ML11298A379

NRC Staff'S Answer to State of New York and Riverkeeper'S Joint Motion to File a New Contention and New Joint Contention NYS-38/RK-TC-5

ML11298A379
Person / Time
Site:	Indian Point
Issue date:	10/25/2011
From:	Roth D NRC/OGC
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
RAS 21300, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML11298A379 (151)

Text

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 David E. Roth Counsel for NRC Staff October 25, 2011

TABLE OF CONTENTS PAGE INTRODUCTION .......................................................................................................................... 1 BACKGROUND ............................................................................................................................ 1 DISCUSSION ................................................................................................................................ 2 I. Admissibility Requirements for Timely-Filed Contentions ................................................. 2 II. Additional Requirements for the Admission of Non-Timely and Late-Filed Contentions ... 3 III. Summary of Contention NYS-38/RK-TC-5 ........................................................................ 6 IV. Portions of Contention NYS-8/RK-TC-5 Are Impermissibly Late and Fail to Present a Genuine Dispute of Material Fact or A Material Issue for Litigation .................................. 7 A. The Contentions Claims Regarding Identification of the Most Limiting Locations for Metal Fatigue Calculations are Impermissibly Late and Are Inadmissible .................................................................................................... 8 B. The Contentions Claims Regarding the WESTEMS Code Are Impermissibly Late .............................................................................................. 11 C. The Contentions Claim Regarding Steam Generators Is Impermissibly Late, and Fails to Satisfy 10 C.F.R. § 2.309(f)(1) ................................................ 13 D. The Contentions Claim Regarding Vessel Internals is Impermissibly Late, And Fails to Satisfy 10 C.F.R. § 2.309(f)(1)......................................................... 15 E. The Nontimely Factors of 10 C.F.R. § 2.309(c)(1) Weigh Against Admission..... 17 F. The Contentions References to the Atomic Energy Act Fail to Raise a Cognizable Issue for Litigation ............................................................................ 17 G. The Contention Erroneously Asserts that Commitments Are Not Acceptable In License Renewal Applications ...................................................... 18

1. Commitments to Comply with the Future NRC and Industry Developments .......................................................................................... 18

2. Entergys Commitments Relate to Implementation, not Development of Its AMP .......................................................................... 20

a. The CUFen Calculations Relate to Implementing the Metal Fatigue Program ................................................................ 20

ii

b. The Steam Generator Inspections are Related to Implementing the Program for Steam Generators ....................... 21

c. The Industry Programs Are Related to Implementing the Program for Vessel Internals ................................................. 21

3. Ongoing NRC and Industry Efforts Related to the Management Of Aging Effects ....................................................................................... 22 CONCLUSION ............................................................................................................................ 25

October 25, 2011 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 INTRODUCTION Pursuant to 10 C.F.R. § 2.309(h)(1), and the Atomic Safety and Licensing Board's

("Board") Scheduling Order (July 1, 2010) and Amended Scheduling Order (June 7, 2011), the Staff of the U.S. Nuclear Regulatory Commission (NRC Staff or Staff) hereby files its answer to the State of New York's (New York or NYS) and Riverkeeper Inc.'s (Riverkeeper or RK)

New Joint Contention NYS-38/RK-TC-5, filed on September 30, 2011.1 As more fully set forth below, the Staff opposes the admission of Contention NYS-38/RK-TC-5 because, inter alia, the proffered contention is impermissibly late, is not based upon new, materially different information, and fails to demonstrate a genuine dispute with the application.

BACKGROUND On April 23, 2007, Entergy Nuclear Operations, Inc. (Entergy or Applicant) filed a 1

The Intervenors filing consisted of a transmittal letter dated September 30, 2011, along with (1) "State Of New York And Riverkeepers Joint Motion For Leave To File A New Contention Concerning Entergy's Failure To Demonstrate That It Has All Programs That Are Required To Effectively Manage The Effects Of Aging Of Critical Components Or Systems" ("Motion"); (2) "State Of New York And Riverkeepers New Joint Contention NYS-38/RK-TC-5" ("Contention") with Attachment, (3) Declaration of Dr. Richard T. Lahey, Jr., (4) Declaration of Dr. Joram Hopenfeld with Attachment, and (5) a Certificate of Service.

license renewal application ("LRA"), seeking to renew the operating licenses for Indian Point Nuclear Generating Units 2 and 3 (IP2 and IP3), for an additional period of 20 years beyond their current expiration dates of September 28, 2013 and December 12, 2015, for IP2 and IP3, respectively. The Staff reviewed the LRA for compliance with the safety requirements of 10 C.F.R. Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants."

On August 11, 2009, the Staff issued its "Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3" (SER), which it published as NUREG-1930, Vols. 1 and 2, "Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3" in November 2009. On August 30, 2011, the Staff issued SER Supplement 1 (SSER), and on August 31, 2011 the Staff notified the Board and parties of the availability of SER Supplement 1 in ADAMS.2 On September 30, 2011, New York and Riverkeeper filed their new contention.

DISCUSSION I. Admissibility Requirements for Timely-Filed Contentions The legal requirements governing the admissibility of contentions are well established, and are currently set forth in 10 C.F.R. § 2.309(f). In brief, the regulations require that a contention must satisfy the following requirements in order to be admitted the request or petition must (i) provide a specific statement of the issue of law or fact to be raised or controverted, (ii) provide a brief explanation of the basis, (iii) demonstrate that the issue is within the scope of the proceeding; (iv) demonstrate that the issue raised is material to the findings the NRC must make, (v) provide a concise statement of the alleged facts or expert opinions and other support, and (vi) provide sufficient information to show that a genuine dispute exists with the 2

Letter from Sherwin E. Turk to the Board (Aug. 31, 2011). The formal publication of the SER Supplement as a bound hard copy is pending.

applicant/licensee on a material issue of law or fact, including how a the application fails to contain information on a relevant matter as required by law. 10 C.F.R. § 2.309(f)(1)(i) - (vi).

The purpose of the contention admissibility rule § 2.309(f)(1) is to "focus litigation on concrete issues and result in a clearer and more focused record for decision." Calvert Cliffs 3 Nuclear Project, LLC, and Unistar Nuclear Operating Services, LLC (Combined License Application for Calvert Cliffs Unit 3), LBP-09-04, 69 NRC 170, 189 (2009) (quoting Changes to Adjudicatory Process, 69 Fed. Reg. 2182, 2202 (Jan. 14, 2004)). The Commission has made clear that the contention admissibility rules are strict by design, and it should not have to expend resources to support the hearing process unless there is an issue that is appropriate for, and susceptible to, resolution in an NRC hearing. Id. Conclusory assertions and speculation in pleadings are insufficient to support the admission of a contention. See Entergy Nuclear Operations, Inc. (Indian Point, Units 2 and 3), LBP-08-13, 68 NRC 43, 200 (2008) and cases cited therein. The Commission has stated that [m]ere notice pleading is insufficient under these standards. Fansteel, Inc. (Muskogee, Oklahoma Site), CLI-03-13, 58 NRC 195, 203 (2003). Failure to comply with admissibility requirements is grounds for the dismissal of a contention. Florida Power & Light Co. (St. Lucie Nuclear Power Plant, Units 1 and 2),

LBP-08-14, 68 NRC 279, 288 (2008) (citing 69 Fed. Reg. at 2221); see also Private Fuel Storage, LLC. (Independent Spent Fuel Storage Installation), CLI-99-10, 49 NRC 318, 325 (1999).3 II. Additional Requirements for the Admission of Non-Timely and Late-Filed Contentions The admissibility of late-filed contentions in NRC adjudicatory proceedings is governed by (a) 10 C.F.R. § 2.309(f)(2), concerning late-filed contentions, (b) 10 C.F.R. § 2.309(c),

3 Further, pursuant to 10 C.F.R. § 2.335(a), contentions challenging the adequacy of the Commissions regulations are beyond the scope of individual adjudicatory proceedings unless a waiver is requested and granted. [A] petitioner may not demand an adjudicatory hearing to attack generic NRC requirements or regulations, or to express generalized grievances about NRC policies. Duke Energy Corp. (Oconee Nuclear Station, Units 1, 2, & 3), CLI-99-11, 49 NRC 328, 334 (1999).

concerning non-timely contentions, and (c) 10 C.F.R. § 2.309(f)(1), establishing the general admissibility requirements for contentions. First, a late-filed contention may be admitted as a timely new contention if it meets the requirements of 10 C.F.R. § 2.309(f)(2). Under this provision, a contention filed after the initial filing period may be admitted with leave upon a showing that (i) the information upon which the amended or new contention is based was not previously available; the information upon which the amended or new contention is based is materially different than information previously available; and the amended or new contention has been submitted in a timely fashion based on the availability of the subsequent information.

10 C.F.R. § 2.309(f)(2).4 Second, a contention that does not qualify for admission as a new contention under 10 C.F.R. § 2.309(f)(2) may be admissible under the provisions governing nontimely contentions, set forth in 10 C.F.R. § 2.309(c)(1). Nontimely contentions will not be entertained absent a determination by the presiding officer that the contentions should be admitted based upon a balancing of the eight factors in 10 C.F.R. § 2.309(c)(1); Oyster Creek, CLI-09-07, 69 NRC at 260; Amergen Energy Co., LLC (Oyster Creek Nuclear Generating Station), LBP-06-22, 64 NRC 229, 234 n.7 (2006). Of the eight criteria, the need for a showing of good cause for the late filing is the most important. State of New Jersey (Department of Public Law and Safety), CLI-93-25, 38 NRC 289, 296 (1993). To show good cause for late filing under 10 C.F.R. § 2.309(c)(1), "a petitioner must show that the information on which the new contention is based was not reasonably available to the public, not merely that the petitioner recently found out about it." Dominion Nuclear Connecticut, Inc. (Millstone Power Station, Unit 4

Here, the Board has ruled that new contentions shall be deemed timely under 10 C.F.R.

§ 2.309(f)(2)(iii) if filed within thirty days of the date when new material information undergirding the contention becomes available. Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generating Units 2 and 3), (Scheduling Order) (July 1, 2010), at 6 ¶ F.2. In addition, the Board has ruled that any contentions which arise from new information contained in the Applicants RAI responses of March 28, 2011 or other RAI responses to be submitted by Entergy prior to publication of the SER Supplement, or new information contained in the SER Supplement, are to be filed no later than thirty days after the SER Supplement is issued. Amended Scheduling Order, at 2.

No. 3), CLI-09-05, 69 NRC 115, 126 (2009); emphasis in original. The Commission emphasized in Oyster Creek that:

[O]ur contention admissibility and timeliness rules require a high level of discipline and preparation by petitioners, who must examine the publicly available material and set forth their claims and the support for their claims at the outset. There simply would be no end to NRC licensing proceedings if petitioners could disregard our timeliness requirements and add new contentions at their convenience during the course of a proceeding based on information that could have formed the basis for a timely contention at the outset of the proceeding. Our expanding adjudicatory docket makes it critically important that parties comply with our pleading requirements and that the Board enforce those requirements.

Oyster Creek, CLI-09-07, 69 NRC at 271-272. (internal quotation marks and footnotes omitted).

The Commission made clear that merely filing a contention within a certain number of days after publication of the Staff's SER is insufficient; rather, where the information was available previously, a petitioner cannot delay filing a contention until a document becomes available that "collects, summarizes and places into context the facts supporting that contention." Northern States Power Co. (Prairie Island Nuclear Generating Plant, Units 1 and 2), CLI-10-27, 72 NRC __ (Sept. 30, 2010), slip op. at 17. Those who wish to offer contentions have an "iron-clad obligation to examine the publicly available documentary material . . . with sufficient care to enable it to uncover any information that could serve as the foundation for a specific contention. Id. at 18 (quoting Sacramento Municipal Utility District (Rancho Seco Nuclear Generating Station), CLI-93-3, 37 NRC 135, 147 (1993)). A contention based upon documents that were available well before the Staff's SER was issued would be untimely, absent a discussion in the SER that would make reasonably apparent a foundation for such a contention. Prairie Island, CLI-10-27, 72 NRC __ (slip op. at 17). The Commission stated that [b]y permitting [intervenors] to wait for the Staff to compile all relevant information in a single document, the Board improperly ignored [intervenors] obligation to conduct its own due

diligence. Id. at 18. In addition, the Commission has held that "[n]ew bases for a contention cannot be introduced in a reply brief, or any other time after the date the original contentions are due, unless the petitioner meets the late-filing criteria set forth in 10 C.F.R. § 2.309(c), (f)(2)."

Nuclear Management Co., LLC (Palisades Nuclear Plant), CLI-06-17, 69 NRC 727, 732 (2006)

(emphasis added).

As the Commission has recognized, the requirements governing late-filed contentions and untimely filings, set forth in 10 C.F.R. §§ 2.309(c)(2) and 2.309(f)(2), are stringent. Oyster Creek, CLI-09-07, 69 NRC at 260. Further, each of the factors set forth in the regulations is required to be addressed in a requestors nontimely filing. Id. at 260-61. Indeed, under NRC case law, a petitioners failure to address the late-filing criteria in 10 C.F.R. § 2.309(c) or 10 C.F.R. § 2.309(f)(2) is reason enough to reject the proposed new contention. Millstone, CLI-09-05, 69 NRC at 126.

III. Summary of Contention NYS-38/RK-TC-5 In their newly proffered contention, New York and Riverkeeper seek to litigate the following issue:

Entergy is not in compliance with the requirements of 10 C.F.R.

§§ 54.21(a)(3) and (c)(1)(iii) and the requirements of 42 U.S.C.

§§ 2133(b) and (d) and 2232(a) because Entergy does not demonstrate that it has a program that will manage the affects

[sic] of aging of several critical components or systems and thus NRC does not have a record and a rational basis upon which it can determine whether to grant a renewed license to Entergy as required by the Administrative Procedure Act[.]

Contention at 1 (capitalization omitted). New York and Riverkeeper identify four bases for the contention, in which they assert that Entergys commitments to take certain actions in the future render its LRA incomplete, with respect to (a) identification of the most limiting locations for metal fatigue calculations, (b) use of the WESTEMS computer program for CUFen metal fatigue calculations, (c) use of a Steam Generator Management Program (to be completed by the

Electric Power Research Institute (EPRI) in 2013) and an unspecified inspection program, to manage potential primary water stress corrosion cracking (PWSSC) in the steam generator divider plates, and (d) use of a modified inspection plan for reactor vessel internals, to be issued by EPRI upon incorporating the Staffs proposed modifications of an EPRI guidance document (MRP-227) to which Entergy has committed. Contention at 1-3. In their accompanying Motion, New York and Riverkeeper explained their contention as follows:

The bases for proposed Contention 38, are not that the AMP proposed by Entergy is flawed (it may turn out to be flawed once it is disclosed), but that Entergy has not presented an AMP and thus cannot meet its burden to prove that the undefined and unspecified AMPs are adequate to meet the requirements of 10 C.F.R. §§ 54.21(a)(3) and (c)(1)(iii) nor to demonstrate that the yet to be defined AMP will be consistent with the 10 specific components of each AMP identified in GALL to which Entergy has committed compliance.

Motion at 7.

As discussed below, New Yorks and Riverkeepers assertion of these issues is untimely, in that the underlying information that prompted the claims of omission presented in Contention NYS-38/RK-TC-5 was available long before publication of the Staff's SSER. Accordingly, all aspects of NYS-38/RK-TC-5 are impermissibly late, without the requisite showing of good cause for their tardiness. Further, the Intervenors assertion of these issues fails to identify a genuine dispute with the Applicants LRA. Therefore, the Staff opposes the admission of this newly proffered contention.

IV. Portions of Contention NYS-8/RK-TC-5 Are Impermissibly Late and Fail to Present A Genuine Dispute of Material Fact or A Material Issue for Litigation Contention NYS-38/RK-TC-5 is not premised upon any new information in the SSER or associated RAIs, but instead is premised on the absence of information and omission of details.

See e.g. Contention at 2 (asserting that an "unspecified" inspection program will be instituted for steam generator divider plates). The Intervenors do not dispute the information provided in the

RAIs, the responses, and the SSER, but instead claim the information provided to date does not meet the requirements of 10 C.F.R. §§ 54.21(a)(3) and (c)(1)(iii). Contention at 4.

Further, much of the Intervenors newly proffered contention - and indeed, the underlying assertion that the application is incomplete pending the completion of ongoing NRC and industry programs -- is not based upon new information in the SSER or information provided by the Applicant in its RAI responses in 2011, but instead, is based upon omissions which could have been asserted based upon the original LRA, long before the Staff issued its RAIs and SER Supplement in 2011. To proffer an admissible contention, the Intervenors must show that they could not have previously detected that the LRA was incomplete until the Staff's SSER was written. They do not make this showing. Accordingly, the contention is impermissibly late. In addition, as more fully set forth below, Contention NYS-38/RK-TC-5 fails to satisfy the requirements of 10 C.F.R. §§ 2.309(c) and (f)(1), and accordingly, it is inadmissible for those reasons as well.

In the following discussion, the Staff addresses the timeliness and admissibility of each of the four claims raised in the contention, seriatim.

A. The Contentions Claims Regarding Identification of the Most Limiting Locations for Metal Fatigue Calculations Are Impermissibly Late and Are Inadmissible New York and Riverkeeper assert that Entergy might identify new limiting locations, but the process used and resulting identifications will not be done prior to completion of license renewal. Contention at 1-2. In particular, New York and Riverkeeper say that Entergy has not identified plant-specific locations which might have more limiting environmentally-adjusted cumulative usage factors (i.e. "CUFen").5 Contention at 6, 7. Further, they assert that these 5

Cumulative Use Factor (or, alternatively, Cumulative Usage Factor) - is a means of quantif[ying] the fatigue that a particular metal component experiences during plant operation.

AmerGen Energy Co., LLC (Oyster Creek Nuclear Generating Station), CLI-08-28, 68 NRC 658, 663 (2008). CUFen, in turn, is the term for Cumulative Use [or Usage] Factor Environmentally Adjusted, meaning a CUF modified by an Fen (Environmental Adjustment Factor) to reflect the corrosive

determinations must be made before the NRC makes a decision on Entergy's LRA. See Contention at 3; Hopenfeld Declaration at 3, 4.

New York/Riverkeepers claims regarding this matter are impermissibly late, in that the underlying information was available prior to issuance of SER Supplement 1. Thus, in its original LRA, Entergy observed:

As reported in SECY-95-245, the NRC believes that no immediate staff or licensee action is necessary to deal with the environmentally assisted fatigue issue. In addition, the staff concluded that it could not justify requiring a back fit of the environmental fatigue data to operating plants. However, the NRC concluded that, because metal fatigue effects increase with service life, environmentally assisted fatigue should be evaluated for any proposed extended period of operation for license renewal.

LRA at 4.3-22.

By letter dated August 9, 2010 (NL-10-082), and served upon the parties by Entergy on August 10, 2010, Entergy reported completion of "Commitment 33" under which it used its Fatigue Monitoring Program to update certain fatigue usage calculations. Later, Entergy re-addressed the topic in a letter (NL-11-032) dated March 28, 2011 (Attach. 1). Therein, through "Commitment 43," Entergy stated that prior to September 28, 2013 (for Unit 2) and December 12, 2015 (for Unit 3) (i.e., prior to commencement of the period of extended operation):

IPEC 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 IP2 and IP3 configurations. If more limiting locations are identified, the most limiting location will be evaluated for the effects of the reactor coolant environment on fatigue usage.

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

environment inside a nuclear reactor - a factor that may accelerate fatigue failure. See, e.g., Regulatory Guide 1.207, Guidelines for Evaluating Fatigue Analyses Incorporating the Life Reduction of Metal Components due to the Effects of the Light-Water Reactor Environment for New Reactors, at 2 (Mar.

2007) (ML083300592).

NL-11-032, Attachment 2, at 17 (Attach. 1).

Indeed, New Yorks original Contention 26 disputed, inter alia, Entergy's LRA statement that "More limiting IPEC-specific locations with a valid CUF may be added in addition to the NUREG/ CR-6260 locations."6 Thus, New York has known of this issue for some time, long before Entergy submitted its "Commitment 43," in which it committed to perform a review 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 IP2 and IP3 configurations. Likewise, Riverkeeper raised concerns regarding the NUREG/CR-6260 locations in its original petition to intervene.7 New York and Riverkeeper thus had sufficient information to form their current claim four years ago, based upon the LRAs discussion of NUREG/CR-6260.

New York and Riverkeeper do not provide any reason to believe that Entergy's plans were unclear until the Staff's SSER was published, or that the Intervenors were unable to make a claim of omission sooner. Indeed, New York raised this issue in Contention 26 in November 2007, as well as in Contention NYS-26B, filed on September 9, 2010.8 Accordingly, this issue is impermissibly late. See Prairie Island, CLI-10-27, 72 NRC __ (slip op. at 14).

Further, the metal fatigue issue raised in this contention fails to satisfy 10 C.F.R.

§ 2.309(f)(1), in that it does not identify any failure by Entergy to satisfy a legal requirement.

The claim underlying this portion of the contention is that NRC regulations require Entergy, as a pre-requisite to establishing an acceptable AMP, to identify which components (i.e. what plant-specific locations) have a limiting CUFen. See, e.g., Hopenfeld Declaration at 3 ("Entergy must 6

See New York State Notice of Intention to Participate and Petition to Intervene (Nov. 30, 2007),

at 231.

7 See Riverkeeper, Inc.'s Request for Hearing and Petition to Intervene in the License Renewal Proceeding for the Indian Point Nuclear Power Plant (Nov. 30, 2007), at 14.

8 See, e.g., New York and Riverkeepers Joint Reply to Entergy and NRC Staffs Separate Answers to [New York and Riverkeepers] New and Amended Contention [NYS]-26B/Riverkeeper TC-1B (Metal Fatigue) (Oct. 12, 2010), at 13.

identify the locations that may be more limiting, and which will be the subject of the CUFen calculations, now, and not just articulate a plan to determine such locations later.") (emphasis in original). This assertion is altogether inconsistent with the Commissions rejection of similar claims in Vermont Yankee, where the Commission held as follows:

According to Vermont, the mere fact that an applicant has agreed to implement an AMP does not free it of its obligation to conduct a proper CUFen analysis as a prerequisite to designing the appropriate AMP. Vermont asserts that, [w]ithout the CUFen analysis, identifying which, if any, components will have a CUFen in excess of 1.0 and at what point in their operating history that is likely to occur, the parameters of the AMP monitoring cannot be determined and an applicant would not be able to demonstrate that it has a technically acceptable AMP. Vermonts position lacks legal support. We see nothing in our regulations to suggest that baseline CUFen calculations are prerequisites to establish the parameters of the AMP.

Entergy Nuclear Vermont Yankee, L.L.C. and Entergy Nuclear Operations, Inc. (Vermont Yankee Nuclear Power Station), CLI 10-17, 72 NRC __ (July 8, 2010), slip op. at 50 (addressing Vermonts argument regarding the Boards conclusion that CUFens are TLAAs) (emphasis in original; footnotes omitted).9 The new contention is not only late, but fails to demonstrate a material dispute with the application and lacks a legal basis. 10 C.F.R. § 2.309(f)(1)(iv), (vi).

B. The Contentions Claims Regarding the WESTEMS Code Are Impermissibly Late New York and Riverkeeper seek to challenge Entergys use of CUFen calculations to be performed with the "WESTEMS" computer program. The Intervenors allege that Entergy might make modifications to the WESTEMS computer model, and that the criteria for making such "user interventions" while conducting CUFen calculations will not be disclosed prior to license renewal. Contention at 2. Further, they assert that the AMP is undeveloped without additional 9

Dr. Lahey incorrectly refers to "TLAA fatigue evaluations" (Lahey Declaration at 3). As the Commission has held, where (as here) a CUFen was not calculated as part of the CLB, such evaluations are not TLAAs. Vermont Yankee, CLI 10-17, 72 NRC __ (slip op. at 47-48).

information about the possible future user interventions, and that the documentation is not part of the implementation of the AMP, but is part of the development of the AMP. Contention at 1.

The Intervenors base this concern on Entergy's commitment to provide written justifications and explanations when Entergy is executing WESTEMS. See NL-11-032, Attachment 1 at 27 (Attach. 1).10 Essentially, these allegations amount to a concern over the creation of additional documentation during the use of WESTEMS following license renewal.

This issue - the documentation of user intervention - could have been raised earlier, based upon a review of the WESTEMS user manual. Thus, the issue of user intervention and the documentation of such intervention is part of the method of using WESTEMS; Entergys use of the WESTEMS code was not raised for the first time in the Staff's SSER or associated RAIs.

Indeed, the Intervenors have been aware that WESTEMS would be used as part of the aging management program for some time. See, e.g., Contention at 2 (citing Applicant's answer to New and Amended Contention New York State 26B/ Riverkeeper TC-1B (Metal Fatigue, dated October 4, 2010 at 11). Thus, New York and Riverkeeper could have reviewed the available information to learn about the user intervention options within WESTEMS over a year ago.

Further, Intervenors make no showing that how WESTEMS allows for user interaction was only first revealed from Entergy's commitments in NL-11-032, or that the SSER somehow provided the information needed for NYS/RK to allege an omission of details on how WESTEMS is used.

See Prairie Island, CLI-10-27, 72 NRC __ (slip op. at 14). Consequently, Intervenors could have expressed any concern with the documentation associated with the implementation of WESTEMS in October 2010. Accordingly, they are impermissibly late in raising it now.

10 Entergys statements regarding WESTEMS were contained in Entergys letter of March 28, 2011 (NL-11-032), in Commitments 44 and 45. For Commitment 44, Entergy stated, IPEC will include written explanation and justification of any user intervention in future evaluations using the WESTEMS Design CUF] module. NL-11-032, Attachment 2, p. 17. Similarly, in Commitment 45, Entergy wrote, IPEC will not use the NB-3600 option of the WESTEMS program in future design calculations until the issues identified during the NRC review of the program have been resolved. Id.

Moreover, wholly apart from any timing issue, the issue of what to document and justify in the future is part of the process of executing the computer code while implementing the aging management program.11 The records that might be created in the future reflect steps in execution of the WESTEMS code, not development of the code. Thus, the Intervenors fail to identify an omission from the application, and thus the proffered contention is inadmissible.

10 C.F.R. § 2.309(f)(1)(iv).

C. The Contentions Claim Regarding Steam Generators Is Impermissibly Late, and Fails to Satisfy 10 C.F.R. § 2.309(f)(1)

New York and Riverkeeper challenge Entergys commitment to use (a) a Steam Generator Management Program (to be completed by the Electric Power Research Institute (EPRI) in 2013), and (b) another (unspecified) inspection program, to manage potential primary water stress corrosion cracking (PWSCC) in the steam generator divider plates. In this regard, they argue that Entergy has omitted or not disclosed any description of the inspection program. Contention at 7-8. Further, they assert that Entergys commitment lacks a description of an inspection program that includes examination techniques and frequencies, and they object to Entergys commitment to develop its program in accordance with industry guidance that is to be developed. Id.

New York and Riverkeepers assertion of these claims is impermissibly late, in that Entergys plan to use industry guidance has been known for quite some time. Thus, the topic of primary water stress corrosion cracking was addressed in the original LRA, wherein Entergy wrote:

3.1.2.2.13. Cracking due to Primary Water Stress Corrosion Cracking (PWSCC). Cracking due to PWSCC in most components made of nickel alloy is managed by the Water Chemistry Control - Primary and Secondary, Inservice Inspection, and Nickel Alloy Inspection Programs. The Nickel Alloy Inspection 11 Indeed, the Staff expressed this view in its SSER. See, e.g., SSER at 4-42 (discussing "future calculations using the WESTEMS TM 'Design CUF' module").

Program implements the applicable NRC Orders and will implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines.

LRA at 3.1-9 (Attach. 2). The LRA for Indian Point directly addressed cracking due to primary water stress corrosion cracking in the nickel alloy or nickel alloy-clad steam generator divider plate exposed to reactor coolant. LRA Table 3.1.1 (Attach. 3); Reactor Coolant System, NUREG-1801 Vol. 1, Item Number 3.1.1-81 at p. 3.1-38 (Attach. 4). The LRA cited the water chemistry program as the pertinent aging management program, and no further evaluation was recommended. Id. Further, the LRA stated that the Nickel Alloy Inspection Program will implement applicable . . . staff-accepted industry guidelines. LRA at 3.1-9 (Attach. 2). Thus, from the time of the original application, New York State and Riverkeeper could have reviewed the plans for PWSCC, industry actions, and which programs are appropriate for the steam generator divider plates.

In fact, New York disputed Entergys plan to use industry programs on a different matter.

In its original petition to intervene, filed on November 30, 2007, New York Contention 23 challenged Entergy's plans to participate in the industry programs for investigating and managing aging effects on reactor internals and to evaluate and implement the results of the industry programs as applicable to the reactor internals. NYS Petition at 218-19.12 Now, NYS/RK are untimely re-asserting this issue, focusing for the first time on steam generators. Notwithstanding that this is a repeat of an issue raised in part of Contention 23, the Intervenors make no showing that NL-11-032 or the Staffs SSER somehow provided the last piece of information without which they could not have alleged this omission. Prairie Island, CLI-10-27, 72 NRC __ (slip op.

at 14).

12 Contention NYS-23 asserted that the LRA for IP2 and IP3 fails to comply with the requirements of 10 C.F.R. § 54.21(a) because the applicant had not proposed comprehensive baseline inspections to support its relicensing application and proposed 20-year life extensions. NYS Petition at 21. The Board rejected Contention 23 as outside the scope of license renewal. Indian Point, LBP-08-13, 68 NRC at 126.

Moreover, the Intervenors inclusion of this issue in their new contention fails to identify a genuine dispute with the LRA. On the topic of steam generators, the Intervenors argue that Entergy has omitted or not disclosed any description of the inspection program. Contention at 7-8. Their expert, Dr. Lahey, expresses concern that inspections of the steam generator tube-to-tubesheet welds for PWSCC will not be made until after the period of extended operation has begun. Dr. Lahey does not explain why this inspection schedule is insufficient to manage aging, nor does Dr. Lahey address why a concern with steam generator inspection frequency could not have been raised sooner. Significantly, he provides no information to show that the time period for Entergys planned inspections is inconsistent with the detection of potential PWSCC cracks. Thus, the Intervenors fail to articulate a genuine dispute with the application concerning steam generator issues. See 10 C.F.R. § 2.309(f)(1)(vi).

D. The Contentions Claim Regarding Vessel Internals Is Impermissibly Late, and Fails to Satisfy 10 C.F.R. § 2.309(f)(1)

New York and Riverkeeper assert that Entergy has not provided a final reactor vessel internals program and, instead, has committed to comply with an as yet unissued revision of MRP-227. Motion at 3, 4; Lahey Declaration at 3; Contention at 2-3. This assertion is untimely and fails to raise a genuine dispute with the LRA. 10 C.F.R. § 2.309(f)(1)(vi).

First, Entergys plan to use industry guidance has been known for a long time. In Entergy's original LRA submittal (NL-07-039) dated April 23, 2007 (Attach. 5), Entergy's "Commitment 30" stated:

For aging management of the reactor vessel internals, IPEC will (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.

Attachment to NL-07-039 at 30 (Attach. 5). Similar language was contained in the related LRA Updated Final Safety Analysis Report Supplement sections A.2.1.41 (Unit 2) and A.3.1.41 (Unit 3), filed with the LRA.

Thus, it was clear from the time Entergy filed its LRA that Entergy planned on future completion of programs, and future development of industry plans. If New York and Riverkeeper found this to be unacceptable, they were obliged to raise the issue at the beginning of the proceeding. As discussed above, New York did raise this issue as part of Contention 23, claiming as inadequate Entergy's plans to participate in industry programs for investigating and managing aging effects on reactor internals and to evaluate and implement the results of the industry programs as applicable to the reactor internals. NYS Petition at 218-19. The Intervenors make no showing that Entergy's plans were unclear or that the SSER somehow created the last piece of information without which they could not have alleged an omission related to Commitment 30 -- which essentially repeats information that was available for over four years. Their claim is therefore impermissibly late. Prairie Island, CLI-10-27, 72 NRC __

(slip op. at 14).13 Notwithstanding the Intervenors claims, it appears that this issue has been mooted by Entergys submission of September 29, 2011, inasmuch as NL-11-107 (Attach. 6) "contains the inspection plan satisfying the completion of commitment # 30 to the License Renewal Application regarding the Aging Management Programs for Reactor Vessel Internals." NL 107 at 1 (Attach. 6). Thus, the Intervenors concern with just having a commitment instead of a 13 The Intervenors state that Entergy has not provided a final reactor vessel internals program and instead Entergy has committed to comply with an unissued revision of MRP-227. Motion at 3, 4; Lahey Declaration at 3; Contention at 2-3. They acknowledge, however, that the State received information from Entergy (NL-11-107) on September 29, 2011, in which Entergy provided an inspection plan for reactor vessel internals that appears to rely on MRP-227, but indicate that they and their experts did not have sufficient time to review the document prior to filing the contention. Contention at 3.

Nonetheless, they assert that a commitment to develop a program is insufficient, and that Entergy has not filed any documents to demonstrate that its AMP is consistent with GALL. Id. As explained herein, these claims are now moot.

plan has been overtaken by events; Entergy replaced its brief statement of commitment with a 58-page Reactor Vessel Internals Inspection Plan, and its commitment has been satisfied.

Accordingly, the issue raised regarding Commitment 30 is now moot.

E. The Nontimely Factors of 10 C.F.R. § 2.309(c)(1) Weigh Against Admission The Intervenors do not address the eight nontimely factors of 10 C.F.R.

§-2.309(c)(1)(i)-(viii). A balancing of those factors weighs against admission, in that the issues raised in this contention could have been filed long ago. The Intervenors failure to address these factors warrants the rejection of their contention. See 10 C.F.R. § 2.309(c)(2). Moreover, no "good cause" appears for the Intervenors failure to raise the alleged omissions at the time the information was first available.14 F. The Contentions References to the Atomic Energy Act Fail to Raise a Cognizable Issue for Litigation Contention NYS-38/RK-TC-5 broadly addresses compliance with, inter alia, the Atomic Energy Act of 1954, as amended (the Act), specifically, 42 U.S.C. §§ 2133(b) and (d), and 42 U.S.C. § 2232(a) (i.e., Sections 103(b) and (d), and 182(a) of the Act). See Contention at 1.

These claims fail to state a cognizable issue for litigation.

First, 42 U.S.C. § 2133(b) regards the "nonexclusive basis" by which the NRC issues licenses when certain criteria are met; the Intervenors do not show how the LRA fails to satisfy some requirement imposed by this section of the Act. 10 C.F.R. § 2.309(f)(1)(i). Second, 42 U.S.C. § 2133(d), deals with limitations on jurisdiction and foreign ownership, and the opinions of the NRC, and is even more removed from the scope of a license renewal proceeding. Finally, 42.U.S.C. 2232(a) addresses the "content and form" of license applications, such as the necessity for an applicant to sign an application; the Intervenors do not explain how Entergys 14 Furthermore, because New York and Riverkeeper are both parties to this proceeding, they can continue to participate in the proceeding and represent their interests through adjudication of their existing contentions.

LRA fails to satisfy this section of the Act. Thus, the Intervenors citation of "42 U.S.C. §§ 2133(b) and (d) and 2232(a)" fails to raise a cognizable issue for litigation in this proceeding, and their reference to these statutory provisions should not be admitted as part of their new contention.

G. The Contention Erroneously Asserts that Commitments Are Not Acceptable in License Renewal Applications

1. Commitments to Comply with the Future NRC and Industry Developments The focus of the proffered contention is, according to New York and Riverkeeper, a "fundamental legal deficiency of the AMP record." Contention at 16. The essence of the Intervenors position is that Entergys application for license renewal is insufficient and incomplete where the LRA provides a commitment to develop - in the future - plans and programs for an AMP which the Applicant has already stated will be consistent with GALL. See Motion at 8. The Intervenors assert that this is contrary to legal requirements and precedents, including Vermont Yankee, CLI-10-17. Id. Further, they state that a commitment to develop a plan which will be consistent with GALL does not demonstrate consistency with GALL, and is insufficient under the regulations and law. Contention at 15-16. According to the Intervenors, the missing information is part of the development of an AMP, not the implementation of an AMP. Contention at 1.

The Intervenors view of this matter is contrary to established precedent, under which the Commission has held that a commitment to implement an AMP that the NRC finds is consistent with the GALL Report15 constitutes one acceptable method for compliance with 10 C.F.R.

15 The Commission has cited the GALL Report with approval, stating:

An applicant for license renewal may reference the GALL Report to demonstrate that the programs at the applicants facility correspond to those reviewed and approved therein, and the applicant must ensure and certify that its programs correspond to those reviewed in the GALL

§ 54.21(c)(1)(iii). Vermont Yankee, CLI 10-17, 72 NRC __ (slip op at 44).16 In Vermont Yankee, the Commission "disagree[d] with the Boards conclusion that Entergys future-oriented interpretation would avoid the whole point of the license renewal process - to demonstrate that aging will be properly managed." Id. The Commission repeated its holding from Oyster Creek, CLI-08-23, 68 NRC at 468, stating as follows:

Section 54.29(a) of our regulations speaks of both past and future actions, referring specifically to those that have been or will be taken with respect to . . . managing the effects of aging . . . and . .

. time-limited aging analyses. . . . Moreover, in 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).

Id. (emphasis in original; footnotes omitted). Further, the Commission observed as follows:

The GALL Report provides that one way a license renewal applicant may demonstrate that an AMP will effectively manage the effects of aging during the period of extended operation is by stating that a program is consistent with or based on the GALL Report.

Report. In other words, the license renewal 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.

Oyster Creek, CLI-08-23, 68 NRC at 468.

16 The Commission further stated as follows:

[A]n applicant can satisfy the requirements of section 54.21(c)(1) in any of three ways - it may choose to demonstrate that its fatigue analyses remain valid through the period of extended operation under subsection (i), or that those analyses have been projected to the end of that period under subsection (ii), or that the effects of aging will be adequately managed during that period under subsection (iii) through, e.g., a commitment to implement an approved AMP.

Vermont Yankee, CLI 10-17, 72 NRC __ (slip op. at 42).

An applicant may commit to implement an AMP that is consistent with the GALL Report and that will adequately manage aging. But such a commitment does not absolve the applicant from demonstrating, prior to issuance of a renewed license, that its AMP is indeed consistent with the GALL Report. We do not simply take the applicant at its word. When an applicant makes such a statement, the Staff will draw its own independent conclusion as to whether the applicants programs are in fact consistent with the GALL Report.

Id., slip op. at 45-46 (emphasis in original; footnotes omitted).

In sum, a commitment to comply with the GALL provisions for an AMP does not prevent the Board from reviewing the substance of the commitment and exploring any deficiencies alleged in that commitment, to the extent they are raised by the intervenor. Id. at 47. Those exceptions to the general principle, that compliance with a GALL-approved program demonstrates the adequacy of an AMP, do not apply here.

2. Entergy's Commitments Relate to Implementation, not Development of Its AMP New York and Riverkeeper assert that Entergys commitments to comply with the GALL Report demonstrate that its AMP is incomplete and has yet to be developed. Contention at 15.

Contrary to the Intervenors view, the claimed omissions are all related to implementation of programs and are not directed to the development of an adequate AMP.

a. The CUFen Calculations Relate to Implementing the Metal Fatigue Program The Commission has made clear that calculations to determine which CUFen is limiting are part of the implementation of a metal fatigue program. Vermont Yankee, CLI 10-17, 72 NRC __ (slip op. at 48). This is further evidenced by the Commission's observation that "None of our regulations requires that a license renewal applicant calculate CUFen - that is, adjust the CUF by applying the environmental adjustment factor - prior to the issuance of a renewed license." Id. Further, for an applicant proceeding under 10 C.F.R. § 54.21(c)(1)(iii), the Commission recognized in Vermont Yankee that such calculations are part of implementing an

AMP that is consistent with the GALL Report, and therefore in compliance with 10 C.F.R. § 54.21(c)(1)(iii). Id., slip op. at 41 n.192. Similarly, in this proceeding, Entergy is reviewing locations and may potentially make additional calculations; in doing so, it is implementing its metal fatigue program. Therefore the Intervenors claim that information must be provided now runs afoul of the Commission's holding in Vermont Yankee.

b. The Steam Generator Inspections Are Related to Implementing the Program for Steam Generators The Intervenors allege that the steam generator AMP is missing information because the applicant committed to implementing portions of the program in the future. Contention at 2.

However, the Applicant's commitment to perform future inspections of its steam generators does not affect the content of the program or impact whether the program is adequate to manage the aging effects. As the Commission has explained, such implementation of portions of the AMP at a future date is not material to the determination of whether the AMP is adequate. Thus, the Intervenors contention challenging the Applicant's future implementation of its steam generator AMP is not properly within the scope of this proceeding.

c. The Industry Programs Are Related to Implementing the Program for Vessel Internals Entergys commitment to comply with industry programs for managing the aging effects of reactor vessel internals is consistent with the GALL Report. Thus, throughout section IV.B2 (Reactor Vessel Internals (PWR) - Westinghouse) of the GALL Report, the adequacy of a commitment to comply with such industry programs is repeatedly found to be acceptable:

No further aging management review is necessary if the applicant provides a commitment in the FSAR supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.

E.g., NUREG-1801, Rev. 1, at IV B2-2 (Attach. 4). Further, regarding whether there is a need for any further evaluation, the GALL Report repeatedly states "No, but licensee commitment needs to be confirmed." E.g., id.

Entergys commitment mirrors this approach, stating that for aging management of reactor vessel internals, it will evaluate and implement the results of the industry programs. See Attachment to NL-07-039 at 30 (Attach. 5). By committing to evaluate and implement industry programs, Entergy is implementing the AMP. Accordingly, its commitment establishes the adequacy of its AMP under Vermont Yankee.

3. Ongoing NRC and Industry Efforts Related to the Management of Aging Effects Two of the issues in Contention NYS-38/RK-TC-5 address how Entergy will respond to future developments by the NRC and by industry that could potentially affect its AMPs.

Specifically, these programs involve the EPRI Steam Generator Management Program Engineering and Regulatory Technical Advisory Group Report, and EPRI MRP-227 as ultimately approved by the Staff. Contention at 2-3.

The Intervenors concerns over the potential development of future inspection requirements and future implementation of those requirements are speculative in nature, and do not form an acceptable basis for a contention. In the Prairie Island license renewal proceeding, an issue was raised regarding the applicant's promise to implement the Commission's finalized inspection requirements associated with PWSCC of nickel-alloy upper head penetrations.

Northern States Power Co. (Formerly Nuclear Management Co., LLC) (Prairie Island Nuclear Generating Plant, Units 1 and 2), LBP-08-26, 68 NRC 905, 940-42 (2008) (admitting "PIIC Contention 8" in a modified form). The contention in that proceeding claimed that the AMP, which relied upon an NRC Order (First Revised Order EA-03-009, Issue of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water

Reactors, dated February 20. 2004), was not adequately detailed. Id. at 941. In response, the Board found that EA-03-009 provided adequate details and was incorporated by reference in the GALL Report, as the GALL Report identified EA-03-009 as the relevant AMP. Id.

Accordingly, the Board concluded that the ten elements of the GALL Report need not be addressed. Id. In addition, the Prairie Island Board found inadmissible the contentions claims regarding the applicant's commitment to implement, in the future, the finalized inspection requirements once they are codified into 10 C.F.R.§ 50.55a. Id. The Board stated:

The second part of this issue concerns the future AMP that will be implemented once the NRC incorporates finalized inspection requirements into 10 C.F.R. § 50.55a. The claim here is that [t]he LRA program commitment to do whatever the NRC tells them to do does not demonstrate the effectiveness of an aging management program. The Board believes that the LRA must be evaluated on the basis of AMPs now in effect. This means we will evaluate the LRA based on the requirements of Order EA-03-009.

At some future date, the NRC might or might not implement finalized inspection requirements. The Application has provided a commitment that, should the inspection requirements be changed.

Applicant will implement those new inspection requirements. It will be the responsibility of NRC Staff and Applicant to ensure that this commitment is fulfilled. This Board lacks the authority much less the ability to require Applicant clairvoyantly to predict the future inspection requirements and to describe their future implementation. On this issue, Petitioner has failed to identify any deficiency on a relevant matter in Northern States' Application and therefore does not satisfy 10 C.F.R. § 2.309(f)(1)(vi). This part of the contention is inadmissible.

Id. at 941-942.

The issues raised in Contention NYS-38/RK-TC-5 in this proceeding are analogous to the issue that the Board rejected in Prairie Island. For example, Contention NYS-38/RK-TC-5 takes issue with Entergy's future reliance on an undeveloped EPRI Steam Generator Management Program ("SGMP"), and planned future inspections (i.e., Commitment 41),

asserting that such plans do not meet license renewal requirements. Contention at 8.

However, as the Board found in Prairie Island, concerns over Entergy's future review and

implementation of the SGMP do not form an admissible contention. See Prairie Island, LBP 26, 68 NRC at 942.

The Intervenors assert that Entergy is postponing the development of an inspection plan, and thus it cannot be determined if the plan is consistent with the GALL Report. Contention at 8. But in making this argument, they fail to show why the Applicants current plan is insufficient, why the GALL Report is not satisfied through Commitment 41, or that any other flaw exists in the Applicant's commitment to perform future inspections. Thus, the claim does not satisfy 10 C.F.R. § 2.309(f)(1)(vi) and this part of the contention is inadmissible.

Similarly, the Intervenors take issue with Entergy's plans based on EPRI guidance document MRP-227, as approved by the Staff. See Contention at 2-3, 8. This issue is again analogous to the issue of non-finalized inspections plans discussed in Prairie Island, in that Entergy is planning to review potential modifications to its programs after the Staff completes its effort to determine what, if any, modifications to MRP-227 are needed. Compare Contention at 2-3 with Prairie Island, LBP-08-26, 68 NRC at 942. Significantly, the Intervenors fail to show why the Applicants current plan is insufficient, why the GALL Report is not met in part through the Applicant's actions and statements, or what is otherwise wrong with the applicant's commitment to review and implement any necessary changes to the AMP based on the Staff's final evaluations, when available. Thus, this claim does not satisfy 10 C.F.R. § 2.309(f)(1)(vi).

CONCLUSION Contention NYS-38/RK-TC-5 is not based upon new information that first became available in the SER Supplement or the Applicants recent RAI responses, and it therefore is impermissibly late; further, NYS/RK did not show good cause for its late filing. In addition, the Contention fails to meet the admissibly criteria of 10 C.F.R. § 2.309(f)(1). For these reasons, the Staff respectfully submits that the contention is inadmissible.

Respectfully submitted,

/Signed (electronically) by/

David E. Roth Counsel for NRC Staff U.S. Nuclear Regulatory Commission Mail Stop O-15 D21 Washington, DC 20555-0001 (301) 415-2749 E-mail: David.Roth@nrc.gov Dated at Rockville, MD this 25th day of October 2011

ANSWER CERTIFICATION I certify that I have made a sincere effort to make myself available to listen and respond to the moving parties, and to resolve the factual and legal issues raised in the motion, and that my efforts to resolve the issues have been unsuccessful.

/Signed (electronically) by/

David E. Roth Counsel for NRC Staff U.S. Nuclear Regulatory Commission Mail Stop O-15 D21 Washington, DC 20555-0001 (301) 415-2749 E-mail: David.Roth@nrc.gov Dated at Rockville, MD this 25th day of October 2011

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 ATTACHMENT 1 NL-11-032 - Letter from Entergy, dated March 28, 2011, regarding AMP RAIs

Enteray Nuclear Northeast Indian Point Energy Center w---Enbtergy 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 788-2055 Fred Dacirno Vice President License Renewal NL-1 1-032 March 28, 2011 U.S. Nuclear Regulatory Commission ATTN: 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.

Ifyou 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 d clare under penalty of perjury that the foregoing is true and correct. Executed on Since 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-1 1-032 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 RAI 3.0.3.1.2-1

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 (i.e., piping in direct contact with soil) and/or underground piping (i.e., 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 staff acknowledges that where examining buried pipe from the exterior surface is not possible due to plant configuration (e.g., the piping is located underneath foundations) it is reasonable to substitute a volumetric examination from the interior of 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-1 1-032 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 corrosivity 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 RAI 3.0.3.1.2-1 Part la 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-1 1-032 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 lb 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 RAI 3.0.3.1.2-1 Part lc 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 Carbon steel Hazmat 8 8 Stainless steel 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-1 1-032 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 RAI 3.0.3.1.2-1 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 1P2, 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 1P3, 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:

L. 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?

iii. What is the availability of the 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 1P3 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-1 1-032 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:

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-1 1-032 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 RAI 3.0.3.1.2-1 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 examinations are not possible due 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-1 1-032 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 RAI 3.0.3.1.2-1 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 RAI 3.0.3.1.2-1 Part 5a 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 RAI 3.0.3.1.2-1 Part 5b Not applicable.

Docket Nos. 50-247 and 50-286 NL-1 1-032 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 RAI 3.0.3.1.2-1 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 RAI 3.0.3.1.2-1 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 RAI 3.0.3.1.2-1 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 RAI 3.0.3.1.2-1 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 PEO 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-1 1-032 Attachment 1 Page 10 of 27 RAI 3.0.3.1.6-1

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 inaccessible low voltage power cables (480 V to 2 kV) in the presence of significant moisture, that these cables can potentially experience age related degradation. The staff noted that the applicant's Inaccessible Medium-Voltage Cables Program does not address inaccessible low voltage power cables [400 V (nominally 480 V) to 2 kV inclusive]. In addition, more frequent cable test and cable manhole 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-1 1-032 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 RAI 3.0.3.1.6-1 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 (i.e.,

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-1 1-032 Attachment 1 Page 12 of 27 A.2.1.22 Non-EQ 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-voltage will be tested at least once every ten 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 two-years (annually). In addition to the periodic manhole inspections, inspection of event-driven occurrences, such as heavy rain or flooding will be performed. Inspection frequency will be increased as necessary based on evaluation of inspection results.

The Non-EQ 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-voltage will be tested at least once every ten six years to provide an indication of the condition of the conductor insulation. Test frequencies will be adiusted based on test results and operating experience. The program includes inspections for water accumulation in manholes at least once every two years-(annuallv). In addition to the periodic manhole inspections, inspection for event-driven occurrences, such as heavy rain or flooding will be performed. Inspection frequency 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-1 801 program description.

The inspection frequency for manholes is based on plant-specific operating experience with cable wettinq 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-1 1-032 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 1P3 as described in LRA Section B.1.23.

This new program will be implemented consistent with the corresponding program described in NUREG-1801,.Section XI.E3, Inaccessible 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 RAI 3.0.3.1.6-1 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-1 1-032 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 RAI 3.0.3.1.6-1 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.

RAI 3.0.3.1.10-1

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 (ISI) 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#2010-004-00). 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 ISI 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.

Request

1. Explain how Entergy will manage aging (i.e., cracking) in the weld metal of ASME Code Class 1 small bore socket welds.

Docket Nos. 50-247 and 50-286 NL-1 1-032 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 ISl 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 IP2 ISI 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 1/1/2 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 not necessary. In lieu of this justification provide an aging management program that includes periodic volumetric inspections to manage cracking in small-bore piping and the associated weld metal (socket weld metal and butt weld metal).

Docket Nos. 50-247 and 50-286 NL-1 1-032 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 1P3 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 ISI 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 1P3. 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-1 1-032 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 ISI 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-1 1-032 Attachment 1 Page 18 of 27 RAI 3.0.3.2.10-1

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 RAI 3.0.3.2.10-1 The inspection interval for masonry walls within the scope of license renewal is every five years.

RAI 3.0.3.2.15-1

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 RAI 3.0.3.2.15-1 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 ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures" for concrete structures.

Docket Nos. 50-247 and 50-286 NL-1 1-032 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 ACI 349.3R, "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 ACI 349.9-3R 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-1 1-032 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 Model 44F 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 tubesheet/stub 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 divider plate could propagate to the SG triple point and potentially affect the pressure boundary of the SG channel head.

Request

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 RAI 3.1.2.2.13-1 Part 1 At IP2 and 1P3 the divider plates are Inconel 600 (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-1 1-032 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 all IPEC 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 Xl ISI 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 Report Revision 1, Volume 2, this aging effect is addressed in item IV.D2-4, applicable only to once-through SGs, but not to recirculating SGs.

The staff noted that ASME Code Section XI does not require any inspection of the tube-to-tubesheet welds. In addition, there are no NRC Orders or bulletins requiring examination of this weld. However, the staff's concern is that, ifthe 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 RAI 3.1.2.2.16-1 Part la At IP2 the tube to tubesheet welds are included in the RCS pressure boundary. IP2 does not employ any tubesheet region alternate repair criterion.

lb. 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 l b 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-1 1-032 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.

1P2 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 1P3 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:

1P3 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-1 1-032 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-1 1-032 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 (1P2) and LRA Table 4.3-14 (1P3), 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 (IP3) 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, item (1) of above LRA section and Commitment 33 indicated that more limiting plant-specific locations may be evaluated. However, it is only one of the options that may be taken. Furthermore, the limiting locations may be added and the staff is concerned whether the applicant is committed to verify that the plant-specific locations per NUREG/CR-6260 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-1 1-032 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 ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-1 1-032 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 deletie.n and underlines for additions.

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 1 Enhance the Aboveground Steel Tanks Program for IP2: NL-07-039 A.2.1.1 IP2 and IP3 to perform thickness measurements of September 28, A.3.1.1 the bottom surfaces of the condensate storage tanks, 013 B.1.1 city water tank, and fire water tanks once during the P3:

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.

2 Enhance the Bolting Integrity Program for IP2 and IP3 P2: NL-07-039 A.2.1.2 to clarify that actual yield strength is used in selecting Se013 B.1.2 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 015 270 1 preload and loss of material for all external bolting. _ I I

NL-1 1-032 Attachment 2 Page 2 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE I IRA SECTION

/AUDIT ITEM IP2: NL-07-039 A.2.1.5 3 Implement the Buried Piping and Tanks Inspection Program for IP2 and IP3 as described in LRA Section September 28, A.3.1.5 2013 B.1.6 B.1.6.

NL-07-153 Audit Item This new program will be implemented consistent with P3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.M34, Buried Piping and Tanks 2015 Inspection.

Include in the Buried Piping and Tanks Inspection NL-09-106 Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that NL-09-111 includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Establish inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using inspection techniques with demonstrated effectiveness.

NL-1 1-032 Attachment 2 Page 3 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ I / AUDIT ITEM 4 Enhance the Diesel Fuel Monitoring Program to P2: NL-07-039 A.2.1 .8 include cleaning and inspection of the IP2 GT-1 gas September 28, A.3.1 .8 turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil 2013 B.1.9 day tanks, IP2 SBO/Appendix R diesel generator fuel NL-07-1 53 Audit items oil day tank, and IP3 Appendix R fuel oil storage tank P3: 128,129, and day tank once every ten years.

December 12, 132, 2015 NL-08-057 491,492, Enhance the Diesel Fuel Monitoring Program to 510 include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10mg/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 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 LRA SECTION

/ AUDIT ITEM Enhance the External Surfaces Monitoring Program IP2: NL-07-039 A.2.1.10 5

September 28, A.3.1.10 for IP2 and IP3 to include periodic inspections of and subject to aging management 013 B.1.11 systems in scope review for license renewal in accordance with 10 CFR P3:

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).

Enhance the Fatigue Monitoring Program for IP2 to P2: NL-07-039 A.2.1.11 6

eptember 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 required. Review the number of allowed events and NL-07-153 Audit Item 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 2015 limiting numbers. Update the number of design transients accumulated to date.

7 Enhance the Fire Protection Program to inspect P2: NL-07-039 A.2.1.12 September 28, A.3.1.12 external surfaces of the IP3 RCP oil collection systems for loss of material each refueling cycle. 013 B.1.13 Enhance the Fire Protection Program to explicitly IP3:

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

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

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

NL-1 1-032 Attachment 2 Page 5 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION 1_ 1 1 / AUDITITEM 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.

2013 B.1.14 Acceptance criteria will be revised to verify no NL-07-153 Audit Items unacceptable signs of degradation.

1P3: 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 2015 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-1 1-032 Attachment 2 Page 6 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I_ 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 boundarv. S S I

NL-1 1-032 Attachment 2 Page 7 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I / AUDIT ITEM IP2: NL-07-039 A.2.1.16 10 Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include the following heat exchangers September 28, A.3.1.16 2013 B.1.17, in the scope of the program.

NL-07-153 Audit Item

• Safety injection pump lube oil heat exchangers IP3: 52

• RHR heat exchangers December 12, 2015

• RHR pump seal coolers

• Non-regenerative heat exchangers

• Charging pump seal water heat exchangers

• Charging pump fluid drive coolers

• Charging pump crankcase oil coolers

• Spent fuel pit heat exchangers

• Secondary system steam generator sample coolers

• Waste gas compressor heat exchangers

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

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

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

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

11 Delete commitment. NL-09-056

NL-1 1-032 Attachment 2 Page 8 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 12 Enhance the Masonry Wall Program for IP2 and IP3 IP2: NL-07-039 A.2.1.18 to specify that the IP1 intake structure is included in September 28, A.3.1.18 the program. 2013 B.1.19 IP3:

December 12, 2015 13 Enhance the Metal-Enclosed Bus Inspection Program IP2: NL-07-039 A.2.1.19 to add IP2 480V bus associated with substation A to September 28, A.3.1.19 the scope of bus inspected. 013 B.1.20 NL-07-153 Audit Items Enhance the Metal-Enclosed Bus Inspection Program IP3: 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 2015 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" connections for phase bus maintenance and bolted connection maintenance.

14 Implement the Non-EQ Bolted Cable Connections IP2: NL-07-039 A.2.1.21 Program for IP2 and IP3 as described in LRA Section September 28, A.3.1.21 B.1.22. 2013 B.1.22 IP3:

December 12, 2015

NL-1 1-032 Attachment 2 Page 9 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 15 Implement the Non-EQ Inaccessible Medium-Voltage IP2: NL-07-039 A.2.1.22 Cable Program for IP2 and IP3 as described in LRA September 28, A.3.1.22 Section B.1.23. 2013 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.

16 Implement the Non-EQ Instrumentation Circuits Test IP2: NL-07-039 A.2.1.23 Review Program for IP2 and IP3 as described in LRA September 28, A.3.1.23 Section B.1.24. 2013 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.

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

18 Enhance the Oil Analysis Program for IP2 to sample IP2: NL-07-039 A.2.1.25 and analyze lubricating oil used in the SBO/Appendix September 28, A.3.1.25 R diesel generator consistent with oil analysis for 2013 B.1.26 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.

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.

NL-1 1-032 Attachment 2 Page 10 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 19 Implement the One-Time Inspection Program for IP2 IP2: NL-07-039 A.2.1.26 and IP3 as described in LRA Section B.1.27. September 28, A.3.1.26 2013 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, 2015 20 Implement the One-Time Inspection - Small Bore IP2: NL-07-039 A.2.1.27 Piping Program for IP2 and IP3 as described in LRA September 28, A.3.1.27 Section B.1.28. 2013 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 2015 Code Class I Small-Bore Piping.

21 Enhance the Periodic Surveillance and Preventive P2: NL-07-039 A.2.1.28 Maintenance Program for IP2 ManeacPormfr013 and IP3 as necessary September 28, A.3.1.28 B.1.29 to assure that the effects of aging will be managed such that applicable components will continue to 1P3:

perform their intended functions consistent with the December 12, current licensing basis through the period of extended 015 operation. 2015 22 Enhance the Reactor Vessel Surveillance Program for IP2: NL-07-039 A.2.1.31 IP2 and IP3 revising the specimen capsule withdrawal September 28, A.3.1.31 schedules to draw and test a standby capsule to 013 B.1.32 cover the peak reactor vessel fluence expected IP3:

through the end of the period of extended operation. 3ecember 12, Enhance the Reactor Vessel Surveillance Program for 2015 1P2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor I vessel are maintained in storage.

23 Implement the Selective Leaching Program for IP2 IP2: NL-07-039 A.2.1.32 and IP3 as described in LRA Section B.1.33. September 28, A.3.1.32 2013 B.1.33 This new program will be implemented consistent with NL-07-153 Audit item the corresponding program described in NUREG- IP3: 173 1801,Section XI.M33 Selective Leaching of Materials. December 12, 2015 24 Enhance the Steam Generator Integrity Program for IP2: NL-07-039 A.2.1.34 IP2 and IP3 to require that the results of the condition September 28, A.3.1.34 monitoring assessment are compared to the 013 B.1.35 operational assessment performed for the prior IP3:

operating cycle with differences evaluated. December 12, 015

NL-1 1-032 Attachment 2 Page 11 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ I _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. 2013 B.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 _2015 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 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)

• 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.

S cable trays and supports 0 concrete portion of reactor vessel supports 0 conduits and supports S cranes, rails and girders 0 equipment pads and foundations 0 fire proofing (pyrocrete) 0 HVAC duct supports S jib cranes 0 manholes and duct banks 0 manways, hatches and hatch covers 0 monorails

NL-1 1-032 Attachment 2 Page 12 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I _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). IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides.

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

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

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

NL-1 1-032 Attachment 2 Page 13 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM Enhance the Structures Monitoring Proaram to include more detailed quantitative acceptance criteria NL-1 1-032 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 IP2: NL-07-039 A.2.1.36 Austenitic Stainless Steel (CASS) Program for IP2 September 28, A.3.1.36 and as described in LRA Section B.1.37. 2P3013 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.

27 Implement the Thermal Aging and Neutron Irradiation P2: NL-07-039 A.2.1.37 Embrittlement of Cast Austenitic Stainless Steel September 28, A.3.1.37 2013 B. 1.38 (CASS) Program for IP2 and IP3 as described in LRA 013NL-07-153 Audit item I P3: 1 73 S e ctio n B .1 .3 8 .

IP3: 173 This new program will be implemented consistent with December 12, the corresponding program described in NUREG- 2015 1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

28 Enhance the Water Chemistry Control - Closed IP2: NL-07-039 A.2.1.39 Cooling Water Program to maintain water chemistry of September 28, A.3.1.39 the IP2 SBO/Appendix R diesel generator cooling 2013 .1.40 NP3: 509 system per EPRI guidelines.

Enhance the Water Chemistry Control - Closed December 12, Cooling Water Program to maintain the IP2 and IP3 2015 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 IP2: NL-07-039 A.2.1.40 Secondary Program for IP2 to test sulfates monthly in September 28, B..1.41 the RWST with a limit of <150 ppb. 013 30 For aging management of the reactor vessel internals, SP2: NL-07-039 A.2.1.41 IPEC will (1) participate in the industry programs for September 28, A.3.1.41 investigating and managing aging effects on reactor 011 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 LRA SECTION

/ AUDIT ITEM 31 Additional P-T curves will be submitted as required 1P2: NL-07-039 A.2.2.1.2 per 10 CFR 50, Appendix G prior to the period of September 28, A.3.2.1.2 extended operation as part of the Reactor Vessel 2013 4.2.3 Surveillance Program. IP3:

December 12, 2_015 32 As required by 10 CFR 50.61 (b)(4), IP3 will submit a IP3: NL-07-039 A.3.2.1.4 plant-specific safety analysis for plate B2803-3 to the December 12, 4.2.5 NRC three years prior to reaching the RTPTS 2015 NL-08-127 screening criterion. Alternatively, the site may choose to implement the revised PTS rule when approved.

IP2: NL-07-039 A.2.2.2.3 33 At least 2 years prior to entering the period of extended operation, for the locations identified in LRA September 28, A.3.2.2.3 Table 4.3-13 (1P2) and LRA Table 4.3-14 (1P3), under 2011 4.3.3 the Fatigue Monitoring Program, IP2 and IP3 will NL-07-153 Audit item implement one or more of the following: IP3: 146 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. Representative CUF values from other plants, adjusted to or enveloping the IPEC plant specific external loads may be used ifdemonstrated applicable to IPEC.

4. An analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case) may be performed to determine a valid CUF.

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

NL-1 1-032 Attachment 2 Page 15 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 34 IP2 SBO / Appendix R diesel generator will be April 30, 2008 NL-07-078 2.1.1.3.5 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. __

35 Perform a one-time inspection of representative P2: NL-08-127 Audit Item sample area of IP2 containment liner affected by the September 28, 1973 event behind the insulation, prior to entering the 013 extended period of operation, to assure liner degradation is not occurring in this area.

Perform a one-time inspection of representative P3:

sample area of the IP3 containment steel liner at the December 12, juncture with the concrete floor slab, prior to entering 015 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 Audit359Item 36 Perform a one-time Inspection and evaluation of a Sptb 28, sample of potentially affected IP2 refueling cavity September 28, 359 concrete prior to the period of extended operation. 013 The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel.

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

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

37 Enhance the Containment Inservice Inspection (CII- P2: NL-08-127 Audit Item IWL) Program to include inspections of the September 28, 361 containment using enhanced characterization of 013 degradation (i.e., quantifying the dimensions of noted P3:

indications through the use of optical aids) during the December 12, period of extended operation. The enhancement 015 includes obtaining critical dimensional data of degradation where possible through direct measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections.

NL-11-032 Attachment 2 Page 16 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM future core IP2: N1L-08-143 4.2.1 38 For Reactor Vessel Fluence, should loading patterns invalidate the basis for the projected September 28, values of RTpts or CvUSE, updated calculations will 2013 be provided to the NRC. IP3:

December 12, 2015 39 Deleted NL-09-079 I'JLIUU-* I VU 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 B.1.27 December 12, 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 1assess I -i P2: NL-11-032 N/A 41 IPEC will inspect steam generators for both units to Prior to the condition of the divider plate assemoly, September 28, The examination technique used will be capable of 2023 detecting PWSCC in the steam generator divider plate assemblv welds. The steam generator divider plate IP3: Prior to inspections will be completed within the first ten years December 12, of the period of extended operation (PEO). 2025

-I

NL-11-032 Attachment 2 Page 17 of 18 COMMITMENT IMPLEMENTATION SOURCE I RELATED SCHEDULE LRA SECTION I_ I I / AUDIT ITEM NL-1 1-032 N/A 42 IPEC will develop a plan for each unit to address the P2: Prior to potential for cracking of the primary to secondary March 2024 pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two P3: Within the options.

Wirst 2 refueling QOtion 1 (Analysis) 3utaqes IPEC will perform an analytical evaluation of the Vollowing the steam generator tube-to-tubesheet welds in order to Deginning of the establish a technical basis for either determining that PEO.

the tubesheet claddinq and welds are not susceptible to PWSCC, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not reguired for reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary will be submitted as part of a license amendment request reguiring approval from the NRC.

Option 2 (Inspection)

IPEC will perform a one-time inspection of a representative number of tube-to-tubesheet welds in each steam -generatorto determine if PWSCC crackina is present. If weld cracking is identified:

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

b. An ongoing monitoring grogram will be established to Derform routine tube-to-tubesheet weld inspections for the remainina I.

life of the steam aenerators.

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

IPEC will use the NUREG/CR-6909 methodoloav in the evaluation of the limiting locations consisting of nickel alloy, if any.

NL-1 1-032 Attachment 2 Page 18 of 18

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 44 IPEC will include written explanation and ustification 60 das NL-1 1-032 N/A of any user intervention in future evaluations using the f issuance of WESTEMS "Design CUE" module. theratinq license.

Within 60 days NL-1 1-032 N/A 45 IPEC will not use the NB-3600 ootion of the Wf i ancof WESTEMS program in future design calculations until he renewed the issues identified during the NRC review of the eran program have been resolved, oieratin.

license.

46 Include in the IP2 ISI Program volumetric weld metal P2: NL-1 1-032 N/A inspections of ten socket welds in 2012 and of at least Prior to ten socket welds during each 1 0-year period of the September 28 period of extended operation. 013

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 ATTACHMENT 2 LRA 3.1 Indian Point License Renewal Application page 3.1-9

Indian Point Energy Center License Renewal Application Technical Information 3.1.2.2.10 Loss of Material due to Erosion Loss of material due to erosion could occur in steel steam generator feedwater impingement plates and supports exposed to secondary feedwater. The IPEC steam generator design does not employ a feedwater impingement plate. This item is not applicable to IPEC.

3.1.2.2.11 Cracking due to Flow-Induced Vibration This paragraph in NUREG-1800 applies to BWRs only.

3.1.2.2.12 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted Stress Corrosion Cracking (IASCC)

Cracking due to SCC and IASCC could occur in PWR stainless steel reactor internals exposed to reactor coolant. To manage cracking in vessel internals components, IPEC maintains the Water Chemistry Control - Primary and Secondary Program and will (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The IPEC commitment to these RVI programs is included in UFSAR Supplement, Appendix A, Sections A.2.1.41 and A.3.1.41.

3.1.2.2.13 Cracking due to Primary Water Stress Corrosion Cracking (PWSCC)

Cracking due to PWSCC in most components made of nickel alloy is managed by the Water Chemistry Control - Primary and Secondary, Inservice Inspection, and Nickel Alloy Inspection Programs. The Nickel Alloy Inspection Program implements the applicable NRC Orders and will implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. UFSAR Supplement, Appendix A, Sections A.2.1.20 and A.3.1.20 provide a commitment for this program.

3.1.2.2.14 Wall Thinning due to Flow-Accelerated Corrosion Wall thinning due to flow-accelerated corrosion could occur in steel feedwater inlet rings and supports. The Steam Generator Integrity Program manages loss of material due to flow-accelerated corrosion in the feedwater inlet ring using periodic visual inspections.

3.1.2.2.15 Changes in Dimensions due to Void Swelling Changes in dimensions due to void swelling could occur in stainless steel and nickel alloy reactor internal components exposed to reactor coolant. To manage changes in 3.0 Aging Management Review Results Page 3.1-9

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 ATTACHMENT 3 Table 3.1.1 - Indian Point License Renewal Application Table 3.1.1 - Reactor Coolant System, NUREG-1801 Vol. 1

Indian Point Energy Center License Renewal Application Technical Information Table 3.1.1: Reactor Coolant System, NUREG-1801 Vol. 1 Further Item Aging Effect/ Aging Management Component Evaluation Discussion Number Mechanism Programs Recommended 3.1.1-80 Cast austenitic stainless Loss of fracture Thermal Aging and No Consistent with NUREG-1801. The steel reactor vessel toughness due Neutron Irradiation Thermal Aging and Neutron Irradiation internals (e.g., upper to thermal aging Embrittlement of Embrittlement of Cast Austenitic Stainless internals assembly, lower and neutron CASS Steel (CASS) Program will manage loss of internal assembly, CEA irradiation fracture toughness of cast austenitic shroud assemblies, embrittlement stainless steel vessel internals components control rod guide tube exposed to reactor coolant and high assembly, core support neutron fluence.

shield assembly, lower grid assembly) 3.1.1-81 Nickel alloy or nickel-alloy Cracking due to Water Chemistry No Consistent with NUREG-1801. TheWater clad steam generator primary water Chemistry Control - Primary and divider plate exposed to stress corrosion Secondary Program manages cracking of reactor coolant cracking the nickel-alloy steam generator divider plate exposed to reactor coolant. The Water Chemistry Control - Primary and Secondary Program also manages cracking of the primary nozzle closure rings which form a temporary pressure boundary (nozzle dam) during outages.

3.1.1-82 Stainless steel steam Cracking due to Water Chemistry No Not applicable. The steam generator generator primary side stress corrosion primary side divider plate is composed of divider plate exposed to cracking nickel alloy.

reactor coolant 3.0 Aging Management Review Results Page 3.1-38

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 ATTACHMENT 4 NUREG-1801, Vol. 1 - Page IV B2-2: Reactor Vessel Internals (PWR) - Westinghouse

NUREG-1801, Rev. 1 IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM B2 Reactor Vessel Internals (PWR) - Westinghouse Structure Aging Effect/ Further Item Link and/or Material Environment Aging Management Program (AMP)

Mechanism Evaluation Component IV.B2-1 IV.B2.4-b Baffle/former Stainless Reactor coolant Changes in No further aging management review is No, but assembly steel dimensions/ void necessary if the applicant provides a licensee (R-124) swelling commitment in the FSAR supplement commitment Baffle and to (1) participate in the industry needs to be former plates programs for investigating and confirmed managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended IV B2-2 operation, submit an inspection plan for reactor internals to the NRC for review and approval.

September 2005

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 ATTACHMENT 5 NL-07-039 - Excerpt from Entergy LRA Submittal, dated April 23, 2007, regarding Commitments 28 - 32

Docket Nos. 50-247, 50-286 NL-07-039 Page 12 of 13

1. COMMITMENT IMPLEMENTATION Related SCHEDULE LRA Section 28 Enhance the Water Chemistry Control - Closed IP2: A.2.1.39 Cooling Water Program to maintain water chemistry of September 28, A.3.1.39 the IP2 SBO/Appendix R diesel generator cooling 2013 B.1.40 system per EPRI guidelines. IP3:

Enhance the Water Chemistry Control - Closed December 12, Cooling Water Program to maintain the IP2 and IP3 2015 security generator cooling water system pH within I limits specified by EPRI guidelines.

29 Enhance the Water Chemistry Control - Primary and IP2: A.2.1.40 Secondary Program for IP2 to test sulfates monthly in September 28, B.1.41 the RWST with a limit of <150 ppb. 013 30 For aging management of the reactor vessel internals, P2: A.2.1.41 IPEC will (1) participate in the industry programs for ' September 28, A.3.1.41 investigating and managing aging effects on reactor 011 internals; (2) evaluate and implement the results of lP3:

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.

31 Additional P-T curves will be submitted as required IP2: A.2.2.1.2 per 10 CFR 50, Appendix G prior to the period of September 28, A.3.2.1.2 extended operation as part of the Reactor Vessel 013 4.2.3 Surveillance Program. IP3:

December 12, 2015 32 As required by 10 CFR 50.61(b)(4), IP3 will submit a IP3: A.3.2.1.4 plant-specific safety analysis for plate B2803-3 to the December 12, 4.2.5 NRC three years prior to reaching the RTPTS 2015 screening criterion. Alternatively, the site may choose to implement the revised PTS (10 CFR 50.61) rule when approved, which would permit use of Regulatory Guide 1.99, Revision 3.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 ATTACHMENT 6 NL-11-107 - Entergy Letter, dated September 28, 2011, regarding Completion of Commitment # 30

Enter-qy Nuclear Northeast Indian Point Energy Center Entergy 450 Broadway, GSB P.O. Box 249 Buchanan, N.Y. 10511-0249 Tel (914) 788-2055 Fred Dacimo Vice President Operations License Renewal NL-1 1-107 September 28, 2011 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

License Renewal Application - Completion of Commitment #30 Regarding the Reactor Vessel Internals inspection Plan Indian Point Nuclear Generating Unit Nos. 2 and 3 Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64

REFERENCE:

1. Entergy Letter dated April 23, 2007, Fred Dacimo to Document Control Desk, "License Renewal Application" (NL-07-039)

2. Entergy Letter dated July 14, 2010, Fred Dacimo to Document Control Desk, "Amendment 9 to License Renewal Application (LAR) - Reactor Vessel Internals Program" (NL-10-063)

3. EPRI, Materials Reliability Program (MRP), Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227)

4. NRC, "Final safety Evaluation of EPRI Report, Materials Reliability Program Report 1016596, Revision 0, Pressurized Water reactor (PWR) Internals Inspection and Evaluation Guidelines" dated June 22, 2011

Dear Sir or Madam:

Entergy Nuclear Operations, Inc. applied for renewal of the Indian Point Nuclear Generating Unit Nos. 2 and 3 operating licenses by the reference 1 letter which included a list of regulatory commitments. The commitment list contained commitment # 30 for submitting an inspection plan for reactor vessel internals. Reference 2 provided the Indian Point Nuclear Generating Unit Nos. 2 and 3 Reactor Vessel Internals Program.

This letter contains the inspection plan satisfying the completion of commitment # 30 to the License Renewal Application regarding the Aging Management Programs for Reactor Vessel Internals. The Indian Point Energy Center (IPEC) Reactor Vessel Internals Inspection Plan was developed in accordance with the results of industry programs applicable to the reactor vessel internals and addresses the action items and conditions stated in the NRC Final Safety Evaluation of MRP-227 (Reference 4).

NL-1 1-107 Docket Nos. 50-247 and 50-286 Page 2 of 2 There are no new commitments identified in this submittal. If you have any questions, or require additional information, please contact Mr. Robert Walpole at 914-734-6710.

Si ly, FD/cbr

Attachment:

Indian Point Energy Center Reactor Vessel Internals Inspection Plan cc: Mr. William Dean, Regional Administrator, NRC Region I Mr. J. Boska, Senior Project Manager, NRC, NRR, DORL Mr. David Wrona, NRC Branch Chief, Engineering Review Branch I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel NRC Resident Inspectors Office, Indian Point Mr. Paul Eddy, NYS Dept. of Public Service Mr. Francis J. Murray, Jr., President and CEO, NYSERDA

ATTACHMENT TO NL-1 1-107 Indian Point Energy Center Reactor Vessel Internals Inspection Plan ENTERGY NUCLEAR OPERATIONS, INC INDIAN POINT NUCLEAR GENERATING UNITS 2 AND 3 DOCKET NOS. 50-247 & 50-286

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan 1

INTRODUCTION 1.1 Aging Management Program Inspection Plan The EPRI MRP guidelines define a supplemental inspection program for managing aging effects on the reactor vessel internals and were used to develop this inspection plan for IPEC Units 2 and 3. The EPRI MRP Reactor Internals Focus Group developed the MRP-227 Guidelines to support the demonstration of continued functionality, with requirements for inspections to detect the effects of aging along with requirements for the evaluation of detected aging effects, if any.

The development of MRP-227 combined the results of component functionality assessments with component accessibility, operating experience, existing evaluations and prior examination results to determine the appropriate aging management methods, initial examination timing and the need and timing of subsequent inspections and identified the components and locations for supplemental examination.

In accordance with MRP-227, this inspection plan includes:

• Identification of items for inspection,

• Specification of the type of examination appropriate for each degradation mechanism,

• Specification of the required level of examination qualification,

• Schedule of initial inspection and frequency of subsequent inspections,

" Criteria for sampling and coverage,

• Criteria for expansion of scope if unanticipated indications are found,

• Inspection acceptance criteria,

• Methods for evaluating examination results not meeting the acceptance criteria,

" Updating the program based on industry-wide results, and

• Contingency measures to repair, replace or mitigate.

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NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I hidian Point Energy Center Reactor Vessel InternalsInspection Plan 2

BACKGROUND OF IPEC REACTOR VESSEL INTERNALS DESIGN This section provides a summary of the design characteristics for the IPEC Westinghouse PWR internals.

2.1 Westinghouse Internals Design Characteristics A schematic view of a typical set of Westinghouse-designed PWR internals is Figure 2-1. More detailed views of selected internals components are Figures 2-2 through 2-16 at the end of this section. These figures are typical and are not an exact representation of the IPEC internals.

To help in the categorization of IPEC internals design characteristics as discussed in MRP-227 Section 3.1.3, the following information is provided. IPEC Units 2 and 3 are Westinghouse four loop plants with a downflow baffle-barrel region flow design, and a top hat design upper support plate. Unit 2 had an original thermal output of 2758 MWth and Unit 3 had an original thermal output of 3025 MWth.

Page 2

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan ROD TRAVEL HOUSING CONTROL ROD INSTRUMENTATION DRIVE MECHANISM PORTS THERMAL SLEEVE UPPER SUPPORT PLATE LIFTING LUG INTERNALS CLOSURE HEAD SUPPORT ASSEMBLY LEDGE HOLD-DOWN SPRING CORE BARREL

- CONTROL ROD GUIDE TUBE SUPPORT COLUMN CONTROL ROD DRIVE SHAFT UPPER CORE PLATE OUTLET NOZZLE INLET NOZZLE BAFFLE RADIAL - CONTROL ROD SUPPORT CLUSTER (WmrHDRAWI BAFFLE CORE SUPPORT -- ACCESS PORT COLUMNS INSTRUMENTATION - REACTOR VESSEL THIMBLE GUIDES RADIAL SUPPORT CORE SUPPORT -

CORE PLATE Figure 2-1 Overview of typical Westinghouse internals Page 3

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Westinghouse internals consist of two basic assemblies: an upper internals assembly that is removed during each refueling operation to obtain access to the reactor core and a lower internals assembly that can be removed following a complete core off-load.

The reactor core is positioned and supported by the upper internals and lower internals assemblies. The individual fuel assemblies are positioned by fuel alignment pins in the upper core plate and the lower core plate. These pins control the orientation of the core with respect to the upper and lower internals assemblies. The lower internals are aligned with the upper internals by the upper core plate alignment pins and secondarily by the head/vessel alignment pins. The lower internals are aligned to the vessel by the lower radial support/clevis assemblies and by the head/vessel alignment pins. Thus, the core is aligned with the vessel by a number of interfacing components.

The lower internals assembly is supported in the vessel by clamping to a ledge below the vessel-head mating surface and is closely guided at the bottom by radial support/clevis assemblies. The upper internals assembly is clamped at this same ledge by the reactor vessel head. The bottom of the upper internals assembly is closely guided by the core barrel alignment pins of the lower internals assembly.

Upper Internals Assembly The major sub-assemblies that constitute the upper internals assembly are the: (1) upper core plate (UCP); (2) upper support column assemblies; (3) control rod guide tube assemblies; and (4) upper support plate (USP).

During reactor operation, the upper internals assembly is preloaded against the fuel assembly springs and the internals hold down spring by the reactor vessel head pressing down on the outside edge of the USP. The USP acts as the divider between the upper plenum and the reactor vessel head and as a relatively stiff base for the rest of the upper internals. The upper support columns and the control rod guide tubes are attached to the USP. The UCP, in turn, is attached to the upper support columns. The USP design at IPEC is designated as a top hat design.

The UCP is perforated to permit coolant to pass from the core below into the upper plenum between the USP and the UCP. The coolant then exits through the outlet nozzles in the core barrel. The UCP positions and laterally supports the core by fuel alignment pins extending below the plate. The UCP contacts and preloads the fuel assembly springs and thus maintains contact of the fuel assemblies with the lower coreeplate (LCP) during reactor operation.

The upper support columns vertically position the UCP and are designed to take the uplifting hydraulic flow loads and fuel spring loads on the UCP. The control rod guide tubes are bolted to the USP and pinned at the UCP so they can be easily removed if replacement is desired. The control rod guide tubes are designed to guide the control rods in and out of the fuel assemblies to control power generation. Guide tube cards are located within each control rod guide tube Page 4

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan to guide the absorber rods. The control rod guide tubes are also slotted in their lower sections to allow coolant exiting the core to flow into the upper plenum.

The upper instrumentation columns are bolted to the USP. These columns support the thermocouple guide tubes that lead the thermocouples from the reactor head through the upper plenum to just above the UCP.

The UCP alignment pins locate the UCP laterally with respect to the lower internals assembly.

The pins must laterally support the UCP so that the plate is free to expand radially and move axially during differential thermal expansion between the upper internals and the core barrel. The UCP alignment pins are the interfacing components between the UCP and the core barrel.

Lower Internals Assembly The fuel assemblies are supported inside the lower internals assembly on top of the LCP. The functions of the LCP are to position and support the core and provide a metered control of reactor coolant flow into each fuel assembly. The LCP is elevated above the lower support casting by support columns and bolted to a ring support attached to the inside diameter of the core barrel. The support columns transmit vertical fuel assembly loads from the LCP to the much thicker lower support casting. The function of the lower support casting is to provide support for the core. The lower support casting is welded to and supported by the core barrel, which transmits vertical loads to the vessel through the core barrel flange.

The primary function of the core barrel is to support the core. A large number of components are attached to the core barrel, including the baffle/former assembly, the core barrel outlet nozzles, the thermal shields, the alignment pins that engage the UCP, the lower support casting, and the LCP. The lower radial support/clevis assemblies restrain large transverse motions of the core barrel but at the same time allow unrestricted radial and axial thermal expansion.

The baffle and former assembly consists of vertical plates called baffles and horizontal support plates called formers. The baffle plates are bolted to the formers by the baffle/former bolts, and the formers are attached to the core barrel inside diameter by the barrel/former bolts. Baffle plates are secured to each other at selected corners by edge bolts. In addition, at IPEC, corner brackets are installed behind and bolted to the baffle plates. The baffle/former assembly forms the interface between the core and the core barrel. The baffles provide a barrier between the core and the former region so that a high concentration of flow in the core region can be maintained.

A secondary benefit is to reduce the neutron flux on the vessel.

The function of the core barrel outlet nozzles is to direct the reactor coolant, after it leaves the core, radially outward through the reactor vessel outlet nozzles. The core barrel outlet nozzles are located in the upper portion of the core barrel directly below the flange and are attached to the core barrel, each in line with a vessel outlet nozzle.

Page 5

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan Additional neutron shielding of the reactor vessel is provided in the active core region by thermal shields attached to the outside of the core barrel.

A flux thimble is a long, slender stainless steel tube that passes from an external seal table, through a bottom mounted nozzle penetration, through the lower internals assembly, and finally extends to the top of a fuel assembly. The flux thimble provides a path for a neutron flux detector into the core and is subjected to reactor coolant pressure and temperature on the outside surface and to atmospheric conditions on the inside. The flux thimble path from the seal table to the bottom mounted nozzles is defined by flux thimble guide tubes, which are part of the primary pressure boundary and not part of the internals. The bottom-mounted instrumentation (BMI) columns provide a path for the flux thimbles from the bottom of the vessel into the core. The BMI columns align the flux thimble paths with instrumentation thimbles in the fuel assembly.

In the upper internals assembly, the upper support plate, the upper support columns, and the upper core plate are considered core support structures. In the lower internals assembly, the lower core plate, the lower support casting, the lower support columns, the core barrel including the core barrel flange, the radial support/clevis assemblies, the baffle plates, and the former plates are classified as core support structures.

Z Wear Area Figure 2-2 Typical Westinghouse control rod guide card (17x17 fuel assembly)

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NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan 1p I D Lower Flange Weld II II Figure 2-3 Typical Westinghouse control rod guide tube assembly Page 7 I

NL- 11-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Flange Weld Axial Weld Upper Core Barrel to Lower Core Barrel Circumferential Weld Lower Barrel Axial Weld Lower Barrel Circumferential Weld Lower Barrel Axial Weld Core Barrel to Support Plate Weld Figure 2-4 Major fabrication welds in typical Westinghouse core barrel Page 8

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan CORME EDGE BRAOOMT BAFFLE TO FORME BOLT Figure 2-5 Bolt locations in typical Westinghouse baffle-former-barrel structure.

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NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan (D

(U 0

Figure 2-6 Baffle-edge bolt and baffle-former bolt locations at high fluence seams in bolted baffle-former assembly Page 10

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan T

High Fluence Seams Figure 2-7 High fluence seam locations in Westinghouse baffle-former assembly Page 11

NL- 11-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Potential Gaps at Baffle-Former Plate Levels Figure 2-8 Exaggerated view of void swelling induced distortion in Westinghouse baffle-former assembly.

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NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan Figure 2-9 Vertical displacement of Westinghouse baffle plates caused by void swelling.

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NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan CORE BARREL Figure 2-10 Schematic cross-sections of the Westinghouse hold-down springs Page 14

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Core Barrel Thermal Shield Thermal Shield Flexure Core Support Figure 2-11 Location of Westinghouse thermal shield flexures Page 15

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Lower Core Plate Lower Core Support Structure Core Support Plate (Forging)

Figure 2-12 Schematic indicating location of Westinghouse lower core support structure. Additional details shown in Figure 2-13 LOWER CORE PLATE DIFFUSER PLATE

• CORE SUPPORT PLATE/FORGING BOTTOM MOUNTED INSTRUMENTATION COLUMN Figure 2-13 Westinghouse lower core support structure and bottom mounted instrumentation columns. Core support column bolts fasten the core support columns to the lower core plate Page 16

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan B

Figure 2-14 Typical Westinghouse core support column. Core support column bolts fasten the top of the support column to the lower core plate M

E- 1711 t

Figure 2-15 Examples of Westinghouse bottom mounted instrumentation column designs Page 17

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan

/

Figure 2-16 Typical Westinghouse thermal shield flexure Page 18

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan 3

INSPECTION PLAN

SUMMARY

Management of component aging effects includes actions to prevent or control aging effects, review of operating experience to better understand the potential for aging effects to occur, inspections to detect the onset of aging effects in susceptible components, protocols for evaluation and remediation of the effects of aging, and procedures to ensure component aging effects are managed in a coordinated program.

3.1 Component Inspection and Evaluation Overview This discussion summarizes the guidance of the MRP Inspection & Evaluation (I&E) guidelines necessary to understand implementation but does not duplicate the full discussion of the technical bases. MRP-227 and its supporting documents provide further information on the technical bases of the program.

MRP-227 establishes four groups of reactor internals components with respect to inspections:

Primary, Expansion, Existing Programs and No Additional Measures, as summarized below.

" Primary: Those PWR internals that are highly susceptible to the effects of at least one of the eight aging mechanisms were placed in the Primary group. The aging management requirements that are needed to ensure functionality of Primary components are described in the I&E guidelines. The Primary group also includes components which have shown a degree of tolerance to a specific aging degradation effect, but for which no highly susceptible component exists or for which no highly susceptible component is accessible.

• Expansion: Those PWR internals that are highly or moderately susceptible to the effects of at least one of the eight aging mechanisms, but for which a functionality assessment has shown a degree of tolerance to those effects, were placed in the Expansion group. The schedule for implementation of aging management requirements for Expansion components will depend on the findings from the examinations of the Primary components.

" Existing Programs: Those PWR internals that are susceptible to the effects of at least one of the eight aging mechanisms and for which generic and plant-specific existing AMP elements are capable of managing those effects, were placed in the Existing Programs group.

No Additional Measures: Those PWR internals for which the effects of all eight aging mechanisms are below the screening criteria were placed in the No Additional Measures group. Items categorized as Category A in MRP-191 are those for which aging effects are below the screening criteria, so that aging degradation significance is minimal. Primary, expansion, and Page 19

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel hIternals Inspection Plan existing examinations verify that the chemical control program has been effective at controlling stress corrosion cracking and loss of material due to corrosion for Category A components.

Additional components were placed in the No Additional Measures group as a result of Failure Modes, Effects and Criticality Analysis (FMECA) and the functionality assessment. No further action is required for managing the aging of the No Additional Measures components. However, any core support structures subject to ASME Section XI Examination Category B-N-3 requirements continue to be subject to those ASME Code requirements throughout the period of extended operation.

The inspections required for Primary and Expansion components were selected from visual, surface and volumetric examination methods that are applicable and appropriate for the expected degradation effect (e.g. cracking caused by particular mechanisms, loss of material caused by wear). The inspection methods include: Visual examinations (VT-3, VT-1, EVT-I), surface examinations, volumetric examinations (specifically UT) and physical measurements. MRP-227 provides detailed justification for the components selected for inspection and the specific examination methods selected for each. The MRP-228 report, PWR Internals Inspection Standards, provides detailed examination standards and any inspection technical justification or inspection personnel training requirements.

3.2 Inspection and Evaluation Requirements for Primary Components The inspection requirements for Primary Components at IPEC Units 2 and 3 from MRP-227 are provided in Table 5-2.

3.3 Inspection and Evaluation Requirements for Expansion Components The inspection requirements for Expansion Components at IPEC Units 2 and 3 from MRP-227 are provided in Table 5-3.

3.4 Inspections of Existing Program Components The list of Existing Program Components at IPEC Units 2 and 3 from MRP-227 are provided in Table 5-4. This includes components in the Section XI ISI Program for IPEC Units 2 and 3 designated as B-N-2 and B-N-3 locations.

The Reactor Vessel Component Inspection Plan conducted as part of the ISI program for IPEC Units 2 and 3 is provided in Table 5-6. The components are inspected as part of the ISI Program.

The ISI Program inspections are implemented in accordance with ASME Section XI schedule requirements.

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NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan 3.5 Examination Systems Equipment, techniques, procedures and personnel used to perform examinations required under this program will be consistent with the requirements of MRP-228. Indications detected during these examinations will be characterized and reported in accordance with the requirements of MRP-228.

3.6 Information Supplied in Response to the NRC Safety Evaluation of MRP-227 As part of the NRC Final Safety Evaluation of MRP-227, a number of action items and conditions were specified by the staff. Table 5-8 documents the IPEC response to the NRC Final Safety Evaluation of MRP-227. Wherever possible, these items have been addressed in the appropriate sections of this document. All NRC action items and conditions not addressed elsewhere in this document are discussed in this section.

SER Section 4.2.1. Applicant/Licensee Action Item 1 IPEC has assessed its plant design and operating history and has determined that MRP-227 is applicable to the facility. The assumptions regarding plant design and operating history made in MRP-191 are appropriate for IPEC and there are no differences in component inspection categories at IPEC. IPEC Unit 2 (IP2) had the first 8 years of operation with a high leakage core loading pattern. IPEC Unit 3 (IP3) had the first 10 years of operation with a high leakage core loading pattern. The FMECA and functionality analyses were based on the assumption of 30 years of operation with high leakage core loading patterns; therefore, IPEC is bounded by the assumptions in MRP-191. IPEC has always operated as a base-load plant which operates at fixed power levels and does not vary power on a calendar or load demand schedule.

SER Section 4.2.2. Applicant/Licensee Action Item 2 IPEC reviewed the information in Table 4-4 of MRP-191 and determined that this table contains all of the RVI components that are within the scope of license renewal. This is shown in Table 5-7.

SER Section 4.2.3. Applicant/Licensee Action Item 3 At IP2, the original X750 guide tube support pins (split pins) were replaced in 1995 with an improved X750 Revision B material made from more selective material with more continuous carbide coverage grain boundaries and tighter quality controls, to provide greater resistance to stress corrosion cracking. At IP3 the original X750 guide tube support pins (split pins) were replaced in 2009 (after 33 years in service) with cold-worked 316 stainless steel. The cold-worked 316 stainless steel is a significant improvement over the X750. At IPEC the effects of Page 21

NL- 11-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan aging on these components will be managed in the period of extended operation based on industry experience and plant specific evaluations.

SER Section 4.2.4, Applicant/Licensee Action Item 4 This action item does not apply to Westinghouse designed units.

SER Section 4.2.5, Applicant/Licensee Action Item 5 The IPEC plant specific acceptance criteria for hold down springs and an explanation of how the proposed acceptance criteria are consistent with the IPEC licensing basis and the need to maintain the functionality of the hold down springs under all licensing basis conditions will be developed prior to the first required physical measurement. In accordance with SER Section 4.2.5, IPEC will submit this information to the NRC as part of the submittal to apply the approved version of MRP-227.

SER Section 4.2.6, Applicant/Licensee Action Item 6 This action item does not apply to Westinghouse designed units.

SER Section 4.2.7. Applicant/Licensee Action Item 7 The IPEC plant specific analyses to demonstrate the lower support column bodies will maintain their functionality during the period of extended operation will consider the possible loss of fracture toughness in these components due to thermal and irradiation embrittlement. The analyses will be consistent with the IPEC licensing basis and the need to maintain the functionality of the lower support column bodies under all licensing basis conditions of operation. In accordance with SER Section 4.2.7, IPEC will submit this information to the NRC as part of the submittal to apply the approved version of MRP-227.

SER Section 4.2.8. Applicant/Licensee Action Item 8 This document includes an inspection plan which addresses the identified plant-specific action items contained in the NRC Final Safety Evaluation for MRP-227. IPEC is not requesting any deviations from the guidance provided in MRP-227, as approved by the NRC.

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NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel InternalsInspection Plan 4

EXAMINATION ACCEPTANCE AND EXPANSION CRITERIA 4.1 Examination Acceptance Criteria 4.1.1 Visual (VT-3) Examination Visual (VT-3) examination is an appropriate NDE method for the detection of general degradation conditions in many of the susceptible components. The ASME Code Section XI, Examination Category B-N-3, provides a set of relevant conditions for the visual (VT-3) examination of removable core support structures in Section IWB. These are:

1. structural distortion or displacement of parts to the extent that component function may be impaired;

2. loose, missing, cracked, or fractured parts, bolting, or fasteners;

3. corrosion or erosion that reduces the nominal section thickness by more than 5%;

4. wear of mating surfaces that may lead to loss of function; and

5. structural degradation of interior attachments such that the original cross-sectional area is reduced more than 5%.

For components in the Existing Programs group, these general relevant conditions are sufficient.

However, for components where visual (VT-3) is specified in the Primary or the Expansion group, more specific descriptions of the relevant conditions are provided in Table 5-5 for the benefit of the examiners. One or more of these specific relevant condition descriptions may be applicable to the Primary and Expansion components listed in Tables 5-2 and 5-3.

The examination acceptance criteria for components requiring visual (VT-3) examination is thus the absence of any of the relevant condition(s) specified in Table 5-5.

The disposition can include a supplementary examination to further characterize the relevant condition, an engineering evaluation to show that the component is capable of continued operation with a known relevant condition, or repair/replacement to remediate the relevant condition.

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NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan 4.1.2 Visual (VT-1) Examination Visual (VT-1) examination is defined in the ASME Code Section XI as an examination "conducted to detect discontinuities and imperfections on the surface of components, including such conditions as cracks, wear, corrosion, or erosion." The acceptance criterion for any visual (VT-1) examinations is the absence of any relevant conditions defined by the ASME Code, as supplemented by more specific plant inservice inspection requirements.

4.1.3 Enhanced Visual (EVT-1) Examination Enhanced visual (EVT-l) examination has the same requirements as the ASME Code Section XI visual (VT-1) examination, with additional requirements given in the Inspection Standard, MRP-228. These enhancements are intended to improve the detection and characterization of discontinuities taking into account the remote visual aspect of reactor internals examinations. As a result, EVT- 1 examinations are capable of detecting small surface-breaking cracks and sizing surface crack length when used in conjunction with sizing aids (e.g. landmarks, ruler, and tape measure). EVT- 1 examination is the appropriate NDE method for detection of cracking in plates or their welded joints. Thus the relevant condition applied for EVT- 1 examination is the same as for cracking in Section XI which is crack-like surface-breaking indications.

Therefore, until such time as engineering studies provide a basis by which a quantitative amount of degradation can be shown acceptable for the specific component, any observed relevant condition must be dispositioned. In the interim, the examination acceptance criterion is the absence of any detectable surface-breaking indication.

4.1.4 Surface Examination Surface ET (eddy current testing) examination is specified as an alternative or as a supplement to visual examinations. No specific acceptance criteria for surface (ET) examination of PWR internals locations are provided in the ASME Code Section XI. Since surface ET is employed as a signal-based examination, a technical justification per the Inspection Standard, MRP-228 provides the basis for detection and length sizing of surface-breaking or near-surface cracks. The signal-based relevant indication for surface (ET) is thus the same as the relevant condition for enhanced visual (EVT- 1) examination. The acceptance criteria for enhanced visual (EVT- 1) examinations in 4.1.3 (and accompanying entries in Table 5-5) are therefore applied when this method is used as an alternative or supplement to visual examination.

4.1.5 Volumetric Examination The intent of volumetric examinations specified for bolts and pins is to detect planar defects. No flaw sizing measurements are recorded or assumed in the acceptance or rejection of individual Page 24

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 hidian Point Energy Center Reactor Vessel Internals Inspection Plan bolts or pins. Individual bolts or pins are accepted based on the absence of relevant indications established as part of the examination technical justification. When a relevant indication is detected in the cross-sectional area of the bolt or pin, it is assumed to be non-functional and the indication is recorded. A bolt or pin that passes the criterion of the examination is considered functional.

Because of this pass/fail acceptance of individual bolts or pins, the examination acceptance criterion for volumetric (UT) examination of bolts and pins is based on a reliable detection of indications as established by the individual technical justification for the proposed examination.

This is in keeping with current industry practice. For example, planar flaws on the order of 30%

of the cross-sectional area have been determined reliably detectable in previous bolt NDE technical justifications for baffle-former bolting.

Bolted and pinned assemblies are evaluated for acceptance based on a plant specific evaluation.

4.2 Physical Measurements Examination Acceptance Criteria Continued functionality can be confirmed by physical measurements where, for example, loss of material caused by wear, loss of pre-load of clamping force caused by various degradation mechanisms, or distortion/deflection caused by void swelling may occur. For Westinghouse designs, tolerances are available on a design or plant-specific basis. Specific acceptance criteria will be developed as required, and thus are not provided generically in this plan.

4.3 Expansion Criteria The criterion for expanding the scope of examination from the Primary components to their linked Expansion components is contained in Table 5-5 for IPEC.

Page 25

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 hidian Point Energy Center Reactor Vessel Internals Inspection Plan 5

TABLES Table 5-1 Indian Point 2 & 3 Component Cross Reference Table 5-2 Primary Components at IPEC Units 2 and 3 Table 5-3 Expansion Components at IPEC Units 2 and 3 Table 5-4 Existing Program Components at IPEC Units 2 and 3 Table 5-5 Examination Acceptance and Expansion Criteria at IPEC Units 2 and 3 Table 5-6 Reactor Vessel Component ISI Program Inspection Plan for IPEC Units 2 and 3 Table 5-7 List of IPEC Reactor Vessel Interior Components and Materials Based on MRP-191 - Table 4-4 Table 5-8 IPEC Response to the NRC Final Safety Evaluation of MRP-227 Page 26

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 hidian Point Energy Center Reactor Vessel hiternalshIspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 1 Core Baffle/Former Assembly - Lower Internals Baffle-Former Assembly -

Bolts Assembly - Baffle and Baffle-Edge Bolts (Table Former Assembly 4-3 and 5-3)

Baffle-Edge Bolts Baffle-Former Assembly -

Baffle-Former Bolts (Table Baffle-Former Bolts 4-3 and 5-3) 2 Core Baffle/Former Assembly - Lower Internals Baffle-Former Assembly -

Plates Assembly - Baffle and Assembly (Table 4-3 and Former Assembly 5-3)

Baffle Plates Former Plates 3 Core Barrel Assembly - Bolts and Lower Internals Core Barrel Assembly -

Screws Assembly - Baffle and Barrel-Former Bolts (Table Former Assembly 4-6)

Barrel-Former Bolts 4 Core Barrel Assembly - Axial Lower Internals Thermal Shield Assembly Flexure Plates (Thermal Shield Assembly - Neutron - Thermal Shield Flexures Flexures) Panels/Thermal Shield (Table 4-3 and 5-3)

Thermal Shield Flexures 5 Core Barrel Assembly - Flange Lower Internals Core Barrel Assembly -

Assembly - Core Core Barrel Flange (Table Barrel 4-6 and 4-9)

Core Barrel Flange Page 27

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 6 Core Barrel Assembly - Ring Lower Internals None Assembly - Core Core Barrel Assembly - Shell Barrel Core Barrel Assembly - Thermal Upper Core Barrel Shield Lower Core Barrel Lower Internals Assembly - Neutron panels/thermal shield Thermal shield 7 Core Barrel Assembly - Lower None Core Barrel Assembly -

Core Barrel Flange Weld Lower Core Barrel Flange Lower Internals Weld (Table 4-6)

Core Barrel Assembly - Upper Assembly - Core Core Barrel Flange Weld Barrel Core Barrel Assembly -

Upper Core Barrel Flange Core Barrel Flange Weld (Table 4-3 and 5-3) 8 Core Barrel Assembly - Outlet Lower Internals Core Barrel Assembly -

Nozzles Assembly - Core Core Barrel Outlet Nozzles Barrel (Table 4-6)

Core Barrel Outlet Nozzles 9 Lower Internals Assembly - Interfacing Alignment and Interfacing Clevis Insert Bolt Components - Components - Clevis Insert Interfacing Bolts (Table 4-9)

Components Clevis Insert Bolts Page 28

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel InternalsInspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 10 Lower Internals Assembly - Interfacing None Clevis Insert Components -

Interfacing Components Clevis Inserts 11 Lower Internals Assembly - Lower Internals None Intermediate Diffuser Plate Assembly - Diffuser Plate Diffuser Plate 12 Lower Internals Assembly - Fuel Lower Internals None Alignment Pin Assembly - Lower Core Plate and Fuel Alignment Pins Fuel Alignment Pins 13 Lower Internals Assembly - Lower Internals Lower Internals Assembly Lower Core Plate Assembly - Lower - Lower Core Plate (Table Core Plate and Fuel 4-9, 2 places)

Alignment Pins Lower Core Plate Page 29

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 14 Lower Internals Assembly - Lower Internals None Assembly - Lower "Lower Core Support Castings Support Casting or Forging "Column Cap None Lower Support "Lower Core Support Column Casting Bodies None Lower Internals Lower Support Assembly -

Assembly - Lower Lower Support Column Support Column Bodies (Cast) (Table 4-6)

Assembly Lower Support Column Bodies 15 Lower Internals Assembly - Lower Internals Lower Support Assembly -

Lower Core Support Plate Assembly - Lower Lower Support Column Column Bolt Support Column Bolts (Table 4-6)

Assembly Lower Support Column Bolts 16 Lower Internals Assembly - Lower Internals None Lower Core Support Plate Assembly - Lower Column Sleeves Support Column Assembly Lower Support Column Sleeves 17 Lower Internals Assembly - Lower Internals None Radial Key Assembly - Radial Support Keys Radial Support Keys Page 30

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 18 Lower Internals Assembly - Lower Internals None Secondary Core Support Assembly - Secondary Core Support (SCS)

Assembly SCS Base Plate 19 RCCA Guide Tube Assembly - Upper Internals None Bolt Assembly - Control Rod Guide Tube Assemblies and Flow Downcomers Bolts 20 RCCA Guide Tube Assembly - Upper Internals Control Rod Guide Tube Guide Tube (including Lower Assembly - Control Assembly - Lower Flange Flange Welds) Rod Guide Tube Welds (Table 4-3 and 5-3)

Assemblies and Flow Downcomers Flanges - lower 21 RCCA Guide Tube Assembly - Upper Internals Control Rod Guide Tube Guide Plates Assembly - Control Assembly - Guide Plates Rod Guide Tube (Cards) (Table 4-3 and 5-3)

Assemblies and Flow Downcomers Guide Plates/Cards 22 RCCA Guide Tube Assembly - Upper Internals None Support Pin Assembly - Control Rod Guide Tube Assemblies and Flow Downcomers Guide Tube Support Pins Page 31

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 23 Core Plate Alignment Pin Interfacing Alignment and Interfacing Components - Components - Upper Core Interfacing Plate Alignment Pins Components (Table 4-9)

Upper Core Plate Alignment Pins 24 Head/Vessel Alignment Pin Interfacing None Components -

Interfacing Components Head and Vessel Alignment Pins 25 Hold-down Spring Interfacing Alignment and Interfacing Components - Components - Internals Interfacing Hold Down Spring (Table Components 4-3 and 5-3)

Internals Hold Down Spring 26 Mixing Devices Upper Internals None Assembly - Mixing

- Support Column Orifice Base Devices

- Support Column Mixer Mixing devices 27 Support Column Upper Internals None Assembly - Upper Support Column Assemblies Column Bodies Page 32

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment 1 Indian Point Energy Center Reactor Vessel hiternals hIspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 28 Upper Core Plate, Fuel Alignment Upper Internals None Pin Assembly - Upper Core Plate and Fuel Alignment Pins Fuel Alignment Pins 29 Upper Support Plate, Support Upper Internals Upper Internals Assembly Assembly (Including Ring) Assembly - Upper - Upper Support Ring or Support Plate Skirt (Table 4-9)

Assembly Upper Support Plate 30 Upper Support Column Bolt Upper Internals None Assembly - Upper Support Column Assemblies Bolts 31 Bottom Mounted Instrumentation Lower Internals Bottom Mounted Column Assembly - Bottom- Instrumentation System -

Mounted Bottom Mounted Instrumentation (BMI) Instrumentation (BMI)

Column Assemblies Column Bodies (Table 4-6)

BMI Column Bodies 32 Flux Thimble Guide Tube Lower Internals Bottom Mounted Assembly - Flux Instrumentation System -

Thimbles (Tubes) Flux Thimble Tubes (Table 4-9)

Flux Thimbles (Tubes)

Page 33

NL-11-107 Docket Nos. 50-247 and 50-286 Attachment 1 hidian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-1 Indian Point 2 & 3 Component Cross Reference Item Letter NL-10-063 Component MRP-191 Table 4-4 MRP-227 33 Thermocouple Conduit Upper Internals None Assembly - Upper Instrumentation Conduit and Support Conduits Page 34

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-2 Primary Components at IPEC Units 2 and 3 Effect Examination Item Applicability (Mechanism) Expansion Link Method/Frequency Examination Coverage Control Rod Guide Tube IPEC Units 2 and Loss of Material None Visual (VT-3) examination no 20% examination of the Assembly 3 (Wear) later than 2 refueling outages number of CRGT Guide plates (cards) from the beginning of the assemblies, with all guide license renewal period, cards within each selected Subsequent examinations are CRGT assembly examined.

required on a ten-year interval.

See Figure 2-2 Control Rod Guide Tube IPEC Units 2 and Cracking (SCC, Bottom-mounted Enhanced visual (EVT-1) 100% of outer (accessible)

Assembly 3 Fatigue) instrumentation examination to determine the CRGT lower flange weld Lower flange welds (BMI) column presence of crack-like surface surfaces and adjacent base bodies, flaws in flange welds no later metal.

Lower support than 2 refueling outages from column bodies the beginning of the license See Figure 2-3 (cast) renewal period and subsequent examination on a ten-year interval.

Core Barrel Assembly IPEC Units 2 and Cracking (SCC) None Enhanced visual (EVT- I) 100% of one side of the Upper core barrel flange weld 3 examination, no later than 2 accessible surfaces of the refueling outages from the selected weld and adjacent beginning of the license renewal base metal.

period and subsequent examination on a ten-year See Figure 2-4 interval.

Page 35

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-2 Primary Components at IPEC Units 2 and 3 Effect Examination Item Applicability (Mechanism) Expansion Link Method/Frequency Examination Coverage Baffle-Former Assembly IPEC Units 2 and Cracking (IASCC, None Visual (VT-3) examination, with Bolts and locking devices Baffle-edge bolts 3 Fatigue) that results baseline examination between on high fluence seams.

in 20 and 40 EFPY and subsequent 100% of components

" Lost or broken examinations on a ten-year accessible from core side.

locking devices interval. 75% of a component's total

" Failed or missing (accessible + inaccessible) bolts inspection area or volume

" Protrusion of bolt will be examined or, when heads addressing a set of like components (e.g., bolting),

that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined.

ISee Figure 2-5 Page 36

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I hidian Point Energy Center Reactor Vessel hiternalshIspection Plan Table 5-2 Primary Components at IPEC Units 2 and 3 A ibit Effect Examination Examination Coverage Item Applicability (Mechanism) Expansion Link Method/Frequency ExaminationCoverage Baffle-Former Assembly IPEC Units 2 and Cracking (IASCC, Lower support Baseline volumetric (UT) 100% of accessible bolts or Baffle-former bolts 3 Fatigue) column bolts, examination between 25 and 35 as supported by plant-Barrel-former bolts EFPY, with subsequent specific justification. Heads examination after 10 years to accessible from the core confirm stability of bolting side. UT accessibility may pattern, be affected by complexity of head and locking device designs. 75% of a component's total (accessible + inaccessible) inspection area or volume will be examined or, when addressing a set of like components (e.g., bolting),

that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined.

I See Figures 2-5 and 2-6.

Page 37

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-2 Primary Components at IPEC Units 2 and 3 Effect Examination Item Applicability (Mechanism) Expansion Link Method/Frequency Examination Coverage Baffle-Former Assembly IPEC Units 2 and Distortion (Void None Visual (VT-3) examination to Core side surface as Assembly 3 Swelling), or check for evidence of distortion, indicated.

Cracking (IASCC) with baseline examination that results in between 20 and 40 EFPY and See Figures 2-6, 2-7, 2-8

• Abnormal subsequent examinations on a and 2-9.

interaction with ten-year interval.

fuel assemblies

- Gaps along high fluence baffle joint

- Vertical displacement of baffle plates near high fluence joint

- Broken or damaged edge bolt locking systems

-along high fluence baffle joint Alignment and Interfacing IPEC Units 2 and Distortion (Loss of None Direct measurement of spring Measurements should be Components 3 Load) height within three cycles of the taken at several points Internals hold down spring beginning of the license renewal around the circumference of Note: This period. If the first set of the spring, with a mechanism was not measurements is not sufficient to statistically adequate strictly identified in determine life, spring height number of measurements at the original list of measurements must be taken each point to minimize age-related during the next two outages, in uncertainty. Replacement degradation order to extrapolate the expected of 304 springs by 403 mechanisms, spring height to 60 years. springs is required when the spring stiffness is determined to relax beyond design tolerance.

See Figure 2-10 Page 38

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-2 Primary Components at IPEC Units 2 and 3 Effect Examination Item Applicability (Mechanism) Expansion Link Method/Frequency Examination Coverage Thermal Shield Assembly IPEC Units 2 and Cracking (Fatigue) None Visual (VT-3) no later than 2 100% of thermal shield Thermal shield flexures 3 or Loss of refueling outages from the flexures Materials (Wear) beginning of the license renewal that results in period. Subsequent See Figures 2-I1 and 2-16 thermal shield examinations on a ten year flexures excessive interval.

wear, fracture or complete separation Core Barrel Assembly IPEC Units 2 and Cracking (IASCC, None Enhanced visual (EVT-l) 100% of one side of the Upper and lower core barrel 3 Neutron examination, no later than 2 accessible surfaces of the welds Embrittlement) refueling outages from the selected weld and adjacent beginning of the license renewal base metal.

period and subsequent examination on a ten-year See Figure 2-4 interval.

Core Barrel Assembly IPEC Units 2 and Cracking (IASCC, None Enhanced visual (EVT-1) 100% of one side of the Lower core barrel flange weld 3 Neutron examination, no later than 2 accessible surfaces of the Embrittlement) refueling outages from the selected weld and adjacent (At IPEC this weld is the lower beginning of the license renewal base metal.

core barrel to lower support period and subsequent casting weld. IPEC does not examination on a ten-year See Figure 2-4 (Core Barrel have a lower core barrel flange) interval. to Support Plate Weld)

Page 39

NL-l 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel hiternals hIspection Plan Table 5-3 Expansion Components at IPEC Units 2 and 3 Effect EaiainMto Item Applicability (Mechanism) Primary Link Examination Method Examination Coverage Core Barrel Assembly IPEC Units 2 Cracking (IASCC, Baffle-former Volumetric (UT) examination, 100% of accessible bolts.

Barrel-former bolts and 3 Fatigue) bolts with initial examinations The inspection shall dependent on results of baffle- examine a minimum former bolt examinations. Re- sample size of 75% of the examinations at 10 year total population of bolts.

intervals once degradation is Accessibility may be identified in the primary limited by presence of component. thermal shields. 75% of a component's total (accessible + inaccessible) inspection area or volume will be examined or, when addressing a set of like components (e.g., bolting),

that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined.

See Figure 2-5 Page 40

NL-l 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-3 Expansion Components at IPEC Units 2 and 3 Item Applicability (EMechanism) Primary Link Examination Method Examination Coverage Lower Support Assembly IPEC Units 2 Cracking (IASCC, Baffle-former Volumetric (UT) examination, 100% of accessible bolts Lower support column bolts and 3 Fatigue) bolts with initial examinations or as supported by plant-dependent on results of baffle- specific justification. The former bolt examinations. Re- inspection shall examine a examinations at 10 year minimum sample size of intervals once degradation is 75 percent of the total identified in the primary population of bolts. 75%

component. of a component's total (accessible + inaccessible) inspection area or volume will be examined or, when addressing a set of like components (e.g., bolting),

that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined.

See Figures 2-12 and 2-13 Page 41

NL- I1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-3 Expansion Components at IPEC Units 2 and 3 Effect Meho Coverage Item Applicability (Mechanism) Primary Link Examination Method Examination Coverage Core Barrel Assembly IPEC Units 2 Cracking (SCC, Upper core barrel Enhanced visual (EVT-1) 100% of one side of the Core barrel flange, and 3 Fatigue) flange weld examination, with initial accessible surfaces of the examination frequency selected weld and adjacent Core barrel outlet nozzles dependent on the examination base metal. 75% of a results for upper core barrel component's total flange. Re-examinations at 10 (accessible + inaccessible) year intervals once degradation inspection area or volume is identified in the primary will be examined or, when component. addressing a set of like components (e.g., bolting),

that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined.

See Figure 2-4 Page 42

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-3 Expansion Components at IPEC Units 2 and 3 Effect EaiainMto Item Applicability (Mechanism) Primary Link Examination Method Examination Coverage Lower Support Assembly IPEC lower support column Lower support column bodies bodies are cast.

(non cast) They are captured in the next Item of this table.

Lower Support Assembly IPEC Units 2 Cracking Control rod guide Visual (EVT-1) examination. 100% of accessible Lower support column bodies and 3 (IASCC) tube (CRGT) Re-examinations at 10 year support columns. 75% of a including the lower flanges intervals once degradation is component's total (cast) detection of identified in the primary (accessible + inaccessible) fractured support component. inspection area or volume columns will be examined or, when addressing a set of like components (e.g., bolting),

that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined.

See Figure 2-14 Page 43

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-3 Expansion Components at IPEC Units 2 and 3 Item Applicability Effect Primary Link Examination Method Examination Coverage Bottom Mounted IPEC Units 2 Cracking Control rod guide Visual (VT-3) examination of 100% of BMI column Instrumentation System and 3 (Fatigue) tube (CRGT) BMI column bodies as bodies for which difficulty Bottom-mounted including the lower flanges indicated by difficulty of is detected during flux detection of insertion/withdrawal of flux thimble instrumentation (BMI) column completely thimbles. Flux thimble insertion/withdrawal.

fractured column insertion/withdrawal to be bodies monitored at each inspection interval. Re-examinations at See Figure 2-15 10 year intervals once degradation is identified in the primary component.

Upper Internals Assembly IPEC Units 2 Cracking (SCC, Control rod guide Enhanced visual (EVT-1) 100% of accessible upper Upper core plate and 3 Fatigue) tube (CRGT) examination, with initial core plate. 75% of a lower flange weld examination frequency component's total dependent on the examination (accessible + inaccessible) results for CRGT lower flange inspection area or volume weld. Re-examinations at 10 will be examined or, when year intervals once degradation addressing a set of like is identified in the primary components (e.g., bolting),

component. that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined. See Figure 2-1 Page 44

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel InternalsInspection Plan Table 5-3 Expansion Components at IPEC Units 2 and 3 Item Effect Examination MethodCoverage ImApplicability (Mechanism) Primary Link ExaminationCMethod Lower Support Assembly IPEC Units 2 Cracking (SCC, Control rod guide Enhanced visual (EVT-1) 100% of accessible lower Lower support casting and 3 Fatigue) tube (CRGT) examination, with initial support casting. 75% of a lower flange weld examination frequency component's total dependent on the examination (accessible + inaccessible) results for CRGT lower flange inspection area or volume weld. Re-examinations at 10 will be examined or, when year intervals once degradation addressing a set of like is identified in the primary components (e.g., bolting),

component. that the inspection examine a minimum sample size of 75 percent of the total population of like components. For the inspection of a set of like components, it is understood that essentially 100% of the volume/area of each accessible like component will be examined.

See Figure 2-1 (Core Support)

Page 45

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-4 Existing Program Components at IPEC Units 2 and 3 Effect Item Applicability (Mechanism) Primary Link Examination Method Examination Coverage Core Barrel Assembly IPEC Units 2 Loss of material ASME Code Visual (VT-3) examination All accessible surfaces at Core barrel flange and 3 (Wear) Section XI to determine general ASME Section XI specified condition for excessive frequency.

wear.

Upper Internals Assembly N/A N/A N/A N/A N/A Upper support ring or skirt (This item is N/A because IPEC has a tophat design)

Lower Internals Assembly IPEC Units 2 Cracking (IASCC, ASME Code Visual (VT-3) examination All accessible surfaces at Lower core plate and 3 Fatigue) Section XI of the lower core plates to ASME Section XI specified detect evidence of frequency.

distortion and/or loss of bolt integrity.

Lower Internals Assembly IPEC Units 2 Loss of material ASME Code Visual (VT-3) All accessible surfaces at Lower core plate and 3 (Wear) Section XI examination. ASME Section XI specified frequency.

Bottom Mounted IPEC Units 2 Loss of material N/A Surface (ET) examination. N/A Instrumentation System and 3 (Wear)

Flux thimble tubes Alignment and Interfacing IPEC Units 2 Loss of material ASME Code Visual (VT-3) All accessible surfaces at Components and 3 (Wear) Section XI examination. ASME Section XI specified Clevis insert bolts frequency.

Alignment and Interfacing IPEC Units 2 Loss of material ASME Code Visual (VT-3) All accessible surfaces at Components and 3 (Wear) Section XI examination. ASME Section XI specified Upper core plate alignment pins frequency.

Page 46

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-5 Examination Acceptance and Expansion Criteria at IPEC Units 2 and 3 Examination Acceptance Expansion Link(s) Expansion Criteria Additional Examination Item Applicability Criteria (Note 1) E Acceptance Criteria Control Rod Guide Tube IPEC Units 2 Visual (VT-3) None N/A N/A Assembly and 3 examination.

Guide plates (cards)

The specific relevant condition is wear that could lead to loss of control rod alignment and impede control assembly insertion.

Control Rod Guide Tube IPEC Units 2 Enhanced visual (EVT-!) a. Bottom-mounted a. Confirmation of surface- a. For BMI column bodies, Assembly and 3 examination, instrumentation (BMI) breaking indications in two or the specific relevant Lower flange welds column bodies more CRGT lower flange welds, condition for the VT-3 combined with flux thimble examination is completely The specific relevant insertion/withdrawal difficulty, fractured column bodies.

condition is a detectable b. Lower support shall require visual (VT-3) crack-like surface column bodies (cast) examination of BMI column indication. bodies by the completion of the b. For cast lower support next refueling outage. column bodies, the specific relevant condition is a detectable crack-like

b. Confirmation of surface- surface indication.

breaking indications in two or more CRGT lower flange welds shall require EVT- I examination of cast lower support column bodies within three fuel cycles following the initial observation.

Page 47

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Intenials Inspection Plan Table 5-5 Examination Acceptance and Expansion Criteria at IPEC Units 2 and 3 Examination Acceptance Additional Examination Item Applicability Criteria (Note 1) Expansion Link(s) Expansion Criteria Acceptance Criteria Core Barrel Assembly IPEC Units 2 Enhanced visual (EVT-1) None N/A N/A and 3 examination.

Upper core barrel flange weld Upper and lower core barrel The specific relevant welds condition is a detectable crack-like surface Lower core bare] flange indication.

weld (At IPEC this weld is the lower core barrel to lower support casting weld.

IPEC does not have a lower core barrel flange)

Core barrel flange Core barrel outlet nozzles Baffle-Former Assembly IPEC Units 2 Visual (VT-3) None N/A N/A and 3 examination.

Baffle-edge bolts The specific relevant conditions are missing or broken locking devices, failed or missing bolts, and protrusion of bolt heads.

• L L Page 48

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-5 Examination Acceptance and Expansion Criteria at IPEC Units 2 and 3 Examination Acceptance Expansion Link(s) Expansion Criteria Additional Examination Item Applicability Criteria (Note 1) Acceptance Criteria Baffle-Former Assembly IPEC Units 2 Volumetric (UT) a. Lower support a. Confirmation that more than a and b. The examination and 3 examination, column bolts 5% of the baffle-former bolts acceptance criteria for the Baffle-former bolts actually examined on the four UT of the lower support baffle plates at the largest distance column bolts and the The examination b. Barrel-former bolts from the core (presumed to be the barrel-former bolts shall be acceptance criteria for the lowest dose locations) contain established as part of the UT of the baffle-former unacceptable indications shall examination technical bolts shall be established as require UT examination of the justification.

part of the examination lower support column bolts within technical justification. the next three fuel cycles.

b. Confirmation that more than 5% of the lower support column bolts actually examined contain unacceptable indications shall require UT examination of the barrel-former bolts.

Page 49

NL-l 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-5 Examination Acceptance and Expansion Criteria at IPEC Units 2 and 3 Item Applicability Examination Acceptance Expansion Link(s) Expansion Criteria Additional Examination Criteria (Note 1) E Acceptance Criteria Baffle-Former Assembly IPEC Units 2 Visual (VT-3) None N/A N/A Assembly and 3 examination.

The specific relevant conditions are evidence of abnormal interaction with fuel assemblies, gaps along high fluence shroud plate joints, vertical displacement of shroud plates near high fluence joints, and broken or damaged edge bolt locking systems along high fluence baffle plate joints.

Alignment and Interfacing IPEC Units 2 Direct physical None N/A N/A Components and 3 measurement of spring Internals hold down spring height.

The examination acceptance criterion for this measurement is that the remaining compressible height of the spring shall provide hold.down forces within the plant-specific design tolerance.

Page 50

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel InternalsInspection Plan Table 5-5 Examination Acceptance and Expansion Criteria at IPEC Units 2 and 3 Examination Acceptance Expansion Link(s) Expansion Criteria Additional Examination Item Applicability Criteria (Note 1) Acceptance Criteria Thermal Shield Assembly IPEC Units 2 Visual (VT-3) None N/A N/A and 3 examination.

Thermal shield flexures The specific relevant conditions for thermal shield flexures are excessive wear, fracture, or complete separation.

Upper Internals Assembly IPEC Units 2 Enhanced visual (EVT-1) None N/A N/A Upper core plate and 3 examination.

The specific relevant condition is a detectable crack-like surface indication.

Lower Support Assembly IPEC Units 2 Enhanced visual (EVT-I) None N/A N/A Lower support casting and 3 examination.

The specific relevant condition is a detectable crack-like surface indication.

Notes:

I. The examination acceptance criterion for visual examination is the absence of the specified relevant condition Page 51

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I hidian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-6 Reactor Vessel Component ISI Program Inspection Plan for IPEC Units 2 and 3 Code Examination Component Extent of Exam Category Method Reactor Vessel Interior B-N-2 VT-I or VT-3 Components and areas as accessible Radial Support Keys Reactor Vessel Interior B-N-2 VT-I or VT-3 Components and areas as accessible Bottom Head Instrumentation Nozzles Reactor Vessel Interior B-N-2 VT- I or VT-3 Components and areas as accessible Outlet and Inlet Nozzle mating surfaces and inside of nozzles Reactor Vessel Interior B-N-2 VT-I or VT-3 Components and areas as accessible Upper internal to vessel mating surface with keys and access slots Reactor Vessel Interior B-N-2 VT-I or VT-3 Components and areas as accessible Vessel flange surface Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Core barrel surface Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Thermal Shield Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Irradiation specimen tubes and guides Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Flexures Page 52

NL-1 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-6 Reactor Vessel Component ISI Program Inspection Plan for IPEC Units 2 and 3 Code Examination Component Extent of Exam Category Method Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Fasteners and locking devices Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 22 deg Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 158 deg Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 202 deg Lower Internals - Exterior B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 338 deg Lower Internals - Exterior Bottom B-N-3 VT-3 Components and areas as accessible Lower core support plate Lower Internals - Exterior Bottom B-N-3 VT-3 Components and areas as accessible Flow distribution plate Lower Internals - Exterior Bottom B-N-3 VT-3 Components and areas as accessible Lower support casting Lower Internals - Exterior Bottom B-N-3 VT-3 Components and areas as accessible Core support column Lower Internals - Exterior Bottom B-N-3 VT-3 Components and areas as accessible Secondary core support Page 53

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-6 Reactor Vessel Component ISI Program Inspection Plan for IPEC Units 2 and 3 Code Examination Component Category Method Extent of Exam Lower Internals - Exterior Bottom B-N-3 VT-3 Components and areas as accessible Instrumentation guides Lower Internals - Exterior Bottom B-N-3 VT-3 Components and areas as accessible Radial support keys Lower Internals - Interior Bottom B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 22 deg Lower Internals - Interior Bottom B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 158 deg Lower Internals - Interior Bottom B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 202 deg Lower Internals - Interior Bottom B-N-3 VT-3 Components and areas as accessible Outlet nozzle at 338 deg Lower Internals - Interior Bottom B-N-3 VT-3 Components and areas as accessible Core barrel alignment pin Lower Internals - Interior Bottom B-N-3 VT-3 Components and areas as accessible Lower core plate Lower Internals - Interior Bottom B-N-3 VT-3 Components and areas as accessible Fuel alignment pins I I Page 54

NL-l 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel Internals Inspection Plan Table 5-7 List of IPEC Reactor Vessel Interior Components and Materials Based on MRP-191 - Table 4-4 UPPER INTERNALS ASSEMBLY Sub Assembly Component Material Category from MRP-191 Table 7-2 Anti-rotation studs and nuts Stainless steel A Bolts Stainless steel A C-tubes Stainless steel C Enclosure pins Stainless steel A Upper guide tube enclosures Stainless steel A Flanges intermediate Stainless steel A Flanges lower Stainless steel A Flexureless inserts Stainless steel A Guide plates/cards Stainless steel C Guide tube support pins (split pins) A X-750 (IP2 only) C Control rod guide Guide tube support pins (split pins) Stainless steel (IP3 only) A tube assemblies and flow downcomers Housing plates Stainless steel A Inserts Stainless steel A Lock bars Stainless steel A Sheaths Stainless steel C Support pin cover plate Stainless steel A Support pin cover plate cap screws Stainless steel A Support pin cover plate locking caps Stainless steel A and tie straps Support pin nuts Alloy X-750 A Support pin nuts Stainless steel A Water flow slot ligaments Stainless steel A Mixing Devices Mixing devices CASS A Upper core plate and Fuel alignment pins Stainless steel A fuel alignment pins Upper core plate Stainless steel A Bolting Stainless steel A Bracketsclampsterminal blocks, and conduit straps Stainless steel A Upper Conduit seal assembly-body, Stainless steel A instrumentation tubesheets conduit and supports Conduit seal assembly-tubes Stainless steel A Conduits Stainless steel A Flange base Stainless steel A Locking caps Stainless steel A Support tubes Stainless steel A UHI flow column bases CASS A Upper plenum UHI flow columns Stainless steel A Page 55

NL-l 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel InternalsInspection Plan Table 5-7 List of IPEC Reactor Vessel Interior Components and Materials Based on MRP-191 - Table 4-4 UPPER INTERNALS ASSEMBLY Sub Assembly Component Material Category from MRP-191 Table 7-2 Adapters Stainless steel A Bolts Stainless steel A Column bases CASS A Upper support Column bodies Stainless steel A column assemblies Extension tubes Stainless steel A Flanges Stainless steel A Lock keys Stainless steel A Nuts Stainless steel A Bolts Stainless steel A Deep beam ribs Stainless steel A Deep beam stiffeners Stainless steel A Flange Stainless steel A Upper support plate Inverted top hat flange Stainless steel A assembly Inverted top hat upper support plate Stainless steel A Lock keys Stainless steel A Ribs Stainless steel A Upper suport plate Stainless steel A Upper support ring or skirt Stainless steel B LOWER INTERNALS ASSEMBLY Sub Assembly Component Material Category from MRP-191 Table 7-2 Baffle bolting locking bar Stainless steel A Baffle edge bolts Stainless steel C Baffle and former Baffle plates Stainless steel B assembly Baffle former bolts Stainless steel C Barrel former bolts Stainless steel C Former plates Stainless steel B BMI column bodies Stainless steel B BMI column bolts Stainless steel A Bottom mounted BMI column collars Stainless steel B instrumentation BMI column cruciforms CASS B (BMI) column BMI column extension bars Stainless steel A

.assemblies BMI column extension tubes Stainless steel B BMI column lock caps Stainless steel A BMI column nuts Stainless steel A Core barrel flange Stainless steel B Core barrel Core barrel outlet nozzles Stainless steel B Upper core barrel Stainless steel C Lower core barrel Stainless steel C Diffuser plate Diffuser plate Stainless steel A Page 56

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel InternalsInspection Plan Table 5-7 List of IPEC Reactor Vessel Interior Components and Materials Based on MRP-191 - Table 4-4 LOWER INTERNALS ASSEMBLY Sub Assembly Component Material Category from MRP-191 Table 7-2 Flux thimble tube plugs - IPEC does not use tube plugs. instead tubes are B Flux thimbles (tubes) capped (IP2 has 9 tubes capped, IP3 has 0 tubes capped)

Flux thimbles (tubes) Stainless steel C Irradiation specimen guide Stainless steel A Irradiation specimen Irradiation specimen guide bolts Stainless steel A guides Irradiation specimen lock caps Stainless steel A Specimen plugs Stainless steel A Fuel alignment pins Stainless steel A Lower core plate (LCP) and fuel LCP fuel alignment pin bolts Stainless steel A alignment pins LCP fuel alignment pin lock caps Stainless steel A Lower core plate Stainless steel C Lower support column bodies CASS B Lower support Lower support column bolts Stainless steel B column assemblies Lower support column nuts Stainless steel A Lower support column sleeves Stainless steel A Lower support casting or forging Lower support casting CASS A Thermal shield bolts Stainless steel A Neutron Thermal shield dowels Stainless steel A panels/thermal shield Thermal shield flexures Stainless steel B Thermal shield Stainless steel A Radial support key bolts Stainless steel A Radial support keys Radial support key lock keys Stainless steel A Radial support keys Stainless steel A SCS base plate Stainless steel A SCS bolts Stainless steel A Secondary core Stainless steel A sembly(cor Suponrt SCS energy absorber SCS guide posts Stainless steel A SCS housing Stainless steel A SCS lock keys Stainless steel A Clevis insert bolts A X-750 B Clevis insert lock keys Stainless steel A Clevis inserts Alloy 600 A Interfacing Head and vessel allignment pin bolts Stainless steel A Components Head and vessel alignment pin lock Stainless steel A caps Head and vessel allignment pins Stainless steel A Internals hold down spring 304 Stainless steel B Upper core plate alignment pins Stainless steel B Page 57

NL-I 1-107 Docket Nos. 50-247 and 50-286 Attachment I Indian Point Energy Center Reactor Vessel internals Inspection Plan Table 5-8 IPEC Response to the NRC Final Safety Evaluation of MRP-227 MRP-227 SER Item IPEC Response SER Section 4.1.1, Topical Report In accordance with SER Section 4. 1. 1, the upper core plate and the lower Condition I Moving components to support casting have been added to the IPEC "Expansion" inspection category "Expansion" category from "No and are contained in Table 5-3. The components are linked to the "Primary" additional measures" category. component CRGT lower flange weld. The examination method is consistent with the examinations performed on the CRGT lower flange weld.

SER Section 4.1.2, Topical Report In accordance with SER Section 4.1.2, the upper and lower core barrel welds Condition 2 Inspection of and lower core barrel to lower support casting weld have been added to the components subject to irradiation- IPEC "Primary" inspection category and are contained in Table 5-2. The assisted stress corrosion cracking examination method is consistent with the MRP recommendations for these components, the examination coverage conforms to the criteria described in Section 3.3.1 of the NRC SE, and the re-examination frequency is on a 10-year interval consistent with other "Primary" inspection category components.

SER Section 4.1.3, Topical Report No action required. This item does not apply to components in Westinghouse Condition 3 Inspection of high designed reactors.

consequence components subject to multiple degradation mechanisms SER Section 4.1.4, Topical Report In accordance with SER Section 4.1.4, IPEC will meet the minimum inspection Condition 4 Minimum examination coverage specified in the SER. The appropriate wording has been added to coverage criteria for "expansion" Table 5-3 examination coverage.

inspection category components SER Section 4.1.5, Topical Report In accordance with SER Section 4.1.5, the examination frequency for baffle-Condition 5 Examination former bolts specifies a 10-year inspection frequency following the baseline frequencies for baffle-former bolts inspection in Table 5-2.

SER Section 4. 1.6, Topical Report In accordance with SER Section 4.1.6, Table 5-3 requires a I 0-year re-Condition 6 Periodicity of the re- examination interval for all Expansion inspection category components once examination of "expansion" degradation is identified in the associated Primary inspection category inspection category components component and examination of the expansion category component commences.

SER Section 4.1.7. Topical Report This condition applies to update of the industry guidelines. No plant-specific ConditionseUpating of industry action required.

guideline SER Section 4.2.41, The evaluation of design and operating history demonstrating that MRP-227 is Applicant/Licensee Action Item 4 applicable to IPEC is contained in Section 3.6.

SER Section 4.2.2, The IPEC review of components within the scope of license renewal against the Applicant/Licensee Action Item 2 information contained in MRP-191 Table 4-4 is discussed in Section 3.6.

SER Section 4.2.3, The IPEC discussion regarding guide tube support pins (split pins) is contained Applicant/Licensee Action Item 3 in Section 3.6.

SER Section 4.2.4, No action required. This item does not apply to Westinghouse designed units.

Applicant/Licensee Action Item 4 SER Section 4.2.5. The IPEC discussion regarding hold down springs is contained in Section 3.6.

Applicant/Licensee Action Item 5 SER Section 4.2.6, No action required. This item does not apply to Westinghouse designed units.

Applicant/Licensee Action Item 6 SER Section 4.2.7. The IPEC discussion regarding lower support column bodies is contained in Applicant/Licensee Action Item 7 Section 3.6.

SER Section 4.2.8, The submittal of information for staff review and approval is discussed in Applicant/Licensee Action Item 8 Section 3.6.

Page 58

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

ENTERGY NUCLEAR OPERATIONS, INC. ) Docket Nos. 50-247-LR/286-LR

)

(Indian Point Nuclear Generating )

Units 2 and 3) )

CERTIFICATE OF SERVICE I hereby certify that the foregoing NRC STAFFS ANSWER TO STATE OF NEW YORK AND RIVERKEEPERS JOINT MOTION TO FILE A NEW CONTENTION, AND NEW JOINT CONTENTION NYS-38/RK-TC-5 in the above-captioned proceeding has been filed and served by Electronic Information Exchange (EIE), with copies to be served by the EIE system on the following persons, this 25th day of October, 2011.

Lawrence G. McDade, Chair Office of Commission Appellate Atomic Safety and Licensing Board Panel Adjudication Mail Stop - T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Mail Stop: O-16G4 Washington, D.C. 20555-0001 Washington, DC 20555-0001 E-mail: Lawrence.McDade@nrc.gov E-mail: OCAAMAIL@nrc.gov Dr. Richard E. Wardwell Office of the Secretary Atomic Safety and Licensing Board Panel Attn: Rulemaking and Adjudications Staff Mail Stop - T-3 F23 Mail Stop: O-16G4 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Washington, DC 20555-0001 E-mail: Richard.Wardwell@nrc.gov E-mail: Hearingdocket@nrc.gov Dr. Kaye D. Lathrop Josh Kirstein, Esq.

Atomic Safety and Licensing Board Panel Atomic Safety and Licensing Board Panel 190 Cedar Lane E. Mail Stop - T-3 F23 Ridgway, CO 81432 U. S, Nuclear Regulatory Commission E-mail: Kaye.Lathrop@nrc.gov Washington, D.C. 20555-0001 E-Mail: Josh.Kirstein@nrc.gov

John J. Sipos, Esq.* Melissa-Jean Rotini, Esq.

Charlie Donaldson, Esq. Assistant County Attorney Assistants Attorney General Office of Robert F. Meehan, Esq.

New York State Department of Law Westchester County Attorney Environmental Protection Bureau 148 Martine Avenue, 6th Floor The Capitol White Plains, NY 10601 Albany, NY 12224 E-Mail: MJR1@westchestergov.com E-mail: John.Sipos@ag.ny.gov Charlie.Donaldson@ag.ny.gov Kathryn M. Sutton, Esq.* Phillip Musegaas, Esq.*

Paul M. Bessette, Esq. Deborah Brancato, Esq.

Jonathan Rund, Esq. Riverkeeper, Inc.

Morgan, Lewis & Bockius, LLP 20 Secor Road 1111 Pennsylvania Avenue, NW Ossining, NY 10562 Washington, D.C. 20004 E-mail: phillip@riverkeeper.org E-mail: ksutton@morganlewis.com E-mail: dbrancato@riverkeeper.org E-mail: pbessette@morganlewis.com E-mail: jrund@morganlewis.com Janice A. Dean, Esq.*

Martin J. ONeill, Esq.* Assistant Attorney General, Morgan, Lewis & Bockius, LLP Office of the Attorney General 1000 Louisiana Street, Suite 4000 of the State of New York Houston, TX 77002 120 Broadway, 25th Floor E-mail: martin.o'neill@morganlewis.com New York, NY 10271 E-mail: Janice.Dean@ag.ny.gov Elise N. Zoli, Esq.* Joan Leary Matthews, Esq.*

Goodwin Procter, LLP Senior Attorney for Special Projects Exchange Place New York State Department of 53 State Street Environmental Conservation Boston, MA 02109 Office of the General Counsel E-mail: ezoli@goodwinprocter.com 625 Broadway, 14th Floor Albany, NY 12233-1500 E-mail: jlmatthe@gw.dec.state.ny.us William C. Dennis, Esq.* John Louis Parker, Esq.*

Assistant General Counsel Office of General Counsel, Region 3 Entergy Nuclear Operations, Inc. New York State Department of 440 Hamilton Avenue Environmental Conservation White Plains, NY 10601 21 South Putt Corners Road E-mail: wdennis@entergy.com New Paltz, NY 12561-1620 E-mail: jlparker@gw.dec.state.ny.us

Sean Murray, Mayor Manna Jo Greene*

Kevin Hay, Village Administrator Stephen Filler Village of Buchanan Karla Raimundi, Esq.

Municipal Building Hudson River Sloop Clearwater, Inc.

Buchanan, NY 10511-1298 724 Wolcott Avenue E-mail: vob@bestweb.net Beacon, NY 12508 E-mail: smurray@villageofbuchanan.com E-mail: mannajo@clearwater.org Administrator@villageofbuchanan.com E-mail: stephenfiller@gmail.com E-mail: karla@clearwater.org Robert Snook, Esq.* Daniel Riesel, Esq.*

Office of the Attorney General Thomas F. Wood, Esq.

State of Connecticut Victoria Shiah, Esq.

55 Elm Street Sive, Paget & Riesel, P.C.

P.O. Box 120 460 Park Avenue Hartford, CT 06141-0120 New York, NY 10022 E-mail: robert.snook@ct.gov E-mail: driesel@sprlaw.com E-mail: vshiah@sprlaw.com Michael J. Delaney, Esq.*

Director, Energy Regulatory Affairs New York City Department of Environmental Protection 59-17 Junction Boulevard Flushing, NY 11373 E-mail: mdelaney@dep.nyc.gov

/Signed (electronically) by/

David E. Roth Counsel for NRC Staff U.S. Nuclear Regulatory Commission Mail Stop O-15 D21 Washington, DC 20555-0001 (301) 415-2749 E-mail: David.Roth@nrc.gov