ML13148A389

Comment (343) of Kristin Hines Gladd of on Behalf of the Ayres Law Group, Friends of the Earth and Natural Resources Defense Council on Proposed No Significant Hazards Consideration Determination Regarding License Amendment on San Onofre, U

ML13148A389
Person / Time
Site:	San Onofre
Issue date:	05/23/2013
From:	Gladd K H Ayres Law Group, Friends of the Earth, Natural Resources Defense Council
To:	Rules, Announcements, and Directives Branch
References
78FR22576 00343, NRC-2013-0070
Download: ML13148A389 (183)

Text

Mendiola, Doris From: Kristin Hines Gladd <gladdk@ayreslawgroup.com>

Sent: Thursday, May 23, 2013 8:43 PM To: CHAIRMAN Resource; CMRSVINICKI Resource; CMRAPOSTOLAKIS Resource;CMRMAGWOOD Resource; CMROSTENDORFF Resource; OCAAMAIL Resource; Docket, Hearing; MDOANE@nrc.gov Cc: Dick Ayres; Jessica Olson

Subject:

Notice of FOE and NRDC Joint Motion to Consolidate LARs, Attachment 1 of 3 Attachments:

Part 1 of 3-FoE and NRDC Comments on Proposed NSHC Det for LAR 263.pdf Good evening, I earlier attempted to send as a single email the three attachments to the FOE and NRDC Joint Motion to Consolidate but received an error that the message exceeded the maximum message size. I am enclosing the first of three attachments here, with the other two to follow in separate emails.Thank you, Kristin Hines Gladd /Kristin Hines Gladd Associate Attorney Ayres Law Group 1707 L Street, N.W., Suite 850 Washington, DC 20036 gladdk(ayreslawgroup.com 202.452.9222 7'~$/ ~IJJ En C)I]En r-)F--r-n-.-D C!)7 SUNSI Review Complete Template = ADM -013 E-RIDS= ADM-03 Add= B. Benney (bjb)1 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE NRC STAFF In the Matter of )) Docket ID NRC-2013-0070

)SOUTHERN CALIFORNIA EDISON CO. ))(San Onofre Nuclear Generating Station, )Units 2 and 3) ) May 16,2013 FRIENDS OF THE EARTH'S AND NATURAL RESOURCES DEFENSE COUNCIL'S COMMENTS IN OPPOSITION TO PROPOSED NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION I. INTRODUCTION Friends of the Earth (FoE) and Natural Resources Defense Council (NRDC) submit the following comments in opposition to the recently proposed no significant hazards consideration determination regarding a license amendment request that would modify the terms of San Onofre Nuclear Generating Station Unit 2's operating license. FoE and NRDC assert that there should be a hearing prior to any Nuclear Regulatory Commission (NRC) decision on the proposed license amendment.

The proposed amendment would allow operation at no more than 70%Rated Thermal Power (RTP) (or 2406.6 megawatts thermal) for the duration of Cycle 17.1,2 To analyze the proposed no significant hazards consideration determination, Friends of the Earth has enlisted the assistance of four experts with substantial and relevant experience related to the issues presented by the proposed no significant hazards consideration finding: 1 Application and Amendment to Facility Operating License Involving Proposed No Significant Hazards Consideration Determination, San Onofre Nuclear Generation Station, Unit 2, 78 Fed. Reg. 22576 (April 16, 2013)("Notice of License Amendment Proposal").

2 Because Edison plans to operate Unit 2 intermittently during Cycle 17, this operational period could last between 22 and 24 months.

" Nuclear engineer and former NRC Staff, Dr. Joram Hopenfeld:

During his time at the NRC, Dr. Hopenfeld's work led to the creation of a Steam Generator Action Plan to address safety issues in steam generators.

He has extensive experience with steam generator tube failure." The Honorable Victor Gilinsky, former Commissioner of the United States Nuclear Regulatory Commission:

During Dr. Gilinsky's NRC tenure Congress passed the Sholly amendment 3 and the Commission first interpreted and applied the amendment.

• Nuclear engineer John Large, of Large & Associates:

Mr. Large is a Consulting Engineer and Chartered Engineer, who was a full-time member of the Academic Staff at Brunel University for over 25 years. Mr. Large frequently provides expert evidence on nuclear systems failures and other technical issues in the U.K.Crown and Civil Courts." Mr. Arnold Gundersen, a nuclear engineer:

Mr. Gundersen is a former licensed nuclear reactor operator and Chief Engineer at Fairewinds Associates.

Public comment on the proposed no significant hazards consideration determination is made difficult by the lack of information associated with both the specific license amendment request and the Staff's proposal.

In order to respond to the proposed determination, Friends of the Earth's experts reviewed studies submitted by SCE in the parallel Confirmatory Action Letter (CAL) proceeding supporting a proposal to restart Unit 2 at 70% of power.4 3 Incorporated into the Atomic Energy Act at 42 U.S.C. § 2239(a)(2)(A).

4 SCE submitted the operational assessments reviewed here in response to a March 27, 2012 CAL. See Letter from Elmo E. Collins, Regional Administrator, Region IV, Nuclear Regulatory Commission, to Peter T. Dietrich, Senior Vice President

& Chief Nuclear Officer, Southern California Edison, Confirmatory Action Letter -San Onofre Nuclear Generating Station, Units 2 and 3, Commitments to Address Steam Generator Tube Degradation, CAL 4 001 (Mar. 27, 2012), available at ADAMS Accession No. ML12087A323.

2 Having reviewed these submissions of SCE in support of the proposal to allow operation of Unit 2 at 70% of power, and the analyses of Mr. Large, Dr. Hopenfeld, Dr. Gilinsky, Mr.Gundersen, and consistent with LBP-07-13, the May 13, 2013 opinion of the Atomic Safety &Licensing Board (ASLB), 5 discussed below, FoE and NRDC request that the proposed no significant hazards consideration determination should be withdrawn because (1) the Staff s proposal exceeds the authority granted to it by the Sholly amendment; (2) the licensee's application of the criteria under 10 C.F.R. § 50.92, as adopted by the NRC Staff, does not justify a finding of no significant hazards consideration; and (3) the Staff have not performed an environmental review of the proposed finding and license amendment as required by the National Environmental Policy Act (NEPA), and the proposed actions do not satisfy criteria for a categorical exemption from NEPA review, provided at 10 C.F.R. § 51.22(c)(9)(i).

FoE's and NRDC's analysis is supported by the ASLB's May 13, 2013 decision holding that the licensee's restart plan, which proposes operation in conformance with the proposed license amendment, constitutes a defacto license amendment proceeding.

The decision is based not only on the need to revise technical specification 5.5.2.1 1.b.1 through the license amendment proposed in the present action, but also on the need to revise the Updated Final Safety Analysis Report (UFSAR), which currently fails to account for in-plane fluid elastic instability (FEI)-one of the main defects present in the replacement steam generators.

Approving the requested license amendment-temporary operation at 70% of power-would authorize the licensee to operate the plant with an outdated and insufficient UFSAR; another reason why a finding of no significant hazards consideration is inappropriate in this case.5 Soulhern California Edison Co. (San Onofre Nuclear Generating Station, Units 2 and 3), LBP-13-07 (May 13, 2013) ("ASLB Order"), appended to these comments as Attachment 6.3 The Staff has ignored the language and legislative history of the Sholly Amendment as recited by the Ninth Circuit in the Mothers for Peace case, discussed below. As the court held, the amendment gives the NRC Staff the right to screen out trivial changes that could not possibly affect safety. If a safety issue is identified, however, then the Staff must legally conclude that a significant hazards consideration exists, and must refer the issue(s) to an Atomic Safety and Licensing Board for a hearing prior to the decision on the proposed license amendment.

The court ruled that the NRC Staff should "not resolve doubtful cases with a finding of no significant hazards consideration." The court added, from the legislative history, that the NRC Staff should not "prejudge the merits" of the issues by a proposed license amendment.

The Staff does not determine whether a significant hazard exists; that is for the ASLB to determine.

Thus the Staff s proper role under the Sholly amendment is essentially ministerial:

it determines whether a significant hazard consideration exists, and if so, asks the ASLB to determine whether the proposed amendment creates a significant hazard. Consistent with the Mothers for Peace case, the Staff must refer SCE's proposed license amendment to an ASLB: A probability, not just a possibility, of significant hazards permeates this case.It follows that the Staff has disregarded its appropriate role in proposing a no significant hazard consideration finding in this instance.

The safety issues presented here are real, not trivial, as acknowledged in the ASLB panel decision of May 13, 2013. Under applicable law, the Staff must withdraw the proposal and refer the proposed license amendment to the ASLB for an adjudicatory hearing, as requested by Friends of the Earth and NRDC in these comments, before a decision on the proposed amendment can be made.4 II. FACTUAL BACKGROUND

a. The Shut Down of Units 2 and 3 On January 31, 2012, San Onofre experienced a steam generator tube rupture in Unit 3 that resulted in the release of radioactive material into the environment.

The licensee, Southern California Edison Company (SCE or "Edison")

also discovered excessive wear in the Unit 2 replacement steam generators.

The unit was offline for a refueling outage. Subsequently, untimely degradation of the walls of many tubes was discovered in the replacement steam generators, which had been in operation for eleven months in Unit 3 and less than two years in Unit 2.On March 23, 2012, SCE submitted a description of the steam generator problems and its commitments to address the issues at Units 2 and 3, which were formalized in a CAL to SCE on March 27, 2012.None of the investigations conducted to date have determined the root cause of the premature and extensive tube degradation in the replacement steam generators.

Lacking such understanding, SCE has not proposed any action to actually fix the problems of either Unit 2 or Unit 3. Rather, SCE has proposed a restart plan based on substantially reduced operational limits that it has asserted is safe.b. Southern California Edison's Replacement of the Steam Generators at San Onofre Units 2 and 3 In 2010 and 2011, SCE replaced the original steam generators in Unit 2 and Unit 3, which had operated for 28 years, with ones constructed by a different manufacturer, Mitsubishi Heavy Industries (MHI). The new design differed from the original in significant ways. SCE requested MHI, for example, change the design by adding 377 more tubes, remove the stay cylinder supporting the tube sheet, and replace the "egg crate" tube support with a broached 5 design, among other alterations.6 SCE convinced itself that the replacement steam generators were a "like for like" replacement for the old ones and did not seek a license amendment for these changes. Thus, the impact of these changes on safe operation of the plant has not previously been evaluated by the NRC.c. Extent of Tube Degradation in the Steam Generators in Units 2 and 3 Both units show indications of extensive tube wear after fewer than two years of operation.

The tube degradation in each unit is unlike, in both mechanism and extent, tube wear in other replacement steam generators in other U.S. plants at the same stage of their useful lives: " San Onofre Unit 2 has 1595 degraded tubes; Unit 3 has 1806;" Unit 2 has 4721 tubal wear indications; Unit 3 has 10,284;" Unit 2 has 510 tubes plugged after one cycle of operation of the replacement steam generators; Unit 3 has 807;" SCE and NRC have reported that 9% of the tubes in Unit 3 steam generators have greater than 10% through-wall wear indications; in Unit 2, 12% of the tubes show such wear.Tube wear of this magnitude after such an abbreviated period of operation is unprecedented.

7 d. SCE's Previous Assessments of Operation at 70% of Rated Thermal Power As part of its response in the CAL process, SCE submitted to NRC Staff numerous operational assessments by its consultants.

While agreeing that the proximate cause of wear of the replacement steam generator tubes was excessive vibration, SCE and its consultants have not identified a root cause of the excessive vibration causing the premature and extensive tube wear, 6 For a more detailed description of the changes, see Declaration of Arnold Gundersen (May 31, 2012) (Originally submitted to the NRC as an attachment to a June 18, 2012 Petition to Intervene by Friends of the Earth) at ¶¶ 22-23 and MHI Root Cause Analysis and Supplemental Technical Evaluation Report at pp. 47-48, appended to these comments as Attachment 4 and 5, respectively.

' See ASLB Order at p. 25 (citing SCE's statement to that effect).6 as described in Table 6-1 of SCE's Unit 2 Return to Service Report. In fact, Edison's own consultants disagree with one another on the mechanistic cause of the tube wear. SCE's response to the CAL includes an analysis of tube-to-tube wear and argues that the cause of such wear is FEI. However, this response does not identify the root cause that produced the FEI or acknowledge other thermal hydraulic forces at work in the steam generators.

Without knowing the root cause, as declarant nuclear engineer John Large asserts, it is not possible to determine whether the steam generators can be safely operated in their current condition.

SCE's response to the CAL includes a proposal to restart Unit 2 at no more than 70%power for 150 cumulative days, at which time SCE promises to shut down the reactor and inspect the tube wear. The current proposed license amendment is required because Edison has failed to demonstrate to the NRC that it can meet the terms of the existing license requiring a demonstration of tube structural integrity at 100% of power. This point alone makes it impossible for the NRC to reach a determination that Edison's proposed license amendment presents no significant hazards consideration.

Edison's response to the CAL is nearly identical to the license amendment request in the present instance:

to modify Unit 2's license to limit maximum power for operation at 70% for Cycle 17. SCE hired AREVA NP, Westinghouse Electric Company LLC, and Intertek/APTECH to provide operational assessments (OAs) of this proposal.

MHI, the manufacturer of the replacement steam generators, also examined the unprecedented tube wear and present condition of the tubes.These assessments, which are included in SCE's response to the CAL, not only demonstrate clearly that there are significant hazards to be considered before ruling on the license amendment request, but they also suffer from important omissions.

The studies focus on 7 tube-to-tube wear as the threat to tube rupture, incorrectly assuming that this mode of wear will outpace all other wear modes. They do not analyze the potential safety effects of further degradation of the tubes in Unit 2 that are vibrating against the retainer bars and tube restraint structures; nor do the OAs address extent and impact of metal fatigue on the damaged tubes'structural integrity.

The OAs point to different mechanical interactions resulting from FEI and random fluid excitation sources as the causes of the tube degradation, but none determined the root cause of the in-plane tube motion excitation forces, which appear to be unique to San Onofre's replacement steam generators.

In addition to failing to identify the root cause of the tube degradation or to recognize the different modes of wear, SCE and its consultants also failed to agree on the projected length of time before a tube burst may occur, even by their own inadequate analysis.

Estimates vary from six months to sixteen months of operation at 70% RTP, indicating that the underlying risk analysis is fundamentally flawed.8 In other words, SCE cannot say with confidence that a tube burst is unlikely within the time frame of Cycle 17, which is 22-24 months, at 70% of power.What both assessments say is that the tubes will deteriorate at a pace that will cause steam generator failure, in the best-case scenario within 16 months, and the worst case 6 months-a mere month more than the period SCE proposes to run the plant, were its license amendment to be approved.The consultants' estimates are remarkable for two reasons. First, neither projects the unit can be run safely, even at reduced power, for more than 16 months-even though the original expectation of SCE and the designers was that they would last for three decades or more.Second, the two estimates differ by a factor of nearly three. The fact that each of the consultants 8 Declaration of Mr. John Large, May 16, 2013 ("Large Decl.") at ¶ 8.5.14, appended to these comments as Attachment

2.8 relied

upon by SCE project significantly different periods of time before reaching and surpassing this safety threshold "shows that the underlying data and methodology of the predictions is fundamentally flawed." 9 In view of this "uncertainty and unreliability" Mr. Large concludes that"little assurance can be placed with SCE's confidence that its Cycle 17... will pass without encountering a significant increase in the risk of tube failure.]

0 Moreover, the estimates by SCE's consultants do not account for the fact that "a certain percentage of steam generator tubes have used up their entire or a large fraction of their allowable fatigue life during cycle 16."l1 Fatigued tubes present a more significant risk than tubes degraded by stress corrosion cracking because tube failure caused by fretting fatigue will result a sudden burst and "proceed rapidly to its maximum as it happened a North Anna (NRC Bulletin 88-02)."'12 These facts demonstrate the absurdity of the Staff's proposal to conclude that operation of San Onofre as described in the proposed license amendment presents no significant hazards consideration.

SCE has received assessments on the issue of various tube wear modes by AREVA, the other consultants, and MHI, but SCE did not include important aspects of these assessments in its response to the CAL. For example, SCE have chosen not to emphasize or explain an analysis by MHI, which found that tube wear from contact between the tubes and anti-vibrations bars in Unit 2's replacement steam generators arose in areas of the tube bundle where FEI was inactive, suggesting that the wear was caused by turbulent flow forces that may persist even at the proposed power level of 70% intended to suppress the FEI. In light of these facts, the NRC cannot properly find that no significant hazards consideration is raised by 9 Large Decl. at ¶ 8.5.14.'0 Large Decl. at ¶ 8.5.15.Declaration ofDr. Joram Hopenfeld, May 16, 2013 ("Hopenfeld Decl.") at p. 7.Q: Hopenfeld Decl. at p. 8.9 amending the license to allow the unit to be restarted.

What is clear is that the proposed amendment does present significant hazards consideration that require airing in a public adjudicatory hearing before the license amendment can be granted and tile unit can be allowed to operate again.III. COMMENTS We note at the outset that the record for this proposed no significant hazards consideration determination is perplexingly thin. The docket contains only the Federal Register notice of the proposed finding (along with a few comments from citizens).

To address the significant hazards consideration involved in the proposal to operate the damaged replacement steam generators at 70% of power, FoE's experts were required to review the technical analyses in the public record in another proceeding (i.e., the operational assessments provided by SCE in response to the March 27, 2012 Confirmatory Action Letter).The Staff has not placed any analysis of the § 50.92 factors into the record.1 3 They have ignored the fact that these steam generators are so badly damaged that the licensee has not proposed restarting Unit 3 and concedes that the damaging forces will continue to degrade the steam generator tubes in Unit 2 to the point of failure.In reality, the Staff's proposal ignores the fact that what is at stake is the licensing of badly damaged steam generators that Edison concedes will continue to be further damaged by operation.

It fails even to attempt to explain how operating Unit 2 can pass the rigid standards of 10 C.F.R. § 50.92 and it ignores the Sholly amendment by treating as routine the safe operation of a plant that even the Staff admits is not safe to run at full power.1 See Docket ID No. NRC-2013-0070.10 In a related proceeding, an ASLB convened by the Commission recently determined that SCE's proposal to restart San Onofre Unit 2 at 70% of power on an experimental basis is a de facto license amendment proceeding, which requires "rigorous NRC Staff review appropriate for a licensing action."'1 4 The ASLB found that SCE's proposal would allow Unit 2 to operate outside the current licensing basis of the plant, not only because a maximum operating level of 70% of power does not comply with Technical Specification 5.5.2.11 .b.1, but also because restarting the steam generators in their current degraded condition is outside the bounds of the safety analyses that form the licensing basis for the plant (the UFSAR). Having found that"there is a dearth of applicable experiential data available for in-plane vibrational motion, because, as conceded by SCE, 'tube-to-tube wear due to in-plane [fluid elastic instability]

ha[s]not been previously experienced in U-tube steam generators,'

",,5 the Board held that prior to restart SCE is required to submit a license amendment that properly updates the FSAR to include a full assessment of the effects of in-plane fluid elastic instability:'

6 We conclude that until the tube degradation mechanism is fully understood, until reasonable assurance of safe operation of the replacement steam generators is demonstrated, and until there has been a rigorous NRC Staff review appropriate for a licensing action, the operation of Unit 2 would be outside the scope of its operating license because the replacement steam generator design must be considered to be inconsistent with the steam generator design specifications assumed in the FSAR and supporting analysis.

In short, the start-up of Unit 2 pursuant to the CAL process would transform that process into a de facto license amendment proceeding by allowing steam generator operation with a tube degradation mechanism not considered in the FSAR -i.e., in-plane vibrations due to fluid elastic instability.17 The Staff's proposal to find that the license amendment request presents no significant hazards consideration would authorize SCE to restart Unit 2 at 70% of power without updating 14 ASLB Order at 32.15 ASLB Order at 34, n. 54.16 ASLB Order at 32.17 ASLB Order at 32, 33 (internal citations omitted).11 the FSAR. The proposal, if made final, would thus contravene the ASLB's order. More fundamentally, the three impartial experts who constitute the panel have confirmed the views of FoE's experts that the proposed license amendment and restart plan is an experiment that raises significant safety issues in all three of the regulatory criteria that must be satisfied in order to make a finding of no significant hazards consideration.

For these reasons, the proposed no significant hazards consideration determination should be withdrawn.

Moreover, (1) the ASLB's conclusions mirror the analyses by FoE's experts that the proposed license amendment fails to meet any of the criteria required for a no significant hazards consideration finding, and (2) the Staff's proposed determination violates the terms of the Sholly Amendment.

a. The Proposed Finding of No Significant Hazards Consideration Exceeds the Authority of the NRC Staff Section 189a of the Atomic Energy Act (AEA) requires that, if requested, a public hearing must be held prior to the issuance of any license or license amendment before an Atomic Safety and Licensing Board.1 8 The "Sholly" amendment, 42 U.S.C. § 2239(a)(2)(A), provides a limited exception to this general rule. The NRC staff may issue a license amendment before a hearing only if it finds the license amendment raises no significant hazards consideration.

The relevant regulations are found at 10 C.F.R. § 50.92(c), which we describe in detail below. The legislative history of the Sho~ljy amendment makes clear that it is limited to only the most routine license amendments, which may be granted prior to the hearing guaranteed by the AEA.'9 Under NRC regulation 10 C.F.R. § 50.92, the NRC Staff may not determine that a proposed license amendment raises no significant hazards consideration, and thus must refer the 18 42 U.S.C. § 2239(a)(l)(A).

19 See Declaration of Victor Gilinsky, May 16, 2013 ("Gilinsky Decl.") at ¶ 5, appended to these comments as Attachment 3 ("Congress permitted

[no significant hazards consideration]

determinations in routine cases that obviously had no or essentially no safety significance, but not otherwise.").

12 matter to an ASLB for resolution bejbre the license amendment may be issued, whenever a proposed license amendment will: (1) Involve a significant increase in the probability or consequences of an accident previously evaluated; (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety.The proposal to approve SCE's license amendment application is fundamentally inconsistent with the purpose of the Sholly amendment to the Atomic Energy Act, which is the authority for 10 C.F.R. § 50.92. The Sholly exception to the rule that proposed license amendments should not be approved prior to a public hearing before an ASLB was intended to be a narrow one, to be used to avoid delay for routine amendments no one would suggest posed significant hazards considerations, such as replacing a gauge.20 The three criteria of 10 C.F.R. § 50.92 are therefore to be read narrowly.

Unless the three conditions are met unequivocally, the NRC should grant a hearing before an ASLB prior to deciding whether to approve a license amendment.

In short, if a proposed license amendment presents a significant hazards consideration-that is, if a comment identifies an issue involving significant hazards-then the matter must be referred to an ASLB for resolution before the proposed license amendment may be considered.

SCE's proposed license amendment could not be further from the kind of change Congress sought to exempt from a prior hearing through the Sholly amendment:

as demonstrated by FoE's experts and the recent opinion of the ASLB, the prospect of restarting San Onofre Unit 2 with damaged and unrepaired steam generators presents significant new and ill-understood safety risks, not routine changes to technical specifications such as updated inspection routines or new gaskets or gauges.20 Gilinksy Deci. at ¶ 3.13 The proposed no significant hazards consideration determination in this case must be withdrawn because, rather than determining whether a significant hazards consideration was present requiring referral to an ASLB for a hearing prior to a decision on the license amendment, the NRC Staff preempted the Atomic Safety and Licensing Board, eschewing its proper role as regulator and instead assuming the judicial role allocated to the ASLB under the AEA, including the Sholly amendment.

Rather than identify and refer the obvious significant hazards considerations involved in SCE's application for a license amendment, the NRC Staff simply adopted the licensee's evaluation of the merits of the license amendment request, apparently without question.This is exactly what the Ninth Circuit held invalid in San Luis Obispo Mothers for Peace.21 Under the Mothers for Peace ruling, the purpose of the no significant hazards consideration determination by the Staff is simply to identify whether there are new or increased risk considerations that should be reviewed by an ASLB before the proposed license amendment can be issued. Whether the new or increased risks are acceptable is a decision for the ASLB, to be decided in a hearing held prior to deciding whether to approve the proposed license amendment.

Moreover, the ASLB's recent decision, noted above, on the risks presented by SCE's proposed temporary operation at 70% of power found that, The unprecedented extent of tube wear and failures that SCE experienced in the SONGS Unit 3 replacement steam generators reveal that these steam generators have serious design and operational issues, placing them beyond the envelope of experience with U-tube steam generators.. .Although the Unit 2 steam generators did not experience the accelerated and extensive tube-to-tube wear suffered in the Unit 3 steam generators, they nevertheless are the identical design as those in Unit 3 and they operate under similar conditions.

2 2 21 San Luis Ohispo Mothersj br Peace v. US. Nuclear Regulamopy Commission, 799 F.2d 1268 (9th Cir. 1986).22 ASLB Order at p. 25.14 In these circumstances, a finding of no significant hazards consideration is wholly inappropriate and exceeds the authority of the NRC under the AEA.Thus, the NRC should convene an ASLB prior to making a decision whether to issue the license amendment to examine the significant safety issues posed by SCE's proposed license amendment to allow operation of the damaged replacement steam generators at 70% power for Cycle 17 (22-24 months). Such an adjudicatory hearing would provide reassurance to the people of Southern California and would be consistent with the Commission's announced policy of transparency.

The current attempts to misuse 10 C.F.R. § 50.92 to exclude public participation can only exacerbate public distrust for the NRC and of the safety of the San Onofre plant, whatever decision is ultimately made.b. The Proposed License Amendment Presents New and/or Increased Risks That Endanger Public Health and Safety If it actually considered the criteria of 10 C.F.R. § 50.92, the Staff could not determine that the proposed license amendment for San Onofre entails no significant hazards consideration.

If the proposed change in the license fails to meet any one of the three criteria in 10 C.F.R. § 50.92, the NRC must withdraw the proposed no significant hazards consideration determination.

As demonstrated in the technical analyses appended to these comments, and by the ASLB's recent decision on San Onofre, the proposed amendment does not satisfy any of the three criteria.To assess whether the change proposed by SCE creates a significant hazards consideration, the appropriate comparison is between the operation of the unit with undamaged steam generators as assumed in SCE's current license, on the one hand, and the operation at 70%of power with damaged steam generators that Edison now proposes.

SCE's rationale for concluding that no significant hazards consideration is presented is apparently based on 15 comparing operation with undamaged tubes at 100% and 70%, completely ignoring the current highly-damaged state of the steam generators in Unit 2. As Dr. Hopenfeld states, SCE's evaluation of the § 50.92 criteria "is based on the presumption that change in power level can be discussed without giving any considerations to the physical conditions of the tubes before and after the change.:23 The NRC cannot, despite its best efforts, ignore the events of the past 16.5 months.Major defects causing unprecedented tube wear have been discovered in the replacement steam generators at San Onofre, and while the mechanical force that inflicted the wear has been identified as primarily in-plane FEI, neither the NRC nor the licensee has yet determined the root cause of the FEI, let alone a remedy for it. Instead, SCE and the NRC propose to simply restart Unit 2 and operate it at reduced power for one cycle as an experiment to see whether the plant can be run longer at that reduced rate. One could not possibly conclude that such a proposal does not at least raise "significant hazards" considerations that require further scrutiny in a hearing to decide whether the additional risk of exposing Californians to radiation are acceptable.

The Staff simply ignores the fact that Unit 2's replacement steam generators have already demonstrated design flaws in components and systems critical to the safety of San Onofre Unit 2.i. The Proposed Finding of No Significant Hazards Consideration Should Be Withdrawn Because the Proposed License Amendment Would Involve a Significant Increase in the Probability or Consequence of an Accident Previously Evaluated.

Staff addresses the first criterion of 10 C.F.R. § 50.92 by simply restating SCE's analysis, which concludes that the proposed license amendment would not involve a significant increase in the probability or consequence of an accident previously evaluated "because there is no 23 Hopenfeld Deci. at p. 6.16 adverse effect on plant operations or plant conditions." 2 4 SCE relies on its response to Requests for Additional Information (RAIs) 11-14 as its basis for this assertion.

2 5 SCE, however, fails to make the appropriate comparison when applying this first criterion.

SCE's apparent position is that the relevant comparison is between operation of fully functional undamaged steam generators originally licensed to run 100% of power and operation of those same steam generators at 70% of power. That characterization is incorrect.

The proper consideration is whether operating at 70% of power with defective, damaged, and unrepaired steam generators involves a significant increase in the probability or consequence of an accident previously evaluated, as compared to the risk of operating at 100% of power with fully functional, undamaged steam generators.

In this context, operating the steam generators in their present condition at 70% of power creates a significant increase in the probability of a release of radioactivity and in the consequences

-exposure of potentially millions of people to increased radioactivity.

The three impartial experts who wrote the ASLB's recent decision on San Onofre found that operating the replacement steam generators at 70% would significantly increase the probability and consequences of a previously analyzed accident.2 6 For example, the replacement steam generators can no longer meet 10 C.F.R. Part 50, App. A -General Design Criterion (GDC) 14 (Reactor Coolant Pressure Boundary), which requires "an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture." SCE's own tube-to-tube wear assessment, as the ASLB order notes, shows that "one unstable tube can drive its neighbor into instability through repeated impact events."'2 7 Given this condition, there is no 24 Notice of License Amendment Proposal at p. 22577.25 Notice of License Amendment Proposal at p. 22577.26 ASLB Order at p. 27.27 ASLB Order at p. 27.17 longer "an extremely low probability" of the kind of tube failure GDC 14 is meant to guard against.Nuclear engineers Mr. Large and Dr. Hopenfeld show in the attached declarations that the proposed amendment would involve a significant increase in the probability or consequence of an accident previously evaluated.

Mr. Large explains that the excitation forces present in the steam generators exist due to pressure and temperature conditions that will not be affected by reducing the power from 100% to 70%.28 Thus, contrary to the assertions of SCE, operating Unit 2 at 70% of power during Cycle 17 would not reduce the forces exerted on the tubes during Cycle 16 that caused the unprecedented rapid tube wear and deterioration.

2 9 Both of SCE's operational assessments agree that the damage will continue at an unprecedented pace, differing only between 6 months and 16 months as the remaining life-expectancy of the Unit. Even at 70% of power, large numbers of tubes in the replacement steam generators will continue to wear and degrade and, as a consequence, significantly increase the probability of tube rupture.Dr. Hopenfeld asserts that the probability and consequences of a previously considered accident are significantly increased because, in addition to the fact that operating at 70% of power will not reduce the excitation forces that cause tube wear, SCE also failed to take into account metal fatigue caused by fretting, which is brought on by the FEI-induced vibration.

Tubes in Unit 2's steam generators used up a large fraction, if not all, of their allowable "fatigue life" during the last cycle of operation, Cycle 16.30 Dr. Hopenfeld asserts: The number of tubes which are susceptible to rupture by fatigue during a given accident scenario must be known if one is required to predict accident consequences.

Until this is done the present pressure based burst performance criteria cannot be used as a reliable 28 Large Dec. at T 8.5.3.29 Large Deci. at ¶ 8.5.5.30 Hopenfeld Decd. at p. 7.18 indicator of risk. As a result it must be conservatively concluded that allowing Unit 2 to operate at any power level would significantly increase the consequences of the accidents, which were evaluated by SCE and were described in the UFSAR.3 1 SCE and its consultants have inspected the steam generators for tube surface wear and tube wall thickness but have failed to account for metal fatigue, which cannot be discerned by inspection.

Technical Specification Task Force (TSTF) 449 requires SCE to evaluate additional loads on the tubes that could contribute to burst or collapse, even if they cannot be physically measured.3 2 SCE's analysis ignores the increased probability or consequences of an accident contributed to by metal fatigue in the tubes of the steam generators.

Tube fatigue increases the probability of an accident.

It also increases the consequences, because tube failure owing to metal fatigue happens more suddenly than failure owing to stress corrosion cracking (SCC). A tube failure from fatigue, such as that experienced at the North Anna Generating Station Unit 1 on July 15, 1987, occurs suddenly and quickly.3 3 In the event of a main steam line break, for example, accompanied by the rupture of five or more fatigue-weakened tubes, the operator's inability to control the loss of coolant rapidly enough would lead to a significant increase in the probability of uncovering the core, with major increases in the consequences of a previously evaluated accident, including the exposure of millions of Californians to radiation.

3 4 Dr. Hopenfeld therefore concludes that restarting the plant for another cycle would place Unit 2 outside of the bounds of accidents evaluated in the updated final safety analysis (UFSAR)report by significantly increasing the probability and consequences of a main steam line break 31 Hopenfeld Decl. at p. 8.32 Hopenfeld Dec. at p. 7-8.31 Hopenfeld Decl. at p. 8.34 Hopenfeld Deci. at p. 9, 33.19 (MSLB) accident.3 5 Similarly, Mr. Large found that a single tube burst caused by an MSLB that damages the fuel core could result in severe consequences beyond those considered in the UFSAR.3 6 The NRC's proposed finding of no significant hazards consideration addresses none of the issues identified by Friends of the Earth's experts, as summarized above. Thus, the proposed finding must be withdrawn and a hearing on the proposed license amendment held before a decision is made on the proposal.ii. The Proposed Finding of No S'nifgicant Hazards Consideration Should Be Withdrawn Because the Proposed License Amendment Would Involve the Possibility of a New or Different Kind of Accident From Any Accident Previously Evaluated.

Significantly, the UFSARjbr the original steam generators for SONGS Units 2 and 3 excluded the possibility of in-plane vibrations caused by fluid elastic instability when evaluating the conditions necessary to maintain steam generator tube integrity[,]...

[an assumption that is] demonstrably unjustified for the replacement steam generators.

3 7--- ASLB Opinion, May 13, 2013 The NRC's regulations do not allow the Staff to make a no significant hazards consideration determination if it finds that the proposed license amendment would create the possibility of a new or different kind of accident not previously evaluated.

The Staff restates in the Federal Register notice proposing the license amendment the licensee's position that "the proposed changes do not require a change in any plant systems, structures, or components or the method of operating the plant other than to reduce power for the duration of Cycle 17.Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated." 3 8's Hopenfeld Decl. at p. 32.36 Large Decl. at ¶ 8.5.17.37 ASLB Order at pp. 31-32.38 Notice of License Amendment Proposal at p. 22577.20 Edison's "therefore" is misplaced:

the conclusion of the second sentence does not follow from the statement in the first. The premise of"no change" that SCE relies on for this conclusion, however, is erroneous because it ignores the change that shut the plant down more than a year ago: that an abnormally high amount of tube wear has occurred in the replacement steam generators, and, in particular, the unprecedented fretting fatigue caused by massive FEI and its impact on the steam generator tubes.First, the UFSAR does not consider the possibility of accidents caused by tube wear from in-plane FEI because it is based on an assumption that in-plane FEI will not occur. UFSAR section 5.4.2.3.1.3, which analyzes steam generator tube integrity, is therefore inadequate and demonstrates that operation at 70% of power presents new and different kinds of accidents from those previously evaluated.

The ASLB agrees. In its recent opinion on SCE's proposed restart plan under the CAL, the ASLB found that operating the replacement steam generators in their current degraded condition is a test or experiment as described under 10 C.F.R. § 50.59(C)(2).

3 9 By definition then, the proposed license amendment cannot possibly meet the second criterion for a no significant hazards consideration determination.

Operating at 70% for any length of time with the replacement steam generators in their current condition is an experiment, the outcome of which has not been analyzed in the UFSAR.Second, the UFSAR currently considers only accidents resulting from excessive pressure loads, not fretting fatigue. During Cycle 16, the tubes in Unit 2's steam generators experienced fretting previously not experienced in the history of any U.S. steam generator.

4 0 To allow the operation of the steam generators without repairs would, because of this unanalyzed fatigue, 39 ASLB Order at p. 33.40 ASLB Order at p. 25.21 create the possibility of a new or different kind of accident from any accident previously evaluated.

4'Accidents caused by fretting fatigue are different from accidents caused by stress corrosion cracking (SCC). As described above, unlike SCC, metal fatigue is difficult to detect through in-service inspections, and near or at the end of a tube's fatigue life cracking propagates much more quickly than SCC.42 There is no available data correlating field measurements to leakage from fatigued tubes during a design-basis accident.4 3 Thus, any safety analysis that is based on fatigue failures relates to a new and previously unanalyzed accident.4 4 SCE has yet to perform an analysis of probable accidents owing to fretting fatigue failures, which it must do before the proposed license amendment could possibly satisfy the second criterion of 10 C.F.R. §50.92.Specifically, Dr. Hopenfeld discusses five possible accident scenarios owing to fretting fatigue not considered by the existing UFSAR.4 5 In other words, the risk of these accidents arises from the fact that the tubes have already been substantially fatigued and will experience further fatigue at 70% operation:

1. Fretting fatigue rupture of a tube in the free span with a relief valve stuck open or a broken header;2. Unplanned closure of an isolation valve, increasing steam pressure abruptly, causing rupture of tubes on the border of exhausting their fatigue life;3. Seismically-induced ruptures of both plugged and unplugged tubes near the end of their fatigue life;41 Large Deci. at ¶ 8.6.26; Hopenfeld Deci. at p. 27-34.42 Hopenfeld Decl. at p. 29.43 Hopenfeld Decl. at p. 4.44 Hopenfeld Dec. at p. 27-34.45 Hopenfeld Decl. at p. 30-32.22

4. Severe accident causing rupture of tubes near the end of their fatigue life; and 5. Main steam line break accident:

in situ tests of tube integrity show only the tendency of tubes to leak on the basis of loss-of-wall-material or weakening by stress corrosion cracks. Fatigue failure would cause propagating circumferential cracks.4 6 Little data is available to assess the safety risks presented by these accidents due to the unprecedented and unique nature and extent of the damage to the tubes in Unit 2's steam generators.

4 7 Dr. Hopenfeld calculates that of the nearly 1100 tubes susceptible to fatigue failure, the probability of only 5 tubes rupturing during Cycle 17 exceeds the NRC's safety goals by a factor of 5.48 Thus, the proposed license amendment involves serious risks that SCE and the NRC have not considered, precluding a finding of no significant safety hazards consideration.

The risks associated with fretting fatigue are serious, and must be evaluated under the TSTF 449.Mr. Large also raises a number of considerations not taken into account by the Staff in its no significant hazards consideration determination.

While Mr. Large's technical analysis is presented in detail at section 8.6 of his attached declaration, the key points are summarized here.Foremost, Mr. Large emphasizes a critical omission in SCE's analysis:

SCE did not adequately consider--despite the evidence of extensive damage to literally hundreds of tubes-the possibility of a multiple tube failure, which would greatly exceed the design basis accident of a single tube burst. When evaluated against the current condition of the steam generators in Unit 2, Mr. Large details a number of situations with the potential for multiple tube failure that were ignored by SCE.The first of these situations is a scenario in which one of the restraining structures (the anti-vibration bars, or "AVBs"), some of which are already significantly worn, physically detach, 46 Hopenfeld Decl. at pp. 30-32.47 Hopenfeld Deci. at p. 33.48 Hopenfeld Deci. at p. 33.23 damaging tubes in the surrounding area.4 9 Since the conditions for such a potential AVB "break up" are possible (including a scenario in which seismically induced loading on the tube bundle could detach a worn-through AVB component), 5° SCE is required to consider the possibility of a worn section of an AVB detaching under various accident scenarios, thereby leading to a multiple tube failure.5 1 SCE, however, failed to do so.5 2 Notably, this includes SCE's failure to evaluate the seismic loading of the overall tube bundle, taking into account the degraded and defective tubes and components.

5 3 Mr. Large also describes a second accident scenario ignored by SCE in which both pressurized and plugged tubes failed locally, dislodging shrapnel into the tube bundle and thereby creating a pathway for a multiple tube failure.5 4 Mr. Large notes that various mechanisms exist that could lead to this result, including tube surface damage and flaws-scarring that is already present in the tubes but which SCE has not taken into consideration in the UFSAR.5 In short, SCE has not accounted for the effect of known mechanisms, such as this scarring, in its analysis of whether the proposed amendment would exceed the allowable stress limits in place to ensure tube integrity.s 6 As Mr. Large explains, when a tube is subject to certain stresses such as exist here, it is subject to two types of fatigue 5 7 (one of which, fretting fatigue, is discussed at length in the Hopenfeld Declaration).

A situation in which a number of tubes have high levels of fatigue is 49 Large Deci. at ¶9 8.6.14-8.6.17 (describing a number of situations that could detach portions of a worn AVB and the potential effects of an unrestrained object within the tube bundle).R0 Large Decl. at 8.6.16 (stating "[t]here are a number of situations that could challenge and possibly physically detach sections of such a worn down AVB, including seismically induced loading on the tube bundle, the immediate aftermath of a LOCA, and, quite possibly, the dynamic fluid forces triggered by a MSLB").51 Large DecI. at ¶ 8.6.17.52 Large Decl. at ¶ 8.6.33.53 Large DecI. at ¶ 8.6.34 (noting that, moreover, SCE may in fact be required to undertake a seismic response evaluation for the entire replacement steam generator assembly).

54 Large Decl. at ¶ 8.6.18.55 Large DecI. at ¶¶ 8.6.19-8.6.22.

56 Large Decl, at ¶ 8.6.22.57 Large DecI. at ¶ 8.6.24.24 more likely to result in multiple tube failure, particularly in the event that fatigue-weakened tubes come into contact with either shrapnel from a single burst tube or the severed tube itself.5 8 Having failed to address even the issue offatigue, SCE could not have evaluated, as it must, the effect of fatigue on a new or different type of accident involving multiple tube failures.Last, and significant for the purpose of evaluating the proposed license amendment, fatigue can run its course to failure within a single operation cycle,5 9 underscoring the importance of taking this factor into account in accident scenarios.

At base, the fundamental point here is that the damage to the tubes and tube restraint components that occurred during the previous operating cycle at San Onofre Unit 2 was so substantial that the response of these structural components to both normal-as well as possibly adverse-operating conditions have not been accounted for, either in the original design accident cases, nor in the analyses SCE relies upon to justify restarting Unit 2 at 70% of power.Accordingly, SCE's analysis cannot purport to demonstrate that running the plant at 70% power will not involve the possibility of a new or different kind of accident from the types considered previously.

Soberingly, it is precisely this type of accident, such as, for example, a multiple tube failure, that would result in the most severe consequences for public health and safety.6°58 Large Decl. at ¶ 8.6.25.59 Large Deci. at ¶ 8.6.26.60 Large Decl. at 119.1 (stating that "it is quite feasible that failure of a few defective tubes could trigger a major nuclear plant malfunction that, in itself, provokes the bursting of more degraded or defective tubes creating a very significant radiological release via a primary containment bypass. Also, there is the possibility that a major plant malfunction, such as a MSLB, could rapidly result in failure of multiple tubes already weakened in a degraded or defective condition").

25 iii. The Proposed Finding of No Signifcant Hazards Consideration Should Be Withdrawn Because the Proposed License Amendment Would Involve a Significant Reduction in a Margin of Safety.The assessment in this [Hopenfeld's]

report does not support SCE's position that operation of Unit 2Jbr five months at 70% power will not affect safety. It is shown that SCE conclusions are not conservative.

Operation of Unit 2 even for one month at any power level would present a safety risk. 6r--Dr. Joram Hopenfeld NRC's regulations at 10 C.F.R. § 50.92 prevent the Staff from making a finding of no significant hazards consideration where the proposed amendment would involve a significant reduction in a margin of safety. As an initial matter, the ASLB's decision raises a number of serious safety considerations that are evidence that the Staff's position on the no significant hazards consideration is indefensible.

SCE's optimistic Operational Assessment estimates of the margins of safety of operation at 70% of power are not justified by experience, as the ASLB pointed out: SCE's prediction that accelerated tube wear will be precluded by plant operations limited to 70% power is grounded on theory that is not yet supported by actual experience

.... [T]here is a dearth of applicable experiential data available for in-plane vibrational motion, because, as conceded by SCE, "tube-to-tube wear due to in-plant [fluid elastic instability]

ha[s] not been previously experienced in U-tube steam generators.'62 The ASLB further held that the in-plane vibrations caused by FEI were never considered 63 in the UFSAR. The analyses in the UFSAR provide the basis for operating the plant within an acceptable margin of safety. Restarting a reactor unit with known defects caused by mechanisms (e.g., in-plane FEI) that were not analyzed in the UFSAR thus significantly decreases the margin of safety provided for by the UFSAR.6' Hopenfeld Decl. at p. 10.62 ASLB Order at p. 34, n.54, quoting Edison Answering Brief at 10.63 ASLB opinion at p. 3 1.26 FoE's experts agree that SCE and the Staff cannot show that SCE's license amendment proposal would maintain the required margin of safety in the current license. Dr. Hopenfeld, for example, concludes that operating Unit 2 at 70% of power for Cycle 17 would not be in compliance with ASME code, as required by 10 C.F.R. § 50.55(a), because many of the tubes in Unit 2's steam generators have exhausted their fatigue life.6 4 An increased risk of a MSLB accident is an obvious example of the significant reduction in the margin of safety posed by the license amendment request, since such an accident would cause the largest leakage from the fatigued tubes.6 5 According to Dr. Hopenfeld's analysis, the proposed license amendment would increase the Large Early Release Frequency (LERF) of radiation escaping to the environment to a level 66 five times greater than the Commission's stated safety goals. A five-fold increase in risk with potential for large-scale human exposure and the evacuation of southern California is undoubtedly a "significant reduction in the margin of safety." Mr. Large similarly rejects SCE's conclusion that the proposed amendment would not involve a significant reduction in a margin of safety on the grounds that when it was originally determined, the safety margin 6 7 required by the NRC assumed that the functionality of the replacement steam generators complied with the design specifications.

6 8 The fact that they do not is now evident. Critically, the import of this is that "any detriment arising from a design omission or design shortcoming," such as those discussed above, "would not have been included 64 Hopenfeld Deci. at p. 9.65 Hopenfeld Dec. at p. 9.66 Hopenfeld Decl. at p. 9.67 Large Decl. at ¶ 8.7.2.68 Large Decl. at ¶ 8.7.4.27 for in the safety margin" 6 9-meaning that the safety margin that exists now has been substantially eroded by the defective tube conditions.

This deficiency, which reduces the safety margin by an unknown degree, is further exacerbated by any additional processes created by the design defects, such as, for example, the fretting fatigue discussed by Dr. Hopenfeld.

Thus, as Mr. Large states, the "particular processes arising from such a omission or shortfall, in this case the occurrence of fretting fatigue at the AVB-to-tube contact point and its potential to substantially reduce the plain fatigue life of individual tubes, would also not have been included for in the safety margin." 7°In sum, the safety margin critically does not take into account the current condition of the plant, specifically, the effect that operating with numerous, severely damaged tubes has on the margin of safety assumed to be in place. In other words, the safety margin is not nearly conservative enough, given the condition of the plant. The second critical point the Staff missed is that the safety margin-overly optimistic to begin with-is now being further reduced, according to FoE's expert, "in ways and to an extent that cannot be precisely defined,"71 as operating the plant at 70% versus 100% will not reduce the forces acting to degrade the tubes.7 2 Last, regarding stress analyses, MHI's analysis, performed for SCE, of stress on the tubes in the replacement steam generators is deficient in a number of ways that significantly reduce the margin of safety of the proposed change. For example, MHI used a finite element model to calculate the stress to which the tubes were subjected and concluded based on this model that the 69 Large Decl. at ¶ 8.7.4.'o Large Decl. at ¶ 8.7.5.71 Large Decl. at ¶ 8.7.8.72 Large Decl. at ¶ 8.5.3 (stating "The driving force, so to speak, for single tube failure is the differential pressure acting across the tube wall at the operating temperature.

Operating at the proposed 70% RTP will not result in any significant change in the tube differential pressure and the peak tube wall temperature, so the tubes will be subject to the much same forces (radial stress) and tube material strength response (ie the yield stress weighted in account of temperature) as experienced at 100% RTP.").28 tubes would not fail from fatigue.7 3 MHI's analysis was based on erroneous assumptions, however. When corrected, MHI's model would predict tube failure from fatigue because the stress on the tubes exceeds the ASME Endurance Limit.7 4 Taken together, these analyses by FoE's experts show that the proposed amendment would involve a significant reduction in the margin of safety of Unit 2.iv. Summary In order to issue a finding of no significant hazards considerations, the NRC Staff bears the burden of showing that the hazards considerations raised by Friends of the Earth's experts in these comments and by the ASLB's recent decision in the CAL proceeding are insignificant.

The Staff cannot make that showing, and consequently the proposed finding must be withdrawn and a hearing on the proposed license amendment held by an ASLB before the amendment may be approved by the NRC.c. National Environmental Policy Act The proposed license amendment should not be considered prior to a public hearing because the proposal presents a significant hazards consideration.

The National Environmental Policy Act of 1969 (NEPA), 42 U.S.C. § 4321 et seq., requires NRC Staff in such circumstances to at least prepare an Environmental Assessment (EA), which the Staff has not yet done.NEPA requires federal agencies such as the NRC to examine and report on the environmental consequences of their actions. NEPA is an "essentially procedural" statute intended to ensure "fully informed and well considered" decisionmaking.

7 5 Under NEPA, each 73 Hopenfeld Deci. at p. 11.74 Hopenfeld Decl. at p. 1 1-14; 20, Figure 7.75 Vermont Yankee Nuclear Power Corp. v. NRDC, 435 U.S. 519, 558 (1978).29 federal agency must prepare an Environmental Impact Statement

("EIS") before taking a "major Federal action[] significantly affecting the quality of the human environment." 7 6 An agency can avoid preparing an EIS, however, if it conducts an Environmental Assessment

("EA") and makes a Finding of No Significant Impact ("FONSI").

7 7 Specifically, no EIS is required if the agency conducts an EA and issues a FONSI sufficiently explaining why 78 the proposed action will not have a significant environmental impact. However, in deciding whether to prepare an EIS, the agency must 1) "accurately identif[y]

the relevant environmental concern," 2) take a "hard look at the problem in preparing its EA," 3) make a "convincing case for its finding of no significant impact," and 4) show that even if a significant impact will occur,"changes or safeguards in the project sufficiently reduce the impact to a minimum."'

7 9 An agency's decision not to prepare an EIS must-be set aside if it is "arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law." 8 0 The Federal Register notice is silent as to the application of NEPA to this case. One can only conclude that the Staff is relying on the categorical exemption from the procedural requirements of the NEPA, as described in NRC's regulations at 10 C.F.R. § 51.22(c)(9), available when the Staff makes a finding of no significant hazards consideration.

However, as FoE and NRDC demonstrate in these comments, the Staff cannot make such a finding in this instance.At the very least, an EA and subsequent FONSI must be completed because the proposed amendment would allow steam generators with a severe and dangerous level of wear to operate 76 42 U.S.C. § 4332(2)(C).

77 See Sierra Club v. Dep't of Transp., 753 F.2d 120, 127 (D.C. Cir. 1985); see also Theodore Roosevelt Conservation P'ship v. Salazar, 616 F.3d 497, 503-04 (D.C. Cir. 2010) (explaining NEPA procedures).

78 Dept. of Transportation

v. Public Citizen, 541 U.S. 752, 757-58 (2004).79 Taxpayers of A.!ichigan Against Casinos v. Norton, 433 F.3d 852, 861 (D.C. Cir. 2006) (internal quotation omitted).80 Public Citizen, 541 U.S. at 763 (quoting 5 U.S.C. § 706(2)(A)).

30 without repair. Since the leak of radioactive steam in January 2012 resulting from rapid wear in the steam generator tubes, the licensee has proposed no actions to prevent the conditions that caused the leak. The proposed license amendment therefore poses great potential risk to the environment, as shown by the analyses of FoE's experts and the recent ASLB decision, and thus requires the NRC to follow the procedures under NEPA to address that risk.IV. CONCLUSION For the foregoing reasons, the Staff's proposed finding of no significant hazards consideration should be withdrawn and the significant hazards consideration instead referred to an ASLB, with an attendant public adjudicatory hearing held prior to a decision on SCE's proposed license amendment.

As the ASLB recently held with respect to San Onofre Unit 2: We conclude that until the tube degradation mechanism is fully understood, until reasonable assurance of safe operation of the replacement steam generators is demonstrated, and until there has been a rigorous NRC Staff review appropriate for a licensing action, the operation of Unit 2 would be outside the scope of its operating license because the replacement steam generator design must be considered to be inconsistent with the steam generator design specifications assumed in the FSAR and supporting analysis.81 There is simply no basis for a no significant hazards consideration determination in the case of the proposed license amendment for San Onofre Unit 2.Respectfully submitted,/Signed (electronically) by Richard Ayres/Richard Ayres Jessica Olson Kristin Gladd Counsel for Friends of the Earth Ayres Law Group 1707 L St, N.W., Suite 850 Washington, D.C. 20036 Telephone:

(202) 452-9300 E-mail: ayresr@ayreslawgroup.com 81 ASLB Order at p. 32 (emphasis supplied).

31

/Signed (electronically) by Geoffrey H. Fettus/Geoffrey H. Fettus Counsel for NRDC Natural Resources Defense Council 1152 1 5 th St. N.W. Suite 300 Washington, D.C. 20005 Telephone:

(202) 289-2371 E-mail: gfettus@nrdc.org Dated in Washington, D.C.this 1 6 th day of May 2013 Attachments

1. Declaration of Dr. Joram Hoppenfeld

2. Declaration of John Large 3. Declaration of Dr. Victor Gilinksy 4. Declaration of Arnold Gundersen, in Support of the June 18, 2012 Petition to Intervene by Friends of the Earth Regarding the Ongoing Failure of the Steam Generators at the San Onofre Nuclear Generating Station 5. MHII Root Cause Analysis and Supplemental Technical Evaluation Report (Selected Excerpts)6. Southern California Edison Co. (San Onofre Nuclear Generating Station, Units 2 and 3), LBP-13-07 (May 13, 2013)32 ATTACHMENT 1 Declaration of Dr. Joram Hopenfeld UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE NRC STAFF In the Matter of )))SOUTHERN CALIFORNIA EDISON CO. ))(San Onofre Nuclear Generating Station, )Units 2 and 3) ))Docket ID NRC-2013-0070 May 16, 2013 DECLARATION OF DR. JORAM HOPENFELD I CONTENTS Qualifications of Dr. Hopenfeld

-3 Summary -4 1. No Hazards Change considerations

-6 a. Question I b. Question 2 c. Question 3 Introduction

-NO HAZARDS CHANGE CONSIDERATIONS

-10CFR 50.92 -6 2. APPENDIX A -FATIGUE ANALYSIS -II Part 1.a. Stress Concentration

b. Loss of Wall Thickness c. Surface Finish d. Correction of MHI stress Part 2.Rebuttal of SCE/MHI Fatigue Statements

3. APPENDIX B -Discussion of Accident Scenarios

-25 A. SGTR -stuck open Relief Valve B. SGTR -initiated by Isolation Valve closure C. SGTR -initiated by seismic events D. Station Blackout E. MSLB 4. REFERENCES

-32 2 Qualification of Dr. Hopenfeld to Assess the Southern California Edison Response to 10 CFR 50.92 While employed by the Nuclear Regulatory Commission, NRC, Dr. Hopenfeld's research included a focus on steam generator tube degradation.

Consequently the NRC launched a Steam Generator Action Plan, SGAP, to address the various safety issues raised by Hopenfeld in a series of documents from 1992, known as the DPO and GSI 163. On September 2007 the NRC issued a new performance technical requirement specifications, TS, to reduce the risk from accident induced and normal operations tube ruptures.

This action essentially closed the DPO and GSI 163, as discussed at the May 7, 2009 Advisory Committee on Reactor Safeguards (ACRS) meeting. During the fifteen year review Dr.Hopenfeld made numerous presentations to the Atomic Safety Licensing Board (ASLB)and the ACRS on various steam generator related issues.* Steam Generator Degradation Monitoring.

• Erosion/Corrosion, FAC (relevant to the feed ring failure at SONGS (1992)* Safety Consequences of Steam Generator Tube Failures,* Iodine transport and Spiking,* POD of crack detection by Eddy Current,* Metal Fatigue from Thermal Transients (PWRs and BWRS)* Vibrations in BWR dryers.* Managed a major International program, MB-2 (US, UK, EPRI ) on steam generator performance during design basis accidents.

• Conducted sensitivity studies with the RELAP computer code on operator's ability to keep the SG inventory at mid level as a function of the number ruptured tubes.* Conducted studies on jet erosion as a potential for leakage increase during SG accidents.

• Conducted numerical studies on SG tube ruptures during severe accidents* Designed, fabricated and field-tested instrumentation for a very harsh vibration environment.

• Holds several patents on methods for monitoring wall thinning* Managed the development of acoustic leak detection system for LMFBR steam generators.

• Testified before Congressman DeFazio regarding steam generator degradation at the Trojan Nuclear reactor.3

SUMMARY

Southern California Edison (SCE) requested the approval of the Nuclear Regulatory Commission (NRC) for a change in Technical Specification (TS) 5.5.2.1 .bl to allow operation of San Onofre reactor Unit 2 during Cycle 17 at power levels up to 70% of Rated Thermal Power. To obtain approval, SCE claimed that it has demonstrated that the change would not involve any significant hazards, as required by IOCFR 50.92. The assessment in this declaration for Friends of the Earth demonstrates that that SCE has in fact not met the standards prescribed in I OCFR 50.92 which require a "no" answer to three questions.

The NRC IOCFR 50.92 states, 1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

3. Does the proposed change involve a significant reduction in the margin of safety?SCE's justification for providing the three negative answers is based solely on a brief fatigue assessment by the replacement steam generator manufacture Mitsubishi Heavy Industries (MHI Ref 1), which showed that the vibration-produced stresses were too low to cause fatigue failures.

SCE endorsed these findings despite the fact that MHI, (a)relied on data which was inconsistent with the visual observations of tube degradation and (b) disregarded American Society of Mechanical Engineers (ASME) code requirement to account for variation in code data and field conditions.

Equally important is the fact that in their effort in trying to justify the restart of San Onofre reactor Unit 2 there is no indication that SCE utilized the large amount of data generated by the "lessons learned" from the vibration fatigue tube failures at North Anna (1987), Mihama (1991)and Indian Point (2001).SCE answered "no" to the three 50.92 questions but only by disregarding fatigue damage to existing tubes and industry guidelines of how to evaluate tube integrity under multiple loads. The SCE analysis is based on showing that San Onofre reactor Unit 2 will operate safety because tube rupture is only controlled by tube wall thickness and the tube differential pressure, AP. This declaration shows that the controlling factors of tube rupture are more complex when a significant fraction of tube fatigue life has already been incurred and in addition to AP loads the tube is subjected to cyclic loads from flow-induced vibration.

Under these conditions, the determination of the margin of safety, solely on the basis of AP, is invalid and significantly non-conservative.

4 The assessment herein includes a discussion of potential radiation release from tube ruptures for five design basis accidents and one severe accident.

Because of the unprecedented and unforeseen damage to 1806 tubes during one cycle of operation, there is no data that one can use to reliably calculate the consequences of tube failure risks in such accidents.

This declaration demonstrates the high degree of technical uncertainties and lack of robustness in the "no" answers provided by SCE.The analysis in this declaration indicates that a Main Steam Line Break (MSLB) would result in-the most significant large early radiation release (LERF) because of the potential for many tubes to rupture and the high probability for human errors. Events which occur more frequently than MSLB exposing the tubes to relatively lower stress such as unplanned valve opening or closing or earthquakes have a lower probability for human error but are more difficult to analyze. Considerable effort would be required to ensure that the safety risk from such events is significantly lower than the safety risk from MSLBs.If as few as 1% of the degraded tubes in one steam generator, operating for six months, fail during an MSLB, the result is an LERF of 5x10-5 /yr which exceeds the Commission safety goals by a factor of 5.My assessment leads me to the conclusion that the proposed SCE TS change: ,& Represents a new accident with high risk significance

+/- Would create a new accident previously not evaluated and, , Would involve a significant reduction in the margin of safety.Therefore my answer to each of the three questions is yes.5 NO HAZARD CONSIDERATIONS

-10 CFR 50.92 Introduction A determination of No Significant Hazard must provide assurance that the San Onofre Nuclear Generating Station (SONGS) licensing base (CLB) will be maintained between Steam Generator (SG) inspections during future operation over 18 months so-called cycle 17. However, SCE has failed to demonstrate that the modification of SONGS Technical Specification (TS) which will allow a change from 100% power to 70% power represents an added assurance of the functionality and integrity of SG tubes. As discussed below such a change entails a significant reduction in the margin of safety.SCE answers no to all three 10 CFR 50.92 questions.

Their answers are based on the presumption that a change in power level can be discussed without giving any considerations to the physical conditions of the tubes before and after the change. SCE is mistaken in believing that tube integrity is a function of the power level alone and independent of the actual degree of tube degradation.

As discussed in Appendix A, large numbers of both plugged and unplugged tubes have exceeded their allowable fatigue life.This loss of tube integrity significantly affects primary to secondary leakage during design basis accidents and consequently increases the Large Early Release Frequency (LERF).SCE disregarded the affects of fatigue damage on tube degradation by claiming that the stresses were too low to cause tube fatigue. The analysis in this declaration leads to a different conclusion:

the vibration during cycle 16 resulted in sufficiently large cyclic stresses to cause fatigue damage to a significant number of tubes.Another important factor that must be considered in comparing the change of operating Unit 2 from 100% to 70% power is the unknown behaviour of the tubes at the lower power level. Even if vibrations due to fluid elastic instability were significantly reduced at the beginning of the cycle it is uncertain that this will remain so through the five months of operations.

Tubes with low natural frequencies may continue to wear due to fluid turbulence.

The resultant increase in clearance between the AVB support and the tube could lead to an increase in the intensity of the impacts between these two components.

This could lead to an abrupt failure even for those tubes whose fatigue life has not been used up during cycle 16, i.e their cumulative usage factor was less than one (CUF < 1).It is for these reasons that my answers are in the affirmative to all three 1OCFR 50.92 questions as discussed below.2. Answers to 1OCFR 50.92 Questions 6

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response:

Yes In comparing the change proposed by SCE, one must compare the change in San Onofre reactor Unit 2 at the beginning of cycle 16 to its proposed cycle 17 operations.

Consideration must be given to both power levels and tile degree of tube degradation, not just the power level as SCE have done. The operation of Unit 2 which entered service in in 2011 (cycle 16) at 100% power must be compared to how it would operate if permitted to restart in cycle 17 at 70% power level with a large number of defective tubes.The proposed change would significantly affect the probability of accident initiators because a certain percentage of steam generator tubes have used up their entire or a large fraction of their allowable fatigue life during cycle 16. For this reason the operation of San Onofre reactor Unit 2 during cycle 17 will fall outside the bounds of the accidents that were evaluated in the existing SCE Updated Final Safety Analysis Report (UFSAR).While the proposed change does not affect the design of SG or its method of operation, it does increase adversely the consequences of Design Basis Accidents (DBAs), i.e., main steam line break (MSLB) and tube rupture (SGTR). The SONGS Technical Specifications, TS 5.5.2.11, require that SONGS provide the NRC during every outage an assessment, CM, with respect to tube structural integrity, accident induced leakage, and operational leakage. As discussed by SCE UFSAR Sections 3.2 and 5.2.9, the entire CM assessment is based on "operating experience with SG tube degradation mechanism that result in tube leakage".

Likewise, SCE's determination of Core Damage Frequencies (CDF) is also based on leakage methodology which was derived from tubes that were degraded by stress corrosion cracking.

As discussed below, these results are not applicable to the 70% power operation with fatigued tubes. A comparison of operation at 70% power with fatigued damaged tubes versus operation at 100% power with undamaged tube must consider fatigue damage. SCE is wrong in claiming that the change from 100% power to 70% only changes the power level without any potential adverse safety consequences.

In discussing its "no" response to 10CFR 50.92 question 1, SCE did not explain why industry guidance on how to ensure tube integrity was not included in its submission.

These guidelines, issued by the Technical Specification Task Force, TSTF 449, specify that primary/secondary pressure differential AP loads alone are not sufficient to ensure integrity when other loads are also present. Specifically,"additional loading conditions associated with the design basis accident or combination of accidents in accordance with the design and licensing base shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse." 7 In some accidents cyclic loads may be controlling tube rupture in others, AP loads may act in tandem depending on the degree to which the tube wall thickness was already reduced by wear. Therefore, the mean stress level of any tube must be considered together with superimposed cyclic stresses.

SCE treated cyclic loads as if they have never occurred at San Onofre reactor Unit 2.As discussed in Appendix A, the predominant degradation mechanism at San Onofre reactor Unit 2 during cycle 16 for an unquantified fraction of the tubes is fretting fatigue.Fretting fatigue would result in a larger and faster leakage rate from a tube rupture than the leakage from a tube that was degraded by cracks due to Stress Corrosion Cracking, (SCC) or wall thinning by erosion alone. The existing leakage performance criteria are based on the latter.For those tubes in San Onofre reactor Unit 2 where the Stability Ratio (SR) was relatively low, (less than 0.4,) tube rupture is expected to be controlled by burst pressure.

In this case present performance criteria are applicable.

During operational (non-Loss-Coolant Accidents, LOCAs) and accident transients (LOCAs) cracked tube can be expected to result in a slow progressing leakage, in contrast when fretting fatigue is the cause of tube failure the leakage would occur suddenly and proceed rapidly to its maximum as happened at North Anna (Ref 2).To evaluate the effect of existing defects in San Onofre reactor Unit 2 on the consequences of a given accident one must identify first the fraction of the tubes that were damaged predominantly by fatigue and the fraction of tubes that were damaged by wall thinning alone. This must take into account that high cycle vibration fatigue does not lend itself to in-service detection.

Tube fatigue life is almost entirely spent in the incubation period and once the crack is formed failure would follow quickly.To comply with industry guidelines TST- 449, Rev 4, degradation of each tube must be assessed simultaneously in terms of both its existing fretting damage (wall thinning) and its local SR. The number of tubes which are susceptible to rupture by fatigue during a given accident scenario must be known if one is required to predict accident consequences.

Until this is done the present pressure based burst performance criteria cannot be used as a reliable indicator of risk. As a result, it must be conservatively concluded that allowing San Onofre reactor Unit 2 to operate at any power level would significantly increase the consequences of the accidents, which were evaluated by SCE and were described in the UFSAR.2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response:

Yes 8 The proposed change will introduce significant changes to postulated accidents resulting from tube degradation.

Appendix B discusses how primary to secondary leakage from fatigue-ruptured tubes differs from leakage that resulted from tubes that failed from excessive loads. Since existing safety studies are based solely on changes in AP this represents a new type of accident.The analysis in Appendix A demonstrates that some tubes will enter service in Cycle 17 with no fatigue life left. The leakage from these tubes will not be affected by changes in AP. The rupture of these tubes would depend on the intensity of cyclic stresses that varies with the stability ratio, SR. The SR and the AP are independent variables:

different driving forces govern their respective changes during a given accident.

For this reason the operation of San Onofre reactor Unit 2 with fatigued tubes creates a new and different kind of an accident.3. Does the proposed change involve a significant reduction in the margin of safety?Yes Because many tubes have exhausted their fatigue life the proposed change would not be in compliance with the ASME code as required by 10 C.F.R. 50.55a, Codes and Standards.

Since the SG tubes form a barrier between the radioactive fission products in the primary water and the secondary system, loss of fatigue life reduces the safety function of the SG.Initial assessment in Appendix B suggests that the MSLB accident would be the most damaging accident from the standpoint of causing the largest primary/secondary leakage from fatigued tubes in comparison to more frequently accidents with a lesser damage potential.

Based on a probability of E-4/yr (one in every 10,000 years) that a steam a line break would occur outside containment, the Large Early Release Frequency, LERF of radiation escaping to the environment due to the reactor core becoming exposed is also E-4 /year because, as discussed in Appendix B, no credit can be given to the operators that they would terminate the accident before depleting the reactor water storage tank, RWST. This represents an LERF of 5 E-5 /yr (one in every 20,000 years) for six months operation.

This is an increase by a factor of 5 over NRC goals as considered in NRC Probability Risk Assessments.(Ref 11)Assuming that the AP will not be large enough to rupture tubes, and no leakage from fatigued tubes, SCE calculated a change in LERF of 4E-6/yr (NRC AIT Report July 18 2012)9 SCE results are not realistic and therefore the answer to question 3 must be yes.Conclusions SCE analysis is based on the assumption that any increase of radioactive primary water during hypothetical accidents would be controlled by burst pressure, AP. This assumption is flawed because some tubes at San Onofre reactor Unit 2 have already used up their fatigue life. In this case leakage increase would be controlled by the intensity of vibration-induced stresses, not AP. The large and sudden f~ttigue tube ruptures at North Anna. Mihama and Indian Point occurred when the AP was essentially constant but tubes failed because they exhausted their fatigue life due to intense vibration similar to those that occurred at SONGS.In spite of its 170,000 inspections to understand the tube wear problem, SCE has not even mentioned the possibility that a fraction of the tubes had sustained fatigue damage. Nor did SCE discuss the uncertainties and errors in the NMI fatigue analysis and how they could affect their "no" answers.The assessment in this report does not support SCE's position that operation of San Onofre reactor Unit 2 for five months at 70% power will not affect safety. It is shown, that SCE conclusions are not founded on science and equally important are not conservati ve.Operation of San Onofre reactor Unit 2 even for one month at any power level would present a significant safety risk.I Joram Hopenfeld declare, under penalty of pejury, that the foregoing infomation and facts are true and correct to the best of my knowledge and belief, and that the opinions expressed herein are based on my independent and best professional and personal judgment.Joram Hopenfeld g 4 c 10 APPENDIX A- FATIGUE ANALYSIS Introduction When an SG tube is in contact with its support either the Anti Vibration Bar (AVB) or the plate (TSP), the two contacting surfaces are damaged by fretting.

As discussed in detail by the Electric Power Research Institute (EPRI Ref 4) and Volchock (Ref 5)fretting damage occurs due to a combination of the sliding motion between the surfaces and the impacts when an external cyclic load is superimposed on the sliding motion. The sliding motion alone produces fretting wear while the cyclic impact produces fretting fatigue, the synergy of the two significantly reduces fatigue life and enhances wear. This synergy is especially important when wear predictions are mostly based on empirical parameters from laboratory tests. Even though the EPRI report indicates that wear and fatigue are controlled by different mechanisms and their respective equations are different, SCE, in calculating tube wall thinning, applied equations for wear without considering the differences between wear fatigue and fretting wear. Numerous considerations must be given in extrapolating lab data on fretting wear to SONGS conditions.

Since SCE did not perform any similitude studies on wear rates, SCE projection of tube wear for cycle 17 are unreliable.

This appendix was divided into two parts, the first part shows why SCE analysis lead them to believe that the tubes at SONGS did not suffer fatigue damage. The second part, Part 2, is a rebuttal to SCE and MHI's contention that tube fatigue damage during cycle 16 can be ignored.PART 1 -MHI ANALYSIS.As describe in Attachment 4 MHI Document L5-04GA564, MHI used a finite element model (FE), to calculate that the tubes were subjected to a stress of 4.2 Ksi (P 16-2), which is smaller than the endurance limit stress of 13.6 ksi (P 16-2). Consequently, MHI concluded that the tubes would not fail from fatigue even if they were subjected to infinite number of stress cycles, (P 16-13).The MHI results are based on two erroneous assumptions.

When these assumptions are corrected the opposite conclusion is reached. The issue is not with the FE, rather it is how the FE results were adjusted to account for high stresses at surface discontinuities.

a. Stress Concentration It is a well-established fact that geometrical discontinuities such as sharp corners introduce high local stresses, which act as a site for crack initiation.

A common engineering practice is to fillet or chamfer sharp corners to reduce stress concentrations and increase fatigue life. Any conceivable discontinuity has been considered and the 11 results have been published in numerous publications to guide designers in selecting the particular fillet for a given application.

MHI used a design chart, Figure 2, for a tube in pure tension to determine the stress concentration factor Kt. Assuming an undisclosed value for the fillet radius and the value of the parameter (t) MHI concluded that Kt was less than 1.5 when t/r =1.33. These numbers indicate that MHI used a value oft/h that exceed unity. Had MHI assumed smaller values for t/h, and a smaller radius, Kt would have exceeded 1.5 because Kt is sensitive to the assumed geometry of the fillet. MHI selected an arbitrary geometry, which is not valid, and for this reason they only obtained an unrealistically low value for Kt.Fig 2 is intended for applications when one is trying to minimize stress concentration.

Visual examination of the contact between the AVB plates and the tubes do not suggest that the relative motion resulted in geometry with minimum stress concentration.

On the contrary, as shown in Figures 3 and 4, the method in which the AVB interacted with the tubes allows for a formation of sharp corners at the intersection of the plate with the tube.MHI's own discussion is not consistent with their application of Chart 5 in Fig. 2. The observation that the "tube and the AVB are worn into each other" and the fact that the AVB plate has sharp comers suggest that Chart 3.5 does not apply to observed wear pattern.The model shown in Figure 5, represents more closely the wall thinned geometry than the one used by MHI in selecting the stress concentration factor. Since Figure 2 does not provide data for fillets with very small radius, it is necessary to consider a similar geometry giving Kt values for small radii. In Figure 6 (a special case of Fig 2, di = 0), Kt is plotted for very small radiuses for bending -Kt values in tension are similar).Using a reported wear of 35%TW. Kt is calculated as follows: t = (I -%TW) T = (1-0.35) 0.043 = 0.028in d/D = D/D-2t = 0.750 /0.750 -0.056 = 0.750/0.694

= 1.08 Kt = 5 when r= 0.0014 for Kt =5, r = 0.002 (0 .694) =0.00 14 (Theoretically the chamfer radius of a sharp corner is zero, and therefore Kt will tend to be very large for a finite but small radius of 0.00 15 which is close to describing a sharp comer, Kt exceeds 5.)b. Loss of Wall Thickness (wall thinning)The effective wall thickness Teff of the geometry in Figure 4 can be expressed as: 12 Teff = t x (20 )/360 + T x (360 -20)360 0 = 2 Cos -I (d/2 +t )/(d/2 +T)For a 35% and 70 % tube wear, 0 equals 44.6 and 44.1 degrees respectively, the corresponding effective tube thickness equals 0.0360 and 0.0345 and respectively.

c. Surface Finish Fatigue life, and therefore the endurance limit, is strongly affected by surface finish.Figure 9 show that fatigue life can be considerably reduced by abrasions.

The data (Edison Attachment 6- Appendix D pages 130 -131) indicates that the fretted tube surfaces do not maintain their original surface finish instead they are severely scarred. Such scars are sites for the formation of micro cracks.Bounding calculations would require that the ASME design stress used by MHI (13.6 ksi)be lowered to account for surface finish. It is not clear however that the introduction of both a stress concentration and surface finish correction simultaneously would not be overly conservative.

Since no data was found in the literature where both a sharp corner and adjacent rough surface, a surface finish correction was not included in the present assessment.

In that sense, the application of a concentration factor of 5 together with curve C of Figure 1 may not be conservative.

d. Corrected MHI stress.Corrected stress = MHI stress multiplied by concentration correction factor K, multiplied by thickness correction factor Tc, = 4.2Kx(Tc)K = actual stress concentration factor / MHI concentration factor = 5/1.5 = 3.33 l/Tc = Decrease in wall thickness

/original wall thickness

= 0.036/0.043 for beginning of cycle 0.0345/0.043 at the end of cycle assuming the same wear rate.Tc =1.19to 1.25 Increase in stress= 4.2x 3.33 x 1.19 to 4.2x 3.33 x 1.25 = 16.7 to 17.5 Actual increase over the endurance limit = 16.7/13.6 to 17.5/13.6

= 1.22 to 1.29 e. Conclusions 13 The impact of correcting the MHI calculations is demonstrated in Figure 7: it is self-explanatory.

It should be noted that the stresses that ruptured the tubes at Mihama and North Anna (Ref 5), about 7.4 to 8.7ksi and 4 to 9ksi respectively was within the error band indicated in the Figure. The ruptures at Mihama and North Anna occurred due to support plate/ tube interaction not due to AVB/tube interaction.

14 APPENDIX A GRAPHS/CHARTS

1. Purpose The purpose of this document is to show that the stress of the tube in SONGS RSG due to in-plane vibration is under the fatigue limit.2. Conclusions The stress on the tube due to in-plane vibration is 4.2ksi and is under fatigue limit (13.6ksi).

The tube has structural integrity for the stress due -o in-plane vibration from the view point of fatigue evaluation.

3, Assumptions and Open Items The tube deforms in-plane until contacting with the outer next tube in Row direction due to in-plane vibration.

The stre-ss due to in-plane vibration is high cycle fatigue 4. Acceptance Criteria The fatigue limit is 13.6ksi according to the following design fatigue curve.Fit, 1-91.2 I'MQ sITcrICe Mi, MUMSIO I -A.MMNDCE~S i 74 44 14~ t'2 -:: Iz 4 _t 0 I of Nrnt.er ce coih, PN Figure 4-1 Design Fatigue Curve for Tube I-Figure-I Fatigue data used by MHI to determine tube fatigue life. The cycle independent line represents the endurance limit, MHl used an endurance limit of 13.6ksi. Attachment 4, P 16-2. data for smooth specimen.15 CHARTS 157 1.4-IT -- 1 2 3 4 t/r Chart 3-35 Strcs c.' onceniIraion

' A', for a itt Iens.ion witih i let (Lc mnd Ades. 1956;E^srU 19"4 I).Figure 2 -Stress concentration factors used by MHI for calculating maximum tube stress, Attachment 4 P.16-2. Source: W.D. Pilkey, Peterson's Stress Concentrations Factors, John Wiley and Sons 1997.16 3.2 Wear Pattern-2 (Local Wear on Tube Surface)Characteristics (D Local wear occurs on the tube but the wear surface is not exposed (cannot be seen)Z) Unable to determine if wear occurs on tube or AVB or bothUnable to determine the direction of motion or vibration (4) An extreme interpretation Is that both tube and AVB are worn into each other.aV8 A"'B unable to see the metallc sheen In extreme case, both the tu[ due to narrow wear area & AVB wear into each other (a) Case 1 (b) Case 2 FIg-2 Wear Pattern 2 Fig. 3 -Wear due to AVB/tube Interaction

-Attachment

4. It should be noted that both the impact and the sliding motions play a part in the tube/AVB interaction.

These factors reduce tube strength because of material loss but also because of loss of fatigue strength.17 Non-proprietary Version I) (P.1 0-20)DocumeXL5-04GA564(9)

V R Fig. 6-4 Wear shape of tube at the contact point with AVB Figure 4 -MHI description of wear shape at tube/ AVB contact point. Attachment

4. P. 10-20 T =origina I wall thila1es ttr=rremainig w.all thiclkness d = hiier d~a r-1 Figure 5 -Schematic for determining a stress concentration factor Kt and reduced wall thickness ofa tube due to double sided wear to a tlhickness (t) over an arc defined by 0 18 166 so 4 5 SFOhc'It0m rILLurS 35 30 25 ,0 11 1 5 2 G 215 C aV( 3.w 11 1i .I :I* ,,,III- a K. hý ij, Ib nj n ."f I~ kfýP tar I* k, rtcU tar C Iý s xtt i 171.' h r hm i enc,,; tor s utplemewn Chamrt 3 ill Figure 6 -Stress concentration used in the present analysis.

W.D. Pilkey, Peterson's Stress Concentrations Factors, John Wiley and Sons 1997. (Similar Kt values in tension -Peterson's Chart 3.4, and for internally pressurized vessel Chart 3.6 for a small radius)19 COMPARING THE MHI CALCULATED STRESS WITH THE STRESS CALCULATED IN THE CPUC REPORT Stress U1 NSAFE TO OPERATE (ksi) CORRECTED STRESS (CPUC Repaor)17.5 13.6 ASME Endurance Linfit -UNCERTAINTY¢ MHI CALCULATED BANJ 4.2 STRESS SAFE TO OPERATE _.Number of vibration cycles to failure Figure 7 -Effect on potential ratigue damage by correcting the MHI calculation PART 2 -Rebuttal to SCE/MHI Assessment of Hopenfeld Fatigue Calculations Appendix A was attached to Dr. Hopenfeld Testimony to the CPUC and has been in the public domain since March 29, 2013. In reply to questions from ABC Channel 10 in San Diego, SCE and MHI responded on April 2 5 th as follows: SCE"Hopenfeld's fatigue analysis concerning in-plane tube vibration is significantly flawed in that it applies an unreasonably high stress concentration factor based on solid body geometry rather than the more realistic stress concentration factors for a cylindrical geometry applicable to the SONGS steam generator tubes." MHI MHI did analyze the potential for fatigue failure of the RSG tubes tinder operating conditions and determined that fatigue was not a credible tube failure mechanism because the stresses sustained by the tubes due to in-plane vibration are well below the stresses that would cause fatigue failure. The analysis that supports this conclusion is contained in Appendix 16 to the "Tube wear of Unit-3 RSG -Technical Evaluation Report." It should be noted that the technical reviews and analysis, both by the NRC and industry experts, have not mentioned fatigue failure of the tubing." 20 Since SCE approved MHI fatigue analysis as specified in the original SCE design document, the reply to the above separate statements will be consolidated.

REPLY SCE/MHI calculations are based on ASME data that has not been corrected for the conditions that represent the tube surface following fretting after 18 months of operations.

The S-N fatigue data was obtained by testing a number of polished solid specimens and the lines represent mean stress limits. It is a common practice of a user of the ASME code to make conservative correction when that data is applied to field conditions which are drastically different than those in the code. When applying the data to tube surfaces that have experienced fretting, Curve C, which was used by MHI, must be lowered to reflect the increase in surface roughness due to fretting.

As shown in Figure 9 a change of surface roughness from 0.05 microns to 2.67 microns reduces the fatigue life by a factor of 8.8.In their report (Appendix 16), SCE/MHI stated that because the AVB and the tubes are imbedded in each other the condition of the surface cannot be seen. Given that the respective surfaces have been sliding and impacting each other it is difficult to imagine how SCE/MHI concluded that such motion would produce polished surfaces.

One must conclude that SCE/MHI disregarded the intent of the ASME code by not adjusting the Curve C stress to account for surface roughness.

Comparison of the actual ASME curve with those that were reproduced by SCE/MHI shows that SCE/MHI incorrectly labeled the data to indicate that it was generated for tubes and was limited to operation below 800 F. The data would not be applicable to severe accidents, which were discussed above. It is not clear why SCE/MHI mislabeled the ASME figure to indicate that it was generated for tubes.21 ORNL-OWJG 4-6108 ETD 0 W-j 24 A R CURVE A- I I III 1 6---...k, li 18 CURVECB I I, 10d To 9 N, NUMBER OF CYCLES 1010 NOTE: E -28.3 X 10 osi Fig. I. ASKE Code Sect. III high-cycle design fatigue curves for austenitic steels, nickel-chromium-iron alloy, nickel-iron-chromium alloy, and nickel-copper alloy for temperatures not exceeding 800*F (from Ref.22).Figure 8 -Showing the same ASME data that was shown in Figure 1 but with the original correct caption. This the data was not for SONGS steam generator tubes.22 Table 12-3 Fatigue life of SAE 3130 steel spt=cimnens tested under completely reversed stress at 655 MIPat Median fatigue life, Type of finish Surface roughness, ym cycle's Lathe-formed 2.67 24,000 Partly hand-polished 0.15 91,000 Hand-polished 0.13 137,000 Ground 0.18 217,000 Ground and polished 0.05 234.000 SuDerfini-shed 0.1S 212,000 P. G. Fluck, .-l; .Soc. Tesv. Maarer. Proc.. vol. 51, pp. 584-592, 1951.Figure 9- Effect of surface roughness on Fatigue life 2. Incorrect selection of the Stress Intensity Factor The ASME curves are used only to calculate average stresses only. At least 100 years of experience has been accumulated to show that sharp surface discontinuities introduce high local stress concentrations where crack are initiated.

The ASME code requires that the average stress of a component be multiplied by the appropriate stress intensity factor.Because of the importance of local stresses on fatigue life, hundreds publication are available for smooth discontinuities and thereby reducing local stress. The concept 23 SCE/MHI Field observations Sharp corners = poor fatigue strength Decreasing Failure probability N./p IIi'~A'/~ W~3i fliP cacti )ihQr i'~~NJ /sharp notch smooth notch better notch much better notch Figure 3 -IGNORING FIELD DATA SCE/MHI SELECTED GEOMETRY WITH GOOD FATIGUE LIFE FIGURE 10- This has been duplicated to show why SCE /MHI concluded that the "vibration are well below the stresses that would cause fatigue failure" as illustrated in Figure 7.Sharp corners lead to a poor fatigue strength while smooth comers or a gradual transition reduces stress concentrations thereby improving fatigue strength.

The most common source for stress concentration factors are the Peterson's charts which are available for numerous different geometries.

As shown in Fig. 2of Appendix A, SCE/MHI had to select a fillet radius in order to calculate the stress concentration factor. If one selects the radius arbitrarily, you can get any number he wishes. SCE/MHI used radius that they have redacted, however an examination of their calculated stress concentration factor,(K t) clearly indicates that they selected a relatively a smooth fillet (large radius) and that SCE/MHI did not select a sharp notch. Since SCE/ MHI stated that the interface between the AVB and the tube is not visible, and their interpretation of the contact surface geometry shows a 90 degree corner, it is impossible to conceive how could they justify using a large radius fillet. The Peterson charts were designed to minimize stress concentrations, when the AVBs impact the tubes they do not follow fracture mechanics guidance to avoid formation of sharp notches.Figure 10 above illustrates schematically how fatigue life is improved as the notch radius increases.

In the stress calculation, Par 1, 1 have selected a sharp notch because this is consistent with the observation that the AVB and the tube imbedded in each other through impacts.24 Fatigue damage by impact loads would lead to a brittle fracture because such loads do not mitigate slip. Selection of sharp notch geometry is appropriate because such notches can lead to a brittle fracture.

In contrast, a well-designed fillet would result in a ductile fracture.Another reason why it is incorrect to select an arbitrary fillet radius with smooth surface to calculate fatigue life is the synergy between surface roughness effects and cyclic loading effects. Such synergy leads to a significant reduction in fatigue life as has been clearly demonstrated in Reference

3. Therefore even if MHI had corrected their stress intensity factor (K t) of 1.5 to account for surface roughness (Fig 9) it still would leave a large uncertainty due to synergy. This only indicates that calculations which are solely based on a sharp notch (K t =5) may not be sufficiently conservative.

As a reality check on their fatigue model, one must wonder why SCI/MHI did not compare their calculated stress of 4.2ksi at San Onofre reactor Unit 2 with the stress (7.4-8.7 ksi and 4-10 ksi) that caused the rupture at Mihama and North Anna (Ref 6)respectively.

Such a comparison should be made for each affected tube on the basis of the local velocity, steam quality, tube stiffness, natural frequency, and temperature-gradients across the tube wall and A P. SCE/MHI should show that the differences in conditions at Mihama and North Anna vs. conditions in San Onofre reactor Unit 2 account for the fact that Mihama and North Anna tube ruptures occurred at somewhat a higher stress.The SCE/MHI statement that stress concentrations at sharp discontinuities depend on whether the component is a hollow or solid, appears to be a new discovery in fracture mechanics.

It is well established that stress concentration gradients at sharp notches decrease rapidly with the distance from the notch. In other words, the crack would be initiated at the tip of the discontinuity and is practically independent of the geometry further away. As the comment to Figure 6 indicate, examination of Peterson's charts clearly demonstrates this point.In light of the many unstated assumptions that SCE/MHI used in applying Figures 1 and 2 to the SONGS tubes, the statement that it is unrealistic to apply "stress concentration factor based on solid body geometry rather than the more realistic stress concentration factors for a cylindrical geometry applicable to the SONGS steam generator tubes." Is not appropriate.

I used the solid geometry for convenience only. Extrapolation of the tube data in Figure 2 to sharp comers (r=0) would have resulted in the same stress concentration factor.SCE/MHI appear to justify their position that fatigue failure would not occur at SONG by relying on the fact that the NRC did not raise this issue. In the light of the significant component failures in power plants from high cyclic fatigue due to thermal or hydraulic instabilities, it is puzzling that the NRC did not raise the fatigue issue. The suggestion that the fact that the NRC did not raise the fatigue issue is not a valid technical reason 25 that supports SCE/MHI fatigue analysis.

Nevertheless, ultimately it is SCE's responsibility to operate the plant safely. It is not the NRC's responsibility.

26 APPENDIX B FRETTING FATIGUE TUBE DAMAGE -NEW AND DIFFERENT FROM ANY ACCIDENT PREVIOUSLY EVALUATED AT SONGS 1. Introduction There are two main reasons why fretting fatigue introduces a new un-analyzed accident at SONGs. The massive fretting fatigue suffered by the SONGS steam generators is unique in the history of United States SG tube degradation.

Assessments of accidents, which could be induced by degraded SG tubes, were focused on the consequences of operations with tubes that were degraded by Stress Corrosion Cracking (SSC). With three exceptions, North Ana (1985), Mihama (1991) and IP B (2000) all other tube ruptures resulted from stress corrosion cracking and loose part wear as shown in Table 1 below.Fatigue failures at these three plants were limited to a single tube and unlike at SONGS the root cause was fairly well understood.

Given the fact that fatigue damage in the above three accidents was confined to one tube it is puzzling why SCE/MHI completely ignored the wide spread fatigue damage at SONGS. In comparison very extensive fatigue investigation was conducted in connection with the North Anna event, (Ref 6).Since SCE frequently quotes the existing performance criteria the understanding of these criteria is critical in assessing the SCE conclusion it would be appropriate to briefly review the basis for the present performance criteria.Since it became obvious in the late 1980s that steam generators would have to stay in service with Ssc cracks all efforts were focused on attempting to define the safety consequences of such operations.

Starting in 1991 with a series of documents that became known as Differing Professional Opinion (DPO), efforts were made to cope with various aspect of the problem. In particularly the DPO focused on improving the voltage based methodology of predicting accident leakage from eddy current voltage measurements.

27 tmý1t 0Bý I I rAO.-pw a--n&O.A 11 .25 2 u. nnom 11 SIfne~ &no ) t Sb. 06K og" GUU1 W76 ~ n:W ,dW oe i J.c. ~ U4.O An ., Pý So .Cd. 7 'JJOZFl.m66.

r10 I C1W21 335 Z 3S "m VVg an.W ratMr00T 7G n 4W'SO 20-0 OOtnd h=1 Lý- jriI1Z W0K%W1511~ GOI .- w ,rn~, F- b nhno. e.Z6 Lt ~ ,l.t Ial. 4 X~~~~~~n,~~~~~~~~,s~J&1 bmwg wt- nto. 4 6. n.dbiel X J ib ~ I 0 J4- A 2.0 hmt 3. 60 b; 1 0ia604 rr4 s'de2&,S l.iAi ' TOh5.7 637 3FOD Cic i1u 066en tra TCO 017' %U50 106c04. OL21.). H.2t1-Ccwo 6 0 n~u. 61k of aea nok W.- b-A-51 I 2&O ¶nm ____ __________

o4lg 9. Cd.IA.S SL'pcon. 60nrna 9S 60 5 knoX 6 aAW6 oaaa .5ni Al the klow nz.00 ~O6 000. 00.02:O26 V6.0aW. Wno 22~~r 69201 .-bC ok9 .HoR IB. Ca 1 00Co6,11fl6 060 15 inLA cm6 g1.0 Wn 2-50 no LM0 I SLn qO 01l, 113 I C?, b ýz9n CJ6r XýW mattCW.J144 r[" '*e.aý rss o "r-z" v v 4e F, -0 61 kw* L.. e-l r u- f, ' ; ? C41.G 5 W: ..U_ 000A09 [___ _ _ __ _ _ ___......_

___ __ __-... ... .... .___ __ -Table I -Tube Ruptures in US Plants Excluding Major Tube Leaks The DPO was resolved by the promulgation of new tube performance criteria in 2007.These criteria are strictly based on predicting the probability of tube rupture during various accidents and the related leakage from Bobbin voltage measurements.

Such predictions are not applicable when the mechanism of tube rupture is fretting fatigue.Voltage based methodology of leakage predictions does not bound fretting fatigue leakage because the latter results in an instantaneous circumferential tube rupture.The reason why the leakage from SCC cracks is fundamentally different than leakage from tubes that exceeded their allowable fatigue life can best be illustrated by considering the design basis MSLB. Thermal Hydraulic (T-H) analysis shows that the pressure differential AP across a tube initially increases slowly and therefore even if several tubes contained a very large number of cracks they would open slowly minimizing the primary to secondary leakage. It is only later during the event when the SG has been emptied and the emergency core cooling, ECCS kicks in that the AP starts increasing.

At this time however, its relative value is small. In contrast a rupture of a fretting fatigued tube does not depend on AP, the change in the sudden increase in stress intensity. (Increase in DP would-be important only if wall thinning due to fretting was reduced to below the burst thickness).

During the MSLB event, vibrations triggered by forces from outside or inside the steam generator vessel would be an obvious source for increases in local stress intensities.

High cyclic stress from FEI during the MSLB event would cause a small crack to rapidly propagate circumferentially to failure when the tube is near or at its allowable fatigue life. Leakage increase from the propagation of circumferential fatigue cracks was not addressed in the DPO and therefore is not included in the 2007 tube performance criteria.28 The NRC AIT report states that SCE informed the NRC that "they are reviewing their calculations of the LERF (4E-6/yr) and believe that review that will likely indicate that the differential pressures generated by a steam line break would not be large enough to rupture the degraded tubes as long as operators successfully implemented their emergency procedures.

If this is confirmed, the risk associated with steam line breaks will be significantly reduced." Such a conclusion would be only valid if the tubes had not been damaged by fatigue. Since this is clearly not the case, SCE hope for lowering the LERF is unrealistic.

The stress intensity during the MSLB can best discussed in terms of the Stability Ratio (SR) which is an indicator of the FEI vibration intensity.

SCE calculated that the SR varies from 0.33 to 1.15 and 0.16 to 0.83 for 100% and 70% power respectively, depending on tube location.

Such reduction in the SR may be significant for steady state operation but is insignificantly small compared to the increase in SR on depressurization of the SG during the MSLB accident.

The corresponding increase in velocity and steam quality overshadows the reduction in these parameters by operating San Onofre reactor Unit 2 at 70 % power. Therefore, the reduction in SR has no relevance to accident analysis when the tubes entering cycle 16 have been damaged by fatigue.A second factor that distinguishes tube failures by SCC and high cycle fretting fatigue is the difficulty of detecting the latter during in-service inspections.

This is because the crack initiation phase constitutes a high fraction of the total fatigue life in high cycle fatigue, once an engineering crack has been initiated, fracture occurs abruptly when the intensity level is sufficiently high (Ref. 7, 8, 9). The DPO project invested considerable effort on improving the sensitivity of eddy current detection of SCC cracks for leakage predictions.

Since comparable data for predicting leakage from fatigue induced cracks does not have any safety analysis that is based on fatigue failures one cannot use the 2007 performance criteria to ensure safety. This is a reason why the SCE safety analysis is not valid and why it must be re-evaluated in terms of fretting fatigue induced leakage instead SCC induced leakage.Since it took more then 15 years to develop the SCC based leakage methodology and close-out the DPO (and the related GSI 163) it cannot be expected that the NRC will revise the existing performance criteria any time soon. Until that time, conservative assessments must be performed before nuclear plants with considerable fretting fatigue damage are allowed to remain in service. The SCE safety assessment is not conservative.

Therefore, before starting San Onofre reactor Unit 2 at any power level, SCE must formulate an approach that would assure that the public safety margins would not be decreased.

SCE can use any method for that purpose as long as it can defend it on a technically conservative basis. The following five accident scenarios are discussed to provide further insight why operation with pristine tubes at 100% power, current 29 licensing base (CLB), is drastically different than operation at 70% power with fatigue damage tubes.2. Accident Scenarios The Steam Generators in San Onofre reactor Unit 2 (SGE 88 and SGE 89) contain 482 and 563 tubes respectively, with AVB wear ranging from 10% to 34%. The two SGs also contain a total of 515-plugged tubes. These tubes act as multiple sources for leakage during normal operations and during accidents (Ref. 9). They must be considered as sources for causing accidents and sources for propagating the leakage intensity during the accident.

An assessment of operations with such degraded tubes must demonstrate that at any time during normal operations and during accidents their local gap velocities, the corresponding SR and the burst pressure, will remain at sufficiently low levels to prevent leakages from exceeding acceptable levels. The following accidents are examples of accidents which must be included in such assessments.

A. Spontaneous fretting fatigue rupture of a single steam generator tube in the free span with a stuck open relief valve or a broken header Steam Generator overfill occurs relatively frequently in PWRs, an assessment should consider that the DBA SGTR will cause the relief valve to be stuck open during this event. The resulting higher local gap velocities and the corresponding increase in the SR must not cause additional tubes, (both plugged and un-plugged) to rupture.B. Tube Ruptures from Unplanned closing of an isolation valve.Closing an isolation valve would lead to an increase in steam flow through the unaffected SG. The corresponding increase in gap velocity would increase the local SR causing tubes which are on the border to exhausting their fatigue life to rupture abruptly (Ref 7, 8). This accident is similar to case A above with the exception that the increase in SR is expected to take place at a slower rate.C. Seismically -Induced Tube Rupture Both plugged and unplugged tubes can potentially lead to large primary to secondary leakage. Plugged tubes would behave differently, firstly because they do not generate a failure signal at the steam ejectors, and secondly, because the natural frequency of a broken tube would be lower than that that of an in service tube.Reactor experience (Ref. 9) has demonstrated that tubes that have been plugged due to wear will continue to wear and eventually break to impact and damage adjacent tubes.Material loss by wear not the mode of failure at plants was studied by EPRI. In their studies combining tube swelling with Fluid Induced Vibration (FIV) led to 30 circumferential fatigue failure. The difference between the cases studied by EPRI and the plugged tubes at SONGS is that at SONGS some plugged tube have already suffered considerable fatigue damage prior to plugging and are prone to fatigue failure. In this regard, EPRI recommends that tubes with pre-existing circumferential cracks be evaluated using linear elastic fracture mechanics.

Because some tubes at SONGS used up a significant fraction of their fatigue life they may contain micro cracks of various size.Because such cracks have not been detected at SONGS there is no indication that they do not exist. SCE did not address this issue.EPRI did not assess the effectiveness of tube stabilization in preventing damage to adjacent tubes; neither did SCE provide any information on their criteria for selecting tubes for stabilization.

SCE conclusions that the combined forces of the differential pressure and the seismic loads would not cause any tube to burst cannot be justified when the tubes are also subjected to cyclic loads simultaneously.

SCE calculation are based on the tensile strength that would cause tube rupture, a much lower stress, less than half, would be sufficient to severe tubes with cumulative fatigue usage (CUF) near unity (Ref 8)SCE calculations are based on a non conservative model and therefore their conclusions in the FSAR (5.4.2.2.1.3) regarding the ability of degraded tubes to withstand seismic loads are not valid.D. Station Blackout, SBO Severe accidents are not considered design basis accidents, nevertheless when changes in system operations are contemplated those changes must not increase safety risk. The operation of San Onofre reactor Unit 2 with a large number of fatigued tubes 'represents a new accident that has never been previously analyzed.'

All the analysis to date was based on tube failure by creep at high temperature.

The fact that the tubes were fatigued damaged demonstrates they can fail earlier due to natural flow instabilities in the steam generator.

The SBO accident is briefly described below.In this accident the primary system remains pressurized following a core becoming uncovered.

In the station blackout, SBO, accident scenario after the core is uncovered the secondary sides of all four steam generators are dry while on the primary side, steam flow by natural convection from the core to the steam generators and back to the core.The high pressure, high temperature steam will cause the weakest component in the system to fail thereby depressurizing the primary side. In this regard the hot leg surge line and the SG tubes are the weakest components in the reactor coolant system. If the high hoop stress on the hot leg surge line causes it to fail, the release of the highly radioactive gases will be contained within the containment.

If on the other hand, the high pressure high temperature steam opens up existing cracks in the steam generator tubes or ruptures 31 the tubes the primary side will be depressurized, by-passing the containment and allowing the highly radioactive gases to escape directly to the environment through the SG relief valve. The above scenario, also known as the high/dry core damage sequence, represents an early containment failure, which significantly increases the large early release frequency (LERF). When the containment fails early, the release to the environment is several thousands times larger in comparison to the release when the containment is intact. Most importantly, this early release occurs prior to the evacuation of the close population and therefore may cause early health effects (prompt fatalities).

Conformance to 10 CFR 50, Appendix B Criterion 16 dictates that operation with fatigued tubes will not increase the probability that fatigued tubes will not fail before the surge line. Appendix B dictates that to maintain its licensing basis the licensees must provide measures to assure that conditions adverse to quality such as failures, malfunctions, deficiencies, deviations, defective materials and equipment, are promptly identified and corrected.

Fatigued tubes definitely represent conditions which are adverse to quality.E. Main Steam Line Break, MSLB The fact that San Onofre reactor Unit 2 can pass the existing performance criteria from the in-situ tests results of San Onofre reactor Unit 3 provides no assurance at all that during a spontaneous MSLB accident the leakage will not exceed the DBA leakage. The in-situ tests only show that if the tubes were only exposed to tested pressure they would not leak if they maintained their wall geometry as tested. The in-situ tests were intended to determine leakage on the basis of tube weakening by actual loss of material and inclusions of stress corrosion cracks. In contrast to static pressure tests, fatigue failure due to high cycle FIV would result in a fast propagating circumferential crack at relatively low stresses (Refs 1, 5). Leakage from degraded tubes must be assessed in terms of the mechanism that has the potential to cause the largest leakage.If SCE wants to base their calculations on a realistic accident scenario, it must first demonstrate that the wear equation that was developed for laboratory data would be applicable to a tube that experienced impact wear in the SONGS steam generators.

As discussed in Appendix A, the wear equation which was used by SCE to calculate wall thickness did not properly incorporate the effects of impact wear. Secondly and more importantly, SCE must demonstrate that their burst pressure mechanism of determining leakage is conservative in comparison to the leakage that would occur during the fast MSLB depressurization.

The fast depressurization of the secondary side following an MSLB will lead to rapid increases in local gap velocity steam quality, thereby significantly increasing the stability ratio SR. The higher SR would, in term, increase the stress on the tube leading to rapid circumferential crack propagation as occurred in North Ana (Ref 2 )32 F. Risk Considerations The unusually large tube damage exhibited in both steam generators at San Onofre reactor Unit 2 is unprecedented, therefore little data is available to assess the increase in safety risk that would be associated with the above five accident scenarios.

Consequently accident assessments must be based on conservative assumptions.

The main uncertainty that must be considered in arriving at a risk estimate is the ability of the operator to shut the reactor down in a safe manner before depleting the RW Storage Tank inventory.

Operator's success would depend primarily on the unpredictable increase in leakage in an environment experiencing violent vibrations due to secondary side depressurization.

Operators are not trained in simulators that can reproduce such environments.

In my judgment, based on computer calculations, an operator would not be able to prevent the reactor core from being uncovered if the number of tubes failures would exceed five.Given that steam generator 89 contain at least 500 AVB tubes which have used up a significant fraction of their fatigue life and another 86 TSP tubes (Ref 10) which also lost some fatigue life, a rupture of 5 tubes out of 600 susceptible tubes as result of fatigue failure during an MSLB event is not an overly conservative assumption.

Taken the probability of a steam a line break outside containment at E-4 per year the Large Early Release Frequency, LERF of radiation escaping the environment due to the reactor core being exposed becomes 1E-4 /year or 5 E-5 /yr for six month of operation.

Such an increase is by a factor of 5 higher than Commission goals as described in Reference

11. In contrast, SCE calculated a change in LERF of 4E-6/yr on the basis of that the AP will not be large enough to rupture tubes.The LERF is a measure of risk, the safety goal takes into consideration that the LERF must be by an order of magnitude lower than the core damage frequency (CDF) to account for a large and early radiation release due to containment bypass.As discussed above, when the controlling mechanism of tube rupture is cyclic stresses from FIV, tube rupture will be controlled by variations in the stability ratio SR and not by variations in A P. During the MSLB the SR will be drastically increased due to an increase in local velocities and steam quality.G. Summary The reason that SCE concluded that operation of San Onofre reactor Unit 2 at 70% power would not involve a new unanalysed accident was because SCE assumed that the tubes would enter service in cycle 17 in the same conditions as they were at the beginning of cycle 16. In addition, SCE implicitly assumed that the stability ratio would not increase during Design Basis Accidents and the burst pressure could be determined by ignoring 33 scaling effects in fretting wear by impacts. Based on ample reactor experience and laboratory data there is no basis to accept SCE proposed no statements to CFR 50.92.34 References I -SONGS Unit 2 Return to Service Report attachment 4 MHI Document L5-04GA564 Tube Wear of Unit-3 RSG Technical Evaluation Report [Proprietary Information Redacted], S023-617-1 -M I538TREV.

0, submitted by Southern California Edison to the NRC, October 3rd 2012.2 -NRC Bulletin 88-02: Rapidly Propagating Fatigue Cracks in Steam Generator Tubes, Feb 5, 1988 3 -Application of Risk Assessment and Management to Nuclear Safety George Apostolakis Commissioner US Nuclear Regulatory Commission DOE Nuclear Safety Workshop September 20, 2012 4 -PWR Steam Generator Tube Fretting and Fatigue Wear, EPRI- 6341 April 1989 5 -Volchock et.al. "The effect of Surface regular micro-topography on fretting fatigue life. Wear 253 2002 509-515 6 -H. J. Connors et al. Watts Bar Unit I Evaluation For Tube Vibration Induced Fatigue, April 190 WCAP- 12547 7 -F.A. Simonen and S. R, Gossein "Life Prediction of and Monitoring of Nuclear Power Plant Components for Service Related Degradation" Trans ASME Vol 123 Feb.2001 8 -Case Study of the propagation of a small flaw under PWR loading conditions and comparison with the ASME code design life G.T. Yahr et al ORNL Conf 8607622 -12 9 -Three Mile Island Plugged Tube Severance, May 2003-EPRI 10 -SCE, " San Onofre Nuclear Operating Station Unit 2 Return to Service Report, Oct.3, 2012" 11 -USNRC G. Aposttolakis "Application of Risk Assessment an Management to Nuclear Safety " DOE Workshop, Sept 20, 2012 35 I declare, under penalty of perjury, that the foregoing information is true, accurate, and correct. Executed on May 15, 2013, in Rockville, MD.D./joram Hopenfeld

/36 Mendiola, Doris From: Kristin Hines Gladd <gladdk@ayreslawgroup.com>

Sent: Friday, May 24, 2013 10:38 AM To: CHAIRMAN Resource; CMRSVINICKI Resource; CMRAPOSTOLAKIS Resource;CMRMAGWOOD Resource; CMROSTENDORFF Resource; OCAAMAIL Resource; Docket, Hearing; Doane, Margaret

Subject:

Third Attempt of Notice of FOE and NRDC Joint Motion to Consolidate LARs, Attachment 2 of 3 Attachments:

Part 2 of 3-FoE and NRDC Comments on Proposed NSHC Det for LAR 263.pdf Good morning, We appear to be having technical difficulty with transmitting the attachments to the FOE and NRDC Joint Motion. I apologize for any inconvenience.

Thank you, Kristin Hines Gladd Kristin Hines Gladd Associate Attorney Ayres Law Group 1707 L Street, N.W., Suite 850 Washington, DC 20036 Office: 202.452.9222 GladdK atavreslawgroup.com 1

ATTACHMENT 2 Declaration of John Large UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE NRC STAFF In the Matter of SOUTHERN CALIFORNIA EDISON COMPANY (San Onofre Nuclear Generating Station, Units 2 and 3)Docket ID NRC-2013-0070 May 16,2013 A REVIEW OF THE NRC 1 PROPOSED DETERMINATION OF No SIGNIFICANT HAZARD CONSIDERATION FOR SOUTHERN CALIFORNIA EDISON'S PROPOSED LICENSE AMENDMENT FOR SAN ONOFRE UNIT 2 DECLARATION OF JOHN LARGE I, John Large, being duly sworn, state: I QUALIFICATIONS AND EXPERIENCE 1.1 1 am John H Large of the Gatehouse, I & 2 Repository Road, Ha Ha Road, Woolwich, London, United Kingdom, SE18 4BQ.1.2 1 am a citizen of the United Kingdom.1.3 1 am a Consulting Engineer, Chartered Engineer, Fellow of the Institution of Mechanical Engineers, Graduate Member of the Institution Civil Engineers, Learned Member of the Nuclear Institute and a Fellow of the Royal Society of Arts.1.4 1 head the firm of Consulting Engineers, Large & Associates.

I .5 Based in London UK, Large & Associates provides engineering and analytical services relating to nuclear activities, systems failure and engineering defects.1.6 Prior to founding Large & Associates, from the 1960s through to the early 1990s I was a full time, tenured academic in the School of Engineering of Brunel University (London) where, as a Whereas I acknowledge that this declaration relates to NRC's finding on the no significant hazard consideration.

I have channelled my comments through SCE because the request for the license amendment derives from SCE and the NRC proffers no statement of its own position.

Senior Research Fellow, I undertook applications research on behalf of the United Kingdom Atomic Energy Authority (UKAEA) and other UK government agencies.1.7 A r-Sum6 of my academic and professional consulting careers is available at the Large &Associates website.2 EXPERIENCE OF THE SAN ONOFRE NUCLEAR GENERATING STATION 2.1 1 have previously prepared and submitted evidence in the matter of the San Onofre Nuclear Generating Station (SONGS) to the Nuclear Regulatory Commission (NRC) Atomic Safety Licensing Board (ASLB).2.2 In my Vs! Affidavit (January 2013) to the ASLB I provided opinion on the failings of the SONGS replacement steam generator (RSG) design, how this gave rise to unrestrained tube motion and excessive tube wear, and on the uncertainties of restarting Unit 2 at the proposed maximum limit of 70% rated thermal power (RTP). In my 2"d Affidavit (February 2013) to the ASLB I examined the RSG steamside thermal-hydraulic flow regime and how this determined the types and rates of tube and tube restraint component wear, particularly at the Southern California Edison (SCE) proposal to operate Unit 2 at 70% rated thermal power (RTP).2.3 1 have also prepared and submitted opinion (March 2013) to the NRC Petition Review Board in which I review the involvement of SCE and Mitsubishi Heavy Industries (MHI) in the specification and design of the RSGs.2 3 LICENSE AMENDMENT REQUEST AND No SIGNIFICANT HAZARD CONSIDERATION (NSHC)3 3.1 SCE has submitted a license amendment request for a temporary change to the steam generator management program and license condition for maximum power, both being integral parts of the OL Technical Specification (TS). In short, the amendment applies for the duration of the fuel cycle (Cycle 17) in that power operation would be restricted to up to 70% rated thermal power rating (RTP) and that a tube inspection would be undertaken at 150 days of operation into Cycle 17. Other than the power reduction and tube inspection period, no other physical 2 Tube Wear Identified in the San Onafre Repla,:ement Steam Generators.

Mitsuhishi Reports UES-20120254 Rev.O (3/64)and L05-(4ga588(0)

Together with Other Relevant Mfbirmation, March 2013 -this supplementary report was placed before the Petition Review Board of the NRC as part of the §2.206 process.3 NSHC is required under 10CFR §50.91 and §50.92 and the Reguilatory Issue Simmtry (RSI) Attributes ala Prolposed No ,S'it,,nýfilrat HazjarAa Consideration Delerairnation (March 29 2012) provides the public an opportunity to comment or request a hearing on the proposed amendment request via the published NRC Notice of April 16 2013 Applicatiaio adAmneditnemnt tlo Fl'ilir" Operating censrve Itnvuh'iang Proposed No I-hatrds lConsideonin,, Detelnnuttion:

£1l Onafre Nuclear Generotirtq Station. UDit 2.

changes to the operation and/or detailed installation of the components of the plant were proposed.3.2 A No Significant Hazard Consideration (NSHC) determination requires that operation of the facility in accordance with the proposed amendment would not 3.3 (1) involve a significant increase in the probability or consequences of an accident previously evaluated; or 3.4 (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or 3.5 (3) involve a significant reduction in a margin of safety.4 EXTANT CONDITION OF THE UNIT 2 STEAM GENERATOR TUBING 4.1 My 1 St Affidavit to the ASLB describes the processes that gave rise to the extensive degradation of the tubes in each of the two RSGs serving SONGS Unit 2 and, similarly, Unit 3 -the events, processes and the extent of tube wear degradation have been extensively reported by a number 4 of sources .4.2 A summary of the Units 2 and 3 RSG tube wear is given in APPENDIX I of my 0st Affidavit being a true reproduction of Table 6-1 of the SCE response5 to the CAL of October 2012 -detailed inspection data for Unit 2 tube wear is provided by the SCE Special Report.6 4.3 The OL TS sets out criteria stipulating the condition in which individual tubes have to be withdrawn from pressurized service by plugging?.

Essentially, these tubes are: 4.3.1 a) First, in those instances where the tube wall thinning is equal to or greater than 35% of the original tube wall thickness (TW Depth -Column 1 of Table 6-1) the tube has to be withdrawn from service (by plugging).

4 There are a number of chronological narratives of the events leading up to the withdrawal of all 4 RSGs at SONGS, for example United States Nuclear Regulatory Commission Region IV, San Ot, fre Nuclear Generating Station -- NRC Augmented hispection Tearn Report 05(0)36212012Q07, July 18 2012, also the SCE, Enclosure 2, S, tgs Return to Sernice Report, October 3 2012 and Attachment 4: MHI Document I 5-04GA564

-Tube Wear of Unit-3 RSG Technical Evaluation Report, Mitsubishi Heavy Industries SO23-617-1-M1538 Rev 0.5 SCE. Enclosure 2, SONGS Return to Setiice Report, October 3,2012 6 SCE Special Report. hIspection of Steam Generator Tubes, Cycle 17, San Onofre Nuclear Generating Station, Unit 2, Docket No 50-361, 10 CFR 50.4, April 10, 2013 7 Localised repair of degraded tubes by sleeving is not permitted by the TS.

4.3.2 b) Second, the TS requires that the operational assessment, made at the time of the tube inspection, has to provide assurance that no individual tube will wear beyond the 35% TW Depth limit in the following fuel cycle or until the next tube inspection.

This means that the OA has to project the tube wear rate(s) forward over the next in-service cycle -for Unit 2 this forward projection applies to a period of 150 days into Cycle 17 being the tube inspection interval nominated by SCE as a condition of the restart.4.3.3 c) In addition to those tubes that have experienced or are likely to develop excess levels of wall thinning (=>35%), SCE has also chosen to preventatively plug zones of tubes to reduce the risk and incidence of tube wear.4.4 These three groups of plugged tubes make up the numbers of defective17 tubes of the tube bundles of the two RSGs serving Unit 2. Those tubes that have sustained some degree of wear to a depth of less than 35% and which remain in pressurized service are referred to as degraded17 tubes.5 ADEQUACY OF THE OPERATING LICENSE TECHNICAL SPECIFICATION 5.1 The TS tube integrity criteria relate tube resilience (integrity) to the remaining cross sectional (wall) area of then thinned tube section and the radial stress active within the wall. The radial or membrane stress derives directly (and solely) from the pressure differential between the reactor circuit and lower pressure of the steamside of the RSG. The resilience of a degraded tube is evaluated against allowable stress limits (membrane plus some in-plane bending stress) by multiplying the stresses for a non-degraded tube by the ratio of the corresponding sectional properties (thinned) of the degraded tube.8 5.2 In my opinion this approach, adopted for the TS tube integrity criteria, is overly simplistic in that it provides little account for anomalies (aging, chemical deterioration, etc) of tube material and/or physical degradation of the tube geometry (in this case surface imperfections and flaws).5.3 In effect, the allowable stress limits based on a pressure bursting failure mode provide, so it is assumed, sufficient margin to accommodate all other (undefined) processes and conditions that 8 For the degraded tube case evaluation the minimum tube wall thickness required to meet the structural requirements of UNSCR R.G. 1.121 is calculated by considering (1) wall thickness loss over the entire tube length, (2) wall thickness loss at the tube intersections with tube support plates (TSPs), and (3) wall thickness loss at the tube intersections with the anti-vibration bars (AVBs) in the tube bundle U-bend region and the minimum wall thickness is calculated for: (a) the fault condition, and (b) the normal operating condition.

The more limiting of these two loading conditions detcrmines the minimum allowable tube wall thickness for the tube not to burst under the conditions specified in R.G. 1.121.

could contribute to and/or accelerate failure of the tube -this is the basis of the TS criteria underwriting tube integrity.

5.4 In other words, the underlying premise is that at 35% thinning (for whatever reason and by whichever means), the tube remains a sound structure, there being sufficient margin in hand to safeguard against all other circumstances and conditions that might quite independently progress to tube failure. Moreover, the failure mechanisms of such other 'independent' factors, for example plain fatigue cracking of a vibrating tube, might themselves be enhanced by the nature of the tube wear, either by the presence of surface flaws, abrasions, notches and/or areas of work hardening.

9 5.5 Other than the margin, the TS tube integrity criteria do not provide for quantitative cross linkage of possible separate failure mechanisms to the condition of the tube surface as generated by the degradation processes (tube rubbing, abrasion and impacting) experienced in the San Onofre RSGs.5.6 For example, the 35% tube wall thinning threshold at or over which individual tubes should be plugged and withdrawn from pressurized service, must be drawn from operational and bench-testing experience of past tube failures.

This is because the 35% threshold must provide a satisfactory margin to cover metallurgical and physical geometry features that serve to trigger various failure modes, such as stress corrosion cracking, 1 0 mechanical damage, wastage (thinning), denting, and vibration induced cyclic plain fatigue cracking.5.7 However, the San Onofre tube degradation is acknowledged to be unique so, it follows, that the nature of the tube degradation scars are also likely to include unique features that are not replicated in the data bank of past tube failures at other nuclear plants and from bench-testing trials. If so, the use of the present single-failure mode TS tube integrity criteria (that relies upon 9 The impact behavior and fracture response of Inconel 690 has not attracted that much research, although indications are that impacting results in the formation of localized shear bands which can prompt catastrophic failure -see Woei-Shyan Lee and Tai-Nong Sun. Pla.&ic F/l,,w Behaviour of l'conel 690 Super Alloy Under Compres.ive Impact Loading,.

Materials Trans, Vol. 45, No. 7, 2004 10 The are number of such modes of failure including, but the TS is heavily biased towards stress corrosion cracking which had become by the 1990s the principal degradation mechanism for SG tubing worldwide.

For example outside diameter stress corrosion cracking (ODSCC) where the probability of failure is determined from proprietary coefficients obtained by bench-testing -for example, EPRI suggest the failure finction for ODSCC to be Api(a) = A + B.logl0(a)

+ C where A and B are proprietary coefficients and Apla) is the burst pressure for a given flaw of a dimension.

A common locality for ODSCC is at the TSP where debris, comprising corrosion sludge fills the TSP aperture providing conditions conducive to dry-out and adverse cation/anion being an accelerant to inter-granular SCC and crack linkage. Similar ODSCC is known to occur at dented TSP locations.

Alloy 690 tube material is generally more (about 10 times) resistant to SCC than the earlier Alloy 600.

past experience of tube failures at other nuclear plants, etc) at San Onofre is inappropriate and introduced uncertainty.'

2 6 NATURE OF TnE TUBE DEGRADATION AT SAN ONOFRE 6.1 In its reporting 1 3 to SCE, the manufacturers of the RSGs, Mitsubishi Heavy Industries (MHI), describes distinctly different patterns of wear at the TTW, AVB and TSP locations.

The in-plane direction of the tube vibration, particularly at the AVB-to-tube fretting localities, is generally acknowledged to be unique to the San Onofre RSGs in that this mode of degradation has not been experienced at other US nuclear power plants wherein tube wear is dominated by out-of-plane motion.6.2 These variations in types of tube wear are described by MHI.'3 6.2.1 TTW: This wear pattern occurs on the free span portion of the tubes (between the remaining effective AVB restraint points) in the U-bend region of the tube bundle. TTW produces long scars running in the axial direction of the tube as a result of continuous contact fretting or clashing of impacting tubes.6.2.2 MHI conclude that the tube in-plane motion giving rise to TTW is caused either by random vibration and/or fluid elastic instability (FEI), favoring the latter on the basis that the amplitude of random vibration is small.6.2.3 It is also possible that out-of-plane TTW occurs and that this lower : frequency vibration mode is excited by low frequency flow induced I"' *'forces from, for example, vortex shedding in the wake of tubes or groups of tubes. In this mode, even if the in- and out-of-plane FEI is suppressed in the 70% RTP restart of Unit 2, the tubes will remain vulnerable to excitation by flow induced fluid forces.II The EPRI Steam Generator Examination Guidelines Revision 5 state that flaws in qualification data sets should produce signals similar to those observed in the field in terms of signal characteristics, signal amplitude, and signal-to-noise level.12 For example, MHI describe a zigzag pattern wear scar -see T63.1 -which might provide a stress raiser in the axial tube direction in which the pressure membrane stress acts, although insufficient description of this type of wear scar is publicly available.

13 Attaclmtent 4: MHI Document L5-04GA564

-Tube Wear of Unit-3 RSG Technical Evaluation Report, Mitsubishi Heavy Industries S023-617-1-M 1538 Rev 0.

6.3 AVB: Wear at the tube-to-AVB contact points wear occurs in three distinctive patterns: 6.3.1 In-Plane:

To generate this pattern of wear at the AVB the tube (shown right) moves relative to the AVB in the in-plane direction (up-and down). The resulting wear scar sits across the AV bar depth indicating relatively large in-plane motion.wear amplitude.

Scar 6.3.2 This wear arises because the 'zero tube-to-bar gap and zero-AV Bar preload design functionality of the AVB provides no tube restraint the in-plane direction leaving the tube free to respond Adapted from MHI and slide (up and down) across the AV bar contact surface.6.3.3 This pattern of wear scar is much longer than the typical case adopted in the Updated Final Safety Analysis Report (UFSAR)1 4 for which the scar length is assumed to equal the AVB-to-tube contact length (ie the AV bar cross-section depth). In this case the UFSAR is overly optimistic in determining the permissible tube wall wear depth because it is generally accepted that tubes with shorter wear scar lengths exhibit higher burst pressures.

6.3.4 A variation of this in-plane motion is a zigzag or saw-tooth surface wear pattern suggesting a combination of in- and out-of-plane tube motion. This pattern of tube wear produces a distinctive line flaw orientated in the axis of the tube thereby presenting a weakness in the tensile direction of the principal tube stress arising from the pressure differential.

6.3.5 AVB Dig In: In this pattern of wear the misaligned or twisted AVB digs-in to the tube surface -the pattern is probably unique to Unit 2 because the Unit 3 AVBs were more effectively flattened by a modified manufacturing process -see ¶7.12.UNIT 2 UNIT 3 Twisted AVB Flattened 6.3.6 The resulting wear scar is a sharp notch or 'stress raiser'in Ts.ltd the surface of the tube.AVB d fop WLC 14 San Onofre Nuclear Generating Station Unit 2 & 3 Updated Final Safety Analysis Report Revised April 2011 -see Table 15.10.63.2-4 for the transient analysis summary results for a steam generator tube rupture.

6.3.7 For failure analysis, account of this stress raiser is taken by assuming a stress concentration factor (kt) determined by the dimensional geometry of the notch. Since the detection of this wear is blind from within the tube it is impracticable to n !,/

determine the sharpness and depth of the notch so, it follows, the appropriate value of k, cannot be chosen with absolute Adapfrdfr,,, MUI e~~e certainty.15 6.3.8 A variation of this wear pattern is where there is both in- and out-of-plane movement of the tube to produce the zigzag pattern described earlier (¶6.3.4), similarly producing an axial flaw that presents to the radial tensile stress in the pressurized tube wall.6.3.9 In-Plane AVB and Tube Wear: This wear pattern is where both tube and AVB bar have both worn simultaneously or when the wear between tube and AV bar cannot be distinguished because visual access to the wear interface is not possible, although the left-hand tube in the example shown right, the tube motion has wom substantially through the width of the AV bar (-40%).6.4 All modes of AVB-to-tube wear are provoked by fluid flow random vibration (ie turbulence) and, thus, the AVB-to-tube contact locations remain vulnerable induced excitation and wear even if the 70% RTP eliminates FEI.'6 6.5 These two latter wear patterns (16.3.6 and ¶6.3.9 -as shown by photographs reproduced from the MHI inspection)1 3 highlight the difficulty of accessing the wear scars to determine the extent of surface damage. Much the same applies to the locations of the TTW, where the close proximity of adjacent tubes practicably limits access for visual inspection.

6.6 In other words, although the eddy-current (ET) in-service through-wall inspection results provide a generally reliable measure of overall tube wall thinning, the assessment of the nature of individual incidences of tube surface damage (imperfections, etc) is uncertain.'

7 15 For example the range of stress concentration factor kt given in Chart 3.5 of Walter D. Pilkey, Peterson's Stress Concentration Factors Second Edition, John Wiley, Sons, Inc., 1997 for a tube under axial tension (but not pressurized).

16 Although not discussed here, I consider it likely that the TSP-to-tube wear is also driven by random fluid processes

-this locality of tube wear is an important factor in considering the potential for the tubes that are effectively pinned at the top TSP but with successive AVB-to-tube restraint not active, to fail by high cycle fatigue.

6.7 So far I have considered the surface changes brought about by, for want of a better description,'gouging' of two adjacent parts (eg tube-to-tube, AVB-to-tube and TSP-to-tube) to form distinctive scars or stress raisers in the tube outer surface. Under tensile loading, deriving either from internal pressure, bending or plain cyclic fatigue, the stress concentration can develop cracking resulting in early tube failure from ductile tearing or brittle fracture.6.8 Thus the presence of surface flaws produced in TTW, AVB- and TSP-to-tube wear may bring forward tube failure before that predicted by the TS tube burst criterion (3xAP and 1.4xAP for SIPC and AILPC cases respectively).

Since the TS does not specifically refer to this and other types of tube failure, it vital to maintain the 3xAP and 1.4xAP margins to cover such contingencies.

6.9 There

is another strength of materials phenomenon, referred to as fretting fatigue, occurring at the contacting and sliding surfaces of two adjacent parts under load and subject to slight relative movement by vibration or some other force. At very low stress levels and often after only a few thousands of cycles, fretting fatigue may initiate micro cracking in the rubbing surfaces that then become available to propagate into ductile/brittle failure zones (as in 56.7).6.10 In plain fatigue (without fretting) the initiation and development of small cracks typically represents upwards of 80 to 90% of the total component life, but with a fatigue fretting contribution the plain fatigue strength or endurance limit can be reduced by as much as 50 to 70% during subsequent (or simultaneous) cyclic loading of the tube overall.1 8"19 6.11 As I previously noted in ¶6.6 through-wall El' may not have sufficient resolution to detect fine micro cracking between surfaces in contact (ie the tube and TSP or AVB or another tube) and, if so, the presence of established fretting fatigue may have passed unnoticed.

17 The ET inspection system must detect tube wall internal and surface flaws at an acceptable level of detection reliability and it must also size the significant flaws, For the San Onofre degraded tubes Er must have acceptable reliability to detect and size flaws which are not necessarily significant but which might require action to mitigate further tube damage. This grading of flaws determines whether the tube is degraded but fit for continued pressurized service or defective because it contains a flaw of such severity that it is unacceptable for continued pressurized service until the next tube inspection outage.18 ASM Handbook V 19, Fatigue and Fracture, ASM International 19 Plain fatigue is where there is no direct contact, say where the pipe vibrates in a free span situation.

In fretting fatigue there is contact between two slightly moving parts -the contact point stress gradients are likely to be very high due to the localised stress concentration at the contact and the magnitude of these stress gradients is usually much higher than those associated with typical design features of components, such as notches and holes. Also, loading is likely to be non-proportional in the neighbourhood of the contact with this feature caused by the non-linear nature of the friction at the contact interface.

Localised surface damage at the asperity level may play a role in accelerating the initiation of cracks at the asperity scale.

6.12 Moreover, because surface imperfections contribute strongly to premature failure (ie failure within the TS allowable stress safety margin), it is absolutely essential that the wear surface flaws (either deriving from gouging, fretting fatigue, or just plain fatigue) be fully understood and taken into account when projecting the tube integrity for the Cycle 17 in-service period..7 PROJECTING FURTHER TUBE DEGRADATION INTO CYCLE 17 7.1 Whereas the SCE license amendment request specifically applies to Unit 2 it is, nevertheless, important to consider the extent and nature of the tube wear degradation in the identical Unit 3.7.2 This is because the tube bundle damage in both RSGs serving Unit 3 is universally acknowledged to be so severe and extensive that any level of return to powered operation of this nuclear plant would introduce further risk and lack assurance that Unit 3 could operate safely.This situation is confirmed by the requirement of the Confirmatory Action Letter (CAL)2 0 issued by the NRC following the RSG tube failure that provoked the forced shutdown of Unit 3 in January 2012.7.3 The CAL specifically requires SCE to undertake a number of Actions relating to any intention to restart Unit 3, including 7.4 "... 7. Prior to entry of Unit 3 into Mode 4, SCE will submit to the NRC in writing the results of your assessment of Unit 3 steam generators, the protocol of inspections and/or operational limits, including schedule dates for a mid-cycle shutdown for further inspections, and the basis for SCE's conclusion that there is a reasonable assurance, as required by NRC regulations, that the unit will operate safely." my added emptusis 7.5 On its part SCE has chosen not to respond to this Action 7 (and also four other CAL Actions)and no preparations have been made to restart Unit 3.2. In my opinion, this failure of SCE to respond to Action 7 is tacit acknowledgement that it is not possible to provide a 'reasonable assurance'that Unit 3 with the present level of tube degradation will 'operate safely'.7.6 This brings me to consider Unit 2 which SCE proposes to restart, subject to the license amendment request being accepted and ratified by the NRC. The CAL also required SCE to undertake specific actions, these being: 20 Letter from Elmo E Collins (USNRC) to Peter T Dietrich (SCE), C(",rfirnm.,ot Action Leter 4-12-(01, San Onofre Nuclear Generating Station, Units 2 and 3, Commitments to Address Steam Generator Tube Degradation, March 272012.21 In fact, the nuclear fuel of the reactor core of Unit 3 has been removed and placed in water pool storage.

7.7 "... 1. Southern California Edison Company (SCE) will determine the causes of the tube-to-tube interactions that resulted in steam generator tube wear in Unit 3, and will implement actions to prevent loss of integrity due to these causes in the Unit 2 steam generator tubes. SCE will establish a protocol of inspections and/or operational limits for Unit 2, including plans for a mid-cycle shutdown for fiirther inspections.

2. Prior to entry of Unit 2 into Mode 2, SCE will submit to the NRC in writing the results of your assessment of Unit 2 steam generators, the protocol of inspections and/or operational limits, including schedule dates for a mid-cycle shutdown for fiarther inspections, and the basis for SCE's conclusion that there is reasonable assurance, as required by NRC regulations, that the unit will operate safely." my added emplwzsis 7.8 In responding to the CAL, SCE presented a series of Operational Assessments (OAs) that it claimed justified restarting and operating Unit 2 for a trial period. The OAs of interest here are those by AREVA 2 2 and, independently, the latest revision of the OA by Intertek APTECH.23 7.9 First, it is of interest to note that each OA fails to 'determine the causes of the tube-to-tube interactions' as stipulated by the CAL. This is because all of the OAs (including a third OA by Westinghouse) 2 4 skirt round and stop short of identifying the root cause, delving no further into the design features, peculiarities and processes of the RSGs that give rise, so it seems uniquely at San Onofre, to the tube motion in-plane excitation forces .25 7.10 However, both OAs recognized that 7.10.1 i) the tube wear degradation experienced in Unit 2 was less advanced than the tube wear in Unit 3; although, that said 7.10.2 ii) the wear locations (AVB and TSP) and number of incidences present in Unit 2 were very similar to those present in Unit 3, although Unit 3 had, in addition, a much greater number of TT'W incidences; and that 22 SCE, Attachment 6 -Appendix B: SONGS U2C17 -Steam Generator Operational Assessmentfor Tube-to-Tube Wear, AREVA 23 SCE. Enclosure 1, Amendment I Operational Assessment for SONGS Unit 2 Steam Generators for Tube-to-Tube Wear Degradation 100% Power Operation Case, Intertek AES 13018304-2Q-1 March 2013, March 14,2013.24 Attachment 6 -Appqendix D: Operational Assessment o:f WVear Indications hi the U-benid Regimo ofSan Onofre Unit 2 ReThpcement Steam Generaior%, Westinghouse Rev 3, October 2012.25 In fact, as I discuss in some detail in my I' ASLB affidavit, there is disagreement between the various OA consultants as to whether the tube motion excitation forces derive from random fluid processes (turbulence, downstream wake, etc.) and/or fluid elastic instability.

7.10.3 iii) the wear processes involved in these virtually identical RSGs related to the effectiveness of restraint provided by the anti-vibration bar (AVB) assemblies in the U-bend region of the tube bundle.7.11 It follows that the tube wear mechanism is a two-stage process whereby, first, the AVB contact with the individual tubes is worn away by vibration of individual tubes excited into in-plane motion by local fluid flow forces. Second, loss of the AVB restraint, and successive points of AVB restraints, results in a lengthening of the unsupported or free-span sections of tube to the extent, again by fluid forces, that the tube vibrates at low frequency and at sufficient amplitude to enable tube-to-tube clashing and, hence, accelerated tube-to-tube wear (TTW)26 to occur.7.12 The TTW in the Unit 2 RSGs was less advanced than that of Unit 3 because of the omission in the manufacturing process of the 00P Unit 2 AVB components that, quite fortuitously, resulted in the presence of an unintentional clamping or preload force across the individual tubes -this preload force delayed the loss of the in- A,, plane (IP) AVB restraint and the onset of second phase YTW process in Unit 2.27 7.13 In other words, the tube wear extant in Unit 2 is representative of the first stage of the two stage mechanism that leads to accelerated TTW.7.14 The disadvantages arising from the installation of the distorted (twisted)

AV bars include i)notching and the formation of a stress raiser as shown at 16.3.7, and ii) the opportunity for fretting fatigue in the locality of the notch of i), generated whilst the AVB restraint was active with the preload force. Both of these features could contribute to localized ductile/brittle failure driven either by internal pressure and/or exceeding the modified plain fatigue cyclic loading endurance limit.7.15 SCE's proposed new operating regime for Unit 2 at 70% RTP claims that the 0st and 2 d stages of wear will be slowed but not totally eliminated.

26 For a fuller description of the tube wear processes see my 1' Affidavit to ASLB.27 The intended design function of the AVBs was to provide a 'zero-gap-.ero-conitact-force', that is no preload, across the individual tubes thereby offering no effective restraint in the in-plane direction.

Unit 3 achieved this design functionality following modifications in the manufacturing of the AVBs, whereas the unmodified AVBs of Unit 2 remained distorted (twisted) so much so that certain of the AVB locations applied a tube clamping preload force.

7.16 In fact, both AREVA and Intertek OAs agree that even at the 70% RTP reduction, the 1st stage process (AVB restraint loosening) will progress to the threshold at which the 2nd stage TFW commences in earnest, thereafter putting individual tubes at risk of structural failure (bursting) as a result of tube wall thinning.7.17 Intertek's projection for rate of TTW for the proposed Unit 2 restart (Cycle 17) is summarized by the following 2 graphic:73 i.-7.18 The 1" stage AVB-to-tube restraint 0 0.05 1 t -0 bf If P.loosening proceeds from the time of Comm restart over a period of 12 months at 0.4 1.0 1.6 which time a group of successive TIME INTO CYCLE 17 -YEAR A V B s have little or no preload force in AFTER ....... FiG 1.5-1 the in-plane direction.

FIGURE 1 INTERTEK PROJECTION OF CYCLE 17 TUBE DEGRADATION 7.19 From this point forward the 2 nd stage wear process (TTW) commences following the characteristic

(-).7.20 The TTW wear rate is such that the tube passes the 95% tube burst criterion

(_)28 at about 0.35 years thereafter

-this means that the tube is considered to have failed at about 1.35 years into Cycle 17.7.21 SCE's argument is that the proposed Unit 2 shut down and RSG tube inspection at 5 months ( )safeguards against tube failure by providing a sufficient time buffer ahead of the Intertek 1.35 year (16 months) period to exceed the 95% threshold.

7.22 However, Intertek's projections do not compare at all favorably with the timings evaluated by the AREVA OA29 because: 28 The 95% Probability, 50% Confidence criterion for an individual tube burst is specified in the Operating License Technical Specification for Unit 2 of the San Onofre nuclear plant.29 Attachment 6 -Appendix B: SONGS U2C17 -Steam Generator Operational Assessment for Tube-to-Tube Wear, AREVA -the data presented here relates to Figure 8-3 but this has been declared proprietary information and thus cannot be reproduced here -instead the set points of the AREVA AVB and TTW wear phases have been taken from the same but non-proprietary information available in the text of Appendix B -see Large & Associates Affidavit Response to -tomic Sqtn, and Licerning Board's tactual/.%sues, January 22,2013.

7.23 for AREVA (shown thus), the AVB-to-tube restraint loosening period until the 2 nd stage TTW commences is about is .-0.3 year compared to 1 year by Intertek; and similarly 00 AREVA TTW I 7.24 the equivalent total time to tube burst COM,,NC!s 0I (95% probability) projected by AREVA is in the range of 0.5 to 1.5 year 0.3 0.5 1.0 1.5 TIME INTO CYCLE 17 -YEAR compared to -1.35 year Intertek.

FIGURE 2 AREVA PROJECTION OF CYCLE 17 TUBE DEGRADATION 7.25 In summary: There are two important issues raised by the AREVA and Intertek OAs, these are, first, both of these independent analyses conclude that even at the reduced 70% RTP level of operation, the AVB-to-tube wear 3 0 and TTW will continue to be present in the RSG tube bundles of Unit 2; and second, each OA arrives at significantly different time projections for individual tubes in the tube bundles of the RSGs to reach and exceed the TS tube burst failure criterion.

7.26 On the second issue, it is the broad range of the projected periods for the start of TIW that reflects, for both OAs, the uncertainty about just how far along the path to complete loss of AVB in-plane restraint Unit 2 was at the end of Cycle 16. The difference of 0.3 (AREVA) and 1 year (Intertek) is such a disparity that, equally it might be reasoned, TTW could have commenced at some time towards the end of Cycle 16. If it had, then the periods for TTW to exceed the 95% tube burst probability could be shorter that SCE's 0.4 year (150 days) period over which the tubes would remain acceptably degraded and not defective.17 7.27 Also, it is established that a significant number of tubes in each of the two RSGs serving Unit 2 are defective; some of these tubes have exceeded the wall thinning limit and have been withdrawn from pressurized service by plugging; other tubes that are at risk of exceeding the wall thinning limit during the projected Cycle 17 period 3 t have or are also to be withdrawn from pressurized service by plugging.30 The other modes of tube wear shown in Table 6-1 of my 1V' Affidavit to the ASLB are also likely to continue, these include wear at the tube support plates (TSP) and at certain of the retainer bars (RB), although at the vulnerable RB localities all of the tubes have now been plugged.31 The Operating License Technical Specification (3.4-51 -3.4.17 and Action A I) requires verification of steam generator tube integrity shall be maintained until the next refuelling outage or steam generator tube inspection, 7.28 Undermining SCE's confidence that it is able to reliably schedule a tube inspection frequency (ie 150 days) is that SCE's OA consultants have each failed to identify the root cause that leads to tube wear degradation.

3 2'3 3 In the absence of this root cause understanding, any prediction of the tube wear rates and, from this, the operational time throughout which the tube will continue to be in a degraded state and not defective16 condition, is uncertain and non-compliant with the TS tube integrity criterion that the tubes shall remain serviceable (degraded and not defective) through until the next inspection outage.31 Such uncertainty casts considerable doubt over the reliability of SCE's no significant hazard consideration.

7.29 In summary: This knowledge of the extant condition of the Unit 2 RSG tube bundles, together with the OA projections (and uncertainties and differences in these) of the future wear rates at the proposed 70% RTP level, enable me to consider the no significant hazard consideration.

8 No SIGNIFICANT HAZARD CONSIDERATION (NSHC)8.1 Previously I have considered the 1OCFR §50.92 criteria requirement that the proposed OL amendment would not 1) involve a significant increase in the probability or consequences of an accident previously evaluated; or 2) create the possibility of a new or different kind of accident from any accident previously evaluated; or 3) involve a significant reduction in a margin of safety.8.2 1 should note here that the 'hazard' of the NSHC is a composite of the risk or probability of radiological release coupled to the ensuring radiation dose exposure to the most critical individual

-the risk of release must be acceptable and the radiological consequences tolerable.

8.3 A SG tube rupture (SGTR) incident is a penetration of the barrier between the reactor cooling circuit (RCS) and the main steam system (steamside).

The integrity of this barrier is significant from the standpoint of radiological safety in that a leaking steam generator tube would allow for 32 The OAs generally commence investigation and analysis of the tube wear on the basis that fluid elastic instability (FEI) is active in the U-bend region of the tube bundle but there is little comment on why FEI is present and, particularly, why the flow regime results in the in-plane activity.33 Whereas the OAs commissioned by SCE broadly agree that the wear mechanics comprises two phases, there are strong differences over the cause of the first phase comprising in-platte AVB wear: AREVA claim this is caused by in-plane FEI whereas, the contrary, Mitsubishi (and Westinghouse) favor random perturbations in the fluid flow regime to be the tube motion excitation cause. Put simply, if AREVA is correct then reducing the reactor power to 70% will eliminate FEI, AVB effectiveness will cease to decline further and TTW will be arrested; however, to the contrary, or if Mitsubishi is right then, even at the 70% power level, the AVB restraint effectiveness will continue to decline thereby freeing up longer free-span tube sections that are more susceptible to TTW- or that the assertion of neither party is wholly or partly correct.

the transfer of radioactive reactor coolant into the steamside.

Radioactivity contained in the reactor coolant would mix with water in the shell side of the affected steam generator and then transported by steam to the turbine and then to the condenser or directly to the condenser via the steam dump bypass system. Non-condensable radioactive gases in the condenser would be removed by the main condenser evacuation system and discharged to the plant vent stack and, hence, a radiological discharge to the environment.

8.4 A single tube SGTR is classified as a limiting fault. The radiological consequences for this design basis case (both with and without a pre-existing or accident induced iodine spike) is given in the UFSAR wherein the predicted radiological doses are compared to the NRC Standard Review Plan Acceptance Criteria.8.5 1) No Significant Increase in Probability/Consequence

-Previously Evaluated Accident 8.5.1 The previously identified accident 3 4 of immediate concern here is the failure of a single tube in the steam generator tube bundle thereby permitting the radioactive primary circuit to bypass the nuclear island containment via the normally isolated the steamside (turbine) circuit.3 5 8.5.2 Maintaining integrity of the barrier between the reactor coolant circuit (RCS) and the RSG steamside is significant from a radiological standpoint since a leaking steam generator tube would result in migration of radioactive reactor coolant into the steamside.

3 6 8.5.3 The driving force, so to speak, for single tube failure is the differential pressure acting across the tube wall at the operating temperature.

Operating at the proposed 70% RTP will not result in any significant change in the tube differential pressure and the peak tube wall temperature, so 34 Here 'accident' refers to postulated design basis accidents, including the internal and external events with which the plant must be able to cope (e.g., earthquake, flooding, turbine missiles, and fire) as described in the updated final safety analysis report (UFSAR).35 See Operating License Technical Specification Docket N" 50-361, NPF-10 San Onofre Improved Technical Specification 50-361 -B)pass is defined (1.1-4 a3) as the reactor coolant system (RCS) LEAKAGE through a steam generator to the secondary system (primary to secondary LEAKAGE) -tube failure is covered by the Steam Generator Program of the TS and relates to maintaining tube integrity (5.0-13/14

-5.5.2.11) for both normal steady state full power (for which a revision to 70% RTP is required) and in account of additional loading conditions induced during the occurrence of design basis accidents and combination of accidents, with tube integrity defined in terms of pressure differentials, leakage rates, and tube wall flaw and/or thinning depth at or exceeding 35% of the nominal wall thickness, with tube integrity assured until the next SG tube inspection (5.0-15 -5.5.2.1 Id).36 Radioactivity of the reactor coolant would mix with.steamside water in the affected steam generator and, during normal plant operations, some of this radioactivity would be transported through the turbine to the condenser where the radioactive materials would be released via the condenser air ejectors.

Since the nuclear plant continues to operate for 15 or so minutes before the increasing levels of radioactivity initiates a trip, there arises an accumulation of radioactivity that is then dumped unfiltered to atmosphere by lifting of the steam generator safety valves.

the tubes will be subject to the much same forces (radial stress) and tube material strength response (ie the yield stress weighted in account of temperature) as experienced at 100% RTP.3 7 8.5.4 Similarly, the tube bundle gross displacement (so called flowering')

will induce some elements of bending and shear stresses but these also would not be expected to radically depart from conditions at 100% RTP operation.

8-5.5 In other words, reducing the power level for 100% to 70% RTP will not reduce the pressure and temperature environment acting within and across the tube wall. In this important respect, the forces driving tube failure do not change (ie are not reduced) and remain essentially independent of the proposed reduction in RTP.8.5.6 On the other side of the tube integrity equation is the nature and extent of the tube wear degradation at the TTW, AVB- and TSP-to-tube locations.

I have described the uncertainties relating to the extent and nature of the tube wear (so far as it is available to me)3 8 at the AVB-to-tube locations in SECrION 6- 1 would expect similar uncertainties to apply to the TSP and TTW locations.

8.5.7 1 should also note here that reducing to 70% RTP will not necessarily result in a lessening of the radiological consequences in the event of a failure of the fission product boundary represented by the RSG tube surface area. The radiological consequences in the public (off-site) domain are dominated by the radioactive inventory of the reactor cooling circuit water, which varies over time and which, under reactor fault conditions, could include high levels of fission products released from damaged or melted fuel, in combination which other factors and circumstances, such as atmospheric stability, energy of the release, and so on.8.5.8 On this basis I am able to respond directly to SCE's 1OCFR §50.92 response: 3 9 8.5.9 SCE claim that 8-5.10 "... The proposed change to reduce the power level will not affect the probability of any accident initiators because the only effect on plant operations is to lower the allowable power level.." 37 Other than small pressure variations as a result of power transients, the RCS steady state operating pressure will be at the pressurizer setpoint pressure which for 70% RTP would not be expected to significantly change from 100% RTP setpoint.38 As noted in SEctioN 6. SCE and its consultants are unlikely to have that much greater detailed knowledge of the surface damage.39 NRC. Applhialion c Anewndma,, i,, I-acilit v Opx.:iting License Prol)osed No Shlnificw#It Hazurd" Cotzidehftiorn i)eten7nillatinn; San Onofre Nuclear Generating Station. Unit 2 -Notice by the Nuclear Regulatory Commission on 04/16/2013.

8.5.11 Presented in this way, the SCE claim implies that the proposed reduction in power level will be accompanied by a reduction in the forces driving tube failure. This is incorrect, because the tube failure driving forces remain sensibility the same at 70% RTP as at 100% RTP.8.5.12 As previously noted (¶14) both the AREVA and Intertek OAs 2 2 23 acknowledge that the RSG tubing will continue to degrade even with the plant operating at 70% RTP. Each of these OAs justifies the Unit 2 plant restart on the basis that the tube inspection will occur (at 150 days into Cycle 17) before the tube resilience has ventured into the unacceptable failure regime of 95%probability (the 0.05 threshold of FIGURES 1 and 2).8.5.13 It follows that (¶7.24) Unit 2 operation into Cycle 17 will incur further and progressive degradation of the RSG tubes with this degradation being accompanied by an increasing probability of tube failure.8.5.14 In terms of the TS, the probability of tube failure becomes significant once that the threshold of 95% probability has been passed. However, each of the consultants relied upon by SCE projects significantly different periods of time to reach and pass this safety threshold (as different as 0.5 and 1.35 year) which, essentially, shows that the underlying data and/or methodology of the predictions is fundamentally flawed.8.5.15 So, on the basis of such uncertainty and unreliability, little assurance can be placed with SCE's confidence that its Cycle 17 inspection period of 150 days (,-0.4 year) will pass without encountering a significant increase in the risk of tube failure.8.5.16 This rationale applies to both the structural integrity performance criteria (SIPC) and the accident induced leakage performance criteria (AILPC),4° although it is worthwhile noting that in a separate assessment of the Unit 3 TTW and TSP wear profiles, AREVA identified a number of tube wear modes, wall thickness wear depths and specific locations that failed AILPC 4 1 with a pop-through' failure mode.4 2 40 AILPC events are: Loss of Coolant Accident LOCA (RSG tube crushing mode)Main Steam Line Break MSLB Feedwater Line Break FWLB Inadvertent Safety Valve Dump ISVD Safe Shutdown Earthquake SSE The design basis to consider a coincident event involving either the LOCA, MSLB or FWLB with a SSE 41 Attachment 3: AREVA Docanment 51-9180143-(X)1

-SONGS Unit 3 Februarv 2012 Letker Outage Steam Generator Condition Monitoring Report. AREVA October I 2012.

8.5.17 For normal operation, the radiological consequences previously referred to in ¶8.4 would, all things being equal, remain much the same for each separate single tube burst event.Should a tube burst be provoked by some internal event in the nuclear plant, for example a loss of coolant accident (LOCA) or main steam line break (MSLB), then in certain circumstances and if the fuel core was damaged by the triggering event, then the radiological consequences arising from a single tube burst could be severe.8.5.18 In Summary: In my opinion, in its NSHC analysis SCE has not taken due account of all of the uncertainties relating to i) the nature and severity of the tube degradation extant; ii)the reliability of the predictions of the period for further AVB restraint and TSP deterioration leading to TTW in order to set the first Cycle 17 inspection period (150 days); and, more generally, iii) the premise that the tube failure is predictable is unreliable because of the uniqueness ofthe tube wear in the AVB, TSP and TTW modes.8.5.19 For these reasons I cannot agree with SCE that there will be no significant increase in the probability of a previously evaluated accident, namely a single tube burst under both SIPC and AILPC situations.

8.6 Create

the Possibility of a New or Different Kind of Accident 8.6.1 SCE claim that 8.6.2 ... The proposed changes do not adversely qffect the nethod 01 operation qf the steam generators nor introduce any changes to existing design functions of systems, structures or components that could create the possibility of a new or different kind (?faccident from am, previously evaluated.

Also, the proposed change will not introduce an'y significant changes to postulated accidents resulting from potential tube degradation.

Because SONGS Unit 2 will operate at or below 70% Rated Thermal Power. the change will continue to ensure that tube integrity is demonstrated over the range of power levels at which the plant will operate. Therefore, there is no significant increase in. tnhe probability that the tubes will,0ail or leak during the period..." my added emphmsis 8.6.3 Relating to 'continuing tube integrity', as I have previously noted (18.5.3) that at 70% RTP the driving force of tube bursting remains sensibly unchanged (determined by the pressurizer 42 SCE does not seem to have applied this Unit 3 finding to setting a limitation on the acceptable tube wall thickness wear for the Unit 2 restart on the basis of AILPC alone which, for TSP and TTW modes of wear, will equally apply in Unit 2 during an MSLB design basis event.

setpoint pressure) so the only outcome of reducing power is, according to the Intertek and AREVA OAs, to slow the rate of AVB slackening and, once triggered, the rate of 'ITW.8.6.4 1 have noted previously, however, the Intertek and AREVA projections for the timing of each leg of the 2-stage process are at such variance that neither can be considered reliable.8.6.5 On 'changes to existing design functions of systems, structures or components', the original design functionality of the AVB was that the contact force or 'preload' acting between tube and AV bar would be absolutely minimal because the 'zero tube-to-bar gap' geometry.

As previously discussed

(¶7.12), the AVB installations in Unit 2 did not comply with this design prerequisite because of a manufacturing omission that resulted in, quite fortuitously, various levels of preload acting in the in-plane direction

-this unintended preload served beneficially in Unit 3 to delay the onset of the second stage of tube wear or TTW.8.6.6 Clearly, returning Unit 2 to service and, particularly, the time offset afforded by the unplanned presence of the AVB preload is a change in the designfimnction.

8.6.7 Moreover, there is great uncertainty as to which of the many thousands of AVB-to-tube locations there is an active preload force and, where it is active, the magnitude of the preload depends on the extent of a dimensional distortion that was never recorded at the time of manufacture of the individual AV bar.8.6.8 First, this gives rise to uncertainty about the proposed restart performance of Unit 2 -for example, how long before the preload force at each AVB-to-tube contact point will remain effective, if there will arise a sequence of loss of preload over a number of adjacent and successive AVB contact points on any one individual tube, 4 3 and so on -all of which places considerable doubt of the reliability of the Intertek and AREVA projection periods for AVB-to-tube slackening and the onset of TTW (¶7.25).8.6.9 Second, since the preload force was unintentional and not considered in the original AVB-to-tube design it would not have been subject to the design approval and verification process which would have taken in account not just the immediate AVB functionality but, also, the extended flinctionalities and how these aspects of the AVB interacts with and impinges upon 43 The loss of successive AVB restrain lengthens the tube free span length making the tube vulnerable to lower frequency and higher amplitude motion.

other functions (and hence safety) of the overall steam generator assembly, both in part and as a whole.8.6.10 To my knowledge, this expedient adoption of and reliance upon the unintended role of the AVBs -at those undefined AVB contact points where a preload does exist -has not been thoroughly thought through and, hence, its inclusion has not been justified by the Design Authority, be this SCE and/or MHI.8.6.11 The extendedfilictionalities of the AVBs apply in both SIPC and AILPC senses,' with the latter involving a Safe Shutdown Earthquake (SSE) coincidence event during and following which the RSG tubes and AVB assemblies would all be subject to material stresses in addition to the acting pressure differential (primary membrane) stresses in each tube wall .44 8.6.12 Multiple Tube Failure: 4 5 SCE should have undertaken further analysis on the possibility of a multiple tube failure which would, in terms of off-site radiological consequences, greatly exceed the design basis accident of a single tube burst.8.6.13 There are a number of situations with potential for a multiple tube failure that should have been evaluated by SCE, including:

8.6.14 AVB BREAK UP: The MHI photograph alongside

¶6.3.9 shows a situation where a Unit 3 tube has abraded and worn away a significant part of the AV bar. Although it is not possible to distinguish between tube wall and AV bar wear depths, it is obvious from the photograph that the AV bar wear greatly exceeds the tube wall thickness

-on this basis, the AV bar wear depth is about 40% of the original bar thickness.

44 Additional (mechanical stress) RSG tube loading from an SSE event (ie a horizontal shaking mode) would be expected to be at a maximum in the free-span tube sections in the top region of the U-bend of the tube bundle -ineffective AVB support would further heighten these SSE generated stresses -induced SSE tube loading is highest at the top of the U-bend.The principal RSG tube loading during a LOCA is generated by the rarefaction wave initiated in the primary at the break location.

This wave travels through the primary circuit and will generate a differential pressure across the hot and cold legs of the U-bend, resulting in in-plane movement that gives rise to significant bending stress across the U-bend tube sections and large in-plane reaction forces at the top TSP locations.

The RSG tubing and AVBs may also be subject to shaking loads caused by the LOCA break hydrodynamics and reactor coolant circuit motion.MSLB, FWLB and ISVD events introduce secondary bending stresses in the lower portions of the RSG tube bundle. For the MSLB event very high, two-phase fluid cross-flow velocities would be expected to instantaneously develop in the U-bend region, triggering vigorous FEI that could, particularly if the AVB restraints are ineffective, promote violent tube to tube clashing and the potential for a multiple tube failure event.45 Rupture of a single tube is the design basis event. A multiple tube rupture would be a very much more hazardous event because reactor coolant water could be expelled rapidly through the ruptured tubes, resulting in water inventory for the emergencycore cooling system being depleted followed by fuel core meltdown.

8.6.15 The tubes are arranged in a dense triangular grillage so in-plane motion of two or more tubes in adjacent rows could result in deep wear simultaneously occurring on opposite sides of the AV bar, and/or any in-plane tube motion could extend the AV bar wear into an extended crescent substantially weakening the AV bar in its cross section. Conceivably, the upshot of this situation would be a section of the AV bar detaching and acting adversely on a number of tubes in or nearby its original location in the tube bundle.8.6.16 There are a number of situations that could challenge and possibly physically detach sections of such a worn down AVB, including seismically induced loading on the tube bundle, the immediate aftermath of a LOCA,46 and, quite possibly, the dynamic fluid forces triggered by a MSLB. 4 8.6.17 The presence of such a large unrestrained object within the tube bundle could impose a threat to a number of tubes. Hence, SCE should have included in the NSHC for the possibility of a worn down section of AV bar detaching under SSE, LOCA and MSLB fault event conditions, leading to a multiple tube failure.8.6.18 PLUGGED AND IN SERVICE TUBE FAILURE AND BREAK UP: It is possible that both pressurized and plugged tubes could fail locally and dislodge shrapnel into the tube bundle, thereby providing opportunity for multiple in-service tube failure.8.6.19 There are a number of mechanisms for this, including:

8.6.20 a) In a situation where the degraded tube surface is heavily scored and/or includes one or more notched stress raisers -see the diagram of ¶6.3.7 -this type of degradation scar can be generated on both in-service, pressurized and plugged tubes,48 leading to a pressure driven brittle failure of one or more tubes.46 The principal RSG tube loading during a LOCA is generated by the rarefaction wave initiated in the primary at the break location.

This wave travels through the primary circuit and will generate a differential pressure across the hot and cold legs of the U-bend, resulting in in-plane movement that gives rise to significant bending stress across the U-bend tube sections and large in-plane reaction forces at the top TSP locations.

The RSG tubing may also be subject to shaking loads caused by the LOCA break hydrodynamics and reactor coolant circuit motion.47 For the MSLB event very high, two-phase fluid cross-flow velocities would be expected to instantaneously develop in the U-bend region, triggering vigorous FEI that could, particularly if the AVB restraints are ineffective, promote violent tube to tube clashing and the potential for multiple tube failure.48 Plugging a tube does not remove it from the risk of it being excited into motion by fluid forces and/or by impact from an adjacent tube or tubes and, of course, a faulty plug may enable an individual plugged tube to become pressurized but with near zero flow through it.

8.6.21 UFSAR (S5.4.2.31.3) considers integrity of a degraded tube with wall thinning at TTW, AVB and TSP locations for SIPC and AILPC cases. The analysis, although not presented in detail in the UFSAR, arrives at the stresses in the degraded tube cross section by weighting the stresses in the non-degraded tube by the ratio of the corresponding sectional properties of nominal and degraded tubes.8.6.22 This comparative approach, as it is described in the UFSAR, omits to give any regard to the tube surface damage and flaws that I have described in 16.2.1, T6.3.1 and ¶6.3.5 -if surface scarring and notching was taken into account (weighting via k,), particularly for the AVB Dig-hi case, then it is possible then the allowable stress limit of 74.3ksi would exceeded .49 8.6.23 b) I assume that in its NSHC SCE has considered the possibility of tube failure via in-plane high cycle vibration mode -if it has done so then it may have relied upon the previous MHI analysis.s° 8.6.24 Where a tube is pinched at a particular location (say at the top TSP), displaced laterally from its zero load state (such as in flowering) thus inducing bending and shear stresses, its excitation into oscillatory motion (vibration) renders it subject to i) high cycle plain fatigue and some element of the separate phenomenon ii) fretting fatigue. A similar combination of plain and fretting fatigue can also occur at the AVB-to-tube contact point, particularly at the Dig-In locations where there is AVB-to-tube contact force and high inter-surface (Coulomb) friction exists.8.6.25 Both in-service and plugged, cable stabilized tubes could also be vulnerable to this combined i) and ii) mode of fatigue failure with the resulting shrapnel, or the severed tube itself, resulting in high rates of wear and possible multiple failure of nearby in-service tubes.8.6.26 Failure of a plugged tube and associated wear damage of two adjacent in-service tubes at TMI-1 in October 2001, suggests that high cycle plain fatigue can run its course to failure 49 The AVB degraded tube locality represents the worst case where the degradation length is assumed to be equal to the average tube-to-AVB contact length, the minimum wall thickness is 0.01526 inch. Therefore, the degraded tube minimum wall thickness is conservatively taken as 0.01923 inch, which corresponds to 55.17% tube wall thinning for 0.0419 inch nominal wall thickness.

50 Enclosure 3, Part 2 AllI Document L5-04GA564 Tube Wear of Unit-3 RSG- Technical Evahlation Report Appendix-16 Fatigue Evaluation of the Tube due to In-Plane Vibration MHI Proprietary Class B within a single fuel cycle and, although there was surface fretting evident, the post-event analysis did not consider a fretting fatigue contribution to the tube failure.5 1 8.6.27 The MHI analysis5° that SCE probably relies upon contains proprietary information that I am obliged not to reveal in a public document such as this declaration.

8.6.28 That said, I consider the in-plane fatigue model adopted by MHI to have a number of shortcomings, particularly in that the TSP restraint should be clamped and not freely pinned and that the derivation and final selection of the stress concentration factor kt is somewhat conservative.

Also, it is not clear to me that MHI has given any regard to the quite possible contribution of fretting fatigue at the TSP location where some TSP-to-tube sliding motion would have occurred -as I have previously noted (¶6.10) the combination of plain and fretting fatigue can result in a substantial reduction of component life, that is bringing on unexpected early bursting of the tube.8.6.29 In ¶6.3.5 1 refer to the notch-like flaw caused by what I term to be AVB Dig In which develops a radial notch-like flaw in the tube. This provides a weakness for brittle failure in the out-of-plane direction in which the individual tubes and, indeed, sections of the tube bundle, are susceptible to excitation by fluid forces. Once again, because the interface between tube and the AV bar is hidden and cannot be reliably determined by through-wall ET, the determination of the stress concentration factor k, is very uncertain.

8.6.30 I believe that it would be prudent for SCE to review the MHI analysis of tube fatigue limit of 13.6ksi ,52 together the selection of the stress concentration factor kt and restraint conditions for both TSP and AVB Dig In cases, and in combination with this, if the possible contribution of fretting fatigue has been properly accounted for.8.6.31 I understand that another party is to provide more detailed expert opinion on this aspect of tube vulnerability to high cycle plain fatigue failure.8.6.32 SEISMIC LOADING: I have already commented on the possibility that seismically induced loading on the tube bundle could detach a worn through AV bar component

(¶8.6.16).

51 In October 2001 a plugged tube severed at TMI-I and inflicted wear on two adjacent tubes at such a high rates that the structural integrity of both tubes was challenged within one fuel cycle. The circumstances that apparently contributed to the severed tube included tube swelling and flow-induced vibration leading to high cycle fatigue failure -the SG at TMI-I was a once-through and not the recirculation type as at San Onofre.52 ksi -kilo pounds force per square inch.

8.6.33 Here I note my surprise that in answering the NSHC SCE has chosen not to explore, apparently neither generally nor in the detail that it merits, seismic loading of the overall tube bundle, taking into account the degraded and defective tubes and components (including both inactive and preloaded AVBs).8.6.34 Indeed, I am surprised that SCE has not been required to undertake a seismic response evaluation for the entire RSG assembly, particularly now that it has been established by the ASLB Hearing 5 3 that the CAL was in effect a de facto license amendment, meaning that the steam generator replacements at San Onofre were not like-for-like replacements and therefore should have qualified for the rigors of a full safety evaluation, including for response to seismic events.8.6.35 In Summary: In my opinion, in its NSHC analysis SCE has not considered that the extant condition (notching, fretting fatigue, etc) of the individual tubes, tube bundle and its restraint components could lead to new or different kinds of event.8.6.36 SCE's proposal to derate the plant to 70% RTP may 'not adversely affect the method of operation' but, on the other hand, the Cycle 16 operation resulted in substantial degradation and damage to the RSG tubes and restraint components, so much so, that the response of these components to normal and adverse operating conditions had not been accounted for in the original design case.8.6.37 Moreover, it has been acknowledged by SCE that the degree of twisting of certain of the Unit 2 AVBs resulted in an unintentional tube clamping preload force (see ¶7.12), with result that these AVBs do not comply with the original design intent.54 8.6.38 In these respects alone, SCE cannot rule out that new or different kinds of event will occur.53 Atomic Safety Licensing Board, In the Matter of Southern California Edison Co, Memorandum and Order, May 13 2013 54 In this situation, in pressing against the tube the AVB-to-tube contact surface, which must sense the vibration of the up- or downstream free span portion in the form of slight relative movement (or vibration of the AV bar itself), is likely to be conducive the fretting fatigue. Thereafter if and when the AVB preload is loosened (a process acknowledged by both Intertek and AREVA), then the total plain fatigue life of the same but now freely vibrating tube may have its endurance limit shortened by as much as 50 to 70% -see T6.10 -in this respect the NSHC should have included account for fretting and plain fatigues modes of tube failure.

8.7 Involve

a Significant Reduction in a Margin of Safety 8.7.1 The current regulatory practice (the TS) assumes a prescriptive approach under which tube plugging is required when certain conditions are met. The most notable of these is that degradation depth by any process cannot, in general, exceed 35% of the tubing wall thickness.

8.7.2 The 35% maximum wear was chosen to provide a factor x3AP safety margin against burst under operating conditions (SIPC) and xl.4AP against burst under postulated accident conditions (AILPC).8.7.3 The safety margin takes in a number of uncertainties, including allowances for ET and other in-tube measurement errors, flaw growth between inspections, temperature compensation, various processes that contribute to tube material and geometry degradation, and so on.8.7.4 When originally compiled the safety margin would have assumed that the RSG functionality was compliant with the design specification.

Generally, this means any detriment arising from a design omission or design shortcoming, such as the inadvertent introduction of AVB preload, would not have been included for in the safety margin.8.7.5 It follows that particular processes arising from such a omission or shortfall, in this case the occurrence of fretting fatigue at the AVB-to-tube contact point and its potential to substantially reduce the plain fatigue life of individual tubes, would also not have been include for in the safety margin.8.7.6 At San Onofre the proposed Cycle 17 operation will include for continuing degradation of the tubes, TSP and AVB restraint points, and it will do so on the basis of largely uncertain data and information about the detailed extant condition of the tubes, TSPs and AVBs -see FIGURES 1 and 2.8.7.7 Such intention to knowingly permit further erosion of the safety margin when it has to be acknowledged that the root cause and processes that have led to, and are continuing to degrade the tubing, are not fully understood nor can be reliably described in a quantitative way is, in my opinion, altogether unacceptable.

8.7.8 In summary: I consider that to permit the established safety margins to be reduced in ways and to an extent that cannot be precisely defined to be wholly unjustified and beyond the discipline of sound engineering design and practice.9 ASPECTS RELATING TO THE POTENTIAL RADIOLOGICAL CONSEQUENCES 9.1 In this declaration I have focused on the opportunity for tube failures due to the degraded or, more properly, defective condition of the tubes themselves and how this if sufficiently severe, such as a multiple tube failure, could lead to malfunction of the nuclear plant. Of course, it is quite feasible that failure of a few defective tubes could trigger a major nuclear plant malfunction that, in itself, provokes the bursting of more degraded or defective tubes creating a very significant radiological release via a primary containment bypass. Also, there is the possibility that a major plant malfunction, such as a MSLB, could rapidly result in failure of multiple tubes already weakened in a degraded or defective condition.

9.2 The radiological potential of the release is generally set by the rapidity of the events. Thus, a rapid or near simultaneous multiple tube failure in a single steam generator could overwhelm the reactor safety systems, for example by outstripping the capacity of the emergency core cooling system (ECCS), so much so that the uncovered fuel core would proceed to high temperature melt that would greatly add to the radiological inventory en-route via the SG containment bypass for release to atmosphere.

9.3 The point here is that, by whatever cause, failed steam generator tubing presents a direct and rapid route for the release of radioactivity to the atmosphere for onward dispersion and deposition in the public domain. Because the release route bypasses the primary containment, the impact on the public is virtually immediate,there being little or no time to prepare mitigation in the forms of prophylaxis, sheltering and evacuation countermeasures.

9.4 In other words, failure of a number of steam generator tubes in either or both of the Unit 2 steam generators, could result in a significant radiation dose uptake and onerous health detriment being borne by members of the public in the San Onofre region.10 CONCLUDING REMARKS 10.1 For my assessment of the NSHC I have been reliant upon the information and data provided by SCE and its consultants.

Much of this information and data continues to be heavily redacted and many reports are simply not available in the public domain.

10.2 Nevertheless, I am confident that even though I have relied upon elements of qualitative judgment my overall opinion is sound.10.3 1 note that SCE's NSHC omits to apportion proper regard to all of the uncertainties deriving from the extant and future degradation of the Unit 2 RSG tubing, particularly the surface flaws; it fails to address how and to what extent the thermal-hydraulic flow regimes will lessen the excitation forces acting across the tube bundles and whether these forces are generated by fluid elastic instability, which it claims will be largely eliminated by a reduction in RTP, or if tube motion is driven by random two-phase fluid processes which are likely to remain even at reduced RTP; and, it has yet to address the root cause of why the tube degradation processes were so vigorous in the design of the San Onofre RSGs.10.4 In these and other respects, I find SCE's NSHC evaluation insufficient in breadth and detail of examination, and lacking the substance that the all-important issue of nuclear safety merits.10.5 Each finding of SCE's NSHC tripartite evaluation is in error because, amongst other things: 10.5.1 (1) it fails to recognize that the degraded condition of the tubing and restraint components is such that there will arise a greater probability of single tube failure before the proposed 150 day tube inspection outage is reached;10.5.2 (2)10.5.3 (3)it assumes that the quite fortuitous change of design functionality of the AVB-to-tube restraint (ie the preload) will not carry forward with it detriment that fosters opportunity for different kinds of accident (ie break-up of the AV bar) leading to, for example, multiple tube failure and the knock-on events (not considered in the UFSAR) that could lead to a very significant radiological event in the public domain; and it plans to knowingly diminish the all-important tube integrity safety margin by operating Unit 2 under such conditions that are acknowledged to foster continuing tube degradation (wear) and add to existing levels of flaws (surface notches) and adverse processes (fretting and plain fatigue).10.6 In these and other crucial respects, the outcome of the SCE No Significant Hazard Consideration is incorrect and inappropriate.

10.7 Also, I am surprised that the SCE submission in this respect is so wanting in detail and depth. For such an important matter that bears heavily on public safety I would expect a very much more substantive consideration

-in my opinion, the SCE submission of the No Significant Hazard Consideration does not pass muster and would fail any reasonable Public Interest Test.10.8 Overall, I consider that in view of the extensive degradation of the San Onofre Unit 3 RSG, which I consider to be a portend of how further tube degradation would occur if Unit 2 was to resume operation then, like Unit 3, Unit 2 should not be considered fit-for-purpose for return to any level of nuclear power operation.

Moreover, my opinion is that such is the uncertainty about the condition of the two Unit 2 RSGs and how these individually or in combination would contribute to and/or respond to an adverse event (for example a MSLB) then, on nuclear safety grounds alone, Unit 2 should not be permitted to restart nuclear operation.

10.9 I John H Large declare, under penalty of perjury, that the foregoing information and facts are true and correct to the best of my knowledge and belief, and that the opinions expressed herein are based on my independent and best professional and personal judgment.JOHN H LARGE CONSULTING ENGINEER LkRG(E &A.%&)aA LONUO)N Mendiola, Doris From: Kristin Hines Gladd <gladdk@ayreslawgroup.com>

Sent: Friday, May 24, 2013 10:42 AM To: CHAIRMAN Resource; CMRSVINICKI Resource; CMRAPOSTOLAKIS Resource;CMRMAGWOOD Resource; CMROSTENDORFF Resource; OCAAMAIL Resource; Docket, Hearing; Doane, Margaret

Subject:

Third Attempt of Notice of FOE and NRDC Joint Motion to Consolidate LARs, Attachment 3 of 3 Attachments:

Part 3 of 3-FoE and NRDC Comments on Proposed NSHC Det for LAR 263.pdf Please find attached Attachment 3.Thank you, Kristin Hines Gladd Kristin Hines Gladd Associate Attorney Ayres Law Group 1707 L Street, N.W., Suite 850 Washington, DC 20036 Office: 202.452.9222 GladdK(2avreslawgroup.com

1.

ATTACHMENT 3 Declaration of Dr. Victor Gilinsky I UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE STAFF In the Matter of )) Docket ID NRC-2013-0070

)SOUTHERN CALIFORNIA EDISON CO. ))(San Onofre Nuclear Generating Station, )Units 2 and 3) ) May 16, 2013 DECLARATION OF VICTOR GILINSKY I, Victor Gilinsky, state: 1. This affidavit, on behalf of Friends of the Earth ("FOE"), presents my views on the proposed determination by the Staff of the Nuclear Regulatory Commission

("NRC") that "no significant hazards consideration" ("NSHC") is involved in approving a license amendment to permit San Onofre Unit 2 to operate at 70 percent power. The Unit's defective steam generators preclude operation at 100 percent power; the issue is whether it is safe to do so at 70 percent. Under the NRC's rules an NSHC determination would allow the NRC to deprive the public of an opportunity for a hearing on this question in advance of plant operation.

FOE seeks to participate in such a hearing and so opposes the NRC Staff's proposed determination.

My view in brief, on the basis of my NRC experience, is that the NRC Staff misreads its regulations, that an NSHC determination is not permissible in this instance, and that therefore a public hearing should take place before the NRC authorizes any restart of Unit 2.2. My professional qualifications and experience for dealing with the issues in this 2 case include an engineering degree and physics doctorate and two terms as an NRC commissioner.

I was nominated by President Ford and re-nominated by President Carter. After leaving the NRC in 1984 1 was principally involved as a consultant and expert witness in commercial and regulatory litigation over nuclear power plants. In one of the first such cases, in the late 1980s, I participated on behalf of Southern California Edison ("SCE") in its proceedings before the California Public Utilities Commission regarding the reasonableness of the construction costs for San Onofre Units 2 and 3. I subsequently participated in about twenty-five such major cases, in court trials, regulatory proceedings, and arbitrations.

From. 2001 to 2010 1 was a consultant to the State of Nevada, which intervened in the NRC licensing proceeding over the proposed national nuclear repository at Yucca Mountain.

A more detailed resume is attached to this affidavit as Exhibit 1.3. My tenure on the NRC covered the adoption of the so-called Sholly amendment to the Atomic Energy Act. The Sholly amendment underlies the NRC's regulations, 10 CFR 50.91 and 50.92, on approval of license amendments for power reactors.

The NRC sought this change in the law after the United States Court of Appeals for the District of Columbia Circuit held that the NRC could not make any power reactor licensing amendments, for which a hearing had been requested, immediately effective without a prior hearing. The NRC wanted to be able to deal simply and promptly with the many routine license amendments involving minor plant design changes of no or negligible safety significance, the replacement of a particular flow meter, for example, with a more accurate one.

3 4. In its 1986 analysis of a similar case to the one at hand, one involving changes to Diablo Canyon's spent fuel pool, the Ninth Circuit drew attention to the importance of the language in the Conference Committee Report accompanying the Sholly amendment, and specifically the Report's warning that the NRC Staff should not abuse the new authority.

The Report warned the NRC not to apply the new authority regarding license amendments in cases where the NRC Staff required extensive investigation to resolve a power plant safety issue to its satisfaction, and instructed the NRC to resolve "borderline" cases in favor of a prior hearing. San Luis Obispo Mothers for Peace v. US NRC, 799 F.2d 1268 (9th Cir. 1986)..5. In short, Congress permitted NSHC determinations in routine cases that obviously had no or essentially no safety significance, but not otherwise.

That is why the Sholly determination is not phrased as "no significant hazards," but as"no significant hazards consideration." The NSHC question is whether there is a safety issue, not whether the NRC Staff resolved the safety issue to its satisfaction.

6. As an NRC commissioner, I participated in a case that bears considerable similarity to the present one, and I then interpreted the law in the same way as I do now. In 1982 the owners of Three Mile Island Unit 1 sought to repair steam generator tubing using a new explosive technique.

The NRC Staff concluded that because the new technique involved unreviewed safety issues, a license amendment was necessary.

But when it came to restarting the plant the NRC Staff made an NSHC determination to allow restart in advance of a hearing.

4 7. In November 1983 Commissioner James Asselstine pointed out that the NRC staff made its determination after extensively analyzing the safety issue, but what the Sholly change to the law required was for "the Commission to determine whether the amendment presents any significant safety questions," not whether the NRC Staff was satisfied after its review. In January 1984, on the question of whether to concur with the NRC Staff, the Chairman and one commissioner voted to concur while Commissioner Asselstine and I opposed. In doing so I said I agreed with the NRC General Counsel's reading of the law, which was opposed to that of the Staff. NRC Public meeting Transcript, "Discussion/Possible Vote on TMI Steam Generators," January 10, 1984.8. Commissioner Asselstine also observed that if one accepted the NRC Staff's interpretation of the regulations on NSHC determinations, then the NRC would never have to offer the opportunity for a hearing before authorizing any license amendments.

Indeed, that is apparently the NRC Staff view. If there are any recent cases for which the Staff went along with a hearing in advance of authorizing an amendment, they are rare. Even a proposed 20 percent increase in a reactor's authorized power level-the maximum uprate approved to date and one that involved extensive safety analysis-merited an NRC Staff NSHC determination.

Vermont Yankee Final Determination, March 2, 2006. (To get a sense of how much NRC has changed: in publishing the NSHC rule two decades earlier, the NRC had given an authorized power level increase as an example that was "likely to involve significant hazards considerations." Cited in SECY-0 1-0142, July 27, 2001.)

5 9. In the current case, the NRC adopts the SCE's NSHC analysis without a word of explanation.

That analysis treats the issue as if SCE were proposing to down rate a plant with healthy steam generators.

It essentially argues that since the plant is licensed for 100 percent power, how can there be a problem in running it at 70 percent?10. The actual situation is rather different.

San Onofre has defective steam generators that pose a safety problem. That is why SCE cannot get NRC approval for 100 percent operation and proposes instead to operate at 70 percent power. Resolution of the safety issues involves subtle technical questions and complex analyses of the vibrational modes of the approximately 9,000 long thin steam generator tubes through which flows water heated by the reactor's core.(The Technical Evaluation Report on the issues by the steam generators' Japanese manufacturer, Mitsubishi Heavy Industries, runs to 142 pages.)11. SCE and NRC Staff failed to appreciate the safety significance of the technical issues when the replacement steam generators were designed.

The question now is whether they have finally gained a solid understanding of the safety issues and can confidently determine at what power level it is safe to operate. That is what the hearing needs to be about.12. Outside the hearing context the NRC acknowledges the seriousness of the San Onofre steam generator tube degradation:

that is of course why the Units are not operating, why the case is spotlighted on the NRC web page, and why the plant was put into the special NRC oversight category.13. In evaluating the NSHC determination it is important to understand the full 6 safety significance of a breach in the steam generators.

Although the NRC's safety doctrine stresses multiple barriers between the radioactive reactor core and the external environment, in fact, the steam generator tubing, about an acre of thin metal, less than 1/1 0 th of an inch thick, is the single sure barrier between the hot pressurized water flowing from the reactor core, and the outside environment.

On the steam side of the steam generator there are large safety valves that lift if the steam line pressure is too high. These valves sometimes stick open. If this were to happen during the course of a severe accident involving core melting accompanied by failure of many steam generator tubes, there would be no way to contain the radioactive release. The possibilities for such extreme accidents were not considered during the original licensing of US nuclear plants. But since the 2011 Fukushima accident it has become clear that the regulatory system has to take them into account.14. Fukushima also demonstrated that up to now the NRC has omitted in its analyses the most important consequences and costs of severe accidents.

The NRC has only counted the possible radiation doses that individuals might receive after an accident.

But we have learned from Fukushima that the most important consequences are the costs that attach to evacuation of large populations--the disruption to lives and communities and the essentially permanent loss of large land areas. So far as I can tell these costs are still not considered in any NRC license safety reviews.15. Under Section 50.92 of the NRC regulations, the NRC Staff deems a proposed amendment to involve "no significant hazards considerations" if it meets a three-7 part test: that the proposed amendment does not "(1) Involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety." In my opinion the proposed San Onofre Unit 2 amendment does not qualify for an NSHC determination under any of these three criteria in the sense that Congress intended for these to be interpreted.

16. The first thing to say about the application of 50.92 is that it requires calculations of accident probabilities.

The methodology the NRC Staff uses to do this, so-called probabilistic risk assessment, while useful for certain purposes, is not reliable for estimating overall accident probabilities.

The complex calculations involve many questionable assumptions about the interconnections of individual subsystems.

This puts any proposed amendment involving a hardware change that requires sophisticated technical safety analysis at least into the "borderline" category that Congress warned did not qualify for an NSHC determination.

17. Regarding (1), that the proposed amendment does not "involve a significant increase in the probability or consequences of an accident previously evaluated," it is clear that a current calculation of the consequences of an accident, including the previously omitted costs of large-scale evacuation, would show a significant increase in accident consequences from what was previously calculated.

18. Regarding (2), the original accident analyses conducted in connection with the plant's licensing examined the consequences of the failure of a very limited number of steam generator tubes. The flawed design of San Onofre's 8 replacement steam generators raised the possibility of failures beyond those previously analyzed during licensing.

That was NRC's concern and that is why it required SCE and its vendor to carry out sophisticated analyses of the vibrational modes of the steam generator tubing and the possibilities for inducing wear in the tube walls.19. Criterion (3) asks whether the amendment would permit a significant reduction in the previously approved margin of safety: We know the NRC Staff is concerned that operation of the plant at 100 percent power may significantly reduce the safety margin at that level. Whether that safety reduction is eliminated at 70 percent power is a complex question whose resolution involves technical analyses and professional judgment.20. To arrive at its answer the NRC had to require considerable effort on the part of the SCE, and to expend considerable effort itself, to reach into the merits of the issue. This makes this exactly the kind of case Congress warned the NRC about when it wrote (in the Sholly amendment Conference Committee Report, as cited by the Ninth Circuit's 1986 decision in San Luis Obispo Mothers for Peace) that the NSHC standard "should not require the NRC staff to prejudge the merits of the issues raised by the proposed license amendment." But that is exactly what the NRC Staff has done.21. In addition to the law, the public interest argues strongly for holding a hearing on a safety-significant amendment in advance of a licensing decision.

In my experience, the working level Staff reviewers are generally competent and responsible, but they are also under pressure to meet agency schedules.

They do 9 a much better job when they know they will have to defend the soundness of their technical conclusions before impartial judges in a public hearing on which a licensing decision depends. A hearing after the fact is a pale substitute.

22. The special circumstances of this case provide an additional reason for conducting a public hearing in advance of any licensing decision.

As mentioned earlier, the NRC Staff failed in its first chance to review adequately the steam generator design when SCE proposed replacing the original one with a different design. The NRC Staff is now in the position of judging the significance of that failure and how much can be recovered from the earlier mistakes.

It would be only human if this earlier experience affected the NRC Staff's objectivity.

In this situation it would be especially useful for the NRC Staff's conclusions to be tested before an impartial adjudicatory panel, and for that panel to hear the views of outside experts, before these conclusions are put into effect.23. In sum, in this case involving important safety issues regarding operating with defective steam generators, both the law and public interest call for an NRC hearing in advance of any decision about plant operation.

I declare, under penalty of perjury, that the foregoing information is true, accurate, and correct. Executed on May 14, 2013, in Los Angeles, CA.Vi ortilinsk-y RANDOLPH EDELMAN Commission

1. 186347201< ~ Notary PUblic -C alioinia zz My Cmm.ExpresSep 3,21 ACI(NO'WLEDGMENT State of California County of .-4&c A on /41 4 -e -/ -1, -- .Zt)21 before mneamand er (insert name and title of the officer)personally appeared I-" c. -t .--t 4', 6.t, who proved to me on. the basis of satisfactory evidence to be the name() is/'ae sUbscribed to.the within instrument and'acknowledged to me that helskUeInhay ekecuted the same in bjp/hert'h-eir authorized oapacity(ie*-

and that by h Ls/heth.eir sigra-"ture(s),on the instrument the person(-or the entity upon behalf of which the person(s).qcted, executed the instrument.

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.WITNESS my, hand and official seal.Signature RANDOLPH EDELIM'I- Commission

1. 1863472 t, Notary Pubi~c -Calirornia zz Los Angeles County om.Expires Sep 30, 201J3 (Seal)K ~OPTIONAL IINFORMATION DECROI2'TJON OF THE- ATTAC-1-D DODCUMBNT (T itm w r dworiiiab bf -i~he d nawn=nt Mim)of Pags DO-.=-int Date r- ' / V 1 (hde, Idona ~fWmuron)

VICTOR GILINSKY 369 Sumac Lane, Santa Monica, CA 90402, USA +1 310 459 0233 victor@gilinsky.com Professional Activities:

1984-present Independent consultant to energy firms and governmental, commercial, and non-profit organizations, primarily on matters related to nuclear energy 1975-1984 Commissioner U.S. Nuclear Regulatory Commission Washington, DC 1973-1975 Head, Physical Sciences Department, and Director, Applied Science and Technology Program The Rand Corporation Santa Monica, CA 1972-1973 Assistant Director for Policy and Program Review, Office of Planning and Analysis U.S. Atomic Energy Commission Washington, DC 1961-1971 Physicist The Rand Corporation Education:

Ph.D., Physics, California Institute of Technology, 1961 Bach. Engineering Physics, Cornell University, 1956 Awards: California Institute of Technology Distinguished Alumni Award, 1982 Member: American Physical Society Institute of Electrical and Electronics Engineers ATTACHMENT 4 Declaration of Arnold Gundersen (in Support of the June 18, 2012 Petition to Intervene by Friends of the Earth Regarding the Ongoing Failure of the Steam Generators at the San Onofre Nuclear Generating Station)

Docket No. 50-361 and 50-362 FRIENDS OF THE EARTH EXHIBIT ONE UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION In the matter of) May 31, 2012 Southern California Edison Company ) Docket No. 50-361 and 50-362)San Onofre Nuclear Generating Station )DECLARATION OF ARNOLD GUNDERSEN SUPPORTING THE PETITION TO INTERVENE BY FRIENDS OF THE EARTH REGARDING THE ONGOING FAILURE OF THE STEAM GENERATORS AT THE SAN ONOFRE NUCLEAR GENERATING STATION 1, Arnold Gundersen, declare under penalty of perjury under the laws of the United States of America that the following is true and correct, and executed this 31st day of May 2012: 1.- My name is Arnold Gundersen.

I am sui juris. I am over the age of 18-years-old.

2. As Chief Engineer for Fairewinds Associates, I have been retained by Friends of the Earth to provide expert services in connection with the above captioned matter regarding the ongoing failure and deterioration of the steam generators at San Onofre Nuclear Generating Station.3. I earned my Bachelor Degree in Nuclear Engineering from Rensselaer Polytechnic Institute (RPI) cum laude. I earned my Master Degree in Nuclear Engineering from RPI via an Atomic Energy Commission Fellowship.

Cooling tower operation and cooling tower plume theory were my area of study for my Master Degree in Nuclear Engineering.

Page 2 of 17 4. 1 began my career as a reactor operator and instructor in 1971 and progressed to the position of Senior Vice President for a nuclear licensee prior to becoming a nuclear engineering consultant and expert witness. My Curriculum Vitae is attached as Exhibit 2.5. I have testified before the Nuclear Regulatory Commission (NRC) Atomic Safety and Licensing Board (ASLB) and Advisory Committee on Reactor Safeguards (ACRS), the State of Vermont Public Service Board, the State of Vermont Environmental Court, the Florida Public Service Commission, the State of New York Department of Environmental Conservation, and in Federal Court.6. 1 am an author of the first edition of the Department of Energy (DOE) Decommissioning Handbook, and the book entitled Fukushima Dahichi." The Truth And The Way Forward, Shueisha Publishing, 2012-2-17, Japan.7. I have more than 40-years of professional nuclear experience including and not limited to: Cooling Tower Operation, Cooling Tower Plumes, Consumptive Water Loss, Nuclear Plant Operation, Nuclear Management, Nuclear Safety Assessments, Reliability Engineering, In-service Inspection, Criticality Analysis, Licensing, Engineering Management, Thermohydraulics, Radioactive Waste Processes, Decommissioning, Waste Disposal, Structural Engineering Assessments, Nuclear Fuel Rack Design and Manufacturing, Nuclear Equipment Design and Manufacturing, Prudency Defense, Employee Awareness Programs, Public Relations, Contract Administration, Technical Patents, Archival Storage and Document Control, Source Term Reconstruction, Dose Assessment, Whistleblower Protection, and NRC Regulations and Enforcement.

8. I have personal knowledge of the facts contained in this Declaration; and I am qualified to testify in support of this Petition.

I have previously testified to the Advisory Committee on Reactor Safeguards and the NRC's 2.206 Petition Review Board.OVERVIEW AND SCOPE OF THE PROCEEDING

9. My declaration is intended to support Friends of the Earth's Petition Concerning the Steam Generators at San Onofre Nuclear Generating Station.

Page 3 of 17 SAN ONOFRE NUCLEAR REACTOR BACKGROUND

10. Originally designed and built by Combustion Engineering (CE), San Onofre's nuclear steam generators are a very unique design that is radically different from all other Pressurized Water Reactor (PWR) designs. Southern California Edison (Edison) decided to replace each San Onofre steam generator due to tube deterioration and degradation that slowly evolved during each Unit's 25-years of operation.

11. Documents reviewed show that the four replacement steam generator specifications are identical to each other and they were purchased together under a single contract with Mitsubishi Heavy Industries (MHI). However, rather than simply rebuild the steam generators to their original design specifications, Edison decided to extensively modify the original San Onofre steam generator design. Furthermore, none of the design modifications were necessary for operation of either San Onofre Unit 2 or 3.ISSUES OF REACTORS 12. It now appears that after new Steam Generators were installed at San Onofre Unit 2 and Unit 3, the new tubes began to seriously degrade very quickly. Technicians first detected the unanticipated problems of significant wear in the tubes during the Unit 2 refueling outage in January 2012.13. The wear-rate for these steam generator tubes is extraordinary because tube thickness has been reduced by as much as 30 percent in less than two years. While Unit 2 was shutdown for refueling, San Onofre Unit 3 was operating at full power when it experienced a complete perforation of one steam generator tube that allowed highly radioactive water from inside the reactor to mix with the non-radioactive water that turns the turbine.14. As a consequence, an uncontrolled release of radiation into the environment ensued, and San Onofre Unit 3 was also forced to shut down due to steam generator failure.

Page 4 of 17 RISKS POSED 15. The San Onofre reactors have significant problems because their newly installed steam generators have extensive degradation and are unable to perform their design function of containing the radioactive water in the facility.

Steam generator tube degradation, like that which San Onofre is experiencing, causes a significant nuclear safety risk by substantially increasing the likelihood of an accident that releases radioactivity into the environment.

16. Unfortunately, a leak or disintegration of one or more tubes would cause the radioactive water to escape the containment.

Because there is a 1,000-pound-per-square-inch (psi)pressure difference between the high-pressure radioactive side of the tubes and the lower pressure steam that then leaves the containment, a leak will inevitably release radioactivity to the environment.

17. Gross failure of one or more of the steam generator tubes could create a nuclear design basis accident and cause the nuclear reactor core to lose a portion of its cooling water. However, the unique concern of degraded steam generator tubes is that uncontrolled radiation releases from a tube break do not remain inside the containment building and instead leak out of the facility and into public areas via atmospheric dump valves and steam generator blowdown.18. If a steam line break accident were to occur, the depressurization of the steam generator caused by the steam line break coupled with the lack of water at the top of the steam generators would cause cascading tube failures, involving hundreds of tubes. The cascading tube failures would pop like popcorn and cause excessive offsite radiation exposures.

CASCADING DESIGN CHANGES AS BASIC CAUSE 19. A cascading series of deliberate design changes likely caused the tube failures and tube degradation.

20. The key fabrication change supplanted to the San Onofre steam generators by the Edison/MHL team increased the total number of tubes in each steam generator by almost 400 Page 5 of 17 tubes to more than 104 percent of each generator's original design. Each Original Steam Generator contained 9350 tubes while the Replacement Steam Generators each contain 9727 tubes.21. Fairewinds believes it was this management decision to increase the number of tubes that lead in turn to a series of cascading design changes that created the serious problems San Onofre is experiencing in 2012.22. The original San Onofre steam generator contained a tubesheet, which is a metal disc approximately 13-feet in diameter and slightly less than two feet thick, located near the bottom of the steam generator.

Due to the already extremely large size of the CE steam generators, this tubesheet is one of the largest tubesheets ever fabricated after which 18,700 holes (9,350 in-hot/9,350 out-cold) were then drilled. This metallic disk serves as an anchor into which both sides of the U-tubes are inserted.

Not only is the tubesheet extraordinarily heavy, but also there can be a pressure difference of approximately 2,000 pounds per square inch (psi) between the radioactive water on one side and non-radioactive water on the other.23. In order to support the enormous tubesheet metallic disk, the original steam generator design at San Onofre contained a 'stay cylinder' in the center of the tubesheet that is a support pillar designed to relieve the weight in the middle of the tubesheet.

23.1. When Edison decided to cram in additional steam generator tubes, the fabrication technique created by Edison!MHl for the San Onofre steam generators necessitated the removal of the 'stay cylinder' so that more tube holes could be drilled through the tubesheet.

The Edison/MHI decision to add additional tubes and replace this key support pillar was part of the cascading fabrication changes that caused additional stresses and steam generator failure.23.2. Removing the stay cylinder required additional cascading fabrication changes.Because the tubesheet was no longer supported in the center by the stay cylinder, Edison/MHI required the fabrication of a thicker tubesheet so that it could bear the additional stress without a stay cylinder.

This change in the tubesheet thickness meant Page 6 of 17 yet another design change by reducing the volume of water in the steam generator and changing the flow pattern and also reducing the inspection access area beneath the tubesheet that is required to fit personnel and equipment for tube inspection.

23.3. Changing the structural loads on the tubesheet have not only affected the reliability of the steam generators but also should have raised a serious safety concern because the tubesheet is the key barrier keeping radiation inside the containment.

Should the tubesheet fail, radiation within the reactor would bypass the containment and pass directly into the environment.

Due to the installation of the 'stay cylinder' in the original San Onofre steam generator configuration, a tubesheet failure and subsequent radiation release is considered to be beyond the calculations for a design basis accident at San Onofre. Yet Edison chose to challenge this critical safety barrier and licensing parameter by removing the "stay cylinder" in order to install more, unnecessary tubes.23.4. Fabricating more tubes increased nuclear reactor core flow, which was unacceptable because it changed the original design basis safety calculations for cooling the reactor.For that reason Edison welded a flow-restricting ring into the steam generator nozzle in order to reduce the flow of cooling water back into the reactor to the original design parameters, which also changes the flow distribution to the tubes. Thus significant operational changes were also made to the radioactive side of the steam generator as a result of Edison's addition of more steam generator tubes.23.5. All of these changes necessitated even more fabrication changes within the steam generator.

For example, more tubes meant that the tube supports had to be modified in an attempt to avoid the increased vibration caused by the flow changes induced by the Edison/MHI fabrication changes. The feedwater distribution ring inside the steam generator was also dramatically modified in order to avoid a serious flow induced water hammer.

Page 7 of 17 SIGNIFICANCE OF DESIGN MODIFICATIONS ON SAFETY 24. The requirements for the process by which nuclear power plant operators and licensees may make changes to their facilities and procedures as delineated in the safety analysis report and without prior NRC approval are limited by specific regulations detailed in The Nuclear Regulatory Commission's 10 CFR Part 50, Domestic Licensing of Production and Utilization Facilities, Section 50.59, Changes, Tests and Experiments.

25. The implementing procedures for the 10 CFR 50.59 regulations have eight criteria that are important for nuclear power plant safety. (These eight criteria are provided in Table 1, footnote A below.)26. These implementing procedures created for 10 CFR. 50.59 require that the license be amended unless none of these eight criteria are triggered by any change made by Edison at San Onofre. If a single criterion is met, then the regulation requires that the licensee pursue a license amendment process.27. By claiming that the steam generator replacements were a like-for-like design and fabrication, Edison avoided the more rigorous license amendment process. From the evidence reviewed, it appears that the NRC accepted Edison's statement and documents without further independent analysis.

In the analysis detailed below, Fairewinds identified 39 separate safety issues that failed to meet the NRC 50.59 criteria.

Any one of these 39 separate safety issues should have triggered the license amendment review process by which the NRC would have been notified of the proposed significant design and fabrication changes.28. As the NRC guidelines state: "(c)(l) A licensee may make changes in the facility as described in the final safety analysis report (as updated), make changes in the procedures as described in the final safety analysis report (as 1 .187-A- I updated), and conduct tests or experiments not described in the final safety analysis report (as updated) without obtaining a license amendment pursuant to § 50.90 only if: (i)A change to the technical specifications Page 8 of 17 incorporated in the license is not required, and (ii) The change, test, or experiment does not meet any of the criteria in paragraph (c)(2) of this section."'

[Emphasis Added]29. In its previous reports, Fairewinds identified at least eight modifications to the original steam generators at San Onofre.30. Table 1 below was designed to compare the eight major design modifications that Fairewinds identified in its analysis with the eight criteria the NRC applies to the license review process in order to determine whether or not a new license amendment process is required.3 1. The major design changes are located at the top of the table, and the NRC Criteria are listed in the left hand column of table. The term SSC stands for Systems, Structures and Components.

A green No means that the like-for-like criteria were, indeed met and that no license amendment was required.

A red Yes means that Edison should have applied for a license amendment.

32. Table I shows that 7 out of 8 of the major design changes to the original steam generators meet a total of 39 of the NRC's 50.59 criteria requiring amendment to the license.See, 1.187-A-1, ttp://pbadupws.nrc.gov/docs/ML0037/ML00375971 O.pdf Page 9 of 17 Table 1 Changes Identified By Fairewinds Steam Generator Design Steam Generator Design Compared With The NRC's Like-For-Like Criteria 50:59 (B) Remove Change Tube alloy Add tubes Change Add flow Additional Feed water Criteria stay tube sheet change tube restrictor water distribution (A) cylinder support volume ring i- Accident Yes (1) Yes (1) No Yes (3,4) Yes (3,4,8) No No No Frequency Increase ii -Increase Yes (I) Yes (I) No Yes (3,4) Yes (3,4,8) No No No in SSC Malfunction occurrence iii -Accident Yes (1) Y"s (1) No Yes (3,4) Yes (3,4,8) Yes (2) Yes (2,5,6) No consequent increase iv -Increase Yes (I) Yes (1) No Yes (3,4) Yes (3,4,8) Yes (2) Yes (2,.5,6) No in SSC consequence of malfunction v -Create Yes (I) Yes (I) No No N o Yes (2) Yes (2,5,6) Yes (3,7,8)unanalysed accident vi -Create Yes (1) Yes (1) No No Yes (3,8) Yes (2) No Yes (3,7,8)new malfunction vii -Alter Yes (1) Yes (1) No Yes (3) No No No No fission product barrier viii -Change Yes (2) Yes (2) No Yes (2) Yes (2,8) Yes (2) Yes (2,5,6) No design basis evaluation method Table Footnotes A -The criteria listed in the left column in the table above refers to the criteria as laid out in the NRC Guidelines-2 which states as follows: "(2) A licensee shall obtain a license amendment pursuant to § 50.90 prior to implementing a proposed change, test, or experiment if the change, test, or experiment would: (i) Result in more than a minimal increase in the frequency of occurrence of an accident previously evaluated in the final safety analysis report (as updated);(ii) Result in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety previously evaluated in the final safety analysis report (as updated);(iii) Result in more than a minimal increase in the consequences of an accident previously evaluated in the final safety analysis report (as updated);(iv)Result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the final safety analysis report (as updated);2 See, 1.187-A- 1, ibid, ttp://pbadupws.nrc.gov/docs/ML0037/ML0O37597 I 0.pdf Page 10 of 17 (v) Create a possibility for an accident of a different type than any previously evaluated in the final safety analysis report (as updated);(vi) Create a possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the final safety analysis report (as updated);(vii) Result in a design basis limit for a fission product barrier as described in the FSAR (as updated)being exceeded or altered; or (viii) Result in a departure from a method of evaluation described in the FSAR (as updated) used in establishing the design bases or in the safety analyses." B -The horizontal axis contains a list of design changes made by Edison and whether they meet or have not met the criteria as set out in 10 CFR 50.59.1 -The Steam Generator Replacement Project modified the tube sheets and stay cylinder that are a containment barrier -The NRC was not informed nor did it specifically approve these changes to the containment barrier as they were apparently not addressed under Edison's analysis for the 10 CFR 50.59 process;2 -The Mitsubishi thermo hydraulic code is inadequate to assess flow inside the Steam Generators that dramatically affect the ability to cool the nuclear reactor core in the event of an accident;3 -The Steam Generator Replacement Project increases the consequences of a steam line break accident;4 -The Steam Generator Replacement Project has already proven to increase the frequency of tube failure;5 -The Steam Generator Replacement Project changed the volume of primary coolant because more tubes were added, which changes the Final Safety Analysis Report;6 -The Steam Generator Replacement Project changed the flow rate of primary coolant, which changes the Final Safety Analysis Report;7 -The Steam Generator Replacement Project changed the potential for water hammer. Given that the Mitsubishi thermo hydraulic code is inadequate, the potential for water hammer is increased; 8 -The Steam Generator Replacement Project created steam binding at top of steam generator.

The steam generator is designed to remove heat in the event of an accident and its role has been compromised.

The Actual Steam Generator Problem Causing Vibration 33. As water moves vertically up in a steam generator, the water content reduces as more steam is created. When the volume of steam is much greater than water then the flow resistance of the water/steam mixture passing through the tube supports accounts for one third of the total resistance at the top of the steam generator.

Therefore to avoid vibration at the top of the tubes, Mitsubishi needed to specifically analyze the type of tube support to use in this unique application.

34. The flow resistance of the Mitsubishi broached plate is much higher than that of the original Combustion Engineering egg crate design because the tubes are so tightly packed in the original CE San Onofre steam generators.

By reviewing the documents thus far produced, it appears that due to Mitsubishi's fabrication experience with broached plates, both Edison and Mitsubishi missed this key difference in the design and fabrication of the new San Onofre steam generators.

Page II of 17 35. Not only is Mitsubishi unfamiliar with the tightly packed CE design, but also Edison's engineers created so many untested variables to the new fabrication that this new design had a significantly increased risk of failure. As a result of the very tight pitch to diameter ratios used in the original CE steam generators, Mitsubishi fabricated a broached plate design that allows almost no water to reach the top of the steam generator.

36. The maximum quality of the water/steam mixture at the top of the steam generator in the U-Bend region should be approximately 40 to 50 percent, i.e. half water and half steam. With the Mitsubishi design the top of the U-tubes are almost dry in some regions.3 Without liquid in the mixture, there is no damping against vibration, and therefore a severe fluid-elastic instability developed.

37. In response to the Edison/Mitsubishi steam generator changes, the top of the new steam generator is starved for water therefore making tube vibration inevitable.

Furthermore, the problem appears to be exacerbated by Mitsubishi's three-dimensional thermal-hydraulic analysis determining how the steam and water mix at the top of the tubes that has been benchmarked against the Westinghouse but not the Combustion Engineering design.38. The real problem in the replacement steam generators at San Onofre is that too much steam and too little water is causing the tubes to vibrate violently in the U-bend region. The tubes are quickly wearing themselves thin enough to completely fail pressure tests. Even if the new tubes are actively not leaking or have not ruptured, the tubes in the Mitsubishi fabrication are at risk of bursting in a main steam line accident scenario and spewing radiation into the air.RAMIFICATIONS OF AN INADEQUATE NRC REVIEW 39. Edison's strategic goal was to avoid the process of license amendment according to the January 2012 article in Nuclear Engineering International NEI Magazine.4 Had Edison 3 With the Mitsubishi design the top of the U-tubes are almost dry in some regions. Fairewinds research and four independent industry experts., who wish to remain anonymous, substantiate this statement.

4 Improving Like-For-Like Replacement Steam Generators by Boguslaw Olech of Southern California Edison and Page 12 of 17 notified the NRC that the new steam generators at San Onofre were not a like-for-like replacement, a more thorough review through the license amendment process would have been required.

Given that scenario, it is likely that the requisite and thorough NRC review would have identified the design and fabrication inadequacies that appear to have caused the San Onofre steam generator tube failures.40. More specifically, Fairewinds believes that the NRC would have identified the inadequacy of the Mitsubishi Heavy Industry computer code applied to validate the tube design and vibration pattern prior to fabrication.

Mitsubishi's computer code was simply not capable of analyzing Combustion Engineering (CE) designs like San Onofre and was only qualified for Westinghouse designs that are not similar to the original CE steam generator design. In NRC licensing jargon, the Mitsubishi design codes were not benchmarked for the CE Design.41. While Mitsubishi Heavy Industry has been supplying steam generators for many years in Japan, it did so under a specific license from Westinghouse for Westinghouse nuclear reactors.

Although Mitsubishi made several incremental changes to the Westinghouse design, such as switching to alloy 690 tubing and the use of stainless steel broached plate tube supports, Mitsubishi has had very little experience with the tight tube pitch and the egg crate design used in the original CE design for San Onofre.REPAIR 42. San Onofre engineers should have precise maps detailing the degraded and leaking tubes as well as the exact location of the leak(s) on each tube. Such data is just one piece of critical information required in conducting athorough root cause analysis of the problem and determining an accurate solution.

Edison claims that the proximate cause of these U-tube failures at San Onofre is high vibration, and it has embarked upon a process of plugging some of these damaged tubes in hopes of quickly restarting one or both units. Fairewinds Tomouki Inoue of Mitsubishi Heavy Industries, Nuclear Engineering International, January 2012, page 39. This article was based on a paper published at ICAPP 2011, 2-5 May 2011, Nice, France, paper 11330. Boguslaw Olech, P.E., Southern California Edison Company, 14300 Mesa Rd., San Clemente, CA 92674, USA, Email: bob.olech@sce.com.

Tomoyuki lnoue, Mitsubishi Heavy Industries Ltd. (MHt), 1-1 Wadasaki-cho 1-Chome, HyogoKu, Kobe, Japan 652 8585, Email: tomoyukiJnoue@mhi.co.jp.

Page 13 of 17 believes that this damage is occurring on the outside of the tubes where they collide with each other, while access to the tubes for repair and/or plugging can only be conducted from inside the tubes. Space limitations due to the tight fit of the 9,700 tubes (19,400 holes in the tube sheet) in each steam generator have made it impossible to access the outside of the U-tubes for inspection where the wear is actually occurring.

43. Presently, the Edison approach is to plug tubes in the most heavily damaged zone of each steam generator.

Plugging the tubes only eliminates the radioactive water inside the tubes, but it does not eliminate the vibration, so the plugged tubes will continue to vibrate and damage adjacent tubes.44. If a steam line break accident were to occur, the depressurization of the steam generator caused by the steam line break coupled with the lack of water at the top of the steam generators would cause cascading tube failures, involving hundreds of tubes. The cascading tube failures would pop like popcorn and the cascading failures would cause excessive offsite radiation exposures.

45. Fairewinds investigation has found that plugging the tubes is not a sure solution, because it fails to deal with the root causes of a failed design and it relies upon the incorrectly applied Mitsubishi 3-Dimensional steam analysis to determine which tubes should be plugged.Realistically, the 3-D steam analysis is not accurate enough to apply to such important safety-related determinations.

To make such mathematical risk 3-D analysis, a very large margin of error must be applied, and that has not been done. For example, if the 3-D steam analysis determines that plugging 100 tubes is a solution, then plugging ten times that number might be the appropriate solution due to the mathematical errors in the 3-D analysis being applied by Edison and Mitsubishi.

46. Fairewinds concludes that plugging the tubes will never solve the underlying problem because vibration is the result not the root cause of the steam generator problems at San Onofre. The actual problem is a variety of design changes that have caused too much steam and too little water at the top of the steam generators.

Plugging tubes cannot repair these design changes that are causing the tubes to collide with each other.

Page 14 of 17 OPTIONS FOR CONTINUED OPERATION 47. Complete Replacement

-The ongoing plugging of the tubes will not eliminate the vibrational failure mechanism causing tube failures.

Over time, the damaged tubes that are plugged will in turn damage more tubes. Therefore, Fairewinds believes that the only sure solution to this significant safety issue is to once again cut open the reactor containment and install new steam generators that replicate the original CE design.48. Repair In Place -While technically this would be an extremely challenging repair process, it may be possible to cut the steam generators apart while still inside the containment.

Such a process would take approximately 18 months to make repairs and then weld the steam generators back together again without cutting the containment open. Cutting the top off the steam generators would allow construction personnel access so that additional supports could be inserted into the U-tube region. Smaller replacement packages would fit through the existing equipment hatch and the containment would not be compromised another time. The cost for these repairs would be less than completely redesigning and manufacturing new steam generators and replacement power costs would be less.49. Power Reduction

-Reducing power does not provide a remedy for the underlying structural problems that are creating the vibration that has damaged and will continue to damage tubes deep inside the San Onofre steam generator.

Edison has suggested that plugging tubes and operating at indeterminate reduced power levels for the remainder of the life of the plant may be a solution to the San Onofre tube vibration problem.50. Unfortunately this course of action would leave San Onofre operating with a significant safety risk if the NRC were to allow the reactors to restart.51. Operating at reduced power will not prevent previously damaged tube supports and plugged tubes from vibrating and damaging surrounding tubes and tube supports, and it will worsen the existing damage.52. More importantly, Fairewinds concern is that operating the San Onofre reactors at a lower power and flow rate might actually create a resonant frequency within the steam generators at Page 15 of 17 which some of the tubes will vibrate as bad or worse than they did originally.

Because the plugged tubes are now filled with air their weight has changed, and therefore the plugged tubes will vibrate with a different amplitude and frequency.

The inaccuracies in the Edison and Mitsubishi computer code do not allow Edison and Mitsubishi to conduct a resonant frequency analysis proving that such a problem will not occur.53. Historical evidence from other operating nuclear reactors that have attempted to mitigate vibrational damage by using power reductions rather than solving the resonant frequency issues have in fact compromised other nuclear safety related components by operating at reduced power.53.1. In 2002 the Exelon Quad Cities Nuclear Power Plant in Illinois operated its Unit 2 reactor at reduced power in order to eliminate vibrationally induced damage causing high moisture carryover in its steam dryer. While the power reduction temporarily reduced moisture carryover, the problem reoccurred and a shutdown was ordered causing an extended unplanned outage. Vibrationally induced severe cracking was discovered in the steam dryer and repaired.

Following an analysis and subsequent repairs, Exelon claimed to have rectified the Quad Cities Unit 2 problems only to be forced in 2003 to once again attempt operation at a reduced power level when vibrationally induced steam dryer moisture carryover became excessive.

Following this second attempt to operate the reactor at a reduced power level, pieces of the dryer as large as a man broke off and damaged nuclear power safety related components, and a second unplanned extended outage ensued. Once again, vibration was determined to be the cause of the gross failure and another unplanned and forced outage. Finally, following years of analysis and two damaged steam dryers, Quad Cities made major piping modifications that are alleged to have eliminated harmonic frequencies, prevented further component damage, and allowed Unit 2 to eventually return to full power production.

5 53.2. A second example of a failed attempt to reduce power to solve vibrationally induced resonance frequency problems occurred at the Susquehanna nuclear plant in 5 http://pbadupws.nrc.gov/docs/ML0609/ML060960338.pdf Page 16 of 17 Pennsylvania.

During the mid 1990s, a vibrationally induced failure in the jet pump sensing lines occurred at Susquehanna.

This failure was attributed to the vane passing frequency from the recirculation pumps causing harmonic vibration of the lines. Like Quad Cities, Susquehanna attempted to implement a power reduction in order to minimize the harmonic vibrations.

Unfortunately, the resonant vibration issues continued to damage systems after the power was reduced thereby forcing an unplanned outage and extensive modifications and repairs.CONCLUSION

54. In conclusion, the NRC has stated that nuclear power plants like San Onofre cannot risk compromising critical safety systems and possible radiological contamination in an effort to return to operation before a thorough root cause analysis, modifications, and subsequent repairs are adequately reviewed by the NRC and implemented.

Historical evidence has proven that power reductions do not solve underlying and serious degradation problems, resonance frequency issues. Rather, power reductions can significantly increase the risk of unplanned, forced outages during times of peak demand and can cause significant risk to public health in the event of a single tube rupture or a series of ruptures if the main steam line were to break.55. Finally, if a steam-line accident were to occur, vibrationally induced tube damage at San Onofre could cause an inordinate amount of radioactivity to be released outside of the containment system compromising public health and safety in one of the most heavily populated areas in the entire United States.-End-Page 17 of 17 I declare that under penalty of perjury that the foregoing is true and correct to the best of my knowledge.

The facts presented in this declaration are true and correct to the best of my knowledge, and the opinions expressed are based on my best professional judgment.Executed in Accord with 10 CFR 2.304 (d) and 2.326 (b), (Electronically signed)Arnold Gundersen, MENE, RO Fairewinds Associates, Inc Burlington, Vermont 05408 Tel: (802) 865 9955 Email: arnie@sailcharnplain.net Date: May 31, 2012.. ... .. .. .Arnol'd G

..

1'2 ATTACHMENT 5 MHI Root Cause Analysis and Supplemental Technical Evaluation Report (Selected Excerpts) 0 UNITED STATES NUCLEAR REGULATORY COMMISSION REGION IV 1600 EAST LAIAR BLVD ARLINGTON, TEXAS 76011-4511 March 6, 2013 Edmund Baumgartner, Esquire Corporate Counsel Mitsubishi Nuclear Energy Systems, Inc.1001 1 9th Street North Suite 2000 Arlington, VA 22209

SUBJECT:

MITSUBISHI HEAVY INDUSTRIES

-REQUEST FOR WITHHOLDING ROOT CAUSE ANALYSIS AND SUPPLEMENTAL TECHNICAL EVALUATION REPORT INFORMATION FROM PUBLIC DISCLOSURE

Dear Mr. Baumgartner:

In a February 14, 2013, letter to you, the NRC requested Mitsubishi Heavy Industries (MHI) to provide the MHI document "Root Cause Analysis Report for tube wear identified in the Unit 2 and Unit 3 Steam Generators of San Onofre Nuclear Generating Station," and a redacted version of that document.

You provided the requested documents in a letter (ML13057A012) dated February 25, 2013, and requested that certain information contained within the root cause analysis (RCA) and a supplemental technical evaluation report (STER), provided as a supplement to the RCA, be withheld from public disclosure pursuant to 10 CFR 2.390.Redacted versions of the RCA and STER documents were provided as Enclosures 4 and 6 of your letter, respectively (ML13057A013 and ML13057A014).

Mitsubishi Heavy Industries stated in affidavits dated February 22, 2013, that it considered certain information within MHI's RCA and STER to be proprietary and confidential and requested that the information be withheld from public disclosure pursuant to 10 CFR 2.390. A summary of the key points in the affidavits is as follows: 1. The information has been held in confidence by MHI.2. The information describes unique design, manufacturing, experimental, and investigative information developed by MHI and not used in the exact form by any of MHI's competitors.

3. The information was developed at significant cost to MHI.4. The RCA is MHI's organizational and programmatic root cause analysis, which is a sensitive, internal document of the type that MHI and others in the industry do not make public, because its purpose is to set forth a critical self-appraisal, with the benefit of hindsight, containing information and analyses that are the result of candid assessments performed by MHI.5. MHI provided the information to the NRC voluntarily in confidence.

Mr. Edmund Baumgartner 6. The information is not available in public sources and could not be gathered readily from other publicly available information.

7. Disclosure of the information would assist competitors of MHI in their design and manufacture of nuclear plant components without incurring the costs or risks associated with the design and manufacture of the subject component.

We have carefully reviewed your original redacted documents and the information contained in your request. Additionally, we held several discussions with you regarding the redacted information in your documents.

Based on these discussions, MHI made some revisions to release additional information.

Subsequently, MHI provided final revised versions of Enclosures 4 and 6 via e-mail on February 28 and March 6, 2013, respectively.

We have concluded that the submitted information sought to be withheld in the final revised versions contains proprietary and confidential information.

Therefore, the final revised versions of the submitted information marked as proprietary will be withheld from public disclosure pursuant to 10 C.F.R. 2.390(a)(4).

Withholding from public inspection shall not affect the right, if any, of persons properly and directly concerned to inspect the documents.

If the need arises, we may send copies of this information to our consultants working in this area. We will, of course, ensure that the consultants have signed the appropriate agreements for handling proprietary information.

If the basis for withholding this information from public inspection should change in the future such that the information could then be made available for public inspection, you should promptly notify the NRC. You also should understand that the NRC may have cause to review this determination in the future if, for example, the scope of a Freedom of Information Act request includes your information.

In all review situations, if the NRC makes a determination adverse to the above, you will be notified in advance of any public disclosure.

Sincerely, IRA!Ryan E. Lantz, Chief SONGS Project Branch Dockets: 50-361, 50-362 Licenses:

NPF-10, NPF-15

Enclosures:

MHI's Revised Non-Proprietary RCA and STER Mr. Edmund Baumgartner Internal Distribution A. Howell, TM J. Andersen, DTM R. Lantz, C:SPB G. Werner, I&AL N. Taylor, SPE B. Parks, PE G. George, SRI J. Reynoso, RI K. Fuller, RC V. Dricks, PAO T. Rothschild, OGC R. Hall, NRR D. Broaddus, NRR E. Roach, NRO D. Dorman, NRR D. Merzke, OEDO J. Weil, OCA A. Powell, OCA R:\_REACTORS\_SONGS\2013\Review of MHI and STER MNES 2-25-13 LetterAgreement with Revised NonProp Reviews G:\ORA\SPB\MHI Letter and RCA and STER Enclosures ML13065A097 ADAMS: E] No 9 Yes 9 SUNSI Review Complete Reviewer Initials:

GEW*l Publicly Available ED Non-Sensitive El Non-publicly Available El Sensitive RIV:I&AL:SPB RC C:SPB __"_"_.. .....GEWerner;dlf KDFuller RELantz_IRA/ IRA! IRA/3/6/13 3/6/13 3/6/13 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax UES-20120254Rev.0 (1/64) Non-Proprietart San Onofre Nuclear Generating Station, Unit 2 & 3 REPLACEMENT STEAM GENERATORS Root Cause Analysis Report for tube wear identified in the Unit 2 and Unit 3 Steam Generators of San Onofre Nuclear Generating Station Purchase Order No. 4500024051 Specification No.S023-617-01 R3 ORDER No. DATE PURCHASER QUALITY ASSURANCE DEPARTMENT ITEM No. REFERENCE Edison 2593015 -APPROVED BY CHECKED BY (MNES) 7000 -PREPARED BY DRAWN BY ISSUE DATE CO Cl).20C1)O ~0 ~ C/) 0 0 0 0~ z cn z cn z 0 UP n-E 8 C ZZ Document No.UES-20120254 Rev. No.0=-+, -~-- + -Cl) 'i) I --I ..-111111111 1 1 II I I e 1e 2 MITSUBISHI HEAVY INDUSTRIES, LTD.

UES-20120254Rev.O (2/64) INon-Proprietary Revision History Date Approved Checked Prepared Rev. Summary of Changes issued By by by 0 Original Issue See See See See Cover Page Cover Page Cover Page Cover Page UES-20120254 Rev.O (3/64) INon-Proprietar Root Cause Analysis Report for tube wear identified in the Unit 2 and Unit 3 Steam Generators of San Onofre Nuclear Generating Station I~i Jb~;II; IýIj Root Cause Analysis Report for tube wear identified in the Unit 2 and Unit 3 Steam Generators of San Onofre Nuclear Generating Station (Attachment-3 UES-20120254 Rev.0 (47/64) Non-Proprietar Change analysis For the SONGS RSGs, a change analysis was performed in two stages. The first stage compared the SONGS SG design to previous MHI SG designs for the triangular tube configuration.

MHI had previously performed three steam generator designs using a triangular tube configuration.

The second stage compared the SONGS RSGs to the previous SONGS SG design (Combustion Engineering type design). Only the most significant changes are included in this analysis.The change analysis results are set out below.(1) Differences between SONGS RSGs and previous MHI SG triangular design.--The SONGS RSGs have:* ( )circulation ratio* ( )maximum flow velocity[ ( )average flow velocity[ ] P/D ratio out-of-plane FEI stability ratio Largest U bundle radius Specified AVB twist( )II )* ( )range of G-value (tube diameter, out-of-plane)

Highest steam quality (void fraction)* Thinnest and longest retainer bar* ( ) nominal tube-to-AVB gap (0.002" cold / 0.000" hot)* ( ) variation in tube-to-AVB gap (3 sigma((2) Differences between SONGS RSGs and the previous SONGS OSG design. --Increase in tube bundle heat transfer surface area (11%)* Increase in number of tubes (5%)Root Cause Analysis Report for tube wear identified in the Unit 2 and Unit 3 Steam Generators of San Onofre Nuclear Generating Station (Attachment-3 UES-20120254 Rev.0 (48/64) Non-Proprietar

• Removal of stay cylinder Change from lattice bars to trefoil broached tube support plates* Change in tube support configuration in U region* Change from CE to MHI moisture separators

• Power level / operating temperature

/ tube plugging margin (3) Identification of the changes from previous SG designs led to the recognition that the RSG design deserved close scrutiny.

MHI considered the changes in the SONGS design from previous steam generator designs and compared the basic design parameters of the SONGs RSGs (e.g., heat transfer area, circulation ratio, steam pressure, etc.) with other steam generator designs. Further, as part of the development of the SONGS RSG design, MHI conducted a detailed comparison between its proposed AVB support for the tubes in the U-bend region and that of a comparison plant of similar design. A special AVB team was formed and included industry experts to conduct an extensive design review process in 2005 / 2006 to optimize the U-bend design and address the technical issues. The team concluded that the SONGS design was significantly more conservative than previous designs in addressing U-bend tube vibration and wear.Also MHI and SCE recognized that the SONGS RSG steam quality (void fraction) was high and MHI performed feasibility studies of different methods to decrease it.Several design adjustments were made to reduce the steam quality (void fraction)but the effects were small. Design measures to reduce the steam quality (void fraction) by a greater amount were considered, but these changes had unacceptable consequences and MHI and SCE agreed not to implement them. It was concluded that the final design was optimal based on the overall RSG design requirements and constraints.

These included physical and other constraints on the RSG design in order to assure compliance with the provisions of 10 C.F.R. §50.59.Thus, MHI did compare the SONGs RSG design with previous steam generator designs, and in particular did a detailed evaluation of different options of the AVB design taking into account other large steam generator designs.Root Cause Analysis Report for tube wear identified in the Unit 2 and Unit 3 Steam Generators of San Onofre Nuclear Generating Station ATTACHMENT 6 Southern California Edison Co. (San Onofre Nuclear Generating Station, Units 2 and 3), LBP-13-07 (May 13, 2013) ("ASLB Order")

LBP-13-07 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges: E. Roy Hawkens, Chairman Dr. Anthony J. Baratta Dr. Gary S. Arnold In the Matter of Docket Nos. 50-361-CAL, 50-362-CAL SOUTHERN CALIFORNIA EDISON CO.ASLBP No. 13-924-01-CAL-BDO1 (San Onofre Nuclear Generating Station, Units 2 and 3)May 13, 2013 MEMORANDUM AND ORDER (Resolving Issues Referred by the Commission in CLI-12-20)

In its November 8, 2012 decision in CLI-12-20, the Commission referred to the Atomic Safety and Licensing Board Panel (ASLBP) a portion of the June 18, 2012 hearing request filed by Friends of the Earth (Petitioner) challenging aspects of a Confirmatory Action Letter (CAL)issued by the NRC to Southern California Edison Company (SCE) on March 27, 2012.1 In particular, the Commission directed a duly constituted Licensing Board to "consider whether: (1) the [CAL] issued to SCE constitutes a de facto license amendment that would be subject to a hearing opportunity under [s]ection 189a [of the Atomic Energy Act (AEA)]; and, if so, (2) whether the petition meets the standing and contention admissibility requirements of 10 C.F.R. § 2.309." CLI-12-20, 76 NRC at _ (slip op. at 5).For the reasons discussed below, we resolve the first issue in the affirmative, concluding that this CAL process constitutes a de facto license amendment proceeding that is subject to a hearing opportunity.

Because this resolution provides Petitioner with all the relief its contention 1 See Southern Cal. Edison Co. (San Onofre Nuclear Generating Station, Units 2 and 3), CLI-12-20, 76 NRC _, _ (slip op. at 5) (Nov. 8, 2012).

2 seeks, the second issue referred by the Commission is moot, and the proceeding before this Board is therefore terminated.

I. FACTUAL AND PROCEDURAL BACKGROUND A. Factual Back-ground The San Onofre Nuclear Generating Station (SONGS) is located near San Clemente, California.

2 SONGS Units 2 and 3 are pressurized water nuclear reactors with two steam generators per unit.3 SCE is the licensee for SONGS Units 2 and 3. See Brabec Aff. at 3-4.SCE's steam generators are recirculating, vertical U-tube type heat exchangers in which primary coolant is circulated inside the tubes, with heat from the primary-side coolant transferred to the secondary-side feedwater that circulates outside the tubes. This converts the feedwater into saturated steam that is used to drive a turbine-generator to create electricity.

See Brabec Aff. at 4.Steam generator tubes serve critical safety functions.

For example, they are an integral part of the reactor coolant pressure boundary and thus are essential for maintaining primary system pressure and coolant inventory.

They also isolate the radioactive fission products in the primary coolant from the secondary system.4 In September 2009, SCE shut down Unit 2 for a scheduled refueling outage and the replacement of its steam generators to resolve corrosion and other degradation issues in the original steam generators, which had been in service for nearly thirty years.5 SCE completed 2 See [SCE's] Brief on Issues Referred by the Commission (Jan. 30, 2013) at 3[hereinafter SCE's Answering Brief].3 See id., Att. 1, Affidavit of Richard Brabec (Jan. 30, 2013) at 3-4 [hereinafter Brabec Aff.]. SONGS Unit 1 ceased operation in 1992 and has since been decommissioned.

See SCE's Answering Brief at 3.4 See SCE's Answering Brief, Att. 8 [SONGS] Unit 2 Return to Service Report (Oct. 3, 2012) at 14 [hereinafter Unit 2 Return to Service Report].5 See Brabec Aff. at 4; Unit 2 Return to Service Report at 10, 17; Letter from Ryan E.Lantz, Chief, Project Branch D, Division of Reactor Projects, US NRC, to Ross T. Ridenoure, 3 the Unit 2 refueling and steam generator replacement outage in April 2010, and that unit returned to full power in May 2010.6 In October 2010, SCE shut down Unit 3 for a scheduled refueling outage and the replacement of its steam generators, which also had been in service for nearly thirty years. In February 2011, SCE completed the Unit 3 refueling and steam generator replacement outage, and that unit returned to full power in March 2011.8 The replacement steam generators for Units 2 and 3, which were manufactured by Mitsubishi Heavy Industries (MHI) (see Brabec Aff. at 4), differ in design from the original steam generators.

9 For example, each replacement steam generator (1) has 9,727 tubes, which is 377 Senior Vice President and Chief Nuclear Officer, SCE, NRC's [SONGS] -Unit 2 Steam Generator Replacement Project Inspection Report 05000361/2009007 (Mar. 4, 2010), Enclosure at 5 (ADAMS Accession No. ML100630838).

6 See Letter from Ryan E. Lantz, Chief, Project Branch D, Division of Reactor Projects, US NRC, to Ross T. Ridenoure, Senior Vice President and Chief Nuclear Officer, SCE, NRC's[SONGS] -Unit 2 Steam Generator Replacement Project Inspection Report 05000361/20010008 (June 30, 2010), Enclosure at 3 (ADAMS Accession No. ML101810506).

7 See Letter from Ryan E. Lantz, Chief, Project Branch D, Division of Reactor Projects, US NRC, to Peter Dietrich, Senior Vice President and Chief Nuclear Officer, SCE, NRC's [SONGS]-NRC Integrated Inspection Report 05000361/2010005 and 05000362/2010005 (Feb. 10, 2011), Enclosure at 7 (ADAMS Accession No. ML1 10420223).

8 See Letter from Ryan E. Lantz, Chief, Project Branch D, Division of Reactor Projects, US NRC, to Peter Dietrich, Senior Vice President and Chief Nuclear Officer, SCE, NRC's [SONGS]-Unit 3 Steam Generator Replacement Project Inspection Report No. 05000362/2010009 (May 10, 2011), Enclosure at 3 (ADAMS Accession No. ML1 11300448).

9 See SCE's Answering Brief, Att. 31, NRC Augmented Inspection Team [AIT] Report (July 18, 2012) at 36 [hereinafter July 18 AIT Report]; see also Opening Brief of Petitioner Friends of the Earth (Jan. 11, 2013) at 1, 3 [hereinafter Petitioner's Opening Brief]; Petitioner's Opening Brief, Att. 3, Far Outside the Norm: The San Onofre Nuclear Plant's Generator Problems in the Context of the National Experience with Replacement Steam Generators at 4[hereinafter Hirsch Report]; Petition to Intervene and Request for Hearing by Friends of the Earth (June 18, 2012), Exh. 1, Declaration of Arnold Gundersen Supporting the Petition to Intervene by Friends of the Earth Regarding the Ongoing Failure of the Steam Generators at[SONGS] at 3 [hereinafter May 31 Gundersen Decl.].SCE urges this Board to discount the Hirsch Report attached to Petitioner's Opening Brief because, in alleged disregard of the directive in this Board's December 7 Order, Petitioner"did not provide an affidavit to support the factual assertions in the Hirsch Report, which are 4 more tubes than are in the original; (2) does not have a stay cylinder supporting the tube sheet;and (3) has a broached tube design rather than an "egg crate" tube support.1 0 As discussed infra Part ll.B.2, a licensee must obtain a license amendment from the NRC if a change to its facility triggers the safety standards described in 10 C.F.R. § 50.59.Despite the design differences mentioned above between the replacement and original steam generators, SCE concluded that the replacements were a like-for-like change that did not require a license amendment.

1 1 On January 9, 2012, SCE shut down Unit 2 for a scheduled refueling outage and steam generator inspection.

1 2 On January 31, 2012, while Unit 2 was still shut down, Unit 3 operators received secondary plant system radiation alarms, diagnosed a steam generator tube leak of approximately 82 gallons per day, and shut down Unit 3 as required by plant procedures.

See relied upon throughout

[Petitioner's]

Brief." SCE's Answering Brief at 14. Petitioner counters that an affidavit was not necessary to support the Hirsch Report because (1) it "uses data submitted to the NRC by utilities operating nuclear reactors with replacement steam generators to compare San Onofre to the experience of [replacement steam generators]

nationally";

(2) it was "commissioned by Senator Barbara Boxer, Chair of the Senate Environment and Public Works Committee, and admitted into the Senate record in a joint hearing on September 12, 2012"; and (3) the NRC Commissioners "placed the Hirsch Report into the record of the Commission briefing on steam generator problems held on February 7, 2013 .... at which Daniel Hirsch was invited to testify." Reply Brief of Petitioner Friends of the Earth (Feb. 13, 2013) at 27-28 [hereinafter Petitioner's Reply Brief]. In these circumstances, and given that SCE does not identify particular factual errors in the Hirsch Report, we decline SCE's suggestion to disregard that Report.10 See July 18 AIT Report at 36; see also May 31 Gundersen Decl. at 4-6; Petitioner's Opening Brief, Att. 2, Affidavit of Arnold Gundersen (Jan. 9, 2013) at 8-9 [hereinafter Gundersen Aft.]; Petitioner's Opening Brief, Att. 1, Corrected Affidavit of John H. Large (Jan. 22, 2013) at 11[hereinafter Jan. 22 Large Aft.]. For a full description of the replacement steam generators, including a diagram, see Brabec Aft. at 4-5.11 See May 31 Gundersen Decl. at 7; Gundersen Aft. at 8. Although SCE did not seek a license amendment relating to the design differences of the steam generators, it did obtain a license amendment in 2009 for changes to certain "SONGS Technical Specifications related to steam generator tube integrity." SCE's Answering Brief at 6.12 See NRC Staffs Answering Brief in the [SONGS] CAL Proceeding (Jan. 30, 2013)[hereinafter NRC's Answering Brief], Att. 1, NRC Integrated Inspection Report 05000361/2012002 and 05000362/2012002 (May 8, 2012) at 18-19 [hereinafter May 8, 2012 Inspection Report].

5 May 8, 2012 Inspection Report at 39.SCE's inspection of the Unit 3 steam generators revealed "extensive

[tube-to-tube wear]" (SCE's Answering Brief at 9) that SCE determined "was caused by in-plane fluid elastic instability from the combination of localized high steam velocity, high steam void fraction, and insufficient contact forces between the tubes and the [anti-vibration bars]." Id. SCE states that more than 150 tubes of the 9,727 tubes in each [of the Unit 3 replacement steam generators]

experienced

[tube-to-tube wear], including more than 100 tubes in each [replacement steam generator]

with wear equal to or greater than 35% of the width of the tube wall (which is the criterion in SONGS Technical Specification 5.5.2.11 for removal of the tube from service by plugging of the tube).Id. (footnote omitted).1 3 Significantly, SCE acknowledges that "[tube-to-tube wear] due to in-plane [fluid elastic instability]

had not been previously experienced in U-tube steam generators." SCE's Answering Brief at 10. SCE describes fluid elastic instability as a phenomenon in which the tubes vibrate with increasingly larger amplitudes due to the flow velocity exceeding the critical velocity for a tube, given its supporting conditions and thermal-hydraulic environment.

[Fluid elastic instability]

occurs when the amount of energy imparted on the tube by the fluid is greater than the amount of energy that the tube can dissipate back to the fluid and to the supports.

During in-plane [fluid elastic instability], tubes within the same column are excited by the fluid and move with the plane of the column, resulting in tube-to-tube contact and wear of the tubes.Id. at 9 (footnotes omitted).With regard to Unit 2, SCE states, "[i]n contrast to the extensive

[tube-to-tube wear] in Unit 3, [tube-to-tube wear in Unit 2] existed in only a single pair of tubes ... in one of the two 13 As characterized by Petitioner, each Unit 3 steam generator "exhibited approximately 5,000+ indications of wear localities, with many tubes having wear indications at more than one locality and of differing degrees of wear severity, with a total of about 900 individual tubes affected in each [replacement steam generator]." Jan. 22 Large Aff. at 10. A total of 193 tubes in one steam generator and a total of 188 in the other exceeded the wall thinning threshold of 35%, above which tube plugging is mandatory.

See id. "Because of the depth and length of certain of the tube wear scars, a number of tubes were subjected to in situ hydrostatic pressure testing in March 2012, [which] resulted in 8 individual tube failures, all located in one[replacement steam generator]." Id.; see also Hirsch Report at 4-5, 7-9.

6... [steam generators]." SCE's Answering Brief at 9. One of SCE's contractors "concluded that the [tube-to-tube wear] in Unit 2 was not due to [fluid elastic instability], but instead to proximity of the tubes in question and random vibration of those tubes." Id. at 10. But other SCE analyses "assumed that [fluid elastic instability]

could occur in Unit 2 at 100% power." Id. SCE attributes the difference in tube-to-tube wear between Units 2 and 3 to fabrication differences arising from allowable fabrication tolerances.'

4 See id. at 10, 92; infra note 43.On March 23, 2012, SCE submitted to the NRC Staff a "Steam Generator Return-to-Service Action Plan" and described actions it committed to take before restarting Units 2 and 3.15 On March 26, 2012, the NRC Staff confirmed, by telephone, its understanding of the actions to which SCE had committed.

See NRC Staff s Answering Brief at 3. On March 27, 2012, the NRC Staff memorialized its understanding in a CAL that confirmed the actions SCE would take prior to restarting either unit.1 6 As discussed in greater detail infra Part II.A.1, the NRC Staff uses a CAL to commence an enforcement process in which (as relevant here) a licensee agrees "to take certain actions to remove significant concerns regarding health and safety, safeguards, or the environment." 1 7 In 14 The extent of the tube-to-tube wear is described in the SONGS Unit 2 Return to Service Report's Steam Generator Operational Assessment for Tube-to-Tube Wear. See SCE's Answering Brief, Att. 12, SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear [hereinafter Assessment for Tube-to-Tube Wear]; see also Jan. 22 Large Aff. at 10-11; Hirsch Report at 4-6, 8-10.15 See SCE's Answering Brief, Att. 7, Docket Nos. 50-361 and 50-362 Steam Generator Return-to-Service Action Plan [SONGS] (Mar. 23, 2012) [hereinafter Mar. 23, 2012 Return-to-Service Plan].16 See SCE's Answering Brief, Att. 3, [CAL] -- [SONGS], Units 2 and 3, Commitments to Address Steam Generator Tube Degradation (Mar. 27, 2012) [hereinafter CAL].17 SCE Answering Brief, Att. 13, NRC Enforcement Policy (June 7, 2012) at 68 [hereinafter NRC Enforcement Policy]. The NRC Enforcement Manual describes a CAL as follows:[Confirmatory Action Letters (CALs)] are flexible and valuable tools available to the staff to resolve licensee issues in a timely and efficient manner, e.g., when an order is warranted to address a specific issue, a CAL is a suitable instrument to confirm initial, agreed upon, short-term actions covering the interval period prior 7 the instant case, the March 27, 2012 CAL provides, inter alia, that (1) SCE will take specified investigatory and corrective actions and provide information to the NRC Staff as prescribed in the CAL; and (2) SCE may not restart Units 2 and 3 until the NRC Staff has completed its review of SCE's Restart Reports and has authorized such restarts.

See CAL at 2.B. Procedural

Background

On June 18, 2012, Petitioner submitted a hearing request to the Commission arising out of the Staff's issuance of the CAL.1 8 Petitioner (1) requested that the Commission recognize that the CAL process for the start up of Units 2 and 3 is a de facto license amendment proceeding requiring an adjudicatory hearing (see Petition to Intervene at 2), and (2) proffered the following contention: "Petitioner contends that [SONGS] cannot be allowed to restart without a license amendment and attendant adjudicatory public hearing as required by 10 C.F.R. § 2.309, in which Petitioner and other members of the public may participate." Id. at 16.19 On July 13, 2012, SCE and the NRC Staff filed answers opposing Petitioner's hearing request.2 0 Petitioner filed a reply to those answers on July 20, 2012.21 to the actual issuance of the order.SCE's Answering Brief, Att. 14, [NRC] Enforcement Manual (rev. 7, Oct. 1, 2010) at 3-30 [hereinafter NRC Enforcement Manual].18 See Petition to Intervene and Request for Hearing by Friends of the Earth (June 18, 2012) [hereinafter Petition to Intervene].

19 Petitioner also advanced two other claims in its hearing request that are not relevant to this proceeding.

See infra note 24. In the meantime, on June 27, 2012, the National Resources Defense Council (NRDC) filed a response in support of Petitioner's hearing request. See NRDC's Response in Support of FOE Petition to Intervene, San Onofre Units 2 and 3 (June 27, 2012).20 See [SCE's] Answer Opposing Friends of the Earth Hearing Request and the [NRDC]Response Regarding

[SONGS] Unit 2 and 3 (July 13, 2012); NRC Staff's Answer to Petition to Intervene and Request for Hearing by Friends of the Earth on the Restart of the San Onofre Reactors (July 13, 2012).21 See Reply to SCE's and NRC Staff's Answer to Petition to Intervene and Request for 8 Meanwhile, consistent with its commitment in the CAL, on October 3, 2012, SCE submitted a CAL response to the NRC Staff entitled "Unit 2 Return to Service Report."'2 2 In that Report, SCE represented that it had taken the following corrective actions for Unit 2 and would impose the following operational limits to prevent loss of tube integrity in the steam generators due to tube-to-tube wear: SCE will administratively limit Unit 2 to 70% reactor power prior to a mid-cycle inspection outage....

This administrative limit is temporary and may change based upon the results of inspections, further analysis and long-term corrective actions.SCE has plugged the tubes adjacent to the retainer bars, plugged the two tubes with [tube-to-tube wear] in Unit 2, plugged the tubes with wear that exceeds the 35% through-wall criterion in SONGS Technical Specifications, and preventively plugged additional tubes in Unit 2 based on wear characteristics in Unit 3 tubes and actual wear patterns in Unit 2 (those tubes are in approximately the same region that experienced

[fluid elastic instability]

in Unit 3 at 100% power)....

[A]bout 3% of the total number of tubes in each of the [steam generators]

in Unit 2 have been plugged.SCE will shut down for a mid-cycle steam generator tube inspection outage within 150 cumulative days of operation at or above 15% power.SCE's Answering Brief at 10-11 .23 On November 8, 2012, the Commission issued a decision on Petitioner's hearing request. As relevant here, the Commission referred to the ASLBP that portion of the request in which Petitioner argued that "the [CAL] issued to SCE, including the process for resolving the issues raised in the [CAL], constitutes a de facto license amendment proceeding." CLI-12-20, 76 NRC at _ (slip op. at 4). The Commission thus directed a duly constituted Licensing Board Hearing by Friends of the Earth (July 20, 2012).22 See SCE's Answering Brief, Att. 4, Docket No. 50-361, [CAL] -Actions to Address Steam Generator Tube Degradation

[SONGS], Unit 2 (Oct. 3, 2012) [hereinafter SCE's Unit 2 Restart Plan].23 SCE has not yet submitted a Unit 3 Return to Service Report (see SCE's Answering Brief at 11), and it represents that "its CAL response and restart actions for Unit 3 ... may be quite different than those for Unit 2 because the [tube-to-tube wear] in Unit 3 is far more extensive and severe than in Unit 2." Id. at 21.

9 to "consider whether: (1) the [CAL] issued to SCE constitutes a de facto license amendment that would be subject to a hearing opportunity under [s]ection 189a [of the Atomic Energy Act];and, if so, (2) whether the petition meets the standing and contention admissibility requirements of 10 C.F.R. § 2.309." Id. at 5.24 Following its establishment on November 19, 2012,25 this Licensing Board held a conference call on December 3, 2012 to discuss the procedural path forward, including a briefing schedule.2 6 Petitioner filed its opening brief with attachments on January 11, 2013 (see Petitioner's Opening Brief); SCE and the NRC Staff each filed an answering brief with attachments on January 30, 2013 (see SCE's Answering Brief; NRC Staffs Answering Brief);and Petitioner filed its reply brief on February 13, 2013. See Petitioner's Reply Brief.2 7 On March 22, 2013, this Board held an oral argument in the ASLBP's Rockville Hearing Room on the issues referred by the Commission.

2 8 24 As mentioned supra note 19, in its hearing request, Petitioner also advanced two additional claims, asserting that (1) SCE violated 10 C.F.R. § 50.59 insofar as it replaced the steam generators in Units 2 and 3 without seeking a license amendment; and (2) the Commission should exercise its inherent supervisory authority to initiate a discretionary adjudicatory hearing. See Petition to Intervene at 2. The Commission (1) referred Petitioner's section 50.59 claim to the NRC Executive Director for Operations for consideration as a petition under 10 C.F.R. § 2.206 (see CLI-12-20, 76 NRC at __ (slip op. at 4)); and (2) denied, without prejudice, Petitioner's request that the Commission initiate a discretionary adjudicatory hearing.See id. at 5.25 See Southern Cal. Edison Co., Establishment of Atomic Safety and Licensing Board, 77 Fed. Reg. 70,487 (Nov. 26, 2012).26 See Licensing Board Order (Scheduling Conference Call) (Nov. 26, 2012) (unpublished).

This Board's subsequent procedural directives are contained in the following orders: Licensing Board Order (Conference Call Summary and Directive Relating to Briefing) (Dec. 7, 2012)(unpublished);

Licensing Board Order (Granting in Part and Denying in Part Petitioner's Motion for Clarification and Extension) (Dec. 20, 2012) (unpublished).

27 Additionally, NRDC filed an amicus brief in support of Petitioner (see [NRDC's] Amicus Response in Support of Friends of the Earth (Jan. 18, 2013)), and Nuclear Energy Institute (NEI) filed an amicus brief in support of SCE and the NRC Staff. See Amicus Curiae Brief of[NEI] in Response to the NRC [ASLBP's]

Briefing Order (Jan. 30, 2013).28 See Official Transcript of Proceedings (Mar. 22, 2013) [hereinafter Tr.]. The oral argument was web streamed for the benefit of individuals who were unable to attend. See 10 II. ANALYSIS In Part IIA, we define the scope of the de facto license amendment issue referred by the Commission, concluding that -- based on the nature of the CAL process and the language in CLI-1 2-20 -- the Commission tasked us with determining whether any aspect of this CAL process, including a close-out of the CAL for Unit 2 that results in a plant start-up pursuant to SCE's Unit 2 Return to Service Plan, would constitute a de facto license amendment proceeding.

2 9 In Part II.B, we discuss the legal standards that will guide us in resolving this issue. In Part II.C, we apply the governing legal standards to the facts of this case, and we conclude that this CAL process constitutes a de facto license amendment proceeding that triggers the hearing requirements in section 189a of the AEA. Finally, in Part II.D, we consider the second issue referred by the Commission

-- i.e., whether Petitioner has standing and has submitted an admissible contention.

We conclude that, because our resolution of the first issue Licensing Board Order (Format for Oral Argument) (Mar. 12, 2013) at 2 (unpublished).

During oral argument, SCE announced that it was "considering filing a voluntary license amendment request with a no significan[t]

hazards consideration as the most expeditious method to resolve the issue raised by [Request for Additional Information]

32." See Tr. at 10.Subsequently, on April 8 and 9, 2013, respectively, SCE filed (1) a License Amendment Request for Unit 2; and (2) Supplement 1 to the License Amendment Request for Unit 2. See Docket No. 50-361, Amendment Application Number 263, Steam Generator Program,[SONGS], Unit 2 (Apr. 8, 2013); Docket No. 50-361, Supplement 1 to Amendment Application Number 263, Steam Generator Program, [SONGS], Unit 2 (Apr. 9, 2013). On April 11, 2013, the NRC Staff filed a copy of a "Notice of Application and Amendment to Facility Operating License Involving Proposed No Significant Hazards Consideration Determination, and Opportunity for a Hearing," which it had forwarded the previous day to the Office of the Federal Register for publication.

See [SONGS], Unit 2 -Notice of Application and Amendment to Facility Operating License Involving Proposed No Significant Hazards Consideration Determination, and Opportunity for Hearing (TAC No. MF1 379) (Apr. 11, 2013). No party has filed a motion suggesting that this new development materially affects this proceeding, nor do we discern such an effect, because SCE's license amendment request for Unit 2 does not fully resolve the referred issue for Unit 2 (see infra note 48), much less for Unit 3.29 In this decision, we focus principally on Unit 2, because SCE has not yet submitted a"Unit 3 Return to Service Report." However, because SCE concedes that the tube-to-tube wear in Unit 3 is "far more extensive and severe" than in Unit 2 (see SCE's Answering Brief at 21), our conclusion on the first referred issue (infra Part II.C) would perforce apply to Unit 3 if SCE sought to restart it without a license amendment.

11 grants Petitioner all the relief that its contention seeks, the second issue referred by the Commission is now moot.A. The Scope of the De Facto License Amendment Issue Referred to this Board SCE and the Petitioner disagree sharply about the scope of the first issue referred to this Board. The Commission "direct[ed]

the Board to consider whether.., the [CAL] issued to SCE constitutes a de facto license amendment that would be subject to a hearing opportunity under section 189a [of the AEA].3 0 CLI-12-20, 76 NRC at _ (slip op. at 5). SCE argues that, consistent with the above language, this Board should cabin its review to "the provisions in the[March 27, 2012 letter] itself, without recourse to SCE's CAL response or its restart actions." SCE's Answering Brief at 20. The NRC Staff agrees with SCE's narrow view of the issue. See NRC Staffs Answering Brief at 48-49.On the other hand, Petitioner argues that the Commission referred a broader issue to this Board. Petitioner claims that the Commission viewed the CAL as a process, not as a discrete letter, and it therefore directed this Board to resolve whether any aspect of the CAL process, including a close-out of the CAL that results in a plant start-up pursuant to SCE's Unit 2 Return to Service Plan, would constitute a de facto license amendment proceeding.

See Petitioner's Opening Brief at 6. This conclusion, argues Petitioner, is compelled by (1) the nature of the CAL process; (2) the plain language in CLI-12-20; and (3) common sense. See Petitioner's Opening Brief at 9-10; Tr. at 23-24. We agree with Petitioner.

1. The Nature of the CAL Process Supports Petitioner's Interpretation Regarding the Scope of the Referred Issue SCE and the NRC Staff argue that the first issue requires us to limit our review to the four corners of the March 27, 2012 confirmatory action letter and determine whether that letter, viewed in isolation, constitutes a de facto license amendment.

This argument ignores that, 30 lI.B.1.The hearing opportunity mandated by section 189a of the AEA is discussed infra Part 12 although a "confirmatory action letter" can be referred to as a "CAL," the NRC Enforcement Manual also considers the term "CAL" to be a "process." See NRC Enforcement Manual at 3-32.As described in the NRC Enforcement Manual and as explained by the NRC Staff, the CAL process involves (1) the identification of a significant concern regarding health and safety, safeguards, or the environment; (2) the NRC Staffs issuance of a specific CAL; (3) a licensee responding by taking action and/or providing information as prescribed in the CAL; and (4) when the circumstances that prompted the NRC to issue the CAL have been addressed, the closing out of the CAL.3 1 See NRC Staffs Answering Brief at 31; NRC Enforcement Manual at 3-29 to 3-36; see also NRC Enforcement Policy at 68.In the instant case, the NRC Staffs use of the CAL process serves, inter alia, to confirm SCE's "[v]oluntary...

suspension of licensed activities" and its "agreement to NRC approval prior to resumption of licensed activities." NRC Enforcement Manual at 3-30. The March 27, 2012 letter thus states that the CAL will remain in effect until the NRC Staff (1) completes its review of SCE's tests, assessments and evaluations, corrective actions, and proposed protocol 31 The Enforcement Manual describes the process for closing out a CAL as follows: 3.5.7 Closing Out CALs A. A CAL may or may not require follow-up inspection to verify completion of the specified licensee actions. Whether the staff believes that an inspection is necessary to close a CAL will be determined on a case-by-case basis and will depend on the circumstances of the case.B. The issuing office (i.e., region, NRR, NMSS, FSME, NRO or NSIR) will issue documentation formally closing out the CAL.C. Correspondence closing out a CAL should be sent to the same person/address as the CAL; however, verbal notification, in advance of written correspondence, may be sufficient to permit plant restart or resumption of affected licensee activities.

NRC Enforcement Manual at 3-35 to 3-36.

13 of inspections and/or operational limits; and (2) concludes that the SONGS Units 2 and 3 can be operated without undue risk to public health and safety, and the environment.

See CAL at 2, 3.On October 3, 2012, SCE informed the NRC Staff that it had completed the actions prescribed in the March 27, 2012 letter for the restart of Unit 2, and it provided detailed information regarding fulfillment of those actions in a document entitled "Unit 2 Return to Service Report." See Unit 2 Return to Service Report.The NRC Staff has not yet closed out the CAL for Unit 2, because it continues to review SCE's "Unit 2 Return to Service Report." Incident to that review, to date, the NRC Staff has issued over 70 Requests for Additional Information (RAIs) to SCE, while SCE has submitted 8 voluminous responses.

3 2 In short, the CAL process for Units 2 and 3 is a protracted and evolving process. It will culminate in a close-out that will permit plant restart if the NRC Staff concludes such action can be accomplished without undue risk to public health and safety, and the environment.

This Board cannot determine whether that process constitutes a de facto license amendment proceeding by looking solely at the March 27, 2012 document that set this lengthy and complex process in motion. Rather, our resolution of that issue must be informed by considering the entire process and the documents generated incident to that process.We recognize that Licensing Boards are not empowered "to supervise or direct NRC Staff regulatory reviews." Duke Energy Corp. (Catawba Nuclear Station, Units 1 and 2), CLI-04-6, 59 NRC 62, 74 (2004). Our resolution of the referred issue will not violate that rule.We do not presume to supervise or to direct the NRC Staff in the performance of its CAL duties, including its review of the adequacy and safety of SCE's restart plan; rather, the scope of our authority is limited to adjudicating the issue referred by the Commission

-- i.e., whether this CAL process constitutes a de facto license amendment proceeding.

32 The NRC Staff issued RAIs to SCE on December 26, 2012 (RAIs 1-32), March 18, 2013 (RAIs 33-67), and March 15, 2013 (RAIs 68-72). See SCE's Eighth Notification of Responses to RAIs (Apr. 23, 2013).

14 The NRC Staff nevertheless argues that the CAL process "does not involve issuing [a license] amendment.

Instead, closing out a CAL would 'permit plant restart or resumption of affected licensee activities."'

NRC Staffs Answering Brief at 32 (quoting NRC Enforcement Manual at 3-36). "If the licensee or Staff determined a license amendment was required," argues the NRC Staff, "that would be done separately from the CAL close-out process." NRC Staffs Answering Brief at 32 n. 157.The short answer to this argument is that "it is the substance of the NRC action that determines entitlement to a section 189a hearing, not the particular label the NRC chooses to assign to its action." Citizens Awareness Network, Inc. v. NRC, 59 F.3d 284, 295 (1st Cir.1995). Consistent with the Commission's directive in CLI-12-20, it is this Board's responsibility to scrutinize the substance of this CAL process to determine whether it constitutes a de facto license amendment proceeding.

To resolve that issue, our inquiry must extend to determining whether the Unit 2 Return to Service Report, in which SCE seeks a CAL close-out that "permit[s a] plant restart" (NRC Enforcement Manual at 3-36), constitutes a de facto license amendment proceeding that triggers a hearing opportunity under section 189a of the AEA.2. The Language in the Commission's Referral Order Supports Petitioner's Interpretation Regardinq the Scope of the Referred Issue The above conclusion is compelled by the plain language in the Commission's referral order. The Commission explicitly stated that Petitioner "contend[ed]

that the [CAL] issued to SCE, including the process for resolving the issues raised in the [CAL], constitutes a de facto license amendment proceeding" (CLI-12-20, 76 NRC at _ (slip op. at 4)), and it was "this portion of the petition" that the Commission referred to the ASLBP for resolution.

Id. at 4-5.Insofar as the Commission referred a de facto license amendment claim that "includ[ed a challenge to] the process for resolving the issues raised in the [CALI' (CLI-1 2-20, 76 NRC at __(slip op. at 4) (emphasis added)), we conclude that the referred issue requires us to determine whether this process, in which SCE seeks a CAL close-out resulting in a plant restart, 15 constitutes a de facto license amendment proceeding.

It is true that there can be no actual license amendment until (and unless) it is issued by the NRC Staff. See 10 C.F.R. § 50.92. It might therefore be argued that this Board should refrain from resolving the de facto license amendment issue until the Staff completes the CAL process by, for example, authorizing the start up of Units 2 and 3.This we decline to do for three reasons. First and foremost, we see no indication in CLI-12-20 that the Commission intended this Board to stay its hand until the Staff has taken final action in the CAL process. Second, if the hearing provision in section 189a of the AEA is to serve its intended purpose, the parties in interest should be afforded a meaningful opportunity to request a hearing before the NRC Staff takes final action that could result in authorizing SCE to operate in a manner that is beyond the ambit of its existing license. Cf. Citizens Awareness Network, Inc., 59 F.3d at 294-95 ("[I]f section 189a is to serve its intended purpose, surely it contemplates that parties in interest be afforded a meaningful opportunity to request a hearing before the Commission retroactively reinvents the terms of an extant license by voiding its implicit limitations on the licensee's conduct.").

Third, all the parties urge this Board to resolve the referred issue without awaiting final Staff action. See Tr. at 59 (SCE), 27 (Petitioner), 112 (NRC Staff). To do otherwise could result in years of delay. See Tr. at 59 (SCE advises that, in its estimation, the CAL close-out for Unit 3 is "not imminent" and is not likely to occur for several years).3. Common Sense Supports Petitioner's Interpretation Regarding the Scope of the Referred Issue Common sense also supports the conclusion that the Commission did not intend this Board to limit its review to the four corners of the March 27, 2012 confirmatory action letter.Otherwise, it would have resolved the issue itself, concluding

-- without difficulty

-- that this austere four-page document, viewed in isolation at the incipient stage of the CAL process, does not constitute a de facto license amendment.

16 However, by referring the issue to the ASLBP, and by acknowledging that Petitioner's claim "include[ed]

the process for resolving the issues raised in the [CAL]" (CLI-12-20, 76 NRC at _ (slip op. at 4) (emphasis added)), it may fairly be concluded that the Commission intended a Licensing Board to examine the entire CAL process, and to determine whether any aspect of that process -- including a close-out of the CAL that results in a plant start up pursuant to SCE's Unit 2 Return to Service Plan -- constitutes a de facto license amendment proceeding.

3 3 SCE advances a policy reason in support of its argument that this Board should focus exclusively on the March 27, 2012 CAL and conclude that it is not a de facto license amendment.

Namely, to do otherwise may discourage licensees in the future from agreeing to a CAL, thus (1) diminishing the NRC Staffs use of this important regulatory tool in the future;and (2) undermining the Staffs discretion to select the enforcement action that best fits the factual circumstances.

See SCE Brief at 20-23.This argument lacks merit. First, whether a CAL process constitutes a de facto license amendment proceeding is a highly fact-specific question, and there is no reason to believe that this Board's resolution of this fact-specific issue in this exceptionally unusual case will influence other licensees when they are considering whether to agree to a CAL. Second, "unreviewed Board rulings do not constitute precedent or binding law" (Baltimore Gas & Elec. Co. (Calvert Cliffs Nuclear Power Plant, Units 1 and 2), CLI-98-25, 48 NRC 325, 343 n.3 (1998)), which fortifies our conclusion that our resolution of the referred issue in this unique case will not impact the decision-making process of other licensees when they are considering whether to agree to a CAL. Finally, and dispositively, SCE's policy argument cannot trump the Commission's directive in CLI-1 2-20 that a Licensing Board examine this CAL process and determine whether it 33 We thus agree with the NRC Staffs assertion (see NRC Staffs Answering Brief at 35)that if we were to limit our review to the March 27, 2012 letter, we would conclude that this document, viewed in isolation, is not a de facto license amendment.

In our judgment, however, the Commission eschewed such a facile analytic approach by referring Petitioner's claim to the ASLBP, "including the process for resolving the issues raised in the CAL." CLI-12-20, 76 NRC at _ (slip op. at 4).

17 constitutes a de facto license amendment proceeding.

B. Legal Standards That Address License Amendments I. Relevant Statutory Provisions Related to License Amendments It is imperative that the terms of a reactor operating license be clear and unambiguous, and also that a licensee scrupulously adhere to those terms, because section 101 of the AEA makes it "unlawful

... for any person within the United States to ... use ... any utilization...

facility except under and in accordance with a license issued by the Commission." 42 U.S.C.§ 2131.34 Section 182a of the AEA addresses what must be included in a reactor operating license. It states that such licenses must include "technical specifications" that include, inter alia, "the specific characteristics of the facility, and such other information as the Commission may, by rule or regulation, deem necessary in order to enable it to find that the utilization

... of special nuclear material ... will provide adequate protection to the health and safety of the public." 42 U.S.C. § 2232(a).3" The Commission is empowered to issue an order amending any license as it deems necessary to "effectuate the provisions of [the AEA]" (42 U.S.C. § 2233) -- that is, to "promote the common defense and security or to protect health or to minimize danger to life or property." Id. § 2201; see also id. § 2237. Additionally, the Commission "may at any time.., before the expiration of the license, require further written statements

[from the licensee]

to determine whether...

a license should be modified." Id.. § 2232(a).Finally, section 189a of the AEA states that "[i]n any proceeding under [the AEA], for the 34 A "utilization facility" includes a commercial nuclear power reactor. See 10 C.F.R.§ 50.2.35 "The AEA, however, leaves it up to the Commission to determine, and prescribe by rule or regulation, what additional information should be included in technical specifications to ensure public health and safety and the common defense and security." Dominion Nuclear Connecticut, Inc. (Millstone Nuclear Power Station, Units 2 and 3), CLI-01-24, 54 NRC 349, 351 (2001).

18... amending of any license..., the Commission shall grant a hearing upon the request of any person whose interest may be affected by the proceeding, and shall admit any such person as a party to such proceeding." 42 U.S.C. § 2239(a)(1)(A).

2. Relevant Regulatory Provisions Related to License Amendments 10 C.F.R. §§ 50.90 to 50.92 provide the applicable process when a licensee wishes to request a license amendment.

Specifically, section 50.90 authorizes applications to amend existing operating licenses; section 50.91 provides for notice and comment regarding license amendment applications, as well as consultation with the State in which the facility is located;and section 50.92 provides the standard considered by the NRC when determining whether to issue an amendment.

Section 50.59 establishes standards for a licensee to request a license amendment before it may make "changes in the facility as described in the [updated]

final safety analysis report [UFSAR 3 6], make changes in the procedures as described in the [UFSAR], and conduct tests or experiments not described in the [UFSAR]." 10 C.F.R. § 50.59(c)(1).

Section 50.59 states that a licensee need not request a license amendment pursuant to section 50.90 if "(i) A change to the technical specifications incorporated in the license is not required, and (ii) The change, test, or experiment does not meet any of the criteria in paragraph (c)(2) of this section." Id. § 50.59(c)(1)(i)-(ii).

Restated, a licensee must request a license amendment if the proposed action requires that existing technical specifications be changed (see 10 C.F.R. § 50.59(c)(1)(i)), 3 7 or if a 36 A final safety analysis report (FSAR) is part of the application for an operating license, and it contains "a description of the facility; the design bases and limits on operation; and the safety analysis for the structures, systems, and components (SSC) and of the facility as a whole." Changes, Tests, and Experiments:

Proposed Rule, 63 Fed. Reg. 56,098, 56,099 (Oct.21, 1998). "When a plant is licensed, the NRC states in its Safety Evaluation Report (SER) why it found each FSAR analysis acceptable." Id. Licensees must periodically update their FSARs to reflect changes to the facility "so that the [updated FSAR (UFSAR)] remains a complete and accurate description and analysis of the facility." Id.37 Because changes to technical specifications require a license amendment, the 19 change, test, or experiment satisfies any of the eight criteria in section 50.59(c)(2).

See id.§ 50.59(c)(1)(ii).

The section 50.59(c)(2) criteria require a licensee to seek a license amendment if the proposed change, test, or experiment would (i) Result in more than a minimal increase in the frequency of occurrence of any accident previously evaluated in the [UFSAR];(ii) Result in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety previously evaluated in the [UFSAR];(iii) Result in more than a minimal increase in the consequences of an accident previously evaluated in the [UFSAR];(iv) Result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the [UFSAR];(v) Create a possibility for an accident of a different type than any previously evaluated in the [UFSAR];(vi) Create a possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the [UFSAR];(vii) Result in a design basis limit for a fission product barrier as described in the[UFSAR] being exceeded or altered; or (viii) Result in a departure from a method of evaluation described in the [UFSAR]used in establishing the design bases or in the safety analyses.Id. § 50.59(c)(2).

3 8 Commission has instructed that technical specifications should be limited to "'those plant conditions most important to safety."'

Millstone, CLI-01-24, 54 NRC at 360 (quoting Final Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors, 58 Fed. Reg.39,132, 39,135 (July 22, 1993)). Thus, technical specifications "should be reserved for those reactor operation

'conditions or limitations

... necessary to obviate the possibility of an abnormal situation or event giving rise to an immediate threat to the public health or safety."'

Id.at 361 (quoting Technical Specifications, Final Rule, 60 Fed. Reg. 36,953, 36,957 (July 19, 1995)). See also 10 C.F.R. § 50.36 (identifying criteria to be used in determining what items must be included in technical specifications).

38 The term "design bases" to which section 50.59(c)(2)(vii) and (viii) refer is defined as follows: Design bases means that information which identifies the specific functions to be performed by a structure, system, or component of a facility, and the specific values or ranges of values chosen for controlling parameters as reference bounds for a design. These values may be (1) restraints derived from generally accepted "state of the art" practices for achieving functional goals, or 20 Finally, 10 C.F.R. § 2.105 implements the hearing opportunity provision for license amendment procedures that is mandated by section 189a of the AEA, and Subpart C of 10 C.F.R. Part 2 contains the general rules governing hearing requests and subsequent hearing-related activities.

In sum, Congress has commanded that licensees may not, under penalty of law, deviate from the terms of their reactor operating licenses.

See 42 U.S.C. § 2131. If a licensee is unable to operate a reactor in strict accordance with its license, it must seek authorization from the NRC for a license amendment (10 C.F.R. §§ 50.59, 50.90 to 50.92), which is a process that triggers a right to request an adjudicatory hearing by persons whose interests may be affected by the proceeding.

See 42 U.S.C. § 2239(a)(1)(A);

10 C.F.R. § 2.105.3. De Facto License Amendments As shown above, amending a license is, by design, a carefully considered process that is closely regulated by the NRC and in which "any person whose interest may be affected" is entitled to request a hearing. 42 U.S.C. § 2239(a)(1)(A).

As discussed below, however, there have been occasions when the NRC has taken action that effectively constituted a license amendment, but it failed to recognize that its actions effectively amended the license.In other words, there have been occasions when the NRC has -- without formally amending a license and without providing the public with the opportunity for a hearing as required by section 189a of the AEA -- authorized activity by the licensee that was incompatible with the statutory requirement that the facility operate "in accordance with" its existing operating license. 42 U.S.C. § 2131. Such NRC action is characterized as a de facto license amendment.

According to Petitioner, this CAL process is a de facto license amendment (2) requirements derived from analysis (based on calculation and/or experiments) of the effects of a postulated accident for which a structure, system, or component must meet its functional goals.10 C.F.R. § 50.2.

21 proceeding because SCE seeks effectively to amend its license via the CAL process.Specifically, Petitioner argued to the Commission that "the [CAL] issued to SCE, including the process for resolving the issues raised in the [CAL], constitutes a de facto license amendment proceeding within the hearing provision of section 189a of the AEA, and therefore an adjudicatory hearing is required." CLI-12-20, 76 NRC at _ (slip. op at 4). The Commission referred that claim to the ASLBP for resolution.

Id.Determining whether the CAL process constitutes a de facto license amendment proceeding "is a highly fact-specific question." NRC Staff's Answering Brief at 10. Case law, however, provides a straight-forward analytic framework for assessing the relevant facts. For example, in Cleveland Elec. Ilium. Co. (Perry Nuclear Power Plant), CLI-96-13, 44 NRC 315 (1996), the Commission considered whether the NRC Staffs decision to authorize changes to a material specimen withdrawal schedule was a de facto license amendment.

Examining decisions from the U.S. Courts of Appeals for the First Circuit and the District of Columbia Circuit, the Commission distilled the following factors that are material to determining whether NRC actions constitute a de facto license amendment:

In evaluating whether challenged NRC authorizations effected license amendments within the meaning of section 189a, courts repeatedly have considered the same key factors: did the challenged approval grant the licensee any "greater operating authority," or otherwise "alter the original terms of a license"?

If so, hearing rights likely were implicated.

For example, in Citizens Awareness Network, Inc. v. NRC, 59 F.3d 284, 295 (1st Cir. 1995) (CAN) .... the court found that the challenged NRC approval "undeniably supplement[edr the original license. The agency had permitted the licensee to dismantle major structural components, an activity that the court found unauthorized by the original license and agency rules. Similarly, in another case [San Luis Obispo Mothers for Peace v. NRC, 751 F.2d 1287 (D.C. Cir. 1984) (SL.0)], where the NRC Staff extended the duration of a low-power license, a reviewing court viewed the Staff approval to be a license amendment changing a term of the license, and therefore triggering an opportunity for a hearing under section 189a.44 NRC at 326-27 (footnotes omitted).

Guided by CAN and SLO, the Commission in Perry considered whether the Staffs action (1) "alter[ed]

the ... license," or (2) "permit[ted]

the licensee to operate 'in any greater capacity' than [the original license prescribes]." Id. After 22 examining the relevant terms and technical specifications in the license, the Commission resolved both inquiries in the negative.3 9 As illustrated in the Perry case, a de facto license amendment claim typically involves a tribunal "looking backward" to determine whether action already taken by the NRC Staff effectively constituted a license amendment.

Here, however, consistent with the Commission's referral order, we are tasked with looking at an ongoing CAL process to determine whether that process constitutes a de facto license amendment proceeding.

See supra Part II.A. To resolve that issue, this Board must determine whether the requested change in authority to operate Unit 2 sought by SCE pursuant to the CAL process is strictly "in accordance with" the terms and technical specifications in its existing license. 42 U.S.C. § 2131.In other words, this Board must consider the following connate factors: whether SCE's start-up request, if granted, would permit SCE to operate (1) in a manner that deviates from a technical specification in its existing license; (2) beyond the ambit, or outside the restrictions, of its existing license; or (3) in a manner that is neither delineated nor reasonably encompassed 39 For additional pronouncements on standards employed by tribunals in the context of considering de facto license amendment issues, see, eq., Perry, CLI-96-13, 44 NRC at 319 ("Because technical specifications are an integral part of an operating license, changes to technical specifications require a license amendment.");

id. at 320 (the UFSAR "can be modified without a license amendment, so long as the modifications do not involve a change to the technical specifications or an unreviewed safety question");

CAN, 59 F.3d at 294 ("[B]y its nature a license is presumptively an exclusive

-- not an inclusive

-- regulatory device. ...Regulated conduct which is neither delineated, nor reasonably encompassed within delineated categories of authorized conduct, presumptively remains unlicensed.");

id. at 295 (NRC's actions constitute de facto license amendment when they authorize licensee to "engage in[activities]

beyond the ambit of [its] original license");

Massachusetts

v. NRC, 878 F.2d 1516, 1520-21 (1st Cir. 1989) (NRC's actions in requiring 47 improvements, granting an exemption from emergency drills, and lifting a license suspension did not require a license amendment, because the licensee can "operate[]

in accordance with its unaltered license" and need not be"exempted...

from following a specific license requirement");

In re Three Mile Island Alert, Inc., 771 F.2d 720, 729 (3d Cir. 1985) (NRC's lifting of license suspension and authorizing restart under stipulated restrictions was not a license amendment because "nothing in this record ...indicates

... that license amendments are necessary to permit the licensee to operate in accordance with the restrictions which have been imposed"), cert. denied, 475 U.S. 1082 (1986).

23 within the prescriptive terms of its existing license. See supra note 39 and accompanying text.4°In assessing the referred issue, this Board can refer to 10 C.F.R. § 50.59, which -- as discussed supra Part Il.B.2 -- identifies situations where a licensee must request a license amendment.

In our view, reference to the criteria in section 50.59 is eminently appropriate here, because the ultimate question before this Board is whether SCE's request that the Staff close out the CAL by permitting a plant restart constitutes a de facto license amendment proceeding that triggers a hearing opportunity under section 189a of the AEA. To resolve this question, we must look at SCE's Unit 2 Return to Service Plan to determine whether SCE is seeking authority from the NRC Staff to deviate from a technical specification or to otherwise operate in a manner that is beyond the ambit, or inconsistent with the prescriptive terms, of its existing license.Section 50.59 establishes standards that may guide this Board in resolving that issue.Contrary to arguments advanced by.the NRC Staff (see NRC Staff Answer at 43-47; Tr.at 140), the fact that section 50.59 is designed for a licensee to determine whether it must seek a license amendment ab initio poses no impediment to this Board referring to those same regulatory standards as guides in determining whether this CAL process constitutes a de facto license amendment proceeding.

The standards in section 50.59 -- which establish when a"licensee shall obtain a license amendment" (10 C.F.R. § 50.59(c)(2))

-- have the imprimatur of the Commission and therefore, a fortiori, are appropriate guides for determining whether SCE's Unit 2 Return to Service Plan requires a license amendment, thereby converting the CAL process into a de facto license amendment proceeding.

Our use of section 50.59 as a tool in resolving the referred issue is to be distinguished from scrutinizing the actual actions taken by SCE under section 50.59. The latter is prohibited 40 At the March 22, 2013 oral argument, counsel for the NRC Staff was asked whether the need for a license amendment is limited to circumstances that involve an increase in licensing authority, or whether a license amendment would also be required where, for example, the Staff were to change the licensing authority by decreasing the maximum operating thermal power for a nuclear reactor. Counsel responded that a license amendment would be required for both situations.

See Tr. at 130.

24 by case law, which establishes that "[a] member of the public may challenge an action taken under 10 C.F.R. § 50.59 only by means of a petition under 10 C.F.R. § 2.206." Yankee Atomic Elec. Co. (Yankee Nuclear Power Station), CLI-94-3, 39 NRC 95, 101 n.7 (1994). Contrary to the NRC Staffs assertion (see NRC Staff Answer at 44-49; Tr. at 141), any reference we might make to section 50.59 will not run afoul of this rule, because the issue presented here is not a challenge to SCE's previous actions taken under section 50.59.41 Rather, the Commission directed us to determine whether this CAL process constitutes a de facto license amendment proceeding.

To resolve this issue, it is manifestly appropriate for this Board to consider, and to be guided by, all relevant analytic tools, including

-- if warranted

-- the standards in section 50.59. Cf. Tr. at 31-32, 59-60 (SCE and Petitioner both agree that this Board can properly refer to section 50.59 for purposes of resolving whether this CAL process constitutes a de facto license amendment proceeding).

C. This CAL Process Constitutes a De Facto License Amendment Proceedingq We turn now to the first of the two issues referred by the Commission:

whether this CAL process for the start up of SONGS Unit 2 constitutes a de facto license amendment proceeding.

4 2 As discussed supra Part ll.B.3, to constitute a de facto license amendment proceeding, this CAL process must involve proposed actions by SCE that, if authorized, would allow SCE to deviate from a technical specification or otherwise operate Unit 2 in a manner that is inconsistent with existing licensing requirements or restrictions.

We conclude that this CAL process constitutes a de facto license amendment proceeding for the following three independent reasons: 41 Indeed, it is impossible on the present record -- as a legal and factual matter -- for Petitioner to challenge, or for this Board to review, SCE's section 50.59 analysis for the Unit 2 Return to Service Plan because a copy of SCE's analysis has not even been filed with this Board.42 As stated supra note 29, although our analysis focuses on Unit 2, it would necessarily apply to Unit 3 if SCE sought to restart it without a license amendment.

25 (1) The restart of Unit 2 would grant SCE authority to operate without the ability to comply with all applicable technical specifications; (2) The restart of Unit 2 would allow SCE to operate beyond the scope of its existing license; and (3) SCE's Unit 2 Return to Service Plan includes a test or experiment that meets the criteria in 10 C.F.R. § 50.59 that require a license amendment.

Below, we provide a factual backdrop for our analysis, after which we discuss each of the above reasons in turn.The unprecedented extent of tube wear and failures that SCE experienced in the SONGS Unit 3 replacement steam generators reveal that these steam generators have serious design and operational issues (see SCE's Answering Brief at 10; supra Part I.A), placing them beyond the envelope of experience with U-tube steam generators.

SCE's investigation into the cause of the multiple tube leaks indicates that the design is prone to tube-to-tube wear caused by in-plane fluid elastic instability, which "had not been previously experienced in U-tube steam generators." SCE's Answering Brief at 10.As mentioned supra Part IA, fluid elastic instability results from the combination of localized high steam velocity, high steam void fraction, and insufficient contact forces between the tubes and the anti-vibration bars. The fluid elastic instability caused vibration of steam generator tubes in the in-plane direction resulting in rapid, localized tube wear. See SCE's Unit 2 Restart Plan at 2; Assessment for Tube-to-Tube Wear at 15."In contrast to the extensive

[tube-to-tube wear] in Unit 3, [tube-to-tube wear in Unit 2]existed in only a single pair of tubes ... in one of the two [replacement steam generators]." SCE's Answering Brief at 9. Although the Unit 2 steam generators did not experience the accelerated and extensive tube-to-tube wear suffered in the Unit 3 steam generators, they nevertheless are the identical design as those in Unit 3 and they operate under similar conditions.

See SCE's Answering Brief, Att. 18, SONGS UFSAR Excerpt at 5.4-20 [hereinafter SONGS UFSAR]; Brabec Aff. at 4-6, 18.

26 SCE claims that the fact that steam generator tube-to-tube wear was significantly less in Unit 2 than in Unit 3 is attributable to the differences in meeting fabrication tolerances.

See SCE's Answering Brief at 10, 92. Fabrication tolerances permit small differences between components designed to the same specifications, and SCE attributes the large difference in steam generator operational performance to very small differences in their construction.

4 3 More precisely, SCE asserts that the difference in steam generator tube wear between Unit 3 and Unit 2 is due in large part to differences in contact between the steam generator tubes and the anti-vibration bars arising from differences in meeting fabrication tolerances.

SCE explains the role played by anti-vibration bars in preventing in-plane vibrations as follows: "The effect of flat bar supports with small clearance is to act as apparent nodal points for flow-induced tube response.

They not only prevent out-of-plane mode as expected but also in-plane modes." Assessment for Tube-to-Tube Wear at 17.But "[w]ear at [anti-vibration bar] locations will degrade in-plane support effectiveness over time." Assessment for Tube-to-Tube Wear at 104. Such degradation can be caused "by a combination of turbulence and out-of-plane fluid-elastic excitation." Id. at 15. As contact is lost between the tube and the bar, the restraining effect of the anti-vibration bars in the in-plane direction decreases.

These decreases, when combined with certain thermal hydraulic conditions, allow in-plane vibration and tube-to-tube wear to develop over time at locations 43 Manufacturing of components is never perfectly exact. Thus, if the nominal design specifies a required distance between adjacent steam generator tubes, it will also specify how closely the manufacturer must come to that required distance.

This permitted variance from the design is referred to as the fabrication tolerance.

See SONGS Unit 2 Return to Service Report, Att. 6 -App, D, Operational Assessment of Wear Indications in the U-bend Region of San Onofre Unit 2 Replacement Steam Generators at 100-02 (ADAMS Accession No.ML12285A269, which is entitled "Attachment 6: Appendix A: Estimate of FEI-Induced TTW Rates" on ADAMS, but also contains Appendix D, starting on page 78 of 209 of the ADAMS portable document format (PDF) version).

Ironically, SCE indicates that the steam generators for Unit 3 were built more closely to design specifications than those in Unit 2, and it maintains that this greater manufacturing precision rendered the Unit 3 steam generators more susceptible to in-plane tube vibration.

See SCE's Answering Brief at 92; accord Unit 2 Return to Service Report at 36.

27 where it previously had not occurred.

See id. at 104; SONGS Unit 2 Return to Service Report, Att. 6 -App. B, SONGS U2C17 Generator Operational Assessment for Tube-to-Tube Wear at 21 (ADAMS Accession No. ML12285A268).

Moreover, tube-to-tube wear "due to in-plane fluid elastic instability is a unique degradation mechanism because one unstable tube can drive its neighbor into instability through repeated impact events." Assessment for Tube-to-Tube Wear at 18. It is thus possible for in-plane instability to develop in a single tube and propagate to a larger number of tubes in the vicinity.Wear of steam generator tubes is of critical importance to evaluations performed in the FSAR, because the tubes are part of the reactor coolant pressure boundary, and assurance of their integrity is required by General Design Criterion

14. Numerous analyses are grounded on the assumed integrity of steam generator tubes, and technical specifications exist to assure their integrity.

4 5 Any new phenomenon that could negatively impact tube integrity can affect, and possibly negate, assumptions used in FSAR analyses.SCE and its contractors have evaluated the in-plane tube-to-tube wear due to fluid elastic instability and have developed a theory to explain its occurrence and to predict how it can be avoided. As a result of comparing the thermal hydraulic conditions in the SONGS replacement steam generators with those of other steam generators, SCE concluded that the likelihood of fluid elastic instability will decrease if the steam quality in the steam generators is reduced (i.e., if the moisture content of the steam is increased).

See Unit 2 Return to Service Report at 37. SCE determined that a reduced steam quality results in greater "damping" within the steam generators, which decreases the potential for fluid elastic instability.

See id.44 10 C.F.R. Part 50, App. A -General Design Criteria for Nuclear Power Plants, Criterion 14, states: "Reactor Coolant Pressure Boundary.

The reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture." 45 See, eq., SCE's Answering Brief, Att. 9, SONGS Technical Specification 5.5.2.11, Steam Generator Program [hereinafter SONGS Unit 2 Technical Specifications].

28 SCE provided the following explanation regarding the relation between steam quality and damping, and the effect of damping on fluid elastic instability:

Damping is the result of energy dissipation and delays the onset of [fluid elastic instability].

Damping is greater for a tube surrounded by liquid compared to a tube surrounded by gas. Since quality describes the mass fraction of a vapor in a two-phase mixture, it provides insight into the fluid condition surrounding the tube. A higher steam quality correlates with dryer conditions and provides less damping. Conversely, lower steam quality correlates with wetter conditions resulting in more damping, which decreases the potential for [fluid elastic instability].

Unit 2 Return to Service Report at 38.When compared to steam generators at other plants that do not experience fluid elastic instability, SCE calculated that the steam quality in the SONGS replacement steam generators was higher when operated at 100% power. On the other hand, when SONGS steam generators were operated at70% power, steam quality was in the same range as those steam generators that did not experience fluid elastic instability.

See Assessment for Tube-to-Tube Wear, Figures 4-3 and 5-1.SCE concluded that limiting the power generated at SONGS Unit 2 to 70% would reduce steam quality and hydrodynamic pressure to values that would eliminate the thermal hydraulic conditions that cause fluid elastic instability and associated tube-to-tube wear in the SONGS Unit 2 steam generators.

See SCE's Unit 2 Restart Plan at 3; Unit 2 Return to Service Report at 37.46 SCE's most recent assessment indicates that, after operating for less than two years (i.e., 20.6 months), tube integrity for the Unit 2 steam generators can be guaranteed only for another eleven months of operation at 100% power. See SCE's Fifth Notification of Responses to RAIs, Enc. 1, Docket No. 50-361, Operational Assessment for 100% Power Case Regarding 46 See also Transcript of Briefing Before Commission on Steam Generator Tube Degradation (Feb. 7, 2013) at 48 (MHI agrees that a reduction to 70% power would improve the thermal hydraulic condition in the steam generators by reducing the steam quality and bringing it into a range seen in other steam generators manufactured by MHI).

29[CAL] Response (TAC No. ME9727) [SONGS], Unit 2 (Mar. 14, 2013) [hereinafter SCE's Fifth Notification of Responses to RAIs].Against the above backdrop, we explain below why we conclude that this CAL process is a de facto license amendment proceeding.

1. Under SCE's Return to Service Plan, Unit 2 Cannot be Operated "Over the Full Range Of Normal Operating Conditions" Up to 100% Power, Which is Inconsistent with a Technical Specification and Therefore Requires a License Amendment SONGS Unit 2 Technical Specification 5.5.2.11 b. 1 requires that "[a]ll inservice steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents.

4 7 Under its current license, SCE is authorized to operate Unit 2 up to 3,438 megawatts thermal, which is defined as 100% power. See SCE's Answering Brief, Aft. 19, SONGS Operating License 226 at 3.In its Unit 2 Return to Service Report, SCE proposes administratively to limit Unit 2 to 70% reactor power prior to a mid-cycle inspection outage. See SCE's Unit 2 Restart Plan at 3.Based on its analyses, asserts SCE, a 70% power-level limit will provide adequate margin to preclude the onset of in-plane fluid elastic instability and excessive tube wear. See id.If, pursuant to the CAL process, the NRC Staff were to authorize SCE to operate Unit 2 at a power limit not to exceed 70%, this condition would result in a deviation from the technical specification requirement that tube integrity be maintained over the "full range of normal operation conditions" up to 100%. Such a deviation from a technical specification requires a license amendment, thus converting this CAL process to a de facto license amendment proceeding.

4 8 47 See NRC's Answering Brief, Att. 8, Docket No. 50-361, SONGS Unit 2 Facility Operating License No. NPF-10 Excerpts at 5.0-14.48 In SCE's license amendment request for Unit 2 (see supra note 28), SCE seeks the following licensing revisions:

30 2. Unit 2 Cannot Operate Within the Scope of its Operating License, 4 9 Which Requires that the License Must be Amended SONGS Unit 2 is currently licensed to operate anywhere in the normal power range from 0% to 100% power with steam generators that meet the original design specifications.

The original steam generators in SONGS Unit 2 (and Unit 3) were replaced without a license amendment arising from design differences, which SCE claims was in compliance with 10 C.F.R. § 50.59. See Tr. at 79-81. As discussed in greater detail supra Part ll.B.2, section 50.59 permits changes with respect to components Ci.(., steam generators) without a license amendment under prescribed conditions that assure the replacement components are sufficiently similar to the original so that safety requirements are maintained or improved.

See 10 C.F.R. § 50.59(c)(2).

The replacement steam generators in SONGS Unit 3, however, unexpectedly demonstrated significant in-plane vibrations due to fluid elastic instability.

The vibrations were The proposed amendment requests that Technical Specification 5.5.2.11.b.1 be revised to add a footnote to require that compliance with the steam generator structural integrity performance criterion (SIPC) be demonstrated up to 70%Rated Thermal Power (2406.6 megawatts thermal) and that Facility Operating License Condition 2.C(1) "Maximum Power Level" be revised to add a footnote to restrict operation of SONGS Unit 2 to no more than 70% Rated Thermal Power for the SONGS Unit 2, Cycle 17.Docket No. 50-361, Amendment Application Number 263, Steam Generator Program [SONGS], Unit 2 (Apr. 5, 2013) at 1. Although SCE's license amendment request addresses the first reason underlying our conclusion that this CAL process constitutes a de facto license amendment proceeding, it does not address the alternative reasons underlying our conclusion (see infra Parts I1.C.2 and I1.C.3) and it, thus, does not fully address, much less moot, the first issue referred by the Commission.

49 Although the term "scope of an operating license" does not have a regulatory definition, it is a useful concept in the instant context, because the Court of Appeals for the First Circuit has held that actions by the NRC Staff constitute a de facto license amendment when they authorize a licensee to "engage in [activities]

beyond the ambit i[Le., scope] of [its] original license." CAN, 59 F.3d at 295; accord Perry, CLI-96-13, 44 NRC at 327. As described by the Commission, an operating license reflects a specific facility-design basis, a safety analysis documented in an FSAR, facility-specific technical specification, and NRC regulations.

See 63 Fed. Reg. 56,098, 56,099-100.

These factors comprise the scope of an operating license as we use the term in this Memorandum and Order.

31 severe enough to cause tube-to-tube contact resulting in accelerated wear of the tube wall and premature wall failure. See Assessment for Tube-to-Tube Wear at 18. This phenomenon has never before been seen in a U-tube steam generator (see SCE's Answering Brief at 10), which supports a conclusion that the replacement steam generators differ in significant respects from the originals.

Because the Unit 3 steam generators are identical in design to the Unit 2 steam generators (see SONGS UFSAR at 5.4-20; Brabec Aff. at 4-6, 18), we conclude that the latter steam generators likewise differ in significant respects from the originals.

Concerning the FSAR analysis of steam generator tube integrity, SCE states that "[t]he original analysis was fine if we had simply received steam generators that met our specifications" (i.e., were like-for-like replacements), but "[w]hat we had is a degraded or nonconforming condition in our steam generators where they did not perform per the procurement specifications." See Tr. at 98. The extent to which the replacement steam generators failed to perform per the procurement specifications is graphically illustrated by the fact that the original steam generators lasted about twenty-eight years, whereas SCE's most recent operational assessment indicates that, after less than two years of operation (i.e., 20.6 months), tube integrity for Unit 2 steam generators can be guaranteed only for another eleven months of operation at 100% power. See SCE's Fifth Notification of Responses to RAIs.Significantly, the UFSAR for the original steam generators for SONGS Units 2 and 3 excluded the possibility of in-plane vibrations caused by fluid elastic instability when evaluating the conditions necessary to maintain steam generator tube integrity.

In this regard, the UFSAR states: The steam generator was designed to ensure that critical vibration frequencies are well out of the range expected during normal operation and during abnormal conditions.

The tubing and tubing supports are designed and fabricated with considerations given to both secondary side flow-induced vibration and reactor coolant pump-induced vibrations.

32 SONGS UFSAR at 5.4-21 ;5 see also id. at 5.4-23 to 5.4-26 (analysis in section 5.4.2.3.1.3 evaluating conditions necessary to maintain tube integrity in the original steam generators based on the assumption that vibrations caused by in-plane fluid elastic instability will not occur). " However, the UFSAR assumption for the original steam generators that in-plane vibrations caused by fluid elastic instability were excluded by design is demonstrably unjustified for the replacement steam generators.

This renders inadequate the UFSAR section 5.4.2.3.1.3 analysis of steam generator tube integrity, which places the replacement steam generators outside the scope of the operating license.5 1 We conclude that until the tube degradation mechanism is fully understood, until reasonable assurance of safe operation of the replacement steam generators is demonstrated, and until there has been a rigorous NRC Staff review appropriate for a licensing action, the operation of Unit 2 would be outside the scope of its operating license because the replacement steam generator design must be considered to be inconsistent with the steam generator design specifications assumed in the FSAR and supporting analysis.

In short, the start-up of Unit 2 pursuant to the CAL process would transform that process into a de facto license amendment 50 The reference in the UFSAR to "critical vibration frequencies" and "secondary side flow-induced vibration" subsume the in-plane vibrations caused by fluid elastic instability experienced in the SONGS replacement steam generators.

See ,qenerally SONGS Unit 2 Return to Service Report, Att. 6 -App. D, Operational Assessment of Wear Indications in the U-bend Region of San Onofre Unit 2 Replacement Steam Generators at 10-12 (ADAMS Accession No.ML12285A269, which is entitled "Attachment 6: Appendix A: Estimate of FEI-Induced TTW Rates" on ADAMS, but also contains Appendix D, starting on page 78 of 209 of the ADAMS portable document format (PDF) version);

cf. SCE's Answering Brief, Att. 5, MHI Document L5-04GA564 Tube Wear of Unit-3 RSG Technical Evaluation Report at 11 (MHI states that incident to the design of the SONGS replacement steam generators, "only out-of-plane vibration of the[steam generator]

U-tubes was evaluated").

51 The purpose of the UFSAR section 5.4.2.3.1.3 analysis is to verify that General Design Criterion 14 -- which concerns maintaining integrity of the reactor coolant pressure boundary (see supra note 44) -- is satisfied.

We now know that General Design Criterion 14 cannot be satisfied for the steam generator tubes without an analysis of in-plane fluid elastic instability.

33 proceeding by allowing steam generator operation with a tube degradation mechanism not considered in the FSAR -i.e., in-plane vibrations due to fluid elastic instability.

5 2 3. A Unit 2 Start-Up Pursuant to SCE's Return to Service Report Would Result in SCE Conducting a Test or Experiment Pursuant to 10 C.F.R. § 50.59(c)(2)(viii), Which Requires a License Amendment In Part ll.B.3 supra, we determined that we may use the standards in section 50.59 --which establish when a "licensee shall obtain a license amendment" (10 C.F.R. § 50.59(c)(2))

-- as guidance to determine whether implementation of SCE's Unit 2 Return to Service Report requires a license amendment.

As relevant here, section 50.59 requires a licensee to seek a license amendment before implementing a "test or experiment" that will "[r]esult in a departure from a method of evaluation described in the [UFSAR] used in establishing the design basis or in the safety analysis." 10 C.F.R. § 50.59(c)(2)(viii).

Guided by that provision, we conclude that the authority to operate sought by SCE in its Unit 2 Return to Service Report is such a "test or experiment" that requires a license amendment and, thus, transforms this CAL process into a de facto license amendment proceeding.

5 3 SCE's analysis of the cause of the excessive tube wear and the measures it proposes to implement to preclude such wear are based on a theory as applied to U-tube steam generators, 52 The required change to the current FSAR analysis is that it must be augmented with a vibration analysis to assure that steam generator tubes do not fail prematurely due to tube-to-tube wear and that tubes are thus able to satisfy their design bases. As the Commission has explained, a licensee must seek a license amendment "at the point in time [when] the revised method [in the FSAR] becomes the means used for purposes of satisfying FSAR safety analysis or design bases." Changes, Tests, and Experiments:

Final Rule, 64 Fed. Reg. 53,582, 53,598 (Oct. 4, 1999).53 Although Petitioner's briefs rely heavily on 10 C.F.R. § 50.59 in support of its argument that this CAL process constitutes a de facto license amendment proceeding (see, e._., Petitioner's Brief at 19-23), they do not specifically reference section 50.59(c)(2)(viii).

We do not view this omission as a waiver, however, because Petitioner's brief included an argument based on the rationale in section 50.59(c)(2)(viii).

See Petitioner's Brief at 13; Large Affidavit at 5; see also Tr. at 42-44. Indeed, SCE understood Petitioner to be advancing such an argument, as evidenced by the fact that SCE endeavored to rebut it. See SCE's Answering Brief, App. A, Examples of Mischaracterizations in the FOE Brief, Affidavits, and NRDC Brief at 118-19.

34 although that theory is not yet supported by actual experience.

5 4 SCE nevertheless proposes to implement the following sequence of steps incident to the start-up and operation of Unit 2: (1) Unit 2 will be operated at 70% power for a limited duration; (2) this duration will be selected in such a manner that if the calculations are wrong, tube-to-tube wear will likely not progress far enough to cause any tube failures; (3) Unit 2 will then be shut down; and (4) 100% of the steam generator tubes will be inspected, and the inspection results can be compared to current wear data to determine the wear rate and provide confirmation vel non of the theoretical analysis.See SCE's Answering Brief at 10-11.The above steps satisfy the regulatory definition of "tests or experiments not described in the [UFSAR,]" which constitute "any activity where any structure, system, or component is utilized or controlled in a manner which is either: (i) [o]utside the reference bounds of the design bases as described in the [UFSAR] or (ii) [i]nconsistent with the analyses or descriptions in the [UFSAR]." 10 C.F.R. § 50.59(a)(6).

Because the phenomenon of in-plane fluid elastic instability had not previously been observed in U-tube steam generators, and because tube 54 As evidenced by the following, SCE's prediction that accelerated tube wear will be precluded by plant operations limited to 70% power is grounded on theory that is not yet supported by actual experience.

First, SCE's Steam Generator Operational Assessment for Tube-to-Tube Wear by Areva states that "[i]n-plane modes that have never been observed to be unstable even though the computed fluid-elastic stability margins are well below 1." Assessment for Tube-to-Tube Wear at 16. In other words, in-plane vibrations due to fluid elastic instability have not occurred even though the theory predicts in-plane instability.

Second, regarding the tests conducted by Westinghouse, which developed the criteria for in-plane vibrations used for the Unit 2 steam generators, SCE states that the "[in-plane]

instability was never observed in any of [the] square-pitch U-bend tests despite early attempts to force its occurrence without any [anti-vibration bar] support for flows up to three times the [out-of-plane]

instability threshold." SONGS Unit 2 Return to Service Report, Aft. 6 -App. D, Operational Assessment of Wear Indications in the U-bend Region of San Onofre Unit 2 Replacement Steam Generators at 14 (ADAMS Accession No. ML12285A269, which is entitled "Attachment 6: Appendix A: Estimate of FEl-Induced TTW Rates" on ADAMS, but also contains Appendix D, starting on page 78 of 209 of the ADAMS portable document format (PDF) version).Additionally, SCE states that in subsequent tests using triangular arrays, "[a]s was the case for square array patterns, no in-plane instability was observed in these tests even for U-bend tubes with no supports above the top tube support plate." Id. In short, there is a dearth of applicable experiential data available for in-plane vibrational motion, because, as conceded by SCE, "tube-to-tube wear due to in-plane [fluid elastic instability]

ha[s] not been previously experienced in U-tube steam generators." SCE's Answering Brief at 10.

35 failures based on that phenomenon had not been envisioned, the FSAR did not include an analysis or description of it. See supra note 50 and accompanying text. Accordingly, any operation of Unit 2 that might result in in-plane vibrations due to fluid elastic instability is"[i]nconsistent with the analyses or descriptions in the UFSAR" (10 C.F.R. § 50.59(a)(6)), which, in turn, is the type of "test or experiment" that triggers the obligation under section 50.59(c)(2)(viii) to seek a license amendment.

5" According to SCE, even if the sequence of start-up and operational steps in its Unit 2 Return to Service Report are viewed as tests or experiments that result in a "substantial change in an analysis" in the UFSAR, such a change "does not per se require a license amendment under 10 C.F.R. § 50.59." SCE's Answering Brief at 83. For example, "[i]f the analytical method is not described in the UFSAR," states SCE, "a change to that method does not require[a license amendment pursuant to section 50.59]." Id. "Furthermore, only changes to the'method of evaluation' are covered by 10 C.F.R. § 50.59(c)(2)(viii).

Changes to inputs to methods of evaluation are not covered by this provision" and, hence, do not trigger the requirement of seeking a license amendment.

Id.In other words, SCE claims that the standard in section 50.59(c)(2)(viii) has not been triggered because the tests or experiments embodied in its Unit 2 Return to Service Report are not inconsistent with the analysis or descriptions in the UFSAR. We disagree.The General Design Criteria in Appendix A of 10 C.F.R. Part 50 establish minimum requirements for the principal design criteria for water-cooled nuclear reactor plants. And as discussed supra note 44, General Design Criterion 14 refers to the reactor coolant boundary and includes steam generator tubes.55 The test or experiment proposed by SCE that must be the subject of a license amendment is required (1) to validate the vibration analysis that will become part of the FSAR (see supra note 52); and (2) to assure the steam generator tubes do not fail prematurely due to tube-to-tube wear and, thus, are able to satisfy their design bases. See id. (quoting 64 Fed.Reg. at 53,598).

36 Section 5.4.2.3.1 of the SONGS FSAR analyzes the maintenance of steam generator tube integrity.

Subsection 5.4.2.3.1.3.A describes the "Degraded Tube Evaluation." Its methodology essentially consists of calculating the maximum thinning for which tube integrity can be assured.5 6 Additionally, an inspection program, defined in Technical Specification 5.5.2.11, assures that tubes are removed from service before they reach maximum wall thinning.5 7 SCE's experience with SONGS Unit 3 forcefully demonstrates that the current analysis used to support the maintenance of steam generator tube integrity is inadequate for the replacement steam generators.

More specifically, the current analysis underlying tube inspections to prevent maximum thinning is inadequate to assure tube integrity in light of the accelerated wear mechanism that might occur in this type of steam generator, and that did occur in the Unit 3 steam generators.

Without question, the current analysis described in the FSAR failed to achieve its intended purpose, and it must therefore be changed. We view this change as sufficiently significant to trigger the license amendment requirement of section 50.59(c)(2)(viii), because it is "[i]nconsistent with the analyses or descriptions in the [UFSAR]." 10 C.F.R. § 50.59(a)(6)(ii).

Indeed, this change is a radical deviation from the prior analysis and description in the UFSAR, because without this change, tube integrity cannot be assured for the SONGS steam generators.

In sum, we conclude that SCE's Unit 2 Restart Plan, if implemented, would (1) grant SCE authority to operate without the ability to comply with all technical specifications; (2) grant SCE authority to operate beyond the scope of its existing license; and (3) grant SCE authority to 56 See SONGS UFSAR at 5.4-24, section 5.4.2.3.1.3.A.

57 See SONGS Unit 2 Technical Specification, section 5.5.2.11.

37 operate its replacement steam generators in a manner that constitutes a test or experiment that meets the criteria in 10 C.F.R. § 50.59(c)(2)(viii) for seeking a license amendment.

For these three independent reasons, this CAL process constitutes a de facto license amendment proceeding that is subject to a hearing opportunity under section 189a of the AEA.D. Because Our Resolution of the First Referred Issue Grants Petitioner All the Relief Its Contention Seeks, the Second Issue Referred by the Commission Is Moot The second issue referred to this Licensing Board is whether Petitioner "meets the standing and contention admissibility requirements of 10 C.F.R. § 2.309." CLI-12-20, 76 NRC at-(slip op. at 5).8 In its contention, Petitioner claims that "SONGS cannot be allowed to restart without a license amendment and attendant adjudicatory public hearing as required by 10 C.F.R. § 2.309, in which Petitioner and other members of the public may participate." Petition to Intervene at 16.In the course of resolving the first issue referred by the Commission (supra Part II.C), we concluded that this CAL process constitutes a de facto license amendment proceeding that is subject to a hearing opportunity.

As Petitioner conceded during oral argument (see Tr. at 29), such a conclusion grants all the relief sought in its contention.

Petitioner's contention, therefore, is moot.Were we to adjudicate either (1) the admissibility of a moot contention, or (2) the standing of a petitioner who sought to adjudicate a moot contention, we would be issuing an advisory opinion in derogation of Commission precedent.

This we decline to do. See U.S.Dep't of Energy (High-Level Waste Repository), CLI-08-21, 68 NRC 351, 352 (2008); accord 58 SCE urged this Board to resolve the standing and contention admissibility issues before considering the de facto license amendment issue. See Tr. at 63-65. The NRC Staff and Petitioner disagreed (see Tr. at 138 (NRC Staff); Tr. at 150 (Petitioner)), arguing that SCE's suggested approach was inconsistent with the Commission's unequivocal directive "to consider whether: (1) the [CAL] ... constitutes a de facto license amendment that would be subject to a hearing opportunity

... ; and, if so, (2) whether the petition meets the standing and contention admissibility requirements." CLI-12-20, 76 NRC at __ (slip op. at 5). We agree with the NRC Staff and Petitioner that SCE's suggested approach is at odds with the Commission's clearly expressed instruction in CLI-12-20.

38 Texas Utilities Generating Co. (Comanche Peak Steam Elec. Station), ALAB-714, 17 NRC 86, 94 (1983)."'Ill. CONCLUSION For the foregoing reasons, we resolve the first issue referred by the Commission in the affirmative, concluding that the CAL process for SONGS Units 2 and 3 constitutes a de facto license amendment proceeding that is subject to a hearing opportunity under section 189a of the AEA. Our resolution of the first issue grants Petitioner the relief it seeks in its contention; namely, the opportunity for an adjudicatory hearing incident to the license amendment proceedings for the restart of Units 2 and 3. Petitioner's contention is thus moot, which renders moot the second issue referred by the Commission.

The proceeding before this Board is therefore terminated.

59 "It is well established that, absent compelling reasons, the Commission adheres to the'case' or 'controversy' doctrine in its adjudicatory proceedings." Hydro Resources, Inc. (P.O.Box 777, Crownpoint, New Mexico 87313), LBP-05-17, 62 NRC 77, 91 (2005) (citing Texas Utilities Elec. Co. (Comanche Peak Steam Elec. Station), CLI-93-10, 37 NRC 192, 200 n.28 (1993)). Pursuant to this doctrine, a justiciable controversy must involve parties who raise questions "presented in an adversary context and in a form historically viewed as capable of resolution through the judicial process." Flast v. Cohen, 392 U.S. 83, 95 (1968). When -- as is the case here -- a petitioner obtains the relief it is seeking before the admissibility of its contention is resolved, the admissibility vel non of the contention is no longer justiciable, because it no longer presents a live controversy involving a true clash of interests that is susceptible to meaningful adjudicative relief. Cf. Moore v. Charlotte-Mecklenburcq Bd. of Ed., 402 U.S. 47, 48 (1971) (per curiam) (dismissing appeal for lack of live controversy where both litigants desired the same result); David B. Kuhl (Denial of Senior Reactor Operator License), LBP-09-14, 70 NRC 193, 195-96 (2009) (dismissing hearing request as moot where petitioner's claim was not susceptible to meaningful adjudicative relief).

39 If a party wishes to appeal this decision, it must file a petition for review with the Commission within 25 days after service of this decision.

See 10 C.F.R. § 2.341(b)(1).

Unless otherwise authorized by law, a party to an NRC adjudicatory proceeding must seek Commission review before seeking judicial review of an agency action. See id.It is so ORDERED.THE ATOMIC SAFETY AND LICENSING BOARD IRA!E. Roy Hawkens, Chairman ADMINISTRATIVE JUDGE IRA!Dr. Anthony J. Baratta ADMINISTRATIVE JUDGE IRA!Dr. Gary S. Arnold ADMINISTRATIVE JUDGE Issued at Rockville, Maryland this 13th day of May 2013.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the Matter of SOUTHERN CALIFORNIA EDISON CO.(San Onofre Nuclear Generating Station -Units 2 and 3)))))Docket Nos. 50-361-CAL) 50-362-CAL

)CERTIFICATE OF SERVICE I hereby certify that copies of the foregoing MEMORANDUM AND ORDER (Resolving Issues Referred by the Commission in CLI-12-20)

-LBP-13-07 have been served upon the following persons by Electronic Information Exchange.Office of Commission Appellate Adjudication U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: ocaamail(anrc.gov Atomic Safety and Licensing Board Panel U.S. Nuclear Regulatory Commission Mail Stop -T-3 F23 Washington, DC 20555-0001 E. Roy Hawkens Chief Administrative Judge E-mail: roy.hawkens(anrc..ov Anthony J. Baratta Administrative Judge Email: anthony.baratta(,nrc.qov Gary S. Arnold Administrative Judge Email: .ary.arnold(@nrc.gov U.S. Nuclear Regulatory Commission Office of the Secretary of the Commission Mail Stop O-16C1 Washington, DC 20555-0001 Southern California Edison Company Douglas Porter, Esq.Director and Managing Attorney Generation Policy and Resources Law Department 2244 Walnut Grove Ave., GO1, Q3B, 335C Rosemead, CA 91770 Email: douqlas.porter(csce.com Counsel for Licensee Morgan, Lewis & Bockius, LLP 1111 Pennsylvania, Ave. N.W.Washington, D.C. 20004 Paul M. Bessette, Esq.Kathryn M. Sutton, Esq.Stephen J. Burdick, Esq.Steven P. Frantz, Esq.William E. Baer, Jr.Mary Freeze, Legal Secretary Lena M. Long, Legal Secretary E-mail: pbessefte(,morqanlewis.com sburdickc&-morqanlewis.com ksuttonc-morqanlewis.com wbaer(amorqanlewis.com sfrantz(amorqanlewis.com mfreeze(&)morqanlewis.com Ilong(aqmorqanlewis.com Hearing Docket E-mail: hearingdocket(anrc.gov San Onofre Nuclear Generating Station, Units 2 and 3, Docket Nos. 50-361 and 50-362-CAL MEMORANDUM AND ORDER (Resolving Issues Referred by the Commission in CLI-12-20)

-LBP-13-07 U.S. Nuclear Regulatory Commission Office of the General Counsel Mail Stop 15 D21 Washington, DC 20555-0001 Edward Williamson, Esq.David Roth, Esq.Catherine Kanatas, Esq.David Cylkowski, Esq.Jeremy Wachutka, Esq.Email: edward.williamsoncanrc..gov david.roth(,nrc.qov catherine.kanatas(onrc.qov david.cylkowski(cnrc.gov ieremy.wachutka(anrc.qov OGG Mail Center: opqcmailcenter(ýnrc.qov Dated at Rockville, Maryland this 1 3 th day of May, 2013 Friends of the Earth Ayres Law Group 1707 L St., NW Suite 850 Washington, D.C. 20036 Richard E. Ayres, Esq.Jessica L. Olson, Esq.Kristin L. Hines, Esq.Email: ayresra.ayreslawqroup.com olsoni(@ayreslawqroup.com hinesk(cayreslawqroup.com Natural Resources Defense Council Geoffrey H. Fettus, Esq.1152 15th Street, NW Suite 300 Washington, DC 20005 Email: qfettus(&nrdc.org

[Original signed by Herald M. Speiser Office of the Secretary of the Commission 2