ML081640506

Entergy'S Proposed Findings of Fact and Conclusions of Law on Pilgrim Watch Contention 1

ML081640506
Person / Time
Site:	Pilgrim
Issue date:	06/09/2008
From:	Gaukler P, Doris Lewis Entergy Nuclear Generation Co, Entergy Nuclear Operations, Pillsbury, Winthrop, Shaw, Pittman, LLP
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
50-293-LR, ASLBP 06-848-02-LR, RAS J-146
Download: ML081640506 (69)

Text

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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION DOCKETED USNRC Before the Atomic Safety and Licensing Board Panel June 10, 2008 8:00 am OFFICE OF SECRETARY In the Matter of ) RULEMAKINGS AND

) ADJUDICATIONS STAFF Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

ENTERGY'S PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW ON PILGRIM WATCH CONTENTION 1 David R. Lewis Paul A. Gaukler PILLSBURY WINTHROP SHAW PITTMAN LLP 2300 N Street, NW Washington, DC 20037-1128 Tel. (202) 663-8000 Counsel for Entergy L.L.C.

Dated: June 9, 2008 7&~46 7~6~

TABLE OF CONTENTS I. BA C KG RO U N D ...................................................................................................................... 2 II. LEGAL STANDARDS ........................................................................................................ 6 III. THE PARTIES' WITNESSES AND QUALIFICATIONS ................................................... 11 A . Entergy W itnesses ......................................................................................................... 11 B. Nuclear Regulatory Commission Staff Witnesses ........................................................ 15 C. Pilgrim Watch Witnesses ............................................................................................. 17 IV. FINDINGS OF FACT ......................................................................................................... 18 A. Determination of Buried Pipes and Tanks within the Scope of Contention 1.............. 18

1. License Renewal Systems with Buried Pipe and Radioactive Liquids ................... 18

2. The CSS Buried Pipe Serves No License Renewal Intended Function .................. 19

3. Salt Service Water System ...................................................................................... 23 B. The PNPS Aging Management Programs for In-Scope Systems Provide Reasonable Assurance that Leaks Challenging License Renewal Intended Functions Will Not O ccur ................................................................................................................................. 25

1. Summary Overview of AMP Findings ................................................................... 25

2. Aging Management of External Degradation- The Buried Pipe and Tank Inspection P rogram ....................................................................................................................... 27

3. Aging Management of Internal Degradation .......................................................... 50 C. Additional Surveillance Programs for the CSS and SSW Systems .............................. 61

1. Service Water Integrity Program ........................................................................... 61

2. CSS Surveillance Monitoring Program ................................................................. 62

3. C on clu sion .................................................................................................................. 63 D. Monitoring Wells Are Not Necessary ........................................................................... 64 V. CONCLUSIONS OF LAW ............................................................................................... 64 V I. O R DE R ................................................................................................................................... 65 i

June 9, 2008 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board Panel In the Matter of )

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

ENTERGY'S PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW ON PILGRIM WATCH CONTENTION 1 Pursuant to 10 C.F.R. § 2.712 and the Orders of the Atomic Safety Licensing Board

("Licensing Board" or "Board") dated December 19, 20061 and May 12, 2008,2 Applicants Entergy Nuclear Generation Company and Entergy Nuclear Operations, Inc. (collectively, "Entergy") submit, in the form of an initial decision, their proposed findings of fact and conclusions of law concerning Pilgrim Watch Contention 1 ("Contention 1"). The proposed initial decision is organized as follows.Section I provides the procedural background for Pilgrim Watch Contention 1.Section II presents the standards governing the issuance of a renewed license.Section III identifies and discusses the qualifications of the witnesses for the parties who testified regarding the contention.Section IV presents Entergy's proposed findings of fact on the Contention, in sequentially numbered paragraphs.Section V presents Entergy's proposed conclusions of law on the Contention, also in sequentially numbered paragraphs.

Order (Establishing Schedule for Proceeding and Addressing Related Matters) (Dec. 19, 2006).

2 Order (Setting Deadlines for Provisional Proposed Findings and Conclusions on Contention, and for Pleadings related to Pilgrim Watch's Recent Motion Regarding CUF's) (May 12, 2008).

I. BACKGROUND This proceeding involves the application by Entergy Nuclear Generation Company and Entergy Nuclear Operations, Inc. (collectively, "Entergy") to renew the operating license for Pilgrim Nuclear Power Station ("Pilgrim" or "PNPS") for an additional twenty-year period. 71 Fed. Reg. 15,222 (Mar.. 27, 2006). The current operating license for Pilgrim expires on June 8, 2012. Id.

On October 16, 2006, the Board granted a petition by Pilgrim Watch to intervene in this proceeding and admitted two Contentions: Contention 1, dealing with the aging management of buried pipes and tanks; and Contention 3, regarding analysis of severe accident mitigation alternatives. Entergy Nuclear Generation Co., et al. (Pilgrim Nuclear Power Station), LBP 23, 64 N.R.C. 257 (2006). The Board also granted requests by the Towns of Plymouth and Duxbury to participate in this proceeding pursuant to 10 C.F.R. § 2.315(c). An intervention petition by the Massachusetts Attorney General was denied. Id. at 271.

Contention 3 was later resolved by summary disposition. 3 The Board now issues this Final Initial Decision resolving the remaining Contention 1.

As admitted by the Board, Contention 1 states:

The Aging Management program ["AMP"] proposed in the Pilgrim Application for license renewal is inadequate with regard to aging management of buried pipes and tanks that contain radioactively contaminated water, because it does not provide for monitoring wells that would detect leakage.

LBP-06-23, 64 N.R.C. at 315 (footnote omitted).

On June 8, 2007, Entergy moved for summary disposition on Contention 1L 4 The NRC 5

Staff ("Staff") filed a response supporting the motion, and Pilgrim Watch opposed the motion.

3 Entergy Motion for Summary Disposition of Pilgrim Watch Contention 3 (May 17, 2007).

4 Entergy's Motion for Summary Disposition of Pilgrim Watch Contention 1 (June 8,2007).

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By Memorandum and Order of October 17, 2007, the Board denied this motion, but clarified the appropriate focus ofContention 1 to be litigated, stating:

[P]revention of leaks per se is not a stated objective of any relevant aging management program. On the other hand, prevention of an aging-induced leak large enough to compromise the ability of buried piping or tanks to fulfill their intended safety function is indeed a clear goal of an AMP. Thus, at issue here is the following fundamental question: Do the AMPs for buried pipes and tanks, by themselves, ensure that such safety-function-challenging leaks will not occur, or must some sort of leak detection devices such as the monitoring wells proposed by Intervenors be installed to meet that obligation?

Entergv Nuclear Generation Co., et al. (Pilgrim Nuclear Power Station), LBP-07-12, 66 N.R.C.

113, 129 (2007) ("Summary Disposition Order"). We further stated that "the only issue remaining before this Licensing Board regarding Contention 1 is ... whether Pilgrim's existing AMPs have elements that provide appropriate assurance as required under relevant NRC regulations that the buried pipes and tanks will not develop leaks so great as to cause those pipes and tanks to be unable to perform their intended safety functions." Id. at 129. Conversely, we stated that matters not in dispute are: (1) the health effects of leaking radioactive liquids, (2) leakage from the spent fuel pool, and (3) leakage events at other plants. Id. at 129-30.

In a subsequent order, we reiterated the appropriate focus of the proceeding and contention, stating:

Ongoing monitoring is not within the scope of this proceeding; only challenges to errors or omissions from the Applicant's Aging Management Program (AMP) are properly within the scope. The single admitted contention relates to whether or not Applicant's AMPs are sufficient to enable it to determine whether or not certain buried pipes and tanks are leaking at such great rates that they cannot satisfy their respective intended safety functions. Therefore, unless and until the Applicant expressly advises this Board and the Agency that it intends to rely upon monitoring wells for making its determination that buried NRC Staff Response to Entergy's Motion for Summary Disposition of Pilgrim Watch Contention 1 (June 28, 2007); Pilgrim Watch's Answer Opposing Entergy's Motion for Summary Disposition of Pilgrim Watch Contention 1 (June 27, 2007).

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pipes and tanks are not leaking at such great rates that they cannot satisfy their intended safety functions, information related to monitoring wells is irrelevant to the issues at hand before this Board.6 Shortly thereafter, Pilgrim Watch filed a motion seeking clarification on those buried pipes and tanks that were within the scope of Contention 1.7 In its Motion, Pilgrim Watch asserted that all buried pipes and tanks, not just those containing radioactively contaminated water, were within the scope of the contention. 8 We denied Pilgrim Watch's Motion. We explained that Pilgrim Watch's "original contention concerned only 'systems and components that may contain radioactively contaminated water,' and the Board then admitted the contention, limited somewhat from its original scope, but still concerning only "buried pipes and tanks that 9

contain radioactively contaminated water."

On January 8, 2008, Entergy filed its Initial Statement of Position on Contention 1 and pre-filed expert testimony from four experienced engineers with specific knowledge of Entergy operations, systems, structures, and components. 10 The Staff filed its Initial Statement of Position on Contention 1 and pre-filed expert testimony on January 29, 2008.11 Pilgrim Watch also filed its Statement of Position and pre-filed expert testimony on January 29, 2008.12 6 Order (Revising Schedule for Evidentiary Hearing and Responding to Pilgrim Watch's December 14 and 15 Motions) (Dec. 19, 2007) at 1.

7 Pilgrim Watch Motion for Clarification (Dec. 21, 2007).

8 Id. at 5-7.

9 Order (Denying Pilgrim Watch's Motion for Clarification) (Jan. 11, 2008) at 3-4 (footnotes omitted).

10 Entergy's Initial Statement of Position on Pilgrim Watch Contention 1 ( Jan. 8, 2008); Testimony of Alan Cox, Brian Sullivan, Steve Woods, and William Spataro on Pilgrim Watch Contention 1, regarding Adequacy of Aging Management Program for Buried Pipes and tanks and Potential Need for Monitoring Wells to Supplement Program (Jan. 8, 2008) ("Entergy Test.") (Exh. 1, admitted at Tr. 571).

11NRC Staff initial Statement of Position on Contention 1 (Jan. 29, 2008) ("Staff Statement of Position"); NRC Staff Testimony of Dr. James A. Davis Concerning Pilgrim Watch Contention 1 (Jan. 29, 2008) ("Davis Test.");

NRC Staff Testimony of Terence L. Chan and Andrea T. Keim Concerning Pilgrim Watch Contention 1. (Jan. 29, 2008) ("Staff Test. of Chan and Keim").

12 Pilgrim Watch Presents Statements of Position, Direct Testimony and Exhibits Under 10 CFR 2.1207 (Jan. 29, 2008); Testimony of Arnold Gundersen Supporting Pilgrim Watch's Contention 1 (Jan. .29, 2008) ("Gundersen Test."); Declaration of David P. Ahlfeld, PHD, PE Regarding Groundwater Monitoring Requirements for PNPS (Jan. 29, 2008) ("Ahlfeld Test.").

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After reviewing the initial testimony of the parties, we posed several questions to both the Staff and Entergy related to, among other things, (a) leaks that could reasonably challenge the ability of the condensate storage system ("CSS") to perform its intended functions, and (b) how leaks in the salt-service water ("SSW") buried pipes that might carry radioactive water could challenge the ability of the SSW system to satisfy its intended functions.13 Entergy and the Staff filed responses to these questions on February 11, 2008.14 In an Order and Notice dated February 21, 2008, we posed additional questions for the parties to be responded to with the parties' pre-filed written rebuttal testimony."5 The NRC Staff and Entergy submitted responses to these questions, along with their pre-filed written rebuttal testimony, on March 6, 2008.16 Pilgrim Watch submitted its pre-filed written rebuttal testimony that same day.17 The evidentiary hearing on Contention 1 was held on April 10, 2008, in Plymouth, Massachusetts.1 8 During the hearing, the NRC Staff, Pilgrim Watch, and Entergy collectively submitted 72 exhibits, including pre-filed and rebuttal testimony of their experts. The Staff, Pilgrim Watch, and Entergy offered testimonial evidence in response to Board questions for approximately seven hours. The Board ensured that all parties were given the opportunity to offer testimony on each and every topic.

13 Order (Board Questions for the NRC Staff and Applicant) (Jan. 31, 2008).

14 Entergy's Answer to ASLB Questions posed in 01/31/2008 Order (Feb. 11, 2008); NRC Staff Response to ASLB Questions Posed in 01/31/2008 Order (Feb. 11, 2008).

15 Order and Notice (Regarding Hearing, Limited Appearance Session, and Additional Questions for Parties) (Feb.

21, 2008).

16 NRC Staff Response to Initial Presentations on Contention 1, Rebuttal testimony, and Response to Board Questions (Mar. 6, 2008) ("Staff Reb. Test."); Rebuttal Testimony of Alan Cox Brian Sullivan, Steve Woods, and William Spataro on Pilgrim Watch Contention 1, Regarding Adequacy of Aging Management Program for Buried Pipes and tanks and Potential Need for Monitoring Wells to Supplement Program and Response to Atomic Safety and Licensing Board's Questions of February 21, 2008 (Mar. 6, 2008) ("Entergy Reb. Test.").

17 Pilgrim Watch's Rebuttal Directed to Entergy's Initial Statement of Position on Pilgrim Watch Contention 1, January 8, 2008 and NRC Staff Initial Statement of Position - Contention 1, January 8, 2008 (March 6, 2008);

Testimony of Arnold Gundersen Supporting Pilgrim Watch's Contention 1 (Mar. 6, 2008) ("PW Reb.Test.").

18 Tr. at 557.

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Several weeks after the completion of the hearing, Pilgrim Watch moved to strike prior testimony of Entergy and NRC Staff witnesses on the grounds that the testimony was incorrect and misleading based on information that Pilgrim Watch had allegedly identified since the hearing. 19 In the alternative, Pilgrim Watch requested that the Board reopen the record on Contention 1. Pilgrim Watch also moved to introduce the allegedly new information into the evidentiary record.20 Both the NRC Staff and Entergy opposed Pilgrim Watch's motions.2 1 Finding no merit to Pilgrim Watch's motions, the Board denied them on June 4, 2008.22 II. LEGAL STANDARDS The scope of a license renewal proceeding is limited. License renewal proceedings are "not intended to 'duplicate the Commission's ongoing review of operating reactors."' Florida Power & Light Co. (Turkey Point Nuclear Generating Plant, Units 3 and 4), CLI-01-17, 54 N.R.C. 3, 7 (2001), quotin Final Rule, Nuclear Power Plant License Renewal, 56 Fed. Reg.

64,943, 64,946 (Dec. 13, 1991). Rather, the focus of a license renewal proceeding is on the "potential detrimental effects of aging that are not routinely addressed by ongoing regulatory oversight programs" (CLI-01-17, 54 N.R.C. at 7), which means that the proceeding is "limited to a review of the plant structures and components that will require an aging management review for the period of extended operation and the plant's systems, structures, and components that are subject to an evaluation of time-limited aging analyses." Duke Energy Corp. (McGuire Nuclear Station, Units 1 and 2; Catawba Nuclear Station, Units 1 and 2), CLI-01-20, 54 N.R.C. 211, 212 (2001). Thus, the potential effects of aging define the issues for consideration in license renewal 19 Pilgrim Watch Motion to Strike Incorrect and Misleading Testimony from the Record (May 15, 2008).

20 Pilgrim Watch Motion to Include as part of the Record Exhibits Attached to Pilgrim Watch Motion to Strike Incorrect and Misleading Testimony from the Record of May 15, 2008 (May 27, 2008).

21 NRC Staff Response in Opposition to (1) Pilgrim Watch Motion to Strike testimony and (2) Motion to Include as Part of the Record Exhibits Attached to Pilgrim Watch Motion to Strike Testimony (May 27, 2008); Entergy's Answer Opposing Pilgrim Watch's Motion to Strike and Request to Reopen the Hearing (May 27, 2008);

Entergy's Answer Opposing Pilgrim Watch's Motion to Include Certain Exhibits in the Record (June 2, 2008).

22 Memorandum and Order (Ruling on Pilgrim Watch Motions Regarding Testimony and Proposed Additional Evidence Relating to Pilgrim Watch Contention 1) (June 4, 2008).

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proceedings. Dominion Nuclear Connecticut, Inc. (Millstone Nuclear Power Station, Units 2 and 3), CLI-04-36, 60 N.R.C. 631, 637 (2004).

10 C.F.R. § 54.21(a)(3) requires that a license renewal application demonstrate, for each component within the scope of the license renewal rules, that the effects of aging are being adequately managed so that the intended functions will be maintained consistent with the current licensing basis ("CLB") 23 during the period of extended operation. The standard for this demonstration is one of "reasonable assurance." See 10 C.F.R. § 54.29(a). See also Nuclear Power Plant License Renewal Final Rule Revisions, 60 Fed. Reg. 22,461, 22,479 (May 8, 1995)

("... the [license renewal] process is not intended to demonstrate absolute assurance that structures or components will not fail, but rather that there is reasonable assurance that they will perform such that the intended functions... are maintained consistent with the CLB").

10 C.F.R. § 54.4(a) defines the systems, structure, and components functions that are within the scope of this license renewal review as follows:

(a) Plant systems, structures, and components within the scope of this part are -

(1) safety-related systems, structures, and components which are those relied upon to remain functional during and following design-basis events (as defined in 10 C.F.R. 50.49 (b)(1)) to ensure the following functions.-

(i) the integrity of the reactor coolant pressure boundary; 23 The CLB is defined as the set of NRC requirements applicable to a specific plant and a licensee's written commitments for ensuring compliance with, and operation within, applicable NRC requirements and the plant-specific design basis (including all modifications and additions to such commitments over the life of the license) that are docketed and in effect. The CLB includes the NRC regulations contained in 10 C.F.R. parts 2, 19, 20, 21, 26, 30, 40, 50, 51, 52, 54, 55, 70, 72, 73, 100, and appendices thereto; orders; license conditions; exemptions; and technical specifications. It also includes the plant-specific design-basis information defined in 10 C.F.R. § 50.2 as documented in the most recent final safety analysis report ("FSAR") as required by 10 C.F.R. § 50.71 and the licensee's commitments remaining in effect that were made in docketed licensing correspondence, such as licensee responses to NRC bulletins, generic letters, and enforcement actions, as well as licensee commitments documented in NRC safety evaluations or licensee event reports. 10 C.F.R. § 54.3.

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(ii) the capability to shut down the reactor and maintain it in a safe shut-down condition; or (iii) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in § 50.34(a)(1), § 50.67(b)(2), or § 100.11 of this chapter as applicable.

(2) All nonsafety-related systems, structures, and components whose failure could prevent satisfactory accomplishment of any of the functions identified in paragraphs (a)(1) (i), (ii), or (iii) of this section.

(3) All systems, structures, and components relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 C.F.R. 50.48),

environmental qualification (10 C.F.R. 50.49), pressurized thermal shock (10 C.F.R. 50.61), anticipated transients without scram (10 C.F.R. 50.62), and station blackout (10 C.F.R. 50.63).

Of these items that fall within this scope, 10 C.F.R. § 54.21(a)(1) defines the systems, structures, and components that are subject to aging management review as those that (i) perform an intended function, as described in § 54.4, without moving parts or without a change in configuration or properties; and (ii) are not subject to replacement based on a qualified life or specified time period. 10 C.F.R. § 54.21 (a)(3) requires that the applicant demonstrate that, for each system, structure and component identified under § 54.21 (a)(1), the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation. The license renewal rules define "intended function(s)" as "those functions that are the bases for including them within the scope of license renewal, as specified in [10 C.F.R. § 54](a)(l)-(3).24 As our prior rulings have recognized, groundwater protection is not a function within the scope of 10 C.F.R. § 54.4.25 24 10 CR § 54.4(b).

25 Indeed, the Commission specifically denied a petition for rulemaking that would have revised the scope of license renewal to cover "liquid and gaseous radioactive waste management systems." 66 Fed. Reg. 65,141 (Dec. 18, 2001). The Commission denied the petition because (1) "liquid and gaseous radioactive waste management systems are not involved in design and licensing basis events considered for license renewal," and (2) "the existing regulatoryprocess is acceptable for maintaining the performance of the radioactive waste systems throughout the period of extended operation in order to keep exposures to radiation at the current levels below regulatory limits consistent with the conclusions made in the applicable regulations." Id.

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Thus, with respect to Pilgrim Watch Contention 1, Entergy must demonstrate that its Aging Management Plans ("AMPs") for buried pipes and tanks within the scope of license renewal provide reasonable assurance that those components will perform their "intended functions" as defined in 10 C.F.R. § 54.4(b). In other words, Entergy must demonstrate that the PNPS AMPs have elements that provide reasonable assurance that the in-scope buried pipes and tanks will not develop leaks so great as to cause those pipes and tanks to be unable to perform their intended functions during the license renewal term.

"Reasonable assurance" requires here that Entergy must prove its case by a preponderance of the evidence. See, e.g., Advanced Medical Systems, Inc. (One Factory Row, Geneva, Ohio 44041), CLI-94-6, 39 N.R.C. 285, 302 & n.22 (1994); Amergen Energy Co., LLC (Oyster Creek Nuclear Generating Station), LBP-07-17, 66 N.R.C. 327, 340, 371 (2007) (citin Commonwealth Edison Co. (Zion Station, Units 1 and 2), ALAB-616, 12 N.R.C. 419, 421 (1980)) (license renewal applicant had made requisite showings by a preponderance of the evidence and resolving the sole admitted contention in favor of the applicant). The preponderance of the evidence standard requires "only that the record underlying a finding makes it slightly more likely than not." Inquiry into Three Mile Island Unit 2 Leak Rate Data Falsification, LBP-87-15, 25 N.R.C. 671, 690 (1987); see also Zion, ALAB-616, 12 N.R.C. 419.

Pilgrim Watch has argued that Entergy must demonstrate the adequacy of its programs "with 95 percent certainty." 26 This, however, is not the required legal standard. Indeed, the 95%

26 Pilgrim Watch Presents Statements of Position, Direct Testimony and Exhibits under 10 C.F.R. 2.1207 (Mar. 3, 2008) at 5-10. Pilgrim Watch's argument concerning the meaning of reasonable assurance is lifted nearly verbatim from the intervenor's post-hearing proposed findings in the Oyster Creek license renewal proceeding.

Coinpare Citizen's Post Hearing Proposed Findings of Fact and Conclusions of Law, Docket No. 50-0219-LR (Oct. 10, 2007) (ADAMS accession no. ML073100089) at 52 - 55. However, Pilgrim Watch omitted the portion of those proposed findings acknowledging that the U.S. Court of Appeals for the District of Columbia had rejected the claim that reasonable assurance means "beyond a reasonable doubt." North Anna Envtl. Coal. v.

NRC, 533 F.2d 655, 667-68 (D.C. Cir. 1976). See ML073100089 at 50. Pilgrim Watch also failed to inform the Board that this argument was rejected in the Oyster Creek license renewal proceeding because it was "not supported by Commission regulations or case law." Oyster Creek, LBP-07-17, 66 N.R.C. at 340. Pilgrim Watch 9

certainty standard argued by Pilgrim Watch is "not supported by Commission regulations or case law." Oyster Creek, LBP-07-17, 66 N.R.C. at 340 n.18. Rather, whether an applicant meets the reasonable assurance standard should be evaluated based on "sound technical judgment applied on case-by-case basis" and "compliance with Commission regulations." Id. at 340, cg Union of Concern Scientists v. NRC, 880 F.2d 552, 558 (D.C. Cir. 1989); Maine Yankee Atomic Power Co. (Maine Yankee Atomic Power Station), ALAB-161, 6 A.E.C. 1003, 1009 (1973).

The Commission has made it clear that, in providing reasonable assurance, an applicant does not have to meet an "absolute standard." Zion,ALAB-616, 12 N.R.C. at 421.

"[R]easonable assurance" is not equal to "beyond a reasonable doubt" - the highest level of burden of persuasion and akin to the 95% confidence level advocated by Pilgrim Watch. See North Anna Envtl. Coal., 533 F.2d at 667-68 (equating "reasonable assurance" to "beyond a reasonable doubt" results in a overburden on the applicant). In North Anna Environmental Coalition, the D.C. Circuit found no support in the NRC regulations for placing such a high burden of proof on the applicant: "[h]ad the regulations been intended to require proof beyond a reasonable doubt we believe it would have been clearly so stated." Id. at 667. Likewise, the Commission has noted that "reasonable assurance" as a basis for judging compliance does not imply "a potentially more stringent statistical criteria (e.g*, use of the 95th percentile of the distribution of the estimate of dose)." Final Rule, Disposal of High-Level Radioactive Wastes in a Proposed Geologic Repository at Yucca Mountain, NV, 66 Fed. Reg. 55,732, 55,740 (Nov. 2, 2001).

was certainly aware of this precedent, because it is discussed in a recent petition which Pilgrim Watch's

'representative, Ms. Lampert, signed. See Petition to Suspend License Renewal Reviews (Jan. 3, 2008).

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III. THE PARTIES' WITNESSES AND QUALIFICATIONS A. Entergy Witnesses Entergy's testimony on its AMPs and in-scope buried pipes and tanks was presented by a panel of four experienced and well qualified engineers, Alan B. Cox, Brian R. Sullivan, Steven P. Wood, and William H. Spataro. All four expert engineers are current or retired Entergy staff.

Mr. Cox has served as Entergy's Technical Manager for License Renewal since 2001 and participated in this capacity in preparing the license renewal application and developing the AMPs for the Pilgrim license renewal project. Since.2001, he has worked full-time on license renewal supporting the integrated plant assessment and license renewal application development for Entergy license renewal projects, as well as projects for other utilities. As a member of the Entergy license renewal team, he has participated in the development of seven license renewal applications. In addition, Mr. Cox has participated in industry peer reviews of at least eleven additional license renewal applications. As part of his work on license renewal matters, Mr. Cox is a member of the Nuclear Energy Institute ("NEI") License Renewal Task Force and has been a representative on the NEI License Renewal Mechanical Working Group and the NEI License 27 Renewal Electrical Working Group.

Mr. Cox has 30 years of experience inthe nuclear power industry, having served in various positions related to the engineering and operations of nuclear power plants. He holds a Bachelors degree in nuclear engineering from the University of Oklahoma and a Masters of Business Administration from the University of Arkansas at Little Rock. Further, Mr. Cox has held reactor operator and senior reactor operator licenses issued by the NRC for the operation of 27 Entergy Test. at A2-A3.

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Arkansas Nuclear One, Unit 1. He has been licensed as a registered professional engineer in the 28 State of Arkansas.

Mr. Sullivan has worked at PNPS since 1988 and has served as its Engineering Director since April 2007. During the preparation of the PNPS license renewal application, Mr. Sullivan was the Manager for Engineering Programs and Components for PNPS, in which position he was 29 knowledgeable of the development of the AMPs credited for buried pipes and tanks.

As PNPS Engineering Director, Mr. Sullivan is responsible for providing engineering support at PNPS. His specific duties include maintaining the PNPS design bases; maintaining plant systems through predictive programs and system monitoring; maintaining equipment reliability through preventive maintenance optimization; resolving plant system issues through troubleshooting and problem solving support; providing modifications in support of plant needs; overseeing procedures and documentation which govern and control plant engineering activities; developing and implementing department procedures and corporate level policies; and developing, planning and coordinating or implementing special projects, corrective action plans, 30 or improvement programs to address particular plant or regulatory issues.

Mr. Sullivan holds a Bachelor of Science Degree in Marine Engineering from the Massachusetts Maritime Academy and has more than 24 years of experience in the nuclear power industry. At PNPS, Mr. Sullivan has held positions including Senior Engineer, Control Room Supervisor, Shift Manager, Assistant Operation's Manager ("AOM") Shift, Outage Manager, AOM Support, Programs and Components Manager, Systems Engineering Manager, 28 Entergy Test. at A3.

29 Entergy Test. at A5-A6.

30 Id.

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and now Engineering Director. He was a licensed Senior Reactor Operator and held a United States Coast Guard License as a Second Assistant Engineer.31 Mr. Woods has worked at PNPS since 2000 and currently serves as Manager for Engineering Programs and Components. In that position, he is responsible for developing and maintaining engineering programs and standards as well as monitoring plant components and replacement parts. His specific duties include overseeing code programs, plant programs, predictive maintenance and valve programs; maintaining equipment reliability through preventive maintenance; ensuring that replacement parts and components meet safety standards and technical specifications; managing and coordinating engineering work activities; overseeing procedures and documentation which govern and control plant programs, components, and engineering activities; and interfacing with regulatory and industry representatives on behalf of 32 station activities.

Mr. Woods also worked as a contractor at PNPS as the Site Mechanical Project Engineer dedicated to the Salt Service Water Pipe Replacement project from May 1992 to July 1993. In that role, Mr. Woods was responsible for the site engineering and installation of the titanium piping for the salt service water inlet line, including excavation, shoring of the trenches, construction of concrete vaults, assembly and installation of pipe, and backfilling of 33 excavation.

Mr. Woods holds a Bachelor of Science Degree in Marine Engineering from the Massachusetts Maritime Academy. He has more than 26 years of experience applying engineering methods and capabilities to various projects and engineering disciplines, including repairing and maintaining marine and nuclear facilities, designing and preparing modifications 31 Entergy Test. at A6.

32 Entergy Test. at A8-A9.

33 Entergy Test. at A9.

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for new and existing systems, implementing effective and efficient nuclear power plant procedures, and analyzing mechanical components and piping systems. 34 Prior to his current position, Mr. Woods served at PNPS as the Supervisor Code Programs, Engineering Programs &

Components and as the Senior Engineer, Design Engineering for the Mechanical/Civil/Structural group, where he performed all facets of design engineering, including nuclear changes and field support.3 5 Mr. Spataro served as the Senior Staff Engineer-Corporate Metallurgist with Entergy until his retirement on December 31, 2007. Mr. Spataro is a National Board Registered Certified Nuclear Safety Related Coating Engineer, and since commencing his professional career in 1968, he has worked extensively with applied coatings used to protect buried piping from corrosion.

He has written procedures used for the applications of coatings in the power industry, including hydroelectric, nuclear, fossil, oil, and gas facilities, and has evaluated the effectiveness of coatings that have been in service for many years. He has been involved with the construction of at least 30 nuclear power stations where he specified and evaluated corrosion resistant coatings for use on buried piping, and has worked on projects requiring the specification of coatings and 36 the excavation, analysis, recoating, and re-burying of piping used in the nuclear industry.

As the Senior Staff Engineer-Corporate Metallurgist for Entergy, Mr. Spataro provided technical support in metallurgy, corrosion, welding, and forensic investigation in support of Entergy's operation of its nuclear power plants. Prior to Entergy's purchase of the FitzPatrick and Indian Point Unit 3 plants, Mr. Spataro was Director of Materials Engineering - Consulting Metallurgist for the New York Power Authority ("NYPA"). In that capacity, he managed metallurgical and chemical engineers supporting the operation of NYPA's nuclear, fossil-fueled, 34 Entergy Test. at A9.

35 Id.

36 Entergy Test. at Al 1, A66.

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pumped storage, and hydroelectric power projects and its transmission lines and under-water 37 cables.

Mr. Spataro holds a Bachelor of Engineering (in Metallurgy) degree from New York University. He has nearly 40 years of experience in the fields of metallurgy, welding, corrosion, and forensic investigation, including 27 years of service with Entergy and the NYPA. In addition to being a National Board Registered Certified Nuclear Safety Related Coating Engineer, Mr. Spataro is a Registered Professional Engineer in Connecticut and New York, and 38 an American Welding Society Certified Welding Inspector and Certified Welding Educator.

The Board finds these witnesses well qualified and knowledgeable.

B. Nuclear Regulatory Commission Staff Witnesses The NRC Staff 's testimony concerning Contention 1 was presented by a panel of three equally experienced and well qualified experts, Dr. James A. Davis, a Senior Materials Engineer in the Division of License Renewal, Office of Nuclear Reactor Regulation ("NRR"), Terence L.

Chan, the Chief of the Piping and NDE Branch in the NRR Division of Component Integrity, and Andrea T. Keim, a Materials Engineer in the NRR Division of Component Integrity.

Dr. Davis holds a Doctorate degree in metallurgical engineering and was the audit team leader of the license renewal safety audit team at PNPS. Dr. Davis has worked on coating and corrosion control since 1968, and has worked on coatings issues at nuclear facilities for the past seventeen years at the NRC. Prior to joining the NRC, Dr. Davis worked for a commercial pipeline coating company where he was responsible for a major pipeline coating research project, presented numerous technical papers on pipeline coatings, and examined and evaluated the conditions of pipeline coatings that had been in service for many years. Dr. Davis also has 37 Entergy Test. at All.

38 Entergy Test. at A12.

15

been involved in all aspects of corrosion and corrosion control, including basic research, technical committee work, and while at the NRC, reviewing licensee submittals on a wide range 39 of corrosion issues.

As the audit team leader, Dr. Davis led three safety audits with a team of four NRC staff members, three contractors, two NRC trainees, and one foreign assignee. Dr. Davis reviewed portions of Entergy's license renewal application ("LRA"), including AMPs, and ensured that the remaining AMPs were adequately reviewed. Prior to becoming a safety audit team leader, Dr. Davis was responsible for conducting reviews of coating issues, corrosion of metals, service water issues, threaded fasteners, and license renewal.4 ° Mr. Chan, the Branch Chief for Piping and Nondestructive Examination ("NDE"),

manages and provides technical review to eight engineers involved in the evaluation of generic and plant-specific materials degradation and NDE issues, American Society of Mechanical Engineers ("ASME") Code and standards activities, and inservice inspection ("ISI") activities.

Mr. Chan represents the NRC on four groups within the ASME that address materials degradation or inspection issues: Task Group on Alloy 600, Task Group on Alternate NDE, Working Group on General Requirements, and Subgroup on NDE.41 Ms. Keim is a materials engineer who performs safety reviews of nuclear power plant piping and NDEs of operating nuclear power plants, license renewal applications, and new reactor design certifications. Ms. Keim is further responsible for conducting reviews of corrosion of metals, NDEs, risk-informed ISI programs and repair/replacement activities. Ms.

39 Davis Test. at A3.

40 Davis Test. at A2, A4.

41 Staff Test. of Chan and Keim at A2a.

16

Keim represents the NRC on the ASME Section XI Code working group on Implementation of 42 Risk Based Examinations.

The Board also finds the NRC Staff's witnesses well qualified and knowledgeable C. Pilgrim Watch Witnesses Mr. Gundersen is a nuclear engineer who is currently employed as a high school teacher and has not worked in the nuclear industry in the past 18 years. 43 While we accepted Mr.

Gundersen's testimony, Mr. Gundersen did not demonstrate that he has any education, knowledge, or experience with the design, construction, inspection, or protection of buried piping. Likewise, he did not demonstrate that he has any education, knowledge, or experience with metallurgy or coatings. Indeed, Mr. Gundersen testified that he has no experience with the type of internal liner and epoxy coatings protecting the SSW discharge piping.44 Furthermore, Mr. Gundersen does not purport to hold any certifications or other qualifications in these fields.

None of the areas in which he has worked, as identified in paragraph 7 of his January 26 testimony and in pages 3-4 of his March 6 testimony, appears relevant to the aging management of buried piping.

Mr. Gundersen's testimony states that he was a "Senior Vice President for a nuclear licensee." 45 As indicated in his Curriculum Vitae, Mr. Gundersen has never been an officer at a nuclear plant. Rather, it appears that he was an officer at a vendor, Nuclear Energy Services.

Mr. Gundersen's testimony was not based on direct personal knowledge of relevant facts or experience at Pilgrim, or at other-plants, and his opinions generally lacked credible support.

In particular, there is no indication that Mr. Gundersen has any familiarity with the design of the 42 Staff Test. of Chan and Keim at A2b.

43 Gundersen Declaration, Curriculum Vitae.

44 Tr. at 666, 668, 706.

45 Compare Gundersen Test. at 4-5 with Entergy Test. at A24-A26.

17

Pilgrim plant and his testimony suggests a lack of familiarity with BWR designs. For example, Mr. Gundersen did not know the difference between the standby gas treatment system and the 46 off-gas system.

Dr. Ahlfeld is a professor in the Department of Civil and Environmental Engineering at the University of Massachusetts, Amherst. Dr. Ahlfeld, however, has no experience in the nuclear industry. 47 He teaches, conducts research and has worked on projects in the area of groundwater flow and contaminate subsurface transport and related topics for nearly twenty years. While we accepted his testimony, it is of limited relevance.

IV. FINDINGS OF FACT A. Determination of Buried Pipes and Tanks within the Scope of Contention 1

1. License Renewal Systems with Buried Pipe and Radioactive Liquids

1. To fall within the scope of Contention 1, the buried pipes and tanks must (a) fall within the scope of license renewal, and (b) contain radioactively contaminated water.

2. Entergy identified six systems with buried pipes and tanks that meet, at the system level, the scoping criteria of 10 C.F.R. § 54.4. These are: (1) the CSS; (2) the fire protection water system; (3) the fuel oil system; (4) the SSW system; (5) the standby gas treatment system ("SGTS"); and (6) the station blackout diesel generator system.48

3. None of the parties claim that the fire protection water system, the fuel oil system, or the station blackout diesel system contain radioactively contaminated water. Therefore, these three systems are beyond the scope of Contention 1. Likewise, Entergy and the NRC Staff testified that the SGTS piping carries gas, not water, and is therefore beyond the scope of 46 Comvare Gundersen March 6 Test. at 4-5 with Entergy Test. at A24-A25.

47 Declaration of Dr. Ahlfeld.

48 Entergy Test. at A23.

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Contention 1.49 Mr. Gundersen's written testimony claimed that the buried SGTS piping could contain radioactive liquids. 50 As Entergy pointed out however, and as the NRC Staff s testimony essentially confirms, Mr. Gundersen's testimony pertains to a different system - the off-gas system - that is not within the scope of license renewal. 51 At the 52 hearing, Pilgrim Watch elected to "drop" this claim.

4. The only system with buried pipe that Entergy identified as meeting the license renewal scoping criteria and containing radioactive liquid is the CSS. 53 It is also possible that the SSW system could contain some radioactivity if a cross-contamination event were to occur. 54 However, the SSW system has no history of cross contamination that would introduce radioactivity into the SSW discharge piping, and regular monitoring of the 55 discharge has never indicated the presence of radioactivity.

2. The CSS Buried Pipe Serves No License Renewal Intended Function

5. In a boiling water reactor facility, such as PNPS, the CSS contains radioactively contaminated water. 56 The CSS at PNPS consists of two 275,000 gallon condensate storage tanks ("CSTs") and associated piping and equipment. 57 Through buried piping, the CSTs provides a "preferred" source of water for the reactor core isolation cooling

("RCIC") and the high pressure coolant injection ("HPCI") systems because of its higher quality and cleanliness.58 However, the CSS is not the assured (safety-related) source of 49 Entergy Test. at A24; Davis Test. at Al 6; Staff Test. of Chan and Keim at A6.

50 Gundersen Reb. Test. at 4.

51 Entergy Test. at A24-26; Davis Test. at A16.

52 Tr. at 832-33, 835.

53 Entergy Test. at A24; Davis Test. at A7.

54 Entergy Test. at A24, A32; Staff Test. of Chan and Keim at A6.

55 Entergy Reb. Test. at A35; see also Entergy Test. at A32.

56 Entergy Test. at A24; Tr. at 780 (Cox).

57 Entergy Test. at A24; Staff Test. of Chan and Keim at A10; Exh.53 (PNPS FSAR Excerpt 11.9 - Condensate Storage System). The CST's are not buried. The CSS has no buried tanks. Entergy Test. at A24.

58 Tr. at 781-83 (Cox); Entergy Reb. Test. at A44.

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water for the RCIC or HPCI systems. 59 The assured source of water for the RCIC and 60 HPCI systems is the suppression pool or torus.

6. The RCIC system provides makeup water to the reactor vessel following reactor vessel isolation in order to ensure adequate core cooling. The RCIC system is normally connected via piping to the two 275,000 gallon CSTs. Each CST has a 75,000 gallon reserve dedicated to the HPCI and RCIC systems. While the CSS is the preferred source of water for the RCIC pumps because of its cleanliness, the assured safety supply of cooling water for the RCIC system is the suppression pool or torus. If water is unavailable from the CST for any reason, the safety function of the RCIC system is accomplished by using water from the torus.61

7. The function of the HPCI system is to ensure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the nuclear system which does not result in rapid depressurization of the reactor vessel. The HPCI system is designed to maintain sufficient reactor vessel water inventory until the reactor vessel is depressurized to the point at which the low pressure coolant injection system or core spray system are used to maintain core cooling. Like the RCIC system, the preferred source of water for the HPCI system is the CSS. While the CSS is the preferred source of water for the HPCI pump because of its cleanliness, the assured safety supply of cooling water for the HPCI system is the suppression pool or torus. If water is unavailable from the CST for any 9 Tr. at 781-82 (Cox); Entergy Test. at A28.

60 Tr. at 781-83 (Cox); Entergy Test. at A28: Staff Test. of Chan and Keim at A10; Exh.53 (PNPS FSAR Excerpt 11.9 - Condensate Storage System); Entergy Reb. Test. at A44.

61 Entergy Test. at A28; Entergy Reb. Test. at A44; Tr. at 781-83 (Cox); Staff Test. of Chan and Keim at A10; Exh.53 (PNPS FSAR Excerpt 11.9 - Condensate Storage System).

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reason, the safety function of the HPCI system is accomplished by using water from the 62 torus.

8. The CSTs are connected to the RCIC and HPCI systems by stainless piping. Piping runs from the bottom of each of the two 275,000 gallon CSTs, which are above ground, to an underground CST vault where the pipes are connected to a common header. 63 The header connects to a single stainless steel pipe that leaves the CST vault and runs underground to the reactor building auxiliary bay. 64 The buried stainless steel pipe runs approximately sixty-four feet underground before entering the reactor building auxiliary bay. 65 The 66 buried pipe is approximately seven to ten feet below grade.

9. Entergy performed scoping at the system level and conservatively included the CSS within the scope of its license renewal review because non-buried portions of the CSS piping are directly connected to portions of the HPCI and RCIC systems, even though the CSTs are not relied upon to mitigate accidents. 67 This conservative scoping decision does not mean that each segment or component of the system performs a license renewal intended function. 68 Thus, while Entergy conservatively included the CSS in scope, the buried CSS piping is not safety-related and is not relied upon to provide the assured source of water for HPCI and RCIC (indeed, the CSTs are not even seismically qualified). 69 Therefore, the buried CSS piping serves no license renewal intended function under 10 C.F.R. § 54.4(a)(1).

62 Tr. at 781-83 (Cox); see also Entergy Test. at A28; Entergy Reb. Test. at A44; Staff Test. of Chan and Keim at Al0; Exh.53 (PNPS FSAR Excerpt 11.9- Condensate Storage System).

63 Tr. at 785 (Cox); Entergy Test. at A24.

64 Entergy Test. at A24.

65 Entergy Test. at A24.

66 Entergy Test. at A24.

67 Entergy Reb. Test. at A36; Tr. at 779-80 (Cox).

68 Tr. at 779-80 (Cox).

69 Tr. at 779-80 (Cox); Entergy Reb. Test. at A30.

.21

10. Similarly, Entergy also conservatively credited the CSS under 10 C.F.R. § 54.4(a)(3) because the HPCI and RCIC systems are relied upon in the Appendix R shutdown analyses. 70 However, the Appendix R shutdown analyses only credit the HPCI and RCIC functions and place no particular reliance on the CSTs as the source of water for these functions. 71 Again, the assured source of water for the HPCI and RCIC functions is the torus. Thus, the buried CSS piping is not in fact relied upon for any of the 10 C.F.R. § 72 54.4 functions.

11. The Staff agrees that the CSS is the only system within the scope of Contention 1 that contains radioactive liquid by design and that the system includes no buried tanks. 73 The Staff also agrees that the CSS buried piping does not provide a credited safety function and 74 does not provide accident mitigation.

12. Pilgrim Watch's expert witness, Mr. Gundersen, conceded that the buried CSS piping is not relied upon to perform a safety function, but suggested that a failure of this piping might result in the introduction of contamination into the pumps and reactor. 75 Mr.

76 Gundersen acknowledged, however, that this hypothesis was not based on any analysis.

Further, Entergy testified that the possibility of debris being drawn in was not credible because of the considerable head in that pipe.77 In addition, the buried CSS piping is above the water table. 78 Further, even if it were not, contamination could only be drawn in through the venturi effect if there were a loss of net positive suction head ("NPSH") but 70 Entergy Reb. Test. at A36.

7' Entergy Reb. Test. at A36; see also Entergy Test. at A28.

72 Tr. 780 (Cox).

73 Davis Test. at A7.

74 Staff Test. of Chan and Keim at A7, A8, AlO; Tr. at 789 (Cox).

71 Tr. at 795-96, 800-803 (Gundersen).

76 Tr. at 809 (Gundersen).

77 Tr. at 813 (Sullivan).

78 Tr. at 839 (Cox); see also Entergy Test. at A86.

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such a loss would cause the HPCI and RCIC pumps to trip. 79 Moreover, Mr. Gundersen 80 admitted that he did not question Entergy's ability to maintain a safe shutdown condition.

13. Dr. Ahlfeld suggested that the presence of temporary perched water might result in a pressure head outside of the pipe. 8 1 However, CST piping is buried in engineered fill which is very porous and does not retain water but allows it to percolate through.82

14. In summary, after closely reviewing the evidence presented at hearing, we conclude that the buried CSS pipe does not provide a safety or other license renewal intended function within the scope of 10 C.F.R. § 54.4. We therefore conclude that aging of this buried piping cannot result in the loss of an intended function required by 10 C.F.R. § 54.4.

15. We do note that, because Entergy has conservatively treated the entire CSS as being within the scope of license renewal, the buried stainless steel CSS pipe is subject to the applicable PNPS license renewal AMPs for external and internal degradation. As discussed in Section IV.B infra, we find that these programs provide an acceptable aging management program for the buried stainless steel CSS pipe even if it had an intended function as defined in the license renewal rules.

3. Salt Service Water System

16. The SSW system operates as the ultimate heat sink to transfer heat from safety-related plant equipment and non-safety-related plant equipment. The SSW system cools the reactor building closed cooling water ("RBCCW") system, which in turn cools safety-related equipment. The SSW system draws water through the intake structure and pumps this water to the RBCCW heat exchangers to cool the RBCCW system water. 83 The SSW 79 Tr. at 839-40 (Cox).

80 Tr. at 825-27 (Gundersen).

81 Tr. at 841 (Ahlfeld).

82 Entergy Test. at A63, A83.

83 Entergy Test. at 32; Tr. at 608 (Cox).

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system then discharges the cooling water back into the bay.8 4 The RBCCW system separates the SSW system from systems normally containing radioactively contaminated water. 85

17. The SSW system.has two license renewal intended functions. Regarding 10 C.F.R. § 54.4(a)(1), the SSW system is the ultimate heat sink for all of the systems cooled by the RBCCW system under transient and accident conditions, as well as normal operations, by continuously providing adequate cooling water flow to the RBCCW heat exchangers. This same function is also credited under 10 C.F.R. § 54.4(a)(3) because the SSW is credited in the 10 C.F.R. Part 50 Appendix R safe shutdown analysis for fire protection. The buried 6

piping in this system does not meet the scoping criterion of 10 C.F.R. § 54.4(a)(2).

18. The SSW system includes two loops of buried intake pipes and two loops of buried discharge pipes and no buried tanks. 87 The two buried intake pipes do not contain radioactive water since they draw water from Cape Code Bay.88 Therefore, the buried intake piping is not within the scope of Contention 1 .89

19. The two loops of buried SSW system discharge piping are Loop A, which runs 240 feet from the reactor building auxiliary bay to the discharge canal that runs into Plymouth Bay, and Loop B, which runs 225 feet from the reactor building auxiliary bay to the discharge canal. 9° 84 Entergy Test. at A32.

85 Entergy Test. at A32.

86 Entergy Test. at A30.

87 Entergy Test. at A33.

88 Entergy Test. at A33; Tr. at 608 (Cox).

89 Entergy Test. at A33; Tr. at 609 (Cox).

90 Entergy Test. at A24.

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20. The RBCCW loop is an intermediate loop between the SSW and the primary systems that contain radioactive liquid. 91 In order for the SSW to become contaminated with radioactive fluid, the RBCCW system must first become contaminated due to leakage through heat exchanger tubes. Then, there must be cross contamination due to leakage 92 through additional heat exchanger tubes from the RBCCW system to the SSW system.

However, the SSW system has no history of cross contamination that would introduce radioactivity into the SSW discharge piping, and regular monitoring of the discharge has never indicated the presence of radioactivity. 93 The NRC Staff confirmed that the SSW 94 does not contain radioactive liquids by design.

21. In summary, the uncontroverted testimony demonstrates that the SSW system is highly unlikely to contain radioactively contaminated water. Accordingly, there is no evidence in the record indicating that the SSW discharge piping constitutes buried pipes "that contain radioactively contaminated water." Therefore, there is no indication that this piping is within the scope of Pilgrim Watch's contention.

B. The PNPS Aging Management Programs for In-Scope Systems Provide Reasonable Assurance that Leaks Challenging License Renewal Intended Functions Will Not Occur

1. Summary Overview of AMP Findings

22. Pilgrim implements multiple programs to manage the effects of aging on buried piping and tanks that are within the scope of license renewal and subject to aging management review.

The applicable AMPs for in-scope buried pipes and tanks that contain or potentially contain radioactively contaminated water are (1) the Buried Piping and Tanks Inspection 91 Tr. at 608 (Cox); Entergy Test. at A32..

92 Entergy Test. at A32.

93 Entergy Reb. Test. at A35.

94 Davis Test. at A7; Staff Test. of Chan and Keim at A6.

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Program ("BPTIP"); (2) the Water Chemistry Control-BWR Program; (3) the Service Water Integrity Program; and (4) the One-Time Inspection Program. The BPTIP manages the loss of material due to external degradation of buried pipes, while the other AMPs 95 manage loss of material due to internal degradation of buried pipes.

23. We have reviewed the AMPs, the relevant testimony, and other evidence concerning the potential for buried pipe to develop leaks so significant that they cannot perform their license renewal intended function. As applied to buried pipes, the objective of these AMPs is to maintain the pressure boundary of the buried pipes and tanks in a manner so as to provide reasonable assurance that the associated systems can perform their intended functions. We have concluded, as set forth below, that the AMPs provide this reasonable assurance and that there is no credible evidence that in-scope buried pipes will develop leaks so great as to challenge their license renewal intended functions. We find that the AMPs, by themselves, are adequate to provide reasonable assurance that license renewal intended function challenging leaks will not occur and that the installation of monitoring wells is not necessary to achieve this objective.

24. Entergy's testimony in this proceeding describes Entergy's AMPs and demonstrates the adequacy of those programs to ensure that license renewal challenging leaks will not occur.96 Entergy testified, and the NRC Staff confirmed, that these AMPs are consistent with the Generic Aging Lessons Learned ("GALL") Report, NUREG-1 801.9' The GALL Report is referenced as the technical basis document for NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants." It identifies AMPs that have been determined by the NRC to be acceptable programs to manage the 95 Entergy Test. at A35; Tr. at 775-77 (Cox).

96 See generally Entergy Test.

97 Entergy Test. at A72, A94, A99, A102, A130; Davis Test. at A10, A13.

26

effects of aging on systems, structures and components within the scope of license renewal as required by 10 C.F.R. Part 54. The NRC Staff developed the GALL Report at the direction of the Commission to provide a basis for evaluating the adequacy of aging management programs for license renewal. The GALL Report is based on a systematic compilation of plant aging information and evaluation of program attributes for managing the effects of aging on systems, structures and components for license renewal. 98 While subject to challenge in a hearing, compliance with NRC guidance is nevertheless 99 substantial evidence of compliance with the NRC's regulatory requirements.

2. Aging Management of External Degradation -

The Buried Pipe and Tank Inspection Program

a. Summary Overview of BPTIP Findings

25. We will first discuss the sufficiency of the Buried Piping and Tanks Inspection Program

("BPTIP") to protect against external degradation of license renewal buried pipe. The BPTIP is set forth in Section B. 1.2 of Appendix B to the PNPS license renewal application

("LRA"). The objective of the BPTIP is to manage the effects of aging on the external surfaces of buried components, specifically, the potential loss of material (i.e., the effect of aging caused by corrosion) from the external surfaces of components buried in soil.'°°

26. As explained in the PNPS LRA and by Entergy's witnesses, the BPTIP has two separate but interrelated prongs. The first is the use of preventive measures to inhibit the degradation of buried pipe surfaces exposed to soil, such as selection of corrosion resistant materials and/or application of protective coatings.1'0 PNPS uses corrosion resistant 98 Entergy Test. at A73; GALL Report, Exh. 7 at 1-3, admitted Tr. 572.

99 Guidance documents, such as NUREGs or the Standard Review Plan, do not have the force of legally binding regulations. Private Fuel Storage, L.L.C. (Independent Spent Fuel Storage Installation), CLI-O1-22, 54 N.R.C.

255, 264 (2001). However, where the NRC has developed guidance documents assisting in compliance with applicable regulations, they are entitled to special weight. Id.

100 Exh. 5 at B B-18 (LRA, Appendix B, Excerpts) (Admitted at Tr. 572).

101 Entergy Test. at A36.

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materials, such as stainless steel and titanium, as well as impermeable coatings to protect against the loss of material due to corrosion and other aging effects.' 0 2 The second.is the use of inspections to manage the effects of external surface corrosion on the pressure-10 3 retaining capability of buried carbon steel, stainless steel, and titanium components.

PNPS will conduct various inspections both before and during the period of extended operation to determine whether the protective coatings on the buried pipe are remaining in 04 place so as to prevent external degradation of the pipe as designed. 1

27. Dr. Davis, expert witness for the NRC Staff, confirmed this two-pronged approach for managing the aging effects of external corrosion under the BPTIP. Dr. Davis testified that the BPTIP AMP calls for using "preventive measures to mitigate corrosion and periodic inspections to determine if corrosion is occurring that could affect the pressure-retaining 05 capacity of the buried steel piping and tanks."'1

28. Dr. Davis and Entergy's expert, Mr. Spataro, have extensive experience in the use of protective coatings to protect against the external degradation of buried pipe.10 6 Both Dr.

Davis and Mr. Spataro have provided credible testimony, based on their many years of experience, that the BPTIP provides reasonable assurance against the external degradation of the buried pipe. This testimony is supported by actual field experience at PNPS which revealed the coatings on 25-year old buried pipe to be in place as designed and the external surface of the piping to be in its original pristine condition. 10 In contrast, Mr.

102 Entergy Test. at A38-A42, A47.

103 Entergy Test. at A36.

104 Entergy Test. at A75-A77; Tr. 777 (Cox). Entergy has developed a procedure that specifies the inspection methods for buried pipes (including inspections of buried pipes beyond the scope of the BPTIP). Entergy Test. at A78-A79. Exh. 8 (Procedure No. EN-DC-343, Rev. 0, Buried Piping and Tanks Inspection and Monitoring Program) (admitted at Tr. 572).

105 Davis Test. at A9.

106 Entergy Test. at A66; Davis Test. at A3.

107 Entergy Test. at A74.

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Gundersen's testimony and resume shows no experience in the use of protective coatings for buried pipe.108 Therefore, based on the evidence in the record, we find, as set forth in detail below, that the BPTIP provides reasonable assurance that external degradation will not adversely affect the performance of license renewal intended functions for in-scope buried pipe.

b. PNPS Use of Corrosion Resistant Materials and Impermeable Coatings to Protect Against External Degradation of Buried Pipe

29. PNPS uses several preventive methods as part of the BPTIP AMP to protect against the external degradation of buried pipe.10 9 First, the buried CSS piping and the SSW inlet piping are made of stainless steel and titanium, respectively. Second, PNPS wrapped the SSW and CSS buried piping with a permanent coal-tar or epoxy protective wrapping on the exterior to create a barrier between the pipe and the external environment. Third, PNPS has taken precautions to ensure that piping is not buried in corrosive soil and that when it is buried or excavated, the pipe is handled in a manner that does not damage the 0

protective coatings."Il (i) Use of Corrosion Resistant Materials

30. Entergy's and the Staff's expert witnesses agree that stainless steels are generally resistant to corrosion in soils. 11' While pitting corrosion can occur on some grades of stainless steel under particular conditions (high temperatures, high concentrations of chloride, and low pH levels generally less than 4.5), the CSS buried pipe is not exposed to such conditions. 112 Furthermore, notwithstanding the corrosion resistant properties of stainless 108 See Gundersen Test. and Curriculum Vitae; see also Tr. at 705-706 (Gundersen).

109 Entergy Test. at A37.

110 Entergy Test. at A37-A65; See also Tr.-756-757 (Woods).

111 Entergy Test. at A39; Tr. at 812-13 (Sullivan); Davis Test. at A13.

112 Entergy Test. at A39.

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steel, the CSS buried pipe is wrapped with a permanent coal-tar enamel coating as described below.

31. The SSW inlet pipe is made of titanium. 113 Titanium is immune to corrosion in soils.

Titanium and its alloys are resistant to corrosion from all natural waters and steam to temperatures in excess of 600'F and exhibit negligible corrosion in seawater to temperatures as high as 5007F. 114 Additionally, the buried external surfaces of the SSW inlet pipes at PNPS are also wrapped with permanent coal-tar enamel coating to 115 supplement the titanium pipe's already strong corrosion resistant properties.

32. As stated above, the SSW discharge pipe consists of loops A and B. Both loops of the SSW discharge pipe are made of carbon steel, and the exterior surfaces of both discharge loop pipes are covered with multi-layer permanent coal-tar enamel or epoxy coatings as described below.' 16 The coatings form a moisture and chemical resistant barrier that is permanently bonded to the outer surface of the pipe, creating a waterproof barrier between the soil and the pipe.,17 (ii) Use of Protective Coatings on PNPS Buried Pipe

33. Specification No. 6498-M-306, "Specification for External Surface Treatment of Underground Metallic Pipe for Unit No. 1 Pilgrim Station No. 600 Boston Edison Company," ("Specification M-306") specifies the application of permanent coatings to the 113 Davis Test. at Al1.

114 Entergy Test. at A41; Davis Test. at A10.

115Entergy Test. at A54; Tr. 720-21 (Sullivan).

116 Entergy Test. at A46.

117 Entergy Test. at A47.

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external surfaces of buried piping at PNPS. 18 This specification applied to the original SSW buried piping as well as the CSS buried piping. 119

34. As testified to by Mr. Woods, Specification M-306 provides procedures for installing and inspecting coatings applied in the shop as well as for coatings applied in the field at PNPS.

Regarding coatings applied in the shop, Specification M-306 requires the following eight steps:

• The pipe is first cleaned of all dirt, grease, mill scale, or any loose debris using some mechanical means, e.g*, impact wheel or wire brush; Following cleaning of the pipe, a layer of primer is painted onto the exterior of the cleaned pipe;

• After applying the primer, a coal-tar enamel coating is applied to the clean dry surface of the pipe at the correct temperature to ensure that the primer bonds with the enamel to form a coating which cannot be peeled from the pipe;

• The enamel is then visually inspected for uniformity;

• Before the enamel cools, a fiber-glass pipe wrapping is applied over the enamel in a uniform wrap to cover the entire outside surface of the enamel;

• Thereafter, an additional layer of coal-tar enamel is applied;

• The second layer of enamel is followed by an outerwrap of insulation; and

• A final layer of heavy Kraft 0 paper is wrapped around the entire pipe to complete the process.12

35. Thus, Specification M-306 provides for double wrapping of buried pipe consisting of a permanent protective coal-tar coating, fiberglass wrapping, another layer of coal-tar, a layer of insulation, and a final layer of heavy Kraft paper. This double wrapping specified for PNPS buried pipe exceeds the standard industry practice, which only requires a single wrapping for buried piping under normal soil conditions, such as those at PNPS. The coal-11Exh. 6 (Admitted at Tr. at 572).

119 Entergy Test. at A46.

120 Entergy Test. at A48; see also Davis Test. at Al1.

31

tar enamel permanent coating and bonded double outerwrap used at PNPS is specifically designed for use on submerged lines, river crossings, or similar installations that experience aggressive environments, or where trench conditions are extraordinarily severe, conditions which do not exist at PNPS.a2

36. Specification M-306 also provides specific instructions on field installation of coatings at the joints where pipe segments are joined. Mr. Woods testified that, in accordance with Specification M-306,122 PNPS first cleans the piping by wire brushing to remove any rust, scale, dust, or dirt and by removing oil or grease with a solvent. Following cleaning of the pipe, PNPS applies a layer of primer to the exterior of the cleaned pipe, which is then allowed to dry. Next, PNPS applies coal-tar tape to the primed surface. The coal-tar tape is a 35-millimeter cold-applied tape coating consisting of a 7-millimeter polyethylene film 23 backing and 28 millimeters of adhesive. 1

37. The coatings were inspected at every stage in the installation process. Specification M-306 requires that all shop applied coatings be inspected in accordance with Specification AWWA C-203 before shipment. AWWA C-203 requires visual inspection of the coated piping for any misapplication of the coatings followed by an electrical inspection of the pipe coating by a high-voltage "holiday" detector to identify any voids in the coating. In the field, the pipes are visually inspected upon receipt to ensure that no damage occurred during shipment. After the pipes are fully joined and assembled in place and the field joints are wrapped, and before covering them with soil, the entire pipe is again tested for 121Entergy Test. at A57; see also Entergy Test. at A82 - A89.

122 Mr. Woods was responsible for the installation of the titanium buried piping for the SSW intake at PNPS in 1992-93 and is generally knowledgeable of the procedures for the installation of buried piping PNPS and the industry generally. Entergy Test. at A58; see also Tr. at 755-57 (Woods).

123 Entergy Test. at A49; see also Tr. at 755-56 (Woods).

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voids using a high voltage "holiday" detector to assure that the field joints were properly wrapped and that the shop applied coatings were not damaged during installation.124

38. In 1999, PNPS replaced two forty-foot sections of the SSW discharge piping. 125 The coatings used on the two forty-foot section of replacement SSW discharge piping were an aliphatic amine epoxy coating. A minimum of two coats were applied to each length of piping in the shop to achieve a dry thickness of at least 30 millimeters, and all coated areas were "holiday" tested after the curing was complete. The joints between the two forty-foot sections and the existing pipe were coated in the field.126 The epoxy coating used on the two forty-foot replacement pipes has excellent corrosion resistance equal to or superior to 27 the original double wrapped coatings used on the original SSW discharge piping.1

39. Mr. Spataro testified that the coatings form a barrier resistant to moisture and chemicals that is permanently bonded to the outer surface of the pipe, creating a waterproof barrier between the soil and the pipe. As long as the protective coating remains in place, the buried piping is protected from external degradation. 128 Pilgrim Watch provides no contrary evidence. Based on the evidence, we therefore find that the coatings form a impermeable, protective barrier resistant to moisture and chemicals that protects the buried piping from external degradation.

(iii) Handling Precautions and Protective Environment for PNPS Buried Pipe

40. PNPS took special precautions in burying PNPS piping to ensure that the protective coating remains in place. PNPS utilizes dig-safe measures, safe handling procedures, 124 Entergy Test. at A5 1; see also Tr. at 756 (Woods).

2 5 :Entergy Test. at A42.

126 Entergy Test. at A53.

127 Entergy Test. at A53; see also-Davis Test. at Al1.

128 Entergy Test. at A47; see also Entergy Test. at A67, A71, A90.

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control of the soil surrounding the pipe, and compaction testing to ensure the buried pipes 29 will not corrode and develop leaks. 1

41. During installation of the buried pipe, Specification M-306 requires that the coated pipes be handled with non-abrasive canvas or leather straps, or nylon belts. Chains and other abrasive items are prohibited. 130 Dr. Davis testified that PNPS used non-abrasive canvas 13 1 or leather belts, controlled backfill, and compacted soil while handling the pipe at issue.

The Staff agrees that Entergy takes sufficient precautions when burying piping to ensure that the protective coating remains in place.

42. PNPS excavates the soil in layers in order to maintain control of the soil surrounding the pipe. Once a layer of soil is excavated, it is stockpiled separately from the other layers.

Layers can be as small as six inches in depth. The pipe itself is placed on a bed of sand or specially engineered fill, which consists mostly of fine aggregate sand and specified amounts of fly ash and cement, of approximately 6 inches. The pipe is then covered with another layer of sand or the specially engineered fill material before being covered by the contaminant-free, controlled soil. During backfilling, layers are replaced in the order in which they were removed. Generally, soils are replaced and compacted every six inches, and after twelve inches of backfill is added, the soil is tested to ensure sufficient compaction. 132

43. Based on this evidence in the record, the Board finds that PNPS has taken appropriate precautions to ensure that the coatings on the buried piping are not damaged during installation and will remain in place to protect the buried piping from external degradation.

129 Entergy Test. at A59-A64.

130 Entergy Test. at A61.

131Davis Test. at A12.

132 Entergy Test. at A62-A63; see also Tr. at 756-57 (Woods).

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44. PNPS has also taken precautions to ensure that piping is not buried in an aggressive soil environment. 133 As stated, the buried pipe is placed on a bed of sand or specially engineered fill before it is covered by another layer of special engineered fill or sand. The sand and the engineered fill material do not retain water, but allow water to percolate 134 through the soil and avoid the build-up of corrosive conditions next to the buried pipe.

45. Additionally, during construction of PNPS, the site was excavated for the construction of the various PNPS buildings. During excavation, all rocks over six inches, shrubs, and trees were removed from the soil. Rocks can cause physical damage to buried structures and 35 plants, as they biodegrade, release compounds that may increase soil pH.1

46. These two precautions serve to reduce the corrosivity of the soil surrounding the buried piping at PNPS. The resulting soil pH is 6.2-6.82 and the C1- content is 210 - 420 ppm, 136 which constitutes a non-aggressive soil environment.

47. In addition to surrounding buried pipe with sand or special fill material, two other precautions taken at PNPS prevent high levels of moisture in the soils adjacent to buried piping. First, Entergy installed a storm drain system at construction to prevent the buildup, of water. The storm drain system runs throughout the 90 acre PNPS site in order to carry away excess rainwater.137 Second, all buried pipes are buried above the water table, which ensures that the water percolates down, past the piping, and is taken away with the flow of ground water. The water table at PNPS where the CSS and SSW system piping is buried is approximately 17 feet below the surface. The CSS and SSW system pipes are buried 7 to 133 Entergy Test. at A82-A89.

134 Entergy Test. at A63, A83.

135 Entergy Test. at A83.

136 Entergy Test. at A83, A88.

137 Entergy Test. at A84, A85.

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10 feet below the surface, well above the water table.1 38 Further, the entire area above the 139 buried piping is covered by asphalt paving.

48. The precautions taken by PNPS ensure the low moisture content of the soil surrounding the buried pipe. Because corrosion is an electrochemical process which requires the presence of an electrolyte, maintaining low moisture content of the soil ensures a non-aggressive environment for the buried pipe. 14 0 Thus, considering the pH and high resistivity plus the low chloride concentration and low moisture content, Mr. Spataro testified that, "at worst 141 the soil is mildly corrosive."'

49. Pilgrim Watch's witness, Mr. Gundersen, makes general claims that oxygen, moisture, chloride, acidity, or microbes found in the soil, in one degree or another, corrode all piping materials, and that because Pilgrim is located adjacent to Cape Cod Bay, at a low 42 elevation, and near salty water, the soil surrounding the piping is not "friendly."'1 However, other than his general assertions, Mr. Gundersen provides no evidence to contradict the testimony or soil data Entergy provided which demonstrate the lack of aggressive conditions at PNPS.

50. Mr. Gundersen does claim that precautions taken by Pilgrim to remove vegetation and place the piping on a bed of sand, are futile because "over a period of time vegetation reappears, decays and works its way down to the pipes," resulting in low pH, and soil above the sand migrates downward mixing with the sand to provide a moist environment. 143 However, because the entire area above the buried piping is covered by 138 Entergy Test. at A84, A86.

139 Tr. at 768 (Sullivan).

140 Entergy Test. at A86, A88; see also Tr. at 757-58 (Spataro).

141 Entergy Test. at A89.

142 Gundersen Reb. Test. at A12 (pp. 23-24).

143 Gundersen Reb. Test. at A13 (pp. 25-26).

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• asphalt paving, 144 vegetation will not reappear above the buried pipe. Also, the soil data provided by Entergy's witnesses, which Mr. Gundersen does not challenge, show a pH from 6.2 to 8.2 and a moisture content from 5.5% to 8.1%, which reflect a non-aggressive 45 soil environment.1

51. Therefore, based on the evidence in the record, we find that PNPS has taken precautions to provide a non-aggressive soil environment for buried pipe. This non-aggressive soil environment provides further assurance that buried pipes will not degrade so as to cause leaks that could challenge their-license renewal intended functions.

c. PNPS and Industry Experience with Protective Coatings

52. Both Entergy's and the NRC Staff's experts point to PNPS and industry experience which confirm the effectiveness of the external coating to prevent external degradation of buried pipe. Specific PNPS experience confirms the effectiveness of the PNPS coatings. In 1999, PNPS examined the external buried piping coatings on the two forty-foot sections of SSW system discharge piping that were being replaced more than 25 years after the plant had become operational. The exterior surface of the piping had been wrapped with reinforced fiberglass wrapping, coal-tar saturated felt, and heavy Kraft paper in accordance with Specification M-306 as described above. The exterior wrappings of the pipes were found to be in good condition and no external corrosion of the pipes was observed. PNPS examined the removed piping after its wrapping was removed and found that the outside 46 surface of the-piping was in its original condition. 1

53. Staff witness Dr. Davis confirms PNPS's operational experience with external buried piping coatings. Dr. Davis states that "the coating and external surface on the-two 40-foot 144 Tr. at 768 (Sullivan).

145 Entergy Test. at A88.

146 Entergy Test. at A74.

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sections of piping on the discharge loops were examined in 1999 when the two 40-foot sections were replaced. The coatings were found to be in good condition and no external corrosion was noted. Those coatings were then removed to inspect the outside surface of the piping which was also found to be in good condition."147 Dr. Davis also noted that, after 36 years of inspections, Entergy has never seen any degradation of the exterior coating. 148

54. Mr. Spataro testified concerning industry experience on the use of coal-tar and epoxy coatings used to protect the PNPS buried piping from corrosion. 149 This industry experience demonstrates that if, (1) there is a coal tar or epoxy coating on the outer surface, (2) the coating was properly applied, and (3) the coating was not damaged during 150 installation, the protective coating will protect piping from exterior degradation.

55. Mr. Spataro also testified to his personal experience with investigating coatings that had been in use for 25 years on a buried gas transmission line that had been coated with coal-tar epoxy in accordance with the industry practice for buried piping described above.

Excavation showed that, where the coating had been properly applied and not damaged, both the pipe and coatings were essentially in the same condition as when the pipe was 151 buried, and, as such, they were left in service.

56. Mr. Spataro also testified to his personal experience with investigating coatings that had been in use for 40 years on the hydroelectric dam spill gates for the St. Lawrence Seaway Power Project.I12 These gates were coated with the same type of coal-tar used on buried 147 Davis Test. at A9.

148 Tr. at 642.

149 Entergy Test. at A66 150 EntergyTest. at A67.

151Entergy Test. at A68.

152 Entergy Test. at A69.

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pipes at PNPS and had been submerged, completely or partially, in a flowing river water environment, subject to not just corrosion, but to erosion from water flow and impact damage caused by solid objects, such as trees and ice floes. After 40 years of service under such conditions, the protective coating on the gates was found to be in substantially the original condition and remained tightly adhered to the steel gates. Since the gates were in excellent condition and the coating manufacturer stated that the existing coating was good for another 40 years, those spill gates that did not require modifications were put back in service with their original protective coating.

57. Operating experience at nuclear plants also shows that properly applied coatings will protect buried piping from external corrosion for many years. Entergy's witnesses reference NUREG/CR-6876, "Risk-Informed Assessment of Degraded Buried Piping Systems in Nuclear Power Plants" (2005), which summarizes the operating experience of buried pipes at 12 nuclear power plants that have undergone license renewal and refers to NUREG-1522, which reported on operating experience at six older nuclear plants licensed before 1977 (which did not report any external degradation of buried piping at these six plants). 153 This operating experience confirms that the external surface of buried piping will not corrode during the life of a nuclear power plant if (1) there is a protective coating on the outer surface, (2) the coating was properly applied, and (3) the coating was not 54 damaged during installation. 1

58. This operating experience is also confirmed by the "Operating Experience" review for buried piping and tanks in the GALL Report. The GALL Report states that "[o]perating experience shows" that a program of protective coatings and opportunistic and periodic 153 Entergy Test. at A70.

154 Entergy Test. at A7 1.

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inspections to confirm that the coatings are intact is effective in managing the "corrosion of 55 external surfaces of buried steel piping and tanks."'1

59. Pilgrim Watch's witness, Mr. Gundersen, presented no evidence indicating that these coatings will be ineffective in protecting buried piping from degradation. Both Entergy's and the Staffs experts have extensive experience and knowledge concerning the capability of protective coatings to protect buried pipe against external degradation. Mr. Gundersen has none. Based on the evidence in the record, we find that industry operating experience establishes that properly applied coatings will protect the external surface of the pipe for many years.

d. Sufficiency of the PNPS Periodic and Opportunistic Inspection Program for the Aging Management of PNPS Buried Piping

60. The PNPS BPTIP provides for periodic and opportunistic inspection of the buried piping for the purpose of confirming the continuing integrity of the protective coatings to protect the exterior surface of the piping from degradation.156 The opportunistic and periodic inspections provided for by the PNPS license renewal BPTIP require that:

" Buried components will be inspected when excavated during maintenance.

• Prior to entering the period of extended operation, plant operating experience will be reviewed to verify that an inspection occurred within the past ten years. If not, an inspection will be performed prior to entering the period of extended operation.

" A focused inspection will be performed within the first 10 years of the period of extended operation, unless an opportunistic inspection (or an inspection via a method that allows an assessment57of pipe condition without excavation) occurs within this ten-year period. 1 155 GALL Report at § XI.M34 at XI M-1 12, Exh.42 (Admitted at Tr. 589); see also Entergy Test. at 72.

156 Entergy Test. at A76.

57 1 Entergy Test. at A75.

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61. Thus, the PNPS license renewal BPTIP requires a minimum of two inspections for buried PNPS pipes subject to the BPTIP between 2002 (within ten years prior to entering the period of extended operation) and 2022 (within the first 10 years of the period of extended operation).158 Notably, because the current operating license for Pilgrim expires in 2012 and no credit is being taken for prior opportunistic inspections, the in-scope buried piping must be inspected in the next four years, and then at least once more in the first 10 years of 59 the period of extended operation. 1

62. Mr. Cox and Mr. Spataro testified that the inspection regime provided for by the BPTIP is sufficient to provide reasonable assurance of the continued integrity of the buried piping systems at PNPS to perform their intended functions during the period of extended operation. Both the industry experience and the PNPS experience show that properly applied coatings will not degrade so as to impair the integrity of the buried piping, particularly during the limited time span between inspections as provided for by the BPTIP.' 6 o Thus, the inspections are complementary to the inherent protective capabilities of the coatings and provide additional assurance that the coatings are remaining in place to serve their protective function. More frequent inspections would serve no purpose, and in fact, would create the potential for damage to the protective coatings on the pipes. 161

63. Dr. Davis of the NRC Staff agrees that the BPTIP requires that at least two inspections of the coating take place: one within 10 years prior to the period of extended operation and at least one inspection during the first 10 years of the period of extended operation.162 He further agrees that this inspection regime is sufficient to provide reasonable assurance that 158 Entergy Test. at A77.

"' Tr. at 775 (Cox); Entergy Reb. Test. at A17.

160 Entergy Test. at A77; Entergy Reb. Test. at A17.

161 Entergy Test. at A76.

162 Davis Test. at A9.

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the coatings are remaining in place and are protecting against degradation of the outer 163 surfaces of the buried pipe.

64. Pilgrim Watch's witness, Mr. Gundersen, has raised numerous challenges to the adequacy of the inspection regime provided under the BPTIP. We have reviewed Mr. Gundersen's challenges and find that none have merit.

65. Mr. Gundersen initially claims that the BPTIP is "vague and non-specific" and cannot be used to conclude that Entergy will examine any buried piping during the license renewal period.164 However, as stated above, the BPTIP is very specific in requiring that a minimum of two inspections be performed with respect to buried pipes and tanks subject to the program, and that one of these inspections must occur within the first ten years after license renewal.165 Mr. Gundersen is incorrect in stating that the BPTIP requires no inspection of the buried piping. Moreover, the BPTIP is in conformance with the GALL Report, which identifies AMPs that the NRC has determined acceptable for managing the 166 effects of aging on SSCs within the scope of license renewal.

66. In a similar vein, Mr. Gundersen erroneously asserts in his testimony that the BPTIP is voluntary.167 License renewal AMPs are in no way voluntary.168 The buried pipe AMP is a commitment made by Entergy in the license renewal application which is reflected in a supplement to the Updated Final Safety Analysis Report as required by the NRC's 163 See Davis Test. at A17 ("these amps provide reasonable assurance that the buried piping containing or potentially containing radioactive liquid at Pilgrim will not develop leaks so great as to prevent them from performing their intended safety function....'); see also Staff Reb. Test. at A17.

164 Gundersen Test. at ¶ 9.

165 Entergy Test. at A77; Entergy Reb. Test. at A17; Tr. at 777 (Cox).

166 Entergy Test. at A73, A90.

167 Gundersen Test. at¶ 12.3.

168 Entergy Reb. Test. at A7.

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regulations.'69 Furthermore, implementation of the BPTIP is included in the NRC's 1 70 license renewal Safety Evaluation Report as a commitment.

67. Similarly, we find meritless Mr. Gundersen's suggestion that the entire length of the buried pipe must be inspected. 171 The purpose of the inspections under the BPTIP is to provide additional assurances that the protective coatings remain in place, as would be expected based on previously described industry and PNPS experience, and are not experiencing some unexpected degradation.172 As reflected in, and confirmed by, the GALL Report, a sampling program to assess and verify the general condition of the coatings is sufficient to provide this assurance. The excavation that would be required to examine all underground 73 piping poses unnecessary risk of damage to otherwise sound coatings. 1

68. We also reject Mr. Gundersen's claim that the time interval between inspections proposed for the BPTIP is "too long"'174 for reasons already stated above. Specifically, based on industry and PNPS experience with coated buried piping, such inspections are sufficient to provide reasonable assurance of the continued integrity and ability of the buried piping systems at PNPS to perform their intended functions during the period of extended operation.175 PNPS and industry experience demonstrate that coatings remain in good condition after many years of service and that coated materials are not expected to degrade with exposure to the PNPS soil environment. Coupled with ongoing operational monitoring, inspection of buried piping at the frequency specified by the BPTIP is 169 See Exh. 9 (LRA § A.2.1.2), admitted at Tr. 572.

170 See Exh. 7, NUREG-1891 (Sept. 2007, Published Nov. 2007) at A-3 (Commitment 1), admitted at Tr. 572.

171 Gundersen Test. at ¶¶ 12.4.1.2, 12A.1.3.

172 Entergy Test. at A77; Entergy Reb. Test. at A17.

173 Entergy Reb. Test at A4. At hearing, Mr. Gundersen changed his position and agreed that a visual inspection of the SSW piping should not be undertaken because of the increased risk of damage to the pipes and their coatings.

Tr. at 761 (Gundersen).

174 Gundersen Test. at ¶ 12.4.5.1.

175 Entergy Test. at A77; Entergy Reb. Test. at A17.

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adequate to provide reasonable assurance that intended license renewal functions can be maintained - which is the purpose of the LRA AMPs.

69. Mr. Gundersen's claims that the BPTIP does not utilize opportunistic inspections17 6 are equally without merit. The LRA BPTIP expressly states in LRA Section B. 1.2 that "buried components are inspected when excavated during maintenance."'177 Furthermore, the GALL Report, AMP XI.M34, expressly provides that "buried piping and tanks are opportunistically inspected whenever they are excavated during maintenance."' 178 The BPTIP takes no exception to this provision of the GALL Report AMP. 179 Therefore, buried piping must be opportunistically inspected whenever excavated during maintenance 180 as part of the LRA BPTIP.

70. As noted previously, Entergy developed a fleet-wide procedure, EN-DC-343, Rev. 0, "Buried Piping and Tanks Inspection and Monitoring Program" ("BPTIMP Procedure" or "the Procedure") to implement the PNPS license renewal AMP for the inspection of buried pipes and tanks, but it additionally implements inspections beyond the scope of the license renewal rules.181

71. Mr. Gundersen erroneously claims that BPTIMP acknowledges the validity of Pilgrim Watch's initial contention, based purely on ground water contamination unrelated to any intended license renewal functions. He points to the statement in the BPTIMP that the "program shall include buried or partially buried piping and tanks that, if degraded, could 176 Gundersen Test. at ¶ 12.4.5.4.

177 Exh. 31, admitted at Tr. 581 (emphasis added).

178 Exh. 42, admitted at Tr. 589 (GALL Report § XI.M34).

179 Exh. 31, admitted at Tr. 581 (LRA, Appendix B, Section B.1.2); EntergyReb. Test. atA18.

180 Entergy Reb. Test. at A18.

181 Exh. 8 (Admitted at Tr. at .572); Entergy Test. at A78; Entergy Reb. Test. at A5.

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provide a path for radioactive contamination of groundwater."' 182 However, Section of 5.2 of the BPTIMP clearly sets out the dual functions of the BPTIMP referred to above.

Subsection [2] of Section 5.2 states that the BPTIMP encompasses all buried pipes and tanks that fall within the scope of license renewal, for which it referencesSection XI.M34 of the GALL Report (Buried Piping and Tanks Inspection). Subsection [3] provides that the BPTIMP shall also include buried or partially buried piping and tanks that, if degraded, could provide a pathway for radioactive .contamination of groundwater, and it references the NEI groundwater protection initiative.183 Accordingly, the BPTIMP addresses systems that are not even within the scope of license renewal and the procedure is plainly intended to go beyond implementing license renewal commitmerits. In addition to license renewal AMP functions, the BPTIMP is intended to implement the NEI groundwater initiative to prevent leakage and radioactive contamination of groundwater, which Entergy has 184 voluntarily undertaken at all of its nuclear power plants.

72. Mr. Gundersen also claims that the BPTIMP is inadequate because it does not address internal corrosion. However, as pointed out by both Entergy and the NRC Staff s witnesses, the BPTIMP and the BPTIP are only intended to manage external degradation.' 85 The BPTIMP states in Section 1.0, "PURPOSE," that "the Program consists of inspection and monitoring of selected operational buried piping and tanks for external corrosion." 186 Similarly, as stated in Entergy's pre-filed testimony, the BPTIP is the AMP established to manage external degradation of buried piping.187 Entergy has 182 Gundersen Test. at ¶ 12.4.2.

183 Entergy Reb. Test. at A6 184 Entergy Reb. Test. at A5-A6.

185 Entergy Reb. Test. at A9; Staff Reb. Test. at A14.

186 Entergy Reb. Test. at A9.

187 Entergy Test. at A35.

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established other AMPs to manage internal degradation. The AMPs expressly established to manage internal corrosion are the Water Chemistry Control-BWR Program, the Service Water Integrity Program, and the One-Time Inspection Program discussed below in our 1 88 discussion on the aging management for internal corrosion.

73. Mr. Gundersen also submits that the AMP and the Procedure are inadequate because neither requires a baseline review. However, as testified to by Dr. Davis and Entergy's 89 witnesses, a baseline inspection for buried piping is not required under the BPTIP. 1 Furthermore, the installation inspections of the buried piping at PNPS serve as the baseline inspections, and the assumption of the inspections under the BPTIP and BPTIMP is that 190 the coatings are not degraded from their original condition.

74. Mr. Gundersen also raises in several paragraphs of his testimony related claims regarding the alleged vagueness of acceptance criteria in the BPTIMP and the alleged failure of the BPTIP or BPTIMP to provide for condition reports to follow-up on deficiencies that may be identified by the inspections conducted under the BPTIP or BPTIMP. 19 1 We also find these claims to be without merit.

75. Both Dr. Davis and Entergy's witnesses emphasize that the requirements of 10 C.F.R. Part Appendix B apply to license renewal AMPs.' 92 In this respect, Appendix B.O.3 of the LRA clearly sets forth that Pilgrim's Appendix B Corrective Action Program ("CAP") is applicable to all of the AMPs, including the BPTIP AMP. As reflected by this provision of 188 Entergy Test. at A35, A9l-A102.

189 Staff Reb. Test. at A12; Entergy Reb. Test..at A10, A12.

190 Entergy Reb. Test at All; Staff Reb. Test. at A12.

191 Gundersen Test. at ¶¶ 12.4.7-12.4.10, 12.5.

192 Staff Reb. Test. at A15; Entergy Reb. Test. at A24.

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the LRA, the full panoply of the PNPS corrective action program applies to PNPS aging 193 management programs and activities.

76. Thus, condition reports, corrective actions, and root cause analyses are all required under the BPTIP and BPTIMP in accordance with Pilgrim's Appendix B Quality Assurance Program. 194 As testified to by Mr. Sullivan, if conditions adverse to quality were detected by inspections, corrective action would be required, which would include increased 95 inspection frequency, if needed, to establish the effectiveness of the corrective action.1 The Staff's experts, Terrance Chan and Dr. Davis, testified to this fact stating that NRC resident inspectors would evaluate every condition report created by Entergy in response to the condition adverse to quality. 196

77. Similarly, we find no merit to Mr. Gundersen's claim that the acceptance criteria for the BPTIMP and the BPTIP are unacceptably vague.1 97 As explained by Entergy's witnesses, the acceptance criteria for the BPTIP are those set out in Section XI M-1 12 of the GALL Report. These criteria require inspection for "evidence of damaged wrapping or coating defects, such as coating perforation, holidays, or other damage" and the reporting and evaluation of"[a]ny coating and wrapping degradation" in accordance with the PNPS 98 corrective action procedures. 1

78. Based on the evidence in the record, we find that the periodic and opportunistic inspections of the buried piping provided for under the BPTIP provide reasonable assurance of the continuing integrity of the protective coatings to protect the exterior surface of the piping 193 Exh. 11 (Admitted at Tr. 572); Entergy Reb. Test. at A24.

194 Entergy Reb. Test. at A24, A26-A29.

195 Entergy Reb. Test. at A17; Tr. at 649 (Sullivan).

196 Tr. 649-52.

197 See Gundersen Test. at ¶ 12.4.7.

198 Entergy Reb. Test. at A25 (quoting Gall Report at Section XI M-1 12).

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from degradation. We therefore find, based on a preponderance of credible evidence in the record as presented by Entergy and verified by the Staff, that the BPTIP manages the effects of aging so as to provide reasonable assurance that intended functions can be accomplished as required by the NRC's license renewal regulations such that buried pipes carrying radioactively contaminated water will not develop leaks so great as to cause those pipes to be unable to perform their license renewal intended functions.

e. Cathodic Protection is Neither Required Nor Necessary

79. Pilgrim Watch and Mr. Gundersen also claim, referring to the GALL Report § XI.M28, that, in order to reduce corrosion rates, Entergy can and should backfit the SSW system and CSS buried pipes with cathodic protection.99 However, as the Board stated in our recent Memorandum and Order 200 denying Pilgrim Watch's Motion to Strike Misleading and Inaccurate testimony, cathodic protection is at most a "peripheral" issue here. As we stated previously, and restated in our June 4 Memorandum and Order, "our responsibility is to determine whether the Applicant has proven by a preponderance of the evidence that 20 1 its AMPs are adequate as they currently exist, without monitoring wells.",

80. Entergy has not proposed cathodic protection as part of its AMP for buried pipes, and we have concluded, for the reasons previously stated, that Entergy's AMP, without cathodic protection, provides reasonable assurance that buried pipes carrying radioactively contaminated water will not develop leaks so great as to cause those pipes to be unable to perform their license renewal intended functions. Industry and PNPS experience show that, as long as the coatings remain in place, buried pipes will be protected from external 199 Gundersen Test. at ¶12.4.11, Tr. at 761-63 (Gundersen); see also Exh. 71 GALL Report XIM.28 (Admitted at Tr.

764).

200 Memorandum and Order (Ruling on Pilgrim Watch Motions Regarding Testimony and Proposed Additional Evidence Relating to Pilgrim Watch Contention 1) (June, 4, 2008).

201 June 4 Memorandum and Order, slip op. at 9.

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degradation. Entergy has provided credible evidence that properly applied coatings will remain in place for many years. Entergy has-established a reasonable inspection program to confirm the continued integrity of the coatings, and we find that no additional facets, neither cathodic protection nor monitoring wells, are necessary to provide reasonable assurance the buried pipes will be capable of performing their license renewal intended functions during the period of extended operation.

81. In this respect, the GALL Report expressly recognizes that cathodic protection is but one option to manage corrosion on buried pipe such as the SSW or CSS buried pipe.Section XI.M28 is one of the AMPs listed in Chapter 11 of the GALL Report. Another is the Section XI.M34 AMP, which is the AMP that Entergy credits for the Pilgrim license renewal application. Dr. Davis, the author of the BPTIP AMP in the GALL Report,Section XI.M28' testified that the risks associated with the cathodic protection system causing an unscheduled plant shutdown led to the alternative in Section XI.M34 which requires no cathodic protection. 20 2 Either of these two AMPs is acceptable for managing 20 3 aging effects on buried pipe external surfaces.

82. Based on the Testimony of Dr. Davis, as well as the alternative to cathodic protection offered in the GALL Report and incorporated into the PNPS BPTIP, we conclude that cathodic protection is not a required element of the PNPS BPTIP. Moreover, as clearly established by the record, cathodic protection is not necessary to provide reasonable assurance that PNPS buried pipes will be able to perform their license renewal intended functions during the period of extended operation.

202 Tr. at 769-72 (Davis).

203 Tr. at 768 (Cox).

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3. Aging Management of Internal Degradation

a. Service Water Integrity Program and Corrosion Resistant Materials to Manage Aging of Internal Degradation of the SSW Buried Pipe

83. PNPS uses the Service Water Integrity Program for the aging management of internal degradation of the SSW system buried pipe.204 The Service Water Integrity Program includes surveillance and control techniques to manage the effects of aging on the SSW system or structures and components serviced by the SSW system. 20 5 Under the program, the components of the SSW system are regularly inspected for internal loss of material and other aging effects that can degrade the system. The inspection program includes provisions for visual inspections, eddy current testing of heat exchanger tubes, ultrasonic testing, radiography, and heat transfer capability testing of the heat exchangers. The periodic inspections include direct visual inspections and video inspections accomplished by inserting a camera-equipped robotic device into the SSW system piping. In addition, chemical treatment using biocides, chlorine, and periodic cleaning and flushing of 20 6 infrequently used loops are methods used under this program.

84. PNPS also uses corrosion resistant materials to protect against the internal degradation of SSW system buried pipe. The SSW inlet pipe is made of titanium which as previously discussed, is resistant to corrosion. As such, the SSW inlet pipe is not subject to internal corrosion.20 7

85. Because the SSW discharge piping is made of carbon steel, it is protected by an internal liner. As originally installed at PNPS, the internal liner for the SSW discharge pipe was -a rubber sleeve that was put in place as part of pipe fabrication. 20 8 This rubber sleeve or 204 Entergy Test. at A95-A96; see also Entergy Test. at A44.

205 Entergy Test. at A95.

206 Entergy Test. at A96.

207 Entergy Test. at A4 1.

208 Tr. at 652 (Sullivan); see also Entergy Test. at A44.

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liner had an expected life of approximately 20 years.209 PNPS monitored the integrity of the original rubber lining under the Service Water Integrity Program established as part of the in-service inspection requirements for the SSW developed in response to Generic Letter 89-13.210

86. As the original rubber liner approached the end of its expected life, PNPS undertook increasingly intensive inspections under the Service Water Integrity Program. In 1995, PNPS visually inspected the rubber liner using a robot crawler fitted with a camera, and found minor age-related degradation. The rubber liner was re-inspected using this same method in 1997, which identified additional degradation. Consequently, in 1999 PNPS undertook more intensive inspections by sending an inspector into the pipe to do both visual and ultrasonic examinations with the intent to make any necessary replacements or repairs. Based on the findings of this inspection, PNPS replaced the two forty-foot sections of the carbon steel SSW discharge pipe in 1999, as previously discussed, and made other repairs. 2 1' Entergy applied a protective epoxy coating to the interior and 212 exterior of both replaced sections of pipe.

87. Shortly thereafter, in 2001, Entergy lined the interior of loop B with a cured-in-place pipe

("CIPP") liner. In 2003, Entergy applied a nearly identical liner to loop A. The CIPP liner, which is nominally 1/2" thick, forms a rigid barrier to protect the carbon steel discharge pipe against internal corrosion. The liner material consists of a nonwoven polyester felt tube that is saturated with a resin and catalyst system in loop A, and an epoxy resin and hardener system in loop B, with a polyurethane or polyethylene inner membrane.

209 Entergy Test. at A44; Tr. at 655 (Sullivan).

210 Entergy Test. at A44, A98 211 Entergy Test. at A98; see also Tr. at 638 (Woods). PNPS went into service in 1972. Tr. at 661, 809.

212 Entergy Test at A42.

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Based on the service conditions and the design of the CIPP liner, the expected life of the 213 CIPP is approximately thirty-five years.

88. Mr. Spataro testified to the corrosion resistance of the CIPP lined SSW carbon steel piping at PNPS. 214 The 1/2" thick CIPP liner, consisting of polyester felt material with a resin and catalyst system or an epoxy resin and hardener system, forms a smooth, hard surface that resists moisture intrusion and abrasion, and is resistant to most chemicals and all waters.215 The CIPP liner is superior to the rubber liner since it is an epoxy and polyester thermosetting resin that cures in place and is resistant to biofouling and other forms of degradation. Such an impervious membrane forms an excellent protective barrier, protecting the carbon steel from internal corrosion.

89. CIPP liners such as those used at PNPS have been used for many years in many different applications, in power plants, public water supply systems, waste water treatment facilities, 216 and any place where there is an aggressive environment.

90. Mr. Spataro testified that, based on his professional experience with similar materials used under more aggressive conditions, he expects the PNPS CIPP liner to last at least thirty-five years.217 Mr. Spataro testified that the failure mechanism for the CIPP is by "flaking" caused by the surface drying out due to a "volumetric airflow system or exposure to ultraviolet radiation." 218 Mr. Spataro further testified that such an "environment" that would cause the CIPP to fail does not exist in the buried SSW pipe at PNPS. 219 A wet 213 Entergy Test. at A43, A98; see also Tr. at 653, 655 (Sullivan).

214 Entergy Test. at A45.

215 Tr. at 734-5 (Spataro).

216 Tr. at 683-84, 692 (Spataro); Tr. at 655 (Sullivan); Tr. at 691 (Cox).

217 Tr. at 681 (Spataro).

218 Tr. at 682 (Spataro).

-219 Tr. at 682 (Spataro).

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environment, such as the environment inside the SSW discharge pipe causes "almost no degradation at all.",220 Hence, the CIPP liner is not subject to degradation during the license renewal period.

91. Dr. Davis, the expert for the NRC Staff, agrees that of the CIPP liners that were installed in loops B and A have an expected life of approximately thirty-five years. 22 1 Moreover, Dr.

Davis stated that the CIPP liner is a "much better coating than the rubber lining,' 222 and that the based on his experience the replacement CIPP liner is far superior to the rubber liner. 223 Dr. Davis goes on to say that "the rubber lining will oxidize with time and will degrade" and that the "epoxies are much more resistant." 224 Dr. Davis further notes failures of such epoxy liners of which he is aware have been "usually for mechanical 2 25 reasons," and not from corrosion or related degradation.

92. Mr. Gundersen makes clear on multiple occasions that he does not have any experience with CIPP liner. 226 Despite this fact, Mr. Gundersen makes several assertions. First, he speculates that because the CIPP is applied in the field on top of the rubber sleeve in the SSW discharge pipe, the CIPP is somehow unreliable and he doubts the rubber sleeve is still bonded. 22 7 Second, Mr. Gundersen questions the thirty-five year life of the CIPP, 228 saying that he is "not aware of a manufacturer's guarantee that this is a 35-year process."'

220 Tr. at 683 (Spataro).

221 Tr. .at 669 (Davis).

222 Tr. at 669 (Davis).

223 Davis Test. at A11.

224 Tr. at 669 (Davis).

225 Tr. at 690 (Davis).

226 Tr. at 666, 668.

227 Tr. at 666.

228 Tr. at 664 (Gundersen).

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93. We find that Mr. Gundersen's assertions concerning CIPP liner are contradicted by credible evidence. As testified to by the Entergy witnesses, prior to installing the CIPP liner an inspection of the rubber liner was performed to ensure its integrity and, if degraded, to remove the liner.229 PNPS performed the inspection, via video camera or an inspector, to determine whether the rubber liner had separated from the carbon steel interior surface.2 30 When the integrity of the rubber liner is assured, the surface is then prepared by scraping away any debris or marine growth that might be on the surface of the rubber liner. The scraping not only cleans the surface, but creates a rough surface to which the CIPP epoxy can bond.231 Moreover, the CIPP is installed with an outward pressure.

Therefore, when it hardens in place, it is exerting a radial outward pressure against the rubber sleeve pressing it against the carbon steel SSW discharge pipe. Thus, it becomes 2 32 "literally a pipe within a pipe," that "is not going anywhere.",

94. Thus, as stated in the PNPS Final FSAR, because the CIPP's final "configuration is rigid resin composite pipe within the original pipe" there is "no requirement for bonding between the pipes." 233 Accordingly, we find no basis for Mr. Gundersen's first assertion concerning potential lack of bonding.

95. Mr. Gundersen's second assertion, that no manufacturer's warranty establishes the thirty-five year life of CIPP liner, is irrelevant. Entergy has never claimed nor offered any testimony which relies on a manufacturer's warranty. Entergy's witnesses, based on their professional experience with such liners, have concluded that a thirty-five year life is a 229 Tr. at 673 (Spataro).

230 Tr. at 674 (Woods).

231 Tr. at 674-75 (Spataro).

232 Tr. at 676 (Spataro).

233 Exh. 58, PNPS FSAR - Excerpt - 10.7 "Salt Service Water System" at 10.7-2a, admitted at Tr. 589.

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reasonable life for the CIPP. 234 Mr. Gundersen does not have any experience with epoxy resins and, therefore, cannot offer a professional opinion as to the useful life of SSW discharge pipe CIPP liner.

235

96. The Service Water Integrity Program will be used to monitor the newly installed CIPP.

As described above, this program was effective in detecting degradation of the internal rubber lining in the original SSW system carbon steel piping by increasing inspections as the rubber liner approached its expected end of life.2 36 Entergy will undertake a more aggressive approach with respect to the CIPP liners. After the CIPP has been in service for 10 years - well before the end of its expected 35-year life - PNPS will undertake a complete visual examination of the CIPP, analogous to those undertaken for the original rubber lining.237 Entergy has "gone with a ten-year frequency just to verify and assure that 238 there are no changes in the cured-in-place liner."

97. Thus, the CIPP liner for Loop B would be subject to a complete examination in 2011, before the period of extended operation actually commences. The CIPP liner for Loop A Loop B would be subject to a complete examination in 2013, shortly after the period of 239 extended operation commences.

98. Mr. Sullivan testified that if the inspection of the CIPP liner in 2011 (or subsequent inspections) showed degradation, a condition report would be written under the PNPS corrective action program, and corrective action would be taken as may be required, including increased inspection frequency, to ensure that the SSW system continued to meet 234 Tr. at 655 (Sullivan) & 681 (Spataro); Entergy Test. at A43.

235 Entergy Test at A98.

236 Tr. at 636 (Sullivan); Entergy Test. at A44, A98.

237 Tr. at 648, 774 (Sullivan); Tr. at 776 (Cox).

238 Tr. at 648 (Sullivan).

239 Tr. at 648, 774 (Sullivan); Tr. at 776 (Cox).

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its safety function and licensing basis.24 The Staff s experts, Mr. Chan and Dr. Davis, testified that NRC resident inspectors would evaluate every condition report created by Entergy in response to the condition adverse to quality.241

99. Pilgrim Watch and Mr. Gundersen claim that a 10-year frequency for inspections of the CIPP liner is insufficient to provide reasonable assurance that the SSW safety function will not be lost due to degradation of the CIPP liner and internal corrosion of the SSW discharge pipe.242 However, all the parties' witnesses agreed at the hearing that the only way that SSW pipe corrosion might trigger the loss of SSW safety function would be a total collapse that somehow blocked off the flow path.243 Entergy's experts testified that this would be an incredible type of failure, and were not aware of any history suggesting that such a failure might occur.2 44 100. For such a failure to occur, one would have to assume that the 1/ inch thick CIPP liner had degraded such that it no longer protected the carbon steel pipe from the seawater.

However, as testified to by Mr. Spataro the CIPP liner is not subject to degradation and failure in seawater.245 Moreover, the wearing or erosion of the CIPP liner is at such a slow rate that it would take many years for it to erode.246 Further, even if corrosion of the pipe were to occur, such corrosion would typically be localized and very unlikely to threaten the integrity of the pipe.247 Mr. Gundersen provided no credible evidence to the contrary.

240 Tr. at 649 (Sullivan); Entergy Reb. Test. at Al 7.

24' Tr. 649-52 (Chan and Davis).

242 Tr. at 704-05 (Gundersen).

243 Tr. at 610 (Cox).

244 Tr. at 610 (Cox), 612 (Woods); Exh. 12, Entergy's Answers to Board Questions at 6, admitted at Tr. 572.

245 Tr. at 683-88 (Spataro).

246 Tr, at 685-88 (Spataro).

247 Tr. at 727-31 (Cox, Davis, Chan); Tr. 770-72 (Woods, Chan).

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101. Pilgrim Watch and Mr. Gundersen also referred to through wall corrosion about the size of a quarter that was discovered in 1999.248 However, this condition occurred after the rubber liner had reached, and indeed, exceeded its expected life. Here, the CIPP will be inspected far in advance of its expected end of life. Entergy and the NRC Staff witnesses agreed that the corrosion that was discovered in 1999 would not have led to the failure of the SSW pipe in the event of an earthquake. 249 Mr. Gundersen suggested that the corrosion that was discovered in 1999 in the SSW buried discharge pipe could cause the pipe to collapse if there were a design basis event, but he has not done or seen any analysis that would support this assertion.250 102. To sum up, the SSW discharge piping consists of very large pipes (22 inch outer diameter 251) protected by multiple barriers. Internally, the piping is protected both by the CIPP (which is nominally 1/2" thick 25 2 and essentially constitutes a pipe within a pipe 253) and by the original lining (rubber, or for the sections that were replaced, epoxy).25 4 The discharge piping itself is 3/8" thick.255 Externally, the piping is protected by the coatings discussed earlier in this decision. These multiple barriers provide a high degree of assurance that the buried SSW discharge piping will perform its intended functions.

103. Based on the credible evidence in the record, we therefore conclude that PNPS choice of materials and AMP for the SSW system provides reasonable assurance that the SSW discharge pipe will perform its intended safety function through the period of extended 248 Tr. 647 (Gundersen); Exh. 67 (Photographs), admitted at Tr. 645.

249 Tr. 670-71 (Woods); Tr. 671 (Chan).

250 Tr. 694-98 (Gundersen).

25' Tr. 610-11 (Sullivan, Cox).

252 Tr. 620 (Cox); Tr. 621-22 (Woods); Tr. 658 (Woods).

253 Tr. 677-78 (Cox) 254 Tr. 640-41 (Woods); Tr. 643 (Davis); Tr. 658 (Sullivan), 662 (Woods) 255 Tr. 611 (Sullivan); Tr. 619-20 (Cox).

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operation. The CIPP liner provides protection of the discharge pipe from corrosion and the Service Water Integrity Program has been successfully implemented at PNPS to manage SSW system degradation from loss of material due to internal corrosion prior to the loss of its intended function.

b. Programs and Design Features that Protect against Internal Degradation of the CSS Buried Piping 104. PNPS uses the Water Chemistry Control-BWR Program and the One-Time Inspection 256 Program for the aging management of internal degradation of the CSS buried pipe.

Furthermore, the CSS buried pipe is made of stainless steel, which as previously discussed, is generally resistant to corrosion.257 (i) Water Chemistry Chemistry-BWR Program 105. As testified to by Entergy's witness, Mr. Cox, and by Dr. Davis of the NRC Staff,258 the Water Chemistry Control-BWR Program (the "WCC Program") optimizes the water chemistry in the CSS (among other plant systems) to minimize the potential for loss of material and cracking due to internal corrosion of the system. 259 The WCC Program operates by limiting the levels of contaminants in the CSS that could cause loss of material 2 60 and cracking.

106. The WCC Progam is an existing program at PNPS that has been confirmed as effective at managing the effects of aging on the CSS as documented by the operating experience review. 261 The program uses EPRI BWR water chemistry guidelines, as specified in the 256 Entergy Test. at A90, A91, A101.

257 Davis Test. at A13.

258 Davis Test. at A13.

259 Entergy Test. at A9 1.

260 Entergy Test. at A92.

261 See PNPS LRA at Appendix B, Section B.1.32.2, p. B-106-07.

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GALL Report,262 which include chemistry recommendations for CSTs. The Staff also agrees that the WCC Program is consistent with the GALL Report XI.M2, "Water 2 63 Chemistry."

107. Under the WCC Program, water quality is continuously monitored and confirmed, and timely corrective actions are taken to address water quality issues to ensure that the Program is effective in managing corrosion for applicable components. The Program's effectiveness has also been confirmed by industry operating experience as described in the 264 GALL Report.

108. Dr. Davis testified to the operating experience of the WCC Program at Entergy. From 1998 through 2004, several condition reports were issued by Pilgrim for adverse trends in parameters monitored by the WCC Program. The Pilgrim staff took appropriate actions to return the parameters to within administrative limits. Although the parameters had exceeded administrative limits for PNPS, they had not exceeded the EPRI acceptance limits. The administrative limits had been set by PNPS to be below the EPRI acceptance limits, so that the administrative limits could be exceeded for a short time and corrective 265 actions could be taken before the EPRI acceptance limits had been exceeded.

109. Mr. Gundersen asserts that the WCC Program is a mitigation program and does not provide detection for aging effects and that "[m]ore frequent complete inspections as part of the overall program are the only effective assurance that defects created by aging components will be uncovered.",266 However, both the GALL Report and the LRA expressly identify the WCC Program as an aging management program. Additionally, the 262 Entergy Test. at A94.

263 Davis Test. at A13.

264 GALL Report at XI M-12, M-13, Exh. 7. (admitted at Tr. 572); Entergy Test. at A94.

265 Davis Test. at A14.

266 Gundersen Reb. Test. at A19.

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One-Time Inspection Program, discussed below, also serves as a check on the effectiveness of the WCC. Thus, we find this claim by Mr. Gundersen to be without merit.

110. Mr. Gundersen also asserts that, although Entergy alludes to problems within the WCC Program, it never discusses potential damage caused while operating under the older methodology, nor what remediation steps have been taken regarding any damage that occurred.267 Dr. Davis testified that although the water chemistry parameters had exceeded administrative limits for PNPS, they had not exceeded the EPRI acceptance limits established by EPRI and industry experts. 268 Thus, we find no merit in Mr. Gundersen's claim. Rather, Entergy is aggressively managing the water chemistry to provide reasonable assurance that internal degradation will not impair the functioning of the CSS.

(ii) One-Time Inspection Program 111. As testified to by Mr. Cox, the One-Time Inspection Program, as applied to the CSS, confirms the absence of significant aging effects for the internal surfaces of piping. 269 The purpose of the One-Time Inspection Program, as applied to the Water Chemistry Control-BWR Program and the CSS, is to "verify the effectiveness of the water chemistry control

[AMPs] by confirming that unacceptable cracking, loss of material, and fouling is not 2 70 occurring.",

112. The One-Time Inspection Program consists of an inspection of a representative sample (based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience) of the interior piping surface, which will be performed prior to the period of extended operation. The inspection locations will be chosen based on 267 Gundersen Reb. Test. at A19.

268 Davis Test. at A14.

269 EntergyTest. at A100-A101.

270 Exh. 5 (PNPS LRA at Appendix B, § B.1.23, p. B-76).

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identifying locations most susceptible to aging degradation. The PNPS One-Time Inspection Program comports with the NRC Staff guidance set forth in the GALL Report Section XI.M-105 for such inspection programs.271 113. Mr. Gundersen provides no testimony on the effectiveness of the One-Time Inspection Program.

(iii) Finding of Reasonable Assurance 114. Based on the evidence in the record, we conclude that PNPS has effective AMPs in place for the aging management of internal degradation of the CSS buried pipe. The WCC Program has proven effective to maintain water chemistry parameters within EPRI acceptance limits. Furthermore, the effectiveness of the WCC Program to protect against internal degradation will be confirmed by the One-Time Inspection Program prior to the period of extended operation.

C. Additional Surveillance Programs for the CSS and SSW Systems 115. While not credited as AMPs, Entergy maintains several additional surveillance programs for the CSS and SSW systems. These programs provide further assurance that in-scope buried pipes will not develop leaks so great as to challenge their license renewal intended functions.

1. Service Water Integrity Program 116. Mr. Sullivan testified that Entergy monitors the integrity and functioning of the SSW system buried piping monthly via a flow rate test of the seawater flow through the SSW system.272 More specifically, Entergy tests the flow rate of the SSW system through the RBCCW heat exchanger. The minimum required flow for the test is 4500 GPM, which 271 Entergy Test. at A102.

272 Entergy Test. at A122.

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273 ensures that there is adequate water flow through the heat exchangers and piping. It confirms that a leak, should there be any, from the buried piping is not large enough to prevent the system from satisfactorily performing its intended function. 274 Mr. Sullivan further testified that, if the acceptance criteria for the flow rate test are not met, corrective 275 action will be taken - the problem will be investigated and fixed.

2. CSS Surveillance Monitoring Program 117. Mr. Sullivan further testified that Entergy ensures the continuing integrity and functioning of the CSS buried piping in two ways. First, a water level indicator in each of the two condensate storage tanks ("CST") is monitored every four hours. Second, the water flow rates from the HPCI and RCIC pumps are tested on a quarterly basis, which serves to 2 76 confirm adequate flow rates through the buried CSS piping.

118. The water level in each of the two CST's is maintained above 30 feet. 2 7 7 Corrective action is required if the water level drops below 30 feet. 278 In contrast, only about 11 feet (corresponding to 75,000 gallons) is reserved for the HPCI and RCIC.2 79 Consequently, there would have to be about a 20 foot drop in tank level before the capability of the HPCI and RCIC to perform their system functions using water solely from the CSTs would be impaired.280 Such a large drop would be detected by the established monitoring frequency 281 of every four hours.

273 Entergy Test. at A123-A124.

274 Entergy Test. at A124.

275 Entergy Test. at A125.

276 Entergy Test. at A106.

277 Entergy Answer to Board Questions at 2; Exh. 12 (admitted at Tr. 572) 278 Entergy Test. at Al 11; Entergy Answer to Board Questions at 2; Tr. at 786-88 (Cox and Sullivan).

279 Entergy Test. at Al 12.

280 Entergy Test. at Al 13.

281 Entergy Test. at Al 14.

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119. Mr. Sullivan also described the method Entergy uses in monitoring the HPCI and RCIC system pumps.282 The Pilgrim plant safety analysis requires that the HPCI system maintain a water flow rate of 4,250 GPM and 400 GPM for the RCIC system.2 83 Pursuant to 10 C.F.R. §§ 50.55a(f)-(g) and the technical specification surveillance requirements, Entergy undertakes quarterly in-service testing of the HPCI and RCIC systems to confirm the system capability to deliver the minimum required water flows. These quarterly tests ensure that the required water flow rates of 4,250 GPM and 400 GPM, respectively, are met.284 The quarterly flow rate inspections can detect a leak in the CSS system piping large enough to prevent the HPCI or.RCIC systems from performing their intended 85 function.2 120. Mr. Sullivan also testified that the flow rates for the HPCI and RCIC systems are confirmed during system testing once every operating cycle following each refueling 28 outage.286 These tests are in addition to the quarterly tests. 287 As to the acceptance criteria for the flow rate tests, Mr. Sullivan testified that, if the flow rates are not met, Entergy takes corrective actions.288

3. Conclusion 121. Based on credible evidence in the record, we find that Pilgrim's surveillance programs provide additional assurance that the SSW system and CSS will perform their intended functions. These programs are established to provide assurance that the systems can meet their intended functions in accordance with the licensing basis for the plant. Any leaks that 282 Entergy Test. at Al 18.

283 Entergy Test. at Al 18.

284 Entergy Test. at Al 18.

285 Entergy Test. at A120.

286 Entergy Test. at Al 18.

287 Entergy Test. at Al 18.

288 Entergy Test. at Al 19.

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could challenge the intended functions of the systems would be identified by these periodic surveillances.

D. Monitoring Wells Are Not Necessary 122. For the reasons set forth above, we find that Entergy's AMPs provide reasonable assurance that the SSW system and CSS will perform their intended function through the period of extended operation. Monitoring wells that would be used to detect and monitor radioactivity in the ground water in and around PNPS are therefore unnecessary to provide 289 reasonable assurance during the period of extended operation.

V. CONCLUSIONS OF LAW Based upon a review of the entire hearing record and the foregoing discussion and Findings of Fact, the Board concludes as follows:

1. The AMPs that Entergy has identified in the PNPS License Renewal Application are adequate to maintain the pressure boundary of the in-scope buried pipes in the CSS and SSW systems in order to provide reasonable assurance that these systems containing the in-scope buried pipes and tanks can perform their system intended functions in accordance with 10 C.F.R. §§ 54.4(a)(1), (a)(2) or (a)(3). In other words, Entergy has demonstrated that the PNPS AMPs have elements that provide reasonable assurance that the buried CSS and SSW system pipes will not develop leaks so great (without the need for monitoring wells to detect any such leaks) as to cause those pipes to be unable to perform their intended safety functions during the license renewal term.

2. Entergy has demonstrated that the effects of aging will be adequately managed so that the intended functions of the in-scope buried piping will be maintained consistent with the licensing basis for the period of extended operation, as required by 10 C.F.R. § 54.21.

289 Entergy Test. at A128.

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3. There is reasonable assurance that the PNPS current licensing basis will be maintained throughout the period of extended operation, as required by 10 C.F.R. § 54.29.

VI. ORDER For the foregoing reasons, Pilgrim Watch's Contention 1 is resolved in favor of Entergy.

Accordingly, the Director of Nuclear Reactor Regulation is authorized to issue to Entergy a renewed operating license for the Pilgrim Nuclear Power Station, for a period of twenty years, consistent with the terms of this Initial Decision and the Staff's review of the License Renewal Application. Pursuant to 10 C.F.R. § 2.341(b)(1), any party to this proceeding may file a petition for review of this Initial Decision with the Commission within fifteen (15) days after service of this initial decision. Pursuant to 10 C.F.R. § 2.341(a)(2) and § 2.1210, this Initial Decision shall constitute the final decision of the Commission forty (40) days after its issuance, unless a petition for Commission review is filed, or the Commission decides to review this Initial Decision on its own motion. Unless otherwise authorized by law, a party who wishes to seek judicial review of this Initial Decision must first seek Commission review.

Respectfully Submitted, David R. Lewis Paul A. Gaukler PILLSBURY WINTHROP SHAW PITTMAN LLP 2300 N Street, NW Washington, DC 20037-1128 Tel. (202) 663-8000 Counsel for Entergy Dated: June 9, 2008 65

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of ))

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

CERTIFICATE OF SERVICE I hereby certify that copies of"Entergy's Proposed Findings of Fact and Conclusions of Law on Pilgrim Watch Contention 1," dated June 9, 2008, were served on the persons listed below by deposit in the U.S. Mail, first class, postage prepaid, and where indicated by an asterisk by electronic mail, this 9th day of June, 2008.

• Administrative Judge *Administrative Judge Ann Marshall Young, Esq., Chair Dr. Richard F. Cole Atomic Safety and Licensing Board Atomic Safety and Licensing Board Mail Stop T-3 F23 Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Washington, DC 20555-0001 amyvnrc. gov rfc 16ýnrc. gov

• Administrative Judge

• Secretary Paul B. Abramson Att'n: Rulemakings and Adjudications Staff Atomic Safety and Licensing Board Mail Stop 0-16 Cl Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Washington, DC 20555-0001 secy(Enrc. gov;hearingdocket(dnrc. gov pba(Pnrc.gov Office of Commission Appellate Atomic Safety and Licensing Board Adjudication Mail Stop T-3 F23 Mail Stop 0-16 Cl U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Washington, DC 20555-0001

a

• Susan L. Uttal, Esq. *Mr. Mark D. Sylvia

• Marcia Simon, Esq. Town Manager

• James E. Adler, Esq. Town of Plymouth Office of the General Counsel 11 Lincoln St.

Mail Stop 0-15 D21 Plymouth, MA 02360 U.S. Nuclear Regulatory Commission msylvia(ZZtownhall.plvmouth.ma.us Washington, DC 20555-0001 slu(anrc.gov; ieal (@nrc.gov; Marcia.simon(nrc. gov

• Ms. Mary Lampert *Chief Kevin M. Nord 148 Washington Street Fire Chief and Director, Duxbury Emergency Duxbury, MA 02332 Management Agency marvylampert(acomcast.net 688 Tremont Street P.O. Box 2824 Duxbury, MA 02331 nord(town.duxbury.ma.us

• Sheila Slocum Hollis, Esq. *Richard R. MacDonald Duane Morris LLP Town Manager 505 9th Street, N.W. 878 Tremont Street Suite 1000 Duxbury, MA 02332 Washington, DC 20006 macdonald(atown.duxburv.ma.us sshollis(aduanemorris.com

• Martha Coakley, Attorney General *Diane Curran

• Matthew Brock, Assistant Attorney General Harmon, Curran, Spielberg, & Eisenberg, LLP Commonwealth of Massachusetts 1726 M Street NW, Suite 600 Office of the Attorney General Washington, DC 20036 One Ashburton Place dcurran(oharmoncurran. corn Boston, MA 02108 Martha.Coakley@state.ma.us Matthew.Brock(ostate.ma.us Paul A. Gaukler 67 400839792v7