ML21081A308
| ML21081A308 | |
| Person / Time | |
|---|---|
| Site: | Palisades, Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 03/22/2021 |
| From: | Gill W, Glew W, Leidich A, Doris Lewis, Lovett A, Raimo S Balch & Bingham, LLP, Entergy Nuclear Operations, Entergy Services, Holtec, Pillsbury, Winthrop, Shaw, Pittman, LLP |
| To: | NRC/OCM |
| SECY RAS | |
| References | |
| 50-155-LT, 50-255-LT, 72-007-LT, 72-043-LT, License Transfer, RAS 56015 | |
| Download: ML21081A308 (52) | |
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4834-2343-5490.v1 March 22, 2021 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Commission In the Matter of
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Entergy Nuclear Operations, Inc.,
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Entergy Nuclear Palisades, LLC,
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Docket Nos. 50-255-LT Holtec International, and
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50-155-LT Holtec Decommissioning International, LLC
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72-007-LT
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72-043-LT (Palisades Nuclear Plant and
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Big Rock Point Site)
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Applicants Answer Opposing the Michigan Attorney Generals Petition for Leave to Intervene and Request for a Hearing
2 4834-2343-5490.v1 Table of Contents I. Introduction............................................................................................................................... 3 II. Background............................................................................................................................... 4 III. Legal and Regulatory Framework............................................................................................ 8 A. NRC Decommissioning and Related Financial Assurance Requirements......................... 8 B. Spent Fuel Management................................................................................................... 12 C. NRC Reactor License Transfer Requirements.................................................................. 13 D. Legal Standards for Contention Admissibility................................................................. 15 IV. The Michigan AG Fails to Set Forth an Admissible Contention............................................ 17 A. Contention MI-1 Is Inadmissible Because It Is Speculative and Unsupported by Information Demonstrating a Genuine Material Dispute with the Plausible Assumptions in the Application and DCE........................................................................ 17 The mere existence of differences between the current decommissioning cost estimate and prior estimates does not show that the DCE assumptions are implausible or demonstrate any genuine dispute with the Application...................... 20 The Michigan AG fails to raise a genuine dispute with the plausible DCE assumptions on transfer of spent nuclear fuel............................................................. 24 The mere existence of differences between the current decommissioning cost estimate and dated experience at limited other sites does not demonstrate any genuine dispute with the Application......................................................................... 27 The Michigan AG does not demonstrate any genuine material dispute with the contingency factor in the DCE.................................................................................... 29 The Michigan AG fails to raise a genuine dispute with HDIs estimate of waste volume......................................................................................................................... 30 The Michigan AG fails to raise a genuine dispute with HDIs overall cost estimate....................................................................................................................... 34 The Michigan AG fails to raise a genuine dispute with HDIs estimate for repackaging the VSC-24 canisters.............................................................................. 42 The Michigan AGs dispute with HDIs assumed growth rate is an improper challenge to NRC rules............................................................................................... 42 The Michigan AG fails to raise a genuine dispute with the application when challenging Holtec Palisades reliance on the nuclear decommissioning trust.......... 44 B. Contention MI-2 Is Inadmissible as an Improper Challenge to NRC Rules..................... 48 V. Conclusion.............................................................................................................................. 51
3 4834-2343-5490.v1 March 22, 2021 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Commission In the Matter of
)
)
Entergy Nuclear Operations, Inc.,
)
Entergy Nuclear Palisades, LLC,
)
Docket Nos. 50-255-LT Holtec International, and
)
50-155-LT Holtec Decommissioning International, LLC
)
72-007-LT
)
72-043-LT (Palisades Nuclear Plant and
)
Big Rock Point Site)
)
Applicants Answer Opposing the Michigan Attorney Generals Petition for Leave to Intervene and Request for a Hearing I.
Introduction Pursuant to 10 C.F.R. § 2.309(i)(1), Entergy Nuclear Operations, Inc. (ENOI), Entergy Nuclear Palisades, LLC (ENP), Holtec International (Holtec), and Holtec Decommissioning International, LLC (HDI) (collectively, Applicants) hereby answer and oppose the Michigan Attorney General (Michigan AG) Petition to Intervene and Request for a Hearing filed on February 24, 2021 (Petition).1 The Michigan AG seeks to intervene in the license transfer proceeding for the Palisades Nuclear Plant (Palisades) and Big Rock Point Site (BRP) and requests that the Nuclear Regulatory Commission (Commission or NRC) conduct a hearing on the license transfer request. The Commission should deny the Petition because the Michigan AG has failed to propose an admissible contention.
1 State of Michigan Attorney General, Petition of the Michigan Attorney General for Leave to Intervene and for a Motion (Feb. 24, 2021) (hereinafter Michigan AG Petition or Petition).
4 4834-2343-5490.v1 To be admitted as a party and granted a hearing, a petitioner must demonstrate standing and proffer at least one admissible contention.2 Applicants do not contest that the Michigan AG has standing, but neither of the Michigan AGs two proposed contentions demonstrates a genuine, material dispute with the Application. Proposed Contention M-1 essentially alleges that the license transferees, who would acquire and decommission Palisades after it permanently ceases operation, have not shown financial qualifications because the decommissioning cost estimate (DCE) on which their financial qualifications is based underestimates various costs.
For the most part, the Michigan AGs arguments opine about various hypothetical scenarios and speculate that such scenarios might result in costs above those estimated in the DCE. As a matter of law, this type of speculation is insufficient for an admissible contention, as it fails to show that the DCE relies on any assumptions that are implausible in a manner that could affect the outcome of the proceeding. Proposed Contention M-2 incorrectly argues that the demonstration of financial qualifications cannot assume that the Commission will grant an exemption allowing the Palisades nuclear decommissioning trust (NDT) to be used for spent fuel management and site restoration. This argument has no support in the NRC rules and has been soundly rejected by the Commission in the recent Indian Point license transfer proceeding.
II.
Background
On December 23, 2020, Applicants submitted an application requesting that the Commission approve (1) the indirect transfer of control of Renewed Facility Operating License No. DPR-20 for Palisades and the general license for the Palisades Independent Spent Fuel Storage Installation (ISFSI) and Facility Operating License No. DPR-6 for BRP and the general license for the BRP ISFSI to Holtec; and (2) the transfer of ENOIs operating authority 2 10 C.F.R. § 2.309(a).
5 4834-2343-5490.v1 (i.e., its authority to conduct licensed activities at Palisades and BRP) to HDI.3 The transfer is sought as part of a transaction in which Holtec will acquire indirect control of Palisades and BRP. Under the transaction, Holtec Palisades, LLC (Holtec Palisades), an indirect, wholly-owned subsidiary of Holtec, will become the licensed owner of Palisades and the BRP Site, and ENOIs operating authority will be transferred to HDI, a wholly-owned subsidiary of Holtec formed to decommission nuclear plants. This transaction would occur only after Palisades has permanently ceased operation and all spent nuclear fuel has been permanently removed from the reactor vessel.4 HDI plans to then complete the transfer of Palisades spent nuclear fuel to the Palisades ISFSI as soon as practicable and, following a ten-year period of dormancy, to complete the radiological decommissioning, restoration, and release for unrestricted use of the Palisades Site by approximately 2041.5 The Application provides the information required by 10 C.F.R. § 50.80, including a demonstration of HDIs and Holtec Palisades technical and financial qualifications. Because the license transfers will occur after Palisades has permanently ceased operation and has been permanently defueled, the demonstration of financial qualifications is based on funding assurance for decommissioning and spent fuel management. With respect to Palisades, the Application provides a cash flow analysis demonstrating that, crediting a 2-percent annual real rate of return as permitted by the NRC rules, the balance in Palisades NDT will be sufficient to cover the estimated cost of decommissioning and spent fuel management, as well as site 3 Application for Order Consenting to Transfers of Control of Licenses and Approving Conforming License Amendments, Palisades Nuclear Plant, Docket Nos. 50-255 and 72-007, Renewed Facility Operating License No.
DPR-20, Big Rock Point, Docket Nos. 50-155 and 72-043, License No. DPR-6 (Dec. 23, 2020) (ADAMS Accession No. ML20358A075) (hereinafter Application or LTA).
4 BRP has already been decommissioned and all property other than the ISFSI and an adjacent non-impacted parcel of property has been released for unrestricted use. LTA, Encl. 1 at 2.
5 LTA, Encl. 1 at 18.
6 4834-2343-5490.v1 restoration, with an excess of approximately $20 million remaining at license termination.6 As stated in the Application, reimbursement of spent fuel management expenses by the U.S.
Department of Energy (DOE), which is not credited in the cash flow analysis, would provide a substantial source of additional funds that could be used to adjust funding assurance if necessary.7 On the same day that the license transfer application was filed, HDI also submitted a Post-Shutdown Decommissioning Activities Report (PSDAR),8 which includes HDIs site-specific DCE.9 Because of the reliance on Palisades NDT, HDI also requested, concurrent with submission of the LTA, an exemption to allow the NDT to be used for spent fuel management and site restoration costs.10 The PSDAR and DCE explain that HDIs cost estimate is based on information compiled during an extensive due diligence period,11including review of Palisades decommissioning records required by 10 C.F.R. § 50.75(g), subsurface monitoring reports, groundwater contamination reports, and annual NRC effluent reports12input and professional judgment of experienced specialty subcontractors and subject-matter experts, and real time experience and executed contracts from Holtec-owned nuclear decommissioning sites.13 Additionally, HDIs 6 LTA, Encl. 1, Att. E at 5.
7 LTA, Encl. 1, at 18.
8 Letter from P. Cowan, HDI, to NRC, Post Shutdown Decommissioning Activities Report including Site-Specific Decommissioning Cost Estimate for Palisades Nuclear Plant (Dec. 23, 2020) (ADAMS Accession No. ML20358A232) (hereinafter PSDAR). This PSDAR is contingent upon NRC approval of the license transfers, completion of transfers of the licenses, and the sale closure. Id. at 2.
9 PSDAR, Encl. 1 (hereinafter DCE). The DCE is also summarized in the Application. See LTA, Encl. 1, Att. E at 2-4.
10 Request for Exemptions from 10 CFR 50.82(a)(8)(i)(A) and 10 CFR 50.75(h)(1)(iv), Palisades Nuclear Plant, Docket Nos. 50-255 and 72-007, Renewed Facility Operating License No. DPR-20 (Dec. 23, 2020) (ADAMS Accession No. ML20358A239).
11 PSDAR at 16; DCE at 38.
12 DCE at 21.
13 PSDAR at 16; DCE at 7.
7 4834-2343-5490.v1 breakdown of work and cost estimates incorporate subcontractor estimates for reactor segmentation and waste removal.14 For large contracts, the selected contractors, including affiliates, will be required to post performance bonds (or insurance, where appropriate) issued by Treasury-rated surety companies to guarantee performance of work scope to ensure the work is performed at the specified costs.15 Further, the DCE includes a 12-percent contingency allowance16 (amounting to approximately $50 million in contingency) in the DCE on which the cash flow analysis is based.
As discussed in the DCE, the estimates of costs associated with license termination in NUREG/CR-5884, Revised Analyses of Decommissioning for the Reference Pressurized-Water Reactor Power Station, were reviewed to evaluate the reasonableness of the estimates in the DCE.17 In addition, the Palisades decommissioning cost estimates for license termination, spent fuel management and site restoration activities were compared to costs from similar activities from other decommissioned pressurized water reactor nuclear power plants.18 On February 4, 2021, the NRC published a notice in the Federal Register regarding the Application.19 In the Notice, the Commission provided an opportunity to any person whose interest may be affected, within 20 days of the Notice, to request a hearing and file a petition for leave to intervene in the direct transfer proceeding. The Notice states that any such petitions should be filed in accordance with the Commissions Agency Rules of Practice and Procedure 14 LTA at 18.
15 Id.
16 DCE at 41.
17 Id. at 38.
18 Id.
19 Palisades Nuclear Plant and Big Rock Point Plant Consideration of Approval of Transfer of Control of Licenses and Conforming Amendments, 86 Fed. Reg. 8,225 (Feb. 4, 2021) (the Notice).
8 4834-2343-5490.v1 set forth in 10 C.F.R. Part 2 and lays out the standards for pleading admissible contentions and establishing standing.
On February 24, 2021, the Michigan AG filed its Petition. The Petition includes a Declaration of Nicholas J. Capik (Capik Decl.), which essentially makes statements that are the same as assertions in the Petition without elaboration or further support.
III.
Legal and Regulatory Framework A.
NRC Decommissioning and Related Financial Assurance Requirements Under NRC regulations, decommissioning a nuclear reactor means to safely remove the facility from service, reduce residual radioactivity to a level that allows releasing the property for unrestricted use (or restricted use subject to conditions, not proposed here), and terminate the license.20 NRC regulations require that applicants and licensees provide reasonable assurance that funds will be available for the decommissioning process.21 The primary methods of providing financial assurance for decommissioning permitted by the NRC are through (1) prepayment; (2) an external sinking fund; (3) a surety, insurance, or other guarantee; or (4) a combination of these or equivalent mechanisms.22 Once a licensee decides to cease operations permanently, NRC regulations impose additional requirements that govern three sequential phases for decommissioning activities: (1) initial activities; (2) major decommissioning and storage activities; and (3) license termination activities.23 The decommissioning process begins when a licensee certifies to the NRC Staff that it has permanently ceased operations and it has permanently removed fuel from the reactor 20 10 C.F.R. § 50.2.
21 10 C.F.R. § 50.75(a). The NRC requires nuclear power plant licensees to report to the agency the status of their decommissioning funds at least once every two (2) years, annually within five (5) years of the planned shutdown, and annually once the plant ceases operation.
22 10 C.F.R. § 50.75(e)(1)(i)-(iii), (vi).
23 See generally 10 C.F.R. § 50.82(a).
9 4834-2343-5490.v1 vessel.24 NRC regulations require a licensee to submit a PSDAR prior to or within two years following the permanent cessation of operations.25 The PSDAR must contain a description of the planned decommissioning activities along with a schedule for their accomplishment, a discussion that provides the reasons for concluding that the environmental impacts associated with site-specific decommissioning activities will be bounded by appropriate previously-issued environmental impact statements, and a site-specific decommissioning cost estimate, including the projected cost of managing irradiated fuel.26 The Staff notices its receipt of the PSDAR, makes the PSDAR available for public comment, and holds a public meeting on its contents.27 The PSDAR serves to inform the public and NRC Staff of the licensees proposed activities,28 but approval is not required under the NRC rules.
Thus, absent any objections from the NRC Staff, the licensee may commence major decommissioning activities ninety (90) days after the Staff receives the PSDAR.29 However, under NRC regulations, a licensee may not perform decommissioning activities that would foreclose the release of the site for possible unrestricted use, result in significant environmental 24 10 C.F.R. § 50.82(a)(1)(i)-(ii).
25 10 C.F.R. § 50.82(a)(4)(i).
26 Id.
27 10 C.F.R. § 50.82(a)(4)(ii). The Staff presents comments received at the public meeting held on the PSDAR and makes available to the public a written transcript of the meeting. See Regulatory Guide 1.185, Rev. 1, Standard Format and Content for Post-Shutdown Decommissioning Activities Report (June 2013) at 4 (ADAMS Accession No. ML13140A038). As discussed further below, the PSDAR process does not give rise to a hearing opportunity.
28 Decommissioning of Nuclear Power Reactors, Final Rule, 61 Fed. Reg. 39,278, 39,281 (July 29, 1996) (1996 Decommissioning Rule). In establishing the current process governing decommissioning, the NRC eliminate[d] the need for an approved decommissioning plan before major decommissioning activities can be performed. Id.
29 10 C.F.R. § 50.82(a)(5). A major decommissioning activity for a nuclear power plant such as Palisades is defined as any activity that results in permanent removal of major radioactive components, permanently modifies the structure of the containment, or results in dismantling components for shipment containing greater than class C waste in accordance with [10 C.F.R. § 61.55]. 10 C.F.R. § 50.2.
10 4834-2343-5490.v1 impacts not previously reviewed, or result in the lack of reasonable assurance that adequate funds will be available for decommissioning.30 The PSDAR must include a site-specific DCE.31 Once a licensee submits its decommissioning cost estimate, it generally is allowed access to the balance of the NDT fund monies for the remaining decommissioning activities with broad flexibility.32 However, the use of the NDT fund is limited in three important respects. First, withdrawals from the fund must be for expenses for legitimate decommissioning activities consistent with the definition of decommissioning in 10 C.F.R. § 50.2.33 Second, the expenditure must not reduce the value of the decommissioning trust below an amount necessary to place and maintain the reactor in a safe storage condition if unforeseen conditions or expenses arise.34 Finally, the withdrawals must not inhibit the ability of the licensee to complete funding of any shortfalls in the decommissioning trust needed to ensure the availability of funds to ultimately release the site and terminate the license.35 Additionally, the NRC Staff monitors the licensees use of the decommissioning trust fund via its review of the licensees annual financial assurance status reports.36 Those annual reports must include, among other information, the amount spent on decommissioning activities, the amount remaining in the fund, and an updated estimate of the costs required to complete decommissioning.37 If the licensee or NRC identifies a shortfall between the remaining funds 30 10 C.F.R. § 50.82(a)(6).
31 10 C.F.R. § 50.82(a)(4)(i).
32 See 1996 Decommissioning Rule, 61 Fed. Reg. at 39,285.
33 10 C.F.R. § 50.82(a)(8)(i)(A).
34 10 C.F.R. § 50.82(a)(8)(i)(B).
35 10 C.F.R. § 50.82(a)(8)(i)(C).
36 10 C.F.R. § 50.82(a)(8)(v).
37 10 C.F.R. § 50.82(a)(8)(v)(A)-(B).
11 4834-2343-5490.v1 and the updated cost to complete decommissioning (as a result of these annual status reports or otherwise), then the licensee must provide additional financial assurance.38 The annual reports must also include the status of funding to manage spent fuel, including the amount of funds available, the projected cost of managing spent fuel until it is removed by the DOE and, if there is a funding shortfall, a plan to obtain additional funds to cover the cost.39 Unless otherwise authorized, the site must be decommissioned within sixty (60) years.40 The licensee remains subject to NRC oversight until decommissioning is completed and the license is terminated. The licensee must submit a license termination plan (LTP) at least two (2) years before the planned license termination date.41 The LTP must include (a) a site characterization; (b) identification of remaining dismantlement activities; (c) plans for site remediation; (d) detailed plans for the final radiation survey; (e) description of the end use of the site, if restricted; (f) an updated site-specific estimate of remaining decommissioning costs; (g) a supplement to the environmental report describing any new information or significant environmental change associated with the licensees proposed termination activities; and (h) identification of parts, if any, of the facility or site that were released for use before approval of the license termination plan.
The NRC, in turn, must notice receipt of the LTP in the Federal Register, make the plan available to the public for comment, schedule a public meeting near the facility to discuss the plans contents, and offer an opportunity for a public hearing on the license amendment 38 10 C.F.R. § 50.82(a)(8)(vi). The analysis of whether a shortfall exists assumes a two (2) percent annual real rate of return.
39 10 C.F.R. § 50.82(a)(8)(vii).
40 10 C.F.R. § 50.82(a)(3).
41 10 C.F.R. § 50.82(a)(9)(i).
12 4834-2343-5490.v1 associated with the LTP.42 The NRC will also prepare an environmental assessment or supplemental environmental impacts statement, as appropriate, to update prior environmental documentation prepared for compliance with the National Environmental Policy Act (NEPA).43 The Commission may not approve the LTP (via license amendment) and terminate the license until it makes the findings set forth in 10 C.F.R. § 50.82(a)(10) and (a)(11),
respectively.44 B.
Spent Fuel Management NRC regulations also address the need to ensure adequate funds for the management of spent nuclear fuel. Within two (2) years following permanent cessation of operations or five (5) years before expiration of the reactor operating license, whichever occurs first, a licensee must submit written notification to the NRC for its review and preliminary approval of the program by which the licensee intends to manage and provide funding for the management of all irradiated fuel at the reactor following permanent cessation of operation of the reactor until such fuel is transferred to the U.S. Department of Energy (DOE).45 Licensees also must notify the NRC of any significant changes in the proposed Irradiated Fuel Management Plan (IFMP) as described in the initial notification.46 The DCE required by the PSDAR must include the projected costs of managing spent fuel until the spent fuel is assumed to be removed from the site.47 Once a licensee files that DCE, it must report annually to the NRC on the status of its funding to manage spent fuel, including the amount of funds available, the projected cost of 42 10 C.F.R. § 50.82(a)(9)(iii).
43 10 C.F.R. § 51.95(d).
44 10 C.F.R. § 50.82(a)(10), (11).
45 10 C.F.R. § 50.54(bb).
46 Id.
47 10 C.F.R. § 50.82(a)(4)(i).
13 4834-2343-5490.v1 managing spent fuel until it is removed by the DOE, and, if there is a funding shortfall, a plan to obtain additional funds to cover the cost.48 C.
NRC Reactor License Transfer Requirements Under Section 184 of the Atomic Energy Act, an NRC license, or any right thereunder, may not be transferred, assigned, or in any manner disposed of, either voluntarily or involuntarily, directly or indirectly, through transfer of control of the license to any person, unless the NRC first gives its consent in writing.49 This statutory requirement is codified in 10 C.F.R. § 50.80 and applies to both direct and indirect license transfers.50 A transfer of control may involve either the licensed operator or any individual licensed owner of the facility.51 Before approving a license transfer, the NRC reviews, among other things, the technical and financial qualifications of the proposed transferee.52 The transfer review, in other words, focuses on the potential impact on the licensees ability both to maintain adequate technical qualifications and organizational control and authority over the facility, and to provide adequate funds for safe operation and decommissioning.53 To grant a license transfer application, the NRC must find reasonable assurance of financial qualifications. License transfer applicants for reactors that will be permanently shut 48 10 C.F.R. § 50.82(a)(8)(vii).
49 42 U.S.C. § 2234.
50 See NRC Backgrounder, Reactor License Transfers, at 1-2 (Apr. 2016) (ADAMS Accession No. ML040160803). A direct license transfer occurs when an entity seeks to transfer a license it holds to a different entity (e.g., when a plant is to be sold or transferred to a new licensee in whole or part). An indirect license transfer takes place when there is a transfer of control of the license or of a license holder (e.g., as a result of a merger or acquisition at high levels within or among corporations). Id.
51 See id. at 1.
52 See 10 C.F.R. §§ 50.80(b)(1), (c)(1); see also NUREG-1577, Rev. 1, Standard Review Plan on Power Reactor Licensee Financial Qualifications and Decommissioning Funding Assurance (Dec. 13, 2001) (ADAMS Accession No. ML013330264).
53 See Final Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry, 62 Fed. Reg. 44,071, 44,077 (Aug. 19, 1997).
14 4834-2343-5490.v1 down at the time of the transfer may rely solely on the adequacy of the NDT to demonstrate reasonable assurance.54 Longstanding Commission precedent makes clear that the reasonable assurance standard does not require an applicant to meet an absolute or beyond a reasonable doubt standard.55 [T]he mere casting of doubt on some aspect of an application is legally insufficient to defeat a finding of reasonable assurance.56 In this regard, [w]hen evaluating a license transfer applicants ability to meet financial obligations related to decommissioning, the NRC will accept financial assurances based on plausible assumptions and forecasts, even though the possibility is not insignificant that things will turn out less favorably than expected.57 As the Commission has explained, We accept financial assurance based on plausible assumptions and forecasts because, particularly at the early stages of a decommissioning project, cost estimates are necessarily uncertain. This observation is as true for the site-specific cost estimates submitted by a license transfer applicant as it is for the site-specific estimates submitted by a current licensee that is preparing for and entering the decommissioning process. We see no reason to require that an applicants cost estimates be more detailed, more certain, or more conservative than the site-specific estimates submitted by current NRC licensees, who may rely on plausible assumptions when preparing their estimates.58 54 Entergy Nuclear Operations, Inc. et al. (Indian Point Nuclear Generating Station, Units 1, 2, and 3 and ISFSI),
CLI-21-01, 92 N.R.C. at __ (slip op at 49) (Jan. 2021) (ADAMS Accession No ML21015A201).
55 AmerGen Energy Co., LLC (Oyster Creek Nuclear Generating Station), CLI-09-7, 69 N.R.C. 235, 262 n.142 (2009); Commonwealth Edison Co. (Zion Station, Units 1 & 2), ALAB-616, 12 N.R.C. 419, 421 (1980); N. Anna Envtl. Coal. v. NRC, 533 F.2d 655, 667-68 (D.C. Cir. 1976) (rejecting the argument that reasonable assurance requires proof beyond a reasonable doubt and noting that the licensing board equated reasonable assurance with the preponderance standard).
56 Private Fuel Storage, LLC (Indep. Spent Fuel Storage Installation), CLI-00-13, 52 N.R.C. 23, 31 (2000) (citing La. Energy Servs. (Claiborne Enrichment Center), CLI-97-15, 46 N.R.C. 297 (1997); N. Atl. Energy Serv. Corp.
(Seabrook Station, Unit 1), CLI-99-6, 49 N.R.C. 201, 222 (1999)).
57 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 9).
58 Id.
15 4834-2343-5490.v1 D.
Legal Standards for Contention Admissibility To intervene into a license transfer proceeding, petitioners must set forth an admissible contention that fulfills the requirements set forth in 10 C.F.R. § 2.309(f)(1)(i)-(vi). These standards are enforced rigorously. If any one... is not met, a contention must be rejected.59 The Commissions contention admissibility requirements are strict by design.60 They seek to ensure that NRC hearings serve the purpose for which they are intended: to adjudicate genuine, substantive safety and environmental issues placed in contention by qualified intervenors.61 The requirements thus reflect a deliberate effort to prevent the major adjudicatory delays caused in the past by ill-defined or poorly-supported contentions that were admitted for hearing although based on little more than speculation.62 To warrant an adjudicatory hearing, proposed contentions thus must have some reasonably specific factual or legal basis.63 The petitioner alone bears the burden to meet the standards of contention admissibility.64 Under 10 C.F.R. § 2.309(f)(1), a petitioner must explain the basis for each proffered contention by stating alleged facts or expert opinions that support the petitioners position and on 59 Arizona Public Service Co. (Palo Verde Nuclear Generating Station, Units 1, 2, and 3), CLI-91-12, 34 N.R.C.
149, 155 (1991) (citation omitted); USEC, Inc. (American Centrifuge Plant), CLI-06-9, 63 N.R.C. 433, 437 (2006) (These requirements are deliberately strict, and we will reject any contention that does not satisfy the requirements. (footnotes omitted)).
60 Dominion Nuclear Conn., Inc. (Millstone Nuclear Power Station, Units 2 & 3), CLI-01-24, 54 N.R.C. 349, 358 (2001).
61 Dominion Nuclear Conn., Inc. (Millstone Nuclear Power Station, Unit 2), CLI-03-14, 58 N.R.C. 207, 213 (2003)
(quoting Duke Energy Corp. (Oconee Nuclear Station, Units 1, 2, & 3), CLI-99-11, 49 N.R.C. 328, 334 (1999))
(emphasis added) (internal citation omitted).
62 PPL Susquehanna, LLC (Susquehanna Steam Elec. Station, Units 1 &2), CLI-15-8, 81 N.R.C. 500, 504 (2015)
(quoting Oconee, CLI-99-11, 49 N.R.C. at 334).
63 Id. (quoting Millstone, CLI-03-14, 58 N.R.C. at 213).
64 See Entergy Nuclear Operations, Inc. (Palisades Nuclear Plant), CLI-15-23, 82 N.R.C. 321, 325, 329 (2015) ([I]t is Petitioners responsibility... to formulate contentions and to provide the necessary information to satisfy the basis requirement for admission) (internal citation omitted).
16 4834-2343-5490.v1 which the petitioner intends to rely in litigating the contention at hearing.65 To be admissible, the issue raised must fall within the scope of the proceeding and be material to the findings that the NRC must make with respect to the application.66 The Commission has defined a material issue as meaning one where resolution of the dispute would make a difference in the outcome of the licensing proceeding.67 Contentions that challenge NRC regulations,68 seek to impose requirements stricter than those imposed by the agency,69 or opine on the manner in which Staff should conduct its review70 are all outside the scope of NRC adjudicatory proceedings.
A contention also must provide sufficient information to show a genuine dispute with the applicant on a material issue of law or fact.71 The contention must refer to the specific portions of the application... that the petitioner disputes, along with the supporting reasons for each dispute; or, if the petitioner believes that an application fails altogether to contain information required by law, the petitioner must identify each failure, and provide supporting reasons for the petitioners belief.72 To demonstrate that a genuine material dispute exist, [b]are assertions and speculation, even by an expert, are insufficient to trigger a full adjudicatory proceeding.73 65 10 C.F.R. § 2.309(f)(1)(ii), (v).
66 10 C.F.R. § 2.309(f)(1)(iii)-(iv); PPL Susquehanna, LLC (Susquehanna Steam Elec. Station, Units 1 &2), CLI-17-4, 85 N.R.C. 59, 74 (2017).
67 Final Rule, Rules of Practice for Domestic Licensing ProceedingsProcedural Changes in the Hearing Process, 54 Fed. Reg. 33,168, 33,172 (Aug. 11, 1989) (emphasis added).
68 10 C.F.R. § 2.335(a).
69 See Entergy Nuclear Vt. Yankee, LLC (Vt. Yankee Nuclear Power Station), LBP-15-4, 81 N.R.C. 156, 167 (2015); NextEra Energy Seabrook, LLC (Seabrook Station, Unit 1), CLI-12-5, 75 N.R.C. 301, 315 (2012); GPU Nuclear, Inc. (Oyster Creek Nuclear Generating Station), CLI-00-6, 51 N.R.C. 193, 206 (2000); Curators of the Univ. of Missouri (TRUMP-S Project), CLI-95-1, 41 N.R.C. 71, 170 (1995).
70 See, e.g., Fla. Power & Light Co. (Turkey Point Nuclear Generating Plant, Units 3 & 4), CLI-01-17, 54 N.R.C. 3, 25 (2001) (quoting Balt. Gas & Elec. Co. (Calvert Cliffs Nuclear Power Plant, Units 1 & 2), CLI-98-25, 48 N.R.C. 325, 350 (1998), affd sub nom. Natl Whistleblower Ctr. v. NRC, 208 F.3d 256 (D.C. Cir. 2000), cert.
denied, 531 U.S. 1070 (2001)) ([I]t is the license application, not the NRC Staff review, that is at issue in our adjudications.).
71 10 C.F.R. § 2.309(f)(1)(vi); Susquehanna, CLI-17-4, 85 N.R.C. at 74.
72 Susquehanna, CLI-17-4, 85 N.R.C. at 74 (citing 10 C.F.R. § 2.309(f)(1)(vi)).
73 Entergy Nuclear Generation Co. (Pilgrim Nuclear Power Station), CLI-12-15, 75 N.R.C. 704, 714 (2012)
(emphasis added) (citation omitted).
17 4834-2343-5490.v1
[A]n expert opinion that merely states a conclusion... without providing a reasoned basis or explanation for that conclusion is inadequate.74 IV.
The Michigan AG Fails to Set Forth an Admissible Contention The Michigan AG sets forth two purported contentions (MI-1 and MI-2), the first of which includes a variety of subparts. Neither contention is admissible.
A.
Contention MI-1 Is Inadmissible Because It Is Speculative and Unsupported by Information Demonstrating a Genuine Material Dispute with the Plausible Assumptions in the Application and DCE Contention MI-1which alleges that Holtec Palisades fails to show financial qualifications and provide adequate decommissioning financial assurance and adequate funding for spent fuel management because the PSDAR and DCE underestimate license termination and spent fuel management costs75is inadmissible because it fails to demonstrate any genuine material dispute with the Application. In large measure, the Michigan AG bases this contention on speculation that various contingencies might arise. That one can posit such contingencies does not raise a genuine dispute with the Application. As previously discussed, [w]hen evaluating a license transfer applicants ability to meet financial obligations related to decommissioning, the NRC will accept financial assurances based on plausible assumptions and forecasts, even though the possibility is not insignificant that things will turn out less favorably than expected.76 Thus, the mere casting of doubt on some aspects of proposed funding plans is 74 USEC, Inc. (Am. Centrifuge Plant), CLI-06-10, 63 N.R.C. 451, 472 (2006) (emphasis added) (quoting Private Fuel Storage, LLC (Indep. Spent Fuel Storage Installation), LBP-98-7, 47 N.R.C. 142, 181 (1998), affd, CLI 13, 48 NRC 26 (1998)); see also Power Auth. of N.Y. (James A. Fitzpatrick Nuclear Power Plant and Indian Point, Unit 3), CLI-00-22, 52 N.R.C. 266, 315 (2000) (Unsupported hypothetical theories or projections, even in the form of an affidavit, will not support invocation of the hearing process.).
75 Petition at 9.
76 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 9) (quoting North Atlantic Energy Service Corp. (Seabrook Station, Unit 1), CLI-99-6, 49 N.R.C. 201, 222 (1999)).
18 4834-2343-5490.v1 not by itself sufficient to defeat a finding of reasonable assurance.77 As the Commission has explained:
[W]e have recognized that the potential safety impacts, if any, from a shortfall in financial funding would not be so direct or immediate as the safety impacts of significant technical deficiencies. Therefore, we recognize that the demonstration of reasonable assurance of financial qualification is flexible.
Accordingly, we will admit for hearing here only those contentions based upon adequately supported assertions that a transfer applicants financial assumptions and forecasts are implausible or unrealistic in a way that is material to our assessment of reasonable assurance.78 The requirement to demonstrate that some assumption is implausible in a way that is material to the assessment of reasonable assurance means that the Michigan AG must show that an implausible assumption could make a difference in the outcome of the proceeding.79 To do so, the Michigan AG must provide a sufficient basis to believe that the implausible assumption might overcome the multiple layers of financial assurance provided by the Application and NRCs regulatory regime. These layers include:
- the approximately $50 million contingency included in the DCE;
- the $20 million surplus reflected in the cash flow analysis;
- the ability of Holtec Palisades to provide additional funding assurance through recoveries from DOE of spent fuel management expenses estimated at approximately $160 million;
- the commitment by Holtec Palisades to adjust funding, including providing an alternative funding mechanism if necessary, if annual review of funding assurances indicates a shortfall;80
- the strict oversight and reporting requirements in the NRCs decommissioning funding regulations, including the regulations that prohibit a licensee from making a withdrawal that would inhibit its ability to complete funding of any shortfalls in the 77 Entergy Nuclear Operations, Inc. et al. (Pilgrim Nuclear Power Station), CLI-20-12, 91 N.R.C. __ (slip op. at 20)
(quoting Seabrook, CLI-99-6, 49 N.R.C. at 222).
78 Id. (footnotes omitted).
79 Duke Energy Corp. (Oconee Nuclear Station, Units 1, 2, & 3), CLI-99-11, 49 N.R.C. 328, 333-34 (1999)
(quoting Rules of Practice for Domestic Licensing Proceedings Procedural Changes in the Hearing Process, 54 Fed. Reg. 33,168, 33,172 (Aug. 11, 1989) (Final Rule)).
80 DCE at 44.
19 4834-2343-5490.v1 decommissioning trust, require the licensee to submit an annual financial assurance report, and require the licensee to provide additional funds if the report reveals insufficient funds to complete decommissioning. These regulations provide reasonable assurance that adequate funds will remain to complete decommissioning by requiring [the licensee] and the Staff to monitor the projected cost of decommissioning and available funding and ensure more funding is available as needed.81 Consequently, simply positing delays or cost overruns that could occur is insufficient to demonstrate any material dispute with the Application.
The Michigan AG also seeks to base its contentions on a number of claims specifically rejected by the Commission in the Indian Point proceeding, including certain claims that impermissibly challenge the NRCs rules. As an example, Michigan AG asserts that [p]roposed licensees financial qualifications cannot be predicated solely on access to existing decommissioning trusts, as the Applicants propose here and that Holtec must demonstrate that it has healthy corporate entities with access to the financial resources necessary to procure additional financial assurance [beyond the decommission fund].82 Nearly verbatim claims83 were rejected by the Commission in Indian Point as unsupported by any NRC requirements.84 As a general matter, the Michigan AGs suggestion that Holtec Palisades is relying solely on access to existing decommissioning trusts also mischaracterizes and therefore demonstrates no genuine dispute with the Application. As the Application states,
[r]eimbursement of spent fuel management expenses by DOE, which is not credited in the cash flow analysis, would provide a substantial source of additional funds that could be used to 81 Vermont Yankee, CLI-16-17, 84 N.R.C. at 118. The Commission similarly observed that a licensee is required to submit to the Staff annual reports regarding the status of its funding for irradiated fuel management, including a plan to obtain additional funds to cover any expected shortfalls. Id. at 105 n.13 (citing 10 C.F.R.
§ 50.82(a)(8)(vi)).
82 Petition at 11.
83 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 48-49).
84 Id. at 49 (New York does not identify any NRC requirement that prevents an applicant from relying on a single funding source to establish that it is financially qualified to decommission a site.).
20 4834-2343-5490.v1 provide such adjustment if necessary.85 The Application and DCE estimate these spent fuel management expenses at approximately $160 million.86 Further, the NRCs rules will require HDI to submit decommissioning-funding status reports annually, and if any annual report shows that the decommissioning trust balances will not cover the estimated costs of decommissioning Palisades, HDI will be required by the NRC rules to provide additional financial assurance to cover those costs.87 This constant reporting and NRC oversight belies any suggestion that the revenue stream from DOE recoveries might be unavailable; and in any event, an admissible contention cannot be based on an assumption that Holtec Palisades will refuse to comply with the NRC rules.88 As further described below, each of the implausible assumptions alleged by the Michigan AG is inadequate to support an admissible contention. As a result, contention MI-1 is inadmissible.
The mere existence of differences between the current decommissioning cost estimate and prior estimates does not show that the DCE assumptions are implausible or demonstrate any genuine dispute with the Application.
The Michigan AG first asserts that HDIs cost estimate is unreasonable because it varies from a 2004 cost estimate (with costs in 2003 dollars) that was submitted to the Michigan Public Service Commission in 2006,89 when the facility was operated by Nuclear Management 85 LTA, Encl. 1 at 18.
86 LTA, Encl. 1, Att. E at 3, 5; DCE at 33, 46.
87 10 C.F.R. § 50.82(a)(8)(v)-(vii).
88 Private Fuel Storage, L.L.C. (Indep. Spent Fuel Storage Installation), CLI-01-9, 53 N.R.C. 232, 235 (2001) (the NRC does not presume that a licensee will violate agency regulations wherever the opportunity arises). See also GPU Nuclear, Inc. (Oyster Creek Nuclear Generating Station), CLI-00-6, 51 N.R.C. 193, 207 (2000) (NIRS also fails to offer documentary support for its argument that AmerGen is likely to violate our safety regulations.
Absent such support, this agency has declined to assume that licensees will contravene our regulations.).
89 Petition at 13; Capik Decl., 8. The Michigan AG states that the estimate was provided to the NRC but cites instead a submittal by Consumers Energy Company to the Michigan Public Service Company. Petition at 13 n.32; Capik Decl., 8 n.3. That submittal includes an Executive Summary of a cost study prepared in 2004.
21 4834-2343-5490.v1 Company (NMC) and owned by Consumers Energy Company (Consumers). The Michigan AG asserts that [n]o explanation has been provided by Holtec to support the 52% reduction in estimated costs nor is sufficient detail included in the Holtec DCE for an independent analysis of any factors that could support this 52% reduction in estimated costs.90 But HDI and Holtec Palisades are not required to compare its decommissioning cost estimate to every old decommissioning estimate for a facility and justify the changes. Nor would such a requirement be reasonable. Nuclear power plants update decommissioning cost studies periodically specifically because assumptions do change, and consequently changes in the estimates are unremarkable. This is particularly true given that the nuclear power plants themselves are not static: fuel has regularly moved into dry cask storage, additional subsurface monitoring has been put in place eliminating uncertainty in decommissioning estimates, and remediation may be ongoing. In other words, the basis for an old estimate may be substantially different from the basis for a new estimate, rendering comparisons difficult, at best.
In addition, the state of the art and cost of both decommissioning and waste disposal continue to evolve. Several nuclear power plants have undergone decommissioning activities since the 17-year-old cost study that was prepared for NMC and Consumers, providing more recent experience with the existing group of decommissioning subcontractors,91 and new methodologies are used that improve efficiencies, reduce labor, and reduce the volume of low-level waste requiring disposal.92 The low-level waste disposal market has also changed. The Waste Control Specialists LLC (WCS) facility in Andrews County, TXwith which HDI has 90 Petition at 13; Capik Decl., 8 91 See PSDAR at 9 (noting experience from Oyster Creek and Pilgrim).
92 See, e.g., PNNL Draft Study, Assessment of the Adequacy of the 10 CFR 50.75(c) Minimum Decommissioning Fund Formula, (Nov. 2011) (ADAMS Accession No. ML13063A190) at p.2-7 to 2-8) (hereinafter PNNL Draft Study) (discussing EPRI findings that on improvements to decontamination and dismantlement technologies in recent decades).
22 4834-2343-5490.v1 a fleet-wide waste disposal contractonly began operating around 2012.93 All of these changes in methodologies and the marketplace would undermine a direct comparison between new and old decommissioning cost estimates and render it a long and ultimately fruitless effort.
Further, there are obvious differences between the NMC/Consumers and HDIs cost estimates. For example, the 2004 Site-Specific Decommissioning Cost Study Executive Summary submitted by Consumers and referenced by the Michigan AG94 was an estimate for a large public utility decommissioning a single nuclear plant, whereas HDIs estimate is for a company specializing in conducting decommissioning under a fleet model providing greater efficiency, shared experience, and shared corporate support.95 As another example, the 2004 study provided estimated waste disposal costs on pricing information (at the time) from Barnwell and Envirocare, 96 whereas HDIs estimate bases the costs on a fleet contract with WCS.97 Further, the storage period in the 2004 estimate was longer, and more importantly, assumed that spent fuel would remain in the pools for an eight-year cooling period, resulting in considerably greater cost during the dormancy period.98 Moreover, unlike the 2004 cost study, HDIs DCE is based on real time experience and executed contracts from Holtec-owned nuclear 93 As explained in the Palisades Site-Specific Decommissioning Cost Estimate, HDI has entered into a fleet wide waste contract with Waste Control Specialist (WCS), in Texas, for disposal of all radioactive waste. DCE at 24.
The costs associated with this contract will naturally deviate from any decommissioning cost estimate from 2004, since WCS was not available until 2012. See https://www.nrc.gov/waste/llw-disposal/licensing/statistics.html.
94 Petition at 13 n.32; Capik Decl., 8 n.3.
95 LTA, Encl. 1 at 15-16. Indeed, one of the primary drivers toward the asset-transfer model for decommissioning has been the significant structural and economic differences between traditional utilities, whose primary business focus and supply chain organizations are oriented toward operational assets with long-term dedicated revenue streams, and leaner, more specialized decommissioning contractors with business enterprises and in-house expertise focused on key areas of the decommissioning and dismantlement process (e.g., spent fuel management) and who are more experienced operating under fixed-price, project-based frameworks.
96 2004 Site-Specific Decommissioning Cost Study Executive Summary (2004) at ix.
97 DCE at 24.
98 Id. at vi, Table 3.1.
23 4834-2343-5490.v1 decommissioning sites99 and incorporates subcontractor estimates for reactor segmentation and waste removal.100 Nor does the Michigan AG provide any reason to believe that the 2004 NMC/Consumers estimate is any more accurate or better than HDIs more recent estimate.
Instead, the Michigan AG merely alleges that because the two estimates are different, the onus is on HDI to further explain and justify the differences. No such analysis is required under the NRC rules, and it is the Michigan AGs obligation to demonstrate a genuine material dispute, alleged with particularly, with the application. Having failed to identify any specific item in dispute in the pending Application, the Michigan AG has failed to meet that requirement and has failed to set forth an admissible contention on this point.
The Michigan AGs attempt to compare the spent fuel management cost estimated in the DCE for ISFSI maintenance during three years of the dormancy period (2027 through 2029) against the spent fuel management cost for a standalone ISFSI estimated in NMCs 2006 irradiated fuel management plan101 likewise fails to demonstrate any genuine material dispute with the HDI DCE. The $1.7 million per year estimate for 2027-2029 is not for a standalone ISFSI, but rather for an ISFSI at a larger site in dormancy, where HDI plans to maintain much of the site infrastructure (including the main plant protected area that encompasses one of the ISFSI pads) through the dormancy phase and early parts of dismantlement. O&M costs during this period primarily fall in the Program Management category (e.g., security, taxes, insurance, site upkeep, regulatory compliance programs, and licensing/engineering/home office costs).102 99 DCE at 16.
100 LTA, Encl. 1 at 18.
101 Petition at 14-15 & n.36; Capik Decl., 10 & n.7.
102 See DCE at 31-32 (Table 3-2); PSDAR at 13.
24 4834-2343-5490.v1 These costs are generally incurred on a site-wide basis and then allocated to radiological decommissioning and spent fuel management proportionately. DCE Table 5-1 best illustrates the site-wide hotel load during the years 2027 to 2029the part of the dormancy period when no other major cost drivers are reflected in the annualized cash flows. For those years, site-wide O&M costs come to about $6.3 million.103 For the same reason, the Michigan AGs attempt to compare this estimated cost against the costs of maintaining the stand-alone ISFSI at Big Rock Point fails to demonstrate any genuine dispute with the DCE.
In sum, the Michigan AG misrepresents the spent fuel costs in HDIs DCE and relies on a flawed comparison to the 2004 NMC/Consumers decommissioning estimate. That higher costs were estimated for decommissioning by a utility seventeen years ago does not demonstrate that any of the current assumptions in the DCE are implausible and therefore fails to demonstrate any genuine material dispute with the Application.
The Michigan AG fails to raise a genuine dispute with the plausible DCE assumptions on transfer of spent nuclear fuel.
The Michigan AG next claims that HDIs assumption that transfer of spent fuel to DOE will take place between 2030 and 2040 is not reasonable given DOEs current progress in licensing a repository.104 This assertion does not raise a genuine dispute with the Application because the assumed schedule for removal of spent nuclear fuel from the site is not based on the licensing of a repository, but rather on DOEs 2013 Strategy for the Management and Disposal of Used Nuclear Fuel and High Level Radioactive Waste, which assumes development of an interim storage facility.105 Further, the Commission has already determined that it is plausible to 103 Table 5-1 shows $4.58 million allocated to radiological decommissioning and $1.71 million to spent fuel management in these years. DCE at 46.
104 Petition at 16; Capik Decl., 12.
105 See DCE at 21. The DCE adjusts the start date for transfers to the interim storage period outwards by five years.
Id.
25 4834-2343-5490.v1 assume that a storage facility will be available to accept spent fuel at an interim storage facility by 2030.106 As the Commission found in Indian Point, The NRC currently has two separate applications for privately owned interim storage facilities before the agency. While these applications are still under review, we find the assumption that by 2030 a storage facility to receive spent fuel from Indian Point will be available is plausible.107 The Michigan AG argues that even if the fuel is transported offsite, Holtec Palisades will retain title and continue to incur costs associated with the fuel.108 As the Commission held in Pilgrim, the availability of a storage facility by 2030 is plausible notwithstanding the uncertainty whether statutory changes will be made to allow DOE to take title.109 Further, even if legislation allowing DOE to take title were not enacted, DOE could still pay for interim storage, or Holtec Palisades could seek to recover interim storage costs through settlement or recoveries from DOE.
The Michigan AGs speculation that DOEs strategy might not occur as planned fails to demonstrate a genuine dispute. The Commission finds financial assurance to be acceptable if it is based on plausible assumptions and forecasts, even if the possibility is not insignificant that things will turn out less favorably than expected.110 The Michigan AG also argues that HDI should have used a 34-year acceptance period for spent fuel based on the allocation rate adopted by the courts in the DOE litigation over performance of the Standard Contract.111 To the extent that the Michigan AG argues that it will take longer for DOE to accept the remaining fuel, HDI has explained that it will seek the most 106 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 36).
107 Id.
108 Petition at 16; Capik Decl., 12.
109 Pilgrim, CLI-20-12, 91 N.R.C. at __ (slip op. at 28-29). See also Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 36 n.158) (describing as plausible the expectation that DOE will receive authorization for the transfer of spent fuel).
110 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 37).
111 Petition at 17; Capik Decl., 13.
26 4834-2343-5490.v1 expeditious means of removing fuel from the site, based on shutdown reactor priority and other contract provisions.112 The Michigan AG claims that there is no basis to assume that such provisions can be utilized, nor that these provisions would be available without a significant cost.113 However, the Michigan AG admits that there are provisions in Standard Contract that could potentially be used to accelerate acceptance dates.114 Article VI.B.1(b) provides that priority may be accorded any SNF and/or HLW removed from a civilian nuclear power reactor that has reached the end of its useful life or has been shut down permanently for whatever reason.115 Article V.E of the Standard Contract provides for exchanges of delivery commitment schedules with parties to other Standard Contracts.116 Further, the Federal Circuit has already upheld the use of the exchanges provision in the Standard Contract.117 Consequently, the schedule assumed in the DCE has a basis in the Standard Contract and therefore is certainly plausible.
It is also plausible (though not assumed in HDIs analysis) that DOE will accept fuel more rapidly than contemplated in litigation over the Standard Contract. The allocation rate adopted by the Federal Circuit is based on a DOE estimate from 1987 and represents a non-breach world where DOE would have started performance in 1998. The 1987 allocation rate does not necessarily represent a likely DOE acceptance rate in todays world, with consolidated interim storage facilities on the horizon and advancements in technology. Indeed, if facilities 112 DCE at 22.
113 Petition at 18 & n.50; Capik Decl., 14 & n.20.
114 Id.
115 10 C.F.R. Part 961.11, Text of Standard Contract.
116 Id.
117 See, e.g., Dairyland Power Co-op. v. United States, 645 F.3d 1363, 1370 (Fed. Cir. 2011); Yankee Atomic Electric Co. v. United States, 679 F.3d 1354, 1359-60 (Fed. Cir. 2012); Pacific Gas & Electric Co v. United States, 668 F.3d 1346, 1354 (Fed. Cir. 2012); Sacramento Municipal Utility District v. United States, 556 Fed.
Appx 985, 996 (Fed. Cir. 2014); Sacramento Municipal Utility District v. United States, 120 Fed. Cl. 270, 278 (2015).
27 4834-2343-5490.v1 exist to take the fuel, it is plausible that DOE could accelerate acceptance beyond the 1987 acceptance rate.
Finally, even if HDI were to incur costs for spent fuel management beyond 2040, it is expected under the Standard Contract that those costs would be recovered from DOE. Thus, the impact on HDIs overall cost estimate would be minimal. Either way, financial assurance [is]
acceptable if it is based on plausible assumptions and forecasts, even if the possibility is not insignificant that things will turn out less favorably than expected.118 As the Commission has previously decided, DOE performance is plausible,119 and because disposal of spent fuel and high-level waste is a federal responsibility, additional delays in DOE taking... spent fuel beyond 2030 would mean that Holtec could recover additional spent fuel management costs from DOE.120 In light of these facts, the Michigan AG has not set forth with particularity any reason that the overall HDIs spent fuel cost analysis is implausible in any material manner.
Consequently, the Michigan AG has not raised a genuine material dispute with the plausible spent fuel transfer assumptions in the DCE and cash flow analysis.
The mere existence of differences between the current decommissioning cost estimate and dated experience at limited other sites does not demonstrate any genuine dispute with the Application.
The Michigan AG next summarily asserts that HDIs cost estimate is unreasonable because it is smaller than the NRCs generic formula and smaller than estimates from prior experience at a handful of sites such as Yankee Rowe, Haddam Neck, and Maine Yankee.121 The Michigan AG, however, does not identify any particular inadequacy in HDIs cost estimate 118 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 37).
119 Id. (slip op. at 36).
120 Pilgrim, CLI-20-12, 91 N.R.C. at ___ (slip op. at 29).
121 Petition at 18-20; Capik Decl., 16-17.
28 4834-2343-5490.v1 in support of this allegation. The Michigan AG does not address or dispute the discussion in the Application explaining why the DCE is below the formula amount,122 including the explanation that the formula amount (which was developed nearly forty years ago) is a general level of adequate financial responsibility early in life.123 As a PNNL study evaluating the formula amount observed, Decommissioning technology and practices in use today are significantly different than assumed in the original studies. Specifically, the formula does not reflect the one-piece removal of large components (e.g., steam generators) commonly in use today and the more efficient decontamination/decommissioning processes that potentially significantly reduce, relative to that assumed in the original studies, the volume of LLW requiring disposal.124 Nor does the Michigan AG demonstrate why the other cost estimates or prior experience is better, more accurate, or more applicable to Palisades decommissioning than HDIs estimate.
Indeed, the experience quoted by the Michigan AG is limited to decommissioning work performed before current decommissioning practices, before the current low-level waste market, and before entities such as Waste Control Specialists existed.125 In contrast, HDIs present estimate is based on current practices in the existing market and incorporates concrete cost-estimates from negotiated subcontracts. As an example, HDIs waste disposal costs are based on a fleet wide waste contract with Waste Control Specialist (WCS).126 In addition, the Michigan AG cherry picks the plant decommissioning costs to which it refers, making no mention of Trojan, a PWR that was decommissioned at a cost of $323.8 122 See LTA, Encl. 1 at 18 n.1.
123 53 Fed. Reg. 24,018, 24,030 (June 27, 1988).
124 PNNL Draft Study at p. 1-3 (ADAMS Accession No. ML13063A190).
125 The Michigan AG quotes Yankee Rowe, Maine Yankee, and Connecticut Yankee as purportedly relevant experience. However, all of these facilities were decommissioned from the mid-to-early 1990s through the mid-2000s. As described, supra on page 28, decommissioning techniques have continued to evolve since then.
126 DCE at 24.
29 4834-2343-5490.v1 million (2010 dollars).127 The Michigan AG also provides no information showing that the decommissioning experience to which it refers is applicable to Palisades. For example, the PNNL Draft Study observes, [s]ignificant contaminated soil requiring remediation and very stringent cleanup criteria appeared to be the main drivers for the high cost to decommission Haddam Neck.128 Maine Yankee was also affected by enhanced state cleanup standards that established more restrictive cleanup levels than the NRC regulations.129 In sum, the Michigan AG presents no reason to believe that a general estimate or decades-old experience is objectively better than HDIs estimate, and generally asserting that the cost estimate is unreasonable in comparison to other estimates is not enough to support an admissible contention without further support.
The Michigan AG does not demonstrate any genuine material dispute with the contingency factor in the DCE.
The Michigan AG also challenges HDIs 12% contingency set aside for ISFSI decommissioning, alleging that it is outside industry norms.130 Contrary to this claim, HDIs contingency is within less than a percent of the 12.9% allowance used for Three Mile Island Unit 1 in 2019, referenced in the Commissions Indian Point decision as within the range of allowances that have been commonly added to site-specific decommissioning cost estimates.131 Nonetheless, HDI provides justification for its 12% contingency, noting that it is [b]ased on an evaluation of estimate uncertainty and discrete risk events, combined with experience 127 PNNL Draft Study at iv.
128 Id.
129 Id. at 4-54.
130 Petition at 20-21; Capik Decl., 18.
131 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 27). The Michigan AG claims that the lower 12.9%
contingency at Three Mile Island is related to the greater decommissioning cost estimate for site. But, if anything, it makes sense that the contingency would be higher at Three Mile Island versus Palisades given the uncertainties associated with decommissioning 50 years in the future under a SAFSTOR alternative.
30 4834-2343-5490.v1 gained through decommissioning efforts at Oyster Creek and Pilgrim, newly formed waste contracts, and contingency allowances used for other decommissioning projects.132 The Michigan AG does not challenge this analysis of contingency, or the certainty gained through having set contracts, and instead only generally alleges that HDIs contingency is outside industry norms.133 Such a conclusory allegation fails to raise a genuine dispute with the application and is insufficient to support an admissible contention.
The Michigan AG also asserts that using a 17.15% average contingency value would add about $29 million to the DCE,134 but fails to explain how it arrived at this number, why this additional amount of funding assurance is needed or material, or whether accounting for additional contingency expenditures at various points in the project would jeopardize the $20 million surplus projected at license termination. The NRC rules will require HDI to report annually on the sufficiency of its decommissioning funds and adjust funding assurance if necessary;135 and in light of the estimated $160 million in spent fuel management costs, the revenue stream from DOE recoveries would easily allow a $29 million adjustment in funding assurance if it were necessary.
The Michigan AG fails to raise a genuine dispute with HDIs estimate of waste volume.
The Michigan AG also alleges that HDI significantly underestimates the volume of Class A, B, and C radioactive waste in the decommissioning cost estimate for Palisades.136 In support of this assertion, the Michigan AG points towards higher amounts of low-level waste at Maine 132 DCE at 41.
133 Petition at 20-21; Capik Decl., 18.
134 Petition at 21; Capik Decl., 19.
135 10 C.F.R. § 50.82(a)(8)(v)-(vii).
136 Petition at 22; Capik Decl., 20.
31 4834-2343-5490.v1 Yankee and Haddam Neck.137 The Michigan AG does not, however, point towards any particular reason to believe that the low-level waste volume at Palisades will be the same as Maine Yankee or Haddam Neck, except to say that they are all pressurized water reactors of a similar generating capacity.138 In fact, both Maine Yankee and Haddam Neck were outliers that generated significantly greater than anticipated amounts of low-level waste, and neither example is demonstrative of the low-level waste amount expected at Palisades.
As indicated in the PNNL Draft Study, both Haddam Neck and Maine Yankee had much larger quantities of low-level waste than other decommissioned PWRs, such as Rancho Seco and the Trojan Nuclear Power Plant.139 This high amount of waste can be seen in Figure 1 below, and has been attributed to more restrictive cleanup standards at Maine Yankee, significant soil contamination at Haddam Neck, and the decommissioning methodology used at each site.140 At Haddam Neck, the majority of th[e] waste was demolition debris having very low activity, much of which was shipped to waste processors for treatment and/or disposal at controlled landfills near Memphis and Oak Ridge, Tennessee, at lower cost than shipment to and disposal at the Clive, Utah, disposal facility.141 Normally, such waste is assumed to remain onsite and is not considered decommissioning waste.142 At Maine Yankee, the decommissioning methodology resulted in higher waste volume because of the decision to demolish all buildings to an elevation equivalent to 3 feet below site grade, more restrictive state cleanup standards, and 137 Id.
138 Id.
139 PNNL Draft Study at Tbl. 4.39; Fig. 5.2. HDI estimates that there will be 1.13 million cubic feet (approx. 32,000 cubic meters) of low-level waste. PSDAR at 33. That is more than the amount of waste reported in the referenced table for Rancho Seco and Trojan.
140 PNNL Draft Study at 4-122.
141 Id. at 4-21.
142 Id.
32 4834-2343-5490.v1 the decision to dispose of all demolition debris from the radiologically controlled area at disposal facilities.143 Figure 1. PWR LLW Volume vs. Thermal Capacity144 The Michigan AG has not alleged that these same particular circumstances would apply at Palisades or otherwise explained why the Maine Yankee and Haddam Neck outliers are more appropriate or more accurate than the Palisades estimate. The Michigan AG provides no information indicating that the estimated waste volumes for Palisades would be expected to be similar to those at Haddam Neck or Maine Yankee, and in fact never claims that the estimates for Palisades are implausible. It therefore fails to raise a genuine material dispute with the Application.145 143 Id.
144 Id. at 5-6, Fig. 5.2.
145 Decommissioning methodologies have also changed since the Haddam Neck and Maine Yankee projects, and current NRC subsurface monitoring requirements in 10 C.F.R. § 20.1501, promulgated as part of the Decommissioning Planning Rule in 2011, provide information to avoid the discovery of significant unexpected soil contamination as occurred at Haddam Neck. The Decommissioning Planning Rule is intended to ensure that
33 4834-2343-5490.v1 The Michigan AG also asserts that the Application and PSDAR do not show that the number of truck shipments of radioactive waste are bounded by the environmental analysis in Decommissioning GEIS.146 This claim is outside the scope of the proceeding.147 As the Commission has found, the NRC does not approve a PSDAR, and most of the information in a PSDAR falls outside the scope of a license transfer proceeding.... [A] license transfer review does not itself involve any consideration of the potential environmental impacts of decommissioning activities.148 As set forth in Indian Point, if petitioners have grounds to assert that the impacts of planned decommissioning, site restoration, and spent fuel management activities... exceed those referenced in the PSDAR, their recourse would be a petition for enforcement action to address a potential violation of our rules associated with representations made in the PSDAR.149 Further, the NRC has determined categorically that license transfers do not trigger the need to prepare an environmental assessment or environmental impact statement, except in the case of special circumstances as found by the Commission.150 The NRC made this determination based on the fact that the transfer itself does not permit a licensee to operate a facility any differently than what has been permitted under an existing license and, therefore, will a licensee has a reasonably accurate estimate of the extent to which residual radioactivity is present at the facility, particularly in the subsurface soil and groundwater, to improve decommissioning planning and adequately ensure that a decommissioning fund will cover the costs of decommissioning. See Decommissioning Planning; Final Rule, 76 Fed. Reg. 35,512, 35,514 (June 17, 2011) (Decommissioning Planning Rule). The purpose of this final rule is to improve decommissioning planning and thereby reduce the likelihood that a site will become a legacy site..., i.e., a facility that is decommissioning and has an owner that cannot complete the decommissioning work for technical or financial reasons. Id. at 35,516.
146 Petition at 23; Capik Decl., 21.
147 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 60). The scope of this federal action is discussed in more detail in Applicants response to Beyond Nuclear et al.s NEPA contention. See Applicants Answer Opposing Beyond Nuclear et al.s Petition to Intervene and Hearing Request (Mar. 22, 2021) at 6-9.
148 Pilgrim, CLI-20-12, 91 N.R.C. at __ (slip op. at 41).
149 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 65).
150 10 C.F.R. § 51.22(b), (c)(21).
34 4834-2343-5490.v1 not raise environmental issues that differ from those considered in prior NEPA analyses.151 Any claim that further environmental analysis of waste shipments is required is an impermissible challenge to this categorical exclusion in the NRC rules.
The Michigan AG fails to raise a genuine dispute with HDIs overall cost estimate.
The Michigan AG next alleges a variety of general ways in which the costs for decommissioning could theoretically increase, from schedule delays to state regulatory changes and other causes. While each of these allegations is addressed in greater detail below, the Michigan AG generally fails to provide sufficient reason to believe that any of these claims is likely to have a specific material impact on the decommissioning cost estimate for Palisades, making the DCE implausible.
The Michigan AG first alleges that there may be delays in the schedule.152 The Michigan AG asserts that [t]he risk of delay in the decommissioning schedule exists in all decommissioning projects for reasons including identifying unknown conditions requiring expanding the scope of planned activities or creating the need for additional activities.153 This general claim does not raise any genuine dispute, as the contingency in the DCE considers risk events that may affect schedule estimates.154 In addition, the Michigan AG does not identify any assumption in the decommissioning schedule in the PSDAR or DCE that is implausible.
Instead, the Michigan AG argues that there were almost immediate delays in the Pilgrim decommissioning schedule (from an anticipated 5.5 to 8 years), and that those purported delays 151 Streamlined Hearing Process for NRC Approval of License Transfers, Final Rule, 63 Fed. Reg. 66,721, 66,728 (Dec. 3, 1998) (Subpart M Rule).
152 Petition at 24-25; Capik Decl., 23-24.
153 Petition at 24; Capik Decl., 23.
154 DCE at 40. See Pilgrim, CLI-20-12, 91 N.R.C. __ (slip op. at 30) (Common types of delays... generally are anticipated and covered by the contingency allowance that has been, as a general practice, added to the cost estimates.).
35 4834-2343-5490.v1 at Pilgrim demonstrate why there is a risk of delay at Palisades as well.155 The Michigan AG provides nothing more than speculation that a similar schedule adjustment might occur at Palisades, which (unlike Pilgrim) will have a ten-year dormancy period to prepare for the dismantlement phase, and conveniently ignores the fact that the schedule changes on the Pilgrim project corresponded to cost decreases.156 Assertions of a potential delay at another site are not grounds for an admissible contention unless petitioners, at a minimum, identify the factors underlying these delays or provide how these factors are likely to delay activities at
[Palisades].157 Here, the Michigan AG fails to meet that test.
Further, the assertion by the Michigan AG and Mr. Capik that the increase in overhead and project management arising from Pilgrim schedule adjustment can be estimated to be as much as $100 million is not supported by any reasonable explanation.158 Bare assertions and speculation, even by an expert, are insufficient to trigger a full adjudicatory proceeding.159 Further, this bald and unsupported claim is belied by HDIs 2020 decommissioning funding status report for Pilgrim:
HDI has included an updated schedule that reflects the current decommissioning plan. Figure 1 provides the revised schedule. This schedule reflects actual work progress, further work planning and flattening, subcontract execution, and optimization since HDI assumed control of the site activities in August 2019. The estimate to complete and cash flow analyses provided in Table 1 confirm that these schedule revisions are not significant as defined in 10 CFR 50.82(a)(7).160 155 DCE at 25.
156 See infra notes 160 and161.
157 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 44).
158 Petition at 25; Capik Decl., ¶ 24.
159 See Entergy Nuclear Generation Co. (Pilgrim Nuclear Power Station), CLI-12-15, 75 N.R.C. 704, 714 (2012)
(internal quotations and citations omitted).
160 HDI, Report on Status of Decommissioning Funding for Reactors and Independent Spent Fuel Storage Installations, Encl. 2 at E2-3 (March 31, 2020) (ADAMS Accession No. ML20091M858).
36 4834-2343-5490.v1 Indeed, the cash flow analysis included in this funding report shows a significant increase in the Pilgrim NDT surplus compared to the surplus that was estimated in the Pilgrim license transfer proceeding.161 Neither the Michigan AG nor Mr. Capik make any attempt to address this docketed information and thus fail to provide any support demonstrating that the Pilgrim schedule adjustment raises any genuine material dispute with the Palisades Application.
Second, the Michigan AG speculates that state requirements or unanticipated site conditions could increase costs.162 While the AG summarily asserts that Michigan site restoration requirements beyond those assumed in the Holtec estimated costs would result in a reduction of the funds for radiological decontamination and license termination,163 it does not identify any specific state requirements to support this assertion. These allegations are even more speculative than similar claims in Indian Point, where New York at least identified some agreements and state standards that might (potentially) give rise future costs. Yet, even in Indian Point, the Commission rejected the States assertion of potential future obligations as too uncertain to raise[] a genuine issue over whether the license transfer application need[s] to address these prospective obligations.164 Having provided even less justification for its assertions by failing to identify any prospective state requirements, Michigan AG clearly fails to raise a genuine dispute with the application here.165 161 See id. at E2-8 (currently showing a $217 million surplus upon completion of Pilgrim decommissioning). The Pilgrim license transfer application, in comparison, estimated a surplus of $11.6 million when a full 2 percent real earning rate was used. HDI, Response to NRC Request for Additional Information Encl. at E-5 (July 29, 2019)
(ADAMS Accession No. ML19210E470).
162 Petition at 25-26; Capik Decl., 26.
163 Id.
164 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 30).
165 The Michigan AG generally asserts that, It is important to note, however, that the previous Palisades owner estimated site restoration costs at $78.3 million (2003 dollars), or $110.1 million (2020 dollars). This site-specific estimate significantly exceeds Holtecs $34.7 million dollar estimate. Holtec has not provided any explanation or basis for this 69% reduction in estimated costs. Petition at 26. As explained in detail above, the mere assertion of a difference between two estimates is insufficient grounds to support an admissible contention. Further, the Michigan AG provides no link between these cost estimates and any specific State requirements.
37 4834-2343-5490.v1 Third, the Michigan AG alleges that there is the possibility of discovering previously unknown radiological or nonradiological contamination.166 The AG does not provide any specific reason to expect unknown contamination at the Palisades site, or any information indicating that unknown contamination at Palisades is likely to materially affect the DCE.
Instead, the AG alleges that characterization is not complete, and, even if it were complete, the possibility of finding unexpected contamination later in the decommissioning process remains.167 But as the Commission recently affirmed in Indian Point, the NRC does not require site characterization to be completed at this stage in the decommissioning process.168 Thus, to the extent that the Michigan AG is challenging the cost estimates because site characterization has not yet been completed, it is an impermissible challenge to the NRC regulations.169 Beyond this threshold allegation, the Michigan AG has not provided any specific reason to believe that certain contamination costs are being underestimated at the Palisades site. Unlike New York in Indian Point,170 the Michigan AG does not even attempt to identify any hypothetical causes of further contamination, asserting instead just a general risk of contamination.171 The AG does not identify any specific missing information in the Application, and the mere possibility of additional contamination - without any specific information regarding its scope or the remediation costs expected [at the facility] - is not enough to call into 166 Petition at 26 (emphasis added).
167 Id. at 27 (emphasis added); Capik Decl., 27 (emphasis added).
168 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 21).
169 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 22).
170 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 22-23).
171 See Petition at 27, Capik Decl., 27.
38 4834-2343-5490.v1 question HDIs cost estimates.172 Thus, the AG ha[s] not raised a genuine issue as to whether HDIs assumptions regarding radiological contamination are plausible.173 Further, the Michigan AG does not address or dispute the information in the DCE indicating that HDI reviewed the Palisades decommissioning records required by 10 CFR 50.75(g), including subsurface monitoring reports, groundwater contamination reports, and annual NRC effluent reports, and concluded that events occurring during operation involving the spread of contamination in and around the facility, equipment, or site are well documented and the fate and transport of contaminants are generally understood.174 Similarly, the Michigan AG fails to explain why the NRCs record-keeping, monitoring and reporting requirements are insufficient (and to the extent the Michigan AG is suggesting that they are insufficient, Michigan AG appears to be impermissibly challenging the NRC rules). Those rules require a licensee to maintain:
Records of spills or other unusual occurrences involving the spread of contamination in and around the facility, equipment, or site. These records may be limited to instances when significant contamination remains after any cleanup procedures or when there is reasonable likelihood that contaminants may have spread to inaccessible areas as in the case of possible seepage into porous materials such as concrete. These records must include any known information on identification of involved nuclides, quantities, forms, and concentrations.175 This provision in the NRC rules is specifically intended to prevent incomplete knowledge that might result in underestimation of decommissioning costs.176 The Michigan AG also ignores the NRCs Decommissioning Planning Rule, which requires inter alia licensees to conduct surveys of areas, including the subsurface, that are reasonable to evaluate concentrations 172 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 24).
173 Id.
174 DCE at 21.
175 10 C.F.R. § 50.75(g)(1).
176 General Requirements for Decommissioning Nuclear Facilities, Final Rule, 53 Fed. Reg. 24,018, 24,026 (June 27, 1988).
39 4834-2343-5490.v1 or quantities of residual radioactivity, and to maintain the records from surveys describing the location and amount of subsurface residual radioactivity identified at the site with the records important to decommissioning required by 10 C.F.R. § 50.75(g).177 This rule is intended to ensure that a licensee has a reasonably accurate estimate of the extent to which residual radioactivity is present at the facility, particularly in the subsurface soil and groundwater, to improve decommissioning planning and adequately ensure that a decommissioning fund will cover the costs of decommissioning.178 Fourth, the Michigan AG argues that the risk of a radiological accident could increase decommissioning costs and provides (as an example) the risk of an incident during the transfer of spent fuel to storage casks.179 Once again, however, the AG fails to identify any particular reason why this is a risk at the Palisades site that needs to be addressed in the DCE. As the Commission observed in Indian Point, the mere possibility of additional contamination -
without any specific information regarding its scope or the remediation costs expected [at the facility] - is not enough to call into question HDIs cost estimates.180 The Michigan AG makes no attempt to quantify this risk or show that it is material. Further, as reflected in the Application, HDI and Holtec Palisades will carry onsite property damage and offsite nuclear liability insurance meeting the coverage amounts required by the NRC.181 The Michigan AG provides no explanation why this coverage would be insufficient in the unlikely event of an incident during transfer of spent fuel to storage casks.
177 10 C.F.R. § 20.1501.
178 Decommissioning Planning; Final Rule, 76 Fed. Reg. 35,512, 35,514 (June 17, 2011). The purpose of this final rule is to improve decommissioning planning and thereby reduce the likelihood that a site will become a legacy site...; i.e., a facility that is decommissioning and has an owner that cannot complete the decommissioning work for technical or financial reasons. Id. at 35,516.
179 Petition at 27-28; Capik Decl., 28.
180 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 24).
181 See LTA, Encl. 1 at 20.
40 4834-2343-5490.v1 Fifth, the Michigan AG asserts that spent fuel will need to be repackaged before transfer to DOE and alleges that these potential costs have not been assessed.182 The DCE, however, conservatively includes $38,907,478 that has been allocated to the Transfer of fuel and/or nuclear material away from the ISFSI,183 which includes the estimated costs to repackage in transportation casks.184 The Michigan AG fails to address or dispute this information in the Application, or raise any genuine dispute with the adequacy of this amount for potential repackaging.185 Therefore, it fails to demonstrate any genuine material dispute with the Application.
In addition, the Commission has recognized that these claims regarding repackaging are speculative and that it would be premature to assume (at this stage) which casks DOE will approve for the transportation of spent fuel.186 [The Commission] will not presume, as a reason to deny a license transfer, that DOE will likely succeed in requiring licensees to bear additional fuel packaging-related expenses. Nor would this question be one that could reasonably be resolved in an NRC adjudicatory hearing.187 Consequently, speculation regarding repackaging 182 Petition at 28-29; Capik Decl., 29.
183 DCE at 29.
184 As explained by the International Structure for Decommissioning Costing guidelines referenced by HDI in its submittals, this cost category covers transfers of fuel assemblies into transfer casks. OECD Nuclear Energy Agency, International Structure for Decommissioning Costing of Nuclear Installations, at 176 (2012) (available at https://www.oecd-nea.org/jcms/pl_14804).
185 The Michigan AG and Mr. Capik refer to a Government Accountability Office estimate of $150 to $450 million for the construction of a fuel transfer station (Petition at 29; Capik Decl., ¶ 29), but provide no information explaining why a fuel transfer station would need to be constructed. Mr. Capiks and the Michigan AGs assumption that repackaging would occur after the spent fuel pool has been decommissioned (id.) is itself contrary to the DCE, which assumes that DOE begins removing spent fuel in 2030 (DCE at 22), while major dismantlement activities will not begin until 2035 (DCE at 10). Consequently, the spent fuel pool will still exist for a number of years after DOE acceptance begins.
186 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 40).
187 Pilgrim, CLI-20-12, 91 N.R.C. at __ (slip op. at 26) (no certainty exists at this time regarding how DOE will ultimately perform regarding... spent fuel or which party would bear the cost of transferring fuel to DOE-supplied containers).
41 4834-2343-5490.v1 costs does not indicate that DCE assumptions are implausible or demonstrate any genuine dispute with the Application.
In the alternative, as its sixth claim, the Michigan AG alleges that if the spent fuel does not have to be repackaged then DOE may seek to recover all or some of the costs for the packaging of spent nuclear fuel into dry casks.188 Neither the Michigan AG nor its declarant, Mr. Capik, provide any reason to believe that DOE is likely to assert such a claim, or likely to prevail on it. The Michigan AG and Mr. Capik identify no tested or accepted legal theory that would allow DOE to reverse prior judgments or recoup any portion of the past damages that the Courts have awarded to the owners of nuclear plants or identify any specific DOE recoveries under the Palisades Standard Contract that might be subject to recoupment. For these reasons, the Commission rejected identical allegations in the Indian Point proceeding.
New York provides no basis for presuming that DOE will identify a valid contractual claim, pursue that claim, and succeed in requiring licensees to bear additional packaging-related costs. Nor would these matters be appropriate for resolution in an NRC adjudicatory hearing.189 This ruling is equally applicable to the Michigan AGs assertions.
Finally, in its seventh claim, the Michigan AG alleges that [i]t is unknown how Holtec would provide for the possible contingency of indefinite onsite storage, including all safety and environmental concerns regarding transferring fuel into new dry casks every 100 years.190 In Pilgrim, the Commission rejected this very claim, holding:
We do not require that the site-specific decommissioning cost estimate include estimated costs for potential but highly uncertain contingencies. That indefinite storage is possible does not make it likely....191 188 Petition at 29; Capik Decl., 30.
189 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 41).
190 Petition at 31; Capik Decl., 31.
191 Pilgrim, CLI-20-12, 91 N.R.C. at __ (slip op. at 27).
42 4834-2343-5490.v1 Again, this ruling is equally applicable to the Michigan AGs claims.
The Michigan AG fails to raise a genuine dispute with HDIs estimate for repackaging the VSC-24 canisters.
The Michigan AG next argues that there is no evidence that the cost of reloading the eighteen VSC-24 canisters (not currently licensed for transportation) has been included in the DCE.192 This claim fails to address pertinent information in the DCE and therefore demonstrates no genuine dispute with the Application. Again, Table 3-1 of the DCE indicates that
$38,907,478 has been allocated to the Transfer of fuel and/or nuclear material away from the ISFSI,193 which includes the estimated costs to repackage in transportation casks.194 Because the Michigan AG does not dispute that funds in this category would cover the costs of repackaging the VSC-24 casks, these claims do not support admitting the Contention.195 Thus, the AG fails to raise a genuine dispute with the Application.
The Michigan AGs dispute with HDIs assumed growth rate is an improper challenge to NRC rules.
The Michigan AG next claims that HDIs assumption that the NDT funds will grow at a two percent per year real rate is unreasonable after decommissioning, even if it is consistent with NRC regulations.196 This claim is inadmissible as an impermissible challenge to the NRCs rules. 10 C.F.R. § 50.75(e)(1)(i) provides:
A licensee that has prepaid funds based on a site-specific estimate under
§ 50.75(b)(1) of this section may take credit for projected earnings on the prepaid decommissioning trust funds, using up to a 2 percent annual real rate of return from the time of future funds collection through the projected decommissioning period, provided that the site-specific estimate is based on a period of safe storage 192 Petition at 31; Capik Decl., 32.
193 DCE at 29.
194 See supra note 184.
195 See Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 41).
196 Petition at 32-34; Capik Decl., 33-36.
43 4834-2343-5490.v1 that is specifically described in the estimate. This includes the periods of safe storage, final dismantlement, and license termination.
Here, the Application provides the funding assurance for Palisades through the prepayment method,197 and bases it on the site specific DCE that specifically describes a period of safe storage.198 The Michigan AG does not dispute the applicability of 10 C.F.R.
§ 50.75(e)(1)(i), and in Indian Point, the Commission made it clear that the rule does not require extended periods of storage.199 Further, 10 C.F.R. § 50.82(a)(8)(vi), indicates that in demonstrating the adequacy of decommissioning funds following permanent cessation of operations, the licensee may credit earnings on such funds calculated at not greater than a 2 percent real rate of return. The Michigan AGs claim impermissibly challenges this rule, too.
Even if the Michigan AGs claim were not barred as an impermissible challenge to the NRCs rules, the Michigans AGs arguments would not demonstrate a genuine dispute with the Application, as a two-percent annual rate of return would remain plausible. The AG claims that a two-percent growth rate is unreasonable because there have been a few years when it has not been achieved: from April 2007 to December 2010 (during the housing market crisis and market downturn) and from 2000 to 2002 (during the dot-com bubble downturn).200 Of course, having lower than two-percent performance over the course of a few years during two notable stock market downturns does not mean that the funds will under-perform over the twenty-year period in which Palisades will be decommissioned, or that a two-percent real rate of return is not plausible. Indeed, from December 2007 (after Entergy acquired Palisades) through 2020, the 197 LTA, Encl. 1 at 18.
198 DCE at 13.
199 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 14).
200 Petition at 32-33; Capik Decl., 34.
44 4834-2343-5490.v1 Palisades NDT has increased from approximately $258201 million to $552 million.202 Inflation has averaged about 1.7% over this 13-year period, signifying that the average real, after tax annual rate of return achieved over this period after taxes and after fees was approximately 4.3%203more than twice that permitted to be assumed by the NRCs rules and assumed in the DCE.
The Michigan AG fails to raise a genuine dispute with the application when challenging Holtec Palisades reliance on the nuclear decommissioning trust.
In the final subpart to Contention MI-1, the Michigan AG once more claims that [t]he only source of funds available to Holtec Palisades will be the NDT, and argues that no support is provided for how an alternative funding mechanism would or could be funded should a shortfall in the NDT occur.204 As a threshold matter, these claims do not raise an admissible issue because the Michigan AG does not identify any NRC requirement that prevents an applicant from relying on a single funding source to establish that it is financially qualified to decommission a site.205 In any event, contrary to Michigan AGs claims, the Application explicitly states,
[r]eimbursement of spent fuel management expenses by DOE, which is not credited in the cash flow analysis, would provide a substantial source of additional funds that could be used to provide such adjustment if necessary.206 Indeed, the Michigan AG contradicts its own claims 201 ENOI Letter, Decommissioning Fund Status Report, Att. V (May 8, 2008) (ADAMS Accession No. ML081420032).
202 LTA, Encl. at 18.
203 (1.06)13 x $258 million = $550 million.
204 Petition at 34; Capik Decl., 37.
205 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 49).
206 LTA, Encl. 1 at 18.
45 4834-2343-5490.v1 by subsequently acknowledging this statement in the Application.207 Consequently, there is no basis to suggest that the NDT is the only source of funds available. While DOE recoveries have conservatively not been credited in the cash flow analysis, they remain, as the Commission has observed, relevant to whether the companies could provide additional financial assurance if the decommissioning trusts prove insufficient.208 The Michigan AG argues that no analysis is provided to support the statement in the Application that DOE recoveries would provide a substantial source of additional funds that could be used to provide such adjustment if necessary.209 The Application and DCE, however, provide a cash flow analysis showing the annual spent fuel management costs that Holtec Palisades may seek to recover from DOE, and discuss the use of annual funding updates required by the NRC rules to adjust funding levels.210 The Michigan AG does not explain why more of an analysis is needed or point to any NRC requirement for its inclusion. One can perhaps infer from its claims that the Michigan AG is demanding an analysis of whether spent fuel management costs will be recovered through litigation against DOE, but the Commission has made it clear that these matters are not appropriate for resolution an NRC adjudicatory hearing.211 207 Petition at 35.
208 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 49).
209 Petition at 35; Capik Decl., 38.
210 LTA, Encl. 1 at 18 and Att. 5; DCE at 46-47. DOE recoveries could be used to obtain funds for prepayment, or to obtain a surety bond, letter for credit or insurance, all of which would be permissible forms of financial assurance. Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 49 n.215).
211 Id. (slip op. at 41). See also Pilgrim, CLI-20-21, 91 N.R.C. ___ (slip op. at 26) (Nor would this question be one that could reasonably be resolved in an NRC adjudicatory hearing.).
46 4834-2343-5490.v1 In this regard, the Michigan AG then attempts to minimize DOE recovery as a potential additional source of funds by claiming that it could only be $8.5 million,212 but fails to provide reasonable support for this fanciful claim. The Michigan AG and Mr. Capik, allege that following the dormancy period DOE recovery would be largely limited to the on-going costs of spent fuel management, and then calculate an $8.5 million amount for activities from 2036-2040.213 Holtec Palisades can seek DOE recovery for a variety of spent fuel management costs incurred over a considerably longer period time, potentially far greater than the $1.7 million per year incurred in 2027-2029, amounting as shown in the DCE to approximately $160 million in overall spent fuel management costs.214 The Michigan AG and Mr. Capik simply ignore the approximately $140 million in spent fuel management costs incurred before 2036, including $94 million incurred prior to the dormancy period with no explanation why this amount would not be recoverable. They also ignore approximately $17 million of the $25 million in spent fuel management costs estimated to be incurred in 2036 through 2040, asserting only that [w]hether any of the cost of loading DOE-supplied transportation casks could be recovered from DOE is uncertain.215 The suggestion that recovery of such costs is uncertain does not show that such recovery is implausible, and as previously discussed, the Commission will not presume that DOE will likely succeed in requiring licensees to bear additional fuel packaging-related expenses.
212 Petition at 35; Capik Decl., 39. The Michigan AG and Mr. Capik also observe that a funding shortfall could be mitigated by ceasing decommissioning activities and returning the facility to a long-term storage condition to allow NDT funds to grow, but then argue that even accepting a two percent real rate of return, NDT funds during dormancy are only projected to grow at the rate of about $600,000 per year. Id. While HDI and Holtec Palisades have not proposed such a method of addressing a shortfall either in the Application or DCE, it should be noted that if the dormancy period were extended by 40 years, which would be permissible under the NRC rules allowing decommissioning to be completed in 60 years, the net added growth in current dollars assuming a 2%
annual real rate of return over the additional 40 years would be over $36 million.
213 Id.
214 DCE at 8.
215 Petition at 35 n.81; Capik Decl., ¶ 39 n.45.
47 4834-2343-5490.v1 The Michigan AG also asserts that there is no commitment made by Holtec Palisades to retain the reimbursements,216 but provides absolutely no basis to assume that the revenue stream from DOE recoveries, occurring over an extended period, would not be available, or that Holtec Palisades would escape NRC oversight and fail to comply with the NRC regulations requiring annual reporting and updates should a shortfall ever occur. Similar to New Yorks insufficient claims in the Indian Point proceeding, the Michigan AG does not identify any limitation on
[Holtec Palisades] using the prospect of future DOE recoveries to secure additional financial assurance, should the trust funds be insufficient to meet NRCs requirements.217 Further, the Michigan AG fails to address the NRCs ability to address decommissioning funding on a yearly basis. As the Commission previously explained,
[I]f estimated decommissioning costs exceed remaining decommissioning funds, the licensee must, in its annual financial assurance status report, include additional financial assurance to cover the estimated cost of completion. The licensee must also specify how much it has spent on decommissioning activities, both cumulatively and during the previous year, and it must identify the difference between the estimated cost and the actual cost of work performed during the previous year. The NRC therefore can track whether a licensees actual costs exceeded those that were predicted.218 Consequently, the lack of a current commitment to use DOE recoveries for these purposes is not dispositive,... because the NRC could effectively require [the licensee] to apply a portion of these recoveries to cover estimated decommissioning costs.219 In sum, the NRCs regulatory regime is capable of addressing funding shortfalls if they occur and is designed to prevent the scenarios hypothesized by the Michigan AG. The Michigan 216 Petition at 35; Capik Decl., 28.
217 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 55). Nor does the Commission assume that a licensee will refuse to make additional financial commitments and, in so doing, would choose to violated NRC regulations.
Pilgrim, CLI-20-12, 91 N.R.C. __ (slip op. at 26).
218 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 56).
219 Id. (slip op. at 50 n.216).
48 4834-2343-5490.v1 AG not only fails to show that DOE recoveries are implausible but also to address or even acknowledge NRCs oversight, annual reporting and adjustment requirements, and resulting ability to ensure that adequate decommissioning funding assurance is maintained. The Michigan AG thus fails to raise a genuine dispute with the Application.
B.
Contention MI-2 Is Inadmissible as an Improper Challenge to NRC Rules.
Contention MI which alleges that because HDI and Holtec Palisades have not received an exemption to use the nuclear decommission trust for site restoration and spent fuel management, they fail to satisfy NRC regulations at 10 C.F.R. §§ 50.54(bb) and 72.30(b)220 -
is inadmissible because it demonstrates no genuine dispute with the Application. There is no provision in the Atomic Energy Act or NRC regulations that precludes the Commission from considering an exemption request as part of licensing application. Rather, as the Commission explained in Indian Point, the exemption request is intertwined with, and constitutes an integral part of, the license transfer application,221 and financial assurance will be acceptable if it is based on plausible assumptions and forecasts.222 Consequently, as the Commission held in Indian Point, a general argument that an applicant cannot rely on an exemption to support its cost estimates does not raise a genuine dispute with the application.223 The Michigan AGs argument that Holtec Palisades must return any DOE recoveries to the trust funds224 likewise fails to demonstrate any genuine dispute with the exemption request or Application. The Michigan AG does not identify any NRC regulation that requires DOE recoveries to be returned to a nuclear decommissioning trust. Instead, it merely repeats the 220 Petition at 36-37.
221 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 18).
222 Id. (citing North Atlantic Energy Service Corp. (Seabrook Station, Unit 1), CLI-99-6, 49 N.R.C. 201, 222 (1999)).
223 Id. at 19.
224 Petition at 40.
49 4834-2343-5490.v1 argument rejected in Indian Point that DOE recoveries should be returned to the trust as the collateral necessary for the additional financial assurance required under 10 C.F.R.
§§ 50.82(a)(8)(vi) and (vii)(C).225 As the Commission held in Indian Point, the cited regulations are financial assurance requirements for the annual status reports a licensee must provide, but these requirements do not apply to a licensees initial estimates of decommissioning funding needs in its PSDAR.226 Nor does Contention 2 include any factual basis demonstrating a genuine dispute with the exemption request. Instead, the Michigan AG raises only general policy concerns, arguing that if HDI is allowed to treat the DOE recoveries purely as a revenue stream[,] the recoveries will become a profit windfall realized by HDI before it has satisfied the entirety of its decommissioning and site restoration.227 That the revenue stream from DOE recoveries might contribute to HDIs profits is sheer speculation and, in any event, irrelevant to whether HDI and Holtec Palisades have demonstrated their financial qualifications.
Further, the Michigan AG provides no basis to assume that this revenue stream (even if it constituted some amount of profit) could not be used to adjust funding assurance if necessary.
As the cash flow analysis shows, the spent fuel management expenses that might be recovered from DOE occur after they have been incurred throughout the decommissioning period.
Consequently, if there were a shortfall in any year, Holtec Palisades would have the ability (and NRC could direct it) to make additional contributions to the NDT or provide one of the other acceptable means of providing funding assurance (such as a providing a surety bond or parent guarantee). An admissible contention cannot be based on an assumption that Holtec Palisades 225 Compare id., with Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 20 & n.85).
226 Indian Point, CLI-21-01, 92 N.R.C. at __ (slip op. at 20).
227 Petition at 39.
50 4834-2343-5490.v1 would fail to comply with such an NRC direction. [T]he NRC does not presume that a licensee will violate agency regulations wherever the opportunity arises.228 In short, the Michigan AG fails to demonstrate any genuine material dispute with the Application.
228 Private Fuel Storage, L.L.C. (Indep. Spent Fuel Storage Installation), CLI-01-9, 53 N.R.C. 232, 235 (2001). See also GPU Nuclear, Inc. (Oyster Creek Nuclear Generating Station), CLI-00-6, 51 N.R.C. 193, 207 (2000) (NIRS also fails to offer documentary support for its argument that AmerGen is likely to violate our safety regulations.
Absent such support, this agency has declined to assume that licensees will contravene our regulations.).
51 4834-2343-5490.v1 V.
Conclusion For all of the foregoing reasons, the Michigan AGs Petition for Leave to Intervene and Request for a Hearing should be denied.
Susan H. Raimo Entergy Services, LLC 101 Constitution Avenue, NW Suite 200 East Washington, DC 20001 Tel. 202-530-7330 Email: sraimo@entergy.com William B. Glew, Jr.
Entergy Services, LLC 639 Loyola Avenue, 22nd Floor New Orleans, LA 70113 Tel. (504) 576-3958 Email: wglew@entergy.com Counsel for Entergy Nuclear Operations, Inc. and Entergy Nuclear Palisades, LLC Respectfully submitted,
/signed electronically by Anne Leidich /
Anne Leidich Pillsbury Winthrop Shaw Pittman, LLP 1200 Seventeenth Street, N.W.
Washington, DC 20036-3006 Tel. 202-663-8707 E-mail: Anne.Leidich@pillsburylaw.com David R. Lewis Pillsbury Winthrop Shaw Pittman, LLP 1200 Seventeenth Street, N.W.
Washington, DC 20036-3006 Tel. 202-663-8474 E-mail: David.lewis@pillsburylaw.com William F. Gill IV Holtec International Holtec Technology Campus 1 Holtec Boulevard Camden, NJ 08104 Telephone: (856) 797-0900 E-mail: w.gill@holtec.com Counsel for Holtec International and Holtec Decommissioning International, LLC Alan D. Lovett Balch & Bingham LLP 1710 Sixth Avenue North Birmingham, AL 35203-2015 Telephone: 205-226-8774 Email: alovett@balch.com March 22, 2021
4834-2343-5490.v1 March 22, 2021 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Commission In the Matter of
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Entergy Nuclear Operations, Inc.,
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Entergy Nuclear Palisades, LLC,
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Docket Nos. 50-255-LT Holtec International, and
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50-155-LT Holtec Decommissioning International, LLC
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72-007-LT
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72-043-LT (Palisades Nuclear Plant and
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Big Rock Point Site)
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CERTIFICATE OF SERVICE I hereby certify that copies of the foregoing Applicants Answer Opposing the Michigan Attorney Generals Petition for Leave to Intervene and Request for a Hearing has been served through the E-Filing system on the participants in the above-captioned proceeding this 22nd day of March 2021.
/signed electronically by Anne R. Leidich/
Anne R. Leidich