accessed 16 June 2015). 37 [DOI] U.S. Department of the Interior, National Park Service. 2015. National Register of 38 Historic Places: Research. Available at <http://www.nps.gov/nr/research/> (accessed 39 28 August 2015). 40 [EA] EA Engineering, Science, and Technology, Inc. 2000. Final Report LaSalle Station 41 Aquatic Monitoring 1999, RM 249.7-248.8. Prepared for Commonwealth Edison Company, 42 Marseilles, Illinois. September 2000. Deerfield, Illinois. ADAMS No. ML15273A420. 3-112

Affected Environment 1 [EA] EA Engineering, Science, and Technology, Inc. 2002. Assessment of the LaSalle County 2 Station Cooling Pond. Prepared for Exelon Generation Company, LLC, March 2002. Deerfield, 3 IL. ADAMS No. ML15195A368. 4 [EA] EA Engineering, Science, and Technology, Inc. 2014. LaSalle County Station 2013 Fish 5 and Benthos Monitoring and Historical Fish and Benthos Comparisons. Prepared for Exelon 6 Generation Company, LLC, Kennett Square, Pennsylvania. May 2014. Deerfield, Illinois. 7 ADAMS No. ML15273A419. 8 [EA] EA Engineering, Science, and Technology, Inc. 2015. Final Impingement and Entrainment 9 Characterization Study LaSalle County Station. Prepared for Exelon Generation Company, 10 LLC, Kennett Square, Pennsylvania. August 2015. Deerfield, Illinois. ADAMS 11 No. ML15273A204. 12 Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 13 [EPA] Environmental Protection Agency. 1974. Information on Levels of Environmental Noise 14 Requisite to Protect Public Health and Welfare with an Adequate Safety of Margin. Available at 15 <http://www.fican.org/pdf/EPA_Noise_Levels_Safety_1974.pdf> (accessed 15 July 2015). 16 [EPA] Environmental Protection Agency. 1981. Noise Effects Handbook: A Desk Reference to 17 Health and Welfare. Available at <http://nepis.epa.gov/Exe/ZyNET.exe/9100OOAJ.TXT? 18 ZyActionD=ZyDocument&Client=EPA&Index=1981+Thru+1985&Docs=&Query=&Time=&EndTi 19 me=&SearchMethod=1&TocRestrict=n&Toc=&TocEntry=&QField=&QFieldYear=&QFieldMonth 20 =&QFieldDay=&IntQFieldOp=0&ExtQFieldOp=0&XmlQuery=&File=D%3A%5Czyfiles%5CIndex 21 %20Data%5C81thru85%5CTxt%5C00000018%5C9100OOAJ.txt&User=ANONYMOUS&Passw 22 ord=anonymous&SortMethod=h%7C-&MaximumDocuments=1&FuzzyDegree=0&ImageQuality 23 =r75g8/r75g8/x150y150g16/i425&Display=p%7Cf&DefSeekPage=x&SearchBack=ZyActionL&B 24 ack=ZyActionS&BackDesc=Results%20page&MaximumPages=1&ZyEntry=1&SeekPage=x&Zy 25 PURL> (accessed 24 April 2015). 26 [EPA] Environmental Protection Agency. 1992. Clarification of Prevention of Significance 27 Deterioration (PSD) Guidance for Modelling Class I Area Impacts. Available at 28 <http://www.epa.gov/ttn/nsr/gen/u3-11.txt> (accessed 15 July 2015). 29 [EPA] Environmental Protection Agency. 2011. 2011 National Emissions Inventory Data. 30 Available at <http://www3.epa.gov/ttn/chief/net/2011inventory.html> (accessed 24 April 2015). 31 [EPA] U.S. Environmental Protection Agency. 2015a. Envirofacts Search: PCS-ICIS. [Permit 32 Compliance System (PCS) and Integrated Compliance Information System (ICIS) databases]. 33 Page updated June 24, 2014. Available at <http://www.epa.gov/enviro/facts/pcs-34 icis/search.html> (accessed 31 August 2015). 35 [EPA] Environmental Protection Agency. 2015b. EPA, Enforcement and Compliance History 36 Online, Exelon LaSalle County Station. Available at <http://echo.epa.gov/?redirect=echo> 37 (accessed 22 April 2015). 38 [EPA] Environmental Protection Agency. 2015c. EPA History: Noise and the Noise Control 39 Act. Available at <http://www2.epa.gov/aboutepa/epa-history-noise-and-noise-control-act> 40 (accessed 15 July 2015). 41 [EPA] Environmental Protection Agency. 2015d. National Ambient Air Quality Standards. 42 Available at <http://www.epa.gov/air/criteria.html> (accessed 10 July 2015). 43 [EPA] U.S. Environmental Protection Agency. 2015e. Safe Drinking Water Information System 44 (SDWIS), County Search Grundy, LaSalle and Will Counties, Illinois. Available at 45 <http://www.epa.gov/enviro/facts/sdwis/search.html> (accessed October 2015). 3-113

Affected Environment 1 [ESPA] Illinois Compiled Statutes, Chapter 520, Wildlife, Part 10, Illinois Endangered Species 2 Protection Act. 3 [Exelon] Exelon Generation Company, LLC. 2001. Letter from W. Riffer, Regulatory Assurance 4 Manager, LaSalle County Station to U.S. NRC, Document control Desk.

Subject:

5 Environmental Non-Routine Event Report for Exelon Generation Company, LLCLaSalle 6 County Station. August 17, 2001. ADAMS No. ML012330070. 7 [Exelon] Exelon Generation Company, LLC. 2002. Letter from G.T. Kaegi, Regulatory 8 Assurance Manager, LaSalle County Station to U.S. NRC, Document control Desk.

Subject:

9 Environmental Protection Plan and Operating Report Appendix B to Facility License No. NPF-11 10 and NPF-18. April 29, 2002. ADAMS No. ML021330421. 11 [Exelon] Exelon Generation Company, LLC. 2009. Letter from D. Rhoads, Plant Manager, 12 LaSalle County Station to U.S. NRC, Document control Desk.

Subject:

Environmental 13 Non-Routine Event Report for Exelon Generation Company, LLCLaSalle County Station. 14 July 22, 2009. ADAMS No. ML092040381. 15 [Exelon] Exelon Generation Company, LLC. 2010. Letter from P.J. Karaba, Plant Manager, 16 LaSalle County Station to U.S. NRC, Document control Desk.

Subject:

Environmental Non-17 Routine Event Report for Exelon Generation Company, LLCLaSalle County Station. 18 August 25, 2010. ADAMS No. ML102371289. 19 [Exelon] Exelon Generation Co. LLC. 2011a. Illinois Water Inventory Program [LaSalle County 20 Station report submitted to the Illinois State Water Survey for calendar year 2010]. ADAMS 21 No. ML15195A385. 22 [Exelon] Exelon Generation Company, LLC. 2011b. LaSalle County Station, 2010 Radioactive 23 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 26, 2011. ADAMS 24 No. ML11124A101. 25 [Exelon] Exelon Generation Co. LLC. 2012a. Illinois Water Inventory Program [LaSalle County 26 Station report submitted to the Illinois State Water Survey for calendar year 2011]. ADAMS 27 No. ML15195A385. [RAI response SW-01] 28 [Exelon] Exelon Generation Company, LLC. 2012b. LaSalle County Station, 2011 Radioactive 29 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 20, 2012. ADAMS 30 No. ML12116A148. 31 [Exelon] Exelon Generation Co. LLC. 2013a. Illinois Water Inventory Program [LaSalle County 32 Station report submitted to the Illinois State Water Survey for calendar year 2012]. ADAMS 33 No. ML15195A385. 34 [Exelon] Exelon Generation Company, LLC. 2013b. LaSalle County Generating Station Wildlife 35 Management Plan. ADAMS No. ML15273A416. 36 [Exelon] Exelon Generation Company, LLC. 2013c. LaSalle County Station, 2012 Radioactive 37 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 26, 2013. ADAMS 38 No. ML131280052. 39 [Exelon] Exelon Generation Company, LLC. 2013d. Offsite Dose Calculation Manual (ODCM). 40 Revision 4. Marseilles, IL: Exelon Nuclear. CY-LA-170-301. April 2013. ADAMS 41 No. ML13128A059. 3-114

Affected Environment 1 [Exelon] Exelon Generation Company, LLC. 2013e Storm Water Pollution Prevention Plan, 2 LaSalle County Station, Marseilles, Illinois. June 2013. In Letter from M.P. Gallagher, Vice 3 President, License Renewal Projects, to NRC Document Desk.

Subject:

Response to NRC 4 Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County Station, 5 Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. ADAMS 6 No. ML15195A389. 7 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 8 Operating License Renewal Stage LaSalle County Station, Unit 1 and Unit 2. Chicago, Illinois: 9 Exelon. December 9, 2014. ADAMS Nos. ML14343A849, ML14343A883, and ML14343A897. 10 [Exelon] Exelon Generation Co. LLC. 2014b. Illinois Water Inventory Program [LaSalle County 11 Station report submitted to the Illinois State Water Survey for calendar year 2013]. ADAMS 12 No. ML15195A385. 13 [Exelon] Exelon Generation Company, LLC. 2014c. LaSalle County Station, 2013 Radioactive 14 Effluent Release Report. Marseilles, IL: Exelon Nuclear. May 1, 2014. ADAMS 15 No. ML14121A217. 16 [Exelon] Exelon Generation Company, LLC. 2014d. LaSalle County Station, Units 1 and 2 17 Seismic Hazard and Screening Report. Chicago, Illinois: Exelon. March 31, 2014. ADAMS 18 No. ML14091A013. 19 [Exelon] Exelon Generation Company, LLC. 2014e. LaSalle, Units 1 and 2, Updated Final 20 Safety Analysis Report, Revision 20, Chapter 2.0, Figure 2.5-19, Sheet 40 through 21 Figure 2.5-92. Chicago, Illinois: Exelon. April 11, 2014. ADAMS No. ML14113A086. 22 [Exelon] Exelon Generation Company, LLC. 2014f. LaSalle, Units 1 and 2, Updated Final 23 Safety Analysis Report, Revision 20, Chapter 2.0Site Characteristics. Chicago, Illinois: 24 Exelon. April 11, 2014. ADAMS No. ML14113A084. 25 [Exelon] Exelon Generation Company, LLC. 2014g. LaSalle County Station, Updated Final 26 Safety Analysis Report, Revision 20. Chicago, Illinois: Exelon. April 11, 2014. ADAMS 27 No. ML14113A099. 28 [Exelon] Exelon Generation Company, LLC. 2014h. Letter from M.P. Gallagher, Vice 29 President, License Renewal Projects, to Illinois Environmental Protection Agency, Bureau of 30 Water.

Subject:

Application for Clean Water Act Section 401 Certification associated with 31 Renewal of LaSalle County Station Units 1 and 2 Operating Licenses. February 4, 2014. In: 32 LaSalle County Station, Units 1 and 2, License Renewal Application, Appendix E, Applicants 33 Environmental Report, Operating License Renewal Stage. ADAMS No. ML14343A897 34 (Appendix B). 35 [Exelon] Exelon Generation Company, LLC. 2015a. Corrected LaSalle Groundwater Tritium 36 Concentrations. Chicago, Illinois: Exelon. July 28, 2015. ADAMS No. ML15195A402. 37 [Exelon] Exelon Generation Company, LLC. 2015b. LaSalle County Station, 2014 Radioactive 38 Effluent Release Report. Marseilles, IL: Exelon Nuclear. April 30, 2015. ADAMS 39 No. ML15120A282. 40 [Exelon] Exelon Generation Company, LLC. 2015c. Letter from M.P. Gallagher, Vice 41 President, License Renewal Projects, to the NRC Document Control Desk.

Subject:

Response

42 to NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 43 Station, Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. 44 ADAMS No. ML15195A351. 3-115

Affected Environment 1 [Exelon] Exelon Generation Company, LLC. 2015d. Letter from M.P. Gallagher, Vice President 2 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 6 Review Requests for Additional Information. Response to Request for Additional Information 7 LU-01. July 2, 2015. ADAMS No. ML15195A373. 8 [Exelon] Exelon Generation Company, LLC. 2015e. Letter from M.P. Gallagher, Vice President 9 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 10 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 11 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 12 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 13 Review Requests for Additional Information. Response to Request for Additional Information 14 LU-02. July 2, 2015. ADAMS No. ML15195A374. 15 [Exelon] Exelon Generation Company, LLC. 2015f. Letter from M.P. Gallagher, Vice President 16 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 18 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 19 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 20 Review Requests for Additional Information. Response to Request for Additional Information 21 LU-03. July 2, 2015. ADAMS No. ML15195A375. 22 [Exelon] Exelon Generation Company, LLC. 2015g. Letter from M.P. Gallagher, Vice President 23 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 24 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 25 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 26 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 27 Review Requests for Additional Information. Response to Request for Additional Information 28 LU-04. July 2, 2015. ADAMS No. ML15195A376. 29 [Exelon] Exelon Generation Company, LLC. 2015h. Letter from M.P. Gallagher, Vice President 30 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 31 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 32 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 33 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 34 Review Requests for Additional Information. Response to Request for Additional Information 35 LU-05. July 2, 2015. ADAMS No. ML15195A377. 36 [Exelon] Exelon Generation Company, LLC. 2015i. Letter from M.P. Gallagher, Vice President 37 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 38 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 39 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 40 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 41 Review Requests for Additional Information. Response to Request for Additional Information 42 LU-06. July 2, 2015. ADAMS No. ML15195A378. 3-116

Affected Environment 1 [Exelon] Exelon Generation Company, LLC. 2015j. Letter from M.P. Gallagher, Vice President 2 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 6 Review Requests for Additional Information. Response to Request for Additional Information 7 MA-01. July 2, 2015. ADAMS No. ML15195A344. 8 [Exelon] Exelon Generation Company, LLC. 2015k. Letter from M.P. Gallagher, Vice President 9 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 10 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 11 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 12 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 13 Review Requests for Additional Information. Response to Request for Additional Information 14 MA-05. July 2, 2015. ADAMS No. ML15195A348. 15 [Exelon] Exelon Generation Company, LLC. 2015l. Letter from M.P. Gallagher, Vice President 16 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 18 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 19 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 20 Review Requests for Additional Information. Response to Request for Additional Information 21 MA-09. July 2, 2015. ADAMS No. ML15195A353. 22 [Exelon] Exelon Generation Company, LLC. 2015m. Letter from M.P. Gallagher, Vice 23 President License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

24 Response to NRC Request for Additional Information, dated May 22, 2015, Regarding the 25 LaSalle County Station, Units 1 and 2, License Renewal Application, Environmental Review. 26 Enclosure B: LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal 27 Environmental Review Requests for Additional Information. Response to Request for Additional 28 Information MA-10. July 2, 2015. ADAMS No. ML15195A354. 29 [Exelon] Exelon Generation Company, LLC. 2015n. Letter from M.P. Gallagher, Vice President 30 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 31 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 32 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 33 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 34 Review Requests for Additional Information. Response to Request for Additional Information 35 TE-02. July 2, 2015. ADAMS No. ML15195A380. 36 [Exelon] Exelon Generation Company, LLC. 2015o. Letter from M.P. Gallagher, Vice President 37 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 38 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 39 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 40 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 41 Review Requests for Additional Information. Response to Request for Additional Information 42 TE-03. July 2, 2015. ADAMS No. ML15195A381. 43 [Exelon] Exelon Generation Company, LLC. 2015p. Letter from M.P. Gallagher, Vice President 44 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Revisions to 45 LaSalle County Station, Units 1 and 2, License Renewal Application, Applicant's Environmental 46 Report - Operating License Renewal Stage. July 31, 2015. ADAMS No. ML15212A259. 3-117

Affected Environment 1 Exelon Nuclear. 2007. LaSalle County Station Units 1 and 2, Annual Radiological 2 Environmental Operating Report, 1 January Through 31 December 2006. May 2007. ADAMS 3 No. ML071410244. 4 Exelon Nuclear. 2008. LaSalle County Station Units 1 and 2, Annual Environmental Operating 5 Report, Annual Radiological Environmental Operating Report, 1 January through 6 31 December 2007. May 2008. ADAMS No. ML081420473. 7 Exelon Nuclear. 2009. LaSalle County Station Units 1 and 2, Annual Environmental Operating 8 Report, Annual Radiological Environmental Operating Report, 1 January through 9 31 December 2008. May 2009. ADAMS No. ML091350485. 10 Exelon Nuclear. 2010. LaSalle County Station Units 1 and 2, Annual Environmental Operating 11 Report, Annual Radiological Environmental Operating Report, 1 January through 12 31 December 2009. May 2010. ADAMS No. ML101320380. 13 Exelon Nuclear. 2011. LaSalle County Station Units 1 and 2, Annual Environmental Operating 14 Report, Annual Radiological Environmental Operating Report, 1 January through 15 31 December 2010. May 2011. ADAMS No. ML111320602. 16 Exelon Nuclear. 2012. LaSalle County Station Units 1 and 2, Annual Environmental Operating 17 Report, Annual Radiological Environmental Operating Report, 1 January through 18 31 December 2011. May 2012. ADAMS No. ML12130A420. 19 Exelon Nuclear. 2013. LaSalle County Station Units 1 and 2, Annual Environmental Operating 20 Report, Annual Radiological Environmental Operating Report, 1 January through 21 31 December 2012. May 2013. ADAMS No. ML13136A007. 22 Exelon Nuclear. 2014. LaSalle County Station Units 1 and 2, Annual Environmental Operating 23 Report, Annual Radiological Environmental Operating Report, 1 January through 24 31 December 2013. May 2014. ADAMS No. ML14135A214. 25 Exelon Nuclear. 2015. LaSalle County Station Units 1 and 2, Annual Environmental Operating 26 Report, Annual Radiological Environmental Operating Report, 1 January through 27 31 December 2014. May 2015. ADAMS Nos. ML15141A195 and ML15141A219. 28 Fagan BM. 2005. Ancient North America. 4th ed. London: Thames & Hudson Ltd. 568 p. 29 Farmer A, Cade S, Staufer DF. 2002. Evaluation of Habitat Suitability Index Model. In: Kurta 30 A, Kennedy J, editors. The Indiana Bat: Biology and Management of an Endangered Species. 31 Austin, TX: Bat Conservation International. pp. 172-181. 32 Federal Water Pollution Control Act (Clean Water Act) of 1972, as amended. 33 33 U.S.C. §1251 et seq. Rivers and Harbors Appropriation Act of 1899, as amended. 34 33 U.S.C. §403 Section 10. 35 [FEMA] Federal Emergency Management Agency. 2015. Earthquake hazard maps available at 36 <www.fema.gov/earthquake/earthquake-hazard-maps#0> (accessed 16 June 2015). 37 [FHA] Federal Highway Administration. 2011. Highway Traffic Noise Analysis and Abatement 38 Policy and Guidance. Available at <https://www.fhwa.dot.gov/environment/noise/ 39 regulations_and_guidance/polguide/polguide02.cfm> (accessed August 2015). 40 Fritts, MW. 2013. Email from M.W. Fritts, Illinois Natural History Survey, to P. Moore, Tetra 41 Tech.

Subject:

RE: Request: Illinois River Reports. June 24, 2013. ADAMS No. 42 ML15273A418. 3-118

Affected Environment 1 [FWS] U.S. Fish and Wildlife Service. 1990. Decurrent False Aster Recovery Plan. U.S. Fish 2 and Wildlife Service, Twin Cities, Minnesota. 26 p. Available at 3 <http://ecos.fws.gov/docs/recovery_plans/1990/900928c.pdf.> (accessed 28 August 2015). 4 [FWS] U.S. Fish and Wildlife Service. 2009. Indiana Bat (Myotis sodalis) 5-Year Review: 5 Summary and Evaluation. Midwest Region - Region 3. Available at 6 <http://www.fws.gov/midwest/endangered/recovery/5yr_rev/pdf/INBA5Yr30Sept2009.pdf.> 7 (accessed 28 August 2015). 8 [FWS] U.S. Fish and Wildlife Service. 2011. A National Plan for Assisting States, Federal 9 Agencies, and Tribes in Managing White-Nose Syndrome in Bats. Hadley, MA: FWS. 10 May 2011. 21 p. Available at <http://static.whitenosesyndrome.org/sites/default/files/ 11 white-nose_syndrome_national_plan_may_2011.pdf> (accessed 22 August 2013). 12 [FWS] U.S. Fish and Wildlife Service. 2012a. 2011 Rangewide Population Estimate for the 13 Indiana Bat (Myotis sodalis) by USFWS Region. ADAMS No. ML14265A502. 14 [FWS] U.S. Fish and Wildlife Service. 2012b. Decurrent False Aster (Boltonia decurrens) 15 5-Year Review: Summary and Evaluation 2012. Midwest Region. Available at 16 <http://www.fws.gov/midwest/endangered/plants/5yrreviews/Boltonia5YrRev2012.pdf.> 17 (accessed 28 August 2015). 18 [FWS] U.S. Fish and Wildlife Service. 2013a. USFWS: Eastern Prairie Fringed Orchid 19 (Platanthera leucophaea) Fact Sheet. July 9, 2013. Available at 20 <http://www.fws.gov/midwest/endangered/plants/epfo.html> (accessed 18 December 2013). 21 [FWS] U.S. Fish and Wildlife Service. 2013b. USFWS: Endangered Species: Sheepnose 22 Mussel (Plethobasus cyphyus). January 3, 2013. Available at 23 <http://www.fws.gov/midwest/endangered/clams/sheepnose/> (accessed 20 December 2013). 24 [FWS] U.S. Fish and Wildlife Service. 2013c. White-Nose Syndrome Confirmed in Illinois Bats: 25 Illinois becomes 20th state in U.S. to confirm deadly disease in bats. Midwest Region. 26 November 4, 2013. Available at <http://www.fws.gov/midwest/news/621.html.> (accessed 27 1 September 2015). 28 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 29 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 30 September 30, 2015. Available at <http://www.fws.gov/midwest/endangered/lists/illinois-31 cty.html> (accessed 9 October 2015). 32 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC.

Subject:

LaSalle 33 Power Plant License Renewal. List of threatened and endangered species that may occur in 34 your proposed project location, and/or may be affected by your proposed project. 35 February 27, 2015. ADAMS ML15126A069. 36 [FWS] U.S. Fish and Wildlife Service. 2015c. Letter from L. Nelson, Regional Environmental 37 Officer, FWS, to D. Wrona, NRC. May 8, 2015. ADAMS No. ML15131A004. 38 [FWS] U.S. Fish and Wildlife Service. 2015d. Letter from Rock Island Ecological Services 39 Field Office, FWS, to NRC.

Subject:

List of threatened and endangered species that may occur 40 in your proposed project location, and/or may be affected by your proposed project. 41 February 27, 2015. ADAMS No. ML15126A069. 42 [FWS] U.S. Fish and Wildlife Service. 2015e. National Wetlands Inventory Wetlands Mapper. 43 Available at <http://www.fws.gov/wetlands/Data/Mapper.html> (accessed 10 March 2015). 3-119

Affected Environment 1 [HDR] HDR Engineering, Inc. 2010. Zebra Mussel Monitoring Program at LaSalle Nuclear 2 Station, 2009. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2010. Woodstock, 3 Illinois. ADAMS No. ML15273A421. 4 [HDR] HDR Engineering, Inc. 2011. Zebra Mussel Monitoring Program at LaSalle Nuclear 5 Station, 2010. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2011. Woodstock, 6 Illinois. ADAMS No. ML15273A422. 7 [HDR] HDR Engineering, Inc. 2012. Zebra Mussel Monitoring Program at LaSalle Nuclear 8 Station, 2011. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2012. Woodstock, 9 Illinois. ADAMS No. ML15273A440. 10 [HDR] HDR Engineering, Inc. 2013. Zebra Mussel Monitoring Program at LaSalle Nuclear 11 Station, 2012. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2013. Woodstock, 12 Illinois. ADAMS No. ML15273A441. 13 [HDR] HDR Engineering, Inc. 2014. Zebra Mussel Monitoring Program at LaSalle Nuclear 14 Station, 2013. Prepared for Exelon Nuclear, Warrenville, Illinois. February 2014. Woodstock, 15 Illinois. ADAMS No. ML15273A442. 16 [HUD] U.S. Department of Housing and Urban Development. 2014. Noise and Abatement 17 Control. Available at <https://www.hudexchange.info/environmental-review/noise-abatement-18 and-control/> (accessed 15 July 2015). 19 [IDNR] Illinois Department of Natural Resources. 2005. The Illinois Comprehensive Wildlife 20 Conservation Plan & Strategy. Version 1.0. July 11, 2005. 380 p. Available at 21 <http://www.dnr.illinois.gov/conservation/IWAP/Documents/WildlifeActionPlanFinal.pdf> 22 (accessed 9 March 2015). 23 [IDNR] Illinois Department of Natural Resources. 2007. Status of the Catfish Fishery. Illinois 24 Department of Natural Resources, Division of Fisheries. March 2007. Available at 25 <http://www.dnr.state.il.us/orc/fisheries/07/07%20catfish%20status%20report.pdf> (accessed 26 21 May 2015). 27 [IDNR] Illinois Department of Natural Resources. 2009. Status of the Striped Bass/Hybrid 28 Striped Bass Fishery. Illinois Department of Natural Resources, Division of Fisheries. 29 March 2009. Available at 30 <http://www.prairiestateoutdoors.com/images/uploads/2009_Striped_Bass_Status.pdf> 31 (accessed 21 May 2015). 32 [IDNR] Illinois Department of Natural Resources. 2011a. Illinois Rivers and Lakes, Fact 33 Sheets. Illinois Department of Natural Resources, Aquatic Illinois, DNR158-6/12. Available at 34 <http://dnr.state.il.us/education/aquatic/aquaticillinoisrivlakefactshts.pdf> (accessed 35 10 September 2015). 36 [IDNR] Illinois Department of Natural Resources. 2011b. State of Illinois Coastal Management 37 Program. Available at <http://www.dnr.illinois.gov/cmp/Documents/ICMPPD.pdf> (accessed 38 6 March 2015). 39 [IDNR] Illinois Department of Natural Resources. 2014a. Illinois Natural Areas Inventory (INAI) 40 Sites. October 2014. Available at <http://dnr.state.il.us/conservation/ 41 naturalheritage/Documents/INAI_by_County.pdf> (accessed 10 March 2015). 42 [IDNR] Illinois Department of Natural Resources. 2014b. Illinois Threatened and Endangered 43 Species By County. Updated October 2014. Available at 44 <http://www.dnr.illinois.gov/ESPB/Documents/ET_by_County.pdf> (accessed 9 March 2015). 3-120

Affected Environment 1 [IDNR] Illinois Department of Natural Resources. 2014c. Letter from S.R. Fairfield, Impact 2 Assessment Section, to M.P. Gallagher, Vice President License Renewal, Exelon Nuclear. Re: 3 Renewal of Facility Operating Licenses by the U.S. Nuclear Regulatory Commission (NRC) for 4 LaSalle Generating Station, Units 1 and 2 - Correspondence dated March 7, 2014 County: 5 LaSalle. May 22, 2014. In Appendix D of Exelon 2014a. 6 [IDNR] Illinois Department of Natural Resources. 2015a. Checklist of Illinois Endangered and 7 Threatened Animals and Plants, Illinois Endangered Species Protection Board. May 19, 2015. 8 Available at <http://www.dnr.illinois.gov/ESPB/Documents/2015_ChecklistFINAL_for_webpage 9 _051915.pdf> (accessed 15 October 2015). 10 [IDNR] Illinois Department of Natural Resources. 2015b. Illini State Park. Available at 11 <http://dnr.state.il.us/lands/Landmgt/parks/i&m/east/illini/park.htm> (accessed 10 March 2015). 12 [IDNR] Illinois Department of Natural Resources. 2015c. Illinois Coastal Management 13 Program Boundaries. Available at <http://www.dnr.illinois.gov/cmp/Pages/boundaries.aspx> 14 (accessed 6 March 2015). 15 [IDNR] Illinois Department of Natural Resources. 2015d. Marseilles State Fish and Wildlife 16 Area. Available at <http://dnr.state.il.us/lands/Landmgt/parks/r1/MARSEIL.HTM> (accessed 17 15 October 2015). 18 [IDNR] Illinois Department of Natural Resources. 2015e. Marseilles State Fish & Wildlife Area 19 (Upland) Hunter Fact Sheet. Available at 20 <http://www.dnr.illinois.gov/hunting/FactSheets/Pages/MarseillesStateFishWildlifeAreaUpland.a 21 spx> (accessed 6 March 2015). 22 [IDNR and Exelon] Illinois Department of Natural Resources and Exelon Generation Company, 23 LLC. 2014. IDNR and Exelon Meeting Notes, Review of Braidwood, Clinton and LaSalle, Lake 24 Fishery and Land Management Plans. March 5, 2014. ADAMS No. ML15195A368. 25 [IDNR and Exelon] Illinois Department of Natural Resources and Exelon Generation Company, 26 LLC. 2015. IDNR and Exelon Meeting Notes, Review of Braidwood, Clinton and LaSalle, Lake 27 Fishery and Land Management Plans. March 4, 2015. ADAMS No. ML15195A368. 28 [IDPH] Illinois Department of Public Health. 2009. Salmonella. January 2009. Available at 29 <http://www.idph.state.il.us/public/hb/hbsam.htm> (accessed 23 October 2013). 30 [IDPH] Illinois Department of Public Health. 2013. Shigellosis Healthbeat. Available at 31 <http://www.idph.state.il.us/public/hb/hbshigellosis.htm> (accessed 23 October 2013). 32 [IDPH] Illinois Department of Public Health. 2014. Email from K. Marshall, IDPH, to N. Ranek, 33 Exelon,

Subject:

RE: LaSalle County Station Units 1 and 2- Consultation about thermophilic 34 organisms. February 19, 2014. ADAMS No. ML15273A445. 35 [IEPA] Illinois Environmental Protection Agency. 1987. Field and Laboratory Methods Manual: 36 Section C, Macroinvertebrate Monitoring. IEPA. Springfield, IL. 55 p. 37 [IEPA] Illinois Environmental Protection Agency. 2000. Federally Enforceable State Operating 38 Permit for LaSalle County Generating Station No. 75040086. December 11, 2000. ADAMS 39 No. ML15195A419. 40 [IEPA] Illinois Environmental Protection Agency. 2013. NPDES Permit No. IL0048151, National 41 Pollutant Discharge Elimination System, Reissued (NPDES) Permit. Exelon Generation 42 Company, LLC, LaSalle County Generating Station. Effective date, August 1, 2013. 43 Springfield, IL: Division of Water Pollution Control. In: LaSalle County Station, Units 1 and 2, 44 License Renewal Application, Appendix E, Applicants Environmental Report, Operating License 45 Renewal Stage. ADAMS No. ML14343A897 (Appendix C). 3-121

Affected Environment 1 [IEPA] Illinois Environmental Protection Agency. 2014a. Email from G. Good, IEPA, to 2 N. Ranek, Exelon.

Subject:

RE: LaSalle County Station Units 1 and 2- Consultation about 3 thermophilic organisms. February 19, 2014. ADAMS No. ML15273A446. 4 [IEPA] Illinois Environmental Protection Agency. 2014b. Illinois Integrated Water Quality 5 Report and Section 303(d) List, 2014 - Volume I: Surface Water, Appendix A-1, Illinois' 2014 6 303(d) List and Prioritization, Appendix A-5, 2014 Illinois Water Quality Maps, Appendix B-2, 7 Specific Assessment Information for Streams, 2014, Appendix B-3, Specific Assessment 8 Information for Lakes, 2014. Illinois Environmental Protection Agency, Bureau of Water. 9 March 2014. (Final submitted to USEPA Region 5.) Available at 10 <http://www.epa.illinois.gov/topics/water-quality/watershed-management/tmdls/303d-list> 11 (accessed 21 August 2015). 12 [IEPA] Illinois Environmental Protection Agency. 2014c. Letter from A. Keller, Manager, Permit 13 Section, Division of Water Pollution Control, to U.S. Nuclear Regulatory Commission, Division of 14 License Renewal- Office of Nuclear Reactor Regulation.

Subject:

Exelon Generation Company 15 (LaSalle County Station), Renewal of Nuclear Regulatory Commission Operating Licenses for 16 Exelon LaSalle Station Units I and 2 (NPF-11 and NPF-18), Log # C-0054-14 [NPF-11 17 and NPF-18]. December 29, 2014. ADAMS No. ML15022A325. 18 [IEPA] Illinois Environmental Protection Agency. 2015. Illinois Permit Database, All Permit 19 Records: Available at <http://www.epa.gov/reg5oair/permits/ilonline.html> (accessed 20 10 July 2015). 21 [Illinois DOT] Illinois Department of Transportation. 2012. The Illiana Expressway Corridor - 22 Historic and Forecasted Growth of Employment and Population in the Extended Region of 23 Chicago. Market-Driven versus Policy-Based Socio-Economic Forecasts (2010-2040), No-Build 24 Illiana Expressway Scenario. February 2012. Available at 25 <http://www.idot.illinois.gov/Assets/uploads/files/Transportation-26 System/Reports/Desenv/Enviromental/Illiana/Appendix%20E1%20-27 %20%20Historic%20and%20Forecasted%20Growth%20of%20Employment%20and%20Popula 28 tion%20February%202012.pdf> (accessed October 2015). 29 [Illinois DOT] Illinois Department of Transportation. 2015. Getting Around Illinois - 2013-2014 30 Annual Average Daily Traffic. Map. Available at 31 <http://www.gettingaroundillinois.com/default.htm> (accessed October 2015). 32 [IHPA] Illinois Historic Preservation Agency. 2013. National Register of Historic Places in 33 Illinois. 50 p. Available at <http://www.illinois.gov/ihpa/Preserve/SiteAssets/Pages/Places/ 34 National%20Register%20Properties%20in%20Illinois.pdf> (accessed 28 August 2015). 35 Illinois Environmental Protection Act of 1970. 415 ILCS 5/Title VI. Illinois Compiled Statutes. 36 Chapter 415, 5, Noise. 37 [ISGS] Illinois State Geological Survey. 2015. Illinois Water Well (ILWATER) Interactive Map. 38 Available at <http://maps.isgs.illinois.edu/ilwater/> (accessed 13 July 2015). 39 [ISM] Illinois State Museum. 2002. Native Americans: American Indian Tribes of Illinois. 40 October 2, 2002. Available at 41 <http://www.museum.state.il.us/muslink/nat_amer/post/index.html> (accessed 15 June 2015). 42 [ISWS] Illinois State Water Survey. 2015a. Water Supply Planning. Illinois State Water 43 Survey, Prairie Research Institute University of Illinois at Urbana-Champaign. Available at 44 <http://www.isws.illinois.edu/wsp> (accessed 21 August 2015). 3-122

Affected Environment 1 [ISWS] Illinois State Water Survey. 2015b. Illinois Water Inventory Program. Illinois State 2 Water Survey, Prairie Research Institute University of Illinois at Urbana-Champaign. Available 3 at <http://www.isws.illinois.edu/gws/iwip/> (accessed 21 August 2015). 4 Kanter R. Environmental Almanac: Rare mussel found in Illinois River. News Gazette. 5 Sunday, July 7, 2013. 6 LaSalle County. 2014. LaSalle County Comprehensive Plan, LaSalle County, Illinois. 7 Available at <http://www.lasallecounty.org/envsvcs/lccp-2014.pdf> (accessed 11 May 2015). 8 Lerczak TV, Sparks RE, Blodgett, KD. 1994. The Long Term Illinois River Fish Population 9 Monitoring Program: Final Report. Project F-101-R. Illinois Natural History Survey. River 10 Research Laboratory. Havana, IL. June 1994. Available at 11 <https://www.ideals.illinois.edu/bitstream/handle/2142/10575/inhscaev01994i00006_opt.pdf?se 12 quence=2> (accessed 19 March 2015). 13 Lerczak TV. 1996. Illinois River Fish Communities: 1960s vs. 1990s. Illinois Natural History 14 Survey. April 4, 1996. Available at <http://wwx.inhs.illinois.edu/resources/inhsreports/may-15 jun96/fish/> (accessed 19 March 2015). 16 Magnuson-Stevens Fishery Conservation and Management Act, as amended. 17 16 U.S.C. §1801 et seq. 18 Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. §1361 et seq. 19 [Maryland DNR] Maryland Department of Natural Resources. 2015. Maryland Fish Facts, 20 American Gizzard Shad. Available at <http://dnr2.maryland.gov/Fisheries/Pages/Fish-21 Facts.aspx?fishname=American%20Gizzard%20Shad> (accessed 29 October 2015). 22 McClelland MA, Sass GG. 2007. The Long-Term Illinois River Fish Population Monitoring 23 Program, Project F-101-R-18. Illinois Natural History Survey. River Research Laboratory. 24 Havana, IL. April 2007. Available at 25 <https://www.ideals.illinois.edu/bitstream/handle/2142/48748/INHS2007_24.pdf?sequence=2> 26 (accessed 20 August 2015). 27 McClelland MA, Sass GG, Cook TR, Irons KS, Michaels NM, OHara NM, Smith CS. 2012. The 28 Long-Term Illinois River Fish Population Monitoring Program. Fisheries 37(8): 340-350. 29 Mid-America Earthquake Center. 2009. New Madrid Seismic Zone Catastrophic Earthquake 30 Response Planning ProjectImpact of New Madrid Seismic Zone Earthquakes on the Central 31 USA, Volume I. October 2009. Available at 32 <https://www.ideals.illinois.edu/bitstream/handle/2142/14810/ImpactofNewMadridSeismicZone 33 Earthquakeso%20theCentral%20USAVol1.pdf?sequence=3> (accessed 11 May 2015). 34 Migratory Bird Treaty Act of 1918, as amended. 16 U.S.C. §703 et seq. 35 [Minnesota DNR] Minnesota Department of Natural Resources. 2014. Species Profile: Rare 36 Species Guide: Spike (Elliptio dilatata). Available at <http://www.dnr.state.mn.us/rsg/ 37 profile.html?action=elementDetail&selectedElement=IMBIV14100> (accessed 7 April 2014). 38 [Mississippi DNR] Mississippi Department of Natural Resources. 2015. Step in Establishing 39 Indicators. Available at <http://www.dakotaswcd.org/pdfs/Final%20Indicators%20MDNR.pdf> 40 (accessed 29 October 2015). 41 Missouri Department of Natural Resources. 2013. The New Madrid Seismic Zone, Division of 42 Geology and Land Survey Fact Sheet Number 26. January 2013. Available at 43 <http://www.dnr.mo.gov/pubs/pub2465.pdf> (accessed 11 May 2015). 3-123

Affected Environment 1 Moore BC, Martinez E, Gay JM, Rice DH. 2003. Survival of Salmonella enterica in freshwater 2 and sediments and transmission by the aquatic midge Chironomus tentans (Chironomidae: 3 Diptera). Applied and Environmental Microbiology 69(8):4556-4560. Available at 4 <http://www.ncbi.nlm.nih.gov/pmc/articles/PMC169145/> (accessed 23 October 2013). 5 [NASS] National Agricultural Statistics Service, U.S. Department of Agriculture. 2015. 2012 6 Census of Agriculture, Volume 1, Chapter 2, County Level, Table 7. Hired Farm Labor - 7 Workers and Payroll: 2012. 2012 Census of Agriculture, Volume 1 Chapter 2, County Level 8 Data for Illinois. Last modified: 4/15/2014. Available at 9 <http://www.agcensus.usda.gov/Publications/2012/Full_Report/Census_by_State/> (accessed 10 October 2015). 11 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 12 [NatureServe] NatureServe Explorer. 2014a. Moxostoma carinatum. Available at 13 <http://explorer.natureserve.org> (accessed 7 April 2014). 14 [NatureServe] NatureServe Explorer. 2014b. Elliptio dilatata. Available at 15 <http://explorer.natureserve.org> (accessed 7 April 2014). 16 [NCES] National Center for Education Statistics. 2015a. College Navigator. U.S. Department 17 of Education, Washington, D.C. College and university student population within 50 mi of ZIP 18 code 61341. Released July 2015. Available at 19 <http://nces.ed.gov/collegenavigator/default.aspx> (accessed October 2015). 20 [NCES] National Center for Education Statistics. 2015b. Grundy County, LaSalle County and 21 Will County Public and Private School Districts. 2013-2014 school year. Available at 22 <http://nces.ed.gov/ccd/districtsearch/> (accessed October 2015). 23 [NCDC] National Climatic Data Center. 2004. Climate of Illinois. Available at 24 <http://www.crh.noaa.gov/Image/dvn/downloads/Clim_IL_01.pdf> (accessed 10 July 2015) 25 [NCDC] National Climatic Data Center. 2015a. Local Climatological Data Annual Summary 26 with Comparative Data, Peoria, Illinois (KPIA). Available at 27 <http://www.ncdc.noaa.gov/IPS/lcd/lcd.html> (accessed 14 July 2015). 28 [NCDC] National Climatic Data Center. 2015b. Storm Events Database, LaSalle County. 29 Available at <https://www.ncdc.noaa.gov/stormevents/> (accessed 10 July 2015). 30 [NEI] Nuclear Energy Institute. 2007. Industry Ground Water Protection Initiative - Final 31 Guidance Document. Washington, DC: NEI. NEI 07-07. August 2007. ADAMS 32 No. ML072600295. 33 Neusius SW, Gross GT. 2007. Seeking Our Past: An Introduction to North American 34 Archaeology. New York, NY: Oxford University Press, Inc. 720 p. 35 Noise Control Act of 1972. 42 U.S.C. §4901 et seq. 36 [NRC] U.S. Nuclear Regulatory Commission. 1978. Final Environmental Statement Related to 37 Operation of LaSalle County Nuclear Power Station Unit Nos. 1 and 2. Washington, DC: NRC. 38 NUREG-0486. November 1978. ADAMS No. ML14353A388. 39 [NRC] U.S. Nuclear Regulatory Commission. 1999. Generic Environmental Impact Statement 40 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Volume 1, 41 Addendum 1. August 1999. 3-124

Affected Environment 1 [NRC] U.S. Nuclear Regulatory Commission. 2012. Letter from E.J. Leeds, Director, Office 2 Nuclear Reactor Regulation, and MJ Johnson, Director, Office of New Reactors to All Power 3 Reactor Licensees and Holders of Construction Permits in Active or Deferred Status.

Subject:

4 Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) 5 Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review of Insights 6 from the Fukushima Dai-ichi Accident. March 12, 2012. ADAMS No. ML12053A340. 7 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 8 for License Renewal of Nuclear Plants. Revision 1. Washington, DC: NRC. NUREG-1437, 9 Volumes 1, 2, and 3. June 2013. 1,535 p. ADAMS No. ML13107A023. 10 [NRC] U.S. Nuclear Regulatory Commission. 2014a. Letter from E.J. Leeds, Director, Office 11 Nuclear Reactor Regulation to All Power Reactor Licensees and Holders of Construction 12 Permits in Active or Deferred Status.

Subject:

Seismic Screening and Prioritization Results 13 Regarding Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) 14 Regarding Seismic Hazard Reevaluations for Recommendation 2.1 of the Near-Term Task 15 Force Review of Insights from the Fukushima Dai-ichi Accident. May 9, 2014. ADAMS 16 No. ML14111A147. 17 [NRC] U.S. Nuclear Regulatory Commission. 2014b. Occupational Radiation Exposure at 18 Commercial Nuclear Power Reactors and Other Facilities 2012: Forty-Fifth Annual Report. 19 Washington, DC: NRC. NUREG-0713, Volume 34, April 2014. ADAMS No. ML14126A597. 20 [NRC] U.S. Nuclear Regulatory Commission. 2014c. Probabilistic Seismic Hazard Analysis: 21 Background Information. May 20, 2014. ADAMS No. ML14140A648. 22 [NRC] U.S. Nuclear Regulatory Commission. 2015a. LaSalle County Station, Units 1 and 2 23 Staff Assessment of Information Provided Pursuant to Title 10 of the Code of Federal 24 Regulations Part 50, Section 50.54(F), Seismic Hazard Reevaluations for Recommendation 2.1 25 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident 26 (TAC Nos. MF3881 AND MF3882). April 21, 2015. ADAMS No. ML15013A132. 27 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Memorandum from B. Wittick, Chief, 28 Projects Branch 2, Division of License Renewal, Office of Nuclear Reactor Regulation, to 29 M.P. Gallagher, Vice President, License Renewal Projects, Exelon Generation Company, LLC. 30

Subject:

Summary of the License Renewal Environmental Audit for LaSalle County Station, 31 Units 1 And 2. May 20, 2015. 5 p. ADAMS No. ML15132A674. 32 [NRC] U.S. Nuclear Regulatory Commission. 2015c. Note to File: Summary of Visit to Illinois 33 Historic Preservation Agency Associated with the LaSalle County Station, Units 1 and 2, 34 License Renewal Application Environmental Audit, May 2015. ADAMS No. ML15205A286. 35 Nyboer RW, Herkert JR, Ebinger JE, editors. 2006. Endangered and Threatened Species of 36 Illinois: Status and Distribution, Volume 2 - Animals. Illinois Endangered Species Protection 37 Board, Springfield, Illinois. 181 p. Available at 38 <https://www.dnr.illinois.gov/ESPB/Pages/Publications.aspx> (accessed 20 August 2015). 39 Occupational Safety and Health Act of 1970, as amended. 29 U.S.C. §651 et seq. 40 [OEPA] Ohio Environmental Protection Agency. 1987. Biological Criteria for the Protection of 41 Aquatic Life. Ohio Environmental Protection Agency. July 1987. Columbus, Ohio. Available at 42 http://www.epa.state.oh.us/Portals/35/documents/Vol1.pdf (accessed on 26 October 2015). 43 [OSHA] Occupational Safety and Health Administration. 2008. OSHA Directive 44 CSP 03-01-003, Voluntary Protection Programs (VPP): Policies and Procedures Manual, 45 April 18, 2008, at page 7. Available at <https://www.osha.gov/OshDoc/Directive_pdf/CSP_03-46 01-003.pdf> (accessed May 29, 2015). 3-125

Affected Environment 1 [OSHA] Occupational Safety and Health Administration. 2015a. OSHA Voluntary Protection 2 Programs, Current Federal and State Plan Sites. Available at 3 <https://www.osha.gov/dcsp/vpp/sitebystate.html> (accessed May 29, 2015). 4 [OSHA] Occupational Safety and Health Administration. 2015b. Voluntary Protection 5 Programs. Available at <https://www.osha.gov/dcsp/vpp/> (accessed May 29, 2015). 6 Osmond DL, Line DE, Gale JA, Gannon RW, Knott CB, Bartenhagen KA, Turner MH, Coffey 7 SW, Spooner J, Wells J, Walker JC, Hargrove LL, Foster MA, Robillard PD, Lehning DW. 1995. 8 WATERSHEDSS: Water, Soil and Hydro-Environmental Decision Support System 9 <http://www.water.ncsu.edu/watershedss/info/aqlife.html> (accessed 28 October 2015). 10 Ottawa Area Chamber of Commerce & Industry. 2009. Community Profile Overview - Major 11 Industries. Available at <http://www.ottawaindustrialpark.com/comm-profile.html> (accessed 12 October 2015). 13 Parmalee PW, Bogan AE. 1998. Freshwater Mussels of Tennessee. University of Tennessee 14 Press, Knoxville, Tennessee. 15 Pauketat TR. 1993. A Guide to the Prehistory and Native Cultures of Southwestern Illinois and 16 the Greater St. Louis Area. Illinois Archaeological Educational Series No. 2. Springfield, IL: 17 Illinois Historic Preservation Agency. 60 p. 18 Pearson WE. 2003. Legionella 2003: An Update and Statement by the Association of Water 19 Technologies (AWT). Rockville, MD: Association of Water Technologies. June 2003. 33 p. 20 Available at <http://awt.org/IndustryResources/Legionella03.pdf> (accessed 21 October 2013). 21 Pruitt L, TeWinkel L, editors. 2007. Indiana Bat (Myotis sodalis) Draft Recovery Plan. 22 First Revision. Fort Snelling, MN: U.S. Fish and Wildlife Service. April 2007. 258 p. Available 23 at <http://ecos.fws.gov/docs/recovery_plan/070416.pdf> (accessed 26 September 2013). 24 [RESA] Will Regional Educational Service Agency. 2014. Districts and PSA [Public School 25 Academies]. Available at <http://www.resa.net/aboutus/districts/> (accessed December 2014). 26 Rivers and Harbors Appropriation Act of 1899. 33 U.S.C. §403 Section 10. 27 Sietman BE, Whitney SD, Kelner DE, Blodgett DK, Dunn HL. Post-Extirpation Recovery of the 28 Freshwater Mussel (Bivalve: Unionidea) Fauna in the Upper Illinois River. Journal of 29 Freshwater Ecology 16(2):273-281. 30 Smith PW. 2002. The Fishes of Illinois. University of Illinois Press, Urbana and Chicago, IL. 31 Smith M, Caswell H, Mettler-Cherry P. 2005. Stochastic flood and precipitation regimes and 32 the dynamics of a threatened floodplain plant. Ecological Applications 15(3):1036-1052. 33 State of Illinois. 2006. 2006-01 Executive Order for the Development of State and Regional 34 Water-Supply Plans. Executive Department. January 9, 2006. Available at 35 <http://www.illinois.gov/Government/ExecOrders/Documents/2006/execorder2006-1.pdf> 36 (accessed 21 August 2015). 37 Stevens AR, Tyndall RL, Coutant CC, Willaert E. 1977. Isolation of the etiological agent of 38 primary amoebic meningoencephalitis from artificially heated waters. Applied and 39 Environmental Microbiology 34(6):701-705. Available at 40 <http://aem.asm.org/content/34/6/701.full.pdf+html> (accessed 23 October 2013). 41 Talkington, LM. 1991. The Illinois River--Working for our State. Champaign, IL: Illinois State 42 Water Survey. January 1991. Miscellaneous Publication 128. Available at 43 <http://www.isws.illinois.edu/pubdoc/MP/ISWSMP-128.pdf> (accessed 21 August 2015). 3-126

Affected Environment 1 [Teledyne] Teledyne Brown Engineering Environmental Services. 2011. LaSalle County 2 Station, 2010 Annual Radiological Environmental Operating Report, 1 January through 3 31 December 2010. Marseilles, IL: Exelon Nuclear. May 12, 2011. ADAMS 4 No. ML111320602. 5 [Teledyne] Teledyne Brown Engineering Environmental Services. 2012. LaSalle County 6 Station, 2011 Annual Radiological Environmental Operating Report, 1 January through 7 31 December 2011. Marseilles, IL: Exelon Nuclear. May 9, 2012. ADAMS No. ML12130A420. 8 [Teledyne] Teledyne Brown Engineering Environmental Services. 2013. LaSalle County 9 Station, 2012 Annual Radiological Environmental Operating Report, 1 January through 10 31 December 2012. Marseilles, IL: Exelon Nuclear. May 15, 2013. ADAMS 11 No. ML13136A007. 12 [Teledyne] Teledyne Brown Engineering Environmental Services. 2014. LaSalle County 13 Station, 2013 Annual Radiological Environmental Operating Report, 1 January through 14 31 December 2013. Marseilles, IL: Exelon Nuclear. May 15, 2014. ADAMS 15 No. ML14135A214. 16 [Teledyne] Teledyne Brown Engineering Environmental Services. 2015. LaSalle County 17 Station, 2014 Annual Radiological Environmental Operating Report, 1 January through 18 31 December 2014. Marseilles, IL: Exelon Nuclear. May 13, 2015. ADAMS No. ML15141A19. 19 Todar K. 2004. Todars Online Textbook of Bacteriology. University of Wisconsin, 20 Department of Bacteriology. Available at <http://textbookofbacteriology.net/index.html> 21 (accessed 23 October 2013). 22 [USACE] United States Army Corps of Engineers. 1998. Illinois Waterway Navigational Charts. 23 Available at <http://www2.mvr.usace.army.mil/NIC2/ilwwcharts.cfm> (assessed on 24 8 September 2015). 25 [USACE] U.S. Army Corps of Engineers. 2006. Department of the Army Permit, CEMVR 26 OD-P-2006-185. Issued to Exelon Generating Company, LLC. U.S. Army Corps of Engineers, 27 Rock Island District. Issued April 12, 2006; expiration 31 December 2015. ADAMS 28 No. ML15195A399. 29 [USACE] U.S. Army Corps of Engineers. 2012. Illinois Waterway Locks & Dams. Available at 30 <http://www.mvr.usace.army.mil/Portals/48/docs/CC/FactSheets/IL/Illinois_Waterway_Locksand 31 Dams%20(2012).pdf> (accessed 6 March 2015). 32 [USACE] U.S. Army Corps of Engineers. 2014. Marseilles Lock & Dam. Rock Island, IL: Rock 33 Island District. October 2014. Available at 34 <http://www.mvr.usace.army.mil/Missions/Navigation/MarseillesLockandDam.aspx> (accessed 35 21 August 2015). 36 [USCB] U.S. Census Bureau. 2015a. American FactFinder, American Community Survey, 37 Table DP03 - Selected Economic Characteristics, 2014, 1-Year Estimates for LaSalle and Will 38 Counties, Illinois, and 2009-2013, 5-Year Estimates, for Grundy, County, Illinois. Available at 39 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015). 3-127

Affected Environment 1 [USCB] U.S. Census Bureau. 2015b. American FactFinder, 2014 American Community 2 Survey 1-Year Estimates for Illinois and LaSalle and Will Counties, Table S1701 - Poverty 3 Status in the Past 12 Months, Table S1702 - Poverty Status in the Past 12 Months of 4 Families, Table B19013 - Median Household Income in the Past 12 Months (In 2014 5 Inflation-Adjusted Dollars), and Table B19301 - Per Capita Income in the Past 12 Months (In 6 2014 Inflation-Adjusted Dollars). American FactFinder, 2011-2013 American Community 7 Survey 3-Year Estimates for Grundy, County, Illinois, Table DP05 - ACS Demographic and 8 Housing Estimates, Table S1701 - Poverty Status in the Past 12 Months, Table S1702 - 9 Poverty Status in the Past 12 Months of Families, Table B19013 - Median Household Income 10 in the Past 12 Months (In 2013 Inflation-Adjusted Dollars), and Table B19301 - Per Capita 11 Income in the Past 12 Months (In 2013 Inflation-Adjusted Dollars). Available at 12 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015). 13 [USCB] U.S. Census Bureau. 2015c. American FactFinder, 2014 American Community 14 Survey 1-Year Estimates for Illinois and LaSalle and Will Counties, Table S2301 - 15 Employment Status, and 2011-2013 American Community Survey 3-Year Estimates for 16 Grundy, County, Illinois, Table S2301 - Employment Status. Available at 17 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015). 18 [USCB] U.S. Census Bureau. 2015d. American FactFinder, 1980 - 2010 Decennial Census: 19 1900 to 1990; Table DP Profile of General Demographic Characteristics: 2000, and Table 20 DP Profile of General Population and Housing Characteristics: 2010 for Grundy, LaSalle, 21 and Will Counties Illinois. Available at 22 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015). 23 [USCB] U.S. Census Bureau. 2015e. American FactFinder, 2010 Census Summary File 1, 24 Table DP Profile of General Population and Housing Characteristics: 2010. Available at 25 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015). 26 [USCB] U.S. Census Bureau. 2015f. American FactFinder, 2014 American Community Survey 27 1-Year Estimates for Illinois and LaSalle and Will Counties, Table PEPSR6H - Annual 28 Estimates of the Residential Population by Sex, Race, and Hispanic Origin for the United 29 States, and Counties: April 1, 2010 to July 1, 2014 - 2014 Population Estimates, and 30 2011-2013 American Community Survey 3-Year Estimates for Grundy, County, Illinois, Table 31 DP05 - ACS Demographic and Housing Estimates. Available at 32 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015). 33 [USCB] U.S. Census Bureau. 2015g. American FactFinder, 2009-2013 American Community 34 Survey 5-Year Estimates, Table 25001 - Housing Units and Table B25004 - Vacancy 35 Status. Available at <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed 36 October 2015). 37 [USCB] U.S. Census Bureau. 2015h. American FactFinder, 2014 American Community 38 Survey 1-Year Estimates for LaSalle and Will Counties, Table DP04 - Selected Housing 39 Characteristics, and 2011-2013 American Community Survey 3-Year Estimates for Grundy, 40 County, Illinois, Table DP04 - Selected Housing Characteristics. Available at 41 <http://factfinder2.census.gov/faces/nav/jsf/pages/index.xhtml> (accessed October 2015). 42 [USDA] U.S. Department of Agriculture. 2008. Soil Survey of LaSalle County, Illinois. 43 Available at 44 <http://www.nrcs.usda.gov/Internet/FSE_MANUSCRIPTS/illinois/IL099/0/La_Salle_IL.pdf> 45 (accessed 11 May 2015). 3-128

Affected Environment 1 [USDA] U.S. Department of Agriculture. 2015a. CropScape - Cropland Data Layer. 2014 2 Cropland Data Layer Statistics for LaSalle, Illinois. Available at 3 <http://nassgeodata.gmu.edu/CropScape/> (accessed October 2015). 4 [USDA] U.S. Department of Agriculture. 2015b. Custom Soil Resource Report for LaSalle 5 County, Illinois. National Resources Conservation Service. Available at 6 <http://websoilsurvey.nrcs.usda.gov/app/WebSoilSurvey.aspx> (accessed 5 January 2015). 7 [USFS] U.S. Forest Service. undated a. Threatened, Endangered, and Proposed (TEP) Plant 8 Profile: Dalea foliosa, Leafy Prairie-Clover. Available at 9 <http://www.fs.fed.us/wildflowers/Rare_Plants/profiles/TEP/dalea_foliosa/index.shtml> 10 (accessed 3 January 2013). 11 [USFS] U.S. Forest Service. undated b. Celebrating Wildflowers: Contributing to the 12 Recovery of Leafy Prairie-Clover in Northeastern Illinois by Growing Plants from Seed and 13 Planting in Restored Dolomite Prairie Habitat. Available at 14 <http://www.fs.fed.us/wildflowers/Rare_Plants/conservation/success/ 15 dalea_foliosa_recovery.shtml> (accessed 3 January 3 2013). 16 [USGS] U.S. Geological Survey. 1994. National Water Quality Assessment Program, The 17 Lower Illinois River Basin. Urbana, IL: U.S. Geological Survey. USGS FS 94-018. Page dated 18 June 1994. Available at <http://il.water.usgs.gov/proj/lirb/pubs/factsheet.html#head1> 19 (accessed 21 August 2015). 20 [USGS] U.S. Geological Survey. 1998. National Water-Quality Assessment Program, Upper 21 Illinois River Basin. Urbana, IL: U.S. Geological Survey, WRD. USGS Fact Sheet FS-072-98. 22 June 1998. Available at <http://il.water.usgs.gov/pubs/fs072_98.pdf> (accessed 23 21 August 2015). 24 [USGS] United States Geological Survey. 1999a. Ecological status and trends of the Upper 25 Mississippi River System 1998: A report of the Long Term Resource Monitoring Program. 26 U.S. Geological Survey, Upper Midwest Environmental Sciences Center, La Crosse, Wisconsin. 27 April 1999. LTRMP 99-T001. 236 p. Available at 28 <http://www.umesc.usgs.gov/reports_publications/status_and_trends.html> (accessed 29 21 October 2015). 30 [USGS] U.S. Geological Survey. 1999b. Illinois River at Marseilles. Page dated 31 October 12, 1999. Available at 32 <http://il.water.usgs.gov/proj/lirb/bst/site_descrip/marseilles.html> (accessed 21 August 2015). 33 [USGS] U.S. Geological Survey. 2009. Earthquake Hazard in the New Madrid Seismic Zone 34 Remains a Concern. Available at <http://pubs.usgs.gov/fs/2009/3071/pdf/FS09-3071.pdf> 35 (accessed 5 September 2013). 36 [USGS] U.S. Geological Survey. 2013a. Earthquake History of Illinois. Available at 37 <http://earthquake.usgs.gov/earthquakes/states/illinois/history.php> (accessed 38 4 September 2013). 39 [USGS] U.S. Geological Survey. 2013b. Largest Earthquake in Illinois. Available at 40 <http://earthquake.usgs.gov/earthquakes/states/events/1968_11_09.php> (accessed 41 4 September 2013). 42 [USGS] U.S. Geological Survey. 2013c. Isoseismal Map of 1968 Earthquake. Available at 43 <http://earthquake.usgs.gov/earthquakes/states/events/1968_11_09_iso.php> (accessed 44 4 September 2013). 3-129

Affected Environment 1 [USGS] U.S. Geological Survey. 2015. USGS Water-Year Summary 2014, 05543500 Illinois 2 River at Marseilles, Illinois. Available at 3 <http://waterdata.usgs.gov/nwis/inventory/?site_no=05543500&agency_cd=USGS> (accessed 4 5 June 2015). 5 Watrous KS, Donovan TM, Mickey RM, Darling SR, Hicks AC, Von Oettingen SL. 2006. 6 Predicting minimum habitat characteristics for the Indiana bat in the Champlain Valley. The 7 Journal of Wildlife Management 70(5):1228-1237. 8 Whitaker JO Jr, Brack V Jr. 2002. Distribution and summer ecology in Indiana. pp. 48-54. In: 9 Kurta A, Kennedy J, editors. 2002. The Indiana Bat: Biology and Management of an 10 Endangered Species. Austin, TX: Bat Conservation International. 253 p. 11 Wiken E, Nava FJ, Griffith G. 2011. North American Terrestrial EcoregionsLevel III. 12 Commission for Environmental Cooperation, Montreal, Canada. April 2011. Available at 13 <http://www3.cec.org/islandora/en/item/10415-north-american-terrestrial-ecoregionslevel-iii-14 en.pdf> (accessed 5 August 2015). 15 Woods AJ, Omerinik JM, Pederson CL, Moran BC. 2006. Level III and Level IV Ecoregions of 16 Illinois. EPA/600/R-06/104. Prepared on behalf of Oregon State University, U.S. Geological 17 Survey, Eastern Illinois University, U.S. Environmental Protection Agency. Washington, DC: 18 EPA. 45 p. Available at <ftp://ftp.epa.gov/wed/ecoregions/il/il_report.pdf> (accessed 19 9 March 2015). 3-130

4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS 4.1 Introduction In this chapter, the U.S. Nuclear Regulatory Commission (NRC) evaluates the environmental consequences of the proposed action (i.e., license renewal of LaSalle County Station, Units 1 and 2 (LSCS)), including the (1) impacts associated with continued operations similar to those that have occurred during the current license terms; (2) impacts of various alternatives to the proposed action; (3) impacts from the termination of nuclear power plant operations and decommissioning after the license renewal term (with emphasis on the incremental effect caused by an additional 20 years of operation); (4) impacts associated with the uranium fuel cycle; (5) impacts of postulated accidents (design-basis accidents and severe accidents); (6) cumulative impacts of the proposed action; and (7) resource commitments associated with the proposed action, including unavoidable adverse impacts, the relationship between short-term use and long-term productivity, and irreversible and irretrievable commitment of resources. The NRC also considers new and potentially significant information on environmental issues related to operation during the renewal term. NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS) (NRC 2013d) identifies 78 issues to be evaluated in the license renewal environmental review process. Generic issues (Category 1) rely on the analysis presented in the GEIS, unless otherwise noted. Applicable site-specific issues (Category 2) have been analyzed for LSCS and assigned a significance level of SMALL, MODERATE, or LARGE. Section 1.4 of this supplemental environmental impact statement (SEIS) provides an explanation of the criteria for Category 1 and Category 2 issues, as well as the definitions of SMALL, MODERATE, and LARGE. Resource-specific impact significance level definitions are provided where applicable. 4.2 Land Use and Visual Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on land use and visual resources. 4.2.1 Proposed Action Section 3.2 describes land use and visual resources in the vicinity of the LSCS site. Table 4-1 identifies the issues that apply to land use and visual resources during the proposed license renewal period. The GEIS (NRC 2013d) discusses these issues in Section 4.2.1. The GEIS does not identify any site-specific (Category 2) land use or visual resource issues. The NRC staff did not identify any new and significant information related to the generic (Category 1) land use and visual resource issues during the review of the applicants Environmental Report (ER) (Exelon 2014a), the site audit, or the scoping process. Therefore, the NRC staff expects no impacts associated with these issues beyond those discussed in the GEIS. The GEIS concludes that the impact level for each of these issues is SMALL. 4-1

Environmental Consequences and Mitigating Actions Table 4-1. Land Use and Visual Resource Issues Issue GEIS Section Category Land Use Onsite land use 4.2.1.1 1 Offsite land use 4.2.1.1 1 Offsite land use in transmission line right-of-ways (ROWs)(a) 4.2.1.1 N/A(b) Visual Resources Aesthetic impacts 4.2.1.2 1 (a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid. As described in Section 3.1.6, all in-scope transmission lines subject to the evaluation of environmental impacts for license renewal are located within the LSCS site property boundary. (b) This issue does not apply to LSCS because no offsite transmission lines are within the scope of license renewal. Section 3.1.6 describes the in-scope transmission lines. Source: Table B-1 in Appendix B, Subpart A, to Title 10 of the Code of Federal Regulations (10 CFR) Part 51 4.2.2 No-Action Alternative 4.2.2.1 Land Use If LSCS were to shut down, the impacts to land use would remain similar to those during operations until the plant is fully decommissioned. Temporary buildings and staging or laydown areas may be required during large component and structure dismantling. LSCS is likely to have sufficient space within previously disturbed areas for these needs; therefore, no additional land would need to be disturbed that would result in changes to current land uses. In NUREG-0586, Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities, Supplement 1, the NRC (2002) concludes generically that land use during decommissioning activities would be SMALL. The GEIS (NRC 2013b) notes that land use impacts could occur in other areas beyond the immediate nuclear plant site as a result of the noaction alternative if new power plants are needed to replace lost capacity. The NRC staff did not identify any impacts that may result at LSCS beyond those discussed in NUREG-0586, and the NRC staff concludes that the noaction alternative is unlikely to noticeably alter or have more than minor effects on land use. Thus, the NRC staff concludes that the impacts of the no-action alternative on land use during the proposed license renewal term would be SMALL. 4.2.2.2 Visual Resources If LSCS were to shut down, visual resource impacts would remain similar to those experienced during operations until the site is fully decommissioned. The vent stack, reactor buildings, and turbine buildings, which create the largest visual impact, would eventually be dismantled, which would reduce the already SMALL impacts to visual resources that would occur during the proposed license renewal term. Thus, the NRC staff concludes that the impacts of the no-action alternative on visual resources would be SMALL. 4-2

Environmental Consequences and Mitigating Actions 4.2.3 New Nuclear Alternative 4.2.3.1 Land Use The new nuclear alternative assumes that Exelon Generation Company, LLC (Exelon) would build a new nuclear facility in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin at an existing power plant site. Construction of the facility would require an estimated 324 ac (131 ha) for permanent buildings and facilities and an additional 232 ac (94 ha) for temporary facilities, laydown areas, and other temporary land disturbances. Additional offsite land would be required for uranium mining, although this impact would result in no net change in land use impacts from those that would be associated with the proposed license renewal of LSCS. During construction, the use of an existing power plant site would maximize the availability of existing infrastructure and minimize disruption to land that had not been previously disturbed for industrial uses. However, given the land requirements, some undisturbed or non-industrial-use lands would likely be affected or converted to industrial areas. Such impacts would likely be noticeable within the direct footprint of the facility but would not result in changes that would destabilize surrounding land uses such that those lands would no longer function for their designated uses. Accordingly, the NRC staff concludes that construction impacts would be MODERATE. Operation of a new nuclear facility would incur impacts similar to those assessed for the proposed LSCS license renewal, which the NRC staff concludes, in Section 4.2.1, would be SMALL. Overall, impacts of a new nuclear alternative on land use would be MODERATE during construction and would be SMALL during operation. 4.2.3.2 Visual Resources Because the facility would be located on an existing power plant site, visual resource impacts of most new buildings and infrastructure would be minimal. The construction of natural draft cooling towers would be the largest visual impact because both the towers themselves and the plume could be visible from a distance. The magnitude of this impact would vary based on the topography of the chosen site and surrounding area. The NRC staff concludes that the impacts to visual resources from construction and operation of a new nuclear alternative would be SMALL to MODERATE. 4.2.4 IGCC Alternative 4.2.4.1 Land Use The integrated gasification combined-cycle (IGCC) alternative assumes that the new facility would be built at an existing power plant site in Illinois, including the LSCS site, or at another power plant site in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin. The facility would require 2,000 ac (800 ha) of land to construct the facility. If the facility were to be sited on the LSCS site, the area currently occupied by the LSCS facilities, the undeveloped areas immediately surrounding the facility, and the area occupied by the Illinois fish hatchery would be affected. Exelon would also need to acquire adjacent parcels of land to provide the full complement of acreage required for the IGCC facility. Additional offsite land would be required for coal mining, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS. During construction, the use of an existing site would maximize availability of existing infrastructure. However, construction would likely significantly affect surrounding natural areas 4-3

Environmental Consequences and Mitigating Actions on the site and within purchased adjacent land parcels because it would require the clearing and grading of these areas for industrial use. Whether sited on the LSCS site or elsewhere, the large footprint of the facility would likely require the conversion of land to industrial use from other land uses. Accordingly, construction would likely noticeably alter land uses, and the large area of land required for the IGCC facility could destabilize important attributes or functions of sensitive lands, such as nearby wetlands, if present. Accordingly, the NRC staff concludes that construction impacts would be MODERATE to LARGE. Operation of an IGCC facility would likely not incur additional land use changes; therefore, operational impacts would be SMALL. Overall, impacts of an IGCC alternative on land use would be MODERATE to LARGE during construction, depending on the location and types of lands affected by construction, and would be SMALL during operation. 4.2.4.2 Visual Resources Because the IGCC facility would be located on an existing industrial site, additional visual resource impacts would be minimal. The visibility of the plant stacks and mechanical draft cooling towers would vary based on the topography of the chosen site and surrounding area. Some temporary visual impacts may occur during construction from cranes and other construction equipment that may be visible off site. During operation, cooling tower plumes could create noticeable visual impacts. The NRC staff concludes that the impacts from the construction and operation of an IGCC alternative on visual resources would be SMALL. 4.2.5 Natural Gas Combined-Cycle Alternative 4.2.5.1 Land Use The natural gas combined-cycle (NGCC) alternative assumes that a new NGCC facility would be built at the LSCS site. The facility would require 94 ac (38 ha) of land and would be sited on the undeveloped land immediately surrounding the LSCS. Some infrastructure upgrades could be required, as well as a new or upgraded pipeline, which would affect additional land. Additional offsite land would be required for gas extraction and collection, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS. During construction, the use of the existing site would maximize the availability of existing infrastructure. However, construction would convert natural areas to industrial use because the new facility would be built outside the existing industrial footprint. Although these land use changes would be noticeable, construction would be unlikely to destabilize important attributes of surrounding lands, due to the small size of the facility footprint. Accordingly, the NRC staff concludes that construction impacts would be MODERATE. Operation of an NGCC facility would likely not incur additional land use changes; therefore, operational impacts would be SMALL. Overall, impacts of the NGCC alternative on land use would be MODERATE during construction and would be SMALL during operation. 4.2.5.2 Visual Resources Because the NGCC facility would be located on an existing industrial site, additional visual resource impacts would be minimal. The mechanical draft cooling towers would likely not be taller than other buildings on site. Some temporary visual impacts may occur during construction from cranes and other construction equipment that may be visible off site. During 4-4

Environmental Consequences and Mitigating Actions operation, cooling tower plumes could create some visual impacts in the immediate vicinity of the facility. The NRC staff concludes that the impacts from the construction and operation of an NGCC alternative on visual resources would be SMALL. 4.2.6 Combination Alternative (NGCC, Wind, Solar) 4.2.6.1 Land Use The NGCC component of the combination alternative would have the same land requirements as discussed for the NGCC alternative in Section 4.3.3.1. Accordingly, the impacts to land use would be similar to those concluded for the NGCC alternative and, therefore, would be MODERATE during construction and SMALL during operation. The wind component of this alternative would require an estimated 3,376 to 10,127 ac (1,366 to 4,098 ha) of land at onshore wind farm sites and agricultural cropland across the region of influence (ROI). However, the majority of this land would only be temporarily disturbed during construction. Permanently disturbed land would hold the wind turbines, access roads, and transmission lines and would account for 5 to 10 percent of the estimated required acreage. Land used for equipment laydown and turbine component assembly and erection could be returned to its original state following construction. Given the large footprint of the wind component, land use could be affected, although most land uses, such as agriculture, could continue once the wind turbines are operational. Land use impacts for the wind component would range from SMALL to MODERATE depending on the amount and types of land that would be affected by wind turbine construction. The solar component would require an estimated 6,749 ac (2,731 ha) of land across the ROI. The majority of solar installations could be installed on building roofs at existing residential, commercial, or industrial sites or at larger standalone solar facilities; therefore, only a little land would possibly be required for construction. However, the exact magnitude of impacts on land use would depend on the amount of land that must be converted for construction of solar installations. Unlike wind power, solar-powered installations often cannot be collocated with existing land uses (such as in crop-producing agricultural fields). The impacts of the solar component of this alternative on land use would range from SMALL to MODERATE, depending on the amount and types of land that would be affected by construction of the solar installations. The NRC staff concludes that the overall impacts of the combination alternative on land use would be SMALL to MODERATE. This range is primarily the result of the variability in land required for the wind and solar components. 4.2.6.2 Visual Resources Visual resource impacts for the NGCC component of this alternative would be similar to or less than those described in Section 4.3.3.2 for the NGCC alternative and, therefore, would be SMALL. Visual resources would be significantly affected by construction of the wind component. Although specific effects would vary based on the topography and remoteness of the wind turbine locations, the visual impact of wind energy is often one of the most significant energy-generating visual impacts and could range from MODERATE to LARGE. The visual impacts of the solar component would also vary, based on the topography of the area, but the NRC staff expects these impacts to be minimal because individual solar installations are not tall or expansive, and many of the installations could be constructed on building roofs at existing residential, commercial, or industrial sites. Larger standalone solar facilities could have a greater visual impact, depending on the location, but the impacts of the solar component would likely be SMALL overall. The NRC staff concludes that the impacts of the combination 4-5

Environmental Consequences and Mitigating Actions alternative on visual resources would be SMALL to LARGE. This range is primarily the result of the potential visual impacts from the wind component of the alternative. 4.2.7 Purchased Power Alternative 4.2.7.1 Land Use The purchased power alternative would have wide ranging impacts that are hard to specifically assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI. This alternative would likely have little-to-no construction impacts because it would include power from already existing power generating facilities. The construction of additional transmission lines could affect land uses if the lines require the clearing of new transmission line corridors. However, if collocated with existing lines, transmission-line construction would be unlikely to alter existing land uses. The types of operational impacts from this alternative would be similar to the effects discussed in the preceding alternative sections. This alternative would be more likely to intensify already existing effects at power generating facilities than create wholly new effects on land use. Existing facilities would likely have best management practices (BMPs) and other procedures in place to ensure that effects to the environment during operations are minimized. The NRC staff concludes that the impacts on land use from the purchased power alternative would be SMALL. 4.2.7.2 Visual Resources The purchased power alternative would likely not result in the construction of any buildings or facilities or any other changes to existing visual resources. Visual impacts from transmission-line construction could be minimized by collocating lines within existing transmission line corridors. The NRC staff concludes that the purchased power alternative would not have noticeable impacts on visual resources, and as such, would be SMALL. 4.3 Air Quality and Noise This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on air quality and noise conditions. 4.3.1 Proposed Action 4.3.1.1 Air Quality Section 3.3 describes the meteorological, air quality, and noise conditions in the vicinity of LSCS. Table 4-2 identifies two Category 1 air quality issues that are applicable to LSCS: (1) air quality impacts (all plants) and (2) air quality effects of transmission lines. There are no Category 2 issues for air quality. The Category 1 issue, air quality effects of transmission lines, considers the production of ozone and nitrogen oxides (NOx); the GEIS (NRC 2013d) found that minute and insignificant amounts of ozone and nitrogen oxides are generated during the transmission of power to the nuclear plant from the grid. The Category 1 issue, air quality impacts (all plants), considers the air quality impacts from continued operation and refurbishment associated with license renewal. 4-6

Environmental Consequences and Mitigating Actions Table 4-2. Air Quality and Noise Issue GEIS Section Category Air quality impacts (all plants) 4.3.1.1 1 Air quality effects of transmission lines 4.3.1.1 1 Noise impacts 4.3.1.2 1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 The NRC staff did not identify any new and significant information during the review of LSCSs ER (Exelon 2014a), the site audit, or the scoping process. As a result, the NRC did not identify any information or impacts related to these issues that would change the conclusions presented in the GEIS. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. The GEIS concludes that the impact level for each of these issues is SMALL. 4.3.1.2 Noise One Category 1 noise issue is applicable to LSCS: noise impacts (Table 4-2). The 1996 GEIS (NRC 1996) concluded that noise was not a problem at operating plants and that it was not expected to be a problem at any nuclear plant during the license renewal term. The GEIS (NRC 2013d) did not identify new information that would alter this conclusion; therefore, impacts are expected to be SMALL. The NRC staff did not identify any new and significant information during the review of LSCSs ER (Exelon 2014a, 2015j), the site audit, or the scoping process. As a result, the NRC did not identify any information or impacts related to this issue that would change the conclusions presented in the GEIS. Therefore, there are no impacts related to this issue beyond those discussed in the GEIS. The GEIS concludes that the impact level for this issue is SMALL. 4.3.2 No-Action Alternative 4.3.2.1 Air Quality When the plant stops operating, there will be a reduction in emissions from many activities related to plant operation, such as the use of stationary combustion sources (i.e., diesel generators and pumps) and vehicle traffic (i.e., employee and delivery vehicles). Therefore, if emissions decrease, the impact on air quality from shutting down LSCS would be SMALL. 4.3.2.2 Noise When the plant stops operating, there will a reduction in noise from activities related to plant operations, such as the turbines, switchyard/transformers, sirens, loudspeakers, and vehicle traffic (i.e., employee and delivery vehicles). As activity from noise sources is reduced below levels associated with operation of LSCS, impacts would remain SMALL. 4.3.3 New Nuclear Alternative 4.3.3.1 Air Quality This alternative includes the construction and operation of two Westinghouse AP1000 reactors, each with an approximate generating capacity of 1,120 megawatts electric (MWe). Due to the moratorium preventing the construction of new nuclear power plants within Illinois, the new nuclear alternative would have to be located elsewhere in the ROI (Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin) at an existing nuclear plant or retired coal site to maximize the use of existing infrastructure. Because the new nuclear alternative could be located 4-7

Environmental Consequences and Mitigating Actions anywhere within the seven-state ROI, it is unknown at this time whether the specific site(s) would be located within a designated attainment area. Construction of the new nuclear plant would result in temporary impacts on local air quality. During the construction phase, the primary sources of air emissions would consist of engine exhaust and fugitive dust emissions. Engine exhaust emissions would be from heavy construction equipment and commuter, delivery, and support vehicular traffic traveling within, to, and from the facility. Fugitive dust emissions would be from soil disturbances by heavy construction equipment (e.g., earthmoving, excavating, and bulldozing); vehicle traffic on unpaved surfaces; concrete batch plant operations (if any); and wind erosion to a lesser extent. Air emissions include criteria pollutants (i.e., particulate matter, nitrogen oxide, carbon monoxide, and sulfur dioxide); volatile organic compounds (VOCs); hazardous air pollutants (HAPs), and greenhouse gases (GHGs). Small quantities of VOC and HAP emissions would be released from equipment refueling; organic solvents used in cleaning, onsite storage, and use of petroleum-based fuels; onsite maintenance of the heavy construction equipment; and certain painting and other construction-finishing activities. Air emissions would be intermittent and would vary, based on the level and duration of a specific activity throughout the construction phase. Based on the State and Federal permits and regulated practices for managing air emissions from construction equipment and temporary stationary sources, controlling fugitive dust, and inspecting vehicles and traffic management plans, the NRC staff expects that potential impacts on air quality from building a nuclear power plant would be minimal. Because air emissions from construction activities would be limited, local, and temporary, the NRC staff concludes that the overall air quality impacts associated with construction of a new nuclear alternative would be SMALL. Operation of a new nuclear generating plant would result in similar air emissions to those at LSCS. Nuclear power plants do not burn fossil fuels to generate electricity. Sources of air emissions include stationary combustion sources (e.g., diesel generators and diesel pumps), cooling towers, and mobile sources (e.g., worker vehicles, onsite heavy equipment and support vehicles, and delivery of materials and disposal of wastes). Air pollutants emitted from stationary combustion sources (e.g., criteria pollutants, VOCs, HAPs, and GHGs) and from cooling towers (particulate matter as drift) associated with operating a nuclear power plant would be permitted in accordance with state and Federal regulatory requirements. As noted in Section 3.3, LSCS maintains a Federally Enforceable State Operating Permit (also known as a synthetic minor air permit). A synthetic minor source has the potential to emit air pollutants in quantities at or above the major source threshold levels but has accepted Federally enforceable limitations to keep the emissions below such levels. Because air emissions would be similar for a new nuclear plant, the NRC staff expects similar air permitting conditions and regulatory requirements. Subpart P of 40 CFR 51.307 contains the visibility protection regulatory requirements, including the review of the new sources that may affect visibility in any Federal Class I area. If a new nuclear plant were located near a mandatory Class I area, additional air pollution control requirements may be required. In general, most stationary combustion sources at a nuclear power plant would operate only for limited periods, often for periodic maintenance testing. Thus, emissions from stationary combustion sources would fall far below the threshold for major sources (100 U.S. short tons per year) and the threshold for mandatory GHG reporting (25,000 metric tons (MT) per year). The NRC staff expects similar air emissions for combustion sources from a new nuclear plant as are currently being emitted from LSCS (Exelon 2014a), as follows:

  • carbon monoxide (CO)2.2 tons (2 MT),
  • nitrogen oxides (NOx)8.4 tons (7.6 MT),

4-8

Environmental Consequences and Mitigating Actions

  • sulfur dioxide (SO2)0.002 tons (0.002 MT),
  • particulate matter (PM10)0.15 tons (0.14 MT), and
  • particulate matter (PM2.5)0.15 tons (0.14 MT).

Additional particulate matter emissions would result from cooling tower operation and worker vehicles commuting to and from the plant. However, a nuclear power plant located in the ROI would use cooling water taken from a nearby river or lake, which would have relatively low concentrations of total dissolved solids. In addition, modern cooling towers would be equipped with drift eliminators to minimize the loss of cooling water from the tower via drift. Thus, particulate matter emissions from cooling towers would be anticipated to be minimal. The NRC staff evaluated potential impacts on air quality associated with criteria pollutants and GHG emissions from operating a new nuclear alternative. The NRC staff determined that the impacts would be minimal. Therefore, the NRC staff concludes that the impacts of operation of a new nuclear alternative on air quality from emissions of criteria pollutants and GHGs would be SMALL. The NRC staff concludes that the air quality impacts associated with construction and operation of a new nuclear alternative would be SMALL. 4.3.3.2 Noise Construction of a new nuclear power plant is similar to that of other large industrial projects and involves many noise-generating activities. In general, noise emissions vary with each phase of construction, depending on the level of activity, the mix of construction equipment for each phase, and site-specific conditions. Noise propagation to receptors is affected by several factors, including source-receptor configuration; land cover; meteorological conditions (i.e., temperature, relative humidity, and vertical profiles of wind and temperature); and screening (e.g., topography and natural or manmade barriers). Typical construction equipment, such as dump trucks, loaders, bulldozers, graders, scrapers, air compressors, generators, and mobile cranes, would be used, and pile-driving and blasting activities would take place during the construction of a new nuclear power plant. Other noise sources include commuter, delivery, and support vehicular traffic traveling within, to, and from the facility. During the construction phase, a variety of construction equipment would be used and at varying duration. Noise emissions from construction equipment are predicted to be in the 85- to 100-dBA range (FHWA 2006); however, noise levels attenuate rapidly with distance. At a 0.5-mi (0.8-km) distance from construction equipment, 85 to 90-dBA noise levels can drop to 51 to 61 dBA (NRC 2002). Additionally, noise abatement and controls can be incorporated to reduce noise impacts. Accounting for attenuation from the construction site and noise controls, predicted noise levels can exceed the U.S. Environmental Protection Agency (EPA) guideline of 55 dBA but can be less than the U.S. Department of Housing and Urban Development acceptable noise level guideline of 65 dBA. Based on the temporary nature of construction activities, consideration of noise attenuation from the construction site to residences, the location and characteristics (i.e., ground cover), and good noise control practices, the NRC staff concludes that the potential noise impacts of construction activities from a new nuclear alternative would be SMALL. During the operation phase, noise sources from the new nuclear power plant would include cooling towers; transformers; turbines; pumps; compressors; other auxiliary equipment (e.g., standby generators); and vehicular traffic (e.g., commuting, delivery, and support), similar to those for LSCS discussed in Section 3.3.2 of this SEIS. Although the plant layout and the distance from primary noise sources to the nearby receptors at LSCS might be different from those at a new nuclear alternative site and the new nuclear 4-9

Environmental Consequences and Mitigating Actions alternative will likely have cooling towers, the NRC staff does not expect noise impacts for a new nuclear plant to be any greater than those analyzed for the existing LSCS site. Although there would be noise generated by the impact of falling water associated with the cooling tower, noise from fans would not occur because the cooling tower would be a natural draft cooling tower, thus resulting in lower noise levels. Therefore, the noise impacts from operations of a new nuclear plant located within the ROI region would be SMALL. The NRC staff concludes that the noise impacts associated with construction and operation of a new nuclear alternative would be SMALL. 4.3.4 IGCC Alternative 4.3.4.1 Air Quality This alternative includes the construction and operation of four IGCC units with a total output of 2,472 MWe and a capacity factor of 85 percent. The new power plant is assumed to be located at an existing power plant site(s). These sites could be located in Illinois (including the LSCS site) or other adjoining States in the ROI (i.e., Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin). New infrastructure and infrastructure upgrades would depend on specific-site locations. Because the IGCC alternative could be located anywhere within the seven-state ROI, it is unknown at this time whether the specific site(s) would be located within a designated attainment area. If the IGCC alternative were to be located at LSCS, it would be located in LaSalle County; LaSalle County is designated as an attainment area for all National Ambient Air Quality Standards (NAAQS) (40 CFR 81.314). Construction of an IGCC plant would be similar to that of other large industrial projects and involves many activities similar to those for a new nuclear alternative presented in Section 4.3.3. Construction of an IGCC plant would result in the release of various criteria pollutants (i.e., particulate matter, nitrogen oxides, carbon monoxide, and sulfur dioxide); VOCs; HAPs; and GHGs from operation of internal combustion engines in construction vehicles, equipment, delivery vehicles, and vehicles used by the commuting construction workforce. In addition, soil disturbance activities, such as earthmoving and material handling, would generate fugitive dust. The onsite storage and dispensing of vehicle and equipment fuels result in VOC releases. Air emissions would be intermittent and would vary, based on the level and duration of a specific activity throughout the construction phase. Construction lead times for IGCC plants are estimated to be 3 years (NETL 2013). Impacts would be localized, intermittent, and short lived, and adherence to standard construction BMPs would mitigate such impacts. The NRC staff concludes that construction-related impacts on air quality from an IGCC alternative would be of relatively short duration and would be SMALL. The sources of air emissions during operation include heat recovery steam generator (HRSG) stacks, the wet gas sulfuric acid (WSA) exhaust system, acid gas removal process startup/shutdown vents, startup stacks, flares, material-handling equipment, and mechanical draft cooling towers (DOE 2010a). The HRSG stacks would release the most emissions. Auxiliary boilers and diesel-driven pumps would also generate emissions on an infrequent basis. Compared to conventional coal-fired power plants, the proposed IGCC power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate matter emissions by removing constituents from the synthetic syngas (syngas) (i.e., gasifiers convert coal into a gas) (DOE 2010a). The IGCC alternative would also result in lower nitrogen oxide emissions because nearly 100 percent of the fuel-bound nitrogen from the syngas would be removed from the syngas before combustion in the gas turbine. Sulfur removal technology would remove more than 99 percent of the sulfur in the syngas. The use of sulfide-activated carbon could remove more than 92 percent of mercury from the syngas. More than 99.9 percent of 4-10

Environmental Consequences and Mitigating Actions particulate matter emissions would be removed from the syngas using high-temperature, high-pressure filtration. Various Federal and state regulations aimed at controlling air pollution would affect an IGCC alternative located in the seven-state ROI. A new IGCC plant would qualify as a new major source because of its potential to emit greater than 100 tons per year of criteria pollutants and would be subject to the requirements of a new source review (NSR) permitting program under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.) (EPA 2015f). An NSR permit or construction permit would specify emission limits for each pollutant, along with monitoring and reporting requirements; specifications for fuel and control equipment; and monitoring and performance testing for the IGCC units, auxiliary boiler, and WSA process. The new IGCC plant would be required to secure a Title V operating permit from the state agency. An NSR review would limit emissions for criteria pollutants and would reflect existing ambient air quality at the selected location. An analysis regarding NAAQS compliance would be conducted at the specific site location. The IGCC alternative also would need to comply with the standard of performance for new stationary sources set forth in Subpart Da, Standards of Performance for Electric Utility Steam Generating Units, of 40 CFR Part 60. If the IGCC alternative were located close to a mandatory Class I area, additional air pollution control requirements would be necessary (Subpart P of 40 CFR Part 51) as mandated by the Regional Haze Rule. Within the ROI, there are five Class I Federal areas, including Mammoth Cave National Park in Kentucky (40 CFR 81.411), Isle Royale National Park and Seney Wilderness Area in Michigan (40 CFR 81.414), and Hercules-Glades Wilderness Area and Mingo Wilderness Area in Missouri (40 CFR 81.416). The rule could apply to the IGCC alternative but would depend on specific site location(s). If the IGCC alternative were to be located at the LSCS, the nearest Class I Federal area for visibility protection is the Mingo National Wildlife Refuge, which is approximately 306 mi (492 km) southwest of LSCS. Air emissions for the IGCC alternative were estimated based on emission factors presented in Table 4.3-1 in the GEIS (NRC 2013d). The resulting estimated emissions are as follows:

  • sulfur dioxide (SO2)820 tons (740 MT) per year,
  • nitrogen oxides (NOx)3,000 tons (2,720 MT) per year,
  • particulate matter (PM10)480 tons (435 MT) per year,
  • carbon monoxide (CO)2,045 tons (1,850 MT) per year, and
  • carbon dioxide equivalent (CO2e)14.3 million tons (13.0 million MT) per year.

The IGCC alternative would produce 820 tons (740 MT) per year of sulfur dioxide and 3,000 tons (2,072 MT) per year of nitrogen oxides. The IGCC plant would have to comply with Title IV of the CAA (42 U.S.C. 7651) reduction requirements for sulfur oxides and nitrogen oxides, which are the main precursors of acid rain and are the major causes of reduced visibility. Title IV establishes maximum sulfur oxide and nitrogen oxide emission rates from the existing plants and a system of sulfur oxide emission allowances that can be used, sold, or saved for future use by the new plants. The new plant would be subjected to the continuous monitoring requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75. The Cross-State Air Pollution Rule (Volume 76 of the Federal Register, page 48208 (FR 48208)) requires 28 states (including Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin) to improve air quality and requires power plants to reduce annual sulfur dioxide and/or nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. A new IGCC plant would be subject to these additional rules and regulations. 4-11

Environmental Consequences and Mitigating Actions The IGCC alternative would emit approximately 14.3 million tons (approximately 13 million MT) per year of CO2e emissions. The plant would be subjected to the continuous monitoring requirements for carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued a final rule tailoring the criteria that determine which stationary sources and modifications to existing projects become subject to permitting requirements for GHG emissions under the prevention of significant deterioration (PSD) and Title V Federal permit programs of the CAA (77 FR 41051). Beginning January 2, 2011,2 operating permits issued to major sources of GHG under the PSD or Title V permit programs must contain provisions requiring the use of best available control technology to limit the emissions of GHGs, if those sources would be subject to PSD or Title V permitting requirements because of their non-GHG pollutant emission potentials and if their estimated GHG emissions are at least 75,000 tons per year of CO2e. If the IGCC alternative meets PSD or Title V permitting requirements for non-GHG pollutant emissions and the GHG emission thresholds established in the rule, GHG emissions from this alternative would be regulated under the PSD and Title V permit programs. Furthermore, the IGCC alternative would be subject to carbon dioxide emission performance rate standards set forth in the Clean Power Plan aimed at reducing carbon pollution from power plants (80 FR 64661-65120). In response to the Consolidated Appropriations Act of 2008 (Public Law 110-161), EPA issued final mandatory GHG reporting regulations for major sources effective in December 2009 (74 FR 56260). Major sources are defined as those sources emitting more than 25,000 MT per year of all GHGs. An IGCC alternative would be subject to these reporting regulations with or without carbon capture. On January 8, 2014, EPA issued a new proposal for GHG emissions from new fossil fuel-fired electric utility steam generating units (79 FR 1430). It also proposes standards of performance for IGCC units that burn coal. The performance standards are based on partial implementation of carbon capture and sequestration (CCS) as the best system of emission reduction. Although the proposed rule has not been finalized, the IGCC alternative analysis includes an option for future implementation of CCS. An IGCC alternative also would be subject to the Mercury and Air Toxics Standards (MATS) final rule, which was finalized by EPA on December 16, 2011 (77 FR 9304). Standards for emissions of heavy metals (i.e., mercury, arsenic, chromium, and nickel) and acid gases (i.e., hydrochloric acid and hydrofluoric acid) are set by MATS. Mercury is the most prominent HAP emitted and is subject to regulation by the MATS rule. New IGCC units are required to meet a mercury emission limit of 0.003 lb per gigawatt hour (Subpart UUUUU of 40 CFR Part 63). The NRC staff estimates that an IGCC alternative replacing the electrical output of LSCS would generate 0.03 ton (0.02 MT) of mercury per year. The impact from sulfur dioxide, nitrogen oxide, particulate matter, and carbon monoxide emissions would be significant and would be subject to Title V permitting. GHG emissions also would be noticeable and significant; GHG emissions would be much larger than the threshold in the EPA GHG Tailoring Rule (77 FR 41051), and GHG emissions may be regulated under the PSD and Title V permit programs that would trigger a regulated NSR. In the near future, carbon dioxide emissions could be reduced considerably if CCS technology were installed. 2 On June 23, 2014, the U.S. Supreme Court issued a decision that EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a PSD or Title V permit but could continue to require PSD and Title V permits otherwise required, based on emissions of conventional pollutants. In July 2014, EPA issued a memorandum in response to the Supreme Courts decision and acknowledged that, although the decision is pending judicial action, EPA will no longer require PSD or Title V permits for GHG-emitting sources that are not sources subject to PSD or Title V permits based on emissions of conventional pollutants (e.g., nitrogen oxides and carbon monoxide) (EPA 2015b). 4-12

Environmental Consequences and Mitigating Actions As result of the significant criteria air emissions, a major air source, and significant GHG emissions, the NRC staff concludes that the air quality impacts associated with operation of an IGCC alternative would be MODERATE. The NRC staff concludes that the overall air quality impacts associated with construction and operation of an IGCC alternative would be MODERATE. 4.3.4.2 Noise Construction of an IGCC plant is similar to that of other large industrial projects, and construction-related noise sources would be virtually the same as those for construction of the nuclear alternative. However, the construction period for the IGCC alternative would be shorter, and activities would be scattered over a wider area as compared with construction of a nuclear alternative. Consequently, with construction-related noise for the nuclear alternative as a bounding condition, the NRC staff concludes that construction-related noise impacts associated with the IGCC alternative would be SMALL. Operation of an IGCC plant would introduce mechanical sources of noise that would be audible off site. Continuous sources include the mechanical equipment associated with normal plant operations and mechanical draft cooling towers. Mechanical draft cooling towers may result in greater sound levels than natural draft cooling towers as a result of the mechanical noise associated with the movement of fans. However, mechanical draft cooling towers can be equipped with fans with sound attenuators. Intermittent sources include the equipment related to coal handling, solid waste disposal, transportation related to coal and lime/limestone delivery, and the commuting of plant employees. Noise associated with rail delivery of coal and lime/limestone would extend beyond the plant site boundary and would be most significant for residents living in the vicinity of the facility and along the rail route. Transportation-related noise sources have the potential for causing impacts, as these noise sources reach beyond the plant site boundary. Noise impacts associated with rail delivery are predicted to be in the 80- to 96-dBA range (NRC 2002). As a result of additional noise associated with both the mechanical cooling towers and the rail line and unknown distance from primary noise sources to nearby sensitive receptors, the NRC staff concludes that the potential offsite noise impacts on residents in the vicinity of an IGCC alternative site would range from SMALL to MODERATE The NRC staff concludes that the overall potential impacts of noise associated with construction and operation of the IGCC alternative and the rail line are considered to range from SMALL to MODERATE. 4.3.5 NGCC Alternative 4.3.5.1 Air Quality This alternative includes the construction and operation of five NGCC 560-MWe units (total 2,800 MWe) and a capacity factor of 85 percent. These sites could be located at an existing power plant site in the ROI (including the LSCS site). Some infrastructure upgrades may be required and would require construction of a new or upgraded pipeline. Using existing power plant sites maximizes availability of infrastructure and reduces disruption to land and populations. Because the NGCC alternative could be located anywhere within the seven-state ROI, it is unknown at this time whether the specific site(s) would be located within a designated attainment area. If the NGCC alternative were to be located at LSCS, it would be located in LaSalle County; LaSalle County is designated as an attainment area for all NAAQS (40 CFR 81.314). 4-13

Environmental Consequences and Mitigating Actions Construction of an NGCC power plant would be similar to that of other large industrial projects. Construction of an NGCC power plant would result in the release of various criteria pollutants (i.e., particulate matter, nitrogen oxides, carbon monoxide, and sulfur dioxide); VOCs; HAPs; and GHGs from the operation of internal combustion engines in construction vehicles, equipment, delivery vehicles, and vehicles used by the commuting construction workforce. In addition, onsite soil disturbance activities, such as earthmoving and material handling, would generate fugitive dust. Releases of VOCs will also result from the onsite storage and dispensing of vehicle and equipment fuels. Air emissions would be intermittent and would vary, based on the level and duration of a specific activity throughout the construction phase. Gas-fired power plants are constructed relatively quickly; construction lead times for NGCC plants are around 2 to 3 years (EIA 2011; OECD/NEA 2005). Impacts would be localized, intermittent, and short lived, and adherence to standard construction BMPs would mitigate such impacts. Therefore, the NRC staff concludes that construction-related impacts on air quality from an NGCC alternative would be of relatively short duration and would be SMALL. Operation of the NGCC plant could result in significant emissions of certain criteria pollutants, including carbon monoxide, nitrogen oxides, and particulate matter. The sources of air emissions during operation include gas turbines through HRSG stacks and mechanical draft cooling towers. An analysis regarding NAAQS compliance would be conducted at the specific site location. Various Federal and state regulations aimed at controlling air pollution would affect an NGCC alternative located in the seven-state ROI. An NGCC plant would be subject to NSR permitting program requirements to ensure that air emissions are minimized and that the local air quality is not substantially degraded (EPA 2015e). The new NGCC plant would be required to secure a Title V operating permit from the state agency. The NGCC plant would need to comply with the standards of performance for stationary combustion turbines set forth in Subpart KKKK of 40 CFR Part 60. If the NGCC alternative were located close to a mandatory Class I area, additional air pollution control requirements would be required (Subpart P of 40 CFR Part 51), as mandated by the Regional Haze Rule. A detailed discussion of these Federal and state regulations is provided in Section 4.3.4 (see the air quality operation discussion for the IGCC alternative). Emissions for the NGCC alternative were estimated using emission factors developed by the U.S. Department of Energys (DOEs) National Energy Technology Laboratory (NETL) NGCC analysis (NETL 2010). Assuming a total gross capacity of 2,800 MWe and a capacity factor of 0.85, the resulting estimated NGCC emissions are as follows:

  • sulfur dioxide (SO2)32 tons (29 MT) per year,
  • nitrogen oxides (NOx)700 tons (635 MT) per year,
  • particulate matter (PM10)51 tons (46 MT) per year,
  • carbon monoxide (CO)72 tons (65 MT) per year, and
  • carbon dioxide equivalent (CO2e)9.8 million tons (8.2 million MT) per year.

The NGCC alternative would produce 32 tons (29 MT) per year of sulfur dioxide and 700 tons (635 MT) per year of nitrogen oxides. The new plant would be subjected to the continuous monitoring requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75. A new NGCC plant would be subject to these additional rules and regulations set forth in the Cross-State Air Pollution Rule (see Section 4.3.4 above). The NGCC alternative would emit approximately 9.8 million tons (approximately 8.2 million MT) per year of CO2e. The plant would be subjected to the continuous monitoring requirements for carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued a final rule 4-14

Environmental Consequences and Mitigating Actions tailoring the criteria that determine which stationary sources and modifications to existing projects become subject to permitting requirements for GHG emissions under the PSD and Title V programs of the CAA (77 FR 41051). Beginning January 2, 2011, operating permits issued to major sources of GHG under PSD or Title V Federal permit programs must contain provisions requiring the use of best available control technology to limit the emissions of GHGs, if those sources would be subject to PSD or Title V permitting requirements because of their non-GHG pollutant emission potentials and if their estimated GHG emissions are at least 75,000 tons per year of carbon dioxide equivalent (CO2e) emissions. If the NGCC alternative meets PSD or Title V permitting requirements for non-GHG pollutant emissions and the GHG emission thresholds established in the rule, GHG emissions from this alternative would be regulated under the PSD and Title V permit programs. Furthermore, the NGCC alternative would be subject to carbon dioxide emission performance rate standards set forth in the Clean Power Plan aimed at reducing carbon pollution from power plants (80 FR 64661-65120). In response to the Consolidated Appropriations Act of 2008 (Public Law 110-161), EPA issued final mandatory GHG reporting regulations for major sources effective in December 2009 (74 FR 56260). Major sources are defined as those emitting more than 25,000 MT per year of all GHGs. An NGCC alternative would be subject to these reporting regulations with or without carbon capture. On January 8, 2014, EPA issued a new proposal for GHG emissions from new fossil fuel-fired electric utility steam generating units (79 FR 1430). It also proposes standards of performance for natural gas-fired stationary combustion turbines based on modern, efficient NGCC technology as the best system of emission reduction. In December 2000, EPA issued regulatory findings on emissions of HAPs from electric utility steam-generating units (65 FR 79825). These findings indicated that natural gas-fired plants emit HAPs, such as arsenic, formaldehyde, and nickel and stated the following: [T]he impacts due to HAP emissions from natural gas-fired electric utility steam generating units were negligible based on the results of the study. The Administrator finds that regulation of HAP emissions from natural gas-fired electric utility steam generating units is not appropriate or necessary [65 FR 79825]. Mercury is not emitted from NGCC power plants because natural gas used as fuel does not contain mercury. Nitrogen oxide emissions from an NGCC alternative would be significant and subject to Title V permitting. GHG emissions also would be noticeable and significant; carbon dioxide emissions would be much larger than the threshold in the EPA GHG Tailoring Rule. The NRC staff concludes that the overall air quality impacts associated with operation of an NGCC alternative would be MODERATE. The NRC staff concludes that the overall air quality impacts associated with construction and operation of an NGCC alternative would be MODERATE. 4.3.5.2 Noise The construction-related noise sources for an NGCC alternative would be virtually the same as those for construction of the IGCC alternative. Construction vehicles and equipment associated with the construction of the NGCC plant would generate noise; these impacts would be intermittent and would last only through the duration of plant construction. Noise emissions from common construction equipment would be in the 85- to 100-dBA range (FHWA 2006). However, noise abatement and controls can be incorporated to reduce noise impacts. The 4-15

Environmental Consequences and Mitigating Actions NRC staff concludes that construction-related noise impacts associated with the NGCC alternative would be SMALL. Noise impacts from operations would include mechanical draft cooling towers, transformers, turbines, pumps, compressors, exhaust stacks, the combustion inlet filter house, condenser fans, high-pressure steam piping, and vehicles (Saussus 2012). As discussed under the IGCC alternative, mechanical draft cooling towers can be equipped with fans with sound attenuators. Pipelines delivering natural gas fuel could be audible off site near gas compressor stations, but such noise impacts would be similar to impacts already occurring in the vicinity of the existing pipeline to which the new NGCC site would connect. Most noise-producing equipment is located inside the power block buildings, and no outside fuel-handling activities will occur. Minor offsite noise sources could include pipeline compressor stations. The NRC staff concludes that operation-related noise impacts from the NGCC alternative would be SMALL. The NRC staff concludes that construction- and operation-related noise impacts from the NGCC alternative would be SMALL. 4.3.6 Combination Alternative (NGCC, Wind, Solar) The combination alternative relies on NGCC-, wind-, and solar-generating capacity. The solar photovoltaic (PV) portion would consist of a total net capacity of 227 MWe; the onshore wind portion would consist of a total net capacity of 1,813 MWe; and the NGCC portion would consist of a total net capacity of 360 MWe. The NGCC portion of this alternative would be located at LSCS and in an attainment area (LaSalle County) for all NAAQS. The solar and wind portion of this alternative would be located in Illinois or other adjoining States in the ROI (i.e., Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin). 4.3.6.1 Air Quality Air emissions associated with the construction of the NGCC portion of the combination alternative are similar to the NGCC alternative but due to its smaller size, would be proportionally reduced. As discussed in Section 4.3.5.1, construction activities for an NGCC alternative would cause some temporary impacts to air quality from dust generation during operation of the earth-moving and material-handling equipment and exhaust emissions from worker vehicles and construction equipment. These emissions include criteria pollutants, VOCs, GHGs, and small amounts of HAPs. However, these impacts would be localized, intermittent, and short lived, and adherence to standard construction BMPs would mitigate such impacts. The NRC staff concludes that construction-related impacts on air quality from an NGCC portion of the combination alternative would be of relatively short duration and would be SMALL. For the wind portion of the combination alternative, the total estimated land requirement would be between 3,376 and 10,127 ac (1,366 to 4,098 ha), but only a small percentage of the committed land area (5 to 10 percent or less) would be disturbed by construction activities because wind turbines need to be separated from one another to maximize energy production and to avoid wake turbulences created by upwind turbines. Construction of the wind portion of the combination alternative would involve a number of activities, including road and staging/laydown area construction, land clearing, topsoil stripping, earth-moving operations, grading, ground excavation, drilling, foundation treatment, erecting wind turbines, ancillary building/structure construction, and electrical and mechanical installation. For most wind energy facilities, the site preparation phase would last for only a few months, followed by a year-long construction phase (depending on the size of the wind energy facilities) (Tegen 2006). Air emissions associated with construction activities result from fugitive dust from soil disturbances and engine exhaust from heavy equipment and vehicular traffic. These emissions include 4-16

Environmental Consequences and Mitigating Actions criteria pollutants, VOCs, GHGs, and HAPs. Dust-suppression methods and other mitigation measures could reduce impacts from fugitive dust. The wind portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the heavy equipment used, workforce, level of activities, and construction duration would be substantially lower than other alternatives. Therefore, the NRC staff concludes that the overall air quality impacts associated with construction of the wind portion of the combination alternative would be SMALL. Construction of the solar portion of the combination alternative would cause temporary impacts to air quality from fugitive dust from soil disturbances and engine exhaust from heavy equipment and vehicular traffic. Air emissions associated with construction activities include criteria pollutants, VOCs, GHGs, and HAPs to a lesser amount. Dust-suppression methods and other mitigation measures could reduce impacts from fugitive dust. The solar PV portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the number of heavy equipment and workforce, level of activities, and construction duration would be substantially lower than those for other alternatives. Therefore, the NRC staff concludes that the overall air quality impacts associated with construction of the solar PV portion of the combination alternative would be SMALL. Air emissions associated with the operation of the NGCC portion of the combination alternative are similar to the NGCC alternative in Section 4.3.5.1 but are reduced proportionally because its generating capacity is approximately 13 percent of the NGCC alternative. Emissions for the NGCC alternative were estimated using emission factors developed by DOEs NETL NGCC analysis (NETL 2010). Assuming a total gross capacity of 360 MWe and a capacity factor of 0.85, the resulting estimated NGCC emissions are as follows:

  • sulfur dioxide (SO2)4.2 tons (3.8 MT) per year,
  • nitrogen oxides (NOx)90 tons (81 MT) per year,
  • particulate matter (PM10)6.5 tons (5.9 MT) per year,
  • carbon monoxide (CO)9.3 tons (8.4 MT) per year, and
  • carbon dioxide equivalent (CO2e)1.2 million tons (1.1 million MT) per year.

Estimated annual emissions of sulfur dioxide, nitrogen oxides, carbon monoxide, and particulate matter would be lower than the major source threshold. Furthermore, the NGCC portion of this alternative would be located at LSCS and would be a designated attainment area (LaSalle County) for all NAQQS. Therefore, the overall air quality impacts associated with operation of the NGCC portion of the combination alternative would be SMALL. Emissions from the operation of wind energy facilities would include minor dust and engine exhaust emissions from vehicles and heavy equipment associated with site inspections, maintenance activities, and wind erosion from cleared land and access roads. The types of emission sources and pollutants during operation would be similar to those during construction, but emissions would be much less during operation. The NRC staff concludes that the overall air quality impacts associated with the operation of the wind portion of the combination alternative would be SMALL. In general, air emissions associated with the operation of solar energy facilities are negligible because no fossil fuels are burned to generate electricity. Emissions from solar fields would include fugitive dust and engine exhaust emissions from vehicles and heavy equipment associated with site inspections, maintenance activities (e.g., panel washing or replacement), and wind erosion from cleared lands and access roads. The types of emission sources and 4-17

Environmental Consequences and Mitigating Actions pollutants during operation would be similar to those during construction, but emissions would be much lower during operation. These emissions should not cause exceedances of air quality standards or have any impacts on climate change. The NRC staff concludes that the overall air quality impacts associated with the operation of the solar PV portion of the combination alternative would be SMALL. The overall air quality impacts associated with construction and operation of the combination alternative would be SMALL. 4.3.6.2 Noise The construction-related noise sources for the NGCC portion of the combination alternative would be virtually the same as those for construction of the NGCC alternative. The construction period for the NGCC portion would be shorter, and the level of construction activities would be less extensive than for the NGCC alternative. Consequently, the NRC staff concludes that construction-related noise impacts associated with the NGCC portion of the combination alternative would be SMALL. Construction of the wind portion of the combination alternative would involve a number of activities, as described above. The wind portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the number of heavy equipment and workforce, level of activities, and construction duration would be substantially lower than other alternatives. Considering these factors, the NRC staff concludes that construction-related noise impacts associated with the wind portion of the combination alternative would be SMALL. Construction of the solar PV portion of the combination alternative would involve a number of activities. The solar PV portion of the combination alternative would have no power block that would otherwise require intensive construction activities. Accordingly, the number of heavy equipment and workforce, level of activities, and construction duration would be substantially lower than other alternatives. Considering these factors, the NRC staff concludes that construction-related noise impacts associated with the solar PV portion of the combination alternative would be SMALL. Besides noise from the power block area, cooling towers, and vehicular traffic, operation-related noise for the NGCC portion would include limited outdoor waste-handling activities. Pipelines delivering natural gas fuel could be audible off site near gas compressor stations, but such sound impacts would be similar to impacts already occurring in the vicinity of the existing pipeline to which the new NGCC site would connect. Most noise-producing equipment is located inside the power block buildings, and no outside fuel-handling activities would occur. The NRC staff concludes that operation-related noise impacts from the NGCC portion of the combination alternative would be SMALL. Noise impacts from wind generation operations would include aerodynamic noise from the turbine rotors and mechanical noise from the turbine drive-train components. Noise levels are dependent on the wind and atmospheric conditions, which vary with time, and site-specific conditions, including the number and size of wind turbines, their layout, their distance to nearby sensitive receptors, land cover, and topography. Wind turbine noise levels can reach 105 dBA; however, studies show that at approximately 1,000 ft (300 m) from a wind turbine, noise levels can reach 43 dBA (GE 2010; Hessler 2011). Therefore, masking effects of background noise should be taken into consideration. Unless noise from wind turbines is masked by high background levels (e.g., near major highways or industrial complexes), it can be noticeable and annoying at farther distances. One study indicated that, for the same A-weighted sound level, proportions of respondents annoyed by wind turbine noise are higher than for other community 4-18

Environmental Consequences and Mitigating Actions noise, such as aircraft, road, or railway traffic, and that the proportion of respondents annoyed by the noise increases more rapidly (Pedersen and Persson Waye 2004). Therefore, the NRC staff concludes that operation-related noise impacts from the wind portion of the combination alternative would be SMALL to MODERATE, depending on the layout and location of the wind facility and on its distance to nearby sensitive receptors. The solar PV portion of the combination alternative would have no power block and cooling towers; therefore, there would be a minimal number of noise sources with low-level noises. Noise sources include small-scale cooling systems to dissipate heat from solar module assemblies, solar tracking devices, inverters, transformers, and vehicle traffic for maintenance and inspection. Because of minimal noise-generating activities, noise from a solar PV facility would be anticipated to be inaudible or barely perceptible at the facility boundaries. Considering the minimum number of sources with low-noise levels and the area size of the solar PV facility, the NRC staff concludes that operation-related noise impacts from the solar PV portion of the combination alternative would be SMALL. The noise impacts associated with construction and operation of the combination alternative would be SMALL to MODERATE. 4.3.7 Purchased Power Alternative 4.3.7.1 Air Quality As discussed in Section 2.2.2.5, purchased power would come from common types of existing technology (i.e., coal, natural gas, and nuclear) within the ROI, and the construction of new facilities to replace LSCS would be unlikely. Construction of new transmission lines would result in additional amounts of air emissions. Air emissions associated with the construction of transmission lines would be from operation of the earth-moving and material-handling equipment and exhaust emissions from worker vehicles and construction equipment. These emissions include criteria pollutants, VOCs, GHGs, and HAPs. However, these impacts would be temporary and would not likely be high. For purchased power from existing plants, the impacts on air quality are expected to be SMALL because change to existing plant operations would be minimal. If new facilities were to be constructed for purchased power, the impact on air quality would depend on the plant technology constructed and the air quality status (i.e., attainment, nonattainment, or maintenance status) where the generating plant is located because air emissions can vary substantially based on the alternative air quality discussions provided above. For instance, natural gas- and coal-fired plants emit higher amounts of nitrogen oxides, sulfur oxides, particulate matter, and carbon dioxide than nuclear power plants do. Purchased power from new nuclear plants would not have noticeable impacts on air quality. New natural gas- and coal-fired plants would have noticeable impacts on air quality as a result of the higher amounts of air emissions. Furthermore, if the plant is sited in a designated nonattainment or maintenance area, emission impacts from plant operation can be greater than those for a designated attainment area. Based on the above, impacts on air quality from purchased power from new plants would be SMALL to MODERATE. 4.3.7.2 Noise Purchased power from existing electricity generating facilities would not have noticeable impacts on noise because change to existing plant operations would be minimal. Purchased power from new generating facilities could have impacts on noise. Construction and operation of new facilities could result in additional noise sources, including mechanical equipment 4-19

Environmental Consequences and Mitigating Actions associated with normal plant operations and vehicular traffic. Additionally, construction of new transmission lines could increase noise levels. Increase in noise levels from construction of new transmission lines and new facilities would be dependent on the distance of residents to the noise sources. Noise levels from operation would also be dependent on the type of technology; for instance, operation of nuclear or wind power. Therefore, impacts from purchased power on noise would be SMALL to MODERATE. 4.4 Geologic Environment This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on geologic and soil resources. 4.4.1 Proposed Action Section 3.4 describes the local and regional geologic environment of the LSCS site. Table 4-3 identifies the issue related to geology and soils that is applicable to the LSCS site during the license renewal term. Table 4-3. Geology and Soils Issues Issue GEIS Section Category Geology and Soils 4.4.1 1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 The NRC staff did not identify any new and significant information associated with the Category 1 geology and soils issue identified in Table 4-3 during the review of the applicants ER, the site audit, the scoping process, or the evaluation of other available information. As a result, the staff did not identify any information or impacts related to this issue that would change the conclusions presented in the GEIS (NRC 2013d). For this issue, the GEIS concludes that the impacts are SMALL. It is expected that there would be no incremental impacts related to this Category 1 issue during the renewal term beyond those discussed in the GEIS; therefore, the impacts associated with this issue are SMALL. 4.4.2 No-Action Alternative There would not be any impacts to the geology and soils at the LSCS site with the shutdown of the facility. With the shutdown of the facility, no additional land would be disturbed. Therefore, impacts would be SMALL. 4.4.3 New Nuclear Alternative For the new nuclear alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. During construction, sources of aggregate material, such as crushed stone and sand and gravel, would be required to construct buildings, foundations, roads, and parking lots. These resources would likely be obtained from commercial suppliers using local or regional sources. Land clearing during construction and the installation of power plant structures and impervious surfaces would expose soils to erosion and would alter surface drainage. Best management practices would be implemented in accordance with applicable permitting requirements to reduce soil erosion. These practices would include the use of sediment fencing, staked hay bales, check dams, 4-20

Environmental Consequences and Mitigating Actions sediment ponds, riprap aprons at construction and laydown yard entrances, mulching and geotextile matting of disturbed areas, and rapid reseeding of temporarily disturbed areas. Removed soils and any excavated materials would be stored on site for redistribution, such as for backfill, at the end of construction. Construction activities would be temporary and localized. Therefore, the impacts of the new nuclear alternative on geology and soil resources would be SMALL. 4.4.4 IGCC Alternative For the coal IGCC alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. Geologic construction material would be obtained, and BMPs would be applied as described in the new nuclear alternative in Section 4.4.3. Therefore, the impacts of the IGCC alternative on geology and soil resources would be SMALL. 4.4.5 NGCC Alternative For the NGCC generation alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. Geologic construction material would be obtained, and BMPs would be applied as described in the new nuclear alternative in Section 4.4.3. Therefore, the impacts of the NGCC on geology and soil resources would be SMALL. 4.4.6 Combination Alternative (NGCC, Wind, Solar) For the combination NGCC, wind, and solar alternative, the impacts on geology and soil resources would occur during construction, and no additional land would be disturbed during operations. Geologic construction material would be obtained, and BMPs would be applied as described in the new nuclear alternative in Section 4.4.3. The solar PV and the wind farm part of this alternative would require a large amount of land. However, much of the land would be undisturbed because road and facility construction would disturb only a small fraction. Therefore, the impacts of the combination NGCC, wind, and solar alternative on geology and soil resources would be SMALL. 4.4.7 Purchased Power Alternative The impacts of the purchased power alternative are likely to be bounded by the impact descriptions of the other alternatives. Purchased power is likely to come from existing facilities, or if new facilities are constructed, it would likely be from one of the previously discussed alternatives. These alternatives have SMALL impacts. Therefore, the impact of this alternative on geology and soil resources would be SMALL. 4.5 Water Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on surface water and groundwater resources. 4-21

Environmental Consequences and Mitigating Actions 4.5.1 Proposed Action 4.5.1.1 Surface Water Resources Section 3.5.1 describes surface water resource-related aspects and conditions relevant to the LSCS site. Table 4-4 identifies the Category 1 (generic) and Category 2 surface water use and quality issues applicable to LSCS. Table 4-4. Surface Water Resources Issues Issue GEIS Section Category Surface water use and quality (non-cooling system impacts) 4.5.1.1 1 Altered current patterns at intake and discharge structures 4.5.1.1 1 Scouring caused by discharged cooling water 4.5.1.1 1 Discharge of metals in cooling system effluent 4.5.1.1 1 Discharge of biocides, sanitary wastes, and minor chemical spills 4.5.1.1 1 Surface water use conflicts (plants with cooling ponds or cooling towers 4.5.1.1 2 using makeup water from a river) Effects of dredging on surface water quality 4.5.1.1 1 Temperature effects on sediment transport capacity 4.5.1.1 1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 Generic Surface Water Resources Issues The NRC staff did not identify any new and significant information associated with the Category 1 surface water issues identified in Table 4-4 during the review of the applicants ER (Exelon 2014a, 2015b), the applicants responses to the NRCs requests for additional information (RAIs), the scoping process, the results of the environmental site audit, or the evaluation of other available information as documented under Section 3.5.1 of this SEIS. As a result, no information or impacts related to these issues were identified that would change the conclusions presented in the GEIS (NRC 2013d). For these issues, the GEIS concludes that the impacts are SMALL. It is expected that there would be no incremental impacts related to these Category 1 issues during the renewal term beyond those discussed in the GEIS. The Category 2 (Table 4-4) issue related to surface water during the renewal term is discussed in the following text. Surface Water Use Conflicts This section presents the NRC staffs review of the plant-specific (Category 2) surface water use conflict issue listed in Table 4-4. For nuclear power plants using cooling towers or cooling ponds supplied with makeup water from a river, the potential impact on the flow of the river and water availability to meet the demands of other users is a Category 2 issue. This designation requires a plant-specific assessment. In evaluating the potential impacts resulting from surface water use conflicts associated with license renewal, the NRC staff uses as its baseline the surface water resource conditions as described in Sections 3.1.3 and 3.5.1. These baseline conditions encompass the defined hydrologic (flow) regime of the surface water(s) that is potentially affected by continued 4-22

Environmental Consequences and Mitigating Actions operations, as well as the magnitude of surface water withdrawals for cooling and other purposes (as compared to relevant appropriation and permitting standards). The baseline also considers other downstream uses and users of surface water. The mean annual discharge of the Illinois River (described in Section 3.5.1.1) measured at the U.S. Geological Survey (USGS) gage at Marseilles, Illinois, is 10,750 cubic feet per second (cfs) (304 cubic meters per second (m3/s)). This gaging station is approximately 3 mi (4.8 km) downstream from the LSCS river screen house and associated river intake structure and blowdown discharge canal. Flows measured at this gaging station are also inclusive of surface water withdrawals that other entities make in the same general vicinity as LSCS and that withdraw surface water from the same portion of the Marseilles Pool as LSCS. These include Agrium U.S., Inc., and PCE Phosphate, Marseilles Operation. These facilities are discussed in Section 3.5.1.2 and shown in Figure 3-5. As described in Section 3.5.1.2, LSCSs average surface water withdrawal rate from the Marseilles Pool of the Illinois River is approximately 105 cfs (2.96 m3/s or 67.8 million gallons per day (mgd)), with consumptive use averaging about 49.7 cfs (1.4 m3/s or 32.1 mgd). This consumptive use is equivalent to about 0.5 percent of the Illinois Rivers average annual flow. The NRC staff also evaluated the impacts of continued LSCS operations on low-flow conditions in the Illinois River. The lowest annual mean flow recorded for the Illinois River at Marseilles is 5,583 cfs (157.7 m3/s), and the mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the period of record (USGS 2015). The 90-percent exceedance flow is an indicator value of hydrologic drought. It signifies the flow rate that is equaled or exceeded 90 percent of the time as compared to the average flow for the period of record. Compared to these measures of reduced river flow, LSCSs current consumptive water use (i.e., 49.7 cfs (1.4 m3/s or 32.1 mgd)) represents a 0.9- and a 1.1-percent reduction, respectively, in the flow of the river downstream of the LSCS site. LSCSs consumptive water use is not expected to increase during the license renewal term (Exelon 2015b). As Exelon noted in its ER (Exelon 2014a), drought conditions could cause the flows in the main stem of the Illinois River and surface water elevations to fall below levels that could impact LSCS operations. As previously discussed in Section 3.5.1.2 of this SEIS, Exelon maintains an Extreme Heat Implementation Plan that is part of an overall Summer Readiness Plan. The Extreme Heat Implementation Plan provides procedural guidance to plant personnel for responding to worst-case summer weather and hydrologic conditions to ensure compliance with LSCSs National Pollutant Discharge Elimination System (NPDES) permit for thermal discharge limits and to safeguard plant equipment. As necessary, plant personnel run thermal models and will adjust makeup pumping rates to the cooling pond or the rate of blowdown to the river to maintain permit compliance. Under extreme cases, it may be necessary for Exelon to reduce LSCSs power output or to shut down the plant (e.g., under conditions of extremely low water levels). In conclusion, the NRC staffs review of available data indicates that consumptive water use associated with LSCS operations combined with other surface water withdrawals within the Marseilles Pool have no substantial impact on downstream water availability. LSCSs surface water withdrawals and low rate of consumptive use of flow in the Illinois River are very unlikely to substantially impact downstream water availability or instream uses of surface water within the Marseilles Pool during the license renewal term. Thus, operation of LSCS during the license renewal term is not expected to result in a water use conflict on the Illinois River. In addition, in the event of worst-case summer weather and hydrologic conditions affecting LSCS, Exelon has operational procedures in place to minimize hydrologic and thermal impacts on the river. In total, the NRC staff concludes that the potential impacts on surface water 4-23

Environmental Consequences and Mitigating Actions resources and downstream water availability from LSCSs continued withdrawals and consumptive water use during the license renewal term would be SMALL. 4.5.1.2 Groundwater Resources Section 3.5.2 describes groundwater resources at LSCS. Table 4-5 identifies issues related to groundwater that are applicable to LSCS during the license renewal term. Table 4-5. Groundwater Issues Issue GEIS Section Category Groundwater contamination and use (non-cooling system impacts) 4.5.1.2 1 Groundwater use conflicts (plants that withdraw less than 100 gpm) 4.5.1.2 1 Groundwater use conflicts (plants with closed-cycle cooling systems that 4.5.1.2 2 withdraw makeup water from a river) Groundwater quality degradation (plants with cooling ponds at inland sites) 4.5.1.2 2 Radionuclides released to groundwater 4.5.1.2 2 Source: Table B-1 in Appendix B, Subpart A to 10 CFR Part 51 The NRC staff did not identify any new and significant information associated with the Category 1 groundwater issues identified in Table 4-5 during the review of the applicants ER, the site audit, the scoping process, or the evaluation of other available information. As a result, no information or impacts related to these issues were identified that would change the conclusions presented in the GEIS (NRC 2013d). For these issues, the GEIS concludes that the impacts are SMALL. Therefore, it is expected that there would be no incremental impacts related to these Category 1 issues during the renewal term beyond those discussed in the GEIS; therefore, the impacts associated with these issues are SMALL. The three Category 2 issues (see also Table 4-5) related to groundwater during the renewal term are discussed below. Groundwater Use Conflicts (Plants with Closed-Cycle Cooling Systems That Withdraw Makeup Water from a River) This issue looks at the potential impact of the consumption of river water on the availability of groundwater supplies. LSCS uses a cooling pond and withdraws water from a small river. In turn, the cooling pond loses water to the atmosphere by evaporation. As a result, less water is returned to the Illinois River than that withdrawn. This issue evaluates the impact of river water consumption and lowered river water levels on groundwater supplies. The Illinois River alluvium is hydrologically connected to the Alluvial Aquifer. The Alluvial Aquifer is found below and on each side of the Illinois River. It is underlain by the Pennsylvanian Aquitard (see Figure 3-8 in Section 3.4.1 of this document). Because the Pennsylvanian Aquitard is not a significant source of groundwater, the Alluvial Aquifer is the aquifer that would be most impacted by changes in Illinois River water levels. The average flow in the Illinois River at the Marseilles stream gage (5 mi (8 km) downstream from the intake and discharge structures) is 10,750 cfs (304 m3/s) (Exelon 2014a; USGS 1979, 2015). LSCSs normal peak withdrawal rate from the river at the intake structure is 134 cfs (3.8 m3/s), and 67 cfs (1.89 m3/s) of blowdown is discharged to the river from the cooling pond. This means that 67 cfs (1.89 m3/s) is not returned to the river. This rate of consumption is 0.6 percent of the normal river flow in the area of the intake and discharge structures. From 4-24

Environmental Consequences and Mitigating Actions 1920 through 2014, the lowest annual river flow recorded at the Marseilles stream gage was 5,583 cfs (158 m3/s) in 1964 (USGS 2015). During this period of low flow, the average rate of consumption by the plant would be 1.2 percent of the flow in the river. This rate of consumption is also unlikely to have much impact on river levels and little or no impact on water levels in the Alluvial Aquifer. Therefore, the NRC staff concludes that impacts to groundwater use would be SMALL. Groundwater Quality Degradation (Plants with Cooling Ponds at Inland Sites) This issue looks at the potential for the use of closed-cycle inland unlined cooling ponds to degrade the surrounding groundwater quality and the water quality of offsite wells. The total dissolved solids concentration in the cooling pond is limited by LSCS operational procedures to a maximum of 750 milligrams per liter (mg/L), which is less than half the total dissolved solids concentration (1,709 mg/L) in water obtained from the Cambrian-Ordovician Aquifer. The water quality of the cooling pond is good enough to support a highly successful recreational fishery. With the exception of a few tritium samples that were near background values, between 2009 and 2014, radionuclide concentrations in the cooling pond have not been detected above background values (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015). The cooling pond is enclosed on the north, east, and south by dikes. On the west side of the cooling pond, the natural topography serves as the shoreline. Seepage from the cooling pond is negligible because the pond was built on the Glacial Drift Aquitard (Wedron Silty-Clay Till), which has a very low permeability and is 120- to 140-ft (37- to 43-m) thick in the area of the cooling pond. Seepage modeling, using data from test boring and pits in the reservoir area, indicates that any seepage rates would be very low (Exelon 2014a). As previously discussed in Section 3.5.2.1, this aquitard contains only small volumes of extractable groundwater (Exelon 2014a). Therefore, the impact of the cooling pond on groundwater quality would be SMALL. Radionuclides Released to Groundwater This issue looks at the potential contamination of groundwater from the inadvertent release of radioactive liquids from plant systems into the environment. Section 3.5.2.3 of this SEIS characterizes the groundwater quality at the LSCS site and vicinity, including historical releases of tritium to groundwater. In evaluating the potential impacts on groundwater quality associated with license renewal, the NRC staff uses, as its baseline, the existing groundwater conditions as described in Section 3.5.2.3 of this SEIS. These baseline conditions encompass the existing quality of groundwater potentially affected by continued operations (as compared to relevant State or EPA primary drinking water standards), as well as the current and potential onsite and offsite uses and users of groundwater for drinking and other purposes. The baseline also considers other down-gradient or in-aquifer uses and users of groundwater. Historical releases of liquids containing tritium have not impacted groundwater quality in aquifers within or beyond the LSCS site boundary. With the exception of the 2010 leak from the recycled condensate tank, all radiological leaks into groundwater have been successfully remediated. The 2010 leak from the recycled condensate tank contaminated groundwater in engineered granular fill but did not contaminate groundwater in an aquifer. The groundwater contaminated by this leak into the engineered fill has undergone significant cleanup, and because of the low permeability, thickness, and lateral extent of the surrounding Wedron Silty-Clay Till, it is very unlikely that the leak will impact offsite groundwater. The Cambrian-Ordovician Aquifer System is overlain by 312 ft (95 m) of aquitard and is too deep to be impacted by site activities. A search of Illinois State Geological Survey water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant buildings 4-25

Environmental Consequences and Mitigating Actions (ISGS 2015). With the exception of one well completed in the Pennsylvanian Aquitard, all the wells have been completed in the Cambrian-Ordovician Aquifer. Given the low permeability, thickness, and lateral extent of the Wedron Silty-Clay Till, there is little chance of significant impact to the groundwater quality of onsite and offsite aquifers. Present and future LSCS operations are not expected to impact the quality of groundwater in any aquifers that are a current or potential future source of water for offsite users. Therefore, the NRC staff concludes that the impacts on groundwater use and quality during the license renewal term would be SMALL. 4.5.2 No-Action Alternative 4.5.2.1 Surface Water Resources Surface water withdrawals and the rate of consumptive water use would greatly decrease and eventually cease after LSCS is shut down. Wastewater discharges would be reduced considerably. Therefore, shutdown would reduce the overall impacts on surface water use and quality. Stormwater would continue to be discharged from the plant site throughout plant shutdown and decommissioning. Overall, the impact of this alternative on surface water resources would be SMALL. 4.5.2.2 Groundwater Resources With the cessation of operations, there should be little or no impacts on groundwater quality, and the consumption of groundwater would be much less. The Glacial Drift Aquitard (Wedron Silty-Clay Till) and surrounding dikes would continue to limit groundwater movement either into or out of the cooling pond. Therefore, the impact of this alternative on groundwater resources would be SMALL. 4.5.3 New Nuclear Alternative 4.5.3.1 Surface Water Resources Impacts from construction activities on surface water resources associated with the new nuclear alternative would be considerable in scale by virtue of the land area required for new nuclear units (i.e., 556 ac (225 ha). Deep excavation work for the nuclear island, extensive site clearing, and a large laydown area for facility construction would have the potential for direct and indirect impacts on water resources, which would vary based on site-specific conditions. Construction activities would alter any onsite surface water drainage features. Some temporary impacts to surface water quality may result from increased sediment loading and from any pollutants in stormwater runoff from disturbed areas, from excavation, and from any dredge-and-fill activities. Stormwater runoff from construction areas and spills and leaks from construction equipment could potentially affect downstream surface water quality. Nevertheless, application of BMPs in accordance with a State-issued NPDES general permit, including appropriate waste management, water discharge, stormwater pollution prevention, and spill prevention practices, would prevent or minimize surface water or groundwater quality impacts during construction. The NRC staff assumes that any existing intake and discharge infrastructure at an alternative site location would be refurbished and used to reduce construction-related impacts on surface water quality. Dredge-and-fill operations would be conducted under a permit from the U.S. Army Corps of Engineers (USACE) and State-equivalent permits requiring the implementation of applicable BMPs to minimize associated impacts. 4-26

Environmental Consequences and Mitigating Actions The staff assumes that there would be no direct use of surface water during construction and that water would be obtained from onsite groundwater or from a local water utility or trucked to the point of use. During construction, the dewatering of excavations would not be expected to affect offsite surface water bodies. The operation of the two new nuclear units using closed-cycle cooling with natural draft cooling towers would require an estimated 86.6 cfs (2.45 m3/s or 56 mgd) of surface water for cooling makeup and related processes. Consumptive water use would be approximately 65 cfs (1.84 m3/s or 42 mgd). The projected consumptive water use under this alternative represents about a 31-percent increase as compared to current LSCS operations, which consume approximately 49.7 cfs (1.4 m3/s or 32.1 mgd) of surface water (see Sections 3.5.1.2 and 4.5.1.1). However, a State or regional permitting within the ROI could impose limits on surface water withdrawals and consumption, which would potentially reduce the cited makeup water and consumptive use demands for this alternative on an annualized basis, particularly during periods of drought. The NRC staff further expects that water treatment additives for new nuclear plant operations and effluent discharges would be relatively similar in quality and volume to LSCS. Effluent discharges and stormwater discharges would be subject to a State-issued NPDES permit, and surface water withdrawals would be subject to applicable State water appropriation and registration requirements. To prevent and respond to accidental non-nuclear releases to surface water, facility operations would be conducted in accordance with a spill prevention, control, and countermeasures plan; storm water pollution prevention plan; or equivalent plans and associated BMPs and procedures. Based on the above, the overall impacts on surface water use and quality from construction and operations under the new nuclear alternative would be SMALL to MODERATE. 4.5.3.2 Groundwater Resources For the new nuclear alternative, the staff assumed that construction water would be obtained from onsite groundwater or from a local water utility. During construction and throughout the life of this alternative, groundwater withdrawals would be subject to applicable State water appropriation and registration requirements. The application of BMPs in accordance with a State-issued NPDES general permit, including appropriate waste management, water discharge, stormwater pollution prevention plan, and spill prevention practices, would prevent or minimize groundwater quality impacts during construction. During operations, the consumptive use of groundwater for potable water and water for fire protection would be similar to the proposed action. Therefore, the impact of this alternative on groundwater resources would be SMALL. 4.5.4 IGCC Alternative 4.5.4.1 Surface Water Resources Impacts from construction activities associated with the IGCC alternative on surface water resources would be expected to be similar to, but somewhat greater than, those under the new nuclear alternative (see Section 4.5.3.1). The potential for greater impacts is attributable to the additional land required for construction of the power blocks for four IGCC units and for excavation and construction of other onsite facilities for coal handling and storage and for coal ash and scrubber waste management. The same assumptions for construction and operations also apply to this alternative, except as noted. Some temporary impacts to surface water quality may result from increased sediment loading and from pollutants in stormwater runoff from disturbed areas and from excavation and 4-27

Environmental Consequences and Mitigating Actions dredge-and-fill activities. In addition, hydrologic and water-quality impacts could occur from the extension or refurbishment of rail spurs to transport coal and other materials to potential site locations and to transfer coal ash from those sites. Using an existing power plant site would allow the use of the existing cooling water intake, effluent discharge, and rail infrastructure. If the IGCC plant is located at the LSCS site, portions of the cooling pond and other plant areas may be repurposed to construct IGCC facilities, including closed-cycle mechanical draft cooling towers. Regardless, as described in Section 4.5.3.1 for the new nuclear alternative, water-quality impacts from construction activities would be minimized by the application of BMPs and through compliance with State-issued NPDES permits. Any dredge-and-fill operations would be conducted under a permit from the USACE and State-equivalent permits requiring the implementation of BMPs to minimize impacts. Operation of an IGCC plant would require less makeup water and would have lower consumptive use than that of either the new nuclear alternative or current LSCS operations. The projected cooling water makeup requirement for an IGCC plant under this alternative is approximately 39 cfs (1.09 m3/s or 25 mgd), with consumptive use of about 31 cfs (0.87 m3/s or 20 mgd). This alternative would consume about 38 percent less surface water than that under current LSCS operations, which consumes approximately 49.7 cfs (1.4 m3/s or 32.1 mgd). As summarized in Section 4.5.3.1 for the new nuclear alternative, surface water withdrawals and effluent discharges would be subject to applicable regulatory requirements under this alternative. However, management of runoff and leachate from coal and ash storage facilities would require additional regulatory oversight and would present an additional risk to surface water resources near site locations. For this alternative, based on the projected magnitude of ground disturbance and hydrologic alteration and potential water quality impacts from coal and ash handling and management, impacts on surface water resources would range from SMALL to MODERATE. 4.5.4.2 Groundwater Resources The impact significance level on groundwater resources for the coal IGCC alternative is less than the new nuclear alternative described in Section 4.5.3.2. Approximately the same amount of groundwater would be consumed during the operation of the facility, but less groundwater would be consumed in the construction of the facility than for the new nuclear alternative. Therefore, impacts of the IGCC alternative on groundwater resources would be SMALL. 4.5.5 NGCC Alternative 4.5.5.1 Surface Water Resources Direct impacts from construction activities associated with the NGCC alternative on surface water resources would be expected to be much smaller than those under either the new nuclear or IGCC alternative. A new NGCC plant and associated pipelines would occupy a much smaller footprint (i.e., about 94 ac (38 ha)) than that of the current LSCS facility or the proposed new nuclear or IGCC facilities. This smaller footprint would result in less extensive excavation and earthwork. Otherwise, the same assumptions for construction and operations also apply to this alternative, except as noted. Some temporary impacts to surface water quality may result from increased sediment loading, any pollutants in stormwater runoff from disturbed areas, excavation, and dredge-and-fill activities. Depending on the path of any required new gas pipelines and transmission lines to service the NGCC plant, some stream crossings could be necessary. However, because of the short-term nature of any required dredge-and-fill operations and stream-crossing activities, the hydrologic alterations and sedimentation would be localized, and water-quality impacts would be 4-28

Environmental Consequences and Mitigating Actions temporary and would cease after construction has been completed and the site has been stabilized. The use of modern pipeline construction techniques, such as horizontal directional drilling, would further minimize the potential for water-quality impacts in the affected streams. In addition, as described in Section 4.5.3.1 for the new nuclear alternative, water-quality impacts would be minimized by the application of BMPs and through compliance with State-issued NPDES permits for construction. Any dredge-and-fill operations would be conducted under a permit from the USACE and State-equivalent permits requiring the implementation of BMPs to minimize impacts. For onsite facility operations, a five-unit NGCC plant would have a smaller cooling water demand and lower consumptive water use as compared to that under current LSCS operations and for the new nuclear and IGCC alternatives. It is projected that an NGCC plant would require approximately 26.3 cfs (0.74 m3/s or 17 mgd) of surface water for cooling and related processes, with consumptive use totaling about 20.1 cfs (0.57 m3/s or 13 mgd). Thus, this alternative would consume about 60 percent less surface water than that under current LSCS operations, which consumes approximately 49.7 cfs (1.4 m3/s or 32.1 mgd). Based on this analysis, the overall impacts on surface water resources from construction and operations under the NGCC alternative would be SMALL. 4.5.5.2 Groundwater Resources The impact significance level on groundwater resources for the NGCC alternative are less than the new nuclear alternative described in Section 4.5.3.2. Approximately the same amount of groundwater would be consumed during the operation of the facility, but less groundwater would be consumed in the construction of the facility. Therefore, impacts of the NGCC alternative on groundwater resources would be SMALL. 4.5.6 Combination Alternative (NGCC, Wind, Solar) 4.5.6.1 Surface Water Resources For the NGCC component of this alternative, the impacts on surface water resources from facility construction and operations at either the LSCS site or another existing power plant site would be a fraction of those described in Section 4.5.5.1 because the NGCC plant would be scaled back to a single 360-megawatt (MW) unit. As a result, operational cooling water demands would be reduced by roughly 90 percent. Impacts on surface water resources from constructing land-based wind turbines would primarily be limited to the relatively small amounts of water needed at each installation site for dust suppression and soil compaction during site clearing, turbine pad preparation, and concrete production. Construction of utility-scale solar PV farms would require relatively larger volumes of water per site due to the larger land area required per megawatt of replacement power produced. For both components under this alternative, the NRC assumes that required construction water would be procured from offsite sources and trucked to the point of use on an as-needed basis. Water could also be supplied via a local water utility. The likely use of ready-mix concrete would also reduce the need for onsite use of nearby water sources for construction. Installation of land-based wind turbines and utility-scale solar PV farms would also require construction of access roads and possibly transmission lines (especially for sites that are not already proximal to transmission line corridors). Access road construction would also require some water for dust suppression and roadbed compaction and would have the potential to result in soil erosion and stormwater runoff from cleared areas. For such activities, construction water would likely be trucked to the point of use from offsite locations, along with road 4-29

Environmental Consequences and Mitigating Actions construction materials. In all cases, it is expected that construction activities would be conducted in accordance with State-issued NPDES or equivalent permits for stormwater discharges associated with construction activity, which would require the implementation of appropriate BMPs to prevent or mitigate water-quality impacts. In contrast to land-based wind turbine sites and utility-scale solar PV farms, installation of small solar PV units on rooftops and at already-developed sites within the electric service ROI (see Section 2.2.2) would have little or no impact on surface water resources. To support the operation of wind turbine and PV installations, no direct use of surface water would be expected. Water would likely be obtained from groundwater or purchased from a water utility. Regardless, only very small amounts of water would be needed to periodically clean turbine blades and motors, and water could be trucked to the point of use as part of routine servicing. Water also would be required to clean panels at solar PV farms or those situated in rooftop arrays. Adherence to appropriate waste management and minimization plans, spill prevention practices, and pollution prevention plans during servicing of wind turbine and solar PV installations and operation of vehicles connected with site operations would minimize the risks to soils and surface water resources from spills of petroleum, oil, and lubricant products and stormwater runoff. Given the information presented above, the impacts on surface water resources from construction and operations under the combination alternative would be SMALL. 4.5.6.2 Groundwater Resources Construction dewatering would be minimal because of the small footprint of foundation structures, pad sites, and piling emplacements. Little or no impacts on groundwater use or water quality would be expected from routine operations. Consequently, the impacts on groundwater use and quality under this combination alternative would be SMALL. 4.5.7 Purchased Power Alternative 4.5.7.1 Surface Water Resources The impacts of this alternative on surface water resources are likely to be bounded by the impact descriptions for the other alternatives, although new transmission lines may be required. Specifically, new and continued operation of nuclear, coal-fired, and natural gas-fired plants and renewable energy projects would not be expected to result in incremental impacts on surface water use and quality that are greater than those described in Sections 4.5.3, 4.5.4, 4.5.5, and 4.5.6, as long as all energy-generating facilities operate within the bounds of applicable water use and NPDES permits. Therefore, the impact of this alternative on surface water resources would be expected to range from SMALL to MODERATE. 4.5.7.2 Groundwater Resources The impacts of the purchased power alternative on groundwater resources are likely to be bounded by the impact descriptions for the other alternatives. Purchased power is likely to come from existing facilities, or if new facilities are constructed, it would likely be from one of the previously discussed alternatives. These alternatives have SMALL impacts. Therefore, the impact of this alternative on groundwater resources would be SMALL. 4.6 Terrestrial Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on terrestrial resources. 4-30

Environmental Consequences and Mitigating Actions 4.6.1 Proposed Action Section 3.6 describes terrestrial resources on and in the vicinity of the LSCS site. Table 4-6 identifies the generic (Category 1) and site-specific (Category 2) issues that apply to terrestrial resources during the proposed license renewal period. Table 4-6. Terrestrial Resource Issues Issue GEIS Section Category Effects on terrestrial resources (non-cooling system impacts) 4.6.1.1 2 Exposure of terrestrial organisms to radionuclides 4.6.1.1 1 Cooling system impacts on terrestrial resources (plants with 4.6.1.1 1 once-through cooling systems or cooling ponds) Cooling tower impacts on vegetation (plants with cooling towers) 4.6.1.1 N/A(a) Bird collisions with plant structures and transmission lines(b) 4.6.1.1 1 Water use conflicts with terrestrial resources (plants with cooling ponds 4.6.1.1 2 or cooling towers using makeup water from a river) Transmission line right-of-way (ROW) management impacts on 4.6.1.1 1 terrestrial resources(b) Electromagnetic fields on flora and fauna (plants, agricultural crops, 4.6.1.1 1 honeybees, wildlife, livestock)(b) (a) This issue does not apply because LSCS does not have cooling towers. (b) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid. Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 4.6.1.1 Generic GEIS Issues For the generic (Category 1) terrestrial resource issues listed in Table 4-6, the NRC staff did not identify any new and significant information related to the generic (Category 1) issues listed above during the review of the applicants ER (Exelon 2014a), the site audit, or the scoping process. Therefore, the NRC staff expects no impacts associated with these issues beyond those discussed in the GEIS. The GEIS concludes that the impact level for each of these issues is SMALL. 4.6.1.2 Effects on Terrestrial Resources (Non-Cooling System Impacts) In the GEIS (NRC 2013d), the NRC staff determined that noncooling system effects on terrestrial resources is a Category 2 issue (see Table 4-6) that requires site-specific evaluation during each license renewal review. According to the GEIS, non-cooling system impacts can include those impacts that result from landscape maintenance activities, stormwater management, elevated noise levels, and other ongoing operations and maintenance activities that would occur during the renewal period and that could affect terrestrial resources on and near a plant site. Landscape Maintenance Activities Approximately 25 percent (379 ha (936 ac)) of the LSCS site remains as undeveloped, uncultivated natural areas (see Table 3-1, in Section 3.2.1 of this document). The majority of 4-31

Environmental Consequences and Mitigating Actions site landscape maintenance is performed within the protected area and not within natural areas on the site (Exelon 2015f). Typically, only grassy areas within the developed, industrial portion of the site are mown to keep vegetation short. Small trees or brush that might pose a safety concern may also be removed from these areas as needed. Leased agricultural land is maintained by the leasee and in accordance with the standing lease. Exelon (2014a) has no plans to disturb undeveloped areas of the site as part of the proposed license renewal. Several ongoing restoration projects would result in positive impacts to terrestrial resources during the license renewal term. These projects are discussed in Section 3.6 and include ongoing management of a small area of native prairie, native vegetation plantings, removal of the invasive common reed (Phragmites australis) around the cooling pond, and various bird habitat enhancements. Stormwater Management Natural drainage of the LSCS site is generally toward the cooling pond. Two stormwater ponds on the west side of the LSCS site receive stormwater runoff from the sites protected area, which is divided into two zones (I and II) for purposes of stormwater management. A system of surface ditches and underground piping drain the two zones. Zone I discharges to the north stormwater pond, and Zone II discharges to the south stormwater water pond. Each stormwater pond discharges to the cooling pond discharge canal via NPDES-permitted Outfalls G01 (north stormwater pond) and H01 (south stormwater pond). Some storm drains on the site are routed through oil separators before entering the stormwater ponds. Areas to the northwest and south of the protected area are drained away by existing creeks and gullies (Exelon 2014a). Exelon maintains a stormwater pollution prevention (SWPP) plan in accordance with Special Condition 8 of the sites NPDES permit (Permit No. IL0048151; IEPA 2013). The SWPP plan identifies potential sources of pollutants that could affect stormwater discharges at Outfalls G01, H01, and 002 and practices that Exelon uses to reduce pollutants in stormwater discharges and ensure compliance with applicable conditions of the NPDES permit (Exelon 2014c). The NPDES permit also requires that the SWPP plan identify areas with a high potential for significant soil erosion due to topography, activities, or other factors, and that the SWPP plan contain measures to limit erosion in these areas (IEPA 2013). Exelon further monitors areas with potential for spills of oil or other regulated substances under the LSCS Spill Prevention Control and Countermeasure Plan (Exelon 2014c). Collectively, these measures ensure that the effects to terrestrial resources from pollutants carried by stormwater would be small during the proposed license renewal term. Noise The GEIS (NRC 2013d) indicates that elevated noise levels could be a non-cooling system impact to terrestrial resources. However, the GEIS also concludes that generic noise impacts would be small because noise levels would remain well below regulatory guidelines for offsite receptors during continued operations and refurbishment associated with license renewal. The NRC staff did not identify any information during its review that would indicate that noise impacts to terrestrial resources at LSCS would be unique or require separate analysis. Other Operations and Maintenance Activities Exelon (2014a) anticipates no refurbishment or other operations or maintenance activities during the license renewal term that would disturb terrestrial habitats or result in changes to existing land uses. Exelon (2015e) states that it would continue to comply with all applicable environmental laws and regulations and would adhere to its company policy of regularly evaluating and 4-32

Environmental Consequences and Mitigating Actions implementing options that move beyond compliance. Such options may include maintaining Exelons Wildlife Management Plan and Wildlife Habitat Council certification for LSCS throughout the proposed license renewal term. When new activities that could impact the environment occur at LSCS, Exelon states that it follows several procedures to ensure that potential environmental effects are considered and appropriately addressed. Exelon (2015g) maintains an Environmental Review procedure (EN-AA-103) that provides a process for screening proposed activities to determine if an activity requires further evaluation for environmental impacts and risks. Such activities include engineering configuration changes, maintenance activities, and operational changes. If further environmental evaluation is warranted, Exelons (2015g) Environmental Evaluations procedure (EN-AA-103-0001) provides guidance on identifying the environmental and regulatory impacts of an activity. If Exelon personnel determine that implementation of a proposed activity would result in an unacceptable environmental condition or risk, the proposed activity is not implemented until the environmental impact is appropriately addressed. These procedures would continue to be implemented during the proposed license renewal term and would ensure that environmental impacts to terrestrial resources would be addressed or mitigated prior to site operational or maintenance activities. Conclusion Based on the NRC staffs independent review, the staff concludes that the landscape maintenance activities, stormwater management, elevated noise levels, and other ongoing operations and maintenance activities that Exelon might undertake during the renewal term would primarily be confined to disturbed areas of the LSCS site. These activities would not have noticeable effects on terrestrial resources, nor would they destabilize any important attribute of the terrestrial resources on or in the vicinity of the LSCS site. Therefore, the staff expects non-cooling system impacts on terrestrial resources during the license renewal term to be SMALL. 4.6.1.3 Water Use Conflicts with Terrestrial Resources In the GEIS (NRC 2013d), the NRC staff determined that effects of water use conflicts on terrestrial resources is a Category 2 issue (see Table 4-6) that requires site-specific evaluation during each license renewal review. Water use conflicts occur when the amount of water needed to support terrestrial riparian communities is diminished as a result of demand for agricultural, municipal, or industrial use; decreased water availability due to droughts; or a combination of these factors. As indicated in Section 4.5.1.1, the amount of Illinois River water LSCS consumes is minor in comparison to the flow of water past the plant. In Section 4.5.1.1, the NRC staff found that water use conflicts with surface water resources would be SMALL during the proposed license renewal term because the surface flows in the Illinois River are able to meet the consumptive demand and because regulatory mechanisms are in place that limit LSCSs consumptive use. These regulatory mechanisms ensure that LSCS does not consume an amount that would be harmful to riparian communities during low river flow conditions. The terrestrial resources near the plant (described in Section 3.6) do not appear to be affected by the consumption of water from the river. The NRC staff concludes that water use conflicts would not occur from the proposed license renewal or would be so minor that the effects on terrestrial resources would be undetectable. Thus, the NRC staff concludes that the impacts of water use conflicts on terrestrial resources during the proposed license renewal term would be SMALL. 4-33

Environmental Consequences and Mitigating Actions 4.6.2 No-Action Alternative If LSCS were to shut down, the impacts to terrestrial ecology would remain similar to those during operations until the plant is fully decommissioned. Temporary buildings and staging or laydown areas may be required during large component and structure dismantling. LSCS is likely to have sufficient space within previously disturbed areas for these needs, and therefore, no additional land disturbances would occur on previously undisturbed land. Adjacent lands may experience temporary increases in erosional runoff, dust, or noise, but these impacts could be minimized with the implementation of standard BMPs (NRC 2002). In NUREG-0586, the NRC (2002) concludes generically that impacts to terrestrial ecology during decommissioning activities would be SMALL. The GEIS (NRC 2013d) notes that terrestrial resource impacts could occur in other areas beyond the immediate nuclear plant site as a result of the noaction alternative if new power plants are needed to replace lost capacity. The NRC staff concludes that the noaction alternative is unlikely to noticeably alter or have more than minor effects on terrestrial resources. Thus, the NRC staff concludes that the impacts of the no-action alternative on terrestrial resources during the proposed license renewal term would be SMALL. 4.6.3 New Nuclear Alternative The new nuclear alternative assumes that Exelon would build a new nuclear facility in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin at an existing power plant site. Construction of the facility would require an estimated 324 ac (131 ha) for permanent buildings and facilities and an additional 232 ac (94 ha) for temporary facilities, laydown areas, and other temporary land disturbances. Additional offsite land would be required for uranium mining, although this impact would result in no net change in land use impacts from those that would be associated with the proposed license renewal of LSCS. During construction, terrestrial species could experience habitat loss or fragmentation, loss of food resources, and altered behavior due to noise and other construction-related disturbances. Erosion and sedimentation from clearing, leveling, and excavating land could affect adjacent riparian and wetland habitats, if present. Implementation of appropriate BMPs would minimize these effects. This alternative could also require construction of new transmission lines or upgrades to existing lines. Because the new nuclear facility would be located on an existing energy-producing site, transmission lines could likely be collocated within existing transmission line corridors to minimize land disturbance. Although construction activities could noticeably alter terrestrial resources through habitat loss or fragmentation, construction is unlikely to destabilize any important attributes of the terrestrial environment. The exact magnitude of impacts would vary based on the chosen location of the facility and the amount and types of undisturbed habitat that would be affected by construction of the alternative, and thus, impacts of construction could range from SMALL to MODERATE. During operation, impacts would be similar in type and magnitude to those assessed in Section 4.6.1 for continued operation of LSCS under the proposed renewal term and would, therefore, be SMALL. The NRC staff concludes that the impacts of the new nuclear alternative on terrestrial resources would be SMALL to MODERATE during construction and SMALL during operation. The range in construction impacts is primarily the result of the uncertainty in the amount and types of undisturbed habitat that construction would affect. 4-34

Environmental Consequences and Mitigating Actions 4.6.4 IGCC Alternative The IGCC alternative assumes that the new facility would be built at an existing power plant site in Illinois, including the LSCS site, or at another power plant site in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin. The facility would require 2,000 ac (800 ha) of land to construct the facility. If the facility were to be sited on the LSCS site, the area currently occupied by the LSCS facilities, the undeveloped areas immediately surrounding the facility, and the area occupied by the Illinois fish hatchery would be affected. Exelon would also need to acquire adjacent parcels of land to provide the full complement of acreage required for the IGCC facility. Additional offsite land would be required for coal mining, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS. During construction, impacts to terrestrial habitats and species are likely to be similar to the types of impacts described for the new nuclear alternative in Section 4.6.3 but would likely be larger in magnitude due to the larger footprint of the IGCC facility. If the facility were to be sited on the LSCS site, the purchase of additional parcels of land could affect sensitive habitats, including wetlands and riparian areas. Accordingly, construction would likely noticeably alter terrestrial resources and could destabilize important attributes of the terrestrial environment. The exact magnitude of impacts would vary, based on the chosen location of the facility and the amount and types of undisturbed habitat that would be disturbed for construction of the alternative. Thus, impacts of construction could range from MODERATE, if some disturbances to terrestrial habitats occur, to LARGE, if significant disturbances to terrestrial habitats occur, especially if disturbed habitats are wetlands or other sensitive habitat types. The GEIS (NRC 2013d) concludes that impacts on terrestrial resources from the operation of fossil energy alternatives would essentially be similar to those from continued operations of a nuclear facility. Unique impacts would include periodic maintenance dredging if coal is delivered by barge, which could create noise, dust, and sedimentation. Dredging and delivery of coal to the site could introduce minerals and trace elements to water resources on which terrestrial biota rely. Elements from these minerals could also bioaccumulate in nearby riparian or wetland habitats. Air emissions during operation would include sulfur oxides and nitrogen oxides, which can combine with water vapor and create sulfuric and nitric acids. These acids would then be released back into the environment through precipitation, which could affect the acidity levels of water resources and have detrimental effects to plant foliage. Acid precipitation has the potential to destabilize the terrestrial environment by creating conditions that are too acidic for certain plants or animals and by mobilizing certain metals. The IGCC facility would also emit various GHGs during operation, which is an effect that can have far-reaching consequences because GHGs contribute to climate change. The effects of climate change on terrestrial resources are discussed in Section 4.13.3.2. The various air emissions during operation of the IGCC facility could create noticeable impacts on the terrestrial environment, and therefore, the operational impacts would be MODERATE. The NRC staff concludes that the impacts of the IGCC alternative on terrestrial resources would be MODERATE to LARGE during construction and MODERATE during operation. The range in construction impacts is primarily the result of the uncertainty in the amount and types of undisturbed habitat that construction would affect. 4.6.5 NGCC Alternative The NGCC alternative assumes that a new NGCC facility would be built at the LSCS site. The facility would require 94 ac (38 ha) of land and would be sited on the undeveloped land immediately surrounding the LSCS. Some infrastructure upgrades could be required, as well as 4-35

Environmental Consequences and Mitigating Actions a new or upgraded pipeline, which would affect additional land. Additional offsite land would be required for gas extraction and collection, although this impact would be partially offset by the elimination of land used for uranium mining to supply fuel to LSCS. During construction, impacts to terrestrial habitats and species are likely to be similar to the types of impacts described for the new nuclear alternative in Section 4.6.3 but would likely be smaller in magnitude, due to the smaller footprint of the NGCC facility. Because the NGCC facility would be built outside of the existing industrial footprint of LSCS, construction would require the conversion of natural areas to industrial use, which would result in the direct destruction of some existing terrestrial habitats. Although construction would noticeably alter terrestrial resources, it would be unlikely to destabilize important attributes of the terrestrial environment due to the small footprint size and the pre-disturbed nature of much of the existing land on the LSCS site. Thus, impacts of construction would likely be MODERATE. The GEIS (NRC 2013d) concludes that impacts to terrestrial resources from the operation of fossil energy alternatives would essentially be similar to those from continued operations of a nuclear facility. Unique impacts would include air emissions of GHGs such as nitrogen oxides, carbon dioxide, and methane, all of which can have far-reaching consequences because they contribute to climate change. The effects of climate change on terrestrial resources are discussed in Section 4.13.3.2. Although the impacts of operating the NGCC alternative may be noticeable, they are unlikely to destabilize any important attribute of the terrestrial environment and would, therefore, be SMALL. The NRC staff concludes that the impacts of the NGCC alternative on terrestrial resources would be MODERATE during construction and SMALL during operation. 4.6.6 Combination Alternative (NGCC, Wind, Solar) The NGCC component of the combination alternative would have the same land requirements as discussed for the NGCC alternative in Section 4.3.3.1. Accordingly, the impacts to terrestrial resources would be similar to those concluded for the NGCC alternative and, therefore, would be MODERATE during construction and SMALL during operation. The wind component of this alternative would require an estimated 3,376 to 10,127 ac (1,366 to 4,098 ha) of land at onshore wind farm sites and agricultural cropland across the ROI. Permanently disturbed land would hold the wind turbines, access roads, and transmission lines. Land used for equipment laydown and turbine component assembly and erection could be returned to its original state. Use of BMPs would ensure that disturbed lands were appropriately restored to reduce long-term impacts to the terrestrial environment. Operation of wind turbines could uniquely affect terrestrial species through mechanical noise, collision with turbines and meteorological towers, and interference with migratory behavior. Bat and bird mortality from turbine collisions is an ongoing concern for operating wind farms; however, recent developments in turbine design have reduced the potential for bird and bat strikes. The NRC staff expects that this component has the potential to noticeably alter terrestrial resources, primarily through the loss of habitat and bird and bat mortalities associated with wind turbine operation. However, it is unlikely that the wind component would destabilize any important attribute of the terrestrial environment, and thus, impacts would be MODERATE. The solar component of this alternative would require an estimated 6,749 ac (2,731 ha) of land across the ROI. The majority of solar installations could be installed on building roofs at existing residential, commercial, or industrial sites or at larger standalone solar facilities, and thus, it is possible that little terrestrial habitat would be disturbed during construction. However, the exact magnitude of impacts on terrestrial resources would depend on the amount of terrestrial habitat that is lost or fragmented during construction of solar installations. Operation would have no 4-36

Environmental Consequences and Mitigating Actions measurable effects on the terrestrial environment. Overall impacts from construction and operation of this component of the alternative would range from SMALL to MODERATE, depending on the locations of solar installations and the amount of terrestrial habitat affected. Overall, the NRC staff concludes that the impacts of the combination alternative on terrestrial resources would be SMALL to MODERATE. This range is primarily the result of the variability in land required for the wind and solar components and the types of terrestrial habitats that would be disturbed by construction of these components. 4.6.7 Purchased Power Alternative The purchased power alternative would have wide-ranging impacts that are hard to specifically assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI. This alternative would likely have little to no construction impacts because it would include power from already existing power generating facilities. The construction of additional transmission lines would require implementation of BMPs to minimize erosion and sedimentation in nearby streams, ponds, or rivers. The types of operational impacts would be similar to the effects discussed in the preceding alternative sections. This alternative would be more likely to intensify already existing effects at power generating facilities than create wholly new effects on terrestrial species and habitats. Existing facilities would likely have BMPs and other procedures in place to ensure that effects to the environment during operations are minimized. The NRC staff concludes that the impacts on terrestrial resources from the purchased power alternative would be SMALL. 4.7 Aquatic Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on aquatic resources. 4.7.1 Proposed Action Section 3.1.3 describes the LSCS cooling and auxiliary water systems, and Section 3.7 describes the aquatic resources of interest. Table 4-7 identifies the generic (Category 1) and site-specific (Category 2) issues that apply to aquatic resources at LSCS during the proposed license renewal period. Table 4-7. Aquatic Resource Issues Issue GEIS Section Category All plants Entrainment of phytoplankton and zooplankton 4.6.1.2 1 Infrequently reported thermal impacts 4.6.1.2 1 Effects of cooling water discharge on dissolved oxygen, gas 4.6.1.2 1 supersaturation, and eutrophication Effects of non-radiological contaminants on aquatic organisms 4.6.1.2 1 Exposure of aquatic organisms to radionuclides 4.6.1.2 1 Effects of dredging on aquatic organisms 4.6.1.2 1 Effects on aquatic resources (non-cooling system impacts) 4.6.1.2 1 Impacts of transmission line right-of-way (ROW) management on 4.6.1.2 1 aquatic resources(a) 4-37

Environmental Consequences and Mitigating Actions Issue GEIS Section Category Losses from predation, parasitism, and disease among organisms 4.6.1.2 1 exposed to sublethal stresses Plants with once-through cooling systems or cooling ponds Impingement and entrainment of aquatic organisms 4.6.1.2 2 Thermal impacts on aquatic organisms 4.6.1.2 2 Plants with cooling ponds or cooling towers using makeup water from a river Water use conflicts with aquatic resources 4.6.1.2 2 (a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid. Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 4.7.1.1 GEIS Category 1 Issues The GEIS concludes that the nine Category 1 issues listed in Table 4-7 would have a SMALL impact on aquatic resources during the license renewal term for all plants. For these issues, no additional plant-specific analysis is required unless new and significant information is identified. During its review, the NRC staff considered Exelons ER, aquatic surveys and studies performed at LSCS and in the Illinois River, and available scientific literature; participated in a site audit; and considered Federal and State agency and public comments received during the scoping process. The NRC staff did not identify any new and significant information related to any of the Category 1 issues. Therefore, no site-specific analysis is required for these issues, and there would be no impacts associated with these issues beyond those discussed in the GEIS. 4.7.1.2 Impingement and Entrainment of Aquatic Organisms In the GEIS (NRC 2013d), the NRC determined that impingement and entrainment of aquatic organisms is a Category 2 issue (see Table 4-7) that requires site-specific evaluation during each license renewal review for plants with once-through cooling systems or cooling ponds, such as LSCS. Impingement is the entrapment of all life stages of fish and shellfish on the outer part of an intake structure or against a screening device during periods of water withdrawal (40 CFR 125.83). Impingement can kill organisms immediately or contribute to a slower death resulting from exhaustion, suffocation, injury, and other physical stresses. The potential for injury or death is generally related to the amount of time an organism is impinged, its susceptibility to injury, and the physical characteristics of the screen washing system and fish return (if present) of the plant. Entrainment is the incorporation of all life stages of fish and shellfish with intake water flow entering and passing through a cooling-water intake structure and into a circulating water system (CWS) (40 CFR 125.83). Organisms susceptible to entrainment are generally of smaller size than those susceptible to impingement and include ichthyoplankton (fish eggs and larvae), larval stages of shellfish and other macroinvertebrates, zooplankton, and phytoplankton. Entrained organisms may experience physical trauma and stress, pressure changes, excess heat, and exposure to chemicals, all of which may result in injury or death (Mayhew et al. 2000). 4-38

Environmental Consequences and Mitigating Actions A particular species can be subject to both impingement and entrainment if some individual fish are impinged on screens while others pass through the screens and are entrained. For instance, adults could be impinged while juveniles could be entrained, if they are small enough to pass through the intake screen openings. At LSCS, aquatic organisms may be impinged or entrained at two locations. Organisms that inhabit the Illinois River may be impinged or entrained when makeup water is drawn from the river, through the river screen house, and into the cooling pond. Organisms that inhabit the cooling pond may be impinged or entrained when water is drawn from the pond, through the cooling pond screen house, and into the CWS. Organisms that are entrained by passing through the cooling ponds screen house and into the LSCS CWS are subject to mechanical, thermal, and toxic stresses that make survival unlikely. This sections analysis uses a retrospective assessment of the present and past impacts to the aquatic ecosystem resulting from LSCS operation in order to provide a prospective assessment for the future impacts over the proposed license renewal term (i.e., through 2042 for Unit 1 and through 2043 for Unit 2). The timeframe and geographic extent are two components of the assessment that bound the analysis. The timeframe defines how far back and how far forward the analysis will extend. In assessing the level of impact, the staff looked at the projected effects in comparison to a baseline condition. In agreement with National Environmental Policy Act (NEPA) guidance (CEQ 1997), the baseline of the assessment is the condition of the resource without the action (i.e., under the no-action alternative). Under the no-action alternative, the plant would shut down, and the resource would conceptually return to its condition without the plant, which is not necessarily the same as the condition before the plant was constructed. The timeframe for analyzing ecological resources extends far enough into the past to understand trends and to determine whether the resource is stable, which the NRC definitions of impact levels require. For assessing direct and indirect impacts, the geographic boundaries depend on the biology of the species under consideration. The NRC staff used a modified weight-of-evidence (WOE) approach to evaluate the effects of impingement and entrainment on the aquatic resources in the Illinois River and LSCS cooling pond. The NRC chose this approach because EPA recommends a WOE approach for ecological risk assessment (EPA 1998). The WOE approach is a useful tool due to the complex nature of assessing risk (or impact), and the NRC has used this approach in other evaluations of the effects of nuclear power plant cooling systems on aquatic communities (e.g., NRC 2010, 2013b, 2015a, 2015b). Menzie et al. (1996) defines WOE as the process by which multiple measurement endpoints are related to an assessment endpoint to evaluate whether significant risk of harm is posed to the environment. In the present WOE approach, the NRC staff examined five lines of evidence (LOE) to determine if operation of LSCS is contributing to adverse impacts on aquatic resources in the Illinois River or LSCS cooling pond. The lines of evidence are as follows: LOE Description 1 Results of impingement studies performed at LSCS 2 Results of entrainment studies performed at LSCS 3 Temporal trends in fish populations in the Illinois River 4 Spatial differences in fish populations in the Illinois River 5 Consideration of engineered designs and operational controls that affect impingement and entrainment rates 4-39

Environmental Consequences and Mitigating Actions LOE 1: Impingement Studies Exelon contracted EA Engineering, Science, and Technology, Inc. (EA) to conduct a study to determine the impingement rates among the fish and shellfish in the Illinois River. From April 2014 through March 2015, EA (2015) collected 20 samples of all fish and shellfish impinged at the river screen house within set 24-hour collection periods. EA identified all impinged fish and shellfish to species, or the lowest taxonomic level possible. EA (2015) extrapolated annual impingement rates for each species by multiplying the number of fish collected during a 24-hour collection period by the volume of water that would be withdrawn during 1 year and dividing it by the volume of water withdrawn during the 24-hour collection period. EA (2015) collected a total of 635 fish representing 41 species, 9 crayfish representing 2 taxa, and 9 mussels representing 3 species. The most commonly impinged fish include gizzard shad (Dorosoma cepedianum; 29 percent of all samples), round goby (Neogobius melanostomus; 11 percent), threadfin shad (Dorosoma petenense; 9 percent), bluegill (Lepomis macrochirus; 6 percent), freshwater drum (Aplodinotus grunniens; 6 percent), and bluntnose minnow (Pimephales notatus; 5 percent). Gizzard shad was the most commonly impinged species and the most commonly collected species during electrofishing surveys in 2013 (EA 2014 and 2015). In addition, EA (2014) collected gizzard shad more often downstream of the intake as compared to upstream, which would suggest that impingement is not noticeably altering populations of gizzard shad near LSCS. Bluegill, bluntnose minnow, and freshwater drum each comprised 5 to 6 percent of the impinged fish and each comprised 2 to 3 percent of the electrofishing or seining samples in 2013 (EA 2014, 2015). These results suggest that the impingement rate is similar to the occurrence rate in monitoring surveys in the river near LSCS. In addition, EA (2014) reported similar numbers of these three fish species directly upstream and downstream of the river intake, which would suggest that impingement is not noticeably altering populations of bluegill, bluntnose minnow, and freshwater drum near LSCS. The NRC staff notes that EA (2014) may not conclusively determine whether impingement affects populations of fish near LSCS due to the limited sample size and because some fish may migrate sufficient distances such that a noticeable difference would not likely be identified between samples collected immediately upstream and downstream of the intake. Both round goby and threadfin shad are invasive species. All other impinged species comprised less than 5 percent of the impinged fish (EA 2015). The nine impinged crayfish included eight Orconectes species, seven of which were northern Clearwater crayfish (Orconectes propinquus) and one Procamarus sp. (EA 2015). The nine impinged mussels included two fragile papershell (Leptodea fragilis), one pink heelsplitter (Potamilus alatus), and six paper pondshell (Utterbackia imbecillis). EA (2015) estimated the annual impingement to be 10,673 organisms per year. The estimated annual impingement rates at LSCS are approximately 1 to 6 percent of the impingement rate at Dresden Nuclear Station, which is located at the confluence of the Kankakee and Illinois Rivers (EA 2015; Exelon 2015b). Dresden Nuclear Station operates in either an indirect-open cycle or operates its cooling pond in a closed-cycle mode, similar to LSCS. NRC (2004) determined that the impacts from impingement would be SMALL on aquatic resources at Dresden Nuclear Station. LOE 1 Conclusion Based on the available impingement studies, intake of makeup water from the Illinois River appears to have a minor effect on the aquatic community in the vicinity of LSCS, and the NRC 4-40

Environmental Consequences and Mitigating Actions staff finds that impingement is not likely to noticeably alter or destabilize any important attributes of the community. Although fish and aquatic biota are also impinged at the lake screen house when cooling pond water is drawn into LSCSs cooling system, the impacts of impingement on the aquatic community within the cooling pond are unknown because they have not been addressed in studies. LOE 2: Entrainment Studies Exelon contracted EA to conduct a study to determine the entrainment rates among the fish and shellfish taxa in the Illinois River. As part of this study, EA (2015) collected icthyoplankton samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected samples using 0.5-m (1.6-ft) conical plankton nets with 505 micron mesh suspended from the forebay bridge in front of the river intake (see Figure 3.7-1). EA (2015) collected samples during the 2014 spawning season, from late April 2014 through August 2014, when icthyoplankton densities would likely be highest. EA (2015) extrapolated annual entrainment rates for each taxa based on the number of taxa collected during a 24-hour collection period, the volume of water that would be withdrawn during 1 year, and the volume of water withdrawn during the 24-hour collection period. EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 27 distinct taxa. The most common taxa included carps, minnows, and suckers, which combined comprised 79 percent of the ichthyoplankton sample. EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles. The most common taxa by life stage included lctiobinae yolk-sac larvae (24 percent), cyprinidae yolk-sac larvae (23 percent), and common carp yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent of the icthyoplankton samples (EA 2015). EA (2015) estimated the annual entrainment rate to be about 38 million organisms per year. The estimated annual entrainment rates at LSCS are approximately 28 to 38 percent of the entrainment rate at Dresden Nuclear Station, which is located at the confluence of the Kankakee and Illinois Rivers (EA 2015; Exelon 2015b). Dresden Nuclear Station operates in either an indirect-open cycle or operates its cooling pond in a closed-cycle mode, similar to LSCS. NRC (2004) determined that the impacts from entrainment would be SMALL on aquatic resources at Dresden Nuclear Station. LOE 2 Conclusion Based on the available entrainment studies, intake of makeup water from the Illinois River appears to have a minor effect on the aquatic community in the vicinity of LSCS, and the NRC staff finds that entrainment is not likely to noticeably alter or destabilize any important attributes of the community. Although fish and aquatic biota are also entrained at the lake screen house when cooling pond water is drawn into LSCSs cooling system, the impacts of entrainment on the aquatic community within the cooling pond are unknown because they have not been addressed in studies. LOE 3: Temporal Trends in Fish Populations in the Illinois River Impingement and entrainment from the withdrawal of makeup water from the Illinois River have removed individuals from the river ecosystem since LSCS began operating in 1982. Over this period of time, the aquatic community has changed in a number of ways, including species richness (the number of species present), species composition (the kinds of species present), 4-41

Environmental Consequences and Mitigating Actions and species evenness (the relative abundance of species). This LOE compares fish populations prior to and during operations to determine whether changes have occurred and if such changes can be attributed to LSCS operations. If impingement and entrainment were to affect fish within the vicinity of LSCS, fish abundances and species richness would likely be lower post-operation as compared to before operations. In the section below, the NRC staff made general characterizations of fish populations during preoperational and operational surveys. However, differences between time periods could occur for multiple reasons, including variations in sampling equipment, the frequency and timing of sampling events, and sampling locations. Furthermore, the lack of repeated samples over time prevented the NRC staff from conducting statistical analyses on the changes in fish populations over time. Therefore, the trends presented below for LSCS studies describe general patterns in fish populations that have not been tested for statistical significance. As discussed in Section 3.7, fish populations near LSCS have changed over time. The main trends have been an increase in species richness and increases in the abundance of species that are sensitive to poor water quality. For example, two commonly collected species during preoperational surveys, common carp (Cyprinus carpio) and white sucker (Catostomus commersonii), were not commonly collected during the 1999 or 2013 study (NRC 1978; EA 2000, 2014). OEPA (1987) classifies both of these species as pollution tolerant. On the other hand, brook silverside (Labidesthes sicculus), sand shiner (Notropis stramineus), smallmouth bass (Micropterus dolomieu), smallmouth buffalo (Ictiobus bubalus), golden redhorse (Moxostoma erythrurum), and blue gill (Lepomis macrochirus) were among the six most commonly collected species in the 1999 or 2013 study but were not commonly collected in the preoperational studies (NRC 1978; EA 2000, 2014). Five of these seven species are native species that are sensitive to declines in water quality or habitat degradation (Smith 2002; Lerczak 1996). These results suggest that the quality of aquatic habitat within the Illinois River near LSCS has improved since the 1970s. Similar trends of improved water quality, increased species richness, and increases in the relative abundance of pollution-sensitive species have been documented in several studies on the Illinois River (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012; Fritts 2013). These results suggest that the major changes in fish populations near LSCS are the result of improved water quality, likely from the protections provided in the Clean Water Act (CWA), advances in municipal and industrial waste treatment, agricultural conservation measures, and other factors. Conclusion Given that species richness and populations of pollution-sensitive fish have increased since LSCS began operations, and populations of pollution-tolerant fish have decreased, the NRC staff concludes that impingement and entrainment are not having a noticeable impact on temporal changes in fish population in the Illinois River near LSCS. Other factors, such as improved habitat diversity and quality, are having a more noticeable impact on the temporal patterns in fish populations (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012). LOE 4: Spatial Differences in Fish Populations in the Illinois River This LOE compares fish populations upstream and downstream of the river intake structure to determine whether spatial changes have occurred since LSCS began operating and if such changes can be attributed to LSCS operations. If impingement and entrainment were to affect fish populations within the vicinity of LSCS, fish abundances and species richness would likely be lower downstream of the river intake structure as compared to upstream of the river intake structure, due to the removal of fish, eggs, and larvae from impingement and entrainment. The NRC staff notes that this LOE may not conclusively determine whether LSCS operation affects populations of fish near LSCS due to the limited sample size and because some fish may 4-42

Environmental Consequences and Mitigating Actions migrate sufficient distances such that a noticeable difference would not likely be identified between samples collected immediately upstream and downstream of the intake. In the section below, the NRC staff made general characterizations of the fish populations upstream and downstream of the river intake. Neither EA (2014) nor the NRC staff conducted statistical analyses on the differences in fish populations among the sample sites. Therefore, the trends presented below for LSCS studies describe general patterns in fish populations that have not been tested for statistical significance. In 2013, EA (2014) conducted fish surveys and compared fish abundances and species richness between upstream and downstream of the river intake. During electrofishing surveys, EA (2014) collected more fish downstream of the intake (43 fish) as compared to upstream (36 fish). However, species richness was moderately higher upstream of the intake (13 species) compared to downstream of the intake (9 species). For seining samples, EA (2014) collected more fish and species of fish upstream (location 1; 245 fish; 6 species) as compared to the closest downstream location (location 2; 65 fish; 3 fish species). EA (2014) attributed the higher fish abundances and species richness upstream of the river intake to better habitat quality, particularly regarding instream cover for sunfish. The NRC staff is not aware of any studies to determine whether the heated effluent has affected the density of aquatic plants that may provide cover for fish. Rocks and tree limbs could also provide cover for fish. EA (2014) collected the most amount of fish and species of fish at the furthest downstream sampling site near South Kickapoo Creek (location 5; 906 fish; 12 species). During seining surveys, EA (2014) collected four species exclusively at the furthest downstream sampling site (location 5). EA (2014) attributed the high fish abundance and diversity at the furthest downstream location to its proximity to South Kickapoo Creek, as well as the habitat diversity at the site and the suitability of that location to seining. Conclusion Given that no clear pattern exists regarding the species richness and species abundances upstream and downstream of the river intake structure, the NRC staff concludes that impingement and entrainment are not having a noticeable impact on spatial patterns in fish population in the Illinois River near LSCS. Other factors, such as habitat diversity and quality, are likely having a more noticeable impact on temporal fish population trends near LSCS (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012). LOE 5: Engineered Design and Operational Controls In August 2014, EPA published a final rule establishing requirements under section 316(b) of the CWA for cooling-water intake structures at existing facilities (79 FR 48300). The final rule indicates that two basic approaches can reduce impingement and entrainment mortality: (1) flow reduction and (2) including technologies into the cooling-water intake design that gently exclude organisms or collect and return organisms without harm to the water body. The EPA also notes that two additional approaches can reduce impingement and entrainment but that these technologies may not be available to all facilities. The two additional approaches are: relocating the facilitys intake to a less biologically rich area in a water body and reducing the intake velocity. The LSCS CWS on the Illinois River incorporates several of these approaches. Flow Reduction Reducing the amount of water that is withdrawn for cooling purposes from a water body reduces the number of aquatic organisms that are drawn through the intake structure and subject to impingement or entrainment. Because LSCS uses a cooling-pond-based heat-dissipation system, the majority of cooling water needed for plant operation is drawn from the cooling pond 4-43

Environmental Consequences and Mitigating Actions rather than the Illinois River. The cooling pond system is similar to a closed-cycle cooling system in that water in the pond continues to be recirculated through the plant for cooling, and only makeup water (water lost to evaporation or discharged as blowdown) is drawn directly from the Illinois River. Depending on the quality of the makeup water, closed-cycle cooling systems can consume significantly less water than if the same facility were to use a once-through cooling system. Exelon (2014a) determined that the maximum withdrawal rate, with all three makeup pumps operating at capacity, would withdraw approximately 1.8 percent of the rivers 92-year annual average mean flow. Similarly, NRC (1978) estimated that the annual average amount of water withdrawn from the Illinois River for cooling pond makeup would be about 1 percent of the typical flow, or 3 percent of the 7Q10 (e.g., the 7-day, 10-year low flow) flow. Technologies That Exclude or Collect and Return Organisms The LSCS cooling system has several technologies that help exclude organisms from becoming impinged or entrained. Water enters the river screen house through an intake bay equipped with bar grills and 3/8-in. (9.5-mm) mesh travelling screens to prevent debris and aquatic biota from entering the system (Exelon 2014a). The EPA indicates that, ideally, traveling screens would be used with a fish handling and return system (79 FR 48300). LSCSs river screen house does not contain a fish return system (Exelon 2014a). However, the intake velocity (discussed below) should allow some fish to swim away and escape impingement. Intake Flow Water velocity associated with the intake structure greatly influences the rate of impingement and entrainment. The higher the approach velocity, through-screen velocity, or both, the greater the number of organisms that will be impinged or entrained. At an approach velocity of 0.5 ft/s (0.15 m/s) or less, most fish can swim away and escape from the intake current (79 FR 48300). As indicated in Section 3.1.3, water velocity within the intake channel ranges from 0.3 to 0.5 ft/s (0.1 to 0.2 m/s) with one pump operating to 0.6 to 1.0 ft/s (0.2 to 0.3 m/s) with two pumps operating (EA 2015). The velocity at the face of the travelling screens is 0.5 ft/s (0.2 m/s) during one-pump full-flow operation and 0.9 ft/s (0.3 m/s) during two-pump full-flow operation (EA 2015). Thus, when one pump is operating, the river screen house intake velocities are within the 0.5-fps (0.15-m/s) intake velocity recommended by EPA for protection of aquatic organisms. However, the through-screen velocity when two or three pumps are operating could contribute to impingement and entrainment effects. Best Technology Available On July 5, 2013, the Illinois EPA (IEPA) renewed LSCSs NPDES permit (No. IL0048151). Special Condition 15 relates to potential impacts from cooling water intake and whether LSCS utilizes the Best Technology Available (BTA) for cooling-water intake structures to prevent or minimize impingement mortality in accordance with the Best Professional Judgment (BPJ) provisions of 40 CFR 125.3. In the permit, IEPA determined that: The facility utilizes a closed-cycle recirculating cooling system, a 2058 acre cooling pond, for cooling of plant condensers and is determined to be the equivalent of BTA for cooling water intake structures to prevent/minimize impingement mortality in accordance with the BPJ provisions of 40 CFR 125.3 because it allows the facility to only withdraw the amount of water necessary to maintain the cooling pond level rather than the entire volume used for cooling of the plant condensers. Conclusion While flow control measures, traveling screens, and low intake velocities reduce the effects of impingement and entrainment mortality at LSCS, the lack of a fish return system and the 4-44

Environmental Consequences and Mitigating Actions through-screen velocity when two or three pumps are operating could contribute to impingement and entrainment effects. This LOE does not conclusively indicate whether impingement or entrainment at LSCS is creating detectable effects on the Illinois River aquatic community. Thus, this LOE, considered alone, is inconclusive. Overall Impingement and Entrainment Conclusion The NRC staff reviewed available impingement and entrainment studies, assessed spatial and temporal changes in fish populations near LSCS in the Illinois River, and considered engineered designs and operational controls that affect impingement and entrainment rates. The NRC staff concludes that the impacts to aquatic resources in the Illinois River from impingement and entrainment would be SMALL and would not likely noticeably alter aquatic resources in the vicinity of LSCS based on the following:

  • relatively low impingement and entrainment rates,
  • increases in species richness and relative abundance of pollution-sensitive species since LSCS began operations,
  • reduced flow due to operation as a closed-cycle system with the use of the LSCS cooling pond,
  • bar grills and traveling screens with 3/8 in. (0.95-cm) openings to exclude fish, and
  • IEPAs determination of BTA for use of a closed-cycle recirculating cooling system.

Although fish and aquatic biota are also impinged and entrained at the cooling pond screen house when cooling pond water is drawn into LSCSs cooling system, the impacts of impingement on the aquatic community within the cooling pond are unknown because Exelon has not conducted any impingement or entrainment studies at the cooling pond intake, nor have any consistent fish monitoring studies been implemented in the cooling pond. The NRC staff notes that the use of bar grills and traveling screens with 3/8-in. (0.95-cm) openings would reduce the impacts from impingement and entrainment in the cooling pond. 4.7.1.3 Thermal Impacts on Aquatic Organisms In the GEIS (NRC 2013d), the NRC determined that thermal impacts on aquatic organisms is a Category 2 issue (see Table 4-7) that requires site-specific evaluation during each license renewal review for plants with once-through cooling systems or cooling ponds, such as LSCS. The NRCs regulations at 10 CFR Part 51 concerning license renewal reviews and the GEIS direct the NRC to consider all aquatic resources that may be affected by plant operations, regardless of the type of water body in which such resources reside. For instance, Section 4.2.2 of the 1996 GEIS specifically notes that aquatic biota of cooling ponds may be affected by thermal discharges and that these effects should be considered the same as those considered for once-through cooling systems, except that such effects mainly influence aquatic communities that did not exist before the creation of the cooling pond. The 2013 GEIS did not identify new information that would alter this methodology or alter any conclusions regarding impacts to aquatic populations in cooling ponds. Consideration of the impact on aquatic resources in cooling ponds is consistent with previous NRC license renewal reviews (e.g., NRC 2008b, 2013c, 2015b). The NRC staff used a modified WOE approach to evaluate thermal impacts on the aquatic resources in the Illinois River and LSCS cooling pond. The NRC staff examined the five LOEs as follows. 4-45

Environmental Consequences and Mitigating Actions LOE Description 1 Results of past NRC reviews on thermal impacts of LSCS operations 2 A review of regulatory and administrative controls on thermal effluents 3 Population trends of indicator species 4 Health of fish populations as an indicator of water quality 5 Fish kills LOE 1: Past NRC Reviews The NRC (1978) previously assessed the potential thermal impacts of LSCS operations in the Final Environmental Impact Statement for LSCS Operations. The NRC (1978) estimated the size of the thermal plume under two scenarios, one in March and one in July, using relatively conservative assumptions (e.g., the 7Q10 low-flow estimate, maximum blowdown rate, 100 percent load factor). For the March scenario, the NRC (1978) determined that the 5 °F (3 °C) isotherm would range from 2,500 m2 (27,000 ft2) in March to 400 m2 (4,300 ft2) in July. The thermal plume would cover approximately 9 percent of the river in March and 8 percent in July (NRC 1978). The zone of passage for fish would be 91 to 92 percent, which would be greater than the minimum 75 percent required by Illinois water quality standards. Thus, the NRC (1978) concluded that juvenile and adult fish would either be able to avoid the thermal plume, or a small number of organisms may be exposed to the thermal plume for a short period of time. The NRC staff concluded that the discharge impacts would likely be minimal and of little influence on the natural biotic populations in the Illinois River. LOE 1 Conclusion The NRCs past review of the thermal impacts from LSCS discharges to the Illinois River indicated that the thermal impacts on the aquatic community would be minor. LOE 2: Regulatory and Administrative Controls The Illinois Administrative Code (IAC) and the LSCS NPDES permit (IEPA 2013) impose regulatory controls on LSCSs thermal effluent that ensure that impacts on the aquatic environment are reduced or mitigated. Title 35, Environmental Protection, Section 302, Water Quality Standards, of the IAC contains stipulations pertaining to effluent temperature as well as mixing zones and zones of initial dilution. The following limitations and requirements included in Section 302 pertain to effluent temperature and serve to protect aquatic biota from the effects of such effluents. The maximum temperature rise shall not exceed 2.8 °C (5 °F) above natural receiving water body temperatures. [35 IAC 302.211(d)] Water temperature at representative locations in the main river shall at no time exceed 33.7 °C (93 °F) from April through November and 17.7 °C (63 °F) in other months. [35 IAC 302.211(e)] Several IAC stipulations pertaining to mixing zones also protect aquatic biota from thermal effluents. Mixing is not allowed in waters which include a tributary stream entrance. [35 IAC 302.102(b)(2)] Mixing is not allowed in waters containing mussel beds, endangered species habitat, fish spawning areas, areas of important aquatic life habitat, or any other natural features vital to the well-being of aquatic life. [35 IAC 302.102(b)(4)] Mixing must allow for a zone of passage for aquatic life. [35 IAC 302.102(b)(6)] 4-46

Environmental Consequences and Mitigating Actions The area and volume of mixing must not contain more than 25 percent of the cross-sectional area or volume of a stream and must not intersect any body of water in such a manner that the maintenance of aquatic life in the body of water as a whole would be adversely affected. [35 IAC 302.102(b)(7) and (8)] The area and volume in which mixing occurs must be as small as is practicable, and in no circumstances larger than 26 ac (11 ha). [35 IAC 302.102(b)(12)] The LSCS NPDES permit (IEPA 2013) also contains requirements related to thermal effluents. Special Condition 3 of the permit, which limits the maximum temperature rise above ambient conditions and maximum water temperatures during various times of the year, mirrors the temperature requirements at 35 IAC 302.211 listed above. The NRC staff reviewed the results of recorded maximum cooling pond blowdown temperatures to the Illinois River and associated calculations of river mixing zone temperatures as reported in the discharge monitoring reports (DMR) for the past 5 years (2010 through 2014) and as compiled by Exelon (Exelon 2015b). Based on the NRCs staff review and Exelons responses to the NRCs RAIs, LSCS has received no notices of violation associated with NPDES permitted discharges during the 2010 through 2014 time period (see Section 3.5.1). Nonetheless, Exelon requested three variances with respect to LSCSs effluent discharges to the Illinois River and associated river mixing zone temperature limits. Specifically, these variances (IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in March, July, and August 2012, respectively, due to unusual weather conditions and associated high ambient river water temperatures that impacted the ability for LSCS thermal discharges to meet the requirements of Special Condition 3 of LSCSs NPDES permit. This limits the number of temperature excursion hours to 1 percent (87.6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />) of the hours in a 12-month period, ending with any month (see footnote d in Table 3-7 of this document). During the variance period(s), Exelon was required, in part, to continuously monitor both the discharge and receiving water temperatures and visually inspect all discharge areas at least three times each day to assess the impact on aquatic life. These thermal discharge excursions were not found to have any impact on aquatic life (Exelon 2015b). Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan and associated procedures to mitigate the impacts of summer drought and/or high river temperature and river low-flow conditions. Depending on predefined conditions set forth in the plan and implementing procedures, such actions may include a combination of monitoring and modeling of river intake and mixing zone temperatures; manipulation of the water level of the cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the technical specification limits on the condenser inlet temperature from the cooling pond (Exelon 2014a; 2015a). LOE 2 Conclusion The LSCS thermal effluent is limited by the IAC and the LSCS NPDES permit to ensure that it does not create adverse effects on the aquatic communities in the Illinois River. In the past 5 years, Exelon received no notices of violations and IEPA granted three provisional variances to allow higher-than-permitted temperatures. Exelon reported no fish kills or other events to the IEPA or the NRC that would indicate adverse environmental effects resulting from the provisional variances. The NRC depends on the State to enforce the regulatory controls in place at LSCS and effectively ensure that any environmental effects to Illinois River aquatic 4-47

Environmental Consequences and Mitigating Actions communities are not detectable or are so minor as to neither destabilize nor noticeably alter the community. LOE 3: Spatial and Temporal Trends for Indicator Species Heat shock has the potential to kill or injure individual fish and other organisms in the Illinois River ecosystem. This LOE compares the population trends of indicator species prior to and during operations and upstream and downstream of the discharge structure to determine whether changes have occurred and if such changes can be attributed to LSCS operations. If heat shock were to affect aquatic resources within the vicinity of LSCS, the NRC staff would expect the following:

  • Fish and macroinvertebrate abundances and species richness would likely be lower after operations began as compared to prior to operations, and lower downstream as compared to upstream of the discharge, and
  • Populations of pollution-sensitive fish and macroinvertebrates would likely be lower after operations began as compared to prior to operations, and lower downstream of the discharge as compared to upstream of the discharge.

As described in LOE 3 and 4 in Section 4.7.1.2, the NRC staff reviewed fish population trends in the Illinois River near LSCS from the 1970s through 2013 (NRC 1978; EA 2000, 2014). The NRC staff determined that species richness and populations of pollution-sensitive fish have increased since LSCS began operations, and populations of pollution-tolerant fish have decreased. In addition, the NRC staff did not identify any clear patterns regarding the species richness and species abundances upstream and downstream of the river intake and discharge structures. Therefore, the thermal effluent is not likely having a noticeable impact on the temporal patterns of fish populations in the Illinois River near LSCS. Other factors, such as habitat diversity and improved water quality, are likely having a more noticeable impact on the spatial patterns in fish populations. As described in Section 3.7.1.1.2, EA (2000, 2014) compared the macroinvertebrate communities upstream and downstream of the LSCS discharge. During 1999 surveys, EA (2000) determined that the dominate macroinvertebrate taxa at sites both upstream and downstream of the discharge structure were tolerant to poor water quality. EA (2000) also determined that both total species richness and the number of Ephemeroptera, Plecoptera, and Trichoptera (EPT) species, which are considered intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) compared to upstream (location 1) of the discharge structure. During 2013 surveys, EA (2014) observed dominant taxa that were relatively tolerant to poor water quality as well as dominant taxa that were relatively intolerant or facultative to poor water quality, both upstream and downstream of the discharge. Similarly, species richness among pollution-sensitive EPT was similar among all locations, ranging from three to five taxa (EA 2014). Given that the NRC staff did not identify any clear patterns regarding the species richness and species abundances upstream and downstream of the river discharge structures, the thermal effluent is not likely having a noticeable impact on fish populations near LSCS. Other factors, such as habitat diversity and quality, are having a more noticeable impact on the spatial patterns in fish populations. LOE 3 Conclusion Given that species richness and populations of pollution-sensitive fish have increased since LSCS began operations and no clear pattern exists regarding the species richness and species abundances upstream and downstream of the discharge, the NRC staff concludes that heat 4-48

Environmental Consequences and Mitigating Actions shock is not having a noticeable impact on aquatic resources in the Illinois River near LSCS. Other factors, such as habitat diversity and quality, are likely having a more noticeable impact on the temporal and spatial patterns in fish populations. LOE 4: Health of Fish Populations as an Indicator of Water Quality Fish parasites and anomalies generally occur most often in fish that inhabit waterbodies with poor water quality (OEPA 1989). Therefore, if the LSCS thermal effluent were to result in heat stress for fish near LSCS, one would expect an increase in the occurrence of parasites and anomalies since operations began. During preoperational studies, the NRC (1978) noted a high level of external parasitism, disease, and physical abnormalities associated with fish near LSCS. The NRC (1978) did not provide any quantitative estimates of the amount of fish that had external parasitism, diseases, or physical abnormalities. In 1999, EA (2000) observed a total of 63 fish (6.6 percent of the catch) with DELT (deformities, erosions, lesions, or tumors) anomalies. Channel catfish (Ictalurus punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin erosion (52 percent) and deformities (38 percent). In 2013, EA (2014) observed a 0.2-percent DELT rate of all the 1,295 fish collected during electrofishing and seining studies in the Illinois River. Both fish were freshwater drum that exhibited eroded fins. One fish was collected upstream of the discharge structure (location 1) and the other fish was collected downstream of the discharge structure (location 2). EA (2014) did not observe any fish with parasites. These results suggest that the quality of aquatic habitat within the Illinois River near LSCS has improved since the 1970s. Similar trends of improved water quality and decreased rates of fish parasites and DELT anomalies have been documented in other studies on the Illinois River. For example, McClelland and Pegg (2005) reviewed trends in fish parasites and anomalies from Illinois Natural History Survey (INHS) data and found a decrease in anomalies over time, with no anomalies in 2004. These results suggest that the major changes in fish parasites and physical anomalies on fish near LSCS are the result of improved water quality, likely from the protections provided in the CWA, advances in municipal and industrial waste treatment, implementation of agricultural conservation measures, and other factors. LOE 4 Conclusion Given the decreasing rate of fish parasites and DELT anomalies observed on fish in the Illinois River near LSCS, the NRC staff concludes that heat shock from LSCSs thermal effluent is not having a noticeable impact on fish health in the Illinois River near LSCS. Other factors, such as water quality, are likely having a more noticeable impact on the rate of fish parasites and DELT anomalies (Lerczak 1996; McClelland and Pegg 2005; McClelland et al. 2012). LOE 5: Fish Kills Since 2001, Exelon has reported four fish kill events in the LSCS cooling pond; Section 3.7.4 describes these events. Exelon attributes these fish kills to high cooling pond temperatures as a result of high summer temperatures combined with low winds and high humidity (Exelon 2001, 2009, 2010). Each event resulted in the mortality of several hundred to several thousand fish. The largest of these events occurred in July 2001 and included approximately 94,500 dead fish (Exelon 2001). The majority of dead fish (96 percent) were gizzard shad (90,800). 4-49

Environmental Consequences and Mitigating Actions The majority of the fish in kills since 2001 were either gizzard shad or threadfin shad (Exelon 2001, 2009, and 2010). Fish kills have had a noticeable impact on shad populations in the cooling pond. For example, during Illinois Department of Natural Resources (IDNR) surveys in the cooling pond, the gizzard shad catch per hour was 451 in 2000 and in 2001, after the largest fish kill, it was 108 (Exelon 2002). Similarly, in a status review of the cooling pond in 2011, 2012, and in 2014, IDNR noted the decline in the threadfin shad population due to fish kills during each summer (Exelon 2015b). Shad populations generally recovered within 1 year after a kill occurred (Exelon 2002, 2015a) and loss of shad did not substantially affect the community dynamics within the cooling pond (Exelon 2010, 2015a). The NRC staff also did not identify any long-term or destabilizing changes from previous fish kills. Stocked species are generally a small percentage of fish affected by fish kills in the LSCS cooling pond (Exelon 2001, 2009, 2010). IDNR generally stocks the pond with fish that are tolerant to high temperatures. In addition, if a fish kill or other environmental conditions have negatively impacted a stocked species, IDNR can increase the stocking level during the following spring (Exelon 2014a, 2015b). Further, IDNR has often reported abundant, growing populations of various stocked fish, such as striped bass hybrids and channel catfish (IDNR 2007, 2009; Exelon 2015b). The NRC expects that fish kills would continue during the proposed license renewal period because fish kills in the LSCS cooling pond can occur when temperatures rise above 95 °F (35 °C), the temperature at which most fish in the cooling pond are thermally stressed (Exelon 2014a, 2015a). Past temperature records indicate that the cooling pond regularly exceeded 95 °F (35 °C) during the past 10 summers (Exelon 2015b). Further, EA concluded that the LSCS cooling pond has reached a point where fish kills should be expected every summer (Exelon 2002). On August 3, 2015, the NRC staff published an Environmental Assessment in the Federal Register (80 FR 46062) as part of the NRC staffs review of Exelons application to amend LSCS Technical Specification 3.7.3, Ultimate Heat Sink, by increasing the cooling water temperature supplied to the plant from the ultimate heat sink (UHS) from 101.25 degrees Fahrenheit (°F) (38.47 degrees Celsius (°C)) to a variable limit between 101.25 and 104 °F (38.47 and 40 °C), depending on the time of day. On November 19, 2015, NRC approved the amendment (NRC 2015g). In its Environmental Assessment, the NRC staff determined that raising the maximum allowable temperature of the UHS would increase cooling pond water temperatures, especially during extreme warm weather conditions. Fish kills would be more likely to occur, especially when cooling pond temperatures rise above 95 °F (35 °C), the temperature at which most fish in the cooling pond are thermally stressed. The NRC staff concluded that there would likely be an increase in the number or intensity of fish kills, and that the majority of fish killed would be gizzard shad and threadfin shad. The increase in intensity and number of fish kills would not result in a significant impact because the cooling pond is a managed ecosystem where fish populations affected by fish kills generally recover within a year and do not significantly alter the fish community structure. Lastly, any impacts from the increased temperatures would be confined to the cooling pond and would not affect aquatic resources in the Illinois River. Exelon leases the cooling pond to the IDNR for IDNR to manage and stock a portion of the cooling pond. However, Exelon retains the authority to terminate the lease. If the lease were to be terminated during the license renewal period, the NRC staff assumes that the fish community would continue to exist in the cooling pond without stocking, although the distribution of species and population sizes may change without artificial replenishment and with the elimination of recreational fishing pressure. The NRC staff made this determination based on observations of 4-50

Environmental Consequences and Mitigating Actions other cooling ponds at nuclear power plants that are not stocked with fish but contain a growing fish community based on the withdrawal of water from a river (e.g., NRC 2013c). Exelon has not reported any fish kills on the Illinois River since LSCS began operating. Furthermore, discharge to the Illinois River remained within the NPDES-allowed limits during each of the reportable fish kills (Exelon 2015b). LOE 5 Conclusion No fish kills have occurred on the Illinois River. Thus, this LOE indicates that the effects of the thermal discharge on Illinois River aquatic biota are not detectable. Fish kills in the LSCS cooling pond are expected to occur during the license renewal term (Exelon 2002, NRC 2015g). The NRC staff concluded that such fish kills have noticeable effects on threadfin and gizzard shad, based on a decreased population size following a fish kill. Fish kills are not destabilizing to shad populations because they tend to recover within a year. Stocked species are a minor portion of affected fish during most fish kills, and therefore, the NRC staff concludes that fish kills do not noticeably alter populations of stocked species. In addition, if a fish kill negatively impacts a stocked species, IDNR can increase the stocking level during the following spring. Summary of Thermal Impacts Conclusion The NRC staff reviewed past NRC studies of thermal impacts, regulatory and administrative controls to limit the temperature in the LSCS discharge, spatial and temporal patterns of species richness and pollution-sensitive species, the health of fish prior to and during LSCS operations, and the occurrence of fish kills. The NRC staff concluded that the impacts to aquatic resources from heat shock would be SMALL for all fish within the Illinois River and for stock fish within the LSCS cooling pond, based on the following:

  • fish could avoid the thermal plume, which would cover up to 9 percent of the Illinois River,
  • the LSCS thermal effluent is limited by the IAC and the LSCS NPDES permit,
  • species richness and the relative abundance of pollution-sensitive species have increased since LSCS began operations,
  • the occurrence of fish parasites and physical abnormalities, which are indicative of poor water quality, has decreased since LSCS began operations, and
  • stocked species are a minor portion of affected fish during most fish kills in the LSCS cooling pond.

The NRC staff determined that fish kills in the LSCS cooling pond would continue to occur during the license renewal term and would have noticeable effects on threadfin shad and gizzard shad, based on a decreased population size following a fish kill. Fish kills would not be destabilizing to shad populations because they tend to recover within a year. Therefore, the NRC staff concluded the impacts from heat shock would be MODERATE to gizzard shad and threadfin shad in the LSCS cooling pond. The applicant has proposed no mitigation to reduce the MODERATE environmental impacts associated with heat stress to gizzard shad and threadfin shad in the cooling pond (Exelon 2015b). However, because the cooling pond is a highly managed system, any cascading effects resulting from the loss of shad (such as a reduction in prey for stocked species, which in turn could affect a stocked species population) could be mitigated through IDNRs annual stocking and continual management of the pond. 4-51

Environmental Consequences and Mitigating Actions 4.7.1.4 Water Use Conflicts with Aquatic Resources In the GEIS (NRC 2013d), the NRC determined that effects of water use conflicts on aquatic resources is a Category 2 issue (see Table 4-7) that requires site-specific evaluation during each license renewal review. Water use conflicts occur when the amount of water needed to support aquatic resources is diminished as a result of demand for agricultural, municipal, or industrial use or decreased water availability due to droughts, or a combination of these factors. The mean annual discharge of the Illinois River (described in Section 3.5.1.1) measured at the USGS gage at Marseilles, Illinois, is 10,750 cfs (304 m3/s). As described in Section 3.5.1.2, LSCSs average surface water withdrawal rate from the Marseilles Pool of the Illinois River is 105 cfs (2.96 m3/s or 67.8 mgd), with consumptive use averaging about 49.7 cfs (1.4 m3/s or 32.1 mgd). This consumptive use is equivalent to about 0.5 percent of the Illinois Rivers average annual flow. During periods of low flow, LSCSs current consumptive water use (i.e., 49.7 cfs (1.4 m3/s or 32.1 mgd)) represents a 0.9- and a 1.1-percent reduction, respectively, in the flow of the river downstream of the LSCS site. As previously discussed in Section 3.5.1.2 of this SEIS, Exelon maintains an Extreme Heat Implementation Plan that is part of an overall Summer Readiness Plan. The Extreme Heat Implementation Plan provides procedural guidance to plant personnel for responding to worst-case summer weather and hydrologic conditions to ensure compliance with LSCSs NPDES permit for thermal discharge limits and to safeguard plant equipment. As necessary, plant personnel run thermal models and will adjust makeup pumping rates to the cooling pond or the rate of blowdown to the river to maintain permit compliance. Under extreme cases, it may be necessary for Exelon to reduce LSCSs power output or to shut down the plant (e.g., under conditions of extremely low water levels). The amount of Illinois River water LSCS consumes is minor in comparison to the flow of water past the plant, and administrative mechanisms are in place so LSCS does not consume an amount that would be harmful to aquatic biota during low-flow conditions. The NRC staff did not identify any information that indicates that the Illinois River biota are affected by the loss of river water consumed by LSCSs makeup water withdrawals. The NRC staff concludes that water use conflicts would not occur from the proposed license renewal or would be so minor that the effects on aquatic resources would be undetectable. Thus, the NRC staff concludes that the impacts of water use conflicts on aquatic resources during the proposed license renewal term would be SMALL. 4.7.2 No-Action Alternative If LSCS were to cease operating, impacts to aquatic ecology would decrease or stop following reactor shutdown. Some withdrawal of water from the Illinois River would continue during the shutdown period as the fuel is cooled, although the amount of water withdrawn would decrease over time. The reduced demand for cooling water would substantially decrease the effects of impingement, entrainment, and thermal effluents. These effects would likely stop following the removal of fuel from the reactor cores and shutdown of the spent fuel pool. Given the small area of the thermal plume in the Illinois River under normal operating conditions (less than 9 percent), effects from cold shock are unlikely. The cooling pond, however, would likely experience shifts in the relative abundances of fish populations because less heat-tolerant species would no longer be stressed by thermal additions to the pond. Some fish populations, such as stocked recreational species that thrive in warmer waters, may experience population declines or cease to occur in the cooling pond. NUREG-0586 (NRC 2002) concludes generically that impacts to aquatic ecology during decommissioning activities would be SMALL for facilities at which the decommissioning 4-52

Environmental Consequences and Mitigating Actions activities would be limited to existing operational areas. In the case of LSCS, the NRC staff did not identify any effects that would have more than minor impacts on aquatic resources. Thus, the NRC staff concludes that the impacts of the no-action alternative on aquatic resources during the proposed license renewal term would be SMALL. 4.7.3 New Nuclear Alternative Construction of a new nuclear alternative would occur at an existing nuclear power plant site (other than the LSCS site) or a retired coal plant site. Construction activities could degrade water quality of nearby streams, ponds, or rivers through erosion and sedimentation; result in loss of habitat through pond or wetland filling; or result in direct mortality of aquatic organisms from dredging or other in-water work. Due to the relatively short-term nature of construction activities, these effects would likely be relatively localized and temporary. Siting the plant on an existing site could make use of existing transmission lines, roads, parking areas, and other infrastructure, which would limit the amount of habitat disturbance that would be required. Less habitat disturbance would create less erosion and sedimentation. The construction of intake and discharge structures could result in direct mortality of individuals as well as water quality degradation. Appropriate permits would ensure that water quality impacts would be addressed through mitigation or BMPs, as stipulated in the permits. The EPA, USACE, or the State would oversee applicable permitting, including a CWA Section 404 permit, Section 401 certification, and Section 402(p) NPDES general stormwater permit. The NRC (2013a) has completed the review of one combined license application to build and operate a new nuclear plant in the ROI (Fermi 3 in Michigan) and concluded that construction would have SMALL impacts on aquatic resources. Without more specific details on the location of the new nuclear alternative, the NRC staff finds it reasonable to adopt its previous construction conclusions regarding Fermi 3 for the construction portion of this alternative. Operational impacts would include those listed in Table 4-7, and the GEIS (NRC 2013d) conclusions of SMALL for Category 1 issues in the table would apply during the operational phase of the new nuclear alternative. Because this alternative would use a closed-cycle system, impingement, entrainment, and thermal effects would also be SMALL. Water use conflicts with aquatic resources would depend on the site location, water body, and specific aquatic community present and cannot be determined without more specific details on the location of this alternative. The NRC staff concludes that the impacts to aquatic resources from construction and operation of a new nuclear alternative would be SMALL. 4.7.4 IGCC Alternative Construction of an IGCC alternative would occur at the LSCS site or another existing power plant site in the ROI. The GEIS (NRC 2013d) indicates that the impacts of new power plant construction on ecological resources would be qualitatively similar. Thus, those impacts discussed under the new nuclear alternative would apply during the construction phase. Thus, construction impacts would be SMALL. Operation of the IGCC alternative would require less cooling water than LSCS because the plant would operate with a closed-cycle system. Accordingly, impingement, entrainment, and thermal effects on aquatic resources would likely be smaller than for continued operation of LSCS, though the exact magnitude would depend upon the water body and specific aquatic communities present. Chemical discharges from the cooling system would be similar to those at LSCS. Operation would require coal deliveries, cleaning, and storage, which would require periodic dredging (if coal is delivered by barge); create dust, sedimentation, and turbidity; and 4-53

Environmental Consequences and Mitigating Actions introduce trace elements and minerals into the water. Air emissions from the IGCC units would include small amounts of sulfur dioxide, particulates, and mercury that would settle on water bodies or be introduced into the water from soil erosion. If the IGCC plant were located on the same water body (the Illinois River) in the vicinity of the LSCS site, overall operational impacts would be less than for the continued operation of LSCS because of the reduced impingement, entrainment, and thermal effects. However, without knowing the location of the IGCC plant, the associated water body, aquatic species, and their interactions within the ecosystem, the NRC staff cannot assume that overall impacts of operation of an IGCC plant would be less than those for the continued operation of LSCS. The NRC staff concludes that the impacts to aquatic resources from construction of an IGCC plant would be SMALL and the impacts from operation would be SMALL to MODERATE. 4.7.5 NGCC Alternative Construction of an NGCC alternative would occur at the LSCS site. The GEIS (NRC 2013d) indicates that the impacts of new power plant construction on ecological resources would be qualitatively similar. Thus, those impacts discussed under the new nuclear alternative would apply during the construction phase. Construction of new pipelines, if necessary, could impact previously undisturbed habitats. This impact would vary depending on the location of the plant and would be more likely to impact terrestrial resources than aquatic resources. Because the NGCC alternative would be built at the LSCS site, new pipelines could be collocated in existing corridors to reduce impacts. Overall, construction impacts would be SMALL. Operation of the NGCC alternative cooling system would be qualitatively similar to the IGCC alternative but would result in smaller impacts because the NGCC alternative would consume about half as much cooling water. Air emissions from the NGCC units would include nitrogen oxide, carbon dioxide, and particulates that would settle on water bodies or be introduced into the water from soil erosion. Given that the NGCC plant would be located on the same water body (the Illinois River) as LSCS, overall operational impacts would be less than for the continued operation of LSCS, due to the reduced impingement, entrainment, and thermal effects, which were determined to be SMALL for aquatic resources in the Illinois River. The NRC staff concludes that the impacts to aquatic resources from construction and operation of an NGCC plant would be SMALL. 4.7.6 Combination Alternative (NGCC, Wind, Solar) The NGCC portion of this alternative would be located at the LSCS site. Construction and operation impacts would be qualitatively similar to those discussed for the NGCC alternative but would be much less in magnitude because of the smaller footprint of the plant, reduced cooling water consumption, and lowered air emissions. The wind and solar portions of the alternative, which account for 85 percent of the alternatives power generation, would not require cooling or consumptive water use during operation and thus, would not affect aquatic resources. The NRC staff concludes that the impacts on aquatic resources from the combination alternative would be SMALL. 4.7.7 Purchased Power Alternative The purchased power alternative would have wide-ranging impacts that are hard to specifically assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI. This alternative would likely have little to no construction impacts because it would include power from already-existing power generating facilities, and 4-54

Environmental Consequences and Mitigating Actions the types of operational impacts would be similar to the effects discussed in the preceding alternative sections. This alternative would be more likely to intensify already existing effects at power generating facilities than create wholly new effects on aquatic species and habitats. Existing facilities would likely have permits with appropriate mitigation, BMPs, or other procedures in place to ensure that effects to the environment during operations are minimized. The NRC staff concludes that the impacts on aquatic resources from the purchased power alternative would be SMALL. 4.8 Special Status Species and Habitats This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on special status species and habitats. 4.8.1 Proposed Action Section 3.8 describes the special status species and habitats that have the potential to be affected by the proposed action. The discussion of species and habitats protected under the Endangered Species Act of 1973, as amended (ESA), includes a description of the action area as defined by the ESA section 7 regulations at 50 CFR 402.02. The action area encompasses all areas that would be directly or indirectly affected by the proposed LSCS license renewal. Table 4-8 lists the one site-specific (Category 2) issue related to special status species and habitats applicable to LSCS. Appendix C contains information on the NRC staffs consultation with the U.S. Fish and Wildlife Service (FWS) for the proposed action pursuant to section 7 of the ESA. No listed species under the National Marine Fisheries Services (NMFS) jurisdiction occur in the action area, therefore, the NRC staff did not consult with NMFS. Table 4-8. Special Status Species and Habitat Issues Issue GEIS Section Category Threatened, endangered, and protected species, critical habitat and 4.6.1.3 2 essential fish habitat Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 Correspondence In late February 2015, the NRC staff filled in an online form to obtain an updated protected species list for LSCS on the FWSs Environmental Conservation Online System, Information for Planning and Conservation. The FWS (2015b) responded with a list of threatened and endangered species that may occur in the project location and may be affected by the Federal action. In October 2015, the NRC staff checked the FWS (2015a) online Illinois County distribution of listed species for updates. Analysis and Determination of Effects Exelon (2014a) reports that no Federally listed species identified in Section 3.8, have been reported in the action area and no designated or proposed critical habitat under the ESA occurs in the action area. Thus, the NRC staff concludes that the proposed action would have no effect on the Federally listed species identified in Section 3.8. The FWS (2014) does not typically provide its concurrence with no effect determinations by Federal agencies. Thus, the ESA 4-55

Environmental Consequences and Mitigating Actions does not require further informal consultation or the initiation of formal consultation with the FWS for the proposed license renewal. ESA regulations at 50 CFR 402.12(f)(4) direct Federal agencies to consider cumulative effects as part of the proposed action effects analysis. Under the ESA, cumulative effects are defined as those effects of future State or private activities, not involving Federal activities, that are reasonably certain to occur within the action area of the Federal action subject to consultation (50 CFR 402.02). Unlike the NEPA definition of cumulative impacts (see Section 4.16), cumulative effects under the ESA do not include past actions or other Federal actions requiring separate ESA section 7 consultation. When formulating biological opinions under formal section 7 consultation, the FWS and the National Marine Fisheries Service (NMFS) (FWS and NMFS 1998) consider cumulative effects when determining the likelihood of jeopardy or adverse modification. Therefore, consideration of cumulative effects under the ESA is necessary only if listed species will be adversely affected by the proposed action (FWS 2014). Since the NRC staff concludes that no species would be adversely affected by license renewal, the NRC staff did not assess cumulative effects. Reporting Requirements If in the future, a Federally listed species is observed on the LSCS site, the NRC has measures in place to ensure that NRC staff would be appropriately notified so that the NRC staff could determine the appropriate course of action. If the renewed licenses have not yet been issued, the NRCs response could include the initiation of consultation pursuant to section 7 of the ESA. LSCSs Unit 1 and Unit 2 operating licenses, Appendix B, Environmental Protection Plan (see NRC 2001), require Exelon to report to the NRC within 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> any unusual or important event that indicates or could result in significant environmental impact causally related to plant operation. The licenses give the specific example of mortality or unusual occurrence of any species protected by the Endangered Species Act of 1973. Additionally, the NRCs regulations containing notification requirements require that operating nuclear power reactors report to the NRC within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> any event or situation, related toprotection of the environment, for which a news release is planned or notification to other government agencies has been or will be made (10 CFR 50.72(b)(2)(xi)). Such notifications include reports regarding Federally listed species, as described in Section 3.2.12 of NUREG-1022, Event Reporting Guidelines for 10 CFR 50.72 and 50.73 (NRC 2013b). Special Status Species and Habitats Impacts Summary Table 4-9 summarizes the NRC staffs findings. Table 4-9. Federally Listed Species and Designated Habitat in LaSalle County, Illinois, and NRC Effect Determinations for Proposed LSCS License Renewal Federally Listed Federal Group Species Common Name Status(a) Determination Clams and Mussels Plethobasus cyphyus sheepnose mussel E no effect Flowering Plants Boltonia decurrens decurrent false aster T no effect Platanthera leucophaea eastern prairie fringed T no effect orchid Delea foliosa leafy prairie clover E no effect Mammals Myotis sodalis Indiana bat E no effect Myotis septentrionalis northern long-eared bat T no effect 4-56

Environmental Consequences and Mitigating Actions Federally Listed Federal Group Species Common Name Status(a) Determination Critical Habitat Myotis sodalis Indiana bat no effect (a) E=endangered; T=threatened Sources: FWS 2015a, 2015b 4.8.2 No-Action Alternative Under the no-action alternative, the plant would shut down. Federally listed species and designated critical habitat can be affected not only by operation of nuclear power plants but also by activities during shutdown. The ESA action area for the no-action alternative would most likely be the same as discussed in Section 3.8. The plant would require substantially less cooling water, so potential impacts to aquatic species and habitats discussed in Section 4.8.1 would be reduced, although the plant would still require some cooling water for some time. Changes in land use and other shutdown activities might affect terrestrial species differently than under continued operation. Under the no-action alternative, the NRC would assess the need for ESA consultation if any activities associated with plant shutdown have the potential to affect a Federally listed species and if the activities meet the criteria in 50 CFR Part 402 for initiation of section 7 consultation. The ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct. In the case of a take, ESA section 7 requires that the NRC initiate consultation with the FWS or NMFS. If consultation was initiated and then completed, the implementing regulations at 50 CFR 402.16 also direct Federal agencies to reinitiate consultation in circumstances where (a) the incidental take limit in a biological opinion is exceeded, (b) new information reveals effects to Federally listed species or designated critical habitats that were not previously considered, (c) the action is modified in a manner that causes effects not previously considered, or (d) new species are listed or new critical habitat is designated that may be affected by the action. An ESA section 7 consultation could identify impacts on Federally listed species or critical habitat, require monitoring and mitigation to minimize such impacts, and provide a level of exempted takes. Regulations and guidance regarding the ESA section 7 consultation process are provided in 50 CFR Part 402 and in the Endangered Species Consultation Handbook (FWS and NMFS 1998). Typically, the effects on ESA-listed aquatic species would be smaller than the effects under continued operation but would depend on the listed species and habitats present if shutdown were to occur. The types and magnitudes of adverse impacts to terrestrial ESA-listed species would depend on the shutdown activities and the listed species and habitats present when the alternative is implemented. Therefore, the NRC cannot forecast a particular level of impact for this alternative. 4.8.3 New Nuclear Alternative This alternative entails shutdown and decommissioning of LSCS and construction of a new nuclear unit at an alternative industrial location, possibly in Indiana, Iowa, Michigan, Missouri, Kentucky, or Wisconsin. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS. 4-57

Environmental Consequences and Mitigating Actions Because the new nuclear alternative would be built on an existing power plant site outside of Illinois, which has restrictions on new nuclear power plant construction, the special status species and habitats affected by the action would be different than those considered under the proposed action. Because the NRC would be the licensing agency under this alternative, the ESA would require the NRC to initiate consultation with FWS and NMFS, as applicable, prior to construction to ensure that the construction and operation of the new nuclear plant would not adversely affect any Federally listed species or adversely modify or destroy designated critical habitat. Section 4.8.2 discusses general ESA considerations. In the unlikely event that the new nuclear plant is sited in an area that could affect water bodies with designated EFH, which applies only to certain commercially harvested marine and anadromous fish species, consultation with NMFS under the MSA would be required to assess potential impacts to that habitat. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, plant design, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative. 4.8.4 IGCC Alternative This alternative entails shutdown and decommissioning of LSCS and construction of a new IGCC facility at either the LSCS site or an alternative industrial location. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS. Unlike the new nuclear alternative, the NRC does not license IGCC facilities, and the NRC would not be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative. If no other federal agency was involved in licensing the facilities, the facilities themselves would be responsible for protecting listed species because the ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct. If the IGCC alternative were to be built on the LSCS site, the ESA action area might still be different because the activities and structures associated with the construction and operations of an IGCC plant would be different than those described under continued operation of LSCS. If the IGCC alternative were to be built at a site other than the LSCS site, the listed species and habitats affected by the action would be different than those identified for LSCS. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, plant design, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative. 4.8.5 NGCC Alternative This alternative entails the shutdown and decommissioning of LSCS and construction of a new NGCC facility at either the LSCS site or an alternative industrial location. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS. Unlike the new nuclear alternative, the NRC does not license NGCC facilities, and the NRC would not be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative. If no other federal agency was involved in licensing the facilities, the facilities themselves would be responsible for protecting listed species because the ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct. If the NGCC alternative were to be built on the LSCS site, the ESA action area might still be different because the activities and structures associated with construction and operation of an 4-58

Environmental Consequences and Mitigating Actions NGCC plant would be different than those described under continued operation of LSCS. If the NGCC alternative were to be built at a site other than the LSCS site, the listed species and habitats affected by the action would be different than those identified for LSCS. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, plant design, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative. 4.8.6 Combination Alternative (NGCC, Wind, Solar) This alternative entails the shutdown and decommissioning of LSCS and construction of new non-nuclear facilities at the LSCS site and alternative industrial locations. Section 4.8.2 discusses ESA considerations for the shutdown of LSCS. The combination alternative would involve construction and operation of wind turbines and solar PV systems throughout the ROI, as well as an NGCC plant at the LSCS site. Unlike the new nuclear alternative, the NRC does not license NGCC, wind, or solar facilities, and the NRC would not be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative. If no other federal agency was involved in licensing the facilities, the facilities themselves would be responsible for protecting listed species because the ESA forbids take of a listed species, where take means harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in any such conduct. Even though the NGCC portion of the combination alternative would be located on the LSCS site, the ESA action area might be different because the activities and structures associated with the construction and operation of the NGCC portion of the combination alternative would be different than those described under continued operation of LSCS. Since the wind and solar parts of the combination alternative would be located on a site or sites other than the LSCS site, the listed species and habitats affected by the action would be different than those identified for LSCS. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, wind and solar component designs, operation, and species and habitats listed when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative. 4.8.7 Purchased Power Alternative Because the purchased power alternative might include a mixture of coal, natural gas, nuclear, and wind across many different sites in the ROI, the special status species and habitats affected by the action would be different than those considered under continued operation. Because the types and magnitudes of adverse impacts to ESA-listed species would depend on the proposed sites, plant designs, operation, and species and habitats listed at the various sites when the alternative is implemented, the NRC cannot forecast a particular level of impact for this alternative. As with the other alternatives discussed previously, the facilities themselves, or a different federal regulator, but not the NRC, would be responsible for initiating section 7 consultation if listed species or habitats might be adversely affected under this alternative. 4.9 Historic and Cultural Resources This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on historic and cultural resources. 4-59

Environmental Consequences and Mitigating Actions 4.9.1 Proposed Action Section 3.9 describes the historic and cultural resources that have the potential to be affected by the proposed action. Table 4-10 identifies the historic and cultural resource issue applicable to LSCS during the license renewal term. Table 4-10. Historic and Cultural Resources Issue Issue GEIS Section Category Historic and cultural resources 4.7.1 2 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 The National Historic Preservation Act of 1966, as amended (54 USC 300101 et seq. (NHPA)) requires Federal agencies to consider the effects of their undertakings on historic properties, and renewing the operating license of a nuclear power plant is an undertaking that could potentially affect historic properties. Historic properties are defined as resources eligible for listing in the National Register of Historic Places (NRHP). The criteria for eligibility are listed in 36 CFR 60.4, and include: (1) association with significant events in history, (2) association with the lives of persons significant in the past, (3) embodiment of distinctive characteristics of type, period, or construction, and (4) sites or places that have yielded, or are likely to yield, important information. The historic preservation review process (Section 106 of the NHPA) is outlined in regulations issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800. In accordance with the provisions of the NHPA, the NRC is required to make a reasonable effort to identify historic properties included in or eligible for inclusion in the NRHP in the Area of Potential Effect (APE). The APE for a license renewal action is the area at the power plant site, the transmission lines up to the first substation and immediate environs that may be affected by the license renewal decision, and land-disturbing activities associated with continued reactor operations. For LSCS, the first substation is located on site at the 345-kV LSCS Station switchyard. Additionally, LSCS property containing the makeup and blowdown piping from the cooling lake to the Illinois River are included in the APE (Exelon 2014a). If historic properties are present within the APE, the NRC is required to contact the State Historic Preservation Office (SHPO), assess the potential impact, and resolve any possible adverse effects of the undertaking (license renewal) on historic properties. In addition, the NRC is required to notify the SHPO if historic properties would not be affected by license renewal or if no historic properties are present. The SHPO is part of the Illinois Historic Preservation Agency (IHPA). Consultation In accordance with 36 CFR 800.8(c), on February 9, 2015, the NRC initiated consultations on the proposed action by writing to the ACHP and IHPA (NRC 2015c, 2015d). Also on February 9, 2015, the NRC initiated consultation with the following 14 Federally recognized Tribes (NRC 2015e) (see Appendix C for a list of these letters):

  • Ho-Chunk Nation,
  • Miami Tribe of Oklahoma,
  • Peoria Tribe of Indians of Oklahoma, 4-60

Environmental Consequences and Mitigating Actions

  • Citizen Potawatomi Nation,
  • Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki,
  • Sac and Fox Nation of Missouri in Kansas and Nebraska,
  • Sac and Fox Nation,
  • Pokagon Band of Potawatomi,
  • Forest County Potawatomi,
  • Hannahville Indian Community, Band of Potawatomi,
  • Prairie Band of Potawatomi Nation,
  • Winnebago Tribe of Nebraska,
  • Kickapoo Tribe in Kansas, and
  • Kickapoo Tribe of Oklahoma.

By letter, the NRC provided information about the proposed action, defined the APE, and indicated that the NHPA review would be integrated with the NEPA process, according to 36 CFR 800.8(c). The NRC invited participation in the identification and possible decisions concerning historic properties and also invited participation in the scoping process. The NRC received no scoping comments from any of the tribes contacted. In April 2015, the NRC received a determination from the IHPA stating no objection to the undertaking and that no historic properties would be affected (Leibowitz 2015) (see Appendix C). The NRC met with the Illinois SHPO in May 2015. The Illinois SHPO did not express any concerns about the proposed LSCS license renewal during the meeting (NRC 2015f). Exelon currently has no planned physical changes or license-renewal-related refurbishment activities at the LSCS site. Any future ground-disturbing activities at the LSCS site will be done in accordance with established LSCS procedures to determine whether the proposed activities will impact known or potential cultural and historic resources (Exelon 2015b). Exelon would consult with the SHPO, if necessary, to determine what measures would be needed to minimize and mitigate the impacts (Exelon 2014a). Supplemental cultural resource surveys may be performed of the affected areas based on consultation with the SHPO. As described in Section 3.9, there are no historic properties or known NRHP-eligible historic or cultural resources located within the LSCS APE. Exelon has established a draft Cultural Resource Management Plan (CRMP) to help ensure historic and cultural resources are considered prior to ground-disturbing activities. The CRMP instructs Exelons staff on how to evaluate land disturbing activity for possible impacts to historic and cultural resources and identifies previously disturbed areas of the LSCS property and any areas with the potential to contain undiscovered resources (Exelon 2015b). Additionally, Exelon has established procedures in the event that historic or cultural resources are inadvertently discovered during operational activities. These procedures direct the Exelon staff to stop work, protect exposed resources, and contact Exelon environmental personnel to take appropriate action (Exelon 2015b). Cultural resource training is not currently required for LSCS staff members (Exelon 2015b). The NRC staff concludes that license renewal would not affect any known historic properties (36 CFR Section 800.4(d)(1)) based on (1) no current NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelons draft CRMP, (4) no current plan for license-renewal-related physical changes or ground-disturbing activities, (5) IHPA input, and, (6) cultural resource assessment. The NRC staff notes that Exelon could reduce the risk of potential impacts to historic and cultural resources located on or near the LSCS site by finalizing its draft CRMP, 4-61

Environmental Consequences and Mitigating Actions with input from the SHPO, and by providing training on cultural resources for Exelons staff engaged in planning and executing ground-disturbing activities. 4.9.2 No-Action Alternative Not renewing the operating licenses and terminating reactor operations would have no effect on historic properties and cultural resources within the site boundaries of LSCS. In the decommissioning GEIS, the NRC staff determined that, for all nuclear plant sites at which decommissioning does not anticipate disturbing lands beyond existing site boundaries, impacts to cultural resources would be SMALL. If disturbance beyond the operational areas is anticipated, the impacts may or may not be detectable or destabilizing, depending on site-specific conditions, and cannot be predicted generically. In those cases, the NRC staff concludes that, if disturbance beyond the operation areas is anticipated, the potential impacts may be SMALL, MODERATE, or LARGE and must be determined through site-specific analysis (NRC 2002). Title 10 of CFR Section 50.82 requires power reactor licensees to submit to the NRC a post-shutdown decommissioning activities report (PSDAR). The PSDAR is required to be submitted within 2 years following permanent cessation of operations and contains a description of planned decommissioning activities to be completed at that time. Until the PSDAR is submitted, the NRC staff does not know whether land disturbance will remain within the existing site boundary after the plant is shut down. 4.9.3 New Nuclear Alternative Any land areas potentially affected by the construction of the new nuclear alternative power plant would need to be surveyed to identify and record historic and archaeological cultural resources. An inventory of a previously disturbed former plant industrial site may still be necessary if the site has not been previously surveyed or to verify the level of previous disturbance and to evaluate the potential for intact subsurface cultural resources to be present. Power plant developers would need to survey all potentially affected land areas associated with operation of the alternative (e.g., land required for new roads, transmission corridors, other ROWs). Any cultural resources found during these surveys would need to be recorded and evaluated for eligibility for listing on the NRHP. Mitigation of adverse effects would need to be considered if eligible resources properties were encountered. Areas with the greatest sensitivity and most significant cultural resources should be avoided. Visual impacts on significant cultural resources, such as the historic property viewsheds near the proposed power plant site, should also be assessed and evaluated. The potential for impacts to historic and cultural resources from the new nuclear alternative would vary greatly, depending on the location of the site selected for the proposed new nuclear power plant site. Cooling towers could impact historic property viewsheds. However, given the preference to use a previously disturbed former power plant site, avoidance of undisturbed land could further reduce potential impacts to historic and cultural resources. The NRC staff concludes that the impacts on historic and cultural resources from the construction and operation of a new nuclear alternative power plant would be SMALL. 4.9.4 IGCC Alternative Any areas potentially affected by the construction of the IGCC alternative may need to be surveyed to identify and record historic and cultural resources if a Federal undertaking under NHPA is present. If the IGCC alternative is located on the existing LSCS site, previously disturbed areas known to not contain historic and cultural resources could be used. If the 4-62

Environmental Consequences and Mitigating Actions alternative is sited on the approximately 250 ac (101 ha) of undeveloped land on the LSCS site, a survey and inventory for potential historic and cultural resources may need to be performed. If the IGCC power plant is sited at an existing power plant site other than LSCS and a Federal undertaking under NHPA is present, a cultural resource survey may still be necessary if the site has not been previously surveyed or to verify the level of disturbance and evaluate the potential for intact subsurface resources. Any resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered. Areas with the greatest sensitivity should be avoided. Visual impacts on significant cultural resources, such as the historic property viewshed of historic properties near the proposed power plant site, should also be assessed and evaluated. The potential for impacts on historic and cultural resources from the IGCC alternative would vary greatly depending on the location of the proposed site. Given that the preference is to use a previously disturbed former plant site and no major infrastructure upgrades are necessary, avoidance of significant historic and cultural resources should be possible and effectively managed under current laws and regulations. The NRC staff concludes that the impacts on historic and archaeological resources from the IGCC alternative would be SMALL. 4.9.5 NGCC Alternative Any areas potentially affected by the construction and operation of an NGCC power plant may need to be surveyed to identify and record historic and cultural resources if a Federal undertaking under NHPA is present. If the NGCC power plant is constructed at the existing LSCS site, previously disturbed areas known to not contain historic and cultural resources could be used. If the power plant is sited on the approximately 250 ac (101 ha) of undeveloped land on the LSCS site and a Federal undertaking under NHPA is present, a survey and inventory of potential historic and cultural resources would need to be performed. Additionally, plant operators would need to survey all areas associated with the alternative (e.g., a new pipeline, roads, transmission corridors, other ROWs). Any resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered. Areas with the greatest sensitivity should be avoided. Visual impacts on significant cultural resources, such as the viewsheds of historic properties near the proposed power plant site, should also be assessed and evaluated. Given that the NGCC alternative is assumed to be sited at LSCS, avoidance of significant historic and cultural resources should be possible. However, historic and archaeological resources could potentially be affected, depending on the resource richness of the land required for a new gas pipeline; but, as with the plant site itself, avoidance of significant historic and cultural resources should be possible and effectively managed under current laws and regulations. The NRC staff concludes that the impacts on historic and cultural resources from the NGCC alternative would be SMALL. 4.9.6 Combination Alternative (NGCC, Wind, Solar) Areas potentially affected by the construction of the NGCC, wind, and solar alternative may need to be surveyed to identify and record historic and archaeological resources if a Federal undertaking under NHPA is present. Any resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered. Impacts to historic and cultural resources from the NGCC portion of this alternative are similar to the NGCC alternative in Section 4.9.5. The potential for impacts on historic and cultural 4-63

Environmental Consequences and Mitigating Actions resources from the wind portion of this alternative would vary greatly, depending on the location of the proposed sites. Areas with the greatest sensitivity could be avoided or effectively managed under current laws and regulations. However, construction of wind farms and their support infrastructure have the potential to notably impact historic and archaeological resources because of earthmoving activities (e.g., grading and digging) and the aesthetic changes they may bring to the viewshed of historic properties located nearby. The impacts of the construction of a new solar alternative on historic and cultural resources will vary, depending on the form of the solar capacity installed. Rooftop installations minimize land disturbance and the modifications necessary to the transmission system, thereby minimizing impacts to historic and cultural resources. Land-based installations are larger than rooftop installations and will require some degree of land disturbance for installation purposes, potentially causing greater impacts to historic and archaeological resources. Aesthetic changes caused by the installation of both forms could have a noticeable effect on the viewshed of nearby historic properties. Using previously disturbed sites for land-based installations and collocating any new transmission lines with existing ROWs could minimize impacts to historic and archaeological resources. Areas with the greatest sensitivity could be avoided or effectively managed under current laws and regulations. The NRC staff concludes that, depending on the resource richness of the sites chosen for the NGCC, wind, and solar alternative, the impacts could range from SMALL to LARGE. 4.9.7 Purchased Power Alternative No direct impacts on historic and cultural resources are expected from purchased power. If new transmission lines were needed to convey power to the PJM Interconnection area, surveys similar to those discussed in Section 4.9.3 may need to be performed if a Federal undertaking under NHPA is present. However, transmission lines would likely be collocated with existing ROWs, minimizing any impacts to historic and cultural resources. Indirectly, construction of new nuclear, coal-fired, and natural-gas-fired plants, or wind energy projects, and any new transmission lines to support increased demand in the purchased power alternative could affect historic and cultural resources. If the amount of purchased power exceeds the available supply, new electrical power generating facilities may be needed. Any areas potentially affected by construction may need to be surveyed to identify and record historic and cultural resources if a Federal undertaking under NHPA is present. Resources found in these surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were encountered. Plant operators would need to survey all areas associated with operation of the alternative (e.g., roads, transmission corridors, other ROWs). The potential for impacts on historic and cultural resources would vary greatly, depending on the location of the proposed sites; however, using previously disturbed sites could greatly minimize impacts to historic and cultural resources. Areas with the greatest sensitivity could be avoided or effectively managed under current laws and regulations. The NRC staff concludes that, depending on the resource richness of the sites chosen, the impacts on historic and cultural resources could range from SMALL to LARGE. 4.10 Socioeconomics This section describes the potential socioeconomic impacts of the proposed action (license renewal) and alternatives to the proposed action. 4-64

Environmental Consequences and Mitigating Actions 4.10.1 Proposed Action Socioeconomic effects of ongoing reactor operations at LSCS have become well established as regional socioeconomic conditions have adjusted to the presence of the nuclear power plant. These conditions are described in Section 3.10. Any changes in employment and tax payments caused by license renewal and any associated refurbishment activities could have a direct and indirect impact on community services and housing demand, as well as traffic volumes in the communities around a nuclear power plant. Table 4-11 identifies the socioeconomic NEPA issues from Table B-1 in Appendix B to Subpart A of Part 51, applicable to LSCS during the license renewal term. Table 4-11. Socioeconomic NEPA Issues Affected by License Renewal Issue GEIS Sections Category Employment and income, recreation and tourism 4.8.1.1 1 Tax revenues 4.8.1.2 1 Community services and education 4.8.1.3 1 Population and housing 4.8.1.4 1 Transportation 4.8.1.5 1 Source: Table B-1 in Appendix B, Subpart A of 10 CFR Part 51 The supplemental site-specific socioeconomic impact analysis for the license renewal of LSCS included a review of Exelons ER, scoping comments, other information records, and a data-gathering site visit to LSCS. The NRC staff did not identify any new and significant information during the review that would result in impacts that would exceed the predicted socioeconomic impacts evaluated in the GEIS, and no additional socioeconomic NEPA issues were identified beyond those listed in Table B-1. In addition, Exelon indicated in its ER that it has no plans to add non-outage workers during the license renewal term and that increased maintenance and inspection activities could be managed using the current workforce. Consequently, people living in the vicinity of LSCS are not likely to experience any changes in socioeconomic conditions during the license renewal term beyond what is currently being experienced. Therefore, the impact of continued reactor operations during the license renewal term would not exceed the socioeconomic impacts predicted in the GEIS. For these issues, the GEIS predicted that the impacts would be SMALL for all nuclear plants. 4.10.2 No-Action Alternative 4.10.2.1 Socioeconomics Not renewing the operating license and terminating reactor operations would have a noticeable impact on socioeconomic conditions in the communities located near LSCS. The loss of jobs and income would have an immediate socioeconomic impact. Some, but not all, of the approximately 890 employees would begin to leave after reactor operations are terminated, and overall tax revenue generated by plant operations would be reduced (Exelon 2014a). Exelon pays annual property taxes to various entities to partially fund their respective operating budgets. The property tax revenue is used to fund public schools, libraries, county and local township operations, and other services. The loss of tax revenue could reduce or eliminate 4-65

Environmental Consequences and Mitigating Actions some public and educational services. Indirect employment and income generated by power plant operations would also be reduced. Former LSCS workers and their families could leave in search of employment elsewhere. The increase in available housing along with decreased demand could cause housing prices to fall. Since the majority of employees reside in LaSalle and Grundy Counties, socioeconomic impacts from the termination of reactor operations would be concentrated in these counties, with a corresponding reduction in purchasing activity and tax revenue in the regional economy. Income and revenue losses from the termination of reactor operations at LSCS would directly affect LaSalle County and nearby communities most reliant on income from power plant operations. The impact of the job loss, however, may not be as noticeable in local communities, given the amount of time required for decommissioning. The socioeconomic impacts from the termination of nuclear plant operations (which may not entirely cease until after decommissioning) would, depending on the jurisdiction, range from SMALL to LARGE. 4.10.2.2 Transportation Traffic congestion caused by commuting workers and truck deliveries on roads in the vicinity of LSCS would be reduced after power plant shutdown. Most of the reduction in traffic volume would be associated with the loss of jobs. The number of truck deliveries to LSCS would be reduced until decommissioning. Traffic-related transportation impacts would be SMALL as a result of the shutdown of the nuclear power plant. 4.10.3 New Nuclear Alternative 4.10.3.1 Socioeconomics Socioeconomic impacts are defined in terms of changes to the demographic and economic characteristics and social conditions of a region. For example, the number of jobs created by the construction and operation of a power plant could affect regional employment, income, and expenditures. Two types of jobs would be created by this alternative: (1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of a new nuclear power plant were evaluated to measure their possible effects on current socioeconomic conditions. The construction workforce could peak at 3,500 workers (NRC 2008a). The relative economic effect of this many workers on the local economy and tax base would vary, with the greatest impacts occurring in the communities where the majority of construction workers would reside and spend their income. As a result, local communities could experience a short-term economic boom from increased tax revenue and income generated by construction expenditures and the increased demand for temporary (rental) housing and public as well as commercial services. After construction, local communities could experience a return to preconstruction economic conditions. Based on this information and given the number of workers, socioeconomic impacts during construction in communities near an existing nuclear power plant or retired coal site could range from MODERATE to LARGE. Approximately 800 workers would be required during nuclear power plant operations (NRC 2008a). Some LSCS operations workers could transfer to the new nuclear power plant. Local communities near the new nuclear power plant would experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for 4-66

Environmental Consequences and Mitigating Actions housing and public as well as commercial services. The amount of property tax payments under the new nuclear alternative may also increase if additional land is required to support this alternative. This alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS and a corresponding reduction in purchasing activity and revenue contributions to the regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region. The impact of the job loss, however, may not be noticeable in local communities, given the amount of time required for decommissioning of the existing LSCS facilities. Based on this information and given the number of operations workers, socioeconomic impacts during nuclear power plant operations on local communities could range from SMALL to MODERATE. 4.10.3.2 Transportation Transportation impacts associated with construction and operation of a new nuclear power plant would consist of commuting workers and truck deliveries of construction materials to the power plant site. During periods of peak construction activity, up to 3,500 workers could be commuting daily to the construction site (NRC 2008a). Workers commuting to the construction site would arrive via site access roads and the volume of traffic on nearby roads could increase substantially during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Materials could also be delivered by rail or barge, depending on the location. Traffic-related transportation impacts during construction would likely range from MODERATE to LARGE. Traffic-related transportation impacts on local roads would be greatly reduced after the completion of the power plant. Approximately 800 operations workers would be commuting daily to the new nuclear power plant site (NRC 2008a). Transportation impacts would include daily commuting by the operating workforce, material deliveries, and the removal of commercial waste material to offsite disposal or recycling facilities by truck. Traffic on roadways would peak during shift changes and refueling outages, resulting in temporary levels of service impacts and delays at intersections. Overall, at the new nuclear power plant site, transportation impacts would be SMALL to MODERATE during operations. 4.10.4 IGCC Alternative 4.10.4.1 Socioeconomics As explained in Section 4.10.3, two types of jobs would be created by this alternative: (1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of a new IGCC power plant were evaluated to measure their possible effects on current socioeconomic conditions. The construction workforce could peak at 4,600 workers (DOE 2010a). The relative economic effect of this many workers on the local economy and tax base would vary, with the greatest impacts occurring in the communities where the majority of construction workers would reside and spend their income. As a result, local communities could experience a short-term economic 4-67

Environmental Consequences and Mitigating Actions boom from increased tax revenue and income generated by construction expenditures and the increased demand for temporary (rental) housing and public as well as commercial services. After construction, local communities could experience a return to preconstruction economic conditions. Based on this information and given the number of workers, socioeconomic impacts during construction in communities near an existing power plant site could range from MODERATE to LARGE. An estimated 420 workers would be required during power plant operations (DOE 2010a). Local communities would experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for housing and public as well as commercial services. The amount of property tax payments under the IGCC alternative may also increase if additional land is required to support this alternative. This alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS and a corresponding reduction in purchasing activity and revenue contributions to the regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region. The impact of the job loss, however, may not be noticeable in local communities, given the amount of time required for decommissioning the existing LSCS facilities. Based on this information and given the number of operations workers, socioeconomic impacts during IGCC power plant operations on local communities could range from SMALL to MODERATE. 4.10.4.2 Transportation Transportation impacts associated with construction and operation of the two-unit, IGCC power plant would consist of commuting workers and truck deliveries of construction materials to the power plant site. During periods of peak construction activity, up to 4,600 workers could be commuting daily to the construction site. Workers commuting to the construction site would arrive via site access roads, and the volume of traffic on nearby roads could increase substantially during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Materials could also be delivered by rail or barge, depending on location. Traffic-related transportation impacts during construction would likely range from MODERATE to LARGE. Traffic-related transportation impacts on local roads would be greatly reduced after the completion of the power plant. The estimated maximum number of operations workers commuting daily to the power plant site could be 420 (DOE 2010a). Fewer workers would be required if multiple units are operated at the same site. Frequent coal and limestone deliveries and ash removal by rail would add to the overall transportation impact. The increase in traffic on roadways would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Onsite coal storage would make it possible to receive several trains per day at a site with rail access. If the IGCC power plant is located on navigable waters, coal and other materials could be delivered by barge. Coal and limestone delivery and ash removal via rail would cause levels of service impacts due to delays at railroad crossings. Overall, transportation impacts would be SMALL to MODERATE during IGCC power plant operations. 4-68

Environmental Consequences and Mitigating Actions 4.10.5 NGCC Alternative 4.10.5.1 Socioeconomics As explained in Section 4.10.3, two types of jobs would be created by this alternative: (1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of a new NGCC power plant were evaluated to measure their possible effects on current socioeconomic conditions. The construction workforce could peak at 1,783 workers (Exelon 2014a). The relative economic effect of this many workers on the local economy and tax base would vary, with the greatest impacts occurring in the communities where the majority of construction workers would reside and spend their income. As a result, local communities could experience a short-term economic boom from increased tax revenue and income generated by construction expenditures and the increased demand for temporary (rental) housing and public as well as commercial services. After construction, local communities could experience a return to preconstruction economic conditions. Based on this information and given the number of workers, socioeconomic impacts during construction in communities near an existing power plant site could range from MODERATE to LARGE. An estimated 94 workers would be required during power plant operations (Exelon 2014a). Local communities would experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for housing and public as well as commercial services. The amount of property tax payments under the NGCC alternative may also increase if additional land is required to support this alternative. This alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS and a corresponding reduction in purchasing activity and revenue contributions to the regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region. The impact of the job loss, however, may not be noticeable in local communities given the amount of time required for decommissioning the existing LSCS facilities. Based on this information and given the number of operations workers, socioeconomic impacts during NGCC power plant operations on local communities could range from SMALL to MODERATE. 4.10.5.2 Transportation Transportation impacts associated with construction and operation of a three-unit, NGCC power plant would consist of commuting workers and truck deliveries of construction materials to the power plant site. During periods of peak construction activity, up to 1,783 workers could be commuting daily to the construction site. Workers commuting to the construction site would arrive via site access roads, and the volume of traffic on nearby roads could increase substantially during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thus increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Pipeline construction and modification of existing natural gas pipeline systems could also have a temporary impact. Materials also could be delivered by barge or rail, depending on location. 4-69

Environmental Consequences and Mitigating Actions Traffic-related transportation impacts during construction would likely range from MODERATE to LARGE. Traffic-related transportation impacts would be greatly reduced after completing the installation of the NGCC alternative. Transportation impacts would include daily commuting by the operating workforce, equipment and materials deliveries, and the removal of commercial waste material to offsite disposal or recycling facilities by truck. The operations workforce of 94 workers would likely not be noticeable relative to total traffic volumes on local roadways. Since fuel is transported by pipeline, the transportation infrastructure would experience little to no increased traffic from plant operations. Overall, given the relatively small operations workforce estimate of 94 workers, transportation impacts would be SMALL during power plant operations. 4.10.6 Combination Alternative (NGCC, Wind, Solar) 4.10.6.1 Socioeconomics As explained in Section 4.10.3, two types of jobs would be created by this alternative: (1) construction jobs, which are transient, short in duration, and less likely to have a long-term socioeconomic impact, and (2) operations jobs, which have the greater potential for permanent, long-term socioeconomic impacts. Workforce requirements for the construction and operation of the NGCC, wind, and solar generation components of this combination alternative were evaluated to estimate their possible effects on current socioeconomic conditions. Fewer workers would be required to construct the single NGCC unit at the LSCS site than the full-power NGCC alternative. Installation of an estimated 3,376 wind turbines would likely be done in stages and could require up to 931 construction workers (NREL 2013). Additional workers would be required to install solar PV systems on existing buildings or structures at already-developed residential, commercial, or industrial sites. Similar to the wind farms, installation would likely be done in stages and could require up to 600 construction workers (DOE 2010b). Conversely, a small number of operations workers would be needed to operate the single NGCC unit and additional small numbers of workers would be required to maintain the wind farms and PV systems. Local communities could experience the economic benefits from increased tax revenue and income generated by operational expenditures and demand for housing and public as well as commercial services. The amount of property tax payments under the wind and solar PV components may also increase if additional land is required to support this combination alternative. This combination alternative would also result in a loss of approximately 890 relatively high-paying jobs at LSCS, and a corresponding reduction in purchasing activity, tax payments, and revenue contributions would occur in the surrounding regional economy. Should LSCS cease operations, there would be an immediate socioeconomic impact to local communities and businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, the housing market could experience increased vacancies and decreased prices if operations workers and their families move out of the region. The impact of the job loss, however, may not be noticeable in local communities, given the amount of time required for decommissioning of the existing LSCS facilities. Based on this information and given the relatively small numbers of construction and operations workers, socioeconomic impacts during construction and operations on local communities would be SMALL. 4-70

Environmental Consequences and Mitigating Actions 4.10.6.2 Transportation Transportation impacts during the construction and operation of the NGCC unit as well as the wind and solar components of this combination alternative would be less than the impacts for any of the previous alternatives discussed. This is because the construction workforce for each component and the volume of materials and equipment needing to be transported to the respective construction site would be smaller than for any one of the individual replacement power alternatives. In other words, the transportation impacts would not be concentrated as in the other alternatives but spread out over a wider area. Workers commuting to the construction site would arrive via site access roads, and the volume of traffic on nearby roads could increase during shift changes. In addition to commuting workers, trucks would be transporting construction materials and equipment to the work site, thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary levels of service impacts and delays at intersections. Transporting heavy and oversized components on local roads could have a noticeable impact over a large area. Some components and materials could also be delivered by rail or barge, depending on location. Traffic-related transportation impacts during construction could range from SMALL at the LSCS site and SMALL to MODERATE at the wind farms and solar installations; depending on current road capacities and average daily traffic volumes. During operations, transportation impacts would be less noticeable during shift changes and maintenance activities. Given the small numbers of operations workers, the levels of service traffic impacts on local roads from NGCC, wind farm, and solar PV operations would be SMALL. 4.10.7 Purchased Power Alternative 4.10.7.1 Socioeconomics Purchased power from existing power generating facilities would not have any socioeconomic impact, because there would be no change in power plant operations or workforce. If the amount of purchased power exceeds the available supply, new electrical power generating facilities would be needed. Construction and operation of a new electrical power generating facility to supply purchased power could cause noticeable socioeconomic impacts in the communities located near the new facility. The intensity of the impact would depend on the number of workers required to build and operate the new electrical power generating facility and the amount of increased demand for housing and public services. Whether or not there would be a socioeconomic impact would depend on whether a new electrical power generating facility was needed to supply purchased power. If a new power generating facility is needed, socioeconomic impacts would range anywhere from SMALL to LARGE. 4.10.7.2 Transportation Similarly, purchased power from existing power generating facilities would also not have any transportation impact, because there would be no change in power plant operations or workforce. If necessary, construction and operation of a new electrical power generating facility could cause noticeable transportation impacts, depending on the number of workers and truck deliveries required to build and operate the new electrical power generating facility. Consequently, traffic volumes could increase noticeably on local roads near the new power plant site during shift changes. 4-71

Environmental Consequences and Mitigating Actions Whether or not there would be a transportation impact would depend on whether a new electrical power generating facility were needed to supply purchased power. If a new power generating facility is needed, transportation impacts would range anywhere from SMALL to LARGE. 4.11 Human Health This section describes the potential impacts of the proposed action (license renewal) and alternatives to the proposed action on human health resources. 4.11.1 Proposed Action Section 3.11 describes the human health resources associated with LSCS. Table 4-12 identifies the human health resource issues applicable to LSCS during the license renewal term. Table 4-12. Human Health Issues Issue GEIS Section Category Radiation exposures to the public 4.9.1.1.1 1 Radiation exposures to plant workers 4.9.1.1.1 1 Human health impact from chemicals 4.9.1.1.2 1 Microbiological hazards to the public (plants with cooling ponds or 4.9.1.1.3 2 canals or cooling towers that discharge to a river) Microbiological hazards to plant workers 4.9.1.1.3 1 Chronic effects of electromagnetic fields (EMFs)(a) 4.9.1.1.4 N/A(b) Physical occupational hazards 4.9.1.1.5 1 Electric shock hazards(a) 4.9.1.1.5 2 (a) This issue applies only to the in-scope portion of electric power transmission lines, which are defined as transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional power distribution system and transmission lines that supply power to the nuclear plant from the grid. (b) N/A (not applicable) The categorization and impact finding definition does not apply to this issue. Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 4.11.1.1 Normal Operating Conditions Generic Human Health Issues (Category 1) The NRC staff did not identify any new and significant information during its review of Exelons ER (Exelon 2014a), the site audit, or the scoping process for the Category 1 issues listed in Table 4-12. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. For these Category 1 issues, the GEIS concluded that the impacts are SMALL. Chronic Effects of Electromagnetic Fields (EMFs) In the GEIS (NRC 2013d), the chronic effects of 60-Hz electromagnetic fields (EMFs) from power lines were not designated as Category 1 or 2 and will not be until a scientific consensus is reached on the health implications of these fields. 4-72

Environmental Consequences and Mitigating Actions The potential for chronic effects from these fields continues to be studied and is not known at this time. The National Institute of Environmental Health Sciences (NIEHS) directs related research through DOE. The report by NIEHS (NIEHS 1999) contains the following conclusion: The NIEHS concludes that ELF-EMF (extremely low frequency-electromagnetic field) exposure cannot be recognized as entirely safe because of weak scientific evidence that exposure may pose a leukemia hazard. In our opinion, this finding is insufficient to warrant aggressive regulatory concern. However, because virtually everyone in the United States uses electricity and therefore is routinely exposed to ELF-EMF, passive regulatory action is warranted such as continued emphasis on educating both the public and the regulated community on means aimed at reducing exposures. The NIEHS does not believe that other cancers or non-cancer health outcomes provide sufficient evidence of a risk to currently warrant concern. This statement is not sufficient to cause the NRC staff to change its position with respect to the chronic effects of EMFs. The NRC staff considers the GEIS finding of UNCERTAIN still appropriate and will continue to follow developments on this issue. Site-Specific Human Health Issues (Category 2) Microbiological Hazards to the Public In the GEIS (NRC 2013d), the NRC staff determined that effects of thermophilic microorganisms on the public for plants using cooling ponds, lakes, or canals or cooling towers that discharge to a river is a Category 2 issue (see Table 4-12) that requires site-specific evaluation during each license renewal review. In order to determine whether the continued operations of LSCS could promote increased growth of thermophilic microorganisms and thus have an adverse effect on the public, the NRC staff considered several factors: the thermophilic microorganisms of concern, LSCSs thermal effluent characteristics, Exelons chlorination procedures, recreational use of the LSCS cooling pond and the Illinois River, and input from the Illinois Environmental Protection Agency (IEPA) and Illinois Department of Public Health (IDPH). Section 3.11.3 describes the thermophilic microorganisms that the GEIS identified to be of potential concern at nuclear power plants and summarizes data from the Centers for Disease Control and Prevention (CDC) on the prevalence of waterborne diseases associated with these microorganisms that have been linked to recreational water from 2002 through 2011. CDC data indicate that no outbreaks or cases of waterborne Salmonella or Pseudomonas aeruginosa infection from recreational waters have occurred in the United States during this time frame. Shigella and Naegleria fowleri infections linked to exposure in recreational waters were rarely reported, and none of the reported cases occurred in Illinois. Public exposure to aerosolized Legionella from nuclear plant operations is generally not a concern because such exposure would be confined to a small area of the site to which the public would not have access. In the case of LSCS, which does not have cooling towers, exposure of workers to Legionella is unlikely. Based on the information presented in Section 3.11.3, the thermophilic organisms most likely to be of potential concern at Illinois are Shigella and N. fowleri. LSCSs circulating water system and two service water systems discharge heated water to the sites artificial cooling pond through a discharge canal. LSCS also continuously discharges blowdown to the Illinois River, and this discharge is subject to the limitations set forth in the sites NPDES permit (IEPA 2013). The permit limits blowdown discharges to the river (Outfall 001) to a maximum rate of 45 gallons per minute (gpm) (0.17 m3 per minute (m3/min)), 4-73

Environmental Consequences and Mitigating Actions as further described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Sections 3.1.3 and 3.5.1 describe the cooling system and surface water characteristics, respectively. The temperature in the cooling pond is generally below the optimal growth temperature of both Shigella and N. fowleri (95 to 106 °F (35 to 41 °C)). From 2001 through 2014, there have been a few periods during summer months that the temperatures in the cooling pond exceeded 95 °F (35 °C) (Exelon 2015b). Although these temperatures could reasonably enhance survival or growth of Shigella and N. fowleri, the short duration and periodicity of these temperatures are unlikely to have produced a measurable effect on the Shigella and N. fowleri population, if present in the pond. For blowdown to the Illinois River, Special Condition 3 of the NPDES permit limits the maximum temperature rise above ambient conditions and maximum water temperatures at Outfall 001. This condition stipulates that, at the edge of the thermal mixing zone, discharges from Outfall 001 shall not cause the Illinois River water to rise above natural temperatures by more than 2.8 °C (5 °F). The temperature beyond the mixing zone cannot exceed specified monthly limits for longer than 1 percent (i.e., 87.6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />) of any 12-month period and cannot at any time exceed the specified monthly limit by more than 1.7 °C (3 °F). During the months of April through November, the calculated temperature outside the mixing zone cannot exceed 93 °F (34 °C). These limits are consistent with Title 35, Environmental Protection, Section 302, Water Quality Standards, of the IAC, which stipulates that, for thermal effluents, the maximum temperature rise shall not exceed 2.8 °C (5 °F) above natural receiving water body temperatures and that the water temperature at representative locations in the main river shall at no time exceed 33.7 °C (93 °F) from April through November and 17.7 °C (63 °F) in other months (35 IAC 302.211). These temperature limits in the NPDES permits are below the optimal growth temperature for both Shigella and N. fowleri, and thus, would not enhance the growth or survival of these thermophilic organisms, if present in Illinois River water. In addition to temperature limitations, the IAC prohibits the area and volume of thermal mixing from being more than 25 percent of the cross-sectional area or volume of stream flow (35 IAC 302.102). The NRC (1978) determined that LSCSs thermal mixing zone meets the IACs criteria: the surface area of the thermal mixing zone was estimated to be 2,500 m2 (27,000 ft2) in March to 400 m2 (4,300 ft2) in July, which would cover approximately 8 to 9 percent of the river. Thus, the IACs thermal mixing limitations effectively minimize the area and volume over which microorganisms could experience enhanced growth or survival in the Illinois River near the LSCS discharge. Chlorine is an effective disinfectant for water containing the microorganisms of concern. The EPA (1999a) reports that chlorination at concentrations of 1 to 2 milligrams per liter (mg/L) in water at a pH of 6.0 to 8.0 can effectively eliminate health hazards caused by bacteria, including Shigella. The CDC (CDC 2013) reports that chlorine at a concentration of 1 part per million ((ppm) (1 mg/L)) added to 77 °F (25 °C) clear water at a pH of 7.5 will reduce the number of viable N. fowleri trophozoites by 99.99 percent in 12 minutes. Exelon treats water entering the circulating water system and service water systems with sodium hypochlorite to control biofouling (Exelon 2014a). Water discharged to the Illinois River may not contain more than an instantaneous maximum concentration of 0.2 mg/L of residual chlorine or 0.05 mg/L of residual oxides, as measured at Outfall 001, per Special Condition 4 of the NPDES permit (IEPA 2013). Chlorination of the system is likely to prevent some increased growth and survival of microorganisms that might otherwise result from operation of LSCS. Both the cooling pond and the Illinois River are used for recreational purposes. The cooling pond is part of the LaSalle Lake State Fish and Wildlife Area, which Exelon and the IDNR jointly manage. It is generally open to the public from mid-March until mid-October (Exelon 2014a). 4-74

Environmental Consequences and Mitigating Actions Portions of the cooling pond within the exclusion zone, which includes the essential cooling pond, are off limits to the public (Exelon 2014a). Swimming, wading, water skiing, and use of non-motorized boats are prohibited at LaSalle Lake (IDNR 2015b), which further reduces the potential for human exposure to the microorganisms of concern, if present in the cooling pond. As discussed above, LSCSs thermal mixing zone in the Illinois River is relatively small (0.1 ha (0.22 ac)), and the temperature limitations set forth in the NPDES permit are lower than those that would promote increased growth or survival of thermophilic microorganisms. In accordance with the IAC, the discharge is not located near any public access areas because thermal mixing is prohibited in water adjacent to bathing beaches, bank fishing areas, boat ramps or dockages or any other public access area (35 IAC 302.102(b)(3)). Given the small area of thermally altered waters and the unlikelihood of the water to create conditions favorable to thermophilic microorganisms, exposure of recreational Illinois River users to elevated concentrations of the microorganisms of concern is unlikely. The environmental standard review plan for license renewal directs the NRC staff to consult with the State public health department regarding concerns about the potential for waterborne disease outbreaks associated with license renewal. In response to RAIs, Exelon (2015b) included copies of correspondence between Exelon and IDPH and IEPA regarding this issue. Exelon requested information from IEPA and IDPH on the potential increase in adverse effects on public health from exposure to N. fowleri or any other thermophilic pathogen in the Illinois River. In response, IEPA and IDPH each indicated that its staff does not have the expertise necessary to adequately evaluate Exelons assessment (IEPA 2014; IDPH 2014). Accordingly, the NRC staff did not separately contact the IDPH or IEPA during its license renewal review. Conclusion The thermophilic microorganisms Shigella and N. fowleri have been linked to waterborne outbreaks in recreational waters within the United States. However, based on these microorganisms temperature tolerances, Shigella and N. fowleri are unlikely to be present in the vicinity of LSCS. Additionally, Exelons chlorination procedures and the small thermal mixing zones in the cooling pond and Illinois River make exposure of recreational water users to elevated levels of these microorganisms unlikely. The NRC staff concludes that the impacts of thermophilic microorganisms on the public are SMALL for LSCS license renewal. Electric Shock Hazards Based on the GEIS, the Commission found that electric shock resulting from direct access to energized conductors or from induced charges in metallic structures has not been found to be a problem at most operating plants and generally is not expected to be a problem during the license renewal term. However, a site-specific review is required to determine the significance of the electric shock potential along the portions of the transmission lines that are within the scope of this SEIS. As discussed in Section 3.11.4, there are no offsite transmission lines that are in scope for this SEIS. Therefore, there are no potential impacts to members of the public. As discussed in Section 3.11.5, LSCS maintains an occupational safety program in accordance with the Occupational Safety and Health Administration regulations for its workers, which includes protection from acute electric shock. Therefore, the NRC staff concludes that the potential impacts from acute electric shock during the license renewal term would be SMALL. 4.11.1.2 Environmental Impacts of Postulated Accidents This section describes the environmental impacts from postulated accidents that LSCS might experience during the period of extended operation. The term accident refers to any 4-75

Environmental Consequences and Mitigating Actions unintentional event outside the normal plant operational envelope that results in a release or the potential for release of radioactive materials into the environment. The two classes of postulated accidents listed in Table 4-13 are contained in Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 and are evaluated in detail in the GEIS. These two classes of accidents are design-basis accidents (DBAs) and severe accidents. Table 4-13. Issues Related to Postulated Accidents Issue GEIS Section Category DBAs 4.9.1.2 1 Severe accidents 4.9.1.2 2 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 Design-Basis Accidents In order to receive NRC approval to operate a nuclear power facility, an applicant for an initial operating license must submit a Safety Analysis Report (SAR) as part of its application. The SAR presents the design criteria and design information for the proposed reactor and comprehensive data on the proposed site. The SAR also discusses various hypothetical accident situations and the safety features that are provided to prevent and mitigate accidents. The NRC staff reviews the application to determine whether the plant design meets the Commissions regulations and requirements and includes, in part, the nuclear plant design and its anticipated response to an accident. Design-basis accidents are those accidents that both the applicant and the NRC staff evaluate to ensure that the plant can withstand normal and abnormal transients and a broad spectrum of postulated accidents, without undue hazard to the health and safety of the public. Many of these postulated accidents are not expected to occur during the life of the plant but are evaluated to establish the design basis for the preventive and mitigative safety systems of the nuclear power plant. Parts 50 and 100 of 10 CFR describe the acceptance criteria for DBAs. The environmental impacts of DBAs are evaluated during the initial licensing process, and the ability of the plant to withstand these accidents is demonstrated to be acceptable before issuance of the operating license. The results of these evaluations are found in license documentation such as the applicants Final Safety Analysis Report, the safety evaluation report, the final environmental statement (FES), and Section 4.11 of this SEIS. A licensee is required to maintain the acceptable design and performance criteria throughout the life of the plant, including any extended-life operation. The consequences for these events are evaluated for the hypothetical maximum exposed individual; as such, changes in the plant environment will not affect these evaluations. Because of the requirements that continuous acceptability of the consequences and aging management programs be in effect for the period of extended operation, the environmental impacts as calculated for DBAs should not differ significantly from initial licensing assessments over the life of the plant, including the period of extended operation. Accordingly, the design of the plant relative to DBAs during the period of extended operation is considered to remain acceptable, and the environmental impacts of those accidents were not examined further in the GEIS. The Commission has generically determined that the environmental impacts of DBAs are of SMALL significance for all plants because the plants were designed to successfully withstand these accidents. Therefore, for the purposes of license renewal, DBAs are designated as a Category 1 issue. The early resolution of the DBAs makes them a part of the current licensing 4-76

Environmental Consequences and Mitigating Actions basis of the plant; the current licensing basis of the plant is to be maintained by the licensee under its current license and, therefore, under the provisions of 10 CFR 54.30, is not subject to review under license renewal. No new and significant information related to DBAs was identified during the review of the LSCS ER (Exelon 2014a), the site audit, the scoping process, or evaluation of other available information. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. Severe Accidents Severe nuclear accidents are those that are more severe than DBAs because they could result in substantial damage to the reactor core, whether or not there are serious offsite consequences. In the GEIS, the NRC staff assessed the effects of severe accidents during the period of extended operation, using the results of existing analyses and site-specific information to conservatively predict the environmental impacts of severe accidents for each plant during the period of extended operation. Severe accidents initiated by external phenomena such as tornadoes, floods, earthquakes, fires, and sabotage have not traditionally been discussed in quantitative terms in FESs and were not specifically considered for the LSCS site in the GEIS (NRC 1996). However, the GEIS did evaluate existing impact assessments performed by the NRC and by the industry at 44 nuclear plants in the United States and concluded that the risk from beyond-design-basis earthquakes at existing nuclear power plants is SMALL. The GEIS for license renewal performed a discretionary analysis of terrorist acts in connection with license renewal and concluded that the core damage and radiological release from such acts would be no worse than the damage and release expected from internally initiated events. In the GEIS, the Commission concludes that the risk from sabotage and beyond-design-basis earthquakes at existing nuclear power plants is small and, additionally, that the risks from other external events are adequately addressed by a generic consideration of internally initiated severe accidents (NRC 1996, 2013a). Based on information in the GEIS, the staff found the following to be true: The probability weighted consequences of atmospheric releases, fallout onto open bodies of water, releases to ground water, and societal and economic impacts from severe accidents are small for all plants. However, alternatives to mitigate severe accidents must be considered for all plants that have not considered such alternatives. The NRC staff identified no new and significant information related to postulated accidents during the review of Exelons ER for LSCS (Exelon 2014a), the site audit, the scoping process, or evaluation of other available information. Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. However, in accordance with 10 CFR 51.53(c)(3)(ii)(L), the staff has reviewed severe accident mitigation alternatives (SAMAs) for LSCS. Severe Accident Mitigation Alternatives If the NRC staff has not previously evaluated SAMAs for the applicants plant in an environmental impact statement or related supplement or in an environmental assessment, 10 CFR Part 51.53(c)(3)(ii)(L) requires license renewal applicants to consider alternatives to mitigate severe accidents. The purpose of this consideration is to ensure that plant changes (i.e., hardware, procedures, and training) with the potential for improving severe accident safety performance are identified and evaluated. Pursuant to 10 CFR Part 54, the only changes that the applicant must implement as part of the license renewal process are those that are identified 4-77

Environmental Consequences and Mitigating Actions as being cost beneficial, that provide a significant reduction in total risk, and that are related to adequately managing the effects of aging during the period of extended operation. Overview of SAMA Process This section presents a summary of the SAMA evaluation for LSCS, as described in the ER (Exelon 2014a), additional requested information (Exelon 2015h), and the NRC staffs review of those evaluations. The NRC staff performed its review with contract assistance from the Center for Nuclear Waste Regulatory Analyses. Appendix F to this SEIS provides the NRC staffs detailed review, and Appendix F to Exelons ER provides Exelons LSCS SAMA evaluation. The SAMA evaluation for LSCS conducted by Exelon contained the following four main components: (1) Exelon quantified the level of risk associated with potential reactor accidents using the plant-specific probabilistic risk assessment (PRA) and other risk models. (2) Exelon examined the major risk contributors and identified possible ways (SAMAs) of reducing that risk. Common ways of reducing risk are changes to components, systems, procedures, and training. (3) Exelon estimated how much each SAMA could reduce risk. Referred to as potential benefits of implementing each SAMA, those estimates were developed in terms of dollars in accordance with NRC guidance for performing regulatory analyses. The costs of implementing the candidate SAMAs were also estimated. Sensitivity analyses were performed by Exelon to quantify effects on the SAMA evaluation. (4) Exelon compared the cost and benefit of each remaining SAMA to determine whether it was cost beneficial (the benefits of the SAMA exceeded its cost). Estimate of Risk Exelon submitted an assessment of SAMAs for LSCS in Appendix F of the ER (Exelon 2014a). The assessment was based on the most recent LSCS PRA available at that time, a plant-specific offsite consequence analysis performed using the MELCOR Accident Consequence Code System (MACCS2) Version 1.13.1 computer code, and insights from the combined individual plant examination (IPE) and individual plant examination of external events (IPEEE) for LSCS (Commonwealth Edison Company (CECO) 1994). Exelon combined two distinct analyses to form the basis for estimating risk in the SAMA analysis: (1) LSCS Level 1 and Level 2 PRA models and (2) a supplemental analysis of offsite consequences and economic impacts (essentially a Level 3 PRA model) developed specifically for the SAMA analysis. The Level 1 model is a significant upgrade and revision to the IPE Level 1 model, whereas the Level 2 model is an update of the prior large early release frequency (LERF) models. The SAMA analysis is based on the most recent LSCS Level 1 and 2 PRA models available at the time of the ER, referred to as the LSCS PRA 2013A (or LS213A) model. This LSCS PRA includes internal floods but does not include external events. The LSCS core damage frequency (CDF) is approximately 2.6x106 per year (Exelon 2014a). Exelon did not explicitly include the contribution from external events within the LSCS SAMA risk estimates; however, it did account for the potential risk reduction benefits associated with external events by multiplying the estimated benefits for internal events by a factor of 5.2. Section F.2.2.2 of Appendix F discusses this issue further. Using the calculated risk reduction as a quantitative measure of the potential benefit from SAMA implementation, Exelon performed a cost-benefit comparison with estimated implementation costs for each SAMA. 4-78

Environmental Consequences and Mitigating Actions The breakdown of CDF by initiating event is provided in Table 4-14. As shown in this table, events initiated by a turbine trip with bypass, a dual unit loss of offsite power, a loss of instrument air, and a loss of condenser vacuum are the dominant contributors to the CDF. Exelon found that station blackout contributes 6.4x107 per year, or 25 percent of the total CDF for internal events, whereas anticipated transients without scram (ATWS) contribute 4.9x107 per year, or approximately 19 percent of the total CDF for each unit (Exelon 2015h). Exelon stated the following: The expansion of the LERF model to a full Level 2 model involved a reassessment of the timing and release categorization of each containment event tree (CET) endstate. To perform this reassessment, MAAP [Modular Accident Analysis Program] calculations for each accident class were performed and used to assess the CET endstates. Each CET node was evaluated and updated to reflect the current state of knowledge regarding Level 2 accident phenomenology. The endstate timing was also updated to reflect the current emergency plan and evacuation time estimates. The Level 2 model uses three general CET types to assess the accident progression during a core damage event. CETs contain both phenomenological and containment system status events. Level 1 core damage sequences are binned into plant damage states or accident classes, which provide the interface between the Level 1 and Level 2 CET analysis. Each accident class bin is entered into the CET, resulting in 15 LSCS-specific CETs. The CET is linked directly to the Level 1 event trees, and CET nodes are evaluated using supporting fault trees (Exelon 2015h). Table 4-14. LSCS CDF for Internal Events Initiating Event CDF(a) (per year) Percent CDF Contribution Turbine Trip with Bypass 5.6x107 22 Dual Unit Loss of Offsite Power 3.1x107 12 Loss of Instrument Air 2.8x107 11 Loss of Condenser Vacuum 2.7x107 10 Fire Protection System Pipe Rupture in Reactor 1.9x107 7 Building Main Steam Isolation Valve Closure 1.4x107 5 Loss of Turbine Building Component Cooling Water 1.2x107 5 Loss of Feedwater 1.1x108 4 Loss of Offsite Power 7.2x108 3 Manual Shutdown 5.9x108 2 Inadvertently Open Relief Valve 5.9x108 2 Loss of 125-V Direct-Current Bus 2A 5.1x108 2 Loss of 125-V Direct-Current Buses 2A and 2B 3.9x108 2 Other Initiating Events(b) 3.3x107 13 Total (Internal Events)(c) 2.58x106 100 (a) CDF is based on Fussell-Vesely importance and total CDF. (b) For Other Initiating Events, each event would contribute less than 2 percent to the total CDF. (c) Column totals may be different because of rounding. Key: CDF = core damage frequency, and V = volt(s). Source: Exelon 2014a 4-79

Environmental Consequences and Mitigating Actions The result of the Level 2 PRA is a set of 13 release bins or categories with their respective frequency and release characteristics. The results of this analysis for LSCS are provided in Tables F.2-5, F.2-6, F.3-15, F.3-16, and F.3-19 of the ER (Exelon 2014a). The categories were defined based on the timing of release (three release time ranges) and the magnitude of release (four release magnitude ranges). One additional release category was included for an intact containment. For use in the SAMA analysis, the release category for high magnitude and early timing was divided into two bins (one with containment isolation and one without such isolation). Due to the small release category contributions from six categories, the number of release category bins was reduced to eight cases. The frequency of each release category was obtained by summing the frequency of the individual accident progression CET endpoints binned into the release category. Source terms were developed for each of the 13 release categories using the results of MAAP Version 4.0.5 computer code calculations (Exelon 2014a). Exelon computed offsite consequences for potential releases of radiological material using the MACCS2 Version 1.13.1 code and analyzed exposure and economic impacts from its determination of offsite and onsite risks. Inputs for these analyses include plant-specific and site-specific input values for core radionuclide inventory, source term and release characteristics, site meteorological data, projected population distribution and growth within a 50-mi (80-km) radius, emergency response evacuation modeling, and economic data. The estimation of onsite impacts (in terms of cleanup costs, decontamination costs, and occupational dose) is based on guidance in NUREG/BR-0184, Regulatory Analysis Technical Evaluation Handbook (NRC 1997). In its calculation for replacement power costs, Exelon accounted for the increased electric power output of LSCS compared to the generic reactor power output presented in NUREG/BR-0184 (NRC 1997). In the ER, as updated by Exelons response to RAIs from the NRC staff (Exelon 2015h), Exelon estimated the dose risk to be 0.0764 person-sievert (Sv) per year (7.64 person-rem per year) to the population within 50 mi (80 km) of the LSCS site. The offsite economic cost risk was calculated to be $57,700 per year. Table 4-15 summarizes the breakdown of the population dose risk by containment release mode. The medium-magnitude intermediate release category accounted for 52 and 62 percent of the population dose risk and offsite economic cost risk, respectively. Additionally, two categories (1) medium-magnitude early release and (2) high-magnitude early release for breaks outside containment) together accounted for approximately 41 and 31 percent of the population dose risk and offsite economic cost risk, respectively. The NRC staff has reviewed Exelons data and evaluation methods and concludes that the quality of the risk analyses is adequate to support an assessment of the risk reduction potential for candidate SAMAs. Accordingly, the staff based its assessment of offsite risk on the CDFs and offsite doses reported by Exelon. Potential Plant Improvements Exelon considered potential plant improvements (SAMAs) that addressed the major contributors to CDF and release frequency at LSCS and considered SAMA candidates from six other boiling water reactor (BWR) plants, as follows: (1) Susquehanna Steam Electric Station; (2) Cooper Nuclear Station; (3) Duane Arnold Energy Center; (4) Nine Mile Point, Unit 2; 4-80

Environmental Consequences and Mitigating Actions (5) Columbia Generating Station; and (6) Grand Gulf Nuclear Station. Exelon identified potential plant improvements by reviewing the following:

  • LSCS PRA results and PRA group insights;
  • Potentially cost-effective Phase 2 SAMAs from the following:
            -   Susquehanna Steam Electric Station SAMA analysis;
            -   Cooper Nuclear Station SAMA analysis;
            -   Duane Arnold Energy Center SAMA analysis;
            -   Nine Mile Point, Unit 2, SAMA analysis;
            -   Columbia Generating Station SAMA analysis; and
            -   Grand Gulf Nuclear Station SAMA analysis;
  • LSCS IPE; and
  • LSCS IPEEE.

Table 4-15. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk for Internal Events Release Mode Population Dose Risk(a) Offsite Economic Cost Risk Frequency ID(b) (per year) person-rem/yr  % Contribution $/yr  % Contribution H/E-BOC(c) 8.3x108 1.3x100 18 7.2x103 13 H/E 6.0x108 3.2x101 4 2.8x103 5 H/I(d) 1.9x108 1.1x101 1 9.7x102 2 M/E 2.4x107 1.7x100 23 1.0x104 18 M/I(d) 1.0x106 3.9x100 52 3.6x104 62 L/E 3.9x107 8.7x102 1 1.3x102 0.2 L/I(d) 1.5x107 1.1x101 1 1.8x102 0.3 CI 6.2x107 1.4x103 <0.1 1x100 <0.1 Total 2.6x106 7.6x100 100 5.8x104 100 4-81

Environmental Consequences and Mitigating Actions Release Mode Population Dose Risk(a) Offsite Economic Cost Risk (a) Unit Conversion Factor: 1 Sv = 100 rem. (b) Release Mode Nomenclature (Magnitude/Timing) Magnitude: High (H)greater than 10-percent release fraction for cesium iodide Medium (M)1- to 10-percent release fraction for cesium iodide Low (L)0.1- to 1-percent release fraction for cesium iodide Low-Low (LL)less than 0.1-percent release fraction for cesium iodide Containment intact (CI)much less than 0.1-percent release fraction for cesium iodide Timing: Early (/E)less than 5 hours0.208 days <br />0.0298 weeks <br />0.00685 months <br /> Intermediate (/I)5 to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> Late (/L)greater than 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> (c) These are contributions from initiators with breaks outside containment (BOC). (d) The release categories for late timing were negligible and subsumed into the intermediate release categories for H, M, and L releases. Categories for LL magnitude releases were negligible and subsumed into the L release category with intermediate timing. Sources: Exelon 2014a, 2015h Exelon indicated that, in addition to the Industry Phase 2 SAMA review identified above, an industry-based SAMA list in Nuclear Energy Institute (NEI) 05-01, Severe Accident Mitigation Alternative (SAMA) Analysis Guidance Document, issued November 2005 (NEI 2005), was used to help identify the types of changes that could be used to address the areas of concern identified through the LSCS importance list review. Based on this review, Exelon identified an initial set of 26 SAMA candidates, referred to as Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the initial list of SAMAs and eliminated SAMAs from further consideration using the following criteria: Applicability to the Plant. If a proposed SAMA does not apply to the LSCS design or has already been implemented, it is not retained. Implementation Cost Greater Than the Screening Cost. If the estimated cost of implementation is greater than the maximum averted cost risk, the SAMA is screened out from further analysis. During this process, two SAMA candidates were screened out based on the excessive cost criterion. Table F.6-1 of the ER (Exelon 2014a) provides a description of each of the 24 Phase II SAMA candidates, which was later changed3 to 25 Phase II SAMA candidates in Exelons revised analysis (Exelon 2015h). In Phase II, a detailed evaluation was performed for each remaining SAMA candidate, as discussed in Sections F.4 and F.6 of Appendix F. To account for the potential impact of external events, the estimated benefits based on internal events were multiplied by a factor of 5.2, as discussed in Section F.2.2.2 of Appendix F. 3 The results of a sensitivity analysis to determine the impact of a correction to the Level 2 model resulted in the retention of one of the Phase I SAMAs (SAMA 26), which was originally screened out. 4-82

Environmental Consequences and Mitigating Actions Evaluation of Risk Reduction and Costs of Improvements Exelon evaluated the risk-reduction potential of the 25 SAMAs retained for the Phase II evaluation in a revised analysis (Exelon 2015h). The SAMA evaluations were generally performed by Exelon in a realistic or slightly conservative fashion that overestimates the benefit of the SAMA. In most cases, the failure likelihood of the added equipment is taken to be optimistically low, thereby overestimating the benefit of the SAMA. Other cases assumed that the SAMA eliminated all the risk associated with the proposed enhancement. The NRC staff notes that this bounding approach overestimates the benefit and is conservative. Exelon used model requantification to determine the potential benefits for each of the SAMAs. The CDFs, population dose reductions, and offsite economic cost reductions were estimated using the LSCS PRA model. The changes made to the model to quantify the impact of each SAMA are described in Section F.6 of the ER. Table 4-16 summarizes the assumptions used to estimate the risk reduction for each evaluated SAMA, the estimated risk reduction in terms of CDF percent reduction, population dose, offsite economic cost, and the estimated total benefit (present value) of the averted risk. The determination of the benefits for the various SAMAs is further discussed in Section F.6 of Appendix F. The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction estimate of each SAMA, as described in the Section F.6 of the ER. The resolution of RAIs that resulted from this review is discussed in Section F.4 of Appendix F. The determination of the benefits for the various SAMAs is further discussed in Section F.6 of Appendix F. Exelon estimated the costs of implementing the 25 Phase II SAMAs through the use of other licensees estimates for similar improvements and the development of site-specific cost estimates, where appropriate. SAMA cost estimates were based on initial hardware, installation, and implementation costs. In response to an NRC staff RAI to provide further information as to what was included in the LSCS cost estimates, Exelon explained that maintenance and testing costs during the license renewal period were conservatively not included in the estimate (Exelon 2015h). The NRC staff reviewed the applicants cost estimates presented in Section F.6 of the ER (Exelon 2014a). For certain improvements, the NRC staff also compared the cost estimates to estimates developed elsewhere for similar improvements, including estimates developed as part of other licensees analyses of SAMAs for operating reactors. The NRC staff noted that a few SAMAs (e.g., SAMAs 8, 14, and 27) involve use of equipment that may be available as a result of the B.5.b program. In response to an NRC staff RAI to discuss this further, Exelon responded that the B.5.b program at LSCS includes a small generator that is used to support two individual safety relief valve (SRV) solenoids to hold the SRVs open after 125-V direct-current (DC) battery depletion, but the generator does not power the station battery chargers, and it is not designed to support the reactor core isolation cooling (RCIC) system through DC feeds. Because of these limitations, the B.5.b generator is not a viable substitute for the generators that have been proposed for SAMAs 8, 14, and 27; therefore, the availability of the B.5.b generator would not reduce the implementation costs for these SAMAs. With the above clarifications, the NRC staff concludes that the cost estimates provided by Exelon are sufficient and appropriate for use in the SAMA evaluation. 4-83

1 Table 4-16. LSCS Potentially Cost-Beneficial SAMAs(a) 

                                                                                     % Risk Reduction(b)             Total Benefit ($)(c)

Baseline with Individual SAMA and Assumptions Baseline Cost ($)(c) Population Uncertainty CDF OECR (Internal + Dose (95th External) Percentile) 2AUTOMATE SUPPRESSION POOL COOLING 14 20 25 1.4M 3.1M 400K SAMA 2 Modeling: The fault tree incorporated the automation of suppression pool cooling alignment by changing the independent basic event IDs for suppression pool cooling initiation to alternate IDs. This accomplishes two functions: (1) assignment of alternate failure probabilities that are representative of an automated function and (2) prevention of the recovery logic from identifying suppression pool cooling initiation failures as human actions and preclusion of the suppression pool cooling initiation failures from dependent human error combinations. 3INSTALL PASSIVE VENT PATH 36 51 61 1.0M 2.2M 1.0M SAMA 3 Modeling: The basic event for the operator action for venting was replaced with a new placeholder event with a value of 1x106, which prevents the creation of dependent operator actions, including the vent action. The hardware failures associated with the vent path valves have been retained to approximate the potential failures of the rupture disk (with the support system dependencies removed). 4INSTALL A KEYLOCK MSIV LOW-LEVEL ISOLATION 16 12 10 674K 1.4M 635K 4-84 BYPASS SWITCH SAMA 4 Modeling: The independent human error probability to bypass the main steam isolation valve low-level isolation interlock was set to Environmental Consequences and Mitigating Actions 1x105, and the joint human error probabilities that include this action have been eliminated. 5AUTOMATE SBLC INITIATION 8 7 6 386K 827K 400K SAMA 5 Modeling: The automatic SBLC initiation capability is modeled by manipulation of associated basic events. Early SBLC initiation basic event ID (2SLOP-LVLCTRLH--) was changed to SAMA5 and set to a probability of 1x106 to reduce the independent failure contribution to a small value and to prevent the inclusion of dependent operator action combinations with SBLC initiation failures, consistent with the automated action. 8OBTAIN A 480-V AC PORTABLE GENERATOR TO SUPPLY THE 125-V DC BATTERY CHARGERS AND DEVELOP 4 4 4 259K 554K 400K PROCEDURES FOR ITS USE SAMA 8 Modeling: The 480-V AC generator capability has been approximated by adding the diesel fire pump as a low-pressure injection source for station blackout scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480-V AC power source that feeds the Division 1 battery chargers. 9DEVELOP FLOOD ZONE-SPECIFIC PROCEDURES 9 3 3 224K 479K 115K SAMA 9 Modeling: Initiating event frequencies for flooding events were set to zero in the cutsets. 

                                                                                    % Risk Reduction(b)            Total Benefit ($)(c)

Baseline with Individual SAMA and Assumptions Baseline Cost ($)(c) Population Uncertainty CDF OECR (Internal + Dose (95th External) Percentile) 10CHANGE THE LOGIC TO CLOSE THE TURBINE DRIVEN FEEDWATER PUMP DISCHARGE VALVES WHEN THE PUMPS 9 21 23 1.3M 2.8M 260K ARE NOT RUNNING SAMA 10 Modeling: The human failure event associated with closing the turbine-driven feedwater pump discharge valves was changed to a new event with a failure probability of 1x104. This treatment reduces the independent contribution of the isolation failure and precludes the generation of dependent human error combination, including the operator action to isolate the valves. 14PROVIDE A PORTABLE DC SOURCE TO SUPPORT RCIC 9 7 7 444K 949K 489K AND SRV OPERATION SAMA 14 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low-pressure injection source for station blackout scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480-V AC power source that feeds the Division 1 battery chargers. 15TIE RHRSW TO THE LPCS SYSTEM FOR ISLOCA 37 57 57 3.4M 7.2M 1.4M MITIGATION 4-85 SAMA 15 Modeling: Changes were made to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the cross-tie. The cross-tie logic was added at the sequence level for BOC and ISLOCA sequences for which credit was not previously taken for any low-pressure injection systems, and was added to the existing fault tree structure in scenarios for which venting or containment failure resulted in the loss of injection systems. 16PROVIDE PORTABLE FANS FOR ALTERNATE ROOM 14 12 15 866K 1.9M 475K COOLING IN THE CSCS VAULTS SAMA 16 Modeling: The alternate CSCS room cooling capability was approximated by deleting the gates associated with room cooling failures (excluding the automatic initiation failures, which are already addressed in the model). 18IMPROVE THE CONNECTION BETWEEN THE FIRE 9 9 10 609K 1.3M 649K PROTECTION AND FEEDWATER SYSTEMS SAMA 18 Modeling: The fault tree was updated to credit the FPS in places for which LPCI and LPCS are credited, but the system is failed for the LOCA and IORV initiating event and for water hammer scenarios. In addition, the logic was changed to include the FPS injection capability in the early station blackout scenarios in which the ADS is available for those sequences not impacted by the LPCS-LPCI gate. 19PROVIDE REMOTE ALIGNMENT CAPABILITY OF RHRSW 38 58 58 3.4M 7.3M 2.9M TO THE LPCS SYSTEM FOR LOCA MITIGATION Environmental Consequences and Mitigating Actions 

                                                                                              % Risk Reduction(b)   Total Benefit ($)(c)

Baseline with Individual SAMA and Assumptions Baseline Cost ($)(c) Population Uncertainty CDF OECR (Internal + Dose (95th External) Percentile) SAMA 19 Modeling: The inclusion of the RHRSW-LPCS cross-tie required changes to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event for failure to align the cross-tie. Cross-tie logic was added at the sequence level for BOC and ISLOCA sequences for which credit was not previously taken for any low-pressure injection systems and was added to the existing fault tree structure in scenarios in which venting or containment failure resulted in the loss of injection systems. 21INSTALL AUTOMATIC ATWS LEVEL CONTROL SYSTEM 14 14 12 754K 1.6M 1.5M SAMA 21 Modeling: The SAMA is modeled by setting the early and late level control actions to zero in the fault tree. 23ENHANCE THE FUEL POOL EMERGENCY MAKEUP PUMP 27 46 52 3.0M 6.5M 1.4M AND CONNECTION SAMA 23 Modeling: The inclusion of the fuel pool emergency makeup pump cross-tie required changes to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the residual heat removal B injection path (existing logic from the LPCI system). The 4-86 logic was added to the existing fault tree structure in scenarios in which venting or containment failure resulted in the loss of injection systems. (a) Potentiallycost-beneficial SAMAs relate to LSCS, Unit 1 and Unit 2. Environmental Consequences and Mitigating Actions (b) Risk reduction percentages displayed in this table were obtained from the ER (Exelon, 2014) before Exelons revised results (Exelon 2015h). Risk reduction percentages for the revised benefit results were not provided. (c) Exelon identified potentially cost-beneficial SAMAs by comparing the total benefit with uncertainty at the 95th percentile to the estimated implementation cost. Total benefit and cost values presented in this table were obtained from Exelons revised results (Exelon 2015h). Key: AC = alternating current, ADS = automatic depressurization system, ATWS = anticipated transients without scram, BOC = break outside containment, CDF = core damage frequency, CSCS = core standby cooling system, DC = direct current, ECCS = emergency core cooling system, FPS = fire protection system, ID = identification, IORV = inadvertent/stuck open relief valve, ISLOCA = interfacing-systems loss-of-coolant accident, LPCI = low-pressure coolant injection, LPCS = low-pressure core spray, LOCA = loss-of-coolant accident, MSIV = main steam isolation valve, OECR = offsite economic cost risk, RCIC = reactor core isolation cooling, RHRSW = residual heat removal service water, SAMA = severe accident mitigation alternative, SBLC = standby liquid control, and SRV = safety relief valve. Sources: Exelon 2014a, 2015h 1

Environmental Consequences and Mitigating Actions 1 Cost-Benefit Comparison 2 If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 3 was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 4 SAMA candidate was considered to be potentially cost beneficial. Table 4-16 presents the 5 results of the cost-benefit evaluation. Exelons cost-benefit analysis identified 14 SAMA 6 candidates determined to be potentially cost beneficial at the 95th percentile on an individual 7 basis, as follows: 8

  • SAMA 2: Automate suppression pool cooling.

9

  • SAMA 3: Install passive vent path.

10

  • SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level isolation 11 bypass switch.

12

  • SAMA 5: Automate SBLC initiation.

13

  • SAMA 8: Obtain a 480-V AC portable generator to supply the 125-V DC battery 14 chargers and develop procedures for its use.

15

  • SAMA 9: Develop flood zone-specific procedures.

16

  • SAMA 10: Change the logic to close the turbine-driven feedwater pump discharge 17 valves when the pumps are not running.

18

  • SAMA 14: Provide a portable DC source to support RCIC and SRV operation.

19

  • SAMA 15: Tie RHRSW to the LPCS system for ISLOCA mitigation.

20

  • SAMA 16: Provide portable fans for alternate room cooling in the core standby 21 cooling system vaults.

22

  • SAMA 18: Improve the connection between the fire protection and 23 feedwater systems.

24

  • SAMA 19: Provide remote alignment capability of RHRSW to the LPCS system for 25 LOCA mitigation.

26

  • SAMA 21: Install automatic ATWS level control system.

27

  • SAMA 23: Enhance the fuel pool emergency makeup pump and connection.

28 When the planned installation of a hardened vent pipe is considered as the base case, the 29 number of SAMA candidates considered to be potentially cost beneficial at the 95th percentile 30 may be reduced. Because a new baseline is established following the implementation of a 31 SAMA, which further influences the benefits provided by the remaining SAMA candidates, 32 Exelon defined an optimal set to containing SAMAs that, if implemented, would render the 33 remaining SAMAs to be not cost beneficial. Acknowledging Exelons commitment to install the 34 hardened vent pipe (SAMA 1), additional modifications included in the optimal set are 35 SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a). Assessment of the optimal set 36 was performed before Exelon generated revised results in response to the NRC staffs RAIs 37 (Exelon 2015h). Because Exelon did not take a priori credit for installation of the hardened vent 38 pipe, revision to the optimal set assessment was not required. Exelon is referring the 39 14 potentially cost-beneficial SAMAs from its revised analysis (Exelon 2015h) to the LSCS Plant 40 Health Committee for further implementation considerations within the established plant 41 procedural process, as indicated in Section 4.15 of the ER (Exelon 2014a). 4-87

Environmental Consequences and Mitigating Actions 1 Conclusions 2 Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 3 updated probabilistic safety assessment models, SAMA-related industry documentation, 4 plant-specific enhancements, and its review of SAMA candidates from potential improvements 5 primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 6 SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 7 been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 8 costs and benefits associated with each of the 25 potential SAMAs. Exelon concluded that 9 14 SAMA candidates were potentially cost beneficial at the 95th percentile (shown in 10 Table 4-16). Exelon has decided to proceed with the modification to install a hardened vent 11 pipe regardless of cost even though it is not cost beneficial. From a sensitivity analysis, no 12 additional SAMA candidates were identified as potentially cost beneficial. Because the 13 potentially cost-beneficial SAMAs do not relate to aging management during the period of 14 extended operation, their implementation is not required as part of license renewal pursuant to 15 10 CFR Part 54. Nevertheless, as stated in Section 4.15 of the ER (Exelon 2014a), Exelon 16 indicated that the potentially cost-beneficial SAMAs are being referred to the LSCS Plant Health 17 Committee for further implementation considerations within the established plant procedural 18 process. 19 The NRC staff reviewed Exelons SAMA analysis and concludes that, based on the discussion 20 in Appendix F of this document, the methods used and implementation of those methods were 21 sound. On the basis of the applicants treatment of SAMA benefits and costs, the NRC staff 22 finds that the SAMA evaluations performed by Exelon are reasonable and are sufficient for the 23 license renewal submittal. The NRC staff concurs with Exelons conclusion that 14 SAMA 24 candidates are potentially cost beneficial for LSCS and notes that Exelons assessment was 25 based on generally conservative treatment of costs, benefits, and uncertainties. Based on the 26 NRC staffs review of Exelons SAMA evaluations, including Exelons response to the NRC 27 staffs RAIs, the NRC staff concludes that Exelon has adequately identified areas in which risk 28 can be further reduced in a cost-beneficial manner through the implementation of the identified 29 potentially cost-beneficial SAMAs. Given the potential for cost-beneficial risk reduction, the 30 NRC staff agrees that further evaluation by Exelon of the 14 SAMA candidates identified by 31 Exelon as being potentially cost beneficial is warranted. 32 The NRC staff also evaluated whether the identified potentially cost-beneficial SAMAs are 33 subject to aging management. The evaluation considered any structures, systems, and 34 components associated with these SAMAs that perform intended functions without moving parts 35 or without a change in configuration or properties and that would not be subject to replacement 36 based on a qualified life or specified time period. The NRC staff determined that the potentially 37 cost-beneficial SAMAs do not relate to adequately managing the effects of aging during the 38 period of extended operation. Therefore, they do not need to be implemented as part of license 39 renewal in accordance with 10 CFR Part 54. 40 4.11.2 No-Action Alternative 41 Human health risks would be smaller following plant shutdown. The two reactor units, which are 42 currently operating within regulatory limits, would emit less gaseous, liquid, and solid radioactive 43 material to the environment. In addition, following shutdown, the variety of potential accidents at 44 the plant (radiological or industrial) would be reduced to a limited set associated with shutdown 45 events and fuel handling and storage. In Section 4.11.1, the NRC staff concluded that the 46 impacts of continued plant operation on human health would be SMALL, except for chronic 47 effects of electromagnetic fields (EMFs), for which the impacts are UNCERTAIN. In 48 Section 4.11.1.2, the NRC staff concluded that the impacts of accidents during operation were 4-88

Environmental Consequences and Mitigating Actions 1 SMALL. Therefore, as radioactive emissions to the environment decrease, and as the likelihood 2 and types of accidents decrease following shutdown, the NRC staff concludes that the risk to 3 human health following plant shutdown would be SMALL. 4 4.11.3 New Nuclear Alternative 5 Impacts on human health from construction of two new nuclear units would be similar to impacts 6 associated with the construction of any major industrial facility. Compliance with worker 7 protection rules would control those impacts on workers at acceptable levels. Impacts from 8 construction on the general public would be minimal, since limiting active construction area 9 access to authorized individuals is expected. Impacts on human health from the construction of 10 two new nuclear units would be SMALL. 11 The human health effects from the operation of two new nuclear units would be similar to those 12 of operating the two existing LSCS units. As presented in Section 4.11.1, impacts on human 13 health from the operation of LSCS would be SMALL, except for chronic effects of 14 electromagnetic fields (EMFs), for which the impacts are UNCERTAIN. Therefore, the impacts 15 on human health from the operation of two new nuclear units would be SMALL. 16 4.11.4 IGCC Alternative 17 Impacts from construction on workers are expected to be similar to those experienced during 18 construction of any major industrial facility. Impacts from construction of an IGCC facility are 19 expected to be the same as those for construction of fossil fuel facilities. Construction would 20 increase traffic on local roads, which could affect the health of the general public. Human health 21 impacts would be the same for all facilities, whether located on greenfield sites or at an existing 22 power plant. Personal protective equipment, training, and engineered barriers would protect the 23 workforce (NRC 2013d). Therefore, the impacts on human health from the construction of an 24 IGCC facility would be SMALL. 25 The IGCC alternative introduces worker risks from coal and limestone mining, worker and public 26 risk from coal and lime/limestone transportation, worker and public risk from disposal of 27 coal-combustion waste, and public risk from inhalation of stack emissions. In addition, human 28 health risks are associated with the management and disposal of coal combustion waste. Coal 29 combustion generates waste in the form of ash, and equipment for controlling air pollution 30 captures additional ash and produces scrubber sludge, which must be managed as coal 31 combustion waste. Human health risks may extend beyond the facility workforce to the public, 32 depending on their proximity to the coal combustion waste storage and/or disposal facility. The 33 character and the constituents of coal combustion waste depend on both the chemical 34 composition of the source coal and the technology used to combust it. Generally, the primary 35 sources of adverse consequences from coal combustion waste are from exposure to sulfur 36 oxide and nitrogen oxide in air emissions and radioactive elements, such as uranium and 37 thorium, as well as the heavy metals and hydrocarbon compounds contained in fly ash and 38 bottom ash, and scrubber sludge (NRC 2013d). 39 Regulatory agencies, including EPA and state agencies, base air emission standards and 40 requirements on human health impacts. These agencies also impose site-specific emission 41 limits as needed to protect human health. Given the regulatory oversight exercised by EPA and 42 state agencies, the NRC staff concludes that the human health impacts from radiological doses 43 and inhaled toxins and particulates generated from the IGCC alternative would be SMALL 44 (NRC 2013d). 4-89

Environmental Consequences and Mitigating Actions 1 4.11.5 NGCC Alternative 2 Impacts on human health from construction of the NGCC alternative would be similar to effects 3 associated with the construction of any major industrial facility. Compliance with worker 4 protection rules would control those impacts on workers at acceptable levels. Impacts from 5 construction on the general public would be minimal, since crews would limit active construction 6 area access to authorized individuals. Based on the above, the NRC staff concludes that the 7 impacts on human health from the construction of the NGCC alternative would be SMALL. 8 Impacts from the operation of an NGCC facility include public risk from inhalation of gaseous 9 emissions. The risk may be attributable to nitrogen oxide emissions that contribute to ozone 10 formation, which in turn contribute to health risk. Regulatory agencies, including the EPA and 11 state agencies, base air emission standards and requirements on human health impacts. 12 These agencies also impose site-specific emission limits as needed to protect human health. 13 Given the regulatory oversight exercised by EPA and state agencies, the NRC staff concludes 14 that the human health impacts from the NGCC alternative would be SMALL. 15 4.11.6 Combination Alternative (NGCC, Wind, Solar) 16 Impacts on human health from construction of a combination of NGCC, wind, and solar 17 alternative would be similar to effects associated with the construction of any major industrial 18 facility. Compliance with worker protection rules and personal protective equipment, training, 19 and engineered barriers would protect the workforce (NRC 2013d). Impacts from construction 20 on the general public would be minimal, since crews would limit active construction area access 21 to authorized individuals. Based on the above, the NRC staff concludes that the Impacts on 22 human health from the construction of the NGCC, wind, and solar alternative would be SMALL. 23 Operational hazards at an NGCC facility are discussed in Section 4.11.5. 24 Operational hazards at a wind facility for the workforce include working at heights, near rotating 25 mechanical or electrically energized equipment, and in extreme weather. Potential impacts to 26 workers and the public include ice thrown from rotor blades and broken blades thrown as a 27 result of mechanical failure. Potential impacts also include EMF exposure, aviation safety 28 (hazards), and exposure to noise and vibration from the rotating blades. 29 Operational hazards at a solar PV facility may involve exposure to airborne toxic metals 30 (e.g., cadmium) and silicon if the PV cell loses its integrity from a fire. Workers could also inhale 31 silicon dust if a PV cell were smashed by an object or from a fall to the ground. However, based 32 on worker and environmental protection rules, it is expected that remediation of toxic material 33 would occur. Such remediation would minimize the impact to workers and the environment. 34 Therefore, given the expected compliance with worker and environmental protection rules and 35 the use of personal protective equipment, training, and engineered barriers, the NRC staff 36 concludes that the potential human health impacts would be SMALL. 37 4.11.7 Purchased Power Alternative 38 Purchased power is expected to come from the types of electricity generation available within 39 the ROI: coal, natural gas, nuclear, and wind. The human health impacts from the operation of 40 these types of power plants are discussed in Sections 4.11.3, 4.11.4, 4.11.5, and 4.11.6. Based 41 on the information in those sections, the NRC staff concludes that the human health impacts of 42 the purchased power alternative using nuclear, coal, natural gas, wind, and solar would be 43 SMALL. 4-90

Environmental Consequences and Mitigating Actions 1 4.12 Environmental Justice 2 This section describes the potential human health and environmental effects of the proposed 3 action (license renewal) and alternatives to the proposed action on minority and low-income 4 populations. 5 4.12.1 Proposed Action 6 Section 3.12 identifies minority and low-income populations living in the vicinity of LSCS. 7 Table 4-17 identifies the environmental justice issue applicable to LSCS during the license 8 renewal term. 9 Table 4-17. Environmental Justice NEPA Issue Issue GEIS Section Category Minority and low-income populations 4.10.1 2 Source: Table B-1 in Appendix B, Subpart A of 10 CFR Part 51 10 The NRC addresses environmental justice matters for license renewal by (1) identifying the 11 location of minority and low-income populations that may be affected by the continued operation 12 of the nuclear power plant during the license renewal term, (2) determining whether there would 13 be any potential human health or environmental effects to these populations and special 14 pathway receptors, and (3) determining if any of the effects may be disproportionately high and 15 adverse. Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal 16 adverse impacts on human health. Disproportionately high and adverse human health effects 17 occur when the risk or rate of exposure to an environmental hazard for a minority or low-income 18 population is significant and exceeds the risk or exposure rate for the general population or for 19 another appropriate comparison group. Disproportionately high environmental effects refer to 20 impacts or risks of impacts on the natural or physical environment in a minority or low-income 21 community that are significant and appreciably exceed the environmental impact on the larger 22 community. Such effects may include biological, cultural, economic, or social impacts. 23 Figures 3-17 and 3-18 show the location of predominantly minority and low-income population 24 block groups residing within a 50-mi (80-km) radius of LSCS. This area of impact is consistent 25 with the impact analysis for public and occupational health and safety, which also focuses on 26 populations within a 50-mi (80-km) radius of the plant. Chapter 4 presents the assessment of 27 environmental and human health impacts for each resource area. The analyses of impacts for 28 all environmental resource areas indicated that the impact from license renewal would be 29 SMALL. 30 Potential impacts on minority and low-income populations (including migrant workers or Native 31 Americans) would mostly consist of socioeconomic and radiological effects; however, radiation 32 doses from continued operations during the license renewal term are expected to continue at 33 current levels, and they would remain within regulatory limits. Section 4.11.1.2 of this SEIS 34 discusses the environmental impacts from postulated accidents that might occur during the 35 license renewal term, which include both design basis and severe accidents. In both cases, the 36 Commission has generically determined that impacts associated with DBAs are small because 37 nuclear plants are designed and operated to successfully withstand such accidents, and the 38 probability-weighted consequences of severe accidents are small. 39 Therefore, based on this information and the analysis of human health and environmental 40 impacts presented in Chapter 4 of this SEIS, there would be no disproportionately high and 4-91

Environmental Consequences and Mitigating Actions 1 adverse human health and environmental effects on minority and low-income populations from 2 the continued operation of LSCS during the license renewal term. 3 As part of addressing environmental justice concerns associated with license renewal, the NRC 4 staff also assessed the potential radiological risk to special population groups (such as migrant 5 workers or Native Americans) from exposure to radioactive material received through their 6 unique consumption practices and interaction with the environment, including subsistence 7 consumption of fish and wildlife, native vegetation, surface waters, sediments, and local 8 produce; absorption of contaminants in sediments through the skin; and inhalation of airborne 9 radioactive material released from the plant during routine operation. This analysis is presented 10 below. 11 Subsistence Consumption of Fish and Wildlife 12 The special pathway receptors analysis is an important part of the environmental justice 13 analysis because consumption patterns may reflect the traditional or cultural practices of 14 minority and low-income populations in the area, such as migrant workers or Native Americans. 15 Section 4-4 of Executive Order 12898 (1994) directs Federal agencies, whenever practical and 16 appropriate, to collect and analyze information about the consumption patterns of populations 17 that rely principally on fish and/or wildlife for subsistence and to communicate the risks of these 18 consumption patterns to the public. In this SEIS, the NRC considered whether there were any 19 means for minority or low-income populations to be disproportionately affected by examining 20 impacts on American Indian, Hispanics, migrant workers, and other traditional lifestyle special 21 pathway receptors. The assessment of special pathways considered the levels of radiological 22 and nonradiological contaminants in vegetation, crops, soils and sediments, groundwater, 23 surface water, fish, and game animals on or near LSCS. 24 Radionuclides released to the atmosphere may deposit on soil and vegetation and, therefore, 25 may eventually be incorporated into the human food chain. To assess the impact of LSCS 26 operations to humans from the ingestion pathway, samples of fish, milk, green leafy vegetables, 27 surface water, sediment, and groundwater are collected and analyzed for radioactivity. The 28 following describes Exelons radiological environmental monitoring program (REMP). 29 Exelon has an ongoing comprehensive REMP to assess the impact of LSCS operations on the 30 environment. To assess the impact of nuclear power plant operations, samples are collected 31 annually from the environment and analyzed for radioactivity. A plant effect would be indicated 32 if the radioactive material detected in a sample were larger or higher than background levels. 33 Two types of samples are collected. The first type, a control sample, is collected from areas 34 that are beyond the influence of the nuclear power plant or any other nuclear facility. These 35 samples are used as reference data to determine normal background levels of radiation in the 36 environment. These samples are then compared with the second type of samples, indicator 37 samples, collected near the nuclear power plant. Indicator samples are collected from areas 38 where any contribution from the nuclear power plant will be at its highest concentration. These 39 samples are then used to evaluate the contribution of nuclear power plant operations to 40 radiation or radioactivity levels in the environment. An effect would be indicated if the 41 radioactivity levels detected in an indicator sample were larger or higher than the control sample 42 or background levels. 43 Samples were collected from the aquatic and terrestrial environment in the vicinity of LSCS in 44 2014. The aquatic environment includes groundwater, surface water, fish, and river sediment. 45 Aquatic monitoring results for 2014 of water, sediment, and fish showed only naturally occurring 46 radioactivity and radioactivity associated with fallout from past atmospheric nuclear weapons 47 testing and were consistent with levels measured prior to the operation of LSCS. No 4-92

Environmental Consequences and Mitigating Actions 1 radioactivity was detected greater than the minimum detectable activity in any aquatic sample 2 during 2014, and no adverse long-term trends were identified in aquatic monitoring data 3 (Exelon 2015a). 4 The terrestrial environment includes airborne particulates, milk, and food products (i.e., beets, 5 kohlrabi, potatoes, Swiss chard, and kale). However, cow milk samples were not analyzed in 6 2014, as the dairy herd was sold prior to the first sample in 2014 (Exelon 2015a). Terrestrial 7 monitoring results for 2014 of groundwater and leafy garden vegetable samples, showed only 8 naturally occurring radioactivity. The radioactivity levels detected were consistent with levels 9 measured prior to the operation of LSCS. No radioactivity was detected greater than the 10 minimum detectable activity in any terrestrial samples during 2014. The terrestrial monitoring 11 data also showed no adverse trends in the terrestrial environment (Exelon 2015a). 12 Analyses performed on 1,393 samples collected from the environment at LSCS in 2014 showed 13 no significant measurable radiological constituent above background levels. Overall, 14 radioactivity levels detected in 2014 were consistent with previous levels, as well as radioactivity 15 levels measured prior to the operation of LSCS. REMP sampling in 2014 did not identify any 16 radioactivity above the minimum detectable activity (Exelon 2015a). 17 Based on the radiological environmental monitoring data from LSCS, the NRC staff finds that no 18 disproportionately high and adverse human health impacts would be expected in special 19 pathway receptor populations in the region as a result of subsistence consumption of water, 20 local food, fish, and wildlife. Continued operation of LSCS would not have disproportionately 21 high and adverse human health and environmental effects on these populations. 22 4.12.2 No-Action Alternative 23 This section evaluates the potential for disproportionately high and adverse human health and 24 environmental effects on minority and low-income populations that could result from the 25 no-action alternative. Impacts on minority and low-income populations would depend on the 26 number of jobs and the amount of tax revenues lost by communities in the immediate vicinity of 27 the power plant after LSCS ceases operations. Not renewing the operating licenses and 28 terminating reactor operations would have a noticeable impact on socioeconomic conditions in 29 the communities located near LSCS. The loss of jobs and income would have an immediate 30 socioeconomic impact. Some, but not all, of the approximately 890 employees would begin to 31 leave after reactor operations are terminated; and overall tax revenue generated by plant 32 operations would be reduced. The reduction in tax revenue would decrease the availability of 33 public services in LaSalle County. This could disproportionately affect minority and low-income 34 populations that may have become dependent on these services. See also Appendix J of 35 NUREG-0586, Supplement 1 (NRC 2002), for additional discussion of these impacts. 36 4.12.3 New Nuclear Alternative 37 This section evaluates the potential for disproportionately high and adverse human health and 38 environmental effects on minority and low-income populations that could result from the 39 construction and operation of a new nuclear power plant. Some of these potential effects have 40 been identified in resource areas discussed in this SEIS. For example, increased demand for 41 rental housing during replacement power plant construction could disproportionately affect 42 low-income populations. Everyone living near the proposed power plant site could be affected 43 by the construction and operation of a new nuclear power plant, including minority and 44 low-income populations. 4-93

Environmental Consequences and Mitigating Actions 1 Potential impacts to minority and low-income populations from the construction and operation of 2 a new nuclear power plant at an existing nuclear power plant or retired coal plant site would 3 mostly consist of environmental and socioeconomic effects (e.g., noise, dust, traffic, 4 employment, and housing impacts). Noise and dust impacts from construction would be short 5 term and primarily limited to onsite activities. Minority and low-income populations residing 6 along site access roads would be affected by increased commuter vehicle traffic during shift 7 changes and truck traffic. However, these effects would be temporary during certain hours of 8 the day and would not likely be high and adverse. Increased demand for rental housing during 9 construction could affect low-income populations. However, given the proximity of some 10 existing nuclear power plant or retired coal plant sites to metropolitan areas, construction 11 workers could commute to the site, thereby reducing the potential demand for rental housing. 12 Potential impacts to minority and low-income populations from new nuclear power plant 13 operations would mostly consist of radiological effects; however, radiation doses are expected 14 to be well below regulatory limits. All people living near the new nuclear power plant would be 15 exposed to the same potential effects from power plant operations, and permitted air emissions 16 are expected to remain within regulatory standards. 17 Based on this information and the analysis of human health and environmental impacts 18 presented in this SEIS, it is not likely that the construction and operation of a new nuclear power 19 plant would have disproportionately high and adverse human health and environmental effects 20 on minority and low-income populations. However, this determination would depend on the 21 location, plant design, and operational characteristics of the new power plant. Therefore, the 22 NRC staff cannot determine whether this alternative would result in disproportionately high and 23 adverse human health and environmental effects on minority and low-income populations. 24 4.12.4 IGCC Alternative 25 This section evaluates the potential for disproportionately high and adverse human health and 26 environmental effects on minority and low-income populations that could result from the 27 construction and operation of a new IGCC power plant. Some of these potential effects have 28 been identified in resource areas discussed in this SEIS. For example, increased demand for 29 rental housing during replacement power plant construction could disproportionately affect 30 low-income populations. Everyone living near the proposed power plant site could be affected 31 by the construction and operation of a new IGCC power plant, including minority and 32 low-income populations. 33 Potential impacts to minority and low-income populations from the construction and operation of 34 a new IGCC plant at the LSCS site or at another existing power plant site would consist of 35 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 36 impacts). Noise and dust impacts from construction would be short term and primarily limited to 37 onsite activities. Minority and low-income populations residing along site access roads would 38 be affected by increased commuter vehicle traffic during shift changes and truck traffic. 39 However, these effects would be temporary during certain hours of the day and would not likely 40 be high and adverse. Increased demand for rental housing during construction could affect 41 low-income populations. However, given the proximity of some existing power plant sites to 42 Chicago (LSCS site) and other metropolitan areas (at another existing power plant site), 43 construction workers could commute to the site, thereby reducing the potential demand for 44 rental housing. 45 Emissions from the IGCC plant during power plant operations could disproportionately affect 46 minority and low-income populations. However, permitted air emissions are expected to remain 47 within regulatory standards. 4-94

Environmental Consequences and Mitigating Actions 1 Based on this information and the analysis of human health and environmental impacts 2 presented in this SEIS, it is not likely that the construction and operation of a new IGCC plant 3 would have disproportionately high and adverse human health and environmental effects on 4 minority and low-income populations. However, this determination would depend on the 5 location, plant design, and operational characteristics of the new power plant at the LSCS site or 6 at another existing power plant site. Therefore, the NRC staff cannot determine whether this 7 alternative would result in disproportionately high and adverse human health and environmental 8 effects on minority and low-income populations. 9 4.12.5 NGCC Alternative 10 This section evaluates the potential for disproportionately high and adverse human health and 11 environmental effects on minority and low-income populations that could result from the 12 construction and operation of a new NGCC plant. Some of these potential effects have been 13 identified in resource areas discussed in this SEIS. For example, increased demand for rental 14 housing during replacement power plant construction could disproportionately affect low-income 15 populations. Everyone living near the proposed power plant site could be affected by the 16 construction and operation of a new NGCC power plant, including minority and low-income 17 populations. 18 Potential impacts to minority and low-income populations from the construction and operation of 19 a new NGCC plant at the LSCS site would mostly consist of environmental and socioeconomic 20 effects (e.g., noise, dust, traffic, employment, and housing impacts). Noise and dust impacts 21 from construction would be short term and primarily limited to onsite activities. Minority and 22 low-income populations residing along site access roads would be affected by increased 23 commuter vehicle traffic during shift changes and truck traffic. However, these effects would be 24 temporary during certain hours of the day and would not likely be high and adverse. Increased 25 demand for rental housing during construction could affect low-income populations in the vicinity 26 of the LSCS site. However, given the proximity of LSCS to the Chicago metropolitan area, 27 many construction workers could commute to the site, thereby reducing the potential demand 28 for rental housing. 29 Emissions from the NGCC plant during power plant operations could disproportionately affect 30 minority and low-income populations living in the vicinity of the new power plant. However, 31 permitted air emissions are expected to remain within regulatory standards. 32 Based on this information and the analysis of human health and environmental impacts 33 presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant 34 would have disproportionately high and adverse human health and environmental effects on 35 minority and low-income populations. However, this determination would depend on the 36 location, plant design, and operational characteristics of the new power plant at LSCS. 37 Therefore, the NRC staff cannot determine whether this alternative would result in 38 disproportionately high and adverse human health and environmental effects on minority and 39 low-income populations. 40 4.12.6 Combination Alternative (NGCC, Wind, Solar) 41 This section evaluates the potential for disproportionately high and adverse human health and 42 environmental effects on minority and low-income populations that could result from the 43 construction and operation of a combination of NGCC, wind, and solar PV electrical power 44 generating activities. Some of these potential effects have been identified in resource areas 45 discussed in this SEIS. For example, increased demand for rental housing during construction 46 could disproportionately affect low-income populations. Everyone living near the new NGCC, 4-95

Environmental Consequences and Mitigating Actions 1 wind farms, and solar PV installations could be affected by construction activities and facility 2 operations, including minority and low-income populations. 3 Potential impacts to minority and low-income populations from the construction and operation of 4 a new NGCC plant, wind turbines, and solar PV installations would mostly consist of 5 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 6 impacts). Noise and dust impacts from construction would be short term and primarily limited to 7 onsite activities. Minority and low-income populations residing along site access roads would 8 be affected by increased commuter vehicle traffic during shift changes and truck traffic. 9 However, these effects would be temporary during certain hours of the day and would not likely 10 be high and adverse. Increased demand for rental housing during construction could affect 11 low-income populations. However, given the small number of construction workers and the 12 possibility that many workers could commute to these construction sites, the potential need for 13 rental housing would not be significant. 14 Minority and low-income populations living in close proximity to wind farm and solar PV power 15 generating installations could be disproportionately affected by maintenance and operations 16 activities. However, operational impacts from the wind turbines and solar PV installations would 17 mostly be limited to noise and aesthetic effects. 18 Based on this information and the analysis of human health and environmental impacts 19 presented in this SEIS, it is not likely that the construction and operation of a new NGCC plant, 20 wind farms, and solar PV installations would have disproportionately high and adverse human 21 health and environmental effects on minority and low-income populations. However, this 22 determination would depend on the location, plant design, and operational characteristics of 23 these new power generating facilities. Therefore, the NRC staff cannot determine whether this 24 alternative would result in disproportionately high and adverse human health and environmental 25 effects on minority and low-income populations. 26 4.12.7 Purchased Power Alternative 27 This section evaluates the potential for disproportionately high and adverse human health and 28 environmental effects on minority and low-income populations that could result from purchasing 29 electric power. As previously discussed, such effects may include human health, biological, 30 cultural, economic, or social impacts. 31 Purchased power from existing power generating facilities would not likely have any 32 disproportionately high and adverse effects on minority populations, because there would be no 33 change in power plant operations or workforce. However, low-income populations could be 34 disproportionately affected by increased utility bills, due to the cost of purchased power, 35 although programs are available to assist low-income families in paying for increased electrical 36 costs. 37 If the amount of purchased power needed exceeds the available supply, new electric power 38 generating facilities would be needed. Construction and operation of a new electrical power 39 generating facility to supply purchased power could create new human health and 40 environmental effects in communities located near the new facility. Everyone living near the 41 new electric power generating facility could be affected by construction activities and facility 42 operations, including minority and low-income populations. 43 Potential human health and environmental effects from constructing and operating a new power 44 generating facility have been described in the previous sections. Operational impacts for all 45 new power generating facilities would mostly be limited to noise, air emissions, and aesthetic 46 effects. Minority and low income populations could experience disproportionate human health 4-96

Environmental Consequences and Mitigating Actions 1 and environmental effects from the emissions from fossil-fueled power plants (e.g., increased 2 asthma). However, any human health or environmental effects would depend on the location of 3 the new power plant in relation to minority and low-income communities and the magnitude of 4 the change in ambient air quality conditions. Also, permitted air emissions would be expected to 5 remain within regulatory standards. 6 Based on this information and the analysis of human health and environmental impacts 7 presented in this SEIS, it is not likely that purchasing electrical power from existing power 8 generating facilities would have disproportionately high and adverse human health and 9 environmental effects on minority and low-income populations. In addition, this determination 10 would depend on whether a new electrical power generating facility were needed to supply 11 purchased power. If a new power generating facility is needed, impacts to minority and 12 low-income populations would depend on the location, plant design, and operational 13 characteristics of these new power generating facilities. Therefore, the NRC staff cannot 14 determine whether this alternative would result in disproportionately high and adverse human 15 health and environmental effects on minority and low-income populations. 16 4.13 Waste Management 17 This section describes the potential impacts of the proposed action (license renewal) and 18 alternatives to the proposed action on waste management and pollution prevention. 19 4.13.1 Proposed Action 20 Section 3.12 describes LSCS waste management and pollution prevention. Table 4-18 21 identifies the waste management issues applicable to LSCS during the license renewal term. 22 Table 4-18. Waste Management Issues Issue GEIS Section Category Low-level waste storage and disposal 4.11.1.1 1 Onsite storage of spent nuclear fuel 4.11.1.2(a) 1 Offsite radiological impacts of spent nuclear fuel and high-level waste 4.11.1.3(b) 1 disposal Mixed-waste storage and disposal 4.11.1.4 1 Nonradioactive waste storage 4.11.1.4 1 (a) The environmental impact of this issue for the time frame beyond the licensed life for reactor operations is contained in NUREG-2157 (NRC 2014). (b) The environmental impact of this issue is contained in NUREG-2157 (NRC 2014). Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 23 The NRC staffs evaluation of the environmental impacts associated with spent nuclear fuel is 24 addressed in two issues in Table 4-18, Onsite storage of spent nuclear fuel and Offsite 25 radiological impacts of spent nuclear fuel and high-level waste disposal. The issue of onsite 26 storage of spent nuclear fuel now incorporates the generic environmental impact determinations 27 codified in Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 and in the revised 28 10 CFR 51.23, pursuant to the Continued Storage Rule (79 FR 56238)4. The issue of offsite 4 79 FR 56238. U.S. Nuclear Regulatory Commission. Continued Storage of Spent Nuclear Fuel. Federal Register 79 (182): 56238-56263. September 19, 2014. 4-97

Environmental Consequences and Mitigating Actions 1 radiological impacts of spent nuclear fuel and high-level waste disposal are codified in 2 Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51, and the technical feasibility of disposal 3 in a geologic repository is discussed in NUREG-2157, Generic Environmental Impact 4 Statement for Continued Storage of Spent Nuclear Fuel, Volumes 1 and 2 (NRC 2014). 5 The NRC staff did not identify any new and significant information related to waste management 6 issues listed in Table 4-18 during its review of the applicants ER (Exelon 2014a), the site visit, 7 or the scoping process. Therefore, there are no impacts related to these issues beyond those 8 discussed in the GEIS (NRC 2013d) and NUREG-2157 (NRC 2014). During the license 9 renewal term, for these Category 1 issues discussed in the GEIS, the NRC staff concludes that 10 the impacts are SMALL. 11 4.13.2 No-Action Alternative 12 If the no-action alternative were implemented, LSCS would cease operation at the end of the 13 term of the initial operating licenses, or sooner, and enter decommissioning. The plants, which 14 are currently operating within regulatory limits, would generate less spent nuclear fuel and emit 15 less gaseous and liquid radioactive effluents into the environment. In addition, following 16 shutdown, the variety of potential accidents at the plants (radiological and industrial) would be 17 reduced to a limited set associated with shutdown events and fuel handling and storage. In 18 Section 4.14.2 of this SEIS, the NRC staff concludes that the impacts from decommissioning 19 would be SMALL. Therefore, as radioactive emissions to the environment decrease, and the 20 likelihood and variety of accidents decrease following shutdown and decommissioning, the NRC 21 staff concludes that impacts from implementation of the no-action alternative would be SMALL. 22 4.13.3 New Nuclear Alternative 23 Construction-related debris would be generated during construction activities and would be 24 recycled or disposed of in approved landfills. 25 During normal plant operations, routine plant maintenance, and cleaning activities would 26 generate radioactive low-level waste, spent nuclear fuel, and high-level waste, as well as 27 nonradioactive waste. Sections 3.1.4 and 3.1.5 discuss radioactive and nonradioactive waste 28 management at LSCS. Quantities of radioactive and nonradioactive waste generated by LSCS 29 would be comparable to that generated by the two new nuclear plants. 30 According to the GEIS (NRC 2013d), the generation and management of solid radioactive and 31 nonradioactive waste during the license renewal term are not expected to result in significant 32 environmental impacts. 33 Based on this information, the waste impacts would be SMALL for the new nuclear alternative. 34 4.13.4 IGCC Alternative 35 Construction-related debris would be generated during plant construction activities and would 36 be recycled or disposed of in approved landfills. 37 Coal combustion generates waste in the form of fly ash and bottom ash. In addition, equipment 38 for controlling air pollution generates additional ash, spent selective catalytic reduction (SCR) 39 catalyst, and scrubber sludge. The management and disposal of the large amounts of coal 40 combustion waste is a significant part of the operation of a coal-fired power generating facility. 41 Although an IGCC facility is likely to use offsite disposal of coal combustion waste, some 42 short-term storage of coal combustion waste (either in open piles or in surface impoundments) 4-98

Environmental Consequences and Mitigating Actions 1 is likely to take place on site, thus establishing the potential for leaching of toxic chemicals into 2 the local environment. 3 The impacts of managing the substantial amounts of solid waste, especially fly ash and 4 scrubber sludge, generated during operation of this alternative would be MODERATE 5 (NRC 1996). The amount of the construction waste would be small compared to the amount of 6 waste generated during the operational stage and much of it could be recycled (i.e., marketed 7 for beneficial use). Therefore, the NRC staff concludes that the overall waste management 8 impacts from construction of this alternative would be SMALL and from operation of this 9 alternative would be MODERATE. 10 4.13.5 NGCC Alternative 11 Construction-related debris would be generated during plant construction activities, and would 12 be recycled or disposed of in approved landfills. 13 Waste generation from NGCC technology would be minimal. The only significant waste 14 generated at an NGCC power plant would be spent SCR catalyst, which is used to control 15 nitrogen oxide emissions. 16 The spent catalyst would be regenerated or disposed of offsite. Other than the spent SCR 17 catalyst, waste generation at an operating natural-gas-fired plant would be limited largely to 18 typical operations and maintenance of nonhazardous waste. Overall, the NRC staff concludes 19 that waste impacts from the NGCC alternative would be SMALL. 20 4.13.6 Combination Alternative (NGCC, Wind, Solar) 21 Construction-related debris would be generated during construction activities and would be 22 recycled or disposed of in approved landfills. 23 Waste generation from NGCC technology is discussed in Section 4.13.5. 24 Waste generation from a combination of wind and solar PV alternatives would be minimal, 25 consisting of debris from routine maintenance and the disposal of worn or broken parts. Based 26 on this information, the NRC staff concludes that waste impacts from the construction and 27 operation of a combination wind and solar PV alternative would be SMALL. 28 4.13.7 Purchased Power Alternative 29 The types of waste generated by the alternative electricity generation sources (i.e., coal, natural 30 gas, nuclear, and wind) used in the purchased power alternative are discussed in 31 Sections 4.13.3, 4.13.4, 4.13.5, and 4.13.6. Depending on types of power generation plants 32 used to provide the electricity for the purchased power alternative, the NRC staff concludes that 33 the waste management impacts would range from SMALL to MODERATE. 34 4.14 Evaluation of New and Potentially Significant Information 35 New and significant information must be new based on a review of the GEIS (NRC 2013d) and 36 codified in Table B-1 of Appendix B to Subpart A of 10 CFR Part 51, and must bear on the 37 proposed action or its impacts, presenting a seriously different picture of the impacts from those 38 envisioned in the GEIS (i.e., impacts of greater severity than impacts considered in the GEIS, 39 considering their intensity and context). 40 In accordance with 10 CFR 51.53(c), the ER that the applicant submits must provide an analysis 41 of the Category 2 issues in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B. Additionally, 4-99

Environmental Consequences and Mitigating Actions 1 it must discuss actions to mitigate any adverse impacts associated with the proposed action and 2 environmental impacts of alternatives to the proposed action. In accordance with 3 10 CFR 51.53(c)(3), the ER does not need to contain an analysis of any Category 1 issue 4 unless there is new and significant information on a specific issue. 5 The NRC process for identifying new and significant information is described in NUREG-1555, 6 Supplement 1, Standard Review Plans for Environmental Reviews for Nuclear Power Plants, 7 Supplement 1: Operating License Renewal (NRC 2013f). The search for new information 8 includes: 9

  • review of an applicants ER and the process for discovering and evaluating the 10 significance of new information; 11
  • review of public comments; 12
  • review of environmental quality standards and regulations; 13
  • coordination with Federal, state, and local environmental protection and resource 14 agencies; and 15
  • review of technical literature.

16 New information that the staff discovers is evaluated for significance using the criteria set forth 17 in the GEIS. For Category 1 issues in which new and significant information is identified, 18 reconsideration of the conclusions for those issues is limited in scope to assessment of the 19 relevant new and significant information; the scope of the assessment does not include other 20 facets of an issue that the new information does not affect. 21 The NRC staff reviewed the discussion of environmental impacts associated with operation 22 during the renewal term in the GElS and has conducted its own independent review, including a 23 public involvement process (e.g., public meetings) to identify new and significant issues for the 24 LSCS license renewal application environmental review. The NRC staff has not identified new 25 and significant information on environmental issues related to operation of LSCS during the 26 renewal term. The NRC staff also determined that information provided during the public 27 comment period did not identify any new issue that requires site-specific assessment. 28 The NRC staff did, however, find new, but not significant, information regarding the uranium fuel 29 cycle issue, and this information is discussed in Section 4.15.1 and Appendix G of this SEIS. 30 4.15 Impacts Common to All Alternatives 31 This section describes the impacts that are considered common to all alternatives discussed in 32 this SEIS, including the proposed action and replacement power alternatives. The continued 33 operation of a nuclear power plant and replacement fossil fuel power plants both involve the 34 mining, processing, and consumption of fuel, which results in comparative impacts 35 (NRC 2013d). In addition, the termination of operations and the decommissioning of both a 36 nuclear power plant and replacement fossil-fueled power plants, as well as GHG emissions, are 37 discussed in the following sections. 38 4.15.1 Fuel Cycles 39 This section describes the environmental impacts associated with the fuel cycles of the 40 proposed action and replacement power alternatives. Most replacement power alternatives 41 employ a set of steps in the utilization of their fuel sources, which can include extraction, 4-100

Environmental Consequences and Mitigating Actions 1 transformation, transportation, and combustion. Emissions generally occur at each stage of the 2 fuel cycle (NRC 2013d). 3 4.15.1.1 Uranium Fuel Cycle 4 The uranium fuel cycle issues applicable to LSCS are discussed below and listed in Table 4-19 5 for Category 1 issues. Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 contains more 6 information on these issues. 7 Table 4-19. Issues Related to the Uranium Fuel Cycle Issue GEIS Section Category Offsite radiological impactsindividual impacts from other than the 4.12.1.1 1 disposal of spent fuel and high-level waste Offsite radiological impactscollective impacts from other than the 4.12.1.1 1 disposal of spent fuel and high-level waste Nonradiological impacts of the uranium fuel cycle 4.12.1.1 1 Transportation 4.12.1.1 1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 8 The uranium fuel cycle includes uranium mining and milling, production of uranium hexafluoride, 9 isotopic enrichment, fuel fabrication, reprocessing of irradiated fuel, transportation of radioactive 10 materials, and management of low-level wastes and high-level wastes related to uranium fuel 11 cycle activities. The generic potential impacts of the radiological and nonradiological 12 environmental impacts of the uranium fuel cycle and transportation of nuclear fuel and wastes 13 are described in detail in NUREG-1437 (NRC 2013d). 14 The NRC staff did not identify any new and significant information related to the uranium fuel 15 cycle issues Offsite radiological impactsindividual impacts from other than the disposal of 16 spent fuel and high level waste, Offsite radiological impactscollective impacts from other 17 than the disposal of spent fuel and high-level waste, and Nonradiological impacts of the 18 uranium fuel cycle, listed above in Table 4-19, during its review of the applicants ER 19 (Exelon 2014a), the site visit, and the scoping process. Therefore, there are no impacts related 20 to these issues beyond those discussed in the GEIS. For these Category 1 issues, the GEIS 21 concludes that the impacts are SMALL, except for the issue, Offsite radiological impacts 22 collective impacts, to which the NRC has not assigned an impact level. This issue assesses 23 the 100-year radiation dose to the U.S. population (i.e., collective effects or collective dose) from 24 radioactive effluent released as part of the uranium fuel cycle for a nuclear power plant during 25 the license renewal term compared to the radiation dose from natural background exposure. It 26 is a comparative assessment for which there is no regulatory standard to base an impact level. 27 The NRC staff did, however, find new information regarding the uranium fuel cycle issue 28 Transportation, listed above in Table 4-19, in its review of the applicants ER. The NRC has 29 generically determined, in its license renewal application reviews, that the environmental 30 impacts of the transportation of fuel and radioactive wastes to and from nuclear power facilities 31 are small for all reactors as long as certain specific conditions are met. The application for 32 license renewal of LSCS stated that the specific conditions that allow the transportation impacts 33 of spent fuel to be generically determined to be small may not be met for LSCS. Therefore, the 34 NRC staff analyzed the environmental impacts of transporting spent fuel from LSCS in 35 Appendix G of this SEIS. From this analysis, the NRC staff concludes that the environmental 36 impacts of the transportation of spent fuel from LSCS would be consistent with the 4-101

Environmental Consequences and Mitigating Actions 1 environmental impacts associated with the transportation of fuel and radioactive wastes to and 2 from current-generation reactors presented in Table S-4 of 10 CFR 51.52, and thus would be 3 SMALL. 4 4.15.1.2 Replacement Power Plant Fuel Cycles 5 Fossil Fuel Energy Alternatives 6 Fuel cycle impacts for a fossil-fuel-fired plant result from the initial extraction of fuel, cleaning 7 and processing of fuel, transport of fuel to the facility, and management and ultimate disposal of 8 solid wastes from fuel combustion. These impacts are discussed in more detail in 9 Section 4.12.1.2 of the GEIS (NRC 2013d) and can generally include: 10

  • significant changes to land use and visual resources; 11
  • impacts to air quality, including release of criteria pollutants, fugitive dust, VOCs, and 12 coalbed methane in the atmosphere; 13
  • noise impacts; 14
  • geology and soil impacts due to land disturbances and mining; 15
  • water resource impacts, including degradation of surface water and groundwater 16 quality; 17
  • ecological impacts, including loss of habitat and wildlife disturbances; 18
  • historic and cultural resources impacts within the mine footprint; 19
  • socioeconomic impacts from employment of both the mining workforce and service 20 and support industries; 21
  • environmental justice impacts; 22
  • health impacts to workers from exposure to airborne dust and methane gases; and 23
  • generation of coal and industrial wastes.

24 New Nuclear Energy Alternatives 25 Uranium fuel cycle impacts for a nuclear plant result from the initial extraction of fuel, transport 26 of fuel to the facility, and management and ultimate disposal of spent fuel. The environmental 27 impacts of the uranium fuel cycle are discussed above in Section 4.15.1.1. 28 Renewable Energy Alternatives 29 The fuel cycle for renewable energy facilities is difficult to define for technologies such as wind 30 and solar because these natural resources exist regardless of any effort to harvest them for 31 electricity production. Impacts from the presence or absence of these renewable energy 32 technologies are often difficult to determine (NRC 2013d). 33 4.15.2 Terminating Power Plant Operations and Decommissioning 34 This section describes the environmental impacts associated with the termination of operations 35 and the decommissioning of a nuclear power plant and replacement power alternatives. All 36 operating power plants will terminate operations and be decommissioned at some point after the 37 end of their operating life or after a decision is made to cease operations. For the proposed 38 action, license renewal would delay this eventuality for an additional 20 years beyond the 39 current license period, which ends in 2022 and 2023 for LSCS Units 1 and 2, respectively. 4-102

Environmental Consequences and Mitigating Actions 1 4.15.2.1 Existing Nuclear Power Plant 2 Environmental impacts from the activities associated with the decommissioning of any reactor 3 before or at the end of an initial or renewed license are evaluated in Supplement 1 of 4 NUREG-0586 (NRC 2002). Additionally, the incremental environmental impacts associated 5 with decommissioning activities resulting from continued plant operation during the renewal term 6 are discussed in the GEIS. 7 Table 4-20 lists the Category 1 issues in Table B-1 of Title 10 of the CFR Part 51, Subpart A, 8 Appendix B, that are applicable to LSCS decommissioning following the license renewal term. 9 Table 4-20. Issues Related to Decommissioning Issue GEIS Section Category Radiation doses 4.12.2.1 1 Waste management 4.12.2.1 1 Air quality 4.12.2.1 1 Water quality 4.12.2.1 1 Ecological resources 4.12.2.1 1 Socioeconomic impacts 4.12.2.1 1 Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 10 Decommissioning would occur whether LSCS were shut down at the end of its current operating 11 license or at the end of the period of the license renewal term. Exelon stated in its ER 12 (Exelon 2014a) that it is not aware of any new and significant information on the environmental 13 impacts of LSCS during the license renewal term. The NRC staff has not found any new and 14 significant information during its independent review of Exelons ER, the site visit, or the scoping 15 process. Therefore, the NRC staff concludes that there are no impacts related to 16 decommissioning, beyond those discussed in the GEIS. For all of these issues, the NRC staff 17 concluded, in the GEIS, that the impacts are SMALL. 18 4.15.2.2 Replacement Power Plants 19 Fossil Fuel Energy Alternatives 20 The environmental impacts from the termination of power plant operations and 21 decommissioning of a fossil-fuel-fired plant are dependent on the facilitys decommissioning 22 plan. General elements and requirements for a fossil fuel plant decommissioning plan are 23 discussed in Section 4.12.2 of the GEIS and can include the removal of structures to at least 24 3 ft (1 m) below grade; removal of all coal, combustion waste, and accumulated sludge; removal 25 of intake and discharge structures; and the cleanup and remediation of incidental spills and 26 leaks at the facility. The decommissioning plan outlines the actions necessary to restore the 27 site to a condition equivalent in character and value to the greenfield or brownfield site on which 28 the facility was first constructed (NRC 2013d). 29 The environmental consequences of decommissioning are discussed in Section 4.12.2 of the 30 GEIS and can generally include: 31

  • short-term impacts on air quality and noise from the deconstruction of facility 32 structures, 33
  • short-term impacts on land use and visual resources, 4-103

Environmental Consequences and Mitigating Actions 1

  • long-term reestablishment of vegetation and wildlife communities, 2
  • socioeconomic impacts due to the decommissioning workforce and the long-term 3 loss of jobs, and 4
  • elimination of health and safety impacts on operating personnel and the general 5 public.

6 New Nuclear Alternative 7 Termination of operations and decommissioning impacts for a nuclear plant include all activities 8 related to the safe removal of the facility from service and the reduction of residual radioactivity 9 to a level that permits release of the property under restricted conditions or unrestricted use and 10 termination of a license (NRC 2013d). The environmental impacts of the uranium fuel cycle are 11 discussed above in Section 4.15.1.1. 12 Renewable Alternative 13 Termination of power plant operation and decommissioning for renewable energy facilities 14 would be similar to the impacts discussed for fossil-fuel-fired plants above. Decommissioning 15 would involve the removal of facility components and operational wastes and residues in order 16 to restore the site to a condition equivalent in character and value to the greenfield or brownfield 17 site on which the facility was first constructed (NRC 2013d). 18 4.15.3 Greenhouse Gas Emissions and Climate Change 19 The following sections discuss GHG emissions released from operation of LSCS and the 20 environmental impacts that could occur from changes in climate conditions. The cumulative 21 impacts of GHG emissions on climate are discussed in Section 4.16.11, Global Climate 22 Change. 23 4.15.3.1 Greenhouse Gas Emissions from the Proposed Project and Alternatives 24 Gases found in the Earths atmosphere that trap heat and play a role in the Earths climate are 25 collectively termed GHG. GHGs include carbon dioxide (CO2); methane (CH4); nitrous 26 oxide (N2O); water vapor (H2O); and fluorinated gases, such as hydrofluorocarbons (HFCs), 27 perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The Earths climate responds to 28 changes in concentrations of GHGs in the atmosphere because GHGs affect the amount of 29 energy absorbed and heat trapped by the atmosphere. Increasing GHG concentrations in the 30 atmosphere generally increases Earths surface temperature. Atmospheric concentrations of 31 carbon dioxide, methane, and nitrous oxide have significantly increased since 1750 32 (IPCC 2007c, 2013). Carbon dioxide, methane, nitrous oxide, water vapor, and fluorinated 33 gases (termed long-lived GHGs) are well mixed throughout the Earths atmosphere, and their 34 impact on climate is long lasting as a result of their long atmospheric lifetime (EPA 2009a). 35 Carbon dioxide is of primary concern for global climate change, due to its long atmospheric 36 lifetime, and it is the primary gas emitted as a result of human activities. Climate change 37 research indicates that the cause of the Earths warming over the last 50 years is due to the 38 buildup of GHGs in the atmosphere resulting from human activities (USGCRP 2014; 39 IPCC 2013). The EPA has determined that GHGs may reasonably be anticipated both to 40 endanger public health and to endanger public welfare (74 FR 66496). 41 Proposed Action 42 Operation of LSCS does not directly emit GHG emissions because fossil fuel is not used to 43 generate electricity. However, plant operations at LSCS release GHG emissions from 44 stationary combustion sources, such as diesel generators on site. Other GHG emission 4-104

Environmental Consequences and Mitigating Actions 1 sources from LSCS plant operations include refrigerant appliances that contain fluorinated 2 gases, mobile combustion sources (e.g., employee vehicles and nonroad equipment), LSCSs 3 carbon dioxide injection system and fire protection system, use of sulfur hexafluoride to locate 4 leaks in condensers, and indirect purchased electricity emissions (Exelon 2015d). Annual GHG 5 emissions at LSCS are presented in Table 4-21 for the 2010 to 2014 timeframe. Employee 6 vehicle GHG emissions are not provided in Table 4-21 because Exelon does not compile or 7 report GHG data for mobile sources. The NRC staff estimates annual GHG emissions resulting 8 from employee vehicles to be approximately 9,400 metric tons (MT) per year of carbon dioxide 9 equivalent emissions. 10 Table 4-21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)(a) Stationary Combustion Fugitive Purchased Refrigerant-Related Year Sources(a) Emissions(b) Electricity(c) Sources(d) Total 2010 1,022 1,355 34,260 1,104 37,741 2011 322 2,980 36,066 629 39,997 2012 350 1,792 36,066 360 38,568 2013 245 2,508 30,520 955 34,228 2014 605 4,566 32,978 474 38,623 (a) Stationary combustion sources include emissions from large (greater than 600 horsepower) and small (less than 600 horsepower) diesel engines. These emissions were calculated based on fuel-use data and EPA AP-42 emission factors. (b) Fugitive emissions account for LSCSs (1) CO injection system used to adjust pH in the cooling pond, (2) the CO 2 2 fire protection system, and (3) SF6 used to locate leaks in the condensers. These emissions assume that all purchased CO2 and SF6 were released. (c) Purchased electricity emissions were calculated based on monthly billings from the offsite electricity supplier for LSCS. (d) Refrigerant-related sources include emissions from direct HFC/PFC refrigerants and ozone-depleting refrigerants. The emissions assume all purchased refrigerants were released. Key: MT/yr of CO2e = metric ton(s) per year of carbon dioxide equivalent (emissions). Source: Exelon 2015d 11 No-Action Alternative 12 As discussed in previous no-action alternative sections, the no-action alternative represents a 13 decision by the NRC not to renew the operating license of a nuclear power plant beyond the 14 current operating license term. At some point, all nuclear plants will terminate operations and 15 undergo decommissioning. Under the no-action alternative, plant operations for LSCS would 16 terminate at or before the end of the current license. When the plant stops operating, a 17 reduction in GHG emissions from activities related to plant operation, such as use of diesel 18 generators and employee vehicles, will occur. The GHG emissions are anticipated to be less 19 than those presented in Table 4-21. 20 New Nuclear Alternative 21 As discussed in Section 2.2.2.1, the NRC staff evaluated the new nuclear power plant 22 alternative that would consist of two units with an approximate generating capacity of 23 1,120 megawatt electric (MWe) each. The GEIS (NRC 2013d) presents life-cycle GHG 24 emissions associated with nuclear power generation. As presented in Tables 4.12-4 4-105

Environmental Consequences and Mitigating Actions 1 through 4.12-6 of the GEIS, life-cycle5 GHG emissions from nuclear power generation can 2 range from 1 to 288 grams of carbon equivalent per kilowatt hour (g Ce/kWh). Operation of 3 nuclear power plants does not burn fossil fuels to generate electricity and, therefore, does not 4 directly emit GHG emissions. Sources of GHG emissions include stationary combustion 5 sources (e.g., emergency diesel generators and diesel-driven pumps) and mobile sources 6 (e.g., worker vehicles, onsite heavy equipment, support vehicles, delivery of materials, and 7 disposal of wastes). It is anticipated that air emissions from a new nuclear power plant would 8 be similar to those from LSCS. 9 IGCC Generation Alternative 10 As discussed in Section 2.2.2.2, the NRC staff evaluated the IGCC plant alternative that would 11 consist of four 618-MWe units for a total 2,472 MW. The GEIS presents life-cycle GHG 12 emissions associated with coal power generation. As presented in Table 4.12-4 of the GEIS, 13 life-cycle GHG emissions from coal power generation can range from 264 to 1,689 g Ceq/kWh. 14 However, these life-cycle emission factors are for conventional coal power plants; recent studies 15 estimate life-cycle GHG emissions for an IGCC plant to be 937 kilograms of carbon dioxide 16 equivalent per megawatt-hour (kg CO2e/MWh) (NETL 2012). The NRC staff estimates that 17 operation of the IGCC alternative directly will emit about 14.3 million tons per year 18 (13.0 million MT per year) of carbon dioxide equivalent emissions. 19 NGCC Generation Alternative 20 As discussed in Section 2.2.2.3, the NRC staff evaluated an NGCC alternative that consists of 21 five NGCC 560-MWe units (total 2,800 MWe). The GEIS presents life-cycle GHG emissions 22 associated with natural gas power generation. As presented in Table 4.12-5 of the GEIS, 23 life-cycle GHG emissions from natural gas can range from 120 to 930 g Ceq/kWh. The NRC 24 staff estimates that operation of the NGCC alternative directly will emit about 9.8 million tons 25 (8.2 million MT) per year of carbon dioxide equivalent emissions. 26 Combination Alternative (NGCC, Wind, and Solar) 27 As discussed in Section 2.2.2.4, the NRC staff evaluated an alternative that relies on NGCC 28 (15 percent), wind (75 percent), and solar (10 percent) capacity to replace LSCS. The 29 combination alternative would consist of a 360-MWe NGCC unit, a 227-MWe solar PV facility, 30 and a 1,813-MWe windfarm. For this combination alternative, it is assumed that the majority of 31 the GHG emissions result from the NGCC portion only because renewable portions (wind and 32 solar PV) do not burn fossil fuels to generate electricity. As discussed in Section 4.3.5., GHG 33 emissions associated with the operation of the NGCC portion are reduced proportionally 34 because its electricity output is approximately 13 percent that of the NGCC alternative. The 35 NRC staff estimates that operation of the combination alternative will directly result in about 36 1.2 million tons (1.1 million MT) per year of carbon dioxide equivalent emissions. 37 Purchased Power Alternative 38 Purchased power would come from common types of existing technology (coal, natural gas, 39 nuclear, and renewable sources) within the ROI. GHG emissions from purchased power will 40 vary and will depend on the type and combination of technology from which purchased power 41 originates. In 2014, coal, natural gas, and nuclear power accounted for 39-, 27-, and 19-percent 42 shares, respectively, of total U.S. electricity generation (EIA 2015b). Using these percentage 43 shares for the purchased power alternative, the NRC staff estimates 8.0 million ton 44 (7.3 million MT) per year of carbon dioxide equivalent emissions. However, GHG emissions 5 Life-cycle carbon emissions analyses consider construction, operation, decommissioning, and associated processing of fuel (e.g., gas and coal). 4-106

Environmental Consequences and Mitigating Actions 1 may be greater or less than this estimate and will depend on the technology from which the 2 purchased power originates. 3 Summary of GHG Emissions from the Proposed Action and Alternatives 4 Table 4-22 presents the direct GHG emissions from operation of the proposed action and 5 alternatives. GHG emissions from the proposed action (continued operation at LSCS) and the 6 new nuclear alternative would be the lowest. GHG emissions for IGCC, NGCC, combination, 7 and purchased power alternatives are higher than those for the proposed action and a new 8 nuclear alternative by several orders of magnitude. GHG emissions from the purchased power 9 alternative are expected to be greater than those from the NGCC alternative but less than those 10 from the IGCC alternative. 11 Table 4-22. Direct(a) GHG Emissions from Operation 12 of the Proposed Action and Alternatives Technology CO2e (MT/yr) LSCS continued operation 1,022 New Nuclear 1,022 IGCC 13.0x106 NGCC 8.2x106 Combination(b) 1.1x106 Purchased Power(c) 7.3x106 (a) The GHG emissions presented include only direct emissions from operation of the electricity-generating technology. For the NGCC and IGCC alternatives, GHG emissions result from direct combustion of the gas and coal. For the proposed action and new nuclear alternatives, direct GHG emissions are a result of stationary combustion sources. (b) This technology is only the NGCC portion of GHG emissions. (c) Air emissions were estimated by assuming that purchased-power coal accounted for a 39-percent share, natural gas accounted for a 27-percent share, nuclear accounted for a 19-percent share, and renewable accounted for a 15-percent share of electricity generation. 13 4.15.3.2 Climate Change Impacts to Resource Areas 14 Climate change is the decades or longer change in climate measurements (e.g., temperature 15 and precipitation) that has been observed on a global, national, and regional level (IPCC 2007c; 16 EPA 2014; USGCRP 2014). Climate change can vary regionally, spatially, and seasonally, 17 depending on local, regional, and global factors. Just as regional climate differs throughout the 18 world, the impacts of climate change can vary between locations. 19 On a global level, from 1901 to 2013, average surface temperatures rose at a rate of 0.15 F 20 (0.08 C) per decade, and total annual precipitation increased at an average rate of 0.2 percent 21 per decade (EPA 2014). The observed global change in average surface temperature and 22 precipitation has been accompanied by an increase in sea surface temperatures, a decrease in 23 global glacier ice, an increase in sea level, and changes in extreme weather events. Such 24 extreme events include an increase in the frequency of heat waves, heavy precipitation, and 25 recorded maximum daily high temperatures (IPCC 2007c; USGCRP 2009, 2014; EPA 2014). 26 In the United States, the U.S. Global Change Research Program (USGCRP) reports that, from 27 1895 to 2012, average surface temperature increased by 1.3 °F to 1.9 °F (0.72 to 1.06 °C) and, 28 since 1900, average annual precipitation has increased by 5 percent. On a seasonal basis, 4-107

Environmental Consequences and Mitigating Actions 1 warming has been the greatest in winter and spring. Since the 1980s, an increase in the length 2 of the frost-free season, the period between the last occurrence of 32 F (0 °C) in the spring and 3 first occurrence of 32 F (0 °C) in the fall, has been observed for the contiguous United States; 4 between 1991 and 2011, the average frost-free season was 10 days longer than between 1901 5 and 1960 (USGCRP 2014). Since the 1970s, the United States has warmed at a faster rate as 6 the average surface temperature rose at an average rate of 0.31 to 0.45 F (0.17 to 0.25 °C) per 7 decade (EPA 2014). The year 2014 was the warmest on record (AMS 2015). Observed 8 climate-related changes in the United States include increases in the frequency and intensity of 9 heavy precipitation, earlier onset of spring snowmelt and runoff, rise of sea level in coastal 10 areas, increase in occurrence of heat waves, and a decrease in occurrence of cold waves 11 (USGCRP 2014). 12 Temperature data indicate that the Midwest region, where LSCS is located, experienced a 13 0.06 C (0.11 F) per decade increase in annual mean temperature during the 1900 to 14 2010 period (NOAA 2013). Temperature data for the recent past indicate an increased rate of 15 warming for the Midwest region of 0.12 °C (0.22 °F) per decade for the 1950-to-2010 time 16 period and a 0.26 C (0.47 F) temperature increase for the 1979-to-2010 time period. Average 17 annual precipitation data for the Midwest region exhibit an increasing trend of 0.31 in. (0.79 cm) 18 per decade for the long-term period (1895 to 2011) (NOAA 2013). The NRC staff analyzed 19 temperature and precipitation trends for the period of 1865 to 2014 in the northeast region 20 (Climate Division No. 2) of Illinois (NCDC 2015). Average annual temperatures during this time 21 period show large year-to-year variations; however, since 1865, temperatures have increased 22 0.1 °F (0.05 °C) per decade. Average annual precipitation also displays year-to-year variations, 23 although precipitation has increased at a rate of 0.48 in. (1.2 cm) per decade. 24 Future GHG emission concentrations (emission scenarios) and climate models are commonly 25 used to project possible climate change. Climate models indicate that over the next few 26 decades, temperature increases will continue due to current GHG emission concentrations in 27 the atmosphere (USGCRP 2014). Over the longer term, the magnitude of temperature 28 increases and climate change effects will depend on both past and future GHG emissions 29 (IPCC 2007c; USGCRP 2009, 2014). 30 For the license renewal period of LSCS, Units 1 and Unit 2 (2022 to 2042 and 2023 to 2043, 31 respectively), climate model simulations (between 2021 and 2050 relative to the reference 32 period (1971 to 1999)) indicate an increase in annual mean temperature in the Midwest region 33 of 2.5 to 3.5 F (4.5 to 6.3 °C) for both a low- and high-emission-modeled scenario 34 (NOAA 2013). The predicted increase in temperature during this time period occurs for all 35 seasons, with the largest increase occurring in the summertime (June, July, and August). 36 Climate model simulations (for the time period 2021 to 2050) suggest spatial differences in 37 annual mean precipitation changes for the Midwest, with northern areas experiencing an 38 increase in precipitation and with the southern areas experiencing a decrease in precipitation. 39 For Illinois, the models indicate a 0- to 3-percent increase in annual mean precipitation, with fall, 40 winter, and spring seasons experiencing precipitation change increases and with the summer 41 season experiencing a decrease in precipitation. However, these changes in precipitation were 42 only statistically significant under a high-emission-modeled scenario (NOAA 2013). 43 The implications of climate change on LSCS operations are outside the scope of the NRCs 44 license renewal environmental review, which documents the potential environmental impacts 45 from continued reactor operations. Site-specific environmental conditions are considered when 46 siting nuclear power plants, including consideration of meteorological and hydrologic siting 47 criteria in 10 CFR Part 100. LSCS was designed and constructed in accordance with the 48 General Design Criteria of Appendix A to 10 CFR Part 50. NRC regulations require that plant 49 structures, systems, and components important to safety be designed to withstand the effects of 4-108

Environmental Consequences and Mitigating Actions 1 natural phenomena, such as flooding, without loss of capability to perform safety functions. 2 Furthermore, nuclear power plants are required to operate within technical safety specifications 3 in accordance with the NRC operating license, including coping with natural phenomena 4 hazards. The NRC conducts safety reviews before allowing licensees to make operational 5 changes due to changing environmental conditions. Additionally, the NRC evaluates nuclear 6 power plant operating conditions and physical infrastructure to ensure ongoing safe operations 7 through its Reactor Oversight Process. If new information about changing environmental 8 conditions becomes available, the NRC will evaluate the new information to determine whether 9 any safety-related changes are needed at existing nuclear power plants. This process is 10 separate and distinct from the NRCs license renewal environmental review that is conducted in 11 accordance with NEPA (42 U.S.C. 4321 et seq.). 12 Changes in climate have broader implications for public health, water resources, land use and 13 development, and ecosystems. For instance, changes in precipitation patterns and an increase 14 in air temperature can affect water availability and quality, distribution of plant and animal 15 species, land-use patterns, and land cover; these impacts can, in turn, affect terrestrial and 16 aquatic habitats. The sections below discuss how future climate change may impact air quality, 17 land use, water resources, aquatic resources, terrestrial resources, human health, and minority 18 and low-income populations in the ROI for LSCS. Although the future effects of climate change 19 are uncertain, the following discussions describe the potential implications of climate change in 20 affected environmental resource areas. 21 Air Quality 22 As discussed above, an increase in average temperatures in Illinois has been observed. 23 Despite the strong year-to-year variations, climate models project continued warming in the 24 Midwest region during the license renewal period. Air pollutant concentrations result from 25 complex interactions between physical and dynamic properties of the atmosphere, land, and 26 ocean. The formation, transport, dispersion, and deposition of air pollutants depend, in part, on 27 weather conditions (IPCC 2007a). Air pollutant concentrations are sensitive to winds, 28 temperature, humidity, and precipitation (EPA 2009a). Hence, climate change can impact air 29 quality as a result of the changes in meteorological conditions. 30 Ozone has been found to be particularly sensitive to climate change (IPCC 2007a; EPA 2009b). 31 Ozone is formed, in part, as a result of the chemical reaction of nitrogen oxides and VOCs in the 32 presence of heat and sunlight. Nitrogen oxides and VOC sources include both natural 33 emissions (e.g., biogenic emissions from vegetation or soils) and human-activity-related 34 emissions (e.g., motor vehicles and power plants). Sunshine, high temperatures, and air 35 stagnation are favorable meteorological conditions to produce higher levels of ozone 36 (IPCC 2007a; EPA 2009a). The emission of ozone precursors also depends on temperature, 37 wind, and solar radiation (IPCC 2007a); both nitrogen oxide and biogenic VOC emissions are 38 expected to be higher in a warmer climate (EPA 2009b). Although surface temperatures are 39 expected to increase in the Midwest, this may not necessarily result in an increase in ozone 40 concentrations. The observed correlation between increased ozone concentrations and 41 temperature has been found to occur in polluted and urban regions (i.e., those areas where 42 ozone concentration are greater than 60 parts per billion). Additionally, increases in ozone 43 concentrations correlated with temperature increases occur in combination with cloud-free 44 regions and air stagnation episodes (Jacob and Winner 2009; IPCC 2013). Furthermore, 45 climate models do not agree on the sign of ozone response to climate change. Some models 46 indicate increases in ozone concentrations with climate change for the Midwest and Northeast 47 (e.g., Wu et al. 2008), and others project decreases in ozone concentrations with climates for 48 the northern regions of the United States (e.g., Tagaris et al. 2009). 4-109

Environmental Consequences and Mitigating Actions 1 Land Use 2 Anthropogenic land use is both a contributor to climate change and a receptor of climate change 3 impacts (Dale 1997). As described previously in this section, the Midwest will likely experience 4 rising temperatures and heavier precipitation events during the proposed license renewal 5 period. Agriculture (the major land use in the vicinity of LSCS) and growing urban areas will 6 further exacerbate these changes by continuing to inhibit natural ecosystem functions that could 7 moderate climate change effects. For instance, air temperatures and near-surface moisture 8 levels change in areas where natural vegetation is converted to agricultural use, and higher 9 temperatures have been observed in the Midwest as a result of converting land to agricultural 10 use (USGCRP 2014). The USGCRP (2014) indicates that land use changes, such as the 11 continued expansion of urban areas, paired with climate change effects, such as heavier 12 precipitation events, can exacerbate climate change effects, including reduced water filtration 13 into the soil and increased surface runoff. Although anthropogenic land uses will contribute to 14 climate change in these and other ways, land uses will also be affected by climate change in 15 several ways. For instance, plant winter hardiness zones are likely to shift one-half to one full 16 zone by the end of the proposed license renewal period (USGCRP 2014). This shift will affect 17 the ability to grow certain crops as the Midwest will likely contain plants now associated with the 18 Southeast by the end of the century (USGCRP 2014). Additionally, the USGCRP (2014) 19 projects that the Midwest will experience a loss in cropland cover and an expansion in exurban 20 and suburban areas. Changes in cropland cover and expansion of exurban and suburban 21 areas could then reduce the quality and availability of land resources and agricultural 22 productivity. 23 Water Resources 24 Predicted changes in the timing, intensity, and distribution of precipitation will likely result in 25 changes in surface water runoff affecting water availability across the Midwest. As discussed 26 above, the Midwest may experience an increase in mean precipitation during the fall, winter, 27 and spring and an increase in the frequency and intensity of extreme (heavy) precipitation 28 (USGCRP 2014). As cited by the USGCRP, in spite of increased annual average precipitation, 29 the loss of moisture from soils because of higher temperatures, along with increased 30 evapotranspiration from vegetation and the increased average number of days without 31 precipitation, is likely to intensify short-term (seasonal or shorter) droughts across the region 32 into the future (USGCRP 2009, 2014). Such conditions can potentially reduce the amount of 33 water available for surface runoff and streamflow on a seasonal timeframe. Runoff and 34 streamflow at a regional scale for the Midwest region indicate no clear trend during the last half 35 century; however, annual runoff and river flow are projected to increase in the upper Midwest. 36 Climate change impacts on groundwater availability depend on basin geology, frequency and 37 intensity of high-rainfall periods, recharge, soil moisture, and groundwater and surface water 38 interactions (USGCRP 2014). Precipitation and evapotranspiration are key drivers in aquifer 39 recharge. Increased precipitation in the fall, winter, and spring is likely to result in increased 40 groundwater recharge. More precipitation during these seasons (as opposed to summer) would 41 percolate into the groundwater because it would experience lower evaporation and transpiration 42 rates. Furthermore, a portion of the winter precipitation would fall as snow. Instead of running 43 off the land, much of the snow is likely to slowly melt in place and contribute to groundwater 44 recharge. 45 Terrestrial Resources 46 As described above, the Midwest will likely experience rising temperatures and heavier 47 precipitation events during the proposed license renewal period. As the climate changes, 48 terrestrial resources will either need to be able to tolerate the new physical conditions or shift 4-110

Environmental Consequences and Mitigating Actions 1 their population range to new areas with a more suitable climate. Scientists currently estimate 2 that species are shifting their ranges at a rate of 20 to 36 ft (6.1 to 11 m) in elevation per decade 3 and 3.8 to 10.5 mi (6.1 to 16.9 km) in latitude per decade (Chen et al. 2011; Thuiller 2007). 4 Although some species may readily adapt to a changing climate, others may be more prone to 5 experience adverse effects. For example, species whose ranges are already limited by habitat 6 loss or fragmentation or who require very specific environmental conditions may not be able to 7 successfully shift their ranges over time. Migratory birds that travel long distances may also be 8 disproportionately affected because they may not be able to pick up on environmental clues that 9 a warmer, earlier spring is occurring in the United States while overwintering in tropical areas. 10 Fraser et al. (2013) found that songbirds overwintering in the Amazon did not leave their winter 11 sites earlier, even when spring sites in the eastern United States experienced a warmer spring. 12 As a result, the song birds missed periods of peak food availability. For many Midwest species, 13 migration to changed habitats is projected to be slow due to flat topography, high latitudes, and 14 fragmented habitats (USGCRP 2014). For instance, in its final rule to list the red knot (Calidris 15 canutus rufa), a shorebird that uses the Great Lakes during spring and fall migration, FWS cites 16 several effects resulting from climate change as factors contributing to the species decline 17 (79 FR 73705). These effects include habitat loss from sea level rise, asynchronies in the 18 timing of annual cycles, and increased frequency of severe storm events. Special status 19 species and habitats, such as those that are Federally protected by the ESA, would likely be 20 more sensitive to climate changes because these species populations are already experiencing 21 threats that are endangering their continued existence throughout all, or a significant portion of 22 their ranges. Habitat ranges for forest systems in the Midwest, such as paper birch 23 (Betula papyrifera), balsam fir (Abies balsamea), and black spruce (Picea mariana), are 24 projected to decline across the Midwest as they shift northward, and species that are common 25 farther south, such as oaks (Quercus spp.) and pines (Pinus spp.), will expand their range north 26 into the Midwest region (USGCRP 2014). Climate changes could also favor non-native, 27 invasive species and promote population increases of insect pests and plant pathogens, which 28 may be more tolerant to a wider range of climate conditions. 29 Aquatic Resources 30 The potential effects of climate change, whether from natural cycles or manmade activities, 31 could result in changes that could affect aquatic resources in the Illinois River. Raised air 32 temperatures could result in higher water temperatures in the cooling pond and in the Illinois 33 River and its tributaries. Higher water temperatures would increase the potential for thermal 34 effects on aquatic biota, such as fish kills within the cooling pond, and could exacerbate existing 35 environmental stressors, such as excess nutrients, sedimentation, and lowered dissolved 36 oxygen associated with eutrophication (USGCRP 2014). The Midwest will likely experience an 37 increased frequency of extreme rainfall events, which will cause erosion and could lead to a 38 decline in water quality (USGCRP 2014). Species that require cleaner waters, such as 39 freshwater mussels, could experience further population declines. The USGCRP (2014) 40 predicts habitat loss and local extinctions of fish and other aquatic species throughout the 41 United States from the combined effects of water withdrawal and climate change. Shifts in 42 species assemblages and distributions are also likely as climate change continues 43 (USGCRP 2014), which could alter the balance of the aquatic community in the Illinois River. 44 As discussed below under the section entitled, Terrestrial Resources, special status species, 45 such as those that are Federally protected under the ESA (16 U.S.C. 1531 et seq.), would be 46 more sensitive to climate changes. Invasions of non-native species that thrive under a wide 47 range of environmental conditions and warmer waters could further disrupt the current 48 composition of aquatic communities (NRC 2013d). 4-111

Environmental Consequences and Mitigating Actions 1 Historic and Cultural Resources 2 Increases in river levels because of changes in meteorological conditions due to climate change 3 could result in the loss of historic and cultural resources from flooding, erosion, or inundation. 4 Due to water-level changes, some resources could be lost before they could be documented or 5 otherwise studied. However, the limited extent of climate change that may occur during the 6 20-year license renewal term would not likely result in any significant loss of historic and cultural 7 resources at LSCS. 8 Socioeconomics 9 Rapid changes in climate conditions could have an impact on the availability of jobs in certain 10 industries. For example, tourism and recreation are major job creators in some regions, 11 bringing billions of dollars to regional economies. Across the Nation, fishing, hunting, and other 12 outdoor activities make important economic contributions to rural economies and are also a part 13 of the cultural tradition. A changing climate would mean reduced opportunities for some 14 activities in some locations and expanded opportunities for others. Hunting and fishing 15 opportunities could also change as animals habitats shift and as relationships among species 16 are disrupted by their different responses to climate change (USGCRP 2014). 17 Water-dependent recreation could also be affected (USGCRP 2009). The USGCRP reports 18 that increasing heat and humidity associated with climate change in parts of the Midwest region 19 by the year 2050 could create unfavorable conditions for summertime outdoor recreation and 20 tourism activity (USGCRP 2014). However, the limited extent of climate change that may occur 21 during the 20-year license renewal term would not likely cause any significant changes in 22 socioeconomic conditions in the vicinity of LSCS. 23 Human Health 24 Increasing temperatures due to changes in climate conditions could have an impact on human 25 health. However, changes in climate conditions that may occur during the license renewal term 26 will not result in any significant change to the impacts discussed in Section 4.11.1 from LSCSs 27 radioactive and nonradioactive effluents. 28 Environmental Justice 29 Rapid changes in climate conditions could disproportionately affect minority and low-income 30 populations. The USGCRP (2009) indicates that infants and children, pregnant women, the 31 elderly, people with chronic medical conditions, outdoor workers, and people living in poverty 32 are especially at risk from a variety of climate-related health effects. Examples of these effects 33 include increased heat stress; air pollution; extreme weather events; and diseases carried by 34 food, water, and insects. The greatest health burdens related to climate change are likely to fall 35 on the poor, especially those lacking adequate shelter and access to other resources, such as 36 air conditioning. Elderly people on fixed incomes, who are more likely to be poor, are more 37 likely to have debilitating chronic diseases or limited mobility. In addition, the elderly have a 38 reduced ability to regulate their own body temperature or the ability to sense when they are too 39 hot. According to the USGCRP (2009), the elderly are at greater risk of heart failure, which is 40 further exacerbated when cardiac demand increases in order to cool the body during a heat 41 wave. The USGCRP (2009) also found that people taking medications, such as diuretics for 42 high blood pressure, have a higher risk of dehydration. The USGCRP (2014) reconfirmed the 43 previous report findings regarding the risks of climate change on low-income populations and 44 also warns that climate change could affect the availability and access to local plant and animal 45 species, thus impacting the people who have historically depended on them for food or 46 medicine. However, minority and low-income populations at LaSalle are not likely to experience 4-112

Environmental Consequences and Mitigating Actions 1 disproportionately high and adverse impacts from climate change, based on the expected small 2 or slow change, effectively, in the environment during the 20-year license renewal term. 3 4.16 Cumulative Impacts of the Proposed Action 4 The NRC staff considered potential cumulative impacts in the environmental analysis of 5 continued operation of LSCS during the 20-year license renewal period. Cumulative impacts 6 may result when the environmental effects associated with the proposed action are overlaid or 7 added to temporary or permanent effects associated with other past, present, and reasonably 8 foreseeable actions. Cumulative impacts can result from individually minor, but collectively 9 significant, actions taking place over a period of time. An impact that may be SMALL by itself 10 possibly could result in a MODERATE or LARGE cumulative impact when it is considered in 11 combination with the impacts of other actions on the affected resource. Likewise, if a resource 12 is regionally declining or imperiled, even a SMALL individual impact could be important if it 13 contributes to, or accelerates, the overall resource decline. 14 For the purposes of this cumulative analysis, past actions are those before the receipt of the 15 license renewal application; present actions are those related to the resources at the time of 16 current operation of the power plant; and future actions are those that are reasonably 17 foreseeable through the end of plant operation, including the period of extended operation. 18 Therefore, the analysis considers potential impacts through the end of the current license terms, 19 as well as the 20-year license renewal term. The geographic area over which past, present, 20 and reasonably foreseeable actions would occur depends on the type of action considered and 21 is described below for each resource area. 22 To evaluate cumulative impacts, the incremental impacts of the proposed action, as described 23 in Sections 4.2 to 4.15, are combined with other past, present, and reasonably foreseeable 24 future actions, regardless of which agency (Federal or non-Federal) or person undertakes such 25 actions. The NRC staff used the information provided in Exelons ER; responses to RAIs; 26 information from other Federal, State, and local agencies; scoping comments; and information 27 gathered during visits to the LSCS site to identify other past, present, and reasonably 28 foreseeable actions. For a project to be considered in the cumulative analysis, the NRC staff 29 determined whether it would occur within the noted geographic areas of interest and within the 30 period of extended operation, whether it was reasonably foreseeable, and whether there would 31 be a potential overlapping effect with the proposed project. For past actions, consideration 32 within the cumulative impacts assessment is resource and project specific. In general, the 33 effects of past actions are included in the description of the affected environment in Chapter 3, 34 which serves as the baseline for the cumulative impacts analysis. However, past actions that 35 continue to have an overlapping effect on a resource that potentially could be affected by the 36 proposed action are considered in the cumulative analysis. 37 Appendix E describes other actions and projects identified during this review and considered in 38 the NRC staffs analysis of the potential cumulative effects. Not all actions or projects listed in 39 Appendix E are considered in each resource area because of the uniqueness of the resource 40 and its geographic area of consideration. 41 4.16.1 Air Quality and Noise 42 This section addresses the direct and indirect effects of license renewal on air quality and noise 43 when added to the aggregate effects of other past, present, and reasonably foreseeable future 44 actions. As described in Section 4.3.1, the incremental impacts on air quality and noise levels 45 from the proposed license renewal would be SMALL. 4-113

Environmental Consequences and Mitigating Actions 1 4.16.1.1 Air Quality 2 The geographic area considered in the cumulative air quality analysis is the county where the 3 proposed action is located, as air quality designations for criteria air pollutants are generally 4 made at the county level. Counties are further grouped together based on a common airshed 5 known as an Air Quality Control Region (AQCR)to provide for the attainment and 6 maintenance of the NAAQS. LSCS is located in LaSalle County, Illinois, which is part of the 7 North Central Illinois Intrastate AQCR (40 CFR 81.262). 8 With regard to NAAQS criteria pollutants, LaSalle County and the entire North Central Illinois 9 Intrastate AQCR are designated as attainment for all NAAQS (40 CFR 81.314). According to 10 EPAs Enforcement and Compliance History Online, there are 20 facilities designated as major6 11 air emission sources, 9 synthetic minor air emissions sources, and 160 facilities designated as 12 minor air emission sources located in LaSalle County (EPA 2015b). LSCS, as discussed in 13 Section 3.3.2 of this SEIS, is a synthetic minor air source. Air emissions from permitted sources 14 at LSCS are presented in Chapter 3, Table 3-4. There will be no refurbishment-related 15 activities during the license renewal period. Additionally, Exelon does not anticipate equipment 16 or operational upgrades or replacement activities that would increase air emissions during the 17 license renewal term (Exelon 2015c). As a result, the NRC staff expects emissions from LSCS 18 during the license renewal period to be similar to those emissions presented in Section 3.3.2. 19 Appendix E provides a list of current projects and reasonably foreseeable future actions that 20 could contribute to cumulative impacts to air quality. Air emissions sources that contribute to air 21 quality identified in Appendix E are currently operating and, given the designated attainment 22 status for all NAAQS in LaSalle County, these emissions have not contributed to a violation of 23 the NAAQS. Consequently, cumulative impacts to air quality in LaSalle County would be the 24 result of changes to present-day emissions and future actions within the county. Development 25 and construction activities associated with regional growth of housing, business, and industry, 26 as well as associated vehicular traffic, can increase air emissions. Regional air quality 27 conditions could deteriorate from the effects of the growth of the county as construction 28 activities give rise to dust, exhaust, and emissions that can degrade air quality. Population 29 growth is estimated to increase by 4 percent per decade in LaSalle County (LaSalle 30 County 2014). Air quality effects of development are monitored through the statewide ambient 31 air quality monitoring network. If degradation in air quality is observed, the IEPA can develop air 32 quality control programs to mitigate the effects of development. Furthermore, any new 33 stationary sources of emissions that would be established in the region would be required to 34 apply for an air permit from the IEPA and be operated in accordance with regulatory 35 requirements. IEPA will examine the potential air quality impacts using various modeling tools 36 to assess any potential changes to compliance with the NAAQS prior to issuing an air permit to 37 a new source (or to an existing source that proposes to undergo significant modification). 38 Climate change can impact air quality as a result of changes in meteorological conditions. Air 39 pollutant concentrations are sensitive to winds, temperature, humidity, and precipitation 40 (EPA 2009a). As discussed in Section 4.15.3.2, ozone levels have been found to be particularly 41 sensitive to climate change influences (EPA 2009b; IPCC 2007c). Climate change may make it 42 difficult for regions to meet ozone NAAQS (USGCRP 2009). However, as discussed in 43 Section 4.15.3, while surface temperatures are expected to increase in the Midwest, this may 44 not necessarily result in an increase in ozone concentrations. Changes in air emission 6 Major sources emit or have the potential to emit 10 tons per year of any one hazardous air pollutant (HAP), 25 tons per year of any combination of HAPs, or 100 tons per year of any other regulated air contaminant. A minor source has a potential to emit that is less than the major source thresholds. A minor synthetic source is an air pollution source that has a Federally Enforceable State Operating Permit (FESOP) with conditions that legally restrict its potential to emit to below threshold levels. 4-114

Environmental Consequences and Mitigating Actions 1 concentrations will depend on the combination of higher temperatures, current levels of ozone 2 (increases in ozone concentrations and temperature correlations have been observed in urban 3 regions), stagnant air masses, sunlight, and emissions of pollutant precursors. Furthermore, 4 climate models do not agree on the direction of ozone changes (increase or decrease) in 5 response to climate change for the Midwest (Wu et al. 2008; Tagaris et al. 2009). 6 Because of the small quantity of emissions from LSCS and that no emissions increase 7 associated with license renewal is expected, the potential for LSCS to contribute to a cumulative 8 impact with other air pollutant sources is SMALL. Given the current designated attainment 9 status of LaSalle County and few reasonably foreseeable projects that may increase air 10 emissions in the region of interest, the NRC staff concludes that, combined with the emissions 11 from other past, present, and reasonably foreseeable future actions, cumulative impacts on air 12 quality would be SMALL. 13 4.16.1.2 Noise 14 Section 3.3.3 presents a summary of noise sources at LSCS and in the vicinity of the site. 15 Noise levels in the vicinity of a nuclear power plant could increase from planned activities 16 associated with urban, industrial, and commercial development. The magnitude of cumulative 17 impacts depends on the nuclear plants proximity to other noise sources. A 3 -A-weighted 18 decibels (-dBA) change in sound level is considered barely discernable (FHWA 2011), as 19 discussed in Section 3.3.3 of this SEIS. A 3-dBA increase would occur with the placement of 20 another identical source over an existing source (e.g., a doubling of the traffic volume). 21 Ongoing or foreseeable future projects in and around LSCS, as identified in Appendix E, would 22 increase noise levels only in the vicinity of the noise sources. Therefore, contributions to noise 23 levels from future actions are limited to projects in the vicinity of LSCS (within a 2 mi (3.3 km) 24 radius). 25 For example, wind farm projects in the immediate vicinity of LSCS may contribute to noise 26 impacts, particularly the Grand Ridge Wind Farm. As discussed in Section 4.3.6, noise impacts 27 from wind generation operations would include aerodynamic noise from the turbine rotors and 28 mechanical noise from the turbine drivetrain components. Wind-turbine-generated noise will 29 vary depending on the speed of the turbine, environmental conditions, and the distance of the 30 receptor from the turbine. Exelon stated that any additional noise from installation and 31 operation of the wind turbine in the vicinity has been imperceptible (Exelon 2015j). The NRC 32 staff identified noise concerns raised by the public regarding wind farm installations in counties 33 surrounding LaSalle (News-Gazette 2013, Daily Herald 2010, FarmProgress 2010; 34 FairWindEnergy undated). However, the NRC staff did not identify noise concerns raised 35 specifically in LaSalle County or the immediate area surrounding LSCS. Furthermore, 36 wind-turbine-generated noise, and other projects, must comply with noise regulations found in 37 IAC Title 35, Subtitle H. Accordingly, the NRC staff concludes that the cumulative impact to the 38 noise environment from past, present, and reasonably foreseeable actions is SMALL. 39 4.16.2 Geology and Soils 40 This section addresses the direct and indirect effects of license renewal on geology and soils 41 when added to the aggregate effects of other past, present, and reasonably foreseeable future 42 actions. As noted in Section 4.4.1, the NRC staff concludes that the impacts of the proposed 43 action (license renewal) on geology and soils would be SMALL. The cumulative impacts on the 44 geologic environment primarily relate to land disturbance and the potential for soil erosion and 45 loss, as well as the projected consumption of geologic resources. Exelon has no plans to 46 conduct refurbishment or replacement actions. Ongoing operation and maintenance activities at 47 LSCS are expected to be confined to previously disturbed areas. Any use of geologic materials 4-115

Environmental Consequences and Mitigating Actions 1 such as aggregates to support operation and maintenance activities would be procured from 2 local and regional sources. Thus, activities associated with continued operations are not 3 expected to affect the geologic environment. 4 The NRC staff assumes that any construction activities would use material from local and 5 regional sources, as these materials are abundant in the region. These identified projects are of 6 such a scale as to not be likely to impact regional sources and supplies of the identified 7 resources. Furthermore, construction activities would need to be conducted in accordance with 8 State and local requirements and development activities would be subject to BMPs for soil 9 erosion and sediment control, which would serve to minimize soil erosion and loss. Considering 10 ongoing activities and reasonably foreseeable actions, the NRC staff concludes the cumulative 11 impacts on geology and soils during the license renewal term would be SMALL. 12 4.16.3 Water Resources 13 This section addresses the direct and indirect effects of the proposed action (license renewal) 14 on water resources when added to the aggregate effects of other past, present, and reasonably 15 foreseeable future actions. 16 4.16.3.1 Surface Water Resources 17 As described in Section 4.5.1.1, the incremental impacts on surface water resources from 18 continued operations of LSCS during the license renewal term would be SMALL. The NRC staff 19 has also evaluated other projects and actions for consideration in determining their contribution 20 to cumulative impacts on surface water resources (see Appendix E). 21 The description of the affected environment under Section 3.5.1 of this SEIS serves as the 22 baseline for the cumulative impacts assessment for surface water resources. The geographic 23 area of analysis for the surface water resources component of the cumulative impacts analysis 24 includes the lowermost portion of the Upper Illinois River Basin, as described in Section 3.5.1.1, 25 with a detailed focus on the Marseilles Pool of the Illinois River and its tributaries. As such, this 26 review focused on those projects and activities that would withdraw water from or discharge 27 effluent to the Marseilles Pool. The cumulative impacts on surface water use and quality, along 28 with associated climate change considerations, are presented below. 29 Water Use Considerations 30 The Upper Illinois River Basin is composed of a 10,949 square mile (mi2) (28,369 square 31 kilometer (km2)) drainage area upstream from Ottawa, Illinois. LSCS is located on the 32 Marseilles Pool of the main stem of the Illinois River. This pool is one of eight such navigation 33 pools along the Illinois River and major tributaries that includes an associated lock and dam. 34 Each pool includes a navigation channel that is at least 9 ft (2.7 m) deep and 300 ft (91 m) wide. 35 Together, the navigation pools are part of the Illinois Waterway, which enables commercial river 36 traffic to travel from Lake Michigan to the Mississippi River and from there to the Gulf of Mexico 37 (Arnold et al. 1999; Talkington 1991; USGS 1998). 38 Operation of the navigation pools using the locks and dams has the effect of decreasing overall 39 river flow velocity and stabilizing river water levels, particularly during low flows. As a result of 40 this extensive management, some 60 percent of the State of Illinois commodities travel the 41 waterway annually. This includes grain, petroleum products, coal, chemicals, sand and gravel, 42 pulp, paper, and others (Talkington 1991). 43 In support of this cumulative impacts analysis, the NRC staff obtained and evaluated the best 44 available data on water consumption and projected trends in water use, as compiled by 45 responsible water resources management agencies. The USGS published a comprehensive 4-116

Environmental Consequences and Mitigating Actions 1 investigation of hydrologic and water quality conditions in the Upper Illinois River Basin in 1999 2 that also considered water use (Arnold et al. 1999). 3 Excluding surface water diversions from Lake Michigan in the Chicago area, nearly five times as 4 much groundwater as surface water is used in the Upper Illinois River Basin for public water 5 supply. Within the basin, surface water is primarily used for cooling and associated 6 thermoelectric power generation, followed by public water supply and industrial and commercial 7 use. In total, more than 90 percent of all reported water use in the basin is for the cooling and 8 thermoelectric power generation sector, with nearly all of the water from surface water sources. 9 This percentage reflects total water demands and does not account for water that is withdrawn 10 and not consumptively used (i.e., water that is returned to the water source rather than being 11 lost) (Arnold et al. 1999). Thermoelectric power generating plants that use once-through cooling 12 systems return most of the water they withdraw back to the source. In contrast, those using 13 closed-cycle cooling systems, which are now the standard for new facilities, withdraw much less 14 water (i.e., about 90 percent less than those with once-through cooling systems) but their 15 operation entails consumptive loses (i.e., primarily due to evaporation) of greater than 16 50 percent, resulting in the return of less water (NRC 2013d). 17 The rankings by water use sector cited above in Arnold et al. (1999) are mirrored in the 18 county-level forecasts of water use prepared by Southern Illinois University for the Illinois State 19 Water Survey (Dziegielewski et al. 2005). As part of its analysis, the NRC staff considered the 20 counties in the lowermost Upper Illinois River Basin, including counties that border LaSalle 21 County, where LSCS is located, and the immediately upstream portion of the Marseilles Pool in 22 Grundy County. Total water demand (both groundwater and surface water) overall in the Illinois 23 counties within the lowermost part of the Upper Illinois River Basin is projected to increase by 24 about 30 percent by 2025, as compared to water use in the year 2000. This is a 1,148 mgd 25 (4.35 million m3/d) (equivalent to 1,776 cfs (50.2 m3/s)) increase over water use in 2000 26 (Dziegielewski et al. 2005). 27 By 2025, the demand for public water use within the lowermost Upper Illinois River Basin is 28 projected to increase by about 36 percent. This reflects an increase of approximately 29 69 mgd (261,000 m3/d) as compared to public water use in the year 2000. For self-supplied 30 commercial and industrial water use, an increase of approximately 16 mgd (60,600 m3/d) by 31 2025 is forecast (Dziegielewski et al. 2005). 32 The NRC staff believes that the county-level total water demand projections likely overestimate 33 future demand, as they are heavily influenced by large forecasted increases in water demand 34 for thermoelectric power generation, which have not been realized to date. In addition, the 35 thermoelectric power generation component of these projections includes the Collins 36 Generating Station, a fossil-fuel fired power plant in Morris (Grundy County), Illinois, which 37 withdrew water from the Illinois River. This facility was permanently decommissioned in 2004 38 and, as a result, the county-level projections, particularly for Grundy County, probably 39 overestimate future total water demand. 40 In LaSalle County, total water demands are projected to increase by approximately 41 3.8 mgd (14,400 m3) to 89.8 mgd (340,000 m3/d) by 2025 as compared to the countys total 42 water use in 2000. This is a rate of increase of about 0.15 mgd (570 m3/d) per year, or an 43 increase of about 4 percent as compared to water use in 2000. This total county demand 44 includes 62.9 mgd (238,100 m3/d) attributable to LSCS operations. This total projected increase 45 by 2025 includes 0.3 mgd (1,140 m3/d) for public water supply (3 percent increase) and 2.5 mgd 46 (9,500 m3/d) increase for self-supplied commercial and industrial uses (a nearly 70 percent 47 increase), with the remainder attributable to use for thermoelectric power generation 48 (Dziegielewski et al. 2005). The projected increase in public water supply demand is in line with 4-117

Environmental Consequences and Mitigating Actions 1 the historical trend in LaSalle Countys population growth, which has averaged about 2 percent 2 per decade. Most recently, the Illinois Department of Commerce and Economic Opportunity has 3 projected county population to grow at a rate of about 4 percent between 2020 and 2030, or 4 about 0.4 percent per year (LaSalle County 2014). 5 Based on the discussion above, the NRC staff estimates that by the end of the period of 6 extended operations for LSCS in 2043, LaSalle Countys total water demands could increase to 7 96.5 mgd (365,000 m3/d). This conservative projection assumes water demand will increase by 8 about 0.4 percent per year equally across all water use sectors and that LSCSs river makeup 9 water withdrawals, which dominate water withdrawals in the county and across the lowermost 10 Upper Illinois River Basin, will also increase proportionally. 11 However, even if the entire projected water demand for LaSalle County (96.5 mgd, equivalent to 12 149 cfs (4.2 m3/s)) which includes water needs by LSCS were to be withdrawn from the 13 Marseille Pool of the Illinois River and not returned, this would be equivalent to approximately 14 1.4 percent of the mean annual flow of the Illinois River through the Marseilles Pool. This small 15 percentage increase would be less because some of the water withdrawn from the pool would 16 be returned, as more than 50 percent of the water withdrawn by LSCS at present (i.e., about 17 55 cfs (1.6 m3/s) is returned directly to the Marseilles Pool). It is extremely likely that future 18 demands for public water supply will continue to be met by groundwater and not surface water. 19 There are no municipalities that use the Marseilles Pool of the Illinois River as a public water 20 supply source. All identified public water supplies within 10 mi (16 km) of LSCS rely on 21 groundwater (Exelon 2014a, 2014b). Given the abundant groundwater supplies in the county 22 and also the higher cost of surface water treatment, the NRC staff does not anticipate public 23 water supplies to switch to surface water as a water source during the license renewal term. 24 Thus, it is extremely unlikely that continued LSCS operations withdrawing surface water from 25 the Marseilles Pool of the Illinois River, combined with those of other users in the county, would 26 substantially impact the downstream availability of surface water. 27 Water Quality Considerations 28 Water quality within the whole of the Illinois River Basin has historically suffered from rapid 29 population growth, urbanization, and industrial development. This resulted in the discharge of 30 poorly treated sewage, the discharge of industrial pollutants and refuse, runoff of agricultural 31 chemicals and sediments, and the alteration of the natural hydrology of the river (Exelon 2014a; 32 Talkington 1991). 33 Nonetheless, over the last 50 years, substantial improvements in water quality have occurred, 34 due to municipal and industrial waste treatment and management efforts to address both point 35 and nonpoint pollutant sources. Ongoing water quality concerns within the Upper Illinois River 36 Basin remain and include the atmospheric deposition of pesticides and trace metals; endocrine 37 disrupting compounds in surface and groundwater; nutrient enrichment of surface and 38 groundwater; the transport and fate of pesticides, trace elements, and volatile organic 39 compounds in surface and groundwater; and the effects of urbanization on biodiversity, habitat, 40 and water quality (USGS 1998, Groschen 2004). 41 As discussed in Section 3.5.1.3 of this SEIS, a segment of the Illinois River that encompasses 42 the Marseilles Pool does not meet designated uses and associated water-quality standards and 43 is listed as an impaired waterway. The segment is listed as impaired for not meeting designated 44 uses for fish consumption due to polychlorinated biphenyls (PCBs) and mercury as well as for 45 primary contact recreation use, due to fecal coliform bacteria. However, the segment is 46 classified as fully supporting its designated use for aquatic life. IEPA has assigned a medium 47 priority for the development of Total Maximum Daily Load (TMDL) limits to improve water quality 4-118

Environmental Consequences and Mitigating Actions 1 in this river segment pursuant to Section 303(d) of the Federal Water Pollution Control Act 2 (i.e., Clean Water Act (CWA)) (33 U.S.C. 1251). 3 As noted previously, development in the lowermost Upper Illinois River Basin, including 4 associated population growth and industrial development, is expected. Upstream development 5 could lead to increased discharges and pollutant loading to the Marseilles Pool of the Illinois 6 River with impacts on ambient water quality. The magnitude of cumulative impacts would 7 depend on the nature and location of the actions relative to receiving surface water bodies, the 8 number of actions (facilities or projects), and the extent of municipal, county, and state 9 regulatory agency development planning and environmental regulatory controls. At a minimum, 10 new and modified industrial and large commercial facilities would be subject to regulation under 11 the Federal CWA (33 U.S.C. 1251) (i.e., Section 402). This would include IEPA-administered 12 NPDES permit limits on stormwater and point source discharges designed to be protective of 13 surface water resources. Likewise, it is this regulatory framework that presently governs 14 industrial effluent and thermal discharges from LSCS and other major industrial facilities in the 15 lowermost Upper Illinois River Basin. 16 Climate Change Considerations 17 The NRC staff also considered the USGCRPs most recent compilations of the state of 18 knowledge relative to global climate change effects (Melillo et al. 2014). Climate change can 19 impact surface water as a result of changes in temperature and precipitation. As discussed in 20 Section 4.15.3.2, climate model simulations for the Midwest region indicate an increase in 21 annual mean temperature as well as precipitation. More especially, the frequency and intensity 22 of heavy precipitation events is forecast to increase. Increased precipitation results in greater 23 runoff and streamflow. The USGCRP (Melillo et al. 2014) predicts that runoff and streamflow for 24 the upper Midwest will increase overall. 25 In its ER, Exelon (2014a) cites an analysis prepared by the Illinois State Water Survey 26 (Knapp 2009) that assesses trends in stream flows encompassing the Illinois River Basin and 27 their implications for flood frequency. For stream gaging sites with a long period of record 28 (90 years), the analysis indicates a consistent trend of increasing stream flows in the upper 29 Midwest, attributed to a 7- to 10-percent increase in precipitation over the past 30 years 30 (through 2008). Results from an earlier study prepared by USGS (Arnold et al. 1999) and 31 specific to the Upper Illinois River Basin also indicate a statistically significant increase in mean 32 annual stream flow (over the period 1950-1997) at all seven stations selected for analysis, 33 including as measured at the USGS gage at Marseilles, Illinois. In contrast to Knapp (2009), the 34 USGS study was not able to correlate any trends in precipitation with the apparent increases in 35 streamflow. Rather, the authors concluded that the observed trends were more likely 36 attributable to land-use changes in the affected watersheds, causing more rapid runoff of 37 precipitation, and to increases in groundwater usage and associated increased return effluent to 38 receiving waters from wastewater treatment plants in the basin. These two studies serve to 39 point to the uncertainty over whether there has been an observable trend in precipitation and/or 40 streamflow in the upper Midwest, as forecast by the USGCRP. 41 Despite any observable trends to date, rapid runoff events occurring due to more frequent and 42 intensive precipitation events associated with climate change, especially over cleared or 43 urbanized areas, will result in increases in erosion and transport of sediment and other 44 pollutants to receiving waters. This can negatively affect ambient water quality. 45 Further, higher air temperatures and increased runoff associated with heavy precipitation events 46 could impact the thermal regime of the Marseilles Pool of the Illinois River, along with increases 47 in runoff laden with nutrients, sediment, and other contaminants. Higher surface water 48 temperatures decrease the cooling efficiency of thermoelectric power generating facilities as 4-119

Environmental Consequences and Mitigating Actions 1 well as plant capacity, due to the need to reduce the discharge of thermal effluent 2 (Melillo et al. 2014). As intake water temperatures warm, cooling water makeup requirements 3 increase. Degradation in ambient surface water quality increases the costs of water treatment 4 for both industrial cooling water and potable water, due to the need for increased filtration and 5 higher additions of chemical treatments for such uses as antiscaling and disinfection. With 6 respect to LSCS operations, these potential climate-induced changes can lead to higher cooling 7 pond temperatures and an increase in evaporative losses from LSCSs cooling pond. This can 8 conceivably result in additional makeup water withdrawals from the Marseilles Pool and an 9 increased need for blowdown discharges from the cooling pond to the Illinois River. At present, 10 the data available to the NRC staff is not sufficient to indicate whether or not a warming trend is 11 evident in the waters of the Illinois River, including the Marseilles Pool. Exelon (2015b) has not 12 identified any increasing trend in cooling pond temperatures to date, although this observation is 13 based on limited data. Regardless, as detailed in Section 3.5.1.3 of this SEIS, the chemical and 14 thermal quality of LSCSs discharges to the Illinois River are subject to the effluent limitations 15 and monitoring requirements prescribed by its NPDES permit (IEPA 2013). Additionally, 16 thermal mixing zone limits set by LSCSs NPDES permit indirectly limit surface water 17 withdrawals and consumptive water use during low river flow and extreme summer weather 18 events. 19 Future thermal and pollutant discharges from new and modified industrial and large commercial 20 facilities in the lowermost Upper Illinois River Basin would be required to comply with applicable 21 NPDES permit requirements under the Federal CWA, local and regional health standards, and 22 TMDLs imposed by the State of Illinois. 23 Conclusion 24 Surface water availability is expected to continue to be sufficient through the license renewal 25 term, based on the projections and associated assumptions cited above. Surface water from 26 the Marseilles Pool of the Illinois River has been able to support ongoing demands for uses 27 ranging from navigation to cooling and thermoelectric power generation to commercial and 28 industrial water supply. Flows within the Upper Illinois River Basin and through the Marseilles 29 Pool are not likely to decrease and may trend higher during the LSCS license renewal term, in 30 part due to climate-induced hydrologic changes. No increase in LSCS consumptive water use 31 is expected during the license renewal term. Surface water withdrawals and associated 32 consumptive water use for LSCS operations are expected to remain a small percentage of the 33 mean annual and 90-percent exceedance flow through the Marseilles Pool of the Illinois River. 34 It is reasonable to anticipate that water-quality-based limits imposed by the IEPA through 35 NPDES permits and other measures on cooling water, wastewater, and stormwater discharges 36 and similar limits on sources of development, agricultural, and urban runoff will continue to 37 maintain or improve ambient surface water quality in the Illinois River. LSCSs combined 38 cooling pond blowdown, wastewater, and stormwater discharges to the Illinois River are 39 regulated under an IEPA-administered NPDES permit. Available data indicate that LSCS 40 operations are a very small contributor to the pollutant and thermal loading to the Illinois River. 41 Based on the foregoing, the NRC staff concludes that the cumulative impacts from past, 42 present, and reasonably foreseeable future actions and trends on surface water resources 43 during the license renewal term would be SMALL. 44 4.16.3.2 Groundwater Resources 45 This section addresses the direct and indirect effects of license renewal on groundwater use 46 and quality when added to the aggregate effects of other past, present, and reasonably 47 foreseeable future actions. As noted in Section 4.5.1.2, the NRC staff concludes the impacts of 48 the proposed action (license renewal) on groundwater consumption and quality would be 4-120

Environmental Consequences and Mitigating Actions 1 SMALL. All groundwater consumed at LSCS is obtained from two wells completed in the 2 Cambrian-Ordovician Aquifer (see Section 3.5.2.2). 3 LaSalle County has an adequate supply of groundwater for industrial, municipal, and domestic 4 purposes (LaSalle County 2014). The Cambrian-Ordovician Aquifer System is a major source 5 of water in LaSalle County. Groundwater levels in the Cambrian-Ordovician Aquifer System of 6 LaSalle County and the plant area have shown little change from 1995 to 2007 7 (Burch 2002, 2008). Even if this trend does not continue, the plant is unlikely to have a 8 significant impact on the Cambrian-Ordovician Aquifer System. 9 Ongoing operations have not impacted the groundwater quality of aquifers on or off the site. 10 The Cambrian-Ordovician Aquifer System is overlain by 312 ft (95 m) of aquitards, which 11 prevent the groundwater quality from being impacted by site activities. Whether an aquifer is 12 located on site or off site, the low permeability, thickness, and lateral extent of the Wedron 13 Silty-Clay Till means there is little chance of significant impact to groundwater quality from site 14 activities. 15 Considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes 16 that the cumulative impacts on groundwater use and quality during the LSCS license renewal 17 term would be SMALL. 18 4.16.4 Terrestrial Resources 19 This section addresses the direct and indirect effects of license renewal on terrestrial resources 20 when added to the aggregate effects of other past, present, and reasonably foreseeable future 21 actions. Section 4.6 of this SEIS finds that the direct and indirect impacts on terrestrial 22 resources from the proposed license renewal, when considered in the absence of the aggregate 23 effects, would be SMALL. The cumulative impact is the total effect on terrestrial resources of all 24 actions taken, no matter who has taken the actions (the second principle of cumulative effects 25 analysis in CEQ 1997). 26 Two related concepts bound the analysis of cumulative impacts: (1) the timeframe and 27 (2) geographic extent. The timeframe for cumulative analyses for ecological resources extends 28 far enough into the past to understand the processes that affect the present resource conditions 29 and to examine whether and why terrestrial resources are stable or unstable, which the NRCs 30 definitions of impact levels require. The timeframe for cumulative impact analysis is more 31 extensive than that for the direct and indirect impact analysis. 32 The geographic extent considered in this cumulative terrestrial resource analysis depends on 33 the particular cumulative impacts being discussed. Direct and indirect impacts from LSCS 34 operation are largely limited to the LSCS site and immediate vicinity. However, projects or 35 actions located beyond this geographic area could directly or indirectly affect terrestrial 36 resources in this area. This section focuses on the cumulative effects of such actions. 37 The level of cumulative impacts is measured against a baseline. Consistent with other Federal 38 agencies and the Council on Environmental Qualitys (CEQ 1997) NEPA guidance, the term 39 baseline pertains to the condition of the resource without the action (i.e., under the no-action 40 alternative). Under the no-action alternative, the plant would shut down, and the resource would 41 conceptually return to its condition without the plant (which is not necessarily the same as the 42 condition before the plant was constructed). The baseline, or benchmark, for assessing 43 cumulative impacts on terrestrial resources takes into account the preoperational environment, 44 as recommended by EPA (1999b) for its review of NEPA documents. 4-121

Environmental Consequences and Mitigating Actions 1 Past Development and Habitat Alteration 2 The LSCS site was partially disturbed during the construction of the facility to develop site 3 buildings and infrastructure and to create the cooling pond. Of the sites 1,528 ha (3,776 ac), 4 65 ha (160 ac) were permanently converted for industrial use to support buildings and 5 infrastructure, and approximately 800 ha (1,976 ac) are occupied by the cooling pond. During 6 construction, some additional land may have been temporarily disturbed to allow for laydown 7 areas for construction supplies or storage of construction equipment. 8 In the broader areathe Illinois/Indiana Prairies Level IV Ecoregionnative tallgrass prairies, 9 wetlands, and floodplain forests have been converted to agricultural and urban land, which now 10 account for the major land-use types. Habitat loss, in general, can negatively affect breeding 11 success, dispersal success, predation rate, and other animal behaviors (Fahrig 2003). Habitat 12 fragmentation (the breaking up of a larger area of habitat into smaller patches of smaller total 13 area) can also negatively affect terrestrial biota. In a study of breeding bird communities in 14 24 Illinois grassland fragments, Herkert (1994) found that fragmentation was likely a factor in 15 Midwestern grassland bird population declines. A study conducted in 2012 on the partridge pea 16 (Chamaecrista fasciculata) concludes that native prairie plant species that occur in smaller, 17 isolated prairie fragments are likely to suffer a reduction in genetic fitness (Mannouris and 18 Byers 2013). IDNR (2005) reports that remaining prairie remnants within the State lack many 19 natural ecosystem functions, due to their small size, and areas of prairie restoration often lack 20 forbs or are overly dominated by big bluestem (Andropogon gerardii) or Indiangrass 21 (Sorghastrum nutans). Accordingly, remaining native populations in these habitats are likely to 22 suffer from reduced genetic fitness, which is further exacerbated by fragmentation. 23 Energy Production and Development 24 Two nuclear power plant sites with four operating reactors (Braidwood Station, Units 1 and 2, 25 and Dresden Nuclear Power Station, Units 2 and 3) lie within 50 mi (80 km) of the LSCS site. 26 Because the effects of these facilities would primarily be limited to the terrestrial resources on 27 each plants site and the immediate vicinity, the operation of these two facilities during the 28 proposed LSCS license renewal term would not result in cumulative effects to the terrestrial 29 resources affected by LSCS operation. 30 Four fossil-fuel-fired energy facilities occur in the region (Table E-1 in Appendix E) and each is 31 about 20 mi (30 km) from LSCS. Although no coal or gas energy projects are under 32 construction in the region at this time, other energy development may arise over the proposed 33 license renewal term. Air emissions from these facilities include GHGs, such as nitrogen 34 oxides, carbon dioxide, and methane, all of which can have far-reaching consequences 35 because they cumulatively contribute to climate change. The effects of climate change on 36 terrestrial resources are discussed in Section 4.15.3.2. 37 Four wind energy facilities exist in the region (Table E-1 in Appendix E). Grand Ridge Wind 38 Farm is a 140-unit wind facility located immediately west of the LSCS property, and it extends 39 southwest for approximately 8 mi (13 km). The other three wind facilities are located between 40 6 mi (10 km) and 27 mi (43 km) from the LSCS site and consist of a total of 450 wind units. 41 Operation of wind farms can result in direct mortality of birds and bats through collision with 42 turbine blades as well as indirect effects, such as wildlife avoidance, habitat disruption, reduced 43 nesting or breeding density, habitat abandonment, and behavioral effects 44 (Stewart et al. 2005, 2007). Given that the majority of bird and bat species are migratory, 45 effects of wind farms on bird and bat populations can be far reaching. 4-122

Environmental Consequences and Mitigating Actions 1 Development, Urbanization, and Habitat Fragmentation 2 As the region surrounding the LSCS site becomes more developed, habitat fragmentation will 3 increase, and the amount of forested, prairie, and wetland habitat is likely to decline further. 4 Transmission lines, pipelines, and associated corridors established to connect new buildings to 5 the regional electric grid and to utilities could further fragment habitats if the corridors split 6 otherwise continuous tracts of habitat. Edge species that prefer open or partially open habitats 7 will likely benefit from the fragmentation, whereas species that require interior forest or wetland 8 habitat will likely suffer. 9 Continued urbanization in the future will likely include construction of additional housing units 10 and associated commercial buildings; roads, bridges, and rail; and water or wastewater 11 treatment and distribution facilities and associated pipelines. Increased development will likely 12 decrease the overall availability and quality of terrestrial habitats. Species that require larger 13 ranges, especially larger predators, will likely suffer reductions in their populations. Similarly, 14 species with threatened or endangered Federal or State status or otherwise declining 15 populations would be more sensitive to declines in habitat availability and quality. Native prairie 16 plants will likely continue to experience reductions in genetic fitness, as previously discussed. 17 Wildlife Refuges, State Parks, and Recreational Areas 18 A number of State parks, State Fish and Wildlife Areas, and State Natural Areas and 19 recreational areas are located near LSCS (Table E-1 in Appendix E) that provide valuable 20 habitat to native wildlife, migratory birds, and protected terrestrial species and habitats. Illini 21 State Park, which comprises 510 ac (206 ha) and lies 6 mi (10 km) north-northwest of the LSCS 22 site, provides habitat for a number deciduous trees, including hickory (Carya spp.), ash 23 (Fraxinus spp.), walnut (Juglans spp.), elm (Ulmus spp.), cottonwood (Populus deltoids), oak 24 (Quercus spp.), and maple (Acer spp.), as well as white-tailed deer (Odocoileus virginianus), 25 eastern gray squirrels (Sciurus carolinensis), opossums (Didelphis virginiana), beavers (Castor 26 canadensis), raccoon (Procyon lotor), groundhogs (Marmota monax), and a variety of waterfowl 27 and songbirds (IDNR 2015a). Starved Rock State Park, which comprises 2,700 ac (1,090 ha) 28 and lies 15 mi (24 km) northwest of the LSCS site along the Illinois River, contains a variety of 29 habitats, including canyons, sandstone bluffs, rolling plains, forest, upland prairies, waterfalls, 30 rivers, and streams, and provides particularly high-quality habitat to many species of native 31 wildlife and migrating birds. As fragmentation and land-use changes continue, these protected 32 areas will become ecologically more important because they provide large, uninterrupted areas 33 of minimally disturbed habitat. 34 Conclusion 35 The NRC staff concludes that the cumulative impacts on terrestrial resources in the vicinity of 36 the LSCS site are MODERATE to LARGE, based on past, present, and reasonably foreseeable 37 future actions. This level of impact is primarily the result of past habitat alteration and loss on 38 the LSCS site and within the larger Illinois/Indiana Prairies Level IV Ecoregion. The 39 environmental effects of these actions are clearly noticeable and have destabilized important 40 attributes of certain terrestrial communities. The loss of genetic fitness of native prairie species 41 and the loss of tallgrass prairies, wetlands, and floodplains are demonstrative of such effects. 42 The incremental, site-specific impact from the continued operation of LSCS during the license 43 renewal period would be an unnoticeable or minor contributor to cumulative impacts on 44 terrestrial resources. 4-123

Environmental Consequences and Mitigating Actions 1 4.16.5 Aquatic Resources 2 This section addresses the direct and indirect effects of license renewal on aquatic resources 3 when added to the aggregate effects of other past, present, and reasonably foreseeable future 4 actions. Section 4.7 finds that the direct and indirect impacts on aquatic resources from the 5 proposed license renewal would be SMALL for all aquatic ecology issues, with the exception of 6 MODERATE impacts to shad from heat shock in the cooling pond. The geographic area 7 considered in the cumulative aquatic resources analysis includes the LSCS cooling pond and 8 the vicinity of the intake and discharge structures on the Illinois River affected by LSCS water 9 withdrawal and discharge. The baseline, or benchmark, for assessing cumulative impacts on 10 aquatic resources takes into account the preoperational environment as recommended by EPA 11 (1999b) for its review of NEPA documents. 12 Section 3.7 presents an overview of the current condition of the LSCS cooling pond and Illinois 13 River and the history and factors that led to current conditions. In summary, the direct and 14 indirect impacts from draining wetlands, construction of locks and dams, maintenance of 15 navigation channels, industrial effluent, and sewage discharge are some of the most influential 16 human activities on the Illinois River Basin (Parker 2014). By the 1960s, biodiversity of fish 17 within the upper Illinois River was low and freshwater mussels were nearly absent from the 18 upper Illinois River (Sietman et al. 2001). Pollution-tolerant non-native common carp (Cyprinus 19 carpio) and goldfish (Carassius auratus) dominated fish populations (Parker 2014). Since the 20 passage of the CWA in 1974, water quality within the Illinois River has improved, and more 21 diverse fish assemblages have inhabited the upper Illinois River (Parker 2014). Similarly, 22 freshwater mussels have recolonized portions of the upper Illinois River since the 1980s 23 (Sietman et al. 2001). 24 Many natural and anthropogenic activities can influence the current and future aquatic biota in 25 the area surrounding the LSCS site and the Illinois River Basin. Potential biological stressors 26 include operational impacts from LSCS (as described in Section 4.7), energy development, and 27 urbanization. 28 4.16.5.1 Energy Development 29 Several other power plants withdraw water from and discharge water to the Illinois River (see 30 Appendix E). The largest nuclear power plant near LSCS and located on the Illinois River is the 31 Dresden Nuclear Station, located on River Mile 272.3 of the Illinois River. Dresden Nuclear 32 Station withdraws water from the Kankakee River and discharges to the Illinois River (EA 2015). 33 For 3.5 months of the year, Dresden operates in an indirect-open-cycle mode, and during the 34 remainder of the year (8.5 months), Dresden operates its cooling pond in a closed-cycle mode, 35 similar to LSCS. Operating in a closed-cycle mode reduces the impacts to aquatic resources 36 because less water is withdrawn and discharged, and therefore, less thermal effluent is 37 discharged to the Illinois River. The NRC (2004) determined that the impacts from 38 impingement, entrainment, and heat shock from Dresden Nuclear Station would be SMALL on 39 aquatic resources. Furthermore, it is unlikely that the thermal effluent from Dresden Nuclear 40 Station and LSCS overlap, given that both thermal plumes dissipate within the vicinity of each 41 respective discharge structure and the distance between the two plants (NRC 2004; 42 Exelon 2014a). Impingement and entrainment at both plants could affect similar fish 43 populations; however, operating in the closed-cycle mode would reduce impacts to fish 44 (NRC 2004; EA 2015). 45 Kendall County Generation is a natural-gas-fueled plant with 1,140 MW generating capacity that 46 withdraws water from and discharges water to the Illinois River. This plant is approximately 47 27 mi (43 km) northeast of LSCS. Given that the discharge plumes are limited to the vicinity of 4-124

Environmental Consequences and Mitigating Actions 1 the discharge structures, the heated effluent from the two plants would not likely overlap. 2 However, many of the same fish populations could be affected by impingement and entrainment 3 at LSCS and Kendall County Generation. 4 The other power plants located on the Illinois River have a much smaller generating capacity 5 less than 180 MW (see Appendix E)and therefore require less cooling water. Given the lower 6 withdraw and discharge rates, effects to aquatic resources from impingement, entrainment, and 7 thermal effluents would also be lower at these facilities. 8 Several wind and solar farms operate within 50 mi (80 km) of LSCS (see Appendix E). These 9 facilities would not have detectable impacts on aquatic resources in the Illinois River because, in 10 general, they do not require water during operation. 11 4.16.5.2 Future Urbanization and Transportation Development 12 Future urbanization in the vicinity of LSCS would likely include construction of new housing units 13 and associated commercial buildings; roads, bridges, and rail; and water or wastewater 14 treatment (or both), distribution facilities, and associated pipelines. Continued development of 15 the area has the potential to increase the rate and volume of stormwater runoff and reduce 16 groundwater recharge. If not managed appropriately, such development could result in 17 increased flooding, higher and more frequent storm-related flows, and low flows of longer 18 duration in streams. The increased runoff rates and high channel velocities from inappropriately 19 managed sites could result in excessive bank erosion and associated sedimentation and stream 20 degradation in the Illinois River and its tributaries. As a result, aquatic biota populations may 21 experience habitat degradation or loss, reduced food or prey availability, and increased 22 susceptibility to exotic species invasions. Such potential impacts can be mitigated through 23 implementation of BMPs that address stormwater quality, quantity, and discharge. Stormwater 24 BMPs are often required by state and local regulations, which would ensure that impacts to 25 aquatic resources resulting from future development would be appropriately mitigated. 26 4.16.5.3 Wildlife Preserves, Parks, and Recreational Areas 27 Several wildlife preserves, parks, and recreation sites lie within the vicinity of LSCS (see 28 Appendix E), including the Marseilles State Fish and Wildlife Area, which lies 1.5 mi (2.4 km) 29 north of the LSCS site. The continued preservation of these areas will protect aquatic habitats 30 and, as land development continues, these areas will become ecologically more important 31 because they will provide large areas of unfragmented natural habitat. 32 4.16.5.4 Illinois Wildlife Conservation Plan 33 The State of Illinois maintains a Comprehensive Wildlife Conservation Plan and Strategy 34 (IDNR 2005), which is implemented by the IDNR and numerous Federal, State, local, and 35 private partners. The plan addresses long-range landscape-level planning initiatives, which 36 include projects to address declining wildlife populations and conservation and restoration of 37 ecologically important, sensitive, and rare habitats. Part of the plan includes the Conservation 38 Reserve Enhancement Program, which is a voluntary program to assist landowners in 39 protecting environmentally sensitive land, decreasing erosion, restoring wildlife habitat, 40 increasing populations of threatened and endangered species, and safeguarding groundwater 41 and surface water in the Illinois River Basin (IDNR 2005). Commitment to this plan will help 42 protect or restore aquatic habitats and continue to support a diversity of aquatic life in the future. 43 4.16.5.5 Conclusion 44 The stresses from past river flow alterations, increasing urbanization, and demand for water 45 resources across the geographic area of interest depend on many factors that the NRC staff 46 cannot quantify but that are likely to noticeably alter aquatic resources when all stresses on the 4-125

Environmental Consequences and Mitigating Actions 1 aquatic communities are assessed cumulatively. Continued protection of aquatic habitats 2 through wildlife preserves, parks, and recreational areas, as well as the implementation of the 3 Illinois Wildlife Conservation Plan, will likely mitigate some of these effects, and, therefore, the 4 NRC staff finds it reasonable to assume that these activities will ensure that future actions do 5 not destabilize important attributes of the aquatic resources in the vicinity of LSCS. Accordingly, 6 the NRC staff concludes that the cumulative impacts from the proposed license renewal and 7 other past, present, and reasonably foreseeable projects would be MODERATE. 8 4.16.6 Historic and Cultural Resources 9 This section addresses the direct and indirect effects of license renewal on historic and cultural 10 resources when added to the aggregate effects of other past, present, and reasonably 11 foreseeable future actions. The geographic area considered in this analysis is the APE 12 associated with the proposed undertaking, as described in Section 3.9. 13 The archaeological record for the region indicates prehistoric and historic occupation of the 14 LSCS site and its immediate vicinity. Given the location of identified cultural resources, the 15 construction of LSCS may have resulted in destruction of cultural resources within the LSCS 16 site and its immediate vicinity. 17 Other land uses in the vicinity of LSCS may have resulted in impacts on and the loss of, cultural 18 resources on the LSCS site and its immediate vicinity. However, there remains the possibility 19 for additional historic or cultural resources to be located within the LSCS site. The present and 20 reasonably foreseeable projects that could affect these resources, reviewed in conjunction with 21 license renewal, are noted in Appendix E of this document. Direct impacts would occur if 22 historic and cultural resources in the APE were physically removed or disturbed. It is unlikely 23 that the projects discussed in Appendix E would impact historic and cultural resources on the 24 LSCS site because those resources are not in areas that would be subject to foreseeable future 25 development. 26 As described in Section 4.9 of this document, no known cultural resources would be adversely 27 affected by LSCS license renewal activities, as no associated changes or ground-disturbing 28 activities will occur (Exelon 2014a). Moreover, as discussed in Section 4.9, Exelon has 29 established draft procedures to ensure cultural resources are considered in project planning 30 during operation of LSCS. 31 The NRC staff concludes that the cumulative impact of the proposed license renewal on historic 32 and cultural resources, when combined with other past, present, and reasonably foreseeable 33 future activities, would be SMALL. 34 4.16.7 Socioeconomics 35 This section addresses socioeconomic factors that have the potential to be directly or indirectly 36 affected by changes in operations at LSCS, in addition to the aggregate effects of other past, 37 present, and reasonably foreseeable future actions. The primary geographic area of interest 38 considered in this cumulative analysis includes LaSalle, Grundy, and Will Counties, where 39 approximately 83 percent of LSCS employees reside (see Table 3-15). This is where the 40 economy, tax base, and infrastructure would most likely be affected because the majority of 41 LSCS workers and their families reside, spend their incomes, and use their benefits within these 42 counties. 43 As discussed in Section 4.10, continued operation of LSCS during the license renewal term 44 would have no impact on socioeconomic conditions in the region beyond what is already being 45 experienced. Since Exelon has no plans to hire additional workers during the license renewal 4-126

Environmental Consequences and Mitigating Actions 1 term, overall expenditures and employment levels at LSCS would remain relatively unchanged 2 with no new or increased demand for housing and public services. Based on this and other 3 information presented in Chapter 4, there would be no contributory effect on socioeconomic 4 conditions in the region during the license renewal term from the continued operation of LSCS 5 beyond what is currently being experienced. Therefore, the only contributory effects would 6 come from reasonably foreseeable future planned activities at LSCS, unrelated to the proposed 7 action (license renewal), and other reasonably foreseeable planned offsite activities. For 8 example, offsite residential development is planned throughout the LSCS region. The 9 availability of new housing could attract individuals and families from outside the region, 10 increasing the local population and causing increased traffic on local roads, as well as increased 11 demand for public services. 12 When combined with other past, present, and reasonably foreseeable future activities, the 13 contributory effects of continued reactor operations at LSCS would have no new or increased 14 impact on socioeconomic conditions in the region beyond what is currently being experienced. 15 4.16.8 Human Health 16 The NRC and EPA established radiological dose limits for protection of the public and workers 17 from both acute and long-term exposure to radiation and radioactive materials. These dose 18 limits are codified in 10 CFR Part 20 and 40 CFR Part 190. As discussed in Section 4.11.1, the 19 NRC staff concluded that impacts to human health from continued plant operations are SMALL. 20 For the purposes of this analysis, the geographical area considered is the area included within 21 an 80-km (50-mi) radius of the LSCS plant site. There are four other nuclear power plants 22 within the applicable geographical area: Braidwood Station, Units 1 and 2, and Dresden 23 Nuclear Power Station, Units 2 and 3. Also, LSCSs 80-km (50-mi) radius overlaps with the 24 80-km (50-mi) radii of Byron Station, Units 1 and 2; Quad Cities Nuclear Power Station, Units 1 25 and 2; and Clinton Power Station, Unit 1. As discussed in Section 3.1.4.4, in addition to storing 26 its spent nuclear fuel in a storage pool, LSCS stores some of its spent nuclear fuel in an onsite 27 independent spent fuel storage installation (ISFSI). 28 EPA regulations in 40 CFR Part 190 limit the dose to members of the public from all sources in 29 the nuclear fuel cycle, including nuclear power plants, fuel fabrication facilities, waste disposal 30 facilities, and transportation of fuel and waste. As discussed in Section 3.1.4.5, LSCS has a 31 REMP that measures radiation and radioactive materials in the environment from LSCS, its 32 ISFSI, and all other sources. The NRC staff reviewed the radiological environmental monitoring 33 results for the 5-year period from 2010 to 2014 as part of the cumulative impacts assessment. 34 The NRC staffs review of Exelons data showed no indication of an adverse trend in 35 radioactivity levels in the environment from LSCS or its ISFSI. The data showed that there was 36 no measurable impact to the environment from operations at LSCS. 37 The NRC staff concludes that the cumulative radiological impacts of the proposed license 38 renewal, when combined with other past, present, and reasonably foreseeable future activities, 39 would be SMALL. This is based on the NRC staffs review of REMP data, radioactive effluent 40 release data, worker dose, and LSCSs expected continued compliance with Federal radiation 41 protection standards during continued operation, and regulation of any future development or 42 actions in the vicinity of the LSCS site by the NRC and the State of Illinois. 43 4.16.9 Environmental Justice 44 The environmental justice cumulative impact analysis evaluates the potential for 45 disproportionately high and adverse human health and environmental effects on minority and 46 low-income populations that could result from past, present, and reasonably foreseeable future 4-127

Environmental Consequences and Mitigating Actions 1 actions, including the continued operational effects of LSCS during the renewal term. Everyone 2 living near LSCS currently experiences its operational effects, including minority and low-income 3 populations. The NRC addresses environmental justice matters for license renewal by 4 identifying the location of minority and low-income populations, determining whether there would 5 be any potential human health or environmental effects to these populations, and determining if 6 any of the effects may be disproportionately high and adverse. 7 Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal adverse 8 impacts on human health. Disproportionately high and adverse human health effects occur 9 when the risk or rate of exposure to an environmental hazard for a minority or low-income 10 population is significant and exceeds the risk or exposure rate for the general population or for 11 another appropriate comparison group. Disproportionately high environmental effects refer to 12 impacts or risks of impacts on the natural or physical environment in a minority or low-income 13 community that are significant and appreciably exceed the environmental impact on the larger 14 community. Such effects may include biological, cultural, economic, or social impacts. Some of 15 these potential effects have been identified in resource areas presented in preceding sections of 16 Chapter 4 in this SEIS. As previously discussed in this chapter, the impact from license renewal 17 for all resource areas (e.g., land, air, water, ecology, and human health) would be SMALL. 18 As discussed in Section 4.12 of this SEIS, there would be no disproportionately high and 19 adverse impacts on minority and low-income populations from the continued operation of LSCS 20 during the license renewal term. Since Exelon has no plans to hire additional workers during 21 the license renewal term, employment levels at LSCS would remain relatively constant, and 22 there would be no additional demand for housing or increased traffic. Based on this information 23 and the analysis of human health and environmental impacts presented in the preceding 24 sections, it is not likely there would be any disproportionately high and adverse contributory 25 effect on minority and low-income populations from the continued operation of LSCS during the 26 license renewal term. Therefore, the only contributory effects would come from the other 27 reasonably foreseeable future planned activities at LSCS, unrelated to the proposed action 28 (license renewal), and other reasonably foreseeable planned offsite activities. 29 Conclusion 30 Exelon has no reasonably foreseeable future planned activities at LSCS beyond continued 31 reactor operations. When combined with other past, present, and reasonably foreseeable future 32 activities, the ongoing contributory effects of continued reactor operations at LSCS would not 33 likely cause disproportionately high and adverse human health and environmental effects on 34 minority and low-income populations residing in the vicinity of LSCS beyond what is currently 35 being experienced. 36 4.16.10 Waste Management 37 This section describes waste management impacts during the license renewal term when added 38 to the aggregate effects of other past, present, and reasonably foreseeable future actions. For 39 the purpose of this cumulative impacts analysis, the area within a 50-mi (80-km) radius of LSCS 40 was considered. The NRC staff concluded, in Section 4.11, that the potential human health 41 impacts from LSCSs waste during the license renewal term would be SMALL. 42 As discussed in Sections 3.1.4 and 3.1.5, Exelon maintains waste management programs for 43 radioactive and nonradioactive waste generated at LSCS and is required to comply with Federal 44 and State permits and other regulatory requirements for the management of waste material. 45 The nuclear power plants and other facilities within a 50-mi (80-km) radius of LSCS are also 46 required to comply with appropriate NRC, EPA, and state requirements for the management of 47 radioactive and nonradioactive waste. Current waste management activities at LSCS would 4-128

Environmental Consequences and Mitigating Actions 1 likely remain unchanged during the license renewal term, and continued compliance with 2 Federal and State requirements for radioactive and nonradioactive waste is expected. 3 Based on the above, the NRC staff concludes that the potential cumulative impacts from 4 radioactive and nonradioactive waste during the license renewal term would be SMALL. 5 Continued compliance with Federal and State requirements for radioactive and nonradioactive 6 waste management by Exelon is expected. 7 4.16.11 Global Climate Change 8 This section addresses the impact of GHG emissions resulting from continued operation of 9 LSCS on global climate change when added to the aggregate effects of other past, present, and 10 reasonably foreseeable future actions. 11 The impacts of climate change on air, water, and ecological resources are discussed in 12 Section 4.15.3. Climate is influenced by both natural and human-induced factors; the observed 13 global warming (increase in Earths surface temperature) in the 21st century has been attributed 14 to the increase in GHG emissions resulting from human activities (USGCRP 2009). Climate 15 model projections indicate that future climate change is dependent on current and future GHG 16 emissions (IPCC 2007b; USGCRP 2009, 2014). As described in Section 4.15.3.1, operations at 17 LSCS emit GHG emissions. 18 The cumulative impact of a GHG emission source on climate is global. GHG emissions are 19 transported by wind and become well mixed in the atmosphere as a result of their long 20 atmospheric residence time. Therefore, the extent and nature of climate change is not specific 21 to where GHGs are emitted. In April 2015, EPA published the official U.S. inventory of GHG 22 emissions, which identifies and quantifies the primary anthropogenic sources and sinks of 23 GHGs. The EPA GHG inventory is an essential tool for addressing climate change and 24 participating with the United Nations Framework Convention on Climate Change to compare the 25 relative global contribution of different emission sources and GHGs to climate change. In 2013, 26 the United States emitted 6,673 teragrams (Tg) (6,673 million metric tons (MMT)) of carbon 27 dioxide equivalents (CO2eq), and from 1990 to 2013, emissions increased by 5.9 percent 28 (EPA 2015d). In 2012 and 2013, the total amount of CO2eq emissions related to electricity 29 generation was 2,022 Tg (2,022 MMT) and 2,039 Tg (2,039 MMT), respectively (EPA 2015d). 30 The Energy Information Administration (EIA) reported that, in 2013, electricity production alone 31 in Illinois was responsible for 94.1 MMT CO2eq (EIA 2015a). Facilities that emit 25,000 MT 32 CO2eq or more per year are required to annually report their GHG emissions to EPA. These 33 facilities are known as direct emitters, and the data are publicly available in EPAs facility-level 34 information on GHGs tool (FLIGHT). In 2013, FLIGHT identified 11 facilities in LaSalle County, 35 Illinois, where LSCS is located, that emitted a total of 0.89 MT CO2eq (EPA 2015c). In 2012, 36 FLIGHT identified 290 facilities in Illinois that emitted a total of 134 MMT CO2eq (EPA 2015c). 37 Appendix E provides a list of current and reasonably foreseeable future projects and actions 38 that could contribute to GHG emissions. Permitting and licensing requirements and other 39 mitigative measures can minimize the impacts of GHG emissions. For instance, in 2012, EPA 40 issued a final GHG Tailoring Rule (77 FR 41051) to address GHG emissions from stationary 41 sources under the CAA permitting requirements; the GHG Tailoring Rule establishes when an 42 emission source will be subject to permitting requirements and control technology to reduce 43 GHG emissions. On June 25, 2013, President Obama set forward a plan to reduce carbon 44 pollution. The Climate Action Plan will reduce carbon pollution, prepare the United States for 45 the impacts of climate change, and lead international efforts to combat global climate change. 46 The Clean Power Plan Final Rule (80 FR 64661-65120), aimed at reducing carbon pollution 47 from power plants, requires carbon emissions from the power sector to be 32 percent below 4-129

Environmental Consequences and Mitigating Actions 1 2005 levels (870 million tons less). The Clean Power Plan sets forth carbon dioxide emission 2 performance rate standards for power plants that should be achieved by 2030. Future actions 3 and steps taken to reduce GHG emissions can lessen the impacts on climate change. 4 EPAs U.S. inventory of GHG emissions illustrates the diversity of GHG sources, such as 5 electricity generation, industrial processes, and agriculture. As presented in Section 4.15.3, 6 direct GHG emissions from combustion sources resulting from operations at LSCS range from 7 245 to 1,022 MT CO2eq, and total emissions range from 34,228 to 39,997 MT CO2eq. In 8 comparing LSCSs GHG emission contribution to different emissions sources, whether it be total 9 U.S. GHG emissions, emissions from electricity production in Illinois, or emissions on a county 10 level, GHG emissions from LSCS are minor relative to these inventories; this is evident, as 11 presented in Table 4-23. The emissions impact of a single source on climate change requires 12 that a climate model account for that specific emissions source in order to project the magnitude 13 and extent of climate change. Climate models indicate that short-term climate change (through 14 the year 2030) is dependent on past GHG emissions. Therefore, climate change is projected to 15 occur with or without present and future GHG emissions from LSCS. The NRC staff concludes 16 that the incremental impact from the contribution of GHG emissions from continued operation of 17 LSCS on climate change would be SMALL. 18 Due to the global significance of GHG emissions, this global climate change cumulative impacts 19 analysis considers the entire Earths atmosphere and therefore global emissions (as opposed to 20 county, state, or national emissions). As discussed in Section 4.15.3.2, climate change and 21 climate-related environmental changes have been observed on a global level, and climate 22 models indicate that future climate change will depend on present and future GHG emissions. 23 With continued increases in GHG emission rates, climate models project that Earths average 24 surface temperature will continue to increase and climate-related changes will persist. 25 Therefore, the cumulative impact of GHG emissions on climate change is noticeable but not 26 destabilizing. The NRC staff concludes that the cumulative impacts of GHG emissions from 27 past, present, and reasonably foreseeable future actions are MODERATE. However, as 28 discussed above, the incremental addition of GHG emissions from continued operation of 29 LSCS, when compared to global emissions, are minor. 30 Table 4-23. Comparison of GHG Emission Inventories Source CO2eq MMT/year Global Fossil Fuel Combustion Emissions (2013) (a) 36,000 U.S. Emissions (2013)(b) 6,673 Illinois (2013)(c) 134 LaSalle County, Illinois (2013)(c) 0.89 LSCS(d) 0.04 (a) Source: GCP 2014 (b) Source: EPA 2015d (c) GHG emissions account only for direct emitters, those facilities that emit 25,000 MT or more a year (EPA 2015c). (d) Emissions rounded from and obtained from Exelon 2015c. 31 4.16.12 Summary of Cumulative Impacts 32 The NRC staff considered the potential impacts resulting from the operation of LSCS during the 33 period of extended operation and other past, present, and reasonably foreseeable future actions 4-130

Environmental Consequences and Mitigating Actions 1 near LSCS. The preliminary determination is that the potential cumulative impacts would range 2 from SMALL to LARGE, depending on the resource. Table 4-24 summarizes the cumulative 3 impacts on resource areas. 4 Table 4-24. Summary of Cumulative Impacts on Resource Areas Resource Area Cumulative Impact Air Quality and Past, present, and reasonably foreseeable future activities exist in the geographic Noise areas of interest (local for noise; local and regional for criteria pollutants) that could affect air quality and noise resources. However, the incremental contribution of impacts on air quality and noise resources from plant operations at LSCS would be minimal. The NRC staff concludes that cumulative impacts from LSCS related actions and other past, present, and reasonably foreseeable future actions on air quality and noise resources in the geographic areas of interest would be SMALL. Geology and Any use of geologic materials, such as aggregates to support operation and Soils maintenance activities, would be procured from local and regional sources. These materials are abundant in the region, and geologic conditions are not expected to change during the license renewal term. Thus, activities associated with continued operations are not expected to affect the geologic environment. Considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes that the cumulative impacts on geology and soils during the LSCS license renewal term would be SMALL. Water No increase in LSCS consumptive water use is expected during the license renewal Resources term. Surface water availability is expected to continue to be sufficient through the license renewal term, and surface water withdrawals and associated consumptive water use for LSCS operations are expected to remain a small percentage of the flow through the Marseilles Pool of the Illinois River. LaSalle County has an adequate supply of groundwater for industrial, municipal and domestic purposes, and ongoing operations at LSCS have not affected groundwater quality. Therefore, considering ongoing activities and reasonably foreseeable actions, the NRC staff concludes that cumulative impact of the proposed license renewal, combined with other past, present, and reasonably foreseeable future activities, would be SMALL on surface water and groundwater resources. Terrestrial NRC staff concludes that the cumulative impacts on terrestrial resources in the vicinity Ecology of the LSCS site are MODERATE to LARGE based on past, present, and reasonably foreseeable future actions. This level of impact is primarily the result of past habitat alteration and loss on the LSCS site and within the larger region. The environmental effects of these actions are clearly noticeable and have destabilized important attributes of certain terrestrial communities. The incremental, site-specific impact from the continued operation of LSCS during the license renewal period would be an unnoticeable or minor contributor to cumulative impacts on terrestrial resources. Aquatic Ecology The stresses from past river flow alterations, increasing urbanization, and demand for water resources across the geographic area of interest depend on many factors that NRC staff cannot quantify, but that are likely to noticeably alter aquatic resources when all stresses on the aquatic communities are assessed cumulatively. Continued protection of aquatic habitats through wildlife preserves, parks, and recreational areas, as well as the implementation of the Illinois Wildlife Conservation Plan will likely mitigate some of these effects, and, therefore, the NRC staff finds it reasonable to assume that these activities will ensure that future actions do not destabilize important attributes of the aquatic resources in the vicinity of LSCS. Accordingly, the NRC staff concludes that the cumulative impacts from the proposed license renewal and other past, present, and reasonably foreseeable projects would be MODERATE. 4-131

Environmental Consequences and Mitigating Actions Resource Area Cumulative Impact Historical No known cultural resources would be adversely affected by LSCS license renewal and Cultural activities as no associated changes or ground-disturbing activities would occur. Resources Exelon has established draft procedures to ensure cultural resources are considered in project planning during operation of LSCS. Therefore, the NRC staff concludes that the cumulative impact of the proposed license renewal when combined with other past, present, and reasonable foreseeable future activities on historic and cultural resources would be SMALL. Socioeconomics When combined with other past, present, and reasonably foreseeable future activities, the contributory effects from the continued operation of LSCS during the license renewal period would have no new or increased impact on socioeconomic conditions beyond what is currently being experienced. Human Health The NRC staff concludes that the cumulative radiological impacts of the proposed LSCS license renewal, when combined with other past, present, and reasonably foreseeable future activities, would be SMALL. Environmental The NRC staff concludes that the contributory effects of continued reactor operations Justice at LSCS, when combined with other past, present, and reasonably foreseeable future activities considered, would not likely cause disproportionately high and adverse human health and environmental effects on minority and low-income populations residing in the vicinity of LSCS. Waste NRC staff concludes that the potential cumulative impacts from radioactive and Management nonradioactive waste during the license renewal term would be SMALL. Continued compliance with Federal and State requirements for radioactive and nonradioactive waste management by Exelon is expected. Global Climate Climate change and climate-related changes have been observed on a global level, Change and climate models indicate that future climate change will depend on present and future GHG emissions. Climate models project that Earths average surface temperature will continue to increase and climate-related changes will persist. Therefore, the cumulative impact of GHG emissions on climate change during the LSCS license renewal timeframe would be noticeable but not destabilizing. The NRC staff concludes that the cumulative impacts from the proposed license renewal and other past, present, and reasonably foreseeable projects would be MODERATE. 1 4.17 Resource Commitments 2 4.17.1 Unavoidable Adverse Environmental Impacts 3 Unavoidable adverse environmental impacts are impacts that would occur after implementation 4 of all workable mitigation measures. Carrying out any of the energy alternatives considered in 5 this SEIS, including the proposed action, would result in some unavoidable adverse 6 environmental impacts. 7 Minor unavoidable adverse impacts on air quality would occur, due to emission and release of 8 various chemical and radiological constituents from power plant operations. Nonradiological 9 emissions resulting from power plant operations are expected to comply with EPA emissions 10 standards, although the alternative of operating a fossil-fueled power plant in some areas may 11 worsen existing attainment issues. Chemical and radiological emissions would not exceed the 12 national emission standards for hazardous air pollutants. 13 During nuclear power plant operations, workers and members of the public would face 14 unavoidable exposure to radiation and hazardous and toxic chemicals. Workers would be 4-132

Environmental Consequences and Mitigating Actions 1 exposed to radiation and chemicals associated with routine plant operations and the handling of 2 nuclear fuel and waste material. Workers would have higher levels of exposure than members 3 of the public, but doses would be administratively controlled and would not exceed standards or 4 administrative control limits. In comparison, the alternatives involving the construction and 5 operation of a non-nuclear power generating facility would also result in unavoidable exposure 6 to hazardous and toxic chemicals to workers and the public. 7 The generation of spent nuclear fuel and waste material, including low-level radioactive waste, 8 hazardous waste, and nonhazardous waste, would be unavoidable. Hazardous and 9 nonhazardous wastes would be generated at non-nuclear power generating facilities. Wastes 10 generated during plant operations would be collected, stored, and shipped for suitable 11 treatment, recycling, or disposal in accordance with applicable Federal and state regulations. 12 Due to the costs of handling these materials, power plant operators would be expected to carry 13 out all activities and optimize all operations in a way that generates the smallest amount of 14 waste possible. 15 4.17.2 Short-Term Versus Long-Term Productivity 16 The operation of power generating facilities would result in short-term uses of the environment, 17 as described in Chapter 4. Short term is the period of time that continued power generating 18 activities take place. 19 Power plant operations require short-term use of the environment and commitment of resources 20 (e.g., land and energy), indefinitely or permanently. Certain short-term resource commitments 21 are substantially greater under most energy alternatives, including license renewal, than under 22 the no-action alternative because of the continued generation of electrical power and the 23 continued use of generating sites and associated infrastructure. During operations, all energy 24 alternatives entail similar relationships between local short-term uses of the environment and 25 the maintenance and enhancement of long-term productivity. 26 Air emissions from power plant operations introduce small amounts of radiological and 27 nonradiological constituents to the region around the plant site. Over time, these emissions 28 would result in increased concentrations and exposure, but they are not expected to impact air 29 quality or radiation exposure to the extent that public health and long-term productivity of the 30 environment would be impaired. 31 Continued employment, expenditures, and tax revenues generated during power plant 32 operations directly benefit local, regional, and state economies over the short term. Local 33 governments investing project-generated tax revenues into infrastructure and other required 34 services could enhance economic productivity over the long term. 35 The management and disposal of spent nuclear fuel, low-level radioactive waste, hazardous 36 waste, and nonhazardous waste requires an increase in energy and consumes space at 37 treatment, storage, or disposal facilities. Regardless of the location, the use of land to meet 38 waste disposal needs would reduce the long-term productivity of the land. 39 Power plant facilities are committed to electricity production over the short term. After 40 decommissioning these facilities and restoring the area, the land could be available for other 41 future productive uses. 42 4.17.3 Irreversible and Irretrievable Commitments of Resources 43 This section describes the irreversible and irretrievable commitments of resources that have 44 been noted in this SEIS. Resources are irreversible when primary or secondary impacts limit 4-133

Environmental Consequences and Mitigating Actions 1 the future options for a resource. An irretrievable commitment refers to the use or consumption 2 of resources that are neither renewable nor recoverable for future use. Irreversible and 3 irretrievable commitments of resources for electrical power generation include the commitment 4 of land, water, energy, raw materials, and other natural and man-made resources required for 5 power plant operations. In general, the commitments of capital, energy, labor, and material 6 resources are also irreversible. 7 The implementation of any of the energy alternatives considered in this SEIS would entail the 8 irreversible and irretrievable commitments of energy, water, chemicals, andin some cases 9 fossil fuels. These resources would be committed during the license renewal term and over the 10 entire life cycle of the power plant, and they would be unrecoverable. 11 Energy expended would be in the form of fuel for equipment, vehicles, and power plant 12 operations and electricity for equipment and facility operations. Electricity and fuel would be 13 purchased from offsite commercial sources. Water would be obtained from existing water 14 supply systems. These resources are readily available, and the amounts required are not 15 expected to deplete available supplies or exceed available system capacities. 16 4.18 References 17 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, Standards for 18 protection against radiation. 19 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 20 production and utilization facilities. 21 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 22 protection regulations for domestic licensing and related regulatory functions. 23 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 24 renewal of operating licenses for nuclear power plants. 25 10 CFR Part 100. Code of Federal Regulations, Title 10, Energy, Part 100, Reactor site 26 criteria. 27 36 CFR 60.4. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, Part 28 60, National Register of Historic Places, Section 60.4, Criteria for evaluation. 29 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property. 30 Part 800, Protection of Historic Properties. 31 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 32 Requirements for preparation, adoption, and submittal of implementation plans. 33 40 CFR Part 60. Code of Federal Regulations, Title 40, Protection of Environment, Part 60, 34 Standards of Performance for New Stationary Sources. 35 40 CFR Part 63. Code of Federal Regulations, Title 40, Protection of Environment, Part 63, 36 National emission standards for hazardous air pollutants for source categories. 37 40 CFR Part 75. Code of Federal Regulations, Title 40, Protection of Environment, Part 75, 38 Continuous emission monitoring. 39 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 40 Designation of areas for air quality planning purposes. 41 40 CFR Part 125. Code of Federal Regulations, Title 40, Protection of Environment, Part 125, 42 Criteria and standards for the National Pollutant Discharge Elimination System. 4-134

Environmental Consequences and Mitigating Actions 1 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 2 Environmental radiation protection standards for nuclear power operations. 3 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 4 Interagency cooperationEndangered Species Act of 1973, as amended. 5 49 FR 34658. U.S. Nuclear Regulatory Commission. Waste confidence decision and 6 requirements for licensee actions regarding the disposition of spent fuel upon expiration of 7 reactor operating licenses; Final Rules. Federal Register 49 (171): 34658-34696. 8 August 31, 1984. 9 55 FR 38472. U.S. Nuclear Regulatory Commission. Consideration of environmental impacts 10 of temporary storage of spent fuel after cessation of reactor operation; and waste confidence 11 decision review; Final Rules. Federal Register 55 (181): 38472-38514. September 18, 1990. 12 59 FR 7629. Executive Order No. 12898. Federal actions to address environmental justice in 13 minority populations and low-income populations. Federal Register 59 (32): 7629-7634. 14 February 16, 1994. 15 61 FR 28467. U.S. Nuclear Regulatory Commission. Environmental review for renewal of 16 nuclear power plant operating licenses. Final Rule. Federal Register 61 (109): 28467-28497. 17 June 5, 1996. 18 61 FR 66537. U.S. Nuclear Regulatory Commission. Environmental review for renewal of 19 nuclear power plant operating licenses. Federal Register 61 (244): 66537-66544. 20 December 18, 1996. 21 64 FR 68005. U.S. Nuclear Regulatory Commission. Waste confidence decision review: 22 status. Federal Register 64 (233): 68005-68007. December 6, 1999. 23 65 FR 79825. U.S. Environmental Protection Agency. Regulatory finding on the emissions of 24 hazardous air pollutants from electric utility steam generating units. Federal Register 65 (245): 25 79825-79831. December 20, 2000 26 74 FR 38117. U.S. Nuclear Regulatory Commission. Revisions to environmental review for 27 renewal of nuclear power plant operating licenses. Proposed Rule. Federal Register 74 (146): 28 38117-38140. July 31, 2009. 29 74 FR 56260. U.S. Environmental Protection Agency. Mandatory Reporting of Greenhouse 30 Gases. Federal Register 74 (209): 56260-56519. October 30, 2009. 31 74 FR 66496. U.S. Environmental Protection Agency. 2009. Endangerment and cause or 32 contribute findings for greenhouse gases under Section 202(a) of the Clean Air Act. 33 Federal Register 74 (239): 66496-66546. December 15, 2009. 34 75 FR 81032. U.S. Nuclear Regulatory Commission. Consideration of environmental impacts 35 of temporary storage of spent fuel after cessation of reactor operation. 36 Federal Register 75 (246): 81032-81037. December 23, 2010. 37 75 FR 81037. U.S. Nuclear Regulatory Commission. Waste confidence decision update. 38 Federal Register 75 (246): 81037-81076. December 23, 2010. 39 76 FR 48208. U.S. Environmental Protection Agency. Federal Implementation Plans: 40 Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals. 41 Federal Register 76 (152): 48208-48483 4-135

Environmental Consequences and Mitigating Actions 1 77 FR 9304. Environmental Protection Agency. National emission standards for hazardous air 2 pollutants from coal- and oil-fired electric utility steam generating units and standards of 3 performance for fossil-fuel-fired electric utility, industrial commercial institutional, and small 4 industrial commercial institutional generating units. Federal Register 77 (32): 9304-9513. 5 77 FR 41051. Environmental Protection Agency. Prevention of significant deterioration and 6 Title V greenhouse gas tailoring rule step 3 and GHG plantwide applicability limits. 7 Federal Register 77 (134): 41051-41075. 8 78 FR 37282. U.S. Nuclear Regulatory Commission. Revisions to environmental review for 9 renewal of nuclear power plant operating licenses. Federal Register 78 (119): 37282-37324. 10 June 20, 2013. 11 79 FR 1430. U.S. Environmental Protection Agency. Standards of Performance for 12 Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units. 13 Federal Register 79 (5): 1430-1519. January 8, 2014. 14 79 FR 48300. U.S. Environmental Protection Agency. National Pollutant Discharge 15 Elimination SystemFinal Regulations to Establish Requirements for Cooling Water Intake 16 Structures at Existing Facilities and Amend Requirements at Phase I Facilities. 17 Federal Register 79 (158): 48300-48439. August 15, 2014. 18 79 FR 56263. U.S. Nuclear Regulatory Commission. Generic environmental impact statement 19 for continued storage of spent nuclear fuel. Federal Register 79 (182): 56263-56264. 20 September 19, 2014. 21 79 FR 56238. U.S. Nuclear Regulatory Commission. Continued storage of spent nuclear fuel. 22 Federal Register 79 (182): 56238-56263. September 19, 2014. 23 79 FR 73705. U.S. Fish and Wildlife Service. 2014. Endangered and threatened wildlife and 24 plants; threatened species status for the rufa red knot. Federal Register 79 (238): 25 73705-73748. December 11, 2014. 26 80 FR 46062. U.S. Nuclear Regulatory Commission. Exelon Generation Company, LLC; LaSalle 27 County Station, Units 1 and 2; Environmental assessment and finding of no significant impact; 28 issuance. Federal Register 80 (148): 46062-46066. August 3, 2015. 29 80 FR 64661. U.S. Environmental Protection Agency. Carbon Pollution Emission Guidelines 30 for Existing Stationary Sources: Electric Utility Generating Units. Federal Register 80 (205): 31 64661-65120. October 23, 2015. 32 35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Part 302, Water 33 Quality Standards. 34 415 ILCS 5/Tit. VI. Illinois Compiled Statutes. Chapter 415, 5, Noise. 35 54 USC 300101. United States Code. Title 54, National Park Service and Related Programs, 36 Section 300101 et seq., National Historic Preservation Act. 37 [AMS] American Meteorological Society. 2015. State of the Climate in 2014. Special 38 Supplement to the Bulletin of American Meteorological Society Vol. 96, No. 7, July 2015. 39 Available at <https://www2.ametsoc.org/ams/index.cfm/publications 40 /bulletin-of-the-american-meteorological-society-bams/state-of-the-climate/> (accessed 41 4 August 2015). 4-136

Environmental Consequences and Mitigating Actions 1 Arnold TL, Sullivan DJ, Harris MA, Fitzpatrick FA, Scudder BC, Ruhl PM, Hanchar DW, 2 Stewart JS. 1999. Environmental Setting of the Upper Illinois River Basin and Implications for 3 Water Quality. Urbana, IL: U.S. Geological Survey, WRD. Water-Resources Investigations 4 Report 98-4268. Available at 5 <http://il.water.usgs.gov/nawqa/uirb/pubs/reports/WRIR_98-4268.pdf> 6 (accessed 21 August 2015). 7 Burch, SL. 2002. A Comparison of Potentiometric Surfaces for the Cambrian-Ordovician 8 Aquifers of Northeastern Illinois, 1995 and 2000. Data/Case Study 2002-02, Illinois State 9 Water Survey. 2002. Available at 10 <http://www.isws.illinois.edu/pubdoc/dcs/iswsdcs2002-02.pdf> (accessed 16 June 2015). 11 Burch, SL. 2008. A Comparison of Potentiometric Surfaces for the Cambrian-Ordovician 12 Aquifers of Northeastern Illinois, 2000 and 2007, Data/Case Study 2008-04, Illinois State Water 13 Survey. 2008. Available at <http://www.isws.illinois.edu/pubdoc/DCS/ISWSDCS2008-04.pdf> 14 (accessed 16 June 2015). 15 [CDC] Centers for Disease Control and Prevention. 2013. Pathogen & Environment: 16 Naegleria fowleri - Primary Amebic Meningoencephalitis (PAM). Updated November 6, 2013. 17 Available at <http://www.cdc.gov/parasites/naegleria/pathogen.html> 18 (accessed 3 January 2014). 19 [CECO] Commonwealth Edison Company. 1994. LaSalle County Nuclear Power Station, 20 Individual Plant Examination and Individual Plant Examination (External Events). April 1994. 21 [CEQ] Council on Environmental Quality. 1997. Considering Cumulative Effects under the 22 National Environmental Policy Act. Executive Office of the President, Washington, DC. 122 p. 23 Available at 24 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/G-CEQ-ConsidCumulEff 25 ects.pdf> (accessed 21 August 2015). 26 Chen IC, Hill JK, Ohlemuller R, Roy DB, Thomas CD. 2011. Rapid range shifts of species 27 associated with high levels of climate warming. Science 333(6045): 1024-1026. 28 Clean Air Act of 1970, as amended (CAA). 42 U.S.C. 7410 et seq. 29 Consolidated Appropriations Act of 2008. 121 Stat. 1844. 30 Daily Herald. 2010. Illinois Emerges as One of the Countrys Leaders in Wind Energy. 31 Available at <http://prev.dailyherald.com/story/?id=345484> (accessed August 2015). 32 Dale VH. 1997. The relationship between land-use change and climate change. Ecological 33 Applications 7(3): 753-769. 34 [DOE] U.S. Department of Energy. 2010a. Kemper County IGCC Project Final Environmental 35 Impact Statement. DOE/EIS-0409. May 2010. Available at 36 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/EIS-0409-FEIS-01-2010. 37 pdf> (accessed 3 August 2015). 38 [DOE] U.S. Department of Energy. 2010b. Final Environmental Assessment for Department of 39 Energy Loan Guarantee for the Agua Caliente Solar Project in Yuma County, Arizona. 40 DOE/EA-1797. November. Available at 41 <http://energy.gov/nepa/downloads/ea-1797-final-environmental-assessment> 42 (accessed 3 August 2015). 4-137

Environmental Consequences and Mitigating Actions 1 Dziegielewski B, Yang X, Bik T, Margono H, Richey M. 2005. County-Level Forecasts of Water 2 Use in Illinois: 2005-2025: Project Completion Report. Carbondale, IL: Southern Illinois 3 University Carbondale. March 30, 2005. 211 p. Available at 4 <http://www.isws.illinois.edu/wsp/waterdemand.asp> (accessed 5 September 2015). 5 [EA] EA Engineering, Science, and Technology, Inc. 2000. Final Report LaSalle Station 6 Aquatic Monitoring 1999, RM 249.7-248.8. Prepared for Commonwealth Edison Company, 7 Marseilles, Illinois. September 2000. Deerfield, Illinois. ADAMS No. ML15273A420. 8 [EA] EA Engineering, Science, and Technology, Inc. 2014. LaSalle County Station 2013 Fish 9 and Benthos Monitoring and Historical Fish and Benthos Comparisons. Prepared for Exelon 10 Generation Company, LLC, Kennett Square, Pennsylvania. May 2014. Deerfield, Illinois. 11 ADAMS No. ML15273A419. 12 [EA] EA Engineering, Science, and Technology, Inc. 2015. Final Impingement and Entrainment 13 Characterization Study LaSalle County Station. Prepared for Exelon Generation Company, 14 LLC, Kennett Square, Pennsylvania. August 2015. Deerfield, Illinois. ADAMS 15 No. ML15243A204. 16 [EIA] U.S. Energy Information Administration. 2011. International Energy Outlook 2011. 17 Washington, DC: EIA. DOE/EIA-0484(2011). September 2011. 301 p. Available at 18 <http://www.eia.gov/forecasts/archive/ieo11/pdf/0484(2011).pdf> (accessed August 2015). 19 [EIA] U.S. Energy Information Administration. 2015a. Electricity, 1990-2013, U.S. Electric 20 Power Industry Estimated Emissions by State (EIA-767, EIA-906, EIA-920, EIA-923). 21 Available at <http://www.eia.gov/electricity/data/state/> (accessed August 2015). 22 [EIA] U.S. Energy Information Administration. 2015b. Frequently Asked Questions, What is 23 U.S. electricity generation by energy source? Available at 24 <http://www.eia.gov/tools/faqs/faq.cfm?id=427&t=3> (accessed August 2015) 25 [ESA] Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 26 [EPA] U.S. Environmental Protection Agency. 1998. Guidelines for Ecological 27 Risk Assessment. Washington, DC: EPA Risk Assessment Forum. EPA/630/R-95/002F. 28 188 p. Available at <http://www.epa.gov/raf/publications/pdfs/ECOTXTBX.PDF> 29 (accessed 27 March 2014). 30 [EPA] U.S. Environmental Protection Agency. 1999a. Alternative Disinfectants and Oxidants 31 Guidance Manual. Washington, DC: EPA Office of Water. EPA 815-R-99-014. 346 p. 32 Available at <http://www.epa.gov/ogwdw/mdbp/alternative_disinfectants_guidance.pdf> 33 (accessed 21 August 2015). 34 [EPA] U.S. Environmental Protection Agency. 1999b. Consideration of Cumulative Impacts in 35 EPA Review of NEPA Documents. EPA-315-R-99-002, Office of Federal Activities (2252A), 36 Washington, D.C. Available at 37 <http://www2.epa.gov/sites/production/files/2014-08/documents/cumulative.pdf> 38 (accessed 20 October 2015). 39 [EPA] U.S. Environmental Protection Agency. 2004. Technical Development Document for the 40 Final Section 316(b) Phase II Existing Facilities Rule. Washington, DC: EPA Office of Water. 41 EPA 821-R-04-007. February 12, 2004. 228 p. Available at 42 <http://water.epa.gov/lawsregs/lawsguidance/cwa/316b/upload/Cooling-Water_Phase-2_TDD_2 43 004.pdf> (accessed 3 June 2014). 4-138

Environmental Consequences and Mitigating Actions 1 [EPA] U.S. Environmental Protection Agency. 2009a. Endangerment and Cause or Contribute 2 Finding for Greenhouse Gases under Section 202(a) of the Clean Air Act. Available at 3 <http://www.epa.gov/climatechange/endangerment/> (accessed 4 August 2015). 4 [EPA] U.S. Environmental Protection Agency. 2009b. Assessment of the Impacts of Global 5 Change on Regional U.S. Air Quality: A synthesis of Climate Change Impacts on Ground-Level 6 Ozone. EPA/600/R-07/094F. April 2009. Available at 7 <http://ofmpub.epa.gov/eims/eimscomm.getfile?p_download_id=491176> 8 (accessed 4 August 2015). 9 [EPA] U.S. Environmental Protection Agency. 2014. Climate Change Indicators in the 10 United States, 2014. EPA-430-R-14-004. Available at 11 <http://www.epa.gov/climatechange/pdfs/climateindicators-full-2014.pdf> 12 (accessed 4 August 2015). 13 [EPA] U.S. Environmental Protection Agency. 2015a. Clean Air Act Permitting for Greenhouse 14 Gases. Available at <http://www.epa.gov/nsr/ghgpermitting.html> (accessed August 2015) 15 [EPA] U.S. Environmental Protection Agency. 2015b. Enforcement and Compliance History 16 Online, LaSalle County. Available at <http://echo.epa.gov/?redirect=echo> 17 (accessed August 2015). 18 [EPA] U.S. Environmental Protection Agency. 2015c. EPA Facility Level GHG Emissions Data, 19 Illinois and LaSalle County. Available at <http://ghgdata.epa.gov/ghgp/main.do> 20 (accessed August 2015). 21 [EPA] U.S. Environmental Protection Agency. 2015d. Inventory of U.S. Greenhouse Gas 22 Emissions and Sinks: 1990-2013. April 15, 2015. Available at 23 <http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2015-Main-T 24 ext.pdf> (accessed August 2015). 25 [EPA] U.S. Environmental Protection Agency. 2015e. Learn About New Source Review. 26 Available at <http://www2.epa.gov/nsr/learn-about-new-source-review> 27 (accessed 5 October 2015). 28 [EPA] U.S. Environmental Protection Agency. 2015f. New Source Review Basic Information 29 on PSD. Available at <http://www.epa.gov/NSR/psd.html> (accessed August 2015). 30 [Exelon] Exelon Generation Company, LLC. 2001. Letter from W. Riffer, Regulatory Assurance 31 Manager, LaSalle County Station to U.S. NRC, Document control Desk.

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32 Environmental Non-Routine Event Report for Exelon Generation Company, LLCLaSalle 33 County Station. August 17, 2001. ADAMS No. ML012330070. 34 [Exelon] Exelon Generation Company, LLC. 2002. Letter from G.T. Kaegi, Regulatory 35 Assurance Manager, LaSalle County Station to U.S. NRC, Document control Desk.

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36 Environmental Protection Plan and Operating Report Appendix B to Facility License 37 No. NPF-11 and NPF-18. April 29, 2002. ADAMS No. ML021330421. 38 [Exelon] Exelon Generation Company, LLC. 2009. Letter from D. Rhoads, Plant Manager, 39 LaSalle County Station to U.S. NRC, Document control Desk.

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Environmental 40 Non-Routine Event Report for Exelon Generation Company, LLCLaSalle County Station. 41 July 22, 2009. ADAMS No. ML092040381. 42 [Exelon] Exelon Generation Company, LLC. 2010. Letter from P.J. Karaba, Plant Manager, 43 LaSalle County Station to U.S. NRC, Document control Desk.

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Environmental 44 Non-Routine Event Report for Exelon Generation Company, LLCLaSalle County Station. 45 August 25, 2010. ADAMS No. ML102371289. 4-139

Environmental Consequences and Mitigating Actions 1 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 2 Operating License Renewal Stage LaSalle County Station, Unit 1 License No. NPF-11, Unit 2 3 License No. NPF-18. Chicago, Illinois: Exelon. December 9, 2014. ADAMS 4 Nos. ML14343A849, ML14343A883, and ML14343A897. 5 [Exelon] Exelon Generation Company, LLC. 2014b. LaSalle County Station, Updated Final 6 Safety Analysis Report (UFSAR). Revision 20, April 2014. ADAMS No. ML14113A099. 7 [Exelon] Exelon Generation Company, LLC. 2014c. Letter from M.P. Gallagher, Vice President 8 License Renewal Projects, Exelon, to Dan Heacock, Facility Evaluation Manager, Illinois 9 Environmental Protection Agency.

Subject:

Application for Clean Water Act Section 401 10 Certification Associated with Renewal of LaSalle County Stations Units 1 and 2 Operating 11 Licenses. February 4, 2014. In Appendix B of ADAMS No. ML14343A883. 12 [Exelon] Exelon Generation Company, LLC. 2015a. LaSalle County Station, Units 1 and 2, 13 Annual Radiological Environmental Operating Report, 1 January through 31 December 2014. 14 May 13, 2015. ADAMS No. ML15141A195. 15 [Exelon] Exelon Generation Company, LLC. 2015b. Letter from M.P. Gallagher, Vice 16 President, License Renewal Projects, to NRC Document Control Desk.

Subject:

Response to 17 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 18 Station, Units 1 and 2, License Renewal Application, Environmental Review. July 2, 2015. 19 ADAMS No. ML15195A351. 20 [Exelon] Exelon Generation Company, LLC. 2015c. Letter from M.P. Gallagher, Vice President 21 License Renewal Projects, to NRC Document Control Desk.

Subject:

Response to NRC 22 Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County Station, 23 Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: LaSalle 24 County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental Review 25 Requests for Additional Information. Response to Request for Additional Information MA-04. 26 July 2, 2015. ADAMS No. ML15195A347. 27 [Exelon] Exelon Generation Company, LLC. 2015d. Letter from M.P. Gallagher, Vice President 28 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 29 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 30 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 31 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 32 Review Requests for Additional Information. Response to Request for Additional Information 33 MA-07. July 2, 2015. ADAMS No. ML15195A350. 34 [Exelon] Exelon Generation Company, LLC. 2015e. Letter from M.P. Gallagher, Vice President 35 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 36 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 37 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 38 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 39 Review Requests for Additional Information. Response to Request for Additional Information 40 TE-02. July 2, 2015. ADAMS No. ML15195A380. 41 [Exelon] Exelon Generation Company, LLC. 2015f. Letter from M.P. Gallagher, Vice President 42 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 43 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 44 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 45 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 46 Review Requests for Additional Information. Response to Request for Additional Information 47 TE-04. July 2, 2015. ADAMS No. ML15195A382. 4-140

Environmental Consequences and Mitigating Actions 1 [Exelon] Exelon Generation Company, LLC. 2015g. Letter from M.P. Gallagher, Vice President 2 License Renewal Projects, Exelon, to NRC Document Control Desk.

Subject:

Response to 3 NRC Request for Additional Information, dated May 22, 2015, Regarding the LaSalle County 4 Station, Units 1 and 2, License Renewal Application, Environmental Review. Enclosure B: 5 LaSalle County Station, Units 1 & 2, Response Sheets for NRC License Renewal Environmental 6 Review Requests for Additional Information. Response to Request for Additional Information 7 TE-05. July 2, 2015. ADAMS No. ML15195A383. 8 [Exelon] Exelon Generation Company, LLC. 2015h. Letter from M.P. Gallagher, Vice 9 President - License Renewal Projects to NRC Document Control Desk.

Subject:

Response to 10 NRC Request for Additional Information on Severe Accident Mitigation Alternatives Regarding 11 the LaSalle County Station, Units 1 and 2 License Renewal Application Environmental Review. 12 Letter RA15-032. May 29, 2015. ADAMS No. ML15149A370. 13 [Exelon] Exelon Generation Company, LLC. 2015i. Letter from M.P. Gallagher, Vice President 14 License Renewal Projects to NRC Document Control Desk.

Subject:

Revised Response to 15 Request for Additional Information (RAI) #TR-09 Regarding the LaSalle County Station, Units 1 16 and 2, License Renewal Application, Environmental Review August 28, 2015. ADAMS 17 No. ML15240A002. 18 [Exelon] Exelon Generation Company, LLC. 2015j. Letter from M.P. Gallagher, Vice President, 19 License Renewal Projects, to NRC Document Control Desk.

Subject:

Revisions to LaSalle 20 County Station, Units 1 and 2, License Renewal Application, Applicants Environmental 21 ReportOperating License Renewal Stage. July 31, 2015. ADAMS No. ML15212A259. 22 Exelon Nuclear. 2010. LaSalle County Station Units 1 and 2, Annual Environmental Operating 23 Report, Annual Radiological Environmental Operating Report, 1 January through 24 31 December 2009. May 2010. ADAMS No. ML101320380. 25 Exelon Nuclear. 2011. LaSalle County Station Units 1 and 2, Annual Environmental Operating 26 Report, Annual Radiological Environmental Operating Report, 1 January through 27 31 December 2010. May 2011. ADAMS No. ML111320602. 28 Exelon Nuclear. 2012. LaSalle County Station Units 1 and 2, Annual Environmental Operating 29 Report, Annual Radiological Environmental Operating Report, 1 January through 30 31 December 2011. May 2012. ADAMS No. ML12130A420. 31 Exelon Nuclear. 2013. LaSalle County Station Units 1 and 2, Annual Environmental Operating 32 Report, Annual Radiological Environmental Operating Report, 1 January through 33 31 December 2012. May 2013. ADAMS No. ML13136A007. 34 Exelon Nuclear. 2014. LaSalle County Station Units 1 and 2, Annual Environmental Operating 35 Report, Annual Radiological Environmental Operating Report, 1 January through 36 31 December 2013. May 2014. ADAMS No. ML14135A214. 37 Exelon Nuclear. 2015. LaSalle County Station Units 1 and 2, Annual Environmental Operating 38 Report, Annual Radiological Environmental Operating Report, 1 January through 39 31 December 2014. May 2015. ADAMS Nos. ML15141A195 and ML15141A219. 40 Fahrig L. 2003. Effects of habitat fragmentation on biodiversity. Annual Review of Ecology, 41 Evolution, and Systematics 34: 487-515. 42 FairWindEnergy. undated. Life in the Vermilion Co., IL, Envernergy LLC Industrial Wind 43 Project. Available at <http://fairwindenergy.org/VermilionWind.php> (accessed August 2015). 4-141

Environmental Consequences and Mitigating Actions 1 FarmProgress. 2010. Wind Farms Generate Conflict Across State. June 2010. Available at 2 <http://farmprogress.com/library.aspx/wind-farms-generate-conflict-across-state-90/93/546> 3 (accessed August 2015). 4 [FHWA] Federal Highway Administration. 2006. Construction Noise Handbook. Available at 5 <http://www.fhwa.dot.gov/environment/noise/construction_noise/handbook/> 6 (accessed June 2015). 7 [FHWA] Federal Highway Administration. 2011. Highway Traffic Noise Analysis and 8 Abatement Policy and Guidance. Available at 9 <https://www.fhwa.dot.gov/environment/noise/regulations_and_guidance/polguide/ 10 polguide02.cfm> (accessed August 2015). 11 Federal Water Pollution Control Act (Clean Water Act) of 1972, as amended. 12 33 U.S.C. §1251 et seq. 13 Fraser KC, Silverio C, Kramer P, Mickle N, Aeppli R, Stutchbury BJM. 2013. A 14 trans-hemispheric migratory songbird does not advance spring schedules or increase migration 15 rate in response to record-setting temperatures at breeding sites. PLoS ONE 8(5): e64587. 16 Fritts, MW. 2013. Email from M.W. Fritts, Illinois Natural History Survey, to P. Moore, Tetra 17 Tech.

Subject:

RE: Request: Illinois River Reports. June 24, 2013. ADAMS 18 No. ML15273A418. 19 [FWS] U.S. Fish and Wildlife Service. 2014. Guidance for Preparing a Biological Assessment. 20 6 p. Available at <http://www.fws.gov/midwest/endangered/section7/pdf/BAGuidance.pdf> 21 (accessed 29 May 2014). 22 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 23 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 24 September 30 2015. Accessed 9 October 2015. Available at 25 http://www.fws.gov/midwest/endangered/lists/illinois-cty.html 26 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC.

Subject:

LaSalle 27 Power Plant License Renewal. List of threatened and endangered species that may occur in 28 your proposed project location, and/or may be affected by your proposed project. 29 27 February 2015. ADAMS No. ML15126A069. 30 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998. 31 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 32 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p. 33 Available at <http://www.nmfs.noaa.gov/pr/pdfs/laws/esa_section7_handbook.pdf> 34 (accessed 12 May 2014). 35 [GCP] Global Carbon Project. 2014. Global Carbon Budget, Media Summary Highlights. 36 Available at <http://www.globalcarbonproject.org/carbonbudget/14/hl-compact.htm> 37 (accessed August 2015). 38 [GE] General Electric. 2010. How Loud is a Wind Turbine? Available at 39 <http://www.gereports.com/how-loud-is-a-wind-turbine/> (August 2015). 40 Groschen GE, Arnold TL, Harris MA, Dupré DH, Fitzpatrick FA, Scudder BC, Morrow WS, 41 Terrio PJ, Warner KL, Murphy EA. 2004. Water Quality in the Upper Illinois River Basin, 42 Illinois, Indiana, Wisconsin, 1999-2001. Reston, VA: U.S. Geological Survey. Circular 1230. 43 June 2004. 42 p. Available at <http://pubs.usgs.gov/circ/2004/1230/pdf/circular1230.pdf> 44 (accessed 21 August 2015). 4-142

Environmental Consequences and Mitigating Actions 1 Herkert JR. 1994. The effects of habitat fragmentation on Midwestern grassland bird 2 communities. Ecological Applications 4(3): 461-471. 3 Hessler DM (Hessler Associates, Inc.). 2011. Assessing Sound Emissions from Proposed 4 Wind Farms and Measuring the Performance of Completed Projects. Washington, DC: The 5 National Association of Regulatory Utility Commissioners (NARUC). October 13, 2011. 69 p. 6 Available at 7 <http://www.naruc.org/Grants/Documents/Final%20full%20MN%20SERCAT%20rep%20with%2 8 0NARUC%20cover%20Hessler.pdf> (accessed August 2015). 9 [IDNR] Illinois Department of Natural Resources. 2005. The Illinois Comprehensive Wildlife 10 Conservation Plan & Strategy. Version 1.0. July 11, 2005. 380 p. Available at 11 <http://www.dnr.illinois.gov/conservation/IWAP/Documents/WildlifeActionPlanFinal.pdf> 12 (accessed 16 October 2015). 13 [IDNR] Illinois Department of Natural Resources. 2007. Status of the Catfish Fishery. Illinois 14 Department of Natural Resources, Division of Fisheries. March 2007. Available at 15 <http://www.dnr.state.il.us/orc/fisheries/07/07%20catfish%20status%20report.pdf> 16 (accessed 21 May 2015). 17 [IDNR] Illinois Department of Natural Resources. 2009. Status of the Striped Bass/Hybrid 18 Striped Bass Fishery. Illinois Department of Natural Resources, Division of Fisheries. 19 March 2009. Available at 20 <http://www.prairiestateoutdoors.com/images/uploads/2009_Striped_Bass_Status.pdf> 21 (accessed 21 May 2015). 22 [IDNR] Illinois Department of Natural Resources. 2015a. Activities at Illini State Park. 23 Available at <http://www.dnr.illinois.gov/Parks/Activity/Pages/Illini.aspx> 24 (accessed 24 September 2015). 25 [IDNR] Illinois Department of Natural Resources. 2015b. LaSalle Lake State Fish & Wildlife 26 Area. Available at <http://www.dnr.state.il.us/lands/landmgt/parks/r1/lasalle.htm> 27 (accessed 15 October 2015). 28 [IDPH] Illinois Department of Public Health. 2014. Letter from K. Marshall, IDPH, to Exelon. 29

Subject:

LaSalle County Station Units 1 and 2 - Consultation about thermophilic organisms. 30 February 28, 2014. ADAMS No. ML15273A445. 31 [IEPA] Illinois Environmental Protection Agency. 2013. NPDES Permit No. IL0048151, National 32 Pollutant Discharge Elimination System, Reissued (NPDES) Permit. Exelon Generation 33 Company, LLC, LaSalle County Generating Station. Effective date, August 1, 2013. 34 Springfield, IL: Division of Water Pollution Control. In: LaSalle County Station, Units 1 and 2, 35 License Renewal Application, Appendix E, Applicants Environmental Report, Operating License 36 Renewal Stage. ADAMS No. ML14343A897 (Appendix C). 37 [IEPA] Illinois Environmental Protection Agency. 2014. Letter from G. Good, Manager, IEPA, to 38 Exelon.

Subject:

LaSalle County Station Units 1 and 2 - Consultation about thermophilic 39 organisms. February 28, 2014. ADAMS No. ML15273A446. 40 [IPCC] Intergovernmental Panel on Climate Change. 2007a. Climate Change 2007: Impacts, 41 Adaptation and Vulnerability. Contribution of Working Group II to the Fourth Assessment 42 Report of the Intergovernmental Panel on Climate Change. Parry ML, Canziani OF, 43 Palutikof JP, van der Linden PJ, Hanson CE, editors. Cambridge University Press, Cambridge, 44 United Kingdom. 4-143

Environmental Consequences and Mitigating Actions 1 [IPCC] Intergovernmental Panel on Climate Change. 2007b. Climate Change 2007: Synthesis 2 Report. Contribution of Working Groups I, II and III to the Fourth Assessment Report of the 3 Intergovernmental Panel on Climate Change [Core Writing Team, Pachauri RK, Reisinger A 4 (eds.)]. IPCC, Geneva, Switzerland. 5 [IPCC] Intergovernmental Panel on Climate Change. 2007c. Climate Change 2007: The 6 Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of 7 the Intergovernmental Panel on Climate Change. Solomon S, Qin D, Manning M, Chen Z, 8 Marquis M, Averyt KB, Tignor M, Miller HL, editors. Cambridge University Press, Cambridge, 9 United Kingdom, and New York, New York, United States. 10 [IPCC] Intergovernmental Panel on Climate Change. 2007c. Climate Change 2007: The 11 Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of 12 the Intergovernmental Panel on Climate Change. 13 [IPCC] Intergovermental Panel on Climate Change. 2013. Climate Change 2013: The Physical 14 Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the 15 Intergovernmental Panel on Climate Change [Stocker TF, Qin D, Plattner G-K, Tignor M, 16 Allen SK, Boschung J, Nauels A, Xia Y, Bex V, Midgley PM (eds.)]. Available at 17 <http://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_SPM_FINAL.pdf> 18 [ISGS] Illinois State Geological Survey. 2015. Illinois Water Well (ILWATER) Interactive Map. 19 Available at <http://maps.isgs.illinois.edu/ilwater/> (accessed 13 July 2015). 20 Jacob DJ, Winner DA. 2009. Effect of climate change on air quality. 21 Atmospheric Environment 43(51-63). 22 Knapp, HV. 2009. Trends in Illinois River Streamflow and Flooding (PowerPoint presentation). 23 Center for Watershed Science, Illinois State Water Survey, University of Illinois at 24 Urbana-Champaign. In 2009 Governor's Conference on the Management of the Illinois River 25 System Looking Back, Moving Forward. October 20-22, 2009. Peoria, IL. Available at 26 <http://ilrdss.sws.uiuc.edu/pubs/govconf2009/session3c/session3c.htm> 27 (accessed 25 August 2015). 28 LaSalle County. 2014. LaSalle County Comprehensive Plan, LaSalle County, Illinois. Updated 29 June 2014. Available at <http://www.lasallecounty.org/envsvcs/lccp-2014.pdf> 30 (accessed 31 August 2015). 31 Leibowitz R. 2015. Letter to D.J. Wrona, NRC, regarding License renewal - U.S. NRC LaSalle 32 County Station, Units 1 and 2, dated April 1, 2015. ADAMS No. ML15106A791. 33 Lerczak TV. 1996. Illinois River Fish Communities: 1960s vs. 1990s. Illinois Natural History 34 Survey. April 4, 1996. Available at 35 <http://wwx.inhs.illinois.edu/resources/inhsreports/may-jun96/fish/> 36 (accessed 19 March 2015). 37 Mannouris C, Byers DL. 2013. The impact of habitat fragmentation on fitness-related traits in a 38 native prairie plant, Chamaecrista fasciculata (Fabaceae). Biological Journal of the Linnean 39 Society 108(1): 55-67. 40 Mayhew DA, Jensen LD, Hanson DF, Muessig PH. 2000. A comparative review of 41 entrainment survival studies at power plants in estuarine environments. Environmental Science 42 and Policy 3: 295-301. 43 McClelland MA, Pegg MA. 2005. The Long-Term Illinois River Fish Population Monitoring 44 Program, Project F-101-R-16. Illinois Natural History Survey. River Research Laboratory. 45 Havana, IL. May 2005. 4-144

Environmental Consequences and Mitigating Actions 1 McClelland, MA, Sass GG, Cook TR, Irons KS, Michaels NM, OHara TM, Smith CS. 2012. 2 The Long-Term Illinois River Fish Population Monitoring Program. Fisheries 37(8): 340-350. 3 Melillo JM (Marine Biological Laboratory), Richmond TC (Van Ness Feldman, LLP), Yohe GW 4 (Wesleyan University), editors. 2014. Climate Change Impacts in the United States: The 5 Third National Climate Assessment. Washington, DC: U.S. Global Change Research Program. 6 May 2014. 841 p. ADAMS No. ML14129A233. 7 Menzie C, Henning MH, Cura J, Finkelstein K, Gentile J, Maughan J, Mitchell D, Petron S, 8 Potocki B, Svirsky S, Tyler P. 1996. Special report of the Massachusetts weight-of-evidence 9 workgroup: A weight-of-evidence approach for evaluating ecological risks. Human and 10 Ecological Risk Assessment 2(2): 227-304. 11 [MSA] Magnuson-Stevens Fishery Conservation and Management Reauthorization Act of 2006, 12 as amended. 16 U.S.C. §§1801-1884. 13 National Environmental Policy Act of 1969 (NEPA). 42 USC 4321, et seq. 14 [NCDC] National 2015. Climate at a Glance: Average Temperature and Precipitation, 15 1895-2015, Illinois, Northeast Climate Division. Available at 16 <https://www.ncdc.noaa.gov/cag/time-series/us> (accessed 21 January 2015). 17 [NEI] Nuclear Energy Institute. 2005. Severe Accident Mitigation Alternative (SAMA) Analysis 18 Guidance Document. NEI 05-01, Rev. A. Washington, DC: NEI. November 2005. ADAMS 19 No. ML060530203. 20 [NETL] National Energy Technology Laboratory. 2010. U.S. Department of Energy, National 21 Energy Technology Laboratory. Life Cycle Analysis, Natural Gas Combined Cycle (NGCC) 22 Power Plant. DOE/NETL-403/110509. Available at 23 <http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=6c2fe989-d368-4bf 24 5-8e5f-3bd85ff79f8f> (accessed August 2015). 25 [NETL] National Energy Technology Laboratory. 2012. Life Cycle Analysis: Integrated 26 Gasification Combined Cycle (IGCC) Power Plant. Available at 27 <http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/IGCC-LCA 28 -Final-Report---9-30-10---Final---Rev-2-1.pdf> (accessed August 2015). 29 [NETL] National Energy Technology Laboratory. 2013. Cost and Performance Baseline for 30 Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2a. 31 DOE/NETL-2010/1397. September. Available at 32 <http://www.netl.doe.gov/energy-analyses/pubs/BitBase_FinRep_Rev2.pdf> 33 (accessed August 2015). 34 [NOAA] National Oceanic and Atmospheric Administration. 2013. Regional Climate Trends and 35 Scenarios for the U.S. National Climate Assessment, Part 3. Climate of the Midwest. NOAA 36 Technical Report NESDID 142-3. 37 News-Gazette. 2013. A setback for wind farms. September 15, 2013. Available at 38 <http://www.news-gazette.com/news/local/2013-09-15/setback-wind-farms.html> 39 (accessed August 2015). 40 [NRC] U.S. Nuclear Regulatory Commission. 1978. Final Environmental Statement Related to 41 Operation of LaSalle County Nuclear Power Station Unit Nos. 1 and 2. Washington, DC: Office 42 of Nuclear Reactor Regulation. NUREG-0486. November 1978. ADAMS No. ML14353A388. 43 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement 44 for License Renewal of Nuclear Plants. Final Report. Washington, DC: NRC. NUREG-1437, 45 Volumes 1 and 2. May 31, 1996. 1,204 p. ADAMS Nos. ML040690705 and ML040690738. 4-145

Environmental Consequences and Mitigating Actions 1 [NRC] U.S. Nuclear Regulatory Commission. 1997. Regulatory Analysis Technical Evaluation 2 Handbook. Washington, DC: NRC. NUREG/BR-0184. ADAMS No. ML050190193. 3 [NRC] U.S. Nuclear Regulatory Commission. 1999. Section 6.3-Transportation, Table 9.1, 4 Summary of findings on NEPA issues for license renewal of nuclear power plants. In: Generic 5 Environmental Impact Statement for License Renewal of Nuclear Plants. Washington, DC: 6 NRC. NUREG-1437, Volume 1, Addendum 1. August 1999. ADAMS No. ML040690720. 7 [NRC] U.S. Nuclear Regulatory Commission. 2001. Exelon Generation Company, LLC; Docket 8 No. 50-373; La Salle County Station, Unit 1; Facility Operating License. Amended 9 January 12, 2001. ADAMS No. ML052990324. 10 [NRC] U.S. Nuclear Regulatory Commission. 2002. Generic Environmental Impact Statement 11 on Decommissioning of Nuclear Facilities, Supplement 1: Regarding the Decommissioning of 12 Nuclear Power Reactors. NUREG-0586, Volumes 1 and 2. Washington, DC: NRC. 13 November 30, 2002. ADAMS Nos. ML023470327, ML023500228, and ML023500295. 14 [NRC] U.S. Nuclear Regulatory Commission. 2004. Generic Environmental Impact Statement 15 for License Renewal of Nuclear Plants, Supplement 17, Regarding Dresden Nuclear Power 16 Station, Units 2 and 3, Final Report. Washington, DC: Office of Nuclear Reactor Regulation. 17 NUREG-1437, Supplement 17. June 2004. ADAMS No. ML041890266. 18 [NRC] U.S. Nuclear Regulatory Commission. 2008a. Final Environmental Impact Statement for 19 an Early Site Permit (ESP) at the Vogtle Electric Generating Plant Site. Final Report. 20 NUREG-1872, Vol 1. August. ADAMS No. ML082240145. 21 [NRC] U.S. Nuclear Regulatory Commission. 2008b. Generic Environmental Impact Statement 22 for License Renewal of Nuclear Plants, Supplement 32: Regarding Wolf Creek Generating 23 Station. Washington, DC: NRC. NUREG-1437. May 2008. 487 p. 24 ADAMS No. ML081260608. 25 [NRC] U.S. Nuclear Regulatory Commission. 2010. Supplemental Environmental Impact 26 Statement Regarding Indian Point Generating, Units 2 and 3. Washington, DC: NRC. 27 NUREG-1437, Supplement 38. ADAMS No. ML103270072. 28 [NRC] U.S. Nuclear Regulatory Commission. 2013a. Environmental Impact Statement for the 29 Combined License (COL) for Enrico Fermi Unit 3, Final Report. Washington, DC: NRC. 30 NUREG-2105, Volume 1. January 2013. 753 p. ADAMS No. ML12307A172. 31 [NRC] U.S. Nuclear Regulatory Commission. 2013b. Event Report Guidelines: 32 10 CFR 50.72 and 50.73. Revision 3. Washington, DC: NRC. NUREG-1022. 33 January 31, 2013. 107 p. ADAMS No. ML13032A220. 34 [NRC] U.S. Nuclear Regulatory Commission. 2013c. Final Supplemental Environmental Impact 35 Statement Regarding South Texas Project. Washington, DC: NRC. NUREG-1437, 36 Supplement 48. ADAMS No. ML13322A890. 37 [NRC] U.S. Nuclear Regulatory Commission. 2013d. Generic Environmental Impact Statement 38 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Revision 1, 39 Volumes 1, 2, and 3. June 30, 2013. 1,535 p. ADAMS No. ML13107A023. 40 [NRC] U.S. Nuclear Regulatory Commission. 2013e. Interim Staff Guidance on Environmental 41 Issues Associated with New Reactors, Attachment 1Staff Guidance for Greenhouse Gas and 42 Climate Change. September 2013. ADAMS No. ML12326A811. 4-146

Environmental Consequences and Mitigating Actions 1 [NRC] U.S. Nuclear Regulatory Commission. 2013f. Standard Review Plans for 2 Environmental Reviews for Nuclear Power Plants, Supplement 1: Operating License Renewal, 3 Revision 1. Washington, DC: NRC. NUREG-1555. June 30, 2013. 325 p. ADAMS 4 No. ML13106A246. 5 [NRC] U.S. Nuclear Regulatory Commission. 2014. Generic Environmental Impact Statement 6 for Continued Storage of Spent Nuclear Fuel. Washington, DC: NRC, Office of Nuclear 7 Material Safety and Safeguards. NUREG-2157, Volumes 1 and 2. September 2014. 8 ADAMS Nos. ML14196A105 and ML14196A107. 9 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Final Supplemental Environmental Impact 10 Statement Regarding Braidwood Station. Washington, DC: NRC. NUREG-1437, 11 Supplement 55. ADAMS No. ML15062A428. 12 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Final Supplemental Environmental Impact 13 Statement Regarding Seabrook Station. Washington, DC: NRC. NUREG-1437, 14 Supplement 46. ADAMS Nos. ML15209A575 and ML15209A870. 15 [NRC] U.S. Nuclear Regulatory Commission. 2015c. Letter from D.J. Wrona to A.E. Haaker, 16 Illinois Historic Preservation Agency.

Subject:

LaSalle County Station, Units 1 and 2 License 17 Renewal Application Review. February 9, 2015. ADAMS No. ML15022A578. 18 [NRC] U.S. Nuclear Regulatory Commission. 2015d. Letter from D.J. Wrona to R. Nelson, 19 Advisory Council on Historic Preservation.

Subject:

LaSalle County Station, Units 1 and 2 20 License Renewal Application Review. February 9, 2015. ADAMS No. ML15023A094. 21 [NRC] U.S. Nuclear Regulatory Commission. 2015e. Letters from D.J. Wrona to 14 tribes. 22

Subject:

Request for Scoping Comments concerning the LaSalle County Station, Units 1 and 2 23 License Renewal Application Review. February 9, 2015. ADAMS No. ML15023A139. 24 [NRC] U.S. Nuclear Regulatory Commission. 2015f. Meeting Summary: NRC Visit to Illinois 25 State Historic Preservation Office on May 7, 2015. ADAMS No. ML15205A286. 26 [NRC] U.S. Nuclear Regulatory Commission. 2015g. Letter from B. Vaidya, Project Manager, 27 Plant Licensing III-2 and Planning and Analysis Branch, Office Nuclear Reactor Regulation, to 28 B.C. Hanson, Senior Vice President, Exelon Generation Company, LLC.

Subject:

LaSalle 29 County Station, Units 1 and 2, Issuance of Amendment Revising the Ultimate Heat Sink 30 Temperature Limit. November 19, 2015. ADAMS Nos. ML15202A578. 31 [NREL] National Renewable Energy Laboratory. 2013. Estimated Economic Impacts of Utility 32 Scale Wind Power in Iowa. Technical Report NREL/TP-6A20-53187. November. Available at 33 <http://www.nrel.gov/docs/fy14osti/53187.pdf>. 34 [OEPA] Ohio Environmental Protection Agency. 1987. Biological Criteria for the Protection of 35 Aquatic Life. Ohio Environmental Protection Agency. July 1987. Columbus, Ohio. Available at 36 <http://www.epa.state.oh.us/Portals/35/documents/Vol1.pdf> 37 (accessed 26 October 2015). 38 [OEPA] Ohio Environmental Protection Agency. 1989. From EA 1999. 39 [OECD/NEA] Organisation for Economic Co-Operation and Development Nuclear Energy 40 Agency. 2005. Projected Costs of Generating Electricity 2005. OECD Publishing. 230 p. 41 Available at <http://www.oecd-ilibrary.org/content/book/9789264008274-en> 42 (accessed August 2015). 4-147

Environmental Consequences and Mitigating Actions 1 Parker J. 2014. Long-term impacts of water quality and climate variability on Illinois River 2 waterway fish assemblages. M.S. Thesis, University of Illinois at Urbana-Champaign. 3 May 30, 2014. Available at <https://www.ideals.illinois.edu/handle/2142/49756> 4 (accessed 20 August 2015). 5 Pedersen E, Persson Waye K. 2004. Perception and annoyance due to wind turbine noisea 6 dose-response relationship. Journal of the Acoustical Society of America 116(6): 3460-3470. 7 Available at <http://www.shipdhamturbines.org.uk/files/RDG08.pdf> (accessed August 2015). 8 Saussus P. 2012. Major noise sources and mitigation cost estimates for gas-fired power 9 facilities. POWER. Available at <http://www.powermag.com/ 10 major-noise-sources-and-mitigation-cost-estimates-for-gas-fired-power-facilities/?pagenum=1> 11 (August 2015). 12 Sietman BE, Whitney SD, Kelner DE, Blodgett DK, Dunn HL. 2001. Post-extirpation recovery 13 of the freshwater mussel (Bivalvia: Unionidae) fauna in the upper Illinois River. Journal of 14 Freshwater Ecology, 16(2): 273-281. 15 Smith PW. 2002. The Fishes of Illinois. University of Illinois Press, Urbana and Chicago, IL. 16 Stewart GB, Coles CF, Pullin S. 2005. Effects of wind turbines on bird abundance review 17 report. Centre for Evidence-Based Conservation, Systematic Review No. 4. Available at 18 <http://tethys.pnnl.gov/sites/default/files/publications/Stewart%20et%20al.%202005.pdf> 19 (accessed 24 September 2015). 20 Stewart GB, Pullin AS, Coles CF. 2007. Poor evidence-base for assessment of windfarm 21 impacts on birds. Environmental Conservation 34(1): 1-11. Available at 22 <https://scholar.google.com/scholar?q=Poor+Evidence-Base+For+Assessment+Of+Windfarm+I 23 mpacts+On+Birds&hl=en&as_sdt=0&as_vis=1&oi=scholart&sa=X&ved=0CBsQgQMwAGoVCh 24 MIz_aWiNSQyAIVBXk-Ch3ROAhK> (accessed 24 September 2015). 25 Tagaris E, Liao KJ, Delucia AJ, Deck L, Amar P, Russel AG. 2009. Potential impact of climate 26 change on air pollution-related human health effects. Environmental Science and 27 Technology 43: 4979-4988. Available at <http://pubs.acs.org/doi/pdf/10.1021/es803650w> 28 (accessed 28 December 2014). 29 Talkington LM. 1991. The Illinois River--Working for our State. Champaign, IL: Illinois State 30 Water Survey. January 1991. Miscellaneous Publication 128. Available at 31 <http://www.isws.illinois.edu/pubdoc/MP/ISWSMP-128.pdf> (accessed 21 August 2015). 32 Tegen S. 2006. Comparing Statewide Economic Impacts of New Generation from Wind, Coal, 33 and Natural Gas in Arizona, Colorado, and Michigan. NREL/TP-500-37720. National 34 Renewable Energy Laboratory. May 2006. 38 p. Available at 35 <http://www.windpoweringamerica.gov/pdfs/38154_econdev_compare_statewide.pdf> 36 (August 2015). 37 Thuiller W (Laboratoire dEcologie Alpine). 2007. Biodiversity: climate change and the 38 ecologist. Nature 448: 550-552. DOI: 10.1038/448550a. 39 [USGCRP] U.S. Global Change Research Program. 2009. Global Climate Change Impacts in 40 the United States. Karl TR, Melillo JM, Peterson TC, editors. ADAMS No. ML100580077. 41 [USGCRP] U.S. Global Change Research Program. 2014. Climate Change Impacts in the 42 United States: The Third National Climate Assessment. Melillo JM, Richmond TC, Yohe GW, 43 editors. May 9, 2014. ADAMS No. ML14129A233. 4-148

Environmental Consequences and Mitigating Actions 1 [USGS] U.S. Geological Survey. 1979. River Mileages and Drainage Areas for Illinois 2 StreamsVolume 2, Illinois River Basin, Water-Resources Investigations Report 79-111. 3 Available at <http://il.water.usgs.gov/pubs/wrir79_111.pdf> (accessed 28 May 2015). 4 [USGS] U.S. Geological Survey. 1998. National Water-Quality Assessment Program, Upper 5 Illinois River Basin. Urbana, IL: U.S. Geological Survey, WRD. USGS Fact Sheet FS072-98. 6 June 1998. Available at <http://il.water.usgs.gov/pubs/fs072_98.pdf> (accessed 7 25 August 2015). 8 [USGS] U.S. Geological Survey. 2015. USGS Water-Year Summary 2014, 05543500 Illinois 9 River at Marseilles, Illinois. Available at 10 <http://waterdata.usgs.gov/nwis/inventory/?site_no=05543500&agency_cd=USGS> (accessed 11 5 June 2015). 12 Wu S, Mickley LJ, Leibensperger EM, Jacob DJ, Rind D, Streets DG. 2008. Effects of 13 2000-2050 global change on ozone air quality in the United States. Journal of Geophysical 14 Research, Volume 113. 4-149

1

5.0 CONCLUSION

2 This draft supplemental environmental impact statement (SEIS) contains the environmental 3 review of the application for renewed operating licenses for LaSalle County Station, Units 1 4 and 2 (LSCS), submitted by Exelon Generation Company, LLC (Exelon), as required by the 5 Code of Federal Regulations (CFR), Part 51 of Title 10 (10 CFR Part 51), the U.S. Nuclear 6 Regulatory Commissions (NRCs) regulations that implement the National Environmental Policy 7 Act (NEPA). This chapter presents conclusions and recommendations from the site-specific 8 environmental review of LSCS. Section 5.1 summarizes the environmental impacts of license 9 renewal; Section 5.2 presents a comparison of the environmental impacts of license renewal 10 and energy alternatives; and Section 5.3 presents the NRC staff preliminary conclusions and 11 recommendation. 12 5.1 Environmental Impacts of License Renewal 13 The NRC staffs review of site-specific environmental issues in this SEIS leads to the conclusion 14 that issuing renewed licenses at LSCS would have SMALL to MODERATE impacts for the 15 Category 2 issues applicable to license renewal at LSCS. The NRC staff considered mitigation 16 measures for each Category 2 issue, as applicable. The NRC staff concluded that no additional 17 mitigation measure is warranted. 18 5.2 Comparison of Alternatives 19 In Chapter 4, the staff considered the following alternatives to LSCS license renewal: 20

  • no-action alternative, 21
  • new nuclear alternative, 22
  • integrated gasification combined-cycle alternative, 23
  • natural gas combined-cycle (NGCC) alternative, 24
  • combination alternative (NGCC, wind, solar), and 25
  • purchased power.

26 Based on the summary of environmental impacts provided in Table 2-2, the NRC staff 27 concluded that the environmental impacts of renewal of the operating licenses for LSCS would 28 be smaller than those of feasible and commercially viable alternatives. The no-action 29 alternative, the act of shutting down LSCS on or before its license expiration dates, would have 30 SMALL environmental impacts with the exception of socioeconomic impacts which would have 31 SMALL to LARGE environmental impacts. Continued operation of LSCS would have SMALL to 32 MODERATE environmental impacts for aquatic resources and SMALL environmental impacts in 33 all other areas. The NRC staff concluded that continued operation of LSCS is the 34 environmentally preferred alternative. 35 5.3 Recommendation 36 The NRCs preliminary recommendation is that the adverse environmental impacts of license 37 renewal for LSCS are not great enough to deny the option of license renewal for 38 energy-planning decisionmakers. This recommendation is based on the following: 5-1

Conclusion 1

  • the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic Environmental 2 Impact Statement for License Renewal of Nuclear Plants; 3
  • the environmental report submitted by Exelon; 4
  • the NRC staffs consultation with Federal, State, local, and Tribal Government 5 agencies; 6
  • the NRC staffs environmental review; and 7
  • the NRC staffs consideration of public comments received during the scoping 8 process.

5-2

1 6.0 LIST OF PREPARERS 2 This supplemental environmental impact statement (SEIS) was prepared by members of the 3 Office of Nuclear Reactor Regulation (NRR) with assistance from other U.S. Nuclear Regulatory 4 Commission (NRC) organizations and contract support from Pacific Northwest National 5 Laboratory (PNNL), the Center for Nuclear Waste Regulatory Analyses (CNWRA), a private 6 contractor and Idoneous Consulting, Inc. (Idoneous). Table 6-1 lists the NRC staff who 7 contributed to the development of the SEIS. PNNL provides contract support for analysis of 8 transportation impacts of high burnup fuel. CNWRA provides contract support for severe 9 accident mitigation alternative (SAMA) reviews. Idoneous provides contract support for 10 technical editing reviews. 11 Table 6-1. List of Preparers Name Education/Experience Function or Expertise NRC-NRR Jim Danna M.S., Civil Engineering/Geology Management oversight 29 years of experience in engineering and project management including 16 years at NRC, including as an NRC technical and projects branch manager David Wrona B.S., Electrical Engineering; 27 years of Management oversight nuclear plant experience, including as an NRC resident inspector, reactor engineer, project manager, and projects and technical branch manager David Drucker B.S., General Engineering; Project management M.S., Engineering Management; 34 years of project and program management experience Jeffrey Rikhoff M.R.P., Regional Planning; Socioeconomics and environmental M.S., Economic Development and justice Appropriate Technology; B.A., English; 35 years of combined industry and government experience including 28 years in NEPA compliance, environmental impact analysis, socioeconomics and environmental justice impact analysis, cultural resource impacts, and comprehensive land-use and development planning Bill Rautzen B.S., Health Physics; B.S., Industrial Human health, radiological, and waste Hygiene; M.S. Health Physics; 5 years management of experience in environmental impact analysis 6-1

List of Preparers Name Education/Experience Function or Expertise Kevin Folk B.A., Geoenvironmental Studies; Surface water resources M.S., Environmental Biology; 25 years of experience in NEPA compliance; geologic, hydrologic, and water quality impacts analysis; utility infrastructure analysis; and environmental regulatory compliance and water supply and wastewater discharge permitting Briana Grange B.S., Conservation Biology; 10 years of Terrestrial ecology, land use, and visual experience in environmental impact resources analysis, section 7 consultations, and essential fish habitat consultations Nancy Martinez A.M., Earth and Planetary Science; Air quality, noise, and climate change B.S., Earth and Environmental Science; 4 years of experience in environmental impact analysis Michelle Moser M.S., Biological Sciences; Aquatic ecology and microbiological B.S., Environmental Sciences; hazards 13 years of experience in ecological studies, environmental impact assessment, and protected resource management Jerry Dozier M.S. Reliability Engineering; M.B.A. SAMA Business Administration; B.S. Mechanical Engineering; 30 years of experience including operations, reliability engineering, technical reviews, and NRC branch management Russell Chazell B.S., Liberal Studies; J.D, Law; Historic and cultural resources M.S., Nuclear Engineering; Certificate Non-radioactive waste management in Project Management; Certificate in Non-radioactive human health NEPA; 26 years of combined industry and government experience including analytical and environmental laboratory science, laboratory project management, technical business development, engineering project management, and NEPA compliance William Ford M.S., Geology; 41 years of combined Geologic environment and groundwater industry and government experience resources working on groundwater, surface water, and geology projects and associated technical and environmental analyses Robert Hoffman B.S., Environmental Resource Alternatives and cumulative effects Management; 29 years of experience in NEPA compliance, environmental impact assessment, alternatives identification and development, and energy facility siting 6-2

List of Preparers Name Education/Experience Function or Expertise Dennis Logan Ph.D., Marine Studies and Biological Threatened and endangered species Oceanography; M.S., Biological Sciences, Marine Biology; B.S., Zoology; 40 years of experience in ecological studies, ecological risk assessment, environmental impact assessment, protected resource management, and project management Don Palmrose B.S., Nuclear Engineering; M.S., High burnup fuel transportation impacts Nuclear Engineering; Ph.D., Nuclear Engineering; 30 years of relevant experience National Laboratory Personnel Steve Maheras, B.A. Zoology; High burnup fuel transportation impacts PNNL(a) M.S. Health Physics Ph.D. Health Physics 27 years of experience in health physics and transportation risk assessment Commercial Contractors R. Benke, CNWRA (b) Ph.D., Nuclear Engineering, SAMA M. Eng., Radiological Health B.S., Nuclear Engineering, 20 years of experience in nuclear engineering, radiological health, risk analysis, and is a certified health physicist D. Speaker, CNWRA B.S., Nuclear Engineering SAMA M.S., Nuclear Engineering 10 years of experience in nuclear engineering, radiation detection, instrumentation, nondestructive evaluation, and nuclear reactor design and analysis E.R. Schmidt, B.S., Mechanical Engineering; SAMA Contractor M.S., Nuclear Engineering 50 years of nuclear industry experience including 35 year experience in performing, managing and reviewing Probabilistic Risk Assessments Susan Anastasi, Technical Editing Idoneous (a) Pacific Northwest National Laboratory (PNNL) is operated by Battelle for the U.S. Department of Energy. (b) CNWRA is a federally funded research and development center sponsored by the NRC. 1 6-3

1 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM 2 COPIES OF THIS SEIS ARE SENT Name Affiliation J. Barrett Tribal NationCitizen Potawatomi Nation H. Frank Tribal NationForest County Potawatomi K. Meshigaud Tribal NationHannahville Indian Community, Band of Potawatomi J. Greendeer Tribal NationHo-Chunk Nation S. Cadue Tribal NationKickapoo Tribe in Kansas G. Salazar Tribal NationKickapoo Tribe of Oklahoma D. Lankford Tribal NationMiami Tribe of Oklahoma J. Froman Tribal NationPeoria Tribe of Indians in Oklahoma J. Warren Tribal NationPokagon Band of Potawatomi S. Ortiz Tribal NationPrairie Band of Potawatomi Nation J. Bender Tribal NationSac and Fox Tribe of the Mississippi in lowa/Meskwaki B. Robidoux Tribal NationSac and Fox Nation of Missouri in Kansas and Nebraska G. Thurman Tribal NationSac and Fox Nation J. Blackhawk Tribal NationWinnebago Tribe of Nebraska R. Nelson Advisory Council on Historic Preservation J. Duyvejonck U.S. Fish & Wildlife Service R. Leibowitz Illinois Historic Preservation Agency Alan Keller Illinois Environmental Protection Agency Nathan Grider Illinois Department of Natural Resources Patty Smith Mayor, City of Marseilles, Illinois Bob Eschbach Mayor, City of Ottawa, Illinois David Spicer Mayor, Village of Seneca, Illinois Kay Hines Mayor, City of Grand Ridge, Illinois EIS Scoping Meeting Participants Reed Wilson Office of U.S. Representative Kinzinger Elizabeth Poole U.S. EPA Region 5 Jerry Hicks LaSalle County Board Chairman Rick Zuffa Illinois Emergency Management Agency Cecil Settles Illinois Emergency Management Agency Doug OBrien Illinois Clean Energy Coalition Jim Carlson Superintendent, Seneca Township High School Roger Blumquist Argonne National Laboratory Beth Jung Nuclear Power Illinois Linda Lewison Nuclear Energy Information Service Ruth Thomas Environmentalists, Inc. Marvin Lewis Public 7-1

List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent Name Affiliation Tom Walsh LaSalle County Board, District 18 Connie Brooks Director, LaSalle County Emergency Management Agency Nelson Dewey Public Shelli Ocepak United Way of Eastern LaSalle County Mike Gallagher Exelon Generation Company Chris Wilson Exelon Generation Company Krista Lopykinski Exelon Generation Company John Keenan Exelon Generation Company Megan Borchers Exelon Generation Company Bryan Mooney Exelon Generation Company Pete Karaba Exelon Generation Company Harold Vinyard Exelon Generation Company Jay Houston Exelon Generation Company Nancy Ranek Exelon Generation Company 7-2

1 8.0 INDEX 2 A 42 Coastal Zone Management Act 43 (CZMA).......................... 3-22, 3-112, B-4 3 accidents ............................ xxiv, xxix, xxx, 4 3-8, 3-12, 3-72, 3-100, 4-75, 4-76, 4-77, 44 cold shock ..........................................4-52 5 4-78, 4-79, 4-80, 4-86, 4-88, 4-91, 4-98, 45 consumptive use ......................3-40, 4-23, 6 F-1, F-2, F-8, F-9, F-10, F-11, F-12, 46 4-27, 4-28, 4-29, 4-33, 4-52 7 F-13, F-15, F-16, F-17, F-18, F-24, F-25, 47 cooling system ............................ xxii, xxiii, 8 F-34, F-37, F-39, F-41, F-46, G-1, G-3, 48 xxviii, 1-3, 1-5, 2-10, 2-12, 2-13, 2-14, 9 G-4, G-9, G-11, G-12 49 3-6, 3-7, 3-8, 3-59, 3-72, 3-74, 3-98, 10 Advisory Council on Historic 50 4-19, 4-22, 4-24, 4-31, 4-32, 4-33, 4-37, 11 Preservation (ACHP) ..................... xxvii, 51 4-39, 4-41, 4-44, 4-45, 4-53, 4-54, 4-74, 12 1-6, 4-60, 4-147, 7-1, B-6, C-3 52 4-86, 4-87, 4-117, F-6, F-9, F-25, F-26, 13 aesthetic ................3-41, 3-101, 4-64, 4-96 53 F-30, F-37 14 alternatives .................................... iii, xxiv, 54 core damage frequency (CDF) ......... xxvii, 15 1-4, 2-1, 2-3, 2-4, 2-5, 2-7, 2-16, 2-17, 55 4-78, 4-79, 4-80, 4-83, 4-84, 4-86, F-1, 16 2-20, 2-21, 2-23, 2-24, 4-1, 4-6, 4-17, 56 F-2, F-3, F-5, F-6, F-7, F-9, F-10, F-11, 17 4-18, 4-20, 4-21, 4-29, 4-30, 4-35, 4-36, 57 F-12, F-13, F-14, F-15, F-17, F-20, F-24, 18 4-37, 4-55, 4-59, 4-64, 4-71, 4-72, 4-77, 58 F-27, F-30, F-31, F-32, F-33, F-37, F-40, 19 4-91, 4-97, 4-99, 4-100, 4-102, 4-107, 59 F-42 20 4-132, 4-133, 4-134, 5-1, 6-2, B-2, C-2, 60 Council on Environmental Quality 21 F-29, F-30, F-43 61 (CEQ) ....................................... xxvii, 1-3, 22 archaeological resources ............1-6, 2-4, 62 3-101, 3-112, 4-39, 4-121, 4-137 23 3-80, 3-82, 4-62, 4-63, 4-64, 4-126 63 critical habitat ...........................3-73, 3-75, 64 3-76, 3-77, 3-78, 3-79, 4-55, 4-57, 4-58, 24 B 65 B-6, C-1, C-2 25 biocide ................................................3-11 66 cultural resources ....................... xxiii, 2-4, 26 biological assessment ................ C-1, C-2 67 2-26, 3-23, 3-79, 3-82, 4-59, 4-60, 4-61, 68 4-62, 4-63, 4-64, 4-102, 4-112, 4-126, 27 biota ......3-10, 3-11, 3-63, 4-35, 4-41, 4-44, 69 4-132, 6-1, 6-2, B-1, B-6 28 4-45, 4-46, 4-51, 4-52, 4-111, 4-122, 29 4-124, 4-125 70 D 30 boiling water reactor ....................2-1, 3-6, 71 decommissioning........................ 2-2, 2-3, 31 4-80, F-1, G-2 72 4-1, 4-2, 4-26, 4-34, 4-52, 4-57, 4-58, 32 burnup ................. 3-6, 6-3, G-2, G-9, G-11 73 4-59, 4-62, 4-66, 4-67, 4-68, 4-69, 4-70, 74 4-98, 4-100, 4-102, 4-103, 4-104, 4-105, 33 C 75 4-106, 4-133, E-1, E-10 34 chronic effects ........4-72, 4-73, 4-88, 4-89 76 design-basis accident ................ 4-1, 4-76 35 Clean Air Act (CAA) ................. xxvii, 3-25, 77 discharges ................................. 2-8, 2-10, 36 3-26, 3-27, 3-112, 4-11, 4-12, 4-15, 78 2-12, 2-13, 2-14, 3-1, 3-6, 3-7, 3-8, 3-10, 37 4-129, 4-135, 4-137, 4-139, B-3, B-8 79 3-11, 3-12, 3-13, 3-14, 3-22, 3-35, 3-36, 38 closed-cycle cooling ..................2-8, 2-12, 80 3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 39 2-13, 2-14, 3-6, 3-7, 4-24, 4-25, 4-27, 81 3-48, 3-54, 3-60, 3-63, 3-64, 3-65, 3-69, 40 4-28, 4-40, 4-41, 4-44, 4-45, 4-53, 4-117, 82 3-74, 3-75, 3-97, 3-98, 3-99, 3-106, 4-22, 41 4-124 83 4-23, 4-24, 4-26, 4-27, 4-28, 4-30, 4-32, 84 4-37, 4-45, 4-46, 4-47, 4-48, 4-49, 4-51, 8-1

Index 1 4-52, 4-53, 4-72, 4-73, 4-74, 4-75, 4-85, 48 3-30, 3-32, 3-33, 3-34, 3-35, 3-36, 3-38, 2 4-87, 4-103, 4-116, 4-118, 4-119, 4-120, 49 3-39, 3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 3 4-124, 4-125, 6-2, B-3, B-4, E-4, E-8, 50 3-46, 3-47, 3-48, 3-49, 3-51, 3-54, 3-55, 4 F-29, F-34, F-41, G-7, G-9 51 3-56, 3-57, 3-58, 3-59, 3-60, 3-63, 3-64, 5 dose ...........................................xxxi, 3-13, 52 3-67, 3-68, 3-69, 3-70, 3-72, 3-74, 3-76, 6 3-14, 3-15, 3-16, 3-96, 3-97, 3-106, 4-80, 53 3-77, 3-78, 3-79, 3-80, 3-82, 3-83, 3-84, 7 4-83, 4-101, 4-127, 4-148, B-2, B-5, F-3, 54 3-85, 3-92, 3-93, 3-94, 3-95, 3-96, 3-97, 8 F-19, F-20, F-21, F-22, F-30, F-31, F-39, 55 3-100, 3-106, 3-113, 3-114, 3-115, 9 F-40, F-42, G-1, G-3, G-4, G-5, G-7, G-8, 56 3-116, 3-117, 3-118, 3-120, 3-121, 10 G-9, G-10, G-11, G-12 57 3-122, 3-125, 3-127, 4-1, 4-3, 4-7, 4-8, 58 4-22, 4-23, 4-24, 4-25, 4-31, 4-32, 4-33, 11 dredging ...................................2-10, 3-45, 59 4-34, 4-35, 4-38, 4-40, 4-41, 4-44, 4-45, 12 3-74, 4-22, 4-26, 4-28, 4-35, 4-37, 4-53, 60 4-47, 4-49, 4-50, 4-51, 4-52, 4-55, 4-56, 13 B-7 61 4-60, 4-61, 4-65, 4-69, 4-72, 4-73, 4-74, 14 E 62 4-75, 4-77, 4-78, 4-79, 4-80, 4-81, 4-82, 63 4-83, 4-86, 4-87, 4-88, 4-92, 4-93, 4-98, 15 education ........................3-90, 3-120, 4-65 64 4-101, 4-103, 4-105, 4-113, 4-114, 16 electromagnetic fields ..................... xxviii, 65 4-115, 4-118, 4-119, 4-120, 4-124, 17 4-72, 4-73, 4-88, 4-89 66 4-126, 4-127, 4-128, 4-129, 4-130, 18 endangered and threatened 67 4-132, 4-136, 4-138, 4-139, 4-140, 19 species ....................................1-6, 3-56, 68 4-141, 4-143, 4-146, 4-147, 5-1, 5-2, 7-2, 20 3-74, 3-75, 3-76, 3-77, 3-79, 3-119, 4-46, 69 B-7, B-8, C-2, D-1, D-2, E-4, E-8, F-1, 21 4-55, 4-125, 4-136, 4-142, 6-3, B-1, B-6, 70 F-2, F-3, F-4, F-5, F-6, F-9, F-10, F-11, 22 C-1, C-2, C-5 71 F-12, F-13, F-14, F-15, F-16, F-17, F-18, 72 F-19, F-20, F-21, F-22, F-23, F-24, F-25, 23 Endangered Species Act (ESA)......... xxiii, 73 F-26, F-27, F-28, F-29, F-30, F-31, F-32, 24 xxviii, 1-5, 1-6, 1-7, 2-4, 2-30, 3-53, 3-57, 74 F-37, F-38, F-39, F-40, F-41, F-42, F-43, 25 3-73, 3-76, 3-77, 3-79, 3-107, 3-113, 75 F-44, F-45, F-46, G-2, G-4, G-5, G-9, 26 4-55, 4-56, 4-57, 4-58, 4-59, 4-111, 76 G-11, G-13 27 4-135, 4-138, 4-142, B-6, B-8, C-1, C-2, 28 C-5 77 F 29 entrainment ............................... xxiii, 3-61, 30 3-70, 3-71, 3-72, 3-74, 3-75, 4-38, 4-39, 78 Fish and Wildlife Coordination Act 31 4-41, 4-42, 4-43, 4-44, 4-45, 4-52, 4-53, 79 (FWCA) ..................................... xxix, B-8 32 4-54, 4-124, 4-125, 4-144 80 G 33 environmental justice (EJ)..................2-4, 34 3-101, 3-108, 4-91, 4-92, 4-102, 4-127, 81 Generic Environmental Impact 35 4-135, 6-1 82 Statement (GEIS) ......................... iii, xxi, 83 xxii, xxv, xxix, 1-2, 1-3, 1-4, 1-5, 1-6, 1-7, 36 essential fish habitat (EFH) ............... xxiii, 84 1-8, 2-1, 2-2, 2-3, 2-4, 2-17, 2-19, 2-31, 37 xxviii, 4-55, 4-58, 6-2, B-6, C-3 85 2-32, 3-6, 3-35, 3-86, 3-99, 3-124, 3-125, 38 eutrophication ................ 3-74, 4-37, 4-111 86 4-1, 4-2, 4-6, 4-7, 4-11, 4-20, 4-22, 4-24, 39 evaporative loss ......................3-40, 4-120 87 4-31, 4-32, 4-33, 4-34, 4-35, 4-36, 4-37, 40 Exelon Generation Company 88 4-38, 4-45, 4-52, 4-53, 4-54, 4-55, 4-60, 41 (LLC) ...................................... iii, xxi, xxii, 89 4-62, 4-65, 4-72, 4-73, 4-75, 4-76, 4-77, 42 xxiv, xxv, 1-1, 1-5, 1-6, 1-7, 1-8, 2-1, 2-2, 90 4-91, 4-97, 4-98, 4-99, 4-100, 4-101, 43 2-3, 2-4, 2-8, 2-9, 2-10, 2-21, 2-26, 2-27, 91 4-102, 4-103, 4-105, 4-106, 4-145, 44 2-28, 2-30, 3-1, 3-2, 3-3, 3-4, 3-5, 3-6, 92 4-146, 4-147, 5-2, G-2, G-14 45 3-7, 3-8, 3-9, 3-10, 3-11, 3-12, 3-13, 93 greenhouse gases..................... 2-7, 2-13, 46 3-14, 3-15, 3-16, 3-17, 3-18, 3-19, 3-20, 94 3-27, 4-8, 4-135, 4-136 47 3-21, 3-22, 3-23, 3-24, 3-25, 3-27, 3-29, 8-2

Index 1 groundwater .............................. xxiii, 3-13, 46 3-57, 3-58, 3-59, 3-60, 3-61, 3-62, 3-63, 2 3-17, 3-18, 3-41, 3-42, 3-43, 3-46, 3-48, 47 3-64, 3-65, 3-66, 3-67, 3-68, 3-69, 3-70, 3 3-51, 3-91, 3-98, 4-21, 4-24, 4-25, 4-26, 48 3-71, 3-72, 3-73, 3-74, 3-75, 3-76, 3-77, 4 4-27, 4-28, 4-29, 4-30, 4-92, 4-93, 4-102, 49 3-78, 3-79, 3-80, 3-82, 3-83, 3-84, 3-85, 5 4-110, 4-117, 4-118, 4-119, 4-120, 50 3-86, 3-87, 3-88, 3-89, 3-90, 3-91, 3-93, 6 4-121, 4-125, 4-131, 6-2, B-1, E-4 51 3-94, 3-95, 3-96, 3-97, 3-98, 3-100, 52 3-101, 3-102, 3-103, 3-104, 3-105, 7 H 53 3-106, 3-110, 3-112, 3-113, 3-114, 8 hazardous waste ...............................3-18, 54 3-115, 3-116, 3-117, 3-118, 3-121, 9 4-133, B-5, B-7, B-8 55 3-122, 3-125, 3-127, 4-1, 4-2, 4-3, 4-4, 56 4-6, 4-7, 4-8, 4-9, 4-10, 4-11, 4-12, 4-13, 10 heat shock .............4-48, 4-49, 4-51, 4-124 57 4-16, 4-17, 4-19, 4-20, 4-22, 4-23, 4-24, 11 high burnup fuel................... 6-1, D-1, D-2 58 4-25, 4-26, 4-27, 4-28, 4-29, 4-31, 4-32, 12 high-level waste ...........................xxii, 1-3, 59 4-33, 4-34, 4-35, 4-36, 4-37, 4-38, 4-39, 13 4-97, 4-98, 4-101, G-2 60 4-40, 4-41, 4-42, 4-43, 4-44, 4-45, 4-46, 61 4-47, 4-48, 4-49, 4-50, 4-51, 4-52, 4-53, 14 I 62 4-54, 4-55, 4-56, 4-57, 4-58, 4-59, 4-60, 63 4-61, 4-62, 4-63, 4-65, 4-66, 4-67, 4-68, 15 Illinois Department of Natural 64 4-69, 4-70, 4-71, 4-72, 4-73, 4-74, 4-75, 16 Resources ................................xxix, 3-1, 65 4-77, 4-78, 4-79, 4-80, 4-81, 4-82, 4-83, 17 3-21, 3-22, 3-23, 3-39, 3-43, 3-52, 3-53, 66 4-84, 4-86, 4-87, 4-88, 4-89, 4-91, 4-92, 18 3-56, 3-57, 3-58, 3-59, 3-60, 3-67, 3-68, 67 4-93, 4-94, 4-95, 4-97, 4-98, 4-100, 19 3-69, 3-70, 3-71, 3-72, 3-78, 3-120, 68 4-101, 4-102, 4-103, 4-104, 4-105, 20 3-121, 4-50, 4-51, 4-74, 4-122, 4-123, 69 4-106, 4-107, 4-108, 4-109, 4-110, 21 4-125, 4-143, 7-1, B-7, E-5, E-6, E-8, E-9 70 4-112, 4-113, 4-114, 4-115, 4-116, 22 impingement.............................3-70, 3-71, 71 4-117, 4-118, 4-119, 4-120, 4-121, 23 3-72, 3-74, 3-75, 4-38, 4-39, 4-40, 4-41, 72 4-122, 4-123, 4-124, 4-125, 4-126, 24 4-42, 4-43, 4-44, 4-45, 4-52, 4-53, 4-54, 73 4-127, 4-128, 4-129, 4-130, 4-131, 25 4-124, 4-125 74 4-132, 4-136, 4-138, 4-139, 4-140, 26 independent spent fuel storage 75 4-141, 4-143, 4-144, 4-147, 5-1, A-1, 27 installation (ISFSI) ..................3-1, 3-17, 76 B-2, B-6, B-7, B-8, C-1, C-2, C-4, D-1, 28 3-19, 4-127 77 D-2, E-1, E-2, E-8, F-1, F-2, F-3, F-4, 29 Indian tribes ...........................3-81, 3-101, 78 F-5, F-6, F-7, F-8, F-9, F-10, F-11, F-12, 30 3-122, 4-91, 4-92 79 F-13, F-14, F-15, F-16, F-17, F-18, F-19, 80 F-20, F-21, F-22, F-23, F-24, F-25, F-26, 31 invasive species......................4-40, 4-111 81 F-27, F-28, F-29, F-30, F-31, F-33, F-37, 82 F-38, F-40, F-41, F-42, F-43, F-44, F-45, 32 L 83 F-46, G-1, G-2, G-3, G-4, G-6, G-7, G-8, 33 LaSalle County Station ................... iii, xxi, 84 G-9, G-10, G-11, G-12, G-13 34 xxii, xxiii, xxiv, xxv, xxx, 1-1, 1-2, 1-4, 85 long-term dose .................................. F-40 35 1-5, 1-6, 1-7, 1-8, 2-1, 2-2, 2-3, 2-4, 2-5, 86 low-level waste ...............3-17, 4-98, 4-101 36 2-8, 2-9, 2-10, 2-12, 2-13, 2-14, 2-16, 37 2-17, 2-18, 2-19, 2-20, 2-21, 2-22, 2-23, 87 M 38 2-24, 2-25, 2-26, 2-30, 3-1, 3-2, 3-3, 3-4, 39 3-5, 3-6, 3-7, 3-8, 3-9, 3-10, 3-11, 3-12, 88 Magnuson-Stevens Fishery 40 3-13, 3-14, 3-15, 3-16, 3-17, 3-18, 3-19, 89 Conservation and Management Act 41 3-20, 3-21, 3-22, 3-23, 3-24, 3-25, 3-26, 90 (MSA) ................................. xxx, 1-5, 1-6, 42 3-27, 3-28, 3-29, 3-30, 3-31, 3-32, 3-33, 91 3-73, 4-58, 4-145, B-6, B-9, C-3 43 3-34, 3-35, 3-36, 3-38, 3-39, 3-40, 3-41, 92 Marine Mammal Protection Act 44 3-42, 3-43, 3-44, 3-45, 3-46, 3-47, 3-49, 93 (MMPA) .................. xxx, 3-73, 3-123, B-9 45 3-50, 3-51, 3-52, 3-53, 3-54, 3-55, 3-56, 8-3

Index 1 mitigation.....................................xxii, xxxi, 43 R 2 1-3, 1-4, 4-17, 4-51, 4-53, 4-55, 4-57, 44 radioactive nuclides...........................3-14 3 4-63, 4-64, 4-86, 4-87, 4-132, 4-148, 5-1, 4 D-1, F-9, F-37, F-41 45 radon .................................. 3-13, 3-17, G-8 5 mixed waste ..............................3-13, 3-17 46 reactor............................ xxi, xxxi, 2-1, 2-2, 47 2-3, 2-9, 2-10, 2-28, 3-1, 3-6, 3-12, 3-15, 6 Myotis sodalis .................3-53, 3-57, 3-75, 48 3-17, 3-19, 3-21, 3-24, 3-29, 3-34, 3-43, 7 3-78, 3-119, 3-126, 3-130, 4-56, 4-57 49 3-51, 3-80, 3-97, 3-106, 4-2, 4-52, 4-60, 50 4-62, 4-65, 4-66, 4-76, 4-77, 4-78, 4-80, 8 N 51 4-83, 4-86, 4-88, 4-93, 4-97, 4-103, 9 National Environmental Policy Act 52 4-108, 4-127, 4-128, 4-132, 4-135, 6-1, 10 (NEPA) ...................................... xxii, xxx, 53 6-3, E-1, E-10, F-3, F-9, F-10, F-12, 11 1-1, 1-7, 2-1, 2-31, 3-73, 3-101, 3-112, 54 F-16, F-18, F-20, F-25, F-26, F-32, F-37, 12 3-124, 4-39, 4-56, 4-61, 4-65, 4-91, 55 F-40, G-1, G-2, G-3, G-4, G-7, G-11, 13 4-109, 4-121, 4-124, 4-137, 4-138, 56 G-12 14 4-145, 4-146, 5-1, 6-1, 6-2, B-2, C-1, 57 refurbishment ............................ 2-2, 3-80, 15 C-3, C-5, G-12, G-14 58 4-6, 4-28, 4-32, 4-61, 4-65, 4-114, 4-115 16 National Marine Fisheries Service 59 replacement power ....................xxiv, xxxi, 17 (NMFS)....................................xxxi, 3-73, 60 2-3, 2-5, 2-7, 2-16, 4-29, 4-71, 4-80, 18 4-55, 4-56, 4-57, 4-58, 4-142, B-6, C-1, 61 4-93, 4-94, 4-95, 4-100, 4-102, F-3, F-22, 19 C-2, C-3, C-5 62 F-39, F-40 20 National Pollutant Discharge Elimination 21 System (NPDES) ....................xxxi, 3-10, 63 S 22 3-11, 3-12, 3-18, 3-39, 3-41, 3-42, 3-43, 64 scoping .............................. iii, xxi, xxii, xxv, 23 3-44, 3-45, 3-97, 3-106, 3-108, 3-109, 65 1-1, 1-2, 1-5, 1-7, 4-1, 4-7, 4-20, 4-22, 24 3-121, 4-23, 4-26, 4-27, 4-28, 4-29, 4-30, 66 4-24, 4-31, 4-38, 4-61, 4-65, 4-72, 4-77, 25 4-32, 4-44, 4-46, 4-47, 4-51, 4-52, 4-53, 67 4-98, 4-101, 4-103, 4-113, 5-2, A-1, C-2, 26 4-73, 4-74, 4-75, 4-119, 4-120, 4-134, 68 C-3, C-4, D-1 27 4-136, 4-143, B-1, B-4, B-7, B-8, E-4, 28 E-7 69 seismic...................................... xxxii, 3-29, 70 3-34, F-4, F-9, F-11, F-12, F-15, F-24, 29 Native American tribes .....................3-81, 71 F-27, F-28 30 3-122, 4-91, 4-92 72 severe accident mitigation alternative 31 no-action alternative ..................... iii, xxiv, 73 (SAMA) .................................... xxiii, xxxi, 32 2-1, 2-3, 2-4, 2-23, 2-24, 2-26, 4-2, 4-34, 74 4-77, 4-78, 4-80, 4-81, 4-82, 4-83, 4-84, 33 4-39, 4-53, 4-57, 4-93, 4-98, 4-105, 75 4-85, 4-86, 4-87, 4-88, 4-145, 6-1, 6-2, 34 4-121, 4-133, 5-1 76 6-3, D-1, F-1, F-2, F-4, F-6, F-10, F-11, 35 nonattainment ...........................3-26, 4-19 77 F-13, F-14, F-15, F-16, F-17, F-18, F-19, 78 F-20, F-21, F-22, F-23, F-24, F-25, F-26, 36 O 79 F-27, F-28, F-29, F-30, F-31, F-32, F-33, 37 once-through cooling..................4-31, 4-38, 80 F-34, F-35, F-36, F-37, F-38, F-39, F-41, 38 4-44, 4-45, 4-117 81 F-42, F-43, F-45 82 severe accidents ........................ xxiii, xxxi, 39 P 83 4-1, 4-76, 4-77, 4-86, 4-91, 6-1, D-1, F-1, 40 postulated accidents .................4-1, 4-75, 84 F-11, F-20, F-37, F-40 41 4-76, 4-77, 4-91, G-1 85 solid waste.................................xxiv, 2-22, 42 pressurized water reactor...................xxxi 86 3-13, 3-16, 3-17, 3-97, 3-106, 4-13, 4-99, 87 4-102, B-1, E-4 8-4

Index 1 spent fuel .............................. xxii, 1-3, 3-6, 41 2-9, 2-10, 2-11, 2-12, 2-14, 2-15, 2-16, 2 3-12, 3-17, 3-19, 3-20, 4-52, 4-101, 42 2-17, 2-18, 2-19, 2-20, 2-21, 2-22, 2-27, 3 4-102, 4-135, E-1, G-1, G-2, G-3, G-4, 43 2-28, 2-29, 2-30, 2-31, 2-33, 3-17, 4-10, 4 G-6, G-7, G-8, G-9, G-11, G-12 44 4-14, 4-17, 4-67, 4-68, 4-70, 4-73, 4-137, 5 State Historic Preservation Office 45 4-138, 4-145, 6-3, G-3, G-5, G-7, G-13 6 (SHPO)...................................3-82, 4-60, 46 U.S. Environmental Protection Agency 7 4-61, 4-62, 4-147 47 (EPA) ..................................... xxviii, xxix, 8 State Pollutant Discharge Elimination 48 1-1, 2-4, 2-12, 2-21, 2-22, 2-23, 2-30, 9 System (SPDES) .............................. B-1 49 3-8, 3-10, 3-12, 3-13, 3-14, 3-15, 3-16, 50 3-25, 3-26, 3-27, 3-28, 3-29, 3-41, 3-42, 10 stormwater ...............................3-36, 3-39, 51 3-45, 3-51, 3-66, 3-67, 3-73, 3-93, 3-97, 11 3-43, 3-44, 3-45, 3-48, 4-26, 4-27, 4-28, 52 3-106, 3-108, 3-110, 3-113, 3-115, 12 4-29, 4-30, 4-31, 4-32, 4-33, 4-53, 4-119, 53 3-121, 3-122, 3-125, 3-130, 4-9, 4-11, 13 4-120, 4-125, B-4 54 4-12, 4-14, 4-15, 4-25, 4-39, 4-43, 4-44, 14 surface runoff .............................3-7, 3-30, 55 4-53, 4-73, 4-74, 4-89, 4-90, 4-104, 15 3-36, 3-39, 3-42, 3-44, 3-60, 4-26, 4-27, 56 4-105, 4-107, 4-108, 4-109, 4-114, 16 4-28, 4-29, 4-30, 4-32, 4-34, 4-108, 57 4-121, 4-124, 4-127, 4-128, 4-129, 17 4-110, 4-118, 4-119, 4-120, 4-125, B-4 58 4-130, 4-132, 4-135, 4-136, 4-138, 18 surface water ............................3-10, 3-35, 59 4-139, 4-140, 4-143, 4-147, 5-1, 7-1, B-1, 19 3-36, 3-39, 3-40, 3-41, 3-45, 3-59, 3-98, 60 B-3, B-4, B-5, B-8, B-9, D-1, E-3, E-4, 20 4-21, 4-22, 4-23, 4-26, 4-27, 4-28, 4-29, 61 E-5, E-8, E-9, F-20 21 4-30, 4-33, 4-47, 4-52, 4-74, 4-92, 4-102, 62 U.S. Fish and Wildlife Service 22 4-110, 4-116, 4-117, 4-118, 4-119, 63 (FWS) ................................ xxix, 1-6, 1-7, 23 4-120, 4-125, 4-131, 6-2, B-1, B-4 64 2-8, 2-9, 2-14, 2-15, 2-33, 3-53, 3-58, 65 3-73, 3-74, 3-75, 3-76, 3-77, 3-78, 3-79, 24 T 66 3-107, 3-108, 3-119, 3-126, 4-55, 4-56, 25 taxes .................................3-93, 3-95, 4-65 67 4-57, 4-58, 4-111, 4-136, 4-142, B-6, 26 transmission line corridors ................4-6, 68 C-1, C-2, C-5 27 4-29, 4-34 69 uranium................................. xxii, 2-8, 3-6, 28 transmission lines ..............................2-4, 70 3-19, 4-1, 4-3, 4-4, 4-34, 4-35, 4-36, 29 2-12, 2-13, 2-14, 2-16, 3-1, 3-7, 3-20, 71 4-89, 4-100, 4-101, 4-102, 4-104, G-1, 30 3-21, 3-72, 3-74, 3-78, 3-79, 3-99, 3-100, 72 G-2, G-4, G-9 31 4-2, 4-5, 4-6, 4-7, 4-19, 4-20, 4-28, 4-29, 32 4-30, 4-31, 4-34, 4-36, 4-37, 4-38, 4-53, 73 W 33 4-60, 4-62, 4-63, 4-64, 4-72, 4-75 74 wastewater................................. 3-1, 3-18, 34 tritium ...............................3-15, 3-51, 4-25 75 3-39, 3-42, 3-43, 3-45, 3-91, 4-119, 76 4-120, 4-123, 4-125, 6-2, E-4, E-7, E-8 35 U 77 Y 36 U.S. Army Corps of Engineers ......... 3-20, 37 3-35, 3-45, 3-59, 3-127, 4-26, 4-28, 4-29, 78 Yucca Mountain ......................... G-2, G-3, 38 4-53, B-4, B-7, B-8 79 G-4, G-6, G-7, G-8, G-9, G-11, G-12, 39 U.S. Department of Energy 80 G-13 40 (DOE) ............................... xxviii, 2-4, 2-8, 8-5

APPENDIX A COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW

A. COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW Comments Received During the Scoping Period The scoping process for the environmental review of the license renewal application for LaSalle County Station, Units 1 and 2 (LSCS) began on February 3, 2015, with the publication of the U.S. Nuclear Regulatory Commissions (NRCs) notice of intent to conduct scoping in the Federal Register (80 FR 5793). The scoping process included two public meetings held in Ottawa, Illinois, on March 10, 2015. Approximately 30 people attended the meetings. After the NRCs prepared statements pertaining to the license renewal process, the meetings were open for public comments. Attendees provided oral statements that were recorded and transcribed by a certified court reporter. A summary and transcripts of the scoping meetings are available using the NRCs Agencywide Documents Access and Management System (ADAMS). The ADAMS Public Electronic Reading Room is accessible at http://www.nrc.gov/reading-rm/adams.html. The scoping meetings summary is available at ADAMS No. ML15091A329. Transcripts for the afternoon and evening meetings are available at ADAMS Nos. ML15083A538 and ML15089A580, respectively. In addition to comments received during the public meetings, one comment was received electronically. A total of 15 commenters provided comments during the scoping period. Comments from 12 of the 15 commenters were in support of license renewal for LSCS or in support of nuclear power in general. These comments are not within the scope of this license renewal review and, thus, were not responded to by the NRC staff. These commenters, along with their affiliation and the source of their comments (i.e., afternoon or evening scoping meeting transcript) are listed in the LSCS Scoping Summary Report available at ADAMS No. ML15147A380. Comments received from the other 3 of the 15 commenters (Linda Lewison, Marvin Lewis, and Nelson Dewey) do not fall within or are specifically excluded from the purview of the NRCs environmental review related to license renewal. These comments addressed the disposition of spent nuclear fuel and safety concerns associated with fuel enrichment and hydraulic fracturing. These comments and the NRC staffs responses to these comments are available in the LSCS Scoping Summary Report at ADAMS No. ML15147A380. A-1

APPENDIX B APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS

1 B. APPLICABLE LAWS, REGULATIONS, AND OTHER 2 REQUIREMENTS 3 There are a number of Federal laws and regulations that affect environmental protection, health, 4 safety, compliance, and consultation at every nuclear power plant licensed by the U.S. Nuclear 5 Regulatory Commission (NRC). Certain Federal environmental requirements have been 6 delegated to state authorities for implementation, enforcement, or oversight. Furthermore, 7 states have also enacted laws to protect public health and safety and the environment. It is the 8 NRCs mission, among other things, to ensure that U.S. nuclear power plants are operated in a 9 manner that provides adequate protection of the public health and safety and of the 10 environment through compliance with applicable Federal and state laws, regulations, and other 11 requirements. 12 The requirements that may be applicable to the operation of NRC-licensed nuclear power plants 13 encompass a broad range of Federal and state laws and regulations, addressing environmental, 14 historic and cultural, health and safety, transportation, and other concerns. Generally, these 15 laws and regulations are relevant to how the work involved in performing the proposed action 16 would be conducted to protect workers, the public, and environmental resources. Some of 17 these laws and regulations require permits or consultation with other Federal agencies or state, 18 tribal, or local governments. 19 The Atomic Energy Act of 1954, as amended (AEA) (42 United States Code (U.S.C.) §2011 20 et seq.), authorizes any state to enter into agreement with the NRC to assume regulatory 21 authority for certain activities (see 42 U.S.C. §2021). For example, through this Agreement 22 State Program, Illinois assumed regulatory responsibility over certain byproduct, source, and 23 quantities of special nuclear materials not sufficient to form a critical mass. The Illinois 24 Emergency Management Agency (IEMA), Division of Nuclear Safety, administers several 25 programs to protect citizens and the environment, including: a comprehensive monitoring 26 system for the 11 operating nuclear power reactors in Illinois, inspection and regulation of 27 radioactive materials licensees and x-ray machines, and oversight of cleanup efforts at sites 28 contaminated with radioactive materials (IEMA undated). 29 In addition to carrying out some Federal programs, state legislatures develop their own laws. 30 State statutes supplement, as well as implement, Federal laws for the protection of air, water 31 quality, and groundwater. State legislation may address solid waste management programs, 32 locally rare or endangered species, and historic and cultural resources. 33 The Clean Water Act (CWA) (33 U.S.C. §1251 et seq.) allows for primary enforcement and 34 administration through state agencies, provided that the state program is at least as stringent as 35 the Federal program. The state program must conform to the CWA and to the delegation of 36 authority for the Federal National Pollutant Discharge Elimination System (NPDES) program 37 from the U.S. Environmental Protection Agency (EPA) to the state. The primary mechanism to 38 control water pollution is the requirement for direct dischargers to obtain an NPDES permit or, in 39 the case of states where the authority has been delegated from the EPA, such as Illinois, a 40 State Pollutant Discharge Elimination System permit. 41 One important difference between Federal regulations and certain state regulations is the 42 definition of waters regulated by the state. Certain state regulations may include underground 43 waters, whereas the CWA only regulates surface waters. The Illinois Environmental Protection 44 Agency (IEPA), Bureau of Water, Water Pollution Control, conducts the numerous programs, 45 including permit programs and surface water quality monitoring and assessment programs, to 46 protect and enhance the quality of the states surface waters (IEPA undated). B-1

Appendix B 1 Federal and State Requirements 2 LaSalle County Station, Units 1 and 2 (LSCS), are subject to Federal and State requirements. 3 Table B-1 lists the principal Federal and State laws and regulations that are used or mentioned 4 in this supplemental environmental impact statement (SEIS) for LSCS. 5 Federal and State Requirements Law/regulation Requirements Current operating license and license renewal Atomic Energy Act of 1954, The AEA and the Energy Reorganization Act of 1974, as amended as amended (AEA), (42 U.S.C. §5801 et seq.), give the NRC the licensing and regulatory 42 U.S.C. §2011 et seq. authority for nuclear energy uses within the commercial sector. These regulations give the NRC responsibility for licensing and regulating commercial uses of atomic energy and allow the NRC to establish dose and concentration limits for protection of workers and the public for activities under NRC jurisdiction. The NRC implements these responsibilities through regulations set forth in Title 10 of the Code of Federal Regulations (10 CFR). National Environmental NEPA requires Federal agencies to integrate environmental values into Policy Act of 1969, as their decisionmaking process by considering the environmental impacts of amended (NEPA), proposed Federal actions and reasonable alternatives to those actions. 42 U.S.C. §4321 et seq. NEPA establishes policy, sets goals (in Section 101), and provides means (in Section 102) for carrying out the policy. Section 102(2) contains action-forcing provisions to ensure that Federal agencies follow the letter and spirit of the Act. For major Federal actions significantly affecting the quality of the human environment, Section 102(2)(C) of NEPA requires Federal agencies to prepare a detailed statement that includes the environmental impact of the proposed action and other specified information. Title 10 of the Code of Regulations in 10 CFR Part 51, Environmental protection regulations for Federal Regulations domestic licensing and related regulatory functions, contain (10 CFR), Energy, Part 51 environmental protection regulations applicable to the NRCs domestic licensing and related regulatory functions. These regulations implement Section 102(2) of NEPA. 10 CFR Part 54 Regulations in 10 CFR Part 54, Requirements for renewal of operating licenses for nuclear power plants, govern the issuance of renewed operating licenses and renewed combined licenses for nuclear power plants licensed pursuant to Sections 103 or 104b of the AEA and Title II of the Energy Reorganization Act. The regulations focus on managing the effects of aging during the period of extended operation on the functionality of specific structures and components. The rule is intended to ensure that important systems, structures, and components will maintain their intended functions during the period of extended operation. B-2

Appendix B Law/regulation Requirements 10 CFR Part 50 Regulations in 10 CFR Part 50, Domestic licensing of production and utilization facilities, are NRC regulations issued under the AEA and Title II of the Energy Reorganization Act to provide for the licensing of production and utilization facilities. This part also gives notice to all persons who knowingly provide to any licensee, applicant, contractor, or subcontractor, components, equipment, materials, or other goods or services, that relate to a licensees or applicants activities subject to this part, that they may be individually subject to NRC enforcement action for violation of 10 CFR 50.5. Air quality protection Clean Air Act (CAA), The CAA is intended to protect and enhance the quality of the Nations air 42 U.S.C. §7401 et seq. resources so as to promote the public health and welfare and the productive capacity of its population. The CAA establishes requirements to ensure maintenance of air quality standards and authorizes individual states to manage permits. Section 118 of the CAA requires each Federal agency, with jurisdiction over properties or facilities engaged in any activity that may result in the discharge of air pollutants, to comply with all Federal, state, inter-state, and local requirements with regard to the control and abatement of air pollution. Section 109 of the CAA directs the U.S. Environmental Protection Agency (EPA) to set National Ambient Air Quality Standards (NAAQS) for criteria pollutants. The EPA has identified and set NAAQS for the following criteria pollutants: particulate matter, sulfur dioxide, carbon monoxide, ozone, nitrogen dioxide, and lead. Section 111 of the CAA requires establishment of national performance standards for new or modified stationary sources of atmospheric pollutants. Section 160 of the CAA requires that specific emission increases must be evaluated before permit approval to prevent significant deterioration of air quality. Section 112 requires specific standards for release of hazardous air pollutants (including radionuclides). These standards are implemented through plans developed by each state and approved by the EPA. The CAA requires sources to meet standards and obtain permits to satisfy those standards. Nuclear power plants may be required to comply with the CAA Title V, Sections 501-507, for sources subject to new source performance standards or sources subject to National Emission Standards for Hazardous Air Pollutants. Emissions of air pollutants are regulated by the EPA in 40 CFR Parts 50 to 99. Illinois Administrative Code This part of the IAC sets standards for air emissions from auxiliary boilers, (IAC), Title 35, emergency generators, radwaste volume reduction system, cooling Environmental Protection, towers, and ancillary operations. Subtitle B, Air Pollution, Chapter I, Pollution Control Board, Subchapter a, Permits and General Provisions, Part 201, Permits and General Provisions B-3

Appendix B Law/regulation Requirements Water resources protection Clean Water Act (CWA), The CWA was enacted to restore and maintain the chemical, physical, 33 U.S.C. §1251 et seq., and biological integrity of the Nations waters. The Act requires each and the NPDES Federal agency, with jurisdiction over properties or facilities engaged in (40 CFR 122) any activity that may result in the discharge or runoff of pollutants to surface waters, to comply with all Federal, state, inter-state, and local requirements. As authorized by the CWA, the National Pollutant Discharge Elimination System (NPDES) permit program controls water pollution by regulating point sources that discharge pollutants into waters of the United States. The NPDES program requires all facilities that discharge pollutants from any point source into waters of the United States to obtain an NPDES permit. A nuclear power plant may also participate in the NPDES General Permit for Industrial Stormwater due to stormwater runoff from industrial or commercial facilities to waters of the United States. EPA is authorized under the CWA to directly implement the NPDES program; however, EPA has authorized many states to implement all or parts of the national program. Section 401 of the CWA requires states to certify that the permitted discharge would comply with all limitations necessary to meet established state water quality standards, treatment standards, or schedule of compliance. The U.S. Army Corps of Engineers is the lead agency for enforcement of CWA wetland requirements (33 CFR Part 320). Under Section 401 of the CWA, the EPA or a delegated state agency has the authority to review and approve, condition, or deny all permits or licenses that may result in a discharge to waters of the State, including wetlands. Coastal Zone Management Congress enacted the CZMA in 1972 to address the increasing pressures Act of 1972, as amended of over-development upon the Nations coastal resources. The National (CZMA), 16 U.S.C. §1451 et Oceanic and Atmospheric Administration administers the Act. The CZMA seq. encourages states to preserve, protect, develop, and, where possible, restore or enhance natural coastal resources such as wetlands, floodplains, estuaries, beaches, dunes, barrier islands, and coral reefs, as well as the fish and wildlife using those habitats. Participation by states is voluntary. To encourage states to participate, the CZMA makes Federal financial assistance available to any coastal state or territory, including those on the Great Lakes, that are willing to develop and implement a comprehensive coastal management program. IAC, Title 35, This part of the IAC implements the NPDES program under the CWA. Environmental Protection, Subtitle C, Water Pollution, Chapter I, Pollution Control Board, Part 309, Permits Wild and Scenic Rivers Act, The Wild and Scenic Rivers Act created the National Wild and Scenic 16 U.S.C. §271 et seq. Rivers System, which was established to protect the environmental values of free flowing streams from degradation by impacting activities, including water resources projects. 415 Illinois Compiled This part of the ILCS sets forth Illinois State standards for water pollution. Statutes (ILCS) 5, Environmental Protection Act, Title III, Water Pollution B-4

Appendix B Law/regulation Requirements Waste management and pollution prevention Resource Conservation and RCRA requires the EPA to define and identify hazardous waste; establish Recovery Act (RCRA), standards for its transportation, treatment, storage, and disposal; and 42 U.S.C. §6901 et seq. require permits for persons engaged in hazardous waste activities. Section 3006 (42 U.S.C. §6926) allows states to establish and administer these permit programs with EPA approval. EPA regulations implementing the RCRA are found in 40 CFR Parts 260 through 283. Regulations imposed on a generator or on a treatment, storage, and/or disposal facility vary according to the type and quantity of material or waste generated, treated, stored, and/or disposed. The method of treatment, storage, and/or disposal also impacts the extent and complexity of the requirements. Pollution Prevention Act, The Pollution Prevention Act establishes a national policy for waste 42 U.S.C. §13101 et seq. management and pollution control that focuses first on source reduction, then on environmental issues, safe recycling, treatment, and disposal. 10 CFR Part 20 Regulations in 10 CFR Part 20, Standards for protection against radiation, establish standards for protection against ionizing radiation resulting from activities conducted under licenses issued by the NRC. These regulations are issued under the AEA and the Energy Reorganization Act. The purpose of these regulations is to control the receipt, possession, use, transfer, and disposal of licensed material by any licensee in such a manner that the total dose to an individual (including doses resulting from licensed and unlicensed radioactive material and from radiation sources other than background radiation) does not exceed the standards for protection against radiation prescribed in the regulations in this part. IAC Title 35, Environmental This part of the IAC establishes standards for generators of hazardous Protection, Subtitle G, waste. Waste Disposal, Chapter I, Pollution Control Board, Subchapter c, Hazardous Waste Operating Requirements, Part 722, Standards Applicable to Generators of Hazardous Waste IAC Title 35, Environmental This part of the IAC presents criteria for transporting, storing, and applying Protection, Subtitle C, sludge on land in an environmentally acceptable manner. In addition, it Water Pollution, Chapter II, identifies methods of sludge transportation, handling, storage, application Environmental Protection and monitoring to control potential environmental problems. Agency, Part 391, Design Criteria for Sludge Application on Land B-5

Appendix B Law/regulation Requirements IAC Title 32, Energy, This part of the IAC establishes one of the systems for the regulation of Chapter II, Illinois the use of facilities in the State of Illinois to: (1) collect, store, treat or Emergency Management dispose of low-level radioactive waste; (2) maintain a data base as to the Agency, Subchapter d, location of all such waste in the State of Illinois; and (3) implement some Low Level Radioactive of the requirements, prohibitions and mandates of the Compact, the Waste/Transportation, Radioactive Waste Compact Enforcement Act (45 ILCS 141), the Part 609, Access to Radioactive Waste Tracking and Permitting Act (420 ILCS 37) and the Facilities for Treatment, Illinois Low-Level Radioactive Waste Management Act (420 ILCS 20). Storage, or Disposal of This Part establishes a system for monitoring and tracking shipments of Low-Level Radioactive low-level radioactive waste into, out of or within the State of Illinois for the Waste purpose of tracking the points of origin of the shipments, as transported to the places of destination of the shipments. This Part establishes an enforcement and verification system directed to the movements of low-level radioactive waste into, out of or within the State of Illinois. This Part applies to any generator, broker, owner or operator of any treatment or disposal facility, or to any person who sends low-level radioactive waste into, within or out of the State of Illinois. Protected species Endangered Species Act The Endangered Species Act (ESA) was enacted to prevent the further (ESA), 16 U.S.C. §1531 decline of endangered and threatened species and to restore those et seq. species and their critical habitats. Section 7 of the Act requires Federal agencies to consult with the U.S. Fish and Wildlife Service or the National Marine Fisheries Service (NMFS) on agency actions that may affect listed species or designated critical habitats. Magnuson-Stevens Fishery The MSA governs marine fisheries management in U.S. Federal waters. Conservation and The Act created eight regional fishery management councils and includes Management Act (MSA), measures to rebuild overfished fisheries, protect essential fish habitat, and 16 U.S.C. §1801 et seq. reduce bycatch. Under Section 305 of the Act, Federal agencies are required to consult with NMFS for any agency actions that may adversely affect essential fish habitat. Historic preservation and cultural resources National Historic The NHPA was enacted to create a national historic preservation program, Preservation Act (NHPA), including the National Register of Historic Places and the Advisory Council 16 U.S.C. §470 et seq. on Historic Preservation. Section 106 of the Act requires Federal agencies to take into account the effects of their undertakings on historic properties. The Advisory Council on Historic Preservation regulations implementing Section 106 of the Act are found in 36 CFR Part 800. The regulations call for public involvement in the Section 106 consultation process, including Indian Tribes and other interested members of the public, as applicable. 1 Operating Licenses and Other Permits 2 Table B-2 lists the licenses and permits issued by Federal, state, and local authorities for 3 activities at LSCS. B-6

Appendix B 1 Licenses and Permits Permit Number Dates Responsible Agency Operating license NPF-11 Issued: 04/17/1982 NRC Expires: 04/17/2022 Operating license NPF-18 Issued: 12/16/1983 NRC Expires: 12/16/2023 NPDES permit IL0048151 Issued: 07/05/2013 IEPA, Division of Expires: 07/31/2018 Water Pollution Control Federally enforceable state Application Issued: 12/11/2000 IEPA, Division of operating permit (FESOP) for #750440086 Expires: 12/11/2005 Air Pollution Control air emissions from ID# 099802AA Renewal application emergency generators, submitted storage tanks, and 7/15/2005(a) dispensing facilities Notification of hazardous ILD000803643 Not Applicable IEPA, Bureau of Land waste activity as a small quantity generator of hazardous waste Department of Army permit CEMVR-OD-P-2006- Issued: 04/16/2006 U.S. Army Corps of for maintenance dredging at 185 Expires: 12/31/2015(b) Engineers river screen house intake Waste tracking permit for IL-0104 Not Applicable IEMA, Division of shipments of low-level Nuclear Safety radioactive waste License to deliver radioactive T-IL009-L14 Renewed annually Tennessee Department material to processing facility of Environment and in Tennessee Conservation Permit to deliver radioactive 010000028 Renewed annually Utah Department of material to disposal facility in Environmental Quality Utah Dam safety regarding DS2000237 Issued: 12/20/2000 Illinois Department of operation and maintenance of Expires: Not Natural Resources, Office cooling reservoir dam Applicable of Water Resources Hazardous materials 051713 550 083VX Issued: 05/17/2013 U.S. Department of certificate of registration Expires: 06/30/2016 Transportation, Pipeline and Hazardous Materials Safety Administration (a) 415 ILCS 5, Title II, Air Pollution, Sec. 9.1(f) extends the effective term of the FESOP if the permit holder submits a completed application for renewal to the IEPA at least 90 days prior to the permit expiration. Exelon met this requirement, therefore, the permit is administratively extended (415 ILCS 5/9.1). (b) Extension of this permit must be filed at least 1 month prior to the permit expiration date (Permit CEMVR-OD-P-2006-185, p.2, General Condition #1). LSCS applied for a renewed permit on 11/20/2015. Sources: Exelon 2014, 2015 B-7

Appendix B 1 References 2 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 3 production and utilization facilities. 4 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 5 protection regulations for domestic licensing and related regulatory functions. 6 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 7 renewal of operating licenses for nuclear power plants. 8 40 CFR Part 122. Code of Federal Regulations, Title 40, Protection of Environment, Part 122, 9 EPA administered permit programs: the National Pollutant Discharge Elimination System. 10 49 CFR Part 107. Code of Federal Regulations, Title 49, Transportation, Part 107, Hazardous 11 materials program procedures. 12 49 U.S.C. 5108. United States Code, Title 49, Chapter 51, Part 5108, Registration. 13 [IAC] Illinois Administrative Code Title 32, Chapter II, Subchapter d, Part 609, Access to 14 facilities for treatment, storage, or disposal of low-level radioactive waste. 15 [IAC] Illinois Administrative Code Title 35, Subtitle B, Chapter I, Subchapter a, Part 201, 16 Permits and general provisions. 17 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter I, Part 309, Permits. 18 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter II, Part 391, Design criteria for 19 sludge application on land. 20 [IAC] Illinois Administrative Code Title 35, Subtitle G, Chapter I, Subchapter c, Part 722, 21 Standards applicable to generators of hazardous waste. 22 415 ILCS 5/Tit. II. Illinois Compiled Statutes. Chapter 415, 5, Environmental Protection Act, 23 Title II, Air pollution. 24 415 ILCS 5/Tit. III. Illinois Compiled Statutes. Chapter 415, 5, Environmental Protection Act, 25 Title III, Water pollution. 26 [AEA] Atomic Energy Act of 1954, as amended. 42 U.S.C. §2011 et seq. 27 [CAA] Clean Air Act of 1963, as amended. 42 U.S.C. §7401 et seq. 28 [CWA] Clean Water Act of 1977, as amended. 33 U.S.C. §1251 et seq. 29 [ESA] Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 30 [Exelon] Exelon Generation Company, LLC. 2014. LaSalle County Station, Units 1 and 2 31 License Renewal Application, Applicants Environmental Report. December 9, 2014. 32 Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 33 ML14343A897. 34 [Exelon] Exelon Generation Company, LLC. 2015. E-mail from N. Ranek, Exelon, to 35 D. Drucker, NRC.

Subject:

RE: USACE permit. December 10, 2015. ADAMS 36 No. ML15363A237. 37 [FWCA] Fish and Wildlife Coordination Act of 1934, as amended. 16 U.S.C. §661 et seq. 38 [IEMA] Illinois Emergency Management Agency, Division of Nuclear Safety. undated. Available 39 at <http://www.illinois.gov/iema/Pages/default.aspx> (accessed September 3, 2015). B-8

Appendix B 1 [IEPA] Illinois Environmental Protection Agency, Bureau of Water. undated. Water Pollution 2 Control. Available at <http://www.epa.state.il.us/water/index-wpc.html> (accessed 3 3 September 2015). 4 [MMPA] Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. §1361 et seq. 5 [MSA] Magnuson-Stevens Fishery Conservation and Management Act, as amended. 6 16 U.S.C. §1801 et seq. 7 [NHPA] National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq. 8 Pollution Prevention Act of 1990. 42 U.S.C. §13101 et seq. 9 [RCRA] Resource Conservation and Recovery Act of 1976, as amended. 42 U.S.C. §6901 10 et seq. 11 Wild and Scenic Rivers Act, as amended. 16 U.S.C. §1271 et seq. B-9

1 APPENDIX C 2 CONSULTATION CORRESPONDENCE

1 C. CONSULTATION CORRESPONDENCE 2 Endangered Species Act (ESA) Section 7 Consultation 3 C.1.1. Federal Agency Obligations Under ESA Section 7 4 As a Federal agency, the U.S. Nuclear Regulatory Commission (NRC) must comply with the 5 Endangered Species Act of 1973, as amended (16 United States Code (U.S.C.) 1531 et seq., 6 herein referred to as ESA), as part of any action authorized, funded, or carried out by the 7 agency, such as the proposed agency action that this supplemental environmental impact 8 statement (SEIS) evaluates whether to issue renewed licenses for the continued operation of 9 LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years beyond the current 10 license terms. Under section 7 of the ESA, the NRC must consult with the U.S. Fish and 11 Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS) (referred to jointly as 12 the Services and individually as Service), as appropriate, to ensure that the proposed agency 13 action is not likely to jeopardize the continued existence of any endangered or threatened 14 species or result in the destruction or adverse modification of designated critical habitat. 15 The ESA and the regulations that implement ESA section 7 (Title 50 of the Code of Federal 16 Regulations (50 CFR) Part 402, Interagency cooperationEndangered Species Act of 1973, 17 as amended) describe the consultation process that Federal agencies must follow in support of 18 agency actions. As part of this process, the Federal agency shall either request that the 19 Services provide a list of any listed or proposed species or designated or proposed critical 20 habitats that may be present in the action area or request that the Services concur with a list of 21 species and critical habitats that the Federal agency has created (50 CFR 402.12(c)). If it is 22 determined that any such species or critical habitats may be present, the Federal agency is to 23 prepare a biological assessment to evaluate the potential effects of the action and determine 24 whether the species or critical habitat are likely to be adversely affected by the action 25 (16 U.S.C. 1536(c), 50 CFR 402.12(a)). Further, biological assessments are required for any 26 agency action that is a major construction activity (50 CFR 402.12(b)), which the ESA 27 regulations define to include major Federal actions significantly affecting the quality of the 28 human environment under the National Environmental Policy Act of 1969, as amended 29 (42 U.S.C. 4321 et seq., herein referred to as NEPA) (50 CFR 402.02). 30 Federal agencies may fulfill their obligations to consult with the Services under ESA section 7 31 and to prepare a biological assessment in conjunction with the interagency cooperation 32 procedures required by other statutes, including NEPA (50 CFR 402.06(a)). In such cases, the 33 Federal agency should include the results of the ESA section 7 consultation in the NEPA 34 document (50 CFR 402.06(b)). Accordingly, Section C.1.2 describes the biological assessment 35 prepared for the proposed agency action evaluated in this SEIS, and Section C.1.3 describes 36 the chronology and results of the ESA section 7 consultation. 37 C.1.2. Biological Assessment 38 The NRC considers this SEIS to fulfill its obligation to prepare a biological assessment under 39 ESA section 7. Accordingly, the NRC did not prepare a separate biological assessment for the 40 proposed LSCS license renewal. 41 Although the contents of a biological assessment are at the discretion of the Federal agency 42 (50 CFR 402.12(f)), the ESA regulations suggest information that agencies may consider for 43 inclusion. The NRC has considered this information in the following sections. C-1

Appendix C 1 Section 3.8 describes the action area and the Federally listed and proposed species and 2 designated and proposed critical habitat that have the potential to be present in the action area. 3 This section includes information pursuant to 50 CFR 402.12(f)(1), (2), and (3). 4 Section 4.8 provides an assessment of the potential effects of the proposed LSCS license 5 renewal on the species and critical habitat present and the NRCs effect determinations, which 6 are consistent with those identified in Section 3.5 of the Endangered Species Consultation 7 Handbook (FWS and NMFS 1998). The NRC also addresses alternatives to the proposed 8 action. This section includes information pursuant to 50 CFR 402.12(f)(4) and (5). 9 C.1.3. Chronology of ESA Section 7 Consultation 10 Upon receipt of Exelons license renewal application, the NRC staff considered whether any 11 Federally listed or proposed species or designated or proposed critical habitats may be present 12 in the action area (as defined at 50 CFR 402.02) for the proposed LSCS license renewal. No 13 species under the NMFSs jurisdiction occur within the action area. Therefore, the NRC staff did 14 not consult with the NMFS. With respect to species under the FWSs jurisdiction, in late 15 February 2015, NRC staff filled an online form for an updated protected species list for LSCS on 16 the FWSs Environmental Conservation Online System (ECOS), Information for Planning and 17 Conservation (IPaC). FWS (2015b) responded with a list of threatened and endangered 18 species that may occur in the project location and may be affected by the Federal action. In 19 October 2015, NRC staff checked the FWS (2015a) online Illinois County distribution of listed 20 species for updates. From this, the NRC staff compiled a list of ESA-protected species and 21 critical habitats in the vicinity of the facility. 22 In Section 3.8, the NRC staff concludes that no ESA-protected species or critical habitats occur 23 in the action area, and, in Section 4.8, concludes that the proposed action would have no effect 24 on any ESA-protected species or critical habitats. The FWS (2013) does not typically provide its 25 concurrence with no effect determinations by Federal agencies. Thus, the ESA does not 26 require further informal consultation or the initiation of formal consultation with the FWS for the 27 proposed LSCS license renewal. Nonetheless, because this SEIS constitutes the NRCs 28 biological assessment, the NRC staff submitted a copy of the draft SEIS to the FWS for its 29 review in accordance with 50 CFR 402.12(j). 30 Table C-1 lists the correspondence related to the NRCs ESA obligations with respect to its 31 review of the LSCS license renewal application. This table will be updated in the final SEIS, as 32 applicable, to include correspondence transpiring between the issuance of the draft and final 33 SEIS. 34 ESA Section 7 Consultation Correspondence Sender and Date Recipient Description ADAMS No.(a) February 27, 2015 FWS to NRC List of threatened and endangered species that ML15126A069 may occur in your proposed project location, and/or may be affected by your proposed project March 3, 2015 NRC to FWS Request for scoping comments/notification of ML15062A534 scoping meetings (a) These documents can be accessed through the NRCs Agencywide Documents Access and Management System (ADAMS) at http://adams.nrc.gov/wba/. C-2

Appendix C 1 Essential Fish Habitat Consultation 2 The NRC must comply with the Magnuson-Stevens Fishery Conservation and Management 3 Act, as amended (16 U.S.C. §1801 et seq., herein referred to as MSA), for any actions 4 authorized, funded, or undertaken, or proposed to be authorized, funded, or undertaken that 5 may adversely affect any essential fish habitat (EFH) identified under the MSA. 6 In Sections 3.8 and 4.8 of this SEIS, the NRC staff concludes that the NMFS has not designated 7 EFH under the MSA in the Illinois River and that the proposed LSCS license renewal would 8 have no effect on EFH. Thus, the MSA does not require the NRC to consult with the NMFS for 9 the proposed LSCS license renewal. 10 National Historic Preservation Act of 1966 Consultation 11 The National Historic Preservation Act (NHPA) requires Federal agencies to consider the effects 12 of their undertakings on historic properties and consult with applicable state and Federal 13 agencies, tribal groups, and individuals and organizations with a demonstrated interest in the 14 undertaking before taking action. Historic properties are defined as resources that are eligible 15 for listing on the National Register of Historic Places. The historic preservation review process 16 (Section 106 of the National Historic Preservation Act of 1966, as amended) is outlined in 17 regulations issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800. 18 In accordance with 36 CFR 800.8(c), the NRC has elected to use the NEPA process to comply 19 with its obligations under Section 106 of the NHPA. 20 Table C-2 lists the chronology of consultations and consultation documents related to the NRC 21 Section 106 review. The NRC staff is required to consult with the noted agencies and 22 organizations in accordance with the statutes listed above. Table C-2 will be updated in the 23 final SEIS, as applicable, to include correspondence transpiring between the issuance of the 24 draft and final SEIS. 25 NHPA Correspondence Date Sender and Recipient Description ADAMS No. (a) February 9, 2015 D. Wrona (NRC) to R. Nelson (ACHP) Request for scoping ML15023A094 comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to A. Haaker, Illinois Request for scoping ML15022A578 Historic Preservation Agency comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Greendeer, Request for scoping ML15023A139 Ho-Chunk Nation comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to S. Cadue, Kickapoo Request for scoping ML15023A139 Tribe of Indians of the Kickapoo comments/notification of Reservation in Kansas Section 106 review February 9, 2015 D. Wrona (NRC) to G. Salazar, Request for scoping ML15023A139 Kickapoo Tribe of Oklahoma comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to D. Lankford, Miami Request for scoping ML15023A139 Tribe of Oklahoma comments/notification of Section 106 review C-3

Appendix C Date Sender and Recipient Description ADAMS No. (a) February 9, 2015 D. Wrona (NRC) to J. Froman, Peoria Request for scoping ML15023A139 Tribe of Indians of Oklahoma comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Barrett, Citizen Request for scoping ML15023A139 Potawatomi Nation comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Bender, Sac and Request for scoping ML15023A139 Fox Tribe of the Mississippi in comments/notification of Iowa/Meskwaki Section 106 review February 9, 2015 D. Wrona (NRC) to B. Robidoux, Sac Request for scoping ML15023A139 and Fox Nation of Missouri in Kansas comments/notification of and Nebraska Section 106 review February 9, 2015 D. Wrona (NRC) to G. Thurman, Sac Request for scoping ML15023A139 and Fox Nation comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Warren, Pokagon Request for scoping ML15023A139 Band of Potawatomi comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to H. Frank, Forest Request for scoping ML15023A139 County Potawatomi comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to K. Meshigaud, Request for scoping ML15023A139 Hannahville Indian Community comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to S. Ortiz, Prairie Request for scoping ML15023A139 Band of Potawatomi Nation comments/notification of Section 106 review February 9, 2015 D. Wrona (NRC) to J. Blackhawk, Request for scoping ML15023A139 Winnebago Tribe of Nebraska comments/notification of Section 106 review April 1, 2015 R Leibowitz, Illinois Historic Illinois Historic ML15106A791 Preservation Agency to D. Wrona Preservation Agency (NRC) Section 106 Clearance (IHPA Log #009031615) August 6, 2015 R. Chazell (NRC) to File Summary of Visit to ML15205A286 Illinois Historic Preservation Agency associated with the LaSalle County Station, Units 1 and 2, License Renewal Application Environmental Audit (a) These documents can be accessed through the NRCs ADAMS at http://adams.nrc.gov/wba/. C-4

Appendix C 1 References 2 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 3 Part 800, Protection of historic properties. 4 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 5 Interagency cooperationEndangered Species Act of 1973, as amended. 6 Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 7 [FWS] U.S. Fish and Wildlife Service. 2013. Endangered Species Program: What We Do: 8 Consultations: Frequently Asked Questions. July 15, 2013. Available at 9 <http://www.fws.gov/endangered/what-we-do/faq.html#8> (accessed 5 June 2014). 10 [FWS] U.S. Fish and Wildlife Service. 2015a. Illinois County Distribution, Federally 11 Endangered, Threatened, and Candidate Species. Midwest Region. Updated 12 September 30, 2015. Available at http://www.fws.gov/midwest/endangered/lists/illinois-cty.html 13 (accessed 9 October 2015). 14 [FWS] U.S. Fish and Wildlife Service. 2015b. Letter from FWS to NRC.

Subject:

LaSalle 15 Power Plant License Renewal. List of threatened and endangered species that may occur in 16 your proposed project location, and/or may be affected by your proposed project. 17 February 27, 2015. ADAMS No. ML15126A069. 18 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998. 19 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 20 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p. 21 Available at <http://www.fws.gov/endangered/esa-library/pdf/esa_section7_handbook.pdf> 22 (accessed 8 July 2013). 23 Magnuson-Stevens Fishery Conservation and Management Act, as amended. 24 16 U.S.C. §1801 et seq. 25 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 26 National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq. C-5

1 APPENDIX D 2 CHRONOLOGY OF ENVIRONMENTAL 3 REVIEW CORRESPONDENCE

1 D. CHRONOLOGY OF ENVIRONMENTAL REVIEW 2 CORRESPONDENCE 3 This appendix contains a chronological listing of correspondence between the U.S. Nuclear 4 Regulatory Commission (NRC) and external parties as part of its license renewal application 5 (LRA) environmental review for LaSalle County Station, Units 1 and 2 (LSCS) other than 6 consultation correspondence and comments received during the scoping process. Consultation 7 correspondence is listed and discussed in Appendix C of this supplemental environmental 8 impact statement (SEIS). Scoping comments are provided and addressed in Appendix A of this 9 SEIS and in the Scoping Summary Report (see Table D-1 below). All documents are available 10 electronically from the NRCs Public Electronic Reading Room found on the Internet at the 11 following Web address: http://www.nrc.gov/reading-rm.html. From this site, the public can gain 12 access to the NRCs Agencywide Documents Access and Management System (ADAMS), 13 which provides text and image files of the NRCs public documents in ADAMS. The ADAMS 14 No. for each document is included in the following table. 15 Environmental Review Correspondence 16 Table D-1 lists the environmental review correspondence, by date, beginning with the request 17 by Exelon Generation Company, LLC (Exelon) to renew the operating licenses for LSCS. 18 Environmental Review Correspondence Date Correspondence Description ADAMS No. December 9, 2014 Transmittal of LSCS LRA from Exelon to NRC ML14343A840 December 11, 2014 Receipt and availability of LSCS LRA ML14337A267 December 29, 2014 Letter from Illinois Environmental Protection Agency to NRC ML15022A325 regarding LSCS Clean Water Act Section 401 Certification January 26, 2015 Determination of acceptability and sufficiency for docketing, ML15021A451 proposed review schedule, and opportunity for a hearing regarding the application, for renewal of the operating licenses for LSCS January 27, 2015 Notice of intent to prepare an environmental impact ML15005A480 statement and conduct scoping for LSCS license renewal March 10, 2015 Transcript from afternoon public scoping meeting ML15083A538 March 10, 2015 Transcript from evening public scoping meeting ML15089A580 March 31, 2015 Transmittal of severe accident mitigation alterative (SAMA) ML15083A546 audit plan from NRC to Exelon April 24, 2015 SAMA audit summary ML15106A812 April 28, 2015 Transmittal of environmental audit plan from NRC to Exelon ML15106A392 April 30, 2015 Transmittal of SAMA requests for additional information ML15114A320 (RAIs) from NRC to Exelon May 20, 2015 Environmental audit summary ML15132A674 May 22, 2015 Transmittal of environmental RAIs from NRC to Exelon ML15142A764 May 29, 2015 Exelon response to SAMA RAIs ML15149A370 June 25, 2015 Summary of teleconference between NRC and Exelon ML15167A486 regarding transportation impacts for LSCS high burnup fuel D-1

Appendix D Date Correspondence Description ADAMS No. June 25, 2015 Transmittal of RAIs regarding transportation impacts for ML15167A488 LSCS high burnup fuel from NRC to Exelon July 2, 2015 Exelon response to environmental RAIs ML15195A351 July 8, 2015 Scoping Summary Report ML15147A380 July 24, 2015 Exelon response to RAIs regarding transportation impacts for ML15205A003 LSCS high burnup fuel July 31, 2015 Exelon transmittal of revisions to the License Renewal ML15212A259 Application Environmental Report August 28, 2015 Revised response to RAIs regarding transportation impacts ML15240A002 for LSCS high burnup fuel September 21, 2015 Resubmittal of Index Item # 058 (ER References to be ML15273A423 Docketed) from Exelon D-2

1 APPENDIX E 2 PROJECTS AND ACTIONS CONSIDERED 3 IN CUMULATIVE IMPACTS ANALYSIS

1 E. PROJECTS AND ACTIONS CONSIDERED IN THE CUMULATIVE 2 IMPACTS ANALYSIS 3 Table E-1 identifies actions and projects considered in the U.S. Nuclear Regulatory 4 Commission (NRC) staffs analysis of cumulative impacts related to the environmental analysis 5 of the continued operation of LaSalle County Station, Units 1 and 2 (LSCS). Potential 6 cumulative impacts associated with these actions and projects are addressed in Section 4.16 of 7 this supplemental environmental impact statement. However, not all actions or projects listed in 8 this appendix are considered in each resource area because of the uniqueness of the resource 9 and its geographic area of consideration. 10 Projects and Actions Considered in Cumulative Impacts Analysis Location (Relative Project Name Summary of Project to LSCS) Status Nuclear Projects Clinton Power Station, Nuclear power plant, DeWitt County, IL, Operational (NRC 2015a) Unit 1 one 1,067-MWe approximately General Electric Type 6 75 mi (121 km) reactor south. 50-mi (80 km) radius overlaps with that of LSCS Byron Station, Units 1 Nuclear power plant, Ogle County, IL, Operational (NRC 2015b, and 2 two 1,121-MWe approximately 2015c) Westinghouse 4-loop reactors 65 mi (105 km) north-northwest. 50-mi (80 km) radius overlaps with that of LSCS Braidwood Station, Nuclear power plant, Will County, IL, Operational (NRC 2015d, Units 1 and 2 two 1,121-MWe approximately 2015e) Westinghouse 4-loop reactors 23 mi (37 km) east Dresden Nuclear Nuclear power plant, Grundy County, IL, Operational (NRC 2015f, Power Station, Units 2 two 867-MWe approximately 2015g) and 3 General Electric Type 3 23 mi (37 km) east-reactors northeast Dresden Nuclear Nuclear power plant Grundy County, IL, Shut down in Power Station, Unit 1 (undergoing approximately October 1978 and is decommissioning) 23 mi (37 km) east- currently in SAFSTOR. northeast No dismantlement activities are under way. All spent fuel from DNPS Unit 1 transferred to the onsite Independent Spent Fuel Storage Installation (NRC 2015h) E-1

Appendix E Location (Relative Project Name Summary of Project to LSCS) Status Quad Cities Nuclear Nuclear power plant, Rock Island Operational Power Station, Units 1 two 867-MWe General Electric County, IL, (NRC 2015i, 2015j) and 2 Type 3 reactors approximately 91 mi (146 km) west-northwest. 50 mi (80 km) radius overlaps with that of LSCS Renewable Energy Projects Grand Ridge Wind 140-unit wind farm with Immediately west Operational Farm 210 MW generating capacity of LSCS property (Invenergy 2015a, 2015b, and 34 MW energy storage and extending 2015c, 2015d; Windpower support facility southwest 2015a, 2015b, 2015c, approximately 2015d) 8 mi (13 km) Top Crop Wind Farm 200-unit wind farm with Grundy, LaSalle Operational (EIA 2015a, 300 MW generating capacity and Livingston 2015b; Windpower 2015e, Counties, IL, 2015f; approximately 6 mi EDP Renewables 2015) (10km) south-southeast Grand Ridge Solar Solar photovoltaic facility with Streator, IL, Operational Farm 20 MW generating capacity approximately 8 mi (EIA 2015c, (13 km) southwest Invenergy 2015e) Minonk Wind Farm 100-unit wind farm with Woodford and Operational (EIA 2015d, 192 MW generating Livingston Mortenson 2015) capacity Counties, IL, approximately 27 mi (43 km) southwest Streator-Cayuga Ridge 150-unit wind farm with Livingston County, Operational (EIA 2015e, Wind Farm 300 MW generating IL, approximately Windpower 2015g) capacity 18 mi (29 km) southeast Starved Rock Power Hydroelectric dam with 6.8 On Illinois River, Operational (EIA 2015f) Station MW generating capacity approximately 17 mi (28 km) west-northwest Midwest Hydro LLC Hydroelectric dam with 3.6 On Fox River, Operational (EIA 2015g) MW generating capacity approximately 12 mi (19 km) northwest Morris Genco LLC Waste-to-energy biomass- Grundy County, IL, Operational (EIA 2015h) fueled facility with 2 MW approximately generating capacity 17 mi (27 km) northwest Prairie View Waste-to-energy biomass- Will County, IL, Operational (EIA 2015i) Renewable Energy fueled facility with 4.8 MW approximately generating capacity 30 mi (49 km) east-northeast E-2

Appendix E Location (Relative Project Name Summary of Project to LSCS) Status Fossil Fuel Projects Peru City Power Plant Petroleum-fueled plant with Peru, IL, Operational (EIA 2015g) 27.5 MW generating capacity approximately 24 mi (38 km) north Oglesby Gas Plant Natural gas-fueled plant with Oglesby, IL, Operational (EIA 2015j) 54 MW generating capacity approximately 21 mi (34 km) west-northwest Morris Cogeneration Natural gas-fueled plant with Morris IL, Operational (EIA 2015k) LLC 176 MW generating capacity approximately 21 mi (34 km) northwest Kendall County Natural gas-fueled plant with Kendall County, IL, Operational (EIA 2015l) Generation 1,140 MW generating approximately capacity 27 mi (43 km) northeast Manufacturing Facilities Agrium Inc. Fertilizer solution Marseilles, IL Operational (Agrium 2015, storage facility approximately 5 mi EPA 2015a) (8 km) north Glen-Gery Marseilles Brick manufacturer Marseilles, IL Operational (EPA 2015a, Plant approximately 5 mi Glen-Gery 2015) (8 km) north Independence Tube Structural steel tubing Marseilles, IL Operational (EPA 2015a, Corporation manufacturer approximately 5 mi Independence 2015) (8 km) north PotashCorp - PCS Phophate animal feed Marseilles, IL Operational (EPA 2015a, Phosphate Marseilles production approximately 5 mi PotashCorp 2015) Operation (8 km) north SABIC Innovative Plastic fabrication Ottawa IL, Operational (EPA 2015a, Plastics approximately SABIC 2015) 7.5 mi (12 km) northwest CF Industries Seneca Fertilizer distribution terminal Seneca, IL Operational (CFIndustries Ammonia Terminal approximately 5 mi 2015, (8 km) northeast EPA 2015a) H.B. Fuller Industrial adhesive, coating, Morris, IL Operational (EPA 2015a, and sealant manufacturer approximately 7 mi H.B. Fuller 2015) (11 km) northeast E-3

Appendix E Location (Relative Project Name Summary of Project to LSCS) Status Landfills LandComp Landfill 188 ac (76 ha) municipal solid Ottawa, IL, Operational until 2034 waste landfill approximately (IEPA 2013, 2015) 14 mi (2 km) northwest Environtech, Inc. 169 ac (68 ha) municipal solid Morris, IL, Expected to close 2015 waste landfill approximately (IEPA 2013, 2015) 17 mi (27 km) northeast Livingston Landfill 550 ac (223 ha) municipal Livingston, IL, Operational until 2037 solid waste landfill approximately (IEPA 2013, 2015) 22 mi (35 km) south Prairie View Recycling 408 ac (165 ha) municipal Wilmington, IL, Operational until 2040, and Disposal Facility solid waste landfill approximately (IEPA 2013, 2015) 30 mi (48 km) northeast within former Joliet Army Ammunition Plant Water Supply and Treatment Facilities City of Marseilles, Withdraws groundwater Approximately 6 mi Operational (EPA 2015b, water supply obtained from wells in the (10 km) north- Exelon 2014) Cambrian-Ordovician Aquifer. northwest City of Seneca, water Withdraws groundwater Approximately 6 mi Operational (EPA 2015b, supply obtained from wells in the (10 km) north- Exelon 2014) Cambrian-Ordovician Aquifer. northeast Village of Grand Ridge, Withdraws groundwater Approximately Operational (EPA 2015a, water supply obtained from wells in the 8.5 mi (13.5 km) Exelon 2014) Buried Bedrock Valleys east Aquifer. City of Marseilles, Water treatment with Approximately 6 mi Operational (EPA 2015a) wastewater treatment discharge to the Illinois River (10 km) north-northwest Various minor NPDES Various businesses with Within 50 mi Operational (EPA 2015a) wastewater discharges smaller wastewater (80 km) discharges Mining Projects U.S. Silica Sandstone mine and silica Ottawa, IL, Operational (EPA 2015a, production facility approximately U.S. Silica 2015) 12 mi (19.5 km) northwest Unimin Corporation Sandstone mine and silica Utica, IL, Operational (EPA 2015a, production facility approximately Unimin 2015) 18.5 mi (30 km) northwest E-4

Appendix E Location (Relative Project Name Summary of Project to LSCS) Status Northern White Sand Sandstone mine and silica Utica, IL, Operational Proposed LLC production facility that is approximately expansion is pending proposing 350 ac (142 ha) 16.5 mi (26.5 km) before the LaSalle County expansion. northwest Board (EPA 2015a, NewsTribune 2014) Mississippi Sand LLC Proposed 314 ac (127 ha) Ottawa, IL, On hold pending legal sandstone mine near eastern approximately challenges entrance to Starved Rock 17 mi (27 km) (NewsTribune 2014) State Park north-northwest, near eastern entrance to Starved Rock State Park Remediation Site Joliet Army 14-sq mi (36-sq. km) military Joliet, IL, Ongoing remediation Ammunition Plant complex operated from early approximately under the purview of the 1940s through 1977 to 28 mi (45 km) U.S. Army. Land use manufacture, load, assemble, northeast controls are restricting and package high-explosive land uses; portions are artillery shells, bombs, mines, now under productive and small-arms ammunition. reuse by the U.S. Forest Other activities on site Service (Midewin National included testing of Tallgrass Prairie), the ammunition, washout and Veterans Administration renovation of shells, and (Abraham Lincoln National burning and demolition of Cemetery), Will County explosives. (500-ac [202-ha] landfill), and productive uses through commercial and industrial redevelopment (EPA 2013). Parks and Recreation Sites LaSalle Lake State 2,058 ac (833 ha) lake that Onsite Operational. Managed by Fish and Wildlife Area serves as the cooling lake for Illinois Department of LaSalle Generating Station. Natural Resources Managed for public boating (IDNR 2015a) and fishing. Marseilles State Fish 2,550 ac (1,032 ha) tract that Approximately Operational. and Wildlife Area serves as joint-use area for 1.5 mi (2.4 km) Cooperatively managed the Illinois Department of north by Illinois Department of Natural Resources (as a Natural Resources and hunting and habitat Illinois Department of management site) and the Military Affairs through Illinois National Guard (for Memorandum of live-fire training when hunting Agreement seasons are closed). (IDNR 2015b, ING undated) E-5

Appendix E Location (Relative Project Name Summary of Project to LSCS) Status Illini State Park 510 ac (206 ha) park along Approximately 6 mi Operational. Managed by the south bank of the Illinois (10 km) north- Illinois Department of River. Hiking, fishing, boating northwest Natural Resources and camping occur within the (IDNR 2015c) park. Buffalo Rock State 298 ac (121 ha) park along Approximately Operational. Managed by Park the north bank of the Illinois 13.5 mi (22 km) Illinois Department of River. Hiking, fishing, and northwest Natural Resources camping occur within the (IDNR 2015d) park. Gebhard Woods 30 ac (12 ha) park along the Approximately Operational. Managed by State Park north bank of the Illinois River. 14 mi (23 km) Illinois Department of Hiking, fishing, boating and northeast Natural Resources camping occur within the (IDNR 2015e) park. Starved Rock State 2,700 ac (1,093 ha) park On Illinois River, Operational. Managed by Park containing sandstone buttes, approximately Illinois Department of 18 canyons, waterfalls, and 15 mi (24 km) Natural Resources 13 mi (21 km) of hiking trails. northwest (IDNR 2015f) Camping, fishing, boating and hunting also occur within the park. Matthiessen State Park 1,938 ac (784 ha) park 18 mi (29 km) west Operational. Managed by containing forested canyons, Illinois Department of rock formations and water Natural Resources falls. Hiking, camping, biking, (IDNR 2015g) and horseback riding occur within the park. Goose Lake Prairie 2,537 ac (1,026 ha) area Approximately Operational. Managed by State Natural Area representing largest remnant 20 mi (31 km) Illinois Department of of prairie in Illinois. Used for north-northeast. Natural Resources hiking, picnicking, cross- Adjacent to (IDNR 2015h) country skiing and hunting Heidecke Lake State Fish and Wildlife Area Heidecke Lake State 1,300 ac (526 ha) lake Approximately Operational. Managed by Fish and Wildlife Area managed for public fishing 20 mi (31 km) Illinois Department of and hunting. Originally north-northeast. Natural Resources constructed in 1978 as the Adjacent to Goose (IDNR 2015i) cooling lake for the former Lake Prairie State Collins Generating Station Natural Area Recreational Areas Various parks, boat launches, Within 10 mi Operational and campgrounds (16 km) E-6

Appendix E Location (Relative Project Name Summary of Project to LSCS) Status Other Projects Future Urbanization Construction of housing units Throughout region Construction would occur and associated commercial in the future, as described buildings; roads, bridges, and in State and local land-use rail; water and/or wastewater planning documents. treatment and distribution facilities; and associated pipelines as described in local land-use planning documents Key: ac = acres; ha = hectares; km = kilometers; mi = miles; NPDES = National Pollutant Discharge Elimination System; sq. = square 1 References 2 Agrium. 2015. Marseilles Solution Storage. Available at <http://www.agrium.com/en/what-3 we-do/locations> (accessed 8 September 2015). 4 CFIndustries. 2015. Seneca Ammonia Terminal. Available at 5 <http://www.cfindustries.com/distribution_seneca-terminal.html> (accessed 18 August 2015). 6 EDP Renewables. 2015. Illinois/Top Crop Factsheet. Available at <http://topcrop.edpr-7 windfarms.com/wp-content/uploads/sites/14/2014/03/Top-Crop_Fact-Sheet_6.25.15.pdf> 8 (accessed 7 August 2015). 9 [EIA] U.S. Energy Information Administration. 2015a. Illinois State Profile and Energy 10 Estimates, Profile Overview Interactive Map - Blackstone [Top Crop] Wind Farm LLC. 11 Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015). 12 [EIA] U.S. Energy Information Administration. 2015b. Illinois State Profile and Energy 13 Estimates, Profile Overview Interactive Map - Blackstone II [Top Cropn II] Wind Farm LLC. 14 Available at <http://www.eia.gov/state/?sid=IL> (accessed 29 September 2015). 15 [EIA] U.S. Energy Information Administration. 2015c. Illinois State Profile and Energy 16 Estimates, Profile Overview Interactive Map - Grand Ridge Solar Farm. Available at 17 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015). 18 [EIA] U.S. Energy Information Administration. 2015d. Illinois State Profile and Energy 19 Estimates, Profile Overview Interactive Map - Minonk Wind Farm. Available at 20 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015). 21 [EIA] U.S. Energy Information Administration. 2015e. Illinois State Profile and Energy 22 Estimates, Profile Overview Interactive Map - Streator Cayuga Ridge South. Available at 23 <http://www.eia.gov/state/?sid=IL> (accessed 30 September 2015). 24 [EIA] U.S. Energy Information Administration. 2015f. Illinois State Profile and Energy 25 Estimates, Profile Overview Interactive Map - Peru Hydro. Available at 26 <http://www.eia.gov/state/?sid=IL> (accessed 14 August 2015). 27 [EIA] U.S. Energy Information Administration. 2015g. Illinois State Profile and Energy 28 Estimates, Profile Overview Interactive Map - Dayton Hydro. Available at 29 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015). E-7

Appendix E 1 [EIA] U.S. Energy Information Administration. 2015h. Illinois State Profile and Energy 2 Estimates, Profile Overview Interactive Map - Morris Genco LLC. Available at 3 <http://www.eia.gov/state/?sid=IL> (accessed 30 September 2015). 4 [EIA] U.S. Energy Information Administration. 2015i. Illinois State Profile and Energy 5 Estimates, Profile Overview Interactive Map - Prairie View. Available at 6 <http://www.eia.gov/state/?sid=IL> (accessed 17 August 2015). 7 [EIA] U.S. Energy Information Administration. 2015j. Illinois State Profile and Energy 8 Estimates, Profile Overview Interactive Map - Oglesby. Available at 9 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015). 10 [EIA] U.S. Energy Information Administration. 2015k. Illinois State Profile and Energy 11 Estimates, Profile Overview Interactive Map - Morris Cogeneration LLC. Available at 12 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015). 13 [EIA] U.S. Energy Information Administration. 2015l. Illinois State Profile and Energy 14 Estimates, Profile Overview Interactive Map - Kendall County Generation Facility. Available at 15 <http://www.eia.gov/state/?sid=IL> (accessed 16 August 2015). 16 [EPA] U.S. Environmental Protection Agency. 2013. Region 5 Cleanup Sites: Joliet Army 17 Ammunition Plant. November 14, 2013. Available at 18 <http://www.epa.gov/region05/cleanup/jolietarmy/index.html> (accessed 17 August 2015). 19 [EPA] U.S. Environmental Protection Agency. 2015a. Envirofacts PCS/ICIS search results for 20 Peru Illinois: Facilities with permits to discharge wastewater to waters of the United States. 21 August 14, 2015. Available at <http://oaspub.epa.gov/enviro/PCSICISQuery.list?minx=- 22 89.148560&miny=40.996484&maxx=-88.187256&maxy=4l> (accessed 14 August 2015). 23 [EPA] U.S. Environmental Protection Agency. 2015b. Envirofacts SDWIS search results for 24 LaSalle, Illinois: List of Safe Drinking Water Systems. August 17, 2015. Available at 25 <http://www.epa.gov/enviro/facts/sdwis/search.html> (accessed 17 August 2015). 26 [Exelon] Exelon Generation Company, LLC. 2014. Applicants Environmental Report - 27 Operating License Renewal Stage, LaSalle County Station, Units 1 and 2, License Renewal 28 Application. Kennett Square, PA: Exelon. December 9, 2014. ADAMS No. ML14343A883. 29 [Glen-Gery] Glen-Gery Corporation. 2015. Marseilles Plant. Available at 30 <http://www.glengery.com/about-us/locations/item/164981492-marseilles-plant/164981492-31 marseilles-plant> (accessed 1 October 2015). 32 H.B. Fuller. 2015. Available at <http://www.hbfuller.com/north-america> 33 (accessed 1 October 2015) 34 [IDNR] Illinois Department of Natural Resources. 2015a. LaSalle Lake State Fish & Wildlife 35 Area. Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/LASALLE.HTM> 36 (accessed 18 August 2015). 37 [IDNR] Illinois Department of Natural Resources. 2015b. Marseilles State Fish & Wildlife 38 Area. Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/MARSEIL.HTM> 39 (accessed 18 August 2015). 40 [IDNR] Illinois Department of Natural Resources. 2015c. Illini State Park. Available at 41 <http://www.dnr.illinois.gov/Parks/Pages/Illini.aspx> (accessed 18 August 2015). 42 [IDNR] Illinois Department of Natural Resources. 2015d. Buffalo Rock State Park. Available 43 at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/I&M/EAST/BUFFALO/Home.htm> 44 (accessed 18 August 2015). E-8

Appendix E 1 [IDNR] Illinois Department of Natural Resources. 2015e. Gebhard Woods State Park. 2 Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/I&M/EAST/ 3 GEBHARD/Park.htm> (accessed 18 August 2015). 4 [IDNR] Illinois Department of Natural Resources. 2015f. Starved Rock State Park. 2015. 5 Available at <http://www.dnr.illinois.gov/Parks/Pages/StarvedRock.aspx> (accessed 6 18 August 2015). 7 [IDNR] Illinois Department of Natural Resources. 2015g. Matthiessen State Park. Available 8 at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R1/mttindex.htm> (accessed 9 18 August 2015). 10 [IDNR] Illinois Department of Natural Resources. 2015h. Goose Lake Prairie State Natural 11 Area. Available at <http://www.dnr.illinois.gov/Parks/Pages/GooseLakePrairie.aspx> 12 (accessed 18 August 2015). 13 [IDNR] Illinois Department of Natural Resources. 2015i. Heidecke Lake State Fish and Wildlife 14 Area. Available at <http://www.dnr.state.il.us/Lands/Landmgt/PARKS/R2/Heidecke.htm> 15 (accessed 18 August 2015). 16 [IEPA] Illinois Environmental Protection Agency. 2013. Nonhazardous Solid Waste 17 Management and Landfill Capacity in Illinois: 2012. Springfield, IL: IEPA. October 2013. 67 p. 18 Available at <http://www.epa.state.il.us/land/landfill-capacity/2012/report.pdf> (accessed 19 14 August 2015). 20 [IEPA] Illinois Environmental Protection Agency. 2015. Illinois Landfill Projections of Disposal 21 Capacity as of January 1, 2015. Springfield, IL: IEPA. July 2015. 48 p. Available at 22 <http://www.epa.illinois.gov/Assets/iepa/waste-management/landfills/landfill-capacity/landfill-23 capacity-report-2015.pdf> (accessed 14 August 2015). 24 [Independence] Independence Tube Corporation. 2015. Available at 25 <http://www.independencetube.com/history> (accessed 1 October 2015). 26 [ING] Illinois National Guard. undated. Marseilles Training Area. Available at 27 <http://www.il.ngb.army.mil/MilitaryAffairs/MTA/> (accessed 18 August 2015). 28 [Invenergy] Invenergy, LLC. 2015a. Grand Ridge I. Available at 29 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeI.aspx> (accessed 30 14 August 2015). 31 [Invenergy] Invenergy, LLC. 2015b. Grand Ridge II - IV. Available at 32 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeIIIV.aspx> (accessed 33 14 August 2015). 34 [Invenergy] Invenergy, LLC. 2015c. Grand Ridge IV Storage. Available at 35 http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeIVStorage.aspx 36 (accessed 14 August 2015). 37 [Invenergy] Invenergy, LLC. 2015d. Grand Ridge Energy Storage. Available at 38 http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeEnergyStorage.aspx 39 (accessed 14 August 2015). 40 [Invenergy] Invenergy, LLC. 2015e. Grand Ridge Solar. Available at 41 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/GrandRidgeSolar.aspx> 42 (accessed 14 August 2015). 43 Mortenson 2015. Minonk Wind Farm Project. Available at 44 <http://www.mortenson.com/wind/projects/minonk-wind-farm> (accessed 14 August 2015). E-9

Appendix E 1 [NewsTribune] LaSalle News Tribune. 2014. Sorting out LaSalle Countys four newest sand 2 mines. July 2, 2014. Available at <http://newstrib.com/main.asp?SectionID= 3 2&SubSectionID=232&ArticleID=37558> (accessed 8 September 2015). 4 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Clinton Power Station, Unit 1. 5 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/clin.html> (accessed 6 11 August 2015). 7 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Byron Station, Unit 1. June 30, 2015. 8 Available at <http://www.nrc.gov/info-finder/reactor/byro1.html> (accessed 11 August 2015). 9 [NRC] U.S. Nuclear Regulatory Commission. 2015c. Byron Station, Unit 2. June 30, 2015. 10 Available at <http://www.nrc.gov/info-finder/reactor/byro2.html> (accessed 11 August 2015). 11 [NRC] U.S. Nuclear Regulatory Commission. 2015d. Braidwood Station, Unit 1. 12 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/brai1.html> (accessed 13 11 August 2015). 14 [NRC] U.S. Nuclear Regulatory Commission. 2015e. Braidwood Station, Unit 2. 15 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/brai2.html> (accessed 16 11 August 2015). 17 [NRC] U.S. Nuclear Regulatory Commission. 2015f. Dresden Nuclear Power Station, Unit 2. 18 June 30, 2015. Available at <http://www.nrc.gov/info-finder/reactor/dres2.html> (accessed 19 11 August 2015). 20 [NRC] U.S. Nuclear Regulatory Commission. 2015g. Dresden Nuclear Power Station, Unit 3. 21 July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/dres3.html> (accessed 22 11 August 2015). 23 [NRC] U.S. Nuclear Regulatory Commission. 2015h. Dresden - Unit 1. June 12, 2015. 24 Available at <http://www.nrc.gov/info-finder/decommissioning/power-reactor/ 25 dresden-nuclear-power-station-unit-1.html> (accessed 11 August 2015). 26 [NRC] U.S. Nuclear Regulatory Commission. 2015i. Quad Cities Nuclear Power Station, 27 Unit 1. July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/quad1.html> 28 (accessed 11 August 2015). 29 [NRC] U.S. Nuclear Regulatory Commission. 2015j. Quad Cities Nuclear Power Station, 30 Unit 2. July 1, 2015. Available at <http://www.nrc.gov/info-finder/reactor/quad2.html> 31 (accessed 11 August 2015). 32 PotashCorp 2015. PotashCorp - Marseilles. Available at 33 <http://www.potashcorp.com/about/facilities/phosphate/marseilles/> (accessed 34 18 August 2015). 35 [SABIC] Saudi Basic Industries Corporation. 2015. Annual Report 2014. Available at 36 <http://www.sabic.com/me/en/newsandmediarelations/publications/overview_annual_report> 37 (accessed 1 October 2015). 38 [Unimin] Unimin Corporation. 2015. Unimin Locations. Available at 39 <http://www.unimin.com/unimin-locations.cfm> (accessed 9 September 2015.) 40 U.S. Silica 2015. U.S. Silica Locations - Ottawa IL. Available at 41 <http://www.ussilica.com/locations/ottawa-il> (accessed 19 August 2015). 42 Windpower 2015a. The Windpower - Grand Ridge I Wind Farm. Available at 43 <http://www.thewindpower.net/windfarm_en_4022_grand-ridge-i.php> (accessed 44 7 August 2015). E-10

Appendix E 1 Windpower 2015b. The Windpower - Grand Ridge II Wind Farm. Available at 2 <http://www.thewindpower.net/windfarm_en_10985_grand-ridge-ii.php> (accessed 3 7 August 2015). 4 Windpower 2015c. The Windpower - Grand Ridge III Wind Farm. Available at 5 <http://www.thewindpower.net/windfarm_en_10986_grand-ridge-iii.php> (accessed 6 7 August 2015). 7 Windpower 2015d. The Windpower - Grand Ridge IV Wind Farm. Available at 8 <http://www.thewindpower.net/windfarm_en_18016_grand-ridge-iv.php> (accessed 9 7 August 2015). 10 Windpower 2015e. The Windpower - Top Crop Wind Farm. Available at 11 <http://www.thewindpower.net/windfarm_en_724_top-crop.php> (accessed 7 August 2015). 12 Windpower 2015f. The Windpower - Top Crop II Wind Farm. Available at 13 <http://www.thewindpower.net/windfarm_en_21266_top-crop-ii.php> (accessed 7 August 2015). 14 Windpower 2015g. The Windpower - Streator Cayuga Ridge Wind Farm. Available at 15 <http://www.thewindpower.net/windfarm_en_10983_streator-cayuga-ridge-wind-farm.php> 16 (accessed 14 August 2015). E-11

1 APPENDIX F 2 U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 3 SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR LASALLE 4 COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF LICENSE 5 RENEWAL APPLICATION REVIEW

1 F. U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 2 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 3 LASALLE COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF 4 LICENSE RENEWAL APPLICATION REVIEW 5 Introduction 6 Exelon Generation Company, LLC (Exelon) submitted a license renewal application for LaSalle 7 County Station (LSCS), Units 1 and 2. Exelon assessed severe accident mitigation alternatives 8 (SAMAs) for LSCS in Appendix F of its Environmental Report (ER) (Exelon 2014a). This 9 assessment was based on the most recent LSCS probabilistic risk assessment (PRA) available 10 at that time, a plant-specific offsite consequence analysis performed using the MELCOR 11 Accident Consequence Code System (MACCS2) Version 1.13.1 computer code, and insights 12 from the LSCS individual plant examination (IPE) and individual plant examination of external 13 events (IPEEE). In identifying and evaluating potential SAMAs, Exelon considered SAMAs that 14 addressed the major contributors to core damage frequency (CDF) and release frequency at 15 LSCS, as well as SAMA candidates from six other boiling water reactor (BWR) plants. Exelon 16 initially identified 27 potential SAMAs. Then, Exelon reduced the list to 25 unique SAMA 17 candidates by eliminating SAMAs that are not applicable to LSCS, that have already been 18 implemented at LSCS, or that have excessive implementation costs. Next, Exelon assessed 19 the costs and benefits associated with each of the 25 potential SAMAs and concluded that 20 14 SAMA candidates were potentially cost beneficial at the 95th percentile. Exelon performed 21 sensitivity analyses on the real discount rate, CDF uncertainty at the 95th percentile, as well as 22 the offsite consequence parameters, and considered those results in the cost-benefit analysis. 23 As an additional sensitivity analysis in the ER, Exelon considered the planned installation of a 24 hardened vent pipe as the base case to provide supplemental information on potentially 25 cost-beneficial SAMAs following the vent pipe installation. 26 Based on a review of Exelons SAMA assessment and the SAMA audit held on April 78, 2015, 27 the U.S. Nuclear Regulatory Commission (NRC) staff issued requests for additional information 28 (RAIs) to Exelon by letter dated April 30, 2015 (NRC 2015). Key questions concerned the 29 differences between LSCS Units 1 and 2, systems shared between the two units and how these 30 are modeled in the PRA; the definition and assignment of accident classes; additional details on 31 the Level 2 and 3 PRA models, including the basis for representative sequences for each 32 release category; the determination of the frequency of the intact release category; the 33 identification and screening of candidate SAMAs; the potential for additional SAMAs to mitigate 34 fire risk; the evaluation of the risk reduction of certain SAMAs; and the basis for the SAMA cost 35 estimates. By letter dated May 29, 2015, Exelon submitted additional information that included 36 revisions and a correction, which changed the determination of one SAMA from potentially cost 37 beneficial in the ER to not cost beneficial (Exelon 2015). Exelons responses addressed the 38 NRC staffs concerns. 39 The evaluation of the LSCS SAMA analysis is presented below. 40 Estimate of Risk for LSCS 41 Exelons estimates of offsite risk at LSCS are summarized in Section F.2.1. The summary is 42 followed by the NRC staffs review of Exelons risk estimates in Section F.2.2. F-1

Appendix F 1 F.2.1. Exelons Risk Estimates 2 Exelon combined two distinct analyses to form the basis for risk estimates used in the SAMA 3 analysis: (1) the LSCS Level 1 and 2 PRA models and (2) a supplemental analysis of offsite 4 consequences and economic impacts (essentially a Level 3 PRA model) developed specifically 5 for the SAMA analysis. The Level 1 model is a significant upgrade and revision of the IPE 6 Level 1 model, while the Level 2 model is an update of the prior large early release frequency 7 (LERF) models. The SAMA analysis is based on the most recent LSCS Level 1 and 2 PRA 8 models available at the time of the ER, referred to as the LSCS PRA 2013A (or LS213A) model. 9 This LSCS PRA includes internal flooding but does not include external events. 10 The LSCS CDF is approximately 2.6x106 per year (Exelon 2014a). Exelon did not explicitly 11 include the contribution from external events within the LSCS SAMA risk estimates; however, it 12 did account for the potential risk reduction benefits associated with external events by 13 multiplying the estimated benefits for internal events by 5.2. This is discussed further in 14 Section F.2.2.2. 15 The breakdown of CDF by initiating event is provided in Table F-1. As shown in this table, 16 events initiated by a turbine trip with bypass, a dual unit loss of offsite power (LOOP), a loss of 17 instrument air, and a loss of condenser vacuum are the dominant contributors to the CDF. In a 18 response to RAIs, Exelon identified that station blackout (SBO) contributes 6.4x107 per year, or 19 25 percent of the total CDF for internal events while anticipated transients without scram 20 (ATWS) contributes 4.9x107 per year, or approximately 19 percent, of the total CDF for each 21 unit (Exelon 2015). 22 Regarding Level 2 analysis, Exelon stated: 23 The expansion of the LERF model to a full Level 2 model involved a 24 reassessment of the timing and release categorization of each containment event 25 tree (CET) end state. To perform this reassessment, MAAP calculations for each 26 accident class were performed and used to assess the CET end states. Each 27 CET node was evaluated and updated to reflect the current state of knowledge 28 regarding Level 2 accident phenomenology. The end state timing was also 29 updated to reflect the current emergency plan and evacuation time estimates. 30 The Level 2 model uses three general containment event tree (CET) types to assess the 31 accident progression during a core damage event. CETs contain both phenomenological and 32 containment system status events. Level 1 core damage sequences are binned into plant 33 damage states (PDSs) or accident classes, which provide the interface between the Level 1 and 34 Level 2 CET analysis. Each accident class bin is entered into the CET, resulting in 35 15 LSCS-specific CETs. The CET is linked directly to the Level 1 event trees, and CET nodes 36 are evaluated using supporting fault trees (Exelon 2015). 37 The result of the Level 2 PRA is a set of 13 release bins or categories with their respective 38 frequency and release characteristics. The results of this analysis for LSCS are provided in 39 Tables F.2-5, F.2-6, F.3-15, F.3-16, and F.3-19 of the ER (Exelon 2014a). The categories 40 were defined based on the timing of release (three release time ranges) and the magnitude of 41 release (four release magnitude ranges). One additional release category was included for an 42 intact containment. 43 For the SAMA analysis, the release category for high magnitude and early timing was divided 44 into two bins (one with containment isolation and one without). Due to the small release 45 category contributions from six categories, the number of release category bins was reduced to 46 eight cases. The frequency of each release category was obtained by summing the frequency 47 of the individual accident progression CET endpoints binned into the release category. Source F-2

Appendix F 1 terms were developed for each of the 13 release categories using the results of Modular 2 Accident Analysis Program (MAAP) Version 4.0.5 computer code calculations (Exelon 2014a). 3 Exelon computed offsite consequences for potential releases of radiological material using the 4 MACCS2 Version 1.13.1 code and analyzed exposure and economic impacts from its 5 determination of offsite and onsite risks. Inputs for these analyses include plant-specific and 6 site-specific input values for core radionuclide inventory, source term and release 7 characteristics, site meteorological data, projected population distribution and growth within a 8 50-mile (80-km) radius, emergency response evacuation modeling, and economic data. The 9 estimation of onsite impacts (in terms of cleanup costs, decontamination costs, and 10 occupational dose) is based on guidance in NUREG/BR-0184 (NRC 1997a). In its calculation 11 for replacement power costs, Exelon accounted for the increased electric power output of LSCS 12 compared to the generic reactor power output presented in NUREG/BR-0184 (NRC 1997a). 13 LaSalle County Station CDF for Internal Events CDF(a) Percent CDF Initiating Event (per year) Contribution Turbine Trip with Bypass 5.6x107 22 Dual Unit Loss of Offsite Power 3.1x107 12 Loss of Instrument Air 2.8x107 11 Loss of Condenser Vacuum 2.7x107 10 Fire Protection System Pipe Rupture in Reactor Building 1.9x107 7 Main Steam Isolation Valve Closure 1.4x107 5 Loss of Turbine Building Component Cooling Water 1.2x107 5 Loss of Feedwater 1.1x108 4 Loss of Offsite Power 7.2x108 3 Manual Shutdown 5.9x108 2 Inadvertently Open Relief Valve 5.9x108 2 Loss of 125 V Direct Current Bus 2A 5.1x108 2 Loss of 125 V Direct Current Buses 2A and 2B 3.9x108 2 Other Initiating Events(b) 3.3x107 13 Total (Internal Events)(c) 2.58x106 100 (a) CDF based on Fussell-Vesely importance and total CDF. (b) Other initiating events each contributing less than 2% to total CDF. (c) Column totals may be different because of rounding. Key: CDF = core damage frequency Source: Exelon 2014a 14 In the ER, as updated by the response to RAIs (Exelon 2015), Exelon calculated the dose risk 15 to be 0.0764 person-sievert (Sv) per year (7.64 person-rem per year) to the population within 16 80 km (50 mi) of the LSCS site. The offsite economic cost risk was calculated to be 17 $57,700 per year. The breakdown of the population dose risk by containment release category 18 is summarized in Table F-2. The medium magnitude, intermediate release category accounted 19 for 52 and 62 percent of the population dose risk and offsite economic cost risk, respectively. F-3

Appendix F 1 Additionally, two categories (medium magnitude, early release and high magnitude, early 2 releases for breaks outside containment) together accounted for approximately 41 and 3 31 percent of the population dose risk and offsite economic cost risk, respectively. 4 F.2.2. Review of Exelons Risk Estimates 5 Exelons determination of offsite risk at the LSCS site is based on the following three major 6 elements of the analysis: 7 (1) Upgraded Level 1 risk model that supersedes the 1994 IPE/IPEEE submittal 8 (CECO 1994), a new interim fire PRA and the seismic and other external event 9 analyses of the 1994 IPE/IPEEE submittal; 10 (2) Expanded Level 2 risk model; and 11 (3) MACCS2 analyses performed by Exelon to translate fission product source terms 12 and release frequencies from the Level 2 PRA model into offsite consequence 13 measures. 14 The NRC staff reviewed each of these analyses to determine the acceptability of the LSCS risk 15 estimates for the SAMA analysis. 16 Base Case Mean Population Dose Risk and 17 Offsite Economic Cost Risk for Internal Events Release Category Population Dose Risk(a) Offsite Economic Cost Risk Frequency ID(b) (per year) person-rem/year  % Contribution $/year  % Contribution H/E-BOC(c) 8.3x108 1.3x100 18 7.2x103 13 H/E 6.0x108 3.2x101 4 2.8x103 5 H/I(d) 1.9x108 1.1x101 1 9.7x102 2 M/E 2.4x107 1.7x100 23 1.0x104 18 M/I(d) 1.0x106 3.9x100 52 3.6x104 62 L/E 3.9x107 8.7x102 1 1.3x102 0.2 L/I(d) 1.5x107 1.1x101 1 1.8x102 0.3 CI 6.2x107 1.4x103 <0.1 1.0x100 <0.1 Total 2.6x106 7.6x10 0 100 5.8x10 4 100 F-4

Appendix F Release Category Population Dose Risk(a) Offsite Economic Cost Risk (a) Unit Conversion Factor: 1 Sv = 100 rem (b) Release Mode Nomenclature (Magnitude/Timing) Magnitude: High (H)Greater than 10 percent release fraction for cesium iodide Medium (M)1 to 10 percent release fraction for cesium iodide Low (L)0.1 to 1 percent release fraction for cesium iodide Low-Low (LL)Less than 0.1 percent release fraction for cesium iodide Containment intact (CI)Much less than 0.1 percent release fraction for cesium iodide Timing: Early (/E)Less than 5 hours0.208 days <br />0.0298 weeks <br />0.00685 months <br /> Intermediate (/I)5 to 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> Late (/L)Greater than 24 hours1 days <br />0.143 weeks <br />0.0329 months <br /> (c) Contributions from initiators with breaks outside containment (BOC) (d) The release categories for late timing were negligible and subsumed into the intermediate release categories for H, M, and L releases. Categories for LL magnitude releases were negligible and subsumed into the L release category with intermediate timing. Sources: Exelon 2014a, 2015 1 F.2.2.1. Internal Events CDF Model 2 Commonwealth Edison Company submitted a combined IPE/IPEEE report to fulfill the 3 requirements of Generic Letter 88-20 (NRC 1988). This submittal was brief and referred to the 4 information in NUREG/CR-4832, Analysis of the LaSalle Unit 2 Nuclear Power Plant: Risk 5 Methods Integration and Evaluation Program (RMIEP), which was performed by Sandia 6 National Laboratories (SNL) and sponsored by the NRC (NRC 1992). 7 The NRC staffs review of the LSCS IPE is described in its 1995 memorandum (NRC 1995). 8 Based on its review of the LSCS nuclear power plant IPE submittal and associated 9 documentation, the NRC staff concluded that the licensee met the intent of Generic Letter 88-20 10 (NRC 1988). As indicated in the NRC staff review, while the licensee concluded that no 11 vulnerabilities exist at LSCS, the licensee cited potential improvements identified and discussed 12 in Volume 3, Part 1 of the RMIEP report. These potential improvements are discussed in 13 Section F.3.2. 14 There have been numerous revisions to the LSCS PRA since the original 1994 IPE submittal. 15 A listing of the complete revision history of the LSCS PRA, since the original IPE submittal, was 16 provided in the ER (Exelon 2014a) and in response to an NRC staff RAI (Exelon 2015). The 17 PRA revision history is summarized in Table F-3. A comparison of the CDF for internal events 18 between the 1994 IPE and the current PRA model indicates there has been a significant 19 reduction in total CDF (point estimate including internal floods from 3.4x105 per year7 to 20 2.6x106 per year). 21 The CDF value from the 1994 IPE (3.4x105 per year) is within the range of CDF values 22 reported in the IPEs for BWR 5/6 plant units. In NUREG-1560, CDF values ranged from 1x105 7 The 3.4x106 per year total CDF is the sum of the point estimates for internal events and internal floods from RMIEP, as given in the Technical Evaluation Report attached to the NRC review of the LSCS IPE (NRC 1995). F-5

Appendix F 1 per year to 4x105 per year (NRC 1997b). It is recognized that other plants have updated the 2 values for CDF subsequent to the IPE submittals to reflect modeling and hardware changes. 3 The NRC staff considered the peer review performed for the LSCS PRA and the potential 4 impact of the review findings on the SAMA evaluation. In the ER, Exelon described the 5 2008 Boiling Water Reactor Owners Group (BWROG) peer review of the LSCS PRA. The peer 6 review was indicated to be performed against Addendum B of the then current PRA Standard 7 (ASME/ANS 2005) with the criteria in Regulatory Guide 1.200, Revision 1 (NRC 2007), 8 including the NRC positions stated in Appendix A of the regulatory guide. 9 Exelon indicated that a PRA update was conducted in 2011 that addressed the majority of 10 2008 peer review findings and American Society of Mechanical Engineers/American Nuclear 11 Society (ASME/ANS) PRA standards supporting requirements assigned a Capability Category II 12 or lower. In ER Table F.2-7 (Exelon 2014a), a summary was presented on the remaining open 13 supporting requirements identified from the peer review as not meeting Capability Category II 14 and associated findings, along with an assessment of the impact on the base PRA. Of the six 15 open supporting requirements, three are related to documentation and three have a relatively 16 minor impact on the PRA results. 17 The NRC staff has determined that Exelon has demonstrated sufficient internal events PRA 18 quality by addressing the peer review open findings noted above consistent with the guidance in 19 Nuclear Energy Institute (NEI) 05-01 (NEI 2005) and that the final resolution of the findings 20 provides reasonable assurance of a minimal impact on the results of the SAMA analysis. As 21 previously indicated, the 2013A update to the PRA model (LS213A) is the most recent 22 evaluation of the risk profile at LSCS for internal events. Exelon indicates this PRA model is 23 documented as an application-specific model developed for use in the SAMA application. The 24 current PRA model of record is the 2011A PRA. In the 2013A model, Level 1 logic from the 25 2011A model was not changed beyond what was required to integrate it with the Level 2 model. 26 CDF portions of the 2011A and 2013A PRA models are identical. Therefore, updates 27 performed in the 2011A model to resolve the peer review comments were carried into the 28 2013A model. 29 Section F.2 of the ER states that the LSCS PRA is a Unit 2 model. Because the units are nearly 30 identical, the PRA for Unit 2 is considered to be applicable to Unit 1, unless otherwise noted. In 31 an RAI, the NRC staff asked Exelon to provide a brief description of the differences between the 32 units, particularly those differences that might impact internal flooding and their impacts on the 33 unit risk. Exelon responded that the major difference between the units is that the common or 34 0 diesel generator is located in the Unit 1 Auxiliary Building and the 0 diesel generator 35 cooling water pump is located in the Unit 1 Division 1 core standby cooling system (CSCS) 36 pump room. A flood event that initiates in the Unit 1 Division 1 CSCS pump room does not 37 propagate from this room, because the surrounding areas are protected by a water tight door 38 and walls. Exelon indicated that this specific flood scenario is a negligible contributor to risk on 39 both units because it only impacts one division of CSCS equipment. The Unit 1 CDF 40 contribution from a flood in this area would be slightly higher than Unit 2 because the internal 41 flood also will impact the Unit 1 residual heat removal service water (RHRSW) pumps. The 42 Unit 1 RHRSW pumps do not have a function for Unit 2; therefore, loss of these pumps has no 43 quantitative impacts on the Unit 2 CDF values. Because these flood scenarios have a negligible 44 CDF impact and a limited impact on plant equipment and operator response, Exelon concluded 45 there would be no impact on the SAMA evaluation. Exelon also discussed the general plant 46 layout; internal flooding scenarios; and other asymmetries between units, including the power 47 supplies for the shared systems. Exelon concluded and the NRC staff agrees that none of the 48 minor differences has an impact on the SAMA evaluation (Exelon 2015). F-6

Appendix F 1 Summary of Major PRA Models and Corresponding CDF and LERF Results CDF(a)(b) LERF(a)(b) PRA Model Summary of Significant Changes From Prior Model (per year) (per year) IPE (4/1994)

  • IPE 3.4x105 Not mean value Quantified Updated IPE
  • Converted to CAFTA linked fault tree 1.0x105 (c) Not (1996)
  • Incorporated plant procedure changes and modifications Quantified 1999 Rev.1
  • Increased credit for offsite AC power recovery 8.6x106 1.5x106 (11/1999)
  • Took appropriate credit for turbine-driven feedwater pump and main condenser
  • Corrected RCIC AC power dependency
  • Revised containment modeling to not always core damage upon containment failure
  • Revised service water system model
  • Credited diesel fire pump for injection post containment challenge 2000A
  • Credited increased 125 V DC battery life for extended 5.9x106(d) 1.0x106 (1/2000) RCIC operability
  • Included room cooling dependency for ECCS systems
  • Included realistic assessment of post venting equipment reliability
  • Updated CCF probabilities
  • Expanded treatment of HRA dependencies
  • Incorporated internal flood scenarios
  • Incorporated unit electrical crossties
  • Credited recovery of station air for containment venting during long-term loss of decay heat removal 2000C(e)
  • Revised turbine building flood model 8.2x106(d) Not (3/2000)
  • Updated HRA Quantified 2001A
  • Changed turbine building flood model to reflect changes in 5.7x106(d) 6.7x107 (8/2001) the pipe inspection program
  • revised the scram failure probabilities based on new industry data
  • incorporated updated service water pump success criteria based on LSCS historical operating practices F-7

Appendix F CDF(a)(b) LERF(a)(b) PRA Model Summary of Significant Changes From Prior Model (per year) (per year) 2003A

  • Revised component failure data including extensive use of 6.6x106(d) 3.6x107 (6/2003) plant-specific component failure data gathered from the LSCS Maintenance Rule program
  • Revised initiating events data utilizing the latest LSCS operating experience
  • Added alternate configuration logic for all systems with alternate/standby trains
  • Added logic for newly installed redundant 125 V DC backup battery chargers on both divisions of Unit 2
  • Added new logic for the trailer-mounted Station Air compressor to the model
  • Revised Station Air success criteria 2006A
  • Model modified to reflect the emergency operating 8.1x106 3.1x107 (1/2007) procedures for LSCS which differ from the generic BWROG EPGs in that they do not direct ADS inhibit unless a failure to scram occurs (or power is unknown)
  • Updated the turbine building flooding accident sequences
  • Allocated LOCA frequencies on a location and size-
  • specific basis
  • Updated data to use the most current industry data and plant-specific data 2006B
  • Completely revised internal flooding analysis 3.6x106 3.0x107 (5/2007)
  • Added additional dependent HEPs to recovery files
  • Quantified several support system initiator fault trees and added frequencies to model 2006C Subject of 2008 Peer Review 4.0x106 3.0x107 (1/2008)
  • Revised RHR suppression pool cooling model to address error
  • Updated several fault tree logics to address internal review issue
  • Revised several CCF probabilities
  • Revised frequency for medium below core LOCA
  • Added additional flood scenario links in system fault tree models
  • Added coincident maintenance links in system fault trees F-8

Appendix F CDF(a)(b) LERF(a)(b) PRA Model Summary of Significant Changes From Prior Model (per year) (per year) 2011A

  • Updated transient frequencies and component failure 2.6x106 1.3x107 (3/2013) rates using latest plant data
  • Deleted loss of bus 241Y and 242Y as initiating events because loss of these buses does not result in a scram
  • Refined treatment of the ECCS water hammer scenarios
  • Crediting closure of the reactor building ventilation check dampers as a potential flood mitigation strategy
  • Deleted most coincident maintenance terms as these events did not meet the current definition of the ASME/ANS PRA Standard
  • Re-evaluated categorization of mitigated ATWS (i.e., SLC successfully injected) scenarios with subsequent failure of containment heat removal from Class IV to Class II
  • Corrected probability of failure of ADS due to environment from 1.0 to 103 based on the controls/steam sensitive portion of the ADS system is not in the reactor building
  • Revised the probability for preexisting containment failure modes from 5x103 to 2.3x103 to be consistent with current industry information 2013A
  • Replace LERF model with full Level 2 model 2.6x106 1.4x107 (7/2014)

(a) All values assumed to be point estimates unless indicated to be otherwise. (b) Models prior to 2000A version did not include internal flooding. (c) CDF value based on information in NUREG-1560, Volume 3, Table B-1. Note that this NUREG volume did not contain specific details on the reported CDF values. (d) CDF values include 1x10-7 per year due to seismic events. LERF value is unknown. (e) 2000B model was not issued in any regulatory applications. Key: AC = alternating current; ADS = automatic depressurization system; ATWS = anticipated transients without scram; BWROG = Boiling Water Reactor Owners Group; CAFTA = Computer-Aided Fault Tree Analysis; CDF = core damage frequency; CCF = common cause failure; DC = direct current; ECCS = emergency core cooling systems; EPG = emergency procedure guidelines; HEP = human error probability; HRA = human reliability analysis; IPE = individual plant examination; LERF = large early release frequency; LOCA = loss-of-coolant accident; LSCS = LaSalle County Station; PRA = probabilistic risk assessment; RCIC = reactor core isolation cooling, RHR = residual heat removal; SLC = standby liquid control Sources: Exelon 2014a, 2015 1 In response to an NRC staff RAI to identify shared plant systems, or those that could be 2 cross-tied between units, and to describe the modeling, including the treatment of unavailability 3 during outages or accidents involving the other unit, Exelon responded that the most significant 4 piece of equipment shared between units is the common or 0 diesel generator. This diesel 5 generator is shared between the Unit 1 and Unit 2 Division 1 AC power divisions. Modeling of 6 this component assumes that it loads automatically to the modeled unit 50 percent of the time 7 when demanded. The model includes an operator action to manually align the 0 diesel 8 generator to the modeled unit if the 0 diesel generator does not automatically align to the unit. 9 The model also includes an operator action related to the failure to control the loading of the 10 diesel generator when it is aligned to both units. Exelon further indicated that the Division 1 and F-9

Appendix F 1 Division 2 AC safety-related 4 (kV) buses can be cross-tied between units, which provides a 2 means to power these buses via the opposite unit offsite power sources. The PRA model 3 includes the opposite unit offsite power sources, divisional crosstie breakers, and the operator 4 action necessary to complete this alignment. 5 Other shared systems include the instrument air system, the service water system, and the fire 6 protection system (FPS). Other than the 0 diesel generator, crosstie breakers, and AC power 7 supplies, the model does not explicitly consider the impacts of events occurring at one unit that 8 affect the other unit. Service water and instrument air have the capability to support both units 9 simultaneously during events at both units. With respect to the FPS, it could be aligned to both 10 units and could be shared for injection. However, the PRA model does not account for this 11 condition probabilistically. For all shared systems, system unavailability during outages is 12 considered in the development of system maintenance unavailability basic events. 13 (Exelon 2015). 14 Exelon stated in the ER: 15 The freeze date for data and plant modifications to be considered for the Level 1 16 portion of the LS213A model (the 2011 LSCS PRA update, LS211A) is 17 December 31, 2010. The Emergency Operating Procedures (EOPs) and Severe 18 Accident Guidelines (SAGs) used in this analysis are those in place as of the 19 freeze date. No significant plant modifications affecting the risk profile were 20 performed since the PRA model freeze date. EOP and SAG changes made 21 since the freeze date were reviewed and incorporated, as necessary, into the 22 LS213A model. The freeze date for the LS213A model was December 31, 2013. 23 In an RAI, the NRC staff asked Exelon to identify any planned changes or modifications to the 24 LSCS design (other than the hardened pipe vent), operation, reactor power level, fuel cycle, or 25 fuel design that might affect the SAMA analysis and describe their expected impacts. In 26 response, Exelon indicated that the PRA open items tracking database (commonly referred to 27 as the updating requirement evaluation (URE) database) was reviewed and no outstanding 28 modifications were identified, with the exception of the necessary plant modifications to meet 29 the NRC order related to the Near Term Task Force (NTTF) on Fukushima. In particular, these 30 changes will be made in relation to mitigating strategies (EA-12-049) and the installation of the 31 hardened pipe containment vent (EA-12-050) (Exelon 2015). 32 As noted above, the CDF due to ATWS events is 4.9x10-7 per year8 or 19 percent of the total 33 CDF for internal events. In response to an RAI to discuss the reasons for the relatively high 34 contribution to the total CDF for internal events, Exelon responded by summarizing the plant 35 design and operating features that affect the ATWS CDF. The joint human error probabilities 36 (HEPs) for operator actions that must be performed in short time windows are prevalent in the 37 ATWS cutsets and are the dominant contributors to CDF from this accident class. Some short 38 time windows for response are due to the plant design and the lack of a redundant, 39 high-pressure, high-volume injection system for use in these scenarios. The only high-pressure, 40 high-volume injection system available in an ATWS is feedwater. Emergency operating 41 procedures require the high-pressure core spray system to be secured, and the Reactor Core 42 Isolation Cooling System (RCIC) is a low-volume system. The capability of feedwater is limited 43 by the rate at which water can be made up to the condenser. 44 Exelon further provided the ATWS CDF and relative contribution to total CDF for a number of 45 other BWR units. Exelon concluded that, in general, ATWS CDF and the percent contribution of 8 This value does not include the CDF contribution from mitigated ATWS events for which standby liquid control (SBLC) injection is successful but core damage occurs due to subsequent coolant injection or heat removal failures. F-10

Appendix F 1 ATWS to the CDF vary significantly in the industry, and values can be found both above and 2 below those documented for LSCS (Exelon 2015). 3 The NRC staff noted that Section F.2.3.1 of the ER states all ATWS events are modeled as a 4 turbine trip. In response to an RAI to clarify this statement, Exelon indicated that this statement 5 was intended to explain the prior statement in the ER that The turbine trip initiating event is 6 important to note because it also represents the ATWS frequency. A better way to describe the 7 relationship of the turbine trip initiator to the ATWS is that ATWS sequences are a large 8 contributor to the percentage of CDF attributed to the turbine trip initiating event. Exelon noted 9 that other initiating events also result in ATWS sequences (Exelon 2015). 10 On the basis of the NRC staffs evaluation of internal events Level 1 PRA previously described 11 in this subsection, and Exelons response to the NRC staff RAIs, the NRC staff concludes that 12 the internal events Level 1 PRA model is of sufficient quality to support the SAMA evaluation. 13 F.2.2.2. External Events 14 As previously indicated, the LSCS PRA used for the SAMA analysis does not include external 15 events. In the absence of such an analysis, Exelon used the results of a new interim fire PRA 16 and the LSCS IPEEE to identify the highest risk accident sequences and the potential means of 17 reducing the risk posed by those sequences and to estimate the benefit of potential SAMAs, as 18 discussed below and in Section F.3.2. 19 The LSCS IPEEE was submitted in April 1994 (CECO 1994) in response to Supplement 4 of 20 Generic Letter 88-20 (NRC 1991). The submittal cited the external events analysis performed 21 as part of the NRC-sponsored RMIEP analysis of LSCS (NRC 1992). This analysis included 22 internal fire, internal flood, and seismic risk assessments, as well as a probabilistic bounding 23 analysis of the other external hazards (turbine-generated missiles, accidental aircraft impacts, 24 high winds, transportation and nearby facility accidents, and external flooding). The IPEEE did 25 not provide a definition of a vulnerability and did not identify any plant improvements resulting 26 from the fire, seismic, or other external hazard analyses in the IPEEE submittal. The RMIEP 27 report identified two issues in the fire area that were provided to the station for disposition. 28 These were (1) to install tops on the main control room electrical panels and (2) to institute an 29 inspection program for penetration seals at the top of switchgear panels. The disposition of 30 these improvements is discussed in Section F.3. Upon completion of the NRC staff review of 31 the IPEEE submittal and the supporting RMIEP work, the NRC staff concluded that the 32 licensees IPEEE process is capable of identifying the most likely severe accidents and severe 33 accident vulnerabilities and the LSCS IPEEE has met the intent of Supplement 4 to Generic 34 Letter 88-20 (NRC 2000). 35 The LSCS IPEEE seismic assessment used the simplified seismic PRA performed for the 36 RMIEP project. This analysis resulted in a point estimate CDF of 6.0x10-7 per year due to 37 seismic events. The dominant seismic CDF sequences are listed in Table F-4. 38 The RMIEP seismic PRA used seismic hazard curves available at that time. In the ER, Exelon 39 provided an updated seismic CDF utilizing currently available hazard curves and the conditional 40 core damage probabilities for each accident sequence and ground motion acceleration range 41 provided in the RMIEP report. This yielded a seismic CDF of 6.6x10-7 per year. In response to 42 an NRC staff RAI to provide more information on the source of these hazard curves, Exelon 43 indicated that the LSCS hazard curves used in the SAMA analysis are the same as the LSCS 44 hazard curves included in the response to the NRCs NTTF on Fukushima Recommendation 2.1 45 (Exelon 2014b, 2015). F-11

Appendix F 1 Also in response to an NRC staff RAI, Exelon provided the LSCS seismic CDF using the 2 simplified methodology from the Generic Issue (GI) 199 evaluation (NRC 2010). The LSCS 3 seismic CDF using this methodology was found to be 2.3x10-6 per year, based on peak ground 4 acceleration (Exelon 2015). The NRC staff notes that this seismic CDF is somewhat larger than 5 that based on the RMIEP conditional core damage probabilities, which can be expected based 6 on the simplified nature of the GI-199 estimate. 7 Dominant LSCS Contributors to Seismic CDF Contribution to Total CDF* Seismic CDF* Sequence Sequence Description (per year) (percent) LOOP-Trans-3 LOOP, HPCS, and RCIC fail due to seismic failure 2.8x10-7 42 of CST, low-pressure injection fails due to random electrical support failures LOOP-Trans-4 LOOP, HPCS, and RCIC fail due to failure of 2.2x10-7 35 reactor level instrumentation or seismic failure of CST, depressurization fails LOOP-Trans-1 LOOP, HPCS fails due to random events, 7.5x10-8 11 containment heat removal fails and low-pressure injection fails Small-LOCA-3 Small LOCA, HPCS, and RCIC fail, low-pressure 3.4x10-8 5 injection fails 

    *Based on RMIEP seismic CDF of 6.6x10-7 per year (NRC 1992) and percent contribution given in the ER (Exelon 2014a)

Key: CDF = core damage frequency; CST = condensate storage tank; ER = environmental report; HPCS = high pressure core spray; LOCA = loss-of-coolant accident; LOOP = loss of offsite power; LSCS = LaSalle County Station; RCIC = reactor core isolation cooling; RMIEP = Risk Methods Integration and Evaluation Program 8 As discussed in Section F.3, Exelon reviewed the dominant sequences listed in Table F-4 to 9 identify potential SAMAs to mitigate those sequences. The total updated seismic CDF was 10 used in developing the external events multiplier, as discussed later in this subsection. 11 Seismic walkdowns of LSCS Units 1 and 2 were conducted as part of Exelons actions in 12 response to the 50.54(f) letter (NRC 2012a) requesting information related to the Fukushima 13 Daiichi NTTF recommendations. Exelon reported that the walkdowns resulted in no adverse 14 anchorage conditions, no adverse seismic spatial interactions, and no other adverse seismic 15 conditions associated with the items on the seismic walkdown equipment list (SWEL) for either 16 unit. Similarly, area walk-bys resulted in no adverse seismic conditions associated with other 17 systems, structures, or components located in the vicinity of the SWEL item(s). The Unit 1 18 seismic walkdown identified 9 minor conditions while the Unit 2 walkdown identified 10 minor 19 conditions. Other than these minor conditions, the seismic walkdowns identified no degraded, 20 nonconforming, or unanalyzed conditions that required either immediate or follow-on action 21 (Exelon 2012a, 2012b). The NRC staff notes that the agencys and industrys response to the 22 Fukushima Daiichi event includes additional seismic evaluations, as outlined in the 23 NRCs 50.54(f) letter dated March 12, 2012 (NRC 2012a). F-12

Appendix F 1 While the LSCS IPEEE/RMIEP included an internal fire PRA, it has been superseded by a new 2 interim LSCS fire PRA. The current LSCS fire PRA gives a fire CDF of 8.9x10-6 per year for 3 Unit 1 and 9.4x10-6 per year for Unit 2. Table F-5(a) and Table F-5(b) provide a summary of 4 dominant fire zone CDF results from the LSCS fire PRA. The LSCS IPEEE fire assessment did 5 not provide a definition of the term fire vulnerability nor identify fire-related improvements. As 6 discussed above, the RMIEP report identified two issues in the fire area that were provided to 7 the station for disposition. These were (1) to install tops on the main control room electrical 8 panels and (2) to institute an inspection program for penetration seals at the top of switchgear 9 panels. The disposition of these improvements is discussed in Section F.3. 10 Exelon considers this fire model to be an interim implementation of NUREG/CR-6850 11 (NRC 2005) because all tasks identified in that document were not completely addressed or 12 implemented in the model. The ER includes a listing of limitations of the current LSCS fire PRA 13 relative to the tasks of NUREG/CR-6850 (NRC 2005). While some limitations may result in 14 additional fire scenarios or impact the frequency of existing scenarios, others lead to 15 conservatisms in the current result. Exelon also notes that the fire PRA utilizes the 16 2006C internal events PRA, which is not integrated with the current internal events 2013A PRA. 17 Accordingly, the LSCS fire PRA cannot be used in an integrated analysis with the internal 18 events PRA. Therefore, the total fire CDF from the analysis was used to determine the external 19 events multiplier, while the listing of dominant sequences was used to identify potential 20 cost-beneficial SAMAs as allowed by the industry guidance in NEI 05-01 and further discussed 21 in Section F.3. 22 The LSCS IPEEE/RMIEP analysis of high winds, tornadoes, external floods, and other external 23 events (HFO) consisted of a bounding probabilistic assessment. For these events, the 24 IPEEE/RMIEP concluded that these events were not significant contributors to plant risk and 25 there were no improvements identified for these events (CECO 1994). 26 The ER discusses each of these external events and provides the following CDF estimates from 27 RMIEP. Turbine Generated Missiles (mean) 9.5x10-8 per year Accidental Aircraft Impact (median) 5.0x10-7 per year High Winds (median) 3.0x10-8 per year Transportation & Nearby Facility Accidents9 3.0x10-8 per year External Flooding3 3.0x10-8 per year Total HFO external events 6.9x10-7 per year 28 The NRC staff considers the use of these CDFs consistent with the guidance provided in 29 NEI 05-01. 9 For the purposes of the SAMA analysis, external event frequencies for external flooding as well as transportation and nearby facility accidents are taken to be the same as the frequency for high winds. F-13

Appendix F 1 Table F-5(a). Dominant LSCS Unit 1 Fire Zone 2 Contributors to Fire CDF of 8.9x10-6 per year Contribution to Total Fire CDF CDF Fire Zone Zone Description (per year) (percent) 4F1 Unit 1Division 1 Essential Switchgear Room 2.7x10-6 30 4E3-2 Unit 1Division 2 Essential Switchgear Room 2.7x10-6 30 4C1 Control Room 5.9x10-7 7 4E1-2 Unit 1Auxiliary Electric Equipment RoomMain AER 3.9x10-7 4 Room 3 Table F-5(b). Dominant LSCS Unit 2 Fire Zone 4 Contributors to Fire CDF of 9.4x10-6 per year Contribution CDF to CDF Fire Zone Zone Description (per year) (percent) 4E4-2 Unit 2Division 2 Essential Switchgear Room 2.9x10-6 30 4F2 Unit 2Division 1 Essential Switchgear Room 2.7x10-6 29 4E2-2 Unit 2Auxiliary Electric Equipment Room-Main AER 7.7x10-7 8 Room 4C1 Control Room 5.9x10-7 6 Key: CDF = core damage frequency; LSCS = LaSalle County Station 5 The NRC staff notes that Exelons response to the NRCs 50.54(f) letter (NRC 2012a) 6 requesting information related to the Fukushima Daiichi NTTF recommendations includes a 7 flooding walkdown and a flood hazards reevaluation. As reported in the NRC staff assessment 8 of the walkdown report (NRC 2014), five deficiencies were identified during the course of the 9 flooding walkdowns and entered into the corrective action program for tracking and resolution. 10 Two deficiencies were related to lack of seal or significant rust in penetrations. 11 Three deficiencies were related to exterior doors threshold elevations being lower than the 12 calculated flood elevation. The NRC staff concluded that the licensees implementation of 13 flooding walkdown methodology meets the intent of the walkdown guidance. 14 In the flood hazards reevaluation (Exelon 2014c), Exelon concluded that The current design 15 basis flood does not bound the reevaluated hazard for all applicable flood-causing mechanisms, 16 combined-effect floods, associated effects, and/or flood event duration parameters. Because 17 of this result, Exelon is preparing a fully integrated assessment of these flood hazards. Exelons 18 flood hazard evaluation also includes a summary of interim evaluations and actions taken or 19 planned to address the instances for which the reevaluated hazard exceeds the design basis. 20 These issues are being addressed via the ongoing Japan Lessons Learned program and 21 implementation of the Fukushima Daiichi NTTF recommendations, including NRC Order 22 EA-12-049, Order to Modify Licenses with Regard to Requirements for Mitigation Strategies for 23 Beyond-Design-Basis External Events (NRC 2012b) and is outside the scope of the SAMA 24 analysis. F-14

Appendix F 1 As discussed in the ER, there are no up-to-date quantitative external event models for LSCS, so 2 a multiplier to the internal events PRA results was developed to account for risk contributions 3 from external events in the SAMA evaluation. For seismic contributions to risk, Exelon used the 4 updated RMIEP seismic CDF value of 6.6x107 per year. For fire contributions to risk, Exelon 5 used a Unit 2 fire CDF of 9.4x106 per year, discussed above. For HFO events, the value of 6 6.9x10-7 per year was used. 7 Based on these results, Exelon indicated in the ER that the total CDF for external events is 8 approximately 1.08x105 per year. The total CDF (internal and external events) is then 9 approximately 1.33x105 per year or 5.2 times the CDF for internal events. This multiplier was 10 used by Exelon in the SAMA analysis to account for the impact of external events on the 11 calculated benefits. 12 The NRC staff agrees with the applicants overall conclusion concerning use of the multiplier to 13 represent the impact of external events and finds that a multiplier of 5.2 will reasonably account 14 for external events in the SAMA evaluation. 15 F.2.2.3. Level 2 Fission Product Release Analysis 16 The NRC staff reviewed the general process Exelon used to translate the results of the Level 1 17 PRA into containment releases, as well as the results of the Level 2 analysis, as described in 18 the ER (Exelon 2014a) and Exelons responses to NRC staff RAIs (Exelon 2015). Exelon 19 indicates this PRA model is documented as an application-specific model developed for the use 20 in the SAMA application. The SAMA Level 2 model is an expansion of the prior LERF-only 21 model to a full Level 2 model. 22 The LSCS Level 1 PRA postulates accident sequences that lead to core damage and potentially 23 challenge containment. These discrete accident sequences contribute to the CDF, represent 24 the spectrum of possible challenges to containment, and are placed into functional sequence 25 groupings (i.e., accident classes and subclasses). The Level 1 accident class bins are then 26 used as the starting point for the Level 2 PRA CET analysis. Level 1 accident sequences and 27 resulting cutsets are incorporated directly into the Level 2 analysis to maintain the propagation 28 of dependencies. The accident classes and subclasses used for the LSCS SAMA analysis are 29 summarized in ER Table F.2-3 (Exelon 2014a). 30 The response of containment to core damage is analyzed by a CET for each accident class or 31 subclass. Each node in the CET is evaluated using the nodal functional fault trees that include 32 the following considerations: 33

  • fault tree models from the Level 1 analysis for the system or function, 34
  • any Level 2 limitations in timing, procedures, access, or dependencies, 35
  • phenomenological effects, and 36
  • environmental impacts on equipment or operator actions.

37 The CETs and the end-state assignments are based on deterministic core melt progression 38 calculations. Exelon directly links the Level 1 and Level 2 models using a single top logic 39 structure and quantifies them using the Electric Research Power Institute (EPRI) 40 Computer-Aided Fault Tree Analysis (CAFTA) software. Functional event nodes of the LSCS 41 Level 2 CET are: 42

  • Containment Isolated (IS),

43

  • RPV Depressurization (OP),

F-15

Appendix F 1

  • Core Melt Arrested In-Vessel (RX),

2

  • Combustible Gas Venting Initiated (GV),

3

  • Containment Remains Intact (CZ),

4

  • Injection Established to RPV or Drywell (TD),

5

  • Containment Flooding Occurs with Drywell Vent (FC),

6

  • Containment Heat Removal (HR),

7

  • Containment Vent (CV),

8

  • Suppression Pool Bypass (SP),

9

  • No Large Containment Failure (NC),

10

  • Inventory Makeup Available (MU),

11

  • Drywell Intact (DI),

12

  • Wetwell (WW) Airspace Failure, and 13
  • Reactor Building Effectiveness (RB).

14 As described in ER Section F.2.1 (Exelon 2014a), the release categories were defined based on 15 the timing and magnitude of releases. Each CET end state represents a radionuclide release to 16 the environment and is assigned to a release category based on the CET sequence 17 characteristics, MAAP 4.0.5 results, and a set of release category rules. When MAAP is not 18 well suited to modeling the accident phenomena associated with a scenario, the scenario is 19 modeled using conservative estimates (e.g., steam explosion) and insights from other Level 2 20 PRA models from plants of a similar type. 21 ER Table F.2-6 provides a summary of the LSCS Level 2 release category frequencies for each 22 of the 15 accident classes or subclasses (Exelon 2014a). For accident class II (accident 23 sequences involving a loss of containment heat removal with the reactor pressure vessel initially 24 intact but with post containment failure or venting induced by core damage), the NRC staff 25 noted in an RAI that the subclasses listed in ER Table F.2-6 were different from those in ER 26 Table F.2-3. In response, Exelon indicated that the four accident Class II subclasses 27 (II, IIE, IIV, IIVE), used in the SAMA analysis and included in ER Table F.2-6, represent early 28 (IIE and IIVE) releases resulting from containment failure and containment venting, respectively; 29 and non-early (II and IIV) releases resulting from containment failure and containment venting, 30 respectively. Exelon indicated that for convenience in modeling, the Class II accident classes 31 are separated into two CETs; one representing the early releases and the other representing 32 intermediate or late (non-early) releases for the containment failure sequences and two similar 33 ones for venting sequences. 34 Exelon further indicated that the analysis of the timing of a General Emergency declaration has 35 been evaluated from a probabilistic standpoint for Class II accident scenarios. This evaluation 36 was performed because of the potential differences in interpretation of the Emergency Action 37 Levels (EALs) and the probability that the Emergency Director could delay the declaration of the 38 General Emergency resulting in an early release. Interviews of key emergency response 39 personnel were performed to determine the best estimate probability that the EALs would be 40 interpreted such that the General Emergency declaration would be delayed resulting in an early 41 release as opposed to an intermediate or late release. These interviews consisted of case 42 studies and a discussion of EALs. The mean probability of failure to declare a General 43 Emergency with adequate time to take protection measures for the general public prior to F-16

Appendix F 1 containment failure is 5 percent or 0.05 based on expert opinions. As a result, the LSCS 2 Level 2 model is structured such that 5 percent of the Class II accidents can result in an Early 3 release, but 95 percent of the Class II accident releases are non-early releases. 4 The NRC staff noted in an RAI that ER Table F.2-6, which provides the accident class 5 frequency contribution to each release category, includes a significant intact containment 6 frequency for the Class II accident subclasses. Class II accidents are normally considered, and 7 defined in ER Table 2-3, to include sequences where core damage occurs after containment 8 failure; therefore, there should be no intact containment sequences in Class II. In response to 9 the RAI to discuss the reasons for these results, Exelon indicated that the intact frequency was 10 obtained from the difference between the CDF for each accident subclass and the total of all the 11 other release category frequencies. As discussed above, the Class II accident classes are split 12 into two timing categories; early and non-early and a separate Class II event tree was used for 13 each category. For the early release class, the total Class II frequency is multiplied by 14 0.05 when the CDF value is transferred into the Level 2 model. Then, the remaining event tree 15 nodes are evaluated. This results in truncation of low-frequency sequences leading to the total 16 of all the release categories being significantly less than the CDF for the Class II subclasses. 17 To account for this undercounting of Class II releases, Exelon performed a sensitivity study to 18 determine the impact of this truncation issue. The study was performed by setting the PRA 19 model basic event related to the General Emergency declaration to 1.0 (instead of 0.95 and 20 0.05) and requantifying the model. After quantification, the 95 percent and 5 percent split 21 between non-early and early releases were calculated. Because the results demonstrated that 22 low-frequency sequences had previously been truncated from the final results, Exelon revised 23 the release category frequencies in its response to the RAI (Exelon 2015, Table F.2-6 revised). 24 Exelon noted that in the requantified results, there is still a very small unaccounted for frequency 25 in the Level 2 release results due to additional truncated sequences (approximately 5 percent of 26 the CDF). This release frequency was divided proportionally among each release category 27 applicable to that accident class (i.e., Class II, IIE, IIV and IIVE). Exelon indicated that model 28 truncation is a known source of uncertainty in model results and while the proportional 29 redistribution of the truncated cutsets does not provide an exact solution to this quantification 30 issue, it is considered to be a reasonable approximation of how these low contributors should be 31 allocated to the release categories. Exelon concluded that any deviations between the true 32 release category allocations of the truncated frequency and those resulting from the proportional 33 distribution of the frequency would correlate to very small changes to the cost-benefit results; 34 therefore, no impacts on the conclusions of the SAMA analysis were expected. 35 Exelon noted further that the Class II accident subclasses are the only accident classes where 36 the CDF values were multiplied by a split fraction before transferring into the Level 2 fault trees. 37 Therefore, the larger impact observed for this accident class is not applicable to other accident 38 classes. Other truncation issues would be small and are bounded by the uncertainty in other 39 inputs. Exelon concluded that the SAMA evaluation would not be impacted by model truncation 40 issues. 41 The NRC staff agrees, for the purposes of the SAMA analysis, with the Exelon approach to 42 resolving the issue associated with the original ER analysis of Class II release category 43 assessment, the conclusions associated with this issue, and the more general issue of impacts 44 from model truncation. The NRC staff also notes that the issue of how the intact release 45 category frequency was determined for other accident classes would have a very small impact 46 on the SAMA analysis because major accident class contributors to those other-than-Class II 47 release categories that are most important to offsite cost risk (Classes IIID, IV, and V) had a 48 zero intact containment frequency in the original ER analysis. Exelons revisions to F-17

Appendix F 1 the release category frequencies influenced the base case maximum averted cost risk (MACR) 2 and the cost-benefit analysis for each SAMA (Exelon 2015). 3 Exelon developed the accident progression and associated release characteristics for each 4 release category by using the results of MAAP Version 4.0.5 computer code calculations. 5 A MAAP case was identified as a representative case for each of the LSCS Level 2 PRA 6 release categories based on a review of the Level 2 model cutsets and the dominant types of 7 scenarios that contribute to the release category. Tables F.3-17 and F.3-18 in the ER provide 8 a description of the representative cases for each release category and additional information 9 on the selection of these representative cases (Exelon 2014a). 10 With regard to the selection of representative cases, the NRC staff noted in an RAI that the 11 dominant contributor to the low-magnitude early (L/E) release category is an ATWS sequence. 12 This event sequence involves successful depressurization of the reactor pressure vessel (RPV) 13 with core melt arresting in the vessel and a WW airspace failure. However, the MAAP scenario 14 stated in ER Tables F.3-17 and F.3-18 to be used as the reference MAAP case for this 15 sequence was not used to represent this release category. Instead, an alternate MAAP case 16 with a significantly lower cesium iodide release fraction was stated to have been used. 17 In response to the RAI, Exelon clarified that the reference MAAP cases in the Level 2 analysis 18 are not necessarily exact models of the sequence but are instead used along with the Level 2 19 Release Category rules to assign an appropriate end state to the Level 2 sequence 20 (Exelon 2015). A specific MAAP scenario modeling the dominant sequence for the L/E release 21 category was not developed for the LSCS SAMA analysis. Rather, expert judgment and review 22 of similar MAAP cases were used. In-vessel retention would be expected to reduce 23 radionuclide release fractions significantly because (1) RPV injection post-core damage 24 prevents further heat up of radionuclides, and (2) the suppression pool is not bypassed 25 (i.e., fission products are retained in the pool instead of being released directly to the 26 environment). 27 Exelon noted that while Tables F.3-17 and F.3-18 of the ER indicate that MAAP 28 case LS130533B was used to represent the L/E release category, MAAP case LS130524B was 29 actually used to represent the L/E release category indicated in Table F.3-19 of the ER. Use of 30 the LS130524B scenario in place of the LS130533B scenario is conservative because the 31 LS130524B release fractions bound the release fractions from the LS130533B scenario, and 32 the LS130524B scenario results in a substantial release of radionuclides several hours earlier 33 than the LS130533B scenario (containment breach in LS130524B vs. containment vent in 34 LS130533B). Both scenarios are containment flooding scenarios. As indicated above, the 35 dominant release category sequence is an ATWS sequence with a WW airspace failure, 36 successful RPV depressurization, in-vessel retention, and no suppression pool bypass. The 37 MAAP case LS130524B represents an ATWS sequence with WW airspace failure, successful 38 RPV depressurization, core spray available after core damage at vessel breach, and 39 containment flooding. Use of MAAP scenario LS130524B to model this sequence as a 40 surrogate for the L/E release category was judged by Exelon to be reasonable since 41 LS130524B models containment flooding shortly after vessel breach, which mimics the actions 42 of in-vessel retention by both cooling debris and retaining fission products in the local water 43 inventory (i.e., scrubbing the release). The NRC staff reviewed the logic of this assessment of 44 the release characteristics for the L/E release category and concludes that the results are 45 acceptable for the purposes of the SAMA analysis because the release category is bounding 46 and conservative. 47 In response to an NRC staff RAI to provide justification for the adequacy of the MAAP release 48 fraction results from simulation times less than 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> past the declaration of a general F-18

Appendix F 1 emergency, Exelon discussed each of these MAAP analysis cases. The run times were 2 considered adequate based on either: (i) results at the end of the run having reached an 3 obvious plateau and being stable well before the end of the run, or (ii) the core debris being 4 quenched in a large body of water (the suppression pool) and stabilized at a relatively low 5 temperature (Exelon 2015). Based on this discussion and the fact that the run times were no 6 more than 8.5 hours0.208 days <br />0.0298 weeks <br />0.00685 months <br /> less than the desired run time, the NRC staff agrees that the run times 7 used in Exelons SAMA analysis are acceptable. 8 Section F.2.2.11 of the ER, titled "2013A UPGRADE" (Exelon 2014a), states: 9 In order to support the SAMA analysis, the LSCS LERF model was replaced by a 10 full Level 2 model. The Level 1 logic from the 2011A model was not changed 11 beyond what was required to integrate it with the Level 2 model. 12 In response to an NRC staff RAI to describe the changes in the Level 2 model that are 13 considered upgrades as opposed to updates and to describe the steps taken to assure technical 14 adequacy of the 2013A Level 2 model, Exelon responded that the word upgrade in the 15 subheading 2013A Upgrade in Section F.2.2.11 of the ER was intended to have its common 16 meaning rather than the meaning ascribed by the ASME/ANS PRA Standard (ASME/ANS 2009) 17 and, in retrospect, was misleading. No change to the LERF analysis or methodology that would 18 be considered an upgrade by the ASME/ANS PRA Standard definition was made during the 19 model update that created the 2013A model. Accordingly, the 2013A model did not require a 20 peer review. Exelon further indicated that it has implemented procedures and processes to 21 assure the technical adequacy of the full power internal event (FPIE) PRA models. 22 The 2013A model was reviewed and approved in accordance with these procedures and 23 processes. (Exelon 2015). 24 On the basis of the NRC staffs review of Exelons Level 2 model, the peer review performed on 25 the 2006C PRA model, the general process Exelon used to translate the results of the Level 1 26 PRA into containment releases, and Exelons responses to NRC staff RAIs, the NRC staff 27 concludes that the Level 2 PRA as modified in response to the NRC staff RAIs is of sufficient 28 quality to support the SAMA evaluation. 29 F.2.2.4. Level 3 Offsite Consequence Analysis 30 The NRC staff reviewed Exelons process to propagate the containment performance (Level 2) 31 portion of the PRA to an assessment of offsite consequences (Level 3 PRA). Using the 32 MACCS2 Version 1.13.1 code, Exelon determined the offsite consequences from potential 33 releases of radioactive material (Exelon 2014a). In the Level 3 analysis, Exelon combined 34 release fractions and release categories, discussed in Section F.2.2.3, with the calculated core 35 inventory to yield potential source terms of radionuclides released to the outside environment. 36 In response to an NRC staff RAI, Exelon indicated that the LSCS radionuclide inventory was 37 calculated with ORIGEN Version 2.1 software (Exelon 2015). The NRC staff finds the 38 MACCS2 and ORIGEN codes to be acceptable for the SAMA evaluation because the codes are 39 widely used for radiological dose calculations resulting from airborne releases of radioactive 40 material and radionuclide source term determinations, respectively. 41 Exelon determined radionuclide inventories in the core for a thermal power output of 42 3489 (MWt). Because the current licensed core power level is 3546 MWt, Exelon applied a 43 scaling factor of 1.0163 (3546 MWt/3489 MWt = 1.0163) to the radionuclide inventories in the 44 core presented in Table F.3-11 of the ER (Exelon 2014a). In response to an NRC staff RAI on 45 the core inventory calculation performed by Exelon for Unit 1, Exelon indicated that the core 46 inventory calculation was bounding for either unit because time spent during refueling outages 47 was ignored, an extended cycle length was modeled, and the higher activity value for each F-19

Appendix F 1 radioisotope was chosen from two results for the end of the fuel cycle (Exelon 2015). 2 Furthermore, Exelon reported the core design process ensures that the core inventory of each 3 unit remains within the single design basis source term. The NRC staff finds these reasons 4 provide reasonable assurance that actual radionuclide core inventories will be lower than the 5 radionuclide inventories used in the SAMA analysis. 6 In response to an NRC staff RAI on planned changes or modifications to the LSCS design, 7 operation, reactor power level, fuel cycle, or fuel characteristics, Exelon indicated planned 8 modifications in response to the NRC order arising from the severe accidents at the Fukushima 9 Daiichi nuclear generating station, include mitigating strategies and installing a hardened pipe 10 containment vent, as required by EA-12-050 and described within the ER. Additionally, Exelon 11 highlighted its PRA sensitivity study that indicated modifications excluding the hardened pipe 12 containment vent lowered the CDF by approximately 5 percent (Exelon 2015). The NRC staff 13 finds the Exelon approach to not take credit for the hardened pipe containment vent or other 14 modifications in the SAMA analysis to be conservative and acceptable because this treatment 15 does not cause potentially cost-beneficial SAMAs to be missed. 16 The NRC staff also requested additional information on the assumptions used to calculate the 17 inventories of radioactive cobalt, and Exelon described that guidance values for cobalt were 18 scaled to the core thermal power level of the LSCS units (Exelon 2015). Exelon further 19 described that one of the cobalt radioisotopes was overestimated and explained the limited 20 influence of cobalt radioisotopes to the offsite dose and offsite economic costs, which are 21 dominated by other radionuclides in the core inventory. Because the radionuclide inventories 22 for cobalt have not been underestimated and the offsite dose and offsite economic cost 23 components provide the largest contributions to the MACR, the NRC staff agrees that the 24 inventories for the radioisotopes of cobalt are acceptable for use in the SAMA analysis. 25 The NRC staff concludes that the current radionuclide inventory calculations in Table F.3-11 of 26 the ER (Exelon 2014a) are adequate for the estimation of offsite consequences because current 27 calculations bound the expected radionuclide inventory for either reactor core, and Exelons 28 additional information further justifies the appropriateness of the calculated core inventory. 29 Exelon presented the major input parameter values and assumptions of the offsite consequence 30 analyses in Appendix F of the ER (Exelon 2014a). Exelon considered site-specific 31 meteorological data for the calendar years 2010, 2011, and 2012. Meteorological data from 32 2012 were selected for input to the MACCS2 code because they resulted in the highest 33 population dose risk and offsite economic cost risk, as described in Section F.3.7 of the ER 34 (Exelon 2014a). Exelon acquired meteorological data, such as wind speed, wind direction, 35 atmospheric stability class, and precipitation, from onsite meteorological monitoring stations at 36 LSCS. Atmospheric mixing heights were obtained from information published by the 37 U.S. Environmental Protection Agency. The NRC staff finds the applicants modeling of 38 atmospheric conditions and plume dispersion to be acceptable because it is supported by 39 site-specific annual meteorological data and implemented using widely accepted software. 40 Because selection of the 2012 meteorological data set resulted in the highest population dose 41 risk and offsite economic cost risk, the NRC staff accepts its use in the SAMA evaluation. 42 Exelon addressed missing meteorological data either by interpolation or by substitution. For 43 missing wind-speed data, a power law was used to convert wind speeds measured at different 44 heights. For data gaps less than 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, interpolation was performed with valid data 45 immediately before and after the data gap. For data gaps greater than 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />, data 46 substitution was performed with valid data for the same times from either the day before or after 47 the missing data. Exelon indicated that missing data represented 2 percent or less for each of 48 the three annual meteorological data sets. Because these percentages of missing data are F-20

Appendix F 1 reasonable and the methods used to substitute missing data are common remedies, the NRC 2 staff finds these approaches to be acceptable for use in the SAMA analysis. 3 Having assessed the sensitivity to different annual meteorological data sets, release heights, 4 plume heat, and deposition velocities, Exelon found the population dose risk and offsite 5 economic cost risk either decreased (by as much as 9 percent) or increased slightly (by as 6 much as 3 percent) due to the alternative inputs. In response to an NRC staff RAI, Exelon 7 quantified the influence of precipitation on the population dose risk and offsite economic cost 8 risk. Specifically, Exelon compared the total annual precipitation, population dose risk, and total 9 offsite economic cost risk for the previously identified calendar years 2010, 2011, and 2012 and 10 reported that the single year (2012) with the highest population dose risk and total economic 11 cost risk had the lowest total annual precipitation (Exelon 2015). This observation indicated that 12 other atmospheric parameters during the modeled release had a greater influence on the 13 consequence analysis results than the time-integrated precipitation for the entire year. 14 The NRC staff finds that the selection of the 2012 meteorological data and the other parameter 15 values for atmospheric dispersion are appropriate for use in the SAMA analysis because 16 changes to the analysis typically lower expected benefits for individual SAMAs and any small 17 increases would not change the identification of cost-beneficial SAMAs. As previously 18 described, the sources of data and models for atmospheric dispersion used by the applicant are 19 appropriate for calculating consequences from potential airborne releases of radioactive 20 material. 21 Exelon used the SECPOP2000 Version 3.12 code, projected the expected growth and 22 distribution of population out to the year 2043, and reported that the total population within 23 80 km (50 mi) surrounding LSCS is anticipated to increase from 1,546,445 in the year 2000 to 24 approximately 3,107,897 in the year 2043, as shown in Table F.3-7 of the ER (Exelon 2014a). 25 From Section F.3.2, as well as Tables F.3-1 and F.3-2 of the ER, Exelon considered census 26 data from years 2000 and 2010, county growth rates for the year 2030, and transient population 27 contributions in the projection. The NRC staff finds that the methodology for population 28 projection is consistent with relevant guidance (NEI 2005). In response to an NRC staff RAI, 29 Exelon indicated the county population growth rate data were based on projections published by 30 the State of Illinois (Exelon 2015). The NRC staff verified the appropriateness of selected data 31 and compared the county growth rate data reported in the ER with the data source and found no 32 discrepancies. 33 Compared to the previously discussed atmospheric parameters, Exelon reported greater 34 influences on potential increases to the population dose risk and offsite economic cost risk from 35 sensitivity assessments of the population within 80 km [50 mi], evacuation speed, intermediate 36 phase resettlement, wealth values, and other economic inputs and rates. These results were 37 presented in Section F.7.3 of the ER (Exelon 2014a). In response to an NRC staff RAI, Exelon 38 confirmed that known SECPOP errors were prevented from influencing the SAMA analysis 39 results and that manual entry of population and economic data conformed to formatting 40 requirements (Exelon 2015). The NRC staff also requested supporting justification for spatial 41 distribution assumptions used in the population projections. Exelon responded by explaining 42 that the uniform population distribution within a county overestimates the population within 43 80 km (50 mi) of the LSCS site because many of the highly dense population areas lie outside 44 the radial distance of 80 km (50 mi), and portions of the highest populated counties that lie 45 within that radial distance tend to be more rural, more suburban, and much less populated 46 (Exelon 2015). The NRC staff finds the use of block-level census data to be acceptable 47 because it is site-specific and more representative than uniformly distributed population 48 estimates within a county. Because the applicant provided adequate RAI responses on the 49 population projection, and because an additional analysis was performed by the applicant that F-21

Appendix F 1 demonstrated the current approach was conservative, the NRC staff finds the methods, 2 assumptions, and data used for estimating population to be reasonable and acceptable for 3 purposes of the SAMA evaluation. 4 For the 16-km (10-mi) emergency planning zone at LSCS, Exelon considered site-specific 5 information in LSCS evacuation time estimates in its determination of evacuation times, time 6 delays, and travel speeds. For the baseline Level 3 calculation described in Section F.3.6 of the 7 ER (Exelon 2014a), Exelon assumed 95 percent of the population within the emergency 8 planning zone would evacuate with an evacuation speed of 1.6 meters per second (3.6 miles 9 per hour). In a sensitivity analysis (Exelon 2014a), Exelon reported an increase in the 10 population dose risk by 5 percent (negligible change to the offsite economic cost risk) due to an 11 assumed factor-of-2 reduction in the average evacuation speed. Because Exelon used 12 site-specific information and applied more pessimistic (lower) fractions for the evacuating 13 population in the emergency planning zone compared to generic values, the NRC staff 14 concludes that the evacuation assumptions and analyses are reasonable and acceptable for the 15 purposes of the SAMA analysis at LSCS. 16 Exelon developed economic values using data from the 2007 National Census of Agriculture 17 and Bureau of Economic Analysis for the counties within the 80-km (50-mi) radius of LSCS. 18 Exelon updated economic values to a reference timeframe of July 2013 using the consumer 19 price index from the Bureau of Labor Statistics. As stated in Table F.3-9 of the ER, weighted 20 average wealth values were $283,637/person for nonfarm wealth and $11,937/hectare for 21 farmland wealth. The NRC staff considers the values for nonfarm wealth to be reasonable 22 ranges that would not be expected to result in underestimates of offsite economic cost risk. 23 In response to an NRC RAI on more recent data from the 2012 National Census of Agriculture, 24 Exelon assessed the differences and indicated that annual sales of farm products and farm 25 wealth values from 2012 were typically larger than the 2007 data adjusted to 2013 values by the 26 consumer price index (Exelon 2015). Overall differences in county data for the fraction of 27 farmland and fraction of dairy farms were small between the 2012 and 2007 data sets. Having 28 calculated that the farm-dependent costs comprise 5 percent of the total offsite economic cost 29 risk, Exelon concluded that incorporation of the data from the 2012 National Census of 30 Agriculture would not have a significant impact on the SAMA analysis (Exelon 2015). 31 Farm-dependent costs do not influence the onsite and replacement power components of the 32 total averted cost risk. Given that estimated benefits at the 95th percentile for SAMA candidates 33 determined to be not cost beneficial were more than 20 percent below their estimated 34 implementation costs in Exelons revised analysis (Exelon 2015), the NRC staff concludes that 35 incorporation of 2012 agricultural data would not change the determination of cost-beneficial 36 SAMAs. Additionally, extrapolation of economic data to the year of the assessment, and not 37 through the period of extended operation, is consistent with guidance accepted by NRC 38 (NEI 2005). Because Exelons assessment included site-specific data and followed an 39 approach that is consistent with economic guidance, the NRC staff finds the data sources, 40 adjustments, and considerations made by the applicant in the Level 3 analysis to be acceptable 41 for the SAMA analysis. 42 Exelon estimated present dollar values based on the internal events PRA at LSCS and applied 43 a multiplication factor of 5.2 to account for external events. As shown in Section F.4.6 of the ER 44 (Exelon 2014a), offsite economic costs and offsite exposure costs provided the greatest 45 contributions to the total dollar value at approximately 74 and 20 percent, respectively. Onsite 46 cleanup and replacement power costs collectively contributed about 6.5 percent to the baseline 47 total dollar value for a real discount rate of 3 percent. Onsite exposure costs contributed less 48 than 1 percent. Section F.6 provides more detailed information on the cost-benefit calculation F-22

Appendix F 1 and its evaluation. Changes to the maximum averted cost risk as a result of Exelons revised 2 analysis are presented in Section F.6.1. 3 Based on its review of Exelons submissions, the NRC staff concludes that Exelons 4 methodology to estimate offsite consequences for LSCS provides an acceptable basis to 5 assess the risk reduction potential for SAMA candidates. Because the conservative modeling 6 assumptions were included in the assessment and input data were either obtained for the LSCS 7 site or found to be consistent with guidance values, the NRC staff concludes that data and 8 modeling assumptions for the Level 3 analysis are appropriate for the SAMA evaluation. 9 Accordingly, the NRC staff based its assessment of offsite risk on the core damage frequencies, 10 population doses, and offsite economic costs reported by Exelon. 11 Potential Plant Improvements 12 The process for identifying potential plant improvements, an evaluation of that process, and the 13 improvements evaluated in detail by Exelon are discussed in this section. 14 F.3.1. Process for Identifying Potential Plant Improvements 15 Exelon identified potential plant improvements (SAMAs) by review of: 16

  • LSCS PRA results and PRA group insights; 17
  • Potentially cost-effective Phase 2 SAMAs from 18 - Susquehanna Steam Electric Station SAMA Analysis, 19 - Cooper Nuclear Station SAMA Analysis, 20 - Duane Arnold Energy Center SAMA Analysis, 21 - Nine Mile Point Unit 2 SAMA Analysis, 22 - Columbia Generating Station SAMA Analysis, and 23 - Grand Gulf Nuclear Station SAMA Analysis; 24
  • LSCS IPE; and 25
  • LSCS IPEEE.

26 Exelon indicated that in addition to the Industry Phase 2 SAMA review identified above, an 27 industry-based SAMA list from NEI 05-01 (NEI 2005) was used to help identify the types of 28 changes that could be used to address the areas of concern identified through the LSCS 29 importance list review. 30 Based on this review, Exelon identified an initial set of 26 SAMA candidates, referred to as 31 Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the 32 initial list of SAMAs and eliminated SAMAs from further consideration using the following 33 criteria: 34

  • Applicability to the plant: If a proposed SAMA does not apply to the LSCS design or 35 has already been implemented, it is not retained.

36

  • Implementation cost greater than the screening cost: If the estimated cost of 37 implementation is greater than the MACR, the SAMA is screened out from further 38 analysis.

F-23

Appendix F 1 During this process, SAMA candidates 17 and 26 in Table F.5-4 of the ER (Exelon 2014a) were 2 screened out based on exceeding the cost criteria.10 Table F.6-1 of the ER (Exelon 2014a) 3 provides a description of each of the 24 Phase II SAMA candidates, which was later revised to 4 25 Phase II SAMA candidates in Exelons revised analysis (Exelon 2015). 5 In Phase II, a detailed evaluation was performed for each remaining SAMA candidate, as 6 discussed in Sections F.4 and F.6. To account for the potential impact of external events, the 7 estimated benefits based on internal events were multiplied by a factor of 5.2, as discussed in 8 Section F.2.2.2. 9 F.3.2. Review of Exelons Process 10 Exelons efforts to identify potential SAMAs focused primarily on areas associated with LSCS 11 specific internal initiating events. The NRC staff reviewed the discussions of the SAMA 12 identification process and the listing of Phase I candidate SAMAs included in the ER. 13 The primary source of candidate SAMAs (22 of a total of 26) was the review of the LSCS 14 Level 1 and Level 2 importance analysis. Four additional SAMAs were identified based on the 15 review of other BWR cost-effective SAMAs and the review of external events. 16 In the ER, Exelon provided a tabular listing of the Level 1 PRA basic events sorted according to 17 their risk reduction worth (RRW) (Exelon 2014a). These results were reviewed by Exelon to 18 identify those potential risk contributors that made a significant contribution to CDF. The RRW 19 rankings were reviewed down to 1.01. Events below this point would influence the CDF by less 20 than 1 percent and are judged, by Exelon, to be highly unlikely contributors for the identification 21 of cost-beneficial enhancements. These basic events, which include component failures, 22 operator actions, initiating events, and sequence identification markers (or flags), were reviewed 23 to determine any additional mitigating actions that may need to be considered. 24 In the ER, Exelon provides a discussion of the appropriate importance threshold for the 25 identification of candidate SAMAs. Guidance in NEI 05-01 indicates that dominant risk 26 contributors should be considered, but a dominant risk contributor was not clearly defined. 27 The NEI 05-01 example uses an RRW of 1.005, which corresponds to the ASME/ANS PRA 28 Standards (ASME/ANS 2009) definition of risk significant events. A 1 percent change in LSCS 29 CDF corresponds to approximately 3x10-8 per year compared to Regulatory Guide 1.174 30 (NRC 2011) definition that anything less than a 1x10-6 per year is a very small change. It is 31 noted that an RRW of 1.01 corresponds to a maximum averted cost risk (including external 32 events) of approximately $56,000, if it is assumed that a SAMA is 100 percent effective in 33 eliminating the events contribution to CDF and that the total cost-risk is proportional to CDF. 34 As Exelon indicates, while this is larger than a typically assumed simple procedure change cost 35 of $50,000, the cost for a procedure change can vary widely depending on complexity of the 36 change and the systems involved. 37 Considering the above and that (1) the Exelon review of the LSCS importance analyses results 38 includes, in addition to basic events, accident sequence markers and the individual contributors 39 to these sequences, which effectively results in looking at risk contributors that are lower than 40 the RRW threshold; and (2) a separate review of the important contributors to fire and seismic 41 risk for candidate SAMAs was performed, as discussed below, the NRC staff therefore 42 concludes that Exelons use of an RRW threshold of 1.01 for identifying candidate SAMAs from 43 the Level 1 internal events importance analysis is acceptable. 10 The results of a sensitivity analysis to determine the impact of a correction to the Level 2 model discussed above, resulted in one of the Phase I SAMAs (SAMA 26) being retained that was originally screened out. F-24

Appendix F 1 In the ER, Exelon also provided tabular listings of the Level 2 PRA basic events for the 2 combined High (H/E-BOC, H/E, H/I), the Medium Early (M/E), and the Medium 3 Intermediate (M/I) release categories. These release categories combine to represent over 4 97 percent of the offsite risk. Exelon used an RRW cutoff of 1.03 when reviewing these basic 5 events for additional SAMA candidates. While higher than the cutoff used for the Level 1 6 review, the NRC staff considers this to be acceptable based on their combined contribution to 7 offsite risk, the release frequency of each is a relatively small part of the total release frequency 8 (6 to 36 percent), and many of the events are also included in the Level 1 importance review. 9 The NRC staff developed several RAIs during its review of Exelons assessment of SAMAs. 10 The following discussion summarizes these RAIs and Exelons responses (Exelon 2015). 11 The NRC staff noted that the turbine trip with bypass initiating event (%TT) is indicated to have 12 a frequency of 0.8 per year, which implies that a number of turbine trips with bypass have 13 occurred over the LSCS operating history and asked if any of these occurrences suggest 14 possible cost-beneficial SAMAs. Exelon responded that the LSCS turbine trip initiating event 15 frequency is based on a Bayesian update of a generic prior for the period of 20062010, which 16 includes two plant-specific events (one for each unit). Review of the two plant-specific events 17 used in the Bayesian update indicates that the causes of the events are not related to one 18 another, and that the site has taken corrective action to address the root causes of the events. 19 These conditions do not imply any outlier behavior at LSCS or indicate that there is a potential 20 to identify cost-beneficial SAMAs related to turbine trip events. 21 The NRC staff noted that the discussion of potential SAMAs for a significant number of events 22 involve water-hammer-induced loss of coolant accidents (LOCAs) related to the generation of a 23 LOCA signal on high drywell pressures when an actual LOCA does not exist. These events are 24 mitigated by SAMA 7, and the NRC staff asked Exelon to provide more detail on the water 25 hammer scenarios and the potential for other SAMAs to mitigate the water-hammer-induced 26 core damage. In response, Exelon provided a discussion of the four typical cases associated 27 with water hammer events at LSCS and the potential for other SAMAs. Exelon indicated that 28 procedures already are in place and credited in the PRA for the operators to prevent residual 29 heat removal (RHR) starting (and thereby preventing the conditions that led to a water hammer) 30 for certain scenarios and that installing fast-acting valves (that also would prevent the conditions 31 that led to water hammer) would be expensive and have some adverse consequences. Exelon 32 clarified that the LOOP-delayed LOCA scenario, that was stated to not have been modeled in 33 the PRA, is a series of operator actions required to address the automated actuations that occur 34 in some potential water hammer scenarios. These actions are not explicitly included in the PRA 35 because the dominant contributors to core damage are considered to be the water hammer 36 events. Exelon concluded and the NRC staff agrees that including these scenarios in the PRA 37 model would result in a very small change in plant risk that would impact neither the SAMA 38 identification process nor the conclusions of the SAMA analysis. 39 The NRC staff noted that for an event involving an emergency core cooling systems (ECCS) 40 room cooling fan failing to run, Exelon indicated that previous LSCS evaluations could not 41 demonstrate that portable fans would provide adequate cooling for the reactor building corner 42 rooms when the normal cooling system failed. Exelon was asked to discuss this previous 43 evaluation and if sufficient cooling can be achieved if the portable fans can provide air 44 movement through the room coolers, assuming cooling water remains available. In response, 45 Exelon provided the results of a cost-benefit assessment for a SAMA that utilized portable fans 46 and ducting to provide air flow through modified room coolers. This assessment assumed that 47 the previously described commitment to install a reliable hardened pipe containment vent 48 (SAMA 1) had been implemented thereby resulting in a benefit including uncertainty of 49 approximately $42,000 versus a cost of $475,000. F-25

Appendix F 1 The NRC staff noted that for an event where the operator fails to recover low-pressure systems, 2 the discussion indicates that low-pressure systems would not have the power to function. 3 Exelon was asked to consider the potential for utilizing a fire truck or other portable 4 self-powered pumps for injection into the containment. Exelon responded that SAMA 1 (reliable 5 hardened pipe containment vent) with its planned implementation and SAMA 8 (portable 6 480V AC generator) were determined to be potentially cost beneficial and are proposed in the 7 ER to address the risk contributions from this event. The combination of these two SAMAs 8 would help prevent core damage by providing a means for (i) containment heat 9 removal/pressure control via the reliable hardened pipe containment vent, and (ii) maintaining 10 RPV injection using the existing FPS connection, by providing long-term support for the safety 11 relief valves (SRVs) so that they do not reclose and cause RPV re-pressurization. The addition 12 of a portable self-powered injection pump without SAMA 8 for these contributors would provide 13 very little additional benefit. There would be no apparent reduction in the implementation cost, 14 and it would serve the less desirable function of mitigating a core-damage event rather than 15 preventing core damage. Exelon concluded and the NRC staff agrees that the use of a portable 16 self-powered pump is not considered to be the optimal choice for mitigating the risk associated 17 with the cited event. 18 Exelons discussion of the review of industry cost-beneficial SAMAs included Grand Gulf 19 SAMA 59 (to increase operator training to alternate the operation of ECCS pumps for 20 loss-of-room cooling). Exelon stated that rather than cycling large pumps in scenarios where 21 the cooling system is lost, a more effective means of maintaining injection with the ECCS 22 pumps is considered to be through the use of portable/temporary cooling alignment, which is 23 addressed in the LSCS importance list review by SAMA 16. In an RAI, the NRC staff asked 24 Exelon to consider a SAMA similar to Grand Gulfs SAMA 59 for rooms where the use of 25 portable fans may not be effective. In response, Exelon provided a discussion of the various 26 cases where use of portable fans may not be effective and pointed out that most are mitigated 27 by the hardened pipe containment vent (SAMA 1), which Exelon has already committed to 28 installing. Exelon concluded and the NRC staff agrees that once the requirement to install the 29 reliable hardened pipe containment vent has been implemented, the potential benefit of a 30 procedure change to cycle the ECCS pumps would be small (Exelon 2015). 31 While the LSCS IPE submittal did not identify any vulnerability, as discussed in the NRCs IPE 32 Safety Evaluation Report, the IPE did cite NUREG/CR-4832, Volume 3, Part 1, for insights into 33 potential improvements to: 34

  • Eliminate the sneak circuit in the RCIC isolation logic that results in the RCIC steam 35 line inboard isolation valve closing when offsite AC power is lost and the appropriate 36 diesel generator starts.

37

  • Change the RCIC room temperature isolation logic so that, in cases where AC power 38 from Train A has failed but AC power from Train B is available, this isolation logic 39 does not isolate if no other ECCS is working.

40

  • Change the venting procedure so that venting does not result in severe 41 environments in the reactor building.

42 In response to an NRC staff RAI to discuss the current status of these potential improvements, 43 Exelon replied, for the first two improvements listed above, changes have been made so that 44 the described sneak circuit and the RCIC isolation no longer exist at LSCS. For the third listed 45 improvement, design improvements were considered and dispositioned at the time of the IPE 46 and no design changes were made at that time to install a hardened pipe containment vent and 47 prevent the rupture of the containment vent piping. Rather, procedure changes were made to 48 acknowledge the design deficiency and initiate alignment of alternate injection systems prior to F-26

Appendix F 1 containment venting, if at all possible. Changes also were made to procedures to control 2 containment pressure within a specific range during the venting evolution. The potential for 3 containment vent path rupture/failure will be addressed through the installation of the reliable 4 hardened pipe containment vent (SAMA 1) (Exelon 2015). 5 Based on the above discussion, the NRC staff concludes that the set of SAMAs evaluated in the 6 ER, together with those identified in response to NRC staff RAIs, addresses the major 7 contributors to the CDF for internal events. 8 As previously discussed, the best available information on seismic and internal fire risk is not 9 compatible with the internal events risk model. Consequently, the search for SAMA candidates 10 to mitigate these risks was based on a review of the dominant risk contributors identified and 11 discussed in Section F.2.2.2. 12 In the ER, Exelon discussed the dominant seismic risk sequences listed in Table F-4 13 (Exelon 2014a), remarked that changes to LSCS as well as reanalysis of important failures has 14 led to reductions in the significance of several of these sequences, and identified two SAMA 15 candidates that mitigate the seismic risk. The NRC staff notes that the lowest seismic risk 16 contribution considered has a CDF of approximately 1 percent of the CDF for internal events. 17 This value corresponds to a benefit of $11,000 if mitigating only the seismic risk, or $56,000 if 18 mitigating all the other risk contributors. The NRC staff concludes that this is an acceptably low 19 cutoff for identification of SAMA candidates since it is lower than the typical cost for revising a 20 procedure. 21 The ER also includes a discussion of the contributors to the dominant fire zone risks listed in 22 Table F-5(a) and Table F-5(b) (Exelon 2014a). This discussion describes the important fire 23 scenarios that contribute to the fire CDF for this fire zone, the results of a review of the 24 important cutsets, and those SAMAs that would reduce the frequency of these fire scenarios. 25 Exelons review and analysis did not identify any unique SAMAs for mitigating these fire 26 scenarios, but Exelon concluded that three of the previous SAMA internal events would 27 significantly impact the fire risk. 28 Exelon noted that the largest unreviewed fire zone represents less than 2.5 percent of the 29 overall total CDF, including external events or about $142,000. In response to an RAI to 30 consider additional fire zones, Exelon provided a discussion of 15 additional fire zones with 31 benefits down to $37,500 per unit. This value was based on a procedure development cost of 32 $50,000 for the first unit and half of that for the second unit, averaging $37,500 per unit. The 33 contributors to the fire risk for each of these zones were reviewed by Exelon to determine if 34 there were any procedure changes that could be potentially cost beneficial. The results of this 35 review are presented in the RAI response on a zone-by-zone basis. No potentially 36 cost-beneficial procedure changes were identified (Exelon 2015). 37 In an RAI, the NRC staff noted that fires in the Division 1 and Division 2 essential switchgear 38 rooms for each unit comprise 60 percent of the total fire CDF and that the only SAMA proposed 39 for mitigating these fires is SAMA 1, installing a reliable hardened pipe containment vent. 40 SAMA 1 only mitigates the adverse consequences of venting and does not mitigate the direct 41 impact of the fire. The NRC staff asked Exelon to discuss these fire scenarios and the potential 42 for other SAMAs to directly mitigate the fire at an earlier stage of the scenario or to mitigate 43 events in the cutsets other than adverse conditions due to venting. Exelon indicated that 44 79 percent of the contributions are cases in which injection is initially available but subsequently 45 fails due to harsh environmental conditions after containment failure. The unavailability of the 46 containment vent is due to fire-induced failures associated with vent valve support systems, with 47 the vent valve control cables, or both. The reliable hardened pipe containment vent (SAMA 1) F-27

Appendix F 1 eliminates support system requirements and would provide a means of preventing the 2 containment failures and vent path failures that lead to loss of injection capability. 3 Further, for the remaining 21 percent of the contributors, hardware failures result in the 4 unavailability of injection systems, such that even if a containment vent path were available, 5 core damage would still occur. The hardware failures are comprised of both failures of the 6 4 kV AC power sources that support the injection systems and the failures of the injection 7 system components themselves. LSCS already has the B.5.b pump, which can provide this 8 RPV injection capability for the long-term scenarios that are characteristic of these contributors, 9 but it is not currently credited in the PRA model. LSCS operators have been trained to use the 10 B.5.b pump and the current emergency operating procedures include the B.5.b pump as a 11 potential alternate RPV injection source that could be used to mitigate the Division 1 and 12 Division 2 essential switchgear room fire scenarios. In addition, diverse and flexible coping 13 capability, FLEX (NRC 2012b), is intended to provide a separate set of portable makeup 14 pumps that also could be used to perform this function. While the details of the FLEX changes 15 are not finalized, they would further improve the capability of LSCS to respond to these types of 16 scenarios (Exelon 2015). 17 In an RAI, the NRC staff noted that the largest contributing fire scenario to the Auxiliary 18 Electrical Equipment Room fire risk is a bounding cable fire caused by hot work but no SAMAs 19 were identified to mitigate this risk. The NRC staff asked Exelon to discuss the potential for a 20 SAMA to mitigate this risk. In response, Exelon indicated that the transient fire ignition 21 frequency calculated for a fire compartment considers the potential for ignition due to hot work 22 (cutting, grinding, or welding tasks), among other sources. Based on the 2009 LSCS Fire PRA, 23 the hot work influence factor for the Auxiliary Electrical Equipment Room is low, which is the 24 lowest possible factor for this area. Procedures already are in place that require a fire watch to 25 be posted (with portable extinguishes available) and for nearby equipment to be protected when 26 hot work is being performed. These practices already are accounted for in the fire risk 27 evaluation for the Auxiliary Electrical Equipment Room. Based on these considerations, no 28 potential SAMAs related to hot work limitations are available that would yield a measurable 29 change in Auxiliary Electrical Equipment Room fire risk. Because the hot work is associated 30 with a bounding transient fire scenario that is assumed to lead to failure of all equipment in the 31 fire compartment, further details are not available to generate additional SAMAs to mitigate the 32 fire beyond those associated with the initiating event frequency (Exelon 2015). 33 As discussed in Section F.2.2.2, the LSCS IPEEE did not provide a definition of vulnerability 34 and did not identify any plant improvements resulting from the fire, seismic, or other external 35 events analyses. However, the RMIEP report identified two issues in the fire area that were 36 provided to the station for disposition. These issues were to install tops on the main control 37 room electrical panels and to institute an inspection program for penetration seals at the top of 38 switchgear panels. As discussed in the ER, these improvements were not implemented. Based 39 on the current understanding of fires in electrical panels, such as those installed at LSCS, and 40 on industry guidance for the treatment of fire in these panels in NUREG/CR-6285, Exelon 41 concluded that these two identified potential improvements would not be effective in mitigating 42 the associated fire risk. 43 In an RAI, the NRC staff noted that the RMIEP Summary (NUREG/CR-4832, Volume 1) 44 identifies the common cause failures (CCF) of the CSCS cooling water pumps as the dominant 45 events in the seismic risk reduction importance assessment. In response to the RAI to discuss 46 these events and their importance in the seismic analysis used for SAMA identification, Exelon 47 discussed the internally cited conflicting information in Volume 1 (Summary) and Volume 8 48 (Seismic Analysis) and concluded that CCFs of the CSCS cooling water pumps do not appear 49 to drive the results of seismic risk at LSCS. While no SAMAs were generated to directly F-28

Appendix F 1 address these specific failures, the consequences of the CCF of the CSCS cooling water pumps 2 is essentially a long-term SBO, a scenario previously addressed by SAMAs evaluated in the 3 LSCS analysis. SAMA 27 mitigates cases in which RCIC remains available (not failed by 4 seismically induced failure of the condensate storage tank), and SAMA 26 reduces the risk 5 associated with scenarios in which RCIC is not available. These SAMAs are considered by 6 Exelon to adequately address any potential contributions from CCF of the CSCS cooling water 7 pumps. In addition, Exelon stated that review of the LOOP and dual unit LOOP contributors 8 from the LSCS 2013A PRA model indicates that CCFs of the CSCS pumps are low contributors 9 to those scenarios. If, as stated in Section 4.5.1 of NUREG/CR-4832 Volume 1, the dominant 10 seismic sequences are all seismically induced losses of offsite power and look exactly like the 11 equivalent internally initiated sequences except that no credit is given for recovering offsite 12 power, then the conclusion would be that CCF of the CSCS cooling water pumps are not 13 significant contributors to seismic risk. Exelon also noted that subsequent to the completion of 14 the RMIEP analysis, Commonwealth Edison (now Exelon) performed a review of that study and 15 largely used the results as the basis for the combined IPE and IPEEE submittal. Exelon 16 indicated that one of the conclusions of the review effort, documented in the executive summary 17 of the April 1994 IPE/IPEEE (CECO 1994), is that Commonwealth Edison considered the Beta 18 factor CCF process used in the RMEIP analysis to be overly conservative (Exelon 2015). As 19 stated earlier, the Exelon IPEEE analysis of other external hazards (high winds, tornadoes, 20 external floods, and other external events) did not identify opportunities for improvements for 21 these events. 22 As discussed in Section F.2.2.2, the LSCS external flooding design and capability was 23 assessed in the engineering walkdowns and flood hazard reevaluation required for the response 24 to the Fukushima NTTFs Recommendation 2.3 (NRC 2012a). The walkdown identified 25 deficiencies that are being addressed through the LSCS corrective action program, while the 26 results of the hazard reevaluation led to the requirement for the performance of a full external 27 flooding integrated assessment, now underway. These issues are being addressed via the 28 ongoing Japan Lessons Learned program and implementation of the Fukushima Daiichi NTTF 29 recommendations, including NRC Order EA-12-049, Order to Modify Licenses with Regard to 30 Requirements for Mitigation Strategies for Beyond-Design-Basis External Events (NRC 2012b). 31 The NRC staff concludes that for the purposes of SAMA identification, external flooding is 32 adequately addressed. Since external flooding is not a significant contributor to plant risk, a 33 cost-beneficial SAMA is not likely to be identified. Additionally, the ongoing programs described 34 above provide improvements to the external flooding risk that are more conservative than a 35 cost-beneficial SAMA. 36 Regarding the prevention of water hammer events, the NRC staff questioned Exelon about 37 potentially lower cost alternatives to SAMA 7 (alter the LOCA signal logic to require both high 38 drywell pressure and low RPV water level for initiation of a LOCA signal). In non-LOCA 39 transient scenarios, the heat load rejected to the containment is sufficient to prompt the initiation 40 of suppression pool cooling (SPC), but even with SPC in operation, the drywell pressure will 41 reach 2 psig and a LOCA signal will register. If a consequential LOOP occurs with the LOCA 42 signal, the RHR discharge line can drain to the suppression pool in the ~45 seconds between 43 RHR pump load shed and the time it is reloaded on the diesel-backed bus, which sets up a 44 water hammer condition in the voided pipe. The lower cost alternative would be to change the 45 suppression pool cooling operating procedures or practices to reduce the chances of the 2 psi 46 high drywell pressure signal being reached for normal transients. In response, Exelon indicated 47 that no changes to the LSCS operating procedures would reduce the chance that the 2 psig 48 high drywell pressure signal would be reached in the scenarios of interest. The issue is that in 49 the scenarios of interest (initiators that result in the loss of containment cooling), SPC does not 50 have the capacity to remove enough heat to prevent the containment pressure from exceeding F-29

Appendix F 1 2 psig without venting containment in accordance with normal operating procedures to maintain 2 containment pressure less than the LOCA signal initiation pressure setpoint. Any changes to 3 the suppression pool cooling system operating procedures intended to increase the time 4 available between the initiating event and the 2 psig high drywell pressure signal would have a 5 very small impact on risk. Human error probabilities (HEPs) are influenced by a number of 6 factors, including time available for response. In this case, the HEP for the operator action to 7 vent the containment to prevent the high drywell signal is not significantly impacted by timing 8 considerations, and increasing the time available to the operators would correlate to very small 9 averted cost-risk values. The more difficult mitigating actions for water hammer scenarios are 10 associated with the approximate 20-second time interval between the occurrence of the loss of 11 the running pump on the LOCA-induced LOOP and the time when the pumps are automatically 12 started and reloaded onto the emergency bus. This short time period is not associated with the 13 operation of suppression pool cooling; therefore, a SAMA would have no benefit to these 14 scenarios. In these scenarios, the operators must put the pump in pull-to-lock to prevent restart 15 and then fill and vent the system to ensure a water hammer does not occur (Exelon 2015). 16 The NRC staff notes that the set of SAMAs submitted is not all-inclusive because additional, 17 possibly even less expensive, alternatives can always be postulated. However, the NRC staff 18 concludes that the benefits of any additional modifications are unlikely to exceed the benefits of 19 the modifications evaluated and that the alternative improvements would not likely cost less 20 than the least expensive alternatives evaluated, when the subsidiary costs associated with 21 maintenance, procedures, and training are considered. 22 The NRC staff concludes that Exelon used a systematic and comprehensive process for 23 identifying potential plant improvements for LSCS, and that the set of potential plant 24 improvements identified by Exelon is reasonably comprehensive and, therefore, acceptable. 25 This search included reviewing insights from the plant-specific risk studies, and reviewing plant 26 improvements considered in previous SAMA analyses. While explicit treatment of external 27 events in the SAMA identification process was limited, the NRC staff has determined that the 28 prior implementation of plant modifications and the absence of external event vulnerabilities 29 reasonably justify examining primarily the internal events risk results for this purpose. 30 Risk Reduction Potential of Plant Improvements 31 Exelon evaluated the risk-reduction potential of the 25 SAMAs retained for the Phase II 32 evaluation in a revised analysis (Exelon 2015). The SAMA evaluations were generally 33 performed by Exelon in a realistic or slightly conservative fashion that overestimates the benefit 34 of the SAMA. In most cases, the failure likelihood of the added equipment is taken to be 35 optimistically low, thereby overestimating the benefit of the SAMA. In other cases, it was 36 assumed that the SAMA eliminated all of the risk associated with the proposed enhancement. 37 The NRC staff notes that this bounding approach overestimates the benefit and therefore 38 is appropriately conservative. 39 Exelon used model requantification to determine the potential benefits for each of the SAMAs. 40 The CDFs, population dose reductions, and offsite economic cost reductions were estimated 41 using the LSCS PRA model. The changes made to the model to quantify the impact of each 42 SAMA are described in Section F.6 of the ER. Table F-6 summarizes the assumptions used to 43 estimate the risk reduction for each evaluated SAMA, the estimated risk reduction in terms of 44 CDF percent reduction, population dose, offsite economic cost, and the estimated total benefit 45 (present value) of the averted risk. The determination of the benefits for the various SAMAs is 46 further discussed in Section F.6. F-30

Appendix F 1 The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction 2 estimate of each SAMA, as described in the Section F.6 of the ER. The resolution of RAIs that 3 resulted from this review follow. 4 The discussions of SAMA 8 in Section F.6.8 of the ER and SAMA 14 in Section F.6.13 of the 5 ER include the statement Flow from the fire protection system, in its current configuration, is 6 only adequate in cases where RCIC.... In response to an RAI to discuss what is meant by 7 current configuration, and the potential for a SAMA to address the FPS configuration and 8 make it possible to use without prior RCIC operation, Exelon responded that there are two major 9 issues that preclude the use of the FPS for RPV makeup in early time frames to prevent core 10 damage. The first is related to the low flow rate of the makeup path, and the second is related 11 to the relatively long time that is required to align the FPS for injection. The connection that is 12 currently used to provide RPV makeup from the FPS consists of fire hoses that are manually 13 aligned between the FPS header and the feedwater injection lines. The RPV pressure must be 14 reduced below 75 psig for Unit 1 and 60 psig for Unit 2 to achieve a flow rate of 200 gpm into 15 the RPV and would be successful only after 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> following initial high pressure injection and 16 subsequent RPV depressurization. Prior to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />, decay heat levels would be such that 17 200 gpm would be insufficient for RPV makeup. Relative to the second issue, Exelon indicated 18 that operator interviews indicate that about 40 minutes are required to establish the flow path 19 from the FPS to the RPV. It would not be possible to align this injection path even if adequate 20 flow could be obtained from the FPS to make up for boil-off. Exelon indicated and the NRC staff 21 agrees that both of these issues were assumed mitigated by SAMA 18, Improvement of the 22 Connection Between the Fire Protection and Feedwater Systems. While this SAMA was 23 developed to reduce the alignment time such that it would be possible to perform the alignment 24 in cases where RCIC injection fails, one of the assumptions made in the SAMA 18 assessment 25 was that the improved connection also would improve the flow rate of FPS injection to a point 26 where it could provide adequate makeup in loss of all injection scenarios (Exelon 2015). 27 In Section F.6.13 of the ER, the discussion of SAMA 14 (provide a portable DC source to 28 support RCIC and SRV operation) indicates that the PRA model was changed to include a 29 lumped event to represent the 480 V AC power source that feeds the Division 1 battery 30 chargers. The SAMA description and the basic events cited to be mitigated by this SAMA 31 indicated that a DC power source to directly supply an engineered safety feature (ESF) DC 32 distribution panel is needed. In response to an RAI to discuss the inclusion of an AC power 33 supply in the model, Exelon responded that the description of the PRA model changes related 34 to the lumped event that was added to represent the 480V AC power source that feeds the 35 Division 1 battery charger is erroneous and that the text should read a lumped event was 36 added to represent the 125 V DC generator that would supply 125 V ESF DC distribution 37 panel 1(2)11Y. The detailed PRA model change descriptions documented in Section F.6.13 of 38 the ER accurately describe how the lumped event (basic event ID SAMA 14) was incorporated 39 into the PRA model for SAMA 14 (Exelon 2015). 40 In an RAI, the NRC staff noted that SAMA 7 (water hammer prevention) and SAMA 25 (periodic 41 training on water hammer scenarios resulting from a false LOCA signal) both are intended to 42 mitigate the water hammer scenarios involving SPC operation interrupted by a LOOP. The 43 changes made to the model and the impacts on population dose risk and offsite economic cost 44 risk are significantly different for the two SAMAs. In response to the NRC staff RAI to discuss 45 these SAMAs and their analyses in more detail to justify these differences, Exelon responded 46 that SAMA 7 and SAMA 25 are different approaches to addressing the risk associated with 47 water hammer events at LSCS. While the different approaches might be expected to lead to 48 some differences in the CDF and risk impact of the two SAMAs, the difference in person-rem 49 and offsite economic risk impacts reported in the ER was found to be due to a recently F-31

Appendix F 1 discovered error in a supporting spreadsheet calculation for SAMA 25. Exelon provided 2 corrected values in the RAI response and indicated that the reduced benefit for SAMA 25 3 changed its disposition from cost beneficial to not cost beneficial (Exelon 2015). The NRC staff 4 agrees that these values are correct. 5 The NRC staff noted that SAMA 9 (Develop flood zone specific procedures) and SAMA 11 6 (Provide the capability to trip the FPS pumps) both address internal flooding; whose principal 7 contributor is a FPS pipe rupture in the reactor building. The assumption that all of the relevant 8 internal flooding risk will be eliminated by implementing SAMA 9, lowers the overall CDF by 9 9 percent and results in this SAMA being cost beneficial. As stated in Section F.6.11 of the ER, 10 SAMA 11 is designed to eliminate the FPSs flow. For SAMA 11, there is less than a 2 percent 11 reduction in CDF. In response to an RAI to discuss the FPS design, the FPS pipe break 12 scenarios, and associated modeling to support the above results, Exelon responded that the 13 primary reason for the significant difference between SAMA 9 and SAMA 11 risk reductions is 14 that they target different portions of flooding risk. SAMA 9 targets all flooding initiators while 15 SAMA 11 targets only a subset of FPS flooding scenarios. SAMA 9 was conservatively 16 modeled by assuming that it eliminated all internal flooding risk. The 9 percent reduction in CDF 17 is consistent with the CDF values reported for the internal flooding initiators in Table F.2-2 of 18 the ER. SAMA 11 provides only a means of tripping the FPS pumps in the main control room, 19 which helps reduce the risk of FPS flooding events that require a rapid response (i.e., large 20 breaks) but would only have a small impact on the longer term FPS flooding scenarios. Since 21 SAMA 11 only improves the reliability of one human action in the PRA model, only a small 22 improvement in CDF is expected. In contrast, SAMA 9 improves the reliability of all human 23 response actions to all flood scenarios and, therefore, has a larger overall impact on the model 24 (Exelon 2015). 25 The NRC staff reviewed Exelons bases for calculating the risk reduction for the various plant 26 improvements and concludes, with the above clarifications and corrections, that the rationale 27 and assumptions for estimating risk reduction are reasonable and generally conservative 28 (i.e., the estimated risk reduction is higher than what would actually be realized). Accordingly, 29 the NRC staff based its estimates of averted risk for the various SAMAs on Exelons risk 30 reduction estimates. F-32

1 SAMA Cost-Benefit Screening Analysis for LSCS Station(a) 

                                                                                       % Risk Reduction(b)               Total Benefit ($)(c)

Baseline With Baseline Uncertainty Population (Internal + (95th Cost Individual SAMA and Assumption CDF Dose OECR External) percentile) ($)(c) 1 - INSTALL RELIABLE HARD PIPE CONTAINMENT VENT 28 36 43 2.5M 5.4M 13M SAMA 1 Modeling: The model was modified by eliminating the support system dependencies, improving the reliability of the venting action to reflect simplification of the controls, and eliminating the events related to vent path rupture and leakage. 2 - AUTOMATE SUPPRESSION POOL COOLING 14 20 25 1.4M 3.1M 400K SAMA 2 Modeling: The fault tree incorporated the automation of suppression pool cooling alignment by changing the independent basic event IDs for suppression pool cooling initiation to alternate IDs. This accomplishes two functions: (i) assignment of alternate failure probabilities that are representative of an automated function, and (ii) prevent the recovery logic from identifying suppression pool cooling initiation failures as human actions and preclude the suppression pool cooling initiation failures from dependent human error combinations. 3 - PASSIVE VENT PATH 36 51 61 1.0M 2.2M 1.0M SAMA 3 Modeling: The basic event for the operator action for venting was replaced with a new placeholder event with a value of 106 (prevents the creation of dependent operator actions, including the vent action). The hardware failures associated with the vent path valves have been F-33 retained to approximate the potential failures of the rupture disk (with the support system dependencies removed). 4 - INSTALL A KEYLOCK MSIV LOW LEVEL ISOLATION 16 12 10 674K 1.4M 635K BYPASS SWITCH SAMA 4 Modeling: The independent human error probability to bypass the main steam isolation valve low level isolation interlock was set to 105 and the joint human error probabilities that include this action have been eliminated. 5 - AUTOMATE SBLC INITIATION 8 7 6 386K 827K 400K SAMA 5 Modeling: The automatic SBLC initiation capability is modeled by manipulation of associated basic events. Early SBLC initiation basic event ID (2SLOP-LVLCTRLH--) was changed to SAMA5 and set to a probability of 106 to reduce the independent failure contribution to a small value and prevent the inclusion of dependent operator action combinations with SBLC initiation failures, consistent with the automated action. 6 - CREATE ECCS SUCTION STRAINER BACKFLUSH 1 1 1 88K 186K 2.9M CAPABILITY WITH RHRSW SAMA Modeling: The contribution related to common cause failure strainer clogging was eliminated by setting the corresponding basic events in the cutset files to zero. Appendix F 

                                                                                     % Risk Reduction(b)              Total Benefit ($)(c)

Baseline With Baseline Uncertainty Population (Internal + (95th Cost Appendix F Individual SAMA and Assumption CDF Dose OECR External) percentile) ($)(c) 7 - WATER HAMMER PREVENTION 7 <1 <1 51K 108K 962K SAMA 7 Modeling: Water hammer events were eliminated from the results through manipulation of the cutsets. The relevant water hammer scenarios are all characterized by two events that identify the residual heat removal train that is placed in suppression pool cooling mode in response to the high suppression pool temperature. Setting these events to zero approximates the impact of eliminating the water hammer events associated with the LOCA signal actuated solely on high drywell pressure. 8 - OBTAIN A 480V AC PORTABLE GENERATOR TO SUPPLY THE 125V DC BATTERY CHARGERS AND PROCEDURALIZE ITS 4 4 4 259K 554K 400K USE SAMA 8 Modeling: The 480V AC generator capability has been approximated by adding the diesel fire pump as a low pressure injection source for SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480V AC power source that feeds the Division 1 battery chargers. 9 - DEVELOP FLOOD ZONE SPECIFIC PROCEDURES 9 3 3 224K 479K 115K F-34 SAMA 9 Modeling: Initiating event frequencies for flooding events were set to zero in the cutsets. 10 - CHANGE THE LOGIC TO CLOSE THE TURBINE DRIVEN FEEDWATER PUMP DISCHARGE VALVES WHEN THE PUMPS 9 21 23 1.3M 2.8M 260K ARE NOT RUNNING SAMA 10 Modeling: The human failure event associated with closing the turbine driven feedwater pump discharge valves was changed to a new event with a failure probability of 104. This treatment reduces the independent contribution of the isolation failure and precludes the generation of dependent human error combination, including the operator action to isolate the valves. 11 - PROVIDE THE CAPABILITY TO TRIP THE FPS PUMPS 2 <1 <1 21K 44K 217K FROM THE MAIN CONTROL ROOM SAMA 11 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low pressure injection source for SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480V AC power source that feeds the Division 1 battery chargers. 12 - CROSSTIE THE HIGH PRESSURE CORE SPRAY AND 19 21 16 1.1M 2.3M 4.4M FEEDWATER INJECTION LINES FOR ATWS MITIGATION SAMA 12 Modeling: This SAMA makes use of an existing injection system (high pressure core spray) to provide high pressure injection in ATWS scenarios. This SAMA eliminates the contribution of all ATWS events by setting the accident Class IV flag (RCVCL-4A) to zero in the cutsets. 

                                                                                    % Risk Reduction(b)               Total Benefit ($)(c)

Baseline With Baseline Uncertainty Population (Internal + (95th Cost Individual SAMA and Assumption CDF Dose OECR External) percentile) ($)(c) 14 - PROVIDE A PORTABLE DC SOURCE TO SUPPORT RCIC 9 7 7 444K 949K 489K AND SRV OPERATION SAMA 14 Modeling: The DC generator capability has been approximated by adding the diesel fire pump as a low pressure injection source for SBO scenarios in which the ADS and RCIC are initially successful. In addition, a lumped event was added to represent the 480V AC power source that feeds the Division 1 battery chargers. 15 - TIE RHRSW TO THE LPCS SYSTEM FOR ISLOCA 37 57 57 3.4M 7.2M 1.4M MITIGATION SAMA 15 Modeling: Changes were made to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the cross-tie. The cross-tie logic was added at the sequence level for BOC and ISLOCA sequences where credit was not previously taken for any low pressure injection systems. The logic also was added to the existing fault tree structure in scenarios where venting or containment failure resulted in the loss of injection systems. F-35 16 - PROVIDE PORTABLE FANS FOR ALTERNATE ROOM 14 12 15 866K 1.9M 475K COOLING IN THE CSCS VAULTS SAMA 16 Modeling: The alternate CSCS room cooling capability was approximated by deleting the gates associated with room cooling failures (excluding the automatic initiation failures, which are already addressed in the model). 18 - IMPROVE THE CONNECTION BETWEEN THE FIRE 9 9 10 609K 1.3M 649K PROTECTION AND FEEDWATER SYSTEMS SAMA 18 Modeling: The fault tree was updated to credit the FPS in the places where LPCI and LPCS are credited, but the system is failed for the LOCA and IORV initiating event and for water hammer scenarios. In addition, the logic was changed to include the FPS injection capability in the early SBO scenarios in which the ADS is available for those sequences not impacted by the LPCS-LPCI gate. 19 - PROVIDE REMOTE ALIGNMENT CAPABILITY OF RHRSW 38 58 58 3.4M 7.3M 2.9M TO THE LPCS SYSTEM FOR LOCA MITIGATION SAMA 19 Modeling: The inclusion of the RHRSW-LPCS cross-tie required changes to both the main fault tree and the recovery fault tree. The cross-tie was assumed to require the LPCS injection path (existing logic from the LPCS system) and the availability of the RHRSW pumps (existing logic from the RHRSW system). ISLOCAs in the LPCS line were included as failure for the cross-tie, as was an event representing the failure to align the cross-tie. The cross-tie logic was added at the sequence level for BOC and ISLOCA sequences where credit was not previously taken for any low pressure injection systems. The logic also was added to the existing fault tree structure in scenarios where venting or containment failure resulted in the loss of injection systems. Appendix F 

                                                                                      % Risk Reduction(b)               Total Benefit ($)(c)

Baseline With Baseline Uncertainty Population (Internal + (95th Cost Appendix F Individual SAMA and Assumption CDF Dose OECR External) percentile) ($)(c) 20 - IMPROVE VACUUM BREAKER RELIABILITY BY INSTALLING 1 2 2 113K 243K 1.2M REDUNDANT VALVES IN EACH LINE SAMA 20 Modeling: The installation of the redundant vacuum breakers is modeled by setting the probability of the vacuum breakers failing to reclose to zero. It is assumed that there are no negative consequences associated with installing the redundant vacuum breakers (i.e., the failure to open probability of the vacuum breakers is not increased). 21 - INSTALL AUTOMATIC ATWS LEVEL CONTROL SYSTEM 14 14 12 754K 1.6M 1.5M SAMA 21 Modeling: The SAMA is modeled by setting the early and late level control actions to zero in the fault tree. 22 - HYDROGEN IGNITORS IN PRIMARY CONTAINMENT <1 1 1 34K 72K 205K SAMA 22 Modeling: The SAMA is modeled by setting the failure probability of hydrogen detonation to zero in the cutsets. 23 - ENHANCE FUEL POOL EMERGENCY MAKEUP PUMP 27 46 52 3.0M 6.5M 1.4M AND CONNECTION SAMA 23 Modeling: The inclusion of the fuel pool emergency makeup pump cross-tie required changes to be made to both the main fault tree F-36 and the recovery fault tree. The cross-tie was assumed to require the residual heat removal B injection path (existing logic from the LPCI system). The logic was added to the existing fault tree structure in scenarios where venting or containment failure resulted in the loss of injection systems. 24 - PROVIDE INTER DIVISION 4 KV AC CROSSTIE CAPABILITY 5 5 6 367K 785K 1.8M SAMA 24 Modeling: The implementation of the inter-division cross-tie is modeled by including the other two diesel generators from the same unit as potential power supply sources for a given emergency bus. 25 - PERIODIC TRAINING ON WATER HAMMER SCENARIOS 5 <1 <1 42K 89K 112K RESULTING FROM A FALSE LOCA SIGNAL SAMA 25 Modeling: This SAMA was modeled by changing basic event values in the cutsets to reflect the improved reliability of the drywell venting action for preventing a LOCA signal in non-LOCA cases. 26 - SEISMICALLY QUALIFIED LOW-PRESSURE RPV MAKEUP 28 33 39 2.3M 4.9M 6.0M CAPABILITY SAMA 26 Modeling: Changes were made to both the main fault tree and the recovery fault tree. Logic was added to the existing fault tree structure in scenarios where LPCI and LPCS are credited and where containment failure results in the loss of injection systems due to adverse environmental conditions. Logic was included in the fault tree preclude credit for loss of inventory scenarios where the 600 gallons per minute makeup rate may be inadequate (e.g., LOCA events and makeup to prevent RPV melt-through). 

                                                                                              % Risk Reduction(b)                   Total Benefit ($)(c)

Baseline With Baseline Uncertainty Population (Internal + (95th Cost Individual SAMA and Assumption CDF Dose OECR External) percentile) ($)(c) 27 - PRECLUDE EMERGENCY DEPRESSURIZATION WHEN RCIC IS THE ONLY INJECTION SYSTEM AVAILABLE AND 4 3 3 196K 420K 512K PROVIDE LONG-TERM DC POWER SAMA 27 Modeling: The SAMA is modeled by setting the failure probability of sequences in which RCIC is initially operational in a SBO to zero in the cutsets. (a) SAMAs in bold are potentially cost beneficial. Potentially cost-beneficial SAMAs relate to both LSCS units, Unit 1 and Unit 2. (b) Risk reduction percentages displayed in this table were obtained from the ER (Exelon 2014a) prior to Exelons revised results (Exelon 2015). Risk reduction percentages for the revised benefit results were not provided. (c) Exelon identified potentially cost-beneficial SAMAs by comparing the total benefit with uncertainty at the 95th percentile to the estimated implementation cost. Total benefit and cost values presented in this table were obtained from Exelons revised results (Exelon 2015). Key: AC = alternating current; ADS = automatic depressurization system; ATWS = anticipated transients without scram; BOC = break outside containment; CDF = core damage frequency; CSCS = core standby cooling system; DC = direct current; ECCS = emergency core cooling system; FPS = fire protection system; ID = identification; IORV = inadvertent/stuck open relief valve; ISLOCA = interfacing-systems loss-of-coolant accident; LPCI = low pressure coolant F-37 injection; LPCS = low pressure core spray; LOCA = loss-of-coolant accident; LSCS = LaSalle County Station; MSIV = main steam isolation valve; OECR = offsite economic cost risk; RCIC = reactor core isolation cooling; RHRSW = residual heat removal service water; RPV = reactor pressure vessel; SAMA = severe accident mitigation alternative; SBO = station blackout; SBLC = standby liquid control; SRV = safety relief valve Sources: Exelon 2014a, 2015 Appendix F

Appendix F 1 Cost Impacts of Candidate Plant Improvements 2 Exelon estimated the costs of implementing the 25 Phase II SAMAs through the use of other 3 licensees estimates for similar improvements and the development of site-specific cost 4 estimates where appropriate. 5 SAMA cost estimates were based on initial hardware, installation, and implementation costs. 6 In response to an NRC staff RAI to provide further information as to what was included in the 7 LSCS cost estimates, Exelon clarified that maintenance and testing costs during the license 8 renewal period were conservatively not included in the estimate (Exelon 2015). 9 The NRC staff reviewed the applicants cost estimates presented in Section F.6 of the ER 10 (Exelon 2014a). For certain improvements, the NRC staff also compared the cost estimates to 11 estimates developed elsewhere for similar improvements, including estimates developed as part 12 of other licensees analyses of SAMAs for operating reactors. 13 The NRC staff noted that a few SAMAs (e.g., 8, 14, and 27) involve use of equipment that may 14 be available as a result of the B.5.b program and asked Exelon to discuss this further and the 15 impact on the cost-benefit analysis. Exelon responded that the B.5.b program at LSCS includes 16 a small generator that is used to support two individual SRV solenoids to hold the SRVs open 17 after 125V DC battery depletion, but the generator does not power the station battery chargers 18 and it is not designed to support the RCIC system through direct DC feeds. Because of these 19 limitations, the B.5.b generator is not a viable substitute for the generators that have been 20 proposed for SAMAs 8, 14, and 27; therefore, the availability of the B.5.b generator would not 21 reduce the implementation costs for these SAMAs. With the above clarifications, the NRC staff 22 concludes that the cost estimates provided by Exelon are sufficient and appropriate for use in 23 the SAMA evaluation. 24 Cost-Benefit Comparison 25 Exelons cost-benefit analysis and the NRC staffs review are described in the following 26 sections. 27 F.6.1. Exelons Evaluation 28 The methodology used by Exelon was based primarily on NRCs guidance for performing 29 cost-benefit analysis, NUREG/BR-0184 (NRC 1997a) and industry guidance (NEI 2005) 30 endorsed by NRC. As described in Section F.4 of the ER (Exelon 2014a), the modified 31 maximum averted cost risk (MMACR) was determined for each SAMA according to the 32 following formula, which the staff accepts as mathematically equivalent to the formula in the 33 NUREG/BR-0184: 34 MMACR = EEM (W PHA + WEA + W O + W CD + W RP) 35 where 36 EEM = external event multiplier (unitless) 37 WPHA = present value of averted offsite exposure cost ($) 38 WEA = present value of averted offsite economic cost ($) 39 WO = present value of averted onsite exposure cost ($) 40 WCD = present value of averted onsite cleanup cost ($) F-38

Appendix F 1 WRP = present value of averted replacement power cost ($) 2 Exelons derivation of each of the associated costs is presented separately in this section. For 3 each SAMA, the applicants analysis determined percentage reductions in population dose risk 4 (PDR%), offsite economic cost risk (OECR%), and onsite cost risk (OCR%). The internal and 5 external benefit from the implementation of an individual SAMA is determined from these 6 percentage reductions and their associated present value costs according to the following 7 formula: 8 SAMA Benefit = EEM [PDR% W PHA + OECR% WEA + OCR% (W O + W CD + W RP)] 9 For each SAMA, the estimated benefit is compared to the cost of implementation. If the cost of 10 implementing the SAMA is larger than the benefit associated with the SAMA, the SAMA is not 11 considered to be cost beneficial. If the cost of implementing the SAMA is smaller than the 12 benefit associated with the SAMA, the SAMA is considered to be cost beneficial. In the ER, 13 Exelon calculated the net value for individual SAMAs in a similar manner. Positive net values 14 indicated a potentially cost-beneficial SAMA, and negative net values implied that the SAMA 15 was not cost beneficial. 16 In accordance with NUREG/BR-0058 guidance (NRC 2004) that states present worth estimates 17 should be developed using both the 3 percent and 7 percent discount rates, Exelon conducted a 18 baseline analysis using the 3 percent discount rate and a sensitivity analysis using the 7 percent 19 discount rate (Exelon 2014a). Additional sensitivity analyses were performed by the applicant to 20 quantify influences on the calculated benefits from the 95th percentile PRA results, offsite 21 consequence modeling parameter changes, and assumed implementation of a hardened pipe 22 containment vent. Additional details on the sensitivity analysis are presented in Section F.6.2. 23 Averted Offsite Exposure Cost (W PHA) 24 Exelon defined WPHA cost as the monetary value of accident risk avoided from population doses 25 after discounting (Exelon 2014a). The W PHA costs were calculated using the following formula: 26 WPHA = Averted public dose risk (person-rem per year) 27 x monetary equivalent of unit dose ($2,000 per person-rem) 28 x present value conversion factor (NRC 1997a) 29 As stated in NUREG/BR-0184 (NRC 1997a), it is important to note that the monetary value of 30 the public health risk after discounting does not represent the expected reduction in public 31 health risk because of a single accident. Rather, it is the present value of a stream of potential 32 losses extending over the remaining lifetime (in this case, the 20-year renewal period) of the 33 facility. Thus, it reflects the expected annual loss caused by a single accident, the possibility 34 that such an accident could occur at any time over the renewal period, and the effect of 35 discounting these potential future losses to present value. For a discount rate of 3 percent, 36 Exelon calculated the W PHA cost of $213,863 due to internal events in the ER (Exelon 2014a). 37 Averted Offsite Economic Cost (W EA) 38 Exelon defined WEA as the monetary value of risk avoided from offsite property damage after 39 discounting (Exelon 2014a). The W EA values were calculated using the following formula: 40 WEA = Annual offsite property damage risk before discounting in dollars per year 41 x present value conversion factor (NRC 1997a) 42 For a discount rate of 3 percent, Exelon calculated the W EA cost of $802,484 due to internal 43 events in the ER (Exelon 2014a). F-39

Appendix F 1 Averted Onsite Exposure Cost (W O) 2 Exelon defined W O as the avoided onsite exposure (Exelon 2014a). Similar to the W PHA 3 calculations, the applicant calculated costs for immediate onsite exposure. Long-term onsite 4 exposure costs were calculated consistent with guidance in the Regulatory Analysis Technical 5 Evaluation Handbook (NRC 1997a), which included an additional term for accrual of 6 long-term doses. 7 Exelon derived the values for averted occupational exposure from information provided in 8 Section 5.7.3 of the Regulatory Analysis Technical Evaluation Handbook (NRC 1997a). Best 9 estimate values providing for an immediate occupational dose (3,300 person-rem) and 10 long-term occupational dose (20,000 person-rem over a 10-year cleanup period) were used. 11 The present value of these doses was calculated using the equations provided in the handbook 12 in conjunction with a monetary equivalent of unit dose of $2,000 per person-rem, a real discount 13 rate of 7 percent, and a time period of 20 years to represent the license renewal period. 14 Immediate and long-term onsite exposure costs were summed to determine the W O cost. For a 15 discount rate of 3 percent, Exelon calculated the WO cost of $1,597 due to internal events in the 16 ER (Exelon 2014a). 17 Averted Onsite Cleanup Cost (W CD) 18 Exelon defined W CD as the avoided cost for cleanup and decontamination of the site 19 (Exelon 2014a). The applicant derived the values for W CD based on information provided in 20 Section 5.7.6 of NUREG/BR-0184, the Regulatory Analysis Technical Evaluation Handbook 21 (NRC 1997a). 22 Averted cleanup and decontamination costs were calculated using the following formula: 23 WCD = Annual CDF x present value of cleanup costs per core damage event x present value 24 conversion factor. 25 The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 26 the Regulatory Analysis Technical Evaluation Handbook to be $1.5x109 (undiscounted). This 27 value was converted to present costs over a 10-year cleanup period and integrated over the 28 term of the proposed license extension. For a discount rate of 3 percent, Exelon calculated the 29 WCD cost of $50,284 due to internal events in the ER (Exelon 2014a). 30 Averted Replacement Power Cost (W RP) 31 Exelon defined W RP as the avoided costs of replacement power (Exelon 2014a). Long-term 32 replacement costs were calculated using the following formula: 33 WRP = Annual CDF x present value of replacement power for a single event 34 x factor for remaining service years for which replacement power is required 35 x reactor power scaling factor 36 Exelon based its calculations on the net electric output for LSCS, specifically 37 1,210 megawatt-electric (MWe), and scaled up from reference plant value of 910 MWe specified 38 in NUREG/BR-0184 (NRC 1997a). For a discount rate of 3 percent, Exelon calculated W RP 39 costs of $18,955 due to internal events in the ER (Exelon 2014a). 40 Modified Maximum Averted Cost Risk (MMACR) 41 Using the above equations and an annual CDF of 2.58x106, Exelon estimated the total present 42 dollar value equivalent associated with completely eliminating severe accidents caused by 43 internal events, referred to as the MACR, to be about $1,087,183 at a single unit for a discount 44 rate of 3 percent in the ER (Exelon 2014a). In Exelons revised analysis, the MACR increased F-40

Appendix F 1 to approximately $1,168,000. To account for the risk contributions from external events and 2 yield the internal and external benefit, Exelon selected an external event multiplier (EEM) value 3 of 5.2 for LSCS, as described in Section F.4.6.2 of the ER (Exelon 2014a). By multiplying 4 MACR and EEM, Exelon estimated MMACR to be about $5,657,600 for a single unit with a 5 discount rate of 3 percent, as presented in Section F.4.6.3 of the ER (Exelon 2014a). In 6 Exelons revised analysis, the MMACR increased to $6,073,600 (Exelon 2015). As described 7 above in the SAMA benefit formula, components of the MMACR calculation factor into the 8 benefit determination for individual SAMAs. When Exelon revised its analysis in response to 9 RAIs from the NRC staff, updates were not presented for the individual components of MACR 10 (W PHA, W EA, W O, W CD, WRP). 11 Exelons Results 12 If the implementation costs for a SAMA candidate exceeded the calculated benefit, the SAMA 13 was determined to be not cost beneficial. If the SAMA benefit exceeded the estimated cost, the 14 SAMA candidate was considered to be potentially cost beneficial. Results of the cost-benefit 15 evaluation are presented in Table F-6. Exelons cost-benefit analysis identified 14 SAMA 16 candidates determined to be potentially cost beneficial at the 95th percentile on an individual 17 basis: 18

  • SAMA 2: Automate suppression pool cooling.

19

  • SAMA 3: Passive vent path.

20

  • SAMA 4: Install a keylock main steam isolation valve (MSIV) low-level isolation 21 bypass switch.

22

  • SAMA 5: Automate standby liquid control (SBLC) initiation.

23

  • SAMA 8: Obtain a 480 V AC portable generator to supply the 125 V DC battery 24 chargers and proceduralize its use.

25

  • SAMA 9: Develop flood zone specific procedures.

26

  • SAMA 10: Change the logic to close the turbine driven feedwater pump discharge 27 valves when the pumps are not running.

28

  • SAMA 14: Provide a portable DC source to support RCIC and SRV operation.

29

  • SAMA 15: Tie RHRSW to the low-pressure core spray (LPCS) system for interfacing 30 systems loss-of-coolant accident (ISLOCA) mitigation.

31

  • SAMA 16: Provide portable fans for alternate room cooling in the CSCS vaults.

32

  • SAMA 18: Improve the connection between the fire protection and 33 feedwater systems.

34

  • SAMA 19: Provide remote alignment capability of RHRSW to the LPCS system for 35 LOCA mitigation.

36

  • SAMA 21: Install Automatic ATWS level control system.

37

  • SAMA 23: Enhance fuel pool emergency makeup pump and connection.

38 When the planned installation of a hardened pipe containment vent is considered as the base 39 case, the number of SAMA candidates considered to be potentially cost beneficial at the 40 95th percentile may reduce. Because a new baseline is established following the 41 implementation of a SAMA, which further influences the benefits provided by the remaining 42 SAMA candidates, Exelon defined an optimal set to containing SAMAs that, if implemented, F-41

Appendix F 1 would render the remaining SAMAs to be not cost beneficial. Acknowledging Exelons planned 2 installation of the hardened pipe containment vent (SAMA 1), additional modifications included 3 in the optimal set are SAMAs 2, 4, 9, and 15, as presented in the ER (Exelon 2014a). 4 Assessment of the optimal set was performed prior to Exelon generating revised results in 5 response to the NRC staffs RAIs (Exelon 2015). Because a priori credit for installation of the 6 hardened pipe containment vent was not taken by Exelon, revision of the optimal set 7 assessment was not required. Exelon is referring the 14 potentially cost-beneficial SAMAs from 8 its revised analysis (Exelon 2015) to the LSCS Plant Health Committee for further 9 implementation considerations within the established plant procedural process, as indicated in 10 Section 4.15 of the ER (Exelon 2014d). 11 F.6.2. Review of Exelons Cost-Benefit Evaluation 12 During its review of the cost-benefit analysis performed by Exelon, the NRC staff compared the 13 applicants approach with guidance in NUREG/BR-0184 (NRC 1997a) and discount rate 14 guidelines in NEI 05-01 (NEI 2005). NEI guidance states that two sets of estimates should be 15 developed for discount rates of 7 percent and 3 percent (NEI 2005). Exelon performed 16 assessments using both discount rates. Exelon provided a baseline set of results using a 17 discount rate of 3 percent. For the other types of potential sensitivity analyses suggested 18 (NEI 2005), the NRC staff finds that Exelons information provided in the ER submittal and 19 subsequent RAI responses on plant modifications, peer review findings or observations, and 20 evacuation speeds have been adequately addressed in the baseline analysis, as discussed in 21 this appendix. As previously indicated, Exelon performed the cost-benefit evaluation using an 22 analysis time period of 20 years. Because Exelon explicitly accounted for uncertainty in its 23 sensitivity analysis by applying a multiplication factor of 2.14 and the results of the sensitivity 24 analysis were used to identify additional potentially beneficial SAMAs, the NRC staff finds that 25 an additional sensitivity analysis for a timeframe longer than 20 years is not necessary. 26 Although longer timeframes would increase estimated benefits compared to baseline results, 27 the 20-year timeframe is consistent with the later expiration month of December 2043 for a 28 renewed license of Unit 2 stated in Section 1.1 of the ER (Exelon 2014a), and it is unlikely that 29 influences from a longer timeframe would exceed the factor of 2.14 already considered by 30 Exelon. Based on its review of the applicants cost-benefit evaluation, the NRC staff determined 31 that the applicants approach is consistent with the guidance and acceptable. 32 The applicant considered possible increases in benefits from analysis uncertainties on the 33 results of the SAMA assessment. In the ER (Exelon 2014a), Exelon indicated that the 34 95th percentile value of the LSCS CDF was greater than the mean CDF by a factor of 2.14, and 35 thus, a multiplication factor of 2.14 was selected to account for uncertainty. This multiplication 36 factor was applied in addition to the separate external events multiplication factor of 5.2 37 (Exelon 2014a). Exelons assessment accounted for the potential risk-reduction benefits 38 associated with both internal and external events. The NRC staff considers the multipliers 39 of 2.14 for uncertainty and 5.2 for external events at LSCS provide an adequate margin and are 40 acceptable for the SAMA analysis. 41 Using Exelons information presented in the ER (Exelon 2014a), the NRC staff spot checked the 42 applicants calculations of delta CDF (i.e., percentage reduction in CDF due to accumulated 43 differences in the release categories for a specific SAMA candidate compared to the base 44 case), population dose risk, and offsite economic cost risk. By applying the formula for SAMA 45 benefit presented in Section F.6.1 and comparing the results with those presented in the ER 46 (Exelon 2014a), the NRC staff found the results to be in agreement and within small round-off 47 errors. F-42

Appendix F 1 Exelons revised cost-benefit analysis identified 14 SAMA candidates as potentially cost 2 beneficial at the 95th percentile (Exelon 2015). From its sensitivity analyses in the ER, no 3 additional SAMA candidates were determined to be potentially cost beneficial. As described in 4 Section F.3.2, the NRC staff asked the applicant to evaluate potentially lower cost alternatives 5 to SAMA 7. From its review of the original SAMA analysis and additional information, the NRC 6 staff agrees with Exelons disposition of potentially lower cost alternatives. 7 Because Exelons cost-benefit evaluations have been reviewed by the NRC staff and Exelon 8 satisfactorily addressed NRC staff questions regarding the evaluations, the NRC staff concludes 9 that the cost-benefit evaluations are of sufficient quality to support the SAMA evaluation. 10 Therefore, the NRC staff concludes that, with the exception of the potentially cost-beneficial 11 SAMAs discussed above, the costs of the other SAMAs evaluated would be higher than their 12 associated benefits and not cost beneficial. 13 Conclusions 14 Exelon considered 26 SAMA candidates based on risk-significant contributors at LSCS from 15 updated probabilistic safety assessment models, SAMA-related industry documentation, 16 plant-specific enhancements, and its review of SAMA candidates from potential improvements 17 primarily at six other BWR plants. Revised Phase I screening reduced the list to 25 unique 18 SAMA candidates by eliminating SAMAs that are not applicable to LSCS, that have already 19 been implemented at LSCS, or that have excessive implementation costs. Exelon assessed the 20 costs and benefits associated with each of the 25 potential SAMAs shown in Table F-6. Exelon 21 concluded that 14 SAMA candidates were potentially cost beneficial at the 95th percentile. 22 Despite it being not cost beneficial, Exelon has decided to proceed with the modification to 23 install a hardened pipe containment vent regardless of cost. Exelon also performed a sensitivity 24 analysis, and no additional SAMA candidates were identified as potentially cost beneficial. 25 Because the potentially cost-beneficial SAMAs do not relate to aging management during the 26 period of extended operation, their implementation is not required as part of license renewal 27 pursuant to Title 10 of the Code of Federal Regulations (10 CFR) Part 54, Requirements for 28 Renewal of Operating Licenses for Nuclear Power Plants. Nevertheless, as stated in 29 Section 4.15 of the ER (Exelon 2014d), Exelon indicated that the potentially cost-beneficial 30 SAMAs are being referred to the LSCS Plant Health Committee for further implementation 31 considerations within the established plant procedural process. 32 The NRC staff reviewed Exelons SAMA analysis and concludes that the methods used and 33 implementation of the methods were sound. On the basis of the applicants treatment of SAMA 34 benefits and costs, the NRC staff finds that the SAMA evaluations performed by Exelon are 35 reasonable and sufficient for the license renewal submittal. The NRC staff concurs with 36 Exelons conclusion that 14 SAMA candidates are potentially cost beneficial for LSCS and notes 37 that Exelons assessment was based on generally conservative treatment of costs, benefits, and 38 uncertainties. Based on the NRC staffs review of Exelons SAMA evaluations, including 39 Exelons response to the NRC staffs RAIs, the NRC staff concludes that Exelon has adequately 40 identified areas where risk can be further reduced in a cost-beneficial manner through the 41 implementation of the identified potentially cost-beneficial SAMAs. Given the potential for 42 cost-beneficial risk reduction, the NRC staff concludes that further evaluation by Exelon of the 43 14 SAMA candidates identified by Exelon as being potentially cost beneficial is warranted. 44 The NRC staff also evaluated whether any of the potentially cost-beneficial SAMAs identified 45 are subject to aging management such that they would be within the scope of license renewal. 46 The evaluation considered any structures, systems, and components associated with these 47 SAMAs that perform intended functions without moving parts or without a change in F-43

Appendix F 1 configuration or properties and would not be subject to replacement based on a qualified life or 2 specified time period. The NRC staff determined that the potentially cost-beneficial SAMAs do 3 not relate to adequately managing the effects of aging during the period of extended operation. 4 Therefore, they need not be implemented as part of license renewal in accordance with 5 10 CFR Part 54. 6 References 7 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 8 Renewal of Operating Licenses for Nuclear Power Plants. 9 [ASME/ANS] (American Society of Mechanical Engineers/American Nuclear Society). 2005. 10 Addenda RA-Sa-2003 and RA-Sb-2005 to ASME RA-S-2002, Standard for Probabilistic Risk 11 Assessment for Nuclear Power Plant Applications. December 2005. 12 [ASME/ANS] American Society of Mechanical Engineers and American Nuclear Society. 2009. 13 Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency 14 Probabilistic Risk Assessment for Nuclear Power Plant Applications. New York, NY: ASME. 15 ASME/ANS RA-Sa-2009. February 2, 2009. 352 p. This document is proprietary and available 16 for sale on www.asme.org. 17 [CECO] Commonwealth Edison Company. 1994. LaSalle County Nuclear Power Station, 18 Individual Plant Examination and Individual Plant Examination (External Events). April 1994. 19 [Exelon] Exelon Generating Company, LLC. 2012a. Seismic Walkdown Report In Response 20 To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 21 Recommendation 2.3: Seismic for the LaSalle County Station, Unit 1, Report Number: 22 12Q0108.50-R-001, Revision 1. November 27, 2012. ADAMS No. ML12353A225. 23 [Exelon] Exelon Generating Company, LLC. 2012b. Seismic Walkdown Report In Response 24 To The 50.54(f) Information Request Regarding Fukushima Near-Term Task Force 25 Recommendation 2.3: Seismic for the LaSalle County Station, Unit 2, Report Number: 26 12Q0108.50-R-002, Revision 1. November 27, 2012. ADAMS No. ML12353A207. 27 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report, 28 Operating License Renewal Stage, LaSalle County Station. Appendix F: Severe Accident 29 Mitigation Alternatives Analysis. ADAMS No. ML14343A897. December 2014. 30 [Exelon] Exelon Generation Company, LLC. 2014b. Letter from Glen T. Kaegi to NRC 31 Document Control Desk.

Subject:

Exelon Generation Company, LLC, Seismic Hazard and 32 Screening Report (Central and Eastern United States (CEUS) Sites), Response to NRC 33 Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the 34 Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident. Exelon letter 35 RS-14-068. March 31, 2014. ADAMS No. ML14091A013. 36 [Exelon] Exelon Generation Company, LLC. 2014c. Letter from T. John Conner to NRC 37 Document Control Desk.

Subject:

Exelon Generation Company, LLC Response to 38 March 12, 2012, Request for Information Enclosure 2, Recommendation 2.1, Flooding, 39 Required Response 2, Flood Hazard Reevaluation Report. Exelon letter RS-14-055. 40 March 12, 2014. ADAMS Nos. ML14079A425 and ML14079A426. 41 [Exelon] Exelon Generation Company, LLC. 2014d. Applicants Environmental Report, 42 Operating License Renewal Stage, LaSalle County Station. ADAMS No. ML14343A883. 43 December 2014. F-44

Appendix F 1 [Exelon] Exelon Generation Company, LLC. 2015. Letter from Michael P. Gallagher, Vice 2 President, License Renewal Projects Exelon Generation Company, LLC, to NRC Document 3 Control Desk.

Subject:

Response to NRC Request for Additional Information on Severe 4 Accident Mitigation Alternatives Regarding the LaSalle County Station, Units 1 and 2 License 5 Renewal Application Environmental Review. Letter RA15-032. May 29, 2015. ADAMS 6 No. ML15149A370. 7 [NEI] Nuclear Energy Institute. 2005. Severe Accident Mitigation Alternative (SAMA) Analysis 8 Guidance Document. Revision A. Washington, DC: NEI. NEI 05-01. November 2005. 79 p. 9 ADAMS No. ML060530203. 10 [NRC] U.S. Nuclear Regulatory Commission. 1988. Individual Plant Examination for Severe 11 Accident Vulnerabilities10 CFR 50.54(f). Washington, DC: NRC. Generic Letter No. 88-20. 12 November 23, 1988. Available at <http://www.nrc.gov/reading-rm/doc-collections/gen-13 comm/gen-letters/1988/gl88020.html> (accessed 21 October 2014). 14 [NRC] U.S. Nuclear Regulatory Commission. 1991. Individual Plant Examination of External 15 Events for Severe Accident Vulnerabilities. Washington, DC: NRC. Generic Letter No. 88-20, 16 Supplement 4. June 28, 1991. 17 [NRC] U.S. Nuclear Regulatory Commission. 1992. Analysis of the LaSalle Unit 2 Nuclear 18 Power Plant: Risk Methods Integration and Evaluation Program (RMIEP). Washington, DC: 19 NRC. NUREG/CR-4832, Vols. 19, 19921993. 20 [NRC] U.S. Nuclear Regulatory Commission. 1995. Memorandum from M. Wayne Hodges, 21 NRC, to Steven A Varga, NRC.

Subject:

Review of LaSalle Individual Plant Examination (IPE) 22 Submittal-Internal Events. November 1, 1995. 23 [NRC] U.S. Nuclear Regulatory Commission. 1997a. Regulatory Analysis Technical Evaluation 24 Handbook. Washington, DC: NRC. NUREG/BR-0184. January 1997. 308 p. ADAMS 25 No. ML050190193. 26 [NRC] U.S. Nuclear Regulatory Commission. 1997b. Individual Plant Examination Program: 27 Perspectives on Reactor Safety and Plant Performance, NUREG-1560, Washington, D.C. 28 1997. 29 [NRC] U.S. Nuclear Regulatory Commission. 2000. Letter from Donna M. Skay to Oliver D. 30 Kingsley, Commonwealth Edison Company.

Subject:

LaSalle County Station, Units 1 and 2, 31 NRC Staff Evaluation of the Individual Plant Examination of External Events (IPEEE) Submittal. 32 (TAC Nos. M83634 and M83635). December 8, 2000. ADAMS No. ML003776159. 33 [NRC] U.S. Nuclear Regulatory Commission. 2004. Regulatory Analysis Guidelines of the 34 U.S. Nuclear Regulatory Commission. Revision 4. Washington, DC: NRC. NUREG/BR-0058. 35 September 2004. 56 p. Available at<http://www.nrc.gov/reading-rm/doc-collections/nuregs/ 36 brochures/br0058/> (accessed 21 October 2014). 37 [NRC] U.S. Nuclear Regulatory Commission. 2005. EPRI/NRC-RES Fire PRA Methodology 38 for Nuclear Power Facilities. Vols. 1 and 2. Washington, DC: NRC. NUREG/CR-6850. 39 September 2005. ADAMS Nos. ML052580075 and ML052580118. 40 [NRC] U.S. Nuclear Regulatory Commission. 2007. An Approach for Determining the 41 Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities. 42 Revision 1. Regulatory Guide 1.200. January 2007. ADAMS No. ML070240001. F-45

Appendix F 1 [NRC] U.S. Nuclear Regulatory Commission. 2010. Letter from T. McGinty, Director, to All 2 Holders of an Operating License.

Subject:

NRC Information Notice 2010-18: Generic 3 Issue 199, Implications of Updated Probabilistic Seismic Hazard Estimates in Central and 4 Eastern United States on Existing Plants. September 2, 2010. ADAMS No. ML101970221. 5 [NRC] U.S. Nuclear Regulatory Commission. 2011. An Approach for Using Probabilistic Risk 6 Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis. 7 Revision 2. Regulatory Guide 1.174. May 2011. ADAMS No. ML100910006. 8 [NRC] U.S. Nuclear Regulatory Commission. 2012a. Letter from E. Leeds, Director, to All 9 Power Reactor Licensees.

Subject:

Request for information pursuant to Title 10 of the Code of 10 Federal Regulations 50.54(f) regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term 11 Task Force review of insights from the Fukushima Dai-ichi accident. March 12, 2012. ADAMS 12 No. ML12053A340. 13 [NRC] U.S. Nuclear Regulatory Commission. 2012b. Letter from E. Leeds, Director, to All 14 Power Reactor Licensees and Holders of Construction Permits in Active or Deferred Status. 15 EA-12-049.

Subject:

Issuance of Order to Modify Licenses with Regard to Requirements for 16 Mitigation Strategies for Beyond-Design-Basis External Events. March 12, 2012. ADAMS 17 No. ML12054A735. 18 [NRC] U.S. Nuclear Regulatory Commission. 2014. Letter from Blake Purnell, Project 19 Manager, NRC, to Michael J. Pacilio, Senior Vice President, Exelon Generation Company. 20

Subject:

LaSalle County Station, Units 1 and 2 - Staff Assessment of the Flooding Walkdown 21 Report Supporting Implementation of the Near-Term Task Force Recommendation 2.3 Related 22 to the Fukushima Dai-ichi Accident. (TAC Nos. MF0240 and MF0241). June 30, 2014. 23 ADAMS No. ML14177A859. 24 [NRC] U.S. Nuclear Regulatory Commission. 2015. Letter from D. Drucker, Environmental 25 Project Manager, to Michael P. Gallagher, Vice President License Renewal Projects, Exelon 26 Generation Company, LLC.

Subject:

Request for Additional Information on Severe Accident 27 Mitigation Alternatives Regarding the LaSalle County Station, Units 1 and 2, License Renewal 28 Application Environmental Review (TAC Nos. MF5567 and MF5568). April 30, 2015. ADAMS 29 Nos. ML15114A320 and ML15114A102. F-46

1 APPENDIX G 2 TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL

1 G. TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL 2 Introduction 3 The U.S. Nuclear Regulatory Commission (NRC) has generically determined in its license 4 renewal application reviews that the environmental impacts of the transportation of fuel and 5 radioactive wastes to and from nuclear power facilities are small for all reactors as long as 6 certain specific conditions are met. The application for license renewal of LaSalle County 7 Station, Units 1 and 2 (LSCS) stated that the specific conditions that allow the transportation 8 impacts of spent fuel to be generically determined to be small may not be met for LSCS. 9 Therefore, this appendix provides the NRC staffs analysis of the environmental impacts of 10 transporting spent fuel from LSCS. 11 Background 12 The U.S. Nuclear Regulatory Commission (NRC) performed a generic analysis of the 13 environmental effects of the transportation of fuel and waste to and from light-water reactors 14 (LWRs) in WASH-1238, Environmental Survey of Transportation of Radioactive Materials to 15 and from Nuclear Power Plants (AEC 1972), and in a supplement to WASH-1238, 16 NUREG-75/038 (NRC 1975), and found the impact to be small. These documents provided the 17 basis for Table S-4 in Title 10 of the Code of Federal Regulations (CFR) Part 51.52(b) that 18 summarizes the environmental impacts of transportation of fuel and waste to and from one 19 3,000- to 5,000-megawatt-thermal (MWt) (1,000- to 1,500-megawatt-electric (MWe)) LWR. 20 Impacts are provided for normal conditions of transport and accidents in transport for a 21 reference 1,100-MWe LWR.11 Dose to transportation workers during normal transportation 22 operations was estimated to result in a collective dose of 4 person-rem per reference 23 reactor-year. The combined dose to the public along the route and the dose to onlookers were 24 estimated to result in a collective dose of 3 person-rem per reference reactor-year. 25 Environmental risks of radiological effects during accident conditions, as stated in Table S-4, 26 are small. Nonradiological impacts from postulated accidents were estimated as one fatal injury 27 in 100 reference reactor-years and one nonfatal injury in 10 reference reactor-years. 28 Subsequent reviews of transportation impacts in NUREG-0170, Final Environmental Statement 29 on the Transportation of Radioactive Material by Air and Other Modes (NRC 1977), and 30 NUREG/CR-6672, Reexamination of Spent Fuel Shipment Risk Estimates (Sprung et al. 2000), 31 concludes that impacts were bounded by Table S-4 in 10 CFR 51.52. In accordance with 32 10 CFR 51.52(a), a full description and a detailed analysis of transportation impacts are not 33 required in the initial licensing of an LWR (i.e., impacts are assumed to be bounded by 34 Table S-4) if the reactor meets the following criteria: 35

  • The reactor has a core thermal power level that does not exceed 3,800 MWt.

36

  • Fuel is in the form of sintered uranium oxide pellets having a uranium-235 37 enrichment not exceeding 4 percent by weight, and the pellets are encapsulated in 38 Zircaloy-clad fuel rods.

11 The transportation impacts associated with LSCS were normalized for a reference 1,100-MWe LWR at an 80-percent capacity factor for comparisons to Table S-4. G-1

Transportation Impacts of High Burnup Fuel 1

  • The average level of irradiation of the fuel from the reactor does not exceed 2 33,000 megawatt-days per metric ton of uranium (MWd/MTU), and no irradiated fuel 3 assembly is shipped until at least 90 days after it is discharged from the reactor.

4

  • With the exception of irradiated fuel, all radioactive waste shipped from the reactor is 5 packaged and in a solid form.

6

  • Unirradiated fuel is shipped to the reactor by truck; irradiated fuel is shipped from the 7 reactor by truck, rail, or barge; and radioactive waste other than irradiated fuel is 8 shipped from the reactor by truck or rail.

9 The environmental impacts of the transportation of fuel and radioactive wastes to and from 10 nuclear power facilities are resolved generically in 10 CFR 51.52 as long as the specific 11 conditions in the rule (see above) are met. 12 10 CFR 51.52 does not specifically address license renewal. However, NUREG-1437, Generic 13 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) 14 (NRC 2013), points out that nuclear fuel is needed for the operation of light water reactors 15 during the license renewal term in the same way that it is needed during the current license 16 period. Therefore, the factors that affect the data presented in Table S-4 of 10 CFR 51.52 do 17 not change when a light water reactor is operating under a renewed license. The GEIS further 18 states that the NRC reevaluated the transportation issues and the adequacy of Table S-4 for 19 license renewal application reviews (NRC 2013). In 1999, the NRC issued an addendum to the 20 GEIS (NRC 1999) in which the agency evaluated the applicability of Table S-4 to future license 21 renewal proceedings, particularly because shipments of spent fuel were likely to involve more 22 highly enriched fresh fuel (more than 4 percent as assumed in Table S-4) and higher-burnup 23 spent fuel (higher than 33,000 MWd/MTU as assumed in Table S-4). On the basis of the 24 evaluations, the NRC concluded that the values given in Table S-4 would still be bounding, as 25 long as the (1) enrichment of the fresh fuel was 5 percent or less, (2) burnup of the spent fuel 26 was 62,000 MWd/MTU or less, and (3) higher-burnup spent fuel (higher than 27 33,000 MWd/MTU) was cooled for at least 5 years before being shipped offsite. 28 The GEIS (NRC 2013) quotes the conclusion of the 1999 addendum as follows: 29 The impacts of transporting spent fuel enriched up to 5 percent uranium-235 with 30 average burnup for the peak rod to current levels approved by NRC up to 31 62,000 MWd/MTU and the cumulative impacts of transporting high-level waste to 32 a single repository, such as Yucca Mountain, Nevada are found to be consistent 33 with the impact values contained in 10 CFR 51.52(c), Summary Table S-4, 34 Environmental Impact of Transportation of Fuel and Waste to and from One 35 Light-Water-Cooled Nuclear Power Reactor. If fuel enrichment or burnup 36 conditions are not met, the applicant must submit an assessment of the 37 implications for the environmental impact values reported in 10 CFR 51.52. 38 Therefore, when the fuel burnup rate may exceed 62,000 MWd/MTU during the period of 39 extended operation, further analysis of transportation impacts is warranted. 40 Exelon Generation Company, LLC (Exelon), submitted an environmental report (ER) 41 (Exelon 2014a) as part of its license renewal application (Exelon 2014b) for LSCS in 42 December 2014. LSCS is located in north-eastern Illinois. Each LSCS reactor is a General 43 Electric boiling water reactor (BWR), Type 5, with a thermal power rating of 3,546 MWt. The 44 two reactors at LSCS have a combined electrical output of 2,327 MWe. Both LSCS units 45 operate using low-enriched uranium dioxide fuel with enrichment not exceeding a nominal 46 5.0 percent by weight of uranium-235; these units have been historically operated within a 47 maximum analyzed fuel burnup rate of 62,000 MWd/MTU. However, during some future fuel G-2

Transportation Impacts of High Burnup Fuel 1 cycles, the peak fuel burnup is projected to exceed 62,000 MWd/MTU in some part-length fuel 2 rods. The part-length fuel rods are attached to the fuel bundle lower tie plate and typically 3 experience higher burnups and higher power than full-length rods due to the bottom-peaked 4 axial power shapes that exist throughout a large portion of a BWR fuel cycle, and a 5 representative high-burnup case was identified based on a burnup of 75,000 MWd/MTU and a 6 uranium-235 enrichment of 5.0 percent by weight. Accordingly, Exelon provided a full 7 description and detailed analyses of the transportation impacts of shipping irradiated fuel from 8 LSCS in its ER (Exelon 2014a) and provided an update to that analysis by letter dated 9 August 28, 2015 (Exelon 2015). In this analysis, the radiological impacts of transporting 10 irradiated fuel from LSCS were calculated using the RADTRAN 6.02 computer code 11 (Weiner et al. 2015). RADTRAN 6.02 was also used in this SEIS and is the most commonly 12 used transportation impact analysis software in the nuclear industry. 13 NRC Analysis of LSCS High Burnup Fuel Transportation Impacts 14 This section provides the NRC staffs analysis of the environmental impacts of transporting 15 spent fuel from LSCS to a monitored retrievable storage facility or a permanent repository for 16 normal operating conditions and transportation accidents. 17 For the purposes of this analysis, the NRC staff considered the proposed Yucca Mountain 18 repository site in Nevada as a surrogate destination. Currently, the NRC has not made a 19 decision about the U.S. Department of Energy (DOE) application for the proposed geologic 20 repository at Yucca Mountain. However, the NRC staff considers that an estimate of the 21 impacts of the transportation of spent fuel to a possible repository in Nevada is a reasonable 22 bounding estimate of the transportation impacts on a storage or disposal facility because of the 23 distances involved and the representativeness of the distribution of members of the public in 24 urban, suburban, and rural areas (i.e., population distributions) along the shipping routes. 25 The NRC Yucca Mountain adjudicatory proceeding is currently suspended, and Yucca 26 Mountain-related matters are pending in Federal Court. Regardless of the outcome of these 27 proceedings, the NRC staff concludes that transportation impacts are roughly proportional to the 28 distance from the reactor site to the repository site, in this case, Illinois to Nevada. 29 This NRC staffs analysis is based on shipment of spent fuel by legal-weight trucks in shipping 30 casks with characteristics similar to currently available casks (i.e., massive, heavily shielded, 31 cylindrical metal pressure vessels). Because of the large size and weight of spent fuel shipping 32 casks, each shipment is assumed to consist of a single shipping cask loaded on a modified 33 trailer. These assumptions are consistent with those made in the evaluation of the 34 environmental impacts of transportation of spent fuel in Addendum 1 to NUREG-1437 35 (NRC 1999). Because the alternative transportation methods involve rail transportation or 36 heavy-haul trucks, which would reduce the overall number of spent fuel shipments (NRC 1999), 37 thereby reducing impacts, these assumptions are conservative. In addition, the use of current 38 shipping cask designs for this analysis results in conservative impact estimates because the 39 current designs are based on transporting short-cooled spent fuel (approximately 120 days out 40 of reactor). Future shipping casks would be designed to transport longer cooled fuel (greater 41 than 5 years out of reactor) and would require much less shielding to meet external dose 42 limitations. Therefore, future shipping casks are expected to have higher cargo capacities, thus 43 reducing the numbers of shipments and associated impacts. 44 The NRC staff calculated radiological impacts of transportation of spent fuel using the 45 RADTRAN 6.02 computer code (Weiner et al. 2015). Routing and population data used in 46 RADTRAN 6.02 for truck shipments were obtained from the Transportation Routing Analysis 47 Geographical Information System (TRAGIS) routing code (ORNL 2015). The population data in G-3

Transportation Impacts of High Burnup Fuel 1 the TRAGIS code are based on the 2010 Census. The traffic accident rates input to 2 RADTRAN 6.02 were taken from Weiner et al. (2015). 3 G.3.1. Normal Conditions 4 Normal conditions, sometimes referred to as incident free transportation, are transportation 5 activities in which shipments reach their destination without an accident occurring en route. 6 Impacts from these shipments would be from the low levels of radiation that penetrate the 7 heavily shielded spent fuel shipping cask. Radiation exposures would occur to the following 8 populations: (1) persons residing along the transportation corridors between LSCS and the 9 proposed repository location, (2) persons in vehicles traveling on the same route as a spent fuel 10 shipment, (3) persons at vehicle stops for refueling, rest, and vehicle inspections, and 11 (4) transportation crew workers (drivers). This analysis assumed that the surrogate destination 12 for the spent fuel shipments is the proposed Yucca Mountain repository site in Nevada. This 13 assumption is conservative because it tends to maximize the shipping distance from LSCS. 14 The NRC staff assumed that the capacity of a truck shipment of reactor spent fuel was 15 0.5 metric ton of uranium (MTU) per shipment, the same capacity as that used in WASH-1238 16 (AEC 1972). Exelon assumed a shipping cask capacity of 0.5 MTU per shipment in its analysis 17 (Exelon 2014a, 2015). 18 Appendix G input to RADTRAN 6.02 includes the total shipping distance between the origin and 19 destination sites and the population distributions along the routes. This information was 20 obtained by running the TRAGIS computer code (ORNL 2015) for highway routes from LSCS to 21 the proposed Yucca Mountain repository site. The resulting route characteristics information is 22 shown in Table G-1. For truck shipments, all the spent fuel is assumed to be shipped to the 23 proposed Yucca Mountain repository site over designated highway-route controlled-quantity 24 routes. In addition, TRAGIS data were used in RADTRAN 6.02 on a state-by-state basis. The 25 use of state-specific data from TRAGIS increases precision and could allow the results to be 26 presented for each state along the route between LSCS and the proposed Yucca Mountain 27 repository site, if desired. 28 Transportation Route Information for Shipments from 29 LSCS to the Proposed Yucca Mountain Repository Site(a) Population Density, Stop Time One-Way Shipping Distance, km persons/km2 per Trip, Reactor Site Total Rural Suburban Urban Rural Suburban Urban hr LSCS 2,871 2,418 393 60 10 334 1,649 2.5 (a) This table presents aggregated route characteristics from Exelon (2014a, 2015). Input to the RADTRAN 6.02 computer code was disaggregated to a state-by-state level. 30 Radiation doses are a function of many parameters, including vehicle speed, traffic count, dose 31 rate, packaging dimensions, number in the truck crew, stop time, and population density at 32 stops. A list of the values for these and other parameters and the sources of the information is 33 provided in Table G-2 34 For the purposes of this analysis, the transportation crew for spent fuel shipments delivered by 35 truck is assumed to consist of two drivers. Escort vehicles and drivers were considered, but 36 they were not included because their distance from the shipping cask would reduce the dose 37 rates to levels well below the dose rates experienced by the drivers and the dose rates would be G-4

Transportation Impacts of High Burnup Fuel 1 negligible (DOE 2002a). Stop times for refueling and rest were assumed to occur at the rate of 2 30 minutes per 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> of driving time. TRAGIS outputs were used to determine the number of 3 stops. Doses to the public at truck stops have been significant contributors to the doses 4 calculated in previous RADTRAN 6.02 analyses. For this analysis, doses to the public at 5 refueling and rest stops (i.e., stop doses) are the sum of the doses to individuals located in two 6 annular rings centered at the stopped vehicle, as illustrated in Figure G-1. The inner ring 7 represents persons who may be at the truck stop at the same time as a spent fuel shipment and 8 extends 1 to 10 m from the edge of the vehicle. The outer ring represents persons who reside 9 near a truck stop and it extends from 10 to 800 m from the vehicle. This scheme is similar to 10 that used by Sprung et al. (2000). Population densities and shielding factors were also taken 11 from Sprung et al. (2000), which were based on observations in Griego et al. (1996). 12 RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters RADTRAN 6.02 Parameter Input Value Source Vehicle speed, km/hr State Specific Weiner et al. (2015) Traffic countRural, vehicles/hr State Specific Weiner et al. (2015) Traffic countSuburban, vehicles/hr State Specific Weiner et al. (2015) Traffic countUrban, vehicles/hr State Specific Weiner et al. (2015) Vehicle occupancy, persons/vehicle 1.5 DOE 2002b Dose rate at 1 m from vehicle, 14 Exelon (2015a, 2015b). Approximate dose mrem/hr rate at 1 m that is equivalent to the maximum dose rate allowed by Federal regulations (i.e., 10 mrem/hr at 2 m from the side of a transport vehicle) Packaging dimensions, m Length5.03 Exelon (2015a, 2015b) Diameter0.88 Number of truck crew 2 AEC 1972; NRC 1977; DOE 2002b Stop time, hr/trip Route Specific See Table G-1 Population density at stops, 30,000 Sprung et al. 2000. Nine persons within 10 m persons/km2 of vehicle. See Figure G-1. Minimum/maximum radii of annular 1 to 10 Sprung et al. 2000 area around vehicle at stops, m Shielding factor applied to annular 1 Sprung et al. 2000 area surrounding vehicle at stops, (no shielding) dimensionless Population density surrounding truck 340 Sprung et al. 2000 stops, persons/km2 Minimum/maximum radius of annular 10 to 800 Sprung et al. 2000 area surrounding truck stop, m Shielding factor applied to annular 0.2 Sprung et al. 2000 area surrounding truck stop, dimensionless 13 The results of these normal (incident-free) exposure calculations are shown in Table G-3 14 Population dose estimates are given for workers (truck crew members), onlookers (doses to G-5

Transportation Impacts of High Burnup Fuel 1 persons at stops and persons on highways exposed to the spent fuel shipment), and persons 2 along the route (persons living near the highway). 3 Shipping schedules for spent fuel generated by LSCS have not been determined. The NRC 4 staff determined that it is reasonable to calculate annual doses assuming the annual number of 5 spent fuel shipments is equivalent to the annual refueling requirements. Population doses were 6 normalized to the reference LWR in WASH-1238 (880 MWe (net)) (AEC 1972). This 7 corresponds to a 1,100-MWe LWR operating at 80-percent capacity. 8 Figure G-1. Illustration of Truck Stop Model 9 Annual Normal (Incident-Free) Radiation Doses to Transport Workers and the 10 Public from Shipping Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 11 Site, Normalized to Reference LWR (880 MWe (net)) Normalized Impacts, Person-rem/yr Normalized Average Public Public Site Annual Shipments Workers Onlookers Along Route Reference LWR (WASH-1238) 60 2.1 26 0.48 LSCS 40 1.4 17 0.32 Table S-4 Condition - 4 3 3 G-6

Transportation Impacts of High Burnup Fuel 1 The bounding cumulative doses to the exposed population given in Table S-4 are as follows: 2

  • 4 person-rem per reactor-year to transport workers and 3
  • 3 person-rem per reactor-year to general public (onlookers) and members of the 4 public along the route.

5 The calculated population doses to onlookers for the reference LWR and the LSCS shipments 6 exceed Table S-4 values. One of the key reasons for the higher population doses relative to 7 Table S-4 is the longer shipping distances assumed for this analysis (i.e., to a proposed 8 repository in Nevada) than the distances used in WASH-1238 (AEC 1972). WASH-1238 9 assumed that each spent fuel shipment would travel a distance of 1,000 mi, whereas the 10 shipping distances used in this SEIS were about 1,800 mi. If the shorter distance were used to 11 calculate the impacts for LSCS spent fuel shipments, the doses to onlookers would be reduced 12 by about 40 percent to 14 person-rem for the reference LWR and to 9.5 person-rem for the 13 LSCS shipments. In addition, some of the other key conservative assumptions in the analysis 14 were as follows: 15

  • Use of the regulatory maximum dose rate (10 millirem (mrem) per hour at 2 m) in the 16 RADTRAN calculations. The shipping casks assumed in the environmental impact 17 statement prepared by DOE in support of the application for a geologic repository at 18 the proposed Yucca Mountain repository site (DOE 2002a) would transport spent 19 fuel that has cooled for a minimum of 5 years (see Subpart B of 10 CFR Part 961).

20 Most spent fuel would have cooled for much longer than 5 years before being 21 shipped to a possible geologic repository. Based on this, shipments from LSCS also 22 are expected to be cooled for longer than 5 years. Consequently, the estimated 23 population doses in Table G-3 could be further reduced if more realistic dose rate 24 projections are used. 25

  • Use of the shipping cask capacity used in WASH-1238 (AEC 1972). The 26 WASH-1238 analyses that form the basis for Table S-4 assumed that spent fuel 27 would be shipped at least 90 days after discharge from a current LWR. The spent 28 fuel shipping casks described in WASH-1238 were designed to transport 29 90-day-cooled fuel; therefore, their shielding and containment designs must 30 accommodate this highly radioactive cargo. Shipping cask capacities assumed in 31 WASH-1238 were approximately 0.5 MTU per truck cask. DOE (2008) assumed a 32 10-year cooling period for spent fuel to be shipped to the repository. This cooling 33 period allowed DOE to increase the assumed shipping cask capacity to about 34 0.88 MTU per truck shipment of spent fuel. The NRC staff believes this is a 35 reasonable projection for future spent fuel truck shipping cask capacities. If this 36 assumption was used in this SEIS, the number of shipments of spent fuel would be 37 reduced by about 40 percent to 23 shipments with a similar reduction in incident-free 38 radiological impacts.

39

  • Use of 30 minutes as the average time at a truck stop in the calculations. Many 40 stops made for actual spent fuel shipments are of short duration (i.e., 10 minutes) for 41 brief visual inspections of the cargo (e.g., checking the cask tie-downs). These stops 42 typically occur in minimally populated areas (e.g., an overpass or freeway ramp in an 43 unpopulated area). Furthermore, empirical data provided by Griego et al. 1996 44 indicate that a 30-minute duration is toward the high end of the stop time distribution.

45 Average stop times observed by Griego et al. 1996 were about 18 minutes. More 46 realistic stop times would further reduce the population doses in Table G-3 G-7

Transportation Impacts of High Burnup Fuel 1 A sensitivity study was performed by the NRC staff to demonstrate the effects of using more 2 realistic dose rates and stop times on the incident-free population dose calculations for 3 shipments of LSCS spent fuel. For this sensitivity study, the dose rate was reduced to 5 mrem 4 per hour, which is the approximate 50-percent confidence interval of the dose rate distribution 5 estimated by Sprung et al. (2000) for future spent fuel shipments. The number of shipments 6 was reduced to 23 shipments per year, and the stop time was reduced to 18 minutes per stop. 7 All other RADTRAN 6.02 input values were unchanged. The result is that the annual crew 8 doses, onlooker doses, and doses to persons along the route were reduced by about 80 percent 9 of the annual doses shown in Table G-3 to 0.29 person-rem, 2.7 person-rem, and 10 0.078 person-rem, respectively. If the shipping distance was reduced from 1,800 mi to 1,000 mi 11 as discussed above, the annual crew doses, onlooker doses, and doses to persons along the 12 route would be further reduced to 0.16 person-rem, 1.5 person-rem, and 0.043 person-rem, 13 respectively. 14 Radiation protection experts assume that any amount of radiation may pose some risk of 15 causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 16 exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 17 relationship between radiation dose and detriments, such as cancer induction. The National 18 Research Council (National Research Council 2006) uses the linear, no-threshold dose 19 response model as a basis for estimating the risks from low doses. This approach is accepted 20 by the NRC as a conservative method for estimating health risks from radiation exposure, 21 recognizing that the model may overestimate those risks. Based on this method, the NRC staff 22 estimated the risk to the public from radiation exposure using the nominal probability coefficient 23 for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 24 severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem. 25 The coefficient is taken from the International Commission on Radiological Protection (ICRP) 26 Publication 103 (ICRP 2007). 27 Both the National Council on Radiation Protection and Measurements (NCRP) and ICRP 28 suggest that when the collective effective dose is smaller than the reciprocal of the relevant risk 29 detriment (in other words, less than 1/0.00057, which is less than 1,754 person-rem), the risk 30 assessment should note that the most likely number of excess health effects is zero 31 (NCRP 1995; ICRP 2007). The annual public dose impacts for transporting spent fuel from 32 LSCS to the proposed Yucca Mountain repository site were estimated to be about 33 17 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 34 NCRP (1995) suggest would most likely result in zero excess health effects. 35 To place these impacts in perspective, the average U.S. resident receives about 311 mrem per 36 year effective dose equivalent from natural background radiation (i.e., exposures from cosmic 37 radiation; naturally occurring radioactive materials, such as radon; and global fallout from testing 38 of nuclear explosive devices) (NCRP 2009). Using this average effective dose, the collective 39 population dose from natural background radiation to the population along the route from LSCS 40 to the proposed Yucca Mountain repository site would be about 1.6x105 person-rem. Therefore, 41 the radiation doses from transporting irradiated fuel from LSCS to the proposed Yucca Mountain 42 repository site are minimal compared to the collective population dose to the same population 43 from exposure to natural sources of radiation. This assessment is a comparative assessment 44 for which there is no regulatory standard to base an impact level, and, again, it is provided only 45 to place the impacts in perspective. G-8

Transportation Impacts of High Burnup Fuel 1 G.3.2. Radiological Impacts of Accidents 2 As discussed previously, the NRC staff used the RADTRAN 6.02 computer code to estimate the 3 impacts of transportation accidents involving spent fuel shipments. RADTRAN 6.02 considers a 4 spectrum of postulated transportation accidents, ranging from those with high frequencies and 5 low consequences (e.g., fender benders) to those with low frequencies and high 6 consequences (i.e., accidents in which the shipping container is exposed to severe mechanical 7 and thermal conditions). 8 Radionuclide inventories are important parameters in the calculation of accident risks. The 9 radionuclide inventories used in this analysis were from the Exelon ER (Exelon 2014a, 2015). 10 The spent fuel inventory used in the NRC staff analysis is listed in Table G-4 and is based on a 11 burnup of 75,000 MWd/MTU. 12 Robust shipping casks are used to transport spent fuel because of the radiation shielding and 13 accident resistance required by 10 CFR Part 71. Spent fuel shipping casks must be certified 14 Type B packaging systems, which means that they must withstand a series of severe postulated 15 accident conditions with essentially no loss of containment or shielding capability. These casks 16 also are designed with fissile material controls to ensure that the spent fuel remains subcritical 17 under normal and accident conditions. According to Sprung et al. (2000), the probability of 18 encountering accident conditions that would lead to shipping cask failure is less than 19 0.01 percent (i.e., more than 99.99 percent of all accidents would result in no release of 20 radioactive material from the shipping cask). The NRC staff assumed that shipping casks 21 approved for transportation of LSCS spent fuel would provide equivalent mechanical and 22 thermal protection of the spent fuel cargo. 23 Accident frequencies are calculated in RADTRAN 6.02 using user-specified accident rates and 24 conditional shipping cask failure probabilities. State-specific accident rates were taken from 25 Weiner et al. (2015) and used in the RADTRAN 6.02 calculations. Conditional shipping cask 26 failure probabilities (i.e., the probability of cask failure as a function of the mechanical and 27 thermal conditions applied in an accident) were taken from Sprung et al. 2000. 28 The RADTRAN 6.02 accident risk calculations were performed using the radionuclide 29 inventories (curie(s) per metric ton of uranium [Ci/MTU]) in Table G-4 multiplied by the shipping 30 cask capacity (0.5 MTU). The resulting risk estimates were then multiplied by assumed annual 31 spent fuel shipments (shipments per year) to derive estimates of the annual accident risks 32 associated with spent fuel shipments from LSCS to the proposed Yucca Mountain repository 33 site in Nevada. As was done for routine exposures, the NRC staff assumed that the numbers of 34 shipments of spent fuel per year are equivalent to the annual discharge quantities. For this 35 assessment, release fractions for current-generation LWR fuel designs (Sprung et al. 2000) 36 were used. 37 The NRC staff used RADTRAN 6.02 to calculate the population dose from the released 38 radioactive material from four of five possible exposure pathways.12 These pathways are as 39 follows: 40

  • External dose from exposure to the passing cloud of radioactive material 41 (cloudshine).

42

  • External dose from the radionuclides deposited on the ground by the passing plume 43 (groundshine). The NRC staffs analysis included the radiation exposure from this 12 Internal dose from ingestion of contaminated food was not considered because the NRC staff assumed evacuation and subsequent interdiction of foodstuffs following a postulated transportation accident.

G-9

Transportation Impacts of High Burnup Fuel 1 pathway even though the area surrounding a potential accidental release would be 2 evacuated and decontaminated, thus preventing long-term exposures from this 3 pathway. 4

  • Internal dose from inhalation of airborne radioactive contaminants (inhalation).

5

  • Internal dose from resuspension of radioactive materials that were deposited on the 6 ground (resuspension). The NRC staffs analysis included the radiation exposures 7 from this pathway even though evacuation and decontamination of the area 8 surrounding a potential accidental release would prevent long-term exposures.

9 Radionuclide Inventories Used in Transportation 10 Accident Risk Calculations for the LSCS Reactors(a)(b) Radionuclide Inventory Ci/Assembly Inventory Ci/MTU Am-241 1.87x102 1.06x103 Am-243 1.76x101 9.96x101 Ce-144 2.42x103 1.37x104 Cm-242 7.42 4.20x101 Cm-243 8.06 4.56x101 Cm-244 3.46x103 1.96x104 Cs-134 1.38x104 7.81x104 Cs-137 3.65x104 2.07x105 Eu-154 1.52x103 8.60x103 Eu-155 5.84x102 3.31x103 H-3 1.83x102 1.04x103 Kr-85 2.39x103 1.35x104 Np-239 1.76x101 9.96x101 Pm-147 8.70x103 4.92x104 Pu-238 1.43x103 8.09x103 Pu-239 4.37x101 2.47x102 Pu-240 1.22x102 6.90x102 Pu-241 1.81x104 1.02x105 Ru-106 5.22x103 2.95x104 Sb-125 8.88x102 5.03x103 Sr-90 2.41x104 1.36x105 Sr-89 1.33x10-6 7.53x10-6 Y-90 2.41x104 1.36x105 Co-60 5.93x102 3.36x103 Co-58 3.96x10-6 2.24x10-5 Fe-59 3.65x10-11 2.07x10-10 G-10

Transportation Impacts of High Burnup Fuel Radionuclide Inventory Ci/Assembly Inventory Ci/MTU Fe-55 3.50x102 1.98x103 Mn-54 2.42 1.37x101 Cr-51 6.48x10-17 3.67x10-16 Total 1.45x105 8.19x105 (a) Multiply curie per assembly or MTU by 3.7x1010 to obtain becquerel per assembly or MTU. (b) Radionuclide inventory is based on a burnup of 75,000 MWd/MTU. Sources: Exelon (2014a, 2015) 1 Table G-5 presents the environmental consequences of transportation accidents when shipping 2 spent fuel from LSCS to the proposed Yucca Mountain repository site. The shipping distances 3 and population distribution information for the routes were the same as those used for the 4 normal incident-free conditions (see Section G.3.1). The results are normalized to the 5 WASH-1238 (AEC 1972) reference reactor (880-MWe) net electrical generation (1,100-MWe 6 reactor operating at 80-percent capacity) to provide a common basis for comparison to the 7 impacts listed in Table S-4. Note that the impacts (1.2x105 person-rem per year) are less than 8 the reference LWR impacts (1.8x105 person-rem per year). The transportation accident impact 9 analysis conducted by Exelon (Exelon 2014a, 2015) used methods and data that are similar to 10 those used in this SEIS. The differences are insignificant in terms of the overall results. 11 Annual Spent Fuel Transportation Accident Impacts from Shipping Spent Fuel 12 from LSCS to the Proposed Yucca Mountain Repository Site, Normalized to Reference 13 LWR Reactor (880 MWe (net)) Normalized Average Annual Normalized Population Impacts, Site Shipments Person-rem/yr Reference LWR (WASH-1238) 60 1.8x105 LSCS 40 1.2x105 14 Radiation protection experts assume that any amount of radiation may pose some risk of 15 causing cancer or a severe hereditary effect and that the risk is higher for higher radiation 16 exposures. Therefore, a linear, no-threshold dose response relationship is used to describe the 17 relationship between radiation dose and detriments, such as cancer induction. The National 18 Research Council (National Research Council 2006) uses the linear, no-threshold dose 19 response model as a basis for estimating the risks from low doses. This approach is accepted 20 by the NRC as a conservative method for estimating health risks from radiation exposure, 21 recognizing that the model may overestimate those risks. Based on this method, the NRC staff 22 estimated the risk to the public from radiation exposure using the nominal probability coefficient 23 for total detriment. This coefficient has the value of 570 fatal cancers, nonfatal cancers, and 24 severe hereditary effects per 1,000,000 person-rem, equal to 0.00057 effects per person-rem. 25 The coefficient is taken from ICRP Publication 103 (ICRP 2007). 26 Both the NCRP and ICRP suggest that when the collective effective dose is smaller than the 27 reciprocal of the relevant risk detriment (in other words, less than 1/0.00057, which is less than 28 1,754 person-rem), the risk assessment should note that the most likely number of excess 29 health effects is zero (NCRP 1995; ICRP 2007). The annual accident impacts from transporting G-11

Transportation Impacts of High Burnup Fuel 1 spent fuel from LSCS to the proposed Yucca Mountain repository site were estimated to be 2 about 1.2x10-5 person-rem, which is less than the 1,754 person-rem value that ICRP (2007) and 3 NCRP (1995) suggest would most likely result in zero excess health effects. 4 In addition, the collective population dose from natural background radiation to the population 5 along the representative routes from LSCS to the proposed Yucca Mountain repository site 6 would be about 1.6x105 person-rem. Therefore, the accident impacts from transporting spent 7 fuel to the proposed Yucca Mountain repository site are minimal compared to the collective 8 population dose to the same population from exposure to natural sources of radiation. This 9 assessment is a comparative assessment for which there is no regulatory standard to base an 10 impact level and is provided only to place the impacts in perspective. 11 G.3.3. Nonradiological Impacts of Accidents 12 A nonradiological accident is a truck accident in which the property damage, injuries, or fatalities 13 are caused by the force of the impact; no release of, or exposure to, radiological materials 14 occurs as a result of the truck accident. In WASH-1238 (AEC 1972) and NUREG-75/038 15 (NRC 1975), the NRC staff assessed the impacts of these nonradiological truck accidents that 16 may occur during the transport of fuel and waste to and from LWRs and estimated the impacts 17 from these nonradiological accidents as one fatal injury in 100 reference reactor-years and one 18 nonfatal injury in 10 reference reactor-years. Using data from the National Highway 19 Transportation Safety Administration for large trucks over the period 2009 through 2013, NRC 20 staff estimated that there would be less than one fatal injury per 100 reference reactor-years 21 and less than one nonfatal injury per 10 reference reactor-years for shipments of spent fuel from 22 LSCS to the proposed Yucca Mountain repository site. Therefore, the nonradiological impacts 23 of accidents from the transportation of LSCS spent fuel would be small. 24 Conclusions for Transportation Impacts of High Burnup Fuel 25 The NRC staff performed an independent confirmatory analysis of the impacts under normal 26 operating and accident conditions of transporting irradiated fuel from LSCS to the proposed 27 Yucca Mountain repository site. To make comparisons to Table S-4, the environmental impacts 28 were adjusted (i.e., normalized) to the environmental impacts associated with the reference 29 LWR in WASH-1238 (AEC 1972) by multiplying the LSCS impact estimates by the ratio of the 30 total electric output for the reference reactor to the electric output of the LSCS reactors. 31 Because of the conservative approaches and data used to calculate impacts, the NRC staff 32 does not expect the actual environmental effects to exceed those calculated in this SEIS. Thus, 33 the NRC staff concludes that the environmental impacts of the transportation of irradiated fuel 34 from LSCS would be SMALL and would be consistent with the environmental impacts 35 associated with the transportation of fuel and radioactive wastes to and from current-generation 36 reactors presented in Table S-4 of 10 CFR 51.52. 37 The NRC staff concludes that transportation impacts are roughly proportional to the distance 38 from LSCS to the repository sitein this case Illinois to Nevada. The distance from LSCS to 39 any new planned repository in the contiguous United States would be no more than double the 40 distance from LSCS to the proposed Yucca Mountain repository site. Doubling the 41 environmental impact estimates from the transportation of spent reactor fuel, as presented in 42 this section, would provide a reasonable bounding estimate of the impacts to meet the 43 requirements of the National Environmental Policy Act of 1969, as amended (42 U.S.C. 4321 44 et seq.). The NRC staff concludes that the environmental impacts of these doubled estimates 45 would not be significant and, therefore, would still be SMALL. G-12

Transportation Impacts of High Burnup Fuel 1 References 2 10 CFR Part 50. 2012. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic 3 licensing of production and utilization facilities. 4 10 CFR Part 51. 2011. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 5 protection regulations for domestic licensing and related regulatory functions. 6 10 CFR Part 71. 2011. Code of Federal Regulations, Title 10, Energy, Part 71, Packaging and 7 transportation of radioactive material. 8 10 CFR Part 961. 2002. Code of Federal Regulations, Title 10, Energy, Part 961, Standard 9 contract for disposal of spent nuclear fuel and/or high-level radioactive waste. 10 65 FR 794. U.S. Nuclear Regulatory Commission. FirstEnergy Nuclear Operating Company, 11 Davis-Besse Nuclear Power Station, Unit 1; Environmental Assessment and Finding of No 12 Significant Impact. Federal Register (65):794. January 6, 2000. 13 [AEC] U.S. Atomic Energy Commission. 1972. Environmental Survey of Transportation of 14 Radioactive Materials to and from Nuclear Power Plants. Washington, DC: AEC. 15 WASH-1238. December 2002. ADAMS No. ML14092A626. 16 [DOE] U.S. Department of Energy. 2002a. Final Environmental Impact Statement for a 17 Geologic Repository for the Disposal of Spent Nuclear Fuel and High-Level Radioactive Waste 18 at Yucca Mountain, Nye County, Nevada. Washington, DC: DOE. DOE/EIS-0250, Office of 19 Civilian Radioactive Waste Management. February 2002. Available at 20 <http://energy.gov/nepa/downloads/eis-0250-final-environmental-impact-statement> (accessed 21 5 October 2015). 22 [DOE] U.S. Department of Energy. 2002b. A Resource Handbook on DOE Transportation Risk 23 Assessment. Washington, DC: DOE. DOE/EM/NTP/HB-01. July 2002. ADAMS 24 No. ML12192A286. 25 [DOE] U.S. Department of Energy. 2008. Final Supplemental Environmental Impact 26 Statement for a Geologic Repository for the Disposal of Spent Nuclear Fuel and High-Level 27 Radioactive Waste at Yucca Mountain, Nye County, Nevada. Washington, DC: DOE. 28 DOE/EIS-0250F-S1. June 2008. Available at http://energy.gov/downloads/final-supplemental-29 environmental-impact-statement-geologic-repository-disposal-spent-2 (accessed 30 5 October 2015). 31 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 32 Operating License Renewal Stage, LaSalle County Station. Chicago, Illinois: Exelon. 33 December 9, 2014. ADAMS Nos. ML14343A883 and ML14343A897. 34 [Exelon] Exelon Generation Company, LLC. 2014b. License Renewal Application, LaSalle 35 County Station, Units 1 and 2. Chicago, Illinois: Exelon. December 9, 2014. 36 ADAMS No. ML14343A849. 37 [Exelon] Exelon Generation Company, LLC. 2015. LaSalle County Station, Units 1 and 2 38 Revised Response to Request for Additional Information (RAI) #TR-09 Re License Renewal 39 Application, Environmental Review. Chicago, Illinois: Exelon. August 28, 2015. ADAMS 40 No. ML15240A002. 41 Griego, NR, Smith JD, Neuhauser KS. 1996. Investigation of RADTRAN Stop Model Input 42 Parameters for Truck Stops. Albuquerque, New Mexico: Sandia National Laboratories. 43 March 13, 1996. ADAMS No. ML14111A188. G-13

Transportation Impacts of High Burnup Fuel 1 [ICRP] International Commission on Radiological Protection. 2007. The 2007 2 Recommendations of the International Commission on Radiological Protection. 3 ICRP Publication 103, Elsevier, Maryland Heights, Missouri. Available at 4 <http://www.sciencedirect.com/science/journal/01466453/37/2-4> (accessed 9 October 2015). 5 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 6 National Research Council. 2006. Health Risks from Exposure to Low Levels of Ionizing 7 Radiation BEIR VII Phase 2. National Academies Press, Washington, DC. Available at 8 <http://www.nap.edu/openbook.php?record_id=11340&page=1> (accessed 9 October 2015). 9 [NCRP] National Council on Radiation Protection and Measurements. 1995. Principles and 10 Applications of Collective Dose in Radiation Protection. NCRP Report No. 121, Bethesda, 11 Maryland. Available at <http://www.ncrppublications.org/Reports/121>. 12 [NCRP] National Council on Radiation Protection and Measurements. 2009. Ionizing Radiation 13 Exposure of the Population of the United States. NCRP Report No. 160, Bethesda, Maryland. 14 Available at <http://app.knovel.com/web/toc.v/cid:kpIREPUS05> (accessed 9 October 2015). 15 [NRC] U.S. Nuclear Regulatory Commission. 1975. Environmental Survey of Transportation of 16 Radioactive Materials to and from Nuclear Power Plants, Supplement 1. Washington, DC: 17 NRC. NUREG-75/038. April 30, 1975. ADAMS No. ML14091A176. 18 [NRC] U.S. Nuclear Regulatory Commission. 1977. Final Environmental Statement on the 19 Transportation of Radioactive Material by Air and Other Modes. Washington, DC: NRC. 20 NUREG-0170, Volume 1. December 31, 1977. ADAMS No. ML12192A283. 21 [NRC] U.S. Nuclear Regulatory Commission. 1999. Generic Environmental Impact Statement 22 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Volume 1, 23 Addendum 1. August 31, 1999. ADAMS No. ML040690720. 24 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 25 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Revision 1, 26 Volumes 1, 2, and 3. June 19, 2013. ADAMS No. ML13107A023. 27 [ORNL] Oak Ridge National Laboratory. 2015. WebTRAGIS, v.6. Transportation Routing 28 Analysis GIS. Available at <https://webtragis.ornl.gov/tragis/app/login> (accessed 29 1 August 2015). 30 Sprung J, Ammerman DJ, Breivik NL, Dukart RJ, Kanipe FL, Koski JA, Mills GS, Neuhauser KS, 31 H.D. Radloff, Weiner RF, and Yoshimura HR. 2000. Reexamination of Spent Fuel Shipment 32 Risk Estimates. Albuquerque, NM: Sandia National Laboratories. NUREG/CR-6672. 33 March 31, 2000. ADAMS No. ML003698324. 34 Weiner RF, Hinojosa D, Heames TJ, and Farnum CO. 2015. RADTRAN 6/RadCat 6 User 35 Guide. G-14

NUREG-1437 Generic Environmental Impact Statement for License Renewal of Nuclear Plants February 2016 Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft

NUREG-1437 Supplement 57 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft Report for Comment Office of Nuclear Reactor Regulation

AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material Non-NRC Reference Material As of November 1999, you may electronically access Documents available from public and special technical NUREG-series publications and other NRC records at libraries include all open literature items, such as books, NRCs Library at www.nrc.gov/reading-rm.html. Publicly journal articles, transactions, Federal Register notices, released records include, to name a few, NUREG-series Federal and State legislation, and congressional reports. publications; Federal Register notices; applicant, Such documents as theses, dissertations, foreign reports licensee, and vendor documents and correspondence; and translations, and non-NRC conference proceedings NRC correspondence and internal memoranda; bulletins may be purchased from their sponsoring organization. and information notices; inspection and investigative reports; licensee event reports; and Commission papers Copies of industry codes and standards used in a and their attachments. substantive manner in the NRC regulatory process are maintained at NRC publications in the NUREG series, NRC regulations, The NRC Technical Library and Title 10, Energy, in the Code of Federal Regulations Two White Flint North may also be purchased from one of these two sources. 11545 Rockville Pike Rockville, MD 20852-2738

1. The Superintendent of Documents U.S. Government Publishing Office These standards are available in the library for reference Mail Stop IDCC use by the public. Codes and standards are usually Washington, DC 20402-0001 copyrighted and may be purchased from the originating Internet: bookstore.gpo.gov organization or, if they are American National Standards, Telephone: (202) 512-1800 from Fax: (202) 512-2104 American National Standards Institute 11 West 42nd Street
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Address: U.S. Nuclear Regulatory Commission The NUREG series comprises (1) technical and adminis-Office of Administration trative reports and books prepared by the staff (NUREG-XXXX) or agency contractors (NUREG/CR-XXXX), (2) Publications Branch proceedings of conferences (NUREG/CP-XXXX), (3) reports Washington, DC 20555-0001 resulting from international agreements (NUREG/IA-XXXX), E-mail: distribution.resource@nrc.gov (4) brochures (NUREG/BR-XXXX), and (5) compilations of Facsimile: (301) 415-2289 legal decisions and orders of the Commission and Atomic and Safety Licensing Boards and of Directors decisions Some publications in the NUREG series that are posted under Section 2.206 of NRCs regulations (NUREG-0750). at NRCs Web site address www.nrc.gov/reading-rm/ DISCLAIMER: This report was prepared as an account doc-collections/nuregs are updated periodically and may of work sponsored by an agency of the U.S. Government. differ from the last printed version. Although references to Neither the U.S. Government nor any agency thereof, nor any employee, makes any warranty, expressed or implied, material found on a Web site bear the date the material or assumes any legal liability or responsibility for any third was accessed, the material available on the date cited partys use, or the results of such use, of any information, may subsequently be removed from the site. apparatus, product, or process disclosed in this publication, or represents that its use by such third party would not infringe privately owned rights.

NUREG-1437 Supplement 57 Generic Environmental Impact Statement for License Renewal of Nuclear Plants Supplement 57 Regarding LaSalle County Station, Units 1 and 2 Draft Report for Comment Manuscript Completed: February 2016 Date Published: February 2016 Office of Nuclear Reactor Regulation

1 Proposed Action Issuance of renewed operating licenses NPF-11 and NPF-18 for LaSalle 2 County Station, Units 1 and 2 (LSCS), in LaSalle County, Illinois 3 Type of Statement Draft Supplemental Environmental Impact Statement 4 Agency Contact Mr. David Drucker 5 U.S. Nuclear Regulatory Commission (NRC) 6 Office of Nuclear Reactor Regulation 7 Mail Stop O-11F1 8 Washington, DC 20555-0001 9 Phone: 1-800-368-5642, extension 6223 10 E-mail: david.drucker@nrc.gov 11 Comments Any interested party may submit comments on this draft supplemental 12 environmental impact statement. Please specify NUREG-1437, 13 Supplement 57, draft, in your comments, and send them by the end of the 14 comment period specified in the Federal Register notice announcing the 15 availability of this report. Comments may be submitted electronically by 16 searching for docket ID NRC-2014-0268 at the Federal rulemaking Web 17 site, http://www.regulations.gov. Comments also may be mailed to the 18 following address: 19 Chief, Rules, Announcements, and Directives Branch 20 Division of Administrative Services 21 Office of Administration 22 Mail Stop: OWFN-12 H08 23 U.S. Nuclear Regulatory Commission 24 Washington, DC 20555-0001 25 Please be aware that any comments that you submit to the NRC will be 26 considered a public record and entered into the Agencywide Documents 27 Access and Management System. Do not provide information you would 28 not want to be publicly available.

1 COVER SHEET 2 Responsible Agency: U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor 3 Regulation. There are no cooperating agencies involved in the preparation of this document. 4 Title: Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 5 Supplement 57, Regarding LaSalle County Station, Units 1 and 2, Draft Report for Comment 6 (NUREG-1437). LaSalle County Station is located in LaSalle County, Illinois. 7 For additional information or copies of this document contact: 8 Division of License Renewal 9 U.S. Nuclear Regulatory Commission 10 Office of Nuclear Reactor Regulation 11 Mail Stop O-11F1 12 11555 Rockville Pike 13 Rockville, Maryland 20852 14 Phone: 1-800-368-5642, extension 6223 15 Email: david.drucker@nrc.gov 16 ABSTRACT 17 This supplemental environmental impact statement (SEIS) has been prepared in response to an 18 application submitted by Exelon Generation Company, LLC (Exelon), to renew the operating 19 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20 years. 20 This SEIS includes the preliminary analysis that evaluates the environmental impacts of the 21 proposed action and alternatives to the proposed action. Alternatives considered include: 22 (1) new nuclear power generation, (2) coal-integrated gasification combined-cycle, (3) natural 23 gas combined-cycle (NGCC), (4) a combination of NGCC, wind, and solar generation, 24 (5) purchased power, and (6) the no-action alternative (i.e., no renewal of the license). 25 The U.S. Nuclear Regulatory Commission (NRC) staffs preliminary recommendation is that the 26 adverse environmental impacts of license renewal for LSCS are not so great that preserving the 27 option of license renewal for energy-planning decisionmakers would be unreasonable. The 28 NRC staff based its recommendation on the following factors: 29

  • the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic Environmental 30 Impact Statement for License Renewal of Nuclear Plants; 31
  • the Environmental Report submitted by Exelon; 32
  • the NRC staffs consultation with Federal, State, local, and Tribal Government 33 agencies; 34
  • the NRC staffs independent environmental review; and 35
  • the NRC staffs consideration of public comments received during the scoping 36 process.

iii

1 TABLE OF CONTENTS 2 ABSTRACT .............................................................................................................................. iii 3 TABLE OF CONTENTS ............................................................................................................ v 4 FIGURES ................................................................................................................................. xv 5 TABLES ................................................................................................................................ xvii 6 EXECUTIVE

SUMMARY

........................................................................................................ xxi 7 ABBREVIATIONS AND ACRONYMS ..................................................................................xxvii 8

1.0 INTRODUCTION

.......................................................................................................... 1-1 9       1.1      Proposed Federal Action.................................................................................. 1-1 10       1.2      Purpose and Need for Proposed Federal Action .............................................. 1-1 11       1.3      Major Environmental Review Milestones .......................................................... 1-1 12       1.4      Generic Environmental Impact Statement ........................................................ 1-2 13       1.5      Supplemental Environmental Impact Statement ............................................... 1-4 14       1.6      Decisions to Be Supported by the SEIS ........................................................... 1-5 15       1.7      Cooperating Agencies ...................................................................................... 1-5 16       1.8      Consultations ................................................................................................... 1-5 17       1.9      Correspondence .............................................................................................. 1-6 18       1.10     Status of Compliance ....................................................................................... 1-6 19       1.11     Related Federal and State Activities ................................................................ 1-6 20       1.12     References ...................................................................................................... 1-7 21 2.0  ALTERNATIVES INCLUDING THE PROPOSED ACTION .......................................... 2-1 22       2.1      Proposed Action .............................................................................................. 2-1 23                2.1.1           Plant Operations during the License Renewal Term......................... 2-1 24                2.1.2           Refurbishment and Other Activities Associated with License 25                                Renewal ........................................................................................... 2-2 26                2.1.3           Termination of Nuclear Power Plant Operations and 27                                Decommissioning after the License Renewal Term .......................... 2-2 28       2.2      Alternatives ...................................................................................................... 2-3 29                2.2.1           No-Action Alternative ....................................................................... 2-3 30                2.2.2           Replacement Power Alternatives ..................................................... 2-4 31                                2.2.2.1            New Nuclear Alternative ................................................ 2-9 32                                2.2.2.2            IGCC Alternative ......................................................... 2-11 33                                2.2.2.3            NGCC Alternative ........................................................ 2-13 34                                2.2.2.4            Combination Alternative (NGCC, Wind, and Solar)...... 2-13 35                                2.2.2.5            Purchased Power Alternative ...................................... 2-16 36       2.3      Alternatives Considered but Dismissed .......................................................... 2-17 37                2.3.1           Energy Conservation and Energy Efficiency .................................. 2-17 38                2.3.2           Solar .............................................................................................. 2-17 v

Table of Contents 1 2.3.3 Wind .............................................................................................. 2-18 2 2.3.3.1 Offshore Wind ............................................................. 2-18 3 2.3.3.2 Wind Power with Storage ............................................ 2-19 4 2.3.3.3 Conclusion .................................................................. 2-19 5 2.3.4 Biomass ......................................................................................... 2-19 6 2.3.5 Hydroelectric .................................................................................. 2-20 7 2.3.6 Wave and Ocean Energy ............................................................... 2-20 8 2.3.7 Fuel Cells ....................................................................................... 2-21 9 2.3.8 Delayed Retirement ....................................................................... 2-21 10 2.3.9 Geothermal .................................................................................... 2-22 11 2.3.10 Municipal Solid Waste .................................................................... 2-22 12 2.3.11 Petroleum ...................................................................................... 2-23 13 2.3.12 Supercritical Pulverized Coal ......................................................... 2-23 14 2.4 Comparison of Alternatives ............................................................................ 2-23 15 2.5 References .................................................................................................... 2-27 16 3.0 AFFECTED ENVIRONMENT ....................................................................................... 3-1 17 3.1 Description of Nuclear Power Plant Facility and Operation .............................. 3-1 18 3.1.1 External Appearance and Setting ..................................................... 3-1 19 3.1.2 Nuclear Reactor Systems................................................................. 3-6 20 3.1.3 Cooling and Auxiliary Water Systems .............................................. 3-6 21 3.1.4 Radioactive Waste Management Systems ..................................... 3-13 22 3.1.4.1 Radioactive Liquid Waste Management ...................... 3-13 23 3.1.4.2 Radioactive Gaseous Waste Management .................. 3-15 24 3.1.4.3 Radioactive Solid Waste Management ........................ 3-16 25 3.1.4.4 Radioactive Waste Storage ......................................... 3-17 26 3.1.4.5 Radiological Environmental Monitoring Program ......... 3-17 27 3.1.5 Nonradioactive Waste Management Systems ................................ 3-18 28 3.1.6 Utility and Transportation Infrastructure.......................................... 3-18 29 3.1.6.1 Electricity ..................................................................... 3-19 30 3.1.6.2 Fuel ............................................................................. 3-19 31 3.1.6.3 Water .......................................................................... 3-19 32 3.1.6.4 Transportation Systems............................................... 3-19 33 3.1.6.5 Power Transmission Systems ..................................... 3-20 34 3.1.7 Nuclear Power Plant Operations and Maintenance ........................ 3-20 35 3.2 Land Use and Visual Resources .................................................................... 3-21 36 3.2.1 Land Use ....................................................................................... 3-21 37 3.2.1.1 Onsite Land Use ......................................................... 3-21 38 3.2.1.2 Coastal Zone ............................................................... 3-22 39 3.2.1.3 Offsite Land Use ......................................................... 3-22 40 3.2.2 Visual Resources ........................................................................... 3-24 41 3.3 Meteorology, Air Quality, and Noise ............................................................... 3-24 vi

Table of Contents 1 3.3.1 Meteorology and Climatology ......................................................... 3-24 2 3.3.2 Air Quality ...................................................................................... 3-25 3 3.3.3 Noise ............................................................................................. 3-28 4 3.4 Geologic Environment .................................................................................... 3-29 5 3.4.1 Physiography and Geology ............................................................ 3-29 6 3.4.2 Soils ............................................................................................... 3-30 7 3.4.3 Seismic Setting .............................................................................. 3-34 8 3.5 Water Resources ........................................................................................... 3-35 9 3.5.1 Surface Water Resources .............................................................. 3-35 10 3.5.1.1 Surface Water Hydrology ............................................ 3-35 11 3.5.1.2 Surface Water Use ...................................................... 3-39 12 3.5.1.3 Surface Water Quality and Effluents ............................ 3-41 13 3.5.2 Groundwater Resources ................................................................ 3-46 14 3.5.2.1 Site Description and Hydrogeology ............................. 3-46 15 3.5.2.2 Groundwater Use ........................................................ 3-48 16 3.5.2.3 Groundwater Quality ................................................... 3-51 17 3.6 Terrestrial Resources ..................................................................................... 3-52 18 3.6.1 LSCS Ecoregion ............................................................................ 3-52 19 3.6.2 LSCS Site Surveys, Studies, and Reports...................................... 3-53 20 3.6.3 LSCS Site ...................................................................................... 3-54 21 3.6.3.1 Vegetation ................................................................... 3-54 22 3.6.3.2 Wildlife ........................................................................ 3-55 23 3.6.4 LSCS Wildlife Management Plan ................................................... 3-55 24 3.6.5 Important Species and Habitats ..................................................... 3-56 25 3.6.5.1 Important Species ....................................................... 3-56 26 3.6.5.2 Important Habitats ....................................................... 3-58 27 3.6.6 Invasive and Non-Native Species................................................... 3-59 28 3.7 Aquatic Resources ......................................................................................... 3-59 29 3.7.1 Illinois River ................................................................................... 3-59 30 3.7.1.1 Aquatic Communities in the Illinois River ..................... 3-60 31 3.7.2 LSCS Cooling Pond ....................................................................... 3-67 32 3.7.2.1 Aquatic Community in the Cooling Pond ..................... 3-68 33 3.7.2.2 Cooling Pond Fish Kill Events...................................... 3-69 34 3.7.3 Important Species and Habitats ..................................................... 3-69 35 3.7.3.1 State-Listed Species ................................................... 3-69 36 3.7.3.2 Important Habitats ....................................................... 3-72 37 3.7.4 Non-Native Species ....................................................................... 3-72 38 3.8 Federally Protected Species and Habitats...................................................... 3-73 39 3.8.1 Action Area .................................................................................... 3-73 40 3.8.2 Federally Protected Species and Habitats Considered................... 3-74 41 3.9 Historic and Cultural Resources ..................................................................... 3-79 vii

Table of Contents 1 3.9.1 Cultural Background....................................................................... 3-80 2 3.9.2 Historic and Cultural Resources ..................................................... 3-82 3 3.10 Socioeconomics ............................................................................................. 3-82 4 3.10.1 Power Plant Employment and Expenditures .................................. 3-83 5 3.10.2 Regional Economic Characteristics ................................................ 3-83 6 3.10.2.1 Employment and Income ............................................. 3-84 7 3.10.2.2 Unemployment ............................................................ 3-86 8 3.10.3 Demographic Characteristics ......................................................... 3-86 9 3.10.3.1 Transient Population ................................................... 3-88 10 3.10.3.2 Migrant Farm Workers ................................................. 3-89 11 3.10.4 Housing and Community Services ................................................. 3-90 12 3.10.4.1 Housing ....................................................................... 3-91 13 3.10.4.2 Education .................................................................... 3-91 14 3.10.4.3 Public Water Supply .................................................... 3-91 15 3.10.5 Tax Revenues ................................................................................ 3-93 16 3.10.6 Local Transportation ...................................................................... 3-95 17 3.11 Human Health ................................................................................................ 3-96 18 3.11.1 Radiological Exposure and Risk ..................................................... 3-96 19 3.11.2 Chemical Hazards .......................................................................... 3-97 20 3.11.3 Microbiological Hazards ................................................................. 3-97 21 3.11.3.1 Thermophilic Microorganisms of Concern ................... 3-98 22 3.11.3.2 Prevalence of Waterborne Diseases Associated 23 with Recreational Waters............................................. 3-99 24 3.11.4 Electromagnetic Fields ................................................................... 3-99 25 3.11.5 Other Hazards.............................................................................. 3-100 26 3.12 Environmental Justice .................................................................................. 3-101 27 3.12.1 Minority Population ...................................................................... 3-102 28 3.12.2 Low-Income Population................................................................ 3-102 29 3.13 Waste Management and Pollution Prevention.............................................. 3-106 30 3.13.1 Radioactive Waste ....................................................................... 3-106 31 3.13.2 Nonradioactive Waste .................................................................. 3-106 32 3.14 References .................................................................................................. 3-106 33 4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS ........................ 4-1 34 4.1 Introduction ...................................................................................................... 4-1 35 4.2 Land Use and Visual Resources ...................................................................... 4-1 36 4.2.1 Proposed Action............................................................................... 4-1 37 4.2.2 No-Action Alternative ....................................................................... 4-2 38 4.2.2.1 Land Use ....................................................................... 4-2 39 4.2.2.2 Visual Resources .......................................................... 4-2 40 4.2.3 New Nuclear Alternative ................................................................... 4-3 41 4.2.3.1 Land Use ....................................................................... 4-3 viii

Table of Contents 1 4.2.3.2 Visual Resources .......................................................... 4-3 2 4.2.4 IGCC Alternative .............................................................................. 4-3 3 4.2.4.1 Land Use ....................................................................... 4-3 4 4.2.4.2 Visual Resources .......................................................... 4-4 5 4.2.5 Natural Gas Combined-Cycle Alternative ......................................... 4-4 6 4.2.5.1 Land Use ....................................................................... 4-4 7 4.2.5.2 Visual Resources .......................................................... 4-4 8 4.2.6 Combination Alternative (NGCC, Wind, Solar) ................................. 4-5 9 4.2.6.1 Land Use ....................................................................... 4-5 10 4.2.6.2 Visual Resources .......................................................... 4-5 11 4.2.7 Purchased Power Alternative ........................................................... 4-6 12 4.2.7.1 Land Use ....................................................................... 4-6 13 4.2.7.2 Visual Resources .......................................................... 4-6 14 4.3 Air Quality and Noise ....................................................................................... 4-6 15 4.3.1 Proposed Action............................................................................... 4-6 16 4.3.1.1 Air Quality ..................................................................... 4-6 17 4.3.1.2 Noise ............................................................................. 4-7 18 4.3.2 No-Action Alternative ....................................................................... 4-7 19 4.3.2.1 Air Quality ..................................................................... 4-7 20 4.3.2.2 Noise ............................................................................. 4-7 21 4.3.3 New Nuclear Alternative ................................................................... 4-7 22 4.3.3.1 Air Quality ..................................................................... 4-7 23 4.3.3.2 Noise ............................................................................. 4-9 24 4.3.4 IGCC Alternative ............................................................................ 4-10 25 4.3.4.1 Air Quality ................................................................... 4-10 26 4.3.4.2 Noise ........................................................................... 4-13 27 4.3.5 NGCC Alternative .......................................................................... 4-13 28 4.3.5.1 Air Quality ................................................................... 4-13 29 4.3.5.2 Noise ........................................................................... 4-15 30 4.3.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-16 31 4.3.6.1 Air Quality ................................................................... 4-16 32 4.3.6.2 Noise ........................................................................... 4-18 33 4.3.7 Purchased Power Alternative ......................................................... 4-19 34 4.3.7.1 Air Quality ................................................................... 4-19 35 4.3.7.2 Noise ........................................................................... 4-19 36 4.4 Geologic Environment .................................................................................... 4-20 37 4.4.1 Proposed Action............................................................................. 4-20 38 4.4.2 No-Action Alternative ..................................................................... 4-20 39 4.4.3 New Nuclear Alternative ................................................................. 4-20 40 4.4.4 IGCC Alternative ............................................................................ 4-21 41 4.4.5 NGCC Alternative .......................................................................... 4-21 ix

Table of Contents 1 4.4.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-21 2 4.4.7 Purchased Power Alternative ......................................................... 4-21 3 4.5 Water Resources ........................................................................................... 4-21 4 4.5.1 Proposed Action............................................................................. 4-22 5 4.5.1.1 Surface Water Resources ........................................... 4-22 6 4.5.1.2 Groundwater Resources.............................................. 4-24 7 4.5.2 No-Action Alternative ..................................................................... 4-26 8 4.5.2.1 Surface Water Resources ........................................... 4-26 9 4.5.2.2 Groundwater Resources.............................................. 4-26 10 4.5.3 New Nuclear Alternative ................................................................. 4-26 11 4.5.3.1 Surface Water Resources ........................................... 4-26 12 4.5.3.2 Groundwater Resources.............................................. 4-27 13 4.5.4 IGCC Alternative ............................................................................ 4-27 14 4.5.4.1 Surface Water Resources ........................................... 4-27 15 4.5.4.2 Groundwater Resources.............................................. 4-28 16 4.5.5 NGCC Alternative .......................................................................... 4-28 17 4.5.5.1 Surface Water Resources ........................................... 4-28 18 4.5.5.2 Groundwater Resources.............................................. 4-29 19 4.5.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-29 20 4.5.6.1 Surface Water Resources ........................................... 4-29 21 4.5.6.2 Groundwater Resources.............................................. 4-30 22 4.5.7 Purchased Power Alternative ......................................................... 4-30 23 4.5.7.1 Surface Water Resources ........................................... 4-30 24 4.5.7.2 Groundwater Resources.............................................. 4-30 25 4.6 Terrestrial Resources ..................................................................................... 4-30 26 4.6.1 Proposed Action............................................................................. 4-31 27 4.6.1.1 Generic GEIS Issues ................................................... 4-31 28 4.6.1.2 Effects on Terrestrial Resources (Non-Cooling 29 System Impacts) ......................................................... 4-31 30 4.6.1.3 Water Use Conflicts with Terrestrial Resources ........... 4-33 31 4.6.2 No-Action Alternative ..................................................................... 4-34 32 4.6.3 New Nuclear Alternative ................................................................. 4-34 33 4.6.4 IGCC Alternative ............................................................................ 4-35 34 4.6.5 NGCC Alternative .......................................................................... 4-35 35 4.6.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-36 36 4.6.7 Purchased Power Alternative ......................................................... 4-37 37 4.7 Aquatic Resources ......................................................................................... 4-37 38 4.7.1 Proposed Action............................................................................. 4-37 39 4.7.1.1 GEIS Category 1 Issues .............................................. 4-38 40 4.7.1.2 Impingement and Entrainment of Aquatic 41 Organisms ................................................................... 4-38 x

Table of Contents 1 4.7.1.3 Thermal Impacts on Aquatic Organisms ...................... 4-45 2 4.7.1.4 Water Use Conflicts with Aquatic Resources ............... 4-52 3 4.7.2 No-Action Alternative ..................................................................... 4-52 4 4.7.3 New Nuclear Alternative ................................................................. 4-53 5 4.7.4 IGCC Alternative ............................................................................ 4-53 6 4.7.5 NGCC Alternative .......................................................................... 4-54 7 4.7.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-54 8 4.7.7 Purchased Power Alternative ......................................................... 4-54 9 4.8 Special Status Species and Habitats.............................................................. 4-55 10 4.8.1 Proposed Action............................................................................. 4-55 11 4.8.2 No-Action Alternative ..................................................................... 4-57 12 4.8.3 New Nuclear Alternative ................................................................. 4-57 13 4.8.4 IGCC Alternative ............................................................................ 4-58 14 4.8.5 NGCC Alternative .......................................................................... 4-58 15 4.8.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-59 16 4.8.7 Purchased Power Alternative ......................................................... 4-59 17 4.9 Historic and Cultural Resources ..................................................................... 4-59 18 4.9.1 Proposed Action............................................................................. 4-60 19 4.9.2 No-Action Alternative ..................................................................... 4-62 20 4.9.3 New Nuclear Alternative ................................................................. 4-62 21 4.9.4 IGCC Alternative ............................................................................ 4-62 22 4.9.5 NGCC Alternative .......................................................................... 4-63 23 4.9.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-63 24 4.9.7 Purchased Power Alternative ......................................................... 4-64 25 4.10 Socioeconomics ............................................................................................. 4-64 26 4.10.1 Proposed Action............................................................................. 4-65 27 4.10.2 No-Action Alternative ..................................................................... 4-65 28 4.10.2.1 Socioeconomics .......................................................... 4-65 29 4.10.2.2 Transportation ............................................................. 4-66 30 4.10.3 New Nuclear Alternative ................................................................. 4-66 31 4.10.3.1 Socioeconomics .......................................................... 4-66 32 4.10.3.2 Transportation ............................................................. 4-67 33 4.10.4 IGCC Alternative ............................................................................ 4-67 34 4.10.4.1 Socioeconomics .......................................................... 4-67 35 4.10.4.2 Transportation ............................................................. 4-68 36 4.10.5 NGCC Alternative .......................................................................... 4-69 37 4.10.5.1 Socioeconomics .......................................................... 4-69 38 4.10.5.2 Transportation ............................................................. 4-69 39 4.10.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-70 40 4.10.6.1 Socioeconomics .......................................................... 4-70 41 4.10.6.2 Transportation ............................................................. 4-71 xi

Table of Contents 1 4.10.7 Purchased Power Alternative ......................................................... 4-71 2 4.10.7.1 Socioeconomics .......................................................... 4-71 3 4.10.7.2 Transportation ............................................................. 4-71 4 4.11 Human Health ................................................................................................ 4-72 5 4.11.1 Proposed Action............................................................................. 4-72 6 4.11.1.1 Normal Operating Conditions ...................................... 4-72 7 4.11.1.2 Environmental Impacts of Postulated Accidents .......... 4-75 8 4.11.2 No-Action Alternative ..................................................................... 4-88 9 4.11.3 New Nuclear Alternative ................................................................. 4-89 10 4.11.4 IGCC Alternative ............................................................................ 4-89 11 4.11.5 NGCC Alternative .......................................................................... 4-90 12 4.11.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-90 13 4.11.7 Purchased Power Alternative ......................................................... 4-90 14 4.12 Environmental Justice .................................................................................... 4-91 15 4.12.1 Proposed Action............................................................................. 4-91 16 4.12.2 No-Action Alternative ..................................................................... 4-93 17 4.12.3 New Nuclear Alternative ................................................................. 4-93 18 4.12.4 IGCC Alternative ............................................................................ 4-94 19 4.12.5 NGCC Alternative .......................................................................... 4-95 20 4.12.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-95 21 4.12.7 Purchased Power Alternative ......................................................... 4-96 22 4.13 Waste Management ....................................................................................... 4-97 23 4.13.1 Proposed Action............................................................................. 4-97 24 4.13.2 No-Action Alternative ..................................................................... 4-98 25 4.13.3 New Nuclear Alternative ................................................................. 4-98 26 4.13.4 IGCC Alternative ............................................................................ 4-98 27 4.13.5 NGCC Alternative .......................................................................... 4-99 28 4.13.6 Combination Alternative (NGCC, Wind, Solar) ............................... 4-99 29 4.13.7 Purchased Power Alternative ......................................................... 4-99 30 4.14 Evaluation of New and Potentially Significant Information .............................. 4-99 31 4.15 Impacts Common to All Alternatives............................................................. 4-100 32 4.15.1 Fuel Cycles .................................................................................. 4-100 33 4.15.1.1 Uranium Fuel Cycle ................................................... 4-101 34 4.15.1.2 Replacement Power Plant Fuel Cycles...................... 4-102 35 4.15.2 Terminating Power Plant Operations and Decommissioning ........ 4-102 36 4.15.2.1 Existing Nuclear Power Plant .................................... 4-103 37 4.15.2.2 Replacement Power Plants ....................................... 4-103 38 4.15.3 Greenhouse Gas Emissions and Climate Change ....................... 4-104 39 4.15.3.1 Greenhouse Gas Emissions from the Proposed 40 Project and Alternatives............................................. 4-104 41 4.15.3.2 Climate Change Impacts to Resource Areas ............. 4-107 xii

Table of Contents 1 4.16 Cumulative Impacts of the Proposed Action ................................................. 4-113 2 4.16.1 Air Quality and Noise ................................................................... 4-113 3 4.16.1.1 Air Quality ................................................................. 4-114 4 4.16.1.2 Noise ......................................................................... 4-115 5 4.16.2 Geology and Soils ........................................................................ 4-115 6 4.16.3 Water Resources ......................................................................... 4-116 7 4.16.3.1 Surface Water Resources ......................................... 4-116 8 4.16.3.2 Groundwater Resources............................................ 4-120 9 4.16.4 Terrestrial Resources ................................................................... 4-121 10 4.16.5 Aquatic Resources ....................................................................... 4-124 11 4.16.5.1 Energy Development ................................................. 4-124 12 4.16.5.2 Future Urbanization and Transportation 13 Development ............................................................. 4-125 14 4.16.5.3 Wildlife Preserves, Parks, and Recreational Areas .... 4-125 15 4.16.5.4 Illinois Wildlife Conservation Plan .............................. 4-125 16 4.16.5.5 Conclusion ................................................................ 4-125 17 4.16.6 Historic and Cultural Resources ................................................... 4-126 18 4.16.7 Socioeconomics ........................................................................... 4-126 19 4.16.8 Human Health .............................................................................. 4-127 20 4.16.9 Environmental Justice .................................................................. 4-127 21 4.16.10 Waste Management ..................................................................... 4-128 22 4.16.11 Global Climate Change ................................................................ 4-129 23 4.16.12 Summary of Cumulative Impacts.................................................. 4-130 24 4.17 Resource Commitments............................................................................... 4-132 25 4.17.1 Unavoidable Adverse Environmental Impacts .............................. 4-132 26 4.17.2 Short-Term Versus Long-Term Productivity ................................. 4-133 27 4.17.3 Irreversible and Irretrievable Commitments of Resources ............ 4-133 28 4.18 References .................................................................................................. 4-134 29

5.0 CONCLUSION

............................................................................................................. 5-1 30      5.1   Environmental Impacts of License Renewal ..................................................... 5-1 31      5.2   Comparison of Alternatives .............................................................................. 5-1 32      5.3   Recommendation ............................................................................................. 5-1 33 6.0 LIST OF PREPARERS ................................................................................................ 6-1 34 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES 35      OF THIS SEIS ARE SENT .......................................................................................... 7-1 36 8.0 INDEX .......................................................................................................................... 8-1 37 APPENDIX A    COMMENTS RECEIVED ON THE LSCS ENVIRONMENTAL REVIEW ...... A-1 38 APPENDIX B    APPLICABLE LAWS, REGULATIONS, AND OTHER 39               REQUIREMENTS ......................................................................................... B-1 40 APPENDIX C    CONSULTATION CORRESPONDENCE ..................................................... C-1 xiii

Table of Contents 1 APPENDIX D CHRONOLOGY OF ENVIRONMENTAL REVIEW 2 CORRESPONDENCE .................................................................................. D-1 3 APPENDIX E PROJECTS AND ACTIONS CONSIDERED IN CUMULATIVE IMPACTS 4 ANALYSIS.................................................................................................... E-1 5 APPENDIX F U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 6 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR 7 LASALLE COUNTY STATION, UNITS 1 AND 2, IN SUPPORT OF 8 LICENSE RENEWAL APPLICATION REVIEW............................................ F-1 9 APPENDIX G TRANSPORTATION IMPACTS OF LSCS HIGH BURNUP FUEL ................G-1 xiv

1 FIGURES 2 Figure 1-1. Environmental Review Process........................................................................ 1-2 3 Figure 1-2. Environmental Issues Evaluated for License Renewal ..................................... 1-4 4 Figure 2-1. Territories of MISO and PJM Interconnection................................................... 2-6 5 Figure 3-1. LSCS 50-mi (80-km) Radius Map .................................................................... 3-2 6 Figure 3-2. LSCS 6-mi (10-km) Radius Map ...................................................................... 3-3 7 Figure 3-3. LSCS Site Layout............................................................................................. 3-4 8 Figure 3-4. LSCS Plant Features ....................................................................................... 3-5 9 Figure 3-5. Closed-Cycle Cooling System with Cooling Pond ............................................ 3-7 10 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities ...................................... 3-9 11 Figure 3-7. Site Physiography, LSCS Vicinity ................................................................... 3-31 12 Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity ...................................... 3-32 13 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity ................................ 3-33 14 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries ..................... 3-37 15 Figure 3-11. LSCS Surface Water and Related Water Resource Features ........................ 3-38 16 Figure 3-12. LSCS Site Hydrogeologic Units...................................................................... 3-47 17 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill .................................... 3-49 18 Figure 3-14. LSCS Hydrogeologic Cross-Section............................................................... 3-50 19 Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure........... 3-62 20 Figure 3-16. Sampling Locations in LSCS Aquatic Surveys ............................................... 3-63 21 Figure 3-17. Minority Block Groups within a 50-mi (80-km) Radius of LSCS .................... 3-104 22 Figure 3-18. Low-Income Block Groups within a 50-mi (80-km) Radius of LSCS ............. 3-105 23 Figure G-1. Illustration of Truck Stop Model ....................................................................... G-6 xv

1 TABLES 2 Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 3 License Renewal............................................................................................. xxiii 4 Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 5 Considered in Depth ........................................................................................ 2-8 6 Table 2-2. Summary of Environmental Impacts of Proposed Action and 7 Alternatives .................................................................................................... 2-25 8 Table 3-1. LSCS Site Land Uses by Area ....................................................................... 3-21 9 Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS ........................................... 3-23 10 Table 3-3. National Ambient Air Quality Standards ......................................................... 3-26 11 Table 3-4. LSCS Air Emissions (MT/year)....................................................................... 3-27 12 Table 3-5. Common Noise Sources and Noise Levels .................................................... 3-28 13 Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, 14 LSCS ............................................................................................................. 3-40 15 Table 3-7. National Pollutant Discharge Elimination System-Permitted Outfalls, 16 LSCS ............................................................................................................. 3-43 17 Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion............................... 3-52 18 Table 3-9. State-Listed Species in LaSalle County ......................................................... 3-56 19 Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River ............ 3-65 20 Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural 21 History Electrofishing Surveys from 1957 through 2009 ................................. 3-67 22 Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 ................................... 3-68 23 Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle 24 County ........................................................................................................... 3-70 25 Table 3-14. Federally Listed Species and Designated Habitat in La Salle County, 26 Illinois............................................................................................................. 3-75 27 Table 3-15. LSCS Employees Residence by County ........................................................ 3-83 28 Table 3-16. Employment by Industry in the LSCS ROI (2014, 1-year estimates and 29 2009-2013, 5-year estimates) ........................................................................ 3-84 30 Table 3-17. Major Employers in LaSalle County in 2009 ................................................... 3-85 31 Table 3-18. Estimated Income Information for the LSCS ROI (2014 estimates, 32 unless otherwise indicated) ............................................................................ 3-85 33 Table 3-19. Population and Percent Growth in LSCS ROI Counties 1980-2010, 34 2014 (estimated), and Projected for 2020-2060 ............................................ 3-86 35 Table 3-20. Demographic Profile of the Population in the LSCS ROI in 2010 ................... 3-87 36 Table 3-21. 2014 LSCS ROI Demographic Profile (2013 for Grundy County) ................... 3-87 37 Table 3-22. 2013 Estimated Seasonal Housing in Counties within 50 mi (80 km) of 38 LSCS ............................................................................................................. 3-88 39 Table 3-23. Migrant Farm Workers and Temporary Farm Labor in Counties Located 40 within 50 mi (80 km) of LSCS (2012).............................................................. 3-90 41 Table 3-24. Housing in the LSCS ROI (2014 estimate) ..................................................... 3-91 42 Table 3-25. Local Public Water Supply Systems ............................................................... 3-92 xvii

1 Table 3-26. LSCS Power Block Tax Payments and Valuations 2007-2014 (in 2 dollars) ........................................................................................................... 3-93 3 Table 3-27. 2013 LSCS Tax Payments to Taxing Entities as a Percentage of Total 4 Levy ............................................................................................................... 3-94 5 Table 3-28. Annual Payments to Illinois Emergency Management Agency 2009-6 2014............................................................................................................... 3-95 7 Table 3-29. Major Commuting Routes in the Vicinity of LSCS: 2013-2014 Average 8 Annual Daily Traffic Count ............................................................................. 3-95 9 Table 4-1. Land Use and Visual Resource Issues............................................................. 4-2 10 Table 4-2. Air Quality and Noise ....................................................................................... 4-7 11 Table 4-3. Geology and Soils Issues............................................................................... 4-20 12 Table 4-4. Surface Water Resources Issues ................................................................... 4-22 13 Table 4-5. Groundwater Issues ....................................................................................... 4-24 14 Table 4-6. Terrestrial Resource Issues ........................................................................... 4-31 15 Table 4-7. Aquatic Resource Issues ............................................................................... 4-37 16 Table 4-8. Special Status Species and Habitat Issues .................................................... 4-55 17 Table 4-9. Federally Listed Species and Designated Habitat in LaSalle County, 18 Illinois, and NRC Effect Determinations for Proposed LSCS License 19 Renewal ......................................................................................................... 4-56 20 Table 4-10. Historic and Cultural Resources Issue ........................................................... 4-60 21 Table 4-11. Socioeconomic NEPA Issues Affected by License Renewal .......................... 4-65 22 Table 4-12. Human Health Issues ..................................................................................... 4-72 23 Table 4-13. Issues Related to Postulated Accidents ......................................................... 4-76 24 Table 4-14. LSCS CDF for Internal Events ....................................................................... 4-79 25 Table 4-15. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 26 for Internal Events .......................................................................................... 4-81 27 Table 4-16. LSCS Potentially Cost-Beneficial SAMAs ...................................................... 4-84 28 Table 4-17. Environmental Justice NEPA Issue ................................................................ 4-91 29 Table 4-18. Waste Management Issues ............................................................................ 4-97 30 Table 4-19. Issues Related to the Uranium Fuel Cycle ................................................... 4-101 31 Table 4-20. Issues Related to Decommissioning ............................................................ 4-103 32 Table 4-21. Estimated GHG Emissions from Operations at LSCS (MT/yr of CO2e)......... 4-105 33 Table 4-22. Direct GHG Emissions from Operation of the Proposed Action and 34 Alternatives .................................................................................................. 4-107 35 Table 4-23. Comparison of GHG Emission Inventories ................................................... 4-130 36 Table 4-24. Summary of Cumulative Impacts on Resource Areas .................................. 4-131 37 Table 6-1. List of Preparers .............................................................................................. 6-1 38 Table B-1. Federal and State Requirements ..................................................................... B-2 39 Table B-2. Licenses and Permits ....................................................................................... B-7 40 Table C-1. ESA Section 7 Consultation Correspondence ..................................................C-2 41 Table C-2. NHPA Correspondence....................................................................................C-3 42 Table D-1. Environmental Review Correspondence ..........................................................D-1 43 Table E-1. Projects and Actions Considered in Cumulative Impact Analysis ..................... E-1

Tables 1 Table F-1. LaSalle County Station CDF for Internal Events ............................................... F-3 2 Table F-2. Base Case Mean Population Dose Risk and Offsite Economic Cost Risk 3 for Internal Events ............................................................................................ F-4 4 Table F-3. Summary of Major PRA Models and Corresponding CDF and LERF 5 Results............................................................................................................. F-7 6 Table F-4. Dominant LSCS Contributors to Seismic CDF ............................................... F-12 7 Table F-5(a). Dominant LSCS Unit 1 Fire Zone Contributors to Fire CDF of 8.9x10-6 8 per year ......................................................................................................... F-14 9 Table F-5(b). Dominant LSCS Unit 2 Fire Zone Contributors to Fire CDF of 9.4x10-6 10 per year ......................................................................................................... F-14 11 Table F-6. SAMA Cost-Benefit Screening Analysis for LSCS Station .............................. F-33 12 Table G-1. Transportation Route Information for Shipments from LSCS to the 13 Proposed Yucca Mountain Repository Site ..................................................... G-4 14 Table G-2. RADTRAN 6.02 Normal (Incident-Free) Exposure Parameters ....................... G-5 15 Table G-3. Annual Normal (Incident-Free) Radiation Doses to Transport Workers 16 and the Public from Shipping Spent Fuel from LSCS to the Proposed 17 Yucca Mountain Repository Site, Normalized to Reference 18 LWR (880 MWe (net)) ..................................................................................... G-6 19 Table G-4. Radionuclide Inventories Used in Transportation Accident Risk 20 Calculations for the LSCS Reactors ...............................................................G-10 21 Table G-5. Annual Spent Fuel Transportation Accident Impacts from Shipping 22 Spent Fuel from LSCS to the Proposed Yucca Mountain Repository 23 Site, Normalized to Reference LWR Reactor (880 MWe (net)).......................G-11 xix

1 EXECUTIVE

SUMMARY

2 BACKGROUND 3 By letter dated December 9, 2014, Exelon Generation Company, LLC (Exelon) submitted an 4 application to the U.S. Nuclear Regulatory Commission (NRC) to issue renewed operating 5 licenses for LaSalle County Station, Units 1 and 2 (LSCS) for an additional 20-year period. 6 Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 51.20(b)(2), the renewal of a 7 power reactor operating license requires preparation of an environmental impact statement 8 (EIS) or a supplement to an existing EIS. In addition, 10 CFR 51.95(c) states that, in connection 9 with the renewal of an operating license, the NRC shall prepare an EIS, which is a supplement 10 to the Commissions NUREG-1437, Generic Environmental Impact Statement (GEIS) for 11 License Renewal of Nuclear Plants. 12 Upon acceptance of Exelons application, the NRC staff began the environmental review 13 process described in 10 CFR Part 51 by publishing a Notice of Intent to prepare a supplemental 14 environmental impact statement (SEIS) and to conduct scoping. In preparation of this SEIS for 15 LSCS, the NRC staff performed the following: 16

  • conducted public scoping meetings on March 10, 2015, in Ottawa, Illinois; 17
  • conducted a site audit at LSCS from May 5-7, 2015; 18
  • reviewed Exelons Environmental Report (ER) and compared it to the GEIS; 19
  • consulted with Federal, State, Tribal, and local agencies; 20
  • conducted a review of the issues following the guidance set forth in 21 Standard Review Plans for Environmental Reviews for Nuclear Power Plants:

22 Environmental Standard Review Plan for Operating License Renewal (NUREG-1555 23 Supplement 1, Revision 1, Final Report); and 24

  • considered public comments received during the scoping process.

25 PROPOSED ACTION 26 Exelon initiated the proposed Federal action (i.e., issuance of renewed power reactor operating 27 licenses) by submitting an application for license renewal of LSCS for which the existing 28 licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023. The NRCs 29 Federal action is to decide whether to renew the licenses for an additional 20 years. The 30 regulation at 10 CFR 2.109 states that, if a licensee of a nuclear power plant files an application 31 to renew an operating license at least 5 years before the expiration date of that license, the 32 existing license will not be deemed to have expired until the safety and environmental reviews 33 are completed and until the NRC has made a final decision on whether to issue a renewed 34 license for the additional 20 years. 35 PURPOSE AND NEED FOR ACTION 36 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 37 option that allows for power generation capability beyond the term of the current nuclear power 38 plant operating licenses to meet future system generating needs. Such needs may be 39 determined by other energy-planning decisionmakers, such as states, operators, and, where 40 authorized, Federal agencies (other than the NRC). This definition of purpose and need reflects xxi

Executive Summary 1 the NRCs recognition that, unless there are findings in the safety review required by the Atomic 2 Energy Act of 1954, as amended, or findings in the National Environmental Policy Act of 1969, 3 as amended, environmental analysis that would lead the NRC to reject a license renewal 4 application, the NRC does not have a role in the energy-planning decisions as to whether a 5 particular nuclear power plant should continue to operate. 6 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL 7 The SEIS evaluates the potential environmental impacts of the proposed action. The 8 environmental impacts from the proposed action are designated as SMALL, MODERATE, or 9 LARGE. As established in the GEIS, Category 1 issues are those that meet all of the following 10 criteria: 11

  • The environmental impacts associated with the issue SMALL: Environmental 12 are determined to apply either to all plants or, for some effects are not detectable or 13 issues, to plants having a specific type of cooling are so minor that they will 14 system or other specified plant or site characteristics. neither destabilize nor noticeably alter any important 15
  • A single significance level (i.e., SMALL, MODERATE, attribute of the resource.

16 or LARGE) has been assigned to the impacts except MODERATE: 17 for collective offsite radiological impacts from the fuel Environmental effects are 18 cycle and from high-level waste and spent fuel sufficient to alter noticeably, but not to destabilize, 19 disposal. important attributes of the 20

  • Mitigation of adverse impacts associated with the issue resource.

21 is considered in the analysis, and it has been LARGE: Environmental 22 determined that additional plant-specific mitigation effects are clearly noticeable and are sufficient to 23 measures are likely not to be sufficiently beneficial to destabilize important 24 warrant implementation. attributes of the resource. 25 For Category 1 issues, no additional site-specific analysis is 26 required in this SEIS unless new and significant information is identified. Chapter 4 of this SEIS 27 presents the process for identifying new and significant information. Site-specific issues 28 (Category 2) are those that do not meet one or more of the criteria for Category 1 issues; 29 therefore, an additional site-specific review for these non-generic issues is required, and the 30 results are documented in the SEIS. 31 Neither Exelon nor the NRC identified information that is both new and significant related to 32 Category 1 issues that would call into question the conclusions in the GEIS. This conclusion is 33 supported by the NRC staffs review of the applicants ER and other documentation relevant to 34 the applicants activities, the public scoping process, and the findings from the environmental 35 site audit conducted by the NRC staff. Therefore, the NRC staff relied upon the conclusions of 36 the GEIS for all Category 1 issues applicable to LSCS. 37 The NRC staff did find new information regarding the Category 1 a uranium fuel cycle issue 38 (Transportation), but this new information was not considered significant and therefore did not 39 affect the conclusions for these issues presented in the GEIS. This new information is 40 discussed in Section 4.15.1 and Appendix G of this SEIS. 41 Table ES-1 summarizes the Category 2 issues relevant to LSCS and the NRC staffs findings 42 related to those issues. If the NRC staff determined that there were no Category 2 issues 43 applicable for a particular resource area, the findings of the GEIS, as documented in 44 Appendix B to Subpart A of 10 CFR Part 51, are incorporated for that resource area. xxii

Executive Summary 1 Table ES-1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 2 License Renewal Resource Area Relevant Category 2 Issues Impacts Surface Water Resources Surface water use conflicts SMALL Groundwater Resources Groundwater Use Conflicts SMALL Groundwater Quality Degradation SMALL Radionuclides released to groundwater SMALL Terrestrial Resources Effects on terrestrial resources (non-cooling SMALL system impacts) Water use conflicts with terrestrial resources SMALL Aquatic Resources Impingement and entrainment of aquatic SMALL organisms Thermal impacts on aquatic organisms SMALL to MODERATE(a) Water use conflicts with aquatic resources SMALL Special Status Species and Threatened, endangered, and species and No effect (b) Habitats essential fish habitat Historic and Cultural Historic and cultural resources No adverse effect (c) Resources Human Health Microbiological hazards to the public SMALL Electric shock hazards SMALL Environmental Justice Minority and low-income populations See note below (d) Cumulative Impacts Terrestrial Ecology MODERATE to LARGE Aquatic Resources MODERATE Socioeconomic See note below (e) Environmental Justice See note below (d) Global Climate Change MODERATE All other resource areas SMALL (a) Thermal impacts would be SMALL for all aquatic resources in the Illinois River and SMALL for aquatic resources in the cooling pond, except for gizzard shad and threadfin shad. Gizzard shad and threadfin shad would experience MODERATE thermal impacts in the cooling pond. (b) For Federally protected species, the NRC reports the effects from continued operation of LSCS during the license renewal period in terms of its Endangered Species Act of 1973, as amended, findings of no effect, may effect, but not likely to adversely effect, or may affect, and is likely to adversely affect. (c) The National Historic Preservation Act of 1966, as amended, requires Federal agencies to consider the effects of their undertakings on historic properties. (d) There would be no disproportionately high and adverse impacts to minority and low-income populations. (e) The contributory effects from the continued operation of LSCS during the license renewal period would have no new or increased impact on socioeconomic conditions beyond what is currently being experienced. 3 SEVERE ACCIDENT MITIGATION ALTERNATIVES 4 Since severe accident mitigation alternatives (SAMAs) have not been previously considered in 5 an environmental impact statement or environmental assessment for LSCS, xxiii

Executive Summary 1 10 CFR 51.53(c)(3)(ii)(L) requires Exelon to submit, with the ER, a consideration of alternatives 2 to mitigate severe accidents. SAMAs are potential ways to reduce the risk or potential impacts 3 of uncommon, but potentially severe accidents. SAMAs may include changes to plant 4 components, systems, procedures, and training. 5 The NRC staff reviewed Exelons ER evaluation of potential SAMAs and concluded that none of 6 the potentially cost-beneficial SAMAs relate to adequately managing the effects of aging during 7 the extended period of operation. Therefore, the potentially cost-beneficial SAMAs identified 8 need not be implemented as part of the license renewal, pursuant to 10 CFR Part 54. 9 ALTERNATIVES 10 The NRC staff considered the environmental impacts associated with alternatives to license 11 renewal. These alternatives include other methods of power generation, as well as not 12 renewing the LSCS operating licenses (the no-action alternative). The NRC staff considered 13 the following feasible and commercially viable replacement power alternatives: 14

  • new nuclear power; 15
  • coal-integrated gasification combined-cycle; 16
  • natural gas combined-cycle (NGCC); and 17
  • combination alternative (NGCC, wind, and solar power), and 18
  • purchased power.

19 The NRC staff initially considered a number of additional alternatives for analysis as alternatives 20 to the license renewal of LSCS. The NRC staff later dismissed these alternatives because of 21 technical, resource availability, or commercial limitations that currently exist and that the NRC 22 staff believes are likely to continue to exist when the current LSCS licenses expire. The 23 no-action alternative and the effects it would have were also considered by the NRC staff. 24 Where possible, the NRC staff evaluated potential environmental impacts for these alternatives 25 located at both the LSCS site and some other unspecified alternate location. The NRC staff 26 considered the following alternatives, but dismissed them: 27

  • energy conservation and energy efficiency, 28
  • solar power, 29
  • wind power, 30
  • biomass, 31
  • hydroelectric power, 32
  • wave and ocean energy, 33
  • fuel cells, 34
  • delayed retirement, 35
  • geothermal power, 36
  • municipal solid waste, 37
  • oil-fired power, and 38
  • supercritical pulverized coal.

xxiv

Executive Summary 1 The NRC staff evaluated each alternative using the same resource areas that were used in 2 evaluating impacts from license renewal. 3 PRELIMINARY RECOMMENDATION 4 The NRC staffs preliminary recommendation is that the adverse environmental impacts of 5 license renewal for LSCS are not so great that preserving the option of license renewal for 6 energy-planning decisionmakers would be unreasonable. The NRC staff based its 7 recommendation on the following: 8

  • the analyses and findings in the GEIS; 9
  • the ER submitted by Exelon; 10
  • the NRC staffs consultation with Federal, State, local, and Tribal Government 11 agencies; 12
  • the NRC staffs independent environmental review; and 13
  • the NRC staffs consideration of public comments received during the scoping 14 process.

xxv

Abbreviations and Acronyms 1 ABBREVIATIONS AND ACRONYMS 2 ac acre(s) 3 AC alternating current 4 ACC averted cleanup and decontamination costs 5 ACHP Advisory Council on Historic Preservation 6 ADAMS Agencywide Documents Access and Management System 7 AEA Atomic Energy Act of 1954 (as amended) 8 AFW auxiliary feedwater 9 AMSAC ATWS mitigating system actuation circuitry 10 ANL Argonne National Laboratory 11 ANS American Nuclear Society 12 AOC averted offsite property damage costs 13 AOE averted occupational exposure 14 AOSC averted onsite costs 15 AP auxiliary power 16 APE averted public exposure 17 ASLB Atomic Safety and Licensing Board (NRC) 18 ASME American Society of Mechanical Engineers 19 ATWS anticipated transient(s) without scram 20 AWEA American Wind Energy Association 21 BEA Bureau of Economic Analysis 22 BLM Bureau of Land Management 23 BLS Bureau of Labor Statistics 24 BOEM Bureau of Ocean Energy Management 25 BTU/ft3 British thermal unit(s) per cubic foot 26 CAA Clean Air Act 27 CAES compressed air energy storage 28 CCS carbon capture and storage 29 CCW component cooling water 30 CDF core damage frequency 31 CEQ Council on Environmental Quality 32 CET containment event tree 33 CFE early containment failure 34 CFR Code of Federal Regulations xxvii

Abbreviations and Acronyms 1 cfs cubic foot (feet) per second 2 CLB current licensing basis/bases 3 CO carbon monoxide 4 CO2 carbon dioxide 5 CO2/MWh carbon dioxide per megawatt hour 6 COL combined license 7 CVCS chemical and volume control system 8 CWA Clean Water Act 9 div. Division 10 DLOOP dual unit loss(es) of offsite power 11 DMS Diverse Mitigation System 12 DOE U.S. Department of Energy 13 DSIRE Database of State Incentives for Renewables and Efficiency 14 DSM demand-side management 15 ECCS emergency core cooling system 16 EFH essential fish habitat 17 EIA Energy Information Administration 18 EIS environmental impact statement 19 ELPC Environmental Law and Policy Center 20 Elv. elevation 21 EMF electromagnetic field 22 EPA U.S. Environmental Protection Agency 23 EPRI Electric Power Research Institute 24 EPZ emergency planning zone 25 ER Environmental Report 26 ERC Energy Recovery Council 27 ES Environmental Services 28 ESA Endangered Species Act of 1973, as amended 29 ESF engineered safety feature 30 ESFAS engineered safety features actuation system 31 ESP early site permit 32 ESW emergency service water 33 Exelon Exelon Generation Company, LLC 34 FEIS final environmental impact statement 35 FERC Federal Energy Regulatory Commission xxviii

Abbreviations and Acronyms 1 FESOP Federally Enforceable State Operating Permit 2 FIVE fire-induced vulnerability evaluation 3 FR Federal Register 4 FRN Federal Register notice 5 ft3 cubic foot (feet) 6 FW feedwater 7 FWCA Fish and Wildlife Coordination Act of 1934, as amended 8 FWS U.S. Fish and Wildlife Service 9 GEIS generic environmental impact statement 10 GI generic issue 11 GL generic letter 12 gpd gallon(s) per day 13 gpm gallon(s) per minute 14 ha hectare(s) 15 HCLPF high confidence in low probability of failure 16 HEP human error probability 17 HFE human failure event 18 HFO high winds, floods, and other 19 HRA human reliability analysis 20 HX heat exchanger 21 IDNR Illinois Department of Natural Resources 22 IDOT Illinois Department of Transportation 23 IDPH Illinois Department of Public Health 24 IEA International Energy Agency 25 IEPA Illinois Environmental Protection Agency 26 IGCC integrated gasification combined-cycle 27 IHPA Illinois Historic Preservation Agency 28 ILCS Illinois Compiled Statutes 29 INEEL Idaho National Engineering and Environmental Laboratory 30 IPE individual plant examination 31 IPEEE individual plant examination(s) of external events 32 ISLOCA interfacing-systems loss-of-coolant accident 33 JHEP joint human error probability 34 km kilometer(s) 35 kW kilowatt(s) xxix

Abbreviations and Acronyms 1 kWe kilowatt(s) electric 2 kWh/m2/d kilowatt hours per square meter per day 3 lb pound(s) 4 LER large early release 5 LERF large early release frequency 6 LMFW loss of main feedwater 7 LOCA loss-of-coolant accident 8 LOOP loss(es) of offsite power 9 Lpd liters per day 10 LRA license renewal application 11 LSCS LaSalle County Station, Units 1 and 2 12 m/s meter(s) per second 13 m3 cubic meter(s) 14 MAAP Modular Accident Analysis Program 15 MACCS2 MELCOR Accident Consequence Code System 2 16 MACR maximum averted cost risk 17 MATS Mercury and Air Toxics Standards 18 MCR main control room 19 mgd million gallons per day 20 mi mile(s) 21 MISO Midcontinent Independent System Operator 22 MMPA Marine Mammal Protection Act 23 MOV motor-operated valve 24 mph mile(s) per hour 25 MSA Magnuson-Stevens Fishery Conservation and Management Act, 26 as amended through 2006 27 MUR measurement uncertainty recapture 28 MW megawatt(s) 29 MWe megawatt(s) electric 30 MWh megawatt hour(s) 31 MWt megawatt(s) thermal 32 NEIS National Energy Information Service 33 NEPA National Environmental Policy Act of 1969, as amended 34 NETL National Energy Technology Laboratory 35 NGCC natural gas combined-cycle xxx

Abbreviations and Acronyms 1 NHPA National Historic Preservation Act of 1966, as amended 2 NMFS National Marine Fisheries Service (of the National Oceanic and 3 Atmospheric Administration) 4 NO2 nitrogen dioxide 5 NOx nitrogen oxide(s) 6 NPDES National Pollutant Discharge Elimination System 7 NRC U.S. Nuclear Regulatory Commission 8 NREL National Renewable Energy Laboratory 9 NRR Nuclear Reactor Regulation, Office of (NRC) 10 O3 ozone 11 OECR offsite economic cost risk 12 ORNL Oak Ridge National Laboratory 13 Pb lead 14 PDR population dose risk 15 PDS plant damage state 16 PEIS programmatic environmental impact statement 17 PL public law 18 PNNL Pacific Northwest National Laboratory 19 PORV power-operated relief valve 20 PRA probabilistic risk assessment 21 PV photovoltaic 22 PWR pressurized water reactor 23 RAI request(s) for additional information 24 RCP reactor coolant pump 25 RCRA Resource Conservation and Recovery Act of 1976, as amended 26 rem roentgen equivalent(s) man 27 RHR residual heat removal 28 ROI region(s) of influence 29 RPC replacement power cost 30 RPS reactor protection system 31 RPV reactor pressure vessel 32 RRW risk reduction worth 33 RTO Regional Transmission Organization 34 RWST refueling water storage tank 35 SAMA severe accident mitigation alternative xxxi

Abbreviations and Acronyms 1 SAT system auxiliary transformer 2 SBO station blackout 3 SCPC supercritical pulverized coal 4 SEIS supplemental environmental impact statement 5 SER safety evaluation report 6 SG steam generator 7 SGTR steam generator tube rupture 8 SI safety injection 9 SMA seismic margin assessment 10 SO2 sulfur dioxide 11 SR supporting requirement 12 SSC structure, system, and component 13 SSEL Safe Shutdown Equipment List 14 Sv sievert(s) 15 SW service water 16 SX essential service water 17 syngas synthesis gas 18 TAC technical assignment control 19 TEEIC Tribal Energy and Environmental Information Clearinghouse 20 TS technical specification 21 U.S. United States 22 U.S.C. United States Code 23 UAT unit auxiliary transformer 24 UFSAR updated final safety analysis report 25 USDA U.S. Department of Agriculture 26 USGS U.S. Geological Survey 27 yd 3 cubic yard(s) 28 W/m2 watt(s) per square meter xxxii

1

1.0 INTRODUCTION

2 Under the U.S. Nuclear Regulatory Commissions (NRCs) environmental protection regulations 3 in Part 51 of Title 10 of the Code of Federal Regulations (10 CFR Part 51)which implement 4 the National Environmental Policy Act (NEPA)the issuance or renewal of a nuclear power 5 plant operating license requires the preparation of an environmental impact statement (EIS). 6 The Atomic Energy Act of 1954 (AEA) specified that licenses for commercial power reactors can 7 be granted for up to 40 years. NRC regulations (10 CFR 54.31) allow for an option to renew a 8 license for up to an additional 20 years. The initial 40-year licensing period was based on 9 economic and antitrust considerations rather than on technical limitations of the nuclear facility. 10 The decision to seek a license renewal rests entirely with nuclear power facility owners and, 11 typically, is based on the facilitys economic viability and the investment necessary to continue 12 to meet NRC safety and environmental requirements. The NRC makes the decision to grant or 13 deny license renewal based on whether the applicant has demonstrated that the environmental 14 and safety requirements in the agencys regulations can be met during the period of extended 15 operation. 16 1.1 Proposed Federal Action 17 Exelon Generation Company, LLC (Exelon), initiated the proposed Federal action by submitting 18 an application for license renewal of LaSalle County Station, Units 1 and 2 (LSCS), for which 19 the existing licenses (NPF-11 and NPF-18) expire on April 17, 2022, and December 16, 2023. 20 The NRCs Federal action is to decide whether to renew the licenses for an additional 20 years. 21 1.2 Purpose and Need for Proposed Federal Action 22 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 23 option that allows for power generation capability beyond the term of a current nuclear power 24 plant operating license to meet future system generating needs, as such needs may be 25 determined by other energy-planning decisionmakers. This definition of purpose and need 26 reflects the NRCs recognition that, unless there are findings in the safety review required by the 27 AEA or findings in the NEPA environmental analysis that would lead the NRC to reject a license 28 renewal application (LRA), the NRC does not have a role in the energy-planning decisions of 29 state regulators and utility officials as to whether a particular nuclear power plant should 30 continue to operate. 31 1.3 Major Environmental Review Milestones 32 Exelon submitted an Environmental Report (ER) (Exelon 2014a) as part of its 33 LRA (Exelon 2014b) in December 2014. After reviewing the LRA and ER for sufficiency, the 34 NRC staff published a Federal Register Notice of Acceptability and Opportunity for Hearing 35 (Volume 80 of the Federal Register (FR), page 5822 (80 FR 5822)) on February 3, 2015. Also, 36 on February 3, 2015, the NRC published another notice in the Federal Register (80 FR 5793) on 37 the intent to conduct scoping, thereby beginning the 60-day scoping period. 38 The NRC staff held two public scoping meetings on March 10, 2015, in Ottawa, Illinois. In a 39 letter dated July 2, 2015, the NRC issued a report entitled, Environmental Impact Statement 40 Scoping Process Summary Report, LaSalle County Station, Units 1 and 2, Brookfield Township, 1-1

Introduction 1 LaSalle County, IL, which includes both the comments received during the scoping process 2 and the NRC staffs responses to those comments (NRC 2015a). 3 In order to independently verify information provided in the ER, the NRC staff conducted a site 4 audit at LSCS in May 2015. During the site audit, the NRC staff met with plant personnel, 5 reviewed specific documentation, toured the facility, and met with interested local agencies. In 6 a letter dated May 20, 2015, the NRC summarized that site audit and listed the attendees 7 (NRC 2015b). 8 Upon completion of the scoping period and site audit, the NRC staff compiled its findings in a 9 draft supplemental environmental impact statement (SEIS). This document is made available 10 for public comment for 45 days. During this time, the NRC staff will host public meetings and 11 collect public comments. Based on the information gathered, the NRC staff will amend the draft 12 SEIS findings, as necessary, and will publish the final SEIS. Figure 1-1 shows the major 13 milestones of the NRCs LRA environmental review process. 14 Figure 1-1. Environmental Review Process 15 16 The NRC has established a license renewal process that can be completed in a reasonable 17 period of time with clear requirements to ensure safe plant operation for up to an additional 18 20 years of plant life. The NRC staff conducts the safety review simultaneously with the 19 environmental review. The NRC staff documents the findings of the safety review in a safety 20 evaluation report (SER). The findings in the SEIS and the SER are both factors in the NRCs 21 decision to either grant or deny the issuance of a renewed license. 22 1.4 Generic Environmental Impact Statement 23 The NRC staff performed a generic assessment of the environmental impacts associated with 24 license renewal to improve the efficiency of its license renewal review. NUREG-1437, Generic 25 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS) 1-2

Introduction 1 (NRC 1996, 1999, 2013), documents the results of the NRC staffs systematic approach to 2 evaluate the environmental consequences of renewing the licenses of individual nuclear power 3 plants and operating them for an additional 20 years. The NRC staff analyzed in detail, and 4 resolved, those environmental issues that could be resolved generically in the GEIS. The NRC 5 originally issued the GEIS in 1996, issued Addendum 1 to the GEIS in 1999, and issued 6 Revision 1 to the GEIS in 2013. Unless otherwise noted, all references to the GEIS include 7 Addendum 1 and Revision 1 to the GEIS. 8 The GEIS establishes separate environmental impact issues for the NRC staff to independently 9 verify. Of these issues, the NRC staff determined that some generic issues are generic to all 10 plants (Category 1). Other issues do not lend themselves to generic consideration (Category 2 11 or uncategorized). The NRC staff evaluated these issues on a site-specific basis in the SEIS. 12 Appendix B to Subpart A of 10 CFR Part 51 summarizes the NRC staffs findings in the GEIS. 13 For each potential environmental issue, the NRC staff does the following in the GEIS: 14

  • describes the activity that affects the environment, 15
  • identifies the population or resource that is affected, 16
  • assesses the nature and magnitude of the impact on the affected population or 17 resource, 18
  • characterizes the significance of the effect for both beneficial and adverse effects, 19
  • determines whether the results of the analysis apply to all plants, and 20
  • considers whether additional mitigation measures would be warranted for impacts 21 that would have the same significance level for all plants.

22 The NRC established its standard of significance for impacts using the Council on 23 Environmental Quality terminology for significant. The NRC established three levels of 24 significance for potential impactsSMALL, MODERATE, and LARGE, as defined below. 25 SMALL: Environmental effects are not 26 detectable or are so minor that they will neither Significance indicates the importance of likely environmental impacts and is determined by 27 destabilize nor noticeably alter any important considering two variables: context and intensity. 28 attribute of the resource. Context is the geographic, biophysical, and social 29 MODERATE: Environmental effects are context in which the effects will occur. 30 sufficient to alter noticeably, but not to Intensity refers to the severity of the impact in 31 destabilize, important attributes of the resource. whatever context it occurs. 32 LARGE: Environmental effects are clearly 33 noticeable and are sufficient to destabilize important attributes of the resource. 34 The GEIS includes a determination of whether the analysis of the environmental issue could be 35 applied to all plants and whether additional mitigation measures would be warranted. Issues 36 are assigned a Category 1 or a Category 2 designation. As set forth in the GEIS, Category 1 37 issues are those that meet the following criteria: 38

  • The environmental impacts associated with the issue have been determined to apply 39 either to all plants or, for some issues, to plants having a specific type of cooling 40 system or other specified plant or site characteristics.

41

  • A single significance level (i.e., SMALL, MODERATE, or LARGE) has been assigned 42 to the impacts (except for collective offsite radiological impacts from the fuel cycle 43 and from high-level waste and spent fuel disposal).

1-3

Introduction 1

  • Mitigation of adverse impacts associated with the issue has been considered in the 2 analysis, and it has been determined that additional plant-specific mitigation 3 measures are likely not to be sufficiently beneficial to warrant implementation.

4 For generic issues (Category 1), no additional site-specific analysis is required in the SEIS 5 unless new and significant information is identified. The process for identifying new and 6 significant information for site-specific analysis is presented in Chapter 4. Site-specific issues 7 (Category 2) are those that do not meet one or more of the criteria of Category 1 issues; 8 therefore, additional site-specific review for these issues is required. A site-specific analysis is 9 required for 17 of those 78 issues evaluated in the GEIS. Figure 1-2 illustrates this process. 10 The results of that site-specific review are documented in the SEIS. 11 Figure 1-2. Environmental Issues Evaluated for License Renewal 12 1.5 Supplemental Environmental Impact Statement 13 The SEIS presents an analysis that considers the environmental effects of the continued 14 operation of LSCS, alternatives to license renewal, and mitigation measures for minimizing 15 adverse environmental impacts. Chapter 4 contains analysis and comparison of the potential 16 environmental impacts from alternatives. Chapter 5 presents the NRCs recommendation on 17 whether the environmental impacts of license renewal are so great that preserving the option of 1-4

Introduction 1 license renewal would be unreasonable. The NRC will make its final recommendation after 2 considering comments received on the draft SEIS during the public comment period. 3 In the preparation of the SEIS for LSCS, the NRC staff carried out the following activities: 4

  • reviewed the information provided in Exelons ER; 5
  • consulted with Federal, state, and local agencies, and tribal nations; 6
  • conducted an independent review of the issues during site audit; and 7
  • considered the public comments received for the review (during the scoping 8 process).

9 New information can be identified from many 10 sources, including the applicant, the NRC, other New and significant information. To merit 11 agencies, or public comments. If a new issue is additional review, information must be both new and bear on the proposed action or its impacts, 12 revealed, it is first analyzed to determine whether presenting a seriously different picture of the 13 it is within the scope of the license renewal impacts from those envisioned in the GEIS. 14 environmental evaluation. If the new issue is not 15 addressed in the GEIS, the NRC staff would determine the significance of the issue and 16 document the analysis in the SEIS. 17 1.6 Decisions to Be Supported by the SEIS 18 The decision to be supported by the SEIS is whether to renew the operating licenses for LSCS 19 for an additional 20 years. The NRC decision standard is specified in 10 CFR 51.103(a)(5), as 20 follows: 21 In making a final decision on a license renewal action pursuant to Part 54 22 of this chapter, the Commission shall determine whether or not the 23 adverse environmental impacts of license renewal are so great that 24 preserving the option of license renewal for energy planning 25 decisionmakers would be unreasonable. 26 There are many factors that the NRC takes into consideration when deciding whether to renew 27 the operating license of a nuclear power plant. The analyses of environmental impacts 28 evaluated in this GEIS will provide the NRCs decisionmaker (in this case, the Commission) with 29 important environmental information for use in the overall decisionmaking process. There are 30 also decisions outside the regulatory scope of license renewal that cannot be made on the basis 31 of the GEIS analysis. These decisions include the following issues: changes to plant cooling 32 systems, disposition of spent nuclear fuel, emergency preparedness, safeguards and security, 33 need for power, and seismicity and flooding (NRC 2013). 34 1.7 Cooperating Agencies 35 During the scoping process, no Federal, state, or local agencies were identified as cooperating 36 agencies in the preparation of this SEIS. 37 1.8 Consultations 38 The Endangered Species Act of 1973, as amended (ESA) (16 U.S.C. 1531 et seq.); the 39 Magnuson-Stevens Fisheries Conservation and Management Act of 1996, as amended (MSA) 40 (16 U.S.C. 1801 et seq.); and the National Historic Preservation Act of 1966, as amended 41 (NHPA) (16 U.S.C. 470 et seq.), require Federal agencies to consult with applicable state and 1-5

Introduction 1 Federal agencies and groups before taking action that may affect endangered species, 2 fisheries, or historic and archaeological resources, respectively. The NRC consulted with the 3 following agencies and groups; Appendix C provides a discussion of the consultation 4 documents: 5

  • U.S. Fish and Wildlife Service (FWS);

6

  • Illinois Historic Preservation Agency; 7
  • Advisory Council on Historic Preservation; 8
  • Ho-Chunk Nation; 9
  • Miami Tribe of Oklahoma; 10
  • Peoria Tribe of Indians of Oklahoma; 11
  • Citizen Potawatomi Nation; 12
  • Sac and Fox Tribe of the Mississippi in Iowa/Meskwaki Nation; 13
  • Sac and Fox Nation of Missouri in Kansas and Nebraska; 14
  • Sac and Fox Nation; 15
  • Pokagon Band of Potawatomi; 16
  • Forest County Potawatomi; 17
  • Hannahville Indian Community, Band of Potawatomi; 18
  • Prairie Band Potawatomi Nation; 19
  • Winnebago Tribe of Nebraska; 20
  • Kickapoo Tribe in Kansas; and 21
  • Kickapoo Tribe of Oklahoma.

22 1.9 Correspondence 23 During the course of the environmental review, the NRC staff contacted Federal, state, regional, 24 local, and tribal agencies listed in Section 1.8. Appendix C lists the correspondence associated 25 with the ESA, MSA, and NHPA. Appendix D lists all other correspondence. 26 1.10 Status of Compliance 27 Exelon is responsible for complying with all NRC regulations and other applicable Federal, 28 state, and local requirements. Appendix F of the GEIS describes some of the major applicable 29 Federal statutes. There are numerous permits and licenses issued by Federal, state, and local 30 authorities for activities at LSCS. Appendix B contains further information about LSCSs status 31 of compliance. 32 1.11 Related Federal and State Activities 33 The NRC reviewed the possibility that activities of other Federal agencies might impact the 34 renewal of the operating licenses for LSCS. There are no Federal projects that would make it 35 necessary for another Federal agency to become a cooperating agency in the preparation of 36 this SEIS. 1-6

Introduction 1 There are no known American Indian lands within 50 miles (mi) (80 kilometers (km)) of the 2 LSCS. There are three Federally owned facilities within 50 mi (80 km) of the LSCS: (1) Fermi 3 National Accelerator Laboratory, (2) Argonne National Laboratory, and (3) Joliet Army 4 Ammunition Plant. 5 Section 102(2)(C) of NEPA requires the NRC to consult with, and obtain comments from, any 6 Federal agency that has jurisdiction by law or special expertise with respect to any 7 environmental impact involved in the subject matter of the SEIS. For example, during the 8 course of preparing the SEIS, the NRC consulted with the FWS. Appendix C lists all 9 consultation correspondences. 10 1.12 References 11 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 12 protection regulations for domestic licensing and related regulatory functions. 13 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 14 renewal of operating licenses for nuclear power plants. 15 80 FR 5793. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 16 notice of intent to prepare an environmental impact statement and conduct the scoping process; 17 public meetings and request for comment. Federal Register 80(22):5793-5795. 18 February 3, 2015. 19 80 FR 5822. U.S. Nuclear Regulatory Commission. LaSalle County Station, Units 1 and 2, 20 license renewal application; opportunity to request a hearing and to petition for leave to 21 intervene. Federal Register 80(22):5822-5825. February 3, 2015. 22 Atomic Energy Act of 1954, as amended. 42 U.S.C. §2011 et seq. 23 Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 24 [Exelon] Exelon Generation Company, LLC. 2014a. Applicants Environmental Report 25 Operating License Renewal Stage, LaSalle County Station. Exelon. December 9, 2014. 26 Agencywide Documents Access and Management System (ADAMS) Nos. ML14343A883 and 27 ML14343A897. 28 [Exelon] Exelon Generation Company, LLC. 2014b. License Renewal Application, LaSalle 29 County Station, Units 1 and 2. Exelon. December 9, 2014. ADAMS No. ML14343A849. 30 Magnuson-Stevens Fishery Conservation and Management Act of 1996, as amended. 31 16 U.S.C. §1801 et seq. 32 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 33 National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq. 34 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement 35 for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG-1437, 36 Volumes 1 and 2. May 31, 1996. ADAMS Nos. ML040690705 and ML040690738. 37 [NRC] U.S. Nuclear Regulatory Commission. 1999. Section 6.3Transportation, Table 9.1, 38 Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants. 39 In: Generic Environmental Impact Statement for License Renewal of Nuclear Plants. 40 Washington, DC: NRC. NUREG-1437, Volume 1, Addendum 1. August 1999. ADAMS 41 No. ML040690720. 1-7

Introduction 1 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 2 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG-1437, Revision 1, 3 Volumes 1, 2, and 3. June 19, 2013. ADAMS No. ML13107A023. 4 [NRC] U.S. Nuclear Regulatory Commission. 2015a. Letter from BD Wittick (NRC), Branch 5 Chief, to MP Gallagher (Exelon).

Subject:

Issuance of Scoping Summary Report Associated 6 with the LaSalle County Station, Units 1 and 2, License Renewal Application Environmental 7 Review (TAC Nos. MF5567 and MF5568). July 2, 2015. ADAMS No. ML15147A380. 8 [NRC] U.S. Nuclear Regulatory Commission. 2015b. Letter from BD Wittick (NRC), Branch 9 Chief, to MP Gallagher (Exelon).

Subject:

Summary of the License Renewal Environmental 10 Audit for LaSalle County Station, Units 1 and 2 (TAC Nos. MF5567 and MF5568). 11 May 20, 2015. ADAMS No. ML15132A674. 1-8

1 2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION 2 Although the U.S. Nuclear Regulatory Commissions (NRCs) decisionmaking authority in 3 license renewal is limited to deciding whether or not to renew a nuclear power plants operating 4 license, the NRCs implementation of the National Environmental Policy Act of 1969 (NEPA), as 5 amended (42 U.S.C. 4321 et seq.), requires consideration of the environmental impacts of 6 potential alternatives to renewing a plants operating license. While the ultimate decision about 7 which alternative (or the proposed action) to carry out falls to operator, state, or other non-NRC 8 Federal officials, comparing the impacts of renewing the operating license to the environmental 9 impacts of alternatives allows the NRC to determine whether the environmental impacts of 10 license renewal are so great that preserving the option of license renewal for energy-planning 11 decisionmakers would be unreasonable (Title 10 of the Code of Federal Regulations 12 (10 CFR) 51.95(c)(4)). 13 Energy-planning decisionmakers and owners of the nuclear power plant ultimately decide 14 whether the plant will continue to operate, and economic and environmental considerations play 15 important roles in this decision. In general, the NRCs responsibility is to ensure the safe 16 operation of nuclear power facilities and not to formulate energy policy or encourage or 17 discourage the development of alternative power generation. The NRC does not engage in 18 energy-planning decisions and makes no judgment as to which energy alternatives evaluated 19 would be the most likely alternative in any given case. 20 The remainder of this chapter provides (1) a description of the proposed action, (2) a description 21 of alternatives to the proposed action (including the no-action alternative), and (3) alternatives to 22 LaSalle County Station, Units 1 and 2 (LSCS) license renewal that were considered and 23 eliminated from detailed study. Chapter 4 of this plant-specific supplemental environmental 24 impact statement (SEIS) compares the impacts of renewing the operating licenses of LSCS and 25 continued plant operations to the environmental impacts of alternatives. 26 2.1 Proposed Action 27 As stated in Section 1.1 of this document, the NRCs proposed Federal action is the decision of 28 whether to renew the LSCS operating licenses for an additional 20 years. For the NRC to 29 determine the impacts from continued operation of LSCS, an understanding of that operation is 30 needed. Section 2.1.1 describes normal power plant operations during the license renewal 31 term. LSCS is a two-unit, nuclear-powered steam-electric generating facility that began 32 commercial operation in January 1984 (Unit 1) and October 1984 (Unit 2). The nuclear reactors 33 at both units are General Electric boiling water reactors (BWRs), and together they produce an 34 annual average net output of 2,327 megawatts electric (MWe) (Exelon 2014). 35 2.1.1 Plant Operations during the License Renewal Term 36 Most plant operation activities during license renewal would be the same as, or similar to, those 37 occurring during the current license term (NRC 2013). Section 2.1.1 of NUREG-1437, Generic 38 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS), 39 Revision 1 (NRC 2013), describes the general types of activities that are carried out during the 40 operation of a nuclear power plant, such as LSCS, as follows: 41

  • reactor operation; 42
  • waste management; 2-1

Alternatives Including the Proposed Action 1

  • security; 2
  • office and clerical work; 3
  • surveillance, monitoring, and maintenance; and 4
  • refueling and other outages.

5 As stated in the Exelon Generation Company, LLCs (Exelons) Environmental Report (ER) 6 (Exelon 2014), LSCS will continue to operate during the license renewal term in the same 7 manner as it does during the current license term except for, as appropriate, additional aging 8 management programs to address structure and component aging in accordance with 9 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants. 10 2.1.2 Refurbishment and Other Activities Associated with License Renewal 11 Refurbishment activities include replacement and repair of major systems, structures, and 12 components. For example, replacement activities may include replacement of recirculation 13 piping systems for BWRs. The intent of the major refurbishment class of activities characterized 14 in the GEIS (NRC 2013) is to encompass actions that typically take place only once in the life of 15 a nuclear plant, if at all. Refurbishment activities may have an impact on the environment 16 beyond those that occur during normal operations and may require evaluation depending on the 17 type of action and the plant-specific design. 18 In preparation for its license renewal application, Exelon performed an evaluation of LSCS 19 structures, systems, and components in accordance with 10 CFR 54.21, Contents of 20 applicationtechnical information, to identify whether any major refurbishment activities would 21 be necessary to support the continued operation of LSCS during the proposed 20-year period of 22 extended operation (Exelon 2014). 23 Exelon did not identify any major refurbishment or replacement activities needed to support the 24 continued operation of LSCS beyond the existing operating license term (Exelon 2014). 25 Therefore, these activities are not discussed under the proposed action in Chapter 4. 26 2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning after the 27 License Renewal Term 28 NUREG-0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear 29 Facilities: Supplement 1, Regarding the Decommissioning of Nuclear Power Reactors, 30 describes the impacts of decommissioning (NRC 2002). Most activities associated with plant 31 operations would cease with reactor shutdown. Some activities (e.g., security and oversight of 32 spent nuclear fuel) would remain unchanged, whereas others (e.g., waste management; office 33 and clerical work; laboratory analysis; and surveillance, monitoring, and maintenance) would 34 continue at reduced or altered levels. Systems dedicated to reactor operations would cease 35 operations; however, impacts from their physical presence may continue if they are not removed 36 after reactor shutdown. For multiple-unit sites, such as LSCS, shared systems may operate at 37 reduced capacities. Impacts associated with dedicated systems that remain in place or shared 38 systems that continue to operate at normal capacities would remain unchanged. 39 Decommissioning will occur whether LSCS is shut down at the end of its current operating 40 license term or at the end of the period of extended operation. There are no site-specific issues 41 related to decommissioning. The license renewal GEIS concludes that license renewal would 42 have a negligible (SMALL) effect on the impacts of terminating operations and decommissioning 43 on all resources. 2-2

Alternatives Including the Proposed Action 1 2.2 Alternatives 2 As stated above, the NRC has the obligation to consider reasonable alternatives to the 3 proposed action of renewing the licenses for the nuclear reactors at LSCS. To be reasonable, a 4 replacement power alternative must be commercially viable on a utility scale and operational 5 prior to the expiration of the reactors operating licenses, or expected to become commercially 6 viable on a utility scale and operational prior to the expiration of the reactors operating licenses 7 (NRC 2013). The 2013 GEIS update incorporated the latest information on replacement power 8 alternatives; however, rapidly evolving technologies are likely to outpace the information 9 presented in the GEIS. As such, a site-specific analysis of alternatives must be performed for 10 each SEIS, taking into account changes in technology and science since the preparation of the 11 GEIS. 12 Section 2.2.1 below describes the no-action alternative (i.e., the NRC takes no action and does 13 not issue renewed licenses for LSCS). Sections 2.2.2.1-2.2.2.5 describe the characteristics of 14 replacement power alternatives for LSCS. 15 2.2.1 No-Action Alternative 16 At some point, operating nuclear power plants will terminate operations and undergo 17 decommissioning. The no-action alternative represents a decision by the NRC not to renew the 18 operating license of a nuclear power plant beyond the current operating license term. Under the 19 no-action alternative, the NRC does not renew the operating licenses, and the LSCS plant shuts 20 down at or before the end of the current licenses in 2022 and 2023. After shutdown, plant 21 operators will initiate decommissioning in accordance with 10 CFR 50.82, Termination of 22 License. 23 Only those impacts that arise directly as a result of plant shutdown will be addressed in this 24 SEIS. The environmental impacts from decommissioning and related activities are addressed in 25 several other documents, including the decommissioning GEIS (NRC 2002); the license renewal 26 GEIS, Chapter 4 (NRC 2013); and Chapter 4 of this SEIS. These analyses either directly 27 address or bound the environmental impacts of decommissioning whenever Exelon ceases to 28 operate LSCS. 29 Even with renewed operating licenses, LSCS will eventually shut down, and the 30 environmental impacts addressed later in Chapter 4 of this SEIS will occur at that time. 31 As with decommissioning impacts, shutdown impacts are expected to be similar whether they 32 occur at the end of the current license term or at the end of a renewed license term. 33 Termination of operations at LSCS would result in the total cessation of electrical power 34 production. Unlike the alternatives described in Section 2.2.2, the no-action alternative does not 35 meet the purpose and need of the proposed action because it does not provide a means of 36 delivering baseload power to meet future electric system needs. Given the current need for the 37 power generated by LSCS, the no-action alternative would likely create a need for a 38 replacement power alternative. A full range of replacement power alternatives (including new 39 nuclear, fossil fuels, and renewable energy sources) are described in the following section, and 40 their potential impacts are assessed in Chapter 4. Although the NRCs authority only extends to 41 the decision of whether to renew the LSCS operating licenses, the replacement power 42 alternatives described in the following sections represent possible options for energy-planning 43 decisionmakers should the NRC choose not to renew the LSCS operating licenses. 2-3

Alternatives Including the Proposed Action 1 2.2.2 Replacement Power Alternatives 2 In evaluating alternatives to license renewal, the NRC considered energy technologies or 3 options currently in commercial operation, as well as technologies not currently in commercial 4 operation but likely to be commercially available by the time the current LSCS operating 5 licenses expire. The current operating licenses for the LSCS, Units 1 and 2, expire on 6 April 17, 2022, and December 16, 2023, respectively. Alternatives that are not likely to be 7 constructed, permitted, and connected to the grid by the time the LSCS licenses expire were 8 eliminated from detailed consideration. 9 Alternatives that cannot provide the equivalent of LSCSs current generating capacity and, in 10 some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 11 reasonable alternatives, were not considered in detail. Each alternative eliminated is briefly 12 discussed, and the basis for its elimination is provided in Section 2.3. In total, 17 alternatives to 13 the proposed action were considered (see text box) and then narrowed to the 5 alternatives 14 considered in Sections 2.2.2.1-2.2.2.5. The NRC staff evaluated the environmental impacts of 15 these five alternatives and the no-action alternative. They are discussed in depth in Chapter 4 16 of this SEIS. 17 The GEIS presents an overview of some energy technologies but does not reach conclusions 18 about which alternatives are most appropriate. Because many energy technologies are 19 continually evolving in capability and cost and because regulatory structures have changed to 20 either promote or impede development of particular alternatives, the analyses in this chapter 21 may include updated information from the following sources: 22

  • U.S. Department of Energy (DOE), U.S. Energy Information Administration (EIA),

23

  • other offices within the DOE, 24
  • U.S. Environmental Protection Agency (EPA),

25

  • industry sources and publications, and 26
  • information submitted by Exelon in its ER.

27 The evaluation of each alternative in Chapter 4 of this SEIS considers the environmental 28 impacts across several impact categories: land use and visual resources, air quality and noise, 29 geologic environment, water resources, ecological resources, historic and cultural resources, 30 socioeconomics, human health, environmental justice, and waste management. Most 31 site-specific issues (Category 2) have been assigned a significance level of SMALL, 32 MODERATE, or LARGE. For ecological and historic and archaeological resources, the impact 33 significance determination language is specific to the authorizing legislation (e.g., Endangered 34 Species Act of 1973, as amended (16 U.S.C. 1531 et seq.), and National Historic Preservation 35 Act of 1966, as amended (16 U.S.C. 470 et seq.)). The order of presentation of the alternatives 36 is not meant to imply increasing or decreasing level of impact. Nor does it imply that an 37 energy-planning decisionmaker would be more likely to select any given alternative. 38 To ensure that the alternatives analysis is consistent with state or regional energy policies, the 39 NRC reviewed energy-related statutes, regulations, and policies within the LSCS region. As a 40 result, the staff considers alternatives that include wind power or solar photovoltaic (PV) power, 41 as well as a combination that includes both of them. 42 Region of Influence 43 LSCS is owned and operated by Exelon and provides electricity to the region of influence (ROI) 44 through transmission lines owned by Commonwealth Edison (ComEd) (Exelon 2014). ComEd 2-4

Alternatives Including the Proposed Action 1 operates under the PJM Interconnection, LLC Alternatives Evaluated in Depth: 2 (PJM), a regional transmission organization 3 that coordinates the movement of wholesale

  • new nuclear 4 electricity in 13 states across the Midwest
  • coal-integrated gasification combined-cycle 5 and Northeast (Exelon 2014). ComEd
  • natural gas combined-cycle 6 provides service to 3.8 million customers
  • combination alternative (wind power, natural gas 7 across northern Illinois. Its service territory combined-cycle, and solar power) 8 borders Iroquois County to the south, the
  • purchased power 9 Wisconsin border to the north, the Iowa 10 border to the west, and the Indiana border to Other Alternatives Considered:

11 the east (ComEd 2015). However, electricity 12 consumption in Illinois is not limited to

  • energy efficiency and conservation 13 electricity that is generated within the State.
  • solar power 14 Although northern Illinois relies on electricity
  • wind power 15 from ComEd, the rest of Illinois and
  • biomass 16 surrounding states, which are not part of the
  • hydroelectric power 17 PJM, are part of the Midcontinent
  • wave and ocean energy 18 Independent System Operator, Inc. (MISO)
  • fuel cells 19 (see Figure 2-1) (Exelon 2014).
  • delayed retirement 20 If renewed licenses were not issued,
  • geothermal power 21 replacement power for LSCS would be
  • municipal solid waste 22 required in northern Illinois. Electricity could
  • petroleum 23 be replaced by generation sources from a
  • supercritical pulverized coal 24 variety of locations. Electricity could be 25 transported from within the PJM; however, the PJM in Illinois is geographically distant from the 26 rest of the PJM region (see Figure 2-1). It is also possible that electricity within MISO could be 27 purchased by PJM, and efforts are currently being made to increase coordination and 28 deliverability between the regional transmission organizations (Ott 2013b). In addition, the State 29 of Illinois has a renewable portfolio standard that includes a stipulation that eligible renewable 30 resources must be procured from facilities located in Illinois or the States that adjoin Illinois 31 (Wisconsin, Indiana, Iowa, Kentucky, Michigan, and Missouri) (ILGA 2011). Renewable 32 resources can be obtained only from other regions of the country if they are not available in 33 Illinois or in the adjoining States (ILGA 2011).

34 Because replacement power would be required in northern Illinois, and any renewable energy 35 resources would need to be procured from facilities in Illinois or the adjoining States, the NRC 36 staff evaluated the impacts of locating replacement power facilities within the States of Illinois, 37 Indiana, Iowa, Kentucky, Michigan, Missouri, and Wisconsin. These seven states constitute the 38 ROI for the NRC staffs analysis of alternatives. The NRC assumes that replacement power 39 would either be produced in northern Illinois within the PJM region or would be purchased by 40 PJM from MISO. 41 In 2012, electric generators in the ROI had a net summer generating capacity of approximately 42 179,000 megawatts (MW). This capacity included units fueled by coal (49 percent), natural gas 43 (27 percent), nuclear (11 percent), and wind (6.6 percent) (EIA 2014c). 44 In 2011, the electric industry in the ROI provided approximately 744 million megawatt hours 45 (MWh) of electricity. Electricity produced in the ROI was dominated by coal (67 percent) and 46 nuclear (21 percent). Although natural gas makes up nearly 30 percent of the installed 47 generating capacity in the ROI, it provides only 6 percent of electricity in the region. 48 Nonhydroelectric renewable energy produced 1.3 percent of the electricity in the ROI 49 (EIA 2014b). 2-5

Alternatives Including the Proposed Action 1 Figure 2-1. Territories of MISO and PJM Interconnection 2 Source: MISO-PJM undated 3 Renewable Energy Legislation in the Region of Influence 4 Renewable energy legislation in Illinois allows the purchase of electricity generation in adjoining 5 States; therefore, any legislation targeting renewable energy in these States could impact a 6 States incentive to develop renewable resources. Five States in the ROI (Illinois, Iowa, 7 Missouri, Wisconsin, and Michigan) have legally mandated renewable energy programs. The 8 State of Indiana has a voluntary program, and State of Kentucky does not have any renewable 9 energy requirements. The paragraphs below briefly outline each States program, including 10 renewable energy goals and benchmarks. 11 In August 2007, Illinois adopted a renewable portfolio standard that requires the States utilities 12 to produce at least 25 percent of their power from renewable sources by 2025, 75 percent of 13 which must come from wind. Solar PV must comprise 6 percent of the annual requirement for 14 calendar year 2015 and thereafter. Other eligible sources include biomass and existing 15 hydroelectric power (DSIRE 2015a). The law also includes an energy efficiency standard that 16 requires utilities to implement cost-effective energy efficiency measures to meet energy savings 17 of 1 percent by calendar year 2016 and thereafter (ILGA 2011). For electric utilities (including 18 ComEd), eligible resources must be located in Illinois; resources can be purchased from 19 adjoining States only if there are insufficient in-State resources (ILGA 2011). 20 Iowas Alternative Energy Production Law requires the States two investor-owned utilities to 21 generate a combined total of 105 MW of their generating capacity from renewable energy 22 sources. A 2007 order allows the utilities to participate in renewable energy credit trading 23 programs by distinguishing between renewable electricity production capacity used to comply 24 with Iowa law and that which can be used to satisfy other states renewable portfolio standards 25 (DSIRE 2014). 26 Missouri adopted a renewable portfolio standard that requires investor-owned utilities to 27 increase their use of renewable sources by 15 percent by 2021 and includes a provision 28 specifying that 2 percent of the renewable portfolio standard requirement must be met by solar 29 energy. Resources can be purchased from outside Missouri, but renewable energy generated 30 in-State receives a multiplier of 1.25 compared to out-of-State generation (DSIRE 2015b). 2-6

Alternatives Including the Proposed Action 1 Wisconsins renewable portfolio standard requires utilities to produce 10 percent of their 2 electricity from renewable sources by 2015. Included in the renewable portfolio standard is a 3 provision that allows electricity providers to create and sell or transfer renewable resource 4 credits and renewable energy certificates. Renewable energy generated outside Wisconsin is 5 eligible, provided that the electricity is distributed to Wisconsin customers (DSIRE 2015c). 6 Michigan enacted a Renewable Energy Standard in 2008 that requires utilities to generate 7 10 percent of their retail electricity sales from renewable energy resources by 2015. 8 The standard also allows energy efficiency and advanced cleaner energy systems to meet part 9 of the requirement. Renewable energy credits can be purchased from in-State or out-of-State 10 facilities, provided that the facilities are located within the retail electric service territory of a 11 utility that is recognized by the Michigan Public Service Commission (DSIRE 2015d). 12 Indiana does not have a mandatory renewable or alternative energy portfolio standard. On 13 July 9, 2012, Indiana adopted a Clean Energy Portfolio Standard, which sets a voluntary goal of 14 10 percent clean energy by 2025, based on the amount of electricity supplied by the utility in 15 2010. Unlike many of the other ROI states, up to 30 percent of the goal may be met with clean 16 coal technology, nuclear energy, combined heat and power systems, natural gas that displaces 17 electricity from coal, and net-metered distributed generation facilities. Fifty percent of qualifying 18 energy must come from within the State. Utilities that participate in the program and meet the 19 program goals are eligible for incentives that are used to pay for the compliance projects 20 (DSIRE 2015e). 21 Kentucky is the only State in the ROI that does not have mandatory or voluntary renewable 22 energy requirements. 23 Given known technological and demographic trends, the EIA predicts that 34 percent of 24 electricity in the United States will be generated by coal in 2040 (EIA 2015). Natural gas 25 generation rose from 16 percent in 2000 to 27 percent in 2013 and is projected to increase to 26 31 percent in 2040 (EIA 2013a, 2015). Electricity generation from renewable energy is 27 expected to grow from 13 percent of total generation in 2013 to 18 percent in 2040 (EIA 2015). 28 However, there are uncertainties that could affect this forecast, particularly the implementation 29 of policies aimed at reducing greenhouse gas emissions, which would have a direct effect on 30 fossil fuel-based generation technologies. 31 The remainder of this section describes replacement power alternatives to license renewal 32 considered in depth. These include a new nuclear alternative in Section 2.2.2.1; a 33 coal-integrated gasification combined-cycle (IGCC) alternative in Section 2.2.2.2; a natural gas 34 combined-cycle (NGCC) alternative in Section 2.2.2.3; a combination natural gas, wind, and 35 solar power alternative in Section 2.2.2.4; and a purchased power alternative in Section 2.2.2.5. 36 Table 2-1 summarizes key design characteristics of the alternative technologies evaluated in 37 depth. The environmental impacts of these alternatives are evaluated in Chapter 4. 2-7

Alternatives Including the Proposed Action 1 Table 2-1. Summary of Replacement Power Alternatives and Key Characteristics 2 Considered in Depth(a) New Nuclear Combination Alternative IGCC Alternative NGCC Alternative Alternative Summary of Two-unit nuclear Four 618-MWe units, Five 560-MWe One 360 MWe Alternative plant, each with for a total of units, for a total of NGCC unit; a 1,120 MWe, for a total 2,472 MWe 2,800 MWe 1,813 MWe wind of 2,240 MWe farm; and a 227 MWe installed solar PV facility, for a total of 2,400 MWe Location An existing nuclear On the LSCS site or On the LSCS site. The NGCC plant site or retired at another existing New transmission component would coal plant site outside power plant site. line(s) and other be located on the Illinois. New New transmission infrastructure LSCS site. The transmission line(s) line(s) and other upgrades may be wind and solar and other infrastructure required; would components would infrastructure upgrades may be require construction be spread across upgrades may be required. Some of a new or multiple sites required. Some facilities (e.g., support upgraded pipeline. throughout the ROI. facilities (e.g., support buildings, potable Some facilities buildings, potable water supply, and (e.g., support water supply, and sanitary discharge buildings, potable sanitary discharge structures) could be water supply, and structures) could be shared with existing sanitary discharge shared with existing plant. structures) could be plant. shared with existing plant. Cooling Closed-cycle with Closed-cycle with Closed-cycle with For the NGCC System natural draft cooling mechanical draft mechanical draft portion, towers. Cooling cooling towers. cooling towers. closed-cycle with water withdrawal Cooling water Cooling water mechanical draft 56 mgd; consumptive withdrawal25 mgd; withdrawal cooling towers. water use42 mgd consumptive water 17 mgd; Cooling water (NRC 2008). use20 mgd consumptive water would be 15% of (NETL 2013a). use13 mgd that required for (NETL 2013a). NGCC alternative. Minimal water use for wind and solar. Land 556 ac (225 ha) 2,000 ac (800 ha) for 94 ac (38 ha) for the Wind farms would Require- (NRC 2008); 520 ac the major permanent plant, including require 3,376 ac ments (210 ha) for uranium facilities; 1,100 ac pipelines (1,366 ha) to mining and (450 ha) per year for (Exelon 2014); 10,127 ac processing(b) mining (DOE 2010a) 10,080 ac (4,098 ha) (WAPA (NRC 2013) (4,079 ha) for gas and FWS 2013); extraction and solar PV facilities collection would require (NRC 1996) 6,749 ac (2,731 ha) (Ong et al. 2013). For the NGCC portion, land use would remain the 2-8

Alternatives Including the Proposed Action New Nuclear Combination Alternative IGCC Alternative NGCC Alternative Alternative same at 94 ac (38 ha) (Exelon 2014). Work Force 3,500 workers during 4,600 workers during 1,783 workers Solar PV peak construction; peak construction; during peak 600 workers during 812 workers during 420 workers during construction; peak construction, operations operations 94 workers during 60 workers during (NRC 2008) (DOE 2010a) operations operations (Exelon 2014) (DOE 2010b). Wind931 workers during construction, 566 workers during operations (DOE 2008). NGCCnumber of construction and operations workers would be less than the NGCC alternative but would not be a linear reduction because of the need for a minimum number of workers regardless of the size of the plant. Key: ac = acres, ha = hectares, IGCC = coal-integrated gasification combined-cycle (alternative), mgd = million gallons per day, MWe = megawatts electric, NGCC = natural gas combined-cycle (alternative), PV = photovoltaic, and ROI = region of influence. (a) Because of the speculative nature of using purchased power to replace LSCS capacity and because of the inherent variability of characteristics associated with such an approach, this table does not include the purchased power alternative. (b) This is normalized to model the light water reactor annual fuel requirement. Forty-two percent of this land requirement is temporarily committed land. Sources: DOE 2008, 2010a, 2010b; Exelon 2014; NETL 2013a; NRC 1996, 2008, 2013; Ong et al. 2013; WAPA and FWS 2013 1 2.2.2.1 New Nuclear Alternative 2 In this section, the NRC staff describes the new nuclear alternative. The NRC staff evaluates 3 the environmental impacts from this alternative in Chapter 4. 4 The NRC staff considered the construction of a new nuclear plant to be a reasonable alternative 5 to license renewal. For example, nuclear generation currently provides 21 percent of electricity 6 generation in the ROI (EIA 2014b). Twelve nuclear power plants operate in the ROI; 7 eight applicants have received renewed licenses, and three additional applicants have applied 8 for renewed licenses from the NRC (including LSCS) (NRC 2015). In addition, there is interest 9 in new nuclear power plant development in the region; combined operating license (COL) 10 applications have been filed for two new nuclear power plants in the ROI. On July 24, 2008, 2-9

Alternatives Including the Proposed Action 1 Union Electric Company submitted a COL application for Callaway Plant, Unit 2, in Callaway 2 County, Missouri, on the existing Callaway site (AmerenUE 2009). However, Ameren UE has 3 since announced that they are canceling their COL application (Barker 2015). An application 4 was also filed in September 2008 for Enrico Fermi Atomic Power Plant, Unit 3, in Monroe 5 County, Michigan, on the existing Fermi site. On May 1, 2015, the NRC issued a COL 6 authorizing DTE Electric Company to build and operate an economic simplified BWR at the 7 Fermi site (Volume 80 of the Federal Register, 26302 (80 FR 26302)). The NRC staff 8 determined that there may be sufficient time for Exelon to prepare and submit an application, 9 build, and operate two new nuclear units using a certified design before the LSCS licenses 10 expire in April 2022 and December 2023. 11 In evaluating the new nuclear alternative, the NRC staff assumed that two new nuclear reactors 12 would be built on an existing nuclear or coal power plant site, allowing for the maximum use of 13 existing ancillary facilities at those locations, such as support buildings and transmission 14 infrastructure. In 1987, Illinois enacted a moratorium preventing the construction of new nuclear 15 power plants within the State. Until the moratorium is lifted, a new nuclear alternative would 16 require siting elsewhere in the ROI. For the purposes of this analysis, the NRC relied on the 17 Vogtle Electric Generating Plant (Vogtle), Units 3 and 4 (located in Waynesboro, Georgia), COL 18 environmental impact statement for technological parameters for the new nuclear alternative 19 because the Vogtle, Units 3 and 4, COL considers two new nuclear reactor units with a similar 20 output as LSCS and is representative of the reactors that could be constructed in the ROI 21 before LSCSs licenses expire (NRC 2011). As such, the NRC staff assumed 22 two Westinghouse AP1000 reactors with a net electrical output of 2,240 MWe would replace 23 LSCSs current reactors for this alternative. The NRC staff estimated that 324 ac (131 ha) of 24 land would be required on a long-term basis because of permanent facilities, and an additional 25 232 ac (94 ha) would be disturbed for temporary facilities, a laydown area, and storage of 26 dredge material (NRC 2008). 27 The heat rejection demands of a new nuclear alternative would be similar to those of LSCS. 28 The new reactors may require a new cooling system (including natural draft cooling towers and 29 intake and discharge structures). The NRC staff assumes that water requirements for the new 30 nuclear alternative would be similar to current water use at LSCS. A new onsite transmission 31 line and drinking water wells may be required if insufficient infrastructure occurs on the site. 32 Construction materials would be delivered by a combination of rail spur, truck, and barge, 33 depending on the specific site location. It is possible that modifications would be required to 34 deliver such materials, depending on the existing infrastructure at the site; modifications could 35 include new rail lines or access roads. 36 The NRC staff also considered the installation of multiple small modular reactors as an 37 alternative to renewing the LSCS licenses. The NRC established the Advanced Reactor 38 Program in the Office of New Reactors because of considerable interest in small modular 39 reactors along with anticipated license applications by vendors. Small modular reactors are 40 approximately 300 MW or less, would have lower initial capacity than that of large-scale units, 41 and would have siting flexibility for locations that are not large enough to accommodate 42 traditional nuclear reactors (DOE undated). As of October 2015, no applications for small 43 modular reactors have been submitted to the NRC. The DOE has estimated that the technology 44 may achieve commercial operation by 2021 to 2025 (DOE undated). Because small modular 45 reactors are not expected to be operational at a commercial scale until near the time LSCSs 46 licenses expire, it is unlikely that eight new small modular reactors (the number of units required 47 to replace LSCSs current output) could be constructed in the ROI; therefore, this analysis 48 focuses on nuclear generation by larger nuclear units. 2-10

Alternatives Including the Proposed Action 1 2.2.2.2 IGCC Alternative 2 In this section, the NRC staff describes the IGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4. 4 Coal provides the greatest share of electrical power in the ROI, and in 2010, coal represented 5 49 percent of installed generation capacity and accounted for 67 percent of all electricity 6 generated in the ROI (EIA 2014b). IGCC is a technology that generates electricity from coal 7 and combines modern coal gasification technology with both gas-turbine and steam-turbine 8 power generation. The technology is cleaner than conventional pulverized coal plants because 9 some of the major pollutants are removed from the gas stream before combustion. An IGCC 10 power plant consists of coal gasification and combined-cycle power generation. Coal gasifiers 11 convert coal into a gas (synthesis gas, also referred to as syngas), which fuels the 12 combined-cycle power generating units. The combined-cycle system for a 618-MWe IGCC 13 power plant includes two combustion turbines, two heat recovery steam generators, and a 14 steam turbine. The combined-cycle units combust gas in one or more combustion turbines, and 15 the resulting hot exhaust gas is then used to heat water into steam to drive a steam turbine. 16 The steam turbine then uses the heat from the gas turbines exhaust through a heat recovery 17 steam generator to produce additional electricity (DOE 2010a). This two-cycle process has a 18 high rate of efficiency because the exhaust heat that would otherwise be lost is captured and 19 reused. In addition, the power plant would reduce sulfur dioxide, nitrogen oxides, mercury, and 20 particulate emissions by removing constituents from the syngas before combustion. Nearly 21 100 percent of the nitrogen from the syngas would be removed before combustion in the gas 22 turbines and would result in lower nitrogen oxide emissions compared to conventional coal-fired 23 power plants (DOE 2010a). 24 IGCC power plants have been in operation since the mid-1990s; the Wabash Rice IGCC 25 repowering project in Indiana and the Polk Power Station in Florida are two examples of 26 operating IGCC plants. Recently, there has been an increased interest in new IGCC projects, 27 and multiple new projects have been proposed or have recently begun operations in the 28 United States. The Duke Energy Edwardsport Generation Station (Edwardsport) in Indiana is a 29 618-MWe IGCC power plant in the ROI that began commercial operation in June 2013. Duke 30 Energy estimates that the IGCC plant will produce 10 times as much power as the retired coal 31 plant it replaced with 70 percent fewer emissions of sulfur dioxide, nitrogen oxides, and 32 particulates. The IGCC plant will reduce carbon emissions per megawatt hour by nearly half 33 compared to conventional coal-fired plants (Duke Energy 2013). In addition, Edwardsport has 34 the potential for carbon capture and geologic sequestration. Space has been reserved at the 35 site for carbon dioxide capture equipment (NETL 2013b). 36 Many IGCC power plants have been designed with carbon capture and storage (CCS) to further 37 reduce carbon dioxide emissions. The Kemper County IGCC project in east-central Mississippi 38 proposes to use CCS to reduce carbon dioxide emissions by almost 70 percent by removing 39 carbon from the syngas post-gasification (DOE 2010a). According to a 2013 National Energy 40 Technology Laboratory (NETL) report, nine IGCC projects totaling over 4,000 MW are currently 41 active; these projects are in the planning stages, or they have begun construction. 42 Thirteen projects have been proposed and subsequently canceled for a variety of reasons, 43 including air quality issues, state laws and regulations, redirected focus on gas-fired generation 44 and renewables, and unanticipated rising costs (NETL 2013c). 45 IGCC technology and proposed projects have experienced a number of setbacks and 46 opposition, hindering IGCCs ability to fully integrate into the energy market. The most 47 significant roadblock is IGCCs high capital cost compared to conventional coal-fired power 48 plants. Cost overruns have been experienced at both the Edwardsport IGCC project and the 2-11

Alternatives Including the Proposed Action 1 Kemper County IGCC project. FutureGen, an IGCC plant featuring CCS, lost DOE financial 2 support because of escalating cost estimates (Reuters 2012). Other issues include construction 3 timeline overruns, a limited track record for reliable performance, and opposition from an 4 environmental perspective. 5 Despite some of the current setbacks and concerns associated with IGCC projects, the NRC 6 staff considers IGCC technology to be a reasonable source of baseload power to replace LSCS 7 by the time its licenses expire in 2022 and 2023 because of the current regulatory framework 8 and the number of active IGCC plants within the ROI. On August 3, 2015, EPA signed a final 9 rule for carbon pollution that would apply to new fossil fuel-fired power plants 10 (80 FR 64661-65120). The action establishes performance standards for utility boilers and 11 IGCC units based on partial implementation of a CCS system as a method of emission 12 reduction. The emission limit for these sources is 1,305 lb carbon dioxide per megawatt hour 13 (CO2/MWh), and any new coal-fired power plants could require CCS in order to achieve this 14 emission limit. 15 Overall, the NRC staff considers IGCC power plants as an alternative to LSCS because the 16 Edwardsport IGCC project in Indiana is currently in operation and because the Kemper County 17 IGCC project in Mississippi is under construction. The technology parameters for these plants 18 are considered the current state of technology and are used here to describe a hypothetical 19 IGCC power plant located on an existing power plant site within the ROI. 20 To replace the electricity that LSCS generates, the NRC staff considered four IGCC units, each 21 with a net capacity of 618 MWe. Various coal sources are available to coal-fired power plants in 22 the ROI. For the purpose of this evaluation, the NRC staff assumes that the IGCC alternative 23 would burn a sub-bituminous coal based on the type of coal used in electric plants in Illinois. 24 The NRC staff presumes that coal burned in Illinois will be representative of coal that would be 25 burned in an IGCC alternative regardless of where it may be located (EIA 2012). The IGCC 26 units would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 27 removing constituents from the syngas. In addition, the units would be designed with the 28 potential to add CCS later. Using CCS, carbon dioxide emission would be compressed and 29 piped off site where it could be sold for beneficial use or geologic storage. 30 The IGCC alternative would be located at an existing site (such as an existing power plant site) 31 to maximize availability of infrastructure and to reduce other environmental impacts. Depending 32 on the specific site location, there might be a need to construct new intake and discharge 33 facilities and a new cooling system. The IGCC alternative would use about the same amount of 34 water as LSCS and a similar amount as the Edwardsport IGCC plant. The NRC staff assumes 35 that the cooling system would use a closed-cycle system with mechanical draft cooling towers. 36 This system would withdraw 25 million gallons per day (gpd) (95 million liters per day (Lpd)) of 37 water and would consume 20 million gpd (76 million Lpd). Onsite visible structures could 38 include the boilers, exhaust stacks, intake and discharge structures, mechanical draft cooling 39 towers, transmission lines, and an electrical switchyard. Construction materials would be 40 delivered by a combination of rail spur, truck, and barge, depending on the specific site location. 41 Modifications may be required to deliver such materials; modifications could include new rail 42 lines or access roads. 43 The NRC staff also considered supercritical pulverized coal (SCPC) as an alternative to 44 renewing the LSCS licenses. SCPC was dismissed as the coal alternative because of new 45 regulations aimed at limiting the environmental impacts from conventional pulverized coal 46 plants. The presence of active IGCC plants in the ROI also contributed to the selection of IGCC 47 for analysis. 2-12

Alternatives Including the Proposed Action 1 2.2.2.3 NGCC Alternative 2 In this section, the NRC staff describes the NGCC alternative. The NRC staff evaluates the 3 environmental impacts from this alternative in Chapter 4. 4 Natural gas represents nearly 30 percent of installed generation capacity in the ROI but 5 provides only 6 percent of all electrical power in the ROI (EIA 2014b, 2014c). Nationwide, the 6 percentage of power generated by natural gas is expected to rise through 2040, although the 7 actual rise in natural gas generation will depend on future natural gas prices (EIA 2013a). The 8 NRC staff considers the construction of an NGCC power plant to be a reasonable alternative to 9 license renewal because it is a feasible, commercially available option for providing electrical 10 generating capacity beyond the expiration of LSCSs current licenses. 11 Baseload NGCC power plants have proven their reliability and can have capacity factors as high 12 as 85 percent. In an NGCC system, electricity is generated using a gas turbine that burns 13 natural gas. A steam turbine uses the heat from gas turbine exhaust through a heat recovery 14 steam generator to produce additional electricity. This two-cycle process has a high rate of 15 efficiency because the exhaust heat that would otherwise be lost is captured and reused. Like 16 other fossil fuel sources, NGCC power plants are a source of greenhouse gases, including 17 carbon dioxide. An NGCC power plant, however, produces significantly fewer greenhouse 18 gases per unit of electrical output than conventional coal-powered plants. 19 To replace the electricity that LSCS generates, the NRC staff considered five NGCC units, each 20 with a net capacity of 560 MWe (NETL 2007). The NRC staff assumes that each plant 21 configuration consists of two combustion turbine generators, two heat recovery steam 22 generators, and one steam turbine generator with mechanical draft cooling towers for heat 23 rejection. The power plant is assumed to incorporate a selective catalytic reduction system to 24 minimize the plants nitrogen oxide emissions (NETL 2007). 25 This 2,800-MWe NGCC plant would consume 124 billion cubic feet (3,500 million cubic meters) 26 of natural gas annually, assuming an average heat content of 1,021 British thermal units per 27 cubic foot (EIA 2013c). Natural gas would be extracted from the ground through wells, and then 28 it would be treated to remove impurities and blended to meet pipeline gas standards before 29 being piped through the State pipeline system to the plant site. This NGCC alternative would 30 produce relatively little waste, primarily in the form of spent catalysts used for control of nitrogen 31 oxide emissions. 32 The NGCC alternative would be located on undeveloped land at LSCS to maximize availability 33 of infrastructure and to reduce other environmental impacts. Depending on the specific site 34 location, there might be a need to construct new intake and discharge facilities and a new 35 cooling system. Because NGCC power plants generate much of their power from a gas-turbine 36 combined-cycle plant and because the overall thermal efficiency of this type of plant is high, an 37 NGCC alternative would require less cooling water than LSCS would. This system would 38 withdraw 17 million gpd (64 million Lpd) of water and would consume 13 million gpd 39 (49 million Lpd). The NRC staff assumes that the cooling system would use a closed-cycle 40 system with mechanical draft cooling towers. Onsite visible structures could include the cooling 41 towers, exhaust stacks, intake and discharge structures, transmission lines, natural gas 42 pipelines, and an electrical switchyard. Construction materials could be delivered by a 43 combination of rail spur, truck, and barge. Modifications may be required to deliver such 44 materials; modifications could include new rail lines or access roads. 45 2.2.2.4 Combination Alternative (NGCC, Wind, and Solar) 46 In this section, the NRC staff describes the combination alternative to the continued operation of 47 LSCS consisting of an NGCC facility constructed at an existing power plant site and operating in 2-13

Alternatives Including the Proposed Action 1 conjunction with land-based wind farms and solar energy facilities, all of which would be located 2 within the ROI. The NRC staff evaluates the environmental impacts from this alternative in 3 Chapter 4. 4 To serve as an effective baseload power alternative to the LSCS reactors, this combination 5 alternative must be capable of providing an equivalent amount of baseload power. For the 6 purpose of this evaluation, the NRC staff presumes that NGCC, wind farms, and solar PV 7 facilities would comprise the combination alternative. 8 NGCC Portion of the Combination Alternative 9 To produce its required share of power (360 MWe), the NGCC portion, operating at an expected 10 capacity factor of 85 percent (NETL 2007), would need to have a nameplate rating of 11 approximately 425 MWe. 12 In 2013, the EIA reported that natural gas-fired power plants are generally used infrequently for 13 shorter periods to meet peak demand. Capacity factors for natural gas plants averaged less 14 than 5 percent during off-peak demand hours for most regions of the country. Natural gas is 15 used for these peaker plants because natural gas combustion turbines can respond quickly; 16 therefore, they tend to be used to meet short-term increases in electricity demand (EIA 2013d). 17 A report prepared by CITI Research stated that gas-fired power plants can help overcome the 18 intermittent nature of renewable energy (Channell et al. 2012). The peaking aspect of natural 19 gas-fired power plants makes natural gas an ideal addition to an otherwise renewable energy 20 combination alternative. 21 The NRC staff assumed that one new NGCC unit of the type described in Section 2.2.2.3 would 22 be constructed and installed at LSCS with a total net capacity of 360 MWe. The appearance of 23 an NGCC unit would be similar to that of the full NGCC alternative considered in 24 Section 2.2.2.3, although only one unit would be constructed. The NRC staff assumes that the 25 NGCC portion of this alternative, which is assumed to be located at LSCS, would use existing 26 electrical switchyards, substations, and transmission lines. Depending on the existing site 27 conditions, it is possible that intake and discharge structures of the existing cooling system 28 could continue in service but would be connected to a new closed-cycle cooling system. For the 29 purposes of this analysis, the NRC staff assumes that the NGCC portion of the combination 30 would use mechanical draft cooling towers. 31 Wind Portion of the Combination Alternative 32 The NRC staff assumes that the wind-generated power from this combination alternative would 33 come from land-based wind farms, which would be located in the ROI within the States of 34 Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, or Wisconsin. The wind portion, assuming 35 a capacity factor of 30 percent, would require a nameplate capacity of 6,042 MWe (WAPA and 36 FWS 2013). 37 The American Wind Energy Association reports a total of more than 67,000 MW of installed 38 wind energy capacity nationwide as of June 30, 2015 (DOE 2015). As of June 2015, Texas is 39 by far the leader in installed land-based capacity with 15,635 MW. Two States in the ROI have 40 the third and fifth largest installed capacity: Iowa with 5,708 MW, followed by Illinois with 41 3,667 MW (DOE 2015). The installed wind capacity in the ROI has been increasing annually by 42 1,000 MWe to 2,500 MWe in each of the past 8 years, for a total of over 13,000 MWe of 43 additional wind capacity from 2007 to 2014 (DOE 2015). Therefore, the NRC staff considers 44 6,042 MW of wind energy to be a reasonable amount by the time the LSCS licenses expire in 45 2022 and 2023. As is the case with other renewable energy sources, the feasibility of wind 46 resources serving as alternative baseload power is dependent on the location (relative to 47 expected load centers), value, accessibility, and constancy of the resource. Wind energy must 2-14

Alternatives Including the Proposed Action 1 be converted to electricity at or near the point where it is extracted, and there are limited energy 2 storage opportunities available to overcome the intermittency and variability of wind resources. 3 At the current stage of wind energy technology development, wind resources in wind power 4 class 3 and higher are suitable for most utility scale applications (NREL 2014a). Wind power 5 class 3 is defined as having a wind speed of 15.7 miles per hour (7.0 meters per second) and a 6 wind density of 500 watts per square meter at 164 ft (50 m) (NREL 2014a). Each State in the 7 ROI, other than Kentucky, has wind resources meeting this power class, with the highest 8 concentrations occurring in Iowa and Illinois (NREL 2015a). 9 Individual wind turbine capacity increased from 0.71 MW in 1999 to 1.79 MW in 2010. The size 10 of turbine most frequently installed in the United States in recent years is the 1.5-MW turbine 11 (WAPA and FWS 2013). For the purposes of this analysis, the NRC staff assumes wind 12 turbines with a capacity of 1.79 MW. The capacity factors of land-based wind farms are lower 13 than offshore wind farms (WAPA and FWS 2013). For the wind portion of the combination 14 alternative, the NRC staff assumed a capacity factor of 30 percent, resulting in an estimated 15 total net capacity of 1,813 MWe. Wind turbines must be well separated from each other to 16 avoid interferences to wind flowing through the wind farm, resulting in wind farms requiring 17 substantial amounts of land. Wind turbines may require as much as 1 to 3 ac (0.4 to 1.2 ha) of 18 land for each turbine (WAPA and FWS 2013). Based on the size of the turbines and amount of 19 land required between each turbine, approximately 3,376 turbines and 3,376 to 10,127 ac 20 (1,366 to 4,098 ha) would be required for the wind portion of the combination alternative. 21 Wind energys intermittency affects its viability and value as a baseload power source. 22 However, the variability of wind-generated electricity can be lessened if the proposed wind 23 farms were located at a large distance from one another and were operated as interconnected 24 wind farms, an aggregate controlled from a central point. Distance separation ensures that the 25 two wind farms will not simultaneously experience the same climate, and power will likely be 26 produced at some of the wind farms at any given time (Archer and Jacobson 2007). 27 Solar Photovoltaic Portion of the Combination Alternative 28 The solar portion of the combination alternative would be generated through one or more solar 29 PV energy facilities located in the ROI. Assuming a capacity factor of 19 percent, the solar 30 energy facilities would need a collective nameplate rating of 1,193 MWe. Solar PV technologies 31 could be installed on building roofs at existing residential, commercial, or industrial sites or at 32 larger standalone solar facilities. 33 Nationwide, growth in large solar PV facilities (greater than 5 MW) has resulted in an increase 34 from 70 MW in 2009 to over 700 MW installed capacity in 2011. As of January 2012, it is 35 estimated that more than 11,000 MW of large solar PV projects have signed power purchase 36 agreements (Mendelsohn et al. 2012). Over 9,000 MW of those solar projects are 50 MW or 37 greater, although most are located in the southwestern United States (Mendelsohn et al. 2012). 38 As described in Section 2.2.2, two States in the ROI (Missouri and Illinois) have renewable 39 energy legislation that includes requirements for solar PV technology. Missouris renewable 40 portfolio standard includes a provision specifying that 2 percent of the renewable portfolio 41 standard requirement must be met by solar energy by 2021. Illinois renewable portfolio 42 standard specifies that solar PV must comprise 6 percent of the annual requirement for 43 compliance year 2015-2016 and thereafter. As of 2012, only 33 MW of solar energy capacity 44 had been installed in the ROI (EIA 2014c). 45 Solar PV resources in the ROI range from 4.0 to 5.0 kilowatt hours per square meter per day 46 (kWh/m2/day). The most viable solar resources are located in Missouri, Iowa, and southern 47 Illinois and Indiana (NREL 2015b). Economically viable solar resources are considered to be 48 6.75 kWh/m2/day and greater (BLM and DOE 2010). As is the case with wind energy sources, 2-15

Alternatives Including the Proposed Action 1 the feasibility of solar energy resources serving as alternative baseload power is dependent on 2 the location, value, accessibility, and constancy of the resource. Solar PV uses solar panels to 3 convert solar radiation into usable electricity. Solar cells are formed into solar panels that can 4 then be linked into PV arrays to generate electricity. The electricity generated can be stored, 5 used directly, fed into a large electricity grid, or combined with other electricity generators as a 6 hybrid plant. Solar PV can generate electricity whenever there is sunlight, regardless of 7 whether the sun is directly shining on solar panels. Therefore, solar PV technologies do not 8 need to directly face and track the sun, which has allowed solar PV systems to have broader 9 geographical use than concentrated solar power (Ardani and Margolis 2011). Because the ROI 10 contains average solar PV resources and because solar PV is a commercially available option 11 for providing electrical generating capacity, the NRC staff considers the construction of solar PV 12 facilities to be a reasonable alternative to license renewal when combined with wind and NGCC. 13 For the purposes of this analysis, the NRC staff assumes solar PV facilities with a capacity 14 factor of 19 percent (Ardani and Margolis 2011). Solar PV facilities may require 6.2 ac (2.5 ha) 15 of land per megawatt (NRC 2013). Although not all of this land would be cleared of vegetation 16 and permanently impacted, it represents the land enclosed in the total site boundary of the solar 17 facility (Ong et al. 2013). For the solar portion of this combination alternative, approximately 18 7,397 ac (2,993 ha) would be required to support an installed net capacity of 227 MWe. In this 19 analysis, the NRC staff does not speculate on the number and size of individual solar facilities, 20 nor their locations within the ROI. However, as stated above, some of the output could be 21 realized by solar PV installations on building roofs at existing residential, commercial, or 22 industrial sites or at larger standalone solar facilities. To the extent that rooftop or 23 building-integrated solar PV installations remain popular, land impacts would be relatively minor. 24 Solar PV systems do not require water for cooling purposes, but a small amount of water is 25 needed to clean the panels and for potable water for the workforce. Impacts identified in the 26 U.S. Department of the Interior Bureau of Land Management (BLM) and DOEs Solar Energy 27 Programmatic Environmental Impact Statement (PEIS) (BLM and DOE 2010, 2012) provide 28 information used in the analyses presented in the impact sections in Chapter 4. 29 2.2.2.5 Purchased Power Alternative 30 In this section, the NRC staff describes purchased power as an alternative to the continued 31 operation of LSCS. 32 The impacts from purchased power would depend substantially on the generation technologies 33 used to supply the purchased power. Impacts from operation of other electricity generators 34 would likely occur in the ROI. As discussed in Section 2.2.1, replacement power for LSCS 35 would be required in northern Illinois and could come from anywhere within Illinois or adjoining 36 states in either the PJM or MISO Regional Transmission Organizations (RTOs). Given the large 37 geographic area, multiple RTOs within the ROI, and wide-ranging generating facilities, the NRC 38 staff considers purchased power to be a feasible source of baseload power to replace LSCS by 39 the time the licenses expire in 2022 and 2023. 40 Purchased power would likely come from the most common types of electricity generation within 41 the ROI: coal, natural gas, nuclear, and wind. All these power sources are discussed as 42 alternatives to license renewal of LSCS and are identified in Sections 2.2.2.2 to 2.2.2.4. 43 Construction and operational impacts from these sources of electricity generation are 44 considered in Chapter 4. Purchased power may require new transmission lines (which may 45 require new construction) and may also rely on older and less-efficient power plants operating at 46 higher capacities than they currently operate or on new facilities that would be constructed. 47 During operations, impacts from nuclear, coal-fired, and natural gas-fired plants and from wind 2-16

Alternatives Including the Proposed Action 1 and solar energy projects would be similar to those described under the new nuclear, coal, 2 natural gas, and combination alternatives described in Chapter 4 for all resource areas. 3 2.3 Alternatives Considered but Dismissed 4 Alternatives to LSCS license renewal that were considered and eliminated from detailed study 5 are presented in this section. These alternatives were eliminated because of technical resource 6 availability or current commercial limitations. Many of these limitations would continue to exist 7 when the current LSCS licenses expire. 8 2.3.1 Energy Conservation and Energy Efficiency 9 Energy conservation can include reducing energy demand through behavioral changes or 10 altering the shape of the electricity load and usually does not require the addition of new 11 generating capacity. Conservation and energy efficiency programs are more broadly referred to 12 as demand-side management. 13 Conservation and energy efficiency programs can be initiated by a utility, transmission 14 operators, the state, or other load-serving entities. The State of Illinois renewable portfolio 15 standard includes an energy efficiency portfolio standard that requires utilities to reduce electric 16 usage by 2 percent of demand by 2015 (DSIRE 2015a), which is equivalent to 4 million MWh, 17 only 20 percent of the amount that would be required to offset LSCSs current electrical 18 generation. 19 In general, residential electricity consumers have been responsible for the majority of peak load 20 reductions, and participation in most programs is voluntary. Therefore, the existence of a 21 program does not guarantee that reductions in electricity demand would occur. The GEIS 22 concludes that, although the energy conservation or energy efficiency potential in the 23 United States is substantial, there are likely no cases where an energy efficiency or 24 conservation program has been implemented expressly to replace or offset a large baseload 25 generation station (NRC 2013). Although significant energy savings are possible in the ROI 26 through demand-side management and energy efficiency programs, conservation and energy 27 efficiency programs are not likely to replace LSCS as a standalone alternative; therefore, the 28 NRC staff does not consider conservation and energy efficiency to be a reasonable alternative 29 to license renewal. 30 2.3.2 Solar 31 Solar power, including solar PV and concentrated solar power technologies, produce power 32 generated from sunlight. PVs convert sunlight directly into electricity using solar cells made 33 from silicon or cadmium telluride. Concentrating solar power uses heat from the sun to boil 34 water and produce steam to drive a turbine connected to a generator to produce electricity 35 (NREL 2014b). To be considered a viable alternative, a solar alternative must replace the 36 amount of electricity LSCS provides. Assuming a capacity factor of 19 percent (Ardani and 37 Margolis 2011), approximately 12,400 MWe of electricity would need to be generated by solar 38 energy facilities in the seven-State ROI. 39 In 2012, 33 MW of solar energy capacity was installed in the ROI (EIA 2014c). The DOEs 40 National Renewable Energy Laboratory (NREL) reports that the States in the ROI receive solar 41 insolation of 4.0 to 5.0 kWh/m2/day, which is considered low to average (NREL 2015b). For 42 utility-scale development, insolation levels below 6.5 kWh/m2/day are not considered 43 economically viable given current technologies (BLM and DOE 2010). There is more potential 44 for solar development using local PV applications, such as rooftop solar panels, than through 2-17

Alternatives Including the Proposed Action 1 utility-scale solar facilities. In addition, a solar facility can only generate electricity when the sun 2 is shining. Energy storage can be used to overcome intermittency for concentrating solar power 3 facilities; however, current and foreseeable storage technologies that have been paired with 4 solar power facilities have a much smaller capacity than would be necessary to replace LSCS. 5 Taking all of the factors above into account, it is unlikely that solar PV or concentrated solar 6 power technologies could serve as baseload power in the ROI to replace LSCSs current 7 electricity output. Given the modest levels of solar energy available throughout the ROI, the 8 lack of substantial installed solar capacity in the ROI and the weather-dependent intermittency 9 of solar power, the NRC staff concludes that a solar power energy facility in the ROI would not 10 be a reasonable alternative to license renewal. The NRC staff described an alternative of solar 11 power in combination with wind and an NGCC plant in Section 2.2.2.4. 12 2.3.3 Wind 13 Two States in the ROI have the third and fifth largest installed capacity in the Nation: Iowa with 14 5,708 MW, followed by Illinois with 3,667 MW (DOE 2015). The installed wind capacity in the 15 ROI has been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 8 years, for 16 a total of over 13,000 MWe of additional wind capacity from 2007 to 2014 (DOE 2015). All of 17 the wind energy facilities and the electricity generation from wind currently being produced in 18 the ROI are land based. To be considered a viable alternative, a wind alternative must replace 19 the amount of electricity LSCS provides. Assuming a capacity factor of 30 percent for 20 land-based wind and 40 percent for offshore wind, a range of 5,665 to 7,553 MWe of electricity 21 would need to be generated by some combination of land-based and offshore wind energy 22 facilities in the seven-State ROI. 23 As is the case with other renewable energy sources, the feasibility of wind resources serving as 24 alternative baseload power is dependent on the location (relative to expected load centers), 25 value, accessibility, and constancy of the resource. Wind energy must be converted to 26 electricity at or near the point where it is extracted, and there are limited energy storage 27 opportunities available to overcome the intermittency and variability of wind resource availability. 28 Although wind power is intermittent and although individual facilities are unable to provide 29 baseload power, it has been proposed that multiple interconnected wind installations separated 30 by long distances could theoretically function as a virtual power plant and could provide 31 baseload power since individual facilities would be exposed to different weather and wind 32 conditions. To date, however, no states or utilities operate arrays of wind installations as virtual 33 power plants. 34 Given the amount of wind capacity necessary to replace LSCS and the intermittency of wind 35 power, the NRC staff finds a completely wind-based alternative to be unreasonable. However, 36 the NRC staff also concludes that, when used in combination with other technologies with 37 inherently higher capacity factors, wind energy can provide a viable alternative. The NRC staff 38 described such a possible combination alternative in Section 2.2.2.4. 39 2.3.3.1 Offshore Wind 40 The United States does not have any offshore wind farms in operation; however, approximately 41 20 projects representing more than 2,000 MW of capacity are in the planning and permitting 42 process as of 2010 (Musial and Ram 2010). Offshore wind projects have been developed in 43 Europe, most of which are located close to shore and in shallow water less than 98.4 ft (30 m) in 44 depth. Total worldwide installed capacity has been estimated at 2,377 MW (Musial and 45 Ram 2010). 46 Although wind data suggest a potential for offshore wind farms in the Great Lakes, project costs 47 likely will limit the future potential of large-scale projects (Tidball et al. 2010). NREL 2-18

Alternatives Including the Proposed Action 1 (Tidball et al. 2010) estimated that offshore project costs would run approximately 200 to 2 300 percent higher than land-based systems. In addition, based on current prices for wind 3 turbines, the 20-year levelized cost of electricity produced from an offshore wind farm would be 4 above the current production costs from existing power generation facilities. In addition to cost, 5 other barriers include the immature status of the technology, limited resource area, and high 6 risks and uncertainty (Tidball et al. 2010). Because no offshore wind capacity yet exists in 7 either the Great Lakes or on the Atlantic Coast and because none appears likely to exist on a 8 large commercial scale in the Great Lakes by 2022 (given the current state of development), the 9 NRC staff finds that offshore wind will not be a reasonable alternative to LSCS. 10 2.3.3.2 Wind Power with Storage 11 Energy storage is one possible way to overcome intermittency. Besides pumped hydroelectric 12 facilities, compressed air energy storage (CAES) is the technology most suited for storage of 13 large amounts of energy. In CAES systems, electricity generated during low-demand periods 14 can be stored by using a compressor to pressurize and store air; during high-demand periods, 15 the compressed air can be used to drive a turbine to generate electricity. A 2011 DOE report 16 analyzed various power-generation sources, including wind, coupled with CAES systems 17 (Ilic et al. 2011). The report considered siting criteria, using (1) proximity to natural gas lines, 18 high voltage transmission, and a market for wholesale electric power and (2) availability of 19 geology and wind resources. The results show that, within the ROI, the potential exists for 20 one CAES site in northwestern Iowa. Without detailed wind-speed data, specific site 21 information, and detailed information on the energy-storage capacity of the potential CAES site, 22 estimating how much wind capacity would be necessary and determining whether it could 23 provide for an all-wind alternative would be difficult. Furthermore, the NRC staff is not aware of 24 a CAES project coupled with wind generation that is providing baseload power. Therefore, the 25 NRC staff concludes that the use of CAES in combination with wind turbines to replace the 26 LSCS power plant is unlikely. 27 2.3.3.3 Conclusion 28 Despite the relatively high reliability demonstrated by modern turbines, the recent technological 29 advancements in turbine design and wind farm operation, and wind energys dramatic market 30 penetrations of recent years, empirical data on wind farm capacity factors and wind energys 31 limited ability to store power for delayed production of electricity cause the NRC staff to 32 conclude that wind energyon shore, off shore, or a combination thereofcould not serve as a 33 discrete alternative to the baseload power supplied by the LSCS reactors. However, the NRC 34 staff also concludes that, when used in combination with other technologies with inherently 35 higher capacity factors, wind energy can provide a viable alternative. The NRC staff described 36 such a possible combination alternative in Section 2.2.2.4. 37 2.3.4 Biomass 38 Biomass resources used for biomass-fired generation include agricultural residues, animal 39 manure, wood wastes from forestry and industry, residues from food and paper industries, 40 municipal green wastes, dedicated energy crop, and methane from landfills (IEA 2007). Using 41 biomass-fired generation for baseload power depends on the geographic distribution, available 42 quantities, constancy of supply, and energy content of biomass resources. For this analysis, the 43 NRC staff assumed that biomass would be combusted for power generation in the electricity 44 sector. Biomass is also used for space heating in residential and commercial buildings and can 45 be converted to a liquid form for use in transportation fuels (Haq undated). 46 In the GEIS, the NRC staff indicated a wood waste facility could provide baseload power and 47 could operate with capacity factors between 70 and 80 percent (NRC 2013). Although the ROI 2-19

Alternatives Including the Proposed Action 1 currently produces electricity from biomass fuels, the plants operating within the ROI generated 2 less than 1 percent of the total power generation in 2011 (EIA 2014b). Based on the relatively 3 low electricity generation currently produced at biomass plants, it is unlikely that these plants, or 4 the construction of several new biomass plants, could increase capacity by adding 2,327 MWe 5 of electricity from biomass-fired generation by the time LSCSs licenses expire in 2022 and 6 2023. 7 For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 8 used for biomass conversion would be similar to fossil fuel plants, including the direct 9 combustion of biomass in a boiler to produce steam (NRC 2013). Biomass generation is 10 generally more cost-effective when co-fired with coal plants (IEA 2007). Biomass-fired 11 generation plants generally are small and can reach capacities of 50 MWe, which means that 12 more than 40 new facilities would be required before the LSCS licenses expire. After 13 reevaluating current technologies, the NRC staff finds biomass-fired alternatives as still unable 14 to reliably replace the LSCS capacity. For this reason, the NRC staff does not consider 15 biomass to be a reasonable alternative to LSCS license renewal. 16 2.3.5 Hydroelectric 17 Hydroelectric power uses the force of water to turn turbines that spin a generator to produce 18 electricity. In a run-of-the-river system, the force of a river current provides the force to create 19 the needed pressure for the turbine. In a storage system, water is accumulated in reservoirs 20 created by dams and is released as needed to generate electricity. 21 The DOEs Idaho National Environmental Engineering Laboratory (now Idaho National 22 Laboratory) completed a comprehensive survey of hydropower resources in 1997. The ROI has 23 hydroelectric generating potential of 1,954 MW, adjusting for environmental, legal, and 24 institutional constraints (Conner et al. 1998). These constraints could include (1) scenic, 25 cultural, historical, and geological values, (2) Federal and state land use, and (3) legal 26 protection issues, such as wild and scenic legislation and threatened or endangered fish and 27 wildlife legislative protection. A separate assessment by DOE of nonpowered dams (dams that 28 do not produce electricity) concluded that there is potential for 4,185 MW of electricity in the ROI 29 (ORNL 2012). These nonpowered dams serve various purposes, such as providing water 30 supply to inland navigation. 31 The EIA reported that the States comprising the ROI generated 2,262 MW of electricity from 32 hydroelectric power in 2012 (EIA 2014c). In order to replace LSCSs current output, 33 hydroelectric generation across the ROI would need to double by 2022. Although there is 34 potential for anywhere between 1,954 MW and 4,185 MW of hydroelectric power, it is unlikely 35 that the maximum levels of development would occur across the entire ROI by the time LSCSs 36 licenses expire in 2022 and 2023 because the generating capacity of hydroelectric power is 37 projected to continue to decrease through 2040 (EIA 2013b). Given the decrease in projected 38 power generation from hydroelectric facilities, the NRC staff does not consider hydroelectric 39 power to be a reasonable alternative to license renewal. 40 2.3.6 Wave and Ocean Energy 41 Waves, currents, and tides are often predictable and reliable, making them attractive candidates 42 for potential renewable energy generation. Four major technologies may be suitable to harness 43 wave energy: terminator devices that range from 500 kilowatts to 2 MW, attenuators, point 44 absorbers, and overtopping devices (BOEM undated). Point absorbers and attenuators use 45 floating buoys to convert wave motion into mechanical energy, driving a generator to produce 46 electricity. Overtopping devices trap a portion of a wave at a higher elevation than the sea 2-20

Alternatives Including the Proposed Action 1 surface; waves then enter a tube and compress air that is used to drive a generator that 2 produces electricity (NRC 2013). Some designs are undergoing demonstration testing at 3 commercial scales, but none are currently used to provide baseload power (BOEM undated). 4 The Great Lakes do not experience large tides, and there is limited energy output for wave 5 technologies in the Great Lakes. The Electric Power Research Institute (EPRI) published a 6 document that assessed ocean wave energy resources in the United States. The Great Lakes 7 were not included in the analysis, suggesting that the resource potential is not great enough to 8 use on a commercial scale (EPRI 2011). Consequently, the limited resource availability and 9 infancy of the technologies in the Great Lakes support the NRC staffs conclusion that wave and 10 ocean energy technologies are not feasible substitutes for LSCS. 11 2.3.7 Fuel Cells 12 Fuel cells oxidize fuels without combustion and its environmental side effects. Fuel cells use a 13 fuel (e.g., hydrogen) and oxygen to create electricity through an electrochemical process. The 14 only byproducts (depending on fuel characteristics) are heat, water, and carbon dioxide 15 (depending on hydrogen fuel type) (DOE 2013a). Hydrogen fuel can come from a variety of 16 hydrocarbon resources. Natural gas is a typical hydrogen source. 17 Fuel cells are not economically or technologically competitive with other alternatives for 18 electricity generation. EIA projects that fuel cells may cost $6,835 per installed kilowatt (total 19 overnight capital costs, 2010 dollars), which is high compared to other alternative technologies 20 analyzed in this section (EIA 2010). More importantly, fuel cell units are likely to be small in size 21 (approximately 10 MWe). Replacing the power LSCS provides would be extremely costly; it 22 would require the construction of approximately 230 units and modifications to the existing 23 transmission system. Given the immature status of fuel cell technology and high cost, the NRC 24 staff does not consider fuel cells to be a reasonable alternative to LSCS license renewal. 25 2.3.8 Delayed Retirement 26 A delayed retirement alternative would consider deferring the retirement of generating facilities 27 in Illinois and its six adjoining states that include MISO and PJM RTOs. 28 To maintain reliable operations, electric systems must be able to meet peak load requirements. 29 To ensure sufficient capacity, this must also include a planning reserve margin (FERC 2013). 30 The projected MISO reserve margin for 2021 is 18.6 percent, which exceeds the reserve margin 31 requirement of 17.4 percent. However, recent EPA regulations may lead to increased coal plant 32 retirements at a faster pace than projected. In that case, 3,000 MW to 12,600 MW of plant 33 retirements could decrease the projected reserves anywhere from 16.22 to 6.9 percent, well 34 below the reserve margin requirement (MISO 2011). 35 PJM is facing similar constraints due, in large part, to retirements of coal plants given air quality 36 regulations (Ott 2013a). This indicates an emerging reliability problem potentially affecting 37 major population centers within the PJM region in the near future (Ott 2013a). Because the 38 current generation mix has not resulted in the long-term commitment of generation needed for 39 reliability, generation retirements that have occurred with short notice have created 40 unanticipated reliability problems for PJM (Ott 2013a). 41 The EIA expects that more coal plant retirements will occur before 2016 than those previously 42 predicted. These accelerated retirements are driven by low natural gas prices, slow growth in 43 electricity demand, and the requirements of the Mercury and Air Toxics Standards that will 44 require significant reductions in plant emissions (EIA 2014a, EPA 2015). Exelon also expects 45 increased generation retirements for a variety of reasons, including increased operating costs 2-21

Alternatives Including the Proposed Action 1 for older facilities, increased environmental regulations and competition, and decreased load 2 (Exelon undated). As generators are required to adhere to future regulations, some power 3 plants may opt for early retirement of older units rather than incur the cost for compliance. 4 Exelon has further stated that some of their nuclear fleet may be retired early because of low 5 wholesale energy prices and current energy policy (Associated Press 2015). Because of the 6 uncertain regulatory environment and concerns expressed by MISO and PJM concerning the 7 retirement pace of coal power plants, the NRC staff does not consider delayed retirement to be 8 a reasonable alternative to LSCS license renewal. 9 2.3.9 Geothermal 10 Geothermal technologies extract the heat contained in geologic formations to produce steam to 11 drive a conventional steam turbine generator. Facilities producing electricity from geothermal 12 energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 13 a potential source of baseload electric power. However, the feasibility of geothermal power 14 generation to provide baseload power depends on the regional quality and accessibility of 15 geothermal resources. Utility-scale geothermal energy generation requires geothermal 16 reservoirs with a temperature above 200 °F (93 °C). Utility-scale power plants range from small 17 300 kilowatts electric to 50 MWe and greater (TEEIC undated). Geothermal resources are 18 concentrated in the western United States. Specifically, these resources are found in Alaska, 19 Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, 20 Washington, and Wyoming. In general, most assessments of geothermal resources have been 21 concentrated on these western states (DOE 2013b; USGS 2008). Geothermal resources are 22 used in the ROI for heating and cooling purposes, but no electricity is currently being produced 23 from geothermal resources in the ROI (EIA 2014c). Given the low resource potential in the ROI, 24 the NRC staff does not consider geothermal to be a reasonable alternative to license renewal. 25 2.3.10 Municipal Solid Waste 26 Energy recovery from municipal solid waste converts nonrecyclable waste materials into usable 27 heat, electricity, or fuel through combustion (EPA 2014b). The three types of combustion 28 technologies include mass burning, modular systems, and refuse-derived fuel systems 29 (EPA 2014a). Mass burning is the method used most frequently in the United States. The heat 30 released from combustion is used to convert water to steam, which is used to drive a turbine 31 generator to produce electricity. Ash is collected and taken to a landfill, and particulates are 32 captured through a filtering system (EPA 2014a). As of 2010, approximately 33 86 waste-to-energy plants are in operation in 25 states, processing more than 28 million tons of 34 waste per year (EPA 2014b). These waste-to-energy plants have an aggregate capacity of 35 2,720 MWe, and although some plants have expanded to handle additional waste and produce 36 more energy, no new plants have been built in the United States since 1995 (EPA 2014b). The 37 average waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can 38 operate at capacity factors greater than 90 percent (Michaels 2010). Indiana has one waste 39 recovery facility that produces steam; Iowa has one waste-to-energy facility that produces 40 10 MW of electricity; Michigan has three facilities that produce 89.7 MW of electricity; and 41 Wisconsin has two facilities that generate 32.3 MW of electricity (Michaels 2010). In total, as of 42 2010, the ROI had a municipal solid waste generating capacity of 132 MW. More than 43 46 average-sized plants would be necessary to provide the same level of output as LSCS, 44 almost doubling the national waste-to-energy generation. 45 The decision to burn municipal waste to generate energy is usually driven by the need for an 46 alternative to landfills rather than energy considerations. Given the improbability that additional 47 stable supplies of municipal solid waste would be available to support approximately 46 new 2-22

Alternatives Including the Proposed Action 1 facilities and that so few existing plants operate in the ROI, the NRC staff does not consider 2 municipal solid waste combustion to be a reasonable alternative to LSCS license renewal. 3 2.3.11 Petroleum 4 In the ROI, oil-fired generation in 2012 had a generating capacity of 4,986 MW (EIA 2014c). 5 The variable costs of oil-fired generation tend to be greater than those of the nuclear or 6 coal-fired operations, and oil-fired generation tends to have greater environmental impacts than 7 natural gas-fired generation. The high cost of oil has resulted in a steady decline in its use for 8 electricity generation (EIA 2013a). Given the high cost of oil and the small generating capacity 9 from oil-fired power plants in the ROI, the NRC staff does not consider oil-fired generation a 10 reasonable alternative to LSCS license renewal. 11 2.3.12 Supercritical Pulverized Coal 12 In general, SCPC power plants are feasible, commercially available options for providing 13 electrical generating capacity. Baseload coal units have proven their reliability and can sustain 14 capacity factors as high as 79 percent. Pulverized coal power generation uses crushed coal 15 that is fed into a boiler where it is burned to create heat. The heat produces steam that is used 16 to spin one or more turbines to generate electricity. Among the technologies available, 17 pulverized coal boilers producing supercritical steam (SCPC boilers) are increasingly common 18 for new coal-fired plants given their high operating temperatures and pressures that increase 19 thermal efficiencies and overall reliability. SCPC facilities consume less fuel per unit output, 20 reducing environmental impacts (NETL undated). 21 As described in Section 2.2.3, EPA has signed a final rule for carbon pollution that would apply 22 to new fossil fuel-fired power plants, including SCPC facilities (80 FR 64661-65120). The 23 action establishes performance standards and has identified a CCS system as a method of 24 emission reduction. The emission limit for these sources of 1,305 lb CO2/MWh, and any new 25 coal-fired power plants could require CCS in order to achieve this emission limit. 26 In addition, given known technology and technological and demographic trends, EIA predicts 27 that by 2040 natural gas will surpass coal as the largest share of U.S. electric power generation 28 (EIA 2013a). This does not consider the EPA rule described above but indicates a general 29 trend away from coal-fired facilities in favor of natural gas-fired power plants due to falling 30 natural gas prices. MISO projected that the EPA regulations could lead to increased coal plant 31 retirements and estimated retirements between 3,000 MW to 12,600 MW, which could have a 32 large impact on MISOs reserve margin in the future (MISO 2011). 33 Although SCPC plants are currently the most widely used source of electricity generation within 34 the ROI, given the potential for stringent air quality regulations and trends toward natural 35 gas-fired power plants, the NRC staff does not consider SCPC to be a reasonable alternative to 36 LSCS license renewal. Instead, the NRC staff describes an IGCC plant under the coal 37 alternative in Section 2.2.2.2. 38 2.4 Comparison of Alternatives 39 In this chapter, the NRC staff considered the following alternatives to LSCS license renewal: 40 new nuclear generation; IGCC generation; NGCC generation; a combination alternative of 41 natural gas, wind, and solar; and purchased power. The NRC also considered the no-action 42 alternative and its effects. The impacts for all alternatives to LSCS license renewal are 43 discussed in Chapter 4 and summarized in Table 2-2 below. 2-23

Alternatives Including the Proposed Action 1 The environmental impacts of the proposed action (issuing renewed LSCS operating licenses) 2 would be SMALL for all impact categories. The environmental impacts from all other 3 alternatives would be larger than the proposed license renewal, as shown in Table 2-2. 4 In conclusion, the environmentally preferred alternative is the granting of renewed licenses for 5 LSCS. All other alternatives capable of meeting the needs currently served by LSCS entail 6 potentially greater impacts than those of the proposed action of renewing the license for LSCS. 7 To make up the lost power generation if a renewed license is not issued (the no-action 8 alternative), one or a combination of alternatives would be implemented, all of which have 9 greater impacts than the proposed action. Hence, the NRC staff concludes that the no-action 10 alternative will have environmental impacts greater than or equal to those of the proposed 11 license renewal action. 2-24

1 Table 2-2. Summary of Environmental Impacts of Proposed Action and Alternatives LSCS License Combination Renewal Alternative Impact Area (Proposed New Nuclear IGCC NGCC (NGCC, Wind, Purchased (Resource) Action) No-Action Alternative Alternative Alternative and Solar) Power Land Use and Visual Resources SMALL TO SMALL TO SMALL TO SMALL TO Land Use SMALL SMALL SMALL MODERATE LARGE MODERATE MODERATE SMALL TO SMALL TO Visual Resources SMALL SMALL SMALL SMALL SMALL MODERATE LARGE Air Quality and Noise SMALL TO Air Quality SMALL SMALL SMALL MODERATE MODERATE SMALL MODERATE SMALL TO SMALL TO SMALL TO Noise SMALL SMALL SMALL SMALL MODERATE MODERATE MODERATE Geologic Environment SMALL SMALL SMALL SMALL SMALL SMALL SMALL 2-25 Water Resources Surface Water SMALL TO SMALL TO SMALL TO SMALL SMALL SMALL SMALL Resources MODERATE MODERATE MODERATE Groundwater SMALL SMALL SMALL SMALL SMALL SMALL SMALL Resources SMALL TO MODERATE SMALL TO SMALL TO Terrestrial Resources SMALL SMALL SMALL MODERATE TO LARGE MODERATE MODERATE SMALL to SMALL to Aquatic Resources SMALL SMALL SMALL SMALL SMALL MODERATE1 MODERATE Special Status Species NO EFFECT SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 SEE NOTE2 

      & Habitats Historic and                                                                                    SMALL TO       SMALL TO SEE NOTE3     SMALL       SMALL          SMALL         SMALL Cultural Resources                                                                              LARGE          LARGE Socioeconomics SMALL TO    SMALL TO       SMALL TO      SMALL TO                      SMALL TO Socioeconomics           SMALL                                                                 SMALL LARGE       LARGE          LARGE         LARGE                         LARGE Alternatives including the Proposed Action

LSCS License Combination Renewal Alternative Impact Area (Proposed New Nuclear IGCC NGCC (NGCC, Wind, Purchased (Resource) Action) No-Action Alternative Alternative Alternative and Solar) Power SMALL TO SMALL TO SMALL TO SMALL TO SMALL TO Transportation SMALL SMALL LARGE LARGE LARGE MODERATE LARGE Human Health SMALL SMALL SMALL SMALL SMALL SMALL SMALL Environmental Justice SEE NOTE4 SEE NOTE5 SEE NOTE6 SEE NOTE6 SEE NOTE6 SEE NOTE6 SEE NOTE6 Waste Management SMALL TO SMALL TO and Pollution SMALL SMALL SMALL SMALL SMALL MODERATE MODERATE Prevention Key: IGCC = coal-integrated gasification combined-cycle (alternative), NGCC = natural gas combined-cycle (alternative), NRHP = National Register of Historic Places, APE = area of potential effect, CRMP = Cultural Response Management Plan, and IHPA = Illinois Historic Preservation Agency. (1) Thermal impacts would be SMALL for aquatic resources in the Illinois River and SMALL to MODERATE for aquatic resources in the cooling pond. Alternatives including the Proposed Action MODERATE thermal impacts would primarily be experienced by gizzard and threadfin shad in the cooling pond. (2) The magnitude of impacts could vary widely based on site selection and the presence or absence of special status species and habitats when the alternative is implemented; therefore, the NRC staff cannot forecast a level of impact for this alternative. 2-26 (3) Based on (1) there being currently no NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelons draft CRMP, (4) the fact that no license renewal-related physical changes or ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource assessment, license renewal would not affect any known historic properties (36 CFR 800.4(d)(1)). (4) Continued operation of LSCS would not have disproportionately high and adverse human health and environmental effects on minority and low-income populations. (5) The no-action alternative could disproportionately affect minority and low-income populations. (6) Based on this information and the analysis of human health and environmental impacts presented in this SEIS, it is not likely that this alternative would have disproportionately high and adverse human health and environmental effects on minority and low-income populations. However, this determination would depend on the location, plant design, and operational characteristics of the alternative. Therefore, the NRC staff cannot determine whether this alternative would result in disproportionately high and adverse human health and environmental effects on minority and low-income populations.

Alternatives Including the Proposed Action 1 2.5 References 2 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, Domestic licensing of 3 production and utilization facilities. 4 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, Environmental 5 protection regulations for domestic licensing and related regulatory functions. 6 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, Requirements for 7 renewal of operating licenses for nuclear power plants. 8 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forest, and Public Property, 9 Part 800, Protection of historic properties. 10 80 FR 26302. U.S. Nuclear Regulatory Commission. DTE Electric Company: Fermi 3. 11 Combined license and record of decision: Issuance. Federal Register 80:26302-26303. 12 May 7, 2015. 13 AmerenUE. 2009. Callaway Plant Unit 2 Combined License Application Part 3: Environmental 14 Report. Revision 1. February 2009. 1,444 p. Agencywide Documents Access and 15 Management System (ADAMS) No. ML090710402. 16 Archer CL, Jacobson MZ. 2007. Supplying baseload power and reducing transmission 17 requirements by interconnecting wind farms. Journal of Applied Meteorology and 18 Climatology 46(11):1701-1717. Available at 19 <http://www.stanford.edu/group/efmh/winds/aj07_jamc.pdf> (accessed 28 August 2015). 20 Ardani K, Margolis R. 2011. 2010 Solar Technologies Market Report. Golden, Colorado: 21 National Renewable Energy Laboratory. November 2011. 136 p. Available at 22 <http://www.nrel.gov/docs/fy12osti/51847.pdf> (accessed 28 August 2015). 23 Associated Press. 2015. Nuclear plants in Illinois could be shuttered if they dont get a break 24 from state, Exelon says. Chicago Sun-Times. March 28, 2015. Available at 25 <http://chicago.suntimes.com/business/7/71/477077/nuclear-plants-illinois-shuttered-dont-get-26 break-state-exelon-says> (accessed 28 August 2015). 27 Barker, J. 2015. Ameren officially pulls plug on new Callaway nuke. St. Louis Post-Dispatch. 28 July 31, 2015. Available at <http://www.stltoday.com/business/local/ameren-officially-pulls-plug-29 on-new-callaway-nuke/article_c4202562-c6c3-5b93-95ee-f45dd8778378.html> (accessed 30 2 September 2015). 31 [BLM and DOE] U.S. Department of the Interior Bureau of Land Management and 32 U.S. Department of Energy. 2010. Draft Programmatic Environmental Impact Statement for 33 Solar Energy Development in Six Southwestern States. DES 10-59, DOE/EIS-0403, Volumes 1 34 to 8. December 2010. 11,145 p. Available at 35 <http://www.solareis.anl.gov/documents/dpeis/index.cfm> (accessed 4 September 2015). 36 [BLM and DOE] U.S. Department of the Interior Bureau of Land Management and 37 U.S. Department of Energy. 2012. Final Programmatic Environmental Impact Statement 38 (PEIS) for Solar Energy Development in Six Southwestern States. FES 12-24, DOE/EIS-0403, 39 Volumes 1 to 7. July 2012. 3,596 p. Available at 40 <http://www.solareis.anl.gov/documents/fpeis/index.cfm> (accessed 28 August 2015). 41 [BOEM] Bureau of Ocean Energy Management. undated. Ocean Wave Energy. Available at 42 <http://www.boem.gov/Renewable-Energy-Program/Renewable-Energy-Guide/ 43 Ocean-Wave-Energy.aspx> (accessed 28 August 2015). 2-27

Alternatives Including the Proposed Action 1 Channell J, Lam T, Pourreza S. 2012. Shale & renewables: A symbiotic relationship. 2 CITI Research. September 12, 2012. 88 p. Available at <http://www.ourenergypolicy.org/ 3 wp-content/uploads/2013/04/citigroup-renewables-and-natgas-report.pdf> (accessed 4 28 August 2015). 5 [ComEd] Commonwealth Edison Company. 2015. ComEdAn Exelon Company: 6 Company Profile. Available at <https://www.comed.com/about-us/company-7 information/Pages/profile.aspx> (accessed 28 August 2015). 8 Conner AM, Francfort JE, Rinehart BN. 1998. U.S. Hydropower Resource Assessment, Final 9 Report. Idaho Falls, Idaho. Idaho National Engineering and Environmental Laboratory. 10 DOE/ID-10430.2. December 1998. 49 p. Available at 11 <http://hydropower.inl.gov/resourceassessment/pdfs/doeid-10430.pdf> (accessed 12 28 August 2015). 13 [DOE] U.S. Department of Energy. 2008. 20% Wind Energy by 2030Increasing Wind 14 Energys Contribution to U.S. Electricity Supply. DOE/GO-102008-2567. July 2008. 228 p. 15 Available at <http://www.nrel.gov/docs/fy08osti/41869.pdf> (accessed 10 September 2015). 16 [DOE] U.S. Department of Energy. 2010a. Kemper County Integrated Gasification 17 Combined-Cycle (IGCC) Project, Final Environmental Impact Statement (EIS). 18 Washington, DC: DOE. DOE/EIS-0409, Volume 1. May 2010. 671 p. Available at 19 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/ 20 EIS-0409-FEIS-01-2010.pdf> (accessed 28 August 2015). 21 [DOE] U.S. Department of Energy. 2010b. Final Environmental Assessment for Department of 22 Energy Loan Guarantee for the Agua Caliente Solar Project in Yuma County, Arizona. 23 DOE/EA-1797. November 2010. Available at 24 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/EA-1797-FEA-2010.pdf> 25 (accessed 28 August 2015). 26 [DOE] U.S. Department of Energy. 2015. WINDExchange: U.S. Installed Wind Capacity. 27 Available at <http://www.windpoweringamerica.gov/wind_installed_capacity.asp> (accessed 28 28 August 2015). 29 [DOE] U.S. Department of Energy. 2013a. Fuel CellBasics. August 14, 2013. Available at 30 <http://energy.gov/eere/energybasics/articles/fuel-cell-basics> (accessed 31 August 2015). 31 [DOE] U.S. Department of Energy. 2013b. Geothermal Resource Basics. August 14, 2013. 32 Available at <http://energy.gov/eere/energybasics/articles/geothermal-resource-basics> 33 (accessed 31 August 2015). 34 [DOE] U.S. Department of Energy. undated. Small Modular Nuclear Reactors. Available at 35 <http://energy.gov/ne/nuclear-reactor-technologies/small-modular-nuclear-reactors> (accessed 36 28 August 2015). 37 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2014. Iowa Alternative 38 Energy Law. October 31, 2014. Available at 39 <http://programs.dsireusa.org/system/program/detail/265> (accessed 31 August 2015). 40 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015a. Illinois Renewable 41 Portfolio Standard. June 26, 2015. Available at 42 <http://programs.dsireusa.org/system/program/detail/584> (accessed 31 August 2015). 43 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015b. Missouri 44 Renewable Electricity Standard. May 18, 2015. Available at 45 <http://programs.dsireusa.org/system/program/detail/2622> (accessed 31 August 2015). 2-28

Alternatives Including the Proposed Action 1 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015c. Wisconsin 2 Renewable Portfolio Standard. May 6, 2015. Available at 3 <http://programs.dsireusa.org/system/program/detail/190> (accessed 31 August 2015). 4 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2015d. Michigan 5 Renewable Energy Standard. June 25, 2015. Available at 6 <http://programs.dsireusa.org/system/program/detail/3094> (accessed 31 August 2015). 7 [DSIRE] Database of State Incentives for Renewable Energy. 2015e. Indiana Clean Energy 8 Portfolio Goal. May 12, 2015. Available at 9 <http://programs.dsireusa.org/system/program/detail/4832> (accessed 31 August 2015). 10 Duke Energy. 2013. Project Overview. Available at <http://www.duke-energy.com/ 11 about-us/edwardsport-overview.asp> (accessed 31 August 2015). 12 [EIA] U.S. Energy Information Administration. 2010. Updated Capital Cost Estimates for 13 Electricity Generation Plants. November 2010. Available at 14 <http://www.eia.gov/oiaf/beck_plantcosts/index.html> (accessed 31 August 2015). 15 [EIA] U.S. Energy Information Administration. 2012. Voluntary Reporting of Greenhouse 16 Gases ProgramEmission Factors and Global Warming. Available at 17 <http://www.eia.gov/oiaf/1605/emission_factors.html> (accessed 31 August 2015). 18 [EIA] U.S. Energy Information Administration. 2013a. Annual Energy Outlook 2013 with 19 Projections to 2040. DOE/EIA 0383 (2013). Washington, DC: EIA. April 26, 2013. 244 p. 20 Available at <http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf> (accessed 28 August 2015). 21 [EIA] U.S. Energy Information Administration. 2013b. Annual Energy Outlook 2014 Early 22 Release. December 16, 2013. Available at <http://www.eia.gov/forecasts/archive/ 23 aeo14/er/pdf/0383er(2014).pdf> (accessed 28 August 2015). 24 [EIA] U.S. Energy Information Administration. 2013c. U.S. Energy Information Administration 25 Frequently Asked Questions. How much coal, natural gas, or petroleum is used to generate a 26 kilowatthour of electricity? Available at <http://www.eia.gov/tools/faqs/faq.cfm?id=667&t=2> 27 (accessed 31 August 2015). 28 [EIA] U.S. Energy Information Administration. 2013d. U.S. Energy Information Administration 29 Today in Energy. Natural gas-fired combustion turbines are generally used to meet peak 30 electricity load. October 1, 2013. Available at 31 <http://www.eia.gov/todayinenergy/detail.cfm?id=13191> (accessed 31 August 2015). 32 [EIA] U.S. Energy Information Administration. 2014a. U.S. Energy Information 33 AdministrationToday in Energy. AEO2014 projects more coal-fired power plant retirements 34 by 2016 than have been scheduled. February 14, 2014. Available at 35 <http://www.eia.gov/todayinenergy/detail.cfm?id=15031&src=email> (accessed 36 31 August 2015). 37 [EIA] U.S. Energy Information Administration. 2014b. State Electricity Profiles 2011. 38 Washington, DC: EIA. Available at <http://www.eia.gov/electricity/state/archive/sep2011.pdf> 39 (accessed 31 August 2015). 40 [EIA] U.S. Energy Information Administration. 2014c. State Electricity Profiles 2012. 41 Washington, DC: EIA. Available at <http://www.eia.gov/electricity/state/archive/2012/> 42 (accessed 1 September 2015). 2-29

Alternatives Including the Proposed Action 1 [EIA] U.S. Energy Information Administration. 2015. Annual Energy Outlook 2015 with 2 Projections to 2040. DOE/EIA 0383 (2015). Washington, DC: EIA. April 14, 2015. 154 p. 3 Available at <http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf> (accessed 4 2 September 2015). 5 Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 6 [EPA] U.S. Environmental Protection Agency. 2014a. Municipal Solid Waste: Basic 7 Information about Energy Recovery from Waste. Available at 8 <http://www.epa.gov/osw/nonhaz/municipal/wte/basic.htm> (accessed 31 August 2015). 9 [EPA] U.S. Environmental Protection Agency. 2014b. Municipal Solid Waste: Energy 10 Recovery from Waste. Available at <http://www.epa.gov/osw/nonhaz/municipal/wte/> 11 (accessed 31 August 2015). 12 [EPA] U.S. Environmental Protection Agency. 2015. Mercury and Air Toxics Standards. 13 Available at <http://www3.epa.gov/mats/> (accessed 13 October 2015). 14 [EPRI] Electric Power Research Institute. 2011. Mapping and Assessment of the United States 15 Ocean Wave Energy Resource. Palo Alto, California: EPRI. 1024637. December 2011. 16 176 p. Available at <http://www1.eere.energy.gov/water//pdfs/mappingandassessment.pdf> 17 (accessed 31 August 2015). 18 [Exelon] Exelon Generation Company, LLC. 2014. Applicants Environmental Report 19 Operating License Renewal Stage, LaSalle County Station, Units 1 and 2, License Renewal 20 Application. Kennett Square, Pennsylvania: Exelon. December 9, 2014. ADAMS 21 No. ML14343A883. 22 [Exelon] Exelon Generation Company, LLC. undated. PJM TOA-AC July Meeting, At-Risk 23 Generation Retirement. 6 p. Available at <http://www.pjm.com/~/media/committees-24 groups/committees/toa-ac/20100715/20100715-item-04-generation-retirements.ashx> 25 (accessed 31 August 2015). 26 [FERC] Federal Energy Regulatory Commission. 2013. Centralized Capacity Market Design 27 Elements. Commission Staff Report AD13-7-000. August 23, 2013. 34 p. Available at 28 <http://www.ferc.gov/CalendarFiles/20130826142258-Staff%20Paper.pdf> (accessed 29 31 August 2015). 30 Haq Z. undated. Biomass for Electricity Generation. U.S. Energy Information Administration. 31 18 p. Available at <http://www.eia.gov/oiaf/analysispaper/biomass/pdf/biomass.pdf> (accessed 32 31 August 2015). 33 [IEA] International Energy Agency. 2007. Biomass for Power Generation and CHP. IEA 34 Energy Technology Essentials ETE03. Available at 35 <https://www.iea.org/publications/freepublications/publication/essentials3.pdf> (accessed 36 4 September 2015). 37 [ILGA] Illinois General Assembly. 2011. Illinois Senate Bill 1652, Section 5, Illinois Power 38 Agency Act. Available at <http://www.ilga.gov/legislation/97/SB/09700SB1652enr.htm> 39 (accessed 31 August 2015). 40 Ilic J, Prica M, Rabiei S, Goellner J, Wilson D, Shih C (Booz Allen Hamilton, Inc.). 2011. 41 Technical and Economic Analysis of Various Power Generation Resources Coupled with CAES 42 Systems. National Energy Technology Laboratory. May 17, 2011. DOE/NETL-2011/1472. 43 96 p. Available at <http://www.netl.doe.gov/File%20Library/Research/ 44 Energy%20Analysis/Publications/HybridGeneration05242011.pdf> (accessed 31 August 2015). 2-30

Alternatives Including the Proposed Action 1 Mendelsohn M, Lowder T, Canavan B. 2012. Utility-Scale Concentrating Solar Power and 2 Photovoltaics Projects: A Technology and Market Overview. Golden, Colorado: National 3 Renewable Energy Laboratory. NREL/TP-6A20-51137. April 2012. 65 p. Available at 4 <http://www.nrel.gov/docs/fy12osti/51137.pdf> (accessed 31 August 2015). 5 Michaels T. 2010. The 2010 ERC Directory of Waste-to-Energy Plants. Washington, DC: 6 Energy Recovery Council. November 12, 2010. 32 p. Available at 7 <http://www.energyrecoverycouncil.org/userfiles/file/ERC_2010_Directory.pdf> (accessed 8 31 August 2015). 9 [MISO] Midcontinent Independent System Operator, Inc. 2011. 2011 Long Term Resource 10 Assessment. 34 p. Available at 11 <https://www.misoenergy.org/Library/Repository/Study/Seasonal%20Assessments/ 12 2011%20Long-Term%20Resource%20Assessment.pdf> (accessed 31 August 2015). 13 [MISO-PJM] Midcontinent Independent System Operator, Inc., and PJM Interconnection. 14 undated. Joint and Common Market. Available at <http://www.miso-pjm.com/> (accessed 15 31 August 2015). 16 Musial W (NREL), Ram B (Energetics). 2010. Large-Scale Offshore Wind Power in the 17 United States: Assessment of Opportunities and Barriers. Golden, Colorado: NREL. 18 NREL/TP-500-40745. September 2010. 240 p. Available at 19 <http://www.nrel.gov/docs/fy10osti/40745.pdf> (accessed 31 August 2015). 20 National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 21 National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq. 22 [NETL] National Energy Technology Laboratory. 2007. Natural Gas Combined-Cycle Plant. 23 4 p. Available at 24 <http://www.netl.doe.gov/KMD/cds/disk50/NGCC%20Plant%20Case_FClass_051607.pdf> 25 (accessed 31 August 2015). 26 [NETL] National Energy Technology Laboratory. 2013a. Cost and Performance Baseline for 27 Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity. Revision 2a. 28 DOE/NETL-2010/1397, September 2013. 626 p. Available at 29 <http://www.netl.doe.gov/File%20Library/research/energy%20analysis/publications/ 30 BitBase_FinRep_Rev2.pdf> (accessed 31 August 2015). 31 [NETL] National Energy Technology Laboratory. 2013b. IGCC Project Examples. Available 32 at <http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/ 33 project-examples> (accessed 31 August 2015). 34 [NETL] National Energy Technology Laboratory. 2013c. Gasification Database: Proposed 35 U.S. Projects Having Commercial Potential. October 2013. Available at 36 <http://www.netl.doe.gov/File%20Library/research/coal/energy%20systems/gasification/ 37 worldwide%20database/US-Gasification-Database.xlsx> (accessed 31 August 2015). 38 [NETL] National Energy Technology Laboratory. undated. Supercritical Pulverized Bituminous 39 Coal Plant. 4 p. Available at <http://www.netl.doe.gov/KMD/cds/disk50/ 40 PC%20Plant%20Case_Supercritical_051507.pdf> (accessed 31 August 2015). 41 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement 42 for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG-1437, 43 Volumes 1 and 2. May 31, 1996. 1,204 p. ADAMS Nos. ML040690705 and ML040690738. 2-31

Alternatives Including the Proposed Action 1 [NRC] U.S. Nuclear Regulatory Commission. 2002. Final Generic Environmental Impact 2 Statement on Decommissioning of Nuclear Facilities: Supplement 1, Regarding the 3 Decommissioning of Nuclear Power Reactors. NUREG-0586, Volumes 1 and 2. 4 Washington, DC: NRC. November 30, 2002. 516 p. ADAMS Nos. ML023470327, 5 ML023500228, and ML023500295. 6 [NRC] U.S. Nuclear Regulatory Commission. 2008. Final Environmental Impact Statement for 7 an Early Site Permit (ESP) at the Vogtle Electric Generating Plant Site. Washington, DC: NRC. 8 NUREG-1872, Volumes 1 and 2. August 2008. 1,242 p. Available at 9 <http://www.nrc.gov/reading-rm/doc-collections/nuregs/staff/sr1872/index.html> (accessed 10 31 August 2015). 11 [NRC] U.S. Nuclear Regulatory Commission. 2009. Frequently Asked Questions about License 12 Applications for New Nuclear Power Reactors. NUREG/BR-0468. December 2009. 110 p. 13 Available at <http://www.nrc.gov/reading-rm/doc-collections/nuregs/brochures/br0468/> 14 (accessed 31 August 2015). 15 [NRC] U.S. Nuclear Regulatory Commission. 2011. Final Supplemental Environmental Impact 16 Statement for Combined Licenses (COLs) for Vogtle Electric Generating Plant, Units 3 and 4, 17 Final Report. Washington, DC: NRC. NUREG-1947. March 2011. 568 p. ADAMS 18 No. ML11076A010. 19 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement 20 for License Renewal of Nuclear Plants. Revision 1. Washington, DC: NRC. NUREG-1437, 21 Volumes 1, 2, and 3. June 30, 2013. 1,535 p. ADAMS Nos. ML13106A241, ML13106A242, 22 and ML13106A244. 23 [NRC] U.S. Nuclear Regulatory Commission. 2015. Status of License Renewal Applications 24 and Industry Activities. Available at <http://www.nrc.gov/reactors/operating/licensing/ 25 renewal/applications.html> (accessed 31 August 2015). 26 [NREL] National Renewable Energy Laboratory. 2014a. Dynamic Maps, GIS Data, and 27 AnalysisWind Data Details. February 6, 2014. Available at 28 <http://www.nrel.gov/gis/wind_detail.html> (accessed 4 September 2015). 29 [NREL] National Renewable Energy Laboratory. 2014b. Learning about Renewable Energy 30 Solar Energy Basics. July 25, 2014. Available at <http://www.nrel.gov/learning/re_solar.html> 31 (accessed 31 August 2015). 32 [NREL] National Renewable Energy Laboratory. 2015a. Dynamic Maps, GIS Data, and 33 Analysis ToolsWind Data. April 15, 2015. Available at 34 <http://www.nrel.gov/gis/data_wind.html> (accessed 4 September 2015). 35 [NREL] National Renewable Energy Laboratory. 2015b. Dynamic Maps, GIS Data, and 36 Analysis ToolsSolar Maps. February 2, 2015. Available at 37 <http://www.nrel.gov/gis/solar.html> (accessed 4 September 2015). 38 Ong S, Campbell C, Denholm P, Margolis R, Heath G. 2013. Land-Use Requirements for Solar 39 Power Plants in the United States. Golden, Colorado: National Renewable Energy Laboratory. 40 NREL/TP-6A20-56290. June 2013. 47 p. Available at 41 <http://www.nrel.gov/docs/fy13osti/56290.pdf> (accessed 31 August 2015). 42 [ORNL] Oak Ridge National Laboratory. 2012. An Assessment of Energy Potential at 43 Non-Powered Dams in the United States. Oak Ridge, Tennessee: ORNL. April 2012. 44 p. 44 Available at <http://www1.eere.energy.gov/water/pdfs/npd_report.pdf> (accessed 45 31 August 2015). 2-32

Alternatives Including the Proposed Action 1 Ott A. 2013a. Centralized Capacity Markets in Regional Transmission Organizations and 2 Independent System Operators. Norristown, Pennsylvania: PJM Interconnection, LLC. 3 October 3, 2013. 33 p. Available at <http://www.pjm.com/~/media/about-pjm/who-we-4 are/public-disclosures/20131004-board-response-to-chairman-powelson-regarding-generation-5 retirements.ashx> (accessed 31 August 2015). 6 Ott A. 2013b. PJM/MISO Seams Coordination and Capacity Deliverability. Norristown, 7 Pennsylvania: PJM Interconnection, LLC. June 20, 2013. 9 p. Available at 8 <http://www.ferc.gov/industries/electric/indus-act/rto/pjm.pdf> (accessed 31 August 2015). 9 [Reuters] Thomson Reuters. 2012. Southern, Duke push US coal gasification; others quit. 10 June 12, 2012. Available at <http://www.reuters.com/article/2012/06/12/ 11 utilities-coal-gasification-idUSL1E8H78P420120612> (accessed 31 August 2015). 12 [TEEIC] Tribal Energy and Environmental Information Clearinghouse. undated. Utility-Scale 13 and Direct Use Geothermal Energy Generation. Available at 14 <http://teeic.indianaffairs.gov/er/geothermal/restech/scale/index.htm> (accessed 15 31 August 2015). 16 Tidball R, Bluestein J, Rodriguez N, Knoke S (ICF International). 2010. Cost and Performance 17 Assumptions for Modeling Electricity Generation Technologies. Golden, Colorado: National 18 Renewable Energy Laboratory. NREL/SR-6A20-48595. November 2010. 211 p. Available at 19 <http://www.nrel.gov/docs/fy11osti/48595.pdf> (accessed 31 August 2015). 20 [USGS] U.S. Geological Survey. 2008. Assessment of Moderate- and High-Temperature 21 Geothermal Resources of the United States. Menlo Park, California: USGS. Fact 22 Sheet 2008-3082. 4 p. Available at <http://pubs.usgs.gov/fs/2008/3082/pdf/fs2008-3082.pdf> 23 (accessed 31 August 2015). 24 [WAPA and FWS] Western Area Power Administration and U.S. Fish and Wildlife Service. 25 2013. Upper Great Plains Wind Energy Programmatic Environmental Impact Statement, Draft. 26 DOE/EIS-0408. March 2013. 938 p. Available at 27 <http://plainswindeis.anl.gov/documents/dpeis/Draft_UGP_Wind_Energy_PEIS.pdf> (accessed 28 31 August 2015). 2-33

1 3.0 AFFECTED ENVIRONMENT 2 In this supplemental environmental impact statement (SEIS), the affected environment is the 3 environment that currently exists at and around LaSalle County Station, Units 1 and 2 (LSCS). 4 Because existing conditions are at least partially the result of past construction and operation at 5 the plant, the impacts of these past and ongoing actions and a discussion on how they have 6 shaped the environment are presented here. The facility and its operation are described in 7 Section 3.1. The affected environment is presented in Sections 3.2 to 3.13. 8 3.1 Description of Nuclear Power Plant Facility and Operation 9 LSCS is a two unit nuclear power plant located in LaSalle County, Illinois. It began commercial 10 operation in January 1984 (Unit 1) and October 1984 (Unit 2). Generally, the U.S. Nuclear 11 Regulatory Commission (NRC) staff drew information about LSCSs facilities and operation from 12 the Exelon Generation Company, LLC (Exelon), Environmental Report (ER) (Exelon 2014a). 13 3.1.1 External Appearance and Setting 14 The LSCS site is approximately 82 driving miles (mi) (132 kilometers (km)) southwest of OHare 15 International Airport in Chicago, Illinois, and approximately 26 mi (42 km) west of Exelons 16 Braidwood Generating Station in Braceville, Illinois. Interstate Highway 80 is 8 mi (13 km) north 17 of the site. Figure 3-1 presents the 50-mi (80-km) area around LSCS. 18 The LSCS site is located in a rural and agricultural setting. However, the surroundings are 19 dominated by many wind turbines. Each wind turbine is 389 feet (ft) (119 meters (m)) tall (which 20 includes the length of one of its three 126.5-ft (38.5-m) rotator blades). The town of Seneca lies 21 6 mi (10 km) northeast of LSCS. The town of Marseilles lies 7 mi (11 km) north-northwest of 22 LSCS. The Illinois River is 5 mi (8 km) north of LSCS. The Chicago, Rock Island and Pacific 23 Railroad, which runs parallel to, and slightly north of, the Illinois River, is the closest railroad line 24 in this area. A 6-mi (10-km) rail spur connects LSCS to the Atchison, Topeka, and Santa Fe 25 Railroad south of the site (Exelon 2014a). Figure 3-2 presents the 6-mi (10-km) area around 26 LSCS. 27 The LSCS site is approximately 3,776 acres (ac) (1,528 hectares (ha)) of which approximately 28 2,058 ac (833 ha) are the cooling pond. Underground pipelines approximately 3.5 mi (5.6 km) 29 long connect the cooling pond to the Illinois River, which is the source of the plants makeup 30 water and the receiving body of water for plant discharges. This pipeline corridor right-of-way 31 intersects the eastern portion of the Marseilles State Fish and Wildlife Area, which is managed 32 by the Illinois Department of Natural Resources (IDNR) for hunting and wildlife habitat. Country 33 Road 6 (also known as North 21st Road) provides access to LSCS and runs along the sites 34 southern boundary (Exelon 2014a). Figure 3-3 presents the LSCS site layout. 35 The LSCS sites main structures include two reactor buildings, an auxiliary building (which 36 houses the control room), a turbine building, a diesel generator building, a switchyard, a training 37 building, an interim radioactive waste (radwaste) storage facility, a radwaste building, sewage 38 and wastewater treatment facilities, and an independent spent fuel storage installation (ISFSI). 39 The sites tallest structure is a 400-ft (122-m) meteorological tower. The area of the LSCS site 40 that is completely enclosed by physical barriers and that allows access only at designated 41 control points is called the protected area. A physical protection program at the LSCS site 42 includes surveillance, observation, and monitoring within the protected area (Exelon 2014a). 43 Figure 3-4 presents the LSCS plant features. 3-1

Affected Environment 1 Figure 3-1. LSCS 50-mi (80-km) Radius Map 2 Source: Exelon 2014a 3-2

Affected Environment 1 Figure 3-2. LSCS 6-mi (10-km) Radius Map 2 Source: Exelon 2014a 3-3

Affected Environment 1 Figure 3-3. LSCS Site Layout 2 Source: Exelon 2014a 3-4

Affected Environment 1 Figure 3-4. LSCS Plant Features 2 Source: Exelon 2014a 3-5

Affected Environment 1 3.1.2 Nuclear Reactor Systems 2 The nuclear reactor for each of the two LSCS units is a General Electric boiling water reactor 3 (BWR/5) with Mark II containment. Each LSCS reactor is licensed to produce core power of 4 3,546 megawatts thermal. The annual mean net electrical power capacity for LSCS is 5 2,327 megawatts electric. LSCS uses a 2,058-ac (833-ha) diked cooling pond for core cooling 6 and withdraws makeup water from, and discharges to, the Illinois River (Exelon 2014a). 7 LSCS operates using low-enriched uranium dioxide fuel with enrichment not exceeding a 8 nominal 5.0 percent by weight of uranium-235 and has been historically operated within a 9 maximum analyzed fuel burnup rate of 62,000 megawatt-days per metric ton of 10 uranium (MWd/MTU). In its ER, Exelon stated that, during some future fuel cycles, it expects 11 the peak fuel burnup rate to exceed 62,000 MWd/MTU in some part-length fuel rods. 12 Addendum 1 to Volume 1 of NUREG-1437, Generic Environmental Impact Statement for 13 License Renewal of Nuclear Power Plants (GEIS) (NRC 1999), states that the environmental 14 impacts would be small for transporting spent fuel enriched with up to 5-percent uranium-235 15 with an average burnup for the peak rod of up to 62,000 MWd/MTU. It also states that, if peak 16 fuel burnup is projected to exceed 62,000 MWd/MTU, license renewal applicants must submit 17 an assessment of the implications for the environmental impacts. Exelon submitted an 18 assessment of the environmental impacts of transporting spent fuel enriched with an average 19 burnup for the peak rod exceeding 62,000 MWd/MTU in Section 4.13 of its ER. Appendix G of 20 this document provides the NRC staffs analysis of these projected environmental impacts. 21 Refueling outages for LSCS, Units 1 and 2, are on a staggered 24-month schedule 22 (Exelon 2014a). 23 3.1.3 Cooling and Auxiliary Water Systems 24 LSCS uses a closed-cycle, recirculating cooling system that includes an artificial cooling pond 25 for heat dissipation. In this type of closed-cycle system, the cooling pond serves as the primary 26 source of water to cool plant components and as the primary receiving body for excess heat. 27 In BWRs like those used at LSCS, steam is produced directly in each reactor vessel. The 28 steam passes through moisture separators and steam dryers and then flows to the turbine. 29 Such systems contain only two heat transfer (exchange) loops. The primary loop transports the 30 steam from the reactor vessel directly to the turbine, which generates electricity. The secondary 31 cooling loop removes excess heat from the primary loop in the main condenser. From the 32 condenser, the primary condensate is returned as feedwater to the reactor, and the secondary 33 cooling loop removes the excess heat (NRC 2013). At LSCS, condenser cooling water is 34 discharged directly to the cooling pond, where the heat is dissipated through mixing and 35 evaporation (Exelon 2014a). 36 Cooling water that is not otherwise lost from the pond through evaporation or seepage or that is 37 consumed in the process is recirculated from the cooling pond through the condenser systems 38 in a continuous loop. In addition, a portion of the water in the cooling pond is discharged as 39 blowdown on a near continuously basis under normal conditions. (Blowdown is water that is 40 rinsed from the cooling system (i.e., cooling pond) to remove impurities that may degrade plant 41 performance.) Total dissolved solids are the primary constituents of concern to prevent scale 42 buildup on plant components. 43 All water lost from the recirculating system must be replaced with fresh water; this water is 44 referred to as makeup water (Exelon 2014a; NRC 2013). Makeup water for the onsite cooling 45 pond is withdrawn from, and blowdown is discharged to, the Illinois River, which lies 3.5 mi 46 (5.6 km) north of LSCSs cooling pond. The intake and blowdown pipelines are routed through 3-6

Affected Environment 1 a common right-of-way corridor. Figure 3-5 provides a basic schematic diagram of a 2 closed-cycle, recirculating cooling system that uses a cooling pond. 3 Figure 3-5. Closed-Cycle Cooling System with Cooling Pond 4 Source: Modified from NRC 2013, Figure 3.1-4 5 Groundwater is also used by LSCS for potable water, sanitary water, and demineralized water 6 makeup systems. 7 Unless otherwise cited, the NRC primarily drew information about LSCSs cooling and auxiliary 8 water systems from Exelons ER (Exelon 2014a, 2015b) and its Updated Final Safety Analysis 9 Report (UFSAR) (Exelon 2014b). The NRC staff visited the facilities cited herein during the 10 May 2015 environmental site audit (NRC 2015b). Descriptions of the individual plant cooling 11 and auxiliary systems and components that interact with the environment are provided below. 12 Cooling Pond and Ultimate Heat Sink. Water for the circulating water system (CWS) for 13 condenser cooling water and for the plant service water system are supplied directly from the 14 cooling pond. 15 The LSCS cooling pond is an engineered impoundment encompassing 2,058 ac (833 ha) with 16 an average depth of 15 ft (4.7 m) (NRC 1978) (Figure 3-6). The pond has an elevation of 700 ft 17 (213 m) above mean sea level (MSL) at normal pool elevation. At this water elevation, the 18 cooling pond has a storage capacity of 31,706 acre-feet (39 million cubic meters (m3)) of water. 19 This impoundment was formed by constructing earthen dikes to enclose the north, east, and 20 south sides of the pond; the natural levee of the Illinois River forms the fourth side. Engineered 21 fill consisting of silty-clay, taken from borrow areas within the pond basin, was used in the 22 construction of these peripheral dikes. A perimeter drainage ditch designed to intercept runoff 23 and to capture and direct seepage toward surface drainages and away from the dikes flanks the 24 ponds dikes (Exelon 2014b). 25 Integral to the ponds construction are three internal baffle or finger dikes (i.e., earthen berms), 26 that total 22,623 ft (6,895 m) in length. These structures direct the flow of water from the 27 discharge canal and through the pond to ensure that the coolest water is available for use by 28 LSCS (Exelon 2014b) (Figure 3-6). The average residence time for water in the cooling pond is 29 5.5 days (NRC 1978). 3-7

Affected Environment 1 The peripheral dike system that encloses the cooling pond includes a 300-ft- (91-m)-wide 2 auxiliary spillway structure. The spillway is located northwest of the main plant complex and is 3 adjacent to the discharge canal. The structure is capable of passing a volume of 4 1,069,000 gallons per minute (gpm) (2,380 cubic feet per second (cfs) or 67.2 meters per 5 second (m/s)) of water associated with the probable maximum water level. Discharge from the 6 structure flows north to South Kickapoo Creek, a tributary to the Illinois River (Exelon 2014b). 7 A dedicated portion of the cooling pond located immediately adjacent to the LSCS intake canal 8 serves as the plants ultimate heat sink (UHS). It is also known as the core standby cooling 9 system (CSCS) pond and directly supplies the CSCS equipment cooling water system, as 10 discussed below. This excavated area comprises 83 ac (34 ha) in size and is 5 ft (1.5 m) deep 11 below grade. It can hold 460 acre-feet (567,000 m3) of water. This volume of water is sufficient 12 to supply 30 days of cooling water following safe shutdown from normal operating or accident 13 conditions. The CSCS pond can function even if the perimeter dikes of the cooling pond are 14 breached (Exelon 2014b). 15 Illinois River Water Makeup System. Cooling pond makeup water is withdrawn via the river 16 screen house located on the south bank of the Illinois River at Illinois River Mile (RM) 249.5 17 (River Kilometer (RKm) 401.5) (Figure 3-6). The river screen house is situated approximately 18 3.5 mi (5.6 km) north of the cooling pond. The structure is designed to withstand the 100-year 19 flood of the Illinois River (Exelon 2014b). 20 The river screen house contains three makeup water pumps, each with a capacity of 21 30,000 gpm (67 cfs or 1.9 cubic meters per second (m3/s)). Two pumps are normally operated 22 at all times to meet cooling pond makeup demands, with the third serving as a backup. 23 However, when reduced evaporation demands allow (winter months), the pump discharge ball 24 valves are closed to 30 degrees (one-third open) (Exelon 2015c). 25 River water is first drawn through an intake flume in the bottom of the river and then into a 26 72-ft-- (22-m)-wide funnel inlet basin with concrete dam located 24 ft (7 m) from the shoreline 27 frontage of the river screen house. The inlet is protected by a floating log boom to deflect river 28 debris. From the inlet, water then enters the intake forebay of the screen house and passes first 29 through two adjacent bar grills and then through vertical traveling screens with 3/8-inch (in.) 30 (0.95-centimeter (cm)) openings before entering the pumps (Exelon 2014a, 2015a). The bar 31 grills are galvanized steel and measure 3/8 in. (0.95 cm) thick and 4 in. (10 cm) wide. The 32 narrow dimension of each bar is oriented perpendicular to the incoming water flow, and the 33 centerlines of the narrow dimension of adjacent bars are spaced 3 in. (7.6 cm) apart 34 (Exelon 2015c). 35 Water velocity in the river intake channel is reported as ranging from 0.3 to 0.5 feet per second 36 (fps) (0.10 to 0.15 m/s) with one pump operating and 0.6 to 1.0 fps (0.2 to 0.3 m/s) with two 37 pumps operating. Flow velocity at the travelling screens ranges from about 0.5 to 0.9 fps 38 (0.15 to 0.3 m/s) with one and two makeup pumps in full operation, respectively (NRC 1978; 39 Exelon 2014a). In NRCs Final Environmental Statement for the operating license of LSCS, the 40 NRC staff estimated that the intake velocity at the face of the traveling screens would be 0.5 fps 41 (0.2 m/s) 93 percent of the time and 1.0 fps (0.3 m/s) the remaining 7 percent of the time 42 (NRC 1978). Exelon has not performed any operational studies to further characterize intake 43 flow velocities (Exelon 2015c). Based on the assessment the NRC performed for LSCSs 44 operating license (NRC 1978), the velocity at the face of the traveling screens would typically be 45 within the 0.5fps (0.15m/s) intake velocity now recommended by the U.S. Environmental 46 Protection Agency (EPA) for protection of aquatic organisms (Volume 69 of the Federal 47 Register, page 41576 (69 FR 41576)), although the velocity may be closer to 1.0 fps (0.3m/s) 48 during certain periods during operations. 3-8

Affected Environment 1 Figure 3-6. LSCS Cooling Water Supply and Discharge Facilities 2 Sources: Modified from Exelon 2014a, 2015b 3-9

Affected Environment 1 A backwash system removes debris from the river intake traveling screens, and trash rakes 2 remove debris from bar grills. The backwash system can be set to operate in automatic or 3 manual mode, but the system is normally left in automatic mode unless high debris loading 4 requires manual cleaning. In automatic mode, cleaning is initiated when the measured 5 differential water level across the screens reaches 4 in. (10 cm). With a differential water level 6 of 6 in. (15 cm), the system switches to fast speed. A differential level in excess of 16 in. 7 (40 cm) for at least 15 seconds will cause the associated makeup pumps to trip to prevent 8 cavitation damage. Manual mode with either a slow or fast speed setting may be used during 9 periods of high debris loading (Exelon 2015c). 10 Collected debris, including any impinged biota, is deposited in a trash basket located outside the 11 river screen house, with the debris ultimately disposed of in an offsite permitted landfill. The 12 river screen house is not equipped with a fish return system. Screen backwash and other 13 intermittent discharges from the screen house are discharged to the Illinois River through a 14 National Pollutant Discharge Elimination System (NPDES)-permitted outfall (Outfall 002). The 15 intake forebay of the facility has a floating oil boom to prevent any oil leaks from the screen 16 house from entering the river. Section 3.5.1.3 of this SEIS presents additional information on 17 water quality and LSCSs NPDES permit. 18 With all three river makeup water pumps in operation, LSCSs maximum surface water makeup 19 supply capacity is 90,000 gpm (200 cfs or 5.66 m3/s), which is equivalent to 129.6 million 20 gallons per day (mgd) (491,000 cubic meters per day (m3/day)). Normal peak makeup 21 withdrawal from the Illinois River, with two pumps operating, is 60,000 gpm (134 cfs or 22 3.77 m3/s) or 86.4 mgd (327,000 m3/day). Surface water use is detailed in Section 3.5.1.2. 23 From the river screen house, intake water is pumped south to the northern end of the LSCS 24 cooling pond through a 60-in. (152-cm) pipeline. Upon reaching the pond, the water is 25 conveyed into the pond through a reinforced concrete discharge structure located on the north 26 side of the ponds discharge canal. The structure is designed to prevent erosion of the cooling 27 pond dike (Exelon 2014b) (see Figure 3-6). 28 The river intake pipeline is equipped with air and vacuum relief valves along its course to help 29 guard against pressure surges and other conditions that sometimes occur due to elevation 30 changes along its routing. Nevertheless, the makeup pipeline, which is not a safety-related 31 structure, has experienced a number of breaks resulting in flooding and erosion of areas 32 surrounding the break. The most recent such break occurred on January 23, 2014. Exelon 33 reported the break to both the Illinois Environmental Protection Agency (IEPA) and EPA 34 Region V in accordance with the reporting provisions of Exelons NPDES permit 35 (Exelon 2015c). 36 To address issues associated with pipeline breaks, Exelon has performed maintenance, 37 including replacing relief valves, and has installed instrumentation on the intake traveling 38 screens to alert the LSCS control room operators to abnormal conditions. Exelon has also 39 modified operating and response procedures and has implemented plans and procedures to 40 prevent and quickly respond to any breaks. For example, operational procedures have been 41 modified to include checks on pipeline integrity and to ensure necessary parts are maintained to 42 replace a section of pipeline should a break occur (Exelon 2014a, 2015a). 43 CWS and Blowdown Discharge. The CWS provides cooling water to the main condensers. In 44 addition to the condensers, the system includes the cooling pond, lake screen house, circulating 45 water pumps, piping, valves, and related equipment. The system normally supplies water to the 46 main condensers at temperatures ranging from 32 °F to a maximum of 100 °F (0 to 37.8 °C). 47 However, operating license technical specifications (TS) limit the temperature of the cooling 3-10

Affected Environment 1 water supplied to the facility from the UHS portion of the cooling pond to 101.25 °F (38.5 °C) 2 (Exelon 2014b). 3 The main condenser of each unit requires 616,500 gpm (1,373 cfs or 38.8 m3/s), or 888 mgd 4 (3.36 million m3) of circulating water flow to remove waste heat at 100-percent load. Cooling 5 water is withdrawn from the cooling pond through the lake screen house, which is located at the 6 west end of the intake canal (Figure 3-6). The lake screen house contains six circulating water 7 pumps (three for each unit) that take suction from the service water tunnel (Exelon 2014a). 8 Each pump has a capacity of 205,500 gpm (457.7 cfs or 12.9 m3/s) (Exelon 2015c), with two 9 pumps normally in operation per unit to supply water to the condensers. Water first enters the 10 intake forebays after passing through bar grills and traveling screens with 3/8-in. (0.95-cm) 11 openings. Trash rakes prevent larger debris and aquatic biota from entering the system. The 12 design water intake velocity at the screens is approximately 2.2 fps (0.7 m/s), assuming clean 13 screens. Debris removed from the traveling screens by the screen backwash system and from 14 the bar grills by trash rakes is collected in a trash basket and disposed of in an offsite permitted 15 landfill. Similar to the river intake backwash system, the circulating water backwash system can 16 be operated in either automatic or manual mode. When in automatic mode with a differential 17 water level across the screens ranging between 0 and 6 in. (0 to 15 cm), a timer initiates a 18 3-minute wash cycle every 12 to 14 hours0.583 days <br />0.0833 weeks <br />0.0192 months <br />. With a differential level rising to between 6 and 19 10 in. (15 to 25 cm), a continuous backwash cycle starts at slow speed. The fast setting is 20 triggered with a differential water level exceeding 10 in. (25 cm). Manual mode may be used 21 during fish runs or other periods of high debris intake (Exelon 2015c). Like the river screen 22 house, the lake screen house has no fish return system (Exelon 2014a, 2014b). 23 From the lake screen house, water is pumped through the main condenser of each unit. 24 A chemical feed system, located in facilities adjacent to the lake screen house, injects biocide 25 and other chemical treatments to reduce biofouling, silting, and scale buildup in the condenser 26 systems. After passing through the unit condensers, heated circulating water is returned to the 27 cooling pond through the discharge canal. The nominal (design) temperature rise in the 28 circulating water passing through the main condensers is approximately 26.7 °F (10 °C) 29 (Exelon 2014b). 30 As previously stated, a series of parallel dikes in the cooling pond direct and slow the rate of 31 movement of the returned cooling water through the pond to facilitate residence time cooling 32 processes so that the coolest water is available for uptake again at the lake screen house. 33 This heat dissipation is necessary so that cooling pond blowdown to the Illinois River meets 34 temperature limitations and mixing zone requirements under the Illinois thermal water quality 35 standards (35 IAC 302) and Special Condition 3 of Exelons NPDES Permit No. IL0048151 36 (IEPA 2013). The permit also authorizes the discharge of various other effluent streams to the 37 cooling pond in addition to condenser cooling water, as further described in Section 3.5.1.3 of 38 this SEIS. 39 Blowdown combined with other comingled effluent streams flows through an open channel 40 originating at the west shore of the cooling pond (UHS portion) and then northwest to a spillway 41 adjacent to the LSCS discharge canal. This combined effluent stream can include processed 42 liquid radioactive waste (radwaste), which may be discharged on a batch basis directly into the 43 cooling pond blowdown line at a maximum rate of 45 gpm (0.17 cubic meters per minute), as 44 further described in Section 3.5.1.3 of this SEIS (Exelon 2014a). Nevertheless, the blowdown 45 line is equipped with a radiation monitor that will automatically isolate the radwaste discharge 46 line in the event of a high-radiation signal (Exelon 2014b). 47 The blowdown spillway connects to a 66-in. (168-cm) diameter pipeline through which the 48 collected blowdown travels underground via gravity flow. The pipeline discharges into an 3-11

Affected Environment 1 approximately 500-ft- (150-m)-long discharge structure consisting of a plunge pool and rip-raped 2 lined swale that connects with the Illinois River at RM 249.4 (RKm 401) and just upstream of the 3 LSCS river screen house (see Figure 3-6). The maximum blowdown rate of the system is 4 equal to the maximum intake rate of 90,000 gpm (200 cfs or 5.66 m3/s). However, 5 motor-operated values at both the river and lake ends of the discharge line can be used to 6 isolate the pipeline for maintenance and are used to adjust the blowdown to an average of 7 58,000 gpm (129 cfs or 3.65 m3/s) or less with a target annual average of 30,000 gpm (67 cfs or 8 1.89 m3/s) (Exelon 2014a, 2014b). The blowdown discharge point is regulated under LSCSs 9 NPDES permit as Outfall 001 (see Section 3.5.1.3). 10 Because the blowdown pipeline functions under gravity flow, it is less susceptible to surges and 11 breakage than the river intake pipeline. It is also equipped with air and vacuum relief valves. 12 Nevertheless, breaks do occur. The most recent such break occurred on July 13, 2012. Exelon 13 reported the break to both the IEPA and EPA Region V. As discussed above for the makeup 14 pipeline, Exelon has implemented a program to reduce the frequency of breaks and their 15 impacts on operations and the environment (Exelon 2015c). 16 Plant Service Water System. The service water system provides cooling water for various 17 nonsafety-related auxiliary systems and components, including cooling water for the turbine 18 generator; various air conditioning condensers; and the fuel pool, turbine building, and reactor 19 building heat exchangers. It also supplies water for the lake screen house traveling screen 20 backwash system and the radwaste system, and it is used to fill the fire protection system and 21 serves as a backup fire water supply. Service water is normally supplied by four pumps, with a 22 fifth pump serving as a backup, located in the lake screen house. Each pump has a capacity of 23 16,000 gpm (35.6 cfs or 1.01 m3/s). The pumps take suction from the lake screen house intake 24 service water tunnel and discharge into a common header. Automatic backwash strainers 25 remove any debris that might be passed through the circulating water screens. In addition, the 26 system has two jockey pumps rated at 5,000 gpm (11.1 cfs or 0.31 m3/s). These pumps are 27 powered by an emergency diesel generator and are used to meet minimum flow requirements 28 during a loss of offsite power. The service water is also treated by the chemical feed system to 29 guard against biofouling, scale buildup, corrosion, and silting. Chemical injection occurs directly 30 to the service water tunnel feed lines. All service water return flows are discharged back to the 31 cooling pond (Exelon 2014a, 2014b). 32 Fire Protection Water System. The cooling pond is the source of fire protection water for the 33 LSCS fire hydrants, the water sprinkler and deluge systems, and the hose valve stations. 34 One of two 75-gpm (0.17-cfs or 0.005-m3/s) jockey pumps normally keep the system 35 pressurized. If a system demand occurs, a 225-gpm (0.50-cfs or 0.014-m3/s) intermediate 36 pump is activated. If the demands of the intermediate pump are exceeded, the first of two 37 diesel-driven pumps are automatically engaged. These pumps, each with a capacity of 38 2,500 gpm (51 cfs or 1.44 m3/s), are located in the lake screen house and take suction directly 39 from the service water tunnel (Exelon 2014b). 40 Core Standby Cooling System. This system is equivalent in purpose to the essential service 41 water systems at other nuclear power plants and provides cooling water for the purpose of 42 cooling safety-related equipment necessary for safe shutdown of the reactors. This equipment 43 includes the residual heat removal heat exchangers, pump seal coolers, and emergency diesel 44 generators; the system also provides emergency spent fuel pool makeup water and a source of 45 water for containment flooding for post-accident recovery. The CSCS withdraws cooling pond 46 water from the UHS portion of the cooling pond (as discussed earlier) via the lake screen house 47 service water tunnel. The water is chemically treated by the chemical feed system as previously 48 described. As a safeguard against blockage of the traveling screens ahead of the service water 49 channel, the system has a 54-in. (137-cm) bypass line that can be opened to directly supply 3-12

Affected Environment 1 CSCS water. All pumps and strainers for conveying emergency cooling water are located in 2 watertight spaces within the basements of the various plant buildings (Exelon 2014a, 2014b). 3 Potable Water System. LSCS uses groundwater from two deep wells (Nos. 1 and 2) to supply 4 potable (drinking) water, sanitary water, and raw makeup water for the demineralized water 5 system. The wells were installed during plant construction with completion depths of 1,629 ft 6 (497 m) and 1,620 ft (494 m), respectively (Exelon 2014a). Each well has a pump capacity of 7 300 gpm (1.14 cubic meters per minute) (Exelon 2014b). Water is stored in a 350,000-gallon 8 (gal) (1,325-m3) storage tank before distribution. The plant supply wells and LSCSs 9 groundwater use are further discussed in Section 3.5.2.2. 10 3.1.4 Radioactive Waste Management Systems 11 As part of normal operations and as a result of equipment repairs and replacements due to 12 normal maintenance activities, nuclear power plants routinely generate both radioactive and 13 nonradioactive wastes. Nonradioactive wastes include hazardous and nonhazardous wastes. 14 There is also a class of waste, called mixed waste that is both radioactive and hazardous. The 15 systems used to manage (i.e., treat, store, and dispose of) these wastes are described in this 16 section. Waste minimization and pollution prevention measures commonly employed at nuclear 17 power plants are also discussed in this section. 18 All nuclear plants were licensed with the expectation that they would release very limited 19 quantities of radioactive material to both the air and water during normal operation. However, 20 NRC regulations require that gaseous and liquid radioactive releases from nuclear power plants 21 must meet radiation dose-based limits specified in Title 10 of the Code of Federal Regulations 22 (10 CFR) Part 20, and the as low as is reasonably achievable (ALARA) criteria in Appendix I to 23 10 CFR Part 50. Regulatory limits are placed on the radiation dose that members of the public 24 can receive from radioactive effluents released by a nuclear power plant. All nuclear power 25 plants use radioactive waste management systems to control and monitor radioactive wastes. 26 LSCS uses liquid, gaseous, and solid waste processing systems to collect and process, as 27 needed, radioactive materials produced as a by-product of plant operations. The liquid and 28 gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 29 discharge into the environment. This is to ensure that the dose to members of the public from 30 radioactive effluents is reduced to levels that are ALARA in accordance with NRCs regulations. 31 The radioactive material removed from the effluents is converted into a solid form for eventual 32 disposal at a licensed radioactive disposal facility. 33 Exelon has a radiological environmental monitoring program (REMP) to assess the radiological 34 impact, if any, to the public and the environment from radioactive effluents released during 35 operations at LSCS. The REMP measures the aquatic, terrestrial, and atmospheric 36 environment for radioactivity, as well as the ambient radiation. In addition, the REMP measures 37 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 38 material, including radon) (Teledyne 2015). 39 LSCS has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 40 parameters used to calculate offsite doses resulting from liquid and gaseous radioactive 41 effluents. These methods are used to ensure that radioactive material discharges from the plant 42 meet NRC and EPA regulatory dose standards. The ODCM also contains the requirements for 43 the REMP (Exelon 2013d). 44 3.1.4.1 Radioactive Liquid Waste Management 45 LSCS Units 1 and 2 share a common liquid radioactive waste system (LRWS). The LRWS 46 collects, monitors, and processes any potentially radioactive liquid wastes produced in the plant. 3-13

Affected Environment 1 The LRWS also recycles as much processed liquid waste as can be accommodated within the 2 LSCS water balance. Although LSCS tries to limit any radioactive releases via the liquid 3 pathway, discharges from the system are authorized and may occur if treated waste water is not 4 needed for other plant uses. The LRWS is designed so that any liquid radioactive waste 5 discharged from the site will have radioactive nuclide concentrations below the limits specified in 6 10 CFR Part 20 and Appendix I to10 CFR Part 50. 7 Processing of liquids in the LRWS results in a clean product stream and a reject stream. The 8 clean product stream returns water for use by the main plant systems via the condensate 9 storage tanks if the water quality is found acceptable and if the plant has the need for the 10 makeup water. Water in the reject stream is processed for disposal in the solid radioactive 11 waste system. Unused treated waste water can be sent to a discharge tank and held until a 12 discharge batch accumulates. Before any release of a discharge batch, it would be sampled 13 and treated if necessary to ensure radionuclide concentrations and resulting radiation doses to 14 LSCS personnel and the general public comply with NRC regulations in 10 CFR Part 20 and 15 Appendix I to 10 CFR Part 50. The LWRS sends discharge batches directly into the cooling 16 pond blowdown line. 17 The LRWS consists of a waste processing subsystem, a floor drain processing subsystem, a 18 chemical waste subsystem, and a sludge subsystem. All subsystems are shared by LSCS 19 Units 1 and 2. A vendor-provided liquid waste treatment system is also available to supplement 20 the LRWS if needed. 21 The waste processing subsystem collects and processes water from sources such as 22 equipment drains. This water is treated by settling, filtration, and demineralization. After 23 treatment and sampling, the water is returned for reuse through the condensate storage tanks. 24 The floor drain processing subsystem collects and processes water from the floor drain 25 systems. After treatment and sampling, the water is returned for reuse through the condensate 26 storage tanks. The chemical waste subsystem collects and processes water from areas like the 27 laboratory drains and the radwaste building sump. After treatment and sampling, plant 28 procedures are used to determine where the processed water goes, which may include 29 discharge. The sludge subsystem is not a processing stream, but rather a group of tanks and 30 associated pumps that serve as an interface between the LRWS and the solid radioactive waste 31 handling system. After radioactive contaminants have been removed from the LRWS, 32 concentrated, and treated or held up to allow radioactive decay if necessary, they are 33 transferred to the solid radioactive waste system for processing, temporary storage, and 34 shipment for disposal. 35 The use of these radioactive waste systems and the procedural requirements in the ODCM 36 ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 37 dose standards. 38 Dose estimates for members of the public are calculated based on radioactive liquid effluent 39 release data and aquatic transport models. Exelons annual radiological effluent release report 40 contains the radioactive liquid effluents release data from LSCS and the resultant calculated 41 doses. The NRC staff reviewed 5 years of radioactive effluent release data: 2010 through 2014 42 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year period provides a data set that covers a 43 broad range of activities that occur at a nuclear power plant, such as refueling outages, routine 44 operation, and maintenance activities that can affect the generation of radioactive effluents. 45 LSCS did not have any radioactive liquid effluent releases over the period of 2010 through 46 2014. 47 Since LSCS had no radioactive liquid effluent releases for the period of 2010 through 2014, its 48 radioactive liquid effluent control program showed that radiation doses to members of the public 3-14

Affected Environment 1 were controlled within the NRCs and EPAs radiation protection standards contained in 2 Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR Part 190. Also, since LSCS had no 3 radioactive liquid effluent releases for the period of 2010 through 2014, no adverse trends were 4 observed in the dose levels. 5 Routine plant refueling and maintenance activities currently performed will continue during the 6 license renewal term. Based on the past performance of the radioactive waste system to 7 maintain doses from radioactive liquid effluents to be ALARA, similar performance is expected 8 during the license renewal term. 9 3.1.4.2 Radioactive Gaseous Waste Management 10 LSCS Units 1 and 2 share a common gaseous radioactive waste system (GRWS) with a 11 common vent stack located on the roof of the containment building between the two units. The 12 GRWS is designed to process and control radioactive gases and minimize the amount of 13 radioactive gaseous material released into the environment. The gaseous radioactive wastes 14 released consist primarily of xenon, argon, iodine, tritium, and carbon. The steam in a BWR 15 plant such as LSCS contains impurities in the form of radioactive gases that are continuously 16 removed during plant operation from the main condenser by an air ejector. This process is the 17 major source of radioactive gases generated by LSCS (Exelon 2014a). The GRWS removes 18 some radioactive gases and delays the release of other radioactive gases by adsorption on 19 charcoal beds to allow time for radioactive decay. As a final step, the gaseous waste stream 20 passes through a high efficiency particulate air filter, and is discharged through the common 21 vent stack. Other plant facilities that are potential sources of radioactive gas emissions include 22 the primary containment, the secondary containments (reactor buildings), the turbine buildings, 23 and the radwaste building. The ventilation systems in each of these facilities have filtration and 24 treatment systems that the air passes through before being discharged through the vent stack 25 (Exelon 2014a). 26 The use of these radioactive waste systems and the procedural requirements in the ODCM 27 ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 28 dose standards. 29 Dose estimates for members of the public are calculated based on radioactive gaseous effluent 30 release data and atmospheric transport models. Exelons annual radioactive effluent release 31 report contains a detailed presentation of the radioactive gaseous effluents released from LSCS 32 and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 33 release data: 2010 through 2014 (Exelon 2011b, 2012b, 2013c, 2014c, 2015b). A 5-year 34 period provides a data set that covers a broad range of activities that occur at a nuclear power 35 plant, such as refueling outages, nonrefueling outage years, routine operation, and maintenance 36 activities that can affect the generation of radioactive effluents. The NRC staff compared the 37 data against NRC dose limits and looked for indication of adverse trends (i.e., increasing dose 38 levels) over the period of 2010 through 2014. Since the radioactive gaseous effluents are 39 released from a common vent stack shared by both Unit 1 and Unit 2, the resultant calculated 40 doses presented in the effluent release are divided in half to evaluate compliance with the 41 Appendix I to 10 CFR Part 50 dose criteria. The following summarizes the calculated doses 42 from radioactive gaseous effluents released from LSCS Units 1 and 2 during 2014: 43 Unit 1 44

  • The air dose at the site boundary from gamma radiation in gaseous effluents from 45 LSCS was 2.36x102 millirad (mrad) (2.36x104 milligray (mGy), which is well below 46 the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

3-15

Affected Environment 1

  • The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 2 was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 3 dose criterion in Appendix I to 10 CFR Part 50.

4

  • The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 5 carbon-14 from LSCS was 4.56x101 millirem (mrem) (4.56x103 millisievert (mSv)),

6 which is well below the 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR 7 Part 50. 8 Unit 2 9

  • The air dose at the site boundary from gamma radiation in gaseous effluents from 10 LSCS was 2.36x102 mrad (2.36x104 mGy), which is well below the 10 mrad 11 (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

12

  • The air dose at the site boundary from beta radiation in gaseous effluents from LSCS 13 was 1.10x103 mrad (1.10x105 mGy), which is well below the 20 mrad (0.2 mGy) 14 dose criterion in Appendix I to 10 CFR Part 50.

15

  • The dose to an organ (thyroid) from radioactive iodine, radioactive particulates, and 16 carbon-14 from LSCS was 4.56x101 mrem (4.56x103 mSv), which is well below the 17 15 mrem (0.15 mSv) dose criterion in Appendix I to 10 CFR Part 50.

18 The NRC staffs review of LSCSs radioactive gaseous effluent control program showed that 19 radiation doses to members of the public were controlled within NRCs and EPAs radiation 20 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 21 40 CFR Part 190. No adverse trends were observed in the dose levels. 22 Routine plant refueling and maintenance activities currently performed will continue during the 23 license renewal term. Based on the past performance of the radioactive waste system to 24 maintain doses from radioactive gaseous effluents to be ALARA, similar performance is 25 expected during the license renewal term. 26 3.1.4.3 Radioactive Solid Waste Management 27 LSCS Units 1 and 2 share a common solid radioactive waste system (SRWS). The SRWS 28 receives, dewaters, solidifies, packages, handles, and provides temporary storage facilities for 29 all radioactive wet solid wastes prior to offsite shipment and disposal in accordance with NRC 30 regulations in 10 CFR Parts 61 and 71. It also receives, decontaminates, compacts 31 (as necessary), and provides temporary storage facilities for all radioactive dry wastes prior to 32 offsite shipment and disposal (Exelon 2014a). Transportation of the radioactive solid waste is 33 governed by the U.S. Department of Transportation regulations in 49 CFR Parts 171 to 178. 34 LSCS disposes of solid radioactive waste at facilities in Utah and Texas. LSCS also utilizes 35 offsite vendor services in Tennessee for dry active waste processing, including compaction, 36 incineration, thermal processing, and sorting of the dry active waste. 37 LSCS Units 1 and 2 have a shared Interim Radwaste Storage Facility (IRSF) with the capacity 38 to hold 270 containers of Class B and Class C (Class B/C) low-level radioactive wastes in two 39 layers of 135 spots each. In 2011, LSCS Units 1 and 2 both received license amendments to 40 allow their IRSF to store Class B/C waste from Braidwood, Byron, and Clinton Stations in 41 addition to the wastes generated at LSCS. Exelon states that LSCS has sufficient excess 42 storage capacity to accommodate extended storage of the Class B/C wastes generated by all 43 four Exelon stations. Also, LSCS can ship Class B/C wastes for treatment and disposal to the 44 Waste Control Specialists facility in Texas to reduce the demand for any extended onsite 3-16

Affected Environment 1 storage of those wastes. Therefore, storage capacity for low-level radioactive wastes should be 2 sufficient for the length of the license renewal term. (Exelon 2014a) 3 LSCS infrequently generates small quantities of mixed waste (waste having both a hazardous 4 component and radioactive component). The IEPA regulates the hazardous component of the 5 waste and the Illinois Emergency Management Agency Division of Nuclear Safety and the NRC 6 regulate the radioactive component. When generated, mixed wastes are accumulated in the 7 Mixed Waste Storage Building before transport to a licensed offsite facility for treatment and 8 disposal (Exelon 2014a). 9 LSCS has contracts to send its low-level waste (LLW) to two licensed LLW disposal sites: 10 EnergySolutions in Clive, Utah, and Waste Control Specialists in Andrews, Texas. LSCS also 11 sends certain wastes to Toxco Materials Management Center in Oak Ridge, Tennessee, and 12 EnergySolutions in Oak Ridge, Tennessee for processing before disposal. 13 In 2014, 30 LLW shipments were made from LSCS for processing and disposal to the 14 EnergySolutions Clive facility in Clive, Utah, the EnergySolutions Bear Creek facility in Oak 15 Ridge, Tennessee, and the Toxco Materials Management Center in Oak Ridge, Tennessee. 16 The total volume and radioactivity of LLW shipped offsite in 2014 was 1.23x103 m3 17 (4.34x104 cubic feet and 1.34x101 curies (4.95x105 megabecquerels)), respectively 18 (Exelon 2015b). Routine plant operation, refueling outages, and maintenance activities that 19 generate radioactive solid waste will continue during the license renewal term. Radioactive 20 solid waste is expected to be generated and shipped off site for disposal during the license 21 renewal term. 22 3.1.4.4 Radioactive Waste Storage 23 Low-level radioactive waste (LLRW) is stored temporarily onsite before being shipped offsite for 24 disposal at a licensed LLRW disposal facility. Exelon (2014a) stated that LSCS has sufficient 25 capability to store Class B/C LLRW from Braidwood, Byron, and Clinton Stations in addition to 26 LSCS Class B/C waste in the IRSF (Exelon 2014a). 27 LSCS stores its spent fuel in a spent fuel pool and also in an onsite independent spent fuel 28 storage installation (ISFSI). The ISFSI is used to safely store spent fuel in licensed and 29 approved dry cask storage containers onsite. The installation and monitoring of this facility is 30 governed by NRC requirements in 10 CFR Part 72, Licensing requirements for the independent 31 storage of spent nuclear fuel, high-level radioactive waste, and reactor-related Greater than 32 class C waste. The LSCS ISFSI will remain in place until the U.S. Department of Energy takes 33 possession of the spent fuel and removes it from the site for permanent disposal or processing. 34 Spent fuel transfers to the ISFSI began in 2010 when fuel from the spent fuel pool was placed 35 in casks and transferred to the ISFSI storage pad. As of December 2014, there are 16 dry 36 casks containing spent fuel on the ISFSI storage pad (Exelon 2015b). 37 3.1.4.5 Radiological Environmental Monitoring Program 38 Exelon conducts a REMP to assess the radiological impact, if any, to the public and the 39 environment from operations at LSCS. 40 The REMP measures the aquatic, terrestrial, and atmospheric environment for ambient 41 radiation and radioactivity. Monitoring is conducted for the following: direct radiation, air, water, 42 groundwater, milk, local agricultural crops, fish, and sediment. The REMP also measures 43 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 44 material, including radon). 45 In addition to the REMP, LSCS has an onsite ground water protection program designed to 46 monitor the onsite plant environment for detection of leaks from plant systems and pipes 3-17

Affected Environment 1 containing radioactive liquid (Teledyne 2015). Information on the groundwater protection 2 program is contained in Section 3.5.2 of this document. 3 The NRC staff reviewed 5 years of annual radiological environmental monitoring data: 4 2010 through 2014 (Teledyne 2011, 2012, 2013, 2014, 2015). A 5-year period provides a data 5 set that covers a broad range of activities that occur at a nuclear power plant, such as refueling 6 outages, routine operation, and maintenance activities that can affect the generation and 7 release of radioactive effluents into the environment. The NRC staff looked for indication of 8 adverse trends (i.e., buildup of radioactivity levels) over the period of 2010 through 2014. 9 The NRC staffs review of Exelons data showed no indication of an adverse trend in 10 radioactivity levels in the environment. The data showed that there was no measurable impact 11 to the environment from operations at LSCS. 12 3.1.5 Nonradioactive Waste Management Systems 13 Like any other industrial facility, nuclear power plants generate wastes that are not 14 contaminated with either radionuclides or hazardous chemicals. 15 LSCS has a nonradioactive waste management program to handle its nonradioactive hazardous 16 and nonhazardous wastes. The waste is managed in accordance with Exelons procedures. 17 Listed below is a summary of the types of waste materials generated and managed at LSCS. 18

  • LSCS is a small quantity hazardous waste generator; however, hazardous wastes 19 are managed according to large quantity generator standards. LSCS has contracts 20 in place to transfer hazardous waste to licensed offsite treatment and disposal 21 facilities.

22

  • LSCSs nonhazardous wastes include potentially infectious medical waste (PIMW),

23 waste/used oil, grease, antifreeze, adhesives, and other petroleum-based liquids. 24 PIMW is generated at a health facility onsite and can include used and unused 25 hypodermic needles and syringes, as well as items contaminated with human blood. 26 PIMW is considered a unique special waste category in Illinois and transportation 27 and disposal of this waste is regulated under the Illinois Administrative Code (IAC) 28 Title 35, Sections 1420 through 1422 and 1450, (35 IAC 1420-1422, 1450). 29

  • Universal wastes, such as batteries and mercury-containing lamps are managed in 30 accordance with 35 IAC 733 standards. Other wastes, such as, oils, metals, paper, 31 and other recyclables are managed according to Exelon procedures and Illinois 32 regulations.

33 Exelon operates an onsite sewage treatment plant. Sewage treatment effluent is discharged to 34 the LSCS cooling pond. Nonradioactive industrial wastewater is also processed at the 35 treatment plant and the treated effluent is discharged into the cooling pond. Cooling pond 36 blowdown is discharged to the Illinois River under NPDES permit IL0048151 (Exelon 2014a). 37 3.1.6 Utility and Transportation Infrastructure 38 The utility and transportation infrastructure at nuclear power plants typically interfaces with 39 public infrastructure systems available in the region. Such infrastructure includes utilities, 40 including suppliers of electricity, fuel, and water, as well as roads and railroads that provide 41 access to the site. The following sections briefly describe the existing utility and transportation 42 infrastructure at LSCS. 3-18

Affected Environment 1 3.1.6.1 Electricity 2 Nuclear power plants generate electricity for other users; however, they also use electricity to 3 operate. Offsite power sources provide power to engineered safety features and emergency 4 equipment in the event of a malfunction or interruption of power generation at the plant. 5 Independent backup power sources provide power in the event that power is interrupted from 6 both the plant and offsite power sources. 7 At LSCS, connections to the Commonwealth Edison Company (ComEd) 345-kilovolt (kV) 8 system at the onsite switchyard provide offsite power sources for essential safety systems and 9 emergency equipment (Exelon 2014g). The switchyard is arranged in a double ring bus such 10 that offsite power to both units cannot be lost due to any single failure (Exelon 2014g). In the 11 event of total loss of auxiliary power from offsite sources, onsite diesel generators serve as an 12 independent source of power for safe shutdown (Exelon 2014g). LSCS has six diesel 13 generators (three for each nuclear unit) that can each provide up to 4.16 kV of power, which is 14 ample capacity to supply all power required for the safe shutdown of both units in the event of a 15 total loss of offsite power (Exelon 2014g). 16 3.1.6.2 Fuel 17 The LSCS nuclear units are operated using low-enriched uranium dioxide fuel with enrichment 18 not exceeding 5 percent by weight of uranium-235. At any given time, the LSCS units contain 19 approximately 140 metric tons (MT) (308,600 pounds) of uranium fuel (Exelon 2015e). Exelon 20 replaces about 36 percent of that fuel at each refueling, which occurs on a staggered 24-month 21 cycle (Exelon 2014a). Fresh (i.e., unirradiated) fuel is brought to the site and stored onsite in 22 the LSCS new fuel storage facility prior to installation in the reactor cores (Exelon 2014g). 23 Exelon stores spent fuel in a spent fuel pool and an ISFSI. Nuclear fuel and radioactive waste 24 systems are further described in Section 3.1.4. 25 In addition to nuclear fuel, LSCS requires diesel fuel to operate the emergency diesel power 26 generators. To meet emergency demands, Exelon stockpiles diesel fuel and gasoline on the 27 site. In total, Exelon stores 204,080 gal (772,530 liters) of diesel fuel and gasoline for a variety 28 of uses, including emergency diesel generators, diesel fire pumps, and plant vehicles 29 (Exelon 2015e). 30 3.1.6.3 Water 31 In addition to cooling and auxiliary water (described in Section 3.1.3), nuclear power plants 32 require potable water for sanitary and everyday uses by personnel (e.g., drinking, showering, 33 cleaning, laundry, toilets, and eye washes). At LSCS, two deep wells supply the site with 34 potable water. Water pumped from the wells is routed to an onsite vendor trailer, which 35 deionizes the water and routes the water to a 1.3-million-liter (350,000-gal) storage tank. Water 36 drawn from the storage tank may be used in either the demineralized water makeup system or 37 the potable and sanitary water system. Water withdrawn for use in the potable water system 38 undergoes chlorination prior to entering the system. LSCS withdraws approximately 98 liters 39 per minute (L/min) (26 gpm) from the wells for potable water uses. (Exelon 2014a) 40 3.1.6.4 Transportation Systems 41 All nuclear power plants are served by controlled access roads. In addition to roads, many 42 plants also have railroad connections for moving heavy equipment and other materials. Some 43 plants that are located on navigable waters, such as rivers, Great Lakes, or oceans, have 44 facilities to receive and ship loads on barges. 45 At LSCS, County Road 6, also known as North 21st Road and Grand Ridge-Mazon Road, 46 provides access to the site from the southern boundary. Major roads in the area include State 3-19

Affected Environment 1 Route 170 (SR-170), which lies 0.8 km (0.5 mi) east of the site, and Interstate 80 (I-80), which 2 lies 13 km (8 mi) north of the site. Section 3.10.6 describes local transportation systems, 3 including roadway access, in more detail. 4 Two major railway systems provide service near the LSCS site: the CSX Railroad runs parallel 5 to and slightly north of the Illinois River, and a 10-km (6-mi) rail spur connects LSCS to the 6 Atchison, Topeka, and Santa Fe Railroad south of the site. Exelon uses a portion of the onsite 7 rail spur to transport spent fuel casks to the onsite storage area, but the spur has not been used 8 to deliver equipment or materials to the site from external sources in many years. 9 (Exelon 2015f) 10 LSCS lies south of the Marseilles Pool in the reach of the Illinois River between the Marseilles 11 Lock and Dam at Marseilles, Illinois, and the Dresden Lock and Dam south of Channahon, 12 Illinois (Exelon 2014a). These lock and dam sites are part of the Illinois Waterway, which flows 13 from Chicago, Illinois, to St. Louis, Missouri, and is composed of seven water systems: Illinois 14 River, Des Plaines River, Chicago Sanitary and Shipping Canal, South Branch Chicago River, 15 Cal-Sag Channel, Little Calumet River, and the Calumet River (USACE 2012). Much of the 16 barge traffic in this area is dominated by transportation of agricultural products (grains, corn, 17 and soybeans) and other commodities, such as cement and concrete (USACE 2012). 18 Exelon (2015g) does not own or maintain a barge slip for LSCS and does not otherwise receive 19 or ship equipment for LSCS by barge. 20 Major airports in the vicinity of LSCS include Chicago Midway International Airport, Chicago 21 OHare International Airport, and Central Illinois Regional Airport, which lie approximately 93 km 22 (58 mi) northeast, 100 km (60 mi) north-northeast, and 110 km (70 mi) south of the site, 23 respectively. Additionally, Illinois Valley Regional Airport in Peru, Illinois, serves LaSalle 24 County, and eight private airports in the county accommodate smaller cargo, passenger, and 25 private aircraft (LaSalle County 2014). 26 3.1.6.5 Power Transmission Systems 27 ComEd owns and operates the 345-kV onsite switchyard that connects LSCS with the regional 28 electric grid. From the switchyard, a total of six transmission lines extend to four substations. 29 Two 345-kV lines travel 66 km (41 mi) north from the site to the Plano substation east of Plano, 30 Illinois. Two 345-kV lines travel 100 km (62 mi) northeast to Braidwood Station, Units 1 and 2, 31 in Braceville, Illinois. Two 138-kV lines are connected to the switchyard through a 345/138-kV 32 transformer. One of the 138-kV line extends 27 km (17 mi) to Mazon, Illinois, and the other 33 138-kV line extends 40 km (25 mi) to Streator, Illinois (AEC 1973; NRC 1978; Exelon 2015h). 34 For license renewal, the NRC (2013) evaluates as part of the proposed action the continued 35 operation of those transmission lines that connect the nuclear power plant to the substation 36 where electricity is fed into the regional power distribution system and transmission lines that 37 supply power to the nuclear plant from the grid. Exelon (2015h) has determined that the four 38 electrical connections between the main plant and the LSCS switchyard are in scope for the 39 license renewal environmental review. These connections extend a distance of 1,300 ft (400 m) 40 across flat, primarily gravel laydown areas and paved roads (Exelon 2015h). Because 41 redundant offsite power is provided to LSCS through the LSCS substation, no offsite 42 transmission lines supply power to the nuclear plant from the grid (Exelon 2015h). All of the 43 in-scope transmission lines lie within the owner-controlled and industrial-use area of the site. 44 3.1.7 Nuclear Power Plant Operations and Maintenance 45 Maintenance activities conducted at LSCS include inspection, testing, and surveillance to 46 maintain the current licensing basis of the facility and to ensure compliance with environmental 3-20

Affected Environment 1 and safety requirements. Various programs and activities currently exist at LSCS to maintain, 2 inspect, test, and monitor the performance of facility equipment. These maintenance activities 3 include inspection requirements for reactor vessel materials, boiler and pressure vessel 4 inservice inspection and testing, and maintenance of water chemistry. 5 Additional programs include those carried out to meet TS surveillance requirements, those 6 implemented in response to the NRC generic communications, and various periodic 7 maintenance, testing, and inspection procedures. LSCS must periodically discontinue the 8 production of electricity for outages supporting refueling, periodic in-service inspection and 9 testing, and maintenance activities. The LSCS reactor units are on staggered 24-month 10 refueling cycles (Exelon 2014a). 11 3.2 Land Use and Visual Resources 12 3.2.1 Land Use 13 3.2.1.1 Onsite Land Use 14 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 15 Illinois (Exelon 2015p). The site lies 8 km (5 mi) south of the Illinois River, about 10 km (6 mi) 16 southwest of Seneca, Illinois, and 120 km (75 mi) southwest of downtown Chicago. 17 (Exelon 2014a) 18 A cooling pond occupies the western side of the site and accounts for about half of the site area. 19 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 20 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac). This 21 industrial area is surrounded by about 142 ha (350 ac) of undeveloped natural areas, including 22 grassland, old field, scrub-scrub, and small forested fragments (Exelon 2015p). 23 On the southwest shore of the cooling pond, the IDNR operates the LaSalle Fish Hatchery 24 under a lease agreement with Exelon. The hatchery encompasses approximately 18 ha (45 ac) 25 and includes several small buildings and 16 fish-rearing pools (Exelon 2014a). 26 A 5.6-km (3.5-mi) corridor for the makeup and blowdown pipelineswhich travel underground 27 from the Illinois River screen house south to the cooling pondcontains woodlands, pastures, 28 and wetlands as well as mowed and maintained right-of-way for a portion of the 29 LaSalle-to-Plano 345-kV transmission line (Exelon 2014a). 30 Table 3-1 lists site land uses, and Figure 3-3 depicts the site layout. Sections 3.1 and 3.6 31 describe the developed and natural areas of the site in more detail, respectively. 32 Table 3-1. LSCS Site Land Uses by Area Land Use Area (in acres)(a) Percent Open Water 1,976(b) 52.3 Developed, Open Space 120 3.2 Developed, Low Intensity 218 5.8 Developed, Medium Intensity 73 1.9 Developed, High Intensity 90 2.4 Barren Land 5 0.1 Deciduous Forest 386 10.2 Shrub/Scrub 17 0.5 3-21

Affected Environment Land Use Area (in acres)(a) Percent Grassland/Herbaceous 473 12.5 Pasture/Hay 11 0.3 Cultivated Crops 346 9.2 Woody Wetlands 58 1.5 Emergent Herbaceous Wetlands 2 0.1 Total 3,776 100.0 (a) To convert acres to hectares, divide by 2.4711. (b) Exelon used the 2011 National Land Cover Database (NLCD) to estimate acreage of site land uses. Of the 3,776-acre site, the 2011 NLCD identified 1,976 acres as open water, most of which consists of the cooling pond. This number of acres is inconsistent with the 2,058 acres reported in ComEds Environmental Report that evaluated the operation of LSCS (ComEd 1977). However, because the methodologies used to estimate land use acreages are different between these documents and the NLCD, and because both methodologies are inherently uncertain, Exelon was unable to resolve the discrepancy between the cooling pond acreage estimates. It is possible that, in the 1977 Environmental Report, features such as dikes, screen house, discharge canals, and storm water ponds were included in the cooling pond acreage estimate. Accordingly, all estimates should be considered approximate. Source: Exelon 2015d 1 3.2.1.2 Coastal Zone 2 In 1972, Congress promulgated the Coastal Zone Management Act (16 USC 1451 et seq.; 3 CZMA) to encourage and assist States and territories in developing management programs that 4 preserve, protect, develop, and, where possible, restore the resources of the coastal zone 5 (i.e., the coastal waters and the adjacent shore lands strongly influenced by one another, which 6 may include islands, transitional and intertidal areas, salt marshes, wetlands, beaches, and 7 Great Lakes waters). Individual states are responsible for developing a Federally approved 8 Coastal Management Plan and implementing a coastal management program in accordance 9 with such a plan. In Illinois, the IDNR administers the coastal management program. 10 Section 307(c)(3)(A) of the CZMA requires that applicants for Federal permits whose proposed 11 activities could reasonably affect coastal zones certify to the licensing agency (here, the NRC) 12 that the proposed activity would be consistent with the states coastal management program. 13 The regulations that implement the CZMA indicate that this requirement is applicable to renewal 14 of Federal licenses for actions not previously reviewed by the state (15 CFR 930.51(b)(1)). 15 LSCS is outside of the boundary of the Illinois coastal zone (IDNR 2011b, 2015c). Accordingly, 16 a consistency determination is not required for the proposed LSCS license renewal. 17 3.2.1.3 Offsite Land Use 18 Within a 10-km (6mi) radius of the LSCS site, most lands are contained within LaSalle County; 19 however, this radius also includes a small area of land in Grundy County to the east. Land use 20 in this area is primarily agricultural. Cropland or pastures border the LSCS site to the east, 21 south, and west. The Illinois River lies to the north of the site, and the bluffs overlooking the 22 Illinois River are mostly forested. The rivers south bank floodplain includes agricultural fields 23 and woodlots, while the north bank is more developed and includes parts of the incorporated 24 towns of Seneca and Marseilles. The majority of land cover (about 70 percent) within 10 km 25 (6 mi) is used for crop cultivation. Deciduous forest accounts for about 12 percent of land cover, 26 and the remaining 18 percent is composed of various land cover types, including open water, 3-22

Affected Environment 1 developed land, wetlands, and grasslands. Table 3-2 characterizes the land uses within a 2 10-km (6-mi) radius of LSCS. 3 Table 3-2. Land Use within a 10-km (6-mi) Radius of LSCS Area Land Use (in acres)(a) Percent Open Water 2,915 4.0 Developed, Open Space 3,124 4.3 Developed, Low Intensity 2,676 3.7 Developed, Medium Intensity 451 0.6 Developed, High Intensity 256 0.4 Barren Land 84 0.1 Deciduous Forest 8,479 11.7 Evergreen Forest 4 0.0 Shrub/Scrub 43 0.1 Grassland/Herbaceous 2,165 3.0 Pasture/Hay 966 1.3 Cultivated Crops 50,755 70.2 Woody Wetlands 425 0.6 Emergent Herbaceous Wetlands 8 0.0 Total 72,351 100.0 (a) To convert acres to hectares, divide by 2.4711. Source: Exelon 2015i 4 The IDNR manages three areas for public use and recreation within 10 km (6 mi) of LSCS. The 5 LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling pond that is 6 managed by the IDNR and open to the public for fishing and other recreational purposes 7 (Exelon 2014a). The Marseilles State Fish & Wildlife Area is approximately 2.4 km (1.5 mi) 8 north of the LSCS site. The IDNR (2015e) manages this 1,032-ha (2,550-acre) tract of 9 predominantly wooded land for wildlife habitat and hunting. Illini State Park lies approximately 10 10 km (6 mi) northwest of LSCS on the south bank of the Illinois River and encompasses 11 206 ha (510 ac) (Exelon 2014a). 12 LaSalle County, in which LSCS is located, is a predominantly agricultural county; 85 percent of 13 the countys 1,135 square miles (m2) (294,000 ha or 726,400 ac) are in agricultural production 14 (LaSalle County 2014). Much of the countys agricultural lands were formerly prairie. LaSalle 15 Countys major agricultural crops include corn, soybeans, and its major livestock commodities 16 include cattle and calves, hogs and pigs, and sheep and lambs (LaSalle County 2014). The 17 LaSalle County Comprehensive Plan (LaSalle County 2014) anticipates that the county will 18 experience a slight (4 percent) increase in population over the next 15 years and reach an 19 estimated 141,615 people by 2030. The county plans to manage its land resources in a manner 20 that will preserve prime farmland and to encourage continued urban growth in areas where 21 public infrastructure and services already exist so that farmland, open spaces, and natural and 22 cultural resources are preserved. 3-23

Affected Environment 1 3.2.2 Visual Resources 2 As described in the previous section, the LSCS site is located in a predominantly agricultural 3 region. The sites grade elevation is approximately 216 m (710 ft) above MSL, which is the 4 highest point within a 3-km (5-mi) radius. The sites generating facilities were built 60 m (200 ft) 5 above the Illinois River floodplain elevation, which ranges from 152 to 155 m (500 to 510 ft) 6 above mean sea level. The tallest structures on the LSCS site are the meteorological tower and 7 the station vent stack, which are 122 m (400 ft) tall and 113 m (370 ft) tall, respectively. The 8 vent stack is painted with thick white and red horizontal stripes. The largest and most visible 9 buildings on the site are the reactor and turbine buildings, which are 56 m (185 ft) and 41 m 10 (134 ft) tall, respectively (Exelon 2014a). 11 To the west and the southwest, the Grand Ridge Energy Center wind farm is situated on slightly 12 higher ground (221 to 227 m (725 to 750 ft) above MSL) on a north-south ridgeline. A second 13 wind farm, Top Crop I, is sited south and east of the Grand Ridge Energy Center. Wind turbines 14 at these facilities stand 118.5 m (389 ft) tall and have rotor blades that are 38.5 m (126.5 ft) 15 long. These two facilities 134 wind turbines dominate the viewscape in the vicinity of LSCS. 16 (Exelon 2014a) 17 From most vantage points, the wind turbines are more noticeable than the LSCS buildings or 18 facilities. A motorist travelling north on Highway 170 from Ranson, Illinois, to Seneca, Illinois, 19 would see wind turbines to the west, south, and east until the motorist crested the bluffs of the 20 Illinois River at an elevation of about 200 m (650 ft) above MSL. The motorist would then lose 21 sight of the turbines at the highway bridge that crosses the Illinois River, at which point the 22 roads elevation descends to approximately 152 m (500 ft) (Exelon 2014a). 23 3.3 Meteorology, Air Quality, and Noise 24 3.3.1 Meteorology and Climatology 25 LSCS is located in LaSalle County in northeastern Illinois, approximately 70 mi (113 km) 26 southwest of Chicago and 35 mi (56 km) southwest of Joliet, Illinois. The regional climate is 27 continental with cold winters; warm summers; and frequent short fluctuations in temperature, 28 humidity, cloudiness, and wind direction (NCDC 2004). During fall, winter, and spring, the polar 29 jet stream is located near or over northeastern Illinois, which causes large-scale synoptic storms 30 to move through the area bringing precipitation, winds, and often dramatic temperature changes 31 (NCDC 2004). Temperature and precipitation conditions vary widely throughout Illinois and 32 between years. A wide range of temperature extremes is common in this region 33 (NCDC 2015a). Tornadoes, thunderstorms, hail, and heat and cold waves are common in the 34 State, and flooding is the most damaging weather-related hazard in Illinois (NCDC 2004). 35 The NRC staff obtained climatological data collected at the Peoria, Illinois, airport station 36 (KPIA), which is located approximately 62 mi (100 km) from LSCS. Additionally, LSCS 37 maintains a meteorological monitoring program that includes a 400-ft (122-m) meteorological 38 tower located approximately 0.5 mi (0.8 km) southeast of the reactor buildings. The tower 39 measures wind direction, wind speed, temperature, and precipitation. Data from these stations 40 were used to characterize the regions climate and are presented below. 41 The prevailing wind direction, for the 1981 through 2010 timeframe, at the KPIA station was 42 from the south-southwest (NCDC 2015a). The mean annual wind speed for the 1981 through 43 2010 timeframe is 8.4 miles per hour (mph) (13.5 kilometers per hour (kph)), and the mean 44 monthly wind speed ranges from 6.0 mph (9.7 kph) in August to 10.2 mph (16.4 kph) in March. 45 The annual predominant wind direction from the meteorological tower at LSCS for the 3-24

Affected Environment 1 2010 through 2014 timeframe was from the south-southwest direction (for 2011 and 2012) and 2 from the west-northwest direction (for 2010, 2013, and 2014) (Exelon 2015j). The mean annual 3 wind speed at LSCS for the 2010 through 2014 timeframe is 10.4 mph (16.7 kph) 4 (Exelon 2015j). 5 The mean annual temperature for the 1985 through 2014 period of record at the KPIA station is 6 51.9 °F (11.1 °C), with a mean monthly temperature ranging from a low of 25.2 °F (-3.7 °C) in 7 January to a high of 75.8 °F (24.3 °C) in July (NCDC 2015a). The hottest year over the period 8 of record was in 2012, and coolest was in 1996. The mean annual temperature for the 2010 9 through 2014 timeframe at LSCS is 50.7 °F (10.3 °C), with a mean monthly temperature ranging 10 from a low of 22.5 °F (-5.3 °C) in January to a high of 75.4 °F (24.1 °C) in July (Exelon 2015j). 11 The mean total annual liquid precipitation for the 1985 through 2014 period of record measured 12 at the KPIA station is 35.9 in. (91.2 cm). The wettest year for the period of record is 55.35 in. 13 (140.6 cm) in 1990 (NCDC 2015a); the driest year from the same period is 22.16 in. (56.2 cm) in 14 1988 (NCDC 2015a). Monthly precipitation amounts tend to be evenly distributed throughout 15 the year and range from an average of 1.9 in. (4.8 cm) in January to 4.3 in. (10.9 cm) in May 16 (NCDC 2015a). The mean total annual precipitation measurements taken at LSCSs 17 meteorological tower for the 2010 through 2014 timeframe is 29.83 in. (75.8 cm). Average 18 monthly precipitation ranges from a low of 0.93 in. (2.4 cm) in January to a high of 5.89 in. 19 (14.9 cm) in June (Exelon 2015j). 20 LaSalle County, where LSCS is located, experiences severe weather events, such as 21 tornadoes, floods, and hail. For the 1950 through 2014 period of record, the following events 22 have been recorded (NCDC 2015b): 23

  • 40 tornado events, 24
  • 26 flash floods events, 25
  • 131 hail events, and 26
  • 4 blizzard events.

27 3.3.2 Air Quality 28 Under the Clean Air Act of 1970, as amended (CAA) (42 U.S.C. 7410 et seq.), EPA has set 29 primary and secondary National Ambient Air Quality Standards (NAAQS) (40 CFR Part 50) for 30 six common criteria pollutants to protect sensitive populations and the environment. Primary 31 standards specify maximum ambient concentration levels of the criteria pollutants aimed at 32 providing public health protection, including protecting the health of sensitive populations, such 33 as asthmatics, children, and the elderly. Secondary standards specify maximum ambient 34 concentration levels of the criteria pollutants aimed at providing public welfare protection, 35 including protection against decreased visibility and damage to animals, crops, vegetation, and 36 buildings. The NAAQS criteria pollutants include carbon monoxide (CO), lead (Pb), nitrogen 37 dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter (PM). Particulate matter 38 is further categorized by sizePM10 (aerodynamic diameter of 10 micrometers (µm) or less) 39 and PM2.5 (aerodynamic diameter of 2.5 µm or less). Table 3-3 identifies the NAAQS for the six 40 common criteria pollutants. 3-25

Affected Environment 1 Table 3-3. National Ambient Air Quality Standards Primary/Secondary Pollutant Standard Averaging Time Level Carbon Monoxide (CO) Primary 8 hour 9 ppm 1 hour 35 ppm Lead (Pb) Primary and Secondary Rolling 3-month average 0.15 µg/m3 Nitrogen Dioxide (NO2) Primary 1 hour 100 ppb Primary and Secondary Annual 53 ppb Ozone (O3) Primary and Secondary 8 hour 0.075 ppm Particulate matter less than Primary Annual 12 µg/m3 2.5 µm (PM2.5) Secondary Annual 15 µg/m3 Primary and Secondary 24 hour 35 µg/m3 Particulate matter less than Primary and Secondary 2 hour 150 µg/m3 10 µm (PM10) Sulfur Dioxide (SO2) Primary 1 hour 75 ppb Secondary 3 hour 0.5 ppm Key: ppb = parts per billion, ppm = parts per million, µg/m3 = micrograms per cubic meter, and µm = micrometers. Source: EPA 2015d 2 EPA designates areas of attainment and nonattainment with respect to the NAAQS. Areas 3 that have insufficient data to determine designation status are denoted as unclassifiable. 4 Areas that were once in nonattainment, but are now in attainment, are called maintenance 5 areas; these areas are under a 10-year monitoring plan to maintain the attainment designation 6 status. States have primary responsibility for ensuring attainment and maintenance of the 7 NAAQS. Under Section 110 of the CAA and related provisions, states are to submit, for EPA 8 approval, State Implementation Plans that provide for the timely attainment and maintenance of 9 the NAAQS. 10 Air quality designations are generally made at the county level. For the purpose of planning and 11 maintaining ambient air quality with respect to the NAAQS, EPA has developed air quality 12 control regions (AQCRs), which are intrastate or interstate areas that share a common airshed 13 (40 CFR Part 81). LSCS is located in LaSalle County, Illinois. This County, along with an 14 additional five neighboring Counties (Bureau, Lee, Marshall, Putnam, and Stark Counties) in 15 Illinois compose the North Central Illinois Intrastate AQCR (40 CFR 81.262). With regard to the 16 NAAQS criteria pollutants, LaSalle County is designated as an attainment area for all NAAQS 17 (40 CFR 81.314). The nearest designated nonattainment area is Grundy County, for the 8-hour 18 ozone 2008 standard. The nearest designated maintenance area is Grundy County for the 19 PM2.5 1997 standard. Grundy County is adjacent to LaSalle County, approximately 4 mi (6 km) 20 from LSCS. Although Grundy County is adjacent to LaSalle County, it is not part of the same 21 AQCR that LaSalle County belongs to. 22 Illinois air pollution control rules are issued under Title 35 of the IAC. Air emission sources at 23 LSCS are regulated under a Federally Enforceable State Operating Permit (FESOP) (Permit 24 No. 099802AAA, issued in December 2000) issued by the IEPA (IEPA 2000). A source is 3-26

Affected Environment 1 eligible for a FESOP (also known as synthetic minor air permit) if the potential to emit from the 2 source triggers CAA permit program requirements but if maximum actual emissions are below, 3 or can be restricted to remain below, major source thresholds. LSCSs FESOP permit was 4 issued in December 2000, and expired in December 2005. In accordance with 35 IAC Part 201 5 and the Illinois Environmental Protection Act of 1970 (415 Illinois Compiled Statute (ILCS) 5/39), 6 Exelon submitted a renewal application for the FESOP permit (on July 15, 2005) to the IEPA 7 90 days before the expiration of the permit; therefore, the conditions of the FESOP are 8 administratively extended. On April 7, 2015, the IEPA issued a draft FESOP permit for LSCS 9 for public review and comment (IEPA 2015). 10 Permitted sources at LSCS include five diesel-fired generators, a gasoline storage tank, and 11 gasoline dispensing facilities. The LSCS FESOP permit limits nitrogen oxides, carbon 12 monoxide, particulate matter, volatile organic compounds, and/or the sulfur dioxide emissions 13 from the diesel generators and storage tank, as well as the fuel consumption of the diesel 14 generators and gasoline of the fuel storage tank. LSCS has been in compliance with the 15 requirements established in its FESOP permit, and there have been no reported violations in the 16 past 5 years (Exelon 2015k; EPA 2015b). Emissions from permitted sources at LSCS are 17 presented in Table 3-4. LSCS also has additional air emission sources that are exempt from 18 permitting requirements, but it must still comply with applicable environmental laws and 19 regulations. These air emission sources include diesel pumps and generators that are less than 20 600 horsepower and that are intended to be used during emergency circumstances and only 21 operated during routine surveillance and testing (Exelon 2015j). Air emissions for LaSalle 22 County in 2011 for carbon monoxide, nitrogen oxides, sulfur dioxide, particulate matter less than 23 10 µm, and particulate matter less than 2.5 µm were 1,213 tons, 2,308 tons, 611 tons, 832 tons, 24 and 483 tons, respectively (EPA 2011). LSCS permitted annual emissions are less than 25 1 percent of the total 2011 emissions for LaSalle County. 26 Table 3-4. LSCS Air Emissions (MT/year)(a) Pollutant 2008 2009 2010 2011 2012 2013 CO 1.10 1.76 1.65 1.52 2.01 1.9 SO2 0.0042 0.0017 0.0021 0.0017 0.0021 0.001 NOx 4.18 6.62 6.21 5.73 7.58 6.0 PM10 0.075 0.12 0.11 0.10 0.14 0.11 PM2.5 0.075 0.12 0.11 0.10 0.14 0.11 VOC 0.25 0.33 0.32 0.30 0.35 0.30 CO2 -(b) -(b) 315.79 295.46 390.91 308.3 Key: CO = carbon monoxide, NOx = nitrogen oxides, SO2 = sulfur dioxide, PM10 = particulate matter less than 10 micrometers, PM2.5 = particulate matter less than 2.5 micrometers, and VOC = volatile organic compounds. (a) To convert metric tons (MT) per year to tons per year, multiply by 1.1023. (b) Carbon dioxide emissions reporting commenced in 2010; therefore, prior year emissions are not available. Sources: Exelon 2014, 2015k 27 On October 30, 2009, EPA published a rule for the mandatory reporting of greenhouse gases 28 (GHGs) from sources that in general emit 25,000 MT or more of carbon dioxide equivalent 29 (CO2e) per year in the United States (74 FR 56260). Most small facilities across all sectors of 30 the economy fall below the 25,000-MT threshold and are not required to report GHG emissions 31 to EPA. On June 3, 2010, EPA issued the Prevention of Significant Deterioration (PSD) and 3-27

Affected Environment 1 Title V GHG Tailoring Rule (75 FR 31514). Beginning January 2, 2011, operating permits 2 issued to major sources of GHGs under the PSD or Title V Federal permit programs must 3 contain provisions requiring the use of best available control technology to limit the emissions of 4 GHGs if those sources would be subject to PSD or Title V permitting requirements because of 5 their non-GHG pollutant emission potentials and because their estimated GHG emissions are at 6 least 75,000 tons per year of CO2e. As discussed above, LSCS is a synthetic minor source, 7 and, as shown in Table 3-4, GHG emissions from sources at LSCS are below the GHG 8 Mandatory Reporting (40 CFR Part 98) and Tailoring Rule thresholds. Section 4.15 of this SEIS 9 further discusses GHG emissions. 10 EPA issued the Regional Haze Rule (RHR) to improve and protect visibility in national parks 11 and wilderness areas from haze, which is caused by numerous, diverse sources located across 12 a broad region (40 CFR 51.308-309). Specifically, Subpart D of 40 CFR Part 81 lists mandatory 13 Class I Federal Areas where visibility is an important value. The Regional Haze Rule requires 14 states to develop State Implementation Plans to reduce visibility impairment at Class I Federal 15 areas. The nearest Class I Federal area for visibility protection is the Mingo National Wildlife 16 Refuge, which is approximately 306 mi (492 km) southwest of the LSCS site. EPA recommends 17 that emission sources located within 62 mi (100 km) of a Class I area be modeled to consider 18 adverse impacts (EPA 1992). Considering the distance to the nearest Class I area and the 19 minor nature of air emissions from the site, there is little likelihood that ongoing activities at 20 LSCS adversely affect air quality and air quality-related values (e.g., visibility or acid deposition) 21 in any of the Class I areas. 22 3.3.3 Noise 23 Noise is unwanted sound and can be generated by many sources. Sound intensity is measured 24 in logarithmic units called decibels (dB). A dB is the ratio of the measured sound pressure level 25 to a reference level equal to a normal persons threshold of hearing. Most people barely notice 26 a difference of 3 dB or less (FHA 2011). Another characteristic of sound is frequency or pitch. 27 Noise may be composed of many frequencies, but the human ear does not hear very low or 28 very high frequencies. To represent noise as closely as possible to the noise levels people 29 experience, sounds are measured using a frequency weighting scheme known as the A scale. 30 Sound levels measured on this A scale are given in units of A-weighted decibels (dBA). Table 31 3-5 presents common noise sources and their respective noise levels. Noise levels can 32 become annoying at 80 dBA and very annoying at 90 dBA. To the human ear, each increase of 33 10 dBA sounds twice as loud (EPA 1981). 34 Table 3-5. Common Noise Sources and Noise Levels Noise Source Noise Level (dBA) Human hearing threshold 0 Soft whisper 30 Quiet residential area 40 Dishwasher 55-70 Lawn mower 65-95 Blender 80-90 Ambulance siren, jet plane 120 Source: CHC undated 3-28

Affected Environment 1 Several different terms are commonly used to describe sounds that vary in intensity over time. 2 The equivalent sound intensity level (Leq) represents the average sound intensity level over a 3 specified interval, often 1 hour. The day-night average sound intensity level (LDN) is a single 4 value calculated from an hourly Leq over a 24-hour period, with the addition of 10 dBA to sound 5 levels from 10 p.m. to 7 a.m. This addition accounts for the greater sensitivity of most people to 6 nighttime noise. Statistical sound level (Ln) is the sound level that is exceeded n percent of the 7 time during a given period. For example, L90, is the sound level exceeded 90 percent of the 8 time and is considered the background level. 9 There are no Federal regulations1 for public exposures to noise (EPA 2015c). The EPA 10 recommends day-night average sounds levels (LDN) of 55 dBA as guidelines or goals for 11 outdoors in residential areas (EPA 1974). However, these are not standards. The Federal 12 Housing Administration has established noise assessment guidelines for housing projects and 13 finds that day-night average sound levels (LDN) of 65 dBA or less are acceptable (HUD 2014). 14 Sections 25 and 27 of the Illinois Environmental Protection Act of 1970 (Chapter 415) 15 established the authority to create noise regulations. The actual noise regulations are found in 16 the IAC (Title 35, Subtitle H). These noise regulations have allowable octave-band sound levels 17 according to emitting and receiving land class (Class A, B, and C) and time of day. 18 Major offsite noise sources in the vicinity of LSCS include vehicles, wind turbines, and 19 agricultural equipment/machinery (Exelon 2015l). Common noise sources from nuclear power 20 plant operations include transformers, loudspeakers, cooling towers, auxiliary equipment, and 21 worker vehicles (NRC 2013). Major noise sources at LSCS include pumps, turbine building 22 supply and exhaust fans, sirens, generators, transformers, and loudspeakers (Exelon 2015m). 23 However, most of these noise sources are inside buildings, at approximately a 980-ft (300-m) 24 distance from the site boundary, and/or are intermittent. The nearest resident is approximately 25 0.7 mi (1.1 km) from the reactor buildings (Exelon 2014a). Exelon has not received any noise 26 complaints from residents in the vicinity of LSCS (Exelon 2014a). Additional noise sensitive 27 receptors nearby include the LaSalle Lake State Fish and Wildlife Area and Marseilles State 28 Fish and Wildlife Area. LSCS is subject to, and in compliance with, Illinois noise pollution 29 control regulations (Exelon 2015c, 2015m). 30 3.4 Geologic Environment 31 This section describes the current geologic environment of the LSCS site and vicinity, including 32 landforms, geology, soils, and seismic conditions. 33 3.4.1 Physiography and Geology 34 The site is located in an area that contains glacially deposited sediments overlying a bedrock 35 surface. These deposits formed during successive periods of glaciation. The power block and 36 the cooling pond are located on a glacial moraine (a depositional landform directly deposited by 37 a glacier). This area has a flat gently rolling topography. The river screen house is located 38 north of both the power block and cooling pond on the flat-lying river valley of the Illinois River. 39 The river valley is approximately 3.5 mi (5.6 km) north of the site and is topographically 40 separated from the glacial moraine by the bluffs along the Illinois River. The bluffs along the 41 Illinois River are dissected by stream valleys that cut into the glacial sediments and drain north 1 In 1972, Congress passed the Noise Control Act of 1972 (42 U.S.C. 4901 et seq.) establishing a national policy to promote an environment free of noise that impacts the health and welfare of the public. However, in 1982, there was a shift in Federal noise control policy to transfer the responsibility of regulation noise to state and local governments. The Noise Control Act of 1972 was never rescinded by Congress, but it remains unfunded (EPA 2015c). 3-29

Affected Environment 1 to the Illinois River. The maximum topographic relief between the site and the river is 2 approximately 255 ft (78 m) (Exelon 2014a; USDA 2008) (Figure 3-7). 3 In the area of the power block and the cooling pond, the land is covered by a 4- to 8-ft (1.2- to 4 2.4-m) layer of Richland Loess. The loess consists of windblown silt that has been weathered 5 to slightly clayey silt. The Richland Loess is underlain by the Wedron Silty-Clay Till. The till was 6 directly deposited by glacial activity. It consists of unsorted silt and clay sedimentary deposits. 7 In localized areas, the till also contains scattered, disconnected bodies of sand and gravel. In 8 the area of the plant buildings and cooling pond, the Wedron Silty-Clay Till ranges in thickness 9 from 120 to 140 ft (37 to 43 m). Moving north from the plant buildings and the cooling pond to 10 the river, the Wedron Silty-Clay Till decreases in thickness until it disappears near the Illinois 11 River (Figure 3-8) (Exelon 2014a). 12 Below the LSCS site, the Wedron Silty-Clay Till is underlain by bedrock. The topography of the 13 bedrock reflects the surface of the land before glaciation. This topography is now buried by 14 glacially deposited sediments. The site is located between two bedrock valleys that are filled 15 with the Wedron Silty-Clay Till and some alluvial sand and gravel deposits from ancient streams 16 that flowed through the bedrock valleys before they were completely buried. One alluvium-filled 17 buried valley runs east-west and is located between the plant facility and the Illinois River Bluff, 18 and one valley is located south of the plant facility and trends northwest and southeast 19 (Exelon 2014a, 2014c) (Figure 3-9). 20 The underlying bedrock consists of 4,500 ft (1,371 m) of dolomite, sandstone, and shale rock. 21 In turn, these rocks are underlain by granites and metamorphic rocks to a great depth. The 22 Pennsylvanian aged Carbondale Formation forms the top of the bedrock surface over most of 23 the site area. It is composed of alternating strata of shale, sandstone, clay, coal, limestone, and 24 siltstone (Exelon 2014a). 25 LaSalle County contains a number of geologic resources of economic importance. The County 26 is one of a handful of locations that can easily access the St. Peter Sandstone Formation. The 27 unique characteristics of this sandstone make it valuable for a number of commercial uses, 28 including glass, sand filters, sand molding, and abrasives. It is also in high demand for the 29 extraction of oil and gas using conventional horizontal drilling and shale fracking techniques. 30 LaSalle County also contains commercial deposits of gravel and limestone. Limestone and 31 gravel are used in concrete, agricultural limestone, and road surfaces. Clay is mined in the 32 county to manufacture bricks, drain tile, and dinnerware. Coal is no longer mined in the County 33 but historically was mined in bluffs along the Illinois River and around Streator, Illinois 34 (Ataner and Butler 2013; LaSalle County 2014; USDA 2008). 35 The LSCS site is underlain by coal seams, limestone beds, and the St. Peter Sandstone. 36 However, they lie too deep beneath the land surface to be economically accessed. No oil and 37 gas deposits have been identified beneath the site. 38 3.4.2 Soils 39 Eighty-five percent of the soil in LaSalle County is designated as prime farmland, and 9 percent 40 is farmland of State importance (Exelon 2014a). Within the site boundary, almost all the soil is 41 either silty loam or silty clay loam and is designated as prime farmland or farmland of State 42 importance (Exelon 2014a; USDA 2008, 2015b). 43 Following initial construction of the facility, areas surrounding LSCS were graded to control 44 runoff and to minimize erosion. Many areas were revegetated to support this effort 45 (Exelon 2014a). 3-30

Affected Environment 1 Figure 3-7. Site Physiography, LSCS Vicinity 2 Source: NRC Generated 3-31

Affected Environment 1 Figure 3-8. North-South Geologic Cross Section, LSCS Vicinity 2 (Elevation Exaggerated) 3 Source: Modified from Exelon 2014a 3-32

Affected Environment 1 Figure 3-9. Bedrock Topography and Buried Valleys, LSCS Vicinity 2 Source: Modified from Exelon 2014e 3-33

Affected Environment 1 3.4.3 Seismic Setting 2 The site is located in an area of Illinois that might experience slight damage from earthquakes 3 (FEMA 2015; Mid-America Earthquake Center 2009). A number of earthquakes (USGS 2013a, 4 2013b, 2013c) have originated within Illinois, including the following: 5

  • On May 26, 1909, a large earthquake knocked over many chimneys in Aurora and 6 swayed buildings in Chicago.

7

  • On July 18, 1909, an earthquake knocked down chimneys in Petersburg.

8

  • On August 14, 1965, a sharp local earthquake knocked down chimneys in Elco, 9 Unity, Olive Branch, and Olmstead.

10

  • On November 9, 1968, a magnitude 5.3 earthquake was felt over the entire State of 11 Illinois and in 22 other states.

12 Dozens of earthquakes originating outside Illinois have been felt inside the State without 13 causing damage. These earthquakes originated in Missouri, Arkansas, Kansas, Nebraska, 14 Tennessee, Indiana, Ohio, Michigan, Kentucky, and Canada. Illinois can be affected by two 15 major seismic zones, the Wabash Valley Seismic Zone and the New Madrid Seismic Zone. The 16 Wabash Valley Zone lies between southeastern Illinois and southwestern Indiana about 322 mi 17 (518 km) from the site. The New Madrid Seismic Zone is about 300 mi (483 km) from the site in 18 southern Illinois, Missouri, Kentucky, and Tennessee. Of these two seismic zones, the New 19 Madrid Seismic Zone is capable of producing very powerful earthquakes. If a large magnitude 20 earthquake occurs in the New Madrid Seismic Zone, major damage could be experienced in 21 southern Illinois (Missouri Department of Natural Resources 2013; USGS 2009). 22 The NRC requires every nuclear power plant to be designed for site-specific ground motions 23 that are appropriate for its location. Nuclear power plants, including LSCS, Units 1 and 2, are 24 designed and built to withstand site-specific ground motion based on their location and nearby 25 earthquake activity. For LSCS, this includes earthquakes originating in either the Wabash 26 Valley Zone or the New Madrid Seismic Zone (Exelon 2014a). The seismic design basis is 27 established during the initial siting process using site-specific seismic hazard assessments. For 28 each nuclear power plant site, applicants estimate a design-basis ground motion based on 29 earthquake sources, wave propagations, and site responses; this estimate is then accounted for 30 in the design of the plant. In this way, nuclear power plants are designed to withstand the 31 maximum credible earthquake for a given site. Because methods of assessing seismic hazards 32 evolve over time and the scientific understanding of earthquake hazards improve (NRC 2014c), 33 the NRCs understanding of the seismic hazard for a given nuclear power plant may change 34 over time. As new seismic information becomes available, the NRC evaluates the new 35 information to determine whether changes are needed at existing plants or to NRC regulations. 36 The NRCs evaluation of the impact of seismic activity on a nuclear power plant is an ongoing 37 process that is separate from the license renewal process. 38 On December 23, 2011, the Consolidated Appropriations Act (Public Law 112-074) was signed 39 into law. Section 402 of the law directs the NRC to require reactor licensees to re-evaluate the 40 seismic hazard at their sites against current applicable Commission requirements and 41 thereafter, when appropriate, as determined by the Commission (NRC 2012). In 2012, the NRC 42 required all licensees to re-evaluate the seismic hazards at their sites using updated seismic 43 information and present-day regulatory guidance and methodologies (NRC 2012). The purpose 44 of that request was to gather information to update the seismic hazards analysis to enable the 45 NRC staff to determine whether individual site licenses should be modified, suspended, or 46 revoked (NRC 2014a). On March 31, 2014, Exelon responded to this request and provided its 3-34

Affected Environment 1 Seismic Hazard and Screening Report (SHSR) for LSCS (Exelon 2014d). On April 21, 2015, 2 the NRC staff issued an assessment (NRC 2015a) documenting its review of the Seismic 3 Hazard and Screening Report. The NRC staff concluded that Exelon met the intent of the 4 guidance for determining the re-evaluated seismic hazard and that it had provided an 5 acceptable response to the request. In addition, the NRC staff directed Exelon to perform 6 further seismic evaluations for NRC review. 7 3.5 Water Resources 8 3.5.1 Surface Water Resources 9 This section describes the current surface water resources within and near LSCS. 10 NUREG-1437, Generic Environmental Impact Statement for License Renewal of Nuclear Plants 11 (GEIS) (NRC 2013), states that surface water encompasses all water bodies that occur above 12 the ground surface, including rivers, streams, lakes, ponds, and man-made reservoirs or 13 impoundments. 14 3.5.1.1 Surface Water Hydrology 15 The major surface water body in the region is the Illinois River, located approximately 4 mi 16 (6.4 km) to the north of the LSCS main plant complex (see Figure 3-2). The LSCS site is 17 situated within the lowermost portion of the Upper Illinois River Basin, which includes the 18 10,949- mi2 (28,369-square-kilometer (km2)) drainage area upstream from Ottawa, Illinois 19 (Figure 3-10). The Illinois River is formed from the confluence of the Kankakee and Des 20 Plaines Rivers at a point approximately 10 mi (16 km) east of Morris, Illinois. The main stem of 21 the Illinois River is joined by the Fox River at Ottawa (Arnold et al. 1999; USGS 1998). 22 The Illinois River is also central to the Illinois Waterway, which provides for navigation from Lake 23 Michigan to the Mississippi River and on to the Gulf of Mexico. The origins of this waterway 24 began with the construction of canals from the lake to the Chicago and Illinois Rivers, beginning 25 in the 1830s. Construction of the formal Illinois Waterway began in 1919 with the State of 26 Illinois leading efforts in the upper part of the river basin and the U.S. Army Corps of Engineers 27 (USACE) in the lower part. Today, the Illinois Waterway includes part of the Chicago River, the 28 Chicago Sanitary and Ship Canal, the Des Plaines River, and the Illinois River. Navigation is 29 made possible by a series of eight major locks and dams and associated navigation pools along 30 the Illinois River and its tributaries. Each pool is named for the dam downstream of each pool 31 (Exelon 2014a; Talkington 1991). Along its length, the waterway contains a navigation channel 32 at least 9 ft (2.7 m) deep and 300 ft (91 m) wide (Talkington 1991). In the vicinity of LSCS, at 33 normal pool elevation, the river has a depth of 12 ft (3.7 m) and a width of 800 ft (244 m) 34 (Exelon 2014a). 35 LSCS is located along the Marseilles Pool portion of the Illinois River. The Marseilles Lock and 36 Dam at Illinois RM 247 (RKm 397.5) is approximately 2.4 mi (3.9 km) downstream of the LSCS 37 intake and discharge structures near RM 249.5 (RKm 401.5) (see Section 3.1.3). However, the 38 lock itself is located a further 2.5 mi (4.0 km) downstream of the dam on a bypass canal 39 (Marseilles Canal) (USACE 2014). The Dresden Island Lock and Dam is 22 mi (35 km) 40 upstream of the LSCS intake structure at RM 271.5 (RKm 437) (Exelon 2014a). The Marseilles 41 Dam is 24 ft (7.3 m) high, and the Dresden Dam is 22 ft (6.7 m) high (Talkington 1991). 42 In total, the main stem of the Illinois River flows for approximately 270 mi (439 km) through 43 Illinois and ultimately discharges into the Mississippi River at Grafton, Illinois (Exelon 2014a; 44 USGS 1994; Talkington 1991). However, when accounting for the other components of the 45 Illinois Waterway, the total length of the river system is 327 mi (526 km) (Talkington 1991). 3-35

Affected Environment 1 The U.S. Geological Survey (USGS) maintains a gaging station on the Illinois River at 2 Marseilles, Illinois (Station 05543500) and RM 246.5 (RKm 396.7). This station is 3 approximately 3 mi (4.8 km) downstream from the LSCS river screen house intake and nearby 4 discharge structure near RM 249.4 (RKm 401). The gaging station is also 0.5 mi (0.8 km) 5 downstream of the Marseilles Dam and 6.9 mi (11 km) upstream from the confluence of the Fox 6 River with the main stem of the Illinois River (Exelon 2014a; USGS 1999b, USGS 2015). 7 The mean annual discharge measured at the USGS gage at Marseilles for water years 1920 8 through 2014 is 10,750 cfs (304 m3/s). For water year 2014, the mean discharge was 9 11,190 cfs (316 m3/s). The mean 90-percent exceedance flow is 4,340 cfs (123 m3/s) for the 10 period of record (USGS 2015). The 90 percent exceedance flow is an indicator value of 11 hydrologic drought. It signifies a rate of streamflow that is equaled or exceeded 90 percent of 12 the time, as compared to the average flow for the period of record. Based on average monthly 13 flow over the period of record at the station, November is the low-flow month, and April is the 14 high-flow month for the Marseilles Pool (USGS 2015). 15 Tributaries to the Illinois River in the immediate vicinity of LSCS include South Kickapoo Creek, 16 Spring Brook, Deadly Run, Armstrong Run, and Hog Run (Figure 3-11). These headwater 17 streams and manmade ditches drain the glacial upland on which LSCS is located and generally 18 flow north toward the dissected bluffs of the river and across the river valley and into the Illinois 19 River. The most extensive of these nearby tributaries is South Kickapoo Creek. With its 20 headwaters on the northwest side of the LSCS property, this stream receives stormwater runoff, 21 cooling pond dike seepage collected by the LSCS perimeter drainage ditch, and overflow from 22 the cooling pond auxiliary spillway (see Figures 3-3 and 3-5). The main channel of South 23 Kickapoo Creek flows north to northwest from LSCS, with the main channel discharging to the 24 Illinois River at a point approximately 3.5 mi (5.6 km) northwest of the LSCS cooling pond and 25 approximately 0.4 mi (0.6 km) downstream of the LSCS blowdown discharge structure 26 (Exelon 2014a). 27 On the northeast perimeter of the cooling pond is Armstrong Run. Armstrong Run previously 28 drained much of the area that is now occupied by LSCS before plant construction. Like many of 29 the manmade drainage channels (called runs) in the region, it was constructed to convey 30 drainage collected by agricultural drain tile systems (NRC 1978). Armstrong Run now receives 31 runoff and seepage collected from the northeast end of the peripheral dike drainage ditch. 32 It discharges to the Illinois River at a point approximately 3.2 RM (5.1 RKm) northeast of the 33 cooling pond and about 4.5 RM (7.2 RKm) upstream of the river screen house (Exelon 2014a). 34 As further described in Section 3.1.3, the dominant surface water feature within the LSCS site 35 and vicinity is the 2,058- ac (833- ha) cooling pond (Figure 3-5). Other surface water features 36 on the LSCS plant site include two stormwater management ponds (North and South Storm 37 Water Ponds), two sewage treatment lagoons, and a collection of hatchery ponds as 38 summarized below. The NRC staff visited the facilities cited herein during the May 2015 39 environmental site audit (NRC 2015b). 40 The North and South Storm Water Ponds are located west of the LSCS main plant complex and 41 receive stormwater runoff from the protected area, serving the north and south zones of the 42 plant, respectively. Within the site, a system of ditches, storm drains, culverts, and underground 43 storm sewers collect runoff and drainage from the protected area and convey much of it to 44 either of the two ponds. Uncontaminated runoff from the north zone of the plant is conveyed to 45 the North Storm Water Pond, with some runoff sources first passing through the Unit 2 oil-water 46 separator. A portion of the switchyard also drains toward the north zone, although most of the 47 switchyard drains east to the cooling pond. 3-36

Affected Environment 1 Figure 3-10. The Upper Illinois River Basin and Drainage Basin Boundaries 2 Source: Modified from Arnold et al. 1999 3-37

Affected Environment 1 Figure 3-11. LSCS Surface Water and Related Water Resource Features 2 Source: Modified from Exelon 2014a, 2015b 3-38

Affected Environment 1 Most runoff from the south zone enters the smaller South Storm Water Pond; this pond then 2 discharges to the cooling pond discharge canal through internal Outfall H01. Before entering 3 the pond, some flows first pass through the Unit 1 oil-water separator. The south pond also 4 receives runoff from the firing range. Areas of the plant site to the northwest and south of the 5 developed plant complex do not drain to the ponds but instead are drained by existing surface 6 stream segments and ditches (Exelon 2014a, 2014c). 7 Stormwater management and pollution control at LSCS is subject to Exelons Storm Water 8 Pollution Prevention Plan (SWPPP) (Exelon 2013e), which Exelon has implemented in 9 accordance with Special Condition 8 of the sites NPDES permit (IEPA 2013). The SWPPP 10 applies to industrial stormwater runoff from the site, which is not otherwise process-related and 11 not captured and processed by LSCSs wastewater treatment facilities. It describes the best 12 management practices, controls, inspection, and monitoring requirements, and the associated 13 implementing procedures and personnel responsibilities for reducing pollutants in stormwater 14 discharge and for ensuring compliance with the terms and conditions of the site NPDES permit 15 (Exelon 2013e). 16 Two open sewage treatment lagoons provide primary and secondary treatment for LSCSs 17 sanitary effluent. These lagoons are geotextile-lined impoundments and are located to the north 18 of the main plant complex adjacent to LSCSs sewage treatment plant (as shown in 19 Figure 3-3). Together, the NRC staff estimates the two impoundments cover an area of about 20 1.6 ac (0.65 ha). After filtration and final disinfection in the sewage treatment plant, the final 21 effluent from the treatment system is discharged into the cooling pond via NPDES internal 22 Outfall B01 (Exelon 2014a, 2014c). 23 A cluster of 16 small fish-rearing ponds is located on the southwest shore of the cooling pond 24 (see Figures 3-3 and 3-5). The NRC staff estimates that the ponds total approximately 29 ac 25 (12 ha) of open water. These ponds comprise the LaSalle Fish Hatchery operated by the IDNR 26 on plant property and subject to a lease agreement with Exelon. The hatchery uses the cooling 27 pond as a makeup water source. Runoff and drainage from the hatchery ponds flow back to the 28 cooling pond and are ultimately subject to LSCSs NPDES permit provisions 29 (Exelon 2014a, 2014c). The LSCS sites NPDES permit is further discussed in Section 3.5.1.3. 30 LSCS is not susceptible to riverine flooding because it is located upland and away from the 31 Illinois River. 32 The grade elevation at the plant site is 710 ft (216 m) above MSL, and the floor elevation of the 33 LSCS facilities is 710.5 ft (217 m) above MSL. The plant floor lies at an elevation that is 188 ft 34 (57 m) above the level of a postulated probable maximum flood on the Illinois River 35 (Exelon 2014a, 2014g). Although the river screen house is not a safety-related structure, it is 36 designed to withstand the 100-year flood on the Illinois River. Its loss would not impact the 37 ability to safely shut down the plant as water could still be drawn from the cooling pond and from 38 the UHS portion of the cooling pond, as described in Section 3.1.3 of the SEIS (Exelon 2014a, 39 2014g). 40 Furthermore, a failure of the peripheral dike system enclosing the cooling pond would not flood 41 the power plant area because the onsite topography would cause cooling pond water to flow 42 north and away from the plant following the existing drainage network (Exelon 2014a, 2014g). 43 3.5.1.2 Surface Water Use 44 LSCS withdraws surface water from the Illinois River as makeup water for the plants cooling 45 pond. The cooling pond provides water for the plants circulating water, service water, and 46 essential cooling water systems. Cooling tower blowdown and other permitted effluent streams 47 are discharged back to the Illinois River via the plants primary NPDES outfall (Outfall 001) at a 3-39

Affected Environment 1 point located about 900 ft (270 m) downstream from LSCSs river intake structure and 2 associated river screen house. 3 The maximum (nominal) surface water withdrawal rate for LSCS, Units 1 and 2, is 90,000 gpm 4 (200 cfs or 5.66 m3/s). This is equivalent to 129.6 million gallons per day (mgd) 5 (491,000 m3/day). However, Exelon reports in its ER that LSCSs normal peak makeup 6 withdrawal rate from the Illinois River is 60,000 gpm (134 cfs or 3.77 m3/s) or 86.4 mgd 7 (327,000 m3/day). This rate assumes a two-pump operation with valves open at 100 percent. 8 The third makeup pump located in the river screen house normally serves as a backup 9 (see Section 3.1.3). 10 The NRC staff reviewed submittals by Exelon to the Illinois State Water Survey that document 11 the volume of surface water withdrawn from, and discharged back to, the Illinois River during 12 the period 2009 to 2013 (Table 3-6). Based on these data, LSCS surface water withdrawals 13 have averaged 24,745 million gallons per year (mgy) (93.7 million cubic meters per year 14 (m3/yr)). This is equivalent to an average withdrawal rate of approximately 105 cfs (2.96 m3/s or 15 67.8 mgd). Return discharges (blowdown) to the Illinois River have averaged 13,046 mgy 16 (49.4 million m3/yr), which is equivalent to an average discharge rate of about 55.3 cfs 17 (1.56 m3/s or 35.7 mgd). The difference between withdraw and discharge (i.e., approximately 18 49.7 cfs (1.40 m3/s)) generally reflects process consumptive use or other losses, evaporative 19 losses, and presumably seepage from the cooling pond. In total, these data indicate a 20 consumptive use rate averaging 47 percent. 21 Table 3-6. Annual Surface Water Withdrawals and Returns to the Illinois River, LSCS Withdrawals Discharges Year (mgy) mgd cfs (mgy) mgd cfs 2009 28,598.4 78.5 121 19,405.0 53.2 82.2 2010 25,876.8 70.9 110 13,686.0 37.5 58.0 2011 23,328.0 63.9 98.9 11,961.1 32.8 50.7 2012 28,857.6 79.1 122 14,005.7 38.4 59.4 2013 17,064.0 46.7 72.3 6,173.0 16.9 26.2 Average 24,745.0 67.8 105 13,046.1 35.7 55.3 Note: Reported and calculated values are rounded. To convert million gallons per year (mgy) to million cubic meters (m3), divide by 264.2. To convert, million gallons per day (mgd) to cubic feet per second (cfs), multiply by 1.547. Sources: Exelon 2011a, 2012a, 2013a, 2014a, 2014d 22 LSCSs surface water withdrawals and consumptive water use are not subject to any water 23 allocation or related permitting requirements at the present time. In 2006, the Governor of 24 Illinois issued an executive order establishing a Statewide program for State and regional water 25 supply planning and management, which included the development and approval of regional 26 plans in designated Priority Water Quantity Planning Areas (State of Illinois 2006). LaSalle 27 County, where LSCS is located, is not included within any of the three designated planning 28 areas (Exelon 2014a; ISWS 2015a). Nevertheless, as referenced above, Exelon reports its 29 surface water withdrawals to the State of Illinois under the State Illinois Water Inventory 30 Program (Exelon 2014a; ISWS 2015b). Reporting is required in accordance with the Illinois 31 Water Use Act of 1983 (525 ILCS 45) and its 2010 amendments. The general purpose and 32 intent of the Act is to establish a means of reviewing potential water conflicts before damage to 3-40

Affected Environment 1 any person is incurred and to establish a rule for mitigating water shortage conflicts. The 2 2010 amendments to the Illinois Water Use Act added high-capacity intakes as subject to the 3 Acts water use reporting provisions. Such intakes are surface water intakes on a property in 4 which the rate or capacity of water withdrawal of all intakes for the property is equal to, or in 5 excess of, 100,000 gal (380 m3) during any 24-hour period (525 ILCS 45). 6 Under certain conditions, Exelon may take action to curtail surface water withdrawals from, and 7 cooling pond blowdown to, the Illinois River in accordance with the LSCS Extreme Heat 8 Implementation Plan. As necessary, plant personnel would take actions prescribed by the plan 9 and associated procedures to mitigate the impacts of summer drought and/or high river 10 temperature and river low-flow conditions. Depending on predefined conditions set forth in the 11 plan and implementing procedures, such actions may include a combination of monitoring and 12 modeling of river intake and mixing zone temperatures; manipulation of the water level of the 13 cooling pond, including adjusting blowdown flow from and makeup water withdrawals to the 14 cooling pond; and taking other actions to meet NPDES mixing zone thermal limits and the TS 15 limits on condenser inlet temperature from the cooling pond (Exelon 2014a, 2015c). 16 Two other industrial facilities withdraw water from the Marseilles Pool of the Illinois River in the 17 vicinity of LSCS (Figure 3-5) and are listed in the Illinois Water Inventory Program. These are 18 Agrium U.S., Inc., and PCE Phosphate, Marseilles Operation. The volume of water withdrawn 19 by these commercial facilities is not publicly available (Exelon 2014a). Because they are 20 included in the States inventory, the NRC staff presumes that each facility withdraws in excess 21 of 100,000 gpd (380 m3). Both are also currently subject to NPDES individual permits 22 (i.e., Permits IL0001708 and IL0036463). Based on reported return discharges to the Illinois 23 River, it is estimated that Agriums surface water withdrawals are on the order of 5 mgd 24 (18,900 m3) (EPA 2015a). 25 The public water supply systems in the vicinity of LSCS (i.e., the city of Marseilles and the 26 village of Seneca) do not withdraw water from the Illinois River but instead rely upon 27 groundwater-supplied systems (Exelon 2014a) (see Section 3.5.2.2). 28 Surface water withdrawals within the Marseilles Pool have shown no significant effects on water 29 availability to date (Exelon 2014a). 30 3.5.1.3 Surface Water Quality and Effluents 31 The Illinois Pollution Control Board (IPCB), a sister agency to the IEPA, promulgates water 32 quality standards in the State. Two Sections of Title 35 of the IAC (35 IAC 302 and 35 IAC 303) 33 contain the standards applicable to lakes and streams. Procedures that must be followed in 34 using water quality standards to set NPDES permit limits appear in Section 309 (35 IAC 309). 35 Designated uses prescribed by 35 IAC 303 are those uses specified in water quality standards 36 for each lake, river, stream, and groundwater resource. In designating uses for a waterbody, 37 the IPCB considers the use and value of the waterbody for public water supply; propagation of 38 fish, shellfish, and wildlife; and recreational, agricultural, industrial, and navigational purposes. 39 The main stem of the Illinois River is designated a general use water by the IPCB. Waters in 40 the general use category must meet water quality standards protective of aquatic life, wildlife, 41 agricultural use, and secondary contact use, as well as most industrial uses and aesthetic 42 quality (35 IAC 303.201). These standards pertain to pH; phosphorus; dissolved oxygen; 43 radioactivity (gross beta, strontium-90, and radium-226 and -228); various chemical constituents 44 (metals and organic compounds); fecal coliform; and other toxic substances. In addition, a 45 segment of the main stem of the Illinois River within LaSalle and Grundy Counties, and 46 encompassing the entire Marseilles Pool on which LSCS is located, is afforded enhanced 47 dissolved oxygen protection. Dissolved oxygen levels must be not less than 5.0 milligrams per 3-41

Affected Environment 1 liter at any time during March through July and not less than 4.0 milligrams per liter at any time 2 during August through February (35 IAC 302.206). 3 Over the last 150 years, water quality within the whole of the Illinois River Basin has historically 4 suffered from rapid population growth; urbanization; and industrial development, including the 5 conversion of prairie, wetlands, and forests. This change resulted in the discharge of untreated 6 and inadequately treated sewage, the discharge of industrial pollutants and refuse, runoff of 7 agricultural chemicals and sediments, and the alteration of the natural river hydrology due to 8 navigation and flood control projects (Exelon 2014a; Talkington 1991). 9 Over the last 50 years, substantial improvements in water quality have occurred because of 10 municipal and industrial waste treatment and management efforts to address both point and 11 nonpoint pollutant sources. Ongoing water quality concerns within the upper Illinois River Basin 12 include the atmospheric deposition of pesticides and trace metals; endocrine disrupting 13 compounds in surface and groundwater; nutrient enrichment of surface and groundwater; the 14 transport and fate of pesticides, trace elements, and volatile organic compounds in surface and 15 ground water; and the effects of urbanization on biodiversity, habitat, and water quality 16 (USGS 1998). 17 Section 303(d) of the Federal Water Pollution Control Act (i.e., Clean Water Act of 1977, as 18 amended (CWA) (33 U.S.C. 1251 et seq.)) requires the State of Illinois and other states to 19 identify all impaired waters for which effluent limitations and pollution control activities are not 20 sufficient to attain water quality standards in such waters. The Section 303(d) list includes those 21 water quality-limited stream segments that require the development of total maximum daily 22 loads (TMDLs) to ensure future compliance with water quality standards. The TMDLs specify 23 the maximum amount of a pollutant that a waterbody can receive and still meet water quality 24 standards. Once established, TMDLs are typically implemented through watershed-based 25 programs administered by the State, primarily through the NPDES permit program and 26 associated point and nonpoint source water quality improvement plans and associated best 27 management practices. The IEPA has classified a 30.1-mi- (48.4-km)-long segment (IL_D-23) 28 of the Illinois River between Morris and Ottawa, Illinois, that includes the LSCS site as impaired. 29 This segment is listed as impaired because it does not meet designated uses for fish 30 consumption due to polychlorinated biphenyls (PCBs) and mercury contamination. It is also 31 impaired for primary contact recreation use due to fecal coliform bacteria (IEPA 2014b). Special 32 Condition 13 of the NPDES permit for LSCS prohibits the discharge of PCBs in plant effluents 33 (IEPA 2013). The river segment is classified as fully supporting its designated use for aquatic 34 life. IEPA has assigned a medium priority for the development of TMDLs for segment IL_D-23 35 (IEPA 2014b). 36 As for other streams and runs in the vicinity of LSCS, IEPA (2014b) designates them as 37 Category 3, which are waters for which no use-support determination can be made due to 38 insufficient available data and/or information. 39 The LSCS cooling pond is included in the IEPAs CWA Section 314 inventory of lakes and has 40 also been designated as Category 3 (IEPA 2014b). However, LSCSs cooling pond is defined 41 by the State of Illinois as a wastewater treatment works pursuant to 35 IAC 301.415. Under this 42 definition, the cooling pond is not waters of the State under 35 IAC 301.440. Likewise, as 43 defined in 40 CFR 230.3, pursuant to the Federal CWA, waste treatment systems, including 44 treatment ponds or lagoons designed to meet the requirements of the Clean Water Act are 45 explicitly excluded from the definition of waters of the United States. Therefore, the cooling 46 pond is not subject to State or Federal water quality standards. 47 To operate a nuclear power plant, licensees must comply with the CWA, including associated 48 requirements imposed by EPA or the state as part of the NPDES permitting system under 3-42

Affected Environment 1 Section 402 of the CWA, as well as state water quality certification requirements under 2 Section 401 of the CWA. The EPA or the state, not the NRC, sets the limits for effluents and 3 operational parameters in plant-specific NPDES permits. Nuclear power plants cannot operate 4 without a valid NPDES permit and a current CWA Section 401 Water Quality Certification. The 5 EPA has delegated responsibility to the State of Illinois for the administration of the NPDES 6 program in Illinois. NPDES permits are issued by the IEPA on a 5-year cycle. 7 LSCS is authorized to discharge various wastewater (effluent) streams, including cooling pond 8 blowdown and stormwater under NPDES Permit IL0048151, reissued on July 5, 2013; the 9 current permit expires on July 31, 2018 (Exelon 2014a; IEPA 2013). The permit specifies the 10 discharge standards and monitoring requirements for effluent chemical and thermal quality 11 through the plants outfalls to the Illinois River, as summarized in Figure 3-7. The location of 12 the LSCSs primary outfall (001) to the Illinois River is shown in Figure 3-5. 13 Table 3-7. National Pollutant Discharge Elimination 14 System-Permitted Outfalls, LSCS Average Flow Outfall Rate (mgd)(a) Description 001(b,c,d,e) 34.9 Cooling Pond Blowdown; includes effluents from internal Outfalls A01 through H01, as well as IDNR fish hatchery effluents; discharge to the Illinois River A01(b,f,g) Intermittent Demineralizer Regenerant Wastes; includes makeup demineralizer regenerant wastes, off-specification demineralized water, makeup demineralizer maintenance wastewater, unit waterbox vacuum pump condensate, and radioactive waste (radwaste) treatment acid/caustic system drains discharges B01(b,c,f,g,h) 0.06 Sewage Treatment Plant Effluent; includes sanitary wastewater and eyewash station wastewater C01(b,c,f,g,i) 0.044 Wastewater Treatment System Effluent; includes nonsanitary drains composed of turbine building fire and miscellaneous nonradioactive wastewater sump, greensand filter backwash, diesel fuel storage and service water building sump, auxiliary boiler blowdown, water softener regenerant waste, demineralizer regenerant wastes, heat bay building roof area, fire protection system flushing and maintenance, service water system flushing and maintenance, domestic water system flushing and maintenance, clean condensate system flushing and maintenance, laboratory liquid wastes, station heat system condensate, diesel generator cooling water, standby liquid control test skid flush water, and groundwater D01(f) Intermittent Cooling Water Intake Screen Backwash E01(b,f g,i) Intermittent Unit 1 and 2 Radwaste Treatment System Effluent; includes equipment and floor drains in the turbine, auxiliary, and reactor buildings, as well as condensate polisher waste from the turbine building and decontamination and laundry waste F01(f) Intermittent Auxiliary Reactor Equipment Cooling and Flushing Water G01(f,j) Intermittent North Site Stormwater Runoff H01(f,j) Intermittent South Site Stormwater Runoff I01(b,f,g) Intermittent Reverse Osmosis System Reject Water and Greensand Filter Backwash 3-43

Affected Environment Average Flow Outfall Rate (mgd)(a) Description 002(k) Intermittent Illinois River Makeup Water Intake Screen Backwash; includes river intake screen backwash; trench wash water; process sampling discharge; lake makeup pump gland leakoff; coolers/reliefs flow; lake makeup pump strainer backwash; air compressor receiver and prefilter drainage; dewatering pump discharge; fire protection water; and river screen house switchyard stormwater runoff, floor drains, and roof drains; discharge to the Illinois River at the river screen house (a) To convert million gallons per day (mgd) to million cubic meters (m3), divide by 264.2. (b) Flow is subject to monitoring and reporting in units of mgd as a monthly average and as a daily maximum on Discharge Monitoring Report (DMR) (NPDES permit Special Condition 1). (c) pH is subject to limit of 6.0 to 9.0 (NPDES permit Special Condition 2). (d) Temperature is subject to continuous monitoring and DMR reporting of maximum monthly, as well as with temperature limits and mixing zone criteria (NPDES permit Special Condition 3). The calculated temperature at the edge of the mixing zone is limited to no more than 5 °F (2.8 °C) higher than ambient river temperature. The temperature beyond the mixing zone cannot exceed specified monthly limits for longer than 1 percent (i.e., 87.6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />) of any 12-month period and cannot at any time exceed the specified monthly limit by more than 1.7 °C (3 °F). During the months of April through November, the calculated temperature outside the mixing cannot exceed 93 °F (34 °C). (e) Total residual chlorine is subject to a limit of 0.05 milligrams per liter (NPDES permit Special Conditions 4 and 16). (f) This outfall is the NPDES permit internal monitoring point before the numbered point source outfall. (g) Total suspended solids are subject to specified limits and monitoring. (h) Carbonaceous biochemical oxygen demand is subject to specified limits and monitoring. (i) Oil and grease are subject to specified limits and monitoring. (j) Stormwater is subject to requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8). (k) Adequate maintenance of intake screen system is required to prevent discharge of floating debris back to the river. The stormwater portion is subject to the requirements of the Storm Water Pollution Prevention Plan (NPDES permit Special Condition 8). Note: The release of complex metal-bearing waste streams and polychlorinated biphenyls (PCBs) from all outfalls is prohibited by NPDES permit Special Conditions 5 and 13, respectively. Special Condition 9 authorizes the use of water treatment additives that were requested by Exelon as part of the renewed NPDES permit application. Source: IEPA 2013 1 As indicated in Table 3-7, the NPDES permit for LSCS requires Exelon to monitor and sample 2 site effluents for various parameters in accordance with applicable effluent limits. Monitoring 3 results are reported in monthly Discharge Monitoring Reports (DMRs) submitted to the State. 4 The NRC staff reviewed the DMRs submitted by Exelon to the IEPA for the period 2010 through 5 2014. This review encompassed the results of recorded maximum cooling pond blowdown 6 temperatures to the Illinois River and associated calculations of river mixing zone temperatures 7 as reported in the DMRs for the past 5 years (2010 through 2014) and as compiled by Exelon 8 (Exelon 2015c). Based on the NRCs staff review and Exelons responses to the NRCs 9 requests for additional information, LSCS has received no notices of violation associated with 10 NPDES permitted discharges during the 2010 through 2014 time period. Nonetheless, Exelon 11 recorded several unusual occurrences in its DMR reports. These included reports of a makeup 12 pipeline line failure on January 29, 2010; a blowdown line failure on July 13, 2012; a makeup 13 pipeline line failure on January 25, 2013; a blowdown line air release valve failure on 3-44

Affected Environment 1 February 8, 2013; a makeup pipeline failure on May 21, 2013; and a makeup pipeline failure on 2 January 23, 2014 (Exelon 2015c). 3 The DMR submittals also document actions taken to comply with provisional variances granted 4 by the IEPA to Exelon with respect to LSCSs effluent discharges to the Illinois River and 5 associated river mixing zone temperature limits. Specifically, these variances 6 (IEPA-12-15, IEPA-12-24, and IEPA-12-24 extension) were sought and granted in 7 March, July, and August 2012, respectively, due to unusual weather conditions and associated 8 high ambient river water temperatures that impacted the ability for LSCS thermal discharges to 9 meet the requirements of Special Condition 3 of LSCSs NPDES permit. This limits the number 10 of temperature excursion hours to 1 percent (87.6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br />) of the hours in a 12-month period, 11 ending with any month (see footnote d in Table 3-7). During the variance period(s), Exelon was 12 required, in part, to continuously monitor both the discharge and receiving water temperatures 13 and visually inspect all discharge areas at least three times each day to assess the impact on 14 aquatic life. These thermal discharge excursions were not found to have any impact on aquatic 15 life (Exelon 2015c). 16 An applicant (in this case, Exelon) for a Federal license to conduct activities that may cause a 17 discharge of regulated pollutants into navigable waters of the United States is required by 18 Section 401 of the CWA to provide the licensing agency (in this case, the NRC) with water 19 quality certification from the state (in this case, the State of Illinois). This certification implies 20 that discharges from the project or facility to be licensed will comply with CWA requirements and 21 will not cause or contribute to a violation of state water quality standards. If the applicant has 22 not received Section 401 certification, the NRC cannot issue a renewed license unless that state 23 has waived the requirement. The NRC recognizes that some NPDES-delegated states explicitly 24 integrate their 401 certification process with NPDES permit issuance. However, LSCSs 25 NPDES permit does not explicitly convey water quality certification under CWA Section 401. 26 By letter dated February 4, 2014, Exelon submitted an application to the IEPA Bureau of Water 27 that requested certification from the IEPA that renewal of Exelons NRC operating licenses for 28 LSCS would not violate State water quality standards (Exelon 2014h). The IEPA Division of 29 Water Pollution Control issued a letter to the NRC, and copied Exelon, which provides 30 Section 401 water quality certification for renewal of the operating licenses for LSCS. The 31 certification was issued with the condition that Exelon shall be responsible for obtaining NPDES 32 permits required for wastewater or stormwater discharges to waters of the State (IEPA 2014c). 33 As previously stated in this section, NRC licensees must comply with the CWA, including 34 associated requirements imposed by EPA or the state, as part of the NPDES permitting system 35 under CWA Section 402. The NRC staff concludes that the IEPAs response provides the 36 necessary certification pursuant to CWA Section 401. 37 To maintain LSCSs surface water intake system on Marseilles Pool of the Illinois River, Exelon 38 conducts occasional maintenance dredging at the river screen house (Exelon 2014a). The 39 need for maintenance dredging at the river screen house forebay is periodically evaluated in 40 accordance with an Exelon operating procedure. Currently, needed dredging is conducted 41 under a USACE Section 10 permit, which is issued pursuant to the Rivers and Harbors 42 Appropriation Act of 1899 (33 U.S.C. 403) (USACE 2006). Dredging was most recently 43 conducted in October 2013 in compliance with the provisions of the permit. Less than 100 cubic 44 yards (76 m3) of sediment was removed, and the material was dewatered and placed out of the 45 floodplain near the screen house. Future maintenance dredging will be conducted as needed 46 and with the necessary permits. Exelon does not expect to perform any dredging in the vicinity 47 of the LSCS discharge channel during the license renewal term and does not anticipate the 48 need to conduct any fill activities (Exelon 2015c). 3-45

Affected Environment 1 3.5.2 Groundwater Resources 2 This section describes the current groundwater resources at the LSCS site and in the vicinity. 3 3.5.2.1 Site Description and Hydrogeology 4 The site is characterized by five hydrogeologic units. By increasing depth, they are as follows: 5

  • the Alluvial Aquifer, 6
  • the Glacial Drift Aquitard, 7
  • the Buried Bedrock Valley Aquifers, 8
  • the Pennsylvanian Aquitard, and 9
  • the Cambrian-Ordovician Aquifer System.

10 The hydrogeologic characteristics of these units are summarized in Figure 3-12. 11 Alluvial (stream) deposits are found beneath, and extend along each side of, the Illinois River. 12 These deposits form the Alluvial Aquifer that lays on top of the bedrock (the Pennsylvanian 13 Aquitard) (Figure 3-8). The river functions as a hydrologic boundary, which prevents 14 groundwater within the Alluvial Aquifer from flowing from one side of the river to the other. The 15 Alluvial Aquifer is generally 2 to 4 ft (0.6 to 1.2 m) thick, is located in the vicinity of the river 16 screen house, and ranges from 3,500 to 4,800 ft (1,067 to 1,463 m) in width. Yields in the 17 Alluvial Aquifer are restricted by the limited areal extent and thickness of the sand and gravel 18 deposits that make up the aquifer. Small dependable yields suitable for domestic purposes are 19 only locally available. The aquifer receives recharge primarily by precipitation and from the 20 river. Well yields from the Alluvial Aquifer in the vicinity of the river screen house are most likely 21 adequate only for domestic use (Exelon 2014a). 22 The Glacial Drift Aquitard is made up of the Richland Loess and the Wedron Silty-Clay Till 23 (see Section 3.4.1). The aquitard largely consists of silty-clay till (unsorted sediment containing 24 a range of grain sizes) with very low permeability. In the area of the plant buildings, the Glacial 25 Drift Aquitard is over 200 ft (61 m) thick (CRA 2006). Any extractable groundwater in this 26 aquitard is produced from thin discontinuous sand and gravel pockets that are recharged by the 27 slow infiltration of precipitation through the silty-clay till. The volume of groundwater produced 28 from these pockets is limited so that it is primarily used as a source of water for domestic or 29 farm activities (Exelon 2014a). 30 As discussed in Section 3.4.1, the site is located between two buried bedrock valleys that 31 contain alluvial deposits of sandy gravels and gravelly sands with lesser amounts of silt and clay 32 in scattered thin layers. These alluvial deposits are overlain and merge with the Wedron 33 Silty-Clay Till. They are recharged by the slow infiltration of precipitation through the thick 34 overlying Glacial Drift Aquitard. Therefore, the volume of groundwater that can be produced 35 from the Buried Bedrock Valley Aquifers is limited to supplying water for domestic or farm 36 activities (Exelon 2014a). 37 The Pennsylvanian Aquitard forms the bedrock. It consists of alternating beds of shale, 38 siltstone, underclay, sandstone, limestone, coal, and many gradational layers. Low permeability 39 shale and siltstone comprise more than 90 percent of the aquitard. In the area of the plant 40 buildings, the Pennsylvanian Aquitard is approximately 176 ft (54 m) thick. Groundwater in the 41 aquitard occurs under artesian conditions. Wells finished in the aquitard get water primarily 42 from thin sandstone and limestone beds within the aquitard, which are recharged by seepage 43 through the overlying shales and through the silty-clay till of the Glacial Drift Aquitard. In 44 general, the sandstone and limestone beds within the aquitard can only supply enough water for 3-46

Affected Environment 1 domestic or farm use because well yields are commonly less than 36 L/min (10 gpm) 2 (Exelon 2014a). 3 Figure 3-12. LSCS Site Hydrogeologic Units 4 Source: Modified from Exelon 2014a 3-47

Affected Environment 1 The Pennsylvanian Aquitard is underlain by the Cambrian-Ordovician Aquifer, which is an 2 important aquifer in the region. Beneath the site, this aquifer is composed of the following strata 3 (listed from shallowest to deepest): 4

  • Platteville Group, 5
  • GlenwoodSt. Peter Sandstone, 6
  • Potosi Dolomite, 7
  • Franconia Formation, 8
  • Ironton Sandstone, and 9
  • Galesville Sandstone.

10 At the site, the Cambrian-Ordovician Aquifer is approximately 1,090 ft (469 m) thick. Although 11 numerous alternating layers of sandstones, limestone, and dolomites impart a heterogeneous 12 character to the system, these units are hydraulically connected and behave as a single aquifer 13 (Exelon 2014a). The Cambrian-Ordovician Aquifer is the most important supplier of public 14 water in the region. 15 The Cambrian-Ordovician Aquifer is underlain by 450 ft (137 m) of the Eau Claire Formation 16 Aquitard, which is underlain by 2,500 ft (762 m) of the Mt. Simon Aquifer. The Mt. Simon 17 Aquifer is underlain by granitic and metamorphic rock. 18 In addition to the hydrogeologic units previously described, the plant area is directly underlain by 19 engineered granular fill that has been placed on top of the Wedron Silty-Clay Till. The 20 engineered granular fill underlies and surrounds the plant buildings and structures. It is 21 composed of sand and gravel and silty clay and contains groundwater that is recharged by local 22 precipitation. Because the underlying Wedron Silty-Clay Till has a very low permeability, 23 groundwater in the granular fill flows laterally eastward until it discharges into the intake canal, 24 or it flows laterally and discharges to the stormwater ponds and the discharge canal to the west 25 (CRA 2006) (Figures 3-12 and 3-13). 26 3.5.2.2 Groundwater Use 27 LaSalle County has an adequate supply of groundwater to meet current needs for industrial, 28 municipal, and domestic purposes. Regionally, the most abundant groundwater supplies are 29 obtained from the Cambrian-Ordovician Aquifer (LaSalle County 2014). 30 At the site, water for potable usage is obtained from two cased onsite wells completed into the 31 Cambrian-Ordovician Aquifer. These wells were installed in 1972 and 1974 in the area of the 32 plant buildings. They were drilled to a depth of 1,620 and 1,629 ft (494 and 496 m) and cased 33 to a depth of 921 and 989 ft (281 and 301 m) (Exelon 2014a, 2014f; ISGS 2015). Together the 34 two wells withdraw groundwater at an average rate of 26.1 gpm (98.7 L/min) (Exelon 2014a). 3-48

Affected Environment 1 Figure 3-13. LSCS Groundwater Flow in Engineered Granular Fill 2 Source: Modified from Exelon 2014a 3-49

Affected Environment 1 Figure 3-14. LSCS Hydrogeologic Cross-Section 2 (Elevation Exaggerated) 3 Source: Modified from CRA 2006 3-50

Affected Environment 1 Within 10 mi (16 km) of the LSCS site, almost all water used for public water supplies is 2 obtained from the Cambrian-Ordovician Aquifer. However, the Village of Ransom withdraws 3 water from both the Cambrian-Ordovician Aquifer and from permeable zones in the 4 Pennsylvanian Aquitard, and the Village of Grand Ridge obtains water from the Buried Bedrock 5 Valley Aquifers. People in small communities within 10 mi (16 km) of the LSCS site that are not 6 served by a public water supply system obtain water from individual wells in the glacial drift, the 7 Pennsylvanian strata, or the upper portion of the Cambrian-Ordovician Aquifer (Exelon 2014a). 8 3.5.2.3 Groundwater Quality 9 In general, the quality of groundwater in the Alluvial Aquifer, the Glacial Drift Aquitard, the 10 Buried Bedrock Valley Aquifers, the Pennsylvanian Aquitard, and the Cambrian-Ordovician 11 Aquifer is suitable for public use and consumption. A search of Illinois State Geological Survey 12 water well files identified six wells outside the site boundary but within 1 mi (1.6 km) of the plant 13 buildings. With the exception of one well completed in the Pennsylvanian Aquitard, all these 14 wells withdraw water from the Cambrian-Ordovician Aquifer (ISGS 2015). 15 In 1985, a condensate line broke in the area east-southeast of the LSCS reactor building. 16 Tritium was detected near the broken line in groundwater near the surface. The line was 17 repaired soon after it broke. In 1986, the highest tritium concentrations detected in the 18 groundwater was approximately 11,000 picocuries per liter (pCi/L). Tritium concentrations in the 19 groundwater near the broken line have declined to the point that, since 2007, tritium 20 concentrations in the groundwater have been below the lower limit of detection (Exelon 2014a; 21 Exelon Nuclear 2008, 2009, 2010, 2011, 2012, 2013, 2014, 2015). 22 In September 2001, a spill of water from a recycled condensate storage tank resulted in tritium 23 contamination into groundwater near the land surface. Tritium concentrations in the 24 groundwater ranged from 766 to 1,280 pCi/L in 2006 (Exelon 2014a; Exelon Nuclear 2007). 25 These concentrations are well below the EPA Maximum Contaminant Level for tritium of 26 20,000 pCi/L. In 2014, tritium concentrations in the groundwater had further decreased below 27 the lower limit of detection (Exelon Nuclear 2015). 28 Another leak from a recycled condensate tank was identified in 2010. The tank is located near 29 the plant buildings and is underlain by 10 ft (3 m) of engineered granular fill. In turn, the fill is 30 underlain by the Wedron Silty-Clay Till. Soon after the leak was detected, the tank was drained 31 and repaired. The leak contaminated groundwater in engineered granular fill with condensate 32 water that contained tritium. Contamination in the engineered granular fill is being addressed 33 through natural monitored attenuation and by active remediation. Exelon is pumping 34 contaminated groundwater from both a well and a French drain installed in the engineered 35 granular fill and then discharging the recovered water into the cooling pond where it is greatly 36 diluted to below the lower limit of detection (Exelon 2014a). Exelon has been monitoring the 37 cleanup of the engineered granular fill using monitor wells. In June 2015, samples from all of 38 the monitor wells recorded tritium concentrations below the EPA Maximum Contaminant Level 39 for tritium of 20,000 pCi/L (Exelon Nuclear 2010, 2011, 2012, 2013, 2014, 2015; Exelon 2015a, 40 2015c). Although the engineered granular fill has been contaminated with tritium and is being 41 cleaned up, it is not an aquifer. No aquifers are known to have been contaminated by 42 inadvertent releases of radionuclides to groundwater. 43 One nonradiological release to groundwater occurred in 1999 when an oil tank was discovered 44 to have leaked. The spill was remediated, and on February 9, 2005, IEPA issued a letter of No 45 Further Remediation for the cleanup activities (Exelon 2014a). 3-51

Affected Environment 1 3.6 Terrestrial Resources 2 3.6.1 LSCS Ecoregion 3 LSCS lies within the Illinois/Indiana Prairies Level IV Ecoregion. This ecoregion encompasses 4 19,557 mi2 (50,652 km2) in eastern and central Illinois and western Indiana (Woods et al. 2006). 5 It is composed of vast glaciated, flat to rolling plains with terminal and recessional moraines, 6 prairie potholes, and old lake beds. Historically, tallgrass prairie covered the majority of the land 7 surface. Oak-hickory forests were common on moraines and floodplains, and marshes and wet 8 prairies occurred in poorly drained areas. Beginning in the 19th century, agricultural land began 9 to replace the natural vegetation, and it is now the dominant land type (Woods et al. 2006). 10 Prairie remnants lack many natural ecosystem functions due to their small size, and areas of 11 prairie restoration often lack forbs (broad-leaved herbs other than grass) or are overly 12 dominated by big bluestem (Andropogon gerardii) (a grass) or Indiangrass (Sorghastrum 13 nutans) (IDNR 2005). Historically, forests were dominated by oak (Quercus spp.), hickory 14 (Carya spp.), elm (Ulmus spp.), ash (Fraxinus spp.), beech (Fagus spp.), and maple (Acer spp.) 15 species (CEC 2008). Remaining forests are highly fragmented and are experiencing species 16 composition shifts to sugar maple (A. saccharum) and other mesophytic species (IDNR 2005). 17 This shift is in part due to fire suppression, which has favored species that do not rely on 18 periodic fires as part of their life cycle (IDNR 2005). Many wetland areas have been drained for 19 row crops, and agriculture now accounts for over 75 percent of land use within this ecoregion 20 (IDNR 2005). 21 Table 3-8 lists representative wildlife for this ecoregion, as well as species that the Illinois 22 Department of Natural Resources (IDNR) considers to be critical to the conservation and 23 restoration of the regions native habitats; species that are indicative of ecosystem health 24 (known as indicator species); and species that are native to the region, but are now extirpated 25 or imperiled. 26 The IDNR maintains the Illinois Wildlife Action Plan (IDNR 2005), which addresses native 27 habitat and species decline and contains a statewide conservation plan. 28 Table 3-8. Wildlife in the Illinois/Indiana Prairies Level IV Ecoregion Wildlife representative of the ecoregion American black bear eastern bluebird North American porcupine (Ursus americanus) (Sialia sialis) (Erethizon dorsatum) American redstart eastern chipmunk raccoon (Setophaga ruticilla) (Tamias striatus) (Procyon lotor) bobcat eastern gray squirrel tree sparrow (Lynx rufus) (Sciurus carolinensis) (Passer montanus) Canada warbler gray fox white-footed mouse (Cardellina canadensis) (Urocyon cinereoargenteus) (Peromyscus leucopus) coyote indigo bunting white-tailed deer (Canis latrans) (Passerina cyanea) (Odocoileus virginianus) 3-52

Affected Environment Wildlife critical to the conservation and restoration of the ecoregions native habitats American badger Henslows sparrow northern harrier (Taxidea taxus) (Ammodramus henslowii) (Circus cyaneus) eastern massasauga(a) Illinois chorus frog ornate box turtle (Sistrurus catenatus) (Pseudacris streckeri illinoensis) (Terrapene ornata ornata) four-toed salamander Indiana bat(b) red squirrel (Hemidactylium scutatum) (Myotis sodalis) (Sciurus vulgaris) gray bat(a) Kirtlands snake short-eared owl (Myotis grisescens) (Clonophis kirtlandii) (Asio flammeus) Wildlife indicative of ecosystem health (indicator species) black rat snake eastern meadowlark prairie vole (Elaphe obsoleta obsoleta) (Sturnella magna) (Microtus ochrogaster) black-capped chickadee great blue heron red-headed woodpecker (Poecile atricapillus) (Ardea herodias) (Melanerpes erythrocephalus) eastern box turtle horned lark red-tailed hawk (Terrapene carolina carolina) (Eremophila alpestris) (Buteo jamaicensis) eastern kingbird prairie king snake tufted titmouse (Tyrannus tyrannus) (Lampropeltis calligaster (Baeolophus bicolor) calligaster) Extirpated or imperiled wildlife American bison Blandings turtle Franklins ground-squirrel (Bison bison) (Emys blandingii) (Poliocitellus franklinii) (a) The eastern massasauga is a candidate for listing under the Endangered Species Act of 1973, as amended (ESA), and the gray bat is listed as endangered under the ESA. While these species occur within the Illinois/Indiana Prairies Level IV Ecoregion, the FWS (2015d) indicates that they do not occur within the area that would be affected by the proposed LSCS license renewal. (b) The Indiana bat is Federally listed as endangered under the ESA and is discussed in detail in Section 3.8. Sources: CEC 1997; IDNR 2005; WIken et al. 2011 1 3.6.2 LSCS Site Surveys, Studies, and Reports 2 A number of vegetation and wildlife surveys have been conducted on the LSCS site beginning 3 with baseline surveys prior to LSCS construction in the early 1970s. This section summarizes 4 these surveys in chronological order. 5 Baseline Terrestrial Surveys (1971-1972) 6 In July and December 1971, and April, July, and October 1972, baseline ecological studies were 7 conducted at the LSCS site. The 1971 studies were primarily qualitative, and the 1972 studies 8 gathered quantitative data on vegetation, mammals, birds, reptiles, and invertebrates present on 9 the LSCS site. The ER for operation of LSCS (ComEd 1977) describes these studies and the 10 associated results in detail. 11 Final Environmental Statement for Construction (1973) 12 In February 1973, the U.S. Atomic Energy Commission (AEC), the NRCs predecessor agency, 13 issued a Final Environmental Statement that evaluated the construction of LSCS (FES-C) 14 (AEC 1973). Although no specific studies were conducted to support the preparation of the 3-53

Affected Environment 1 FESC, the report briefly summarizes the terrestrial wildlife and habitats on the site, including 2 those that were altered or destroyed during the construction of the cooling pond. 3 Terrestrial Monitoring during LSCS Construction (1974-1978) 4 Following the commencement of LSCS construction, ComEd commissioned NALCO 5 Environmental Sciences to conduct a 5-year monitoring program to evaluate the effects of 6 temporary and permanent ecological disturbances related to construction from 1974 7 through 1978. The ER for operation of LSCS (ComEd 1977) describes the results of the first 8 2 years of this monitoring. 9 Final Environmental Statement for Operation (1978) 10 In November 1978, the NRC issued a Final Environmental Statement that evaluated the 11 operation of LSCS (FES-O) (NRC 1978). The report includes updates to the terrestrial habitat 12 and wildlife information presented in the FES-C based on the 5 years of terrestrial monitoring 13 conducted during LSCS construction. 14 Wildlife Habitat Council Vegetation and Wildlife Surveys (2007) 15 In September 2007, Wildlife Habitat Council (WHC) biologists performed a baseline habitat 16 survey for the Wildlife at Work program. The survey results are documented in the LSCS 17 Wildlife Management Plan (Exelon 2013b). 18 LSCS Wildlife Habitat Team Monitoring (Ongoing) 19 The LSCS Wildlife Habitat Team conducts periodic wildlife surveys of the site in the spring 20 (April), summer (July), and fall (September) to monitor changes in wildlife communities and to 21 document any new species found on the site. Results of periodic surveys are collected in 22 Exelons Wildlife Management Plan (Exelon 2013b). 23 3.6.3 LSCS Site 24 The LSCS site encompasses approximately 1,528 ha (3,776 ac) in Marseilles, LaSalle County, 25 Illinois. The cooling pond, generating facilities and associated infrastructure, and LaSalle Fish 26 Hatchery occupy the majority (66 percent) of the site. The remaining areas are undeveloped 27 and include the following terrestrial communities: forest, shrub-scrub, grassland, old-field, and 28 wetlands. 29 A cooling pond occupies the western side of the site and accounts for about half of the site area. 30 The generating facilities and associated infrastructure (roads, parking lots, warehouses, 31 switchyards) lie west of the cooling pond and occupy approximately 65 ha (160 ac) 32 (Exelon 2015p). This industrial area is surrounded by about 142 ha (350 ac) of undeveloped 33 natural areas, including grassland, old field, schub-scrub, and small forested fragments 34 (Exelon 2015p). 35 3.6.3.1 Vegetation 36 Because the majority of the LSCS site is developed or occupied by the cooling pond, only small 37 areas of terrestrial habitat occur on the site. An open grassy area lies between the cooling pond 38 and the sites industrial area. This area is bounded on the north by the discharge canal and on 39 the south by the property boundary. Another grassy area lies to the southwest of the industrial 40 area. These two areas have a few scattered trees (Exelon 2014a). 41 The makeup and blowdown pipeline corridor extends north from the cooling pond to the Illinois 42 River and supports upland habitats, including shrub-scrub, forest, grassland, and old-fields, and 43 scattered wetlands. Common tree species in the upland forest areas, which comprise the 3-54

Affected Environment 1 majority of the corridor, include white oak (Quercus alba), red oak (Q. rubra), shagbark hickory 2 (Carya ovata), sugar maple, hop hornbeam (Ostrya virginiana), hawthorn (Crataegus spp.), 3 black cherry (Prunus serotina), and American elm (Ulmus americana) (Exelon 2014a). The 4 corridor widens as it approaches the Illinois River where it contains several small freshwater 5 emergent and freshwater forested/scrub wetlands. These wetlands are discussed in 6 Section 3.6.5.2. 7 3.6.3.2 Wildlife 8 Mammals 9 During the baseline terrestrial surveys in 1971 and 1972, 29 species of mammals were recorded 10 on the LSCS site. The most commonly observed mammals included raccoon (Procyon lotor), 11 mink (Mustela vison), red fox (Vulpes fulva), gray fox (Urocyon cinereoargenteus), gray squirrel 12 (Sciurus carolinensis), fox squirrel (Sciurus niger), beaver (Castor canadensis), muskrat 13 (Ondatra zibethicus), eastern cottontail (Sylvilagus floridanus), and white-tailed deer 14 (ComEd 1977). During the 2007 WHC baseline inventory of the LSCS site, coyote (Canis 15 latrans), beaver, opossum (Didelphis virginiana), groundhog (Marmota monax), striped skunk 16 (Mephitis mephitis), white-tailed deer, and gray squirrel were observed on the site (Exelon 17 2013b). 18 Birds 19 During the baseline terrestrial surveys in 1971 and 1972, 129 species of birds were recorded on 20 or near the LSCS site. Of these, 41 are considered permanent residents, 45 are summer 21 residents, 13 are winter residents, and 21 are transients (ComEd 1977). Permanent residents 22 included mallard (Anas platyrhynchos), black duck (A. rubripes), red-tailed hawk (Buteo 23 jamaicensis), red-shouldered hawk (Buteo lineatus), bald eagle (Haliaeetus leucocephalus), 24 bobwhite (Colinus virginianus), ring-necked pheasant (Phasianus colchicus), killdeer 25 (Charadrius vociferus), rock dove (Columba livia), mourning dove (Zenaida macroura), great 26 horned owl (Bubo virginianus), short-eared owl (Asio flammeus), saw-whet owl (Aegolius 27 acadicus), northern flicker (Colaptes auratus), red-bellied woodpecker (Melanerpes carolinus), 28 red-headed woodpecker (M. erythrocephalus), horned lark (Eremophila alpestris), blue jay 29 (Cyanocitta cristata), American crow (Corvus brachyrhynchos), black-capped chickadee 30 (Poecile atricapillus), northern mockingbird (Mimus polyglottos), eastern bluebird (Sialia sialis), 31 cedar waxwing (Bombycilla cedrorum), loggerhead shrike (Lanius ludovicianus), starling 32 (Sturnus vulgaris), and house sparrow (Passer domesticus) (ComEd 1977). During the 2007 33 WHC baseline inventory of the LSCS site, 15 species of birds were observed, all of which had 34 been previously recorded as occurring on the site during baseline surveys (Exelon 2013b). 35 Reptiles and Amphibians 36 No reptiles or amphibians were collected on the LSCS site in the 1971 baseline surveys 37 (ComEd 1977). In 1972, two Eastern plains garter snakes (Thamnophis radix radix) were 38 observed in pastureland near an intermittent stream (ComEd 1977). The 2007 WHC baseline 39 inventory did not include reptiles or amphibians. 40 3.6.4 LSCS Wildlife Management Plan 41 The LSCS Wildlife Management Plan (Exelon 2013b) outlines the goals and projects of LSCSs 42 Wildlife at Work program. Some of the plans past and planned wildlife habitat enhancement 43 and conservation activities at the LSCS site include: 44

  • planting native vegetation, including swamp white oak (Quercus bicolor) near the 45 cooling pond, 3-55

Affected Environment 1

  • controlling invasive common reed (Phragmites australis) near the cooling pond, 2
  • enhancing existing habitat for grassland nesting birds through seeding, mowing, and 3 controlled burns, 4
  • maintaining nesting boxes for eastern bluebirds, and 5
  • installing osprey (Pandion haliaetus) platforms near the cooling pond 6 (Exelon 2014a).

7 Exelon (2015n), as a corporation, has been a member of the WHC since 2005, and Exelon first 8 received WHC certification for its Wildlife at Work program at LSCS in November 2011. 9 3.6.5 Important Species and Habitats 10 3.6.5.1 Important Species 11 State-Listed Species 12 The Illinois Endangered Species Protection Act of 1972, as amended, makes illegal the transfer, 13 sale, and possession of species (including skins and products) listed by the State as 14 endangered or threatened. The Act establishes an Endangered Species Protection Board, 15 which maintains a list of endangered and threatened species and advises the IDNR on the 16 conservation of those species. 17 Within LaSalle County, the IDNRs (2014b) Natural Heritage Database indicates that 18 28 State-listed terrestrial species (19 plants, 3 birds, 2 reptiles, 2 mammals, 1 insect, and 19 1 amphibian) occur in the county (see Table 3-9). In September 2013, Exelon generated an 20 IDNR Ecological Compliance Assessment Tool (EcoCAT) report that used Illinois Natural 21 Heritage Database information to further refine the list of State-listed species that could occur 22 on the LaSalle site and that could potentially be affected by the proposed license renewal. The 23 EcoCAT report is included in Appendix C of the applicants ER (Exelon 2014a). The report 24 indicates that there are no terrestrial State-listed species on or near the LSCS site that may be 25 affected by the proposed license renewal. In a May 2014 letter to Exelon, the IDNR (2014c) 26 confirmed that the EcoCAT report was accurate, and in its letter, the IDNR mentioned no 27 records of State-listed terrestrial species on or near the site. Federally protected species are 28 discussed in Section 3.8. 29 Table 3-9. State-Listed Species in LaSalle County Common Name Species Name Status(a) Amphibians four-toed salamander Hemidactylium scutatum ST Birds cerulean warbler Dendroica cerulea ST loggerhead shrike Lanius ludovicianus SE upland sandpiper Bartramia longicauda SE Insects regal fritillary Speyeria idalia ST 3-56

Affected Environment Common Name Species Name Status(a) Mammals gray bat(b) Myotis grisescens SE Indiana bat(b) Myotis sodalis SE Plants American brooklime Veronica americana SE bunchberry Cornus canadensis SE cliff goldenrod Solidago sciaphila ST decurrent false aster(b) Boltonia decurrens ST fibrous-rooted sedge Carex communis ST forked aster Aster furcatus ST golden corydalis Corydalis aurea SE hairy woodrush Luzula acuminata SE hemlock panic grass Dichanthelium portoricense SE long beech fern Phegopteris connectilis SE pink corydalis Corydalis sempervirens SE plantain-leaved sedge Carex plantaginea SE queen-of-the-prairie Filipendula rubra SE red pine Pinus resinosa SE red-berried elder Sambucus racemosa ssp. pubens SE shadbush Amelanchier sanguinea SE snowberry Symphoricarpos albus var. albus SE spike Elliptio dilatata ST weak bluegrass Poa languida SE Reptiles blanding's turtle Emydoidea blandingii SE timber rattlesnake Crotalus horridus ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) These species are also Federally listed under the Endangered Species Act of 1973, as amended (ESA) and are discussed in detail in Section 3.8. Source: IDNR 2014b 1 Although not listed as occurring in LaSalle County by the IDNR, Exelon (2014a) reports that it 2 has observed the State-threatened peregrine falcon (Falco peregrinus) on the LSCS site. A pair 3 of peregrine falcons nested on the roof of the auxiliary building several years ago. Exelon 4 (2014a) personnel have not observed peregrine falcon nesting in recent years, but personnel 3-57

Affected Environment 1 occasionally observe peregrines in flight on the site. The FES-O (NRC 1978) notes the 2 observance of a single peregrine falcon in November 1972 in an offsite woodland. 3 Bald Eagles 4 The bald eagle is protected under the Bald and Golden Eagle Protection Act (16 USC 668 5 et seq.). This Federal act prohibits anyone from taking or disturbing bald eagles or golden 6 eagles (Aquila chrysaetos), including their nests or eggs, without a U.S. Fish and Wildlife 7 Service (FWS)-issued permit. The bald eagle was observed near the LSCS site in April 1972, 8 on the rivers north-facing bluffs (ComEd 1977; NRC 1978). However, Exelon (2014a) is not 9 aware of bald eagle observations at the site in recent years. 10 3.6.5.2 Important Habitats 11 Illinois Natural Areas Inventory Sites 12 In its Illinois Natural Areas Inventory (INAI), the IDNR (2014a) identifies 28 LaSalle County sites 13 as Category I (high quality natural community and natural community restorations), Category II 14 (specific suitable habitat for state-listed species or state-listed species relocations), 15 Category III (State-dedicated Nature Preserves, Land and Water Reserves, & Natural Heritage 16 Landmarks), or a combination of the three categories. The 2013 EcoCAT report (contained in 17 Appendix D of the applicants ER (Exelon 2014a)) indicates that one of these sites with 18 terrestrial habitat lies near the LSCS site: Marseilles Hill Prairie. 19 The Marseilles Hill Prairie (INAI Site No. 1520) lies 3 mi (4.8 km) north of the LSCS main site 20 boundary (Exelon 2015o). It is 39.71 ac (16.07 ha) in size and managed by the IDNR (2014a) 21 to conserve prairie habitat. The IDNR (2014a) designates this INAI site as Category I. 22 State Parks and Wildlife Areas 23 The IDNR manages three areas for State parks or wildlife areas within 10 km (6 mi) of LSCS: 24 LaSalle Lake State Fish & Wildlife Area, Marseilles State Fish & Wildlife Area, and Illini State 25 Park. The LaSalle Lake State Fish & Wildlife Area comprises the portion of the LSCS cooling 26 pond that is managed by the IDNR and open to the public for fishing and other recreational 27 purposes (Exelon 2014a). The Marseilles State Fish & Wildlife Area is open to seasonal 28 hunting of turkey (Meleagris gallopavo), pheasant, quail, dove, deer, rabbit, squirrel, and coyote 29 (IDNR 2015e). Illini State Park provides habitat for a number deciduous trees, including hickory, 30 ash (Fraxinus spp.), walnut (Juglans spp.), elm, cottonwood (Populus deltoids), oak, and maple, 31 as well as white-tailed deer, eastern gray squirrels, opossums, beavers, raccoon, groundhogs, 32 and a variety of waterfowl and songbirds (IDNR 2015b). 33 Wetlands 34 The National Wetlands Inventory Wetlands Mapper identifies eight small areas of freshwater 35 emergent wetland and freshwater forested/scrub wetland on the LSCS site near the Illinois 36 River that total about 10 ac (4 ha) (FWS 2015e). Common tree species in the freshwater 37 forested/scrub wetland include American elm, black cherry, white oak, red oak, black oak, 38 shagbark hickory, bitternut hickory (Carya cordiformis), hackberry (Celtis occidentalis), elm, 39 willow (Salix spp.), and sycamore (Platanus occidentalis) (Exelon 2014a). The freshwater 40 emergent wetlands contain cattail (Typha spp.), horsetail (Equisetum spp.), and other 41 herbaceous vegetation (Exelon 2014a). 42 Managed Prairie Habitat 43 In partnership with Pheasants Forever, Inc., Exelon (2014a) actively manages 4 ha (10 ac) of 44 native prairie to the west of the cooling pond. 3-58

Affected Environment 1 3.6.6 Invasive and Non-Native Species 2 The invasive common reed inhabits parts of the cooling pond, particularly along the ponds 3 western edge. In 2007, as part of its Wildlife at Work program, Exelon (2014a) began an effort 4 to eradicate the species through mechanical harvesting and application of aquatic-safe 5 herbicides. 6 3.7 Aquatic Resources 7 The aquatic communities of interest for the LSCS site occur in the Illinois River and in the sites 8 artificial cooling pond. The Illinois River lies 5 mi (8 km) north of the site. It supplies makeup 9 water to LSCSs cooling system and receives cooling system blowdown. The cooling pond is 10 the sites main source of cooling water and is the plants UHS. Section 3.1.3 describes the 11 cooling system in detail, and Section 3.5.1 describes the surface water characteristics of the 12 Illinois River and the cooling pond. 13 The sections below describe the two main aquatic ecosystems at the LSCS site, the Illinois 14 River and the LSCS cooling pond (see Sections 3.7.1 and 3.7.2, respectively). In addition, 15 Section 3.7.3 describes State-listed species and important habitats and Section 3.7.4 describes 16 non-native species. 17 3.7.1 Illinois River 18 The Illinois River begins southwest of Chicago, at the confluence of the Des Plaines and 19 Kankakee Rivers. It flows south until it reaches the Mississippi River north of St. Louis, 20 Missouri. The total length of the Illinois River is approximately 322 mi (518 km) (IDNR 2011a). 21 The Illinois Rivers watershed drains a total of 29,010 mi2 (75,136 km2) from Illinois, Wisconsin, 22 and Indiana (IDNR 2011a). Major tributaries include the Des Plaines, Fox, Kankakee, 23 Vermilion, Mackinaw, Sangamon, Spoon, and La Moine rivers. 24 Prior to the 1800s, the Illinois River Basin was comprised of prairie savannas and oak-hickory 25 forests. The river provided diverse aquatic habitats including backwater lakes, side channels, 26 and a narrow main channel (USGS 1999a). The rapid expansion of agricultural activities 27 throughout the 1800s and early 1900s converted wet and mesic (relatively well drained) 28 floodplain prairies to crop lands. This land use conversion resulted in increased erosion, 29 sediment loading, and nutrient and herbicide transport to the Illinois River. Beginning in the 30 1900s, several efforts occurred to divert water from Lake Michigan and construct navigation 31 dams or levees to increase the navigability of the Illinois River to the Mississippi River and 32 provide a navigable passage from Chicago (Lake Michigan) to the Gulf of Mexico (USGS 33 1999a). As the population in Chicago continued to grow, sewage disposal and toxic waste 34 disposal further contributed to the degradation of aquatic habitat in the Illinois River (Parker 35 2014). By the 1960s, the biodiversity of fish within the upper Illinois River was low and 36 freshwater mussels were nearly absent (Sietman et al. 2001). Pollution tolerant, non-native 37 common carp (Cyprinus carpio) and goldfish (Carassius auratus) dominated fish populations 38 (Parker 2014). Since the passage of the CWA in 1974, water quality within the Illinois River has 39 improved and more diverse fish assemblages inhabit the upper Illinois River (Parker 2014). 40 Similarly, freshwater mussels have recolonized portions of the upper Illinois River since the 41 1980s (Sietman et al. 2001). 42 Currently, a series of locks and dams along the Illinois River continue to limit habitat connectivity 43 and fish passage along the Illinois River. Four of the locks and dams (Thomas J. OBrien, 44 Lockport, Brandon Road, and Dresden Island) are upstream of LSCS and four (Marseilles, 45 Starved Rock, Peoria, and LaGrange) are downstream (USACE 1998). The closest locks and 3-59

Affected Environment 1 dams to LSCS include the Dresden Island Lock and Dam, 22 mi (26 km) upstream of the LSCS 2 intake, and the Marseilles Lock and Dam, 2.4 mi (3.5 km) downstream of the LSCS discharge 3 (USACE 1998; Exelon 2015c). 4 In 2005, IEPA most recently classified the water quality within the Illinois River as fair, which 5 means that the water quality has been impaired, and the water body meets the needs of a 6 designated use most of the time (IDNR 2011a). Current factors that continue to contribute to 7 the degradation of the Illinois River include the increase in invasive fish, accumulated 8 sediments, continued sedimentation, and agricultural chemical runoff (USGS 1999a; 9 Parker et al. 2005). 10 3.7.1.1 Aquatic Communities in the Illinois River 11 Plankton 12 Plankton are small organisms that float or drift in rivers and other water bodies. Plankton is a 13 primary food source for many whales, fish, and other animals, and consists of bacteria, 14 protozoans, certain algae, tiny crustaceans such as copepods, and many other organisms. 15 ComEd, the previous owner of LSCS, conducted surveys for plankton within the Illinois River 16 both upstream and downstream of the LSCS discharge and river intake structures. ComEd 17 initially sampled plankton prior to operations, from August 1972 through January 1973, and 18 again during construction, from February 1974 through November 1976. These studies are 19 summarized in the Final Environmental Statement for Operations of LSCS (NRC 1978). 20 Phytoplankton. Phytoplankton are microscopic floating photosynthetic organisms that form 21 one base of aquatic food webs by producing biomass from inorganic compounds and sunlight. 22 As primary producers, phytoplankton play key ecosystem roles in the distribution, transfer, and 23 recycling of nutrients and minerals. 24 Diatoms were the most abundant phytoplankton in the Illinois River near LSCS in the 1970s, 25 and reached peak densities in August (NRC 1978). The most common diatom genera included 26 Cyclotella, Melosira, and Stephanodiscus. The NRC staff noted that many of the diatoms 27 collected in preoperational studies were pollution tolerant (NRC 1978). Other phytoplankton 28 followed similar trends with primary production peaking in August and dipping in winter months. 29 The NRC staff is not aware of any additional phytoplankton surveys that have been conducted 30 in the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2. 31 Periphyton. Periphyton includes a mixture of algae, cyanobacteria (in the past often called 32 blue-green algae), heterotrophic microbes, other small organisms, and detritus that attach to 33 submerged surfaces. Like phytoplankton, periphyton are primary producers and provide a 34 source of nutrients to many bottom-feeding organisms. 35 During ComEds initial study prior to construction, diatom densities upstream of the LSCS 36 discharge and intake areas accounted for 75 percent of the total periphyton density in 37 August 1972 and 100 percent in January 1973. The next dominant taxa was green algae, which 38 accounted for 7 percent of the total periphyton density in 1972 and none of the total periphyton 39 density in 1973. Downstream of the LSCS discharge and intake, diatom densities accounted for 40 94 percent of the total periphyton density in August 1972 and 92 percent in January 1973, while 41 the green algae accounted for 1 percent in 1972 and none in 1973 (NRC 1978). Diatoms were 42 the dominant periphyton group during the warmer months (May, August, and November), 43 whereas green algae was dominant during February from 1974 to 1976 (NRC 1978). Dominant 44 diatom genera included Cyclotella, Navicula, and Nitzschia; dominant green algae genera 45 included Stigeoclonium, Cladophora, Rhizoclonium, and Ulothrix (NRC 1978). 3-60

Affected Environment 1 The NRC staff is not aware of any additional periphyton surveys that have been conducted in 2 the vicinity of LSCS since the plant began operating in 1982 for Unit 1 and 1984 for Unit 2. 3 Zooplankton. Zooplankton are small animals that float, drift, or weakly swim in the water column 4 and include ichthyoplankton (fish eggs and larvae) with no or limited swimming ability and larvae 5 of benthic invertebrates. Zooplankton are important trophic links between primary producers 6 (e.g., phytoplankton and periphyton) and carnivores (e.g., fish). 7 During preoperational studies, copepods and rotifers dominated zooplankton samples both prior 8 to and during construction (NRC 1978). Dominant copepod genera included Cyclops and 9 Eucyclops, and dominant rotifer genera included Asplanchna, Brachionus, Filinia, Notholca, 10 Polyarthra, and Synchaeta (NRC 1978). Peak densities for both copepods and rotifers 11 generally occurred in August, and minimum densities generally occurred in February. 12 In 2014, EA Engineering, Science, and Technology, Inc. (EA) (2015) collected icthyoplankton 13 samples in front of the LSCS river intake as part of an entrainment study. EA (2015) collected 14 samples using 0.5-m (1.6-ft) conical plankton nets with 505-µm mesh suspended from the 15 forebay bridge in front of the river intake (see Figure 3-15). EA (2015) collected samples during 16 the 2014 spawning season, from late April through August, when icthyoplankton densities would 17 likely be highest. 3-61

Affected Environment 1 Figure 3-15. Icthyoplankton Sampling Location at the LSCS River Intake Structure 2 Key: LSCS: LaSalle County Station; RSH: River Screen House 3 Source: EA (2015) 4 EA (2015) collected a total of 7,114 ichthyoplankton specimens representing 12 families and 5 27 distinct taxa. The most common taxa included carps, minnows, and suckers, which 6 combined comprised 79 percent of the number of organisms within ichthyoplankton sample. 7 EA (2015) classified icthyoplankton by species or taxa, if identification to the species level was 8 not practicable, and by life stage, including egg, yolk-sac, post yolk-sac, larvae, and juveniles. 9 The most common taxa by life stage included Ictiobinae (buffalo fish) yolk-sac larvae 10 (24 percent), cyprinidae (carps and minnows) yolk-sac larvae (23 percent), and common carp 11 yolk-sac larvae (13 percent). All other taxa-life stage categories comprised less than 10 percent 12 of the icthyoplankton samples (EA 2015). 13 Benthic Macroinvertebrates 14 Benthic macroinvertebrates include aquatic annelids (e.g., aquatic worms or oligochaetes, 15 leeches), mollusks, crustaceans, and insect larvae that inhabit aquatic sediments and 16 submerged surfaces. They accelerate detrital decomposition and nutrient cycling, and serve as 3-62

Affected Environment 1 a food source for fish and other aquatic biota. ComEd, Exelon, and their contractors sampled 2 benthic invertebrates during three time periods: preoperational studies from February through 3 November, 1972 through 1976 (as summarized in NRC 1978); a 1999 study in response to low 4 flow and high air temperatures (EA 2000); and a 2013 study in preparation for Exelons license 5 renewal application (EA 2014). 6 During the preoperational and the 2013 study, ComEd and Exelon sampled benthic 7 macroinvertebrates at one location upstream of the river intake and blowdown discharge 8 (location 1), at one location immediately downstream of the blowdown discharge (location 2), 9 and at two locations further downstream of the blowdown discharge (locations 3 and 4) (Figure 10 3-16). ComEd and Exelon sampled each location with a Hester-Dendy artificial substrate 11 sampler and a Ponar grab sampler (NRC 1978; EA 2014). 12 In 1999, Exelon also collected benthos using a Ponar grab at one site upstream and one site 13 downstream of the blowdown discharge, similar to the sampling sites for the preoperational and 14 2013 study. In addition, EA collected benthos using a Ponar grab at a second downstream site 15 that was further downstream than South Kickapoo Creek (EA 2000). 16 Figure 3-16. Sampling Locations in LSCS Aquatic Surveys 17 Source: EA 2014 18 Collections during preoperational studies resulted in the identification of 143 taxa (NRC 1978). 19 Chironomidae and Oligochaeta were the most dominant groups. The most common 20 oligochaete genera were Limnodrilus and Nais. The most abundant chironomid genera 21 included Cryptochironomous, Dicrotendipes, Procladius, Cricotopus, and Orthocladius. 22 EA (2000) collected a total of 34 taxa from Ponar grab samples. Chironomidae and Oligochaeta 23 were the most taxa-rich groups, with 12 taxa each. EA (2000) determined that the dominant 24 taxa at all sampling sites are considered tolerant to poor water quality. Both total richness and 25 the number of Ephemeroptera, Plecoptera, and Trichoptera species, which are considered 26 intolerant of environmental stress, were slightly higher downstream (locations 2 and 4) 27 compared to upstream (location 1) of the intake and discharge structures. 3-63

Affected Environment 1 EA (2014) collected a total of 61 taxa from the Hester-Dendy artificial substrate collections. 2 Chironomidae was the most taxa rich group with 21 taxa followed by Ephemeroptera and Bivalvia, 3 with 8 taxa each. The dominant taxa from the Hester-Dendy collections included the following 4 insect larvae: Dicrotendipes modestus (a non-biting midge), Maccaffertium integrum (a mayfly), 5 Cyrnellus fraternus (a caddisfly), and Dicrotendipes neomodestus. Among the 10 most dominant 6 taxa for the Hester-Dendy artificial substrate samples, only one taxon is considered tolerant of 7 environmental degradation, Glyptotendipes (IEPA 1987; EA 2014). The remaining taxa are 8 considered facultative to slightly intolerant to poor water quality (IEPA 1987; EA 2014). 9 For the Ponar grab samples, Chironomidae was the most taxa rich group with 15 taxa, followed 10 by 8 Bivalvia and 4 Ephemeroptera taxa. EA (2014) observed the highest taxa richness at 11 locations 1 and 3 (20 to 29 taxa) as compared to locations 2 and 4 (16 to 27 taxa). Species 12 richness among pollution sensitive Ephemeroptera, Plecoptera, and Trichoptera was similar 13 among all locations, ranging from three to five taxa (EA 2014). At all sampling sites, EA (2014) 14 observed dominant taxa that were relatively tolerant to poor water quality as well as dominant 15 taxa that were relatively intolerant or facultative to poor water quality. 16 Fish 17 ComEd, Exelon, and their contractors sampled fish near LSCS during three time periods: 18 preoperational studies from May through November, 1972 through 1976 (as summarized in 19 NRC 1978); a post-operational study in response to low flow and high air temperatures in July 20 through October, 1999 (EA 2000); and a post-operational study in August 2013 in preparation 21 for Exelons license renewal application (EA 2014). 22 During both the preoperational and 2013 study, Exelon sampled fish at one location upstream of 23 the river intake and blowdown discharge (location 1) and at two locations downstream of the 24 blowdown discharge (locations 2 and 5), one of which was South Kickapoo Creek 25 (Figure 3-16). Exelon sampled fish at each sampling site by electrofishing in a downstream 26 direction for 500 m (1,640 ft). In addition, Exelon seined for fish along the shoreline at all three 27 locations using a 25-ft (8-m) long by 6-ft (2-m) deep seine with 0.19- in. (0.48-cm) mesh. 28 Exelon hauled the seine along 15 m (49 ft) of shoreline in a downstream direction. 29 In 1999, EA also electrofished at one site upstream and one site downstream of the blowdown 30 discharge, similar to the sampling sites for the preoperational and 2013 study. In addition, EA 31 electrofished at second downstream site that was further downstream than South Kickapoo 32 Creek (EA 2000). 33 All three studies looked for external parasites or other abnormalities. EA (2000 and 2014) 34 specifically examined all fish for external DELT (deformities, erosions, lesions, or tumors) 35 anomalies. 36 During the preoperational monitoring period, NRC (1978) determined that the most dominant 37 species included emerald shiner (Notropis atherinoides), gizzard shad (Dorosoma cepedianum), 38 common carp, green sunfish (Lepomis cyanellus), bluntnose minnow (Pimephales notatus), and 39 white sucker (Catostomus commersonii) (see Table 3-10). Prior to operations, downstream 40 collection stations generally had lower species abundance and higher species diversity than 41 upstream stations (NRC 1978). The NRC (1978) concluded that the low species abundance 42 and diversity, low condition factors, and the degree of external parasitism and physical damage 43 of the fishes in this area of the Illinois River were indicative of a poor quality aquatic 44 environment. Barge traffic, habitat alteration, and heavy pollution loads contributed significantly 45 to the poor water quality in the Illinois River near LSCS, which primarily supported populations 46 of pollution-tolerant fish in the 1970s (NRC 1978). 3-64

Affected Environment 1 During the 1999 survey, EA (2000) collected 27 species and 1 hybrid for a total of 960 fish. The 2 most commonly collected fish species included gizzard shad (24 percent), smallmouth buffalo 3 (Ictiobus bubalus) (12 percent), spotfin shiner (Cyprinella spiloptera) (10 percent), green sunfish 4 (9 percent) and bluegill (Lepomis macrochirus) (8 percent) (Table 3-10). EA (2000) observed a 5 total of 63 fish (6.6 percent of the catch) with DELT anomalies. Channel catfish (Ictalurus 6 punctatus), freshwater drum (Aplodinotus grunniens), and common carp exhibited the highest 7 DELT affliction rates (greater than 20 percent). The most common DELT anomalies included fin 8 erosion (52 percent) and deformities (38 percent). 9 During the 2013 study, EA (2014) collected 12 fish species for a total of 1,295 fish. The most 10 commonly collected species during electrofishing included gizzard shad (48 percent), spotfin 11 shiner (16.5 percent), smallmouth buffalo (6 percent), golden redhorse (Moxostoma erythrurum) 12 (5 percent), smallmouth bass (Micropterus dolomieu) (4 percent), and freshwater drum 13 (4 percent; EA 2014) (Table 3-10). Gizzard shad dominated samples both upstream and 14 downstream of the intake and discharge (EA 2014). The most commonly collected species 15 during seining surveys included emerald shiner (83 percent), spotfin shiner (9.5 percent), 16 bluntnose minnow (2 percent), and sand shiner (Notropis stramineus) (2 percent) (EA 2014) 17 (Table 3-10). Emerald shiner dominated samples both upstream and downstream of the intake 18 and discharge (EA 2014). EA (2014) observed DELT anomalies on 2 of the 1,295 fish collected 19 (0.2 percent), both of which were eroded fins on freshwater drum. EA (2014) did not observe 20 any external parasites or other abnormalities. 21 Table 3-10. Common Fish Species in LSCS Aquatic Surveys on the Illinois River Commonly Collected Species(d) Species Common Name 1974-1976(a) 1999(b) 2013(c) Cyprinidae Cyprinella spiloptera spotfin (spottail) shiner X X X Cyprinus carpio common carp X Notropis atherinoides emerald shiner X X X Notropis stramineus sand shiner X Pimephales notatus bluntnose minnow X X Pimephales vigilax bullhead minnow X X Centrarchidae Lepomis cyanellus green sunfish X X Lepomis macrochirus bluegill X Catostomidae Catostomus commersoni white sucker X Ictiobus bubalus smallmouth buffalo X X Micropterus dolomieu smallmouth bass X Moxostoma erythrurum golden redhorse X Atherinopsidae Labidesthes sicculus brook silverside X Clupeidae Dorosoma cepedianum gizzard shad X X X 3-65

Affected Environment Commonly Collected Species(d) Species Common Name 1974-1976(a) 1999(b) 2013(c) Sciaenidae Aplodinotus grunniens freshwater drum X (a) NRC 1978 (b) EA 2000 (c) EA 2014 (d) X= one of the sixth most commonly collected species, based on the number of individuals collected during electrofishing or seining sampling within a single time period. Note that a species may still have been observed during the collection period even if it was not one of the sixth most commonly collected species. Sources: NRC 1978; EA 2000, 2014 1 Common carp and white sucker were commonly collected during preoperational studies but 2 were not commonly collected during the 1999 or 2013 study. Ohio EPA (1987) classifies both of 3 these species as pollution tolerant. Brook silverside (Labidesthes sicculus), freshwater drum, 4 sand shiner, smallmouth bass, smallmouth buffalo, golden redhorse, and bluegill were among 5 the commonly collected species in the 1999 or 2013 studies but were not commonly collected in 6 the preoperational studies. Five of these seven species (brook silverside, sand shiner, 7 smallmouth bass, golden redhorse, and bluegill) are native species that are sensitive to declines 8 in water quality or habitat degradation (Lerczak 1996; Smith 2002). 9 These results are consistent with other fish surveys (Lerczak 1996; McClelland et al. 2012) 10 within the upper Illinois River that since the mid-1950s through 1990s and the 2000s, show a 11 decline in fish species that are tolerant of poor water quality and an increase in fish species that 12 are sensitive to habitat degradation. For example, Lerczak (1996) examined fish population 13 data from the Illinois Natural History Survey (INHS), which began monitoring fish populations in 14 the Illinois River in 1957. Since 1957, INHS conducted annual electrofishing surveys at set 15 locations throughout the entire Illinois River, including sampling locations approximately 1 RM 16 downstream of the LSCS river intake, within the vicinity of the LSCS river intake, and 11 RM 17 upstream of the LSCS river intake. Within the upper 50 mi (80 km) of the Illinois River, which 18 includes LSCS, Lerczak (1996) concluded that common carp, which is pollution tolerant, has 19 become less common while bluegill, which is intolerant to degraded habitats, has become more 20 common. For example, in the 1960s, INHS captured an average of 35 common carp per hour 21 as compared to 6 common carp per hour in the 1990s. Bluegill increased from averages of less 22 than 1 per hour in the 1960s to 12 per hour in the 1990s. Lerczak (1996) also noted that in the 23 1990s, fish communities were more evenly distributed among a greater number of species than 24 in the 1960s. For example, in 1962 and 1963, four species comprised 95 percent of all catches: 25 gizzard shad, emerald shiner, common carp, and goldfisha species with pollution tolerance 26 similar to common carp. In 1995, 10 species comprised 95 percent of all catches including 27 several species that are sensitive to habitat degradation, such as the bluegill, largemouth bass 28 (Micropterus salmoides), and several species of small minnows. 29 McClellan et al. (2012) also examined fish populations during three time periods from 1957 30 through 2009 based on INHS data. Table 3-11 describes the species that contributed to 31 approximately 90 percent of all electrofishing catches in the Illinois River (McClelland 32 et al. 2012). The NRC staff further classified fish as either pollution tolerant or intolerant. In 33 addition, the NRC staff determined whether McClelland reported increases or decreases in the 34 relative abundance of each species over time. The NRC staff notes that these general trends 35 were not assessed using regression analyses or other statistical analyses. The most common 3-66

Affected Environment 1 species during the 1957 through 1969 surveys (common carp, gizzard shad, emerald shiner, 2 and goldfish) are considered pollution tolerant species and the relative abundance of these 3 species has generally declined over time. All pollution intolerant species listed in 4 Table 3-11 have generally increased overtime. These data suggest that water quality within the 5 Illinois River has improved over time, allowing species that are pollution sensitive to increase in 6 relative abundance. 7 Table 3-11. Fish Species Comprising 90 Percent of Catch in the Illinois Natural History 8 Electrofishing Surveys from 1957 through 2009 Species(a) Common Name 1957-1969 1970-1989 1990-2009 Trend(c) Pollution Tolerant Species(b) Percent of Catch Cyprinus carpio common carp 24.9 16.4 7.6 Dorosoma cepedianum gizzard shad 20.4 23.0 16.2 Notropis atherinoides emerald shiner 19.3 10.7 10.6 Carassius auratus goldfish 6.6 2.2 - Cyprinus carpio x common carp x goldfish 3.0 - - Carassius auratus Lepomis cyanellus green sunfish 2.4 6.3 5.3 Ictiobus cyprinellus bigmouth buffalo 1.8 1.8 1.3 Ameiurus melas black bullhead 1.4 - - Pimephales vigilax bullhead minnow - - 2.9 Pimephales notatus bluntnose minnow - - 2.3 Lepomis humilis orangespotted sunfish - - 1.2 Aplodinotus grunniens freshwater drum - 3.8 4.8 Pollution Intolerant Species(b) Percent of Catch Lepomis macrochirus bluegill 2.8 6.2 13.1 Micropterus salmoides largemouth bass 2.2 5.1 6.4 Pomoxis nigromaculatus black crappie 1.8 4.2 2.9 Ictalurus punctatus channel catfish - 3.5 5.6 Morone chrysops white bass - 2.9 2.8 Micropterus dolomieu smallmouth bass - - 1.4 Notes: (-) = Fish species not part of 90 percent of the catch during specified time period (a) Species ordered by decreasing relative abundance based on McClelland et al 2012; species contributed to approximately 90 percent of all electrofishing catches in the Illinois River and could be classified as either pollution tolerant or intolerant. (b) Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015. (c) Inclines or declines in the relative abundance of each species are general trends; the NRC staff did not evaluate these trends using regression analyses or other statistical analyses. Sources: Ohio EPA 1987; Osmond et al. 1995; Lerczak 1996; Smith 2002; Maryland DNR 2015; Mississippi DNR 2015; McClelland et al. 2012 9 3.7.2 LSCS Cooling Pond 10 As described in Section 3.5, the 2,058-ac (833-ha) cooling pond was created in 1978 by 11 pumping water from the Illinois River into the excavated pond. Exelon leases a large portion of 12 the LSCS cooling pond to the IDNR, which maintains the LSCS cooling pond as an outdoor 3-67

Affected Environment 1 recreation area for public use and fishing. IDNR has actively managed the LSCS cooling pond 2 since 1984 (Exelon 2014a). For example, IDNR surveys the cooling pond each year and 3 determines which fish to stock based on fishermen preferences, fish abundance, different 4 species tolerance to warm waters, predator and prey dynamics, and other factors (Exelon 2002, 5 2014a, 2015a). The cooling pond can be characterized as a highly managed ecosystem in 6 which IDNR fish stocking and other human activities primarily influence the species composition 7 and population dynamics. 8 3.7.2.1 Aquatic Community in the Cooling Pond 9 IDNR stocks the LSCS cooling pond each year. In 1981, IDNRs fish hatchery located adjacent 10 to the cooling pond started operations, at which point IDNR started stocking the cooling pond 11 with species from the hatchery (EA 2002). Initially, IDNR stocked the LSCS cooling pond with 12 largemouth bass and bluegill (EA 2002). 13 Currently, commonly stocked species include largemouth bass, smallmouth bass, black crappie 14 (Pomoxis nigromaculatus), white crappie (Pomoxis annularis), channel catfish, blue catfish 15 (Ictalurus furcatus), striped bass hybrid (Morone saxatilis x M. chrysops), walleye (Sander 16 vitreus), and bluegill (See Table 3-12; Exelon 2002 and 2015a). Because of the high water 17 temperatures experienced in the summer months, introductions of warm-water species, such as 18 largemouth bass and blue catfish, have been more successful than introductions of cool-water 19 species, such as walleye and tiger muskellunge. 20 In addition to the stocked species, gizzard shad and threadfin shad (Dorosoma petenense) 21 together called shadalso occur in the cooling pond. Shad are not recreationally fished, and 22 IDNR does not currently stock these fish. IDNR stocks some recreationally fished species that 23 consume shad (e.g., catfish and striped bass) in part to limit the size of shad populations 24 (Exelon 2002). 25 Table 3-12. Fish Stockings in the LSCS Cooling Pond 2008-2014 Common Annual Species(a) Name 2008 2009 2010 2011 2012 2013 2014 Average Percent Lepomis bluegill 55,466 11,740 84,661 364,731 73,681 25,031 100,130 102,206 40% macrochirus Micropterus largemouth 66,395 51,207 50,434 30,470 84,166 48,753 2,660 47,726 19% salmoides bass Morone saxatilis striped 80,889 68,404 41,284 52,642 0 20,580 26,047 48,308 19% hybrid bass hybrid Ictalurus blue catfish 18,560 34,452 19,800 23,368 0 0 18,200 22,876 9% furcatus Micropterus smallmouth 25,365 21,155 21,118 22,733 20,683 22,354 20,582 21,999 9% dolomieu bass Lepomis redear 34,151 0 4,830 4,830 0 0 0 14,604 6% microlophus sunfish (a) Species are ordered by relative abundance (highest to lowest). Sources: Exelon 2014a; IDNR and Exelon 2014 and 2015 3-68

Affected Environment 1 3.7.2.2 Cooling Pond Fish Kill Events 2 LSCS has had four reportable fish kills in the cooling pond since 2001, including fish kills in 3 July 2001, June 2005, June 2009, and August 2010 (Exelon 2014a, 2015a). The temperature in 4 the cooling pond during these events ranged from 93 °F (33.9 °C) to 101°F (38.3 °C) 5 (Exelon 2001, 2009, 2010). In addition, several smaller non-reportable fish kills have occurred 6 when the cooling pond was 95 °F (35 °C) or above (Exelon 2015c). Exelon attributes these fish 7 kills to high cooling pond temperatures as a result of high summer temperatures combined with 8 low winds and high humidity, as described below (Exelon 2001, 2009, 2010). 9 The largest fish kill occurred in July 2001 when IDNR reported approximately 94,500 dead fish 10 due to high temperatures that peaked at 98.2 °F (36.9 °C) (Exelon 2001). IDNR found the 11 maximum temperature in the cooling pond discharge canal to be 120 °F (48.9 °C) and dissolved 12 oxygen levels to range from 6.2 to 18.8 parts per million. The majority of dead fish (96 percent) 13 were gizzard shad (90,800) (Exelon 2001). IDNR identified other dead fish to include 14 1,279 carp, 1,143 smallmouth buffalo, 610 freshwater drum, 345 channel catfish, 238 striped 15 bass hybrid, 93 smallmouth bass, 24 walleye, 13 bluegill, 12 white bass (Morone chrysops), 16 6 yellow bullhead catfish (Ameiurus natalis), and 4 yellow bass (M. mississippiensis) 17 (Exelon 2001). 18 In a June 2005 fish kill, IDNR counted 1,515 dead fish, including 1,439 striped bass hybrids 19 (95 percent), 36 smallmouth bass (2 percent), 20 walleye (1 percent),11 channel catfish (less 20 than 1 percent), 4 blue catfish (less than 1 percent), 3 yellow bass (less than 1 percent), and 21 2 sauger (less than 1 percent) (Exelon 2015c). The LSCS cooling pond peaked at 95 °F (35 °C) 22 during the fish kill (Exelon 2015c). 23 In the June 2009 fish kill, 3,000 to 4,000 gizzard shad comprised 99 percent of the dead fish 24 shad (Exelon 2009). Exelon (2009) also observed 26 smallmouth bass, 4 striped bass, and 25 4 walleye. Immediately prior to and during the fish kill, the LSCS cooling pond increased 10 °F 26 from 83 °F (28 °C) on June 20 to 93 °F (34 °C) on June 23. 27 In the August 2010 fish kill, IDNR concluded that over 90 percent of the dead fish were small 28 threadfin and gizzard shad less than 3 in. (8 cm) long (Exelon 2010). IDNR also observed dead 29 carp, striped bass hybrids, walleye, and smallmouth bass (Exelon 2010). The LSCS cooling 30 pond peaked at 101.3 °F (38.5 °C) the day before the fish kill. 31 3.7.3 Important Species and Habitats 32 3.7.3.1 State-Listed Species 33 IDNR lists 35 fish and 26 mussel species as State-endangered or threatened (IDNR 2015a). Of 34 these, IDNR (2014b) indicates that 7 species (5 fish, 2 mussels) occur in LaSalle County (see 35 Table 3-13). 3-69

Affected Environment 1 Table 3-13. State-Listed Aquatic Species with the Potential To Occur in La Salle County Recorded Occurrences Near LSCS LSCS River Intake(d) Starved Rock or Preoperational Studies (b) Marseilles Pool(c) Species Common Name State Status(a) Fish Fundulus diaphanous banded killifish ST x x Moxostoma carinatum river redhorse ST Moxostoma valenciennesi greater redhorse SE Notropis heterolepis blacknose shiner SE Notropis texanus weed shiner SE Mussels Alasmidonta viridis slippershell ST Elliptio dilatata spike ST (a) SE = State-endangered in Illinois; ST = State-threatened in Illinois (b) NRC 1978 (c) McClelland and Sass 2007; Fritts 2013 (d) EA 2014, 2015; Exelon 2015c, 2015p Sources: NRC 1978; IDNR 2014b; McClelland and Sass 2007; Fritts 2013; EA 2014, 2015; Exelon 2014a, 2015a 2 Banded killifish. Banded killifish occur in clear glacial lakes, streams, or tributaries, often near 3 vegetation (Nyboer et al. 2006). This fish forms small schools near the surface of weedy lakes 4 (Nyboer et al. 2006). In recent years, this species has been documented in the Illinois River 5 (McClelland and Sass 2007; McClelland et al. 2012). In 2006, the INHS collected two banded 6 killifish at RM 241.5 in the Starved Rock Pool sampling area, approximately 8 RM (13 Rkm) 7 downstream of the LSCS river intake (McClelland and Sass 2007). However, from 1993 8 through 2012, the INHS did not observe banded killifish in the Marseilles Pool sampling area, 9 which included sampling locations approximately 1 RM (1.6 Rkm) downstream of the LSCS river 10 intake, within the vicinity of the LSCS river intake, and 11 RM (18 Rkm) upstream of the LSCS 11 river intake (Fritts 2013). 12 In 2014, EA (2015) collected a juvenile banded killifish during an impingement and entrainment 13 study at the LSCS river intake. In response to this collection, Exelon noted that EA Engineering 14 intends to request a scientific collectors permit report from IDNR. This species was not 15 collected during preoperational surveys (NRC 1978) or during operational studies in 1999 and 16 2013 (EA 2000, 2014). 17 River Redhorse. The river redhorse inhabits large river systems, including impoundments and 18 pools, in areas of moderate to swift current and clean gravel substrate (NatureServe 2014a). 19 Barbour et al. (1999) classify this species as an insectivore that is intolerant of pollution and 20 other environmental stressors. INHS electrofishing surveys that began in 1957 have 21 documented this species in the Illinois River (McClelland and Sass 2007). However, from 1993 3-70

Affected Environment 1 through 2012, INHS did not observe river redhorse in the Marseilles Pool sampling area, which 2 included sampling locations approximately 1 RM (1.6 RKm) downstream of the LSCS river 3 intake, within the vicinity of the LSCS river intake, and 11 RM (18 RKm) upstream of the LSCS 4 river intake (Fritts 2013). The river redhorse was not collected during preoperational surveys 5 (NRC 1978) or operational surveys in 1999 and 2013 (EA 2000, 2014). From 2013 through 6 2015, EA (2015) conducted an impingement and entrainment study near the LSCS river intake. 7 Although EA (2015) collected several Moxostoma fish that were not identified to species, EA 8 (2015) concluded that these species were most likely the more common Moxostoma spp., such 9 as shorthead, golden, silver, and black redhorse, given that these common species were 10 conclusively identified during the study. 11 Greater Redhorse. The greater redhorse inhabits lakes and large rivers with sandy to rocky 12 pools (Nyboer et al. 2006). This fish was considered extirpated in Illinois until it was observed in 13 the upper Illinois River basin in 1985 (Nyboer et al. 2006). IDNR (2014) recorded three 14 observations of this species in LaSalle County, most recently in July 2004. This species is rare 15 in the Illinois River, and INHS did not observe this species from 1957 through 2006 at any 16 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 17 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 18 (EA 2000, 2014), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 19 1993 through 2012 (Fritts 2013). From 2013 through 2015, EA (2015) conducted an 20 impingement and entrainment study near the LSCS river intake. Although EA (2015) collected 21 several Moxostoma fish that were not identified to species, EA (2015) concluded that these 22 species were most likely the more common Moxostoma spp., such as shorthead, golden, silver, 23 and black redhorse given that these common species were conclusively identified during the 24 study. 25 Blacknose shiner. The blacknose shiner inhabits clear vegetated lakes, and pools and runs of 26 clear streams (Nyboer et al. 2006). Increased turbidity and decreases in aquatic vegetation 27 have contributed to the decline of this species (Nyboer et al. 2006). IDNR (2014) recorded two 28 observations of this species in LaSalle County, most recently in October 2013. This species is 29 rare in the Illinois River and INHS did not observe this species from 1957 through 2006 at any 30 sampling station in the Illinois River (McClelland and Sass 2007). This species was not 31 collected during preoperational surveys (NRC 1978), operational studies in 1999 and 2013 32 (EA 2000, 2014), an impingement and entrainment study at the LSCS river intake from 2013 33 through 2015 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling 34 area from 1993 through 2012 (Fritts 2013). 35 Weed shiner. In Illinois, the weed shiner inhabits clear sand-bottom creeks with some 36 submerged vegetation (Nyboer et al. 2006). IDNR (2014) recorded one observation of this 37 species in LaSalle County, most recently in October 2013. This species is rare in the Illinois 38 River and INHS did not observe this species from 1957 through 2006 at any sampling station in 39 the Illinois River (McClelland and Sass 2007). This species was not collected during 40 preoperational surveys (NRC 1978), operational studies in 1999 and 2013 (EA 2000, 2014), an 41 impingement and entrainment study at the LSCS river intake from 2013 through 2015 42 (EA 2015), nor in INHS electrofishing surveys in the Marseilles Pool sampling area from 1993 43 through 2012 (Fritts 2013). 44 Slippershell. The slippershell is a freshwater mussel that inhabits small to medium sized 45 streams where it is usually found buried in sandy substrates in shallow water 46 (Nyboer et al. 2006). IDNR (2014) recorded five observations of this species in LaSalle County, 47 most recently in October 2013. In 1994, 1995, and 1999, Sietman et al. (2001) conducted 48 freshwater mussel surveys in the Illinois River from RM 232.0 to 271.2 (RKm 373 to 436), 49 including the Starved Rock and Marseilles Pools sampling areas. Sietman et al. (2001) did not 3-71

Affected Environment 1 collect this species during the surveys. Similarly, this species was not observed in 2013 when 2 IDNR collected 14,850 live mussels, representing 23 species, near the Marseilles Dam after a 3 boating accident (Kanter 2013). This species was not collected during LSCS preoperational 4 surveys (NRC 1978), operational studies in 2013 (EA 2014), or during impingement and 5 entrainment studies at the LSCS river intake from 2013 through 2015 (EA 2015). 6 Spike. The spike is a freshwater mussel that inhabits shoals of medium streams to large 7 rivers, reservoirs, and lakes with sand and gravel substrates (Minnesota DNR 2014). It is 8 distributed throughout the eastern United States, the Mississippi River system, and portions of 9 the Great Lakes (NatureServe 2014b). IDNR (2014) recorded one observation of this species in 10 LaSalle County in August 2010. This species was not collected during LSCS preoperational 11 surveys (NRC 1978); the freshwater mussel survey from RM 232.0 to 271.2 in 1994, 1995, and 12 1999 (Sietman et al. 2001); IDNRs collection of mussels near the Marseilles Dam in 2013 13 (Kanter 2013); operational studies in 2013 (EA 2014); or during impingement and entrainment 14 studies at the LSCS river intake from 2013 through 2015 (EA 2015). 15 3.7.3.2 Important Habitats 16 LaSalle Lake State Fish and Wildlife Area is part of the 2,058 ac (833 ha) cooling pond. As 17 described above in Section 3.7.2, IDNR manages this area for public boating and fishing. 18 The Marseilles State Fish and Wildlife Area occurs approximately 1.5 mi (2.4 km) north of the 19 LSCS site and the makeup and blowdown pipeline corridor right-of-way crosses the eastern 20 portion of the area. The Marseilles State Fish and Wildlife Area is a 1,032-ha (2,550-ac) area 21 managed by IDNR for hunting and wildlife habitat (IDNR 2015d). It is a joint-use area with the 22 Illinois Department of Military Affairs, and periodically used by the Illinois National Guard for 23 training (IDNR 2015d). 24 3.7.4 Non-Native Species 25 Several non-native species, including the common carp, goldfish, and Asian carps 26 (Hypophthalmichthys spp.), have been introduced into the Illinois River (McClelland et al. 2012). 27 Common carp and goldfish have been present in the vicinity of LSCS prior to operations 28 (McClelland et al. 2012; Exelon 2014a). Both species dominated non-native fish collections in 29 INHSs long term monitoring surveys from 1957 and 1985 (McClelland et al. 2012). Common 30 carp and goldfish are tolerant of degraded aquatic habitats and can tolerate low levels of 31 dissolved oxygen and high water turbidity. 32 Beginning in 1985, the number of non-native fish observed in the Illinois River increased 33 (McClelland et al. 2012). Species documented in the Illinois River since 1985 include grass 34 carp (Ctenopharyngodon idella), bighead carp (Hypophthalmycthys nobilis), silver carp 35 (Hypophthalmycthys molitrix), round goby (Neogobius melanostomus), white perch (Morone 36 americana), and the white perch-yellow bass hybrid (M. americana x M. mississippiensis) 37 (McClelland et al. 2012). 38 In addition to fish, Exelon has documented the occurrence of invertebrate non-native species 39 near the river intake, the cooling pond intake, and within the cooling system. Bryozoans are 40 aquatic invertebrates that grow into large sessile colonies. Zebra mussels are native to the 41 Black and Caspian Seas, and have invaded Europe and North America. These organisms can 42 cause biofouling of LSCSs underwater piping systems or water intakes. In 1996, Exelon 43 discovered bryozoans at the cooling pond screen house and removed the colony by using a 44 continuous chlorination treatment. In 2010, Exelon observed the bryozoan Plumatella reticulata 45 in the Unit 1 cooling water system and unidentified bryozoans at the river intake and in the 46 cooling pond (HDR 2011). Within the past 5 years, Exelon has continued to regularly observe 3-72

Affected Environment 1 bryozoan colonies and zebra mussels at both the river intake and the cooling pond intake, and 2 limits the growth of these organisms by using biocides (HDR 2012, 2013, 2014; Exelon 2014a). 3 When necessary, Exelon also follows procedures to remove zebra mussels manually. 4 3.8 Federally Protected Species and Habitats 5 Because NRCs issuance of a renewed license for power plants is a Federal action, the NRCs 6 National Environmental Policy Act (NEPA) process considers species and habitats that are 7 protected under Federal acts and possibly affected by license renewal. Federal acts that 8 protect species and habitats possibly affected by the renewal of a nuclear plant license include 9 the Endangered Species Act of 1973, as amended (ESA); the Bald and Golden Eagle 10 Protection Act of 1940, as amended; the Migratory Bird Treaty Act of 1918, as amended; the 11 Magnuson-Stevens Fishery Conservation and Management Act, as amended (MSA); and the 12 Marine Mammal Protection Act of 1972, as amended. Of these, the NRC has direct 13 responsibilities only under the ESA and MSA. No species protected under the MSA, which 14 protects habitat for certain marine and anadromous fish species, occur near LSCS. Species 15 protected under the ESA are discussed in this section, and species protected under other 16 Federal acts where the NRC has no direct responsibilities and under]]

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