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APPENDIX A                                                A-62                                REV, 18, SEPTEMBER 2016
APPENDIX A                                                A-62                                REV, 18, SEPTEMBER 2016


LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC                    COMMITMENT                                                SOURCE SCHEDULE As described below, baseline inspections will occur in the 10-year period prior to the period of extended operation. The maximum interval of subsequent coating inspections will comply with Table 4a of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014 (ADAMS Accession No.
LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC                    COMMITMENT                                                SOURCE SCHEDULE As described below, baseline inspections will occur in the 10-year period prior to the period of extended operation. The maximum interval of subsequent coating inspections will comply with Table 4a of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014 (ADAMS Accession No. ML13262A442).
ML13262A442).
The inspection of the Main Control Room Chiller Condensers will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.
The inspection of the Main Control Room Chiller Condensers will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.
The inspection of the Reactor Enclosure Cooling Water Heat Exchangers will be performed by inspectors with a demonstrated working knowledge of EPRI Report 1019157, Guideline on Nuclear Safety-Related Coatings.
The inspection of the Reactor Enclosure Cooling Water Heat Exchangers will be performed by inspectors with a demonstrated working knowledge of EPRI Report 1019157, Guideline on Nuclear Safety-Related Coatings.
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LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC                      COMMITMENT                                                SOURCE SCHEDULE requirement. For the waste water environment, a maximum of 25 components per population will be inspected. To provide reasonable assurance of the presence of sufficient coating, 10 of the 25 internal inspections will be of the normal waste, oily waste, sanitary waste and storm drain galvanized piping, and 15 of the internal inspections will be of the radioactive floor and equipment drain carbon steel piping.
LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC                      COMMITMENT                                                SOURCE SCHEDULE requirement. For the waste water environment, a maximum of 25 components per population will be inspected. To provide reasonable assurance of the presence of sufficient coating, 10 of the 25 internal inspections will be of the normal waste, oily waste, sanitary waste and storm drain galvanized piping, and 15 of the internal inspections will be of the radioactive floor and equipment drain carbon steel piping.
27  Lubricating Oil Existing program is credited.                            Ongoing            Section A.2.1.27 Analysis The Lube Oil Analysis aging management program also                          LGS Letter dated manages the loss of coating integrity in the RCIC turbine                    3/14/14 bearing pedestals and HPCI turbine bearing pedestals                        RAI 3.0.3-1 and oil reservoir.
27  Lubricating Oil Existing program is credited.                            Ongoing            Section A.2.1.27 Analysis The Lube Oil Analysis aging management program also                          LGS Letter dated manages the loss of coating integrity in the RCIC turbine                    3/14/14 bearing pedestals and HPCI turbine bearing pedestals                        RAI 3.0.3-1 and oil reservoir.
LGS letter dated As described below, baseline inspections will occur                      05/21/14 in the 10-year period prior to the period of extended                    RAI 3.0.3.4-1 operation. The maximum interval of subsequent coating inspections will comply with Table 4a of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014 (ADAMS Accession No.
LGS letter dated As described below, baseline inspections will occur                      05/21/14 in the 10-year period prior to the period of extended                    RAI 3.0.3.4-1 operation. The maximum interval of subsequent coating inspections will comply with Table 4a of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014 (ADAMS Accession No. ML13262A442).
ML13262A442).
The inspection of the RCIC turbine bearing pedestals and HPCI turbine bearing pedestals and oil reservoir will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.
The inspection of the RCIC turbine bearing pedestals and HPCI turbine bearing pedestals and oil reservoir will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.
APPENDIX A                                            A-79                            REV, 18, SEPTEMBER 2016
APPENDIX A                                            A-79                            REV, 18, SEPTEMBER 2016

Latest revision as of 21:19, 4 February 2020

Revision 18 to Updated Final Safety Analysis Report, Appendix a
ML16357A152
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LGS UFSAR APPENDIX A UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT TABLE OF CONTENTS A.1 Introduction.......................................................................................................4 A.1.1 NUREG-1801 Chapter XI Aging Management Programs.................................. 4 A.1.2 Plant-Specific Aging Management Programs.................................................... 7 A.1.3 NUREG-1801 Chapter X Aging Management Programs................................... 7 A.1.4 Time-Limited Aging Analyses............................................................................ 7 A.1.5 Quality Assurance Program and Administrative Controls .................................. 8 A.1.6 Operating Experience..8 A.2 Aging Management Programs ..........................................................................9 A.2.1 NUREG-1801 Chapter XI Aging Management Programs.................................. 9 A.2.1.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD........9 A.2.1.2 Water Chemistry ...............................................................................................9 A.2.1.3 Reactor Head Closure Stud Bolting ..................................................................9 A.2.1.4 BWR Vessel ID Attachment Welds .................................................................10 A.2.1.5 BWR Feedwater Nozzle..................................................................................10 A.2.1.6 BWR Control Rod Drive Return Line Nozzle ...................................................10 A.2.1.7 BWR Stress Corrosion Cracking.....................................................................11 A.2.1.8 BWR Penetrations ..........................................................................................11 A.2.1.9 BWR Vessel Internals .....................................................................................11 A.2.1.10 Flow-Accelerated Corrosion............................................................................12 A.2.1.11 Bolting Integrity ...............................................................................................13 A.2.1.12 Open-Cycle Cooling Water System.................................................................14 A.2.1.13 Closed Treated Water Systems ......................................................................15 A.2.1.14 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems...........................................................................................16 A.2.1.15 Compressed Air Monitoring.............................................................................16 A.2.1.16 BWR Reactor Water Cleanup System ............................................................17 A.2.1.17 Fire Protection ................................................................................................18 A.2.1.18 Fire Water System ..........................................................................................19 A.2.1.19 Aboveground Metallic Tanks...........................................................................21 A.2.1.20 Fuel Oil Chemistry ..........................................................................................23 A.2.1.21 Reactor Vessel Surveillance ...........................................................................24 A.2.1.22 One-Time Inspection.......................................................................................25 A.2.1.23 Selective Leaching..........................................................................................25 A.2.1.24 One-Time Inspection of ASME Code Class 1 Small-Bore Piping ....................25 A.2.1.25 External Surfaces Monitoring of Mechanical Components ..............................26 A.2.1.26 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components ...................................................................................................27 A.2.1.27 Lubricating Oil Analysis...................................................................................28 A.2.1.28 Monitoring of Neutron-Absorbing Materials Other Than Boraflex ....................28 A.2.1.29 Buried and Underground Piping and Tanks ....................................................29 A.2.1.30 ASME Section XI, Subsection IWE .................................................................31 A.2.1.31 ASME Section XI, Subsection IWL..................................................................31 A.2.1.32 ASME Section XI, Subsection IWF .................................................................33 A.2.1.33 10 CFR Part 50, Appendix J ...........................................................................34 A.2.1.34 Masonry Walls ................................................................................................34 A.2.1.35 Structures Monitoring......................................................................................35 APPENDIX A A-1 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.36 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants ..................................................................................................37 A.2.1.37 Protective Coating Monitoring and Maintenance Program ..............................38 A.2.1.38 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements ...................................39 A.2.1.39 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits ...........................................................................................................39 A.2.1.40 Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements .............................................................................40 A.2.1.41 Metal Enclosed Bus ........................................................................................41 A.2.1.42 Fuse Holders ..................................................................................................41 A.2.1.43 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements .............................................................................41 A.2.2 Plant-Specific Aging Management Programs.................................................. 42 A.3 NUREG-1801 Chapter X Aging Management Programs.................................42 A.3.1 Evaluation of Chapter X Aging Management Programs .................................. 42 A.3.1.1 Fatigue Monitoring ..........................................................................................42 A.3.1.2 Environmental Qualification (EQ) of Electric Components ..............................43 A.4 Time-Limited Aging Analyses..........................................................................43 A.4.1 Identification of Time-Limited Aging Analyses................................................. 43 A.4.2 Reactor Pressure Vessel Neutron Embrittlement Analysis .............................. 44 A.4.2.1 Neutron Fluence Projections...........................................................................44 A.4.2.2 Upper-Shelf Energy ........................................................................................44 A.4.2.3 Adjusted Reference Temperature ...................................................................45 A.4.2.4 Pressure - Temperature Limits.......................................................................45 A.4.2.5 Axial Weld Inspection......................................................................................46 A.4.2.6 Circumferential Weld Inspection .....................................................................46 A.4.2.7 Reactor Pressure Vessel Reflood Thermal Shock ..........................................47 A.4.3 Metal Fatigue.................................................................................................. 48 A.4.3.1 ASME Section III, Class 1 Fatigue Analyses...................................................48 A.4.3.2 ASME Section III, Class 2 and 3 and ANSI B31.1 Allowable Stress Calculations ....................................................................................................49 A.4.3.3 Environmental Fatigue Analyses for RPV and Class 1 Piping .........................49 A.4.3.4 Reactor Vessel Internals Fatigue Analyses.....................................................51 A.4.3.5 High-Energy Line Break (HELB) Analyses Based Upon Fatigue.....................51 A.4.4 Environmental Qualification (EQ) of Electric Components .............................. 51 A.4.4.1 Environmental Qualification (EQ) of Electric Components ..............................51 A.4.5 Containment Liner and Penetrations Fatigue Analyses................................... 52 A.4.5.1 Containment Liner and Penetrations Fatigue Analyses...................................52 A.4.6 Other Plant-Specific Time-Limited Aging Analyses ........................................ 53 A.4.6.1 Reactor Enclosure Crane Cyclic Loading Analysis..........................................53 A.4.6.2 Emergency Diesel Generator Enclosure Cranes Cyclic Loading Analysis.......53 A.4.6.3 RPV Core Plate Rim Hold-Down Bolt Loss of Preload ....................................54 A.4.6.4 Main Steam Line Flow Restrictors Erosion Analysis .......................................54 A.4.6.5 Jet Pump Auxiliary Spring Wedge Assembly ..................................................55 A.4.6.6 Jet Pump Restrainer Bracket Pad Repair Clamps...........................................55 A.4.6.7 Refueling Bellows and Supports Cyclic Loading Analysis ...............................56 A.4.6.8 Downcomers and MSRV Discharge Piping Fatigue Analyses .........................56 A.4.6.9 Jet Pump Slip Joint Repair Clamps.................................................................. 52 A.4.6.10 Fuel Pool Girder Loss of Prestress..52 APPENDIX A A-2 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.4.6.11 RHR and Core Spray Suction Strainer Fatigue Anaylses...52 A.5 License Renewal Commitment List ................................................................59 APPENDIX A A-3 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.1 Introduction The application for a renewed operating license is required by 10 CFR 54.21(d) to include a UFSAR Supplement. This appendix, which includes the following sections, comprises the UFSAR supplement:

Section A.1.1 contains a listing of the aging management programs that correspond to NUREG-1801 Chapter XI programs.

Section A.1.2 contains a listing of the plant-specific aging management programs.

Section A.1.3 contains a listing of aging management programs that correspond to NUREG-1801 Chapter X programs associated with Time-Limited Aging Analyses.

Section A.1.4 contains a listing of the Time-Limited Aging Analyses summaries (TLAAs).

Section A.1.5 contains a discussion of the Quality Assurance Program and Administrative Controls.

Section A.2.1 contains a summarized description of the NUREG-1801 Chapter XI programs for managing the effects of aging.

Section A.2.2 contains a summarized description of the plant-specific programs for managing the effects of aging.

Section A.3 contains a summarized description of the NUREG-1801 Chapter X programs that support the TLAAs.

Section A.4 contains a summarized description of the TLAAs applicable to the period of extended operation.

Section A.5 contains the License Renewal Commitment List.

The integrated plant assessment for license renewal identified new and existing aging management programs necessary to provide reasonable assurance that systems, structures, and components within the scope of license renewal will continue to perform their intended functions consistent with the Current Licensing Basis (CLB) for the period of extended operation. The period of extended operation is defined as 20 years from the units operating license expiration date that existed prior to License Renewal.

A.1.1 NUREG-1801 Chapter XI Aging Management Programs The NUREG-1801 Chapter XI Aging Management Programs (AMPs) are described in the following sections. The AMPs are either consistent with generally accepted industry methods as discussed in NUREG-1801 or require enhancements.

The following list reflects the status of these programs at the time of the renewed licenses issuance. Commitments for program additions and enhancements are identified in the Appendix A.5 License Renewal Commitment List.

APPENDIX A A-4 Rev. 18, SEPTEMBER 2016

LGS UFSAR

1. ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (Section A.2.1.1) [Existing]
2. Water Chemistry (Section A.2.1.2) [Existing]
3. Reactor Head Closure Stud Bolting (Section A.2.1.3) [Existing]
4. BWR Vessel ID Attachment Welds (Section A.2.1.4) [Existing]
5. BWR Feedwater Nozzle (Section A.2.1.5) [Existing]
6. BWR Control Rod Drive Return Line Nozzle (Section A.2.1.6)

[Existing - Requires Enhancement]

7. BWR Stress Corrosion Cracking (Section A.2.1.7) [Existing]
8. BWR Penetrations (Section A.2.1.8) [Existing]
9. BWR Vessel Internals (Section A.2.1.9) [Existing - Requires Enhancement]
10. Flow-Accelerated Corrosion (Section A.2.1.10) [Existing]
11. Bolting Integrity (Section A.2.1.11) [Existing - Requires Enhancement]
12. Open-Cycle Cooling Water System (Section A.2.1.12) [Existing -

Requires Enhancement]

13. Closed Treated Water Systems (Section A.2.1.13) [Existing -

Requires Enhancement]

14. Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (Section A.2.1.14)

[Existing - Requires Enhancement]

15. Compressed Air Monitoring (Section A.2.1.15) [Existing]
16. BWR Reactor Water Cleanup System (Section A.2.1.16) [Existing]
17. Fire Protection (Section A.2.1.17) [Existing - Requires Enhancement]
18. Fire Water System (Section A.2.1.18) [Existing - Requires Enhancement]
19. Aboveground Metallic Tanks (Section A.2.1.19) [Existing - Requires Enhancement]
20. Fuel Oil Chemistry (Section A.2.1.20) [Existing - Requires Enhancement]
21. Reactor Vessel Surveillance (A.2.1.21) [Existing]

APPENDIX A A-5 Rev. 18, SEPTEMBER 2016

LGS UFSAR

22. One-Time Inspection (Section A.2.1.22) [New]
23. Selective Leaching (A.2.1.23) [New]
24. One-Time Inspection of ASME Code Class 1 Small-Bore Piping (Section A.2.1.24) [New]
25. External Surfaces Monitoring of Mechanical Components (Section A.2.1.25) [New]
26. Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (Section A.2.1.26) [New]
27. Lubricating Oil Analysis (Section A.2.1.27) [Existing]
28. Monitoring of Neutron-Absorbing Materials Other than Boraflex (Section A.2.1.28) [Existing - Requires Enhancement]
29. Buried and Underground Piping and Tanks (Section A.2.1.29)

[Existing - Requires Enhancement]

30. ASME Section XI, Subsection IWE (Section A.2.1.30) [Existing -

Requires Enhancement]

31. ASME Section XI, Subsection IWL (Section A.2.1.31) [Existing -

Requires Enhancement]

32. ASME Section XI, Subsection IWF (Section A.2.1.32) [Existing -

Requires Enhancement]

33. 10 CFR Part 50, Appendix J (Section A.2.1.33) [Existing]
34. Masonry Walls (Section A.2.1.34) [Existing - Requires Enhancement]
35. Structures Monitoring (Section A.2.1.35) [Existing - Requires Enhancement]
36. RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants (Section A.2.1.36) [Existing - Requires Enhancement]
37. Protective Coating Monitoring and Maintenance Program (Section A.2.1.37) [Existing - Requires Enhancement]
38. Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (Section A.2.1.38) [New]
39. Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits (Section A.2.1.39) [New]

APPENDIX A A-6 Rev. 18, SEPTEMBER 2016

LGS UFSAR

40. Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (Section A.2.1.40) [New]
41. Metal Enclosed Bus (Section A.2.1.41) [New]
42. Fuse Holders (Section A.2.1.42) [New]
43. Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (Section A.2.1.43) [New]

A.1.2 Plant-Specific Aging Management Programs None. Limerick Generating Station, Units 1 and 2 do not have plant-specific aging management programs as a result of License Renewal.

A.1.3 NUREG-1801 Chapter X Aging Management Programs The NUREG-1801 Chapter X Aging Management Programs (AMP) associated with Time-Limited Aging Analyses are described in the following sections. The AMPs are either consistent with generally accepted industry methods as discussed in NUREG-1801 Chapter X or require enhancements. The following list reflects the status of these programs at the time of the renewed licenses issuance. Commitments for program additions and enhancements are identified in Appendix A.5 License Renewal Commitment List.

1. Fatigue Monitoring (Section A.3.1.1) [Existing - Requires Enhancement]
2. Environmental Qualification (EQ) of Electric Components (Section A.3.1.2) [Existing]

A.1.4 Time-Limited Aging Analyses Summaries of the Time-Limited Aging Analyses applicable to the period of extended operation are included in the following sections:

1. Reactor Pressure Vessel Neutron Embrittlement Analysis (Section A.4.2)
2. Metal Fatigue (Section A.4.3)
3. Environmental Qualification (EQ) of Electric Components (Section A.4.4)
4. Containment Liner and Penetrations Fatigue Analysis (Section A.4.5)
5. Other Plant-Specific Time-Limited Aging Analyses (Section A.4.6)

APPENDIX A A-7 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.1.5 Quality Assurance Program and Administrative Controls The Quality Assurance Program implements the requirements of 10 CFR 50, Appendix B, and is consistent with the summary in Appendix A.2, Quality Assurance For Aging Management Programs (Branch Technical Position IQMB-1) of NUREG-1800. The Quality Assurance Program includes the elements of corrective action, confirmation process, and administrative controls, and is applicable to the safety-related and nonsafety-related systems, structures, and components (SSCs) that are subject to Aging Management Review (AMR). In many cases, existing activities were found adequate for managing aging effects during the period of extended operation.

A.1.6 OPERATING EXPERIENCE The Operating Experience program is an existing program that has been enhanced to ensure, through the ongoing review of both internal and external operating experience, that the license renewal aging management programs are effective to manage the aging effects for which they are credited throughout the period of extended operation.

The programs are either enhanced or new programs developed when the review of operating experience indicates that the effects of aging may not be adequately managed.

The Operating Experience program has been enhanced to:

1. Explicitly require the review of operating experience for aging-related degradation.
2. Establish criteria to define aging-related degradation.
3. Establish identification coding for use in identification, trending and communications of aging-related degradation.
4. Require communication of significant internal aging-related degradation, associated with SSCs in the scope of license renewal, to other Exelon plants and to the industry. Criteria will be established for determining when aging-related degradation is significant.
5. Require review of external operating experience for information related to aging management and evaluation of such information for potential improvements to LGS aging management activities.
6. Provide training to those responsible for screening, evaluating and communicating operating experience items related to aging management.

These enhancements were implemented prior to the date that the renewed operating licenses were issued and will be conducted on an ongoing basis throughout the terms of the renewed licenses.

APPENDIX A A-8 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2 Aging Management Programs A.2.1 NUREG-1801 Chapter XI Aging Management Programs This section provides summaries of the NUREG-1801 programs credited for managing the effects of aging.

A.2.1.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD aging management program is an existing program that consists of periodic volumetric and visual examinations of components for assessment, identification of signs of degradation, and establishment of corrective actions.

The program includes inspections performed to identify and manage cracking and loss of fracture toughness in Class 1, 2, and 3 piping and components exposed to reactor coolant and treated water environments. The inspections will be implemented in accordance with 10 CFR 50.55(a) and ASME Code,Section XI Subsections IWB, IWC, and IWD. These activities include inspections, and monitoring and trending of results to confirm that aging effects are managed.

A.2.1.2 Water Chemistry The Water Chemistry aging management program is an existing program whose activities consist of monitoring and control of water chemistry to manage the aging of reactor vessel, reactor internals, piping, piping elements and piping components, heat exchangers and tanks that are exposed to treated water.

The Water Chemistry aging management program keeps peak levels of various contaminants below system-specific limits based on the industry recognized guidelines of the Boiling Water Reactor Vessel and Internals Project (BWRVIP-190, Revision 1, Electric Power Research Institute - 3002002623) for the prevention or mitigation of loss of material, reduction of heat transfer and cracking aging effects. In addition, the water chemistry program is also credited for mitigating loss of material and cracking for components exposed to sodium pentaborate, steam and reactor coolant environments. To mitigate aging effects on component surfaces the chemistry program is used to control water chemistry for impurities that accelerate corrosion.

A.2.1.3 Reactor Head Closure Stud Bolting The Reactor Head Closure Stud Bolting program is an existing program that provides for condition monitoring and preventive activities to manage reactor head closure studs and associated nuts, washers and flange threads for cracking and loss of material. The program is implemented through station procedures based on the examination and inspection requirements specified in ASME Section XI, Table IWB-2500-1 and preventive measures described in NRC Regulatory Guide 1.65, Materials and Inspection for Reactor Vessel Closure Studs, with the exception that stud bolting material having a measured yield stress greater than 150 ksi is used.

APPENDIX A A-9 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.4 BWR Vessel ID Attachment Welds The BWR Vessel ID Attachment Welds aging management program is an existing aging management program that incorporates the inspection and evaluation recommendations of BWRVIP-48-A, and the recommendations described in the Water Chemistry (A.2.1.2) program. The program is implemented through station procedures that provide for mitigation of cracking through management of reactor water chemistry and monitoring for cracking through in-vessel examinations of the reactor vessel internal attachment welds.

The program also manages loss of material due to wear on the steam dryer support brackets via in-vessel examinations. Examinations performed under this program are implemented via augmented inservice inspection requirements.

A.2.1.5 BWR Feedwater Nozzle The BWR Feedwater Nozzle aging management program is an existing program that manages the effects of cracking in the feedwater nozzles by augmented in-service inspection (ISI) in accordance with the requirements of the ASME Code,Section XI, Subsection IWB, Table IWB-2500-1 and the recommendations provided within BWROG Licensing Topical Report, GE-NE-523-A71-0594-A, Revision 1. Inspections of the feedwater nozzles are performed in accordance with the ISI Program Plan.

A.2.1.6 BWR Control Rod Drive Return Line Nozzle The BWR Control Rod Drive Return Line (CRDRL) Nozzle aging management program is an existing program that provides for condition monitoring of the CRDRL reactor pressure vessel nozzle for cracking. The CRDRL nozzle has been capped to mitigate thermal fatigue cracking on both units. The program performs In-service Inspection (ISI) examinations to monitor the effects of cracking on the intended function of the CRDRL nozzle. Volumetric ultrasonic inspection is performed on the CRDRL nozzle including the nozzle-to-vessel weld, nozzle blend radius and nozzle-to-cap welds. The CRDRL nozzle and nozzle-to-vessel weld examinations are performed at the frequency specified in ASME Code,Section XI, Table IWB-2500-1. The CRDRL nozzle-to-cap weld examinations are performed at a frequency specified by the BWR Stress Corrosion Cracking (A.2.1.7) program that implements commitments from NRC Generic Letter 88-01 and BWRVIP-75-A. The nozzle, cap and associated welds are included in the visual inspection (VT-2) during the reactor pressure test performed each refueling outage.

The BWR Control Rod Drive Return Line Nozzle aging management program will be enhanced to:

1. Specify an extended volumetric inspection of the nozzle-to-cap weld to assure that the inspection includes base metal to a distance of one pipe wall thickness or 0.5 inches, whichever is greater, on both sides of the weld.

This enhancement will be implemented prior to the period of extended operation.

APPENDIX A A-10 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.7 BWR Stress Corrosion Cracking The BWR Stress Corrosion Cracking aging management program is an existing augmented Inservice Inspection program that manages intergranular stress corrosion cracking (IGSCC) in relevant piping and piping welds made of stainless steel and nickel based alloy, regardless of code classification, as delineated in NUREG-0313, Revision 2, and NRC Generic Letter 88-01 and its Supplement 1. The program includes preventive measures to mitigate IGSCC, and inspection and flaw evaluation to monitor IGSCC and its effects. The schedule and extent of the inspections are performed in accordance with the NRC staff-approved BWRVIP-75-A report for normal water chemistry conditions.

A.2.1.8 BWR Penetrations The BWR Penetrations aging management program is an existing program that manages the effects of cracking of reactor vessel instrumentation penetrations, and CRD housing and incore-monitoring housing penetrations exposed to reactor coolant through water chemistry and in-service inspections. The scope of the program includes beltline instrumentation nozzles and other instrumentation nozzles; except for the core plate differential pressure (dP) instrumentation nozzle and the jet pumps instrumentation nozzles, which are in the scope of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (A.2.1.1) program. The BWR Penetrations aging management program incorporates the inspection and evaluation recommendations of BWRVIP-49-A, "Instrument Penetration Inspection and Flaw Evaluation Guidelines," BWRVIP-47-A, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines," and the water chemistry recommendations described in the Water Chemistry (A.2.1.2) program.

BWRVIP-27-A does not apply to LGS because Standby Liquid Control (SLC) injects through the Core Spray piping. Inspections of the instrument penetrations and CRD housing and incore-monitoring housing penetrations are implemented through station ISI procedures, which incorporate the requirements of ASME Section XI. The requirements of ASME Section XI are implemented in accordance with 10 CFR 50.55(a).

A.2.1.9 BWR Vessel Internals The BWR Vessel Internals program is an existing program that manages the effects of cracking, loss of material and loss of fracture toughness of reactor pressure vessel internal components through condition monitoring activities that consist of examinations that are implemented through station procedures consistent with the recommendations of the BWRVIP guidelines and ASME Code,Section XI, Table IWB-2500-1. The program also mitigates these aging effects by managing water chemistry per the Water Chemistry (A.2.1.2) program.

The program will include aging management of reactor internal components fabricated from Cast Austenitic Stainless Steel (CASS) for loss of fracture toughness due to thermal aging and neutron embrittlement.

APPENDIX A A-11 Rev. 18, SEPTEMBER 2016

LGS UFSAR The BWR Vessel Internals aging management program will be enhanced to:

1. Perform an assessment of the susceptibility of reactor vessel internal components fabricated from Cast Austenitic Stainless Steel (CASS) to loss of fracture toughness due to thermal aging embrittlement. If material properties cannot be determined to perform the screening, they will be assumed susceptible to thermal aging for the purposes of determining program examination requirements.
2. Perform an assessment of the susceptibility of reactor vessel internal components fabricated from Cast Austenitic Stainless Steel (CASS) to loss of fracture toughness due to neutron irradiation embrittlement.
3. Specify the required periodic inspection of CASS components determined to be susceptible to loss of fracture toughness due to thermal aging and neutron irradiation embrittlement.

These enhancements will be implemented prior to the period of extended operation. The initial inspections will be performed either prior to or within 5 years after entering the period of extended operation.

A.2.1.10 Flow-Accelerated Corrosion The Flow-Accelerated Corrosion (FAC) aging management program is an existing program based on EPRI guidelines in NSAC-202L, Recommendations for an Effective Flow Accelerated Corrosion Program. The program provides guidance for prediction, detection, and monitoring wall thinning in piping and fittings, valve bodies, and heat exchangers due to FAC. Analytical evaluations and periodic examinations of locations that are most susceptible to wall thinning due to FAC are used to predict the amount of wall thinning in pipes, fittings, and feedwater heater shells. Program activities include analyses to determine critical locations, baseline inspections to determine the extent of thinning at these critical locations, and follow-up inspections to confirm the predictions. Repairs and replacements are performed as necessary.

The Flow-Accelerated Corrosion aging management program also manages wall thinning caused by mechanisms other than FAC, such as cavitation, flashing, droplet impingement, and solid particle impingement, in situations where periodic monitoring is used in lieu of eliminating the cause of various erosion mechanism(s).

APPENDIX A A-12 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.11 Bolting Integrity The Bolting Integrity aging management program is an existing program that provides for aging management for loss of material, cracking, and loss of preload of pressure retaining bolted joints within the scope of license renewal.

The Bolting Integrity program incorporates NRC and industry recommendations delineated in NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants, EPRI TR-104213, Bolted Joint Maintenance & Applications Guide, and EPRI NP 5769, Degradation and Failure of Bolting in Nuclear Power Plants, as part of the comprehensive component pressure retaining bolting program. The program provides for managing loss of material, cracking, and loss of preload by performing visual inspections of safety-related pressure retaining bolted joints at least once per refueling cycle for leakage, loss of material, cracking, and loss of preload.

Bolting for other pressure retaining components is inspected for signs of leakage. Inspection activities for bolting in buried and underground applications is performed in conjunction with inspection activities for the Buried and Underground Piping and Tanks (A.2.1.29) aging management program due to the restricted accessibility to these locations.

The Bolting Integrity aging management program is supplemented by aging management activities included in several other programs including ASME Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD (A.2.1.1),

Reactor Head Closure Stud Bolting (A.2.1.3), Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (A.2.1.14),

External Surfaces Monitoring of Mechanical Components (A.2.1.25), Buried and Underground Piping and Tanks (A.2.1.29), ASME Section XI, Subsection IWE (A.2.1.30), ASME Section XI, Subsection IWF (A.2.1.32), Structures Monitoring (A.2.1.35), and Reg. Guide 1.127 Inspection of Water Control Structures Associated With Nuclear Power Plants (A.2.1.36).

The Bolting Integrity aging management program will be enhanced to:

1. Provide guidance to ensure proper specification of bolting material, lubricant and sealants, storage, and installation torque or tension to prevent or mitigate degradation and failure of closure bolting for pressure retaining components.
2. Prohibit the use of lubricants containing molybdenum disulfide for pressure retaining components.
3. Minimize the use of high strength bolting (actual measured yield strength equal to or greater than 150 ksi) for closure bolting for pressure retaining components. High strength bolting, if used, will be monitored for cracking.
4. Perform visual inspection of bolting for the Residual Heat Removal System, Core Spray System, High Pressure Coolant Injection System, and Reactor Core Isolation Cooling System suppression pool suction strainers for loss of material and loss of preload during each ISI inspection interval.

The enhancements will be implemented prior to the period of extended operation.

APPENDIX A A-13 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.12 Open-Cycle Cooling Water System The Open-Cycle Cooling Water System (OCCWS) aging management program is an existing program that manages heat exchangers, piping, piping elements and piping components in safety-related and nonsafety-related raw water systems that are exposed to raw water and air/gas-wetted environments for loss of material, reduction of heat transfer, and hardening and loss of strength of elastomers. This is accomplished through tests and inspections per the guidelines of NRC Generic Letter 89-13. System and component testing, visual inspections, non-destructive examination (i. e. Radiographic Testing, Ultrasonic Testing and Eddy Current Testing), and chemical injection are conducted to ensure that aging effects are managed such that system and component intended functions and integrity are maintained.

The OCCWS includes those systems that transfer heat from safety-related structures, systems and components to the ultimate heat sink as defined in GL-89-13 as well as those raw water systems which are in scope for license renewal for spatial interaction but have no safety-related heat transfer function.

Periodic heat transfer testing or inspection and cleaning of heat exchangers with a heat transfer intended function is performed in accordance with LGS commitments to GL 89-13 to verify heat transfer capabilities. Heat exchangers which have no safety-related heat transfer function are periodically inspected and cleaned.

Periodic volumetric inspections will be performed in the non-buried portions of the Safety Related Service Water System to provide a sufficient understanding of the buried service water piping conditions throughout the period of extended operation. The inspection locations are selected to ensure that conditions are similar (e. g. flow, temperature) to those in the buried portions of the Safety Related Service Water System piping.

The OCCWS aging management program also manages the loss of coating integrity in a raw water environment. Internal coatings in the service water side of the Main Control Room Chiller Condensers and Reactor Enclosure Cooling Water Heat Exchangers, and in circulating water system piping are visually inspected to ensure that loss of coating integrity is detected. The inspections of the Main Control Room Chiller Condensers and circulating water system piping will be performed by inspectors qualified to international standards endorsed in RG 1.54, including, ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II. The inspections of the Reactor Enclosure Cooling Water Heat Exchangers will be performed by inspectors with a demonstrated working knowledge of EPRI Report 1019157, Guideline on Nuclear Safety-Related Coatings. Inspections are performed for signs of coating failures and precursors to coating failures including peeling, delamination, blistering, cracking, flaking, chipping, rusting, and mechanical damage. When acceptance criteria are not met, visual inspection is supplemented by additional testing such as DFT (Dry Film Thickness), adhesion, continuity, or other inspection technique as determined by the qualified inspector to accurately assess coating condition. Adhesion testing will be performed using international standards endorsed in RG 1.54. A coatings specialist qualified to ASTM D-7108 will evaluate the results of the coating inspections. Evaluations APPENDIX A A-14 Rev. 18, SEPTEMBER 2016

LGS UFSAR are performed for inspection results that do not satisfy established acceptance criteria and the conditions are entered into the LGS 10 CFR 50 Appendix B corrective action program. The corrective action program ensures that conditions adverse to quality are promptly corrected. Corrective actions may include coating repair or replacement prior to the component being returned to service.

The Open-Cycle Cooling Water System aging management program will be enhanced to:

1. Perform internal inspection of buried Safety Related Service Water Piping when it is accessible during maintenance and repair activities
2. Perform periodic inspections for loss of material in the Nonsafety-Related Service Water System at a minimum of five locations on each unit once every refueling cycle.
3. Replace the supply and return piping for the Core Spray pump compartment unit coolers.
4. Replace degraded RHRSW piping in the pipe tunnel.
5. Perform periodic inspections for loss of material in the Safety Related Service Water System at a minimum of ten locations every two years.

The enhancements will be implemented prior to the period of extended operation.

A.2.1.13 Closed Treated Water Systems The Closed Treated Water Systems program is an existing mitigation program that includes (a) nitrite-based water treatment, including pH control and the use of corrosion inhibitors for carbon steel and copper alloys, to modify the chemical composition of the water such that the function of the equipment is maintained and such that the effects of corrosion are minimized; and (b) chemical testing of the water to ensure that the water treatment program maintains the water chemistry within acceptable guidelines. The Closed Treated Water Systems program manages the loss of material and the reduction of heat transfer in piping, piping components, piping elements, tanks, and heat exchangers exposed to a closed treated water environment.

The Closed Treated Water Systems aging management program will be enhanced to:

1. Perform condition monitoring and performance monitoring, including periodic testing and opportunistic and periodic NDE, to verify the effectiveness of water chemistry control to mitigate aging effects. A representative sample of piping and components will be selected based on likelihood of corrosion and inspected at an interval not to exceed once in 10 years during the period of extended operation.
2. Perform condition monitoring for the loss of material due to cavitation APPENDIX A A-15 Rev. 18, SEPTEMBER 2016

LGS UFSAR erosion in the reactor enclosure cooling water piping to the 2A Reactor Water Cleanup System (RWCU) non-regenerative heat exchanger. An initial inspection frequency of 4 years has been established. The inspection frequency will be re-evaluated and adjusted as necessary based on trend data.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.14 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems The Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems aging management program is an existing condition monitoring program that manages the effects of loss of material on the bridge, bridge rails, bolting and trolley structural components for those cranes, hoists and rigging beams that are within the scope of license renewal. The program also manages loss of preload of associated bolted connections. Procedures and controls implement the guidance on the control of overhead heavy load cranes specified in NUREG-0612, Control of Heavy Loads at Nuclear Power Plants. The program utilizes periodic inspections as described in the ASME B30 series of standards for inspection, monitoring and detection of aging effects.

The Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems aging management program will be enhanced to:

1. Perform annual periodic inspections as defined in the appropriate ASME B30 series standard for all cranes, hoists, and equipment handling systems within the scope of license renewal. For handling systems that are infrequently in service, such as those only used during refueling outages, annual periodic inspections may be deferred until just prior to use.
2. Perform inspections of structural components and bolting for loss of material due to corrosion, rails for loss of material due to wear and corrosion, and bolted connections for loss of preload.
3. Evaluate loss of material due to wear or corrosion and any loss of bolting preload on cranes, hoists, and equipment handling systems per the appropriate ASME B30 series standard.
4. Perform repairs to cranes, hoists, and equipment handling systems per the appropriate ASME B30 series standard.

Enhancements will be implemented prior to the period of extended operation.

A.2.1.15 Compressed Air Monitoring The Compressed Air Monitoring aging management program is an existing program that manages piping, piping components, piping elements, and valve APPENDIX A A-16 Rev. 18, SEPTEMBER 2016

LGS UFSAR bodies for loss of material in the compressed air systems. The Compressed Air Monitoring aging management activities consist of air quality monitoring and trending, preventive maintenance, and condition monitoring measures to manage the aging effects.

The Compressed Air Monitoring program is based on the LGS response to NRC Generic letter 88-14, "Instrument Air Supply Problems" and utilizes guidance and standards provided in INPO SOER 88-01. The Compressed Air Monitoring program activities implement the moisture and contaminant criteria of ANSI MC11.1 (ISA S7.3, incorporated into ANSI/ISA-S7.0.01). Program activities include air quality checks at various locations to ensure that dew point, particulates, lubricant content and contaminants are maintained within the specified limits.

The Compressed Air Monitoring Program will be enhanced to:

1. Perform periodic analysis and trending of air quality monitoring results.

This enhancement will be implemented prior to the period of extended operation.

A.2.1.16 BWR Reactor Water Cleanup System The BWR Reactor Water Cleanup System program is an existing condition monitoring and mitigation program that describes the requirements for augmented inservice inspection (ISI) for stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) on stainless steel Reactor Water Cleanup (RWCU) System piping welds outboard of the second (outboard) primary containment isolation valves. The program includes the measures delineated in NUREG-0313, Rev. 2, and in NRC Generic Letter (GL) 88-01 and its Supplement 1. The program is implemented in conjunction with the Water Chemistry (A.2.1.2) program to minimize the potential of cracking due to SCC or IGSCC in a treated water environment. The BWR Reactor Water Cleanup System program activities, and the control of reactor water chemistry, manage the aging effects in stainless steel RWCU System piping welds outboard of the second primary containment isolation valves thereby maintaining the intended function of this piping.

APPENDIX A A-17 Rev. 18, SEPTEMBER 2016

LGS UFSAR The BWR Reactor Water Cleanup System program includes acceptable inspection alternatives to staff positions delineated in GL 88-01 as described in GL 88-01, Supplement 1. In accordance with the staff's criteria regarding the acceptable inspection schedules for the portion of the RWCU System piping welds outboard of the second primary containment isolation valves, the NRC has approved the elimination of the requirements to perform examinations of the outboard portion of the RWCU System for both LGS Unit 1 and Unit 2. If one or more of the RWCU System welds inboard of the primary containment isolation valves inspected as part of the on-going GL 88-01 inspections under the BWR Stress Corrosion Cracking (A.2.1.7) program have confirmed IGSCC or SCC indications, then an additional sample of RWCU system welds outboard of the primary containment isolation valves is selected and examined based on the requirements of GL 88-01.

A.2.1.17 Fire Protection The Fire Protection aging management program is an existing program that includes fire barrier visual inspections, and halon and carbon dioxide systems visual inspections and functional tests. The fire barrier inspection program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, floors and other materials that perform a fire barrier function.

Periodic visual inspection and functional testing of the fire rated doors and visual inspection of fire rated dampers is performed to ensure that their functionality is maintained. The program also includes visual inspections and periodic operability tests of halon and carbon dioxide fire suppression systems using the National Fire Protection Association Codes and Standards for guidance.

The Fire Protection aging management program will be enhanced to:

1. Provide additional inspection guidance to identify degradation of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling and loss of material.
2. Provide additional inspection guidance for identification of excessive loss of material due to corrosion on the external surfaces of the halon and carbon dioxide systems.

Enhancements will be implemented prior to the period of extended operation.

APPENDIX A A-18 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.18 Fire Water System The Fire Water System aging management program is an existing program that provides for system pressure monitoring, fire system header flushing and flow testing, pump performance testing, hydrant flushing, and visual inspection activities. System flow tests measure hydraulic resistance and compare results with previous testing as a means of evaluating the internal piping conditions.

The program manages loss of material due to corrosion, including MIC, fouling, flow blockage because of fouling, and loss of coating integrity. Major component types include piping, piping components and piping elements, tanks, pump casings, and valve bodies. Monitoring system piping flow characteristics ensures that signs of loss of material will be detected in a timely manner. Monitoring system piping flow characteristics and opportunistic internal inspections of the cement lined fire main ensure that signs of loss of coating integrity will be detected in a timely manner. Within 10 years prior to the PEO, five inspections of the cement lined fire main will be performed.

Pump performance tests, hydrant flushing and system inspections are based on guidance from the applicable National Fire Protection Association (NFPA) standards. The fire water system is normally maintained at required operating pressure and is monitored such that loss of system pressure is immediately detected and corrective actions initiated. Fire system main header flow tests, sprinkler system inspections, visual yard hydrant inspections, hydrostatic tests, gasket inspections, volumetric inspections, and fire hydrant flow tests and pump capacity tests are performed periodically to assure that aging effects are managed such that the system intended functions are maintained.

The Fire Water System aging management program will be enhanced to:

1. Replace sprinkler heads or perform 50-year sprinkler head testing using the guidance of NFPA 25 Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems (2011 Edition),

Section 5.3.1.1.1. This testing will be performed prior to the 50-year in-service date and every 10 years thereafter.

2. Inspect selected portions of the water based fire protection system piping located aboveground and exposed to the fire water internal environment by non-intrusive volumetric examinations. These inspections shall be performed prior to the period of extended operation and will be performed every 10 years thereafter.
3. Inspect and clean line strainers for deluge systems after each actuation.

Strainers for deluge systems subject to periodic full flow testing will be inspected and cleaned on a frequency consistent with the deluge system test frequency.

4. Inspect and clean the foam system water supply strainer after each system actuation and no less than once per refueling interval.
5. Perform external visual inspection of deluge piping and nozzles for the HVAC charcoal filters for signs of leakage, corrosion, physical damage, and correct orientation once per refueling interval.

APPENDIX A A-19 Rev. 18, SEPTEMBER 2016

LGS UFSAR

6. Perform flow tests for the hydraulically most remote hose stations once every five years, scheduling the testing so that some of the tests are performed in each year of the five year interval.
7. Perform a main drain test annually for the fire water piping in each of the following locations: Unit 1 Reactor Enclosure, Unit 2 Reactor Enclosure, Unit 1 Turbine Enclosure, Unit 2 Turbine Enclosure, Control Enclosure, and Radwaste Enclosure. Flow blockage or abnormal discharge identified during flow testing or any change in pressure during the test greater than ten percent at a specific location is entered into the corrective action program for evaluation.
8. Perform charcoal filter deluge valve exercise testing and air flow testing at least once per refueling interval and perform air flow testing for the deluge systems for the hydrogen seal oil units and lube oil reservoirs every two years.
9. Perform the following for Fire Water System sprinkler and deluge systems:

Perform visual internal inspections, consistent with NFPA 25, for corrosion and obstructions to flow on at least five wet pipe sprinkler systems every five years.

Collect and evaluate solids discharged from wet pipe sprinkler system flow testing. Flow testing through the inspector's test valve will be performed on an interval no greater than 18 months for each wet pipe system.

Perform visual internal inspections for corrosion and obstructions to flow for dry pipe preaction sprinkler systems of surfaces made accessible when preaction and water deluge valves are serviced on an interval no greater than a refueling interval.

Perform visual internal inspections for corrosion and obstructions to flow for deluge systems of surfaces made accessible when deluge valves are serviced on at least ten deluge systems on an interval no greater than three years. To provide reasonable assurance of the presence of sufficient coating, two of the ten inspections will be associated with the galvanized transformer deluge system piping.

Perform a visual internal inspection for corrosion and obstructions to flow for any wet pipe, dry pipe preaction, or deluge system after any system actuation prior to return to service.

Perform an obstruction evaluation for conditions that indicate degraded flow.

Perform follow-up volumetric inspections for pipe wall thickness if internal visual inspections detect surface irregularities that could be indicative of wall loss below nominal wall thickness.

APPENDIX A A-20 Rev. 18, SEPTEMBER 2016

LGS UFSAR Sprinkler and deluge systems that are normally dry but may be wetted as the result of testing or actuations will have augmented tests and inspections on piping segments that cannot be drained or piping segments that allow water to collect. These augmented inspections will be performed in each five year interval beginning five years prior to the period of extended operation and consist of either a flow test or flush sufficient to detect potential flow blockage or a visual inspection of 100 percent of the internal surface of piping segments that cannot be drained or piping segments that allow water to collect. In addition, in each five year interval of the period of extended operation, 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect is subject to volumetric wall thickness inspections.

10. Perform wall thickness measurements using UT or other suitable techniques at five selected locations every year to identify loss of material in the carbon steel backup fire water piping. When these examinations identify pipe degradation, additional examinations will be performed in accordance with the following criteria:

At least four additional locations will be examined if wall loss is greater than 50 percent of nominal wall thickness, Two additional locations will be examined if wall loss is 30 percent to 50 percent of nominal wall thickness and the calculated remaining life is less than two years, No additional examinations will be performed if wall loss is less than 30 percent of nominal wall thickness.

These inspections will be performed until the piping degradation no longer meets the criteria for recurring internal corrosion.

Enhancements will be implemented prior to the period of extended operation, with the testing and inspections performed in accordance with the schedule described above.

A.2.1.19 Aboveground Metallic Tanks The Aboveground Metallic Tanks aging management program is an existing program that manages the loss of material aging effect of the Backup Water Storage Tank. Paint is a corrosion preventive measure, and periodic visual inspections will monitor degradation of the paint and any resulting metal degradation of metallic tanks.

The Aboveground Metallic Tanks aging management program will be enhanced to:

APPENDIX A A-21 Rev. 18, SEPTEMBER 2016

LGS UFSAR

1. Include UT measurements of the bottom of the Backup Water Storage Tank. Tank bottom UT inspections will be performed within five years prior to entering the period of extended operation and every five years thereafter.

If no tank bottom plate material loss is identified after the first two inspections, the remaining inspections will be performed whenever the tank is drained during the period of extended operation.

2. Provide visual inspections of the Backup Water Storage Tank external surfaces and include, on a sampling basis, removal of insulation to permit inspection of the tank surface. An inspection performed prior to entering the period of extended operation will include a minimum of 25 locations to demonstrate that the tank painted surface is not degraded under the insulation. Subsequent tank external surface visual inspection will be conducted on a two-year frequency and include a minimum of four locations. Annual visual inspections will be performed of the tank insulation surface for degradation. Rips, tears and gaps in the insulation skin will be repaired. Evidence of water intrusion beneath the insulation will be evaluated in accordance with the LGS corrective action program.
3. Perform visual inspections of the Backup Water Storage Tank wetted and nonwetted internal surfaces. Tank internal inspections will be performed within five years prior to entering the period of extended operation and every five years thereafter. The tank bottom will be inspected for evidence of voids beneath the floor in accordance with NFPA 25, Section 9.2.6.5.

Where pitting and general corrosion to below the nominal wall thickness occurs or any coating failure occurs in which bare metal is exposed, additional inspections and tests shall be performed in accordance with NFPA 25, Section 9.2.7. These tests include adhesion testing of the coating in the vicinity of the coating failure, dry film thickness measurements, spot wet sponge testing, and nondestructive examination to determine remaining wall thickness where bare metal has been exposed.

Tank bottom weld seams in the area of degraded coating will be leak tested in accordance with NFPA 25, Section 9.2.7, by vacuum-box testing or magnetic particle (MT) examination. In addition, adhesion testing shall be performed in the vicinity of blisters even though bare metal may not be exposed.

These enhancements will be implemented prior to the period of extended operation.

APPENDIX A A-22 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.20 Fuel Oil Chemistry The Fuel Oil Chemistry aging management program is an existing mitigation and condition monitoring program that includes activities which provide assurance that contaminants are maintained at acceptable levels in fuel oil for systems and components within the scope of license renewal. The Fuel Oil Chemistry program manages loss of material in piping, piping elements, piping components and tanks in a fuel oil environment. The fuel oil tanks within the scope of license renewal are maintained by monitoring and controlling fuel oil contaminants in accordance with the Technical Specifications, Technical Requirements Manual, and ASTM guidelines. Fuel oil sampling and analysis is performed in accordance with approved procedures for new fuel oil and stored fuel oil. Fuel oil tanks are periodically drained of accumulated water and sediment, cleaned, and internally inspected. These activities effectively manage the effects of aging by maintaining potentially harmful contaminants at low concentrations.

The Fuel Oil Chemistry program also manages the loss of coating integrity in a fuel oil environment. Fuel oil tank internal coatings are visually inspected to ensure that loss of coating integrity is detected. The inspections will be performed by inspectors qualified to international standards endorsed in RG 1.54, including, ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II. Inspections are performed for signs of coating failures and precursors to coating failures including peeling, delamination, blistering, cracking, flaking, chipping, rusting, and mechanical damage. When acceptance criteria are not met, visual inspection is supplemented by additional testing such as DFT (Dry Film Thickness), adhesion, continuity, or other inspection technique as determined by the qualified inspector to accurately assess coating condition.

Adhesion testing will be performed using international standards endorsed in RG 1.54. A coatings specialist qualified to ASTM D-7108 will evaluate the results of the coating inspections. Evaluations are performed for inspection results that do not satisfy established acceptance criteria and the conditions are entered into the LGS 10 CFR 50 Appendix B corrective action program.

The corrective action program ensures that conditions adverse to quality are promptly corrected. Corrective actions may include coating repair or replacement prior to the component being returned to service.

The Fuel Oil Chemistry aging management program will be enhanced to:

1. Periodically drain water from the Fire Pump Engine Diesel Oil Day Tank and the Fire Pump Diesel Engine Fuel Tank.
2. Perform internal inspections of the Fire Pump Engine Diesel Oil Day Tank, the Fire Pump Diesel Engine Fuel Tank, and the Diesel Generator Day Tanks at least once during the 10-year period prior to the period of extended operation, and, at least once every 10 years during the period of extended operation. Each diesel fuel tank will be drained, cleaned and the internal surfaces either volumetrically or visually inspected. If evidence of degradation is observed during visual inspections, the diesel fuel tanks will require follow-up volumetric inspection.

APPENDIX A A-23 Rev. 18, SEPTEMBER 2016

LGS UFSAR

3. Perform periodic analysis for total particulate concentration and microbiological organisms for the Fire Pump Engine Diesel Oil Day Tank and the Fire Pump Diesel Engine Fuel Tank.
4. Perform periodic analysis for water and sediment and microbiological organisms for the Diesel Generator Diesel Oil Storage Tanks.
5. Perform periodic analysis for water and sediment content, total particulate concentration, and the levels of microbiological organisms for the Diesel Generator Day Tanks.
6. Perform analysis of new fuel oil for water and sediment content, total particulate concentration and the levels of microbiological organisms for the Fire Pump Engine Diesel Oil Day Tank and the Fire Pump Diesel Engine Fuel Tank.
7. Perform analysis of new fuel oil for total particulate concentration and the levels of microbiological organisms for the Diesel Generator Diesel Oil Storage Tanks.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.21 Reactor Vessel Surveillance The Reactor Vessel Surveillance aging management program is an existing program that manages the loss of fracture toughness due to neutron irradiation embrittlement of the reactor vessel beltline materials. The program meets the requirements of 10 CFR 50, Appendix H. The program evaluates neutron embrittlement by projecting Upper Shelf Energy (USE) for reactor materials and impact on Adjusted Reference Temperature for the development of pressure-temperature limit curves. Embrittlement evaluations are performed in accordance with Regulatory Guide 1.99, Rev. 2. The Reactor Vessel Surveillance program is part of the BWRVIP Integrated Surveillance Program (ISP) described in BWRVIP-86-A and BWRVIP-116, and approved by the NRC staff. The schedule for removing surveillance capsules is in accordance the timetable specified in BWRVIP-86-A for the current license term and in accordance with BWRVIP-116 for the period of extended operation.

The program monitors plant operating conditions to ensure appropriate steps are taken if reactor vessel exposure conditions are altered; such as the review and updating of 60-year fluence projections to support upper shelf energy calculations and pressure-temperature limit curves. The program also includes condition monitoring by removal and analysis of surveillance capsules as part of the BWRVIP ISP. These measures are effective in detecting the extent of embrittlement to prevent significant degradation of the reactor pressure vessel during the period of extended operation.

APPENDIX A A-24 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.22 One-Time Inspection The One-Time Inspection program is a new condition monitoring program that will be used to verify the system-wide effectiveness of the Water Chemistry (A.2.1.2) program, Fuel Oil Chemistry (A.2.1.20) program, and Lubricating Oil Analysis (A.2.1.27) program which are designed to prevent or minimize aging to the extent that it will not cause a loss of intended function during the period of extended operation. The program manages loss of material, cracking and reduction of heat transfer in piping, piping components, piping elements, heat exchangers, and other components within the scope of license renewal. The program provides inspections focusing on locations that are isolated from the flow stream, that are stagnant, or that have low flow for extended periods and are susceptible to the gradual accumulation or concentration of agents that promote certain aging effects. The inspections will include a representative sample of the system population and will focus on the bounding or lead components most susceptible to aging due to time in service, and severity of operating conditions. The program either verifies that unacceptable degradation is not occurring or triggers additional actions that will assure the intended function of affected components will be maintained during the period of extended operation.

The One-Time Inspection program will be implemented prior to the period of extended operation. The one-time inspections will be performed within the 10 years prior to the period of extended operation.

A.2.1.23 Selective Leaching The Selective Leaching aging management program is a new condition monitoring program that will include one-time inspections of a representative sample of susceptible components to manage loss of material due to selective leaching. Components include piping and fittings, valve bodies, pump casings, heat exchanger components, tanks, and fire hydrants. The materials of construction for these components are gray cast iron, and copper alloy with greater than 15 percent zinc. These components are exposed to raw water, treated water, closed cycle cooling water, waste water, and soil. These one-time inspections for selective leaching will include visual examinations, supplemented by hardness tests or other mechanical techniques as required.

If selective leaching is found, the condition will be evaluated to determine the need to expand inspection scope.

The Selective Leaching program will be implemented prior to the period of extended operation. One-time inspections will be conducted within the five years prior to entering the period of extended operation.

A.2.1.24 One-Time Inspection of ASME Code Class 1 Small-Bore Piping The One-Time Inspection of ASME Code Class 1 Small-Bore Piping aging management program is a new condition monitoring program that will manage the aging effect of cracking in ASME Code Class 1 small-bore piping that is less than nominal pipe size (NPS) 4-inches, and greater than or equal to NPS 1-inch. The program implements one-time inspection of a sample of piping full APPENDIX A A-25 Rev. 18, SEPTEMBER 2016

LGS UFSAR penetration (butt) and partial penetration (socket) welds that are susceptible to cracking using volumetric examinations. The inspection sample size will include at least 10 percent of the butt welds and 25 socket welds within the population of program welds on each LGS unit. Inspection of socket welds will be performed by volumetric examination technique demonstrated to be capable of detecting cracking. If such a volumetric technique is not available by the time of the inspections, the examination method will be by destructive examination. Inspections required by the program will augment ASME Code,Section XI requirements.

Cracking of ASME Code Class 1 small-bore piping due to stress corrosion cracking, cyclical (including thermal, mechanical, and vibration fatigue) loading, thermal stratification or thermal turbulence has not been experienced at LGS Units 1 and 2. Therefore, this one-time inspection program is applicable and adequate to manage this aging effect during the period of extended operation.

A plant specific periodic inspection program will be implemented if evidence of cracking caused by IGSCC or fatigue is revealed in ASME Class 1 small-bore piping.

The One-Time Inspection of ASME Code Class 1 Small-Bore Piping program will be implemented prior to the period of extended operation. One-time inspections will be performed within the six years prior to the period of extended operation.

A.2.1.25 External Surfaces Monitoring of Mechanical Components The External Surfaces Monitoring of Mechanical Components aging management program is a new condition monitoring program that directs visual inspections of external surfaces of components be performed during system inspections and walkdowns. The program consists of periodic visual inspection of metallic and elastomeric components such as piping, piping components, ducting, and other components within the scope of license renewal. The program manages aging effects of metallic and elastomeric materials through visual inspection of external surfaces for evidence of loss of material and cracking. Visual inspections are augmented by physical manipulation as necessary to detect hardening and loss of strength of elastomers.

Inspections are performed at a frequency not to exceed one refueling cycle.

This frequency accommodates inspections of components that may be in locations that are normally only accessible during outages. Surfaces that are not readily visible during plant operations and refueling outages are inspected when they are made accessible and at such intervals that would ensure the components' intended functions are maintained.

A sample of outdoor component surfaces that are insulated and a sample of indoor insulated components exposed to condensation (due to the in-scope component being operated below the dew point), are periodically inspected, under the insulation, every 10 years during the period of extended operation.

Inspections subsequent to the initial inspection will consist of examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation if the initial inspection verifies no loss APPENDIX A A-26 Rev. 18, SEPTEMBER 2016

LGS UFSAR of material beyond that which could have been present during initial construction and no evidence of cracking. If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or if there is evidence of water intrusion through the insulation, then periodic inspections under insulation to detect corrosion under insulation will continue.

The external surfaces of components that are buried are inspected via the Buried and Underground Piping and Tanks (A.2.1.29) program. The external surface of the backup fire water storage tank is inspected via the Aboveground Metallic Tanks (A.2.1.19) program.

This new aging management program will be implemented prior to the period of extended operation.

A.2.1.26 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components aging management program is a new condition monitoring program that directs visual inspections of internal surfaces of components be performed when they are made accessible during maintenance activities. The program consists of visual inspections of metallic and elastomeric components such as piping, piping elements and piping components, ducting components, tanks, heat exchangers, elastomers and other components within the scope of license renewal. This program will manage the aging effects of loss of material, loss of fracture toughness, reduction of heat transfer, and cracking for metallic components, and loss of material and hardening and loss of strength for elastomers. The program includes provisions for visual inspections of the internal surfaces of components not managed under other aging management programs, augmented by physical manipulation of flexible elastomers where appropriate.

This opportunistic approach is supplemented to ensure a representative sample of components within the scope of this program are inspected. At a minimum, in each 10-year period during the period of extended operation, a representative sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 25 components per population is inspected. Where practical, the inspections focus on the bounding or lead components most susceptible to aging because of time in service, and severity of operating conditions.

Opportunistic inspections continue in each 10-year period despite meeting the sampling minimum requirement. For the waste water environment, a maximum of 25 components per population will be inspected. To provide reasonable assurance of the presence of sufficient coating, 10 of the 25 internal inspections will be of the normal waste, oily waste, sanitary waste and storm drain galvanized piping, and 15 of the internal inspections will be of the radioactive floor and equipment drain carbon steel piping.

This new aging management program will be implemented prior to the period of extended operation.

APPENDIX A A-27 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.27 Lubricating Oil Analysis The Lubricating Oil Analysis aging management program is an existing program that provides oil condition monitoring activities to manage the loss of material and the reduction of heat transfer in piping, piping components, piping elements, heat exchangers, and tanks within the scope of license renewal exposed to a lubricating oil environment. Sampling, analysis, and condition monitoring activities identify specific wear products and contamination and determine the physical properties of lubricating oil within operating machinery.

These activities are used to verify that the wear product and contamination levels and the physical properties of lubricating oil are maintained within acceptable limits to ensure that intended functions are maintained.

The Lubricating Oil Analysis program also manages the loss of coating integrity in a lube oil environment. The RCIC turbine bearing pedestals and HPCI turbine bearing pedestals and oil reservoir internal coatings are visually inspected to ensure that loss of coating integrity is detected. The inspections will be performed by inspectors qualified to international standards endorsed in RG 1.54, including, ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II. Inspections are performed for signs of coating failures and precursors to coating failures including peeling, delamination, blistering, cracking, flaking, chipping, rusting, and mechanical damage. When acceptance criteria are not met, visual inspection is supplemented by additional testing such as DFT (Dry Film Thickness), adhesion, continuity, or other inspection technique as determined by the qualified inspector to accurately assess coating condition.

Adhesion testing will be performed using international standards endorsed in RG 1.54. A coatings specialist qualified to ASTM D-7108 will evaluate the results of the coating inspections. Evaluations are performed for inspection results that do not satisfy established acceptance criteria and the conditions are entered into the LGS 10 CFR 50 Appendix B corrective action program.

The corrective action program ensures that conditions adverse to quality are promptly corrected.

A.2.1.28 Monitoring of Neutron-Absorbing Materials Other Than Boraflex The Monitoring of Neutron-Absorbing Materials Other Than Boraflex program is an existing condition monitoring program that periodically analyzes test coupons of the Boral material in the Unit 1 and Unit 2 spent fuel racks to determine if the neutron-absorbing capability of the material has degraded.

This program ensures that a 5 percent sub-criticality margin is maintained in the spent fuel pool.

The Monitoring of Neutron-Absorbing Materials Other Than Boraflex aging management program will be enhanced to:

1. Perform test coupon analysis on a ten-year frequency, beginning no earlier than 2020 for Unit 1 and 2021 for Unit 2.
2. Initiate corrective action if coupon test result data indicates that acceptance criteria will be exceeded prior to the next scheduled test coupon analysis.

APPENDIX A A-28 Rev. 18, SEPTEMBER 2016

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3. Resume the accelerated exposure configuration for the Boral coupons (surrounded by freshly discharged fuel assemblies) at each of five additional refueling cycles, beginning with the next refueling for each unit (2013 for Unit 2, 2014 for Unit 1).
4. Maintain the coupon exposure such that it is bounding for the Boral material in all spent fuel racks, by relocating the coupon tree to a different spent fuel rack cell location each cycle and by surrounding the coupons with a greater number of freshly discharged fuel assemblies than that of any other cell location.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.29 Buried and Underground Piping and Tanks The Buried and Underground Piping and Tanks aging management program is an existing program that manages the external surface aging effects of loss of material for piping and components in a buried or underground environment.

The LGS program activities consist of preventive, mitigative, (i.e., coatings, backfill quality and cathodic protection) and inspection activities to manage, detect and monitor the loss of material due to external corrosion for piping and components within the scope of license renewal that are in a buried or underground environment.

External inspections of buried components will occur opportunistically when they are excavated for any reason.

The Buried and Underground Piping and Tanks aging management program will be enhanced to:

1. If adverse indications are detected during inspection of in-scope buried piping, inspection sample sizes within the affected piping categories are doubled. If adverse indications are found in the expanded sample, an analysis is conducted to determine the extent of condition and extent of cause. The size of the follow-on inspections will be determined based on the extent of condition and extent of cause.
2. Coat the underground Emergency Diesel Generator System fuel oil piping prior to the period of extended operation. The coating will be in accordance with Table 1 of NACE SP0169-2007 or Section 3.4 of NACE RP0285-2002.
3. Perform direct visual inspections and volumetric inspections of the underground Emergency Diesel Generator System fuel oil piping and components during each 10-year period beginning 10 years prior to the entry into the period of extended operation. Prior to the period of extended operation all in scope Emergency Diesel Generator System fuel oil piping and components located in underground vaults will undergo a 100 percent visual inspection. Volumetric inspections will also be performed. After APPENDIX A A-29 Rev. 18, SEPTEMBER 2016

LGS UFSAR entering the period of extended operation, 2 percent of the linear length of in scope Emergency Diesel Generator System fuel oil piping and components located in underground vaults will undergo direct visual inspections and volumetric inspections every 10 years. Inspection locations after entering the period of extended operation will be selected based on susceptibility to degradation and consequences of failure. Visual inspections will be performed by a NACE Coating Inspector Program Level 2 or 3 qualified inspector or an individual that has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.

4. Perform two sets of volumetric inspections of the Safety Related Service Water System underground piping and components during each 10-year period beginning 10 years prior to the entry into the period of extended operation. Each set of volumetric inspections will assess either the entire length of a run of in scope Safety Related Service Water piping and components in the underground vault or a minimum of 10 feet of the linear length of in scope Safety Related Service Water System piping and components in the underground vault. Inspection locations will be selected based on susceptibility to degradation and consequences of failure.
5. Specify that visual inspections of Safety Related Service Water System underground piping and components will be performed by a NACE Coating Inspector Program Level 2 or 3 qualified inspector or an individual that has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.
6. Perform trending of the cathodic protection testing results to identify changes in the effectiveness of the system and to ensure that the rectifiers remain operational at least 85% of the time and cathodic protection effectiveness will be maintained greater than 80%.
7. Modify the yearly cathodic protection survey acceptance criterion to meet NACE SP0169-2007 standards and add a statement that if negative polarized potential exceeds -1100mV relative to copper/copper sulfate electrode an issue report will be entered into the corrective action program.

In performing cathodic protection surveys, the polarized potential criterion of -850mV for copper/copper sulfate reference electrodes (CSEs) will be used to determine cathodic protection system effectiveness. Other standard reference electrodes may be substituted for the CSEs; however their voltage measurements must be converted to the CSE equivalents in accordance with NACE RP0285-2002.

8. Whenever pipe is excavated and damage to the coating is significant and the damage was caused by non-conforming backfill, an extent of condition evaluation should be conducted to ensure that the as-left condition of backfill in the vicinity of observed damage will not lead to further degradation. Visual inspection of coatings will be performed by a NACE Coating Inspector Program Level 2 or 3 qualified inspector or an individual APPENDIX A A-30 Rev. 18, SEPTEMBER 2016

LGS UFSAR that has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.

These enhancements will be implemented prior to the period of extended operation, with the actions performed in accordance with the schedule described above.

A.2.1.30 ASME Section XI, Subsection IWE The ASME Section XI, Subsection IWE aging management program is an existing program based on ASME Code and complies with the provisions of 10 CFR 50.55(a). The program consists of periodic inspection of the primary containment liner plate surfaces and components, including its integral attachments, diaphragm slab carbon steel liner, downcomers and bracing, penetration sleeves, pressure retaining bolting, personnel airlock and equipment hatches, drywell head, and other pressure retaining components for loss of material, loss of preload, loss of leak-tightness, and fretting or lockup.

Examination methods include visual and volumetric testing as required by ASME Section XI, Subsection IWE. Observed conditions that have the potential for impacting an intended function are evaluated for acceptability in accordance with ASME requirements or corrected in accordance with corrective action program.

The ASME Section XI, Subsection IWE aging management program will be enhanced to:

1. Manage the suppression pool liner and coating system to:
a. Remove any accumulated sludge in the suppression pool every refueling outage.
b. Perform an ASME IWE examination of the submerged portion of the suppression pool each ISI period.
c. Use the results of the ASME IWE examination to implement a coating maintenance plan to perform the following prior to the period of extended operation (PEO):

Local areas (less than 2.5 inches in diameter) of general corrosion that are greater than 50 mils plate thickness loss will be recoated in the outage they are identified. This plate thickness loss criterion for local areas will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

Areas of general corrosion greater than 25 mils average plate thickness loss will be recoated based on ranking of affected surface area, high to low. This plate thickness loss criterion for areas of general corrosion will also be used to determine when the APPENDIX A A-31 Rev. 18, SEPTEMBER 2016

LGS UFSAR submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

For plates with greater than 25 percent coating depletion, the affected area will be recoated based on ranking of affected surface area depleted and metal thickness loss.

d. Use the results of the ASME IWE examination to implement a coating maintenance plan to perform the following during the PEO:

Local areas (less than 2.5 inches in diameter) of general corrosion that are greater than 50 mils plate thickness loss will be recoated in the outage they are identified. This plate thickness loss criterion for local areas will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

Areas of general corrosion greater than 25 mils average plate thickness loss will be recoated in the outage they are identified.

This plate thickness loss criterion for areas of general corrosion will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

For plates with greater than 25 percent coating depletion, the affected area will be recoated no later than the next scheduled inspection.

The coating maintenance plan will be initiated in the 2012 refueling outage for Unit 1 and the 2013 refueling outage for Unit 2. The coating maintenance plan will continue through the period of extended operation to ensure the coating protects the liner to avoid significant material loss.

2. Use the results of the ASME IWE inspection of the submerged portions of the suppression pool downcomers to perform the following:

Local areas (less than or equal to 5.5 inches in any direction) that have 40 mils or more metal thickness loss will be recoated. This downcomer metal thickness loss criteria for local areas will also be used to determine when the submerged portions of the downcomers require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

Areas of general corrosion (greater than 5.5 inches in any direction) that have 30 mils or more metal thickness loss will be recoated.

This downcomer metal thickness loss criteria for areas of general corrosion will also be used to determine when the submerged portions of the downcomers require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

APPENDIX A A-32 Rev. 18, SEPTEMBER 2016

LGS UFSAR The downcomer recoat and augmented inspection criteria will be implemented prior to receipt of the renewed licenses.

3. When IWE examinations are conducted, perform ultrasonic thickness measurements on four areas of submerged suppression pool liner affected by general corrosion. The ultrasonic thickness measurement requirements will be implemented prior to receipt of the renewed licenses.
4. Provide guidance for proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.31 ASME Section XI, Subsection IWL The ASME Section XI, Subsection IWL aging management program is an existing program based on ASME Code and complies with the provisions of 10 CFR 50.55(a). The program requires periodic inspection of Containment Structure concrete surfaces to identify areas of deterioration and distress such as defined in ACI 201.1 and ACI 349.3R, including cracking, loss of bond, and loss of material.

Inspection methods, inspected parameters, and acceptance criteria are in accordance with ASME Section XI, Subsection IWL as approved by 10 CFR 50.55(a). Observed conditions that have the potential for impacting an intended function are evaluated for acceptability in accordance with ASME Section XI, Subsection IWL requirements or corrected in accordance with the corrective action program.

The ASME Section XI, Subsection IWL aging management program will be enhanced to:

1. Include second tier acceptance criteria of ACI 349.3R.

This enhancement will be implemented prior to the period of extended operation.

A.2.1.32 ASME Section XI, Subsection IWF The ASME Section XI, Subsection IWF aging management program is an existing program that consists of periodic visual examinations of ASME Class 1, 2, 3, and MC piping and component supports for identification of signs of degradation such as loss of material, loss of mechanical function and loss of pre-load. The program is implemented through corporate and station procedures, which provide inspection and acceptance criteria consistent with the requirements of the ASME Code,Section XI, Subsection IWF as approved in 10 CFR 50.55(a). The monitoring methods are effective in detecting the applicable aging effects, and the frequency of monitoring is adequate to prevent significant degradation.

APPENDIX A A-33 Rev. 18, SEPTEMBER 2016

LGS UFSAR The ASME Section XI, Subsection IWF aging management program will be enhanced to:

1. Provide guidance for proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.33 10 CFR Part 50, Appendix J The 10 CFR Part 50, Appendix J aging management program is an existing program that monitors leakage rates through the containment pressure boundary, including penetrations and other access openings, in order to detect age related degradation of the containment pressure boundary. Corrective actions are taken if leakage rates exceed acceptance criteria. The Primary Containment Leakage Rate Testing Program (LRT) provides for aging management of pressure boundary degradation due to aging effects from the loss of material, loss of sealing, loss of leak tightness, or loss of preload in systems penetrating containment. The Appendix J program also detects degradation of gaskets and seals for the primary containment pressure boundary access points. Consistent with the current licensing basis, the containment leak rate tests are performed in accordance with the regulations and guidance provided in 10 CFR 50 Appendix J Option B, Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, NEI 94-01 Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50 Appendix J, and ANSI/ANS 56.8, Containment System Leakage Testing Requirements.

A.2.1.34 Masonry Walls The Masonry Walls program is an existing program implemented as part of the Structures Monitoring (A.2.1.35) program. Masonry wall condition monitoring is based on guidance provided in IE Bulletin 80-11, "Masonry Wall Design, and NRC Information Notice 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11," and is implemented through station procedures.

The Masonry Walls aging management program addresses loss of material, and cracking due to age-related degradation of concrete for masonry walls and will inspect for shrinkage or separation, along with gaps between the supports and masonry walls. The program relies on periodic visual inspections to monitor and maintain the condition of masonry walls within the scope of license renewal. Masonry walls that are considered fire barriers are also managed by the Fire Protection (A.2.1.17) program.

The Masonry Walls aging management program will be enhanced to:

1. Add the following structures with masonry walls to the program scope:
a. Administration Building Warehouse APPENDIX A A-34 Rev. 18, SEPTEMBER 2016

LGS UFSAR

b. Fuel Oil Pumphouse
c. Transformer foundation dike walls.
2. Provide additional guidance for inspection of masonry walls for shrinkage, separation, and for gaps between the supports and walls that could impact the walls intended function.
3. Require an inspection frequency of not greater than 5 years.
4. Require that personnel performing inspections and evaluations meet the qualifications specified within ACI 349.3R.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.35 Structures Monitoring The Structures Monitoring program is an existing program that was developed to implement the requirements of 10 CFR 50.65 and is based on NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, and Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. The program includes elements of the Masonry Walls (A.2.1.34) program. The program relies on periodic visual inspections to monitor the condition of structures and structural components, structural bolting, component supports, and masonry block walls.

The inspections are conducted on a frequency not to exceed 5 years.

The Structures Monitoring aging management program will be enhanced to:

1. Add the following structures:
a. Admin Building Warehouse
b. Fuel Oil Pumphouse
c. Service Water Pipe Tunnel
d. Yard Structures Aux Fire Water Storage Tank Foundation Backup Fire Pump House and Foundation Well Pump #3 Enclosure and Foundation Railroad Bridge Manholes 001 and 002 Fuel Oil Storage Tank Dike Transformer foundations and dikes
2. Add the following components and commodities:
a. Pipe, electrical, and equipment component support members
b. Pipe whip restraints and jet impingement shields APPENDIX A A-35 Rev. 18, SEPTEMBER 2016

LGS UFSAR

c. Panels, Racks, and other enclosures
d. Sliding surfaces
e. Sump and Pool liners
f. Electrical cable trays and conduits
g. Electrical duct banks
h. Tube tracks
i. Doors
j. Penetration seals
k. Blowout panels
l. Permanent drywell shielding
m. Roof scuppers
3. Monitor groundwater chemistry on a frequency not to exceed 5 years for pH, chlorides, and sulfates and verify that it remains non-aggressive, or evaluate results exceeding criteria to assess impact, if any, on below-grade concrete.
4. Provide guidance for proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting. Revise storage requirements for high strength bolts to include recommendations of Research Council on Structural Connections (RSCS) Specification for Structural Joints Using High Strength Bolts, Section 2.0.
5. Monitor concrete for areas of abrasion, erosion, and cavitation degradation, drummy areas that can exceed the cover concrete thickness in depth, popouts and voids, scaling, and passive settlements or deflections.
6. Perform inspections on a frequency not to exceed 5 years.
7. Perform inspections of sub-drainage sump pit internal concrete on a 5-year frequency as a leading indicator the condition of below grade concrete exposed to ground water.
8. Require that personnel performing inspections and evaluations meet the qualifications specified within ACI 349.3R.
9. Perform inspection of elastomeric vibration isolation elements and structural seals for cracking, loss of material and hardening. Visual inspections of elastomeric vibration isolation elements are to be supplemented by manipulation to detect hardening when vibration isolation function is suspect.

APPENDIX A A-36 Rev. 18, SEPTEMBER 2016

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10. Monitor accessible sliding surfaces to detect significant loss of material due to wear, corrosion, debris, or dirt, that could result in lock-up or reduced movement.
11. Perform opportunistic inspection of below grade portions of in scope structures in the event of excavation which exposes normally inaccessible below grade concrete.
12. Include applicable acceptance criteria from ACI 349.3R.
13. Clarify that loose bolts and nuts and cracked high strength bolts are not acceptable unless accepted by engineering evaluations.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.36 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants The RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants program is an existing program which will be enhanced to provide management of aging effects for water-control structures. The program monitors the condition of the Spray Pond and Pumphouse and the Yard Facilities dikes around the Condensate Storage Tanks (CST) storage tanks. The RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants aging management program addresses age-related deterioration, degradation due to extreme environmental conditions, and the effects of natural phenomena that may affect the intended function of the water-control structures. The program is used to manage conditions such as, loss of material, loss of preload, cracking, loss of bond, loss of material (spalling, scaling) and cracking, increase in porosity and permeability, loss of strength, or loss of form. Elements of the program are designed to detect degradation and take corrective actions to prevent the loss of an intended function.

The RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants aging management program will be enhanced to:

1. Require inspection of structural bolting integrity (loss of material and loosening of the bolts).
2. Require monitoring of aging effects for increase of porosity and permeability of concrete structures and loss of material for steel components.
3. Require the proper functioning of dike drainage systems.
4. Require increased inspection frequency if the extent of the degradation is such that the structure or component may not meet its design basis if allowed to continue uncorrected until the next normally scheduled inspection.

APPENDIX A A-37 Rev. 18, SEPTEMBER 2016

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5. Require (a) evaluation of the acceptability of inaccessible areas when conditions exist in the accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas, and (b) examination of the exposed portions of the below-grade concrete when excavated for any reason.
6. Monitor raw water chemistry at least once every 5 years for pH, chlorides, and sulfates and verify that it remains non-aggressive, or evaluate results exceeding criteria to assess impact, if any, on submerged concrete.
7. Require visual examinations of the Spray Pond and Pumphouse submerged wetwell concrete for signs of degradation during maintenance activities. If significant concrete degradation is identified, a plant specific aging management program should be implemented to manage the concrete aging during the period of extended operation.
8. Require that active cracks in structural concrete or extent of corrosion in steel are documented and trended, until the condition is no longer occurring or until a corrective action is implemented.
9. Require acceptance and evaluation of structural concrete using quantitative criteria based on Chapter 5 of ACI 349.3R.
10. Provide guidance to ensure proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting. Revise storage requirements for high strength bolts to include recommendations of Research Council on Structural Connections (RSCS) Specification for Structural Joints Using High Strength Bolts, Section 2.0.

These enhancements will be implemented prior to the period of extended operation.

A.2.1.37 Protective Coating Monitoring and Maintenance Program The Protective Coating Monitoring and Maintenance Program is an existing condition monitoring program that provides for aging management of Service Level I coatings inside the LGS primary containment in air-indoor and treated water environments. The failure of the Service Level I coatings could adversely affect the operation of the Emergency Core Cooling Systems (ECCS) by clogging the ECCS suction strainers. Proper maintenance of the Service Level I coating ensures that coating degradation will not impact the operability of the ECCS systems. The Protective Coating Monitoring and Maintenance Program provides for coating system visual inspection, assessment, and repair for any condition that adversely affects the ability of Service Level I coatings to function as intended.

Service Level I coatings will prevent or minimize the loss of material due to corrosion but these coatings are not credited for managing the effects of corrosion for the carbon steel containment liners and components at LGS. This program ensures that the Service Level I coatings maintain adhesion so as to not effect the intended function of the ECCS suction strainers.

APPENDIX A A-38 Rev. 18, SEPTEMBER 2016

LGS UFSAR The program also provides controls over the amount of unqualified coating which is defined as coating inside the primary containment that has not passed the required laboratory testing, including irradiation and simulated Design Basis Accident (DBA) conditions. Unqualified coating may fail in a way to affect the intended function of the Emergency Core Cooling Systems (ECCS) suction strainers. Therefore, the quantity of unqualified coating is controlled to ensure that the amount of unqualified coating in the primary containment is kept within acceptable design limits.

The Protective Coating Monitoring and Maintenance Program will be enhanced to:

1. Create the position of Nuclear Coatings Specialist qualified to ASTM D 7108 standards.

This enhancement will be implemented prior to the period of extended operation.

A.2.1.38 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is a new program that will be used to manage aging of the insulation material for non-EQ cables and connections during the period of extended operation. Accessible cables and connections located in adverse localized environments will be visually inspected at least once every 10 years for indications of reduced insulation resistance, such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination. An adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for the cable or connection.

This new program will be implemented prior to the period of extended operation. In addition, the first inspections will be completed prior to the period of extended operation.

A.2.1.39 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits The Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits aging management program is a new program that will be used to manage aging of non-EQ cable and connection insulation of the in scope portions of the Process Radiation Monitoring and Neutron Monitoring Systems.

The in scope process radiation monitoring and neutron monitoring circuits are sensitive instrumentation circuits with high voltage, low-level current signals and are located in areas where the cables and connections could be exposed to adverse localized environments caused by temperature, radiation, or APPENDIX A A-39 Rev. 18, SEPTEMBER 2016

LGS UFSAR moisture. These adverse localized environments can result in reduced insulation resistance causing increases in leakage currents.

Calibration testing will be performed for the in scope process radiation monitoring circuits. Direct cable testing will be performed for the in scope neutron monitoring circuits. These calibration and cable tests will be performed and results will be assessed for reduced insulation resistance prior to the period of extended operation and at least once every 10 years during the period of extended operation.

A.2.1.40 Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is a new program that will be used to manage the aging effects and mechanisms of non-EQ, in scope, inaccessible power cables. For this program, power is defined as greater than or equal to 400 V. These inaccessible power cables may at times be exposed to significant moisture. Power cable exposure to significant moisture may cause reduced insulation resistance that can potentially lead to failure of the cable's insulation system.

The cables in the scope of this aging management program will be tested using a proven test for detecting reduced insulation resistance of the cables insulation system due to wetting or submergence, such as Dielectric Loss (Dissipation Factor or Power Factor), AC Voltage Withstand, Partial Discharge, Step Voltage, Time Domain Reflectometry, Insulation Resistance and Polarization Index, Line Resonance Analysis, or other testing that is state-of-the-art at the time the test is performed. The cables will be tested at least once every 6 years. More frequent testing may occur based on test results and operating experience. The first tests will be completed prior to the period of extended operation.

Periodic actions will be taken to prevent inaccessible cables from being exposed to significant moisture. Manholes associated with the cables included in this aging management program will be inspected for water collection with subsequent corrective actions (e.g., water removal), as necessary. Prior to the period of extended operation, the frequency of inspections for accumulated water will be established and adjusted based on plant specific operating experience with cable wetting or submergence, including water accumulation over time and event driven occurrences such as heavy rain or flooding.

Operation of dewatering devices will be verified prior to any known or predicted heavy rain or flooding event. The first inspections will be completed prior to the period of extended operation. During the period of extended operation, the inspections will occur at least annually.

APPENDIX A A-40 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.2.1.41 Metal Enclosed Bus The Metal Enclosed Bus aging management program is a new program that will be used to manage aging of in scope metal enclosed bus during the period of extended operation. The internal portions of the bus enclosure assemblies will be inspected for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion. The bus insulation will be visually inspected for signs of reduced insulation resistance, such as embrittlement, cracking, chipping, melting, discoloration, swelling or surface contamination. The internal bus insulating supports will be visually inspected for structural integrity and signs of cracks. Enclosure assembly elastomers will be visually inspected for surface cracking, crazing, scuffing, dimensional change, shrinkage, discoloration, hardening, and loss of strength. A sample of accessible bolted connections will be inspected for increased resistance of connection using thermography. The sample will be 20 percent of the accessible metal enclosed bus bolted connection population with a maximum sample size of 25.

The inspections and thermography will be performed at least once every 10 years for indications of aging degradation. This new program will be implemented prior to the period of extended operation. In addition, the first tests and inspections will be completed prior to the period of extended operation.

A.2.1.42 Fuse Holders The Fuse Holders aging management program is a new program that applies to fuse holders located outside of active devices that have been identified as susceptible to aging effects. Fuse holders located inside an active device are not within the scope of this program. This program will be used to manage aging of the metallic portions of fuse holders. Stressors managed by this aging management program include frequent manipulation, vibration, chemical contamination, corrosion, oxidation, ohmic heating, thermal cycling and electrical transients. Fuse holders subject to increased resistance of connection or fatigue, will be tested, by a proven test methodology, at least once every 10 years for indications of aging degradation. Visual inspection is not part of this program.

The new Fuse Holders program will be implemented prior to the period of extended operation. In addition, the first tests will be completed prior to the period of extended operation.

A.2.1.43 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program is a new program. The program will implement one-time testing of a representative sample of non-EQ electrical cable connections to ensure that either increased resistance of connection is not occurring or that the existing preventive maintenance program is effective such that a periodic inspection program is not required. A representative sample of non-EQ electrical cable connections will be selected for one-time APPENDIX A A-41 Rev. 18, SEPTEMBER 2016

LGS UFSAR testing considering application (medium and low voltage), circuit loading (high loading) and location (high temperature, high humidity and vibration). The sample tested will be 20 percent of the population with a maximum sample size of 25 connections. The technical basis for the sample selected is to be documented. The specific type of test performed will be a proven test for detecting increased resistance of connections, such as thermography, contact resistance measurement, or another appropriate test.

The new Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program will be implemented prior to the period of extended operation. The one-time tests will be completed prior to the period of extended operation.

A.2.2 Plant-Specific Aging Management Programs None. Limerick Generating Station, Units 1 and 2 do not have plant-specific aging management programs as a result of License Renewal.

A.3 NUREG-1801 Chapter X Aging Management Programs A.3.1 Evaluation of Chapter X Aging Management Programs Aging Management Programs evaluated in Chapter X of NUREG-1801 are associated with Time-Limited Aging Analysis for metal fatigue of the reactor coolant pressure boundary and environmental qualification (EQ) of electric components. These programs are evaluated in this section.

A.3.1.1 Fatigue Monitoring The Fatigue Monitoring program is an existing program that manages fatigue damage of reactor coolant pressure boundary (RCPB) and other components subject to the reactor coolant, treated water, steam, and air-indoor uncontrolled environments.

The Fatigue Monitoring program is a preventive program that monitors and tracks the number of critical thermal, pressure, and seismic transients to ensure that the cumulative usage factor (CUF) for each analyzed component does not exceed the design limit of 1.0 through the period of extended operation. The program reviews the temperature and pressure profiles of the actual transients and counts them in the appropriate design transient category.

The program compares the cumulative cycles for each design transient to the cycle limits specified in Technical Specification 5.6, UFSAR Table 3.9-2, "Design Events," and Table 5.2-9, RCPB Operating Thermal Cycles.

If a limit is approached, corrective actions are triggered to prevent exceeding the limit. The fatigue analyses may be revised to account for increased numbers of cycles or increased transient severity such that the cumulative usage factor (CUF) does not exceed the design limit of 1.0, including environmental effects where applicable.

The effect of the reactor coolant environment on RCPB component fatigue life has been determined by performing environmental fatigue analyses for APPENDIX A A-42 Rev. 18, SEPTEMBER 2016

LGS UFSAR locations selected using NUREG/CR-6260 guidance. Additional environmental fatigue analyses were performed for limiting locations within the RPV and for each RCPB system. Environmentally-adjusted cumulative usage factors (CUFen) were computed in accordance with the requirements specified in NUREG/CR-6909 for each material.

The Fatigue Monitoring aging management program will be enhanced to:

1. Monitor additional plant transients that are significant contributors to fatigue usage and to impose administrative transient cycle limits corresponding to the limiting numbers of cycles used in the environmental fatigue calculations.

This enhancement will be implemented prior to the period of extended operation.

A.3.1.2 Environmental Qualification (EQ) of Electric Components The Environmental Qualification (EQ) of Electric Components is an existing program that manages the aging of electrical equipment within the scope of 10 CFR 50.49, Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants. The program establishes, demonstrates, and documents the level of qualification, qualified configurations, maintenance, surveillance and replacements necessary to meet 10 CFR 50.49. A qualified life is determined for equipment within the scope of the program and appropriate actions such as replacement or refurbishment are taken prior to or at the end of the qualified life of the equipment so that the aging limit is not exceeded. The various aging effects addressed by this program are adequately managed so that the intended functions of components within the scope of 10 CFR 50.49 are maintained consistent with the current licensing basis during the period of extended operation.

A.4 Time-Limited Aging Analyses A.4.1 Identification of Time-Limited Aging Analyses As part of the application for a renewed license, 10 CFR 54.21(c) requires that an evaluation of Time-Limited Aging Analyses (TLAAs) for the period of extended operation be provided.

10 CFR 54.21(c)(2) requires that the application for a renewed license include a list of plant-specific exemptions granted pursuant to 10 CFR 50.12 and in effect that are based upon TLAAs as defined in 10 CFR 54.3. It also requires an evaluation that justifies the continuation of these exemptions for the period of extended operation. Only two exemptions were identified that are based upon a TLAA. These were associated with Pressure-Temperature (P-T) limits developed using exemptions to 10 CFR 50 Appendix G to permit use of ASME Code Cases N-588 and N-640. Continuation of these exemptions into the PEO is acceptable because the use of Code Cases N-588 and N-640 as a basis for the 32 EFPY P-T limits was approved by the NRC without a limitation with respect to plant operation beyond the original license term. In addition, this is justified because the provisions of Code Cases N-588 and N-640 utilized in APPENDIX A A-43 Rev. 18, SEPTEMBER 2016

LGS UFSAR developing the current P-T limit curves remain acceptable since they were incorporated into the ASME Code,Section XI, Appendix G, in the 1998 Edition through 2000 Addenda, as described in Regulatory Issue Summary (RIS) 2004-04, and this Code was approved for use as described in 10 CFR 50.55a (b)(2).

A.4.2 Reactor Pressure Vessel Neutron Embrittlement Analysis 10 CFR 50.60 requires that all light-water reactors meet the fracture toughness, P-T limits, and material surveillance program requirements for the reactor coolant pressure boundary as set forth in 10 CFR 50 Appendices G and H.

The reactor pressure vessel embrittlement calculations for LGS that evaluated reduction of fracture toughness of the Unit 1 and Unit 2 reactor pressure vessel beltline materials for 40 years are based upon a predicted End of License fluence of 32 Effective Full Power Years (EFPY). These analyses are considered TLAAs as defined in 10 CFR 54.21(c) and they were evaluated for the increased neutron fluence associated with 60 years of operation as described in the subsections below.

A.4.2.1 Neutron Fluence Projections High energy (>1 MeV) neutron fluence was calculated for the RPV beltline welds and shells using the Radiation Analysis Model Application (RAMA)

Fluence Methodology. Use of this model was performed in accordance with NRC Regulatory Guide 1.190. This RAMA methodology was used to develop 60-year, 57 EFPY fluence values for LGS. The 57 EFPY fluence projections are used in the evaluations of the neutron embrittlement TLAAs.

The 57 EFPY fluence projections have been determined for reactor vessel beltline materials, which include the reactor vessel plate materials, welds, and forgings that will be exposed to 1.0 E+17 neutrons/cm2 (n/cm2) or more during 60 years of operation. Fluence projections have also been determined for specific reactor vessel internals components, both to evaluate fluence-based TLAAs and to determine when specified fluence threshold values may be exceeded that are used to invoke specific aging management requirements for these components, such as inspections.

A.4.2.2 Upper-Shelf Energy 10 CFR 50 Appendix G, Paragraph IV.A.1.a, requires that the reactor vessel beltline materials must maintain Charpy upper-shelf energy (USE) throughout the life of the vessel of no less than 50 ft-lb, unless it is demonstrated in a manner approved by the Director, Office of Nuclear Regulation, that lower values of Charpy upper-shelf energy will provide margins of safety against fracture equivalent to those required by Appendix G of Section XI of the ASME Code.

Upper Shelf Energy (USE) values were computed for all LGS beltline materials that will be exposed to over 1.0 E+17 n/cm2 by the end of the period of extended operation (57 EFPY). The 57 EFPY USE values for the beltline materials were determined using methods consistent with Regulatory Guide 1.99, Revision 2.

APPENDIX A A-44 Rev. 18, SEPTEMBER 2016

LGS UFSAR The USE values for LGS beltline materials remain within the limits of 10 CFR 50 Appendix G requirements at 57 EFPY, either by having USE values of at least 50 ft-lb or through an equivalent margins analysis (EMA). Therefore, the analyses are projected for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

A.4.2.3 Adjusted Reference Temperature The adjusted reference temperature (ART) of the limiting beltline material is used to adjust the beltline P-T limits to account for irradiation effects. The initial nil-ductility reference temperature, RTNDT, is the temperature at which a non-irradiated metal (ferritic steel) changes in fracture characteristics from ductile to brittle behavior. RTNDT is evaluated according to the procedures in the ASME Code,Section III. Neutron embrittlement increases the RTNDT beyond its initial value.

10 CFR 50 Appendix G defines the fracture toughness requirements for the life of the vessel. The shift in the initial RTNDT ( RTNDT) is evaluated as the difference in the 30 ft-lb index temperatures from the average Charpy curves measured before and after irradiation. This increase ( RTNDT) means that higher temperatures are required for the material to continue to act in a ductile manner. The ART is defined as Initial RTNDT + RTNDT + Margin. The Margin term is defined in Regulatory Guide 1.99, Revision 2.

ART values were computed for LGS beltline materials in accordance with Regulatory Guide 1.99, Revision 2. The ART values of the limiting beltline materials at 57 EFPY for each unit remain below 200 degrees F, which is the RTNDT limit.

The analysis for the adjusted reference temperature has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

A.4.2.4 Pressure - Temperature Limits 10 CFR 50 Appendix G requires that the reactor pressure vessel be maintained within established (P-T) limits, including heatup and cooldown operations.

These limits specify the maximum allowable pressure as a function of reactor coolant temperature. As the reactor pressure vessel is exposed to increased neutron irradiation, its fracture toughness is reduced. The P-T limits must account for the anticipated reactor vessel fluence.

The current P-T limits are based upon 32 EFPY fluence projections, consistent with the amount of power to be generated over 40 years of plant operation.

The P-T limits satisfy the criteria of 10 CFR 54.3(a) and have been identified as TLAAs.

In accordance with NUREG-1800, Revision 2, Section 4.2.2.1.3, the P-T limits for the period of extended operation need not be submitted as part of the LRA since the P-T limits need to be updated through the 10 CFR 50.90 licensing process when necessary for P-T limits that are located in the Technical Specifications (TS). It further states that for those plants that have approved APPENDIX A A-45 Rev. 18, SEPTEMBER 2016

LGS UFSAR pressure-temperature limit reports (PTLRs), the P-T limits for the period of extended operation will be updated at the appropriate time through the plants Administrative Section of the TS and the plants PTLR process. In either case, the 10 CFR 50.90 or the PTLR processes, which constitute the current licensing basis, will ensure that the P-T limits for the period of extended operation will be updated prior to expiration of the P-T limit curves for the current period of operation.

The LGS P-T limits are included in the Technical Specifications and updated P-T limits will be approved for use prior to 32 EFPY for each unit, which is prior to the period of extended operation. Maintenance of the P-T limits during the period of extended operation will be managed using the applicable process from those described above, in accordance with 10 CFR 54.21(c)(1)(iii).

A.4.2.5 Axial Weld Inspection The BWRVIP recommendations for inspection of reactor pressure vessel shell welds in BWRVIP-05 include examination of 100 percent of the axial welds and inspection of the circumferential welds only at the intersections of these welds with the axial welds. BWRVIP-05 contains generic analyses supporting a conclusion in the NRC Final Safety Evaluation Report (FSER) that the generic-plant axial weld failure rate is orders of magnitude greater than the 40-year end-of-life circumferential weld failure probability and used this analysis to justify relief from inspection of the circumferential welds. The failure frequency is dependent upon given assumptions of flaw density, distribution, and location. Since the axial weld failure probability assessment is based on 32 EFPY fluence values associated with 40 years of operation, it has been identified as a TLAA requiring evaluation for the period of extended operation.

The LGS axial weld failure probability has been projected for the period of extended operation. In order to evaluate the axial weld failure probability assessment for 60 years, 57 EFPY fluence values were derived for the limiting axial weld. Using the 57 EFPY fluence values, the LGS Mean RTNDT values were computed for each unit and compared to the NRC analytical results for 64 EFPY provided in the FSER to BWRVIP-05. Although a conditional failure probability has not been calculated for the LGS units, the fact that the LGS Mean RTNDT values for the period of extended operation are significantly less than the NRC value leads to the conclusion that the Unit 1 and 2 conditional failure probability is bounded by the NRC analysis, consistent with the requirements defined in GL 98-05. This analysis has been projected through the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

A.4.2.6 Circumferential Weld Inspection ASME Section XI governs the inspection of the reactor pressure vessel circumferential welds, as implemented by the LGS In-service Inspection Program. LGS has received inspection relief for circumferential welds for the remainder of the 40-year license period. The circumferential weld failure probability assessment is based on 32 EFPY fluence values associated with 40 years of operation and has been identified as a TLAA requiring evaluation for the period of extended operation.

APPENDIX A A-46 Rev. 18, SEPTEMBER 2016

LGS UFSAR In order to evaluate the LGS circumferential weld failure probability assessment for 60 years, 57 EFPY fluence values were derived for the limiting circumferential weld. Using the 57 EFPY fluence values, the LGS Mean RTNDT values were computed for each unit and compared to the NRC analytical results for 64 EFPY provided in the FSER to BWRVIP-05. Although a conditional failure probability has not been calculated for the LGS units, the fact that the LGS Mean RTNDT values for the period of extended operation are significantly less than the NRC value leads to the conclusion that the LGS conditional failure probability is bounded by the NRC analysis, consistent with the requirements defined in GL 98-05.

The effects of aging on the reactor pressure vessel intended functions will be managed in accordance with 10 CFR 54.21(c)(1)(iii) for the period of extended operation by reapplication for circumferential weld examination relief under 10 CFR 50.55a (a)(3). The plant-specific information described above demonstrates that at the end of the renewal period, the circumferential welds meet the limiting conditional failure probability for circumferential welds specified in the FSER of BWRVIP-05. Operator training and procedures will continue to be utilized during the license renewal term to limit cold over-pressure events.

A.4.2.7 Reactor Pressure Vessel Reflood Thermal Shock A generic fracture mechanics evaluation was performed in 1979 to evaluate the effects of a postulated Loss of Coolant Accident (LOCA) on the structural integrity of a BWR-6 reactor pressure vessel. The LOCA event considered was a rupture of a main steam line, which was determined to bound all other LOCA events with respect to this evaluation. Several emergency core cooling systems are activated at different times after the LOCA and the vessel is flooded with cooling water. The vessel blowdown and the subsequent injection of cold water produce low temperature and high thermal stresses in the vessel.

This analysis concluded that the reactor pressure vessel has a considerable margin to failure by brittle fracture even in the presence of large postulated initial flaws. This generic analysis envelopes LGS and is based on BWR vessel material properties and cumulative fluence assumed for 40 years of operation. Therefore, this analysis has been identified as a TLAA requiring evaluation for the period of extended operation.

An updated 60-year fracture mechanics evaluation was performed for the reflood thermal shock event using plant-specific reactor pressure vessel data for LGS. The analysis determined that during the period of extended operation for both units, there is sufficient toughness margin to prevent fracture due to reflood thermal shock. An existing flaw in the reactor pressure vessel would not propagate due to brittle fracture during a LOCA.

The reactor pressure vessel reflood thermal shock analysis has been projected for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

APPENDIX A A-47 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.4.3 Metal Fatigue Metal fatigue was considered explicitly in the design process for pressure boundary components designed in accordance with ASME Section III, Class A or Class 1 requirements. Metal fatigue was evaluated implicitly for components designed in accordance with ASME Section III, Class 2 or 3 requirements or ANSI B31.1 requirements. These fatigue analyses and fatigue exemptions are considered to be Time-Limited Aging Analyses (TLAAs) requiring evaluation for the period of extended operation in accordance with 10 CFR 54.21(c).

A.4.3.1 ASME Section III, Class 1 Fatigue Analyses The LGS reactor pressure vessel (RPV) and reactor coolant pressure boundary (RCPB) piping and components were designed in accordance with the ASME Code Section III, Class 1 requirements. Fatigue analyses were prepared for these components to determine the effects of cyclic loadings resulting from changes in system temperature and pressure and for seismic loading cycles.

These Class 1 fatigue analyses are included in stress reports that evaluated an explicit number and type of transients to envelope the number of occurrences projected during the 40-year design life of the plant. These stress reports include fatigue analyses and fatigue exemptions, where applicable, that have been identified as TLAAs since they are based upon 40-year design transients.

Each analysis was required to demonstrate that the Cumulative Usage Factor (CUF) for the component will not exceed the design limit of 1.0 when the component is exposed to all of the postulated transients. The Class 1 valve analyses were required to demonstrate that the valves can be operated for a minimum of 2,000 cycles and that the fatigue usage factor for step changes in fluid temperature It does not exceed a limit of 1.0.

The calculation of fatigue usage factors is part of the current licensing basis and is used to support safety determinations and since the number of occurrences of each transient type was based upon 40-year assumptions, these Class 1 fatigue analyses and fatigue exemptions have been identified as time-limited aging analyses.

Each of the Class 1 fatigue analyses and fatigue exemptions was evaluated for 60 years by determining that the numbers of cycles assumed in the 40-year analysis will remain bounding of the numbers of cycles projected for the component through the end of the period of extended operation. These 60-year projections were based upon cumulative cycles to-date plus future cycles predicted based upon the average rates of past occurrences. In order to ensure that these fatigue analyses and fatigue exemptions remain valid, the Fatigue Monitoring program will be used to ensure the cycle limits are not exceeded during the period of extended operation. The program includes requirements that trigger corrective action if a transient approaches a cycle limit. Corrective action may include reanalysis of affected Class 1 components to address increased numbers of cycles, repair, or replacement of the component.

The effects of aging on the intended functions of components analyzed in accordance with ASME Section III, Class 1 requirements will be adequately APPENDIX A A-48 Rev. 18, SEPTEMBER 2016

LGS UFSAR managed for the period of extended operation by the Fatigue Monitoring program in accordance with 10 CFR 54.21(c)(1)(iii).

A.4.3.2 ASME Section III, Class 2 and 3 and ANSI B31.1 Allowable Stress Calculations Piping designed in accordance with ASME Section III, Class 2 or 3 design rules or ANSI B31.1 Piping Code design rules is not required to have an explicit analysis of cumulative fatigue usage, but cyclic loading is considered in the design process. If the numbers of anticipated thermal cycles exceed specified limits, these codes require the application of a stress range reduction factor to the allowable stress to prevent damage from cyclic loading. This is considered to be an implicit fatigue analysis since it is based upon cycles anticipated for the life of the component.

These codes first require the overall number of thermal and pressure cycles expected during the 40-year lifetime of these components to be determined. A stress range reduction factor is then determined for that number of cycles using the applicable design code. If the total number of cycles is 7,000 or less, the stress range reduction factor of 1.0 is applied which would not reduce the allowable stress values. For higher numbers of cycles, the stress range reduction factor limits the allowable stresses that can be applied to the piping.

For the piping and components that are affected by the reactor vessel operational transients, including the Class 2 and 3 piping extending from Class 1 systems, the 60-year cycle projections demonstrate that the total number of thermal and pressure cycles will not exceed 7,000 cycles during the period of extended operation. The effects of aging on the intended function(s) of components will be adequately managed for the period of extended operation by the Fatigue Monitoring program in accordance with 10 CFR 54.21(c)(1)(iii).

For the remaining systems that are affected by different thermal and pressure cycles, an operational review was performed that also concluded that the total number of cycles, projected for the period of extended operation, will not exceed 7,000 cycles for these systems. This includes portions of the Fire Protection, Emergency Diesel Generator, and Auxiliary Steam systems.

Systems with operating temperatures below specified thresholds were determined to have low numbers of equivalent full temperature cycles since the fluid temperature changes are small. For these systems, the maximum allowable stress range values for the existing fatigue analysis remain valid in accordance with 10 CFR 54.21(c)(1)(i) because the allowable limit for the number of full thermal range transient cycles will not be exceeded during the period of extended operation.

A.4.3.3 Environmental Fatigue Analyses for RPV and Class 1 Piping NUREG-1800, Revision 2 provides a recommendation for evaluating the effects of the reactor water environment on the fatigue life of ASME Section III Class 1 components that contact reactor coolant. One method to satisfy this recommendation is to assess the impact of the reactor coolant environment on a sample of critical components as described in NUREG/CR-6260. Additional APPENDIX A A-49 Rev. 18, SEPTEMBER 2016

LGS UFSAR component locations are evaluated if they are considered to be more limiting than those considered in NUREG/CR-6260.

Environmental fatigue calculations were performed for component locations listed in NUREG/CR-6260 for the newer-vintage BWR. In order to ensure that any other locations that may not be bounded by the NUREG/CR-6260 locations were evaluated, environmental fatigue calculations were performed for each RPV component location that has a reported cumulative usage factor (CUF) in the RPV stress report and for each ASME Class 1 RCPB piping system.

These environmental fatigue calculations were performed for the limiting wetted location for each material within the component that contacts reactor coolant.

NUREG-1800, Revision 2, specifies options for evaluating environmental effects. The formulae specified in the option listed below for each material were used in evaluating the LGS components for environmental effects:

Carbon and Low Alloy Steels Those provided in Appendix A of NUREG/CR-6909, using either the applicable ASME Section III fatigue design curve or the fatigue design curve for carbon and low alloy steel provided in NUREG/CR-6909 (Figure A.1 and A.2, respectively, and Table A.1).

Austenitic Stainless Steels The formula provided in NUREG/CR-6909, using the fatigue design curve for austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2).

Nickel Alloys The formula provided in NUREG/CR-6909, using the fatigue design curve for austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2).

Additional refinements were performed as appropriate and several locations required a reduction in the numbers of postulated cycles. The resulting environmentally-adjusted CUF values (CUFen) were demonstrated not to exceed the design Code limit of 1.0.

These environmental fatigue analyses will be managed by the Fatigue Monitoring program in the same manner as all other Class 1 fatigue analyses.

The program ensures that the cumulative number of occurrences of each transient type is maintained below the number of cycles used in the most limiting fatigue analysis.

If a cycle limit is approached, corrective actions are triggered to prevent exceeding the limit. The fatigue analyses may be revised to account for increased numbers of cycles or transient severity such that the CUF value does not exceed the Code design limit of 1.0, including environmental effects where applicable.

APPENDIX A A-50 Rev. 18, SEPTEMBER 2016

LGS UFSAR Prior to the period of extended operation, the Fatigue Monitoring program will be enhanced to impose administrative transient cycle limits corresponding to the limiting numbers of cycles used in the environmental fatigue calculations.

The effects of aging on the intended functions will be adequately managed for the period of extended operation by the LGS Fatigue Monitoring program in accordance with 10 CFR 54.21(c)(1)(iii).

A.4.3.4 Reactor Vessel Internals Fatigue Analyses The RPV and RPV internal components were included in the NSSS New Loads Design Adequacy Evaluations performed for each unit to address the effects of plant-specific seismic loadings and suppression pool hydrodynamic structural loadings on NSSS equipment. These evaluations included fatigue analyses of components if the applied loadings exceed certain thresholds. These fatigue analyses and fatigue exemptions have been identified as TLAAs that require evaluation for the period of extended operation.

The fatigue analyses and fatigue exemptions performed for the reactor internals components are based upon the same set of design transients as those used in the fatigue analyses for the reactor pressure vessel. Transient cycle projections were prepared that demonstrate the design transient cycle limits will not be exceeded in 60 years. In order to ensure that these fatigue analyses and fatigue exemptions will remain valid, the Fatigue Monitoring program will be used to manage fatigue of these components through the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).

A.4.3.5 High-Energy Line Break (HELB) Analyses Based Upon Fatigue High Energy Line Break (HELB) analyses for LGS used the CUF values from the ASME Class 1 fatigue analyses as input in determining intermediate break locations. Since the Class 1 fatigue analyses that provided the CUF values are based upon 40-year transient assumptions, these analyses have been identified as TLAAs.

Transient cycle projections were performed that determined the 40-year transient cycle limits will not be exceeded in 60 years. The Class 1 piping fatigue analyses were demonstrated to remain valid for the period of extended operation. Therefore, the HELB break determinations based upon these fatigue analyses will also remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.4.4 Environmental Qualification (EQ) of Electric Components A.4.4.1 Environmental Qualification (EQ) of Electric Components Thermal, radiation, and cyclical aging analyses of plant electrical and I&C components, developed to meet 10 CFR 50.49 requirements, have been identified as time-limited aging analyses (TLAAs) for LGS. The NRC has established nuclear station environmental qualification (EQ) requirements in 10 CFR 50.49 and 10 CFR 50, Appendix A, Criterion 4. 10 CFR 50.49 specifically requires that an EQ program be established to demonstrate that APPENDIX A A-51 Rev. 18, SEPTEMBER 2016

LGS UFSAR certain electrical components located in harsh plant environments are qualified to perform their safety function in those harsh environments after the effects of inservice aging. Harsh environments are defined as those areas of the plant that could be subject to the harsh environmental effects of a loss-of-coolant accident (LOCA), high energy line break (HELB), or post-LOCA radiation.

10 CFR 50.49 requires that the effects of significant aging mechanisms be addressed as part of environmental qualification.

The Environmental Qualification (EQ) of Electric Components (A.3.1.2) program will manage the effects of aging effects for the components associated with the environmental qualification TLAA. This program implements the requirements of 10 CFR 50.49 (as further defined and clarified by NUREG-0588, and RG 1.89, Rev. 1). Component aging evaluations are reanalyzed on a routine basis to extend the qualifications of components as part of the LGS EQ Program. Important attributes for the reanalysis of an aging evaluation include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met). The Environmental Qualification (EQ) of Electric Components (A.3.1.2) program methodology is further described in Appendix A, Section A.3.1.2.

Under the LGS EQ Program, the reanalysis of an aging evaluation could extend the qualification of the component. If the qualification cannot be extended by reanalysis, the component must be refurbished, replaced, or requalified prior to exceeding the period for which the current qualification remains valid. A reanalysis is to be performed in a timely manner such that sufficient time is available to refurbish, replace, or requalify the component if the reanalysis is unsuccessful.

A.4.5 Containment Liner and Penetrations Fatigue Analysis A.4.5.1 Containment Liner and Penetrations Fatigue Analysis The LGS primary containment liner and penetrations were designed and analyzed for transient cycles predicted to occur in 40 years. The Class 1 flued-head penetrations were also analyzed for fatigue using cycles predicted to occur for 40 years. These analyses have been identified as TLAAs.

Transient cycle projections were performed that determined the 40-year transient cycle limits will not be exceeded in 60 years. This includes startup and shutdown cycles and Design Basis Accident events. An operational review was performed for the MSRV lift cycles that concluded the total number of cycles, projected for 60 years, will not exceed the number analyzed for 40 years. Therefore, the analyses remain valid for the period of extended operation in accordance with 10 CFR 54-21(c)(1)(i).

APPENDIX A A-52 Rev. 18, SEPTEMBER 2016

LGS UFSAR A.4.6 Other Plant-Specific Time-Limited Aging Analyses A.4.6.1 Reactor Enclosure Crane Cyclic Loading Analysis The LGS reactor enclosure crane is designed to meet the fatigue requirements of the Crane Manufacturers Association of America (CMAA) Specification 70 for a Class A, Standby or Infrequent Service Crane, as discussed in UFSAR Section 9.1.5.2, "Reactor Enclosure Crane, Equipment Design." This evaluation of cycles over the 40-year plant life is the basis of a safety determination and has been identified as a TLAA that requires evaluation for the period of extended operation.

The reactor enclosure crane was purchased as a Class A crane and can be considered a crane experiencing irregular occasional use followed by long idle periods. For this crane, the CMAA design considerations allow a minimum of 20,000 cycles.

The evaluation of the reactor enclosure crane cyclic load limit TLAA included (1) reviewing the existing 40-year design basis to determine the number of load cycles considered in the design of the crane, (2) developing a 60-year projection for load cycles for the crane, and (3) comparing the 60-year projected number of cycles to the minimum allowable design value of 20,000 cycles. The number of cycles projected for 60 years of operation is 3,468 cycles, which is less than 20 percent of the minimum allowable design value.

Therefore, the reactor enclosure crane load cycle fatigue analysis remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.4.6.2 Emergency Diesel Generator Enclosure Cranes Cyclic Loading Analysis LGS has eight emergency diesel generator enclosure cranes. These cranes were designed to meet or exceed the design fatigue requirements of the Crane Manufacturers Association of America (CMAA) Specification 70 for Class A, Standby or Infrequent Service Cranes. The evaluation of cycles expected over the 40-year life has been identified as a TLAA that requires evaluation for the period of extended operation.

The emergency diesel generator enclosure cranes were evaluated for the period of extended operation by developing 60-year projections for crane load cycles and comparing these projected cycles to the number of cycles evaluated for the design life of the cranes. The emergency diesel generator enclosure cranes were purchased as Class A cranes. They are considered to be cranes experiencing irregular occasional use followed by long idle periods." For this category of crane, the CMAA design requirements permit a minimum of 20,000 load cycles.

The 60-year load cycle projection includes all load cycles and is based on an estimated 500 load cycles during original construction and 50 load cycles per year during diesel generator maintenance. The 3,500 load cycles are less than 20 percent of the allowable design value of 20,000 cycles. Therefore, the analysis of the emergency diesel generator enclosure cranes remains valid for the period of extended operation.

APPENDIX A A-53 Rev. 18, SEPTEMBER 2016

LGS UFSAR The analysis remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.4.6.3 RPV Core Plate Rim Hold-Down Bolt Loss of Preload The RPV core plate is attached to the core support structure by stainless steel hold-down bolts that are preloaded during initial installation. These bolts are subject to stress relaxation (loss of preload) due to irradiation effects. An analysis was performed concluding that a reduction in preload as high as 19 percent over the 40-year life of the bolts is acceptable to meet design requirements. A subsequent re-evaluation determined that this maximum relaxation value of 19 percent is applicable to an average fluence level of 8.0 E+19 n/cm2 over the entire length of the bolt located at the azimuthal location with peak fluence. These analyses were identified as TLAAs.

In order to determine if these analyses will remain valid for 60 years, RAMA fluence projections were prepared for LGS for 57 EFPY for the core plate rim bolt located at the azimuthal location with peak fluence. In order to determine the average fluence value along the length of the bolt, fluence projections were made at 75 discrete points along the length of the bolt on the bolt surface nearest the core. These results were integrated and divided by the length of the bolt, resulting in an average fluence value of 3.37 E+19 n/cm2 along the length of the bolt. This is well below the average fluence of 8.0 E+19 n/cm2 value previously evaluated. Therefore, the analysis remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.4.6.4 Main Steam Line Flow Restrictors Erosion Analysis A main steam line flow restrictor is welded into each of the four main steam lines between the main steam relief valves and the inboard main steam isolation valve (MSIV). The restrictor assemblies consist of a stainless steel venture-type nozzle welded into the carbon steel main steam line piping. The restrictors are designed to limit steam flow prior to MSIV closure in the event of a main steam line break outside of primary containment.

There is no specific analysis of main steam line flow restrictor erosion other than that discussed in UFSAR Section 5.4.4. The UFSAR indicates that very slow erosion occurs with time and such slight enlargement has no safety significance. Since the erosion evaluation could have assumed 40 years of operation, erosion of the main steam line flow restrictor has been identified as a TLAA that requires evaluation for the period of extended operation.

Calculations indicate that even with erosion rates as high as 0.004 inch per year, the increase in choked flow rate would be no more than 5 percent after 40 years of operation, and no more than 10 percent after 60 years. The LGS Main Steam Line Break dose calculation determined that the mass of coolant leaving the reactor through the main steam line break is 108,785 lb, but uses 140,000 lb to determine the dose impact from this event. Therefore, sufficient margin exists in the dose calculation to accommodate the postulated erosion of the main steam line flow restrictor through the end of the period of extended operation.

APPENDIX A A-54 Rev. 18, SEPTEMBER 2016

LGS UFSAR The analysis remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.4.6.5 Jet Pump Auxiliary Spring Wedge Assembly Auxiliary spring wedge assemblies have been designed and installed in LGS jet pumps to maintain lateral support for the jet pump inlet mixer. The design analysis considered potential aging effects based upon a design life of 40 years, including fatigue usage and loss of preload due to neutron fluence.

These analyses have been identified as TLAAs.

The jet pump auxiliary spring wedge assembly is not an ASME Code component, but it was evaluated using stress and fatigue limits of the ASME Code as guidelines. The cumulative fatigue usage was determined to be 0.77 using the original design basis load cycles from the reactor vessel thermal cycle diagram. The 60-year transient projections for LGS demonstrate that these transient cycle limits will not be exceeded in 60 years of operation.

Therefore, the fatigue TLAA remains valid for the period of extended operation.

The auxiliary spring wedge assembly design analysis also evaluated loss of preload due to integrated neutron fluence of 1.4 E+20 n/cm2 for 40 years. In order to evaluate loss of bolt preload during the period of extended operation, the maximum service life was first determined. The first Unit 1 wedge assembly installed will have a service life of 41 years by the end of the period of extended operation, and the first Unit 2 wedge assembly will have a service life of 45 years.

The RAMA fluence projections were used to determine how long the auxiliary spring wedge assemblies could remain in service before the analyzed fluence value of 1.4 E+20 n/cm2 would be reached. The fluence projections for the jet pump riser brace location were used since they are bounding for the locations of the auxiliary spring wedge assembly. The evaluation determined that the auxiliary spring wedge assemblies will not reach the previously evaluated fluence value of 1.4 E+20 n/cm2. Therefore, the loss of preload TLAA also remains valid for the period of extended operation in accordance with 10CFR 54.21(c)(1)(i).

A.4.6.6 Jet Pump Restrainer Bracket Pad Repair Clamps Visual inspections at LGS have found wear at the inlet-mixer wedge/restrainer bracket pad interface on several jet pumps. A repair clamp has been designed and installed that replaces the support function of the restrainer bracket pad.

The repair clamp design analysis evaluated end-of-life preload relaxation for 40 years based upon a 5 percent decrease due to thermal and radiation effects.

This analysis was identified as a TLAA.

The fluence value used to determine the loss of preload in the design analysis is five percent higher than the fluence value calculated for the repair location for a 40-year service life. Since the first clamps were installed in Unit 2 in 2009 and no clamps have been installed in Unit 1, these clamps will have a maximum service life of 40.25 years. Therefore, since the repair clamp design APPENDIX A A-55 Rev. 18, SEPTEMBER 2016

LGS UFSAR analysis includes an allowance for loss of preload that is bounding for 42 years, the analysis remains valid in accordance with 10 CFR 54.21(c)(1)(i).

The repair clamp design analysis also evaluated fatigue for 40 years, which was identified as a TLAA. The clamping loads do not cycle except for the load changes associated with startup/shutdown temperature changes. The maximum calculated stress amplitude is 7,781 psi, which is within the American Society of Mechanical Engineers (ASME) Code stress limit for 304 stainless steel of 13,600 psi for 1011cycles, and the General Electric Hitachi design limit of 10,000 psi for flow-induced vibration stress cycles. Since the calculated cyclic loads of 7,781 psi are less than these limits, fatigue usage will be insignificant for up to 1011 startup/shutdown cycles. Therefore the fatigue analysis remains valid through the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.4.6.7 Refueling Bellows and Supports Cyclic Loading Analysis The refueling bellows and supports were analyzed for cycles predicted to occur in 40 years. Therefore, these fatigue analyses have been identified as TLAAs that require evaluation for the period of extended operation.

Transient cycle projections were performed that determined the 40-year transient cycle limits will not be exceeded in 60 years based upon the average rate of occurrence to-date. The analyses remain valid for the period of extended operation in accordance with 10 CFR 54-21(c)(1)(i).

A.4.6.8 Downcomers and MSRV Discharge Piping Fatigue Analyses The downcomers and bracing inside the suppression chamber and the MSRV discharge piping quenchers have been evaluated for transient cycles predicted to occur in 40 years. Therefore, these fatigue analyses have been identified as TLAAs.

The downcomers and bracing were analyzed for a minimum of 7,700 MSRV stress cycles that were considered to account for the pool dynamic loads, based on 1,100 actuations of all MSRVs times seven stress cycles per actuation. For the most frequently actuated MSRVs, the analysis was based on 4,700 actuations times three stress cycles per actuation (14,100 total cycles). They were also analyzed for 3,000 chugging cycles that could occur following a LOCA event, 50 OBE cycles (five events with ten cycles per event),

and ten SSE cycles (one event with ten cycles). The quenchers were analyzed for 7,000 MSRV actuations (opening and closing cycles) and 1,000,000 irregular condensation load cycles.

An operational review was performed for MSRV actuations that concluded the total number of MSRV actuations, projected for 60 years, will not exceed the number analyzed for 40 years in either unit. The 60-year projection for Unit 1 is 211 actuations and for Unit 2 is 138 actuations, which are well below the 1100 actuations analyzed. No OBE or SSE event has occurred to-date and neither has a 60-year projection that exceeds the design limit of one event. The Fatigue Monitoring program is credited for managing fatigue of these components in accordance with 10 CFR 54.21 (c)(1)(iii) by ensuring that the APPENDIX A A-56 Rev. 18, SEPTEMBER 2016

LGS UFSAR analyzed numbers of cycles are not exceeded during the period of extended operation.

The MSRV discharge lines were analyzed for significant thermal and pressure transients defined for the Main Steam system and for the same MSRV, chugging, OBE and SSE cycles described above for the downcomers. Each of these transients has been evaluated and shown to have 60-year projections that do not exceed the numbers of cycles analyzed. The Fatigue Monitoring program is credited for managing fatigue of these components in accordance with 10 CFR 54.21 (c)(1)(iii) by ensuring that the analyzed numbers of cycles are not exceeded during the period of extended operation.

A.4.6.9 Jet Pump Slip Joint Repair Clamps Jet pump slip joint repair clamps have been designed and installed at LGS to minimize vibration and wear of the jet pump assemblies. The structural evaluation determined the loss of preload that would result from neutron fluence during the design life of the clamps. This analysis was identified as a TLAA. The maximum service life of the slip joint clamps from initial installation through the period of extended operation will be less than 40 years for the Unit 1 clamps and less than 45 years for the Unit 2 clamps. RAMA fluence projections for each unit have determined the maximum fluence the slip joint clamps can receive during their service life. These fluence values are less than the fluence value used to determine the loss of preload allowance applied in the structural evaluation of the clamps. Therefore, the jet pump slip joint clamp design analysis for loss of preload due to neutron fluence remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.4.6.10 Fuel Pool Girder Loss of Prestress The design analysis of the LGS Fuel Pool Girders has been identified as a plant-specific TLAA because it includes a time-limited evaluation of loss of prestress of the fuel pool girders. The girder analysis used a 4% stress relaxation value that is based upon stress relaxation test data, projected for 1,000,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> (114 years), which is a time-limited assumption. The TLAA remains valid in accordance with 10 CFR 54.21(c)(1)(i) because the loss of prestress values used in the analysis were demonstrated to remain valid through the period of extended operation.

A.4.6.11 RHR and Core Spray Suction Strainer Fatigue Analyses The design analyses for the RHR and Core Spray suction strainers have been identified as TLAAs because they include a time-limited fatigue analysis of the stainless steel bolting and stainless steel strainer assembly. These analyses were based upon 34,200 MSRV stress cycles (11,400 actuations), 10 SSE stress cycles (1 event), 50 OBE cycles (5 events), and condensation oscillation and chugging cycles that would result from LOCA events. These are the same types of transients analyzed for the downcomers described in LRA Section 4.6.8.

APPENDIX A A-57 Rev. 18, SEPTEMBER 2016

LGS UFSAR The Fatigue Monitoring program is credited for managing fatigue of the RHR and Core Spray strainer assemblies and bolting, in accordance with 10 CFR 54.21(c)(1)(iii).

APPENDIX A A-58 Rev. 18, SEPTEMBER 2016

LGS UFSAR Note: This table contains commitments related to the renewed LGS operating licenses. Because these commitments are contained within the UFSAR, any potential changes to these commitments require evaluation in accordance with 10 CFR 50.59 as defined per the Exelon commitment management process. In addition, that process must be followed to ensure that the commitment tracking database is updated with the latest commitment implementation information. Refer to PIMS AR A1813863 and Passport AR 1232104 for LGS license renewal commitment tracking data.

A.5 License Renewal Commitment List IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 1 ASME Section XI Existing program is credited. Ongoing Section A.2.1.1 Inservice Inspection, Subsections IWB, IWC, and IWD 2 Water Chemistry Existing program is credited. Ongoing Section A.2.1.2 3 Reactor Head Closure Existing program is credited. Ongoing Section A.2.1.3 Stud Bolting 4 BWR Vessel ID Existing program is credited. Ongoing Section A.2.1.4 Attachment Welds 5 BWR Feedwater Existing program is credited. Ongoing Section A.2.1.5 Nozzle 6 BWR Control Rod BWR Control Rod Drive Return Line Nozzle is an Program to be Section A.2.1.6 Drive Return Line existing program that will be enhanced to: enhanced prior to the Nozzle period of extended

1. Specify an extended volumetric inspection of the operation.

nozzle-to-cap weld to assure that the inspection includes base metal to a distance of one pipe wall thickness or 0.5 inches, whichever is greater, on both sides of the weld.

APPENDIX A A-59 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 7 BWR Stress Corrosion Existing program is credited. Ongoing Section A.2.1.7 Cracking 8 BWR Penetrations Existing program is credited. Ongoing Section A.2.1.8 9 BWR Vessel Internals BWR Vessel Internals is an existing program that will be Program to be Section A.2.1.9 enhanced to: enhanced prior to the period of extended

1. Perform an assessment of the susceptibility of operation.

reactor vessel internal components fabricated from Cast Austenitic Stainless Steel (CASS) to loss of The initial inspections fracture toughness due to thermal aging will be performed embrittlement. If material properties cannot be either prior to or determined to perform the screening, they will be within 5 years after assumed susceptible to thermal aging for the entering the period of purposes of determining program examination extended operation.

requirements.

2. Perform an assessment of the susceptibility of reactor vessel internal components fabricated from Cast Austenitic Stainless Steel (CASS) to loss of fracture toughness due to neutron irradiation embrittlement.
3. Specify the required periodic inspection of CASS components determined to be susceptible to loss of fracture toughness due to thermal aging and neutron irradiation embrittlement.

APPENDIX A A-60 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 10 Flow-Accelerated Existing program is credited. Ongoing Section A.2.1.10 Corrosion 11 Bolting Integrity Bolting Integrity is an existing program that will be Program to be Section A.2.1.11 enhanced to: enhanced prior to the period of extended LGS letter dated

1. Provide guidance to ensure proper specification of operation. 3/12/2012 bolting material, lubricant and sealants, storage, and RAI 3.2.2.1.1-1 installation torque or tension to prevent or mitigate degradation and failure of closure bolting for pressure retaining components.
2. Prohibit the use of lubricants containing molybdenum disulfide for closure bolting for pressure retaining components.
3. Minimize the use of high strength bolting (actual measured yield strength equal to or greater than 150 ksi) for closure bolting for pressure retaining components. High strength bolting, if used, will be monitored for cracking.
4. Perform visual inspection of bolting for the Residual Heat Removal System, Core Spray System, High Pressure Coolant Injection System and Reactor Core Isolation Cooling System suppression pool suction strainers for loss of material and loss of preload during each ISI inspection interval.

APPENDIX A A-61 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 12 Open-Cycle Cooling Open-Cycle Cooling Water System is an existing Program to be Section A.2.1.12 Water System program that will be enhanced to: enhanced prior to the period of extended LGS Letter dated

1. Perform internal inspection of buried Safety Related operation. 2/15/12 Service Water Piping when it is accessible during RAI B.2.1.12-1 maintenance and repair activities. Inspection schedule RAI B.2.1.12-2 identified in
2. Perform periodic inspections for loss of material in commitment. LGS letter dated the Nonsafety-Related Service Water System at a 6/22/12 minimum of five locations on each unit once every RAI B.2.1.12-3 refueling cycle.

LGS Letter dated

3. Replace the supply and return piping for the Core 3/14/14 Spray pump compartment unit coolers. RAI 3.0.3-1
4. Replace degraded RHRSW piping in the pipe LGS letter dated tunnel. 05/21/14 RAI 3.0.3.4-1
5. Perform periodic inspections for loss of material in the Safety Related Service Water System at a minimum of ten locations every two years.

The Open-Cycle Cooling Water System aging management program also manages the loss of coating integrity in the service water side of the Main Control Room Chiller Condensers and Reactor Enclosure Cooling Water Heat Exchangers, and, in circulating water system piping.

APPENDIX A A-62 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE As described below, baseline inspections will occur in the 10-year period prior to the period of extended operation. The maximum interval of subsequent coating inspections will comply with Table 4a of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014 (ADAMS Accession No. ML13262A442).

The inspection of the Main Control Room Chiller Condensers will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.

The inspection of the Reactor Enclosure Cooling Water Heat Exchangers will be performed by inspectors with a demonstrated working knowledge of EPRI Report 1019157, Guideline on Nuclear Safety-Related Coatings.

The inspection of 73 one-foot axial length circumferential segments of coated circulating water system piping will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.

The acceptance criteria for coating degradation and the requirements for physical inspections when degradation is identified will be in accordance with Element 6 of GALL Report AMP XI.M42 in draft APPENDIX A A-63 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE LR-ISG-2013-01 dated January 6, 2014.

13 Closed Treated Water Closed Treated Water Systems is an existing program Program to be Section A.2.1.13 Systems that will be enhanced to: enhanced prior to the period of extended LGS Letter dated

1. Perform condition monitoring and performance operation. 4/13/12 monitoring, including periodic testing and RAI B.2.1.13-2.1 opportunistic and periodic NDE, to verify the Inspection schedule effectiveness of water chemistry control to mitigate identified in aging effects. A representative sample of piping commitment.

and components will be selected based on likelihood of corrosion and inspected at an interval not to exceed once in 10 years during the period of extended operation.

2. Perform condition monitoring for the loss of material due to cavitation erosion in the reactor enclosure cooling water piping to the 2A Reactor Water Cleanup System (RWCU) non-regenerative heat exchanger. An initial inspection frequency of 4 years has been established. The inspection frequency will be re-evaluated and adjusted as necessary based on trend data.

14 Inspection of Inspection of Overhead Heavy Load and Light Load Program to be Section A.2.1.14 Overhead Heavy Load (Related to Refueling) Handling Systems is an existing enhanced prior to the and Light Load program that will be enhanced to: period of extended (Related to Refueling) operation.

Handling Systems 1. Perform annual periodic inspections as defined in the appropriate ASME B30 series standard for all cranes, APPENDIX A A-64 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE hoists, and equipment handling systems within the scope of license renewal. For handling systems that are infrequently in service, such as those only used during refueling outages, annual periodic inspections may be deferred until just prior to use.

2. Perform inspections of structural components and bolting for loss of material due to corrosion, rails for loss of material due to wear and corrosion, and bolted connections for loss of preload.
3. Evaluate loss of material due to wear or corrosion and any loss of bolting preload on cranes, hoists, and equipment handling systems per the appropriate ASME B30 series standard.
4. Perform repairs to cranes, hoists, and equipment handling systems per the appropriate ASME B30 series standard.

15 Compressed Air Compressed Air Monitoring is an existing program that Program to be Section A.2.1.15 Monitoring will be enhanced to: enhanced prior to the period of extended LGS letter dated

1. Perform periodic analysis and trending of air quality operation. 2/15/12 monitoring results. RAI B.2.1.15-1 16 BWR Reactor Water Existing program is credited. Ongoing Section A.2.1.16 Cleanup System APPENDIX A A-65 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 17 Fire Protection Fire Protection is an existing program that will be Program to be Section A.2.1.17 enhanced to: enhanced prior to the period of extended

1. Provide additional inspection guidance to identify operation.

degradation of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling and loss of material.

2. Provide additional inspection guidance for identification of excessive loss of material due to corrosion on the external surfaces of the halon and carbon dioxide systems.

18 Fire Water System Fire Water System is an existing program that will be Program to be Section A.2.1.18 enhanced to: enhanced prior to the period of extended LR-ISG-2012-02

1. Replace sprinkler heads or perform 50-year operation. review sprinkler head testing using the guidance of NFPA 03/12/2014 25 Standard for the Inspection, Testing and Inspection schedule Maintenance of Water-Based Fire Protection identified in LGS Letter dated Systems (2011 Edition), Section 5.3.1.1.1. This commitment. 3/14/14 testing will be performed prior to the 50-year RAI 3.0.3-1 in-service date and every 10 years thereafter.

LGS Letter dated

2. Inspect selected portions of the water based fire 5/21/14 protection system piping located aboveground and RAI 3.0.3.3.1-1 exposed to the fire water internal environment by RAI 3.0.3.4-1 non-intrusive volumetric examinations. These inspections shall be performed prior to the period of APPENDIX A A-66 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE extended operation and will be performed every 10 years thereafter.

3. Inspect and clean line strainers for deluge systems after each actuation. Strainers for deluge systems subject to full flow testing will be inspected and cleaned on a frequency consistent with the deluge test frequency.
4. Inspect and clean the foam system water supply strainer after each system actuation and no less than once per refueling interval.
5. Perform external visual inspection of deluge piping and nozzles for the HVAC charcoal filters for signs of leakage, corrosion, physical damage, and correct orientation once per refueling interval.
6. Perform flow tests for the hydraulically most remote hose stations once every five years, scheduling the testing so that some of the tests are performed in each year of the five year interval.
7. Perform a main drain test annually for the fire water piping in each of the following locations: Unit 1 Reactor Enclosure, Unit 2 Reactor Enclosure, Unit 1 Turbine Enclosure, Unit 2 Turbine Enclosure, Control Enclosure, and Radwaste Enclosure. Flow blockage or abnormal discharge identified during APPENDIX A A-67 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE flow testing or any change in pressure during the test greater than ten percent at a specific location is entered into the corrective action program for evaluation.

8. Perform charcoal filter deluge valve exercise testing and air flow testing at least once per refueling interval and perform air flow testing for the deluge systems for the hydrogen seal oil units and lube oil reservoirs every two years.
9. Perform the following for Fire Water System sprinkler and deluge systems:

Perform visual internal inspections, consistent with NFPA 25, for corrosion and obstructions to flow on at least five wet pipe sprinkler systems every five years.

Collect and evaluate solids discharged from wet pipe sprinkler system flow testing. Flow testing through the inspector's test valve will be performed on an interval no greater than 18 months for each wet pipe system.

Perform visual internal inspections for corrosion and obstructions to flow for dry pipe preaction sprinkler systems of surfaces made accessible when preaction and water APPENDIX A A-68 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE deluge valves are serviced on an interval no greater than a refueling interval.

Perform visual internal inspections for corrosion and obstructions to flow for deluge systems of surfaces made accessible when deluge valves are serviced on at least ten deluge systems on an interval no greater than three years. To provide reasonable assurance of the presence of sufficient coating, two of the ten inspections will be associated with the galvanized transformer deluge system piping.

Perform a visual internal inspection for corrosion and obstructions to flow for any wet pipe, dry pipe preaction, or deluge system after any system actuation prior to return to service.

Perform an obstruction evaluation for conditions that indicate degraded flow.

Perform followup volumetric inspections for pipe wall thickness if internal visual inspections detect surface irregularities that could be indicative of wall loss below nominal wall thickness.

APPENDIX A A-69 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE Sprinkler and deluge systems that are normally dry but may be wetted as the result of testing or actuations will have augmented tests and inspections on piping segments that cannot be drained or piping segments that allow water to collect. These augmented inspections will be performed in each five year interval beginning five years prior to the period of extended operation and consist of either a flow test or flush sufficient to detect potential flow blockage or a visual inspection of 100 percent of the internal surface of piping segments that cannot be drained or piping segments that allow water to collect. In addition, in each five year interval of the period of extended operation, 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect is subject to volumetric wall thickness inspections.

10. Perform wall thickness measurements using UT or other suitable techniques at five selected locations every year to identify loss of material in the carbon steel backup fire water piping. When these examinations identify pipe degradation, additional examinations will be performed in accordance with the following criteria:

APPENDIX A A-70 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE At least four additional locations will be examined if wall loss is greater than 50 percent of nominal wall thickness, Two additional locations will be examined if wall loss is 30 percent to 50 percent of nominal wall thickness and the calculated remaining life is less than two years, No additional examinations will be performed if wall loss is less than 30 percent of nominal wall thickness.

The Fire Water System aging management program also manages the loss of coating integrity in the buried cement lined fire main header.

System flow testing activities measure system hydraulic resistance as a means of evaluating the internal piping condition.

Opportunistic internal inspections evaluate the condition of the cement lined fire main header.

Within 10 years prior to the PEO, five internal visual inspections of the cement lining in the fire main header will be performed.

APPENDIX A A-71 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 19 Aboveground Metallic Aboveground Metallic Tanks is an existing program that Program to be Section A.2.1.19 Tanks will be enhanced to: enhanced prior to the period of extended LGS Letter dated

1. Include UT measurements of the bottom of the operation. 2/15/12 Backup Water Storage Tank. Tank bottom UT RAI B.2.1.19-1 inspections will be performed within five years prior Inspection schedule RAI B.2.1.19-2 to entering the period of extended operation and identified in every five years thereafter. If no tank bottom plate commitment. LR-ISG-2012-02 material loss is identified after the first two review inspections, the remaining inspections will be 03/12/2014 performed whenever the tank is drained during the period of extended operation. LGS Letter dated 5/21/14
2. Provide visual inspections of the Backup Water RAI 3.0.3.3.3-1 Storage Tank external surfaces and include, on a RAI 3.0.3.3.3-2 sampling basis, removal of insulation to permit inspection of the tank surface. An inspection performed prior to entering the period of extended operation will include a minimum of 25 locations to demonstrate that the tank painted surface is not degraded under the insulation. Subsequent tank external surface visual inspection will be conducted on a two year frequency and include a minimum of four locations. Annual visual inspections will be performed of the tank insulation surface for degradation. Rips, tears, and gaps in the insulation skin will be repaired. Evidence of water intrusion beneath the insulation will be evaluated in accordance with the LGS corrective action program.

APPENDIX A A-72 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE

3. Perform visual inspections of the Backup Water Storage Tank wetted and nonwetted internal surfaces. Tank internal inspections will be performed within five years prior to entering the period of extended operation and every five years thereafter. The tank bottom will be inspected for evidence of voids beneath the floor in accordance with NFPA 25, Section 9.2.6.5. Where pitting and general corrosion to below the nominal wall thickness occurs or any coating failure occurs in which bare metal is exposed, additional inspections and tests shall be performed in accordance with NFPA 25, Section 9.2.7. These tests include adhesion testing of the coating in the vicinity of the coating failure, dry film thickness measurements, spot wet sponge testing, and nondestructive examination to determine remaining wall thickness where bare metal has been exposed. Tank bottom weld seams in the area of degraded coating will be leak tested in accordance with NFPA 25, Section 9.2.7, by vacuum-box testing or magnetic particle (MT) examination. In addition, adhesion testing shall be performed in the vicinity of blisters even though bare metal may not be exposed.

20 Fuel Oil Chemistry Fuel Oil Chemistry is an existing program that will be Program to be Section A.2.1.20 enhanced to: enhanced prior to the period of extended

1. Periodically drain water from the Fire Pump Engine operation.

APPENDIX A A-73 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE Diesel Oil Day Tank and the Fire Pump Diesel LGS Letter dated Engine Fuel Tank. Inspection schedule 3/14/14 identified in RAI 3.0.3-1

2. Perform internal inspections of the Fire Pump commitment.

Engine Diesel Oil Day Tank, the Fire Pump Diesel LGS letter dated Engine Fuel Tank, and the Diesel Generator Day 05/21/14 Tanks, at least once during the 10-year period prior RAI 3.0.3.4-1 to the period of extended operation and at least once every 10 years during the period of extended operation. Each diesel fuel tank will be drained, cleaned and the internal surfaces either volumetrically or visually inspected. If evidence of degradation is observed during visual inspections, the diesel fuel tanks will require follow-up volumetric inspection.

3. Perform periodic analysis for total particulate concentration and microbiological organisms for the Fire Pump Engine Diesel Oil Day Tank and the Fire Pump Diesel Engine Fuel Tank.
4. Perform periodic analysis for water and sediment and microbiological organisms for the Diesel Generator Diesel Oil Storage Tanks.
5. Perform periodic analysis for water and sediment content, total particulate concentration, and the levels of microbiological organisms for the Diesel Generator Day Tanks.

APPENDIX A A-74 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE

6. Perform analysis of new fuel oil for water and sediment content, total particulate concentration and the levels of microbiological organisms for the Fire Pump Engine Diesel Oil Day Tank and the Fire Pump Diesel Engine Fuel Tank.
7. Perform analysis of new fuel oil for total particulate concentration and the levels of microbiological organisms for the Diesel Generator Diesel Oil Storage Tanks.

The Fuel Oil Chemistry aging management program also manages the loss of coating integrity in the eight main fuel oil storage tanks.

Each fuel oil tank will be internally inspected at least once during the 10-year period prior to the period of extended operation and at least once every 10 years during the period of extended operation The inspection of the eight main fuel oil storage tanks will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II The acceptance criteria for coating degradation and the requirements for physical inspections when degradation is identified will be in accordance with APPENDIX A A-75 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE Element 6 of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014.

21 Reactor Vessel Existing program is credited. Ongoing Section A.2.1.21 Surveillance 22 One-Time Inspection One-Time Inspection is a new program that will be used Program to be Section A.2.1.22 to verify the system-wide effectiveness of the Water implemented prior to Chemistry, Fuel Oil Chemistry and Lubricating Oil the period of Analysis programs. extended operation.

One-time inspections will be performed within the 10 years prior to the period of extended operation.

23 Selective Leaching Selective Leaching is a new program that will include Program to be Section A.2.1.23 one-time inspections of a representative sample of implemented prior to susceptible components to determine if loss of material the period of due to selective leaching is occurring. extended operation.

One-time inspections will be performed within the five years prior to the period of extended operation APPENDIX A A-76 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 24 One-Time Inspection One-Time Inspection of ASME Code Class 1 Small-Bore Program to be Section A.2.1.24 of ASME Code Class Piping is a new program that will manage the aging implemented prior to 1 Small-Bore Piping effect of cracking in stainless steel and carbon steel the period of Class 1 small-bore piping that is less than nominal pipe extended operation.

size (NPS) 4-inches, and greater than or equal to NPS 1-inch. One-time Inspections will be performed within the six years prior to the period of extended operation.

25 External Surfaces External Surfaces Monitoring of Mechanical Program to be Section A.2.1.25 Monitoring of Components is a new program that manages aging implemented prior to Mechanical effects of metallic and elastomeric materials through the period of LR-ISG-2012-02 Components periodic visual inspection of external surfaces for extended operation. review evidence of loss of material. Visual inspections are 03/12/2014 augmented by physical manipulation as necessary to detect hardening and loss of strength of elastomers.

A sample of outdoor component surfaces that are insulated and a sample of indoor insulated components exposed to condensation (due to the in-scope component being operated below the dew point), are periodically inspected, under the insulation, every 10 years during the period of extended operation.

Inspections subsequent to the initial inspection will consist of examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation if the initial APPENDIX A A-77 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE inspection verifies no loss of material beyond that which could have been present during initial construction. If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or if there is evidence of water intrusion through the insulation, then periodic inspections under insulation to detect corrosion under insulation will continue.

26 Inspection of Internal Inspection of Internal Surfaces in Miscellaneous Piping Program to be Section A.2.1.26 Surfaces in and Ducting Components is a new program that implemented prior to Miscellaneous Piping manages aging effects of metallic and elastomeric the period of LR-ISG-2012-02 and Ducting materials through visual inspections of internal surfaces extended operation. review Components for evidence of loss of material. Visual inspections are 03/12/2014 augmented by physical manipulation as necessary to detect hardening and loss of strength of elastomers. LGS letter dated 05/21/14 This opportunistic approach is supplemented to ensure a RAI 3.0.3.4-1 representative sample of components within the scope of this program are inspected. At a minimum, in each 10-year period during the period of extended operation, a representative sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 25 components per population is inspected. Where practical, the inspections focus on the bounding or lead components most susceptible to aging because of time in service, and severity of operating conditions.

Opportunistic inspections continue in each 10-year period despite meeting the sampling minimum APPENDIX A A-78 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE requirement. For the waste water environment, a maximum of 25 components per population will be inspected. To provide reasonable assurance of the presence of sufficient coating, 10 of the 25 internal inspections will be of the normal waste, oily waste, sanitary waste and storm drain galvanized piping, and 15 of the internal inspections will be of the radioactive floor and equipment drain carbon steel piping.

27 Lubricating Oil Existing program is credited. Ongoing Section A.2.1.27 Analysis The Lube Oil Analysis aging management program also LGS Letter dated manages the loss of coating integrity in the RCIC turbine 3/14/14 bearing pedestals and HPCI turbine bearing pedestals RAI 3.0.3-1 and oil reservoir.

LGS letter dated As described below, baseline inspections will occur 05/21/14 in the 10-year period prior to the period of extended RAI 3.0.3.4-1 operation. The maximum interval of subsequent coating inspections will comply with Table 4a of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014 (ADAMS Accession No. ML13262A442).

The inspection of the RCIC turbine bearing pedestals and HPCI turbine bearing pedestals and oil reservoir will be performed by inspectors qualified to ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.

APPENDIX A A-79 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE The acceptance criteria for coating degradation and the requirements for physical inspections when degradation is identified will be in accordance with Element 6 of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014.

28 Monitoring of Monitoring of Neutron-Absorbing Materials Other than Program to be Section A.2.1.28 Neutron-Absorbing Boraflex is an existing program that will be enhanced to: enhanced prior to the Materials Other than period of extended LGS Letter dated Boraflex 1. Perform test coupon analysis on a ten-year operation. 2/28/12 frequency, beginning no earlier than 2020 for RAI B.2.1.28-1 Unit 1 and 2021 for Unit 2. Inspection schedule identified in LGS Letter dated

2. Initiate corrective action if coupon test result data commitment. 4/27/12 indicates that acceptance criteria will be RAI B.2.1.28-2 exceeded prior to the next scheduled test coupon analysis.
3. Resume the accelerated exposure configuration for the Boral coupons (surrounded by freshly discharged fuel assemblies) at each of five additional refueling cycles, beginning with the next refueling for each unit (2013 for Unit 2, 2014 for Unit 1).
4. Maintain the coupon exposure such that it is bounding for the Boral material in all spent fuel racks, , by relocating the coupon tree to a different spent fuel rack cell location each cycle APPENDIX A A-80 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE and by surrounding the coupons with a greater number of freshly discharged fuel assemblies than that of any other cell location.

29 Buried and Buried and Underground Piping and Tanks is an existing Program to be Section A.2.1.29 Underground Piping program that will be enhanced to: enhanced prior to the and Tanks period of extended LGS Letter dated

1. If adverse indications are detected during inspection operation. 2/15/12 of in-scope buried piping, inspection sample sizes RAI B.2.1.29-2 within the affected piping categories are doubled. If Inspection schedule RAI B.2.1.29-3 adverse indications are found in the expanded identified in sample, an analysis is conducted to determine the commitment. LGS Letter dated extent of condition and extent of cause. The size of 3/30/12 the follow-on inspections will be determined based RAI B.2.1.29-2.1 on the extent of condition and extent of cause.

LGS Letter dated

2. Coat the underground Emergency Diesel Generator 6/17/2013 System fuel oil piping prior to the period of extended ISG-2011-03 operation. The coating will be in accordance with Table 1 of NACE SP0169-2007 or Section 3.4 of LGS Letter dated NACE RP0285-2002. 8/6/13 RAI B.2.1.29-4
3. Perform direct visual inspections and volumetric inspections of the underground Emergency Diesel Generator System fuel oil piping and components during each 10-year period beginning 10 years prior to the entry into the period of extended operation. Prior to the period of extended operation all in scope Emergency Diesel Generator System APPENDIX A A-81 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE fuel oil piping and components located in underground vaults will undergo a 100 percent visual inspection. Volumetric inspections will also be performed. After entering the period of extended operation, 2 percent of the linear length of in scope Emergency Diesel Generator System fuel oil piping and components located in underground vaults will undergo direct visual inspections and volumetric inspections every 10 years. Inspection locations after entering the period of extended operation will be selected based on susceptibility to degradation and consequences of failure. Visual inspections will be performed by a NACE Coating Inspector Program Level 2 or 3 qualified inspector or an individual that has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.

4. Perform two sets of volumetric inspections of the Safety Related Service Water System underground piping and components during each 10-year period beginning 10 years prior to the entry into the period of extended operation. Each set of volumetric inspections will assess either the entire length of a run of in scope Safety Related Service Water System piping and components in the underground vault or a minimum of 10 feet of the linear length of in scope Safety Related Service Water System APPENDIX A A-82 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE piping and components in the underground vault. Inspection locations will be selected based on susceptibility to degradation and consequences of failure.

5. Specify that visual inspections of Safety Related Service Water System underground piping and components will be performed by a NACE Coating Inspector Program Level 2 or 3 qualified inspector or an individual that has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.
6. Perform trending of the cathodic protection testing results to identify changes in the effectiveness of the system and to ensure that the rectifiers remain operational at least 85% of the time, and cathodic protection effectiveness will be maintained greater than 80%.
7. Modify the yearly cathodic protection survey acceptance criterion to meet NACE SP0169-2007 standards and add a statement that if negative polarized potential exceeds -1100mV relative to copper/copper sulfate electrode an issue report will be entered into the corrective action program. In performing cathodic protection surveys, the polarized potential criterion of -850mV for APPENDIX A A-83 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE copper/copper sulfate reference electrodes (CSEs) will be used to determine cathodic protection system effectiveness. Other standard reference electrodes may be substituted for the CSEs; however their voltage measurements must be converted to the CSE equivalents in accordance with NACE RP0285-2002.

8. Whenever pipe is excavated and damage to the coating is significant and the damage was caused by non-conforming backfill, an extent of condition evaluation should be conducted to ensure that the as-left condition of backfill in the vicinity of observed damage will not lead to further degradation. Visual inspection of coatings will be performed by a NACE Coating Inspector Program Level 2 or 3 qualified inspector or an individual that has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.

30 ASME Section XI, ASME Section XI, Subsection IWE is an existing Program to be Section A.2.1.30 Subsection IWE program that will be enhanced to: enhanced prior to the period of extended LGS Letter dated Manage the suppression pool liner and coating operation. 9/12/2012 system to: OI 3.0.3.2.13-1

a. Remove any accumulated sludge in the suppression pool every refueling outage.

APPENDIX A A-84 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE

b. Perform an ASME IWE examination of the The coating LGS Letter dated submerged portion of the suppression pool each maintenance plan will 10/25/12 ISI period. be initiated in the RAI B.2.1.30-7
c. Use the results of the ASME IWE examination to 2012 refueling implement a coating maintenance plan to outage for Unit 1 and LGS letter dated perform the following prior to the period of the 2013 refueling 10/25/12 extended operation (PEO): outage for Unit 2. RAI B.2.1.30-2.2 Local areas (less than 2.5 inches in The downcomer LGS letter dated diameter) of general corrosion that are recoat and 10/25/12 greater than 50 mils plate thickness loss will augmented RAI B.2.1.30-6 be recoated in the outage they are identified. inspection criteria will This plate thickness loss criterion for local be implemented prior areas will also be used to determine when to receipt of the the submerged portions of the liner require renewed licenses.

augmented inspection in accordance with ASME Section XI, Subsection IWE, Category The ultrasonic E-C. thickness measurement Areas of general corrosion greater than 25 requirements will be mils average plate thickness loss will be implemented prior to recoated based on ranking of affected receipt of the surface area, high to low. This plate renewed licenses.

thickness loss criterion for areas of general corrosion will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

APPENDIX A A-85 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE For plates with greater than 25 percent coating depletion, the affected area will be recoated based on ranking of affected surface area depleted and metal thickness loss.

d. Use the results of the ASME IWE examination to implement a coating maintenance plan to perform the following during the PEO:

Local areas (less than 2.5 inches in diameter) of general corrosion that are greater than 50 mils plate thickness loss will be recoated in the outage they are identified.

This plate thickness loss criterion for local areas will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

Areas of general corrosion greater than 25 mils average plate thickness loss will be recoated in the outage they are identified.

This plate thickness loss criterion for areas of general corrosion will also be used to determine when the submerged portions of the liner require augmented inspection in APPENDIX A A-86 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE accordance with ASME Section XI, Subsection IWE, Category E-C.

For plates with greater than 25 percent coating depletion, the affected area will be recoated no later than the next scheduled inspection.

The coating maintenance plan will continue through the period of extended operation to ensure the coating protects the liner to avoid significant material loss.

2. Use the results of the ASME IWE inspection of the submerged portions of the suppression pool downcomers to perform the following:
a. Local areas (less than or equal to 5.5 inches in any direction) that have 40 mils or more metal thickness loss will be recoated. This downcomer metal thickness loss criteria for local areas will also be used to determine when the submerged portions of the downcomers require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.
b. Areas of general corrosion (greater than 5.5 inches in any direction) that have 30 mils or more metal thickness loss will be recoated. This APPENDIX A A-87 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE downcomer metal thickness loss criteria for areas of general corrosion will also be used to determine when the submerged portions of the downcomers require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

3. When IWE examinations are conducted, perform ultrasonic thickness measurements on four areas of submerged suppression pool liner affected by general corrosion.
4. Provide guidance for proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting.

31 ASME Section XI, ASME Section XI, Subsection IWL is an existing Program to be Section A.2.1.31 Subsection IWL program that will be enhanced to: enhanced prior to the period of extended

1. Include second tier acceptance criteria of ACI operation.

349.3R.

32 ASME Section XI, ASME Section XI, Subsection IWF is an existing Program to be Section A.2.1.32 Subsection IWF program that will be enhanced to: enhanced prior to the period of extended

1. Provide guidance for proper specification of bolting operation.

material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation APPENDIX A A-88 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE and failure of structural bolting.

33 10 CFR Part 50, Existing program is credited. Ongoing Section A.2.1.33 Appendix J 34 Masonry Walls Masonry Walls is an existing program that will be Program to be Section A.2.1.34 enhanced to: enhanced prior to the period of extended

1. Add the following structures with masonry walls to operation.

the program scope:

a. Administration Building Warehouse Inspection schedule
b. Fuel Oil Pumphouse identified in
c. Transformer foundation dike walls commitment.
2. Provide additional guidance for inspection of masonry walls for shrinkage, separation, and for gaps between the supports and walls that could impact the walls intended function.
3. Require an inspection frequency of not greater than 5 years.
4. Require that personnel performing inspections and evaluations meet the qualifications specified within ACI 349.3R.

35 Structures Monitoring Structures Monitoring is an existing program that will be Program to be Section A.2.1.35 enhanced to: enhanced prior to the period of extended

1. Add the following structures: operation.

APPENDIX A A-89 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE

a. Admin Building Warehouse Inspection schedule LGS Letter dated
b. Fuel Oil Pumphouse identified in 4/13/12
c. Service Water Pipe Tunnel commitment. RAI 3.5.2.3.2-1.1
d. Yard Structures Aux Fire Water Storage Tank Foundation Backup Fire Pump House and Foundation Well Pump #3 Enclosure and Foundation Railroad Bridge Manholes 001 and 002 Fuel Oil Storage Tank Dike Transformer foundations and dikes
2. Add the following components and commodities;
a. Pipe, electrical, and equipment component support members
b. Pipe whip restraints and jet impingement shields
c. Panels, Racks, and other enclosures
d. Sliding surfaces
e. Sump and Pool liners
f. Electrical cable trays and conduits
g. Electrical duct banks
h. Tube tracks
i. Doors
j. Penetration seals
k. Blowout panels
l. Permanent drywell shielding
m. Roof scuppers
3. Monitor groundwater chemistry on a frequency not to APPENDIX A A-90 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE exceed 5 years for pH, chlorides, and sulfates and verify that it remains non-aggressive, or evaluate results exceeding criteria to assess impact, if any, on below-grade concrete.

4. Provide guidance for proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting. Revise storage requirements for high strength bolts to include recommendations of Research Council on Structural Connections (RSCS) Specification for Structural Joints Using High Strength Bolts, Section 2.0.
5. Monitor concrete for areas of abrasion, erosion, and cavitation degradation, drummy areas that can exceed the cover concrete thickness in depth, popouts and voids, scaling, and passive settlements or deflections.
6. Perform inspections on a frequency not to exceed 5 years.
7. Perform inspections of sub-drainage sump pit internal concrete on a 5-year frequency as a leading indicator the condition of below grade concrete exposed to ground water.
8. Require that personnel performing inspections and APPENDIX A A-91 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE evaluations meet the qualifications specified within ACI 349.3R.

9. Perform inspection of elastomeric vibration isolation elements and structural seals for cracking, loss of material and hardening. Visual inspections of elastomeric vibration isolation elements are to be supplemented by manipulation to detect hardening when vibration isolation function is suspect.
10. Monitor accessible sliding surfaces to detect significant loss of material due to wear, corrosion, debris, or dirt, that could result in lock-up or reduced movement.
11. Perform opportunistic inspection of below grade portions of in-scope structures in the event of excavation which exposes normally inaccessible below grade concrete.
12. Include applicable acceptance criteria from ACI 349.3R.
13. Clarify that loose bolts and nuts and cracked high strength bolts are not acceptable unless accepted by engineering evaluations.

36 RG 1.127, Inspection RG 1.127, Inspection of Water-Control Structures Program to be Section A.2.1.36 of Water-Control Associated with Nuclear Power Plants is an existing enhanced prior to the APPENDIX A A-92 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE Structures Associated program that will be enhanced to: period of extended with Nuclear Power operation.

Plants 1. Require inspection of structural bolting integrity (loss of material and loosening of the bolts). Inspection schedule identified in

2. Require monitoring of aging effects for increase of commitment.

porosity and permeability of concrete structures and loss of material for steel components.

3. Require the proper functioning of dike drainage systems.
4. Require increased inspection frequency if the extent of the degradation is such that the structure or component may not meet its design basis if allowed to continue uncorrected until the next normally scheduled inspection.
5. Require (a) evaluation of the acceptability of inaccessible areas when conditions exist in the accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas, and (b) examination of the exposed portions of the below-grade concrete when excavated for any reason.
6. Monitor raw water chemistry at least once every 5 years for pH, chlorides, and sulfates and verify that it remains non-aggressive, or evaluate results APPENDIX A A-93 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE exceeding criteria to assess impact, if any, on submerged concrete.

7. Require visual examinations of the Spray Pond and Pumphouse submerged wetwell concrete for signs of degradation during maintenance activities. If significant concrete degradation is identified, a plant specific aging management program should be implemented to manage the concrete aging during the period of extended operation.
8. Require that active cracks in structural concrete or extent of corrosion in steel are documented and trended, until the condition is no longer occurring or until a corrective action is implemented.
9. Require acceptance and evaluation of structural concrete using quantitative criteria based on Chapter 5 of ACI 349.3R.
10. Provide guidance for proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting. Revise storage requirements for high strength bolts to include recommendations of Research Council on Structural Connections (RSCS) Specification for Structural Joints Using High Strength Bolts, Section 2.0.

APPENDIX A A-94 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 37 Protective Coating Protective Coating Monitoring and Maintenance Program Program to be Section A.2.1.37 Monitoring and is an existing program that will be enhanced to: enhanced prior to the Maintenance Program period of extended

1. Create the position of Nuclear Coatings Specialist operation.

qualified to ASTM D 7108 standards.

38 Insulation Material for Insulation Material for Electrical Cables and Connections Program and initial Section A.2.1.38 Electrical Cables and Not Subject to 10 CFR 50.49 Environmental inspections to be Connections Not Qualification Requirements is a new program that will be implemented prior to Subject to 10 CFR used to manage aging of the insulation material for non- the period of 50.49 Environmental EQ cables and connections. Accessible cables and extended operation.

Qualification connections located in adverse localized environments Requirements will be visually inspected at least once every 10 years for Inspection schedule indications of reduced insulation resistance, such as identified in embrittlement, discoloration, cracking, melting, swelling, commitment.

or surface contamination.

39 Insulation Material for Insulation Material for Electrical Cables and Connections Program and initial Section A.2.1.39 Electrical Cables and Not Subject to 10 CFR 50.49 Environmental assessment of Connections Not Qualification Requirements Used in Instrumentation calibration and test Subject to 10 CFR Circuits is a new program that will be used to manage results to be 50.49 Environmental aging of non-EQ cable and connection insulation of the implemented prior to Qualification in scope portions of the Process Radiation Monitoring the period of Requirements Used in and Neutron Monitoring Systems. extended operation.

Instrumentation Circuits Calibration and cable tests will be performed and results Assessment will be assessed for reduced insulation resistance prior schedule identified in to the period of extended operation and at least once commitment.

every 10 years during the period of extended operation.

APPENDIX A A-95 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 40 Inaccessible Power Inaccessible Power Cables Not Subject to 10 CFR 50.49 Program and initial Section A.2.1.40 Cables Not Subject to Environmental Qualification Requirements is a new tests and inspections 10 CFR 50.49 program that will be used to manage the aging effects to be implemented LGS Letter dated Environmental and mechanisms of non-EQ, in scope, inaccessible prior to the period of 2/28/12 Qualification power cables. extended operation. RAI B.2.1.40-1 Requirements RAI B.2.1.40-3 Cables will be tested using a proven test for detecting Test and Inspection RAI B.2.1.40-4 reduced insulation resistance of the cables insulation schedule identified in system. The cables will be tested at least once every 6 commitment.

years. More frequent testing may occur based on test results and operating experience.

Periodic actions will be taken to prevent inaccessible cables from being exposed to significant moisture.

Manholes associated with the cables included in this aging management program will be inspected for water collection with subsequent corrective actions (e.g., water removal), as necessary. Prior to the period of extended operation, the frequency of inspections for accumulated water will be established and adjusted based on plant specific operating experience with cable wetting or submergence, including water accumulation over time and event driven occurrences such as heavy rain or flooding. Operation of dewatering devices will be verified prior to any known or predicted heavy rain or flooding event. During the period of extended operation, the inspections will occur at least annually.

APPENDIX A A-96 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE 41 Metal Enclosed Bus Metal Enclosed Bus is a new program that will be used Program and initial Section A.2.1.41 to manage aging of in scope metal enclosed bus. The tests and inspections internal portions of bus enclosure assemblies, bus to be implemented insulation, bus insulating supports and elastomers will be prior to the period of visually inspected. A sample (20 percent with a extended operation.

maximum sample size of 25) of the accessible metal enclosed bus bolted connection population will be tested Test and inspection using thermography. schedule identified in commitment.

The inspections and thermography will be performed at least once every 10 years for indications of aging degradation.

42 Fuse Holders Fuse Holders aging management program is a new Program and initial Section A.2.1.42 program that applies to fuse holders located outside of tests to be active devices that have been identified as susceptible to implemented prior to aging effects. the period of extended operation.

Fuse holders subject to increased resistance of connection or fatigue, will be tested, by a proven test Test schedule methodology, at least once every 10 years for identified in indications of aging degradation. Visual inspection is not commitment.

part of this program.

43 Electrical Cable Electrical Cable Connections Not Subject to 10 CFR Program and Section A.2.1.43 Connections Not 50.49 Environmental Qualification Requirements one-time tests to be Subject to 10 CFR program is a new program that will implement one-time implemented prior to 50.49 Environmental testing of a representative sample (20 percent with a the period of Qualification maximum sample size of 25) of non-EQ electrical cable extended operation.

Requirements connections to ensure that either aging of metallic cable APPENDIX A A-97 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE connections is not occurring or that the existing preventive maintenance program is effective such that a periodic inspection program is not required.

44 Fatigue Monitoring Fatigue Monitoring is an existing program that will be Program to be Section A.3.1.1 enhanced to: enhanced prior to the period of extended

1. Monitor additional plant transients that are operation.

significant contributors to fatigue usage and to impose administrative transient cycle limits corresponding to the limiting numbers of cycles used in the environmental fatigue calculations.

45 Environmental Existing program is credited. Ongoing Section A.3.1.2 Qualification (EQ) of Electric Components 46 Operating Experience The Operating Experience Program is an existing Complete Section A.1.6 program that will be enhanced to:

Program was LGS Letter dated enhanced prior to the 3/13/ 2012

1. Explicitly require the review of operating experience date that the RAI B.1.4-1 for aging-related degradation. renewed operating RAI A.1-1 licenses were issued.
2. Establish criteria to define aging-related LGS Letter dated degradation. 7/11/2012 RAI B.1.4-3
3. Establish identification coding for use in identification, trending and communications of LGS Letter dated aging-related degradation. 9/12/2012 APPENDIX A A-98 REV, 18, SEPTEMBER 2016

LGS UFSAR IMPLEMENTATION PROGRAM OR TOPIC COMMITMENT SOURCE SCHEDULE OI 3.0.5-1

4. Require communication of significant internal LGS Letter dated aging-related degradation, associated with SSCs in 10/12/2012 the scope of license renewal, to other Exelon plants RAI B.1.4-4 and to the industry. Criteria will be established for determining when aging-related degradation is significant.
5. Require review of external operating experience for information related to aging management, and evaluation of such information for potential improvements to LGS aging management activities.
6. Provide training to those responsible for screening, evaluating and communicating operating experience items related to aging management.

47 BWRVIP-74-A Report Re-evaluate the flaw in the Unit 1 RPV nozzle to Prior to the period of LGS Letter, dated License Renewal safe-end weld VRR-1RD-1A-N2H in accordance with extended operation 2/15/12 Action Item 14 ASME Code Section XI, sub-section IWB-3600 for the RAI BWRVIP-1 60-year service period corresponding to the LR term.

APPENDIX A A-99 REV, 18, SEPTEMBER 2016

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