NL-15-019, Reply to Request for Additional Information 3.0.3-2 from Set 2014-01 for the Review of the License Renewal Application

Reply to Request for Additional Information 3.0.3-2 from Set 2014-01 for the Review of the License Renewal Application

ML15075A022
Person / Time
Site:	Indian Point
Issue date:	03/10/2015
From:	Dacimo F Entergy Nuclear Northeast, Entergy Nuclear Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-15-019, TAC MD5407, TAC MD5408
Download: ML15075A022 (52)

Text

Enteray Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB SEntergy P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-2055 Fred Dacimo Vice President Operations License Renewal NL-15-019 March 10, 2015 U.S. Nuclear Regulatory Commission Document Control Desk 11545 Rockville Pike, TWFN-2 F1 Rockville, MD 20852-2738

SUBJECT:

Reply to Request for Additional Information 3.0.3-2 from Set 2014-01 for the Review of the Indian Point Nuclear Generating Unit Nos. 2 & 3, License Renewal Application (TAC Nos. MD5407 and MD5408)

Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64

REFERENCES:

NRC letter, "Reissue of Request for Additional Information 3.0.3-2 from Set 2014-01 for the Review of the Indian Point Nuclear Generating Unit Nos. 2 & 3, License Renewal Application (TAC Nos. MD5407 and MD5408)," dated December 2, 2014

Dear Sir or Madam:

Entergy Nuclear Operations, Inc. is providing, in Attachment 1, the additional information requested in the referenced letter pertaining to NRC review of the License Renewal Application (LRA) for Indian Point 2 and Indian Point 3. The due date for this information was extended in discussion with the NRC.

The License Renewal Application changes due to the responses in Attachment 1 are included as marked up pages in Attachment 2.

The response provided in Attachment 1 contains new regulatory commitments that are identified in the list of regulatory commitments provided in Attachment 3.

If you have any questions, or require additional information, please contact Mr. Robert Walpole, Regulatory Assurance Manager, at (914) 254-6710.

NL-15-019 Docket Nos. 50-247 & 50-286 Page 2 of 2 I declare under penalty of perjury that the foregoing is true and correct.

Executed on March 10, 2015.

FRD/rI Attachments:

1. Reply to NRC Request for Additional Information Regarding the License Renewal Application

2. License Renewal Application Changes Due To Responses To Requests For Information

3. License Renewal Application IPEC List of Regulatory Commitments Revision 26 cc: Mr. Daniel H. Dorman, Regional Administrator, NRC Region I Mr. Douglas Pickett, NRR Senior Project Manager Ms. Kimberly Green, NRC Sr. Project Manager, Division of License Renewal Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel Mr. Dave Wrona, NRC Branch Chief, Engineering Review Branch I Ms. Bridget Frymire, New York State Department of Public Service Mr. John B. Rhodes, President and CEO NYSERDA NRC Resident Inspector's Office

ATTACHMENT 1 TO NL-15-019 REPLY TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 and 3 DOCKET NOS. 50-247 AND 50-286

NL-1 5-019 Docket Nos. 50-247 & 50-286 Attachment 1 Page 1 of 2 REQUEST FOR ADDITIONAL INFORMATION, SET 2014-01 RELATED TO INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION RAI 3.0.3-2

Background:

On April 1, 2014, the staff issued RAI 3.0.3-2 to obtain information regarding how Entergy plans to manage the effects of aging on internal coatings based on guidance in draft license renewal interim staff guidance (LR-ISG)-2013-01, "Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks" (ADAMS Accession No. ML14084A387). The request sought detailed information to allow the staff to determine how the effects of aging on internal coatings in certain components will be managed at Indian Point.

On November 14, 2014, the staff issued final LR-ISG-2013-01, which contains new recommendations related to managing loss of coating integrity for coatings applied to the internal surfaces of piping, piping components, heatexchangers, and tanks within the scope of license renewal (ADAMS Accession No. ML14225A059).

As described in License Renewal Interim Staff Guidance Process, Revision 2 (ADAMS Accession No. ML100920158), "applicants may reference an LR-ISG in the LRA, or may address it as part of the license renewal regulatory review process, either by responding to a request for additional information, addressing an open item in the draft SER, or by supplementing the LRA. Applicants may propose and justify approaches for complying with the regulations that are different from the staff-accepted approaches in LR-ISGs or the license renewal guidance documents."

Because the LR-ISG has been issued as final guidance, the staff withdraws its previous request to allow Entergy to utilize the final guidance to demonstrate the adequacy of its plans to manage the effects of aging on internal coatings. In this regard, the staff issues the following RAI.

Request:

Provide details on how the guidance in LR-ISG-2013-01 will be accounted for in your aging management programs and aging management review (AMR) items for the Indian Point License Renewal Application. If the recommendations in the LR-ISG will not be incorporated, state an exception and provide the technical basis for the exception. If necessary, provide revisions to Appendix A, Appendix B, and the AMR tables in LRA Section 3.

Response to RAI 3.0.3-2 Application of LR-ISG-2013-01 for the IPEC LRA Entergy developed a list of internally-coated piping, piping components, heat exchangers, and tanks in systems within the scope of license renewal at IPEC. Revisions to affected LRA

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 1 Page 2 of 2 sections have been developed to indicate piping and components for which "loss of coating integrity" is considered an aging effect requiring management (AERM). LRA revisions have been developed to provide programs that will manage the AERM of "loss of coating integrity."

ATTACHMENT 2 TO NL-15-019 LICENSE RENEWAL APPLICATION CHANGES DUE TO RESPONSES TO REQUESTS FOR INFORMATION ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 1 of 25 Revisions to text and tables in LRA Section 3.3 are provided below with additions underlined.

In Section 3.3.2.1.2, Service Water, add the following line items:

Materials

• Metal with internal coating Aging Effects Requiring Management

• Loss of coating integrity Aging Management Programs

• Coating Integrity In Section 3.3.2.1.3, Component Cooling Water, add the following line items:

Materials

• Metal with internal coating Aging Effects Requiring Management

• Loss of coating integrity Aging Management Programs

• Coating Integrity In Section 3.3.2.1.10, Control Room HVAC, add the following line items:

Materials

• Metal with internal coating Aging Effects Requiring Management

• Loss of coating integrity

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 2 of 25 Aging Management Programs

• Coating Integrity In Section 3.3.2.1.11, Fire Protection - Water, add the following line items:

Materials

• Metal with internal coating Aging Effects Requiring Management

• Loss of coating integrity Aging Management Programs

• Coating Integrity In Section 3.3.2.1.13, Fuel Oil, add the following line items:

Materials

• Metal with internal coating Aging Effects Requiring Management

• Loss of coating integrity Aging Management Programs

• Coating Integrity In Section 3.3.2.1.14, Emergency Diesel Generator, add the following line items:

Materials

• Metal with internal coatina

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 3 of 25 Aging Effects Requiring Management

• Loss of coating integrity Aging Management Programs

• Coating Integrity In Section 3.3.2.1.17, City Water, add the following line items:

Materials

• Metal with internal coating Aging Effects Requiring Management

• Loss of coating integrity Aging Management Programs

• Coating Integrity In Section 3.3.2.1.19, Miscellaneous Systems in Scope for 10 CFR 54.4(a)(2), add the following line items:

Materials

• Metal with internal coating Aging Effects Requiring Management

• Loss of coating integrity Aging Management Programs

• Coating Integrity

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 4 of 25 Add the following lines to Table 3.3.2-2-1P2: Service Water System Table 3.3.2-2-1P2: Service Water System Aging Effect Aging Component Intended , Requiring Management NUREG-1801 Table 1 Type Function Material: Environment Management Program Item Item Notes Heat Pressure Metal with Raw Water (int) Loss of coating oating Integrity H Exchanger boundary internal coating integit (Bonnet) r ___

PiPressure Metal with Raw Water (int) Loss of coating ,oatinq Integrity _H boundary nternal coating inteQrity Add the following lines to Table 3.3.2-2-1P3: Service Water System Table 3.3.2-2-1P3: Service Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Pressure Metal with Raw water int) Loss of coating Coating Integrity H boundary internal coating integrity Heat Pressure Metal with Raw water (nt) Loss of coating Coatinq Integrity H Exchanger boundary internal coating inte-nt (Bonnet) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ I__

_ _ _ _ _ _ _ _ _ _ ___

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 5 of 25 Add the following lines to Table 3.3.2-3-1P2: Component Cooling Water System.

Table 3.3.2-3-1P2: Component Cooling Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Raw Water (nt) Loss of coating Coating Integrity - - H Exchanger boundary internal coating integritv Bonnet_

Heat Pressure Metal with Treated Water Loss of coating Coating Integrity H Exchanger boundary internal coating t intenritv Add the following line to Table 3.3.2-10-1P3: Control Room Heating, Ventilation and Cooling Table 3.3.2-10-1P3: Control Room Heating, Ventilation and Cooling Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Raw water (nt) Loss of coating Coating Integrity - H Exchanger boundary internal coating integrity k~ubesI

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 6 of 25 Add the following lines to Table 3.3.2-111-1P2: Fire Protection - Water System.

Table 3.3.2-11-1P2: Fire Protection - Water Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Pressure Metal with Treated water Loss of coating Coating Integrity - H

_boundary internal coating int) integqrity Tank Pressure Metal with reated water Loss of coating Fire Water System - H

_boundary internal coating mint) integrity Add the following lines to Table 3.3.2-11-1P3: Fire Protection - Water Table 3.3.2-11-1P3: Fire Protection -. Water Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tank Pressure Metal with Treated water Loss of coating Fire Water System - H

_______boundary internal coating (int) integrity Pi in Pressure Metal with reated water Loss of coatin oatin Inteqrty H boundary linternal coating it integqrity __ _ _ _ _

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 7 of 25 Add the following line to Table 3.3.2-13-1P2: Fuel Oil System Table 3.3.2-13-1P2: Fuel Oil System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table I Type Function Material Environment Management Program Item Item Notes Tank Pressure Metal with Fuel oil (int) Loss of coating Coating Integrity H

_

_boundary internal coating _integrity Add the following line to Table 3.3.2-13-1P3: Fuel Oil System Table 3.3.2-13-1P3: Fuel Oil System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tank Pressure Metal with Fuel oil (int) Loss of coating Coating Integrity - - H

_boundary* internal coating I Lntegrity I

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 8 of 25 Add the following lines to Table 3.3.2-14-1P2: Emergency Diesel Generators Table 3.3.2-114-1P2: Emergency Diesel Generators Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Raw Water (nt) Loss of coating Coating Inteqrity H Exchanger boundary internal coating integit (Blonnetj Heat Pressure Metal with Treated Water Loss of coating Coating Integrity - H Exchanger boundary internal coatingq integrt*

Heat Pressure Metal with Lube Oil (nt) Loss of coating Coating Inteqrit y H Exchanger boundary internal coatincq intenity Add the following lines to Table 3.3.2-17-1P2: City Water System Table 3.3.2-17-IP2: City Water Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Pi Pressure Metal with Treated water Loss of coatin Coatin Inteqrity H

_ oundary internal coatinq int) integrity Tank Pressure Metal with Treated water Loss of coating Coating Interity z H

_oundary internal coating nt) intearity I I

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 9 of 25 Add the following line to Table 3.3.2-17-1P3: City Water System Table 3.3.2-17-1P3: City Water Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1

. Type Function Material Environment Management Program Item Item Notes Pressure Metal with Treated water Loss of coating Coating Integrity - - H

_boundary internal coating mint) ntegrity Add the following line to Table 3.3.2-19-2-1P2: Conventional Closed Cooling System [10CFR54.4(a)(2)]

Table 3.3.2-19-2 IP2: Conventional Closed Cooling System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Treated Water Loss of coating Coating Integrity - H Exchanger boundary internal coatin it nte rt (Shell) roil

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 10 of 25 Add the following line to Table 3.3.2-19-7-1P2: City Water System [10CFR54.4(a)(2)]

Table 3.3.2-19-7-1P2: City Water System [1 OCFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1

. Type Function Material Environment Management Program Item Item Notes Pipin Pressure Metal with Treated water Loss of coating Coatinq Integrity H

_ _ _ _ boundary internal coating it) integrity I Add the following line to Table 3.3.2-19-11-1P2: Fire Protection System [IOCFR54.4(a)(2)]

Table 3.3.2-19-11-1P2: Fire Protection System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Pressure Metal with Treated water Loss of coating Coating Integrity H

_boundary internal coating (int) integrity Add the following line to Table 3.3.2-19-13-1P2: Fresh Water Cooling System [10CFR54.4(a)(2)]

Table 3.3.2-19-13-1P2: Fresh Water Cooling System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Treated water Loss of coating Coating Integrity - H Exchaner boundar internal coatin (t ite rt F(Shell) Ir ýri

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 11 of 25 Add the following line to Table 3.3.2-19-30-1P2: Reactor Coolant System [10CFR54.4(a)(2)]

Table 3.3.2-19-30-1P2: Reactor Coolant System [1 OCFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tank Pressure Metal with internal Treated water Loss of coating Coating Integrity H boundary oating (int) integrity_

Add the following line to Table 3.3;2-19-39-IP2: Service Water System [10CFR54.4(a)(2)]

Table 3.3.2-19-39-1P2: Service Water System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended , Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Raw Water (int) Loss of coating Coating Integrity - _ H Exchanger boundary internal coatinq intecnrit LaShellI iin Pressure Metal with Raw Water (int) Loss of coating oating Integrity -H

_boundary internal coating __q_ inteqrity _ _ _ I I Add the following line to Table 3.3.2-19-12-1P3: Circulating Water System [10CFR54.4(a)(2)]

Table 3.3.2-19-12-1P3: Circulating Water System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tank Pressure Metal with Raw water int) Loss of coating Coating Integqrity H

_boundary internal coatinq interit

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 12 of 25 Add the following line to Table 3.3.2-19-13-1P3: City Water Makeup System [10CFR54.4(a)(2)]

Table 3.3.2-19-13-1P3: CitY Water Makeup System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Pipin Pressure Metal with Treated water Loss of coating Coating Integrity H

_- iboundary internal coating initnterity_

Add the followingline to. Table 3.3.2-19-20-1P3: Fire Protection System. [10CFR54.4(a)(2)]

Table 3.3.2-19-20-IP3: Fire Protection System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Pipin Pressure Metal with Treated water Loss of coating Coating Integrity - - H

_boundary internal coating int integrity Add the following line to Table 3.3.2-19-31-1P3: Lube Oil System [10CFR54.4(a)(2)]

Table 3.3.2-19-31-1P3: Lube Oil System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Lube oil (nt) Loss of coating Coating Integrity - - H Exchanger boundary internal coating integrity (Shell) - _

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 13 of 25 Add the following line to Table 3.3.2-19-43-1P3: Pressurizer System [10CFR54.4(a)(2)]

Table 3.3.2-19-43-1P3: Pressurizer System [1 OCFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tank Pressure Metal with Treated borated Loss of coating Coatingq Integrity - H boundary internal coating Iwater > 1400F nteqrt Add the following line to Table 3.3.2-19-54-1P3: Main Generator Seal Oil*System [10CFR54.4(a)(2)]

Table 3.3.2-19-54-1P3: Main Generator Seal Oil System [1 OCFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Lube oil (int) Loss of coating Coating Integqrity H Exchanger boundary internal coatin inteqrity

[Shell . IIIF Add the following line to Table 3.3.2-19-56-1P3: Service Water System [10CFR54.4(a)(2)]

Table 3.3.2-19-56-1P3: Service Water System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Pressure Metal with Raw Water int) Loss of coating Coating Integrity H boundary internal coating_ integrity I

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 14 of 25 Add the following line to Table 3.3.2-19-58-1P3: Turbine Hall Closed Cooling System [10CFR54.4(a)(2)]

Table 3.3.2-19-58-1P3: Turbine Hall Closed Cooling System [10CFR54.4(a)(2)]

Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Pressure Metal with Treated water Loss of coating Coating Integqrity H Exchanger boundary internal coatinq t inteqrt

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 15 of 25 Revisions to text and tables are provided below with additions underlined.

A.2.1.13 Fire Water System Program For coated/lined surfaces of fire water storage tanks determined to not meet the acceptance criteria, physical testinq is performed where physically possible in coniunction with the visual inspection. The training and gualification of individuals involved in coating/lining inspections of fire water storage tanks are conducted in accordance with ASTM standards endorsed in RG 1.54 including guidance from the staff associated with a particular standard.

The Fire Water System Program will be enhanced to include the following.

• Revise IP2 Fire Water System Program procedures to ensure that the training and qualification of individuals involved in coating/lining inspections and evaluating degraded conditions for fire water storage tanks is conducted in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with a particular standard.

" Revise IP2 Fire Water System Program procedures to incorporate the following guidance.

o Acceptance criteria for inspections of coatings/linings in fire water storaqe tanks are as follows:

a. Indications of peeling and delamination are not acceptable.

b. Blisters are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with use of a particular standard. Blisters should be limited to a few intact small blisters that are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections (e.g., reference ASTM D714-02, "Standard Test Method for Evaluating Degree of Blistering of Paints").

c. Indications such as cracking, flaking, and rusting are to be evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with use of a particular standard.

d. As applicable, wall thickness measurements, proiected to the next inspection, meet design minimum wall requirements.

• Revise IP2 Fire Water System Program procedures to incorporate the following guidance.

o Coatings/linings for fire water storage tanks that do not meet acceptance criteria are repaired, replaced, or removed. Testing or examination is conducted to

NL-1 5-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 16 of 25 ensure that the extent of repaired or replaced coatings/linings encompasses sound coating/lining material.

o As an alternative, coatings exhibiting indications of peeling and delamination may be returned to service if: (a) physical testing is conducted to ensure that the remaining coating is tightly bonded to the base metal; (b) the potential for further degradation of the coating is minimized, (i.e., any loose coating is removed, the edaqe of the remaining coating is feathered): (c) an evaluation is conducted of the potential impact on the system, including degraded performance of downstream components due to flow blockage and loss of material of the coated component; and (d) followup visual inspections of the degraded coating are conducted within 2 years from detection of the degraded condition, with a re-inspection within an additional 2 years, or until the degraded coating is repaired or replaced.

o If coatings/linings are credited for corrosion prevention (e.g., corrosion allowance in design calculations is zero, the "preventive actions" program element credited the coating/lining) and the base metal has been exposed or it is beneath a blister.

the component's base material in the vicinity of the degraded coating/lining is examined to determine if the minimum wall thickness is met and will be met until the next inspection.

o If a blister is not repaired, physical testing is conducted to ensure that the blister is completely surrounded by sound coating/lining bonded to the surface, such as lightly tapping the coating/lining. Acceptance of a blister to remain in-service should be based both on the potential effects of flow blockage and degradation of the base material beneath the blister.

Enhancements will be implemented prior to December 31, 2019.

A.2.1.42 Coating Integrity The Coating Integrity Program is a new program that will include periodic visual inspections of coatings/linings applied to the internal surfaces of in-scope components where loss of coating or lining integrity could impact the component's and downstream component's current licensinq basis intended function(s). For coated/lined surfaces determined to not meet the acceptance criteria, physical testinq is performed where physically possible in conjunction with the visual inspection. The training and qualification of individuals involved in coating/lining inspections of noncementitious coatings/linings are conducted in accordance with ASTM standards endorsed in RG 1.54 including guidance from the staff associated with a particular standard. For cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces.

This program will be implemented prior to December 31, 2024.

A.3.1.13 Fire Water System Program_

For coated/lined surfaces of fire water storage tanks determined to not meet the acceptance criteria, physical testing is performed where physically possible in coniunction with the visual

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 17 of 25 inspection. The training and qualification of individuals involved in coating/lining inspections of fire water storage tanks are conducted in accordance with ASTM standards endorsed in RG 1.54 including guidance from the staff associated with a particular standard.

The Fire Water System Program will be enhanced to include the following.

" Revise IP3 Fire Water System Program procedures to ensure that the traininq and qualification of individuals involved in coating/lining inspections and evaluating degraded conditions for fire water storage tanks is conducted in accordance with an ASTM International standard endorsed in RG 1.54 includinq staff limitations associated with a particular standard.

• Revise IP3 Fire Water System Program procedures to incorporate the following guidance.

o Acceptance criteria for inspections of coatings/linings in fire water storage tanks are as follows:

e. Indications of peeling and delamination are not acceptable.

f. Blisters are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with use of a particular standard. Blisters should be limited to a few intact small blisters that are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections (e.g., reference ASTM D714-02, "Standard Test Method for Evaluating Degree of Blistering of Paints").

g. Indications such as cracking, flaking, and rusting are to be evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with use of a particular standard.

h. As applicable, wall thickness measurements, projected to the next inspection,

-meet design minimum wall requirements.

• Revise IP3 Fire Water System Program p.rocedures to incorporate the following g-uidance. - - -

o Coatings/linings for fire water storage tanks that do not meet acceptance criteria are repaired, replaced, or removed. Testinq or examination is conducted to ensure that the extent of repaired or replaced coatings/linings encompasses sound coating/lining material.

o As an alternative, coatings exhibiting indications of peeling and delamination may be returned to service if: (a) physical testing is conducted to ensure that the remaining coatinq is tightly bonded -to the base metal; (b) the potential for further degradation of the-coatinq is minimized, (i.e., any loose coating is removed, the

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 18 of 25 edge of the remaining coating is feathered); (c) an evaluation is conducted of the potential impact on the system, including dearaded performance of downstream components due to flow blockage and loss of material of the coated component; and (d) followup visual inspections of the degraded coating are conducted within 2 years from detection of the degraded condition, with a re-inspection within an additional 2 years, or until the degraded coating is repaired or replaced.

o If coatings/linings are credited for corrosion prevention (e.g., corrosion allowance in desigqn calculations is zero, the "preventive actions" program element credited the coating/lining) and the base metal has been exposed or it is beneath a blister, the component's base material in the vicinity of the degraded coating/lining is examined to determine if the minimum wall thickness is met and will be met until the next inspection.

o If a blister is not repaired, physical testing is conducted to ensure that the blister is completely surrounded by sound coating/lining bonded to the surface, such as lightly tapping the coating/lining. Acceptance of a blister to remain in-service should be based both on the potential effects of flow blockaqe and degradation of the base material beneath the blister.

Enhancements will be implemented prior to December 31, 2019.

A.3.1.42 Coating Integrity The Coating Integrity Program is a new program that will include periodic visual inspections of coatings/liningqs applied to the internal surfaces of in-scope components where loss of coating or lining integrity could impact the component's and downstream component's current licensing basis intended function(s). For coated/lined surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible in coniunction with the visual inspection. The training and qualification of individuals involved in coating/lining inspections of noncementitious coatings/linings are conducted in accordance with ASTM standards endorsed in RG 1.54 including guidance from the staff associated with a particular standard. For cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces.

This program will be implemented prior to December 31, 2024.

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 19 of 25 Revisions to LRA Tables B-1, B-2, and B-3 are provided below with additions underlined.

Table B-1 Aging Management Programs Coatinq Integrity B.1.43 New Table B-2 IPEC AMP Correlation with NUREG-1801 Programs NUREG-1801 Number NUREG-1801 Program IPEC Program Internal Coatings/Linings for In-Scope4 Pii~, Pipingq Coatingq Integqrity [B.1.431]

XI.M42 Scope Piping.Pin Components, Heat Exchangers, and Tanks Table B-3 IPEC Program Consistency with NUREG-1801 NUREG-1801 Comparison Program Name Plantef Programs Programs with Specific Consistent Programs with prog s th with Enhancements NUREG-1x801 NUREG-1801N Coating Integrity X Revisions to text are provided below with additions underlined.

B.1.14 FIRE WATER SYSTEM Proaram Descriotion Where the visual inspection of the coated/lined surfaces determines that the coating/lining is deficient or degraded, physical tests are performed, where physically possible, in coniunction with the visual inspection. EPRI Report 1019157. "Guideline on Safety-Related Coatings."

provides information on the ASTM standard guidelines and coatings.

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 20 of 25 NUREG-1 801 Consistency The Fire Water System Program with enhancements will be consistent with the program described in NUREG-1801,Section XI.M27, Fire Water System, as modified by LR-ISG-2012-02 and LR-ISG-2013-01, with exceptions.

E nenhancements The following enhancements will be implemented prior to December 31, 2019.

Attributes Affected Enhancements

4. Detection of Aping Effects Revise IP2 and IP3 Fire Water System Program procedures to ensure that the training and qualification of individuals-,

involved in coating/liningq inspections and evaluating degraded conditions for fire water storage tanks is conducted in accordance with an ASTM International-standard endorsed in RG 1.54 including staff limitations associated with a particular standard.

6. Acceptance Criteria Revise IP2 and IP3 Fire Water System Program procedures to incorporate the following guidance.

Acceptance criteria for inspections of coatings/linings in fire water storage tanks are as follows:

a. Indications of peeling and delamination are not acceptable.

b. Blisters are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with use of a particular standard. Blisters should be limited to a few intact small blisters that are completely surrounded by sound coating/lining bonded to the substrate. Blister size and freguency should not be increasing between inspections (e.g., reference ASTM D714-02,. "Standard Test Method for Evaluating-Degree of Blistering of Paints").

NL-1 5-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 21 of 25 Attributes Affected Enhancements

c. Indications such as cracking, flaking, and rusting are to be evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with use of a particular standard.

d. As applicable, wall thickness measurements, proiected to the next inspection, meet design minimum wall requirements.

7. Corrective Actions Revise IP2 and IP3 Fire Water System Program procedures to incorporate the-following guidance.

Coatings/linings for fire water storage tanks that do not meet acceptance criteria are repaired, replaced, or removed. Testing or examination is conducted to ensure that the extent of repaired or replaced coatings/linings encompasses sound coating/lining material.

As an alternative, coatings exhibiting indications of peeling and delamination may be returned to service if: (a) physical testing is conducted to ensure that the remaining coating is tightly bonded to the base metal; (b) the potential for further degradation of the coating is minimized, (i.e., any loose coating is removed, the edge of the remaining coating is feathered): (c) an evaluation is conducted -

of the potential impact on the system,_..

including deqraded performance of downstream components due to flow blockage and loss of material of the coated component; and (d) followup visual inspections of the degraded coating are conducted within 2 years from detection of the dearaded condition, with a re-

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 22 of 25 Attributes. Affected Enhancements inspection within an additional 2 years, or until the degraded coating is repaired or replaced.

If coatings/linings are credited for corrosion prevention (e.g., corrosion allowance in design calculations is zero, the "preventive actions" program element credited the coating/lininq) and the base metal has been exposed or it is beneath a blister, the component's base material in the vicinity of the degraded coating/lining is examined to determine if the minimum wall thickness is met and will be met until the next inspection.

If a blisteris not repaired, physical testing is conducted to ensure that the blister is completely surrounded by sound coating/lining bonded to the surface, such as lightly tapping the coating/lining.

Acceptance of a blister to remain in-service should be based both on the potential effects of flow blockage and degradation of the base material beneath the blister.

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 23 of 25 Revisions to text are provided below with additions underlined.

B.1.43 COATING INTEGRITY The Coating Integrity Program is a new program that will include periodic visual inspections of internal coatings/linings. Where the visual inspection of the coated/lined surfaces determines that the coating/lining is deficient or degraded, physical tests are performed, where physically possible, in coniunction with the visual inspection. EPRI Report 1019157, "Guideline on Safety-Related Coatings," provides information on the ASTM standard guidelines and coatin-gs.

American Concrete Institute (ACI) Standard 201.1 R-08, "Guide for Conducting a Visual Inspection of Concrete in Service," provides guidelines for inspecting concrete.

This program will be implemented prior to December 31, 2024.

NUREG-1801 Consistency The Coating Integrity Program will be consistent with the program described in NUREG-1801,Section XI.M42, Internal Coatinas/Linings for In-Scope Piping, Pipingi Components, Heat Exchangers, and Tanks, as set forth in LR-ISG-2013-01, "Aging Management of Loss of Coatina or Linina Intearitv for Internal Coatinas/Lininas on In-Scope Pipina. Pipina Components, Heat Exchangers, and Tanks" with exceptions.

Exceotions to NUREG-1801 The Coating Integrity Program will have the following exceptions.

Attributes Affected Exceptions

4. Detection of Aging Effects NUREG-1801 recommends visual inspection of internal coatings. The IPEC program will use external volumetric inspection of concrete-lined piping in the city water systems. Internal inspections of downstream components will be performed as described in LRA B.1.29. 1,2

4. Detection of Aging Effects NUREG-1801 recommends visual' inspection of internal coatings. The IPEC program will use external volumetric inspection of concrete-lined piping in the fire water systems. System flushing and flow testing will be performed as described in LRA B.1.14. 3 '4

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 24 of 25 Exception Notes

1. External volumetric inspection of concrete-lined piping in the city water systems will detect pipe wall thinning resultinq from losses of the internal concrete coating, as well as degradation at welded joints where a gap in the concrete lining could exist. This external inspection approach has been effective in managing the effects of aging on concrete-lined service water system piping and in the resolution of potential operability concerns. Operating experience for the city water systems indicates that degradation of the concrete lining is rare. In addition, internal inspections will ensure that the concrete lining has not caused flow blockage or damage to downstream components.

2. The city water systems for Unit 2 and Unit 3 share piping at some locations, includinq the main header. Draining and isolating these headers to allow internal inspection of concrete-lined piping would disrupt water supplies to critical systems such as fire protection systems and the Appendix R diesel gqenerator, and would require one or both units to enter into a 7-day allowed outage time (AOT) as described in technical specifications. Thus, internal piping inspections of concrete-lined piping in the city water systems would create a hardship.

3. External volumetric inspection of concrete-lined piping in the fire water systems will detect pipe wall thinning resulting from losses of the internal concrete coating, as well as degradation at welded joints where a gap in the concrete lining could exist. This external inspection approach has been effective in managing the effects of agqingq on concrete-lined service water system piping and in the resolution of potential operability concerns. Operating experience for the fire water systems indicates that degradation of the concrete lining is rare. In addition, system flushing and flow testing will ensure that the concrete lining has not caused flow blockage downstream.

4. Draining and isolating fire water system piping to allow internal inspection of concrete-lined piping would place the affected unit into a degraded fire protection status with wide impact on plant operations. Thus, internal piping inspections of concrete-lined piping in the fire water systems would create a hardship.

Enhancements None Operating Experience The Coating Integrity Program is a new progqram. Industry operating experience will be considered in the implementation of this program. Plant operating experience will be gained as the program is executed and will be factored into the program via the confirmation and corrective action elements of the IPEC 10 CFR 50 Appendix B quality assurance program.

As discussed in element 10 to NUREG-1 801,Section XI.M42, the inspection techniques and training of inspection personnel associated with this program are consistent with industry practice and have been demonstrated effective at detecting loss of coating or lining integrity.

NL-15-019 Docket Nos. 50-247 & 50-286 Attachment 2 Page 25 of 25 Not-to-exceed inspection intervals have been established that are dependent on the results of previous plant-specific inspection results.

Conclusion The Coating Integrity Program will be effective at identifying and managing the aging effect of loss of coating integrity because it incorporates proven monitoring technigues, acceptance criteria, corrective actions, and administrative controls. The Coating Integrity Pro-gram provides reasonable assurance that the effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation.

ATTACHMENT 3 TO NL-15-019 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev. 26 ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

NL-15-019 Attachment 3 Page 1 of 20 List of Regulatory Commitments Rev. 26 The following table identifies those actions committed to by Entergy in this document.

Changes are shown as strikethroughs for deletmeFe and underlines for additions.

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 1 Enhance the Aboveground Steel Tanks Program for IP2: NL-07-039 A.2.1.1 IP2 and IP3 to perform thickness measurements of omplete A.3.1.1 the bottom surfaces of the condensate storage tanks, NL-13-122 B.1.1 city water tank, and fire water tanks once during the first ten years of the period of extended operation.

Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to require trending of thickness measurements when material loss is detected.

Implement LRA Sections, A.2.1.1, A.3.1.1 and B.1.1, P2 & P3: NL-14-147 A.2.1.1 as shown in NL-14-147. 1ecember 31, A.3.1.1

___ _____________________ 2_019 B.1.1 2 Enhance the Bolting Integrity Program for IP2 and IP3 P2: NL-07-039 A.2.1.2 to clarify that actual yield strength is used in selecting Complete A.3.1.2 B.1.2 materials for low susceptibility to SCC and clarify the IP3:

prohibition bolting. on use of lubricants containing MoS 2 for Complete NL-07-153 Audit Items 201,241, The Bolting Integrity Program manages loss of NL-13-122 270 1 preload and loss of material for all external bolting. I

NL-15-019 Attachment 3 Page 2 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM Implement the Buried Piping and Tanks Inspection P2: NL-07-039 A.2.1.5 3

IP3 as described in LRA Section Complete A.3.1.5 Program for IP2 and B.1.6.NL-1 3-122 B.1.6Item B.1.6. P3: NL-07-153 Audit This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801 Section XI.M34, Buried Piping and Tanks Inspection.

Include in the Buried Piping and Tanks Inspection NL-09-106 Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that NL-09-111 includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating.- Establish inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using inspection techniques with demonstrated effectiveness. NL-1_1_-101 4IP2: NL-07-039 A.2.1.8 4 Enhance the Diesel Fuel Monitoring Program to ImP2e0e A.2.1.8 include cleaning and inspection of the IP2 GT-1 gas Complete A.1.8 turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil NL-07-153 Audit items eP3: 12, 128, 129, day tanks, IP2 SBO/Appendix R diesel generator fuel oil day tank, and IP3 Appendix R fuel oil storage tank em015- 1 132, and day tank once every ten years. NL-08-057 491,492, Enhance the Diesel Fuel Monitoring Program to 510 include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10mg/I. Water and sediment acceptance criterion will be less than or equal to 0.05%.

Enhance the Diesel Fuel Monitoring Program to include thickness measurement of the bottom of the 1 following tanks once every ten years. IP2: EDG fuel

NL-15-019 Attachment 3 Page 3 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM oil storage tanks, EDG fuel oil day tanks, SBO/Appendix R diesel generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank.

Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; IP3: Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank.

Enhance the Diesel Fuel Monitoring Program to specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program.

Enhance the-Diesel Fuel Monitoring Program to direct samples be taken and include direction to remove water when detected:

Revise applicable procedures to direct sampling of the onsite portable fuel oil contents prior to transferring the contents to the storage tanks.

Enhance the Diesel Fuel Monitoring Program to direct the addition of chemicals including biocide when the I presence of biological activity is confirmed.*

IlP2: NL-07-039 A.2.1.10 5 Enhance the External Surfaces Monitoring Program plete A.3.1.10 for IP2 and IP3 to include periodic inspections of ' omplete A.3.1.10 systems in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs

-that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2). ..... _--

Implement LRA Sections A.2.1.10, A.3.1.10 and P2 & IP3: NL-14-147 A.2.1.10 B.1. 11, as shown in NL-14-147. e019 mbe 31,BA..1.11

NL-15-019 Attachment 3 Page 4 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/_AUDIT ITEM 6 Enhance the Fatigue Monitoring Program for IP2 to P2: NL-07-039 A.2.1.11 monitor steady state cycles and feedwater cycles or omplete A.3.1.11 NL-13-122 B.1.12, perform an evaluation to determine monitoring is not NL-13-122 Ad Item required. Review the number of allowed events and 164 resolve discrepancies between reference documents 164 and monitoring procedures. IP3:

Enhance the Fatigue Monitoring Program for IP3 to ecember 12, include all the transients identified. Assure all fatigue 2015 analysis transients are included with the lowest limiting numbers. Update the number of design transients accumulated to date.

7 Enhance the Fire Protection Program to inspect P2: NL-07-039 A.2.1.12 external surfaces of the IP3 RCP oil collection omplete A.3.1.12 systems for loss of material each refueling cycle. P3:

Enhance the Fire Protection Program to explicitly December 12, state that the IP2 and IP3 diesel fire pump engine 2015 sub-systems (including the fuel supply line) shall be observed while the pump is running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation while running; such as fuel oil, lube oil, coolant, or exhaust gas leakage.

Enhance the Fire Protection Program to specify that the IP2 and IP3 diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating cycle.

Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480V switchgear room, and EDG room C02 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

NL-15-019 Attachment 3 Page 5 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION 1 _ 1 /IAUDIT ITEM IP2: NL-07-039 A.2.1.13 8 Enhance the Fire Water Program to include inspection Complete A.3.1.13 of IP2 and IP3 hose reels for evidence of corrosion.

NL-13-122 B.1.14 Acceptance criteria will be revised to verify no NL-07-153 Audit Items unacceptable signs of degradation.

105, 106 Enhance the Fire Water Program to replace all or test NL-08-014 a sample of IP2 and IP3 sprinkler heads required for 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.

Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP3 fire protection piping on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.

Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks.

Acceptance criteria will be enhanced to verify no sianificant corrosion.

Implement LRA Sections, A.2.1.13, A.3.1.13 and IP2 & IP3: NL-14-147 A.2.1.13 B.1.14, as shown in NL-14-147. December 31, A.3.1.13 2019 B.1.14 IP2 & IP3: NL-15-019 A.2.1.13 Implement LRA Sections A.2.1.13, A.3.1.13 and B.1.14, as shown in NL-15-019 December 31, A.3.1.13 A. __________________________________________________________________

2019 j~.=.-~- J I R_ 114

-.

NL-15-019 Attachment 3 Page 6 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I_ I I/ AUDIT ITEM 9 Enhance the Flux Thimble Tube Inspection Program P2: NL-07-039 A.2.1.15 for IP2 and IP3 to implement comparisons to wear ,omplete A.3.1.15 rates identified in WCAP-12866. Include provisions to NL-13-122 B.1.16 P3:

compare data to the previous performances and December 12, perform evaluations regarding change to test 2-015 frequency and scope.

Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific values based on evaluation of previous test results.

Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance criteria. Also stipulate that flux thimble tubes that cannot be inspected over the tube length and cannot be shown by analysis to be satisfactory for continued service, must be removed from service to ensure the integrity of the reactor coolant system pressure boundary.

NL-15-019 Attachment 3 Page 7 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I. / AUDIT ITEM Enhance the Heat Exchanger Monitoring Program for P2: NL-07-039 A.2.1.16 10 IP2 and IP3 to include the following heat exchangers Domplete A.3.1.16 NL-13-122 B.1.17, in the scope of the program.

P3: NL-07-153 Audit Item

• Safety injection pump lube oil heat exchangers )ecember 12, 52 2015

• RHR heat exchangers

• RHR pump seal coolers

• Non-regenerative heat exchangers

• Charging pump seal water heat exchangers

• Charging pump fluid drive coolers

• Charging pump crankcase oil coolers

• Spent fuel pit heat exchangers

• Secondary system steam generator sample coolers

• Waste gas compressor heat exchangers

• SBO/Appendix R diesel jacket water heat exchanger (IP2 only)

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to perform visual inspection on heat exchangers where non-destructive examination, such as eddy current inspection, is not possible due to heat exchanger design limitations.

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment combinations when determining sample population of heat exchangers.

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to establish minimum tube wall thickness for the new heat exchangers identified in the scope of the program. Establish acceptance criteria for heat exchangers visually inspected to include no indication of tube erosion, vibration wear, corrosion, pitting, NL-09-018 foulina, or scalina.

11 Deleted NL-09-056 NL-1 1-101

NL-15-019 Attachment 3 Page 8 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 12 Enhance the Masonry Wall Program for IP2 and IP3 P2: NL-07-039 A.2.1.18 to specify that the IP1 intake structure is included in omplete A.3.1.18 the program. the prgraI.P3: NL-13-122 B.1.19 Complete 13 Enhance the Metal-Enclosed Bus Inspection Program IP2: NL-07-039 A.2.1.19 for IP2 and IP3 to visually inspect the external surface Complete A.3.1.19 of MEB enclosure assemblies for loss of material at NL-13-122 B.1.20 least once every 10 years. The first inspection will IP3: NL-07-153 Audit Items occur prior to the period of extended operation and ecember 12, 124, the acceptance criterion will be no significant loss of 015 NL-08-057 133,519 material. NL-13-077 Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct.

Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative -

measurements such as thermography or contact resistance measurements. The first inspection will occur prior to the period of extended operation.

The plant will process a change to applicable site procedure to remove the reference to "re-torquing" connections for phase bus maintenance and bolted connection maintenance.-

14 Implement the Non-EQ Bolted Cable Connections IP2: NL-07-039 A.2.1.21 Program for IP2 and IP3 as described in LRA Section Complete A.3.1.21 B.1.22. B.1.22.P3: NL-13-122 B.1.22 December 12,

_ _ _"_ _ _'__ _ 015

NL-15-019 Attachment 3 Page 9 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 15 Implement the Non-EQ Inaccessible Medium-Voltage P2: NL-07-039 A.2.1.22 Cable Program for IP2 and IP3 as described in LRA omplete A.3.1.22 Section B.1.23. NL-13-122 B.1.23 IP3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 NL-1 1-032 1801 Section XI.E3, Inaccessible Medium-Voltage Cables Not Subject To 10 CFR 50.49 Environmental NL-11-096 Qualification Requirements.

NL-11-101 16 Implement the Non-EQ Instrumentation Circuits Test P2: NL-07-039 A.2.1.23 Review Program for IP2 and IP3 as described in LRA omplete A.3.1.23 Section B.1 .24. NL-13-122 B.1.24 SP3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801 Section XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

17 Implement the Non-EQ Insulated Cables and P2: NL-07-039 A.2.1.24 Connections Program for IP2 and IP3 as described in Complete A.3.1.24 LRA Section B.1.25. NL-13-122 B.1.25 P3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801 Section XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

NL-15-019 Attachment 3 Page 10 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 18 Enhance the Oil Analysis Program for IP2 to sample P2: NL-07-039 A.2.1.25 and analyze lubricating oil used in the SBO/AppendixppeNL-13-122 Complete A.3.1.25 B.1.26 R diesel generator consistent with the oil analysis for NL-11-101 other site diesel generators. December 12, Enhance the Oil Analysis Program for IP2 and IP3 to 2015 sample and analyze generator seal oil and turbine hydraulic control oil.

Enhance the Oil Analysis Program for IP2 and IP3 to formalize preliminary oil screening for water and particulates and laboratory analyses including defined acceptance criteria for all components included in the scope of this program. The program will specify corrective actions in the event acceptance criteria are not met.

Enhance the Oil Analysis Program for IP2 and IP3 to formalize trending of preliminary oil screening results as well as data provided from independent laboratories.

19 Implement the One-Time Inspection Program for IP2 P2: NL-07-039 A.2.1.26 and IP3 as described in LRA Section B.1.27. Complete A.3.1.26 NL-13-122 B.1.27 This new program will be implemented consistent with P3: NL-07-153 Audit item the corresponding program described in NUREG- December 12, 173 1801,Section XI.M32, One-Time Inspection. ?015 IP2: NL-07-039 A.2.1.27 20 Implement the One-Time Inspection - Small Bore P2L03 A.3.1.27 Piping Program Seto for IP2 and IP3 as described in LRA B12.NL-13-122 Nomplete2 A..1.27 B. 1.28 Section B.1.28. IP3: NL-07-153 Audit item This new program will be implemented consistent with ecember 12, 173 the corresponding program described in NUREG- 015 1801,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping.

IP2: NL-07-039 A.2.1.28 21 Enhance the Periodic Surveillance and Preventive 1p2L03 A.3.1.28 Maintenance Program for IP2 and IP3 as necessary omplete NL-13-122 A.3.1.28 B.1.29 to assure that the effects of aging will be managed IP3:

such that applicable components will continue to perform their intended functions consistent with the 2015 current licensing basis through the period of extended 0 operation.

NL-15-019 Attachment 3 Page 11 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 22 Enhance the Reactor Vessel Surveillance Program for P2: NL-07-039 A.2.1.31 IP2 and IP3 revising the specimen capsule withdrawal Complete A.3.1.31 NL-13-122 B.1.32 IP3:

schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected December 12, through the end of the period of extended operation. 2015 Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor I vessel are maintained in storage.

P2: NL-07-039 A.2.1.32 23 Implement the Selective Leaching Program for IP2 oplete A.3.1.32 and IP3 as described in LRA Section B.1.33. omplete A.3.1.32 NL-13-122 B.1.33 This new program will be implemented consistent with P3: NL-07-153 Audit item the corresponding program described in NUREG- December 12, 173 1801,Section XI.M33 Selective Leaching of Materials. ?015 24 Enhance the Steam Generator Integrity Program for P2: NL-07-039 A.2.1.34 IP2 and IP3 to require that the results of the condition Womplete A.3.1.34 NL-13-122 B.1.35 monitoring assessment are compared to the IP3:

operational assessment performed for the prior p3 t operating cycle with differences evaluated. omptete 25 Enhance the Structures Monitoring Program to IP2: NL-07-039 A.2.1.35 explicitly specify that the following structures are Complete A.3.1.35 included in the program.- NL-13-122 B.1.36

• Appendix R diesel generator foundation (IP3) IP3: NL-07-153

• Appendix R diesel generator fuel oil tank vault December 12, Audit items (IP3) 2015 86, 87, 88,

• Appendix R diesel generator switchgear and NL-08-057 417 enclosure (IP3)

" city water storage tank foundation

• condensate storage tanks foundation (IP3) NL-13-077

• containment access facility and annex (IP3)

• discharge canal (IP2/3)

• emergency lighting poles and foundations (IP2/3)

• fire pumphouse (IP2)

" fire protection pumphouse (IP3)

• fire water storage tank foundations (IP2/3)

" gas turbine 1 fuel storage tank foundation

• maintenance and outage building-elevated passageway (IP2)

• new station security building (IP2)

• nuclear service building (IP1)

• primary water storage tank foundation (IP3)

• refueling water storage tank foundation (IP3) -_"

NL-15-019 Attachment 3 Page 12 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION 1_ 1 1 / AUDIT ITEM 0 security access and office building (IP3) 0 service water pipe chase (IP2/3) 0 service water valve pit (IP3)

S superheater stack 0 transformer/switchyard support structures (IP2) 0 waste holdup tank pits (IP2/3)

Enhance the Structures Monitoring Program for IP2 and IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspected for each structure as applicable.

• cable trays and supports

• concrete portion of reactor vessel supports

• conduits and supports

" cranes, rails and girders

• equipment pads and foundations

• fire proofing (pyrocrete)

" HVAC duct supports

• jib cranes

• manholes and duct banks

• manways, hatches and hatch covers

• monorails

• new fuel storage racks

• sumps NL-13-077 Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and IP3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurring.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, gaskets, seismic joint filler, and roof elastomers) to identify cracking and change in material properties and for inspection of aluminum vents and louvers to identify loss of material.

Enhance the Structures Monitorinc Procqram for IP2

NL-15-019 Attachment 3 Page 13 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION 1_ 1 1 / AUDIT ITEM and IP3 to perform an engineering evaluation of NL-08-127 Audit Item groundwater samples to assess aggressiveness of 360 groundwater to concrete on a periodic basis (at least once every five years). IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides.

Additionally, to assess potential indications of spent fuel pool leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the IP3 intake structure at least once every 5 years.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of the degraded areas Audit Item of the water control structure once per 3 years rather 358 than the normal frequency of once per 5 years during the PEO.

Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria for inspections of concrete structures in accordance NL-1 1-032 with ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures" prior to the period of extended operation.

NL-1 1-101 26 Implement the Thermal Aging Embrittlement of Cast P2: NL-07-039 A.2.1.36 Austenitic Stainless Steel (CASS) Program for IP2 Nomplete A.3.1.36 and IP3 as described in LRA Section B.1.37. P3 NL-07-153 Audit item This new program will be implemented consistent with ecember 12, 173 the corresponding program described in NUREG- 015 1801,Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program..

NL-15-019 Attachment 3 Page 14 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM Implement the Thermal Aging and Neutron Irradiation P2: NL-07-039 A.2.1.37 27 Complete A.3.1.37 Embrittlement of Cast Austenitic Stainless Steel NL-13-122 B.1.38 (CASS) Program for IP2 and IP3 as described in LRA P3: NL-07-153 Audit item Section B.1.38. Pet 173 Complete 173 This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

28 Enhance the Water Chemistry Control - Closed P2: NL-07-039 A.2.1.39 Cooling Water Program to maintain water chemistry of Complete A.3.1.39 the IP2 SBO/Appendix R diesel generator cooling IP3: NL-08-057 Audit item guidelines. Complete 509 system per EPRI Enhance the Water Chemistry Control - Closed Cooling Water Program to maintain the IP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines.

P2: NL-07-039 A.2.1.40 29 Enhance the Water Chemistry Control - Primary and p2 t N 7 A.1.41 Secondary Program for IP2 to test sulfates monthly in m NL1312 the RWST with a limit of <150 ppb. NL-13-122 30 For aging management of the reactor vessel internals, 1P2: NL-07-039 A.2.1.41 IPEC will (1) participate in the industry programs for omplete A.3.1.41 investigating and managing aging effects on reactor NL-13-122 internals; (2) evaluate and implement the results of 3o the industry programs as applicable to the reactor omplete internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for NL-1 1-107 reactor internals to the NRC for review and approval.

31 Additional P-T curves will be submitted as required IP2: NL-07-039 A.2.2.1.2 per 10 CFR 50, Appendix G prior to the period of Complete A.3.2.1.2 1P3:

extended operation as part of the Reactor Vessel Surveillance Program. December 12,:

-- 015 32 As required by 10 CFR 50.61 (b)(4), IP3 will submit a 1P3: NL-07-039 A.3.2.1.4 plant-specific safety analysis for plate B2803-3 to the December 12, 4.2.5 NRC three years prior to reaching the RTPTS 2015 NL-08-127 screening criterion. Alternatively, the site may choose-to implement the revised PTS rule when approved.

NL-15-019 Attachment 3 Page 15 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I _I I/ AUDIT ITEM At least 2 years prior to entering the period of IP2: NL-07-039 A.2.2.2.3 33 extended operation, for the locations identified in LRA ,omplete A.3.2.2.3 NL-13-122 4.3.3 Table 4.3-13 (1P2) and LRA Table 4.3-14 (1P3), under the Fatigue Monitoring Program, IP2 and IP3 will P3: NL-07-153 Audit item implement one or more of the following: Complete 146 NL-08-021 (1) Consistent with the Fatigue Monitoring Program, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting NL-10-082 for the effects of reactor water environment. This includes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following:

1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of extended operation, use the existing CUF.

2. Additional plant-specific locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component.

3. Representative CUF values from other plants, adjusted to or enveloping the IPEC plant specific external loads may be used if demonstrated applicable to IPEC.

4. An analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-.

approved code case) may be performed to determine a valid CUF.

(2) Consistent with the Fatigue Monitoring Program, Corrective Actions, repair or replace the affected locations before exceeding a CUF of 1.0.

34 IP2 SBO / Appendix R diesel generator will be NL-13-122 2.1.1.3.5 installed and operational by April 30, 2008. This 7Complete committed change to the facility meets the ComNlete requirements of 10 CFR 50.59(c)(1) and, therefore, a license amendment pursuant to 10 CFR-50.90 is not NL-1 1-101 1 required. "_....._,_ _

NL-15-019 Attachment 3 Page 16 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM P2: NL-08-127 Audit Item oP2: 27 35 Perform a one-time inspection of representative sample area of IP2 containment liner affected by the ompleteNL-13-122 1973 event behind the insulation, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area. P3: NL-1 1-101 Perform a one-time inspection of representative December 12, sample area of the IP3 containment steel liner at the 2015 juncture with the concrete floor slab, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area.

Any degradation will be evaluated for updating of the NL-09-018 containment liner analyses as needed.

36 Perform a one-time inspection and evaluation of a oP2: NL-08-127 Audit Item sample of potentially affected IP2 refueling cavity NL-11-10 3 concrete prior to the period of extended operation. NL-13-122 The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel.

Additional core bore samples will be taken, if the NL-09-056 leakage is not stopped, prior to the end of the first ten years of the period of extended operation.

A sample of leakage fluid will be analyzed to NL-09-079 determine the composition of the fluid. If additional core samples are taken prior to the end of the first ten years of the period of extended operation, a sample of leakage fluid will be analyzed.

3P2: NL-08-127 Audit Item 37 Enhance the Containment Inservice Inspection (Cme-IWL) Program to include inspections of the .omplete 361 containment using enhanced characterization of- P3. NL-13-122 degradation (i.e., quantifying the dimensions of noted indications through the use of optical aids) during the omplete period of extended operation. The enhancement includes obtaining critical dimensional data of degradation where possible through direct measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections.

NL-15-019 Attachment 3 Page 17 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM P2: NL-08-143 4.2.1 38 For Reactor Vessel Fluence, should future core loading patterns invalidate the basis for the projected Domplete NL-13-122 values of RTpts or CvUSE, updated calculations will I3P3:

be provided to the NRC. ecember 12, 2_015 39 Deleted NL-09-079 40 Evaluate plant specific and appropriate industry P2: NL-09-106 B.1.6 operating experience and incorporate lessons learned omplete NB.1.22 in establishing appropriate monitoring and inspection NP3: B.1.24 inP3:B.12 frequencies to assess aging effects for the new aging December 12, B.1.25 management programs. Documentation of the B.1.27 operating experience evaluated for each new program B. 1.28 will be available on site for NRC review prior to the B.1.33 period of extended operation. B.1.37 B. 1.38 IP2: NL-1 1-032 N/A 41 IPEC will inspect steam generators for both units to P2fter the assess the condition of the divider plate assembly. eglnning of the The examination technique used will be capable of PEg and prior to detecting PWSCC in the steam generator divider plate September 28, assembly. The IP2 steam generator divider plate 023tember1-07 inspections will be completed within the first ten years 2 of the period of extended operation (PEO). The IP3 steam generator divider plate inspections will be IP3: NL-11-090 completed within the first refueling outage following Prior to the end the beginning of the PEO. of the first NL-1 1-101 e

r~efueling g outage Collowing the eginning of the PEQ. - III

NL-15-019 Attachment 3 Page 18 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I/ I I / AUDIT ITEM NL-1 1-032 N/A 42 IPEC will develop a plan for each unit to address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options.

Option 1 (Analysis)

IPEC will perform an analytical evaluation of the IP2: NL-1 1-074 steam generator tube-to-tubesheet welds in order to Prior to March establish a technical basis for either determining that 2024 NL-1 1-090 the tubesheet cladding and welds are not susceptible IP3: Prior to the to PWSCC, or redefining the pressure boundary in end of the first NL- 11-096 which the tube-to-tubesheet weld is no longer refueling outage included and, therefore, is not required for reactor following the coolant pressure boundary function. The redefinition beginning of the of the reactor coolant pressure boundary must be PEO.

approved by the NRC as a license amendment request.

Option 2 (Inspection) IP2:

Between March IPEC will perform a one-time inspection of a 2020 and March representative number of tube-to-tubesheet welds in 2024 each steam generator to determine if PWSCC -

cracking is present. If weld cracking is identified: 1P3: Prior to the

a. The condition will be resolved through repair end of the first or engineering evaluation to justify continued refueling outage service, as appropriate, and Sollowing the eginning of the

b. An ongoing monitoring program will be PEO.

established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

P2: NL-11-032 4.3.3 43 IPEC will review design basis ASME Code Class 1 Domplete fatigue evaluations to determine whether the NUREG/CR-6260 locations that have been evaluated P3: Prior to NL-13-122 for the effects of the reactor coolant environment on December 12, NL-1 1-101 fatigue usage are the limiting locations for the IP2 and 2015 IP3 configurations. If more limiting locations are identified, the most limiting location will be evaluated for the effects of the reactor coolant environment on fatigue usage.

IPEC will use the NUREG/CR-6909 methodology in the evaluation of the limiting locations consisting of nickel allov, if anv.

NL-15-019 Attachment 3 Page 19 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 44 IPEC will include written explanation and justification P2: NL-11-032 N/A of any user intervention in future evaluations using the omplete 1 -101 WESTEMS "Design CUF" module. P3: Prior to NL-13-122 December 12, 2015 45 IPEC will not use the NB-3600 option of the P2: NL-1 1-032 N/A WESTEMS program in future design calculations until Complete NL-1 1-101 the issues identified during the NRC review of the P3: Prior to NL-13-122 program have been resolved. December 12, 2015 46 Include in the IP2 ISI Program that IPEC will perform P2: NL-1 1-032 N/A twenty-five volumetric weld metal inspections of Complete socket welds during each 10-year ISI interval NL-11-074 scheduled as specified by IWB-2412 of the ASME NL-13-122 Section Xl Code during the period of extended operation.

In lieu of volumetric examinations, destructive examinations may be performed, where one destructive examination- may be substituted for two volumetric examinations.

47 Deleted. NL-14-093 N/A 48 Entergy will visually inspect IPEC underground piping CP2: NL-12-174 N/A within the scope of license renewal and subject to omplete aging management review prior to the period of P3 Prior to NL-13-122 extended operation and then on a frequency of at ecember 12, least once every two years during the period of extended operation. This inspection frequency will be 0 maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03; Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1 801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

NL-15-019 Attachment 3 Page 20 of 20

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM 49 Recalculate each of the limiting CUFs provided in P2: NL-13-052 A.2.2.2 section 4.3 of the LRA for the reactor vessel internals Complete A.3.2.2 to include the reactor coolant environment effects IP3: Prior to NL-13-122 (Fen) as provided in the IPEC Fatigue Monitoring ecember 12, Program using NUREG/CR-5704 or NUREG/CR- 2015 6909. In accordance with the corrective actions specified in the Fatigue Monitoring Program, corrective actions include further CUF re-analysis, and/or repair or replacement of the affected components prior to the CUFen reaching 1.0.

50 Replace the IP2 split pins during the 2016 IP2: NL-13-122 A.2.1.41 refueling outage (2R22). Prior to B. 1.42 completion of NL-14-067 2R22 IP3: N/A 51 Enhance the Service Water Integrity Program by P2 & IP3: NL-14-147 A.2.1.33 implementing LRA Sections A.2.1.33, A.3.1.33 and December 31, A.3.1.33 B.1.34, as shown in NL-14-147. 2019 B.1.34 52 Implement the Coating Integrity Program for IP2 and P2 & IP3: NL-15-019 A.2.1.42 IP3 as described in LRA Section B.1.42, as shown in December 31, A.3.1.42 NL-15-019. 2024 B. 1.43