ML14364A264

10 CFR 54.21(b) Annual Update to the Diablo Canyon Power Plant License Renewal Application (Lra), Amendment 48. Part 2 of 2

ML14364A264
Person / Time
Site:	Diablo Canyon
Issue date:	12/22/2014
From:	Pacific Gas & Electric Co
To:	Office of Nuclear Reactor Regulation
Shared Package
ML14364A259	List: DCL-14-103, License Renewal Application Appendix E Applicant'S Environmental Report - Operating License Renewal Stage Amendment 1. Part 4 of 4 ML14364A261 ML14364A262 ML14364A264 ML14364A265 ML14364A266 ML14364A269
References
DCL-14-103, FOIA/PA-2016-0438
Download: ML14364A264 (113)

Text

{{#Wiki_filter:Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 1 of 20 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section E, "Corrosion Under Insulation" LR-ISG-2012-02, Section E, provides recommendations to inspect the external surfaces underneath insulation to address loss of material and cracking that could remain undetected. PG&E did not credit the Aboveground Metallic Tanks AMP during the preparation of DCPP's LRA, and instead manages the aging of the external surfaces of aboveground metallic tanks with the External Surfaces Monitoring program (B2.1.20). Aging of the external surfaces of insulated aboveground metallic tanks will be managed under the External Surfaces Monitoring Program (B2.1.20). PG&E licensing basis for the DCPP External Surfaces Monitoring program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-130, dated October 12, 2010 The NRC Staff evaluated the DCPP External Surfaces Monitoring program in its SER, Section 3.0.3.2.10, dated June 2,2011.PG&E updates its licensing basis for the External Surfaces Monitoring program as follows to address the recommendations in LR-ISG-2012-02, Section E.(1) Periodic inspections of external surfaces underneath insulation will be conducted during each ten-year period during the PEO.(2) The following inspection will be performed for outdoor in-scope insulated components, except tanks, and all indoor insulated components exposed to condensation (because the in-scope component is being operated below the dew point): (a) Remove insulation and inspect a minimum of 20 percent of the in-scope piping length for each material type.(b) Remove insulation and inspect 20 percent of the surface area of components with configurations that do not conform to a 1-foot axial length determination (e.g., valves, accumulators).(c) Alternatively, remove the insulation and inspect any combination of a minimum of 25 1-foot axial length sections and components for each material type. Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 2 of 20 (d) Inspect each material type and environment (e.g., air-outdoor, moist air) where condensation or moisture on the surfaces of the component could occur routinely or seasonally. (3) The following inspections will be performed for in-scope indoor insulated tanks exposed to condensation, because the in-scope component is being operated below the dew point, or in-scope outdoor insulated tanks: (a) Inspect the tank exterior after removing either 25 1-square-foot sections or 20 percent of the tank's surface area.(b) Sample inspection points will be distributed in such a way that inspections will occur on the tank dome and sides, near the bottom, at points where structural supports or instrument nozzles penetrate the insulation, and where water might collect, such as on top of stiffening rings.(4) Inspection locations will be based on the likelihood of corrosion under insulation occurring (e.g., alternate wetting and drying in environments in which trace contaminants could be present, length of time the system operates below the dew point). Subsequent inspections may consist of examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation when the following conditions are met based on the results of the initial inspection: (a) No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction.(b) No evidence of stress corrosion cracking.(c) If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or jacketing, or there is evidence of water intrusion through the insulation (e.g., water seepage through insulation seams/joints), periodic inspections under the insulation will continue as conducted for the initial inspection. (5) For tightly adhering insulation that is impermeable to moisture: (a) Removal of insulation is not required unless there is evidence of damage to the moisture barrier. Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 3 of 20 (b) Tightly adhering insulation will be considered to be a separate population from the remainder of insulation installed on in-scope components.(c) The entire population of in-scope components that have tightly adhering insulation will be visually inspected for damage to the moisture barrier with the same frequency as for other types of insulation inspections. These inspections will not be credited towards the inspection quantities for other types of insulation. LRA Sections 3.2.2.1.4, 3.3.2.1.9, 3.4.2.1.5, and Tables 3.2.2-4, 3.3.2-4, 3.3.2-9, 3.3.2-10, 3.3.2-11, 3.3.2-18, 3.4.2-1, 3.4.2-3, and 3.4.2-5 are revised to address the changes made by LR-ISG-2012-02, Section E, as shown in this Attachment. LRA Section A1.20 and Table A4-1, Item 8, are revised as shown in Attachment

15.

Enclosure 1 Section 3.2 Attachment 7E AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES PG&E Letter DCL-14-103 Page 4 of 20 3.2.2.1.4 Containment HVAC System Aging Effects Requiring Management The following containment HVAC system aging effects require management:

• Cracking* Hardening and loss of strength* Loss of material* Loss of preload* Reduction of heat transfer Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 5 of 20 Section 3.2 AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES Thhltp. 3 2 2-4 Fnainmp.Prtqd S;fetv Fe~atujres

-Summary of ZAoina Manaaement Evaluation -Containment HVAC Svstem Table 3 2 # ... ...... .... F a u" -,a of ,,7 ...... ........ ........- Containment -V ......Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Piping LBS, PB, Carbon Steel Plant Indoor Loss of material External Surfaces Monitoring VII.F3-2 3.3.1.56 D, 10 SIA, SS Air (Ext) Program (B2.1.20)Piping LBS, PB, Stainless Plant Indoor NeneLoss of Extemal Surfaces Monitoring V1J41J- 1.0-4 AH, 12 SIA, SS Steel Air (Ext) material Program (B2.1.20)NeRe None None Piping LBS, PB, Stainless Plant Indoor Cracking External Surfaces Monitoring None None H, 11 SIA, SS Steel Air (Ext) Program (B2.1.20)Valve PB, SIA, Carbon Steel Plant Indoor Loss of material External Surfaces Monitoring VII.F3-2 3.3.1.56 D, 10 SS Air (Ext) Program (B2.1.20) 1 Valve PB, SIA, Stainless Plant Indoor NeneLoss of External Surfaces Monitoring V11445 3..O4 AH, 12 SS Steel Air (Ext) material Program (B2.1.20)NeG% None None Valve PB, SIA, Stainless Plant Indoor Cracking External Surfaces Monitoring None None H, 11 SS Steel Air (Ext) Program (B2.1.20)10. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.11. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line V.E.E-406 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.12. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line V.E.E-403 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Section 3.3 Attachment 7E AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 6 of 20 3.3.2.1.9 Miscellaneous HVAC Systems Aging Effects Requiring Management The following miscellaneous HVAC systems aging effects require management:

• Cracking* Hardening and loss of strength* Loss of material* Loss of preload Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 7 of 20 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-4 Auxiliary Systems -Summary of Aging Management Evaluation

-Component Cooling Water System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping LBS, PB, Carbon Steel Plant Indoor Air. Loss of material External Surfaces VII.I-8 3.3.1.58 B, 6 SIA (Ext) Monitoring Program (B2.1.20)Piping LBS, PB, Carbon Steel Atmosphere/ Loss of material External Surfaces VII.I-9 3.3.1.58 B, 6 SIA Weather (Ext) Monitoring Program (B2.1.20)Piping PB Stainless Plant Indoor Air Loss of External Surfaces NoneVMj- None&34-.9 H, 7A Steel (Ext) materialNeG% Monitoring Program 4-5 4 (82.1.20)Nene Piping PB Stainless Plant Indoor Air Cracking External Surfaces None None H, 7 Steel (Ext) Monitoring Program (82.1.20)Piping PB Stainless Atmosphere/ Loss of material External Surfaces None None G, 7 Steel Weather (Ext) Monitoring Program B(2.1.20)Piping PB Stainless Atmosphere! Cracking External Surfaces None None H, 7 Steel Weather (Ext) Monitoring Program (B2.1.20)Tank PB Carbon Steel Atmosphere/ Loss of material External Surfaces VII.I-9 3.3.1.58 B, 6 Weather (Ext) Monitoring Program (82.1.20)Valve LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VII.I-8 3.3.1.58 B, 6 SIA (Ext) Monitoring Program (82.1.20)Valve PB Carbon Steel Atmosphere/ Loss of material External Surfaces VII.I-9 3.3.1.58 B, 6 Weather (Ext) Monitoring Program (B2.1.20)Valve PB Stainless Plant Indoor Air Loss of External Surfaces H, 7A Steel (Ext) materialNoie Monitoring Program NoneVll4 None3.3..9 (B2.1.20)Neae 45 4 Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 8 of 20 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-4 Auxiliary Systems -Summary of Aging Management Evaluation -Component Cooling Water System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Valve PB Stainless Plant Indoor Air Cracking External Surfaces None None H, 7 Steel (Ext) Monitoring Program I I_ I (B2.1.20)6. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.7. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VII. C1.A -405 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 9 of 20 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-9 Auxiliarv Systems -Summarv of Aul=/na Manaaement Evaluation -Miscellaneous HVAC Svstems Au iir Sv t m -Sun ar f ain Ma a e ........................... s HVA....... Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping PB, SS Copper Alloy Plant Indoor Air Loss of material External Surfaces VII.F4-12 3.3.1.25 E, 4 (Ext) Monitoring Program (B2.1.20)Valve SIA, SS Copper Alloy Plant Indoor Air Loss of External Surfaces None None CH, 5 (Ext) materialNoe Monitoring Program (B2.1. 20)Neoe Valve PB, SIA, Stainless Plant Indoor Air Loss of External Surfaces None None AH, 5 SS Steel (Ext) materialNene, Monitoring Program (B2.1. 20)NeG%Valve PB, SIA, Stainless Plant Indoor Air Cracking External Surfaces None None H, 5 SS Steel (Ext) Monitoring Program I_ (82.1.20)4. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.5. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VII.I.A-405 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 10 of 20 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-10 Auxiliary Systems -Summary of Aging Management Evaluation -Control Room HVAC System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Notes Type Function Requiring Program 1801 Vol. Item Management 2 Item Piping PB Carbon Steel Plant Indoor Air Loss of material External Surfaces VII.1-11 3.3.1.58 B, 9 (Ext) Monitoring Program (82.1.20)Piping PB Carbon Steel Plant Indoor Air Loss of External Surfaces None3-..4 AH, 2, 10 (Galvanized) (Ext) materialNene Monitoring Program -6 92 (B2.1.20)Nepie Piping PB Copper Alloy Plant Indoor Air Loss of material External Surfaces VII.F1-16 3.3.1.25 E, 9 (Ext) Monitoring Program I_ 1_ (82.1.20)9. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.10. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VILFI.A-405 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Section 3.3 Attachment 7E AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 11 of 20 Auxiliarv Systems -Summary of, Manaaiement Evaluation -Auxiliarv Buildina HVAC System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Notes Type Function Requiring Program 1801 Vol. Item Management 2 Item Piping LBS Carbon Steel Atmosphere/ Loss of material External Surfaces Monitoring VII.I-9 3.3.1.58 B, 7 Weather (Ext) Program (B2.1.20)Piping LBS Carbon Steel Plant Indoor Loss of material External Surfaces Monitoring VII.1-8 3.3.1.58 B, 7 Air (Ext) Program (B2.1.20)Piping LBS Copper Alloy Plant Indoor Loss of material External Surfaces Monitoring VIII.I-2 3.4.1.41 A, 7 Air (Ext) Program (B2.1.20)Valve LBS Carbon Steel Plant Indoor Loss of material External Surfaces Monitoring VII.I-8 3.3.1.58 B, 7 Air (Ext) Program (B2.1.20)Valve LBS, PB, Copper Alloy Plant Indoor Loss of External Surfaces Monitoring VIlk24 4-1-41. AH, 8 SIA Air (Ext) materialNe'e Program (B2.1.20)Nei'e None None 7. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.8. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VII.F2.A-405 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 12 of 20 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-18 Auxiliary Systems -Summary of Aging Management Evaluation -Miscellaneous Systems in scope ONLY for Criterion 10 CFR 54.4 (a) (2)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping SIA Carbon Steel Atmosphere/ Loss of material External Surfaces VII.I-9 3.3.1.58 B, 7 Weather (Ext) Monitoring Program (92.1.20)Piping LBS, SIA Carbon Steel Plant Indoor Air Loss of material External Surfaces VII.I-8 3.3.1.58 B, 7 (Ext) Monitoring Program (B2.1.20)Piping LBS Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 7 (Ext) Monitoring Program (82.1.20)Piping LBS Copper Alloy Plant Indoor Air Loss of material External Surfaces None None H, 8 A (Ext) None Monitoring Program VHH 2 2441 (B2.1.20) None Piping LBS, SIA Stainless Plant Indoor Air Loss of material Extemal Surfaces None None H, 8 A Steel (Ext) None Monitoring Program MW i6 .34.94 (82.1.20) Noe Piping LBS, SIA Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 Steel (Ext) Monitoring Program (B2.1.20)Piping LBS Stainless Plant Indoor Air Loss of material External Surfaces None None H, 8 A Steel (Ext) NOeR Monitoring Program VU404Q 3414 (B2.1.20) Noe% e Piping LBS Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 Steel (Ext) Monitoring Program (B2.1.20)Tank LBS Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 7 (Ext) Monitoring Program I I_ _ I_ _I(B2.1.20) Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 13 of 20 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-18 Auxiliary Systems -Summary of Aging Management Evaluation -Miscellaneous Systems in scope ONLY for Criterion 10 CFR 54.4(a) (2)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Tank LBS Stainless Plant Indoor Air Loss of material External Surfaces None None H, 8 Steel (Ext) Monitoring Program (B2.1.20)Tank LBS Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 Steel (Ext) Monitoring Program (B2.1.20)Valve LBS Carbon Steel Plant Indoor Air Loss of material External Surfaces VII.I-8 3.3.1.58 B, 7 (Ext) Monitoring Program (B2.1.20)Valve LBS Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 7 (Ext) Monitoring Program (82.1.20)Valve LBS, SIA Copper Alloy Plant Indoor Air Loss of material External Surfaces None None H, 8 A (Ext) Nene Monitoring Program Vill -2 34.1.4 (B2.1.20) NePo Valve LBS Copper Alloy Plant Indoor Air Loss of material External Surfaces None None H, 8 A (> 15% Zinc) (Ext) Nemo Monitoring Program VlIkI- 24141 (B2.1.20) Nee Valve LBS Copper Alloy Plant Indoor Air Cracking External Surfaces None None H, 8 (> 15% Zinc) (Ext) Monitoring Program (B2.1.20)Valve LBS, SIA Stainless Plant Indoor Air Loss of material External Surfaces None V1-kJ- None H, 8 A Steel (Ext) Neno Monitoring Program 45 (B2.1.20) Neo%Valve LBS, SIA Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 Steel (Ext) Monitoring Program I_ (B2.1.20) Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 14 of 20 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-18 Auxiliary Systems -Summary of Aging Management Evaluation -Miscellaneous Systems in scope ONLY for Criterion 10 CFR 54.4 (a) (2)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.I Management 2 Item Valve LBS Stainless Plant Indoor Air Loss of material External Surfaces None None H, 8 A Steel (Ext) NeRe Monitoring Program VI4 :10 3.444 (B2.1.20) Nene Valve LBS Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 Steel (Ext) Monitoring Program (B2.1.20)7. Extemal Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.8. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VII.L.A-405 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Section 3.4 Attachment 7E AGING MANAGEMENT OF STEAM AND PG&E Letter DCL-14-103 POWER CONVERSION SYSTEMS Page 15 of 20 3.4.2.1.5 Auxiliary Feedwater System Aging Effects Requiring Management The following auxiliary feedwater system aging effects require management:

• Cracking* Loss of material* Loss of preload* Reduction of heat transfer Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 16 of 20 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEMS Table 3.4.2-1 Steam and Power Conversion System -Summary of Aging Management Evaluation

-Turbine Steam Supply System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping LBS, PB, Carbon Steel Atmosphere/ Loss of material External Surfaces VIII.H-8 3.4.1.28 B, 7 SIA, SS Weather (Ext) Monitoring Program (B2.1.20)Piping LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 7 SIA, SS (Ext) Monitoring Program (B2.1.20)Piping LBS, PB, Stainless Plant Indoor Air Loss of material External Surfaces None None AH, 8 SIA Steel (Ext) None Monitoring Program VIW0 3.4.1.44 (B2.1.20) NePe Piping LBS, PB, Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 SIA Steel (Ext) Monitoring Program (82.1.20)Tank LBS, SIA Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 7 (Ext) Monitoring Program (B2.1.20)Tank SIA Stainless Plant Indoor Air Loss of material External Surfaces None None GH, 8 Steel (Ext) Nene Monitoring Program Vt41--1O 34A.1.41 (82.1.20) Nene Tank SIA Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 Steel (Ext) Monitoring Program (B2.1.20)Valve LBS, PB, Carbon Steel Atmosphere/ Loss of material External Surfaces VIII.H-8 3.4.1.28 B, 7 SIA Weather (Ext) Monitoring Program (B2.1.20)Valve LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 7 SIA (Ext) Monitoring Program (B2.1.20) Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 17 of 20 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEMS Table 3.4.2-1 Steam and Power Conversion System -Summary of Aging Management Evaluation -Turbine Steam Supply System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Valve LBS Copper Alloy Plant Indoor Air Loss of material External Surfaces None None H, 8A (Ext) Nene Monitoring Program V1WI4 .4.44 (B2.1.20) Nese Valve LBS, PB, Stainless Plant Indoor Air Loss of material External Surfaces None None H, 8A SIA Steel (Ext) NeRe Monitoring Program VUH i- 3.444 (82.1.20) Ne~e Valve LBS, PB, Stainless Plant Indoor Air Cracking External Surfaces None None H, 8 SIA Steel (Ext) Monitoring Program I_ (B2.1.20)7. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.8. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VIII.A. S-402 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 18 of 20 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEMS Table 3.4.2-3 Steam and Power Conversion System -Summary of Aging Management Evaluation -Feedwater System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping PB, SIA Carbon Steel Atmosphere/ Loss of material External Surfaces VIII.H-8 3.4.1.28 B, 2 Weather (Ext) Monitoring Program (B2.1.20)Piping LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 2 SIA (Ext) Monitoring Program (82.1.20)Piping LBS Stainless Plant Indoor Air Loss of material External Surfaces None None H, 3 A Steel (Ext) NePi Monitoring Program Vill.! i4 2441 (B2.1.20) NGe_Piping LBS Stainless Plant Indoor Air Cracking External Surfaces None None H, 3 Steel (Ext) Monitoring Program (B2.1.20)Valve PB, SIA Carbon Steel Atmosphere/ Loss of material External Surfaces VIII.H-8 3.4.1.28 B, 2 Weather (Ext) Monitoring Program (B2.1.20)Valve LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 2 SIA (Ext) Monitoring Program (B2.1.20)Valve PB Stainless Atmosphere/ Loss of material External Surfaces None None G, 3 Steel Weather (Ext) Monitoring Program (B2.1.20)Valve PB Stainless Atmospherel Cracking External Surfaces None None G, 3 Steel Weather (Ext) Monitoring Program (B2.1.20)Valve LBS, PB Stainless Plant Indoor Air Loss of material External Surfaces NoneV- I. None&4.4 H, 3A Steel (Ext) Nene Monitoring Program 4-0 4 (B2.1.20)Nene Valve LBS, PB Stainless Plant Indoor Air Cracking External Surfaces None None H, 3 Steel (Ext) Monitoring Program I _(B2.1.20) Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 19 of 20 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEMS 2. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.3. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VIII.D1.S-402 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Attachment 7E PG&E Letter DCL-14-103 Page 20 of 20 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEMS Table 3.4.2-5 Steam and Power Conversion System -Summary of Aging Management Evaluation -Auxiliary Feedwater System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 2 SIA (Ext) Monitoring Program (B2.1.20)Piping LBS, PB, Stainless Plant Indoor Air Loss of material External Surfaces None None H, 3 A-_SIA Steel (Ext) Nene Monitoring Program VHHI-4 3.4.A.1 (B2.1.20) Noe%Piping LBS, PB, Stainless Plant Indoor Air Cracking External Surfaces None None H, 3 SIA Steel (Ext) Monitoring Program (B2.1.20)Tank LBS Stainless Plant Indoor Air Loss of material External Surfaces None None H, 3A-4 Steel (Ext) Nene Monitoring Program viiio 34.1.4 (82.1.20) Noe%Tank LBS Stainless Plant Indoor Air Cracking External Surfaces None None H, 3 Steel (Ext) Monitoring Program (B2.1.20)Valve LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VIII.H-7 3.4.1.28 B, 2 SIA (Ext) Monitoring Program (B2.1.20)Valve LBS, PB, Stainless Plant Indoor Air Loss of material External Surfaces None None H, 3A SIA Steel (Ext) None Monitoring Program VIWI-40 3.4.1.41 (82.1.20) None Valve LBS, PB, Stainless Plant Indoor Air Cracking External Surfaces None None H, 3 SIA Steel (Ext) Monitoring Program 1 1 (2.1.20)2. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E.3. External Surfaces Monitoring (B2.1.20) program provisions for outdoor insulated or for indoor insulated components that operate below the dew point apply. Reference LR-ISG-2012-02 Appendix C Line VIII. G. S-402 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Attachment 7F PG&E Letter DCL-14-103 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section F, "External Volumetric Examination of Internal Piping Surfaces of Underground Piping Removed from GALL Report AMP XI.M41, 'Buried and Underground Piping and Tanks"'LR-ISG-2012-02, Section F, provides recommendations for inspecting the internal surfaces of underground piping covered by AMP XI.M41, Buried and Underground Piping and Tanks, which were previously removed from the AMP by LR-ISG-2011-03. PG&E's licensing basis for the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-10-105, dated August 18, 2010 (4) PG&E Letter DCL-10-147, dated November 24, 2010 The NRC Staff evaluated the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program in its SER, Section 3.0.3.2.11, dated June 2, 2011.In order to address the recommendations in LR-ISG-2012-02, Section F, PG&E updates its licensing basis for the Inspection of Internal Surfaces program as follows.(1) The condition of internal surfaces of buried and underground components can be based on inspections of the interior surfaces of accessible components where the material, environment and aging effects of the buried or underground component are similar to those of the accessible component. (2) If inspections of the interior surfaces of accessible components with material, environment, and aging effects similar to those of the interior surfaces of buried or underground components are not conducted, internal visual or external volumetric inspections capable of detecting loss of material on the internal surfaces of the buried or underground components will be conducted. No changes to the LRA Section 3 tables are necessary to address LR-ISG-2012-02, Section F. LRA Section A1.22 and Table A4-1, Item 9, are revised to address LR-ISG-2012-02, Section F. Enclosure 1 Attachment 7G PG&E Letter DCL-14-103 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section G, "Specific Guidance for Use of the Pressurization Option for Inspecting Elastomers in GALL Report AMP XI.M38" LR-ISG-2012-02, Section G, removes the term "hydrotesting" from the program description for AMP XI.M38. The term is being removed because it is typically associated with test pressures well above the normal operating and design pressures. PG&E's licensing basis for the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-10-105, dated August 18, 2010 (4) PG&E Letter DCL-10-147, dated November 24, 2010 The NRC Staff evaluated the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program in its SER, Section 3.0.3.2.11, dated June 2,2011.The term "hydrotesting" is not used in DCPP's Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program.LR-ISG-2012-02, Section G, also clarifies the intent of the pressurization option. As recommended by LR-ISG-2012-02, Section G, PG&E revises the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (A1.22) to indicate that when the pressurization augmented technique is used, that the component is sufficiently pressurized to expand the surface of the material in such a way that cracks or crazing would be evident. LRA Section A1.22 and Table A4-1, Item 9, are revised to address LR-ISG-2012-02, Section G. Refer to Attachment

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Enclosure 1 Attachment 7H PG&E Letter DCL-14-103 Page 1 of 4 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section H, "Key Miscellaneous Changes to the GALL Report and SRP-LR" LR-ISG-2012-02, Section H, provides recommendations on key miscellaneous changes to the GALL Report, and the SRP for review of LRA.PG&E's licensing basis for the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-10-105, dated August 18, 2010 (4) PG&E Letter DCL-10-147, dated November 24, 2010 The NRC Staff evaluated the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program in its SER, Section 3.0.3.2.11, dated June 2, 2011.PG&E updates its licensing basis for the Inspection of Internal Surfaces program, as follows, to address the recommendations in LR-ISG-2012-02, Section H: (1) The ISG revised the definition of "hardening and loss of strength" to provide a more complete list of aging effects and improve consistency with program Element 3, "Parameters Monitored/Inspected" of GALL Report AMP XI.M38, "Inspection of Internal Surfaces and Miscellaneous Piping and Ducting Components." LRA Section A1.22 is revised to be consistent with the revised definition of hardening and loss of strength in accordance with LR-ISG-2012-02, item H.i.(2) The ISG revised the definition of "elastomer degradation" to include change in material properties as an aging effect example. This makes the definition more consistent with program Element 3, "Parameters Monitored/Inspected" of GALL Report AMP XI.M38, "Inspection of Internal Surfaces and Miscellaneous Piping and Ducting Components." LRA Section A1.22 is revised to be consistent with the revised definition of elastomer degradation in accordance with LR-ISG-2012-02, Item H.ii.(3) The ISG revised program Element 1, "Scope of Program," of GALL Report AMP XI.M38, "Inspection of Internal Surfaces and Miscellaneous Piping and Ducting Components," to allow the aging of internal surfaces of metallic and polymeric components to be managed by inspections from the external surface when the material and environment combinations are Enclosure 1 Attachment 7H PG&E Letter DCL-14-103 Page 2 of 4 the same. PG&E's Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program will allow external inspections of components to be credited for managing: (a) loss of material from internal surfaces of metallic components and (b) loss of material, cracking, and change in material properties from the internal surfaces of polymeric components when this condition is met. LRA Section A1.22 is revised to allow external inspections to be credited if the internal material and environment conditions are similar in accordance with LR-ISG-2012-02, Item H.iii.(4) The ISG revised the definition of fouling to incorporate discussions related to flow blockage of water-based fire protection system piping in LR-ISG-2012-02, Section C. The expanded definition of fouling does not impact the information in the DCPP LRA. Fouling due to flow blockage specific to the fire protection systems is addressed in LR-ISG-2012-02, Section C, "Flow Blockage of Water-Based Fire Protection System Piping," GALL Report AMP XI.M27, "Fire Water System." (5) The SRP-LR and GALL Report were revised with the following: (a) The ISG added an AMR line item for high-density polyethylene piping exposed to an underground environment. DCPP does not have any high-density polyethylene components in-scope for license renewal. No updates to the DCPP LRA are needed to address this change.(b) The ISG added the waste water environment to Line Item 3.3.1-72 in SRP-LR Table 3.3-1, and Item VII.I.A-407 to the GALL Report to reduce the number of non-consistent items in an applicant's LRA.DCPP's LRA was written to GALL Revision 1, which does not include waste water as an environment. The GALL Revision 2 definition of waste water is captured by the GALL Revision 1 definition of raw water. The DCPP Selective Leaching program currently manages in-scope components exposed to raw water.Therefore, no updates to the DCPP LRA are needed to address this change.(c) The ISG added aging management review lines for copper alloy, stainless steel, and steel components exposed to raw water (nonsafety-related components not covered by NRC Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment"), with aging management by GALL Report AMP XI.M38, "Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components." The only existing AMP for Enclosure 1 Attachment 7H PG&E Letter DCL-14-103 Page 3 of 4 copper alloy, stainless steel, and steel exposed to raw water prior to this change was GALL Report AMP XI.M20, "Open Cycle Cooling Water." The existing line items in DCPP's LRA aging management evaluation tables use g Generic Note E and a plant-specific note to show that aging is instead managed by the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program, which is consistent with LR-ISG-2012-02, Section H. Therefore, no updates to the DCPP LRA are needed to address this change. Use of the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program instead of the OCCW program was reviewed and approved by the NRC in the DCPP SER, dated June 2, 2011.(d) The ISG added steel and stainless steel pump casings exposed to waste water being managed for loss of material due to general (steel only), pitting, crevice, and microbiologically influenced corrosion to GALL Report AMP XI.M36, "External Surfaces Monitoring", to allow the use of XI.M36 to manage internal aging effects. Although DCPP has pumps exposed internally to raw water, the only pump casings exposed to waste water or raw water (external) are managed by the OCCW System program. Therefore, no updates to the DCPP LRA are needed to address this change.(e) The ISG added jacketed calcium silicate insulation, fiberglass insulation, and foamglas insulation exposed to outdoor air and uncontrolled indoor air being managed with GALL Report AMP XI.M36 for degradation of thermal insulation due to moisture intrusion. The ISG also stated that walkdowns of jacketing installed on in-scope insulation would be an acceptable method of managing aging. Alternatively, an inspection methodology would need to be proposed by the applicant. DCPP has no insulation of this type in-scope for license renewal. Insulation associated with the safety injection system, containment spray system, auxiliary feedwater system, chemical and volume control system, and the residual heat removal system is not required to minimize heat load into rooms during design basis events. DCPP does not use insulation in the emergency diesel generator exhaust penetrations to maintain temperature of the structure. The pressurizer loop seals are insulated to maintain the loop seal water near saturation conditions so that, upon safety valve operation, most of the seal water flashes to steam, thus reducing the hydraulic loading on the downstream piping. However, by PG&E Letter DCL-10-123, RAI 3.1.2.3.2-2, the calcium silicate insulation on the pressurizer loop seals was Enclosure 1 Attachment 7H PG&E Letter DCL-14-103 Page 4 of 4 replaced with reflective mirror insulation. Therefore, no updates to the DCPP LRA are needed to address this change.LRA Section A1.22 and Table A4-1, Item 9, are revised to address LR-ISG-2012-02, Section H. Refer to Attachment

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Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 1 of 16 LR-ISG-2013-01, "Draft Interim Staff Guidance 2013-01, 'Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings"' The NRC issued the final LR-ISG-2013-01 on November 14, 2014. PG&E will evaluate LR-ISG-2013-01 and provide an updated evaluation to the NRC by February 2015.In response to draft LR-ISG-2013-01, PG&E performed a review to identify the components with internal coatings that are within the scope of license renewal.Based on this review, the in-scope components with internal coatings include: (1) Condensate polisher demineralizer (2) Zinc injection pump pulsation dampener (3) CCW system heat exchanger waterboxes (4) CCW butterfly valves (5) Makeup water system asbestos cement pipe (6) Condensate storage tank (7) CST floating cover (8) Raw water storage reservoir (9) Transfer tank (10) ASW piping and pipe components (11) Circulating water pump equalizing lines (12) Fire water system asbestos cement pipe (13) Fire water storage tank (14) Fire water system sprinkler piping with galvanized coating (15) Demineralizer regenerant receiver tanks (16) Demineralizer regenerant receiver tank piping (17) Hot laundry and shower drain tanks (18) Diesel fuel oil storage tank manway (19) Centrifugal charging pump gear oil cooler shell (20) Steam generator blowdown demineralizer regeneration system piping and pipe components Item number (13): The fire water storage tank internal coating is not addressed in the response to this ISG. The aging effects associated with the fire water storage tank internal coatings are managed by the Fire Water System program as described in PG&E's evaluation of LR-ISG-2012-02 in Attachment 7C of this submittal. Item numbers (15) and (16): The demineralizer regenerant receiver tanks are coated with a rubber liner and the associated demineralizer regenerant receiver tank piping has a plastic liner. The liners were designed to protect the tank from acid and caustic from demineralizer regeneration, but the system was never used for that purpose. Instead, the tanks and associated piping were converted to accept excess equipment floor drain Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 2 of 16 liquid. Degradation of the demineralizer regenerant receiver tank liners and associated piping liner cannot result in downstream effects such as reduction in flow, drop in pressure, or reduction in heat transfer for components in the scope of license renewal.Corrosion rates and inspection intervals are not based on the integrity of the liners.Applying the guidance of the draft LR-ISG-2013-01, the coatings in the demineralizer regenerant receiver tanks and the piping associated with the demineralizer regenerant receiver tanks, do not require inspections of coatings.Item number (17): The interior of the hot laundry and shower drain tanks are coated with paint. Degradation of the tank coating cannot result in downstream effects such as reduction in flow, drop in pressure, or reduction in heat transfer for components in the scope of license renewal. Corrosion rates and inspection intervals are not based on the integrity of the coating. Applying the guidance of the draft LR-ISG-2013-01, the hot laundry and shower drain tanks coatings do not require inspections of coatings.Item number (20): The steam generator blowdown treatment demineralizer system piping and piping components and demineralizers have internal coatings or linings. The flowpath of this system was evaluated and it was determined that failure of these coatings and linings could not adversely affect a safety-related function or prevent satisfactory accomplishment of any function identified under 10 CFR 54.4(a)(3) by causes such as reduction in flow, drop in pressure, or reduction in heat transfer for components in the scope of license renewal. Corrosion rates or inspection intervals are not based on the integrity of these coatings. Applying the guidance of the draft LR-ISG-2013-01, the steam generator blowdown treatment demineralizer system coatings do not require inspections of coatings.For the remaining item numbers, coating inspections are required to manage loss of coating integrity. The inspections will be managed using the Closed Cycle Cooling Water System program, Open Cycle Cooling Water System program, Fire Water System program, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. These programs will include the following elements for the management of internal Service Level III (augmented) coatings: Scope of Program The scope of program includes components manufactured from copper alloy, concrete, foam, nickel alloy, stainless steel, and steel with a Service Level III (augmented) internal coating exposed to closed cycle cooling water, fuel oil, lubricating oil, raw water, treated borated water, and demineralized water.Inspection Method and Parameters Inspected Visual inspections are intended to identify coatings that do not meet acceptance criteria, such as peeling and delamination. The definition of these terms is Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 3 of 16 included in Section 10.2 of ASTM D7167-12, "Standard Guide for Establishing Procedures to Monitor the Performance of Safety-Related Coating Service Level III Lining Systems in an Operating Nuclear Power Plant." Physical testing is intended to identify potential delamination of the coating.Inspection Scope Baseline Service Level III (augmented) coatings inspections will be conducted in the ten-year period prior to the PEO. Subsequent inspections will be established by a coating specialist based on an evaluation (discussed in extent of inspections below). The inspection intervals will not exceed those in Draft LR-ISG-2013-01, Appendix C, Table 4a.Extent of Inspections The extent of each inspection will be determined by a qualified coatings inspector based on an evaluation of the effect of a coating failure on the in-scope component's intended function(s), potential problems identified during prior inspections, and known service life history. Inspection locations are selected based on susceptibility to degradation and consequences of failure. The extent of inspections will not be any less than all accessible internal surfaces of tanks and heat exchangers. The inspection of piping will be no less than a representative 73 1-ft axial length circumferential segments of piping or 50 percent of the total length of each coating material and internal and external environments. The external environment is the material to which the coating is affixed. If geometric limitations impede movement of remote or robotic inspection tools, the number of inspection segments is increased in order to cover an equivalent 73 1-foot axial length sections.Coating surfaces captured between interlocking surfaces (e.g., flanges) are not required to be inspected unless the joint has been disassembled to allow access for an internal coating inspection or other reasons. For areas not readily accessible for direct inspection, such as small pipelines, heat exchangers, and other equipment, consideration is given to the use of remote or robotic inspection tools.Inspection of coatings may be omitted for components where: (a) it has been determined that degradation of coatings cannot result in downstream effects on license renewal intended functions such as reduction in flow, drop in pressure, or reduction in heat transfer for in-scope components, and (b) corrosion rates or inspection intervals of in scope components are not based on the integrity of the coating. For piping or tanks where degradation of the base metal is the only issue related to degradation of the components coating, then external wall Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 4 of 16 thickness measurements may be performed in lieu of visual inspection to confirm the acceptability of the corrosion rate of the base metal.Coatinq Inspector Training and Qualification The training and qualification of individuals involved in coating inspections and evaluating degraded conditions is conducted in accordance with an ASTM International standard endorsed in Regulatory Guide 1.54 including NRC guidance associated with a particular standard.Monitoring and Trending of Coating Degradation Monitoring and trending includes pre-inspection reviews of the previous two inspection results and any subsequent repair activities. The review will be performed by a coatings specialist and includes: (a) a list and location of all areas evidencing deterioration, (b) a prioritization of the repair areas into areas that must be repaired before returning the system to service, (c) areas where repair can be postponed to the next inspection, and (d) where possible, photographic documentation indexed to inspection locations. When corrosion of the base material is the only issue related to coating degradation of the component and external wall thickness measurements are used in lieu of internal visual inspections of the coating, the corrosion rate of the base metal will be trended.Acceptance Criteria (1) Indications of peeling and delamination are not acceptable and the coatings are repaired or replaced. For coated surfaces that show evidence of delamination or peeling, physical testing is performed where physically possible. The test consists of destructive or nondestructive adhesion testing using ASTM International Standards. A minimum of three sample points adjacent to the defective area are tested.(2) Blisters are evaluated by a coatings specialist. The cause of blisters needs to be determined if the blister is not repaired. Physical testing is conducted to ensure that the blister is completely surrounded by sound coating bonded to the surface. If coatings are credited for corrosion prevention, the component's base material in the vicinity of the blister is inspected to determine if unanticipated corrosion has occurred.(3) Indications such as cracking, flaking and rusting are to be evaluated by a coatings specialist. Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 5 of 16 (4) Minor cracking and spalling of cementitious coatings is acceptable provided there is no evidence that the coating is debonding from the base material.(5) As applicable, wall thickness measurements meet design minimum wall requirements. (6) Adhesion testing results meet or exceed the degree of adhesion recommended in engineering documents specific to the coating and substrate. Corrective Action Indications noted will be entered into the DCPP CAP for appropriate evaluation or disposition. Coatings that do not meet acceptance criteria are repaired or replaced.The DCPP fire water system contains galvanized piping (item number (14) above). The Fire Water System program will be used to demonstrate that an adequate amount of the zinc-based coating remains intact throughout the PEO. As discussed in Attachment 7C, LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation, Section C, Flow Blockage of Water-Based Fire Protection System Piping, GALL Report AMP XI.M27, the obstruction investigation requires an internal inspection of fire water sprinkler piping (NFPA 25, Sections 14.2 and 14.3). The DCPP Fire Water System program will be enhanced to internally inspect wet sprinkler systems using a method capable of detecting flow blockage due to fouling in addition to loss of material. At least one of the three sections of fire water sprinkler piping fabricated from galvanized steel will be conducted during each inspection interval.LRA Sections 3.3.2.1.3, 3.3.2.1.4, 3.3.2.1.5, 3.3.2.1.8, 3.3.2.1.12, 3.3.2.1.13, and 3.4.2.1.4 and Tables 3.3.2-3, 3.3.2-4, 3.3.2-5, 3.3.2-8, 3.3.2-12, 3.3.2-13, and 3.4.2-4 are revised as shown in this Attachment to identify systems and components with internal coatings. LRA Sections A1.9, A1.10, A1.13, and A1.22 and Table A4-1, Item 9, are revised as shown in Attachment 15 to identify aging management activities that will be performed to manage loss of coating integrity for in scope components with internal coatings. LRA Table A4-1, Item 74 is added as shown in Attachment

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Enclosure 1 Section 3.3 Attachment 8 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 6 of 16 3.3.2.1.3 Saltwater and Chlorination System Materials The materials of construction for the saltwater and chlorination system component types are:* Metallic with Service Level Ill (augmented) Internal Coating Aging Effects Requiring Management The following saltwater and chlorination system aging effects require management: 0 Loss of coating integrity 3.3.2.1.4 Component Cooling Water System Materials The materials of construction for the component cooling water system component types are:*, Metallic with Service Level Ill (augmented) Internal Coating Aging Effects Requiring Management The following component cooling water system aging effects require management: a Loss of coating integrity 3.3.2.1.5 Makeup Water System Materials The materials of construction for the makeup water system component types are:* Metallic or cement with Service Level Ill (augmented) Internal Coating Aging Effects Requiring Management The following makeup water system aging effects require management:

• Loss of coating integrity I Enclosure 1 Section 3.3 Attachment 8 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 7 of 16 3.3.2.1.8 Chemical and Volume Control System Materials The materials of construction for the chemical and volume control system component types are: Metallic with Service Level Ill (augmented)

Internal Coating Aging Effects Requiring Management The following chemical and volume control system aging effects require management: 0 Loss of coating integrity 3.3.2.1.12 Fire Protection System Materials The materials of construction for the fire protection system component types are:* Metallic or cement with Service Level Ill (augmented) Internal Coating Aging Effects Requiring Management The following fire protection system aging effects require management:

• Loss of coating integrity 3.3.2.1.13 Diesel Generator Fuel Oil System Materials The materials of construction for the diesel generator fuel oil system component types are:* Metallic with Service Level Ill (augmented)

Internal Coating Aging Effects Requiring Management The following diesel generator fuel oil system aging effects require management: 0 Loss of coating integrity Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 8 of 16 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-3 Auxiliary Systems -Summary of Aging Management Evaluation -Saltwater and Chlorination System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping LBS, PB Carbon Steel Raw Water (Int) Loss of coating Open-Cycle Cooling None None H, 3 (with coating integrity Water System (B2.1.9)or lining)Valves LBS, PB Carbon Steel Raw Water (Int) Loss of coating Open-Cycle Cooling None None H, 3 (with coating integrity Water System (B2.1.9)or lining)Plant Specific Notes: 3 The Open-Cycle Cooling Water System (B2.1.9) program is used to monitor piping and valves fabricated of carbon steel (with internal coating or lining) with an internal environment of raw water (Int) for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8 in response to draft LR-ISG-2013-01, Appendix B, Table VII. Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 9 of 16 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-4 Auxiliary Systems -Summary of Aging Management Evaluation -Component Cooling Water System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Heat PB Nickel-Alloys Raw Water (Int) Loss of coating Open-Cycle Cooling None None H, 6 Exchanger (with coating integrity Water System (B2.1.9)(CCW Heat or lining)Exchanger) Heat PB Copper Alloy Raw Water (Int) Loss of coating Open-Cycle Cooling None None H, 6 Exchanger (with coating integrity Water System (B2.1.9)(CCW Heat or lining)Exchanger) Valve LBS, PB, Carbon Steel Closed Cycle Loss of coating Closed-Cycle Cooling None None H, 7 SIA (with coating Cooling Water (Int) integrity Water System (B2.1.10)or lining)Valve PB Carbon Steel Demineralized Loss of coating Inspection of Internal None None H, 8 (with coating Water (Int) integrity Surfaces in or lining) Miscellaneous Piping and Ducting Components (B2.1.22)Valve PB Copper Alloy Closed Cycle Loss of coating Closed-Cycle Cooling None None H, 7 (with coating Cooling Water (Int) integrity Water System (B2.1.10)or lining)Valve PB Stainless Closed Cycle Loss of coating Closed-Cycle Cooling None None H, 7 Steel (with Cooling Water (Int) integrity Water System (B2.1.10)coating or lining)Plant Specific Notes: 6 The Open-Cycle Cooling Water System (82.1.9) program is used to monitor components of the CCW Heat Exchanger fabricated from nickel-alloys or copper alloys (with intemal coating or lining) with an internal environment of raw water (Int) for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8 in response to draft LR-ISG-2013-01, Appendix B, Table VII. Enclosure 1 Section 3.3 Attachment 8 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 10 of 16 7 The Closed-Cycle Cooling Water System (B2. 1.10) program is used to monitor valves fabricated of carbon steel, copper alloy, and stainless steel (with internal coating or lining) closed cycle cooling water (Int) for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8 in response to draft LR-ISG-2013-01, Appendix B, Table VII.8 The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting (B2.1.22) program is used to monitor carbon steel (with internal coating or lining) with an internal environment of demineralized water (Int) for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, Appendix B, Table VII. Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 11 of 16 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-5 Auxiliary Systems -Summary of Aging Management Evaluation -Makeup Water System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping PB Asbestos Raw Water (Int) Loss of coating Inspection of Internal None None H, 6 Cement integrity Surfaces in (with coating Miscellaneous Piping or lining) and Ducting Components (B2.1.22)Tank LBS, PB Carbon Steel Demineralized Loss of coating Inspection of Internal None None H, 6 (with coating Water (Int) integrity Surfaces in or lining) Miscellaneous Piping and Ducting Components (B2.1.22)Tank PB Concrete Raw Water (Int) Loss of coating Inspection of Internal None None H, 6 (with coating integrity Surfaces in or lining) Miscellaneous Piping and Ducting Components (B2.1.22)Tank PB Fiberglass Demineralized Loss of coating Inspection of Internal None None H, 6 Water (Int) integrity Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)Plant Specific Notes: 6 The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting (82.1.22) program is used to monitor tanks fabricated from concrete, fiberglass, and carbon steel (with coating or lining), and piping fabricated from asbestos cement (with internal coating or lining) for loss of coating integrity with an internal environment of demineralized water (Int) or raw water (Int) .Reference DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, Appendix B, Table VII. Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 12 of 16 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-8 Auxiliary Systems -Summary of Aging Management Evaluation -Chemical and Volume Control System Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Pulsation LBS Elastomer Secondary Loss of coating Inspection of Internal Surfaces None None H, 10 Dampener Water (Int) integrity in Miscellaneous Piping and Ducting Components (B2.1.22)Heat PB Carbon Lubricating Oil Loss of coating Inspection of Internal Surfaces None None H, 10 Exchanger Steel (Int) integrity in Miscellaneous Piping and (Centrifugal (Galvanize Ducting Components (B2.1.22)ICharging) IId) I Plant Specific Notes: 10 The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting (B2.1.22) program is used to monitor pulsation dampers (with internal coating or lining) with an internal environment of secondary water (Int) and centrifugal charging heat exchanger (with internal coating or lining)with an internal environment of lubricating oil for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, Appendix B, Table VII. Enclosure 1 Section 3.3 Attachment 8 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 13 of 16 Table 3.3.2-12 Auxiliary Systems -Summary of Aging Management Evaluation -Fire Protection System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping PB Asbestos Raw Water (Int) Loss of coating Inspection of Internal None None H, 5 Cement (with integrity Surfaces in coating or Miscellaneous Piping lining) and Ducting Components (B2.1.22)Piping PB Carbon Steel Raw Water (Int) Loss of coating Fire Water System None None H, 6 (Galvanized) integrity (B2.1.13)Tank PB Carbon Steel Raw Water (Int) Loss of coating Fire Water System None None H, 6 (with coating integrity (B2.1.13)or lining)Plant Specific Notes: 5 The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting (B2.1.22) program is used to monitor asbestos concrete piping (with internal coating or lining) with an internal environment of raw water for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, Appendix B, Table VII.6 The Fire Water System (B2.1.13) program is used to monitor piping fabricated from carbon steel (with internal coating or lining) and tanks fabricated from carbon steel (with internal coating or lining) with an internal environment of raw water for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, Appendix B, Table VII. Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 14 of 16 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-13 Auxiliary Systems -Summary of Aging Management Evaluation -Diesel Generator Fuel Oil System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Tank PB Carbon Steel Fuel Oil (Int) Loss of coating Inspection of Internal None None H, 2 (with coating integrity Surfaces in or lining) Miscellaneous Piping and Ducting Components (B2.1.22)Plant Specific Notes: 2 The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting (B2.1.22) program is used to monitor tanks fabricated from carbon steel (with internal coating or lining) with an internal environment of fuel oil for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, Appendix B, Table VII. Enclosure 1 Section 3.4 Attachment 8 AGING MANAGEMENT OF STEAM AND PG&E Letter DCL-14-103 POWER CONVERSION SYSTEMS Page 15 of 16 3.4.2.1.4 Condensate System Materials The materials of construction for the condensate system component types are:* Metallic with Service Level Ill (augmented) Internal Coating Aging Effects Requiring Management The following condensate system aging effects require management:

• Loss of coating integrity Enclosure 1 Attachment 8 PG&E Letter DCL-14-103 Page 16 of 16 Table 3.4.2-4 Steam ai System Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEMS id Power Conversion System -Summary of Aging Management Evaluation

-Condensate Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Demineralizer LBS Carbon Steel Secondary Water Loss of coating Inspection of Internal None None H, 5 (with coating (Int) integrity Surfaces in or lining) Miscellaneous Piping and Ducting I Components (B2.1.22)Plant Specific Notes: 5 The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting (B2.1.22) program is used to monitor condensate polisher demineralizers fabricated from carbon steel (with internal coating or lining) with an internal environment of secondary water for loss of coating integrity. Reference DCL-14-103, Enclosure 1, Attachment 8 in response to draft LR-ISG-2013-01, Appendix B, Table VIII. Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 1 of 14 Updates to Reflect Installed Plant Equipment and Editorial Corrections The annual review of components identified required changes in materials, environments, and other clarifications. As a result of the review, PG&E is revising the following LRA sections and tables. Unless otherwise indicated, LRA markups are provided in this Attachment. (1) Section 2.1.2.2: During the development of the LRA, DCPP included all nonsafety-related SSCs in the auxiliary building, containment, and the fuel handling building as being within the scope of license renewal for Criterion (a)(2) spatial interaction considerations, except as discussed in LRA Sections 3.1.1 and 3.1.2. As a result, no room by room or any similar structure breakdown was required for these structures. However, engineering evaluations have determined that certain nonsafety-related SSCs are located such that there is no potential to impact safety-related SSCs. Inclusion of these nonsafety-related SSCs in the scope of License Renewal will present an undue burden for inspection or replacement. PG&E is updating its scoping and screening methodology to allow nonsafety-related systems and components that contain fluid or steam included in-scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2), and are located inside structures that contain safety-related SSCs, to be scoped out if a component-specific engineering evaluation is performed. LRA Section 2.1.2.2 is updated to reflect this change in methodology. (2) Section 2.3.2.4: The description of the control rod drive mechanism exhaust system is updated to reflect the replacement reactor head configuration. The replacement reactor heads were installed in Units 1 and 2 in 2010 and 2009, respectively. (3) Table 3.3.2-3: During a review of design documents, PG&E determined that a portion of existing, in-scope, buried piping in the ASW system is super austenitic stainless steel and not carbon steel, as currently listed in Table 3.3.2-3. Table 3.3.2-3 is revised to include this material and environment combination of the existing in-scope piping. The aging management of this piping is discussed in Attachment 3.(4) Table 3.3.2-5: In the makeup water system, PG&E has replaced the temporary PVC portable emergency eyewash stations with permanent emergency eyewash/shower stations made of stainless steel. Table 3.3.2-5 is revised to reflect this different material.(5) Table 3.3.2-7: An editorial correction is made to specify the correct AMP number for the Selection Leaching of Materials AMP. PG&E has also removed an in-scope stainless steel valve from the plant. Since this valve Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 2 of 14 was the only in-scope stainless steel valve in the system with a leakage boundary spatial interaction function, an internal environment of demineralized water and an external environment of plant indoor air, the associated Table 3.3.2-7 line items are revised.(6) Table 3.3.2-8: PG&E determined that Valve LWS-0-TCV-1 0 was actually Valve DC-0-08-P-V-CVCS-0-TCV-10, which was verified to already be in-scope of license renewal. LWS-0-TCV-10 had previously been evaluated and assigned a material of stainless steel. Table 3.3.2-8 line items pertaining to LWS-0-TCV-10 are being deleted.(7) Table 3.3.2-9: PG&E determined that Valves VAC-1-442 and VAC-1-443 were no longer installed in the plant. The valve material is copper alloy and the intended function is structural integrity attached. The external environment is plant indoor air and the internal environment is ventilation atmosphere. Since these valves are the only ones in the system with an intended function of structural integrity attached, structural integrity attached is deleted from the applicable Table 3.3.2-9 line items.(8) Table 3.3.2-11: PG&E determined that the material property for test connections PX-449 and PX-450 in the auxiliary building/heating, ventilation, and air conditioning system is carbon steel. Table 3.3.2-11 line items are added/modified to account for the associated material and environment combination. (9) Table 3.3.2-12: PG&E determined that in-scope fire water sprinklers were brass (copper alloy greater than 15 percent Zn). Table 3.3.2-12 line items are revised to align the LRA with actual plant component information. (10) Table 3.3.2-12 and Section A1.18: PG&E determined that Valve FP-0-1212 was not in-scope of license renewal because it is part of the fire protection system portion that is not relied upon in the fire hazards analysis. The valve material is stainless steel and the intended function is pressure boundary.The external environment is buried and the internal environment is raw water.Since this was the only buried stainless steel valve in the system, the associated line item is deleted from Table 3.3.2-12. Since the deleted component was the only non super austenitic stainless steel component in the scope of the Buried Piping and Tanks Inspection program, Section A1.18 is revised as shown in Attachment 15 to delete reference to visual inspection of stainless steel. The super austenitic stainless steel piping will be managed consistent with LR-ISG-2011-03 as described in Attachment

3.

Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 3 of 14 (11) Table 3.3.2-18: PG&E determined that Sample Coolers -81 in Units 1 and 2 are in-scope of license renewal. Table 3.3.2-18 line items are added to reflect the sample coolers.(12) Table 3.4.2-1: PG&E determined that the Steam Generator Blowdown Tanks are exposed to an environment of atmosphere/weather. Table 3.4.2-1 line items are revised to align the LRA with the actual plant configuration. Enclosure 1 Section 2.2 Attachment 9 PLANT-LEVEL SCOPING RESULTS PG&E Letter DCL-14-103 Page 4 of 14 2.1.2.2 Title 10 CFR 54.4(a)(2) -Nonsafety-Related Affecting Safety-Related Nonsafety-Related SSCs with Spatial Interaction with Safety-Related SSCs The preventative option as implemented at DCPP is based on an approach for scoping of nonsafety-related SSCs having potential spatial interaction with safety-related SSCs. Potential spatial interaction is evaluated for any SSC in proximity to active or passive safety-related SSCs. The structures of concern for potential spatial interaction were identified based on the review of the CLB to determine which structures contained safety-related SSCs.Nonsafety-related systems and components that contain fluid or steam, and are located inside structures that contain safety-related SSCs are included in scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2) unless scoped out by a component-specific engineering evaluation. Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 5 of 14 Section 2.4 SCOPING AND SCREENING RESULTS: STRUCTURES 2.3.2.4 Containment HVAC System Control Rod Drive Mechanism (CRDM) Exhaust System The purpose of the CRDM exhaust system is to remove heat from the CRDM area during normal plant operation. This system consists of integrated shroud assemblies and cooling ducts, an air plenum, exhaust fans, and backdraft dampersexhaust fans mounted on the removable CRDM shroud. This system is not designed to operate during accident conditions. Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 6 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Summary of Aging Management Evaluation -Saltwater and Chlorination System Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 7 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-5 Auxiliary Systems -Summary of Aging Management Evaluation -Makeup Water System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Eye Wash Sink LBS Stainless Plant Indoor Air None None VIIJ- 3.3.1.94 PC Steel (Ext) 15NePne Nene Polyvnyl Eye Wash Sink LBS Stainless Plant Indoor Air None None None None FG Steel (Int)Gh~Fde-I IkP 49D I II;I Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 8 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-7 Auxiliary Systems -Summary of Aging Management Evaluation -Compressed Air System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Regulators PB Copper Alloy Atmosphere/ Loss of material Selective Leaching of None None G (> 15% Zinc) Weather (Ext) Materials (B2.1.4-17) Valve b-BS Stainless-DemineFrie Loss of m~terW WateFhemist~y-V11kE-29 3&.4. A Steel WateF-{1,t) (B2.102) and One Time_______ npecton (2.1.16)Valve -BS-,PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A SIA Steel (Ext) Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 9 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3. 2-8 Auxiliary Systems -Summary of "Aaina Manaaement Evaluation -Chemical and Volume Control System Tal 3.32- Aux .Svtm -Sumr o.. Aan ---eetEalain-CeicladVlm CnrlSs Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Valve 1=138,,S! Sta*Rles em Graekli Water Chemisty (12. 1.2) 2 .4.1.3\Valve ILBS, SIA Staai~less Steam (knt) L966 Of material Water Chemty (B2..B 1.2 3n.I 4..3 Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 10 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-9 Auxiliary Systems -Summary of Aging Management Evaluation -Miscellaneous HVAC Systems Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Valve SIA4-SS CopperAlloy PlantlndoorAir None None VIII.1-2 3.4.1.41 C (Ext)Valve S4AFSS Copper Alloy Ventilation Loss of material Inspection of Internal VII.G-9 3.3.1.28 E Atmosphere (Int) Surfaces in Miscellaneous Piping and Ducting_Components (B2.1.22) Enclosure 1 Section 3.3 Attachment 9 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 11 of 14"l"hl,'Q "I 1z 9-11 AIvilinr .qcftamc -- .mmn rof A,'iinn R -nmrarnn l:iiIh irin -- Av a lilinri, I~bnlrlin, l-I/iA I 4J ...M 1 I I ~ J III i III II.I)UI .[ I [1 111I I I%5VItUlISAU tII IItl IL V LEIS flIIU I I.I IIlv11 vr-t.. .s tl~fL.? ll Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Notes Type Function Requiring Program 1801 Vol. Item Management 2 Item Test Connection LBS Carbon Steel Plant Indoor Loss of material External Surfaces Monitoring Vl1.l-8 3.3.1.58 B Air (Ext) Program (B2.1.20)Test Connection LBS Carbon Steel Plant Indoor Loss of material Inspection of Internal VII. G-23 3.3.1.71 B Air (Int) Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)Test Connection LBS-,SIA Stainless Plant Indoor None None VII.J-15 3.3.1.94 A Steel Air (Ext)Test Connecto 1.49 Stainleess-Plant4Rndef Less of mnateria Inspectien of Internal VI-I.F241 3.3..27 E Steel Aif--(-Int Surface in Misoellaneoc'J Piping and (DUcting_____ ____ __ _ ____ _ __ ____ __ _ ____ ____ ____ ____ ___ ~ .;;~~;;;;tc(92.1.22) _ _ _ _ _ _ _ _ _ _ _ _ _ Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 12 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS S-5 fl1 ~ t A ES-----.1 rgt,~ r* -.r ,' a -.,n e.I aDle J.J...- z wxlnar .ysrems -ummary or k rlng ivianagement Evaluation -F-ire P-rotection Sysrem (Conanu ed)Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Spray Nozzle SP GaFboR-S Atmosphere/ Loss of Material Ext,=" aI Sur..a.es Monitorin-g V11...9 BG CopperAlloy Weather (Int) Program. (12.1.20) None None (> 15% Zinc Selective Leaching of Materials (B2.1.17)Spray Nozzle SP Atmosphere/ Loss of Material Ext=ernal Surfa.es V41W.-9 343A.58 BG CopperAlloy Weather (Ext) (.2.1.20) None None (> 15% Zinc Selective Leaching of Materials (B2.1.17)Spray Nozzle SP Stainless-Plant Indoor Air None None V114S A Steel (Ext) VIII.I-2 3.4.1.41 Copper Alloy (> 15% Zinc)Spray Nozzle SP Stainless-Plant Indoor Air None None None None G Steel (Int)Copper Alloy (> 15% Zinc)Spray Nozzle SP Copper Alloy Raw Water (Int) Loss of Material Selective Leaching of VII.G-13 3.3.1.84 A_> 15% Zinc) Materials (B2.1.17) _ __ _7 Valve P-B Stainless-Buie } Loss of materil Buried Piping and Tanks V"G 20 3 4....__________Steel _______ _______Inspection (B2.11)_____ ______ ____ Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 13 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-18 Auxiliary Systems -Summary of Aging Management Evaluation -Miscellaneous Systems in scope ONLY for Criterion 10 CFR 54. 4(a) (2)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Heat LBS Stainless Plant Indoor Air None None VIII.-10 3.4.1.41 A Exchanger Steel (Ext)(Sample Cooler)Heat LBS Stainless Secondary Water Loss of material Water Chemistry VIII. C-1 3.4.1.16 A Exchanger Steel (Int) (B2.1.2) and One-Time (Sample Inspection (B2.1.16)Cooler)Heat LBS Stainless Secondary Water Cracking Water Chemistry VII. C-2 3.4.1.14 A Exchanger Steel (Int) (B2.1.2) and One-Time (Sample Inspection (B2.1.16)Cooler)Heat LBS Stainless Closed Cycle Loss of material Closed-Cycle Cooling VIII.E-24 3.4.1.25 B Exchanger Steel Cooling Water (Int) Water (B2. 1.10)(Sample Cooler)Heat LBS Stainless Closed Cycle Cracking Closed-Cycle Cooling VIII.E-25 3.4.1.23 B Exchanger Steel Cooling Water (Int) Water (B2. 1.10)(Sample Cooler) Enclosure 1 Attachment 9 PG&E Letter DCL-14-103 Page 14 of 14 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Table 3.4.2-1 Steam and Power Conversion System -Summary of Aging Management Evaluation -Turbine Steam SuDDIv Svstem Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Tank SIA Carbon Steel Atmosphere/ Loss of material External Surfaces VIILH-7 3.4.1.28 B Weather (Ext) Monitoring Program I_ _(B2.1.20) Enclosure 1 Attachment 10 PG&E Letter DCL-14-103 Page 1 of 2 Removal of Caustic Dilution Heat Exchanger Tubes Exposed to Secondary Water from Scope of License Renewal LRA Section 2.3.4.4 states that high energy portions of the condensate system in the turbine building are in the scope of license renewal since they could prevent the satisfactory accomplishment of a safety-related function associated with certain safety-related cables. LRA Table 3.4.2-4 is revised to remove the caustic dilution heat exchanger tube sheet exposed to secondary water from the scope of license renewal since the tube sheet is not a high energy portion of the condensate system.The caustic dilution heat exchanger shell (steam side) will appropriately remain in the scope of license renewal. Refer to revised LRA Table 3.4.2-4 in this Attachment. Enclosure 1 Attachment 10 PG&E Letter DCL-14-103 Page 2 of 2 Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Table 3.4.2-4 Steam and Power Conversion System -Summary of Aging Management Evaluation -Condensate Svstem Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Heat- LBS WAate Les of materi Water Ghemietpy-VIJLA-5 34-.... G EXGhanteF (E*t (132.1.2) and One Time (Gaw.eti(; inspectien (B2.1.16) Enclosure 1 Attachment 11 PG&E Letter DCL-14-103 Page 1 of 5 Update to Reflect WCAP-1 7103 Revisions that Addressed Regulatory Issue Summary 2011-14 Regarding User Intervention in Westems T M.In December 2011, the NRC issued RIS 2011-14, "Metal Fatigue Analysis Performed by Computer Software." This RIS was concerned with Westinghouse WestemsTM software, which allows for a user to manually modify stress peak and valley times in the total stress intensity time history used to calculate the cumulative usage factor.WCAP-17103, "Diablo Canyon Unit 1 Insurge/Outsurge and Environmental Fatigue Evaluations" and WCAP-17104, "Diablo Canyon Unit 2 Insurge/Outsurge and Environmental Fatigue Evaluations" were completed for license renewal and used the Westinghouse WestemsTM software. Both WCAPs were revised to justify user intervention when calculating the fatigue usage. New analyses were performed for Units 1 and 2 to clearly demonstrate the peak selection process. For Unit 1 (WCAP-17103), the new analysis resulted in a change to the calculated pressurizer heater penetration cumulative usage factor. The component remains qualified. The new Unit 2 analysis did not result in any cumulative usage factor changes. Refer to revised LRA Tables 4.3-1 and 4.3-6 and Section 4.9 in this Attachment. Enclosure 1 Attachment 11 PG&E Letter DCL-14-103 Page 2 of 5 Section 4 TIME-LIMITED AGING ANALYSES Table 4.3-1 Summary of Monitored Fatigue Usage, and Method of Management by the Enhanced DCPP Fatigue Management Program Maximum Design CUF Fatigue Component UManagement CtUnit Unit 2 Method RPV Closure Studs 0.7537 0.7537 Global Inlet Nozzle / Support Pad~a) 0.142 0.142 Global Outlet Nozzle / Support Pad&a) 0.311 0.311 Global RPV Core Support Pads 0.892 0.892 Global RPV Bottom Head to Shell~a) 0.0102 0.0102 CBF Hot Leg Surge Nozzleta) 0.5387 0.5387 CBF Pressurizer Spray Nozzle 0.9469 0.7840 Global Pressurizer Heater Penetration 0443940.9598 0.5442 Global Unit 2 Pressurizer Upper Head and Shell NA 0.7598 Global RCS Cold Leg Charging Line Nozzle a) 0.0641 0.0641 CBF Accumulator Safety Injection Nozzleta"'o 0 2.6353 2.6353 CBF RHR-to-Accumulator Safety Injection 0.0093381 0.0093381 CBF Line Tee(a) 1_.0381 100938___Location is a NUREG/CR-6260 location for older vintage Westinghouse plants For further discussion of the Accumulator Safety Injection Nozzle design CUF of greater than 1.0, refer to Section 4.3.4.(a)(b) Enclosure 1 Attachment 11 PG&E Letter DCL-14-103 Page 3 of 5 Section 4 TIME-LIMITED AGING ANALYSES Table 4.3-6 Summary of DCPP Pressurizer A SME Section III Class A Analyses and Fatigue Usage Factors Limiting Location CUF Component Analysis Unit I Unit 2 50-Year 60-Year 50-Year 60-Year Value Projection(a) Value Projection(a) Surge Nozzle Analysis 0.2288 0.2746 0.2201 0.2641 Spray Nozzle Analysis 0.9469 1.13628 0.784 0.9408 Safety and Relief Nozzle 0.0062 0.00744 0.069 0.0828 Analysis Head to Shell Head to Shell 0.088 0.1056 Lower Head Welds(b) Head to Shell Head to Shell 0.2304 0.2765 Head to Head to Surge Nozzle Surge Nozzle 0.2276 0.2731 0.)293-0. 9598 Heater Penetration 2.9643 0.5443 0.6532 Upper Head and Shell 0.2869 0.34428 0.7498 0.8997 Analysis(b) Support Skirt and Flange 0.0045 0.0054 0.0045 0.0054 Analysis 0.269 (lug), 0.3228 (lug), 0.269 (lug), 0.3228 (lug), Support Lug Analysis 0.188 (shell) 0.2256 (shell) 0.188 (shell) 0.2256 (shell)Sa <Manway Analysis 0.00 -endurance -limit(d)Upper Instrument Nozzle 0.121 0.1452 0.121 0.1452 Analysis Lower Instrument Nozzle 0.0424 0.05088 0.08672 0.0037 Analysis Immersion Heater Analysis 0.005 0.006 0.005 0.0060 Valve Support Bracket NA NA 0.0418 0.0502 Analysis Enclosure 1 Attachment 11 PG&E Letter DCL-14-103 Page 4 of 5 Section 4 TIME-LIMITED AGING ANALYSES (a) 60-year Projection = 50-year Design CUF x 1.2 (b) The Unit 1 pressurizer upper and lower heads are cast. The Unit 2 pressurizer upper and lower heads are fabricated.(c) This value is the result of a fatigue analysis performed using the 60-year projected number of transients instead of the design basis numbers of transients.(d) An alternating stress (Sa) less than the endurance limit indicates that there is no fatigue life associated with this components.(e) Unit 1 has no such support bracket. Enclosure 1 Attachment 11 PG&E Letter DCL-14-103 Page 5 of 5 Section 4 TIME-LIMITED AGING ANALYSES

4.9 REFERENCES

20. Westinghouse Report WCAP-17103.

Diablo Canyon Unit I Insurge/Outsurge and Environmental Fatigue Evaluations. Rev. 44. May 2013Otobe 2 .Westinghouse Proprietary Class 2. Enclosure 1 Attachment 12 PG&E Letter DCL-14-103 Page 1 of 3 Reactor Coolant Pump Flywheel Inspection Interval The current TLAA for the RCP flywheel relies on use of NRC Staff-approved WCAP-14535-A to relax the inspection requirements for the RCP flywheel. As stated in LRA Section 4.7.4 and SER Section 4.7.4, WCAP-14535-A performed an evaluation of the probability of failure over the PEO for all operating Westinghouse plants. It demonstrates that the flywheel design has a high structural reliability with a very high flaw tolerance and negligible flaw crack extension assuming 6,000 pump starts over a 60-year life. Since the evaluation is based on the 60-year operating period, the TLAA covers the PEO and is dispositioned under 10 CFR 54.21(c)(1)(i). By letter "Diablo Canyon Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Revision to Technical Specification 5.5.7, 'Reactor Coolant Pump Flywheel Inspection Program,'.in Accordance with TSTF-421A, Revision 1," dated September 5, 2013, the NRC Staff issued Amendment Nos. 216 and 218 to the Units 1 and 2 facility operating licenses, respectively to rely on the analysis provided in WCAP-1 5666-A, Revision 1, "Extension of Reactor Coolant Pump Motor Flywheel Examination." LRA Sections 4.7.4 and 4.9 are revised to reflect License Amendments 216 and 218. LRA Section 4.7.4 is also revised to reflect an additional change in response to request for additional information 4.1-2 in PG&E Letter DCL-1 0-123, "Response to NRC Letter dated August 30, 2010, 'Request for Additional Information (Set 21) for the Diablo Canyon License Renewal Application,"' dated September 29, 2010.Refer to revised LRA Sections 4.7.4 and 4.9 in this Attachment. Enclosure 1 Section 4 Attachment 12 TIME-LIMITED AGING ANALYSES PG&E Letter DCL-14-103 Page 2 of 3 4.7.4 Reactor Coolant Pump Flywheel Fatigue Crack Growth Analysis Summary Description NUREG-1800 identifies "Fatigue analysis of the reactor coolant pump flywheel" as a potential TLAA.During normal operation, the reactor coolant pump flywheel possesses sufficient kinetic energy to potentially produce high-energy missiles inside containment and could also damage pump seals or other pressure boundary components in the unlikely event of failure. Conditions that may result in overspeed of the reactor coolant pump increase both the potential for failure and the kinetic energy. The aging effect of concern is fatigue crack initiation in the flywheel bore keyway. This concern is the subject of Regulatory Guide 1.14, Reactor Coolant Pump Flywheel Integrity. At^ CP, flyD...hecl fatigue is a rccognized aging effect, but the aging efect is not the subject of a TLAA.The original DCPP SER, NUREG-0675, states that the RCP motor flywheel is designed to meet the guidelines of Regulatory Guide 1.14. The DCPP flywheel design and its compliance with Regulatory Guide 1.14 is described in the FSAR Section 5.2.6. The inspection recommendations are incorporated in the DCPP ISI Program and are required by the TS.To reduce the inspection frequency and scope, DCPP amended its initial compliance with Regulatory Guide 1.14 by implementing WCAP.4453515666-A [Reference 9], which supports relaxation of the inspection required by Regulatory Guide 1.14 Position C.4.b(1) and (2). The NRC has reviewed and accepted this topical report for use in license renewal applications. This relaxation was approved for DCPP with-the-Improved T.S conversion [Reference 12] and was incorporated into the DCPP ISI Program and the TS.Analysis WCAP4453515666-A [Reference 9] performed an evaluation of the probability of failure over the period of extended operation for all operating Westinghouse plants. It demonstrates that the flywheel design has a high structural reliability with a very high flaw tolerance and negligible flaw crack extension assuming 6,000 pump starts over a 60 year life. Since the evaluation is based on the 60-year operating period, the TLAA covers the period of extended operation and is dispositioned under 10 CFR 54.21E(1)(i). Disposition: Validation, 10 CFR 54.21E(1)(i) Using a conservative projection of 1,000 cycles for a 60 year plant life, the 6,000 events assumed in the fatigue crack growth analysis for the reactor coolant pump flywheels during 60 years of operation is conservative. The analysis is valid for the period of extended operation in accordance with 10 CFR 54.21*(1)(i). Enclosure 1 Attachment 12 PG&E Letter DCL-14-103 Page 3 of 3

4.9 REFERENCES

Section 4 TIME-LIMITED AGING ANALYSES 9.WAlstinghouse Report WGAP 14535 A. Westinghouse Topic-al Rep-rt. P. L.v trniiurh al Tnonil QR.'ft on Rea.Ghen Coolant MtVI=.. Ara.I .Qm.#1^ =11 -41^ 0;" k k XAI- 6; k KI k 14 nn I #VVI 12.NIl v # -.T I.*s .#*t". a. a q V = 0 ql .V ., m lv mm NVV Or-Westinghouse Report WCAP-15666-A, Revision 1. Westinghouse Topical Report. P.L. Strauch et al. Extension of Reactor Coolant Pump Motor Flywheel Examination. Pittsburgh: Westinghouse, October 2003.US NRC Letter. FroGm Jack N. Donoehew, Senior Projectl Managor, Secation 1 Projecst Directorate IV & Decommissioning, DiVision Of Licensing Project-Management, Office of Nuclear Regulation; to Mr. Grogor' M. SenieoFrVie President and Manager, DCPP. "Conversion to Improved T-echnical Speoficatoone forDiablo Canyon Power Plant, U~nits 1 an~d 2 ,Amendment No. 135 to Facaility Operating License Nos. DPR 80 and DPR 82-(TAG Nos. M98984 an~d M98985)." 28 May 10901.US NRC Letter. From Jennie K. Rankin, Project Manager, Plant Licensing Branch IV, Division of Operating Reactor Licensing, Office of Nuclear Reactor Regulation; to Mr. Edward D. Halpin, Senior Vice President and Chief Nuclear Officer, DCPP. "Diablo Canyon Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Revision to Technical Specification 5.5.7, "Reactor Coolant Pump Flywheel Inspection Program," in Accordance with TSTF-421-A, Enclosure 1 Attachment 13 PG&E Letter DCL-14-103 Flow-Accelerated Corrosion Program (B2.1.6)PG&E revises the DCPP FAC program to address NSAC-202L-R4.

Background

In PG&E Letter DCL-09-079, Enclosure 1, Appendix B2.1.6, PG&E took an exception to NUREG-1801, Scope of Program -Element 1 and Detection of Aging Effects -Element 4, as follows: "NUREG-1801, Section XI.M17, states that the FAC program should be based on the recommendations in NSAC-202L-R2. The guidelines provided in the governing procedure are based on the recommendations provided in the EPRI Guideline NSAC-202L-R3. The third revision of NSAC-202L contains recommendations updated with the experience of members of the CHECWORKS Users Group (CHUG), plus recent developments in detection, modeling, and mitigation technology. These recommendations are intended to refine and enhance those of the earlier versions, without contradiction, so as to ensure the continuity of existing plant FAC programs. The guidance contained in the third revision of NSAC-202L supersedes that contained in all prior versions of NSAC-202L." In letter, "Safety Evaluation Report Related to the License Renewal of Diablo Canyon Nuclear Power Plant, Units 1 and 2," dated June 2, 2011, Section 3.0.3.2.2, "Flow Accelerated Corrosion," the NRC Staff found EPRI NSAC-202L-R3 acceptable because it will continue to allow the applicant to manage wall thinning due to flow-accelerated corrosion on the internal surfaces of carbon and low alloy steel piping and components that contain both single-phase and two-phase, high-energy fluids.PG&E revises its exception to NUREG-1801, Scope of Program -Element 1 and Detection of Aging Effects -Element 4, to utilize the guidelines provided in the governing procedure based on the recommendations provided in the EPRI Guideline NSAC-202L-R4. The recommendations in NSAC-202L-R4 are intended to refine and enhance those of the earlier versions, without contradiction, so as to ensure the continuity of existing plant FAC programs. The guidance contained in NSAC-202L-R4 supersedes that contained in all prior versions of NSAC-202L. PG&E also revises NSAC-202L's revision from Revision 3 to Revision 4 in LRA Section A1.6 as shown in Attachment

15.

Enclosure 1 Attachment 14 PG&E Letter DCL-14-103 Page 1 of 4 License Renewal Application Chapter 2 Update to Address LR-ISGs As shown on the following pages, LRA Section 2.1.5, "Interim Staff Guidance" is updated to add LR-ISG-2011-01 through LR-ISG-2011-05; LR-ISG-2012-01 and LR-ISG-2012-02; and Draft LR-ISG-2013-01 to LRA Table 2.1-2, "NRC Interim Staff Guidance Associated with License Renewal." LRA Sections 2.1.5.8 through 2.1.5.15 were added to provide a summary discussion of the LR-ISGs added to LRA Table 2.1-2. Enclosure 1 Attachment 14 PG&E Letter DCL-14-103 Page 2 of 4 2.1.5 Interim Staff Guidance Section 2.1 SCOPING AND SCREENING METHODOLOGY Table 2.1-2 NRC Interim Staff Guidance Associated with License Renewal Issue Number Purpose Discussion Status LR-ISG-201 1-01 Aging Management of Stainless Steel The staff has issued LR-ISG-2011-01, Structures and Components in Revision I Treated Borated Water LR-ISG-2011-02 Aging Management Program for The staff has issued LR-ISG-2011-02 Steam Generators LR-ISG-2011-03 Aging Management Program for The staff has issued LR-ISG-2011-03 Buried and Underground Piping and Tanks LR-ISH-2011-04 Updated Aging Management The staff has issued LR-ISG-2011-04 Criteria for Reactor Vessel Internal Components of Pressurized Water Reactors LR-ISG-2011-05 Ongoing Review of Operating The staff has issued LR-ISG-2011-05 Experience LR-ISG-2012-01 Wall Thinning Due to Erosion The staff has issued LR-ISG-2012-01 Mechanisms LR-ISG-2012-02 Aging Management of Internal The staff has issued LR-ISG-2012-02 Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation LR-ISG-2013-01 Aging Management of Loss of The staff has issued for public Coating Integrity for Internal Service comment draft LR-ISG-2013-01 Level Ill (Augmented) Coatings 2.1.5.8 (LR-ISG-2011-01) Aging Management of Stainless Steel Structures and Components in Treated Borated Water The staff has issued this LR-ISG to provide guidance as to one acceptable approach for managing the effects of aging during the period of extended operation for stainless steel structures and components exposed to treated borated water within the scope of license renewal. This LR-ISG is discussed in PG&E Letter DCL-14-103. 2.1.5.9 (LR-ISG-2011-02) Aging Management Program for Steam Generators The staff has issued this LR-ISG to evaluate the suitability of using Revision 3 of NEI 97-06 to manage steam generator aging and to correct an incorrect revision in NUREG-1801, Revision 2, to the Steam Generator Integrity Assessment Guidelines. This LR-ISG is discussed in PG&E Letter DCL-14-103. Enclosure 1 Section 2.1 Attachment 14 SCOPING AND SCREENING METHODOLOGY PG&E Letter DCL-14-103 Page 3 of 4 2.1.5. 10 (LR-ISG-2011-03) Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, "Buried and Underground Piping and Tanks" The staff has issued this LR-ISG to provide one acceptable approach for managing the effects of aging of buried and underground piping and tanks within the scope of the License Renewal Rule. This LR-ISG is discussed in PG&E Letter DCL-14-103. 2.1.5.11 (LR-ISG-2011-04) Updated Aging Management Criteria for Reactor Vessel Internal Components of Pressurized Water Reactors The staff issued this LR-ISG to revise the recommendations in the GALL Report and the NRC Staff's acceptance criteria and review procedures in the SRP-LR to ensure consistency with MRP-227-A. This LR-ISG also provides a framework to ensure that PWR license renewal applicants will adequately address age-related degradation and aging management of reactor vessel internal components during the term of the renewed license. This LR-ISG is discussed in PG&E Letter DCL-14-103. 2.1.5.12 (LR-ISG-2011-05) Ongoing Review of Operating Experience The staff issued this LR-ISG to provide a framework to ensure that license renewal applicants' operating experience review activities will adequately address operating experience concerning age-related degradation and aging management during the term of the renewed license. This LR-ISG is discussed in PG&E Letter DCL-14-103. 2.1.5.13 (LR-ISG-2012-01) Wall Thinning Due to Erosion Mechanisms The staff issued this LR-ISG to provide interim guidance for an approach acceptable to the NRC Staff to manage the effects of aging during the period of extended operation for wall thinning due to various erosion mechanisms for piping and components within the scope of the License Renewal Rule. This LR-ISG is discussed in PG&E Letter DCL-14-103. 2.1.5.14 (LR-ISG-2012-02) Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation The staff issued this LR-ISG to provide an acceptable approach for managing the associated aging effects for components within the scope of the License Renewal Rule.This LR-ISG is discussed in PG&E Letter DCL-14-103. Enclosure 1 Attachment 14 PG&E Letter DCL-14-103 Page 4 of 4 Section 2.1 SCOPING AND SCREENING METHODOLOGY 2.1.5.15 (LR-ISG-2013-01) Aging Management of Loss of Coating Integrity for Internal Service Level Ill (Augmented) Coatings This draft LR-ISG was issued in draft for public comment. This draft LR-ISG provides an acceptable approach for managing loss of coating integrity in service level Ill (augmented) coatings for components within the scope of the License Renewal Rule.This draft LR-ISG is discussed PG&E Letter DCL-14-103. Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 1 of 31 LRA Appendix A, "Final Safety Analysis Report Supplement" This Attachment contains revisions to LRA Appendix A resulting from the 2014 DCPP LRA Update. Below is a basis for the changes or a reference to the Attachment that contains the basis.(1) Section Al: Refer to Attachment 5, "LR-ISG-2011-05, 'Ongoing Review of Operating Experience."' (2) Section A1.2: The Water Chemistry Program FSAR Supplement is updated to add the aging effect of reduction of heat transfer listed in LRA Chapter 3 Tables.(3) Section A1.6: (a) Refer to Attachment 6, "LR-ISG-2012-01, 'Wall Thinning Due to Erosion Mechanisms."'(b) Refer to Attachment 13, "Flow-Accelerated Corrosion Program (B2.1.6)." PG&E revises NSAC-202L Revision 3 to Revision 4.(4) Section A1.9: (a) The Open Cycle Cooling Water System program FSAR Supplement is revised to clarify that the program is consistent with PG&E Letters DCL-90-027, dated January 26, 1990, and DCL-91-286, dated November 25, 1991, in response to NRC Generic Letter 89-13 regarding performance testing of the component cooling water heat exchangers.(b) Refer to Attachment 8, "Draft LR-ISG-2013-01, 'Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings.' (5) Section A1.10: Refer to Attachment 8, "Draft LR-ISG-2013-01, 'Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings."' Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 2 of 31 (6) Section A1.13: (a) Refer to Attachment 7C, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section C, "Flow Blockage of Water-Based Fire Protection System Piping, GALL Report AMP XI.M27, 'Fire Water System."'(b) Refer to Attachment 8, "Draft LR-ISG-2013-01, 'Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings.' (7) Section Al.15: Refer to Attachment

17. In order for PG&E to participate in the EPRI PWR Supplemental Surveillance Program, the donated specimens will no longer be stored.(8) Section A1.16: Refer to Attachment 16, "One-Time Inspection." PG&E adopts the NUREG-1801, Revision 2 sample size where the One-Time Inspection program verifies the effectiveness of the DCPP Water Chemistry, Fuel Oil Chemistry, and Lubricating Oil Analysis programs." (9) Section Al.18: (a) Refer to Attachment 3, "LR-ISG-2011-03, 'Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, 'Buried and Underground Piping and Tanks."" (b) Refer to Attachment

9. Section Al.18 is revised to delete reference to visual inspection of stainless steel.(10) Section A1.20: Refer to Attachment 7E, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"'

Section E, "Corrosion Under Insulation." (11) Section A1.22: (a) Refer to Attachment 7A, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section A, "Recurring Internal Corrosion." Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 3 of 31 (b) Refer to Attachment 7B, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section B, "Representative. Minimum Sample Size for Periodic Inspections in GALL Report AMP XI.M38,'Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components."'(c) Refer to Attachment 7D, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section D, "Revisions to the Scope and Inspection Recommendations of Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.M29,'Aboveground Metallic Tank."'(d) Refer to Attachment 7F, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section F, "External Volumetric Examination of Internal Piping Surfaces of Underground Piping Removed from GALL Report AMP XI.M41, Buried and Underground Piping and Tanks." (e) Refer to Attachment 7G, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation."' Section G, "Specific Guidance for Use of the Pressurization Option for Inspecting Elastomers in GALL Report AMP XI.M38." Visual inspections may be augmented by sufficient pressurization of the elastomer material to expand the surface in such a way that cracks or crazing is evident.(f) Refer to Attachment 7H, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section H, "Key Miscellaneous Changes to the GALL Report and SRP-LR." (g) Refer to Attachment 8, "Draft LR-ISG-2013-01, 'Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings."' (12) Section A1.41: Refer to Attachment 4, "LR-ISG-2011-04, 'Updated Aging Management Criteria for Reactor Vessel Internal Components of Pressurized Water Reactors."' Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 4 of 31 (13) Table A4-1, Item 3: Refer to Attachment 7C, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section C, "Flow Blockage of Water-Based Fire Protection System Piping, GALL Report AMP XI.M27, 'Fire Water System.'(14) Table A4-1, Item 8: Refer to Attachment 7E, "LR-ISG-2012-02, 'Aging Management if Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section E, "Corrosion Under Insulation." (15) Table A4-1, Item 9: (a) Refer to Attachment 7A, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section A, "Recurring Internal Corrosion." (b) Refer to Attachment 7B, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section B, "Representative Minimum Sample Size for Periodic Inspections in GALL Report AMP XI.M38,'Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components."' Implementation schedule is changed from prior to the PEO to six months prior to the PEO.(c) Refer to Attachment 7D, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section D, "Revisions to the Scope and Inspection Recommendations of Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.M29,'Aboveground Metallic Tank."'(d) Refer to Attachment 7F, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section F, "External Volumetric Examination of Internal Piping Surfaces of Underground Piping Removed from GALL Report AMP XI.M41, Buried and Underground Piping and Tanks." Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 5 of 31 (e) Refer to Attachment 7G, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.'" Section G, "Specific Guidance for Use of the Pressurization Option for Inspecting Elastomers in GALL Report AMP XI.M38." Visual inspections may be augmented by sufficient pressurization of the elastomer material to expand the surface in such a way that cracks or crazing is evident.(f) Refer to Attachment 7H, "LR-ISG-2012-02, 'Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,"' Section H, "Key Miscellaneous Changes to the GALL Report and SRP-LR." (g) Refer to Attachment 8, "Draft LR-ISG-2013-01, 'Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings."' (16) Table A4-1, Item 20: Refer to Attachment 5, "LR-ISG-2011-05, 'Ongoing Review of Operating Experience.' (17) Table A4-1, Item 22 (Reactor Vessel Internals): Refer to Attachment 4,"LR-ISG-2011-04, 'Updated Aging Management Criteria for Reactor Vessel Internal Components of Pressurized Water Reactors."' (18) Table A4-1, Item 32: This item is complete. A DCPP plant procedure was revised to perform concrete inspections per ASME Section XI, Subsection IWL within a five-year interval.(19) Table A4-1, Item 48: Refer to Attachment 16, "One-Time Inspection." PG&E deleted this commitment because PG&E will determine the nondestructive examination of a representative sample size of 20 percent of the population (defined as components having the same material, environment, and aging effect combination) or a maximum of 25 components. (20) Table A4-1, Item 52: Refer to Attachment 3, "LR-ISG-2011-03, 'Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, 'Buried and Underground Piping and Tanks."" Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 6 of 31 (21) Table A4-1, Item 64: This item is complete. The existing indication was examined during the seventeenth refueling outage in Unit 2. The examination confirmed the absence of service-related flaw growth. Results of the examination were reported to the NRC in PG&E Letter DCL-12-089,"Inservice Inspection Report for Unit 1 Seventeenth Refueling Outage," dated September 13, 2012. WIC-95 will continue to be inspected at a frequency required by the Inservice Inspection Program Plan.(22) Table A4-1, Items 66 and 68: As discussed in PG&E Letter DCL-11-037, dated March 25, 2011, PG&E committed to revising the flux thimble tube inspections plant procedure to, in part, include a 5 percent allowance for predictability and to use a net acceptance criterion of 65 percent (LRA Table A4-1, Items 65 and 68). In PG&E Letter DCL-12-124, dated December 20, 2012, PG&E indicated these commitments were complete.During the Unit 1 18th refueling outage, which began in February 2014, a flux thimble tube scheduled for replacement was found to have a wear scar that was 5.1 percent over the predicted value. Because the actual wear was greater than 5 percent of the predicted wear, it was entered into the DCPP Corrective Action Program for evaluation and disposition. The evaluation concluded that the predictability allowance should be revised to 5.1 percent to account for the new plant-specific wear data. All other acceptance criteria remained the same.As discussed in PG&E Letter DCL-1 1-037, WCAP-1 2866 recommended an 80 percent through wall acceptance criterion. This value includes an additional safety margin established by Westinghouse for allowable wear in the thimble tube. WCAP-12866 did not require adding an allowance for eddy current testing instrument uncertainties. Based on the WCAP-1 2866 80 percent acceptance criterion, including the revised 5.1 percent predictability uncertainty and 10 percent for eddy current testing instrument and wear scar uncertainty, PG&E will use a revised net acceptance criterion of 64.9 percent. The revised acceptance criteria provide an adequate margin of safety to ensure that the integrity of the reactor coolant system pressure boundary is maintained. The flux thimble tube inspections procedure revision was completed in August 2014. The subject flux thimble tube was replaced, as-scheduled, in the Unit 1 18th refueling outage.LRA Table A4-1, Items 66 and 68, are updated to address the revised flux thimble tube acceptance criteria and completion of the procedure revision. Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 7 of 31 (23) Table A4-1, Items 72 and 73: Refer to Attachment 4, "LR-ISG-2011-04,'Updated Aging Management Criteria for Reactor Vessel Internal Components of Pressurized Water Reactors."' (24) Table A4-1, Item 74: Refer to Attachment 8, "Draft LR-ISG-2013-01, 'Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings."' PG&E will conform to Draft LR-ISG-2013-01 as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment

8.

Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 8 of 31 Al

SUMMARY

DESCRIPTIONS OF AGING MANAGEMENT PROGRAMS The integrated plant assessment and evaluation of time-limited aging analyses (TLAA) identified existing and new aging management programs necessary to provide reasonable assurance that 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. Sections Al and A2 describe the programs and their implementation activities. Three elements common to all aging management programs discussed in Sections Al and A2 are corrective actions, confirmation process, and administrative controls.The DCPP 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 that are subject to aging management activities. Operating experience from plant-specific and industry sources is systematically reviewed on an ongoing basis in accordance with the Quality Assurance Program, which meets the requirements of 10 CFR 50, Appendix B, and the operating experience program, which meets the requirements of NUREG-0737, Item I. C. 5.The operating experience program interfaces with and relies on active participation in the Institute of Nuclear Power Operations' (INPO) operating experience program as endorsed in NRC Generic Letter 82-04.The programs and procedures relied upon to meet the requirements of 10 CFR 50, Appendix B, and NUREG-0737, Item L C. 5 will be enhanced to ensure that plant-specific and incoming external operating experience related to age-related degradation and aging management will be systematically evaluated. The ongoing review of operating experience information will provide objective evidence to support the conclusion that the effects of aging are managed adequately so that the structure-and component-intended functions will be maintained during the period of extended operation. When an evaluation determines that the effects of aging may not be adequately managed, existing AMPs will be enhanced or new AMPs will be developed. The following enhancements will be implemented no later than the date the renewed operating license is issued and will be maintained and throughout the term of the renewed license: (1) A specific identification code will be defined and used in the Corrective Action Program (CAP) to consistently identify operating experience conceming age-related degradation applicable to DCPP. Entries associated with this code will be periodically reviewed by plant personnel and adverse trends will be entered into the CAP for evaluation. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 9 of 31 (2) Plant-specific and incoming industry operating experience will be screened to determine whether they may involve age-related degradation or aging management impacts. Sources of industry operating experience will include License Renewal Interim Staff Guidance (LR-ISG) documents; all revisions to NUREG-1801; and other NRC and industry guidance documents and standards applicable to aging management, such as Information Notices, Regulatory Issue Summaries, etc.(3) Items coded as concerning age-related degradation applicable to DCPP will require further evaluation. (4) Plant-specific operating experience associated with age-related degradation and aging management will be reported to the industry in accordance with guidelines established in the operating experience program. This reporting will be accomplished through participation in the INPO operating experience program.(5) An evaluation of plant-specific and industry operating experience will be performed during the development and implementation of new AMPs and documented in the new AMP.(6) Further evaluation of plant-specific and industry operating experience that potentially involves aging will be entered in the CAP and evaluated. The evaluation will be documented and will consider as appropriate: (a) systems, structures and components (SSCs) that are similar or identical to those involved with the identified operating experience issue, to gain relevant lessons learned; (b) material of construction, operating environment and aging effects associated with the identified aging issue so that lessons learned can be applied to susceptible SSCs within the scope of license renewal; (c) aging mechanisms associated with the operating experience to confirm that DCPP has appropriate AMPs in place to manage aging that could be caused by these mechanisms; (d) AMPs associated with this operating experience so that if the AMPs have been demonstrated to be ineffective, similar AMPs in place at DCPP can be evaluated to determine if AMP changes are appropriate, or a new AMP is needed. Included in this review is consideration of activities, criteria, and evaluations integral to the elements of the plant AMPs.(7) The results of implementing each AMP, both acceptable and unacceptable, will be evaluated to determine whether the effects of aging are adequately managed. A determination will be made as to whether the frequency of future inspections should be adjusted, whether new inspections should be established, and whether the inspection scope should be adjusted or expanded. If there is an indication that the effects of aging may not be Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 10 of 31 adequately managed, the CAP will be used to either enhance the AMP or develop and implement new AMPs.(8) Initial and periodic training on age-related degradation and aging management will be provided to those personnel responsible for implementing the AMPs and personnel responsible for submitting, screening, assigning, evaluating, or otherwise processing plant-specific and industry operating experience. The DCPP program for the ongoing review of operating experience implements the recommendations in LR-ISG-2011-05, as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment

5.

Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 11 of 31 A1.2 WATER CHEMISTRY The Water Chemistry program manages loss of material,-aRd cracking, and reduction of heat transfer in the primary and secondary water systems. The program relies on monitoring and control of primary and secondary water chemistry to mitigate damage caused by corrosion and stress corrosion cracking. The Water Chemistry program is a mitigation program and does not provide for the detection of aging effects. Inspections of selected components at susceptible locations in a system (e.g., at low flow or stagnant areas) performed under the separate One-Time Inspection program (Al.16) provide verification of the effectiveness of the Water Chemistry program. The Water Chemistry program is based on the guidelines of EPRI TR-105714, Revision 6 (issued as TR-1014986), PWR Primary Water Chemistry Guidelines, and EPRI TR-1 02134, Revision 7 (issued as TR-1 016555), PWR Secondary Water Chemistry Guidelines or later revisions. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 12 of 31 A1.6 FLOW ACCELERATED CORROSION The Flow-Accelerated Corrosion (FAC) program manages wall thinning due to flow-accelerated corrosion on the internal surfaces of carbon steel piping, elbows, reducers, expanders, and valve bodies which contain high energy fluids (both single phase and two phases) fluids. Analytical evaluations and periodic examinations of locations that are most susceptible to wall thinning due to flow accelerated corrosion are used to predict the amount of wall thinning. The program includes analyses to determine critical locations. Initial inspections are performed to determine the extent of thinning at these critical locations, and follow-up inspections are used to confirm the predictions. Inspections are performed using ultrasonic and/or radiographic inspection techniques capable of detecting wall thinning. Repairs and replacements are performed as necessary. Where applicable, the program also manages wall thinning due to erosion mechanisms such as cavitation, flashing, droplet impingement, and solid particle impingement. Susceptible locations with be identified based on the extent-of-condition reviews from corrective actions in response to plant-specific and industry operating experience. The effectiveness of corrective actions for which design changes have been implemented to eliminate the source of erosion will periodically verified until the effectiveness of the corrective action has been has been confirmed. The FAC program implements the recommendations in LR-ISG-2012-01, as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment 6.The FAC program is based on EPRI guidelines in NSAC-202L-R34, Recommendations for an Effective Flow-Accelerated Corrosion Program.Procedures and methods used by the FAC program are consistent with DCPP's commitments to NRC Bulletin 87-01, Thinning of Pipe Wall in Nuclear Power Plants, and NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 13 of 31 A1.9 OPEN CYCLE COOLING WATER SYSTEM The Open-Cycle Cooling Water System program manages cracking, loss of material, aRid-reduction of heat transfer for components, and loss of integrity for Service Level Ill (augmented) internal coatings that are exposed to the raw water of the DCPP OCCW system. The DCPP OCCW system is the auxiliary saltwater (ASW) system.Components within the scope of the OCCW System program are components of the ASW system and the component cooling water heat exchangers that are cooled by the ASW system. The program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in components of the ASW system or structures and components serviced by the ASW system that are within the scope of license renewal. The program also includes periodic visual inspections and non-destructive examinations to detect biofouling, defective coatings, and degraded piping and components of, systems and components.-and The program also currently performs periodic CCW heat exchanger performance testingT to ensure that the effects of aging on components are adequately managed for the period of extended operation. The program is consistent with commitments as established in PG&E Letters DCL-90-027, dated January 26, 1990, and DCL-91-286, dated November 25, 1991, DGPP in responses to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Components, including Supplement 1.As discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, the program includes visual inspections of Service Level Ill (augmented) internal coatings. For coated surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing). The test consists of destructive or nondestructive adhesion testing using ASTM International Standards endorsed in RG 1.54, "Service Level I, II, and Ill Protective Coatings Applied to Nuclear Plants." The training and qualification of individuals involved in coating inspections are conducted in accordance with ASTM International Standards endorsed in RG 1.54 including guidance from the NRC associated with a particular standard. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 14 of 31 A1.10 CLOSED-CYCLE COOLING WATER SYSTEM The Closed-Cycle Cooling Water System program manages loss of material, cracking, and-reduction in heat transfer, and loss of integrity for Service Level IIl (augmented) internal coatings for components within the scope of license renewal in closed-cycle cooling water systems. The program includes maintenance of system chemistry parameters following the guidance of EPRI TR-107396, Revision 1, Closed Cooling Water Chemistry Guidelines (EPRI-IQ 07820) to minimize aging.The program provides for: (1) preventive measures to minimize corrosion including maintenance of corrosion inhibitor, pH buffering agent, and biocide concentrations, and (2) periodic system and component performance testing and inspection. Periodic inspection and testing to confirm function and monitor corrosion is performed in accordance with EPRI TR 107396, Revision 1 (EPRI 1007820), and industry and plant operating experience. As discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment 8, in response to draft LR-ISG-2013-01, the program includes visual inspections of Service Level Ill (augmented) internal coatings. For coated surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing). The test consists of destructive or nondestructive adhesion testing using ASTM International Standards endorsed in RG 1.54, "Service Level I, II, and Ill Protective Coatings Applied to Nuclear Plants." The training and qualification of individuals involved in coating inspections are conducted in accordance with ASTM International Standards endorsed in RG 1.54 including guidance from the NRC associated with a particular standard. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 15 of 31 A1.13 FIRE WATER SYSTEM The Fire Water System program manages loss of material due to corrosion, including MIC, er-biofouling, flow blockage because of fouling, and loss of integrity for Service Level Ill (augmented) internal coatings for water-based fire protection systems. Internal and external inspections and tests of fire protection equipment are performed consistent, with exceptions identified in PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C, with considering applicable National Fire Potertien-Asseoiatieon(NFPA-25 (2011 edition)) codes, and Testing or replacement of sprinklers that have been in place for 50 years is performed in accordance with NFPA-25 (2011 edition). Portions of the deluge systems that are normally dry but periodically subjected to flow and cannot be drained or allow water to collect will undergo augmented testing beyond that in NFPA-25 consisting of volumetric wall thickness examinations. The fire water system is managed by performing routine preventive maintenance, inspections-and testing; operator rounds, performance monitoring, and reliance on the corrective action program; and system improvements to address aging and obsolescence issues.The Fire Water System program will conducts a-wate flow test with air, water, or other medium through each open spray nozzle to verify that deluge systems nozzles are unobstructed. Water flow tests will verify that the deluge system provide full coverage of the equipment it protects. Eith-. periodic nn intrusive volumetric examinations or vVisual inspections will be performed on firewater piping. Non-intrusive follow-up volumetric examinations will be performed if internal visual inspections detect surface irregularities to determine if would dctec. t loss of material due to.corosion and would confirmn wall thickness is within acceptable limits so that, aging will. bc deteed before the loss of intended function. Visual inspections would-will evaluate for the presence of sufficient foreign material to obstruct fire water pipe or sprinklers. (1) wall thickness as it applies to aoidance of catastrophic failWre, aRd (2) the inner diameter of the pi ina it applies to the design flow of the fr protection system. The volum"etbriw exainaio tec-hnique employed will be one that is generally accepted OR the industr,', such as ultrasonRic Or eddy current.Inspections of the firewater tank will be performed to detect loss of material.In response to draft LR-ISG-2013-01, the program includes visual inspections of Service Level Ill (augmented) internal coatings. For coated surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing). The test consists of destructive or nondestructive adhesion testing using ASTM International Standards endorsed in RG 1. 54, "Service Level I, lI, and Ill Protective Coatings Applied to Nuclear Plants." The training and qualification of individuals involved in coating inspections are conducted in accordance with AS TM International Standards endorsed in RG 1. 54 including guidance from the NRC associated with a particular standard. Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 16 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT The Fire Water program implements the recommendations in LR-ISG-2012-02, as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachments 7C and 8. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 17 of 31 Al. 15 Reactor Vessel Surveillance The Reactor Vessel Surveillance program manages loss of fracture toughness due to neutron embrittlement in reactor materials exposed to neutron fluence exceeding 1 .0E 1 7 n/cm2 (E>1.0 MeV). The program is consistent with ASTM E 185-70 and ASTM E 185-73 for Units 1 and 2, respectively. Capsules are periodically removed during the course of plant operating life. Neutron embrittlement is evaluated through surveillance capsule testing and evaluation, ex-vessel neutron fluence calculations, and monitoring of reactor vessel neutron fluence. The testing program and reporting conform to requirements of 10 CFR 50 Appendix H, Reactor Vessel Material Surveillance Program Requirements. Data resulting from the program is used to: Determine pressure-temperature limits, minimum temperature requirements, and end-of-life Charpy upper-shelf energy (Cv USE) in accordance with the requirements of 10 CFR 50 Appendix G, Fracture Toughness Requirements; and, Determine end-of-life RTpTs values in accordance with 10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock.The Reactor Vessel Surveillance program provides guidance for removal and testing or storage of material specimen capsules. As discussed in PG&E Letter DCL- 14-103, in order for PG&E to participate in the EPRI PWR Supplemental Surveillance Program, the donated specimens will no longer be stored. All other capsules that have been withdrawn and tested were stored.In order for PG&E to participate in the EPRI PWR Supplemental Surveillance Program, PG&E takes exception to NUREG-1801, Revision 1, Section XI.M31, Criterion 4, which states that pulled and tested capsules are placed in storage.Participation in the EPRI PWR Supplemental Program includes donation of up to seven Charpy V-Notch specimens (material Plate B5454-1) from the already tested DCPP Unit 2 Capsule V. The donated specimens will no longer be stored.For Unit 1, the last capsule is expected to be withdrawn during the 1 R23 refueling outage after it has accumulated a fluence equivalent to 94.2 years of operation. The remaining four standby capsules have low lead factors, will remain inside the vessel throughout the vessel lifetime, and will be available for future testing.There are no capsules remaining in the Unit 2 vessel. All capsules were removed because high lead factors produced exposures comparable to the fluences expected at the end of the period of extended operation. Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 18 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT DCPP Units 1 and 2 currently. use ex-vessel monitoring dosimetry, which consists of four gradient chains with activation foils outside the reactor vessel, which will be used to monitor the neutron fluence environment within the beltline region. Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 19 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT A1.16 ONE-TIME INSPECTION The One-Time Inspection program conducts one-time inspections of plant system piping and components to verify the effectiveness of the Water Chemistry program (A1.2), Fire Water System program (Al.13), Fuel Oil Chemistry program (Al.14), and Lubricating Oil Analysis program (Al.23). The aging effects to be evaluated by the One-Time Inspection program are loss of material, cracking, and reduction of heat transfer. The One-Time Inspection program determines non-destructive examination of a representative sample size of 20 percent of the population (defined as components having the same material, environment, and aging effect combination) or a maximum of 25 components as discussed in DCL-14-103, Enclosure 1, Attachment

16. .for cach m-aterial environment go u.. ng an engineered sampling technique fr each mat..ial e.ironm.ent.

group This sample will be based on criteria such as the longest service period, most severe operating conditions, lowest design margins, lowest or stagnant flow conditions, high flow conditions, and highest temperature. The One-Time Inspection program evaluates unacceptable inspection results using the corrective action program.This new program will be implemented and completed during the 10-year period prior to the period of extended operation. Industry and plant-specific operating experience will be evaluated in the development and implementation of this program. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 20 of 31 A1.18 BURIED PIPING AND TANKS INSPECTION The Buried Piping and Tanks Inspection program manages cracking, loss of material, and change in surface conditions of buried and underground piping, piping components and tanks in the auxiliary saltwater system, diesel generator fuel transfer system, fire protection system, and the makeup water system. The program manages aging through preventive, mitigative, (i.e., coatings, backfill quality, and cathodic protection) and inspection activities. Visual inspections monitor the condition of protective coatings and wrappings found on steel and copper alloy components and directly assess the surface condition of stainless steel, and cast iron, polyvinyl chloride, and asbestos cement components with no protective coatings or wraps. Evidence of damaged wrapping or coating defects is an indicator of possible age-related degradation to the external surface of the components. The presence of discolorations, discontinuities in surface texture, cracking, crazing, changes in material properties or loss of material of unwrapped cast iron, polyvinyl chloride, and asbestos cement components is an indicator of possible Go--ceic.", damage4oaging of the external surface of the components. The program includes opportunistic inspection of buried piping and tanks as they are excavated or on a planned basis if opportunistic inspections have not occurred.Soil samples will be conducted in the vicinity of in-scope buried, non-cathodically protected steel piping and piping components. Soil samples will be conducted in the vicinity of in-scope buried auxiliary saltwater system steel piping in which the cathodic protection system does not meet the availability or effectiveness requirements. Soil samples will be conducted during the ten-year period prior to the period of extended operation and in each subsequent ten-year period during the period of extended operation. Altemative to visual inspection of the extemal surface of steel piping, hydrostatic testing or an inspection of the intemal surface of the piping that is capable of precisely determining pipe wall thickness may be used.The Buried Piping and Tanks Inspection program is a new program that will be implemented prior to the period of extended-of operation. Inspections will be conducted during each 10-year period beginning 10 years prior to entering the period of extended operation. Examinations of buried piping and tanks will consist of visual inspections. Significant indications of degradation observed during visual inspections of buried piping will require a supplemental surface and/or volumetric non-destructive testing.as well as non des6trutive examinations (e.g. ultrasonic; exam natiOn capable of wall to perform an oVerall asse ment-.v.. .. Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 21 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT The Buried Piping and Tanks Inspection program implements the recommendations in LR-ISG-2011-03 as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment

3.

Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 22 of 31 A1.20 EXTERNAL SURFACES MONITORING PROGRAM The External Surfaces Monitoring Program manages loss of material for external surfaces of steel, stainless steel, aluminum, and copper alloy components, and hardening and loss of strength for elastomers. The program is a visual monitoring program that includes those systems and components within the scope of license renewal that require external surfaces monitoring. Surfaces that are inaccessible or not readily visible during plant operations are inspected during refueling outages. Surfaces that are inaccessible or not readily visible during both plant operations and refueling will be evaluated by the DCPP Corrective Action Program to evaluate applicable industry and plant specific aging operating experience for the material and environment combination. The evaluation will determine if there is a representative location, based on the material, environment, and applicable aging effect that has been or can be inspected in place of the inaccessible components. A sample of outdoor component surfaces that are insulated and indoor insulated components exposed to condensation (due to the in-scope component being operated below the dew point) are periodically inspected during the period of extended operation. When appropriate for the component configuration and material, physical manipulation of elastomers is used to augment visual inspections to confirm absence of hardening or loss of strength for elastomers. Personnel performing external surfaces monitoring inspection will be qualified in accordance with site controlled procedures and processes. The External Surfaces Monitoring Program is a new program that will be implemented six months prior to the period of extended operation. The External Surfaces Monitoring program implements the recommendations in LR-ISG-2012-02, as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment 7E. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 23 of 31 A1.22 INSPECTION OF INTERNAL SURFACES IN MISCELLANEOUS PIPING AND DUCTING COMPONENTS The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, loss of material, change in material properties, and-hardening, shrinkage, loss of sealing, crazing, dimensional change, --loss of strength of the internal surfaces, and loss of integrity for Service Level Ill (augmented) internal coatings of piping, piping components, and piping elements, ducting, heat exchanger components, polymeric and elastomeric components, tanks, and other components that are not within the scope of other aging management programs (i.e. exposed to environments of plant indoor air;atmosphere/weather, borated water leakage; diesel exhaust; and any water environment other than open-cycle cooling water, treated borated water, and fire water). The program al"e addresses the management of aging internal surfaces of miscellaneous piping and ducting components that are inaccessible during both normal operations and refueling. The program allows internal inspections to be credited if the internal and external material and environment conditions are similar.if inspections of the interior surfaces of accessible components with material, environment, and aging effects similar to those of the interior surfaces of buried or underground components are not conducted, internal visual or external volumetric inspections capable of detecting loss of material on the intemal surfaces will be conducted. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program uses the work control process to conduct and document inspections. The program performs visual inspections to detect aging effects that could result in a loss of component intended function. Visual inspections of internal surfaces of plant components are performed opportunistically during the conduct of periodic maintenance, predictive maintenance, surveillance testing and corrective maintenance. Additionally, visual inspections may be augmented by physical manipulation to detect hardening and loss of strength of both internal and external surfaces of elastomers or by sufficient pressurization of the elastomer material to expand the surface in such a way that cracks or crazing is evident. The program also includes volumetric evaluation to detect stress corrosion cracking of the internal surfaces of stainless steel components exposed to diesel exhaust.At a minimum, in each ten-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, inspections focus on the bounding or lead components most susceptible to aging Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 24 of 31 because of time in service and severity of operating conditions. Opportunistic inspections continue in each period despite meeting the sampling limit. Inspections (other than opportunistic inspections) will be based on assessments of the potential degradation which could lead to loss of intended function, and on current industry and plant-specific operating experience. Opportunistic inspections will be based on assessments of the potential degradation which could lead to loss of intended function, and on current industry and plant-specific operating experience. In accordance with LR-ISG-2012-02, Appendix E, Table 4a, volumetric examination of the refueling water storage tanks, condensate storage tanks, and transfer tanks bottoms from the inside will be performed for each ten-year period starting 10 years before entering the period of extended operation to confirm the absence of loss of material due to corrosion. In response to draft LR-ISG-2013-01, the program includes visual inspections of Service Level Ill (augmented) internal coatings. For coated surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing). The test consists of destructive or nondestructive adhesion testing using ASTM Intemational Standards endorsed in RG 1.54, "Service Level I, II, and Ill Protective Coatings Applied to Nuclear Plants." The training and qualification of individuals involved in coating inspections are conducted in accordance with ASTM Intemational Standards endorsed in RG 1.54 including guidance from the NRC associated with a particular standard.This program is not intended for use on piping and ducts where repetitive failures have occurred from loss of material that resulted in loss of intended function.However, if the criteria for recurring intemal corrosion, as described in LR-ISG-2012-02, Section A are met, the use of this program is allowed if it includes augmented requirements to ensure that any recurring aging effects are adequately managed.The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program that will be implemented six months prior to the period of extended operation, except for the volumetric tank inspections, which will begin ten years prior to the PEO in accordance with LR-ISG-2012-02, Appendix E, Table 4a. The Inspection of Intemal Surfaces in Miscellaneous Piping and Ducting Components program implements the recommendations in LR-ISG-2012-02 and LR-ISG-2013-01, as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachments 7A, 7B, 7D, 7F, 7G, 7H, and 8. Enclosure 1 Appendix A Attachment 15 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT PG&E Letter DCL-14-103 Page 25 of 31 A 1.41 PRESSURIZED WATER REACTOR VESSEL INTERNALS The PWR Vessel Internals program relies on implementation of the inspection and evaluation guidelines in EPRI TR-1022863 (MRP-227-A) and EPRI TR-1016609 (MRP-228) to manage the aging effects of the reactor vessel internals components. This program is consistent with LR-ISG-2011-04 as discussed in DCL-14-103, Enclosure 1, Attachment 4, and is used to manage: (a) cracking, including stress corrosion cracking, primary water stress corrosion cracking, irradiation-assisted stress corrosion cracking, and cracking due to fatigue/cyclical loading; (b) loss of material induced by wear, (c) loss of fracture toughness due to either thermal aging embrittlement, irradiation embrittlement, or void swelling; (d) dimensional changes due to void swelling or distortion; and E loss of preload due to thermal and irradiation-enhanced stress relaxation or irradiation-enhanced creep.The PWR Vessel Internals program is a new program that will be implemented prior to the period of extended operation. Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 26 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Table A4-1 License Renewal Commitments LRA Implementation Item # Commitment Section Schedule 3 Enhance the Fire Water System program: B2.1.13 Por",to the period (a) Sprinkler heads in service for 50 years will be replaced or representative samples from extended one or more sample areas will be tested consistent with NFPA 25, Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 2011 Edition guidance. Program is Test procedures will be repeated at 10-year intervals during the period of extended implemented 5 operation, for sprinkler heads that were not replaced prior to being in service for 50 years before the years, to ensure that signs of degradation, such as corrosion, are detected prior to the period of extended loss of intended function, and operation.(b) For either periodic, non intrusive volumetric examinations, or visual inspections on Inspections of firewater piping. N'To perform non-intrusive follow-up volumetric examinations if wetted normally internal visual inspections detect surface irregularities to determine if would-deteGt-any-dry piping loss of mFaterial due to to ensure that aging afe managed , wall segments that thickness is within acceptable limits and degradation would be detected before the loss cannot be drained of intended function. Visual inspections will weuld evaluate for the presence of or that allow water sufficient foreign material to obstruct fire water pipe or sprinklers(!) wall thickness as it to collect begin 5 applies to avoidance of catastro.phic failur, and (2) the inner diameter of thc i ping a. years before the it applies to the design. flow of the fire protection system. The vut e.inatio.n period of extended technique employed will be one that is generally a e indust~y, such as operation. The ultrasonic or eddy current, and program's (c) To state trending ..... To be in conformance with LR-ISG-2012-02, Section C remaining as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C. inspections begin during the period of extended operation Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 27 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Table A4-1 License Renewal Commitments LRA Implementation Item # Commitment Section Schedule 8 Implement the External Surfaces Monitoring Program as described in LRA Section B2.1.20 B2.1.20 Six months Pprior to and to be in conformance with LR-ISG-2012-02, Section E as discussed in PG&E Letter the period of DCL-14-103, Enclosure 1, Attachment 7E. extended operation. 9 Implement the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting B2.1.22 Six months prior to Components program as described in LRA Section B2.1.22 and to be in conformance with the period of LR-ISG-2012-02 and Draft LR-ISG-2013-01 as discussed in PG&E Letter DCL-14-103, extended operation Enclosure 1, Attachments 7A, 7B, 7D, 7F, 7G, 7H, and 8 respectively. 20 As additional y and appliable plant specific -pe;ating experience become RPl-1 1 PDrior t the d the operating exeIec w ill be evaluated and appropriately incorporated into the new R-2.1.1 extended operation proras hrugh the DCPP Corrective Action and Operating Experience Programs. This RP I1A4 Upon receipt of the ongoing .....w of operating expr!incc -will continue throughout the period of extended B2.4.20 renewed operating operatio and 'the results will be maintained on site. DCPP procedures will be enhanced and 12.1.22 licenses implemented to conform to LR-ISG-2011-05, "Ongoing Review of Operating Experience," as 12.24 discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment

5. 92.1.34 A1 22 PG&E will: 3.1 Concurrent with A. For Reactor Coolant System Nickel-Alloy Pressure Boundary Components:

industry initiatives (1) Implement applicable NRC Orders, Bulletins and Generic Letters associated with nickel- and upon completion alloys; (2) implement staff-accepted industry guidelines, (3) participate in the industry submit an inspection initiatives, such as owners group programs and the EPRI Materials Reliability Program, for plan and not less managing aging effects associated with nickel-alloys, and (4) upon completion of these than 24 months programs, but not less than 24 months before entering the period of extended operation, before entering the PG&E will submit an inspection plan for reactor coolant system nickel-alloy pressure boundary period of extended components to the NRC for review and approval,-,,a. operation. B. For ReaGtor Vessel 4.3.3 'a'Fmafien-(1) Participate in the industry programns for investigating and managing aging effects on requested an-the-reactor internals; (2) evaluate and implement the results of the industry programns as safet evaluation for appli~able toteFatFtm.; 3 PRG~lte f thes pI,~F, but not~ les thaA. MRP 2-27 will be Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 28 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Table A4-1 License Renewal Commitments LRA Implementation Item # Commitment Section Schedule 21 months before enteFRng the perrid of extended operation, PG&E will submit an submitted no later plan for reactor internals to the NRC for review and approval. PG&E will validate the schedule-than 2 years after for inspection of the baffle and former bolts on a plant specific basis to ensure that it will issuance of the app..priatcly manage the design fatigue analysis. and (4) in acordanGe with RIS 2011 07, renewed license or PG&E will submit Infaomation requested in the safe" eyaluation for M4RP 22:7 "Pressurized no later than 2 years Water Reactor (PW^R) Internals .nspection and Evalua t.i Guidelines," dated June 22, 2011 befGFe-the p!to the NRC for review and approval no later than 2 years after issuance of the renewed enters-PEG,- license Or no later than 2 years before the plant enters PEG, whichever comes firt whichever comes#Fist, 32 DCPP plant procedures will be revised to perform concrete inspections per ASME Section XI B2.1.28 Prior to the period of Subsection IWL within a 5-year interval. extended epatiepComplete 4& DCPP2 will performA 100 percent eddy curr~ent testing of one nonregenerative heat exchanger 132.146 During the 10 years as parF of the One Time Inspection ProgramA within teyarpio to the period of extended prior to the period of eperaties.Deleted in PG&E Letter DCL-14-103, Enclosure 1, Attachment

16. eAtended operation.

The Buried Piping and Tanks Inspection Program will be revised to- conform to LR-ISG-2011-03 as discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment

3. -i nclude the following inspections that will be conducted duing each 10 year beginning 10 years prior to the entr,' in the period of extended operation.

Examinations of buried piping and tanks will consist of visual inspectio.s as well as non destructive examinations (e.g.ultrasonic examination capable of measuring wall thickness) to an everFall assessment of the condition of buried piping and tanks.. Within 10 years 52 Each inspection will examine either the entire length of a run of pip oramnmm of 10 feet. B2.1.18 prior to the period of extended I.F the u _mber of inspetions times the minimum inspection length (10 feet) exceeds 10 operation percent of the length of the piping under consideration, only 10 percent will need to be I nspeted. If the total length of the in sII pe pip constUrted of a given material times the percentage to be inpce sless, than 10 feet, eithe 10 feet or the total length of pipe present, whichever is less will be isetd lnsEe~nt4ne n f, ,rnrie ivonq Basedl on Mate+r'ia a.ndl Enynrnmenn Gembnatbnnlnn Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 29 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Table A4-1 License Renewal Commitments LRA Implementation Item # Commitment Section Schedule Fire mains will be subject to a periodic flow test in accordance with NFPA 25 section 7.3 at a frequency of at least one test in each one year period. These flow tests will be performed in lieu of excavating buried portions of Fire Water pipe for visual inspections. For cathodically protected meta"lli piping, at least one excavation and visual inspection of steel piping will be conducted. Cathoditally protected steel piping within the ,cope of license renewal exists in the Auxiliar,' Salt Water (ASW) system intake lines.Fonr nonp c-athodically protected buried metallic piping, at least four eXcavations and visual i nspections of steel piping will be conducted. Non Cathodically protected steel piping within the scope of license renewal exists in the ASW system discharge. For non metallic piping, at least one excavation and visual inspection each of polyvinyl chloride (PVC) and Asbestos Cement Pipe (ACP) will be conducted. PVC piping within the scope Of license renewal exists in the Fire W~ater system. Asbestos cement piping within the scope of license renewal exists in the Fire Water System and Make up Water systm Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 30 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Tnhla Ad_1 I ipnontna Ponfl wnic. cinmmitmontiz LRA Implementation Item # Commitment Section Schedule 64 PG&E will perform a regularly scheduled ISI ultrasonic inspection of WIC-95 during the upcoming 1 R17 refueling outage, scheduled for May 2012, to confirm the absence of service-related flaw growth. Should service-related flaw growth be identified in this inspection, the P-ior-to-the corrective action program will be entered and appropriate corrective action will be taken in B2.1.1 empletiof accordance with ASME Section Xl Code. In absence of flaw growth, WIC-95 will continue to 1-R7-o mplete be inspected at a frequency required by the ISI Program Plan.66 PG&E will revise its plant procedure to include a 5.1 percent allowance for predictability and a B2.1.21 Completed. PG&E 10 percent allowance to account for instrument and wear scar uncertainty. This procedure will Letter DCL-12-124. also be revised to include an 80 percent through wall acceptance criterion based upon its plant-specific FTT data wear and NRC acceptance of this 80 percent criterion. In conclusion, Commitment based on the WCAP-1 2866 80 percent acceptance criterion, including

5. 1 percent modified and predictability uncertainty and 10 percent for eddy current testing instrument and wear scar completed per PG&E uncertainty, PG&E will use a net acceptance criterion of 65-64.9 percent. This procedure Letter DCL-14-103.

revision is currently scheduled to be completed prior to December 2011, but will be completed prior to the period of extended operation. 68 PG&E will revise its plant procedure to require the actual plant FTT specific wear data versus B2.1.21 Completed. PG&E wear projections be evaluated every refueling outage to ensure it remains consistent with a Letter DCL-12-124. maximum nonconservative wear projection of 5.1 percent for wear above 40 percent. If the wear projection for a tube is determined to exceed the 5.1 percent under-prediction and has Commitment over 40 percent wear the previous cycle, PG&E will enter it into the corrective action program modified and for evaluation and disposition. This procedure revision is currently scheduled to be completed completed per DCL-prior to December 2011, but will be completed prior to the period of extended operation. 14-103.Implement the PWR Vessel Internals Program to conform to LR-ISG-2011-04 as discussed in Prior to the period PG&E Letter DCL-14-103, Enclosure 1, Attachment 4, including the plant-specific action B2.1.41 of extended 72 items, conditions, and limitations identified in the NRC Safety Evaluation, Revision 1, for operation MRP-227. operation The NRC SE for MRP-227 contains eight action items for applicants/licensees to consider.Responses to the applicable aging management program plant-specific action items, B2.1. 41 December 2015 73 conditions, and limitations identified in the NRC SE, Revision 1, on MRP-227 will be submitted to the NRC by December 2015. Reference DCL-14-103, Enclosure 1, Attachment

4.

Enclosure 1 Attachment 15 PG&E Letter DCL-14-103 Page 31 of 31 Appendix A FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Table A4-1 License Renewal Commitments LRA Implementation Item # Commitment Section Schedule No later than six months before the period of extended B2.1.9 operation and PG&E will conform to Draft LR-ISG-2013-01 as discussed in PG&E Letter DCL-14-103, B2. 1.10 inspections begin 74 Enclosure 1, Attachment

8. B2.1.13 no later than the B2.1.22 last refueling outage before the period of extended operation Enclosure 1 Attachment 16 PG&E Letter DCL-14-103 Page 1 of 2 One-Time Inspection PG&E's licensing basis for the DCPP One-Time Inspection program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-10-129, dated October 8, 2010 (4) PG&E Letter DCL-10-134, dated October 27, 2010 (5) PG&E Letter DCL-1 3-119, dated December 23, 2013 The NRC evaluated the DCPP One-Time Inspection program in its SER, Section 3.0.3.1.10, dated June 2, 2011.The DCPP LRA was prepared to NUREG-1801, Revision 1. After the DCPP LRA was submitted, NUREG-1801, Revision 2, was issued, which incorporates additional operating experience.

The NRC did not request any additional information that specifically referenced NUREG-1801, Revision 2, regarding DCPP's One-Time Inspection program.SER Section 3.0.3.1.10 summarizes DCPP's current commitment for One-Time Inspection sampling size: "The applicant stated that it will conduct a ten percent inspection of the most susceptible locations (e.g., stagnant flow, low points) for each in-scope system to verify the effectiveness of (a) the Water Chemistry Program in managing loss of material, and cracking of stainless steel components exposed to an environment greater than 140 0 F, and (b) the Fuel Oil Chemistry Program in managing loss of material. The applicant also stated that it would inspect one heat exchanger per in-scope system that is (a) exposed to treated water and being managed by the Water Chemistry Program for fouling of heat exchanger tubes, and (b) exposed to lubricating oil and being managed by the Lubricating Oil Analysis Program for loss of material. The applicant further stated that it will perform a 100 percent eddy current test of stainless steel tubes in one of the nonregenerative heat exchangers." PG&E is revising its licensing basis for the One-Time Inspection program to adopt the sample size for inspections recommended by Element 4, "Detection of Aging Effects" of AMP XI.M32, One-Time Inspection in NUREG-1801, Revision 2. The following describes the recommended sample size: For components managed by the AMP XI.M2, Water Chemistry"; AMP XI.M30,"Fuel Oil Chemistry"; and AMP XI.M39, "Lubricating Oil Analysis," programs, a representative sample size is 20 percent of the population (defined as Enclosure 1 Attachment 16 PG&E Letter DCL-14-103 Page 2 of 2 components having the same material, environment, and aging effect combination) or a maximum of 25 components. Otherwise, a technical justification of the methodology and sample size used for selecting components for one-time inspection should be included as part of the program's documentation. This NUREG-1801, Revision 2, sample size will supersede the sample size previously described in PG&E's licensing basis where the One-Time Inspection program verifies the effectiveness of the DCPP Water Chemistry, Fuel Oil Chemistry, and Lubricating Oil Analysis programs. Other portions of the program will remain as evaluated by the NRC in SER Section 3.0.3.1.10. PG&E revises LRA Section Al.16 as shown in Attachment 15 to state that the One-Time Inspection program determines nondestructive examination of a representative sample size of 20 percent of the population (defined as components having the same material, environment, and aging effect combination) or a maximum of 25 components. Because the revised sample size will be representative of all component types, including heat exchangers, PG&E deletes Table A4-1, Item 48, as shown in Attachment

15.

Enclosure 1 Attachment 17 PG&E Letter DCL-14-103 Page 1 of 2 Reactor Vessel Surveillance Program In order for PG&E to participate in the EPRI PWR Supplemental Surveillance Program, PG&E takes exception to NUREG-1801, Revision 1, Section XI.M31, Criterion 4, which states that pulled and tested capsules are placed in storage. Participation in the EPRI PWR Supplemental Program includes donation of up to seven Charpy V-Notch specimens (material Plate B5454-1) from the already tested DCPP Unit 2 Capsule V.The donated specimens will no longer be stored.PG&E Letter DCL-09-079, Enclosure 1, Section B2.1.15 states that the Reactor Vessel Surveillance program provides guidance for removal and testing or storage of material specimen capsules. All capsules that have been withdrawn and tested were stored.The NRC Staff evaluated the Reactor Vessel Surveillance program in its SER, Section 3.0.3.1.9, dated June 2, 2011. SER Section 3.0.3.1.9 (page 3-29) states: "The applicant stated, in LRA Section B2.1.15, that the Reactor Vessel Surveillance Program provides guidance for removal and testing or storage of material specimen capsules, and it stored all capsules that have been withdrawn. The staff noted that a new license condition will require that all capsules placed in storage be maintained for future insertion, and any changes to storage requirements must be approved by the staff Therefore, the Reactor Vessel Surveillance Program is consistent with GALL with respect to Criterion 4." NUREG-1801, Revision 2, Section XI.M31 recommends that all pulled and tested capsules with a neutron fluence greater than 50 percent of the projected reactor vessel neutron fluence at the end of the PEO are placed in storage (these specimens and capsules are saved for future reconstitution and reinsertion use). XI.M31 also states that if all surveillance capsules have been removed, alternative dosimetry may be used to monitor neutron fluence during the PEO.DCPP has ample capsules remaining for future use since all of the Unit 2 capsules are in storage and are available for future use.The Unit 2 capsules with the highest effective full power years are Capsules V, W, and Z. These capsules have a neutron fluence greater than 50 percent of the projected reactor vessel neutron fluence at the end of the PEO. DCPP FSAR Update, Table 5.2-22, Unit 2 Capsule V, was removed in refueling outage 9 (2R9) at 52.5 EFPY and tested. Unit 2 Capsules W and Z were also removed in 2R9 at 61.5 EFPY. All of these capsules are in storage.FSAR Update Section 5.2.4.4.2, states that the six Unit 2 capsules contain a total of 180 Charpy V-Notch specimens (material Plate B5454-1). Unit 2 Capsule V contains a total of 30 Charpy V-Notch specimens (material Plate B5454-1). The EPRI PWR Enclosure 1 Attachment 17 PG&E Letter DCL-14-103 Page 2 of 2 Supplemental Surveillance Program requests use of up to seven of these from Capsule V, leaving twenty three other Unit 2 Capsule V subject specimens in storage for future use.The DCPP Unit 2 reactor vessel surveillance program currently relies on monitoring of ex-vessel dosimetry (LRA Section B2.1.15; SER Section 3.0.3.1.9(7)) in lieu of in-vessel capsules.Since the Unit 2 reactor vessel surveillance program can be successfully reestablished with the remaining available Capsule V specimens or use of any of the other five available capsules that are in storage, PG&E can participate in the EPRI PWR Supplemental Surveillance Program with a donation of up to seven Charpy V-Notch specimens (material Plate B5454-1).In conclusion, PG&E takes exception to NUREG-1801, Revision 1, Section XI.M31, Criterion 4, which states that pulled and tested capsules are placed in storage (Note: These specimens are saved for future reconstitution use, in case the surveillance program is reestablished.). While all capsules that have been withdrawn and tested were stored, several Charpy V-Notch specimens from Unit 2 Capsule V have been donated to an industry research program. These donated specimens will no longer be available for future use at DCPP. If the Unit 2 surveillance program were to be reestablished, the remaining available Charpy V-Notch specimens within Unit 2 Capsule V could be used. Further, two other Unit 2 capsules of similar exposure are available to reestablish the surveillance program.PG&E revises LRA Section Al. 15 as shown in Attachment

15.

Enclosure 1 Attachment 18 PG&E Letter DCL-14-103 Acronym List AMP AMR ASTM ASW CAP CCW CST DCPP DFOST ECG EPRI FAC FSAR FWST GALL Report LR-ISG LRA MRP MW mV NEI NDT NFPA NRC NSAC OCCW OE PEO PG&E ppb PVC PWR RCP RIC RIS RWSR RWST SE SER SRP SSC TLAA Aging Management Program Aging management review American Society for Testing and Materials Auxiliary saltwater corrective action program Component cooling water Condensate storage tank Diablo Canyon Power Plant Diesel fuel oil storage tank equipment control guideline Electric Power Research Institute Flow Accelerated Corrosion Final Safety Analysis Report Fire water storage tank Generic Aging Lessons Learned License Renewal -Interim Staff Guidance License Renewal Application Materials Reliability Program Makeup water milllivolt Nuclear Energy Institute Non-destructive testing National Fire Protection Association Nuclear Regulatory Commission Nuclear Safety Analysis Center Open-Cycle Cooling Water Operating experience Period of extended operation Pacific Gas and Electric Company Parts per billion Poly-vinyl chloride Pressurized water reactor Reactor coolant pump Recurring internal corrosion Regulatory Issue Summary Raw water storage reservior Refueling water storage tank Safety Evaluation Safety Evaluation Report Standard Review Plan Structure, system, or component Time-limited aging analysis Enclosure 1 Attachment 19 PG&E Letter DCL-14-103 Page 1 of 3 References (1) PG&E Letter DCL-90-027, "Service Water System Problems Affecting Safety-Related Equipment," dated January 26, 1990 (2) PG&E Letter DCL-91-286, "Supplemental Response to Generic Letter 89-13,"Service Water System Problems Affecting Safety-Related Equipment," dated November 25, 1991 (3) PG&E Letter DCL-09-079, "License Renewal Application," dated November 23, 2009 (4) PG&E Letter DCL-10-073, "Supplemental Response to Generic Letter 89-13,"Service Water System Problems Affecting Safety-Related Equipment," dated July 7, 2010 (5) PG&E Letter DCL-10-097, "Response to NRC Letter dated July 19, 2010, Request for Additional Information (Set 9) for the Diablo Canyon License Renewal Application," dated August 2, 2010 (6) PG&E Letter DCL-10-105, "Response to NRC Letter dated July 22, 2010, Request for Additional Information (Set 15) for the Diablo Canyon License Renewal Application," dated August 18, 2010 (7) PG&E Letter DCL-1 0-113, "Response to NRC Letter dated August 3, 2010, Request for Additional Information (Set 16) for the Diablo Canyon License Renewal Application," dated August 26, 2010 (8) PG&E Letter DCL-10-122, "Response to NRC Letter dated August 26, 2010, Request for Additional Information (Set 20) for the Diablo Canyon License Renewal Application and LRA Errata," dated September 22, 2010 (9) PG&E Letter DCL-10-123, "Response to NRC Letter dated August 30, 2010, Request for Additional Information (Set 21) for the Diablo Canyon License Renewal Application," dated September 29, 2010 (10) PG&E Letter DCL-10-129, "Response to NRC Letter dated September 15, 2010, Summary of Telephone Conference Call Held on August 18, 2010, Between the U.S. Nuclear Regulatory Commission and Pacific Gas and Electric Company Concerning Responses to Requests for Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application," dated October 8, 2010 Enclosure 1 Attachment 19 PG&E Letter DCL-14-103 Page 2 of 3 (11) PG&E Letter DCL-10-130, "Response to NRC Letter dated September 17, 2010, Request for Additional Information (Set 24) for the Diablo Canyon License Renewal Application," dated October 12, 2010 (12) PG&E Letter DCL-10-134, "Response to NRC Letter dated September 28, 2010, Summary of Telephone Conference Call Held on September 2, 2010, Between the U.S. Nuclear Regulatory Commission and Pacific Gas and Electric Company Concerning Responses to Requests for Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application," dated October 27, 2010 (13) PG&E Letter DCL-10-147, "Response to Draft Requests for Additional Information (Sets 31 & 33) for the Diablo Canyon License Renewal Application," dated November 24, 2010 (14) PG&E Letter DCL-10-148, "Response to NRC Letter dated November 03, 2010, Request for Additional Information (Set 29) for the Diablo Canyon License Renewal Application, dated November 24, 2010 (15) PG&E Letter DCL-1 0-151, "Response to Telephone Conference Call Held on November 9, 2010, Between the U.S. Nuclear Regulatory Commission and Pacific Gas and Electric Company Concerning Responses to Requests for Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application," dated November 24, 2010 (16) PG&E Letter DCL-1 1-002, "Response to Telephone Conference Call Held on December 9, 2010, Between the U.S. Nuclear Regulatory Commission and Pacific Gas and Electric Company Concerning Responses to Requests for Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application," dated January 21, 2011 (17) PG&E Letter DCL-11-022, "Pacific Gas and Electric Company Supplements a Response to Requests for Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application," dated March 14, 2011 (18) PG&E Letter DCL-1 1-037, "Response to Telephone Conference Calls Held on February 2 and 4, 2011, Between the U.S. Nuclear Regulatory Commission and Pacific Gas and Electric Company Concerning Responses to Requests for Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application," dated March 25, 2011 Enclosure 1 Attachment 19 PG&E Letter DCL-14-103 Page 3 of 3 (19) PG&E Letter DCL-1 1-136, "10 CFR 54.21(b) Annual Update to the DCPP License Renewal Application and License Renewal Application Amendment Number 45," dated December 21, 2011 (20) PG&E Letter DCL-12-089, "Inservice Inspection Report for Unit 1 Seventeenth Refueling Outage," dated September 13, 2012 (21) PG&E Letter DCL-12-124, "10 CFR 54.21(b) Annual Update to the Diablo Canyon Power Plant License Renewal Application and License Renewal Application Amendment Number 46," dated December 20, 2012 (22) PG&E Letter DCL-13-119, "10 CFR 54.21(b) Annual Update to the Diablo Canyon Power Plant License Renewal Application and License Renewal Application Amendment Number 47," dated December 23, 2013 Enclosure 2 PG&E Letter DCL-14-103 Page 1 of 3 Affected LRA Appendix E Sections, Tables, Figures, and Appendices The following LRA Appendix E sections, tables, figures, and appendices were updated to provide information necessary to complete the NRC environmental review, as requested in the letter dated July 3, 2014, "Summary of June 5, 2014, Conference Call to Discuss the Status of the License Renewal Application Review of the Diablo Canyon Nuclear Power Plant, Units 1 and 2." LRA Appendix E, Chapter 7, "Alternatives to the Proposed Action," Chapter 8, "Comparison of Environmental Impacts of License Renewal With the Alternatives," Section 9.2, "Alternatives", and Attachment F, "Severe Accident Mitigation Alternatives," are currently scheduled to be submitted to the NRC in February 2015.ER Reference Subject Section 1.2 Environmental Report Scope and Methodology Section 1.4 References Table 1.2-1 Environmental Report Responses to License Renewal Environmental Regulatory Requirements Section 2.1 Location and Features Section 2.2 Aquatic Ecology Section 2.3 Groundwater Resources Section 2.4 Important Terrestrial Habitats Section 2.5 Threatened or Endangered Species Section 2.6 Demography Section 2.7 Taxes Section 2.8 Land Use Planning Section 2.9 Social Services and Public Facilities Section 2.10 Meteorology and Air Quality Section 2.11 Historic and Archaeological Resources Section 2.12 Known or Reasonably Foreseeable Projects in the Site Vicinity Section 2.13 Geology and Soils (previously References) Section 2.14 References Table 2.2-1 Phylogenic Listing of Intertidal (I) and Subtidal (S) Marine Organisms Associated with the DCPP Coastline Table 2.2-3 Aquatic Special Status Species with the Potential to Occur Off the Diablo Canyon Lands Table 2.4-1 Terrestrial Special Status Species with the Potential to Occur On the Diablo Canyon Lands.Table 2.5-1 List of Federally Threatened or Endangered Species that may Occur on the DCPP Site or Immediately Offshore Table 2.6-1 Population Trends of the State of California and of San Luis Obispo and Santa Barbara Counties Table 2.6-2 Minority and Low Income Population Information Table 2.7-1 Property Tax Breakdown for 2004-2014 Table 2.8-1 Housing Statistics for San Luis Obispo and Santa Barbara Counties Enclosure 2 PG&E Letter DCL-14-103 Page 2 of 3 ER Reference Subject Table 2.9-2 Current and Future -Roadways LOS Classifications Table 2.9-3 San Luis Obispo County School District Statistics Table 2.10-1 Attainment Status of SLO County, All Monitoring Stations Figure 2.3-1 Onsite Monitoring Well Locations Figure 2.5-2 Black Abalone Decline Figure 2.6-1 Aggregate Minority Populations Figure 2.6-2 Hispanic Minority Populations Figure 2.6-3 Low-Income Populations Figure 2.6-4 Other Minority Populations Figure 2.6-5 Black/African American Minority Populations Figure 2.8-1 Land-Use Map Figure 2.13-1 Geomorphic Regions in the DCPP Vicinity Figure 2.13-2 Geologic Units in the DCPP Vicinity Figure 2.13-3 Faults in the DCPP Vicinity Section 3.1 General Plant Information Section 3.2 Refurbishment Activities Section 3.4 Employment Section 3.5 References Figure 3.1-1 Site Layout Section 4.0 Discussion of Updated GElS License Renewal Categories Section 4.2 Entrainment of Fish and Shellfish in Early Life Stages Section 4.3 Impingement of Fish and Shellfish Section 4.4 Heat Shock Section 4.5 Groundwater Use Conflicts (Plants Using <100 GPM of Groundwater) Section 4.10 Threatened or Endangered Species Section 4.11 Air Quality During Refurbishment (Non-Attainment Areas)Section 4.17 Offsite Land Use Section 4.18 Transportation Section 4.21 Environmental Justice Section 4.22 References Chapter 5 Assessment of New and Significant Information Section 5.1 References Section 6.1 License Renewal Impacts Section 6.2 Mitigation Section 6.3 Unavoidable Adverse Impacts Section 6.4 Irreversible and Irretrievable Resource Commitments Section 6.6 References Table 6-1 Category 2 Environmental Impacts related to License Renewal at DCPP Chapter 7 Alternatives to the Proposed Action (currently scheduled to be submitted in February 2015) Enclosure 2 PG&E Letter DCL-14-103 Page 3 of 3 ER Reference Subject Chapter 8 Comparison of Environmental Impacts of License Renewal With the Alternatives (currently scheduled to be submitted in February 2015)Section 9.1 Proposed Action Section 9.2 Alternatives (currently scheduled to be submitted in February 2015)Table 9-1 Environmental Authorizations for Current DCPP Operations Table 9-2 Environmental Authorizations for DCPP License Renewal Attachment A NRC NEPA Issues for License Renewal of Nuclear Power Plants Table A-2 DCPP Environmental Report Cross-Reference of New License Renewal NEPA Issues Identified in the Revised GElS Attachment E CZMA Consistency Certification Attachment F Severe Accident Mitigation 'Alternatives (currently scheduled to be submitted in February 2015)}}