ML11271A203

Applicants Opposition to the State of New Yorks Motion for an Extension of Time

ML11271A203
Person / Time
Site:	Indian Point
Issue date:	09/28/2011
From:	Bessette P, O'Neill M, Sutton K Entergy Nuclear Operations, Morgan, Morgan, Lewis & Bockius, LLP
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
RAS 21150, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML11271A203 (113)

Text

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of ) Docket Nos. 50-247-LR and

) 50-286-LR ENTERGY NUCLEAR OPERATIONS, INC. )

)

(Indian Point Nuclear Generating Units 2 and 3) )

) September 28, 2011 APPLICANTS OPPOSITION TO THE STATE OF NEW YORKS MOTION FOR AN EXTENSION OF TIME In accordance with 10 C.F.R. § 2.323(b) and paragraph G.5 of the Atomic Safety and Licensing Boards (Boards) July 1, 2010 Scheduling Order,1 Entergy Nuclear Operations, Inc.

(Entergy) files this answer opposing New York States (NYS or the State) September 27, 2011 Motion for an Extension of Time So That Outstanding Issues Affecting the Content of Prefiled Direct Testimony and Statements of Positions May Be Resolved (Motion). NYS requests an extension of time of at least 90 days for the submission of initial written statements of position, prefiled direct testimony, and supporting reports and exhibits.2 For the reasons set forth below, NYS has not demonstrated sufficient cause for the requested extension and the Board should deny the request.

I. REGULATORY BACKGROUND The Commission has repeatedly expressed its policy of expediting the handling of license renewal applications (LRA), by both limiting the scope of matters for review in license 1

Licensing Board Scheduling Order at 7 (July 1, 2010) (unpublished) (Scheduling Order).

2 See Motion at 1.

DB1/ 68215717.4

renewal proceedings and by urging the Board to conclude its hearings in a timely manner.3 As the Commission repeatedly has expressed, resource constraints or other routine obligations, such as those resulting from the States voluntary decision to participate in various judicial or administrative proceedings,4 do not provide cause for delay. Neither these bases nor others cited by NYS provide good cause to delay this four-year-long proceeding for an additional 90 days (or longer).5 NYS asserts that Entergy and the U.S. Nuclear Regulatory Commission (NRC) Staff are responsible for continued modifications and amendments to their position on critical licensing issues, but, as explained below, NYS focuses on actions that Entergy must take in the near term to implement its aging management plans (AMPs) and fulfill its commitmentsnot changes to the AMPs themselves. The review of AMP implementation, as distinguished from the nature and sufficiency of an AMP or an AMP commitment, is the subject of ongoing regulatory oversight by the NRC Staff and not within the scope of a license renewal proceeding.

Instead, AMP implementation typically occurs after issuance of the renewed license. In the case of Indian Point Energy Center (Indian Point), because this proceeding has continued for so many years, the period of extended operation (PEO) is approachingfirst for Indian Point Unit 2 (IP2) and then Unit 3 (IP3). Entergy is taking actions now, as it must, to meet its commitments and implement its AMPs.6 The NRC Staff reviews these implementation activities as part of its ongoing regulatory oversightseparate and apart from its review of the 3

See Dominion Nuclear Conn., Inc. (Millstone Nuclear Power Station, Units 2 & 3), CLI-05-24, 62 NRC 551, 566-67 (2005); see also Duke Energy Corp. (Oconee Nuclear Station, Units 1, 2 & 3), CLI-98-17, 48 NRC 123, 126 (1998) (establishing a goal of the issuance of a Commission decision on the pending LRA within two and one-half years from the date of the application).

4 See Motion at 8-9.

5 Id. at 8.

6 See NRC Inspection Manual, Temporary Instruction 2516/001, Review of License Renewal Activities (Mar.

30, 2011), available at ADAMS Accession No. ML110620255, (Entergy Answer to Motion for Extension, Att.

1) (governing NRC Staff inspections on the implementation of license renewal commitments, license conditions, and selected aging management programs).

LRA.7 That ongoing regulatory oversight does not affect the scope of the issues in the adjudicatory proceeding before this Board.8 The adequacy of Entergys ongoing AMP implementation and commitment fulfillment activities is outside the scope of this proceeding, so the fact that such activities are ongoing cannot justify delaying this hearing.

To illustrate the conundrum that NYSs position would create if adopted in this proceeding, consider the NRC Staffs Supplemental Safety Evaluation Report (SSER), which presents the NRC Staffs approved list of 46 separate license renewal commitments from Entergy.9 The implementation schedule for many of these commitments is within the next two to four years, before or at the time IP2 and IP3 enter the PEO.10 Accordingly, if the Board accepts the States theory that such issues must be resolved before moving forward, then the Board would be required to postpone the hearing in this proceeding until Entergy has implemented all of its AMPs and fulfilled all of its license renewal commitments and license conditions. Only at that point would operational activities at Indian Point possibly reach the stasis that NYS apparently desires. Such an outcome is not contemplated by Commission practice, regulations, or policy.

II. THE STATES CLAIMS LACK A LEGAL OR FACTUAL BASIS

1. The deadlines for submittal of testimony have long been established, and have already been postponed once. The Board established the initial milestones for evidentiary submittals 7

See AmerGen Energy Co., LLC (License Renewal for Oyster Creek Nuclear Generating Station), CLI-09-7, 69 NRC 235, 284 (2009) (review and enforcement of license conditions is a normal part of the Staffs oversight function rather than an adjudicatory matter).

8 See Fla. Power & Light Co. (Turkey Point Nuclear Power Plant, Units 3 & 4), CLI-01-17, 54 NRC 3, 10 (2001).

9 See Supplement to Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Units Nos. 2 and 3, App. A (Aug. 30, 2011), available at ADAMS Accession No. ML11243A109 (SSER) (Entergy Answer to Motion for Extension, Att. 2). The States Motion attaches a copy of the SSER, but omits the commitment list in Appendix A.

10 See id.

over one year ago.11 Moreover, NYS already has benefited from one significant extension of time in which to prepare its hearing submissions.12 But for these developments, NYSs prefiled written testimony and other evidentiary submissions would have been due in June 2011, more than three months ago.13 NYS therefore has had ample notice of the specific filing deadlines imposed by the Board and, like all parties, had an obligation to plan accordingly.

2. The States issues do not meet the unavoidable and extreme circumstances test. While this Board is empowered to grant extensions of time, it should do so only when warranted by unavoidable circumstances.14 NYS cites no case law in support of its requested extension, and does not explain why the various issues it raises meet the appropriate legal standards. On the contrary, and as explained below, many of the issues NYS complains of are the natural result of the already-extensive delays in the resolution of this proceeding, while the rest are of its own creation.

3. As a legal matter, NYS misconstrues the scope of the hearing on admitted safety contentions. In accordance with 10 C.F.R. Part 54, hearings are to focus on the adequacy of Entergys proposed AMPs and time-limited aging analyses (TLAAs), as set forth in the LRA, not Entergys implementation of those AMPs either immediately prior to or during the PEO.

And as the Commission explained long ago in Turkey Point: Adjudicatory hearings in 11 See Scheduling Order at 13-15.

12 See Licensing Board Amended Scheduling Order (June 7, 2011) (unpublished).

13 See id. at 13.

14 See Hydro Res., Inc. (2929 Coors Road Suite 101, Albuquerque, NM 87210), CLI-99-1, 49 NRC 1, 3 n.2 (1999) (quoting Statement of Policy on Conduct of Adjudicatory Proceedings, CLI-98-12, 48 NRC 18, 21 (1998)) (We caution all parties in this case, however, to pay heed to the guidance in our policy statement that ordinarily only unavoidable and extreme circumstances provide sufficient cause to extend filing deadlines.);

see also 10 C.F.R. § 2.334 (in evaluating whether there is a showing of good cause to modify the hearing schedule, the presiding officer should consider factors such as whether the requesting party has exercised due diligence to adhere to the schedule, whether the requested change is the result of unavoidable circumstances, and whether the other parties have agreed to the change and the overall effect of the change on the schedule of the case). The Commission recently affirmed the unavoidable and extreme circumstances test from CLI-98-12. See Tennessee Valley Authority (Bellefonte Nuclear Plant Units 1 & 2),

CLI-10-26, 72 NRC __, slip op. at 2-3 & nn.10-11 (2010).

individual license renewal proceedings will share the same scope of issues as our NRC Staff review, for our hearing process (like our Staffs review) necessarily examines only the questions our safety rules make pertinent.15 Furthermore, Part 54 anticipates that some actions taken by licensees to achieve compliance with its requirements will be future or prospective actionsand it expressly authorizes such actions to be taken after the NRC issues the renewed license.16 For example, in the Oyster Creek license renewal proceeding, the applicant had committed, as part of its AMP for the drywell containment, to undertake a finite element structural analysis of the drywell.17 Although intervenors sought to challenge certain aspects of the structural analysis, the Commission held that the review of the applicants compliance with the license condition is not a precondition for granting the license renewal application and is separate and apart from the resolution of the contention . . . review and enforcement of license conditions is a normal part of the Staffs oversight function rather than an adjudicatory matter.18 Similarly, the NRC Staff will review Entergys compliance with its commitments, through its ongoing regulatory process which is outside the scope of this adjudicatory proceeding.19 15 Turkey Point, CLI-01-17, 54 NRC at 10.

16 See, e.g., 10 C.F.R. § 54.29 (stating actions have been identified and have been or will be taken with respect to managing the effects of aging and TLAAs) (emphasis supplied); see also Turkey Point, CLI-01-17, 54 NRC at 8 (Part 54 requires renewal applicants to demonstrate how their programs will be effective in managing the effects of aging during the proposed period of extended operation. . . . Applicants must identify any additional actions, i.e., maintenance, replacement of parts, etc., that will need to be taken to manage adequately the detrimental effects of aging.) (internal citations and quotation marks omitted) (emphasis supplied).

17 See Oyster Creek, CLI-09-7, 69 NRC at 248-49.

18 Id. at 284.

19 See id.; see also Entergy Answer to Motion for Extension, Att. 1. The Commission has held that licensee commitments need not be converted into express license conditions to be enforceable. See, e.g., Private Fuel Storage, L.L.C. (Indep. Spent Fuel Storage Installation), CLI-01-9, 53 NRC 232, 235-36 (2001); Private Fuel Storage, L.L.C. (Indep. Spent Fuel Storage Installation), CLI-03-8, 58 NRC 11, 21 (2003).

The Commission affirmed these important principles again in its recent Vermont Yankee decision resolving a metal fatigue contention similar to that admitted here, and in which the issue was compliance with 10 C.F.R. § 54.21(c)(1)(iii). In CLI-10-17, the Commission held:

[I]n Oyster Creek, we expressly interpreted section 54.21(c)(1) to permit a demonstration after the issuance of a renewed license: an applicants use of an aging management program identified in the GALL Report constitutes reasonable assurance that it will manage the targeted aging effect during the renewal period. We reiterate here that a commitment to implement an AMP that the NRC finds is consistent with the GALL Report constitutes one acceptable method for compliance with 10 C.F.R. § 54.21(c)(1)(iii).20 Licensee commitments therefore provide a well-established and essential mechanism for ensuring that licensees implement their AMPs and TLAAs in a timely and effective manner.21 There is no precedent supporting the States apparent claim that the hearing cannot proceed until the identified commitments are fulfilled. On the contrary, these Commission decisions require this proceeding to move forward now.

4. As a factual matter, NYS is not faced with unavoidable and extreme circumstances because of Entergys ongoing implementation efforts. As explained above, Entergys implementation efforts, including its fulfillment of commitments in the LRA and revisions to implementing procedures, are not prerequisites to NYSs preparation of prefiled testimony. In particular:

a. Reactor Vessel Internals: NYS claims that the Entergys long-planned submittal, by September 28, 2011, of its inspection plan for reactor vessel internals and the current unavailability of the revised EPRI guidance document on PWR reactor vessel internals 20 Entergy Nuclear Vt. Yankee, LLC (Vt. Yankee Nuclear Power Station), CLI-10-17, 72 NRC __, slip op. at 44 (July 8, 2010) (citing AmerGen Energy Co., LLC (License Renewal for Oyster Creek Nuclear Generating Station), CLI-08-23, 68 NRC 461, 468 (2008)).

21 See AmerGen Energy Co., LLC (Oyster Creek Nuclear Generating Station), LBP-06-7, 63 NRC 188, 207 (2006) (accepting a licensee commitment as satisfying regulatory obligation).

inspections, MRP-227-A, impacts the States testimony and consideration of the filing of new or amended contentions.22 As the SSER explains, however, this submittal is intended to fulfill a longstanding commitment in Entergys original LRA submitted on April 23, 2007.23 Although the Staffs SSER labels the fulfillment of this commitment as a supplement to the LRA, the inspection plan is part of the implementation of Entergys AMP and is not a prerequisite to the issuance of a renewed license.24 Further, Entergys reactor vessel internals AMP is based on EPRIs MRP-227, and both of these documents have long been available.25 Accordingly, there is already ample documentation in the record and available to the parties to submit their testimony on NYS-25. There is certainly nothing new, unavoidable, or extreme about these long-anticipated developments.

b. Primary Water Stress Corrosion Cracking: Next, NYS points to the NRC Staffs apparent . . . concerns about primary water stress corrosion cracking in the steam generator, as expressed in the SSER.26 But this is not a contested issue. The States complaints about the alleged unavailability of information on an uncontested issue are not relevant to the question of whether there is sufficient cause to delay testimony on currently admitted contentions.

22 Motion at 6. NYS erroneously implies that Entergys planned submittal is somehow new information: it appears that Entergy is planning to submit a further supplement to the license renewal application by September 28, 2011. See id.

23 See SSER, App. A at A-18 (Commitment 30). The SSER identifies the source of Commitment 30 as NL 039Entergys original LRA for Indian Point. See id.

24 See id. at 3-20 (explaining that Indian Point is a Category C plant under RIS 2011-07, and therefore Entergy is expected to submit its inspection plan, consistent with its previous commitments, by today, September 28, 2011).

25 See Licensing Board Memorandum and Order (Ruling on Pending Motions for Leave to File New and Amended Contentions) at 23-27 (July 6, 2011).

26 Motion at 6.

c. Metal Fatigue: NYS further claims that Entergys commitment to further review its design basis ASME Code fatigue evaluations presents a moving target[ ] that somehow prejudices intervenors.27 Again, NYS fails to mention that this commitment dates back to March 28, 2011, and was made by Entergy in response to an NRC Staff request for additional information regarding a broader industry issue.28 The Staff determined, based in part on this commitment, that there were no changes to its conclusions regarding Entergys metal fatigue analyses for Indian Point license renewal.29 The States challenge to the adequacy of Entergys proposed AMP for metal fatigue is therefore ripe for adjudication, notwithstanding the States desire to delay that adjudication until Entergy completes its commitments as part of the implementation of that AMP. Moreover, to the extent NYS perceives other concerns from the Staff on metal fatigue issues,30 such concerns have been resolved to the Staffs satisfaction, as documented in the SSER, and therefore provide no basis for any delay in the submission of prefiled testimony.

d. Underground Piping and Tanks: The States concerns regarding Entergys Underground Piping and Tanks Inspection and Monitoring Program explicitly relate to the implementation details of the AMP.31 The fact that Entergy is still preparing a document required for the implementation of this AMP has no bearing on whether NYS has sufficient information to prepare its testimony on the adequacy of the AMP itself. On the contrary, the LRA, SSER, 27 Id.

28 See Letter from F. Dacimo, Entergy, to NRC, Response to Request for Additional Information (RAI) Att. 1 at 25-27 (Mar. 28, 2011), available at ADAMS Accession No. ML110960360 (Entergy Answer to Motion for Extension, Att. 3). Entergy also objects to the States attempt, in footnote 6 of its Motion, to insinuate that Entergy is somehow to blame for responding to the NRCs emergent generic concerns regarding metal fatigue analyses.

29 See SSER at 4-3.

30 See Motion at 7.

31 Id. at 8.

regulatory correspondence, and numerous disclosed documents provide NYS with more than sufficient information on the relevant AMPs to proceed with testimony on the adequacy of the LRA.

5. The remaining issues also do not provide sufficient cause for delay. The States various claimed resource constraints do not justify the requested 90-day postponement.32 Nor does the pendency of a Commission appeal or the unavailability of certain witnesses for certain (unspecified) periods of time justify such delay. In particular:

a. NYS claims that Entergys pending petition for review of LBP-11-17 diverted State resources,33 but the State does not explain why a pending appeal on the resolution of one contention requires a delay in the hearing on all of the other contentions.34 The adjudication of Entergys LRA should not be delayed because NYS failed to allocate sufficient resources to address all of the issues the State raised in its intervention. As it stands, there is no testimony due on NYS-35/36, which the Board resolved in LBP-11-17. Further, an ongoing proceeding with multiple contested issues should not effectively be stayed because of a pending appeal on one of those issues.35

b. NYS asserts that the contract with its expert on contention NYS-12C recently ended.36 It is not clear from the Motion how long this situation has been known or whether the State could have avoided the need for additional time to work with a new expert. Entergy understands that witnesses can become unavailable for unexpected reasons, and would have been amenable to consultation on this discreet issue.

c. Next, NYS refers to Riverkeepers requests for certain documents associated with the metal fatigue contention (NYS-26/RK-TC-1).37 But NYS does not explain how Entergys ongoing, good-faith cooperation with Riverkeeper in responding to 32 See Bellefonte, CLI-10-26, slip op. at 3.

33 Motion at 8.

34 See id. at 5.

35 See Entergy Nuclear Generation Co. (Pilgrim Nuclear Power Station), LBP-08-22, 68 NRC 590, 594-95 (explaining that the granting of summary disposition on one contention and the subsequent appeal of that ruling did not halt the litigation of another contention).

36 Motion at 8.

37 Id.

its recent additional document requests impacts the States efforts to prepare its testimony.38

d. The States planned four-day computer system outage39 certainly provides no justification for a 90-day extension of time.

e. Dr. Laheys unavailability during the month of October40 likewise falls short of the unavoidable circumstances standard, because the October 11 deadline for testimony submittal has long been known. In any event, unspecified limitations on one experts availability during the course of one month certainly provide no justification for delaying this entire proceeding for three months.

f. NYS complains that its challenge to the NRCs recent waste confidence rulemaking necessarily diverted State resources,41 but NYS cannot rely on its own decision to engage in that litigation as an excuse to delay the progress of this proceeding. Nor does NYS explain why the delay in the courts briefing schedule requires the State to seek an extension in this proceeding.

g. Finally, Riverkeeper and Clearwaters previous submission of a new contention based on the NRCs Fukushima Near-Term Task Force Report has no discernable impact on the States ability to prepare its prefiled testimony.42

6. NYS will have the opportunity to raise new issues if they arise. To the extent new information arises and is relevant to the admitted contentions, Entergy is obligated to disclose it, consistent with NRC regulations and the Boards July 1, 2010 Scheduling Order. NYS will have the opportunity to file new or amended contentions or seek other appropriate relief if it believes such actions are warranted by the new information. Therefore, moving forward with the current, long-established schedule for this proceeding will not prejudice NYS. On the contrary, further delay will prejudice Entergys right to an efficient adjudication of its LRA.

38 As Riverkeeper noted in its September 28, 2011 Response to States Motion, Entergy has been working cooperatively with Riverkeeper on its various document requests and has responded to all but the most recent request dated September 26. Entergy, however, does not agree that the requested documents, if they in fact exist, are relevant or necessary for the preparation of prefiled testimony.

39 See Motion at 8.

40 See id.

41 Id. at 9.

42 See id.

III. CONCLUSION For the reasons set forth above, the Board should deny the States Motion.

Respectfully submitted, Signed (electronically) by Paul M. Bessette William C. Dennis, Esq. Kathryn M. Sutton, Esq.

Entergy Nuclear Operations, Inc. Paul M. Bessette, Esq.

440 Hamilton Avenue Martin J. ONeill, Esq.

White Plains, NY 10601 MORGAN, LEWIS & BOCKIUS LLP Phone: (914) 272-3202 1111 Pennsylvania Avenue, N.W.

Fax: (914) 272-3205 Washington, D.C. 20004 E-mail: wdennis@entergy.com Phone: (202) 739-3000 Fax: (202) 739-3001 E-mail: ksutton@morganlewis.com E-mail: pbessette@morganlewis.com E-mail: martin.oneill@morganlewis.com Counsel for Entergy Nuclear Operations, Inc.

Dated in Washington, D.C.

this 28th day of September 2011 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of ) Docket Nos. 50-247-LR and

) 50-286-LR ENTERGY NUCLEAR OPERATIONS, INC. )

)

(Indian Point Nuclear Generating Units 2 and 3) )

) September 28, 2011 ANSWER CERTIFICATION Counsel for Entergy certifies that he has made a sincere effort to make himself available to listen and respond to the moving party, and to resolve the factual and legal issues raised in the motion, and that his efforts to resolve the issues have been unsuccessful.

Signed (electronically) by Paul M. Bessette Paul M. Bessette, Esq.

MORGAN, LEWIS & BOCKIUS LLP 1111 Pennsylvania Avenue, N.W.

Washington, D.C. 20004 Phone: (202) 739-5796 Fax: (202) 739-3001 E-mail: pbessette@morganlewis.com Counsel for Entergy Nuclear Operations, Inc.

DB1/ 68215717.4

TABLE OF ENTERGY ANSWER TO MOTION FOR EXTENSION ATTACHMENTS Attachment No.

NRC Inspection Manual, Temporary Instruction 2516/001, Review of License Renewal Activities (Mar. 30, 2011)........................................................................................................ 1 Supplement to Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Units Nos. 2 and 3, App. A (Aug. 30, 2011)......................................................... 2 Letter from F. Dacimo, Entergy, to NRC, Response to Request for Additional Information (RAI) (Mar. 28, 2011) ........................................................................................................... 3 DB1/ 68215717.4

Entergys Answer to Motion for Extension Attachment 1 DB1/ 68215717.4

NRC INSPECTION MANUAL DLR TEMPORARY INSTRUCTION 2516/001 REVIEW OF LICENSE RENEWAL ACTIVITIES PROGRAM APPLICABILITY: This temporary instruction (TI) applies to Indian Point Nuclear Generating Unit 2 and Pilgrim Nuclear Power Station only.

2516/001-01 INSPECTION OBJECTIVES 01.01 To report the status of the applicants implementation of license renewal commitments, license conditions and selected aging management programs as described in a plants license renewal safety evaluation report (LR-SER).

01.02 To verify that the license renewal application is updated annually in accordance with the requirement to submit changes to the current licensing basis (CLB) during the U.S. Nuclear Regulatory Commission (NRC) review of the license renewal application (as required by 10 CFR 54.21(b)).

01.03 To verify that newly identified systems, structures, and components (SSCs) are included in the annual FSAR updates as required by 10 CFR 54.37(b) and the guidance provided in Regulatory Issue Summary (RIS) 2007-16, Revision 1, Implementation of the Requirements of 10 CFR 54.37(b) for Holders of Renewed Licenses, dated April 28, 2010.

01.04 To verify that the applicants description of the programs and activities for managing the effects of aging are consistent with the final safety analysis report (FSAR) supplement summary descriptions (included in Sections 3 and 4 of the LR-SER).

2516/001-02 BACKGROUND Recently, the NRC experienced challenges in the inspection of license renewal activities and documentation of inspection results associated with completion of Inspection Procedure (IP) 71003, Post-Approval Site Inspection for License Renewal, at the Oyster Creek facility. These challenges resulted because (1) IP 71003 was structured to be completed after the license was renewed, (2) license renewal at Oyster Creek station was delayed, and (3) the NRC expected to verify that the applicant had implemented license renewal commitments before it entered the period of extended operation (i.e., the post-40-year license period). This TI is written to allow for timely verification by NRC inspectors that the applicant has made sufficient progress in implementing its license renewal commitments before entering its post-40-year license period and to allow documentation of these inspection activities while the operating Issue Date: 03/30/11 2516/001

license is being considered for renewal.

This TI shall be performed in cases where holders of an operating license meet the criteria of 10 CFR 2.109, Effect of Timely Renewal Application, for timely renewal but IP 71003 cannot be performed in a timely manner because the NRCs final decision regarding the renewal of the operating license may not allow sufficient time to plan and conduct post license-renewal inspection before the period of extended operation.

The primary purpose of this TI is to allow the NRC to verify selected commitments made by the applicant during the license renewal process when such verification requires access to areas normally not accessible during power operations and to verify that the applicant has successfully implemented commitments associated with other SSCs outside containment or high-radiation areas as described in its LR-SER before the applicant enters the period of extended operation (the post-40-year licensing period).

The focus of the TI will be to verify testing of SSCs and applicant implementation of aging management programs associated with SSCs that require inspector access to containment or to areas normally considered high-radiation areas during power operations. Additionally, inspectors will verify the applicants completion of selected license renewal commitments, other than those requiring access to containment or to high-radiation areas, to ensure confidence that the applicant has made reasonable progress in completing its license renewal commitments before entering the period of extended operation. Any additional inspections to follow up on issues identified during this TI should be performed using IP 71003 if the license is renewed. Also, the NRC should have completed IP 71002, License Renewal Inspection, before this TI is performed.

2516/001-03 INSPECTION REQUIREMENTS AND GUIDANCE 03.01 Review of License Renewal Commitments and License Conditions. Select a sample of completed commitments and license conditions to verify that the applicant has completed the actions necessary to comply with the draft license conditions in the NRC staffs LR-SER and has implemented the aging management programs and time-limited aging analyses (TLAAs) included in the LR-SER.

Inspectors should familiarize themselves with the requirements and guidance relating to license renewal in general. The inspectors should familiarize themselves with the specific license renewal application and associated LR-SER for the plant being inspected. License renewal requirements and guidance documents that should be reviewed before an inspection include the following:

• 10 CFR Part 54

• Statement of Consideration published with the revision to 10 CFR Part 54 in the Federal Register, Volume 60, No. 88, May 8, 1995, pages 22461 to 22495

• plant-specific license renewal application Issue Date: 03/30/11 2516/001

• SER and Appendix A for the plant(s) to be inspected In selecting samples, consideration should be given to attributes such as the following:

• risk significance of the commitments, using insights gained from sources such as the NRCs SDP Risk Informed Inspection Notebooks, Revision 2

• extent of previous license renewal audits and inspections of aging management programs

• extent that baseline inspection programs will inspect SSCs or a commodity group

• results of the one-time inspections (e.g., selective leaching inspection) to ensure that either there is no aging effect or the aging effects detected were properly evaluated

• draft license condition(s) to address existing plant issue(s)

Before performing these inspections, the lead inspector will determine the number and nature of proposed license conditions and commitments to be reviewed. The sample should include as many proposed license conditions and commitments, which were identified by the staff during the application review, as inspection resources will allow.

The inspection will also include those proposed license conditions and commitments made by the applicant, which were either modified/enhanced or agreed upon by the staff, and selected in accordance with their risk significance.

The inspection team will inspect the proposed license conditions and commitments to the extent necessary to determine that they were implemented as described in the LR-SER and that any modification of commitments was done in accordance with 10 CFR 50.59, Changes, Tests and Experiments, and established commitment management guidance. The inspection team should determine that there is reasonable assurance that the commitment tracking program is effective.

03.02 Verification of Annual Update. Verify that the license renewal application is updated annually in accordance with the requirement to submit changes to the CLB during NRC review of the license renewal application, according to 10 CFR 54.21(b).

03.03 Verification of Inclusion of Newly Identified SSCs in the FSAR Updates. Verify that newly identified SSCs are included in the annual FSAR updates as required by 10 CFR 54.37(b) and the guidance provided in RIS 2007-16.

Applicants may identify new SSCs that should be within the scope of its license renewal program at any time. These SSCs are newly identified pursuant to 10 CFR 54.37(b),

which has been further clarified in RIS 2007-16 as part of NRC generic communications. The NRC may also specify additional newly identified SSCs that one or more holders of renewed licenses must evaluate and include as applicable in its next FSAR update in accordance with 10 CFR 54.37(b).

Issue Date: 03/30/11 2516/001

Inspectors should contact NRR/Division of License Renewal (DLR) staff for (1) information on generic communications that were issued naming newly identified SSCs, or (2) technical assistance in the review of new aging management programs that have been developed by the applicant.

03.04 Review of License Programs. Verify that the applicants description of the programs and activities for managing the effects of aging are consistent with the FSAR supplement summary descriptions (included in Sections 3 and 4 of the LR-SER).

The updated FSAR (UFSAR) supplement describes the aging management programs and TLAA approved by the NRC in the SER issued with the renewed license. This inspection will also verify that the applicants aging management program or TLAA being implemented is consistent with the UFSAR description and that changes, caused by the inclusion of newly identified SSCs, were included in the UFSAR. If the applicant has not submitted an UFSAR update since implementing the program or TLAA, the inspection team will review the planned UFSAR changes and verify that they are included in an appropriate tracking system.

The inspectors should determine the basis for the removal or addition of SSCs or commodity groups to an aging management program and whether the basis was justified as a part of the annual update.

2516/01-04 REPORTING REQUIREMENTS The inspector should document the following aspects of the inspection for each inspected area or commitment, as appropriate:

a. Identify how the inspection was conducted (i.e., the methods of inspection).

Methods can include a walkdown, an in-office review, observation of tests, and discussion with plant personnel.

b. Identify what was inspected. Include sufficient detail on which and how many samples were completed. If more than six documents were reviewed, then list the items in an attachment and reference the attachment in the scope section.

c. Identify the inspection objectives and the criteria that were used

d. Report the specific conditions that were not met and the planned completion dates for commitments that have not been completely implemented

e. Include reference to applicants corrective action documents that describe issues regarding license renewal commitment implementation to allow follow-up of identified commitment implementation issues in the future.

Issues of concern resulting from this TI shall be documented in an inspection report. An issue of concern in this area is a collection of well-defined observations that raise questions on the applicants adequate implementation of proposed license conditions, commitment or aging management programs. For the purpose of this TI, issue of Issue Date: 03/30/11 2516/001

concern only applies to passive components.

Potential safety issues that may involve performance deficiency by the applicant as defined in the NRC Inspection Manual Chapter (IMC) 0612, Inspection Reports, shall be referred to the site resident inspection staff for follow-up, if needed, and determination of risk significance.

2516/01-05 COMPLETION SCHEDULE Portions of this TI should be completed during the outage preceding the beginning of the period of extended operation for the purpose of observing or verifying commitments of tests or other activities that require containment entries or access to rooms that would be normally be posted as a high-radiation area or higher when the reactor is operating.

The remaining portion of this TI can be completed at any other time before the period of extended operation. The team composition and size can vary for the purpose of conducting either the outage or nonoutage portion of this inspection. Also, additional inspection can be performed during the period of extended operation, after the license has been renewed, to follow up on issues identified during previous license renewal inspections. The inspections, with the exception of the followup portion to be conducted once the license is renewed and during the period of extended operation, should be completed by December 31, 2013.

2516/01-06 EXPIRATION This TI will expire on December 31, 2013.

2516/01-07 CONTACT For questions regarding performance of this TI or emergent issues, contact Chief, Renewal of Program Operations Branch (RPOB)/DLR/NRR, or Chief, Reactor Inspection Branch/Division of Inspection and Regional Support/NRR. The inspectors should request assistance from NRR technical staff if the visual inspection requires more extensive knowledge of aging effects to a specific structures or component.

2516/01-08 STATISTICAL REPORTING Direct inspection effort in implementing this TI should be charged to TI 2516-001. An IPE code of LI should be used for all direct inspection effort. An IPE code of LRP should be used for any indirect inspection effort for preparation and/or documentation.

Issue Date: 03/30/11 2516/001

2516/01-09 RESOURCE ESTIMATES The inspection resources required to complete this TI are the same as the inspection resources required to complete IP 71003. It has been estimated that this TI will require approximately 2 weeks of inspection time on site involving a team of four inspectors and an inspection lead. An additional week will be allocated each to inspection preparation, in-office review between 2 onsite weeks, and documentation of the inspection results.

The team leader will require an additional week of preparation and an additional 2 weeks to finalize the inspection report. Based on these estimates, each inspection will require about 28 inspection weeks. It is estimated that each unit at each site will require an inspection; however, later inspections at multiunit sites may not require the same level of effort as the inspection of the first unit.

Completion of this TI will satisfy completion of IP 71003 inspection requirements.

Inspection resources to complete this TI and IP 71003 should not exceed 28 inspection weeks.

2516/01-10 TRAINING No formal training is proposed for the performance of this TI. Regions should contact the DLR if they need technical support during the inspection of license renewal commitments.

2516/01-11 REFERENCES 10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants Statement of Consideration published with the revision to 10 CFR Part 54 in the Federal Register, Vol. 60, No. 88, May 8, 1995, pp. 22461 to 22495 Plant-specific license renewal application SER and Appendix A for the plant(s) to be inspected END : Revision History Issue Date: 03/30/11 2516/001

Attachment 1 Revision History for TI 2516/001 Commitment Issue Date Description of Change Training Training Comment Resolution Tracking Needed Completion Accession Number Number Date N/A ML110620255 No N/A N/A Reviewed commitments and 03/30/11 none found for 4 years.

CN 11-004 New temporary inspection procedure to provide inspection guidance related to verification of license renewal commitments.

Issue Date: 03/30/11 Att-1 2516/001

Entergys Answer to Motion for Extension Attachment 2 DB1/ 68215717.4

REG U t..r;..

UNITED STATES 0.".... NUCLEAR REGULATORY COMMISSION WASHINGTON. D.C. 20555-0001 8

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Mr. Joseph E. Pollock, Vice President for Operations Entergy Nuclear Operations, Inc.

Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249

SUBJECT:

SUPPLEMENT TO SAFETY EVALUATION REPORT RELATED TO THE LICENSE RENEWAL OF INDIAN POINT NUCLEAR GENERATING UNIT NOS.

2AND3

Dear Mr. Pollock:

By letter dated April 23, 2007, as supplemented by letters dated May 3, and June 21,2007, Entergy Nuclear Operations, Inc. (Entergy) submitted to the U.S. Nuclear Regulatory Commission (NRC) an application to renew the Indian Point Nuclear Generating Unit Nos. 2 and 3, operating licenses for an additional 20 years beyond the current license expiration dates of September 28. 2013 and December 12, 2015, respectively. The license renewal application (LRA) was submitted pursuant to Title 10 of the Code of Federal Regulations Part 54 (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants."

The NRC staff determined that the LRA was complete and acceptable for docketing on July 25. 2007.

The NRC staff has reviewed the license renewal application for compliance with the requirements of 10 CFR Part 54, and issued its findings in NUREG-1930, "Safety Evaluation Report [SER] Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3" on August 11, 2009. The SER was published in November 2009, following the staff's receipt of comments from the Advisory Committee on Reactor Safeguards (ACRS).

The enclosed Supplement to the SER documents the staff's review of additional information provided by Entergy in annual updates, LRA amendments, and responses to staff requests for additional information (RAls) since the issuance of the SER.

-2 If you have any questions regarding this matter, please contact the license renewal project manager, Rob Kuntz, at 301-415-3733 or e-mail robert.kuntz@nrc.gov.

Sincerely, r(;-~~

Brian E. Holian, Director Division of License Renewal Office of Nuclear Reactor Regulation Docket Nos. 50-247 and 50-286

Enclosure:

As stated cc w/encl: Listserv

, y (' , c' , c OFFICE LA:DLR/RPB1 PM:DLR/RPB1 BC:DLR/RPB1 BC:DLR/RARB NAME SFigueroa RKuntz DMorey BPham*

DATE 07/20/2011 08/212011 08/2/2011 . 08/1/2011 OFFICE BC:DLR/RAPB BC:DLR/RASB OGC (NLO) LA: DLR/RPB1 NAME DPelton* RAuluck* STurk SFigueroa (YEdmonds for)

DATE 07/29/2011 08/112011 08/30/2011 08/30/2011 OFFICE D:DLR NAME BHolian DATE 08/30/2011 Letter to Joseph E. Pollock from Brian E. Holian dated August 30,2011

SUBJECT:

SAFETY EVALUATION REPORT RELATED TO THE LICENSE RENEWAL OF INDIAN POINT NUCLEAR GENERATING STATION, UNIT NOS. 2 AND 3 DISTRIBUTION:

HARD COPY:

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NUREG-1930, Supplement 1 Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 Supplement 1 Docket Nos. 50-247 and 50-286 Entergy Nuclear Operations, Inc.

United States Nuclear Regulatory Commission Office of Nuclear Reactor Regulation August 2011

THIS PAGE INTENTIONALLY LEFT BLANK.

ABSTRACT This document is a supplemental safety evaluation report (SSER) for the license renewal application for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) as filed by Entergy Nuclear Operations, Inc., (Entergy or the applicant). By letter dated April 23, 2007, and as supplemented by letters dated May 3 and June 21, 2007, the applicant submitted the LRA in accordance with Title 10, Part 54, of the Code of Federal Regulations, Requirements for Renewal of Operating Licenses for Nuclear Power Plants. Entergy requests renewal of the IP2 and IP3 operating licenses (Facility Operating License Numbers DPR-26 and DPR-64, respectively) for a period of 20 years beyond the current expirations at midnight on September 28, 2013, for IP2, and at midnight on December 12, 2015, for IP3.

The NRC staff published NUREG-1930 Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 in two volumes in November 2009, which summarized the results of its safety review of the renewal application for compliance with the requirements of Title 10, Part 54, of the Code of Federal Regulations, (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants."

This SSER documents the staffs review of supplemental information provided by the applicant since the issuance of the SER. This information includes annual updates required by 10 CFR 54.21(b), and updated information and commitments in response to staff requests for additional information. This document only discusses the changes to the SER.

iii

THIS PAGE INTENTIONALLY LEFT BLANK TABLE OF CONTENTS ABSTRACT ................................................................................................................................ iii SECTION 1 INTRODUCTION AND GENERAL DISCUSSION............................................... 1-1 1.1 Introduction ................................................................................................................. 1-1 SECTION 2 STRUCTURES SYSTEMS AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW ....................................................................................................... 2-1 SECTION 3 AGING MANAGEMENT REVIEW RESULTS ..................................................... 3-1 3.0 Applicants Use of the Generic Aging Lessons Learned Report ................................... 3-1 3.0.3 Aging Management Programs................................................................................ 3-1 3.0.3.1 AMPs Consistent with the GALL Report ........................................................ 3-1 3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements

................................................................................................................................ 3-13 3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report ............... 3-14 3.0.5 Operating Experience for Aging Management Programs ..................................... 3-15 3.0.5.1 Summary of Technical Information in the Application .................................. 3-15 3.0.5.2 Staff Evaluation ........................................................................................... 3-16 3.0.5.3 UFSAR Supplement .................................................................................... 3-17 3.0.5.4 Conclusion .................................................................................................. 3-17 3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant Systems...... 3-17 3.1.2 Staff Evaluation .................................................................................................... 3-17 3.1.2.1 AMR Results Consistent with the GALL Report ........................................... 3-17 3.1.2.2 AMR Results Consistent with the GALL Report for which Further Evaluation is Recommended......................................................................................................... 3-19 3.2 Aging Management of Engineered Safety Features Systems ................................... 3-23 3.2.2 Staff Evaluation ................................................................................................... 3-23 3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ... 3-23 3.3 Aging Management of Auxiliary Systems .................................................................. 3-23 3.3.2 Staff Evaluation ................................................................................................... 3-23 3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ... 3-24 SECTION 4 TIME LIMITED AGING ANALYSIS .................................................................... 4-1 4.3 Metal Fatigue Analyses............................................................................................... 4-1 4.3.3 Effects of Reactor Water Environment on Fatigue Life .......................................... 4-1 4.3.3.1 Summary of Techical Information in the Application ..................................... 4-1 4.3.3.2 Staff Evaluation ............................................................................................ 4-1 4.3.3.1 UFSAR Supplement ..................................................................................... 4-3 4.3.3.4 Conclusion ................................................................................................... 4-3 SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ... 5-1 SECTION 6 CONCLUSION .................................................................................................. 6-1 v

vi Appendices Appendix A: List of Commitments ......................................................................................... A-1 Appendix B: Chronology ........................................................................................................ B-1 vii

THIS PAGE INTENTIONALLY LEFT BLANK ABBREVIATIONS ACI American Concrete Institute ADAMS Agencywide Documents Access and Management System AMP aging management program AMR aging management review ASME American Society of Mechanical Engineers AWWA American Water Works Association CAP corrective action program CASS cast austenitic stainless steel CLB current licensing basis CFR Code of Federal Regulations CUF cumulative usage factor EPRI Electric Power Research Institute EQ environmental qualification Fen environmental fatigue life correction factor GALL Generic Aging Lessons Learned GL Generic Letter IPEC Indian Point Energy Center IP2 and IP3 Indian Point Nuclear Generating Unit Nos. 2 and 3 ISI inservice inspection kV kilovolts LER licensee event report LRA license renewal application LWR light water reactor MRP Materials Reliability Program NRC Nuclear Regulatory Commission OEP operating experience program PEO period of extended operation PVC polyvinyl chloride PWSCC primary water stress corrosion cracking QA Quality Assurance vii

ABBREVIATIONS RAI request for additional information RCPB reactor coolant pressure boundary RIS Regulatory Information Summary SCC stress corrosion cracking SCs Structures and Components SER safety evaluation report SG steam generator SGMP steam generator management program SRP-LR Standard Review Plan for License Renewal Applications for Nuclear Power Plants SSCs systems, structures and components SSER supplemental safety evaluation report UFSAR updated final safety analysis report USAS United States of America Standard V volts viii

APPENDIX A IP LICENSE RENEWAL COMMITMENTS During the review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3), license renewal application (LRA) by the staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff), Entergy Nuclear Operations, Inc. (Entergy or the applicant) made commitments related to aging management programs (AMPs) to manage the aging effects for certain structures and components during the period of extended operation. The following table lists these commitments along with the applicants stated implementation schedules and sources for each commitment. This list supersedes the list published in Appendix A of NUREG-1930.

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 1 Enhance the Above Ground Steel Tanks Program for IP2 and A.2.1.1 IP2: September 28, NL-07-039 IP3 to perform thickness measurements of the bottom surfaces A.3.1.1 2013 of the condensate storage tanks, city water tank, and fire water IP3: December 12, tanks once during the first ten years of the period of extended B.1.1 2015 operation.

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

2 Enhance the Bolting Integrity Program for IP2 and IP3 to clarify A.2.1.2 IP2: September 28, NL-07-039 that actual yield strength is used in selecting materials for low 2013 A.3.1.2 NL-07-153 susceptibility to SCC and clarify the prohibition on use of B.1.2 IP3: December 12, lubricants containing MoS2 for bolting.

2015 The Bolting Integrity Program manages loss of preload and loss Audit Items 201, 241, of material for all external bolting. 270 A-1

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 3 Implement the Buried Piping and Tanks Inspection Program for A.2.1.5 IP2: September 28, NL-07-039 IP2 and IP3 as described in LRA Section B.1.6. 2013 A.3.1.5 NL-07-153 This new program will be implemented consistent with the IP3: December 12, B.1.6 NL-09-106 corresponding program described in NUREG-1801, Section 2015 XI.M34, Buried Piping and Tanks Inspection. Audit Item 173 NL-09-111 Include in the Buried Piping and Tanks Inspection Program NL-11-101 described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that 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.

4 Enhance the Diesel Fuel Monitoring Program to include cleaning A.2.1.8 IP2: September 28, NL-07-039 and inspection of the IP2 GT-1 gas turbine fuel oil storage tanks, 2013 A.3.1.8 NL-07-153 IP2 and IP3 EDG fuel oil day tanks, IP2 SBO/Appendix R diesel IP3: December 12, NL-08-057 generator fuel oil day tank, and IP3 Appendix R fuel oil storage B.1.9 2015 tank and day tank once every ten years. Audit Items 128, 129, 132, 491, 492, 510 A-2

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 4 (continued) Enhance the Diesel Fuel Monitoring Program to include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage 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/l. 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 following tanks once every ten years. IP2: EDG fuel 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 A-3

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule portable fuel oil contents prior to transferring the contents to the 4 (continued) storage tanks.

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

5 Enhance the External Surfaces Monitoring Program for IP2 and A.2.1.10 IP2: September 28, NL-07-039 IP3 to include periodic inspections of systems in scope and 2013 subject to aging management review for license renewal in A.3.1.10 accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall B.1.11 IP3: December 12, include areas surrounding the subject systems to identify 2015 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).

6 Enhance the Fatigue Monitoring Program for IP2 to monitor A.2.1.11 IP2: September 28, NL-07-039 steady state cycles and feedwater cycles or perform an 2013 evaluation to determine monitoring is not required. Review the A.3.1.11 NL-07-153 number of allowed events and resolve discrepancies between B.1.12 IP3: December 12, reference documents and monitoring procedures. 2015 Audit Item 164 Enhance the Fatigue Monitoring Program for IP3 to include all the transients identified. Assure all fatigue analysis transients are included with the lowest limiting numbers. Update the number of design transients accumulated to date.

A-4

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 7 Enhance the Fire Protection Program to inspect external A.2.1.12 IP2: September 28, NL-07-039 surfaces of the IP3 RCP oil collection systems for loss of 2013 material each refueling cycle. A.3.1.12 IP3: December 12, B.1.13 Enhance the Fire Protection Program to explicitly state that the 2015 IP2 and IP3 diesel fire pump engine 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 CO2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

A-5

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 8 Enhance the Fire Water Program to include inspection of IP2 A.2.1.13 IP2: September 28, NL-07-039 and IP3 hose reels for evidence of corrosion. Acceptance 2013 criteria will be revised to verify no unacceptable signs of A.3.1.13 NL-07-153 degradation. IP3: December 12, B.1.14 NL-08-014 2015 Enhance the Fire Water Program to replace all or test a sample Audit Items 105, 106 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 the IP3 foam based fire suppression tanks. Acceptance criteria will be enhanced to verify no significant corrosion.

A-6

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 9 Enhance the Flux Thimble Tube Inspection Program for IP2 and A.2.1.15 IP2: September 28, NL-07-039 IP3 to implement comparisons to wear rates identified in WCAP-2013 12866. Include provisions to compare data to the previous A.3.1.15 performances and perform evaluations regarding change to test B.1.16 IP3: December 12, frequency and scope. 2015 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.

10 Enhance the Heat Exchanger Monitoring Program for IP2 and A.2.1.16 IP2: September 28, NL-07-039 IP3 to include the following heat exchangers in the scope of the 2013 A.3.1.16 NL-07-153 program. IP3: December 12, B.1.17 NL-09-018

• Safety injection pump lube oil heat exchangers 2015 Audit Item 52

• RHR heat exchangers

• RHR pump seal coolers

• Non-regenerative heat exchangers A-7

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 10 (continued)

• 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, fouling, or scaling.

A-8

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 11 Deleted Not applicable Not applicable NL-09-056 NL-11-101 12 Enhance the Masonry Wall Program for IP2 and IP3 to specify A.2.1.18 IP2: September 28, NL-07-039 that the IP1 intake structure is included in the program.

A.3.1.18 2013 IP3: December 12, B.1.19 2015 A-9

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 13 Enhance the Metal-Enclosed Bus Inspection Program to add IP2 A.2.1.19 IP2: September 28, NL-07-039 480V bus associated with substation A to the scope of the bus 2013 inspected. A.3.1.19 NL-07-153 IP3: December 12, B.1.20 NL-08-057 Enhance the Metal-Enclosed Bus Inspection Program for IP2 2015 and IP3 to visually inspect the external surface of MEB Audit Item 124, 133, enclosure assemblies for loss of material at least once every 10 519 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will be no significant loss of material.

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.

A-10

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 14 Implement the Non-EQ Bolted Cable Connections Program for A.2.1.21 IP2: September 28, NL-07-039 IP2 and IP3 as described in LRA Section B.1.22.

2013 A.3.1.21 IP3: December 12, B.1.22 2015 15 Implement the Non-EQ Inaccessible Medium-Voltage Cable A.2.1.22 IP2: September 28, NL-07-039 Program for IP2 and IP3 as described in LRA Section B.1.23.

A.3.1.22 2013 NL-07-153 This new program will be implemented consistent with the IP3: December 12, B.1.23 NL-11-032 corresponding described in NUREG-1801,Section XI.E3, 2015 Inaccessible Medium-Voltage Cables Not Subject to 10 CFR Audit Item 173 NL-11-096 50.49 Environmental Qualification Requirements. NL-11-101 16 Implement the Non-EQ Instrumentation Circuits Test Review A.2.1.23 IP2: September 28, NL-07-039 Program for IP2 and IP3 as described in LRA Section B.1.24.

A.3.1.23 2013 NL-07-153 This new program will be implemented consistent with the IP3: December 12, B.1.24 corresponding described in NUREG-1801,Section XI.E2, 2015 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Audit Item 173 Environmental Qualification Requirements Used in Instrumentation Circuits.

17 Implement the Non-EQ Insulated Cables and Connections A.2.1.24 IP2: September 28, NL-07-039 Program for IP2 and IP3 as described in LRA Section B.1.25.

A.3.1.24 2013 NL-07-153 This new program will be implemented consistent with the IP3: December 12, B.1.25 corresponding described in NUREG-1801,Section XI.E1, 2015 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Audit Item 173 Environmental Qualification Requirements.

A-11

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 18 Enhance the Oil Analysis Program for IP2 to sample and A.2.1.25 IP2: September 28, NL-07-039 analyze lubricating oil used in the SBO/Appendix R diesel 2013 generator consistent with the oil analysis for other site diesel A.3.1.25 NL-11-101 generators. IP3: December 12, B.1.26 2015 Enhance the Oil Analysis Program for IP2 and IP3 to 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 and IP3 as A.2.1.26 IP2: September 28, NL-07-039 described in LRA Section B.1.27. 2013 A.3.1.26 NL-07-153 This new program will be implemented consistent with the B.1.27 IP3: December 12, corresponding program described in NUREG-1801, Section 2015 XI.M32, One-Time Inspection. Audit Item 173 A-12

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 20 Implement the One-Time Inspection - Small Bore Piping A.2.1.27 IP2: September 28, NL-07-039 Program for IP2 and IP3 as described in LRA Section B.1.28.

2013 A.3.1.27 NL-07-153 This new program will be implemented consistent with the IP3: December 12, B.1.28 corresponding program described in NUREG-1801, Section 2015 XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Audit Item 173 Piping.

21 Enhance the Periodic Surveillance and Preventive Maintenance A.2.1.28 IP2: September 28, NL-07-039 Program for IP2 and IP3 as necessary to assure that the effects 2013 of aging will be managed such that applicable components will A.3.1.28 continue to perform their intended functions consistent with the IP3: December 12, B.1.29 current licensing basis through the period of extended operation. 2015 22 Enhance the Reactor Vessel Surveillance Program for IP2 and A.2.1.31 IP2: September 28, NL-07-039 IP3 revising the specimen capsule withdrawal schedules to draw A.3.1.31 2013 and test a standby capsule to cover the peak reactor vessel fluence expected through the end of the period of extended IP3: December 12, B.1.32 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 vessel are maintained in storage.

23 Implement the Selective Leaching Program for IP2 and IP3 as A.2.1.32 IP2: September 28, NL-07-039 described in LRA Section B.1.33.

2013 A.3.1.32 NL-07-153 This new program will be implemented consistent with the IP3: December 12, B.1.33 corresponding program described in NUREG-1801, Section 2015 XI.M33, Selective Leaching of Materials. Audit Item 173 A-13

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 24 Enhance the Steam Generator Integrity Program for IP2 and IP3 A.2.1.34 IP2: September 28, NL-07-039 to require that the results of the condition monitoring 2013 assessment are compared to the operational assessment A.3.1.34 performed for the prior operating cycle with differences IP3: December 12, B.1.35 evaluated. 2015 25 Enhance the Structures Monitoring Program to explicitly specify A.2.1.35 IP2: September 28, NL-07-039 that the following structures are included in the program.

A.3.1.35 2013 NL-07-153

• Appendix R diesel generator foundation (IP3) IP3: December 12,

• Appendix R diesel generator fuel oil tank vault (IP3) B.1.36 NL-08-057 2015

• Appendix R diesel generator switchgear and enclosure (IP3) Audit Items 86, 87, 88, NL-08-127

• city water storage tank foundation 417, 358, 360 NL-11-032

• condensate storage tanks foundation (IP3)

• containment access facility and annex (IP3) NL-11-101

• 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)

• security access and office building (IP3)

• service water pipe chase (IP2/3)

A-14

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 25 (continued)

• service water valve pit (IP3)

• superheater stack

• transformer/switchyard support structures (IP2)

• 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, sump screens, strainers and flow barriers 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 A-15

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 25 (continued) 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 Monitoring Program for IP2 and IP3 to perform an engineering evaluation of groundwater samples to assess aggressiveness of 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 of the water control structure once per 3 years rather than the normal frequency of once per 5 years during the PEO.

A-16

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 25 (continued) Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria for inspections of concrete structures in accordance with ACI 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures prior to the period of extended operation.

26 Implement the Thermal Aging Embrittlement of Cast Austenitic A.2.1.36 IP2: September 28, NL-07-039 Stainless Steel (CASS) Program for IP2 and IP3 as described in 2013 LRA Section B.1.37. A.3.1.36 NL-07-153 B.1.37 IP3: December 12, This new program will be implemented consistent with the 2015 corresponding program described in NUREG-1801, Section Audit Item 173 XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

27 Implement the Thermal Aging and Neutron Irradiation A.2.1.37 IP2: September 28, NL-07-039 Embrittlement of Cast Austenitic Stainless Steel (CASS) 2013 Program for IP2 and IP3 as described in LRA Section B.1.38. A.3.1.37 NL-07-153 B.1.38 IP3: December 12, This new program will be implemented consistent with the 2015 corresponding program described in NUREG-1801, Section Audit Item 173 XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS).

A-17

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 28 Enhance the Water Chemistry Control - Closed Cooling Water A.2.1.39 IP2: September 28, NL-07-039 Program to maintain water chemistry of the IP2 2013 SBO/Appendix R diesel generator cooling system per EPRI A.3.1.39 NL-08-057 guidelines. IP3: December 12, B.1.40 2015 Enhance the Water Chemistry Control - Closed Cooling Water Audit Item 509 Program to maintain the IP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines.

29 Enhance the Water Chemistry Control - Primary and Secondary A.2.1.40 IP2: September 28, NL-07-039 Program for IP2 to test sulfates monthly in the RWST with a limit B.1.41 2013 of <150 ppb.

30 For aging management of the reactor vessel internals, IPEC will A.2.1.41 IP2: September 28, NL-07-039 (1) participate in the industry programs for investigating and A.3.1.41 2011 managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to IP3: December 12, B.1.41 the reactor internals; and (3) upon completion of these 2013 programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.

31 Additional P-T curves will be submitted as required per 10 CFR A.2.2.1.2 IP2: September 28, NL-07-039 50, Appendix G prior to the period of extended operation as part 2013 of the Reactor Vessel Surveillance Program. A.3.2.1.2 4.2.3 IP3: December 12, 2015 A-18

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 32 As required by 10 CFR 50.61(b)(4), IP3 will submit a plant- A.3.2.1.4 NL-07-039 IP3: December 12, specific safety analysis for plate B2803-3 to the NRC three years 2015 prior to reaching the RTPTS screening criterion. Alternatively, the 4.2.5 NL-08-127 site may choose to implement the revised PTS rule when approved.

33 At least 2 years prior to entering the period of extended A.2.2.3.3 IP2: September 28, NL-07-039 operation, for the locations identified in LRA Table 4.3-13 (IP2) 2011 A.3.2.2.3 NL-07-153 and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring IP3: December 12, NL-08-021 Program, IP2 and IP3 will implement one or more of the 4.3.3 2013 following: Audit Item 146 NL-10-082 Complete (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 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.

A-19

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule

4. An analysis using an NRC-approved version of the 33 (continued) 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 installed and 2.1.1.3.5 April 30, 2008 NL-07-078 operational by April 30, 2008. This committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) and, Complete NL-08-074 therefore, a license amendment pursuant to 10 CFR 50.90 is not NL-11-101 required.

35 Perform a one-time inspection of representative sample area of Audit Item 27 IP2: September 28, NL-08-127 IP2 containment liner affected by the 1973 event behind the 2013 insulation, prior to entering the period of extended operation, to NL-09-018 assure liner degradation is not occurring in this area. IP3: December 12, NL-11-101 2015 Perform a one-time inspection of representative sample area of the IP3 containment steel liner at the 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 containment liner analyses as needed.

A-20

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 36 Perform a one-time inspection and evaluation of a sample of Audit Item 359 IP2: September 28, NL-08-127 potentially affected IP2 refueling cavity concrete prior to the 2013 period of extended operation. The sample will be obtained by NL-09-056 core boring the refueling cavity wall in an area that is susceptible NL-09-079 to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel. NL-11-101 Additional core bore samples will be taken, if the 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 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.

37 Enhance the Containment Inservice Inspection (CII-IWL) Audit Item 361 IP2: September 28, NL-08-127 Program to include inspections of the containment using 2013 enhanced characterization of degradation (i.e., quantifying the dimensions of noted indications through the use of optical aids) IP3: December 12, during the period of extended operation. The enhancement 2015 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.

A-21

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule 38 For Reactor Vessel Fluence, should future core loading patterns 4.2.1 IP2: September 28, NL-08-143 invalidate the basis for the projected values of RTPTS or CVUSE, 2013 updated calculations will be provided to the NRC.

IP3: December 12, 2015 39 Deleted Not applicable Not applicable NL-09-079 40 Evaluate plant specific and appropriate industry operating B.1.6 IP2: September 28, NL-09-106 experience and incorporate lessons learned in establishing B.1.22 2013 appropriate monitoring and inspection frequencies to assess aging effects for the new aging management programs. IP3: December 12, B.1.23 Documentation of the operating experience evaluated for each 2015 new program will be available on site for NRC review prior to the B.1.24 period of extended operation. B.1.25 B.1.27 B.1.28 B.1.33 B.1.37 B.1.38 A-22

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule N/A IP2: After the NL-11-032 41 IPEC will inspect steam generators for both units to assess the beginning of the condition of the divider plate assembly. The examination PEO and prior to NL-11-074 technique used will be capable of detecting PWSCC in the September 28, steam generator divider plate assembly. The IP2 steam 2023 NL-11-090 generator divider plate inspections will be completed within the first ten years of the period of extended operation (PEO). The IP3: Prior to the NL-11-101 IP3 steam generator divider plate inspections will be completed end of the first within the first refueling outage following the beginning of the refueling outage PEO.

following the beginning of the PEO N/A Option 1: NL-11-032 42 IPEC will develop a plan for each unit to address the potential IP2: Prior to March for cracking of the primary to secondary pressure boundary due 2024 NL-11-074 to PWSCC of tube-to-tubesheet welds using one of the following two options.

IP3: Prior to the NL-11-090 Option 1 (Analysis) end of the first refueling outage NL-11-096 following the IPEC will perform an analytical evaluation of the steam beginning of the generator tube-to-tubesheet welds in order to establish a PEO. check these technical basis for either determining that the tubesheet cladding against august 9 and welds are not susceptible to PWSCC, or redefining the letter.

pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant Option 2:

pressure boundary function. The redefinition of the reactor IP2: Between coolant pressure boundary must be approved by the NRC as a March 2020 and license amendment request.

March 2024 A-23

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule Option 2 (Inspection)

IP3: Prior to the 42 (cont.) IPEC will perform a one-time inspection of a representative end of the first number of tube-to-tubesheet welds in each steam generator to refueling outages determine if PWSCC cracking is present. If weld cracking is following the identified: beginning of the PEO.

a. The condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and

b. An ongoing monitoring program will be established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

4.3.3 IP2: Prior to NL-11-032 43 IPEC will review design basis ASME Code Class 1 fatigue September 28, evaluations to determine whether the NUREG/CR-6260 2013 NL-11-101 locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations IP3: Prior to for the IP2 and IP3 configurations. If more limiting locations are December 12, identified, the most limiting location will be evaluated for the 2015 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 alloy, if any.

A-24

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS Item Number Commitment UFSAR Applicants Source Supplement Section/ Implementation LRA Section Schedule N/A IP2: NL-11-032 44 IPEC will include written explanation and justification of any user Prior to intervention in future evaluations using the WESTEMS Design September 28, NL-11-101 CUF module.

2013 IP3: Prior to December 12, 2015 N/A IP2: NL-11-032 45 IPEC will not use the NB-3600 option of the WESTEMS program Prior to in future design calculations until the issues identified during the September 28, NL-11-101 NRC review of the program have been resolved.

2013 IP3: Prior to December 12, 2015 N/A IP2: Prior to NL-11-032 46 Include in the IP2 ISI Program that IPEC will perform twenty-five September 28, volumetric weld metal inspections of socket welds during each 2013 NL-11-074 10-year ISI interval scheduled as specified by IWB-2412 of the ASME Section XI 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.

A-25

Entergys Answer to Motion for Extension Attachment 3 DB1/ 68215717.4

Entergv Nuclear Northeast Indian Point Energy Center Entergy: 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 788-2055 Fred Dacimo Vice President License Renewal NL-11-032 March 28, 2011 U.S. Nuclear Regulatory Commission AnN: Document Control Desk Washington, DC 20555-0001

SUBJECT:

Response to Request for Additional Information (RAI)

Aging Management Programs Indian Point Nuclear Generating Unit Nos. 2 & 3 Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64

REFERENCE:

1. NRC Letter, "Request for Additional Information for the Review of the Indian Point Nuclear Generating Unit Numbers 2 and 3, License Renewal Application," dated February 10, 2011

Dear Sir or Madam:

Entergy Nuclear Operations, Inc is providing, in Attachment 1, the response to the referenced letter request for additional information (RAI). In addition, Attachment 1 includes a response to questions asked of other license renewal applicants regarding fatigue analysis software. provides the latest list of regulatory commitments to include new commitments contained in this letter.

If you have any questions, or require additional information, please contact Mr. Robert Walpole at 914-734-6710.

Docket Nos. 50-247 & 50-286 NL-11-032 Page 2 of 2 I {j~(;lare under penalty of perjury that the foregoing is true and correct. Executed on 1!1~ tJ1 £. 9 ) 2.t> 1/.

FRD/cbr

Attachment:

1. Response to Request for Additional Information (RAI), Aging Management Programs

2. IPEC List of Regulatory Commitments (Rev. 13) cc: Mr. William Dean, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel Mr. Dave Wrona, NRC Branch Chief, Engineering Review Branch I Mr. John Boska, NRR Senior Project Manager Mr. Paul Eddy, New York State Department of Public Service NRC Resident Inspector's Office Mr. Francis J. Murray, Jr., President and CEO NYSERDA

ATTACHMENT 1 TO NL-11-032 LICENSE RENEWAL APPLICATION RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION (RAI)

AGING MANAGEMENT PROGRAMS ENTERGY NUCLEAR OPERATIONS, INC.

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

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 2 of 27 INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION (RAI)

AGING MANAGEMENT PROGRAMS RAI3.0.3.1.2-1

Background

In light of Operating Experience (OE) that has occurred coincident with and after the staff evaluation of the Indian Point License Renewal Application (LRA) and issuance of the Safety Evaluation Report (SER), the staff is concerned about the continued susceptibility to failure of buried (Le., piping in direct contact with soil) and/or underground piping (Le., piping not in direct contact with soil, but located below grade in a vault, pipe chase, or other structure where it is exposed to air and where access is limited) that is within the scope of 10 CFR 54.4 and subject to aging management for license renewal. The staff reviewed the LRA, SER and a letter dated July 27,2009 from the applicant addressing buried pipe program modifications as a result of recent site operating experience. Based on the review of these documents subsequent to the recent industry OE, the staff does not have enough information to evaluate how Indian Point is implementing changes to their program based on the industry experience.

Issue

1. The LRA and supplemental material did not contain enough specifics on the planned inspections for the staff to determine if the inspections would be adequate to manage the aging effect for all types/materials of in-scope buried pipes (e.g., safety/code class and potential to release materials detrimental to the environment (e.g., diesel fuel and radioisotopes that exceed Environmental Protection Agency (EPA) drinking water standards>>.

2. The staff believes that buried coated steel piping is more susceptible to potential failure if it is not protected by a cathodic protection system unless soil resistivity is greater than 20,000 ohm-cm.

3. The LRA and supplemental material did not contain enough specifics for the staff to understand the general condition of the backfill used in the vicinity of buried in-scope piping.

4. In a letter dated July 27,2009, the applicant stated that it will employ qualified inspection methods with demonstrated effectiveness for detection of aging effects during the period of extended operation. The acknowledges that where examining buried pipe from the exterior surface is not possible due plant configuration (e.g., the piping is located underneath foundations) it is reasonable to substitute a from the the pipe provided the surface is properly prepared. However, beyond ultrasonic techniques, the staff is not aware of another reliable volumetric inspection methodology that is suitable for inspecting buried in scope piping. This is particularly true, in light of industry experience, with guided wave ultrasonic technology.

5. Based on a review of the LRA and UFSAR, it is not clear to the staff what in-scope systems (if any) have underground piping or if such piping will receive inspections consistent with the program described in LRA AMP B.1.11 External Surfaces Monitoring Program.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 3 of 27

6. LRA Sections A.2.1.5 and A.3.1.5 states that corrosion risk will be determined through consideration of material, soil resistivity, drainage, presence of cathodic protection and type of coating. Given that cathodic protection has not been installed for all buried in-scope piping, the staff lacks sufficient information to conclude that the applicant's evaluation of soil corrosivity will provide reasonable assurance that in-scope buried piping will meet its intended license renewal function{s). Specifically, the staff is concerned with the following:

a. While the applicant stated that it will include consideration of soil resistivity and drainage, it did not state that other important soil parameters would be included such as, pH, chlorides, redox potential, sulfates and sulfides.

b. The applicant did not state how often it will conduct testing of localized soil conditions, nor provide the specific locations relative to buried in-scope piping that is not cathodically protected.

c. The applicant did not state how they would integrate the various soil parameters into an assessment of corrosivi~ of the soil, such as using "Assessment of Overall Soil Corrosivity to Steel,,,1 or AWWA C105 .

d. The applicant did not specifically state how localized soil data will be factored into increased inspections, including the specific increase in the number of committed inspections by material type and location.

Request

1. Respond to the following:

a. Describe how many in-scope buried piping segments for each material, code/safety-related piping, and potential to release materials detrimental to the environment category will be inspected.

Response for RAl3.0.3.1.2-1 Part 1a For the 10-year period prior to the PEO, the following table presents the planned inspections for buried piping subject to aging management review that is code/safety-related (Code/SR) or has the potential to release materials detrimental to the environment (hazmat). Inspections by material and category are indicated.

Material Category IP2 Inspections IP3 Inspections Carbon steel Code/SR 13 14 Carbon steel Hazmat 13 5 Stainless steel Hazmat N/A 6

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 4 of 27

b. For the 45 planned inspections prior to the period of extended operation:

i. How many will consist of an excavated direct visual inspection of the external surfaces of the buried pipe?

ii. What length of piping will be excavated and have a direct visual inspection conducted?

Response for RAI 3.0.3.1.2-1 Part 1b The following table provides the number of planned direct visual inspections prior to the PEO.

For planned direct visual inspections, future excavations will expose a minimum of 10 linear feet of pipe, for full circumferential inspections. Ten completed inspections have ranged from approximately five feet to more than ten feet averaging approximately eight linear feet.

Material Category IP2 Inspections IP3 Inspections Carbon steel Code/SR 9 8 Carbon steel Hazmat 11 3 Stainless steel Hazmat N/A 3

c. Understanding that the total number of inspections performed will be informed by plant-specific and industry operating experience, what minimum number of inspections of buried in-scope piping is planned during the 40 - 50 and 50 - 60 year operating periods? When describing the minimum number of planned inspections, differentiate between material, code/safety-related piping, and potential to release materials detrimental to the environment category piping inspection quantities of buried in-scope piping.

Response for RAI3.0.3.1.2-1 Part 1c IPEC will perform direct visual inspections during each 10-year period of the PEO in accordance with the following table. The table lists inspections for different materials, for code/safety-related piping, and for piping with the potential to release materials detrimental to the environment (indicated as hazmat.)

Material Category IP2 Inspections IP3 Inspections Carbon steel Code/SR 6 6 Hazmat 8 8 Hazmat N/A 2 If sample results indicate the soil is corrosive as described in the response to 2.c below, then the number of inspections for the carbon steel code/safety-related piping will be increased to eight and the number of inspections for the carbon steel hazmat piping will be increased to 12.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 5 of 27

d. What specific inspections will be performed for the IP3 security generator propane tank and at what frequency?

Response for RAl3.0.3.1.2-1 Part 1d The nonsafety-related security generator system is credited for lighting during the response to fires in certain plant areas. Propane fuels the engine that drives the generator. Propane is non-toxic, non-caustic and will not create an environmental hazard if released as a liquid or vapor into water or soil. Monitoring the level of propane in the tank ensures the tank is capable of fulfilling its intended function. Consequently, only opportunistic inspections will be performed on the propane tank.

2. Respond to the following:

a. Confirm at IP2 that the service water system and at IP3 that the service water suction piping are the only in-scope steel piping systems currently protected by a cathodic protection (CP) system.

Response for RAI 3.0.3.1.2-1 Part 2a The IP2 service water lines near the river were originally provided with cathodic protection, but the rectifiers were subsequently removed. For IP2, the only in-scope steel piping cathodically protected is a portion of the city water piping in the area where they cross over the Algonquin gas pipelines.

At IP3, the service water suction is not piping and is not buried, but is the pump column in each respective intake bay. The pump columns were originally provided with cathodic protection.

The cathodic protection, however, was subsequently removed. The pump columns have been replaced with materials with greater resistance to corrosion.

For IP3, the only in-scope buried piping cathodically protected is the city water line over the Algonquin gas pipelines.

b. For those systems that are protected by a CP system:

i. Has annual NACE survey testing been conducted, and if so, for how many years?

ii. Have the output of the beds been trended, and if so, what are the results of the trending?

is cathodic protection system?

Response for RAI 3.0.3.1.2-1 Part 2b A cathodic protection rectifier was installed in 2009 to protect the IP2 and IP3 city water lines near the Algonquin Gas pipelines.

i. Annual NACE surveys have been performed on the system since its installation in November 2009.

ii. The rectifier output has been steady. Final testing and adjustment of the system occurred in July 2010.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 6 of 27 iii. The system has been in service since installation. It was out of service in July 2010 for one week. System availability since installation in November 2009 has been greater than 98%.

c. For buried in-scope steel piping systems that are not cathodically protected:

i. Justify why this piping will continue to meet or exceed the minimum design wall thickness throughout the period of extended operation, assuming that no coatings are applied to the piping, or ii. Justify why the number of the planned inspections of this piping is sufficient to reasonably assure that this piping will continue to meet or exceed the minimum design wall thickness throughout the period of extended operation.

Response for RAI 3.0.3.1.2-1 Part 2c The piping in question is coated which provides a significant barrier to corrosion. Inspections of excavated piping as discussed in the response to 3a below have found the coatings to be in good condition with no piping degradation. In addition, soil resistivity measurements as discussed in 3b below have shown the soil is non- aggressive. The number of planned inspections as discussed in 1a and the recent operating experience from site excavations provide reasonable assurance the piping will meet its license renewal intended functions during the PEO.

In addition, Entergy uses risk ranking to identify piping segments that are limiting (for example, closest to the water table) for direct visual inspection. Inspection results from these segments that show that the piping continues to maintain adequate wall thickness, provides reasonable assurance that similar piping in less limiting locations will maintain adequate wall thickness for the PEO.

To provide additional assurance that the piping will remain capable of performing its intended function, soil will be sampled prior to the PEO to confirm that the soil conditions are not aggressive. The number of inspections during the PEO will be based on the results the soil samples. The soil samples will be taken prior to the period of extended operation and at least once every 10 years thereafter to confirm the initial sample results. Soil samples will be taken at a minimum of two locations at least three feet below the surface near in-scope piping to obtain representative soil conditions for each system. The parameters monitored will include soil moisture, pH, chlorides, sulfates, and resistivity. American Water Works Association (AWWA)

Standard C105 Appendix A will be used to determine corrosiveness of the soil in addition to soil resistivity. If the soil resistivity is < 20,000 ohm-cm or the soil scores higher than 10 points using AWWA C105, the number of inspections provided in the response to question 1.c will be increased to provide additional assurance that the piping can perform its design function during the PEO.

This approach provides reasonable assurance that piping will continue to meet its design function without cathodic protection.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 7 of 27

3. Respond to the following:

a. Provide details on any further excavations conducted since July 2009 that provide insight on the extent of condition of the quality of the backfill in the vicinity of buried pipes.

Response for RAI 3.0.3.1.2-1 Part 3a Excavations since 2009:

• Oct, 2009 inch and 10-inch city water lines from the city water storage tank were inspected during a plant modification to install cathodic protection for city water lines near the Algonquin gas pipelines. Excavation and inspection covered approximately two 10-foot sections of 16-inch piping and approximately eight feet of the 10-inch piping.

Inspections found good coating condition and good quality backfill.

• Nov. 2009 inch fire protection header. Inspection of approximately eight feet of piping found good condition of the coating and good quality of the backfill.

In summary, visual inspections have not identified coating failures. Other than the condensate storage lines, visual observation of the backfill, has not identified rocks or foreign material with a reasonable potential to damage the piping external coating.

b. If there is no further information on the condition of the quality of backfill, justify why the planned inspections are adequate to detect potential degradation as a result of coating damage, particularly in steel buried pipe systems that are not protected by a CP system.

Response for RAI3.0.3.1.2-1 Part 3b The results of the visual inspections performed to date indicate that the quality of the backfill in contact with the coatings is generally good (i.e. no large, sharp rock material in contact with the coating). In addition to those inspection results, data will be acquired from future excavations and direct inspections that will provide input to determine the need for additional inspections or adjusted inspection frequencies.

4. Respond to the following:

a. In absence of a qualified method, and until such time that one is demonstrated to be effective, what alternative inspection methods will Entergy employ when excavated direct visual

..,,,+,,, ... ,, are not to plant configuration.

Response for RAI 3.0.3.1.2-1 Part 4a In absence of a qualified method, and until such time that one is demonstrated to be effective, Entergy has no plans to employ alternate inspection methods.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 8 of 27

b. Justify why the methods identified in response to request 4a will be effective at providing reasonable assurance that the buried in-scope piping systems will meet their current licensing basis function.

Response for RAI3.0.3.1.2-1 Part 4b Entergy has no plans to employ alternate inspection methods

c. If a volumetric examination method is used, what percentage of interior axial length of the pipe will be inspected?

Response for RAI 3.0.3.1.2-1 Part 4c Entergy has no plans to employ alternate volumetric examination methods.

5. For in-scope underground piping, respond to the following:

a. State what systems have underground piping and indicate the corresponding length of piping Response for RAI3.0.3.1.2-1 Part Sa Underground piping and tanks are below grade, but are contained within a tunnel or vault such that they are in contact with air and are located where access for inspection is restricted. In-scope SSCs that are subject to aging management review at IPEC include no underground piping or tanks.

b. State how often and what quantity of underground piping for each system will be inspected by AMP, and indicate which AMP will be used.

Response for RAI3.0.3.1.2-1 Part Sb Not applicable.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 9 of 27

6. Respond to the following for buried in-scope steel piping without cathodic protection:

a. State what soil parameters will be included in the analysis of soil corrosivity beyond soil resistivity and drainage.

b. State how often soil sampling will be conducted and in what locations.

c. State how the various soil parameters will be integrated into an assessment of the corrosivity of the soil.

d. State how localized soil conditions will be factored into increased inspections, including the specific increase in the number of committed inspections by material type and location.

Response for RAI3.0.3.1.2-1 Part 6a Two commonly used methods for assessing soil corrosivity are (1) determination of soil resistivity alone, and (2) based on AWWA C105, which considers the following soil parameters: soil resistivity, pH, redox potential, sulfides, and moisture (drainage). Both of these measures will be used for determining soil corrosivity.

Response for RAI3.0.3.1.2-1 Part 6b Soil samples will be taken prior to the period of extended operation and at least once every 10 years thereafter to confirm the initial sample results. Soil samples will be taken at a minimum of two locations at least three feet below the surface near the in-scope piping to obtain representative soil conditions for each system.

Response for RAI3.0.3.1.2-1 Part 6c AWWA C105 soil corrosivity assessment utilizes a point system, using five (5) soil parameters: soil resistivity, pH, redox potential, sulfides, and moisture (drainage). Accordingly, soils scoring more than 10 points are considered corrosive. Based on soil reSistivity alone, a resistivity> 20,000 ohm-cm is considered non-corrosive.

Response for RAI3.0.3.1.2-1 Part 6d Initial piping inspection priority and re-inspection interval will be based on the overall assessment of a piping segment's impact risk and corrosion risk, based on the best available data. Soil will be sampled prior to the PEa to confirm that the soil conditions are not aggressive. The number of inspections during the PEO will be based on the results of this soil survey. The soil samples will be taken prior to the period of extended operation and at least once every 10 years thereafter to confirm the initial sample results. If the soil resistivity is < 20,000 ohm-cm and the soil scores higher than 10 points using AWWA C105, the number of inspections will be increased as discussed in the response to question 1.c to ensure the piping can perform its deSign function during the PEO. The additional inspections will be in locations with aggressive soil condition.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 10 of 27 RAI3.0.3.1.6-1

Background

NUREG-1801, Rev. 1, "Generic Aging Lessons Learned," (the GALL Report) addresses inaccessible medium voltage cables in Aging Management Program (AMP) XI.E3, "Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The purpose of this program is to provide reasonable assurance that the intended functions of inaccessible medium voltage cables (2 kV to 35 kV), that are not subject to environmental qualification requirements of 10 CFR 50.49 and are exposed to adverse localized environments caused by moisture while energized, will be maintained consistent with the current licensing basis. The scope of the program applies to inaccessible (in conduits, cable trenches, cable troughs, duct banks, underground vaults or direct buried installations) medium-voltage cables within the scope of license renewal that are subject to significant moisture simultaneously with significant voltage.

The application of AMP XI. E3 to medium voltage cables was based on the operating experience available at the time Revision 1 of the GALL Report was developed. However, recently identified industry operating experience indicates that the presence of water or moisture can be a contributing factor in inaccessible power cables failures at lower service voltages (480 V to 2 kV). Applicable operating experience was identified in licensee responses to Generic Letter (GL) 2007-01, "Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients," which included failures of power cable operating at service voltages of less than 2 kV where water was considered a contributing factor.

Recently identified industry operating experience provided by NRC licensees in response to GL 2007-01 has shown: (a) that there is an increasing trend of cable failures with length in service beginning in the 6th through 10th years of operation and, (b) that moisture intrusion is the predominant factor contributing to cable failure.

The staff has determined, based on the review of the cable failure distribution, that an annual inspection of manholes and a cable test frequency of at least every 6 years is a conservative approach to ensuring the operability of power cables and, therefore, should be considered.

In addition, recently identified industry operating experience has shown that some NRC licensees may experience cable manhole water intrusion events, such as flooding or heavy rain, that subjects cables within the scope of program for GALL Report XI.E3 to significant moisture. The staff has determined that event driven inspections of cable manholes, in addition to a 1 year periodic inspection frequency, is a conservative approach and, therefore, should be considered.

Issue The staff has concluded, based on recently identified industry operating experience concerning the failure of low power cables (480 V 2 kV) in the presence of significant moisture, that these cables The staff applicant's Inaccessible Medium-address inaccessible low voltage power cables [400 V (nominally 480 V) to 2 In more test inspection frequencies (e.g., from 10 and two years to six and one year, respectively) should be evaluated to ensure that the Non-EQ Inaccessible Medium Voltage Cable program test and inspection frequencies reflect industry and plant-specific operating experience and that test and inspection frequencies may be increased based on future industry and plant-specific operating experience.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 11 of 27 Request Provide a summary of your evaluation of recently identified industry operating experience and any plant-specific operating experience concerning inaccessible low voltage power cable failures within the scope of license renewal (not subject to 10 CFR 50.49 environmental qualification requirements), and how this operating experience applies to the need for additional aging management activities at your plant for such cables.

Response for RAI3.0.3.1.6-1 As reported in the NRC's November 12, 2008 summary of licensee responses to GL 2007-01, the number of cable failures is a small percentage of the total number of cables in these categories for all nuclear plants.

Indian Point responded to GL 2007-01 on May 7,2007 (ML071350410), and reported that Indian Point Unit 3 had experienced two cable failures, and that Unit 2 had experienced no failures based on the scope criteria set forth in GL 2007-01. Both Unit 3 failures involved low-voltage power cables, and were due to mechanical damage rather than the effects of aging. A search of plant-specific OE since the May 7, 2007 response to GL 2007-01 identified one Unit 2 failure and no Unit 3 failures of low or medium-voltage power cables that are in the scope of the maintenance rule or license renewal rule.

Excavation activities associated with a plant modification damaged a Unit 2 13.8kV off-site power feeder cable causing the Unit 2 cable failure. The effects of aging did not cause the cable failure.

Indian Point is revising its Non-EQ Inaccessible Medium-Voltage Cable Program to include low-voltage power cables that may be exposed to significant moisture.

1. Explain how Entergy will manage the effects of aging on inaccessible low voltage power cables within the scope of license renewal and subject to aging management review; with consideration of recently identified industry operating experience and any plant-specific operating experience. The discussion should include assessment of your aging management program description, program elements (Le.,

Scope of Program, Parameters Monitored/Inspected, Detection of Aging Effects, and Corrective Actions), and FSAR summary description to demonstrate reasonable assurance that the intended functions of inaccessible low voltage power cables subject to adverse localized environments will be maintained consistent with the current licensing basis through the period of extended operation.

Response for RAI 3.0.3.1.6-1 Part 1 Indian Point will include low-voltage power cables in the non-EQ inaccessible medium-voltage cable program, will increase cable testing and manhole inspedction frequency, and will provide for manhole inspections after events that could cause flooding of inaccessible cable raceways. The program will include provisions to increase cable testing and manhole inspection frequency based on the results of testing and inspections.

The following changes to LRA Sections A.2.1.22 and B.1.23 provide for the inclusion of low-voltage power cable in the Non-EQ Inaccessible Medium-Voltage Cable program.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 12 of 27 A.2.1.22 Non-Ea Inaccessible Medium-Voltage Cable Program The Non-EQ Inaccessible Medium-Voltage Cable Program is a new program that entails periodic and event-driven inspections for water collection in cable manholes, and periodic testing of cables. In scope medium-voltage cables (cables with operating voltage from 2kV to 35kV) and low-voltage power cables (400 V to 2 kV) exposed to significant moisture and *...oltage will be tested at least once every teA six years to provide an indication of the condition of the conductor insulation. Test frequencies are adjusted based on test results and operating experience. The program includes periodic inspections for water accumulation in manholes at least once every twG-years (annually). In addition to the periodic manhole inspections, inspection of event-driven occurrences, such as heavy rain or flooding will be performed. Inspection freguency will be increased as necessary based on evaluation of inspection results.

The Non-Ea Inaccessible Medium-Voltage Cable Program will be implemented prior to the period of extended operation. This new program will be implemented consistent with the corresponding program described in NUREG-1801,_Section XI.E3, Inaccessible Medium-Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements.

B.1.23 NON-EQ INACCESSIBLE MEDIUM-VOLTAGE CABLE Program Description The Non-EQ Inaccessible Medium-Voltage Cable Program is a new program that entails periodic inspections for water collection in cable manholes and periodic testing of cables. In scope medium-voltage cables (cables with operating voltage from 2kV to 35kV) and low-voltage power cables (400 V to 2 kV) exposed to significant moisture and '.<oltage will be tested at least once every teA six years to provide an indication of the condition of the conductor insulation. Test freguencies will be adjusted based on test results and operating experience. The program includes inspections for water accumulation in manholes at least once every twa year&-(annually). In addition to the periodic manhole inspections, inspection for event-driven occurrences, such as heavy rain or flooding will be performed. Inspection freguency will be increased as necessary based on evaluation of inspection results.

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

Operating Experience The Non-EQ Inaccessible Medium-Voltage Cable Program is a new program. Industry and plant~

specific operating experience will be considered when implementing this program. Industry operating experience that forms the basis for the program is described in the operating experience element of the NUREG-1801 program description. IPEC plant-specific operating experience is not inconsistent with the operating experience in the NUREG-1801 program description.

The inspection freguency for manholes is based on plant-specific operating experience with cable wetting or submergence in manholes (i.e., the inspection is performed periodically based on water accumulation over time and events such as heavy rain or flooding).

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 13 of 27 The IPEC program is based on the program description in NUREG-1801, which in turn is based on industry operating experience. As such, operating experience provides assurance that the Non-EQ Inaccessible Medium-Voltage Cable Program will manage the effects of aging such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation.

Conclusion The Non-EQ Inaccessible Medium-Voltage Cable Program will be effective for managing aging effects since it will incorporate proven monitoring techniques and industry and plant-specific operating experience. The Non-EQ Inaccessible Medium-Voltage Cable Program assures that the effects of aging will be managed such that the applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation.

Commitment 15 Implement the Non-EQ Inaccessible Medium-Voltage Cable Program for IP2 and IP3 as described in LRA Section 8.1.23.

This new program will be implemented consistent with the corresponding program described in NUREG-18011..Section XI.E3, Inaccessible Medium Voltage Power Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements.

2. Provide an evaluation showing that the proposed Non-EQ Inaccessible Medium-Voltage Cable program test and inspection frequencies, including event-driven inspections, incorporate recent industry and plant-specific operating experience for both inaccessible low and medium voltage cable.

Response for RAI3.0.3.1.6-1 Part 2 The Non-EQ Inaccessible Medium-Voltage Cable Program has been revised to include low-voltage inaccessible power cables. The cable test and manhole inspection frequencies have been increased in response to recent industry operating experience and license renewal correspondence. Provisions have been added to the program to increase the test and inspection frequencies if warranted by plant-specific test and inspection results or industry operating experience. Event-driven inspections have been added to the program based on recent industry license renewal correspondence. No recent adverse plant-specific operating experience has been identified that is inconsistent with industry operating experience. Therefore, the revised program incorporates recent operating experience associated with inaccessible low- and medium-voltage power cables.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 14 of 27

3. In Commitment 40, Entergy committed to evaluate plant-specific and industry operating experience prior to entering the period of extended operation. Explain how the proposed Inaccessible Medium Voltage Program will continue to ensure that future industry and plant-specific operating experience will be incorporated into the program such that inspection and test frequencies may be increased based on test and inspection results.

Response for RAI3.0.3.1.6-1 Part 3 The revised Non-EQ Inaccessible Medium Voltage Cable Program specifies that cable testing frequency and manhole inspection frequency will be adjusted as necessary based on the results of cable testing and manhole inspections. Indian Point will incorporate lessons learned from future industry and plant-specific operating experience, including plant-specific test and inspection results during implementation of the Non-EQ Inaccessible Medium Voltage Program.

RAI3.0.3.1.10-1

Background

By letter dated July 26, 2010, the applicant provided clarification of LRA Section B.1.28, "One Time Inspection

- Small Bore Piping." The applicant stated that its Inservice Inspection (lSI) Program includes periodic volumetric examinations on ASME Class 1 small bore socket welds. The applicant further stated that the inspection volume is in accordance with guidelines established in MRP-146 which recommends examination of the base metal one-half inch beyond the toe of the weld. The applicant also cited recent plant-specific operating experience in which leakage was detected in a Class 1 socket weld, and referenced the related Licensee Event Report (LER#201 0-004-00). The staff noted that the applicant did not provide information that supports its conclusion on the failure mechanism.

The staff noted that for IP2, the facility operating license (DPR-26) expires at midnight September 28,2013, and for IP3, the facility operating license (DPR-64) expires at midnight December 12, 2015. The staff further noted that both IP2 and IP3 will be in their 4th lSI interval upon entering the period of extended operation.

Issue The staff noted that the inspections performed by its Inservice Inspection Program for ASME Class 1 small bore socket welds only include the base metal, one-half inch beyond the toe of the weld. It is not clear to the staff how an inspection of the base metal, one-half inch beyond the toe of the weld, is capable of detecting cracking in the ASME Class 1 small bore socket weld metal.

aging weld ASME 1 bore socket welds.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 15 of 27 Response for RAI 3.0.3.1.10-1 Part 1 IPEC will continue to perform visual examination (VT-2) as is required by ASME Code Case N-578, to manage the effects of aging on the ASME Class 1 small-bore socket welds for both units. In addition, IPEC will implement the One-Time Inspection - Small Bore Piping Program for IP3 and for butt welds on IP2.

For butt welds, IP2 will implement the One-Time Inspection - of ASME Code Class 1 Small Bore Piping Program, which manages cracking due to aging effects. The program will include volumetric examinations of small-bore piping butt weld metal on locations selected by the lSI Program using risk-informed methods to detect potential indications of cracking due to thermal fatigue and stress corrosion. For IP2, IPEC will perform volumetric examination of the weld metal of ten socket welds in 2012 and of at least ten socket welds during each 10-year period of the period of extended operation.

These inspections will be included in the IP21S1 Program.

IP3 has performed volumetric inspections on 25 small-bore piping welds, 21 of which were socket welds. Inspections on 18 of the welds inspected the root of the socket weld metal. The remaining three welds were inspected in accordance with MRp*146 (the base metal Y2 inch from the weld).

Sixteen (16) inspections had no recordable indications. Two socket welds had recordable indications and were cut out and destructively tested by EPRI. Metallographic evaluation determined that the recordable indications noted during the NDE inspections were root anomalies due to lack of fusion (LOF) during the welding process and were not part of the effective throat of the welds.

2. Clarify if the inspection volume selected for the proposed volumetric examinations of ASME Class 1 small bore butt welds, performed by the One Time Inspection - Small Bore Piping Program, includes the weld metal. If it does not include the weld metal, justify that the inspection volume is sufficient and capable of detecting cracking in the ASME Code Class 1 small bore butt weld metal.

Response for RAI 3.0.3.1.10-1 Part 2 The inspection volume selected for the proposed volumetric examination of ASME Class 1 small bore butt welds, performed under the One Time Inspection - Small Bore Piping Program, includes the weld metal. The inspection volume of the completed volumetric examinations of ASME Class 1 small bore butt welds, credited for the One Time Inspection - Small Bore Piping Program, included the weld metal.

3. Based on the operating experience at Indian Point, justify that an aging management program that performs periodic volumetric inspections of the weld metal for ASME Code Class 1 small bore socket and butt welds is necessary. lieu of this justification provide an aging management program that lsoect:lorlS to manage in small-bore piping and associated weld metal}.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 16 of 27 Response for RAI 3.0.3.1.10-1 Part 3 The operating experience at IPEC indicates no Class 1 small bore socket weld or butt weld failures due to stress corrosion, cyclical loading (thermal, mechanical, and vibration fatigue), or thermal stratification and thermal turbulence. A review of operating experience at IP3 identified no leaks from small bore Class 1 piping socket welds. In approximately 38 years of operation, IP2 has experienced five leaks from small bore Class 1 socket welds, but cracking has never been identified as the cause.

Rounded or pin hole defects caused three leaks, including the May 2010 leak, and mechanical damage caused a fourth. No cause was determined for the fifth leak which occurred in 1980, over 30 years ago.

Nevertheless, IPEC performs periodic volumetric inspections of ASME Code Class 1 small bore socket welds. Ongoing inspections under the IPEC Inservice Inspection Program include periodic volumetric inspections of small bore piping welds on both units as determined by risk-informed selection criteria in the program. IPEC will volumetrically inspect the weld metal of at least ten socket welds in 2012 and at least ten socket welds during each 10-year period of the period of extended operation.

4. Whether a one-time inspection program or periodic inspection program is selected, clarify the implementation schedule of the inspections for ASME Code Class 1 small-bore piping including the associated welds (socket welds and butt welds).

Response for RAI 3.0.3.1.10-1 Part 4 For IP2, the schedule for ASME Class 1 small-bore piping inspections is contained in the IP2 151 Program. In 2006, two butt welds were inspected. In 2010, three butt welds were inspected. Ten small-bore piping socket welds will be inspected in 2012 and one butt weld will be inspected prior to the period of extended operation. These future inspections will include the weld metal. In addition to the ten socket weld inspections in 2012, IPEC will perform volumetric weld metal inspections of ten socket welds during each 10-year period of the period of extended operation.

For IP3, One-Time Inspections have been completed. The associated inspections were completed from 2003 through 2007. In 2003, three welds were inspected; two socket welds and one butt weld. In 2005, 18 welds were inspected; 16 socket welds and two butt welds. In 2007, four welds were inspected; three socket welds and one butt weld. Thus, the total numbers of welds inspected was 21 socket welds and four butt welds. Eighteen of the socket weld inspections were volumetric inspections of the weld metal, two of which underwent subsequent destructive examinations. Because more information can be obtained from a destructive examination than from a nondestructive examination, each weld destructively examined is considered equivalent to two welds volumetrically examined. Counting the destructive examinations as two each, the number of volumetric socket weld inspections is 20 weldS, which represents 6% of the population of 333 Class 1 small-bore piping socket welds at IP3. The four butt weld inspections, which inspected the weld metal, constitute 4.1 % of the population of 96 butt welds.

RAI 3.0.3.1.10-2

Background

SRP-LR Section A.1.2.3.4 states that when sampling is used a basis should be provided for the inspection population and sample size.

The "monitoring and trending" program element of GALL AMP XI.M35 recommends that the volumetric inspection should be performed at a sufficient number of locations to assure an adequate sample.

Furthermore, this number, or sample size, will be based on susceptibility, inspectability, dose considerations,

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 17 of 27 operating experience, and limiting locations of the total population of ASME Code Class 1 small bore piping locations.

Issue The staff noted that the applicant did not provide its basis for the sample size that it selected. Specifically, the weld populations and the sample size were not provided to the staff, therefore it is not clear to the staff what percentage of ASME Code Class 1 welds, both full penetration welds and socket welds, will be inspected. It is also not clear to the staff if a sufficient number of locations will be selected to ensure an adequate sample.

Request Provide the total populations of ASME Code Class 1 small bore butt welds and socket welds at Indian Point for each unit. Justify that the number of samples, for both butt welds and socket welds, is sufficient to ensure that an adequate sample is selected for inspections to be performed.

Response for RAI 3.0.3.1.10-2 There are 433 small bore socket welds and 195 small bore butt welds at IP2. There are 333 small bore socket welds and 96 small bore butt welds at IP3.

Of the 195 small bore butt welds on IP2, 5 butt welds have been inspected. All five weld inspections included the weld metal. In addition one butt weld (including the weld metal) will be inspected in 2012, thereby yielding a total sample size of 3%. Of the 333 small bore socket welds on IP3, 21 welds have been inspected. Of those 21 weld inspections, 18 inspections included the weld metal, two of which underwent subsequent destructive examinations. Counting the destructive examinations as two each, the total volumetric socket weld inspections is 20 welds, which represents 6% of the population of 333 Class 1 small-bore piping socket welds at IP3. Of the 96 small bore butt welds, four welds, or 4.1% of butt welds, have been inspected. All four weld inspections included the weld metal. Since IPEC has had no failures of small bore piping welds due to cracking resulting from stress corrosion, cyclical loading (thermal, mechanical, and vibration fatigue), or thermal stratification and thermal turbulence, the numbers of inspections constitute an adequate sample of the small bore weld populations.

Of the 433 small bore socket welds on IP2, 10 welds will be inspected (including the weld metal) in 2012 and 10 welds will be inspected during each 10-year period of the period of extended operation.

Commitment #46 Include in the IP2 lSI Program volumetric weld metal inspections of ten socket welds in 2012 and of at least ten socket welds during each 10-year period of the period of extended operation.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 18 of 27 RAI3.0.3.2.10-1

Background

NRC staff has determined that masonry walls that are within the scope of license renewal should be visually examined at least every five years, with provisions for more frequent inspections in areas where significant loss of material or cracking is observed.

Issue The LRA did not discuss the inspection interval for in scope masonry walls.

Request Provide the inspection interval for in-scope masonry walls. If the interval exceeds five years, clearly explain why and how the interval will ensure that there is no loss of intended function between inspections.

Response for RAI3.0.3.2.10-1 The inspection interval for masonry walls within the scope of license renewal is every five years.

RAI3.0.3.2.15-1

Background

NRC staff has determined that adequate acceptance criteria for the Structures Monitoring Program should include quantitative limits for characterizing degradation. Chapter 5 of ACI 349.3R provides acceptable criteria for concrete structures. If the acceptance criteria in ACI 349.3R are not used, the plant-specific criteria should be described and a technical basis for deviation from ACI 349.3R should be provided.

Issue The LRA did not clearly identify quantitative acceptance criteria for the Structures Monitoring Program inspections.

Request

1. Provide the quantitative acceptance criteria for the Structures Monitoring Program. If the criteria deviate from those discussed in ACI 349.3R, provide technical justification for the differences.

Response for RAI3.0.3.2.15-1 Part 1 For concrete structures, the Structures Monitoring Program (SMP) has a responsible engineer with the appropriate education and experience to identify and evaluate existing conditions using the appropriate industry standards for concrete structures, including ACI standards. Prior to the period of extended operation (PEO), Entergy will enhance the SMP to include more detailed quantitative acceptance criteria of ACI349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures" for concrete structures.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 19 of 27 Commitment Entergy is revising the following commitment (Commitment 25) for the Structures Monitoring Program for implementation prior to the PEO.

Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria for inspections of concrete structures in accordance with ACI349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures".

2. If quantitative acceptance criteria will be added to the program as an enhancement, state whether Entergy plans to conduct an inspection with the quantitative acceptance criteria prior to the period of extended operation. If there are no plans to conduct an inspection with quantitative acceptance criteria prior to entering the period of extended operation, explain how Entergy plans to monitor and trend data.

Response for RAI 3.0.3.2.15-1 Part 2 Program procedures specify that the inspection engineer be a degreed engineer or registered professional engineer, knowledgeable or trained in the design, evaluation, and performance requirements of structures, with at least 5 years structural design/analysis/field evaluation experience.

Using applicable industry codes and standards, the responsible engineer has adequate training and education to determine the acceptability of identified conditions using appropriate references, which may include ACI 349.3R.

While all the detailed quantitative acceptance criteria of ACI 349.3R are not in the existing SMP procedures, the knowledge and experience of the qualified inspection engineers performing regularly scheduled inspections provides reasonable assurance of continued functionality of the concrete structures at IPEC. The enhanced inspection criteria from ACI349.9-3R will be adopted prior to the PEO and will be applied during regularly scheduled inspections.

The enhancement described in part 1 (above) to include more detailed acceptance criteria of ACI 349.3R does not affect ongoing monitoring and trending of data collected during the inspections.

Although the acceptance criteria of ACI 349.3R are not explicitly identified in inspection procedures, qualified inspection personnel have a working knowledge of those criteria. Based on their knowledge and experience, inspectors identify and record degradation outside the acceptance criteria of ACI 349.3R discovered during the inspections so that future monitoring can determine a trend. The documentation includes critical measurements, i.e., crack width, length, depth, or area and depth of spall, so that future inspectors can determine the degree of change, if any. Prior to performing inspections, inspection engineers perform a thorough review of previous inspection reports to identify existing deficiencies. Photos, checklists, notes, etc, are used to determine if further deterioration has occurred. This process for monitoring and trending inspection data will continue during the period of extended operations,

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 20 of 27 RAI 3.1.2.2.13-1

Background

SRP-LR Section 3.1.2.2.13 identifies that cracking due to primary water stress corrosion cracking (PWSCC) could occur in PWR components made of nickel alloy and steel with nickel alloy cladding, including reactor coolant pressure boundary components and penetrations inside the RCS such as pressurizer heater sheathes and sleeves, nozzles, and other internal components. GALL Report Volume 2 Item IV.D1-06 recommends Chapter XI.M2, 'Water Chemistry," for PWR primary water to manage the aging effect of cracking in the nickel alloy steam generator (SG) divider plate exposed to reactor coolant.

LRA Table 3.1.1, item 3.1.1-81, credits the Water Chemistry Control- Primary and Secondary Program to manage cracking due to primary stress corrosion cracking in nickel-alloy steam generator primary channel head divider plate exposed to reactor coolant in the steam generators, and LRA Table 3.1.1, Item 82, indicates that the SG primary side divider plates are composed of nickel alloy.

Unit 2 FSAR Section 4.2.2.3 and Table 4.2-1 describe the construction materials for the replacement Model 44F steam generators. The staff noted that there is no information about the construction materials of the divider plate assembly for the Unit 2 steam generators.

Unit 3 FSAR Section 4.2.2 and Table 4.2-1 describe the construction materials for the replacement Model44F steam generators. The staff noted that there is no information about the construction materials of the divider plate assembly for the Unit 3 steam generators.

Issue In some foreign steam generators with a similar design to that of Indian Point Units 2 and 3 steam generators, extensive cracking due to PWSCC has been identified in SG divider plate assemblies made with Alloy 600, even with proper primary water chemistry. Specifically, cracks have been detected in the stub runner, very close to the tubesheetlstub runner weld and with depths of almost a third of the divider plate thickness.

Therefore, the staff noted that the Water Chemistry Control- Primary and Secondary Program may not be effective in managing the aging effect of cracking due to PWSCC in SG divider plate assemblies.

Although these SG divider plate assembly cracks may not have a significant safety impact in and of themselves, such cracks could affect adjacent items that are part of the reactor coolant pressure boundary, such as the tubesheet and the channel head, if they propagate to the boundary with these items. For the tubesheet, PWSCC cracks in the divider plate could propagate to the tubesheet cladding with possible consequences to the integrity of the tube-to-tubesheet welds. For the channel head, the PWSCC cracks in the plate could SG point and potentially affect the pressure boundary of the SG channel head.

1. Discuss the materials of construction of the Units 2 and 3 SG divider plate assemblies, including the welds within these assemblies and to the channel head and to the tubesheet.

Response for RAI3.1.2.2.13-1 Part 1 At IP2 and IP3 the divider plates are Inconel600 (ASME-SB-168). It is conservatively assumed that the weld materials are the associated Alloy 600 weld materials.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 21 of 27

2. If any constitutive/weld material of the SG divider plate assemblies is susceptible to cracking (e.g., Alloy 600 or the associated Alloy 600 weld materials), explain how Entergy plans to manage PWSCC of the SG divider plate assemblies to prevent the propagation of cracks into other items that are part of the RCPB, whereby it challenges the integrity of the adjacent items.

Response for RAI 3.1.2.2.13-1 Part 2 At IP2 the original Westinghouse Model 44 steam generators were replaced with Model 44F steam generators in 2000. At IP3 the original Westinghouse Model 44 steam generators were replaced with Model 44F steam generators in 1989.

The Electric Power Research Institute (EPRI) has extensively evaluated the foreign operating experience with divider plate cracking in their reports dated June 2007, November 2008, and December 2009, and concluded that a cracked divider plate in a Westinghouse Model F SG is not a safety concern, and does not affect the design of the adjacent pressure boundary components.

The industry plans are to study the potential for divider plate crack growth and develop a resolution to the concern through the EPRI Steam Generator Management Program (SGMP) Engineering and Regulatory Technical Advisory Group. This industry-lead effort is expected to begin in 2011 and be completed within two years.

Recognizing that the EPRI SGMP resolution of this issue is under development, Entergy will inspect alilPEC steam generators to assess the condition of the divider plate assembly. The examination technique used will be capable of detecting PWSCC in the steam generator divider plate assembly welds. The steam generator divider plate inspections will be completed within the first ten years of the PEO. (Commitment 41)

RAI 3.1.2.2.16-1

Background

SRP-LR Section 3.1.2.2.16 identifies that cracking due to primary water stress corrosion cracking (PWSCC) could occur on the primary coolant side of PWR steel steam generator (SG) tube-to-tube sheet welds made or clad with nickel alloy. The GALL Report recommends ASME Section XI lSI and control of water chemistry to manage this aging effect and recommends no further aging management review for PWSCC of nickel alloy if the applicant complies with applicable NRC Orders and provides a commitment in the FSAR supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. In GALL Revision ,Volume this aging effect is addressed in item IV.D2-4, applicable only to once-through to ASME XI the welds.

there are no NRC Orders or bulletins requiring examination of this weld. However, the staff's concern is that, if the tubesheet cladding is Alloy 600 or the associated Alloy 600 weld materials, the tube-to-tubesheet weld region may have insufficient Chromium content to prevent initiation of PWSCC. Similarly, this concern applies to SG tubes made from Alloy 690TT. Consequently, such a PWSCC crack initiated in this region, close to a tube, could propagate into/through the weld, causing a failure of the weld and of the reactor coolant pressure boundary, for both recirculating and once-through steam generators.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 22 of 27 In LRA Table 3.1.1, item 3.1.1-35, the applicant stated that the corresponding GALL Report line applies to once-through steam generators and was used as a comparison for the steam generator tubesheets. The applicant further stated that for the steel with nickel alloy clad steam generator tubesheets, cracking is managed by the Water Chemistry Control- Primary and Secondary and Steam Generator Integrity Programs.

In LRA Section 2.3.1.4, the applicant described that the Unit 2 replacement Westinghouse Model 44 steam generator tubes are fabricated from Alloy 600TT and the Unit 3 replacement Westinghouse Model 44 steam generator tubes are fabricated from Alloy 690TT. The applicant also described that the tubesheet surfaces in contact with reactor coolant are clad with Inconel, and the tube-to-tube sheet joints are welded.

Issue Unless the NRC has approved a redefinition of the pressure boundary in which the autogenous tube-to-tubesheet weld is no longer included, or the tubesheet cladding and welds are not susceptible to PWSCC, the staff considers that the effectiveness of the primary water chemistry program should be verified to ensure PWSCC cracking is not occurring. Moreover, it is not clear to the staff how the Steam Generator Integrity Program is able to manage PWSCC of the tubesheet cladding, including the tube-to-tubesheet welds.

Request 1a. For Unit 2 SGs, clarify whether the tube-to-tubesheet welds are included in the reactor coolant pressure boundary or alternate repair criteria have been permanently approved.

Response for RAI3.1.2.2.16-1 Part 1a At IP2 the tube to tubesheet welds are included in the RCS pressure boundary. IP2 does not employ any tubesheet region alternate repair criterion.

1b. If the SGs do not have permanently approved alternate repair criteria, justify how your Steam Generator Integrity Program is capable to manage PWSCC in tube-to-tubesheet welds, or provide a plant-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurring in tube-to-tubesheet welds.

Response for RAI 3.1.2.2.16-1 Part 1b IP2 will address the potential failure of the steam generator reactor coolant pressure boundary due to PWSCC cracking of tube-to-tubesheet welds via one of two options, an analysis or an inspection.

(Commitment 42)

Analysis Option:

IP2 will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible to PWSCC, or redefining the pressure boundary to exclude the tube-to-tubesheet weld, and therefore the weld will not be required for the reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary will be submitted as part of a license amendment request requiring approval from the NRC. An approved analytical evaluation would obviate the need to develop a plant-specific AMP to verify effectiveness of the Water Chemistry Control - Primary and Secondary program.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 23 of 27 Inspection Option:

Perform a one time inspection of a representative number of tube-to-tubesheet welds in each steam generator to determine if PWSCC cracking is present. If weld cracking is identified:

a. The condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and

b. An ongoing monitoring program will be established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

IP2 replaced its steam generators in 2000. The tube-to-tubesheet welds have been in service approximately eleven years. Considering this limited service time, if Option 1 is not implemented, IP2 will implement Option 2 that includes tube-to-tubesheet weld inspections for PWSCC. These inspections will be performed between March 2020 and March 2024 such that the steam generators will have been in service between 20 and 24 years.

In 2R17 (2006), 166 tubes were inspected to the tube end with a rotating pancake coil (RPC) probe. No degradation was detected.

2. For Unit 3 SGs tube-to-tubesheet welds, justify how your Steam Generator Integrity Program is capable to manage PWSCC in tube-to-tubesheet welds, or provide either a plant-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurring in tube-to-tubesheet welds, or a rationale for why such a program is not needed.

Response for RAI 3.1.2.2.16-1 Part 2 IP3 will address the potential failure of the steam generator reactor coolant pressure boundary due to PWSCC cracking of tube-to-tubesheet welds via one of two options, an analysis or an inspection.

(Commitment 42)

Analysis Option:

IP3 will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible to PWSCC, or redefining the pressure boundary to exclude the tube-to-tubesheet weld, and therefore the weld will not be required for the reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary will be submitted as part of a license amendment request requiring approval from the NRC. An approved analytical evaluation would obviate the need to develop a plant-specific AMP to verify effectiveness of the Water Chemistry Control - Primary and Secondary program.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 24 of 27 Inspection Option:

Perform a one time inspection of a representative number of tube-to-tubesheet welds in each steam generator to determine if PWSCC cracking is present. This one-time inspection would verify the effectiveness of the water chemistry AMP. If weld cracking is identified:

a. The condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and

b. An ongoing monitoring program will be established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

IP3 replaced its steam generators in 1989. The tube-to-tubesheet welds have been in service approximately twenty two years. If Option 1 is not implemented, IP3 will implement Option 2 that includes tube-to-tubesheet weld inspections for PWSCC. For IP3 these inspections will be performed within the first 2 refueling outages following the period of extended operation.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 25 of 27 RAI RCS*3

Background

In LRA Section 4.3.3 and Commitment 33 (as amended by the letter dated January 22, 2008) the applicant discussed the methodology used to determine the locations that required environmentally-assisted fatigue analyses consistent with NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components." The staff recognized that, in LRA Tables 4.3-13 and 4.3-14, there are eight plant-specific locations listed based on the six generic components identified in NUREG/CR-6260.

The applicant also discussed in LRA Tables 4.3-13 and 4.3-14 that the surge line nozzle in the RCS piping is bounded by the surge line piping to safe end weld at the pressurizer nozzle. LRA Section 4.3.3 and Commitment 33 were amended as follow:

At least 2 years prior to entering the period of extended operation, for the locations identified in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring Program, IP2 and IP3, IPEC will implement one or more of the following:

(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 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.

For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (lP3) with existing fatigue analysis valid for the period of extended operation, use the existing CUF.

More plant-specific limiting 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.

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

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.

Issue GALL AMP X.M1 states the impact of the reactor coolant environment on a sample of critical components should include the locations identified in NUREG/CR-6260, as a minimum, and that additional locations may be needed. The staff identified two concerns regarding the applicant's environmentally-assisted fatigue analyses.

First, (1) of above lRA and Commitment 33 indicated that more limiting plant-specific locations be evaluated. However, it is only one of the options that may be taken. Furthermore, the limiting locations is whether the applicant is committed to verify that the plant-specific per are bounding for the generic NUREG/CR-6260 components. Second, the staff noted that the applicant's plant-specific configuration may contain locations that should be analyzed for the effects of reactor coolant environment, that are more limiting than those identified in NUREG/CR-6260. This may include locations that are limiting or bounding for a particular plant-specific configuration or that have calculated CUF values that are greater when compared to the locations identified in NUREG/CR-6260.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 26 of 27 Request

1. Confirm and justify that the plant-specific locations listed in LRA Tables 4.3-13 and 4.3-14 are bounding for the generic NUREG/CR-6260 components.

Response for RAI RCS-3 Part 1 A review of the locations provided in LRA Tables 4.3-13 and 4.3-14 confirmed that they are equivalent to the locations provided in NUREG/CR-6260.

2. Confirm and justify that the locations selected for environmentally-assisted fatigue analyses in LRA Tables 4.3-13 and 4.3-14 consist of the most limiting locations for the plant (beyond the generic components identified in the NUREG/CR-6260 guidance). If these locations are not bounding, clarify which locations require an environmentally-assisted fatigue analysis and the actions that will be taken for these additional locations. If the limiting locations identified consist of nickel alloy, state whether the methodology used to perform environmentally-assisted fatigue calculation for nickel alloy is consistent with NUREG/CR-6909. If not, justify the method chosen.

Response for RAI RCS-3 Part 2 Entergy will review design basis ASME Code Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations for the Indian Point plant 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 alloy, if any. This evaluation will be completed prior to entering the period of extended operation.

Commitment Entergy is providing the following new commitment (Commitment 43) for the Metal Fatigue NUREG/CR-6260; Entergy will review design basis ASME Code Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations for the Indian Point 2 and 3 plant 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 alloy, if any. This evaluation will be completed prior to the period of extended operation.

Docket Nos. 50-247 and 50-286 NL-11-032 Attachment 1 Page 27 of 27 NRC WESTEMS Questions Question #1 For any use of the WESTEMS "Design CUF" module in the future at IPEC, include written explanation and justification of any user intervention in the process.

Response for Question #1 IPEC will include written explanation and justification of user intervention in any future use of the WESTEMS "Design CUF" module. (Commitment 44)

Question #2 Provide a commitment that the NB-3600 option of the WESTEMS "Design CUF" module will not be implemented or used in the future at IPEC.

Response for Question #2 IPEC will not use the ASME Section III, NB-3600 option of the WESTEMS "Design CUF" module until the issues identified during the NRC review of the program has been resolved. (Commitment 45)

ATTACHMENT 2 TO NL-11-032 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMITMENTS Rev. 13 NUCLEAR INDIAN NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

NL-11-032 Attachment 2 Page 1 of 18 List of Regulatory Commitments Rev. 13 The following table identifies those actions committed to by Entergy in this document.

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

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.1 1 Enhance the Aboveground Steel Tanks Program for September 28, A.3.1.1 IP2 and IP3 to perform thickness measurements of the bottom surfaces of the condensate storage tanks, ~013 B.1.1 city water tank, and fire water tanks once during the IP3:

first ten years of the period of extended operation.

December 12, Enhance the Aboveground Steel Tanks Program for 2015 IP2 and IP3 to require trending of thickness measurements when material loss is detected.

IP2: NL-07-039 A.2.1.2 2 Enhance the Bolting Integrity Program for IP2 and IP3 September 28, A.3.1.2 to clarify that actual yield strength is used in selecting materials for low susceptibility to SCC and clarify the ~013 B.1.2 prohibition on use of lubricants containing MoS 2 for IP3: NL-07-153 Audit Items bolting.

December 12, 201,241, The Bolting Integrity Program manages loss of 2015 270 preload and loss of material for all external bolting.

NL-11-032 Attachment 2 Page 2 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.5 3 Implement the Buried Piping and Tanks Inspection September 28, A.3.1.5 Program for IP2 and IP3 as described in LRA Section 2013 B.1.6 B.1.6.

NL-07-153 Audit Item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.M34, Buried Piping and Tanks 2015 Inspection.

NL-09-106 Include in the Buried Piping and Tanks Inspection Program described in LRA Section B.1.6 a risk NL-09-111 assessment of in-scope buried piping and tanks that 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-11-032 Attachment 2 Page 3 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.8 4 Enhance the Diesel Fuel Monitoring Program to September 28, A.3.1.8 include cleaning and inspection of the IP2 GT-1 gas 013 S.1.9 turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil NL-07-153 Audit items day tanks, IP2 SSO/Appendix R diesel generator fuel 128,129, oil day tank, and I P3 Appendix R fuel oil storage tank 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 SSO/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/1. 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 following tanks once every ten years. IP2: EDG fuel oil storage tanks, EDG fuel oil day tanks, SSO/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 oil tanks within scope of the program.

Program to 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 presence of biological activity is confirmed.

NL-11-032 Attachment 2 Page 4 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.10 5 Enhance the External Surfaces Monitoring Program September 28, A.3.1.10 for IP2 and IP3 to include periodic inspections of 013 B.1.11 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 December 12, surrounding the subject systems to identify hazards to 015 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.

IP2: NL-07-039 A.2.1.11 6 Enhance the Fatigue Monitoring Program for IP2 to September 28, A.3.1.11 monitor steady state cycles and feedwater cycles or 013 B.1.12, perform an evaluation to determine monitoring is not NL-07-153 Audit Item required. Review the number of allowed events and 164 resolve discrepancies between reference documents and monitoring procedures.

Enhance the Fatigue Monitoring Program for IP3 to IP3:

include all the transients identified. Assure all fatigue December 12, analysis transients are included with the lowest 015 limiting numbers. Update the number of design transients accumulated to date.

IP2: NL-07-039 A.2.1.12 7 Enhance the Fire Protection Program to inspect September 28, A.3.1.12 external surfaces of the IP3 RCP oil collection 013 B.1.13 systems for loss of material each refueling cycle.

Enhance the Fire Protection Program to explicitly state that the IP2 and IP3 diesel fire pump engine December 12, sUb-systems (including the fuel supply line) shall be 015 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 P2 IP3 diesel carbon steel cycle.

Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480V switchgear room, and EDG room CO 2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

NL-11-032 Attachment 2 Page 5 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.13 8 Enhance the Fire Water Program to include inspection September 28, A.3.1.13 of IP2 and IP3 hose reels for evidence of corrosion.

~013 B.1.14 Acceptance criteria will be revised to verify no NL-07-153 Audit Items unacceptable signs of degradation.

IP3: 105, 106 Enhance the Fire Water Program to replace all or test December 12, NL-08-014 a sample of IP2 and IP3 sprinkler heads required for ~015 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 significant corrosion.

NL-11-032 Attachment 2 Page 6 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.15 9 Enhance the Flux Thimble Tube Inspection Program September 28, A.3.1.15 for IP2 and IP3 to implement comparisons to wear 2013 B.1.16 rates identified in WCAP-12866. Include provisions to compare data to the previous performances and IP3:

perform evaluations regarding change to test December 12, frequency and scope.

2015 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-11-032 Attachment 2 Page 7 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.16 10 Enhance the Heat Exchanger Monitoring Program for September 28, A.3.1.16 I P2 and I P3 to include the following heat exchangers 013 8.1.17, in the scope of the program.

NL-07-153 Audit Item

• Safety injection pump lube oil heat exchangers 52 December 12,

• RHR heat exchangers 015

• 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

• S80/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 Establish for heat NL-09-056 1i Delete commitment.

NL-11-032 Attachment 2 Page 8 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.18 12 Enhance the Masonry Wall Program for IP2 and IP3 September 28, A.3.1.18 to specify that the IP1 intake structure is included in 013 B.1.19 the program.

Enhance the Metal-Enclosed Bus Inspection Program NL-07-039 A.2.1.19 13 to add IP2 480V bus associated with substation A to A.3.1.19 the scope of bus inspected. B.1.20 NL-07-153 Audit Items Enhance the Metal-Enclosed Bus Inspection Program 124, for IP2 and IP3 to visually inspect the external surface December 12, NL-08-057 133,519 of MEB enclosure assemblies for loss of material at 015 least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will be no significant loss of material.

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" IP2: NL-07-039 A.2.1 14 Implement the Non-EQ Bolted Cable Connections September 28, A.3.1.21 Program for IP2 and IP3 as described in LRA Section 013 B.1.22 B.1.22.

NL-11-032 Attachment 2 Page 9 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A2.1.22 15 Implement the Non-EQ Inaccessible Medium-Voltage September 28, A3.1.22 Cable Program for IP2 and IP3 as described in LRA 2013 B.1.23 Section B.1.23.

NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.E3, Inaccessible Medium-Voltage 2015 Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements.

IP2: NL-07-039 A.2.1.23 16 Implement the Non-EQ Instrumentation Circuits Test September 28, A.3.1.23 Review Program for IP2 and IP3 as described in LRA

~013 B.1.24 Section B.1.24.

NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.E2, Electrical Cables and 2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

IP2: NL-07-039 A.2.1.24 17 Implement the Non-EQ Insulated Cables and September 28, A.3.1.24 Connections Program for IP2 and IP3 as described in 2013 B.1.25 LRA Section B.1.25.

NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.E1, Electrical Cables and 2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

IP2: NL-07-039 A.2.1.25 18 Enhance the Oil Analysis Program for IP2 to sample September 28, A.3.1.25 and analyze lubricating oil used in the SBO/Appendix

~013 B.1.26 R diesel generator consistent with oil analysis for other site diesel generators.

IP3:

Enhance the Oil Analysis Program for IP2 and IP3 to December 12, sample and analyze generator seal oil and turbine 2015 hydraulic control oil.

the Analysis Program for IP2 and IP3 to formalize preliminary oil screening for water and particulates 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.

NL-11-032 Attachment 2 Page 10 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.26 19 Implement the One-Time Inspection Program for IP2 September 28, A.3.1.26 and IP3 as described in LRA Section B.1.27.

12013 B.1.27 This new program will be implemented consistent with NL-07-153 Audit item the corresponding program described in NUREG- IP3: 173 1801,Section XI.M32, One-Time Inspection. December 12, 12015 IP2: NL-07-039 A.2.1.27 20 Implement the One-Time Inspection - Small Bore September 28, A.3.1.27 Piping Program for IP2 and IP3 as described in LRA 12013 B.1.28 Section B.1.28.

NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801,Section XI.M35, One-Time Inspection of ASME 12015 Code Class I Small-Bore Piping.

IP2: NL-07-039 A.2.1.28 21 Enhance the Periodic Surveillance and Preventive September 28, A.3.1.28 Maintenance Program for IP2 and IP3 as necessary 12013 B.1.29 to assure that the effects of aging will be managed such that applicable components will continue to IP3:

perform their intended functions consistent with the December 12, current licensing basis through the period of extended operation. 12015 IP2: NL-07-039 A.2.1.31 22 Enhance the Reactor Vessel Surveillance Program for September 28, A.3.1.31 IP2 and IP3 revising the specimen capsule withdrawal 12013 B.1.32 schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected IP3:

through the end of the period of extended operation.

December 12, Enhance the Reactor Vessel Surveillance Program for 12015 IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage.

IP2: NL-07-039 A.2.1.32 23 Implement the Selective Leaching Program for IP2 September 28, A.3.1.32 and IP3 as described in LRA Section B.1.33.

12013 B.1.33 This new program will implemented consistent with NL-07-153 Audit item corresponding program in NUREG- IP3: 173 1801, Section XLM33 Selective Leaching of Materials. December 1

~015 IP2: NL-07-039 A.2.1.34 24 Enhance the Steam Generator Integrity Program for September 28, A.3.1.34 IP2 and IP3 to require that the results of the condition 12013 B.1.35 monitoring assessment are compared to the operational assessment performed for the prior IP3:

operating cycle with differences evaluated.

December 12, 2015

NL-11-032 Attachment 2 Page 11 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM Enhance the Structures Monitoring Program to IP2: NL-07-039 A.2.1.35 25 explicitly specify that the following structures are September 28, A.3.1.35 included in the program. 12013 8.1.36

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

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

• Appendix R diesel generator switchgear and 12015 NL-08-057 417 enclosure (IP3)

• city water storage tank foundation

• condensate storage tanks foundation (IP3)

• containment access facility and annex (IP3)

• discharge canal (IP2/3)

• emergency lighting poles and foundations (IP2/3)

• fire pump house (IP2)

• fire protection pumphouse (IP3)

• fire water storage tank foundations (I P2/3)

• gas turbine 1 fuel storage tank foundation

• maintenance and outage building-elevated passageway (IP2)

• new station security building (IP2)

• nuclear service building (I P1)

• primary water storage tank foundation (IP3)

• refueling water storage tank foundation (IP3)

• security access and office building (IP3)

• service water pipe chase (IP2/3)

• service water valve pit (IP3)

• superheater stack

• transformerlswitchyard support structures (I P2)

• 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.

• supports

• IJUIIIJIt:at::: reactor "esse I 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

NL-11-032 Attachment 2 Page 12 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM

• new fuel storage racks

• sumps, sump screens, strainers and flow barriers 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 Monitoring Program for IP2 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). IPEG 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, IPEG 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 andlP3 perform inspection of normally submerged concrete portions of the intake structures at least once 5 Inspect 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 PE~.

NL-11-032 Attachment 2 Page 13 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM Enhance the Structures Monitoring Program to include more detailed guantitative accegtance criteria NL-11-032 for insgections of concrete structures in accordance with ACI 349.3R, "Evaluation of Existing Nuclear Safet:t-Related Concrete Structures" grior to the period of extended operation.

IP2: NL-07-039 A.2.1.36 26 Implement the Thermal Aging Embrittlement of Cast September 28, A.3.1.36 Austenitic Stainless Steel (CASS) Program for IP2 2013 B.1.37 and I P3 as described in LRA Section B.1 .37.

NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801,Section XI.M12, Thermal Aging Embrittlement 2015 of Cast Austenitic Stainless Steel (CASS) Program.

IP2: NL-07-039 A.2.1.37 27 Implement the Thermal Aging and Neutron Irradiation September 28, A.3.1.37 Embrittlement of Cast Austenitic Stainless Steel B.1.38 (CASS) Program for IP2 and IP3 as described in LRA l2013 NL-07-153 Audit item Section B.1.38.

IP3: 173 This new program will be implemented consistent with December 12, the corresponding program described in NUREG- l2015 1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

IP2: NL-07-039 A.2.1.39 28 Enhance the Water Chemistry Control- Closed September 28, A.3.1.39 Cooling Water Program to maintain water chemistry of l2013 B.1.40 the IP2 SBO/Appendix R diesel generator cooling NL-08-057 Audit item system per EPRI guidelines.

IP3: 509 Enhance the Water Chemistry Control - Closed December 12, Cooling Water Program to maintain the IP2 and IP3 l2015 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines.

IP2: NL-07-039 A.2.1.40 29 Enhance the Water Chemistry Control - Primary and September 28, B.1.41 Secondary Program for IP2 to test sulfates monthly in 2013 the RWST with a limit of <150 ppb.

IP2: NL-07-039 A.2.1.41 reactor vvs"dl internals, September 28, A.3.1.41 in industry programs for 2011 investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of IP3:

the industry programs as applicable to the reactor December 12, internals; and (3) upon completion of these programs, 2013 but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.

NL-11-032 Attachment 2 Page 14 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-07-039 A.2.2.1.2 31 Additional P-T curves will be submitted as required September 28, A.3.2.1.2 per 10 CFR 50, Appendix G prior to the period of 2013 4.2.3 extended operation as part of the Reactor Vessel Surveillance Program.

IP3:

December 12, 2015 As required by 10 CFR 50.61 (b)(4), IP3 will submit a IP3: NL-07-039 A.3.2.1.4 32 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.

IP2: NL-07-039 A.2.2.2.3 33 At least 2 years prior to entering the period of September 28, A.3.2.2.3 extended operation, for the locations identified in LRA 2011 4.3.3 Table 4.3-13 (IP2) and LRA Table 4.3-14 (lP3), under NL-07-153 Audit item the Fatigue Monitoring Program, IP2 and IP3 will IP3: 146 implement one or more of the following:

December 12, NL-08-021 (1) Consistent with the Fatigue Monitoring Program, 2013 Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting Complete 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. Rt::l-ln:::::ientcttivt:: CUF values from other plants, adjusted to or enveloping the plant specific external loads may be used if demonstrated applicable

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.

NL-11-032 Attachment 2 Page 15 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM April 30, 2008 NL-07-078 2.1.1.3.5 34 IP2 SSO / Appendix R diesel generator will be installed and operational by April 30, 2008. This Complete NL-08-074 committed change to the facility meets the requirements of 10 CFR 50.591(1) and, therefore, a license amendment pursuant to 10 CFR 50.90 is not required.

IP2: NL-08-127 Audit Item 35 Perform a one-time inspection of representative September 28, 27 sample area of I P2 containment liner affected by the 2013 1973 event behind the insulation, prior to entering the extended period of operation, to assure liner degradation is not occurring in this area.

Perform a one-time inspection of representative IP3:

sample area of the IP3 containment steel liner at the December 12, juncture with the concrete floor slab, prior to entering 2015 the extended period of 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.

IP2: NL-08-127 Audit Item 36 Perform a one-time Inspection and evaluation of a September 28, 359 sample of potentially affected IP2 refueling cavity 2013 concrete prior to the period of extended operation.

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 ieakaQe fluid will be analyzed.

IP2: NL-08-127 Audit Item II'~

'~r-'

,~ ....+;~ I

~

1-September 28, 361 II '1<:'1 the 2013 containment using enhanced characterization of degradation (Le., quantifying the dimensions of noted IP3:

indications through the use of optical aids) during the December 12, period of extended operation. The enhancement 2015 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 paints for visual inspections.

NL-11-032 Attachment 2 Page 16 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM IP2: NL-08-143 4.2.1 38 For Reactor Vessel Fluence, should future core September 28, loading patterns invalidate the basis for the projected 12013 values of RTpts or CvUSE, updated calculations will be provided to the NRC.

IP3:

December 12, 2015 NL-09-079 39 Deleted IP2: NL-09-106 B.1.6 40 Evaluate plant specific and appropriate industry September 28, B.1.22 operating experience and incorporate lessons learned 2013 B.1.23 in establishing appropriate monitoring and inspection B.1.24 frequencies to assess aging effects for the new aging IP3: B.1.25 management programs. Documentation of the December 12, B.1.27 operating experience evaluated for each new program 12015 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-11-032 N/A 41 IPEC will insQect steam generators for both units to Prior to assess the condition of the divider Qlate assembl~.

September 28, The examination technigue used will be caQable of 2023 detecting PWSCC in the steam generator divider Qlate assembl~ welds. The steam generator divider Qlate I P3: Prior to insQections will be comQleted within the first ten ~ears December 12, of the Qeriod of extended oQeration (PEO).

~025

NL-11-032 Attachment 2 Page 17 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM NL-11-032 N/A 42 iPEC will deveioQ a Qlan for each unit to address the IP2: Prior to Qotential for cracking of the Qrima!y to seconda!y March 2024 Qressure bounda!y due to PWSCC of tube-to-tubesheet welds using one of the following two IP3: Within the oQtions.

irst 2 refuelina OQtion 1 (Analysis) outaaes ollowina the IPEC will Qerform an analvtical evaluation of the beainnina of the steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that ~

the tubesheet cladding and welds are not susceQtible to PWSCC, or redefining the Qressure bounda!y in which the tube-to-tubesheet weld is no longer included and, therefore, is not reguired for reactor coolant Qressure bounda!y function. The redefinition of the reactor coolant Qressure bounda!y will be submitted as Qart of a license amendment reguest reguiring aQQroval from the NRC.

OQtion 2 (I nSQection)

IPEC will Qerform a one-time insQection of a reQresentative number of tube-to-tubesheet welds in each steam generator to determine if PWSCC cracking is Qresent. If weld cracking is identified:

a. The condition will be resolved through reQair or engineering evaluation to justify continued service, as aQQroQriate, and

b. An ongoing monitoring Qrogram will be established to Qerform routine tube-to-tubesheet weld insQections for the remaining life of the steam aenerators.

43 IPEC will review design basis ASME Code Class 1  !.E£;. NL-11-032 4.3.3 Prior to fatigue evaluations to determine whether the September 28 NUREG/CR-6260 locations that have been evaluated for the effects of the reactor coo/ant environment on ~

fatigue usage are the limiting locations for the IP2 and IP3: Prior to IP3 configurations. If more limiting locations are IDecember 12 identified, the most limiting location will be evaluated

@1Q 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-11-032 Attachment 2 Page 18 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM 44 IPEC will include written eXl2lanation and justification Within 60 davs NL-11-032 N/A Iof issuance of of any user intervention in future evaluations using the he renewed WESTEMS "Design CUF" module.

boeratina license.

45 IPEC will not use the NS-3600 ol2tion of the

!Within 60 davs NL-11-032 N/A bf issuance of WESTEMS I2rogram in future design calculations until he renewed the issues identified during the NRC review of the boeratina I2rogram have been resolved.

license.

46 Include in the IP2 lSI Program volumetric weld metal ~

NL-11-032 N/A Prior to insl2ections of ten socket welds in 2012 and of at least September 28 ten socket welds during each 10-year l2eriod of the

~eriod of extended operation. ~

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of ) Docket Nos. 50-247-LR and

) 50-286-LR ENTERGY NUCLEAR OPERATIONS, INC. )

)

(Indian Point Nuclear Generating Units 2 and 3) )

) September 28, 2011 CERTIFICATE OF SERVICE I certify that, on September 28, 2011, a copy of Applicants Opposition to the State of New Yorks Motion for an Extension of Time was served electronically with the Electronic Information Exchange on the following recipients:

Administrative Judge Administrative Judge Lawrence G. McDade, Chair Dr. Kaye D. Lathrop Atomic Safety and Licensing Board Panel Atomic Safety and Licensing Board Panel Mail Stop: T-3 F23 190 Cedar Lane E.

U.S. Nuclear Regulatory Commission Ridgway, CO 81432 Washington, DC 20555-0001 (E-mail: Kaye.Lathrop@nrc.gov)

(E-mail: Lawrence.McDade@nrc.gov)

Administrative Judge Office of the Secretary Dr. Richard E. Wardwell Attn: Rulemaking and Adjudications Staff Atomic Safety and Licensing Board Panel U.S. Nuclear Regulatory Commission Mail Stop: T-3 F23 Washington, D.C. 20555-0001 U.S. Nuclear Regulatory Commission (E-mail: hearingdocket@nrc.gov)

Washington, DC 20555-0001 (E-mail: Richard.Wardwell@nrc.gov)

Office of Commission Appellate Adjudication Josh Kirstein, Law Clerk U.S. Nuclear Regulatory Commission Atomic Safety and Licensing Board Panel Mail Stop: O-7H4M Mail Stop: T-3 F23 Washington, DC 20555-0001 U.S. Nuclear Regulatory Commission (E-mail: ocaamail.resource@nrc.gov) Washington, DC 20555-0001 (E-mail: Josh.Kirstein@nrc.gov)

DB1/ 68215717.4

Sherwin E. Turk, Esq. Melissa-Jean Rotini, Esq.

Beth N. Mizuno, Esq. Assistant County Attorney David E. Roth, Esq. Office of Robert F. Meehan, Esq.

Brian G. Harris, Esq. Westchester County Attorney Andrea Z. Jones, Esq. 148 Martine Avenue, 6th Floor Office of the General Counsel White Plains, NY 10601 Mail Stop: O-15D21 (E-mail: MJR1@westchestergov.com)

U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 (E-mail: Sherwin.Turk@nrc.gov)

(E-mail: Beth.Mizuno@nrc.gov)

(E-mail: david.roth@nrc.gov)

(E-mail: brian.harris@nrc.gov)

(E-mail: andrea.jones@nrc.gov)

Karla Raimundi Daniel Riesel, Esq.

Hudson River Sloop Clearwater, Inc. Victoria Shiah, Esq.

724 Wolcott Ave. Sive, Paget & Riesel, P.C.

Beacon, NY 12508 460 Park Avenue (E-mail: karla@clearwater.org) New York, NY 10022 (E-mail: driesel@sprlaw.com)

(E-mail: vshiah@sprlaw.com)

Joan Leary Matthews, Esq. John Louis Parker, Esq.

Associate Commissioner Office of General Counsel, Region 3 Hearings and Mediation Services NYS Dept. of Environmental Conservation New York State Department of 21 S. Putt Corners Road Environmental Conservation New Paltz, New York 12561-1620 625 Broadway, 14th Floor (E-mail: jlparker@gw.dec.state.ny.us)

Albany, NY 12233-1500 (E-mail: jlmatthe@gw.dec.state.ny.us)

John J. Sipos, Esq. Michael J. Delaney, Esq.

Charlie Donaldson Esq. Vice President -Energy Department Assistant Attorneys General New York City Economic Development Office of the Attorney General Corporation (NYCDEC) of the State of New York 110 William Street New York, NY 10038 The Capitol (E-mail: mdelaney@nycedc.com)

Albany, NY 12224-0341 (E-mail: John.Sipos@ag.ny.gov) 2

Phillip Musegaas, Esq. Kevin Hay Deborah Brancato, Esq. Village of Buchanan Riverkeeper, Inc. Municipal Building 20 Secor Road 236 Tate Avenue Ossining, NY 10562 Buchanan, NY 10511-1298 (E-mail: phillip@riverkeeper.org) (E-mail:

(E-mail: dbrancato@riverkeeper.org) administrator@villageofbuchanan.com)

Robert D. Snook, Esq. Janice A. Dean, Esq.

Assistant Attorney General Assistant Attorney General Office of the Attorney General Office of the Attorney General State of Connecticut of the State of New York 55 Elm Street 120 Broadway, 26th Floor P.O. Box 120 New York, New York 10271 Hartford, CT 06141-0120 (E-mail: Janice.Dean@ag.ny.gov)

(E-mail: Robert.Snook@po.state.ct.us)

Signed (electronically) by Paul M. Bessette Paul M. Bessette, Esq.

MORGAN, LEWIS & BOCKIUS LLP 1111 Pennsylvania Avenue, N.W.

Washington, D.C. 20004 Phone: (202) 739-5796 Fax: (202) 739-3001 E-mail: pbessette@morganlewis.com Counsel for Entergy Nuclear Operations, Inc.

3