ML090930374

Joint Motion for Approval of Settlement and Dismissal of PIIC Contentions 1, 6, and 11

ML090930374
Person / Time
Site:	Prairie Island
Issue date:	04/03/2009
From:	Doris Lewis Northern States Power Co, Pillsbury, Winthrop, Shaw, Pittman, LLP
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
50-282-LR, 50-306-LR, ASLBP 08-871-01-LR-BD01, RAS 3221
Download: ML090930374 (61)

Text

April 3, 2009 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of )

) Docket Nos. 50-282-LR Northern States Power Co. ) 50-306-LR

)

(Prairie Island Nuclear Generating Plant, ) ASLBP No. 08-871-01-LR Units 1 and 2) )

JOINT MOTION FOR APPROVAL OF SETTLEMENT AND DISMISSAL OF PIIC CONTENTIONS 1, 6, AND 11 Pursuant to 10 C.F.R. § 2.338(i), Northern States Power Company, a Minnesota corporation (NSPM) and the Prairie Island Indian Community (PIIC) (collectively, the Parties) hereby move this Atomic Safety and Licensing Board (the Board) to approve a settlement of Contention 1, Contention 6, and Contention 11. Based on this settlement, the Parties seek dismissal of these three Contentions. The NRC Staff has reviewed, supports, and consents to this Joint Motion and settlement.

On December 5, 2008, the Board admitted seven contentions submitted by the PIIC, including Contentions 1, 6, and 11. Contention 1 related to the discussion of historic and archaeological resources in the Environmental Report (ER). Contention 6 alleged that the License Renewal Application (LRA) failed to include a plan to manage aging of containment coatings. Contention 11 alleged that the LRA did not provide sufficient details of the aging management program for flow accelerated corrosion.

On March 4, 2009, NSPM filed an amendment to its ER, which augments the ERs discussion of the archaeological, historical, and cultural resources within and around the Prairie Island Nuclear Generating Plant site and provides additional information about the NSPM actions to identify and protect such resources. A copy of this ER amendment is attached hereto as Exhibit A.

On March 12, 2009, NSPM filed a supplement to its LRA, which (i) adds an aging management program for containment coatings and (ii) expands the description of the flow accelerated corrosion program to address all ten aging management program elements and make explicit the programs consistency with the Generic Aging Lessons Learned (GALL) Report.1 A copy of this LRA supplement is attached hereto as Exhibit B.

Following these additions to the ER and LRA, PIIC agreed to withdraw Contentions 1, 6, and 11, provided that both Parties comply with the terms to which they have agreed. A settlement agreement, attached hereto as Exhibit C in accordance with 10 C.F.R. § 2.338(g), sets forth this understanding.

Accordingly, the Parties request that the Board approve this settlement and dismiss Contention 1, Contention 6, and Contention 11. Dismissal of these Contentions is in the public interest because NSPM has taken actions to address the PIICs concerns, and because the Commission encourages settlement of contested issues in licensing proceedings. 10 C.F.R. § 2.338. As required by 10 C.F.R. § 2.338(g), a proposed consent order is provided as Exhibit D.

1 NUREG-1801, Generic Aging Lessons Learned Report, Rev. 1 (Sept. 2005).

PIICs counsel has authorized NSPM to file this Joint Motion on its behalf. As required by 10 C.F.R. § 2.323(b), counsel for NSPM certifies that he has consulted with the other parties before filing this motion, and does so with the support of all parties.

Respectfully Submitted,

/Signed electronically by David R. Lewis/

David R. Lewis Matias F. Travieso-Diaz PILLSBURY WINTHROP SHAW PITTMAN LLP 2300 N Street, NW Washington, DC 20037-1122 Tel. (202) 663-8474 Counsel for Northern States Power Co.

Dated: April 3, 2009

Exhibit A Exhibit A to Joint Motion for Approval of Settlement (April 3, 2009)

March 4, 2009 L-PI-09-029 10 CFR 51 10 CFR 54 U S Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 License Nos. DPR-42 and DPR-60 Revisions to Environmental Report Regarding Application for Renewed Operating Licenses By letter dated April 11, 2008, Northern States Power Company, a Minnesota Corporation, (NSPM) submitted an Application for Renewed Operating Licenses (LRA) for the Prairie Island Nuclear Generating Plant (PINGP) Units 1 and 2. This application contained the Applicant's Environmental Report - Operating License Renewal Stage (ER) to assess the environmental impacts of license renewal. This letter provides several changes to the ER.

The ER changes fall into three categories. First, a change is made to reflect the transfer of the operating license from Nuclear Management Company to NSPM.

Second, the original Environmental Reports discussion of the archaeological, historical and cultural resources within and around the PINGP property is augmented to provide additional insight into NSPM actions that will further define and protect these resources.

Third, updates are provided for PINGP permits and authorizations which have expired or closed since the NRC site visit in August 2008. provides the changes to the ER. Enclosure 2 provides the complete list of Preliminary License Renewal Commitments, updated to reflect the new commitments contained in this letter.

If there are any questions or if additional information is needed, please contact Mr. James Holthaus, Environmental Project Manager.

Summary of Commitments This letter contains four new Preliminary License Renewal Commitments. These commitments will be implemented prior to entry of the first PINGP Unit into the Period of Extended Operation.

1717 Wakonade Drive East

• Welch, Minnesota 55089-9642 Telephone: 651.388.1121

Document Control Desk Page 3 Enclosures (2) cc:

Administrator, Region III, USNRC License Renewal Environmental Project Manager, Prairie Island, USNRC Resident Inspector, Prairie Island, USNRC Prairie Island Indian Community ATTN: Phil Mahowald Minnesota Department of Commerce

Enclosure 1 Changes to Applicant's Environmental Report - Operating License Renewal Stage Change 1 - Reflect Transfer of Operating Licenses to NSPM In ER Section 1.1, Introduction and Background, on Page 1-1, a new introductory paragraph is hereby added to read as follows:

On September 22, 2008, the operating license for the Prairie Island Nuclear Generating Plant was transferred from Nuclear Management Company, LLC (NMC) to Northern States Power Company - Minnesota (NSPM). All references to NMC in this Environmental Report should be recognized as NSPM.

The remainder of the section is unchanged.

Change 2 - Augmented Discussion of NSPM Actions to Define and Protect Cultural Resources ER Sections 4.16.1 and 4.16.2 (excluding the boxed summaries of NRC guidance) are hereby revised in their entirety to read as follows:

4.16.1 Historic and Archaeological Resources - Refurbishment The NRC has designated the impacts of license renewal (refurbishment) to historic and archaeological resources a Category 2 issue, because determinations of impacts to historic and archaeological resources are site-specific in nature, and the National Historic Preservation Act mandates that impacts must be determined through consultation with the State Historic Preservation Officer (NRC 1996).

As discussed in Section 2.10, the AEC consulted with the State Archaeologist in the course of reviewing the NSP application for a construction permit for PINGP. The AEC did so because previous archaeological surveys in the Mississippi River valley near Red Wing demonstrated that a large number of prehistoric sites were present, and that undisturbed portions of Prairie Island, in particular, contained many undisturbed burial mounds and a large village habitation by late prehistoric (Mississippian) peoples (AEC 1973, p. II-28). The State Archaeologist subsequently uncovered parts of this village on the Prairie Island site. This village, later named the Bartron Site, was added to the National Register of Historic Places in 1970 (NPS 2006). In addition to the Bartron Site, surveys in the 1960s and 1980s identified six other archaeological sites at the Prairie Island site.

As a federally licensed facility, PINGP is subject to several federal laws and their enacting regulations designed to identify and protect cultural resources. The most important of these is the National Historic Preservation Act of 1966, as amended.

Section 106 of this law requires a cultural resources review of any undertakings sponsored or licensed by the federal government. PINGP follows the 106 review process by reviewing any undertaking that may affect cultural resources, conducting studies as indicated, and consulting with the Minnesota State Historic Preservation Office and other interested parties. The following paragraphs detail PINGPs efforts to implement the Section 106 process.

1

Enclosure 1 Changes to Applicant's Environmental Report - Operating License Renewal Stage NSPM has instituted two corporate procedures to protect cultural resources at NSPM nuclear generating plant sites. The excavation and trenching controls procedure requires a review of any planned excavation (greater than 6 inches deep) to ensure the protection of archaeological and historical resources. The Site Environmental Coordinator or designee is responsible for determining if proposed land-disturbing activity will occur in the vicinity of a culturally-significant site, and if so, for consulting with the qualified archaeologist and SHPO to mitigate potential impacts. The qualified archaeologist is responsible for evaluating any cultural artifacts inadvertently discovered during construction to determine if the material discovered has potential archaeological or historic significance and if so, for reporting it to the SHPO. In any case, the discovery of cultural artifacts at NSPM-owned nuclear plants requires employees to stop work until the Site Environmental Coordinator has evaluated the situation with the qualified archaeologist. Work can resume only after the situation has been addressed, disposition of any material or artifacts has been documented, and it has been determined that identified culturally-significant material is not at risk. These controls ensure that known archaeological/historical sites are avoided and newly-discovered archaeological/historical sites are protected.

The archaeological, cultural and historic resources procedure further defines the responsibilities of the Site Environmental Coordinator and serves as a resource whereby plant employees can access information on the rules and regulations protecting cultural resources and the actions to take in the event of accidental discovery of resources.

To further protect and mitigate any potential impacts to archaeological, cultural, and historic resources, NSPM will revise these procedures to identify sensitive areas and provide guidance for ground-disturbing activities. The procedures will be revised to include drawings and illustrations to assist users in identifying culturally sensitive areas, and pictures of artifacts that are prevalent in the area of the PINGP site. The revised procedures will also require training of the Site Environmental Coordinator and other personnel responsible for proper execution of excavation or other ground-disturbing activities. Training topics will include the review of cultural exclusion areas on the plant site (identified during the surveys discussed in Section 4.16.2), artifact identification, situations which would require notification of the State Archaeologist or other technical resource, and the stop-work process.

Based on the Unit 1 SGR project, replacement of Unit 2 steam generators has little potential for disturbing, uncovering, or harming cultural artifacts. Steam generators will be barged up the Mississippi River to the PINGP site and transported to the containment building by a large, all-terrain vehicle (transporter). The transporter will move along an existing aggregate service road that extends from the barge landing, 500 feet east of the Environmental Lab, to the Owner-Controlled Area security fence. The area through which the service road travels was extensively altered during plant construction and is surrounded by buildings, transmission towers, and other infrastructure. Most natural vegetation in the area has been removed and replaced with turf grasses that are mowed during the growing season. Given that the area was cleared and graded for construction of the original units, and that 2

Enclosure 1 Changes to Applicant's Environmental Report - Operating License Renewal Stage moving the steam generators to the containment building will require no land disturbance, it is anticipated that Unit 2 SGR will likely have no impact on the areas archaeological or historic resources.

Several temporary buildings may be built, including a facility for preparing the steam generators, office space for construction contractors, and a decontamination building. Warehouse(s) are also expected to be built on site and remain after the steam generator replacement outage. Any construction will occur within the existing plant boundaries. There should be no clearing of previously-undisturbed areas. Additional construction personnel and traffic on area roadways associated with the steam generator replacement project are not expected to impact archaeological or historical sites in the area. Therefore, NSPM concludes that refurbishment activities will not impact cultural resources and no mitigation measures will be warranted beyond those prescribed in NSPMs excavation and trenching controls procedure.

The Unit 2 SGR project is currently expected to be contained within the areas shown on Figure 4.16-1, which limits activities to previously disturbed areas.

Section 4.16.2 discusses planned surveys to identify areas of archaeological significance at the plant site. If NSPM later identifies any changes in the expected footprint or facilities that would affect either undisturbed areas or areas identified as having archaeological resources potential, NSPM will consult with a qualified archaeologist and perform additional surveys of such areas prior to any ground-disturbing activities. If there are any concerns regarding impacts to cultural resources from refurbishment activities, NSPM may consult with the Minnesota Historical Society, State Historic Preservation Office, Bureau of Indian Affairs, and PIIC.

3

Enclosure 1 Changes to Applicant's Environmental Report - Operating License Renewal Stage 4

Enclosure 1 Changes to Applicant's Environmental Report - Operating License Renewal Stage 4.16.2 Historic and Archaeological Resources - License Renewal Term NRC has designated the impacts of license renewal (continuing operation) to historic and archaeological resources a Category 2 issue, because determinations of impacts to historic and archaeological resources are site-specific in nature, and the National Historic Preservation Act mandates that impacts must be determined through consultation with the State Historic Preservation Officer (NRC 1996).

NSPM is not aware of any historic or archaeological resources that have been affected to date by PINGP operations, including operation and maintenance of transmission lines. NSPM is aware, however, that the site vicinity and the surrounding environs have significant potential for containing cultural resources.

Additionally, NSPM is aware of cultural resources that have already been found within the Plants boundaries. Because NSPM is aware of the potential for the discovery of cultural resources during land-disturbing activities at its facilities and along its transmission line corridors, it has developed corporate procedures that protect cultural resources at NSPM owned nuclear generating plant sites and has instituted those procedures at Prairie Island. As noted in Section 4.16.1, NSPM is revising those procedures to include further protections for cultural resources within the Plants boundaries. Given that NSPM has no plans to construct new license renewal related facilities at PINGP during the license renewal term, and that the policies and procedures established in the site procedures should protect any resources that have been previously identified or inadvertently discovered, NSPM concludes that operation of generation and transmission facilities over the license renewal term will not impact cultural resources.

NSPM is implementing additional efforts to identify, define, and protect the cultural resources present at the facility. Primarily, NPSM will conduct a Phase I Reconnaissance Field Survey of the disturbed areas within the Plants boundaries.

In addition, NSPM will conduct Phase I field surveys of areas of known archaeological sites to precisely determine their boundaries. NSPM will use the results of these surveys to designate areas for archaeological protection. The Phase I Reconnaissance Field Survey will consist of a 100 percent pedestrian survey of disturbed areas at close transects (maximum of 5 meters). There will be no shovel testing, although areas will be identified as candidates for shovel testing.

Soil probes will be used to identify disturbed or undisturbed soil horizons. Surveys will identify areas and the degree and type of disturbance. Findings from the field surveys will be documented using photographs, written descriptions, and sketch maps, as needed. Site layout drawings will be prepared to aid employees in identifying archaeological exclusion areas to be aware of during planning for excavation activities and will be integrated into the revised procedures discussed in Section 4.16.1.

The surveys discussed above will be the primary method by which NSPM will define the resources present at the PINGP facility. Once this information is obtained, NSPM will integrate it into a Cultural Resources Management Plan (CRMP), which is already under development. NSPM will prepare, maintain, and implement the CRMP to ensure the protection of significant historical, 5

Enclosure 1 Changes to Applicant's Environmental Report - Operating License Renewal Stage archaeological, and cultural resources that may currently exist on the Plant site. In connection with the preparation of the CRMP, NSPM will conduct botanical surveys to identify culturally and medicinally important species on the Plant site, and incorporate provisions to protect such plants into the CRMP. NSPM conducted the first botanical survey in the fall of 2008. NSPM intends to complete the additional surveys, amendments to procedures, and consultations on a schedule that will allow finalization of the CRMP by the end of 2010 and implementation prior to entry of the first PINGP Unit into the Period of Extended Operation.

Finally, NSPM has retained a qualified archaeologist for consultation on an as-needed basis. NSPM will consult with the archaeologist prior to conducting any ground-disturbing activity in any area designated as undisturbed and in any disturbed area that is described as potentially containing archaeological resources (as determined by the Phase I Reconnaissance Field Survey previously discussed).

6

Enclosure 1 Changes to Applicant's Environmental Report - Operating License Renewal Stage Change 3 - Updated Listing of Permits and Authorizations Which Have Expired or Closed Since the NRC Site Visit in August 2008 The following information supersedes selected information in ER Table 9.1-1.

Permitting Agency: Minnesota Department of Natural Resources Expired Permit Name/Number: Fisheries Management Section Special Permit

1. 14658 Renewed Permit Name/Number: Fisheries Management Section Special Permit

1. 15552 New Expiration Date: December 31, 2009 Permitting Agency: Minnesota Department of Natural Resources Expired Permit Name/Number: Fisheries Management Section Special Permit

1. 14657 Renewed Permit Name/Number: Fisheries Management Section Special Permit

1. 15553 New Expiration Date: December 31, 2009 Permitting Agency: Minnesota Department of Transportation Expired Permit Name/Number: Hazardous Materials Shipper Certificate of Registration UPR-211635-MN Renewed Permit Name/Number: Hazardous Materials Shipper Certificate of Registration UPR-211635-MN New Expiration Date: October 27, 2009 Permitting Agency: South Carolina Department of Health Expired Permit Name/Number: Radioactive Waste Transport Permit 0051-22-08X Renewed Permit Name/Number: PERMIT NOT RENEWED New Expiration Date: Not Applicable Permitting Agency: Tennessee Department of Environment and Conservation Expired Permit Name/Number: Radioactive Shipment License T-MN003-L08 Renewed Permit Name/Number: Radioactive Shipment License T-MN003-L09 New Expiration Date: December 31, 2009 Permitting Agency: Wisconsin Department of Natural Resources Expired Permit Name/Number: Scientific Collectors Permit SCP-WCR-20-C-08 Renewed Permit Name/Number: Scientific Collectors Permit SCP-WCR-20-C-09 New Expiration Date: December 31, 2009 Permitting Agency: US Fish and Wildlife Service Expired Permit Name/Number: Federal Fish and Wildlife Permit MB074020-0 Renewed Permit Name/Number: Federal Fish and Wildlife Permit MB074020-0 New Expiration Date: March 31, 2012 7

Enclosure 2 Updated Preliminary License Renewal Commitment List 16 Pages

Preliminary License Renewal Commitments The following table provides the list of preliminary commitments included in the Application for Renewed Operating Licenses (LRA) for Prairie Island Nuclear Generating Plant (PINGP) Units 1 and 2. These commitments reflect the contents of the LRA as submitted, and any updates provided in subsequent correspondence, but are considered preliminary in that the specific wording of some commitments may change, and additional commitments may be made, during the NRC review of the LRA.

The final commitments as submitted by NSPM, and accepted by NRC, are expected to be confirmed in the NRC's Safety Evaluation Report (SER) for the renewed operating licenses. The final commitments, as confirmed in the SER, will become effective upon NRC issuance of the renewed operating licenses. In addition, as stated in the LRA, the final commitments will be incorporated into the Updated Safety Analysis Report (USAR).

Commitment Implementation Related LRA Commitment Number Schedule Section Number 1 Each year, following the submittal of the PINGP License 12 months after 1.4 Renewal Application and at least three months before the LRA submittal scheduled completion of the NRC review, NMC will submit date and at least amendments to the PINGP application pursuant to 10 CFR 3 months before 54.21(b). These revisions will identify any changes to the completion of Current Licensing Basis that materially affect the contents of NRC review the License Renewal Application, including the USAR supplements.

2 Following the issuance of the renewed operating license, the First USAR A1.0 summary descriptions of aging management programs and update in TLAAs provided in Appendix A, and the final list of License accordance with Renewal commitments, will be incorporated into the PINGP 10 CFR 50.71(e)

USAR as part of a periodic USAR update in accordance with 10 following issuance CFR 50.71(e). Other changes to specific sections of the PINGP of renewed USAR necessary to reflect a renewed operating license will also operating licenses be addressed at that time.

3 An Aboveground Steel Tanks Program will be implemented. U1 - 8/9/2013 B2.1.2 Program features will be as described in LRA Section B2.1.2. U2 - 10/29/2014 4 Procedures for the conduct of inspections in the External U1 - 8/9/2013 B2.1.6 Surfaces Monitoring Program, Structures Monitoring Program, Updated through 3/4/2009 1

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number Buried Piping and Tanks Inspection Program, and the RG U2 - 10/29/2014 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will be enhanced to include guidance for visual inspections of installed bolting.

5 A Buried Piping and Tanks Inspection Program will be U1 - 8/9/2013 B2.1.8 implemented. Program features will be as described in LRA U2 - 10/29/2014 Section B2.1.8.

6 The Closed-Cycle Cooling Water System Program will be U1 - 8/9/2013 B2.1.9 enhanced to include periodic inspection of accessible surfaces of components serviced by closed-cycle cooling water when the U2 - 10/29/2014 systems or components are opened during scheduled maintenance or surveillance activities. Inspections are performed to identify the presence of aging effects and to confirm the effectiveness of the chemistry controls. Visual inspection of component internals will be used to detect loss of material and heat transfer degradation. Enhanced visual or volumetric examination techniques will be used to detect cracking.

[Revised in letter dated 1/20/2009 in response to RAI 3.3.2 01]

7 The Compressed Air Monitoring Program will be U1 - 8/9/2013 B2.1.10 enhanced as follows:

U2 - 10/29/2014

• Station and Instrument Air System air quality will be monitored and maintained in accordance with the instrument air quality guidance provided in ISA S7.0.01-1996. Particulate testing will be revised to use a particle size methodology as specified in ISA S7.0.01.

Updated through 3/4/2009 2

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number

• The program will incorporate on-line dew point monitoring.

[Revised in letter dated 2/6/2009 in response to Region III License Renewal Inspection]

8 An Electrical Cable Connections Not Subject to 10 CFR 50.49 U1 - 8/9/2013 B2.1.11 Environmental Qualification Requirements Program will be U2 - 10/29/2014 completed. Program features will be as described in LRA Section B2.1.11.

9 An Electrical Cables and Connections Not Subject to 10 CFR U1 - 8/9/2013 B2.1.12 50.49 Environmental Qualification Requirements Program will U2 - 10/29/2014 be implemented. Program features will be as described in LRA Section B2.1.12.

10 An Electrical Cables and Connections Not Subject to 10 CFR U1 - 8/9/2013 B2.1.13 50.49 Environmental Qualification Requirements Used in U2 - 10/29/2014 Instrumentation Circuits Program will be implemented.

Program features will be as described in LRA Section B2.1.13.

11 The External Surfaces Monitoring Program will be enhanced as U1 - 8/9/2013 B2.1.14 follows:

U2 - 10/29/2014

• The scope of the program will be expanded as necessary to include all metallic and non-metallic components within the scope of License Renewal that require aging management in accordance with this program.

• The program will ensure that surfaces that are inaccessible or not readily visible during plant operations will be inspected during refueling outages.

• The program will ensure that surfaces that are inaccessible or not readily visible during both plant Updated through 3/4/2009 3

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number operations and refueling outages will be inspected at intervals that provide reasonable assurance that aging effects are managed such that the applicable components will perform their intended function during the period of extended operation.

• The program will apply physical manipulation techniques, in addition to visual inspection, to detect aging effects in elastomers and plastics.

• The program will include acceptance criteria (e.g.,

threshold values for identified aging effects) to ensure that the need for corrective actions will be identified before a loss of intended functions.

• The program will ensure that program documentation such as walkdown records, inspection results, and other records of monitoring and trending activities are auditable and retrievable.

[Revised in letter dated 2/6/2009 in response to RAI B2.1.14-1 Follow Up question]

12 The Fire Protection Program will be enhanced to require U1 - 8/9/2013 B2.1.15 periodic visual inspection of the fire barrier walls, ceilings, and U2 - 10/29/2014 floors to be performed during walkdowns at least once every refueling cycle.

[Revised in letter dated 12/5/2008 in response to RAI B2.1.15-3]

13 The Fire Water System Program will be enhanced as follows: U1 - 8/9/2013 B2.1.16 U2 - 10/29/2014

• The program will be expanded to include eight additional yard fire hydrants in the scope of the annual visual Updated through 3/4/2009 4

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number inspection and flushing activities.

• The program will require that sprinkler heads that have been in place for 50 years will be replaced or a representative sample of sprinkler heads will be tested using the guidance of NFPA 25, "Inspection, Testing and Maintenance of Water-Based Fire Protection Systems" (2002 Edition, Section 5.3.1.1.1). Sample testing, if performed, will continue at a 10-year interval following the initial testing.

14 The Flux Thimble Tube Inspection Program will be enhanced U1 - 8/9/2013 B2.1.18 as follows: U2 - 10/29/2014

• The program will require that the interval between inspections be established such that no flux thimble tube is predicted to incur wear that exceeds the established acceptance criteria before the next inspection.

• The program will require that re-baselining of the examination frequency be justified using plant-specific wear rate data unless prior plant-specific NRC acceptance for the re-baselining was received. If design changes are made to use more wear-resistant thimble tube materials, sufficient inspections will be conducted at an adequate inspection frequency for the new materials.

• The program will require that flux thimble tubes that cannot be inspected must be removed from service.

15 The Fuel Oil Chemistry Program will be enhanced as follows: U1 - 8/9/2013 B2.1.19

• Particulate contamination testing of fuel oil in the eleven U2 - 10/29/2014 fuel oil storage tanks in scope of License Renewal will be Updated through 3/4/2009 5

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number performed, in accordance with ASTM D 6217, on an annual basis.

• One-time ultrasonic thickness measurements will be performed at selected tank bottom and piping locations prior to the period of extended operation.

16 A Fuse Holders Program will be implemented. Program U1 - 8/9/2013 B2.1.20 features will be as described in LRA Section B2.1.20. U2 - 10/29/2014 17 An Inaccessible Medium Voltage Cables Not Subject to 10 CFR U1 - 8/9/2013 B2.1.21 50.49 Environmental Qualification Requirements Program will U2 - 10/29/2014 be implemented. Program features will be as described in LRA Section B2.1.21 18 An Inspection of Internal Surfaces in Miscellaneous Piping and U1 - 8/9/2013 B2.1.22 Ducting Components Program will be implemented. Program U2 - 10/29/2014 features will be as described in LRA section B2.1.22.

Inspections for stress corrosion cracking will be performed by visual examination with a magnified resolution as described in 10 CFR 50.55a(b)(2)(xxi)(A) or with ultrasonic methods.

[Revised in letter dated 2/6/2009 in response to RAI B2.1.22-1 Follow Up question]

19 The Inspection of Overhead Heavy Load and Light Load U1 - 8/9/2013 B2.1.23 (Related to Refueling) Handling Systems Program will be U2 - 10/29/2014 enhanced as follows:

• Program implementing procedures will be revised to ensure the components and structures subject to inspection are clearly identified.

• Program inspection procedures will be enhanced to Updated through 3/4/2009 6

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number include the parameters corrosion and wear where omitted.

20 A Metal-Enclosed Bus Program will be implemented. Program U1 - 8/9/2013 B2.1.26 features will be as described in LRA Section B2.1.26. U2 - 10/29/2014 21 For the Nickel-Alloy Nozzles and Penetrations Program, PINGP U1 - 8/9/2013 B2.1.27 commits to the following activities for managing the aging of U2 - 10/29/2014 nickel-alloy components susceptible to primary water stress corrosion cracking:

• Comply with applicable NRC orders, and

• Implement applicable NRC Bulletins, Generic Letters, and staff-accepted industry guidelines.

22 The Nickel-Alloy Penetration Nozzles Welded to the Upper U1 - 8/9/2013 B2.1.28 Reactor Vessel Closure Heads of Pressurized Water Reactors U2 - 10/29/2014 Program will be enhanced as follows:

• The program will require that any deviations from implementing the appropriate required inspection methods of the NRC First Revised Order EA-03-009, Issue of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors, dated February 20, 2004 (Order), as amended, will be submitted for NRC review and approval in accordance with the Order, as amended.

• The program will require that any deviations from implementing the required inspection frequencies mandated by the Order, as amended, will be submitted Updated through 3/4/2009 7

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number for NRC review and approval in accordance with the Order, as amended.

• The program will require that relevant flaw indications detected during the augmented inspections of the upper vessel head penetration nozzles will be evaluated in accordance with the criteria provided in the letter from Mr. Richard Barrett, NRC, Office of Nuclear Reactor Regulation (NRR), Division of Engineering to Alex Marion, Nuclear Energy Institute (NEI), dated April 11, 2003, or in accordance with NRC-approved Code Cases that incorporate the flaw evaluation procedures and criteria of the NRC's April 11, 2003, letter to NEI.

• The program will require that, if leakage or evidence of cracking in the vessel head penetration nozzles (including associated J-groove welds) is detected while ranked in the Low, Moderate, or Replaced susceptibility category, the nozzles are to be immediately reclassified to the High susceptibility category and the required augmented inspections for the High susceptibility category are to be implemented during the same outage the leakage or cracking is detected.

23 A One-Time Inspection Program will be completed. Program U1 - 8/9/2013 B2.1.29 features will be as described in LRA Section B2.1.29. U2 - 10/29/2014 24 A One-Time Inspection of ASME Code Class 1 Small-Bore U1 - 8/9/2013 B2.1.30 Piping Program will be completed. Program features will be as U2 - 10/29/2014 described in LRA Section B2.1.30.

25 For the PWR Vessel Internals Program, PINGP commits to the U1 - 8/9/2011 B2.1.32 following activities for managing the aging of reactor vessel Updated through 3/4/2009 8

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number internals components: U2 - 10/29/2012

• Participate in the industry programs for investigating and managing aging effects on reactor internals;

• Evaluate and implement the results of the industry programs as applicable to the reactor internals; and

• Upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.

26 The Reactor Head Closure Studs Program will be enhanced to U1 - 8/9/2013 B2.1.33 incorporate controls that ensure that any future procurement of U2 - 10/29/2014 reactor head closure studs will be in accordance with the material and inspection guidance provided in NRC Regulatory Guide 1.65.

27 The Reactor Vessel Surveillance Program will be enhanced as U1 - 8/9/2013 B2.1.34 follows: U2 - 10/29/2014

• A requirement will be added to ensure that all withdrawn and tested surveillance capsules, not discarded as of August 31, 2000, are placed in storage for possible future reconstitution and use.

• A requirement will be added to ensure that in the event spare capsules are withdrawn, the untested capsules are placed in storage and maintained for future insertion.

Updated through 3/4/2009 9

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number 28 The RG 1.127, Inspection of Water-Control Structures U1 - 8/9/2013 B2.1.35 Associated with Nuclear Power Plants Program will be U2 - 10/29/2014 enhanced as follows:

• The program will include inspections of concrete and steel components that are below the water line at the Screenhouse and Intake Canal. The scope will also require inspections of the Approach Canal, Intake Canal, Emergency Cooling Water Intake, and Screenhouse immediately following extreme environmental conditions or natural phenomena including an earthquake, flood, tornado, severe thunderstorm, or high winds.

• The program parameters to be inspected will include an inspection of water-control concrete components that are below the water line for cavitation and erosion degradation.

• The program will visually inspect for damage such as cracking, settlement, movement, broken bolted and welded connections, buckling, and other degraded conditions following extreme environmental conditions or natural phenomena.

29 A Selective Leaching of Materials Program will be completed. U1 - 8/9/2013 B2.1.36 Program features will be as described in LRA B2.1.36. U2 - 10/29/2014 Updated through 3/4/2009 10

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number 30 The Structures Monitoring Program will be enhanced as U1 - 8/9/2013 B2.1.38 follows: U2 - 10/29/2014

• The following structures, components, and component supports will be added to the scope of the inspections:

o Approach Canal o Fuel Oil Transfer House o Old Administration Building and Administration Building Addition o Component supports for cable tray, conduit, cable, tubing tray, tubing, non-ASME vessels, exchangers, pumps, valves, piping, mirror insulation, non-ASME valves, cabinets, panels, racks, equipment enclosures, junction boxes, bus ducts, breakers, transformers, instruments, diesel equipment, housings for HVAC fans, louvers, and dampers, HVAC ducts, vibration isolation elements for diesel equipment, and miscellaneous electrical and mechanical equipment items o Miscellaneous electrical equipment and instrumentation enclosures including cable tray, conduit, wireway, tube tray, cabinets, panels, racks, equipment enclosures, junction boxes, breaker housings, transformer housings, lighting fixtures, and metal bus enclosure assemblies o Miscellaneous mechanical equipment enclosures including housings for HVAC fans, louvers, and dampers o SBO Yard Structures and components including Updated through 3/4/2009 11

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number SBO cable vault and bus duct enclosures.

o Fire Protection System hydrant houses o Caulking, sealant and elastomer materials o Non-safety related masonry walls that support equipment relied upon to perform a function that demonstrates compliance with a regulated event(s).

• The program will be enhanced to include additional inspection parameters.

• The program will require an inspection frequency of once every five (5) years for structures and structural components within the scope of the program. The frequency of inspections can be adjusted, if necessary, to allow for early detection and timely correction of negative trends.

• The program will require periodic sampling of groundwater and river water chemistries to ensure they remain non-aggressive.

31 A Thermal Aging Embrittlement of Cast Austenitic Stainless U1 - 8/9/2013 B2.1.39 Steel (CASS) Program will be implemented. Program features U2 - 10/29/2014 will be as described in LRA Section B2.1.39.

32 The Water Chemistry Program will be enhanced as follows: U1 - 8/9/2013 B2.1.40 U2 - 10/29/2014

• The program will require increased sampling to be performed as needed to confirm the effectiveness of corrective actions taken to address an abnormal chemistry condition.

Updated through 3/4/2009 12

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number

• The program will require Reactor Coolant System dissolved oxygen Action Level limits to be consistent with the limits established in the EPRI PWR Primary Water Chemistry Guidelines."

[Revised in letter dated 12/5/2008 in response to RAI B2.1.40-3]

33 The Metal Fatigue of Reactor Coolant Pressure Boundary U1 - 8/9/2013 B3.2 Program will be enhanced as follows:

U2 - 10/29/2014

• The program will monitor the six component locations identified in NUREG/CR-6260 for older vintage Westinghouse plants, either by tracking the cumulative number of imposed stress cycles using cycle counting, or by tracking the cumulative fatigue usage, including the effects of coolant environment. The following locations will be monitored:

o Reactor Vessel Inlet and Outlet Nozzles o Reactor Pressure Vessel Shell to Lower Head o RCS Hot Leg Surge Line Nozzle o RCS Cold Leg Charging Nozzle o RCS Cold Leg Safety Injection Accumulator Nozzle o RHR-to-Accumulator Piping Tee

• Program acceptance criteria will be clarified to require corrective action to be taken before a cumulative fatigue usage factor exceeds 1.0 or a design basis transient cycle limit is exceeded.

[Revised in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

Updated through 3/4/2009 13

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number 34 Reactor internals baffle bolt fatigue transient limits of 1835 U1 - 8/9/2013 B3.2 cycles of plant loading at 5% per minute and 1835 cycles of U2 - 10/29/2014 plant unloading at 5% per minute will be incorporated into the Metal Fatigue of Reactor Coolant Pressure Boundary Program and USAR Table 4.1-8.

35 NSPM will perform an ASME Section III fatigue evaluation of U1 - 8/9/2013 4.3.1.3 the lower head of the pressurizer to account for effects of insurge/outsurge transients. The evaluation will determine the U2 - 10/29/2014 cumulative fatigue usage of limiting pressurizer component(s) through the period of extended operation. The analyses will account for periods of both Water Solid and Standard Steam Bubble operating strategies. Analysis results will be incorporated, as applicable, into the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

[Revised in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

36 NSPM will complete fatigue calculations for the pressurizer April 30, 2009 4.3.3 surge line hot leg nozzle and the charging nozzle using the methodology of the ASME Code (Subsection NB) and will report the revised CUFs and CUFs adjusted for environmental effects at these locations as an amendment to the PINGP LRA. Conforming changes to LRA Section 4.3.3, PINGP EAF Results, will also be included in that amendment to reflect analysis results and remove references to stress-based fatigue monitoring.

[Added in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

37 NSPM will revise procedures for excavation and trenching 8/9/2013 ER 4.16.1 controls and archaeological, cultural and historic resource protection to identify sensitive areas and provide guidance for ground-disturbing activities. The procedures will be revised to Updated through 3/4/2009 14

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number include drawings and illustrations to assist users in identifying culturally sensitive areas, and pictures of artifacts that are prevalent in the area of the Plant site. The revised procedures will also require training of the Site Environmental Coordinator and other personnel responsible for proper execution of excavation or other ground-disturbing activities.

[Added in ER revision submitted in letter dated 3/4/2009]

38 NSPM will conduct a Phase I Reconnaissance Field Survey of 8/9/2013 ER 4.16.2 the disturbed areas within the Plants boundaries. In addition, NSPM will conduct Phase I field surveys of areas of known archaeological sites to precisely determine their boundaries.

NSPM will use the results of these surveys to designate areas for archaeological protection.

[Added in ER revision submitted in letter dated 3/4/2009]

39 NSPM will prepare, maintain and implement a Cultural 8/9/2013 ER 4.16.2 Resources Management Plan (CRMP) to protect significant historical, archaeological, and cultural resources that may currently exist on the Plant site. In connection with the preparation of the CRMP, NSPM will conduct botanical surveys to identify culturally and medicinally important species on the Plant site, and incorporate provisions to protect such plants into the CRMP.

[Added in ER revision submitted in letter dated 3/4/2009]

40 NSPM will consult with a qualified archaeologist prior to 8/9/2013 ER 4.16.2 conducting any ground-disturbing activity in any area designated as undisturbed and in any disturbed area that is described as potentially containing archaeological resources (as Updated through 3/4/2009 15

Preliminary License Renewal Commitments Commitment Implementation Related LRA Commitment Number Schedule Section Number determined by the Phase I Reconnaissance Field Survey discussed in Commitment Number 38).

[Added in ER revision submitted in letter dated 3/4/2009]

Updated through 3/4/2009 16

Exhibit B Exhibit B to Joint Motion for Approval of Settlement (April 3, 2009)

March 12, 2009 L-PI-09-036 10 CFR 54 U S Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 License Nos. DPR-42 and DPR-60 Supplemental Information Regarding Application for Renewed Operating Licenses By letter dated April 11, 2008, Northern States Power Company, a Minnesota Corporation, (NSPM) submitted an Application for Renewed Operating Licenses (LRA) for the Prairie Island Nuclear Generating Plant (PINGP) Units 1 and 2. This letter amends the LRA to provide supplemental information addressing certain issues that have been raised as contentions in this License Renewal proceeding. contains an updated LRA Section B1.1 which better defines the meaning of the term "Consistent with NUREG-1801" as it relates to the descriptions of Aging Management Programs. contains new LRA Sections A2.41 and B2.1.41, and revisions to Sections 2.1.1.4.3, B1.5 and B2.0, which incorporate a Protective Coating Monitoring and Maintenance Program. contains updated LRA Sections B2.0 and B2.1.17 to reflect adoption of the latest EPRI guidance in the Flow-Accelerated Corrosion Program and provide additional detail in the LRA. Conforming changes to LRA Section 3 are also provided.

If there are any questions or if additional information is needed, please contact Mr. Eugene Eckholt, License Renewal Project Manager.

Summary of Commitments This letter contains no new commitments or changes to existing commitments.

1717 Wakonade Drive East

• Welch, Minnesota 55089-9642 Telephone: 651.388.1121

Enclosure 1 Revision to LRA Section B1.1 Regarding Consistency with NUREG-1801 LRA Section B1.1 is hereby revised to define NUREG-1801 Consistency as it relates to the descriptions of Aging Management Programs in Appendix B of the LRA.

LRA Section B1.1 on Page B-1 is revised in its entirety to read as follows:

B1.1 Overview License Renewal Aging Management Program (AMP) descriptions are provided in this appendix for each program credited for managing aging effects based upon the aging management review results provided in Sections 3.1 through 3.6 of this application. One additional program, the Protective Coating Monitoring and Maintenance Program, has been included because of its importance to debris control following a postulated LOCA, even though the coatings themselves are not relied upon to protect coated carbon steel components.

Two of the programs consist of commitments that conform to the program descriptions provided in NUREG-1801, Sections XI.M11 and XI.M16, and the discussions in the corresponding aging management review line items of NUREG-1801 Chapter IV.

The remaining programs are described in terms of their consistency with NUREG-1801 (GALL Report). The ten generic program elements defined in Appendix A.1, Section A.1.2.3 of NUREG-1800 have been addressed for each AMP. Each of the new or existing AMPs described in this appendix has been evaluated for consistency with the ten program-specific element discussions in the applicable program description in NUREG-1801, Chapter X or XI. This appendix summarizes the evaluation results for each program and indicates whether the program elements are consistent with, consistent with enhancements, or consistent with exceptions, to the corresponding program described in NUREG-1801.

Where the discussion states that a plant program is (or will be) consistent with the recommendations of NUREG-1801, takes no exceptions to NUREG-1801, and identifies no enhancements, such statements constitute certification that (1) the plant program corresponds to and contains all of the elements of the referenced GALL Report program; (2) the conditions at the plant are bounded by the conditions for which the GALL Report program was evaluated to the extent such conditions are specified in the GALL program description; and (3) verifications have been completed and are documented on site in an auditable form. Therefore, based on this certification, the Aging Management Program identified in the GALL Report is being used.

Where the discussion of an Aging Management Program states that the plant program will be consistent with the recommendations of NUREG-1801, takes no exceptions to NUREG-1801, but identifies enhancements, such statements constitute certification that (1) with those enhancements, the plant program corresponds to and contains all of the elements of the referenced GALL Report program; (2) the conditions at the plant are bounded by the conditions for which the 1

Enclosure 1 Revision to LRA Section B1.1 Regarding Consistency with NUREG-1801 GALL Report program was evaluated to the extent such conditions are specified in the GALL program description; and (3) verifications have been completed and are documented on site in an auditable form. Therefore, based on this certification, the Aging Management Program identified in the GALL Report is being used.

Where the discussion of an Aging Management Program states that the plant program is (or will be) consistent with the recommendations of NUREG-1801 with exception(s), with or without enhancements, such statements constitute certification that (1) with the exclusion of the specific matters identified in each exception, the plant program corresponds to and contains all of the elements of the referenced GALL Report program; (2) the conditions at the plant are bounded by the conditions for which the GALL Report program was evaluated to the extent such conditions are specified in the GALL program description; and (3) verifications have been completed and are documented on site in an auditable form. Therefore, based on this certification, the Aging Management Program identified in the GALL Report is being used, as modified by the exceptions. A justification for each identified exception is provided.

2

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program The LRA is hereby revised to incorporate a Protective Coating Monitoring and Maintenance Program. The specific LRA changes are as follows:

In LRA Section 2.1.1.4.3 on Page 2.1-8, the last paragraph is revised to read as follows:

The contribution of coatings to containment debris is event driven and is not a result of aging. The applicable coatings are not relied upon to protect coated carbon steel components from corrosion. In addition, the issue is not related to the 40-year term of the current operating license; and therefore, is not a TLAA. However, because the management of containment coatings is important for controlling the amount of debris available to be deposited on containment sump strainers following a LOCA, PINGP has chosen to include a Protective Coating Monitoring and Maintenance Program in LRA Section B2.1.41. PINGP does not credit the Protective Coating Monitoring and Maintenance Program for the prevention of corrosion of carbon steel components. The purpose of the Protective Coating Monitoring and Maintenance Program is to ensure that the amount of coatings that could fail during a LOCA and become debris load on the containment sump B strainers does not exceed the strainers design limits.

New LRA Section A2.41 is added on Page A-17 to read as follows:

A2.41 Protective Coating Monitoring and Maintenance Program The Protective Coating Monitoring and Maintenance Program monitors the performance of Service Level I coated surfaces inside containment through periodic coating examinations, condition assessments, and remedial actions including repair or removal. The program provides direction for the procurement of Service Level I coatings and prescribes methods to apply and maintain Service Level I coatings.

Records are maintained to ensure that the amount of unqualified or degraded qualified coatings do not exceed the prescribed limits.

PINGP does not credit the Protective Coating Monitoring and Maintenance Program for the prevention of corrosion of carbon steel components. The purpose of the Protective Coating Monitoring and Maintenance Program is to ensure that the amount of coatings that could fail during a LOCA and become debris load on the containment sump B strainers does not exceed the strainers design limits. The program is implemented as described in the PINGP response to NRC Generic Letter 98-04.

In LRA Section B1.5 on Page B-6, a new item 41 is added to appear as follows:

41. Protective Coating Monitoring and Maintenance Program [Section B2.1.41]

1

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program In LRA Section B2.0 on Page B-11, line item XI.S8 of the NUREG-1801 program correlation table is revised to appear as follows:

NUREG-1801 NUREG-1801 PINGP Program NUREG-1801 ID Program Comparison XI.S8 Protective Coating Protective Coating Existing Program, Monitoring and Monitoring and Consistent with Maintenance Maintenance Program NUREG-1801 Program [Section B2.1.41]

New LRA Section B2.1.41 is added on Page B-82 to read as follows:

B2.1.41 Protective Coating Monitoring and Maintenance Program Program Description The Protective Coating Monitoring and Maintenance Program monitors the performance of Service Level I coated surfaces inside containment through periodic coating examinations, condition assessments, and remedial actions including repair or removal. The program provides direction for the procurement of Service Level I coatings and prescribes methods to apply and maintain Service Level I coatings.

Service Level I coatings are subject to the requirements of ANSI N101.2-1972, ANSI N101.4-1972, and programmatic controls.

Service Level I protective coatings (identified in Regulatory Guide 1.54 as coatings inside containment) are procured, applied, inspected, and maintained in a manner that is consistent with the licensing basis and regulatory requirements applicable to PINGP as indicated in the plants response to NRC Generic Letter 98-04. These activities ensure operability of post-accident safety systems which rely on water recycled through the containment sump system. The Protective Coating Monitoring and Maintenance Program implements these activities.

PINGP does not rely upon protective coatings to protect coated carbon steel components from corrosion, and does not credit the Protective Coating Monitoring and Maintenance Program for the prevention of corrosion. The purpose of the Protective Coating Monitoring and Maintenance Program is to ensure that the amount of coatings that could fail during a LOCA and become debris load on the containment sump B strainers does not exceed the strainers design limits.

NUREG-1801 Consistency The Prairie Island Nuclear Generating Plant Protective Coating Monitoring and Maintenance Program is an existing program. It is consistent with the recommendations of NUREG-1801, Chapter XI, Program XI.S8, Protective Coating Monitoring and Maintenance Program.

2

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program Exceptions to NUREG-1801 None Enhancements None Aging Management Program Elements The elements of the Protective Coating Monitoring and Maintenance Program are described below. The results of an evaluation of each element with respect to the NUREG-1801, Chapter XI Program XI.S8, Protective Coating Monitoring and Maintenance Program, are also provided.

Scope of Program The Protective Coating Monitoring and Maintenance Program manages the condition of Service Level I coatings inside the Units 1 and 2 reactor containment vessels whose failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown. The scope is consistent with the definition of Service Level I coatings identified in Regulatory Guide 1.54, Revision

1. The condition of coated surfaces inside containment is managed to ensure that post-accident accumulation of failed coating debris on the containment sump B strainers does not exceed the strainers design limits.

The Protective Coating Monitoring and Maintenance Program monitors the performance of Service Level I coated surfaces inside containment through periodic coating examinations, condition assessments, and remedial actions including repair or removal. The program provides direction on the procurement of Service Level I coatings and prescribes methods to apply and maintain Service Level I coatings. Records are maintained to ensure that the amount of unqualified or degraded qualified coatings do not exceed the prescribed limits.

The program was established in accordance with the guidance provided in ASTM D 5163-04a.

This element is consistent with NUREG-1801, Program XI.S8 Element 1, Scope of Program.

Preventive Actions Although the application of coatings provides a preventive action of corrosion protection, PINGP does not rely upon Service Level I protective coatings inside containment to manage aging of the coated base metal. The program manages the degradation of coatings to ensure that the amount of coatings that could fail 3

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program during a LOCA and become debris load on the containment sump B strainers does not exceed the strainers design limits.

This element is consistent with NUREG-1801, Program XI.S8 Element 2, Preventive Actions.

Parameters Monitored/Inspected In accordance with ASTM D 5163-04a, subparagraph 9.2, the Protective Coating Monitoring and Maintenance Program parameters monitored or inspected include any visible defects, such as blistering, cracking, flaking, peeling, delaminating, rusting, discoloration, and damage, among other indications.

A line by line comparison of ASTM D 5163-05a, subparagraph 10.2, and ASTM D 5163-04a, subparagraph 9.2, indicates that both standards are identical for this discussion. Therefore the use of ASTM D 5163-04a is not considered an exception to NUREG-1801. (Note: NUREG-1801, Program XI.S8 Element 3, Parameters Monitored/Inspected, incorrectly references subparagraph 10.2 in ASTM D 5163-05. This subparagraph does not exist in this revision to the standard. The correct citation would be to ASTM D 5163-05a, subparagraph 10.2.)

This element is consistent with NUREG-1801, Program XI.S8 Element 3, Parameters Monitored/Inspected.

Detection of Aging Effects A visual inspection is performed inside containment for evidence of degraded qualified coatings during each refueling outage in accordance with the guidance in ASTM D 5163-04a, paragraph 5. Unqualified coatings are all assumed to fail as a result of a LOCA, and their inspection is conducted every other refueling outage to verify the design basis for debris loading of the sump strainers is met.

The qualifications of the individuals who coordinate and perform coating condition assessments or evaluate the inspection results meet or exceed the requirements of ASTM D 5163-04a, paragraph 8.

The development of an inspection plan and the methods of performing the inspection, identified in ASTM D 5163-04a, subparagraph 9.1, are incorporated into the Protective Coating Monitoring and Maintenance Program. The inspection plan provides for visual inspections along with more detailed inspections for certain areas based on their potential to transport debris to the RHR recirculation strainers, potentially plugging the strainers or being ingested into the ECCS. Plant procedures provide requirements for pre-job briefs and post-job critiques. Drawings are used to map out areas inside containment that could be exposed to latent effects from spray or flooding (i.e., Zone of Influence) 4

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program and areas within a specific distance from postulated breaks where spray would cause destruction of the coatings (i.e., Zone of Destruction). Inspection Data Sheets and photographs are used to record the findings/observations. The program also utilizes ASTM Standards and test methods for evaluating degraded conditions. Instruments and equipment used during the inspection process include flashlight, thickness gages, tape measure, knife, marking pen, binoculars, and camera. A containment coatings assessment report is written to document activities performed to verify that coatings continue to meet the design and licensing basis.

A line by line comparison of ASTM D 5163-05a, subparagraphs 6, 9, 10.1 and 10.5, and ASTM D 5163-04a, subparagraphs 5, 8, 9.1 and 9.5, indicates that both standards are identical for these discussions. Therefore the use of ASTM D 5163-04a is not considered an exception to NUREG-1801. (Note: NUREG-1801, Program XI.S8 Element 4, Detection of Aging Effects, incorrectly references subparagraphs in ASTM D 5163-05 that either do not exist or do not contain the desired content. The correct citation would be to ASTM D 5163-05a, subparagraphs 6, 9, 10.1, and 10.5.)

This element is consistent with NUREG-1801, Program XI.S8 Element 4, Detection of Aging Effects.

Monitoring and Trending To assist in predicting the degradation process of coatings, the last two previous Containment Coatings Assessment Reports are reviewed prior to each containment coating inspection in order to identify trends. Trending helps to ensure corrective or mitigative actions are taken in a timely manner. This trending process meets the criteria in subparagraph 6.2 of ASTM D 5163-04a.

Inspection results are reviewed and corrective action is taken, including repair, removal, or evaluation for any identified degradation. Degradation that is not repaired or removed is evaluated in accordance with the plants corrective action process, and degraded coating that is left in place in an area which could add to the volume of failed coatings is added to the Unqualified and Degraded (Qualified) Coatings Log and evaluated. The log compares the current inspection results against the established acceptance criteria and previous assessment results to ensure that the total volume of postulated failed coatings is less than the design limits. This evaluation ensures that the recirculation strainers will not clog from coating debris following a LOCA, and will function as designed satisfying the criteria of subparagraph 10.1.2 of ASTM D 5163-04a.

A line by line comparison of ASTM D 5163-05a, subparagraphs 7.2 and 11.1.2, and ASTM D 5163-04a, subparagraphs 6.2 and 10.1.2, indicates that both standards are essentially identical (except for minor editorial differences) for these discussions. Therefore the use of ASTM D 5163-04a is not considered an 5

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program exception to NUREG-1801. (Note: NUREG-1801, Program XI.S8 Element 5, Monitoring and Trending, incorrectly references subparagraphs 7.2 and 11.1.2 in ASTM D 5163-05 that either do not exist or do not contain the desired content.

The correct citation would be to ASTM D 5163-05a, subparagraphs 7.2 and 11.1.2.)

This element is consistent with NUREG-1801, Program XI.S8 Element 5, Monitoring and Trending.

Acceptance Criteria The Protective Coating Monitoring and Maintenance Program characterizes, documents, and tests defective or deficient coatings in accordance with subparagraphs 9.2.1 through 9.2.6, 9.3, and 9.4 of ASTM D 5163-04a. These items are summarized as follows.

• Characterization: Defective or deficient coated surfaces are characterized as exhibiting blisters, cracking, flaking/peeling/delamination, rusting, and discoloration. If these conditions are identified they are documented per the following instructions.

- Blisters Measure the area of the blistering and the thickness of the coating in that area. Using ASTM D714 categorize the degree of blistering.

Record the information on the Inspection Data Sheet.

- Cracking Measure the length of the crack or if extensive cracking has occurred, measure the size of the area affected. Determine if the cracking is isolated or is part of a pattern. Record measurements and describe crack depth and pattern on the Inspection Data Sheet. Photograph the area affected.

- Flaking/Peeling/Delaminating Measure the approximate size of the peels and note the pattern formed. Carefully test to see if lifting can easily be achieved beyond the obvious peeled area. Note observations on the Inspection Data Sheet and photograph the affected area.

- Rusting Compare with the pictorial standards of ASTM D610/SSPC VIS 2 to determine the degree of rusting. Try to determine the source of rusting (i.e., is it staining from rusting elsewhere or is it a failure of the coating allowing the substrate to rust). Measure the area and thickness of coating in the affected area. Note observations on the Inspection Data Sheet and photograph the area.

6

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program

- Discoloration Identify areas of discoloration. Measure the area and note observations on the Inspection Data Sheet.

Coating defects are documented in a written report and/or in photographs, and include any applicable measurements of the degraded condition.

• Testing: Additional testing such as ASTM D 4541, Test Method for Pull-off Strength of Coatings Using Portable Adhesion Testers, and ASTM D 6677, Standard Test Method for Evaluation by Knife, are employed for areas where the qualification is in question.

The assessment report includes a summary of the inspected areas and inspections performed. The assessment report also summarizes the amount of unqualified and degraded qualified coatings being left in containment and remedial actions taken; identifies new findings; compares current results against established acceptance criteria and previous assessment results; and includes evaluations of coatings not remediated and failure analysis of degraded coatings.

The program requires corrective action (i.e., repair or removal of coating) or an evaluation if the degraded qualified coating is left in place and could add to the volume of failed coatings. The coatings evaluation personnel are knowledgeable and experienced in nuclear coatings work. Coatings evaluation personnel evaluate the Inspection Data Sheets, initiate corrective actions, review trends, and summarize findings of observed conditions and actions taken to correct the conditions.

A line by line comparison of ASTM D 5163-05a, subparagraphs 10.2.1 through 10.2.6, 10.3, 10.4, and 12, and ASTM D 5163-04a, subparagraphs 9.2.1 through 9.2.6, 9.3, 9.4, and 11, indicates that both standards are essentially identical (except for minor editorial differences) for these discussions. Therefore the use of ASTM D 5163-04a is not considered an exception to NUREG-1801. (Note:

NUREG-1801, Program XI.S8 Element 6, Acceptance Criteria, incorrectly references subparagraphs in ASTM D 5163-05 that either do not exist or do not contain the desired content. The correct citation would be to ASTM D 5163-05a, subparagraphs 10.2.1 through 10.2.6, 10.3, 10.4, and 12.)

This element is consistent with NUREG-1801, Program XI.S8 Element 6, Acceptance Criteria.

Corrective Actions, Confirmation Process, Administrative Controls These elements are consistent with the corresponding NUREG-1801, Program XI.S8 aging management program elements. See Section B1.3 for further discussion.

7

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program Operating Experience The Protective Coating Monitoring and Maintenance Program is an existing program that incorporates both industry and plant specific operating experience to provide added assurance that the condition of coatings inside containment will be managed effectively during the period of extended operation.

A review of operating experience indicates that the Protective Coating Monitoring and Maintenance Program has been effective in monitoring coatings inside containment by identifying degraded conditions, performing evaluations and corrective actions ensuring that the amount of coatings that could fail during a LOCA and become debris load on the containment sump B strainers does not exceed the strainers design limits.

Examples of degraded coatings identified during the Unit 1 coatings inspections in May 2006 include:

• Flaking and chipping near the drain at the 695' elevation in zone B over an area of 4 sq ft, and a thickness of 0.028 inches, and

• Flaking and chipping inside the Regenerative Heat Exchanger Room at elevation 695' over an area of 5 sq ft, and a thickness of 0.028 inches.

Examples of degraded coatings identified during the Unit 2 coatings inspections in November 2006 include:

• Flaking on grating below RCS piping in the 21 RCP/SG vault lower level over an area of 6 sq ft, and a thickness of 0.007 inches, and

• Delamination/chipping on the ladder to lower 21 RCP/SG vault of an insignificant area, and a thickness of 0.007 inches.

Examples of degraded coatings identified during the Unit 1 coatings inspections in February 2008 include:

• Cracking on the Sump B platform at elevation 695' of zone A over an area of 0.5 sq ft, and a thickness of 0.028 inches, and

• Flaking on a hanger support at elevation 695' of zone B over an area of 1 sq ft, and a thickness of 0.007 inches.

For the above three examples of degraded coatings inspection findings, corrective action was taken to remove the identified degraded coatings, or for those areas where the degraded coatings were not removed, an evaluation was performed to review the amount of unqualified coatings to ensure that the volume of debris left in containment was less than the calculated limit.

The basis for the program is industry operating experience as documented in NRC Regulatory Guide 1.54 and several NRC Generic Communications 8

Enclosure 2 Revisions to LRA Sections 2.1.1.4.3, A2.41, B1.5, B2.0 and B2.1.41 to Incorporate a Protective Coating Monitoring and Maintenance Program including Information Notice 97-13, Generic Letter 98-04, Bulletin 2003-01 and Generic Letter 2004-02. The industry experience cited in these publications deals principally with debris that could block emergency recirculation during a design basis accident. A few examples of minor coating deterioration are cited.

Accumulated experience with coatings in other applications shows that high temperature and fluid jet forces can result in detachment from the substrate and disintegration. Therefore, the Regulatory Guide and the program both address the possibility that all unqualified coatings, qualified coatings in the Zones of Destruction and degraded qualified coatings in the Zones of Influence will be transported to the recirculation sump inlet strainers. Program activities and acceptance criteria are based on the postulate that this will occur.

This element is consistent with NUREG-1801, Program XI.S8 Element 10, Operating Experience.

Conclusion The PINGP Protective Coating Monitoring and Maintenance Program is an existing program that has successfully monitored the performance of coatings inside the containments. Proper maintenance of protective coatings has ensured that the quantities of unqualified and degraded qualified coatings inside the containments are maintained below the acceptance limits, and that post-accident safety systems that rely on water recycled through the containment sump system remain operable.

Implementation of the Protective Coating Monitoring and Maintenance Program provides reasonable assurance that the performance of coatings inside the containments will be monitored effectively during the period of extended operation.

Through periodic visual inspections, the program will continue to detect, evaluate, and correct degraded coatings to assure that the recirculation strainers will not clog from coating debris following a postulated design basis event.

9

Enclosure 3 Revisions to LRA Sections B2.0 and B2.1.17, and Conforming Changes to Section 3 Regarding the Flow-Accelerated Corrosion Program The LRA is hereby revised to update the Flow-Accelerated Corrosion Program in the LRA to reflect adoption of the latest EPRI guidance (adds an exception to NUREG-1801) and to provide additional detail. The LRA changes are as follows:

In LRA Table 3.1.1 on Page 3.1-29, the second sentence of the Discussion entry for line item 3.1.1-59 is revised to read, "Exceptions apply to NUREG-1801 recommendations for the Flow-Accelerated Corrosion Program implementation and the Steam Generator Tube Integrity Program implementation."

In LRA Table 3.4.1 on Page 3.4-29, the Discussion entry for line item 3.4.1-29 is revised in its entirety to read, "Consistent with NUREG-1801 with exception. Exceptions apply to NUREG-1801 recommendations for the Flow-Accelerated Corrosion Program implementation. This aging effect is managed with the Flow-Accelerated Corrosion Program."

In the LRA 3.x.2 tables, in all cases where the Flow-Accelerated Corrosion Program is cited as the Aging Management Program, Note A is changed to Note B, and Note C is changed to Note D, as applicable. These changes apply to the following tables:

• Table 3.1.2-5 (Steam Generator System) on Pages 3.1-112, -115, and -123

• Table 3.3.2-11 (Heating System) on Pages 3.3-239, -250, -251 and - 252

• Table 3.4.2-2 (Bleed Steam System) on Pages 3.4-52, -53 and -57

• Table 3.4.2-4 (Condensate System) on Pages 3.4-79 and -86

• Table 3.4.2-5 (Feedwater System) on Pages 3.4-91, -94 and -101

• Table 3.4.2-6 (Main Steam System) on Pages 3.4-104, -107, and -108

• Table 3.4.2-7 (Steam Generator Blowdown System) on Page 3.4-115

• Table 3.4.2-8 (Turbine Generator and Support System) on Pages 3.4-138, -139,

-160 and -161 In LRA Section B2.0 on Page B-8, line item XI.M17 of the NUREG-1801 program correlation table is revised to appear as follows:

NUREG-1801 NUREG-1801 PINGP Program NUREG-1801 ID Program Comparison XI.M17 Flow- Flow-Accelerated Existing Program, Accelerated Corrosion Consistent with Corrosion Program [Section NUREG-1801 with B2.1.17] Exception In LRA Section B2.1.17, Flow-Accelerated Corrosion Program, on Pages B-42 and B-43, the existing section is revised in its entirety to read as follows:

Program Description The Flow-Accelerated Corrosion (FAC) Program is a condition monitoring program established in accordance with the Electric Power Research Institute (EPRI) 1

Enclosure 3 Revisions to LRA Sections B2.0 and B2.1.17, and Conforming Changes to Section 3 Regarding the Flow-Accelerated Corrosion Program guidelines in Nuclear Safety Analysis Center (NSAC)-202L-R3 for carbon steel and bronze components containing high-energy single phase or two phase fluids. The program manages loss of material due to flow-accelerated corrosion in piping and components by (a) conducting an analysis to determine critical locations, (b) performing baseline inspections to determine the extent of thinning at these locations, and (c) performing follow-up inspections to confirm the predictions of the rate of thinning, or repairing or replacing components as necessary. This program complies with PINGPs response to NRC Generic Letter 89-08.

NUREG-1801 Consistency The Prairie Island Nuclear Generating Plant Flow-Accelerated Corrosion Program is an existing program. It is consistent, with exceptions, to the recommendations of NUREG-1801, Chapter XI, Program XI.M17, Flow-Accelerated Corrosion.

Exceptions to NUREG-1801 Program Elements Affected

• Scope of Program, Detection of Aging Effects PINGP implements the guidance provided in EPRI NSAC-202L-R3, Recommendations for an Effective Flow-Accelerated Corrosion Program, May 2006, in lieu of the NUREG-1801 recommendation of EPRI NSAC-202L-R2, Recommendations for an Effective Flow-Accelerated Corrosion Program, April 1999. EPRI NSAC-202L-R3 is the most recent revision of this document, and it provides more prescriptive guidance based on the latest industry operating experience. Use of the current guideline is an acceptable method to maintain the FAC-susceptible systems at PINGP.

Enhancements None Aging Management Program Elements The elements of the Flow-Accelerated Corrosion Program are described below. The results of an evaluation of each element with respect to the NUREG-1801, Chapter XI Program XI.M17, Flow-Accelerated Corrosion, are also provided.

Scope of Program The scope of the PINGP Flow-Accelerated Corrosion (FAC) Program is in accordance with the EPRI guidelines in NSAC-202L-R3 for carbon steel and bronze components containing high-energy single phase or two phase fluids.

The program complies with PINGPs response to NRC GL 89-08 and assures 2

Enclosure 3 Revisions to LRA Sections B2.0 and B2.1.17, and Conforming Changes to Section 3 Regarding the Flow-Accelerated Corrosion Program component structural integrity by using procedures, administrative controls and qualified personnel to predict, detect, and monitor wall thinning (loss of material) due to FAC on the internal surfaces of susceptible piping and other components such as fittings, elbows, reducers, expanders, tees, nozzles, heat exchanger components and valve bodies. The program includes (a) conducting an analysis to determine critical locations, (b) performing limited baseline inspections to determine the extent of thinning at these locations, and (c) performing follow-up inspections to confirm the predictions, or repairing or replacing components as necessary. The program uses CHECWORKS to predict component wall thinning and NSAC-202L-R3 to satisfy criteria specified in 10 CFR Part 50, Appendix B, for development of procedures and control of special processes. Susceptible piping and components that can not be adequately modeled in CHECWORKS are qualitatively evaluated, prioritized and ranked based on susceptibility and consequences of failure.

The use of NSAC-202L-R3 is an exception to the NUREG-1801 recommendation which references the use of NSAC-202L-R2. NSAC-202L-R3 is the most recent revision of this document and it provides more prescriptive guidance based on the latest industry operating experience. This revision incorporates lessons learned and new technology that has become available since the previous revision which was published in April 1999. Use of the current guideline is an acceptable method to maintain the FAC-susceptible systems at PINGP.

This AMP consists of PINGP activities that manage aging effects for components of the following systems and/or structures:

• Bleed Steam (BL) System

• Condensate (CD) System

• Feedwater (FW) System

• Heating (HS) System

• Main Steam (MS) System

• Steam Generator Blowdown (SB) System

• Steam Generator (SG) System

• Turbine Generator and Support (TB) System This element is consistent, with exception, to NUREG-1801, Program XI.M17 Element 1, Scope of Program.

Preventive Actions The PINGP FAC Program is a predictive analysis, inspection, and verification program; thus, there are no preventive actions. However, secondary water chemistry is monitored to control pH and dissolved oxygen content in accordance with the Water Chemistry Program; and the FAC program includes guidance for the selection of appropriate piping material, geometry, and hydrodynamic conditions, which are all effective means of reducing FAC.

3

Enclosure 3 Revisions to LRA Sections B2.0 and B2.1.17, and Conforming Changes to Section 3 Regarding the Flow-Accelerated Corrosion Program This element is consistent with NUREG-1801, Program XI.M17 Element 2, Preventive Actions.

Parameters Monitored/Inspected The PINGP FAC Program uses CHECWORKS and qualitative evaluations to predict piping and component wall thinning (loss of material) in susceptible components and uses non-destructive examinations to detect and monitor wall thinning by measuring wall thickness.

This element is consistent with NUREG-1801, Program XI.M17 Element 3, Parameters Monitored/Inspected.

Detection of Aging Effects The PINGP FAC Program generally uses volumetric ultrasonic examinations to detect and monitor wall thinning (loss of material) in susceptible piping and components. The program also allows for the use of radiography, including the use of radiography for small-bore piping. The program utilizes the guidance of NSAC-202L-R3 and identifies susceptible locations using CHECWORKS as well as qualitative evaluations, industry and plant experience, previous inspection results, operating conditions or special considerations, and engineering judgment. The extent and schedule of the examinations assure detection of wall thinning before the loss of intended function.

The use of NSAC-202L-R3 is an exception to the NUREG-1801 recommendation which references the use of NSAC-202L-R2. EPRI NSAC-202L-R3 is the most recent revision of this document and it provides more prescriptive guidance based on the latest industry operating experience. This revision incorporates lessons learned and new technology that has become available since the previous revision which was published in April 1999. Use of the current guideline is an acceptable method to maintain the FAC-susceptible systems at PINGP.

This element is consistent, with exception, to NUREG-1801, Program XI.M17 Element 4, Detection of Aging Effects.

Monitoring and Trending The PINGP FAC Program uses CHECWORKS and qualitative evaluations to predict piping and component wall thinning (loss of material) in systems susceptible to FAC using specific plant data, including material, hydrodynamic, and operating conditions. CHECWORKS and the qualitative evaluations provide a bounding predictive analysis for FAC. The inspection schedule is based on the predictive analysis and provides reasonable assurance that structural integrity will be maintained between inspections. The inspection results are evaluated to 4

Enclosure 3 Revisions to LRA Sections B2.0 and B2.1.17, and Conforming Changes to Section 3 Regarding the Flow-Accelerated Corrosion Program determine if additional inspections are needed to determine the extent of wall thinning, assure that the intended function of the component will not be lost, and identify any corrective actions that may be required.

This element is consistent with NUREG-1801, Program XI.M17 Element 5, Monitoring and Trending.

Acceptance Criteria PINGP inspection results are input into CHECWORKS to calculate the number of refueling outages remaining before the component reaches the minimum allowable wall thickness. If calculations indicate that an area will reach the minimum allowable wall thickness before the next scheduled outage, the component is repaired, replaced, or reevaluated.

This element is consistent with NUREG-1801, Program XI.M17 Element 6, Acceptance Criteria.

Corrective Actions Components which do not satisfy the PINGP wall thickness acceptance criteria are repaired, replaced, or reevaluated prior to service. Long-term corrective actions include adjusting operating parameters, selecting materials resistant to FAC or improving piping design and configuration. See Section B1.3 for further discussion.

This element is consistent with NUREG-1801, Program XI.M17 Element 7, Corrective Actions.

Confirmation Process, Administrative Controls These elements are consistent with the corresponding NUREG-1801, Program XI.M17 aging management program elements. See Section B1.3 for further discussion.

Operating Experience A review of operating experience for the PINGP FAC Program identified no adverse trends or issues with program performance. Wall thinning has been identified, and the associated components replaced, prior to causing any significant impact to safe operation or loss of intended functions. Recent examples of the identification of wall thinning which did not meet acceptance criteria include locations in Heater Drain System line 2 1/2 -2HD-83 elbow and piping in 2005 and Condenser 2A Drain Header at Penetration #75 in 2006. The affected components were replaced. The review of operating experience indicates the PINGP FAC Program is effective in monitoring and detecting 5

Enclosure 3 Revisions to LRA Sections B2.0 and B2.1.17, and Conforming Changes to Section 3 Regarding the Flow-Accelerated Corrosion Program degradation and taking effective corrective actions as needed when acceptance criteria are not met.

This element is consistent with NUREG-1801, Program XI.M17 Element 10, Operating Experience.

Conclusion The Flow-Accelerated Corrosion Program is an existing program for carbon steel and bronze components containing high-energy single phase or two phase fluids.

The program has been effective in predicting, detecting, and monitoring components for FAC; and no adverse trends or significant conditions related to these components have been identified.

Implementation of the Flow-Accelerated Corrosion Program provides reasonable assurance that aging effects will be managed such that structures, systems, and components within the scope of this program will continue to perform their intended function(s) during the period of extended operation.

6

Exhibit C Exhibit C to Joint Motion for Approval of Settlement (April 3, 2009)

EXHIBIT D - PROPOSED CONSENT ORDER UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges:

William J. Froehlich, Chairman Dr. Gary S. Arnold Dr. Thomas J. Hirons In the Matter of Docket Nos. 50-282-LR and 50-306-LR Northern States Power Co. ASLBP No. 08-871-01-LR (Prairie Island Nuclear Generating Plant, April __, 2009 Units 1 and 2)

ORDER (Approving Settlement and Dismissal of Contentions 1, 6, and 11)

On April 3, 2009, the Northern States Power Co. and the Prairie Island Indian Community (collectively, the Parties), with the NRC Staffs support and consent, moved for an order approving settlement and dismissal of Contentions 1, 6, and 11. In accordance with 10 C.F.R. § 2.338(g), the Parties forwarded the settlement agreement and proposed order to this Board.

Consistent with Commission policy to encourage resolution of contested issues in licensing proceedings through settlement, we find dismissal in the public interest.

Pursuant to our authority under 10 C.F.R. § 2.338(i), we grant the Joint Motion and dismiss Contentions 1, 6, and 11.

It is so ORDERED.

THE ATOMIC SAFETY AND LICENSING BOARD William J. Froehlich, Chairman ADMINISTRATIVE JUDGE Dr. Gary S. Arnold ADMINISTRATIVE JUDGE Dr. Thomas J. Hirons ADMINISTRATIVE JUDGE Rockville, Maryland April __, 2009

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of )

) Docket Nos. 50-282-LR Northern States Power Co. ) 50-306-LR

)

(Prairie Island Nuclear Generating Plant, ) ASLBP No. 08-871-01-LR Units 1 and 2) )

CERTIFICATE OF SERVICE I hereby certify that copies of Joint Motion for Approval of Settlement and Dismissal of PIIC Contentions 1, 6, and 11 dated April 3, 2009, was provided to the Electronic Information Exchange for service on the individuals listed below, this 3rd day of April, 2009.

Administrative Judge Administrative Judge William J. Froehlich, Esq., Chair Dr. Gary S. Arnold Atomic Safety and Licensing Board Atomic Safety and Licensing Board Mail Stop T-3 F23 Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Washington, DC 20555-0001 Email: wjf1@nrc.gov Email: gxa1@nrc.gov Administrative Judge Secretary Dr. Thomas J. Hirons Attn: Rulemakings and Adjudications Staff Atomic Safety and Licensing Board Mail Stop O-16 C1 Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Washington, DC 20555-0001 secy@nrc.gov; hearingdocket@nrc.gov Email: thomas.hirons@nrc.gov Office of Commission Appellate Adjudication Philip R. Mahowald, Esq.

Mail Stop O-16 C1 General Counsel, Prairie Island Indian U.S. Nuclear Regulatory Commission Community Washington, DC 20555-0001 5636 Sturgeon Lake Road E-mail: ocaamail@nrc.gov Welch, MN 55089 pmahowald@piic.org

Beth N. Mizuno, Esq.

David E. Roth, Esq.

Peter G. Harris, Esq.

Maxwell C. Smith, Esq, Office of the General Counsel Mail Stop O-15 D21 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: beth.mizuno@nrc.gov; david.roth@nrc.gov; peter.harris@nrc.gov; maxwell.smith@nrc.gov

/Signed electronically by David R. Lewis/

David R. Lewis