ML23004A082: Difference between revisions

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| number = ML23004A082
| number = ML23004A082
| issue date = 11/18/2022
| issue date = 11/18/2022
| title = Applicants' Redacted Initial Statement of Position on Michigan Attorney General Contentions
| title = Applicants Redacted Initial Statement of Position on Michigan Attorney General Contentions
| author name = Day J, Leidich A, Lewis D, Lovett A, Raimo S
| author name = Day J, Leidich A, Lewis D, Lovett A, Raimo S
| author affiliation = Balch & Bingham, LLP, Entergy Nuclear Operations, Inc, Entergy Nuclear Palisades, LLC, Entergy Services, LLC, Holtec Decommissioning International, LLC, Holtec International, Pillsbury, Winthrop, Shaw, Pittman, LLP
| author affiliation = Balch & Bingham, LLP, Entergy Nuclear Operations, Inc, Entergy Nuclear Palisades, LLC, Entergy Services, LLC, Holtec Decommissioning International, LLC, Holtec International, Pillsbury, Winthrop, Shaw, Pittman, LLP
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 November 18, 2022 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of                            )      Docket Nos. 50-255-LT-2 ENTERGY NUCLEAR OPERATIONS,                  )                      50-155-LT-2 INC., ENTERGY NUCLEAR                        )                      72-007-LT PALISADES, LLC, HOLTEC                      )                      72-043-LT-2 INTERNATIONAL,            and      HOLTEC    )
DECOMMISSIONING          INTERNATIONAL,    )      ASLBP No.      22-974-01-LT-BD01 LLC                                          )
                                            )
(Palisades Nuclear Plant and Big Rock Point  )
Site)                                        )
APPLICANTS INITIAL STATEMENT OF POSITION ON MICHIGAN ATTORNEY GENERAL CONTENTIONS
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 TABLE OF CONTENTS I. INTRODUCTION ........................................................................................................... 1 II. APPLICABLE LEGAL STANDARDS ........................................................................... 4 A. Reactor License Transfer Requirements ............................................................... 4 B. NRC Decommissioning and Related Financial Assurance Requirements .............. 6 C. Spent Fuel Management ....................................................................................... 9 III. APPLICANTS EXPERT WITNESSES .......................................................................... 9 A. Frank C. Graves ................................................................................................... 9 B. Christopher F. Tierney ....................................................................................... 10 IV. APPLICANTS STATEMENT OF POSITION ON ADMITTED CONTENTIONS ...... 11 A. It is plausible that, once it begins performance, DOE will accept all of the SNF at Palisades within the eleven-year window assumed in the DCE. ...................... 11
: 1.      The background of the Nuclear Waste Policy Act, the Standard Contract, and DOEs SNF disposal program support HDIs assumed eleven-year pick-up window assumption. ............................................... 13
: 2.      There are multiple removal paradigms available that would allow HDI to transfer all of the Palisadess SNF offsite within the eleven-year window. ................................................................................................. 18
: 3.      Removal of SNF at a pace faster than the 1987 Acceptance Rate would remove all fuel from Palisades even earlier under all plausible acceptance paradigms. ............................................................................ 24
: 4.      HDIs assumption that the government will accept and remove all SNF from Palisades in an eleven-year pick-up window is reasonable. ............. 27 B. The HDI cost estimate reasonably falls below the NRC formula amount due to differences between the formulas vintage and generic purpose and the HDI estimates basis on contemporaneous project-specific inputs. ............................. 28
: 1.      Application of the § 50.75(c) formula neither prescribes nor constrains HDIs DCE. ............................................................................................ 28
: 2.      There are multiple other reasons that provide adequate justification for HDIs DCE falling below the formula amount. ....................................... 37 i
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390
: 3. HDIs estimate is reasonable, despite being $30 million lower than the formula. .................................................................................................. 62 C. The Palisades DCE contingency amount is reasonable and accounts for the types of historically inevitable costs the Commission determined should be addressed by contingency at this stage of the project. ......................................... 63
: 1. Other than high-level requirements in staff guidance, there are no NRC guidelines for the methodology licensees should use to establish contingency, nor does the NRC impose a minimum amount of contingency that must be included in a § 50.82 cost estimate. ................. 65
: 2. The DCE more than adequately addresses inevitable costs expected at this stage of the project. .......................................................................... 71 D. Holtec Palisades has multiple avenues for ensuring there will be sufficient funds available to make any needed adjustments over the dormancy period. ...... 85
: 1. The need to show assurances only applies for the dormancy period. ....... 85
: 2. Holtec Palisades has identified multiple means of adjusting funding in its filings. ............................................................................................... 87
: 3. No license conditions are warranted........................................................ 94 V. CONCLUSION ............................................................................................................. 97 ii
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 APPLICANTS INITIAL STATEMENT OF POSITION ON MICHIGAN ATTORNEY GENERAL CONTENTIONS Pursuant to 10 C.F.R. § 2.1322(a)(1) and the Atomic Safety and Licensing Boards (Board) August 30, 2022 Memorandum and Order setting the schedule for submissions, 1 Applicants Entergy Nuclear Operations, Inc. (ENOI), Entergy Nuclear Palisades, LLC (ENP)
(ENOI and ENP, collectively Entergy), Holtec International (Holtec), and Holtec Decommissioning International, LLC (HDI) (Entergy, Holtec, and HDI, collectively, Applicants) submit this Initial Statement of Position (Statement) on the portions of the Michigan Attorney Generals Contention MI-1 admitted for hearing by Commission Order CLI-22-08.2 This Statement is supported by the testimony of Applicants witnesses Frank C. Graves, Christopher F. Tierney, James B. Buckley, Jr., and Allen Goulette, as well as other exhibits, which are being filed contemporaneously with this Statement.
I.      INTRODUCTION On December 23, 2020, Applicants submitted an application (Application) requesting that the Nuclear Regulatory Commission (Commission or NRC) approve the indirect transfer of control from Entergy to Holtec of Renewed Facility Operating License No. DPR-20 for the Palisades Nuclear Plant (Palisades) and the general license for the Palisades Independent Spent Fuel Storage Installation (ISFSI) as well as Facility Operating License No. DPR-6 for the Big Rock Point Site (Big Rock) and the general license for the Big Rock ISFSI.3 The application 1 Memorandum and Order (Scheduling and Case Management Order) (Aug. 31, 2022) (ADAMS Accession No. ML22243A168).
2 Entergy Nuclear Operations, Inc. (Palisades Nuclear Plant and Big Rock Point Site), Memorandum and Order, CLI-22-08, __ NRC __, slip op. (July 15, 2022).
3 See generally Application for Order Consenting to Transfers of Control of Licenses and Approving Conforming License Amendments, (Dec. 23, 2020) (ADAMS Accession No. ML20358A075) (hereinafter Application); Palisades Nuclear Plant Site-Specific Decommissioning Cost Estimate, attached to Letter from 1
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 also asked the Commission to approve the transfer of ENOIs operating authority (i.e., its authority to conduct licensed activities at Palisades and Big Rock) to HDI. 4 On February 2, 2021, the Commission published a notice in the Federal Register regarding the Application.5 In the Notice, the Commission provided an opportunity to any person whose interest may be affected, within twenty days of the Notice, to request a hearing and file a petition for leave to intervene in the direct transfer proceeding.6 Among others, the Michigan Attorney General (Attorney General) filed on February 24, 2021 a petition seeking leave to intervene and requesting a hearing on certain contentions. 7 On July 15, 2022, the Commission granted the Attorney Generals petition in part, admitting the following four issues contained within Contention MI-1 for hearing:
(a) The projected length of time for transfer of all spent fuel off of the Palisades site:
The applicants should address how they determined that the estimated 11-year spent fuel transfer period constitutes a plausible timeframe for removal of all Palisades spent fuel. In their description, the applicants should clarify the assumptions on which they relied, including what fuel acceptance priority and fuel allocation or transfer rate they assumed for their schedule. . . .
(b) Reasonableness of the site-specific decommissioning cost estimate falling below the minimum formula amount:
The applicants should provide a detailed explanation of the primary reasons that the cost estimate falls significantly below the minimum formula amount. We also direct the parties and invite the staff to address whether the minimum formula regulation in section 50.75(b) applies to this application.
Holtec to US NRC, Post Shutdown Decommissioning Activities Report Including Site-Specific Decommissioning Cost Estimate for Palisades Nuclear Plant, dated Dec. 23, 2020 (ADAMS Accession No. ML20358A232) (hereinafter DCE).
4 See generally id.
5 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) (hereinafter Notice).
6 Id.
7 See generally Petition of the Michigan Attorney General for Leave to Intervene and for a Hearing (Feb.
24, 2021) (ADAMS Accession No. ML21055A888) (hereinafter Petition).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 (c) Adequacy of contingency funding:
The applicants should explain how they calculated and derived the 12% level applied for contingency and concluded that this amount for contingency is reasonably adequate for Palisades. The parties should address relevant industry norms, practices, and standards for the contingency amount added to reactor decommissioning cost estimates at a similar project stage. . . .
(d) Ability to provide additional financial assurance as a means to adjust funding:
The applicants should describe how they will ensure that sufficient additional funding will be available as a means to adjust funding if needed. . . . The parties additionally should address whether license conditions or other forms of assurances are warranted.8 Contention MI-1, and its various subparts, have no merit. As to Contention MI-1(a), an analysis of allocations and pickup rates demonstrates that Applicants assumption that the Department of Energy (DOE) would begin accepting spent nuclear fuel (SNF) from Palisades in 2030 and complete that acceptance process within an eleven-year window is plausible under multiple acceptance models. Contention MI-1(b) also fails under scrutiny,
                                                                                      . Moreover, the minimum formula amount does not substitute for the site-specific decommissioning cost estimate (DCE) at the time of decommissioning, for a variety of reasons, including the inability to reconcile the basic formula with a decommissioning project in progress; technologies, business structures, and expertise that did not exist when the formula was developed four decades ago; and the fact that because it is not site-specific, it does not reflect actual, planned work activities that can be traced to calculate the estimated cost to complete decommissioning. HDIs detailed cost 8 Mem. and Order, CLI-22-08, slip op. at 134-35.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 estimates based on recent experience is also a reason why Contention MI-1(c) must fail HDIs contingency factor was based on a thorough evaluation of Palisades-specific risks and estimation uncertainty that leveraged the combined knowledge of Holtecs and HDIs subject-matter experts and incumbent site personnel, as well as the lessons learned from estimating three previous decommissioning projects and actively decommissioning two of those. Finally, MI-1(d)a challenge to HDIs ability to provide additional financial assurance as a means to adjust funding fails because HDI has multiple avenues for ensuring there will be sufficient funds available to make any needed adjustments over the dormancy period. Not only is there already a sufficient cushion in the NDT to cover any necessary funding adjustments, but HDI can adjust the decommissioning schedule to maximize the NDT and expects to receive recoveries of SNF management costs at the end of the planned dormancy period, when actual decommissioning costs will be about to begin. In sum, a detailed analysis demonstrates that HDIs DCE is well supported and more than sufficiently plausible. Contention MI-1 is without merit and the Commission should deny the Attorney Generals challenge and grant the Application without further financial conditions.
II.      APPLICABLE LEGAL STANDARDS A.      Reactor License Transfer Requirements Under Section 184 of the Atomic Energy Act, an NRC licensee must receive NRC consent in writing for any transfer of control of the license.9 This statutory requirement, which is embodied in 10 C.F.R. § 50.80, applies to both direct and indirect license transfers.10 The NRC reviews the 9 42 U.S.C. § 2234.
10 See NRC Backgrounder, Reactor License Transfers (Apr. 2016), at 1-2 (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). Id.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 transferees technical and financial qualifications prior to approving a license transfer. 11 The purpose of the transfer review is to focus 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.12 The NRC must find reasonable assurance of financial qualifications to grant a license transfer application. Applicants must provide reasonable assurance by a preponderance of the evidence.13 Commission precedent clearly states that the reasonable assurance standard does not require an applicant to meet an absolute or beyond a reasonable doubt standard.14 Merely casting doubt on the application is legally insufficient to defeat a finding of reasonable assurance. 15 When evaluating a license transfer applicants financial qualifications, the NRC 11 See 10 C.F.R. §§ 50.80(b)(1), (c)(1). See also Standard Review Plan on Power Reactor Licensee Financial Qualifications and Decommissioning Funding Assurance, NUREG-1577, Rev. 1, (Dec. 13, 2001)
(ADAMS Accession No. ML013330264).
12 Final Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry, 62 Fed. Reg. 44,071, 44,077 (Aug. 19, 1997).
13 AmerGen Energy Co., LLC (Oyster Creek Nuclear Generating Station), CLI-09-07, 69 N.R.C. 235, 263-64 (2009). See also Commonwealth Edison Co. (Zion Station, Units 1 & 2), ALAB-616, 12 N.R.C. 419, 421 (1980);
N. Anna Envt. Coal v. NRC, 533 F.2d 655, 667-68 (D.C. Cir. 1976). The applicant bears the burden of proof concerning whether the license transfer should be issued, and the applicants position must be supported by a preponderance of the evidence. La. Power & Light Co. (Waterford Steam Electric Station, Unit 3), ALAB-732, 17 N.R.C. 1076, 1093 (1983); (citing Tennessee Valley Auth. (Hartsville Nuclear Plant, Units 1A, 2A, 1B, & 2B) ALAB-463, 7 N.R.C. 341, 360 (1978), reconsideration denied, ALAB-355, 7 N.R.C. 459 (1978)).
14 AmerGen Energy Co., CLI-09-7, 69 N.R.C. at 262 n.142; Commonwealth Edison Co., ALAB-616, 12 N.R.C. at 421; N. Anna Envt. Coal, 533 F.2d at 667-68 (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.).
15 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)).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 accepts financial assurances based on plausible assumptions and forecasts. 16 Discussing financial assurances, the Commission has explained that it accept[s] 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.17 As a result, the Commission has found that there is 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.18 Thus, a site-specific DCE, such as the one prepared for the Application at issue, provides sufficient reasonable assurance if it relies on plausible assumptions and forecasts.
B.      NRC Decommissioning and Related Financial Assurance Requirements Under NRC regulations, decommissioning a nuclear reactor requires safely removing the facility from service, reducing residual radioactivity to a level that allows releasing the property for unrestricted use (or restricted use subject to conditions, not proposed here), and terminating the license.19 NRC regulations require that applicants and licensees provide reasonable assurance that funds will be available for the entire decommissioning process. 20 The primary methods of providing financial assurance for decommissioning permitted by the NRC are through (1) 16 Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generating Station, Units 1,2, and 3 and ISFSI),
CLI-21-01, 93 N.R.C 1, 9 (2021).
17 Id.
18 Id.
19 10 C.F.R. § 50.2.
20 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.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 prepayment; (2) an external sinking fund; (3) a surety, insurance, or other guarantee; or (4) a combination of these or equivalent mechanisms.21 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.22 The decommissioning process begins when a licensee certifies to NRC Staff that it has permanently ceased operations and it has permanently removed fuel from the reactor vessel.23 NRC regulations require a licensee to submit a Post-Shutdown Decommissioning Activities Report (PSDAR) prior to or within two years following the permanent cessation of operations.24 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 DCE, including the projected cost of managing irradiated fuel.25 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 impacts not previously reviewed, or result in the lack of reasonable assurance that adequate funds will be available for decommissioning.26 21 10 C.F.R. § 50.75(e)(1)(i)-(iii), (vi).
22 See generally 10 C.F.R. § 50.82(a).
23 10 C.F.R. § 50.82(a)(1)(i)-(ii).
24 10 C.F.R. § 50.82(a)(4)(i).
25 Id.
26 10 C.F.R. § 50.82(a)(6).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Once a licensee submits its site-specific DCE, it generally is allowed access to the balance of the nuclear decommissioning trust (NDT) fund monies for the remaining decommissioning activities with broad flexibility.27 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. § 50.2.28 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.29 Finally, the withdrawals must not inhibit the ability of the licensee to complete funding of any shortfalls in the NDT needed to ensure the availability of funds to ultimately release the site and terminate the license.30 Unless otherwise authorized, the site must be decommissioned within sixty (60) years of shutdown.31 The licensee remains subject to NRC oversight until decommissioning is completed and the license is terminated. The Commission may not approve the license termination plan (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.32 27 See Decommissioning of Nuclear Power Reactors, 61 Fed. Reg. 39,278, 39,285 (July 29, 1996)
(hereinafter 1996 Decommissioning Rule).
28 10 C.F.R. § 50.82(a)(8)(i)(A).
29 10 C.F.R. § 50.82(a)(8)(i)(B).
30 10 C.F.R. § 50.82(a)(8)(i)(C). Throughout decommissioning, the NRC Staff also monitors the licensees use of the decommissioning trust fund via its review of the licensees annual financial assurance status reports. The annual reports must also include the status of funding to manage SNF, including the amount of funds available, the projected cost of managing SNF until it is removed by the DOE and, if there is a funding shortfall, a plan to obtain additional funds to cover the cost. 10 C.F.R. § 50.82(a)(8)(vii).
31 10 C.F.R. § 50.82(a)(3).
32 10 C.F.R. § 50.82(a)(10), (11).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 C.      Spent Fuel Management NRC regulations also address the need to ensure adequate funds for the management of SNF. Among other requirements, a licensees DCE must include the projected costs of managing SNF until it is removed from the site.33 Once a licensee files that DCE, it must report annually to the NRC on the status of its funding to manage SNF, including the amount of funds available, the projected cost of managing SNF until it is removed by the DOE, and, if there is a funding shortfall, a plan to obtain additional funds to cover the cost.34 III. APPLICANTS EXPERT WITNESSES In addition to the testimony of Applicants fact witnessesJames B. Buckley, Jr., and Allen Gouletteand Applicants exhibits, Applicants also offer testimony from two expert witnessesFrank C. Graves of the Brattle Group and Christopher F. Tierney of HKA.
A.      Frank C. Graves Mr. Frank Graves is a Principal of The Battle Group, an economic and management consulting firm. He received an M.S. with a concentration in finance from the M.I.T. Sloan School of Management in 1980, and a B.A. in Mathematics from Indiana University in 1975. Mr. Graves specializes in regulatory and financial economics, especially for electric and gas utilities, and in litigation matters related to securities litigation, damages from breached energy contracts, and risk management. He has over 35 years of experience in assisting utilities in the design and implementation of long-range planning, investment, and operating policies, and in assisting their counsel with regulatory compliance and policy review. He has provided expert testimony regarding the Governments non-breach performance in removing spent nuclear fuel (SNF) in 33 10 C.F.R. § 50.82(a)(4)(i).
34 10 C.F.R. § 50.82(a)(8)(vii).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 litigation involving the following nuclear power plants: Yankee Atomic, Maine Yankee, Connecticut Yankee, La Crosse, Humboldt Bay, Diablo Canyon, Trojan, Rancho Seco, Vermont Yankee, Kewaunee, Crystal River, Duane Arnold, Fort Calhoun, Oyster Creek, San Onofre, and Three Mile Island. In those cases, Mr. Graves developed an economic model that characterizes the Department of Energy (DOE) spent fuel programs non-breach performance, identifying the timing and amounts of the programs SNF removal from all U.S. nuclear plants, had the government not breached its intended performance of nuclear waste removal (i.e., if it had begun SNF removal in 1998, at the appropriate rate).
The testimony of Mr. Graves in this proceeding focuses on the timing of DOEs removal of the last of the SNF from the Palisades, as it relates to HDIs DCE. Such matters are based on both his technical expertise and experience and his first hand knowledge of the issues raised in the Michigan Attorney Generals contentions.
B.      Christopher F. Tierney Mr. Christopher Tierney is a Partner at HKA Global, Inc., a global consulting firm of accounting, financial, economic, and engineering professionals with experience and expertise in the evaluation of economic damages involving lost profits, business valuation, business interruption, bankruptcy, class action or intellectual property, as well as conducting fraud and regulatory investigations. Mr. Tierney has a Bachelor of Civil Engineering from the Georgia Institute of Technology, and a Master of Business Administration, with concentrations in Accounting and Finance, from Tulane University. Mr. Tierney has over 35 years of experience in the evaluation of economic, accounting, and financial issues, including the quantification of economic damages and analysis of cost estimates. He also has extensive experience in the public utilities and nuclear power industries, including in the construction and government contracts industries. Specifically with respect to commercial nuclear power, Mr. Tierney has assisted clients 10
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 on contract disputes; regulatory and intellectual property matters; and matters involving nuclear plant engineering and construction, licensing, operations, and decommissioning. His decommissioning experience includes the review, analyses, and development of cost estimates and assisting clients to determine the economic impacts of unanticipated events and changed circumstances, as well as related experience including business disputes involving plant owners and decommissioning contractors and the recovery of costs associated with spent nuclear fuel storage and related costs from DOE.
The testimony of Mr. Tierney in this proceeding primarily focuses on the appropriateness of the comparison between HDIs DCE and the NRCs 50.75 formula, the reasons for differences, and the quantification of such differences. These matters are based on both his technical expertise and experience and his first-hand knowledge of the issues raised in the Michigan Attorney Generals contentions.
IV. APPLICANTS STATEMENT OF POSITION ON ADMITTED CONTENTIONS A.      It is plausible that, once it begins performance, DOE will accept all of the SNF at Palisades within the eleven-year window assumed in the DCE.
In its first contention, the Michigan Attorney General urges the Commission to deny the Application because it says HDI failed to demonstrate that it is financially qualified to hold the NRC license for Palisades. In support of its argument, the Attorney General contends that HDIs DCE fails to account adequately for the costs of managing SNF onsite at Palisades until it is transferred to the DOE when it ultimately performs under the Standard Contract. According to the Attorney General, HDIs assumption that it will transfer all of Palisadess SNF to DOE by 2041 is not reasonable given DOEs current progress in licensing a repository. 35 Specifically, the 35 Petition at 16 ¶ 19.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Attorney General challenged HDIs assumption that DOE will begin to pick up SNF from Palisades by 2030. 36 The Attorney General also challenged HDIs projected timeframe of approximately eleven years for DOE to remove all SNF from the Palisades site.37 In its July 15, 2022 Memorandum and Order, the Commission rejected the Attorney Generals challenge to HDIs assumed start date and accept[ed] as plausible that by 2030 a storage facility will be available to receive the Palisades spent fuel. 38 The Commission did, however, order HDI to address how [it] determined that the estimated 11-year spent fuel transfer period constitutes a plausible timeframe for removal of all Palisades spent fuel.39 Thus, the only question regarding HDIs assumed SNF transfer timeline that is at issue in this proceeding is whether an eleven-year transfer window is plausible.
As demonstrated in this Statement, the testimony of Frank GravesApplicants expert on SNF management modelingand in the related exhibits that Mr. Graves relies upon, an eleven-year pick up timeframe is plausible under multiple acceptance models.
36 Id. at 16-18 ¶¶ 20-22.
37 Id.
38 Mem. and Order, CLI-22-08, slip op. at 27.
39 Id. at 134.
40 Id. at 29, n.107.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Finally, given DOEs long delay in beginning acceptance of SNF from civilian nuclear power reactors (and the increasing number of shutdown reactors), it is also reasonable to believe that, when DOE performs, it will do so at a higher acceptance rate than that contained in the 1987 Acceptance Rate. Doing so would yield SNF removal dates for Palisades that are earlier than any of the other paradigms alone. As a result, HDIs assumed eleven-year pickup window is reasonable and the Attorney Generals challenge to Holtecs assumed eleven-year pick up window is without merit.
: 1. The background of the Nuclear Waste Policy Act, the Standard Contract, and DOEs SNF disposal program support HDIs assumed eleven-year pick-up window assumption.
During the 1970s, when many of the countrys existing nuclear plants were licensed and constructed, nuclear utilities expected to be able to ship their SNF offsite for reprocessing.
However, the commercial reprocessing of SNF was effectively halted in the United States in the late 1970s amid concerns that it could contribute to the proliferation of nuclear weapons material.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 This moratorium on reprocessing effectively made storage and ultimately disposal the only option for dealing with SNF from civilian nuclear power reactors.
As a result of the rising inventory of SNF that domestic nuclear electrical utilities were being required to store, in 1982, Congress passed and, in 1983, President Reagan signed the Nuclear Waste Policy Act (NWPA), which established federal responsibility to provide for the permanent disposal of high-level radioactive waste and such [SNF] as may be disposed of in order to protect the public health and safety and the environment.41 To achieve this goal, the NWPA directed the Secretary of Energy to find an appropriate repository site and, following Presidential and Congressional approval of that selection, proceed with construction authorization through the NRC. In 1987, the NWPA was amended to establish Yucca Mountain in Nevada as the sole candidate site for a permanent geologic repository. 42 The NWPA also directed the Secretary to promulgate and enter into contracts with the nations nuclear utilities for the acceptance, transportation, and disposal of SNF.43 As a result, DOE promulgated the Standard Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (Standard Contract), the terms of which are presented at 10 C.F.R. § 961.11.
The Standard Contract provides, among other things, that, in return for the payment of fees into the Nuclear Waste Fund (NWF), the government, beginning not later than January 31, 1998, would begin accepting and take title to SNF from each of the nations domestic nuclear electrical utilities for permanent disposal at the to-be-constructed federal SNF repository at Yucca 41 42 U.S.C. § 10131(a)(4).
42 See Omnibus Budget Reconciliation Act of 1987, Pub. L. No. 100-203, 101 Stat. 1330 (codified at 42 U.S.C. § 10172).
43 42 U.S.C. § 10222(a).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Mountain.44 The Standard Contract also requires that DOE provide the equipment, procedures, and transportation casks necessary to transfer title of the utilities SNF to the federal government.45 Entry into the Standard Contract was effectively mandatory. In fact, the federal government has made the Standard Contract with DOE a prerequisite for the issuance or renewal of nuclear power plant licenses.46 Consumers Power Corporation (Consumers) signed the Standard Contract for Palisades and Big Rock on June 3, 1983.47 Consumers sold Palisades and Big Rock to ENP on April 11, 2007 and assigned the Standard Contract for both to ENP contemporaneously with the sale. Through an internal corporate restructuring, ENPs assets and liabilities, including Palisades and Big Rock Point, were transferred to a new Entergy entity. Holtec subsidiary Nuclear Asset Management Company purchased the new entity on June 28, 2022 and changed that entitys name to Holtec Palisades, LLC (Holtec Palisades).
Despite its obligation to begin accepting SNF from civilian nuclear power reactors by January 31, 1998, the federal government has yet to build the permanent SNF repository that is required by the NWPA and the Standard Contract. As a result, beginning in 1998, nuclear utilities began filing a series of breach of contract actions against the federal government in the United States Court of Federal Claims. As existing law continues to require a repository, these actions are for partial breach of contract only, not total breach.48 In other words, the Standard Contract for 44 HOL007, U.S. Department of Energy Contract No. DE-CR01-83NE44374 Contract for Disposal of Spent Nuclear Fuel And/Or High-Level Radioactive Waste for Palisades Nuclear Plant and Big Rock Point Site at art.
IV(B)(1) (June 3, 1983) (hereinafter Palisades Standard Contract); 10 C.F.R. § 961.11 art. IV(B)(1).
45 HOL007, Palisades Standard Contract at art. IV(B)(2); 10 C.F.R. § 961.11 art. IV(B)(2).
46 42 U.S.C. § 10222(b).
47 See generally HOL007, Palisades Standard Contract.
48 See Ind. Mich. Power Co. v. United States, 422 F.3d 1369, 1378 (Fed. Cir. 2005) (holding that SNF cases are for partial breach of the Standard Contract and holding that, as a result, nuclear utilities must bring any future actions for damages related to DOEs breach of the Standard Contract within six years of incurring such damages).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Palisades remains in force, and the party to the Standard Contract must sue the federal government at least every six years to recover the costs incurred to store SNF during a given claim period.49 According to the Standard Contract, [b]eginning not later than July 1, 1987, DOE shall issue an annual capacity report, which must set forth the projected annual receiving capacity for the DOE facility(ies) and the annual acceptance ranking of all civilian nuclear power reactors, including, to the extent available, capacity information for ten (10) years following the projected commencement of operation of the initial DOE facility. 50 The DOE issued its first Annual Capacity Report (ACR) in June 1987. At the same time, the DOE also issued its 1987 Mission Plan Amendment. These two documents utilize an overall SNF acceptance rate that ramps up to a rate of 2,650 MTU per year by the seventh year of SNF acceptance, and then increases to a steady-state rate of 3,000 MTU per year in the eleventh year of the program.51 While the DOE has issued multiple other ACRs since 1987, the Federal Circuit has held that because [t]he 1987 report was the last attempt to comply with the terms of the contract[,] . . . the Standard Contract required DOE to accept SNF/HLW in accordance with the 1987 ACR process. 52 However, nothing in the Standard Contract prevents DOE from accepting SNF on a more accelerated basis.
Under the Standard Contract, the initial allocation of acceptance priority is based upon the age of the SNF and/or HLW as calculated from the date of discharge of such material from the civilian nuclear power reactor. DOE will first accept from [the utility] the oldest SNF and/or HLW 49 Id.
50 HOL007, Palisades Standard Contract at art. IV(B)(5)(b); 10 C.F.R. § 961.11 art. IV(B)(5)(b).
51 HOL012, Office of Civilian Radioactive Waste Management, Annual Capacity Report at 7 (June 1987)
(hereinafter 1987 ACR); HOL011, OCRWM Mission Plan Amendment at 61 (June 1987) (hereinafter 1987 Mission Plan Amendment).
52 Pac. Gas & Elec. Co. v. United States, 536 F.3d 1282, 1292 (Fed. Cir. 2008).
16
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 for disposal . . . .53 This initial acceptance priority ranking is referred to as oldest-fuel-first or OFF. However, [a] utility is not required by the contract to actually deliver its SNF to the DOE in an oldest-fuel-first order. The OFF priority ranking merely assigns a utility a place in the queue.
It can then use its allocation to deliver any fuel that meets the criteria of the Standard Contract.54 Indeed, once acceptance rights have been allocated, the Standard Contract grants the utility the right to identify all SNF and/or HLW the [utility] wishes to deliver to DOE beginning sixty-three (63) months thereafter.55 This standard allows utilities to pool OFF rights within a fleet of nuclear power plants under the same ownership and to use those OFF rights for acceptance at any of their plants, regardless of which plant was actually responsible for the discharge that created the OFF rights. DOE approval is not required.
OFF is not the only acceptance priority contemplated under the Standard Contract. For example, the Standard Contract contemplates that DOE may give priority in the acceptance queue to shutdown reactors. According to the Standard Contract, [n]otwithstanding the age of the SNF and/or HLW, 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.56 The Standard Contract also contemplates that utilities may exchange OFF rights, thereby moving one utility up in the acceptance queue and the other utility back in the queue. According to the Standard Contract, utilities shall have the right to exchange approved delivery commitment schedules with parties to other contracts with DOE for disposal of SNF 53 HOL007, Palisades Standard Contract at art. VI(B)(1)(a); 10 C.F.R. § 961.11 art. VI(B)(1)(a).
54 Northstar Vermont Yankee, LLC v. United States, 159 Fed. Cl. 575, 579, n.4 (2022).
55 HOL007, Palisades Standard Contract at art. V(B); 10 C.F.R. § 961.11 art. V(B).
56 HOL007, Palisades Standard Contract at art. VI(B)(1)(b); 10 C.F.R. § 961.11 art. VI(B)(1)(b).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 and/or HLW; provided, however, that DOE shall, in advance, have the right to approve or disapprove, in its sole discretion, any such exchanges.57 While DOE approval is necessary for intercompany exchanges, there is no reason to believe that DOE would arbitrarily disapprove of any valid exchange request. In fact, in the event of a disapproval, the Standard Contract specifically requires DOE to advise the [utility] in writing of the reasons for such disapproval.58
: 2.      There are multiple removal paradigms available that would allow HDI to transfer all of the Palisadess SNF offsite within the eleven-year window.
According to the Commissions Order, HDIs projected eleven-year window to transfer all SNF off of the Palisadess site must only be plausible. 59 As Frank Graves illustrates in his testimony, there are a number of removal paradigms that show the eleven-year pickup window submitted by HDI in its DCE is plausible. These removal paradigms are outlined and discussed in further detail below.
a.
As explained above, the Standard Contract authorizes the DOE to use shutdown priority as a possibility for the removal of SNF. Article VI(B)(1)(b) provides: Notwithstanding the age of the SNF and/or HLW, 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.60 While the Standard Contract does not define the precise mechanism DOE 57 HOL007, Palisades Standard Contract at art. V(E); 10 C.F.R. § 961.11 art. V(E).
58 Id.
59 Mem. and Order, CLI-22-08, slip op. at 134.
60 HOL007, Palisades Standard Contract at art. VI(B)(1)(b); 10 C.F.R. § 961.11 art. VI(B)(1)(b).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 would use for shutdown priority, a reasonable implementation of shutdown priority would be to allocate program acceptance to plants in the order in which they retired.61 This approach yields the most conservative result for Palisades, ranking it last among plants that are currently shut down.62 In other words, retired plants would receive first priority for the removal of all of their SNF, and the priority would be ordered by shutdown date.63 61 HOL001, Pre-filed Direct Testimony of Frank C. Graves (hereinafter Graves Test.), at 12.
62 Id.
63 Id.
64 HOL001, Graves Test., at 13.
65 Id.
66 Id.
67 Id.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Further, it is reasonable to assume that the DOE removal program will utilize shutdown priority. The DOEs own statements indicate that it may prioritize the removal of SNF from shutdown sites. For example, in its 2012 report to the Secretary of Energy, the Blue Ribbon Commission on Americas Nuclear Future stated that [t]he arguments in favor of consolidated storage are strongest for stranded spent fuel from shutdown plant sites.68 As it explained, fuel at shutdown sites should be first in line for transfer so that shutdown sites can be completely decommissioned and put to other beneficial uses.69 Further, the Blue Ribbon Commission Report recommended that DOE invest early in planning for the transport of SNF from shutdown reactor sites.70 And the direct cost of maintaining shut down reactor sites alone provides a compelling 68 HOL008, Blue Ribbon Commission on Americas Nuclear Future Report to the Secretary of Energy (hereinafter    Blue  Ribbon      Commission      Report)    at    36    (Jan. 2012), available at https://www.energy.gov/sites/default/files/2013/04/f0/brc_finalreport_jan2012.pdf.
69 Id.
70 Id. at xiii.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 reason to move those sites SNF as quickly as possible. 71 As a result, the Blue Ribbon Commission Report ultimately recommended to DOE that spent fuel currently being stored at shutdown reactor sites be first in line for transfer due to the many equity and cost considerations.72 A year later, the DOE endorsed the key principles underpinning the Blue Ribbon Commission Reports recommendations, adopting a consistent approach in response to the recommendation for use of shutdown priority. In its 2013 Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste, the DOE made clear that the DOEs strategy for removal prioritizes the acceptance of fuel from shut-down reactors.73 In fact, the DOE recommended the development of a pilot interim storage facility with a focus on accepting SNF from reactor sites that are shut down because [a]cceptance of used nuclear fuel from shut-down reactors provides a unique opportunity to build and demonstrate the capability to safely transport and store used nuclear fuel.74 Therefore, it is reasonable to assume that the DOE will prioritize removing SNF from shutdown reactors when it begins accepting fuel for disposal under the Standard Contract.
well within the eleven-year window Holtec assumed in its DCE.
71 Id. at 35.
72 Id. at 36.
73 HOL009, Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste                at            2              (Jan.          2013),            available            at https://www.energy.gov/sites/prod/files/Strategy%20for%20the%20Management%20and%20Disposal%20of%20Us ed%20Nuclear%20Fuel%20and%20High%20Level%20Radioactive%20Waste.pdf.
74 See id. at 6.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 b.
Even without shutdown priority, HDI would be able to transfer all of its SNF to the government within the relevant eleven-year window through intracompany rescheduling.
Intracompany rescheduling is the pooling of OFF rights within a fleet of nuclear power plants under the same ownership.75 This process allows a utility owning multiple plants to use its OFF rights for acceptance at any of its plants, regardless of which plant was actually responsible for the discharge that created the OFF rights.76 DOE approval is not necessary.77 The obvious benefit of intracompany rescheduling is that it allows the fleet owner to allocate its pooled OFF rights according to its own preferences and needs. Because this option does not require DOE approval or reliance on any other predetermined order, 75 HOL001, Graves Test., at 14.
76 Id.
77 Northstar Vermont Yankee, LLC v. United States, 159 Fed. Cl. 575, 579, n.4 (2022); HOL007, Palisades Standard Contract at art. V(B); 10 C.F.R. § 961.11 art. V(B).
78 Id.
79 HOL001, Graves Test., at 16.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390
: c.      Intercompany exchanges put Palisades in an even better position than intracompany rescheduling.
As noted above, the Standard Contract specifically contemplates that utilities may exchange their OFF rights with one another, thereby re-ordering their ranking in the acceptance queue. According to the Standard Contract, utilities shall have the right to exchange approved delivery commitment schedules with parties to other contracts with DOE for disposal of SNF and/or HLW; provided, however, that DOE shall, in advance, have the right to approve or disapprove, in its sole discretion, any such exchanges.80 While DOE approval is necessary for intercompany exchanges, there is no reason to believe that DOE would arbitrarily disapprove of any valid exchange request. In fact, in the event of a disapproval, the Standard Contract specifically requires DOE to advise the [utility] in writing of the reasons for such disapproval.81 As Mr. Graves notes in his testimony, exchanges among utilities are completely voluntary, like any other market-based transaction.82 80 HOL007, Palisades Standard Contract at art. V(E); 10 C.F.R. § 961.11 art. V(E).
81 Id.
82 HOL001, Graves Test., at 18.
83 Id.
84 Yankee Atomic Power Co. v. United States, 94 Fed. Cl. 678, 695 (2010), affd in part, revd in part sub nom. Yankee Atomic Elec. Co. v. United States, 679 F.3d 1354 (Fed. Cir. 2012).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390
: 3.      Removal of SNF at a pace faster than the 1987 Acceptance Rate would remove all fuel from Palisades even earlier under all plausible acceptance paradigms.
Given DOEs long delay in beginning acceptance of SNF from civilian nuclear power reactors and the increasing number of shutdown reactors, it is also reasonable to believe that, when DOE performs, it will do so at a faster acceptance rate than the 1987 Acceptance Rate. Doing so would yield SNF removal dates for Palisades that are earlier than any of the other paradigms described above.
85 HOL001, Graves Test., at 18.
86 HOL001, Graves Test., at 19.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 As explained above, the 1987 Acceptance Rate utilizes an overall SNF acceptance rate that ramps up to a rate of 2,650 MTU per year by the seventh year of SNF acceptance, and then increases to a steady-state rate of 3,000 MTU per year in the eleventh year of the program.87 While the DOE has issued multiple other ACRs since 1987, the Federal Circuit has held that because
[t]he 1987 report was the last attempt to comply with the terms of the contract[,] . . . the Standard Contract required DOE to accept SNF/HLW in accordance with the 1987 ACR process. 88 However, nothing in the Standard Contract prevents DOE from accepting SNF on a more accelerated basis, as would be reasonable to expect in light of the DOEs considerable ongoing liability for ongoing distributed site-by-site storage.
As an example, if DOE were to implement a program that picks up SNF at twice the pace of the 1987 Acceptance Rate, HDI would be able to remove all of its SNF at Palisades significantly earlier under each paradigm discussed above.89 87 HOL012, 1987 ACR at 7; HOL011, 1987 Mission Plan Amendment at 61.
88 Pac. Gas & Elec. Co. v. United States, 536 F.3d 1282, 1292 (Fed. Cir. 2008).
89 HOL001, Graves Test., at 20.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 It is plausible to assume that DOE will accept fuel more rapidly than the 1987 Acceptance Rate, given the much later start date for DOE performance and the large backlog of SNF that has accumulated at sites in the meantime, which is incurring significant ongoing costs for which the federal government is liable.90 As Mr. Graves points out in his testimony, the 1987 Acceptance Rate was developed, in large part, based on the needs of the industry at that time.91 In other words, when it was initially developed, the 1987 Acceptance Rate was sufficient to allow most utilities to avoid the need to construct on-site dry storage facilities.92 But faster acceptance rates were also considered at the time. In fact, the Pacific Northwest National Laboratory (PNL) conducted a study finding that even an annual acceptance rate of up to 6,000 MTU economically justifiable.93 Further, early DOE planning documents characterized a program with two repositories operating largely in parallel. 94 A faster-paced program would result in earlier removal of SNF and even lower at-reactor storage costs for Palisades and other commercial nuclear power plants.95 And while a faster pace might increase some direct costs of the program, such as increased infrastructure to support transportation, the program would not need to transfer any more fuel in total (i.e., the repository 90 HOL001, Graves Test., at 9.
91 HOL001, Graves Test., at 6.
92 HOL001, Graves Test., at 7.
93 HOL001, Graves Test., at 9.
94 Id. For example, the original 1985 Mission Plan included plans for a second repository, which would have begun to accept SNF in 2006, eight years after the start of the program, operating in parallel for seventeen years until the first repository is closed following 2022. See HOL010, Mission Plan for the Civilian Radioactive Waste Management Program at 25-26 (June 1985).
95 HOL001, Graves Test., at 20.
26
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 would be the same size, and the total amount of SNF removed would remain the same). 96 Regardless, a faster-paced program could justify higher incremental costs if the savings in at-reactor costs exceeded the incremental program costs.97 Further, DOE would have an incentive to implement a faster-paced program, as it would reduce its own damages payouts in ongoing SNF litigation.98 In other words, just like the 1987 Acceptance Rates were based on the industrys needs, it is reasonable to expect that DOEs acceptance rates in 2030 will also be based on the needs of the industry at the time, which have changed dramatically since 1987.
: 4.        HDIs assumption that the government will accept and remove all SNF from Palisades in an eleven-year pick-up window is reasonable.
HDIs assumed eleven-year window for transferring all of Palisadess SNF to the government is plausible under the variety of removal options available under the Standard Contractshutdown priority, intracompany rescheduling, and intercompany exchanges.
Thus, even under these two methods, HDI can complete transfer easily within the eleven-year window. In addition, it is reasonable to assume that HDI would have pursued intercompany exchanges to improve its SNF removal schedule further (and that DOE would approve these exchanges).
96 HOL001, Graves Test., at 9-10.
97 HOL001, Graves Test., at 10.
98 See HOL008, Blue Ribbon Commission Report at 41 (noting the likely substantial cost savings associated with . . . accelerating the federal governments ability to begin accepting waste in fulfillment of its existing contractual commitments (and thereby avoiding further damage payments to utilities)).
27
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Finally, an acceptance rate faster than the non-breach rate is plausible given the long delay in program start. A faster acceptance rate would result in removal of all of Palisadess SNF even earlier. Therefore, HDIs submission of an eleven-year window for its SNF removal is plausible.
B.      The HDI cost estimate reasonably falls below the NRC formula amount due to differences between the formulas vintage and generic purpose and the HDI estimates basis on contemporaneous project-specific inputs.
The Commission admitted the portions of the Attorney Generals Contention MI-1 asserting that HDIs cost estimate is unreasonable because it falls below the generic formula codified at 10 C.F.R. § 50.75(c). Specifically, the Commission directed Applicants to provide a detailed explanation of the primary reasons that the cost estimate falls significantly below the minimum formula amount, and directed the Parties and NRC staff to address whether the minimum formula regulation in section 50.75(b) applies to this application.99 Applicants address the legal question first. As explained in Section 1 below, 50.75(b) does not require that HDIs estimate of radiological decommissioning costs at Palisades meet or exceed the formula amount.
At most, the formula serves as one of many reference points used by staff to evaluate a licensees cost estimate for decommissioning. The reasons that HDIs estimate falls below the formula are readily explainable and reasonable in light of the differences between the formulas vintage and purpose and HDIs cost estimate based on contemporaneous project-specific inputs.
: 1.      Application of the § 50.75(c) formula neither prescribes nor constrains HDIs DCE.
The Commission directed the Parties and NRC staff to address a threshold legal question:
whether the minimum formula regulation in section 50.75(b) applies to this application.100 In 99 Mem. and Order, CLI-22-08, slip op. at 134.
100 Id. The Attorney General did not raise this argument in its Petition. Id.
28
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 other words, must HDIs cost estimate for § 50.2 decommissioning activities (and corresponding funding allocated to those activities) meet or exceed the regulatory formula amount in § 50.75(c)?
The answer is no. The formula establishes the minimum funding level during operations (one that ENOI met as of shutdown), but it is not a proxy for a site specific cost estimate and neither prescribes nor constrains the cost estimates for decommissioning.
As Regulatory Guide 1.159 explains, there are five (really six) different means of assessing decommissioning costs under NRC regulations: (1) the initial certification required by § 50.33(k)
[based on the formula]; (2a) annual adjustments required by § 50.75(b) [based on the formula];
(2b) the preliminary decommissioning cost estimate required by § 50.75(f)(3) five years before shutdown [not based on the formula]; (3) the cost estimate in the PSDAR submitted under
§ 50.82(a)(4) [not based on the formula]; (4) the site specific cost estimate required by
§ 50.82(a)(8)(iii) within two years following shutdown [not based on the formula]; and (5) the updated site specific cost estimate provided with the license termination plan under § 50.82(a)(9)
[not based on the formula].101 The HDI DCE at issue in this proceeding is #4the site specific cost estimate required by
§ 50.82(a)(8)(iii) (along with #3, referred to herein as § 50.82 SSCE for brevity). 102 It covers the period after permanent shutdown and defueling of the reactor and subsequent transfer of the license from Entergy to Holtec affiliates, at which point the license no longer authorizes 101 Assuring the Availability of Funds for Decommissioning Nuclear Reactors, Reg. Guide 1.159, Rev. 2 (Oct. 2011), at 5-6 (hereinafter Reg. Guide 1.159, Rev. 2) (ADAMS Accession No. ML112160012).
102 Even though submitted alongside the PSDAR, the HDI DCE is the SSCE required by 50.82(a)(8)(iii).
See Standard Review Plan for Decommissioning Cost Estimate for Nuclear Power Reactors (Final Report),
NUREG-1713 (Dec. 2004), at 4 (hereinafter Standard Review Plan for DCE, NUREG-1713) (ADAMS Accession No. ML043510113) (10 CFR 50.82(a)(8)(iii) requires a licensee to provide a site-specific decommissioning cost estimate within 2 years following permanent cessation of operations. This requirement may be satisfied by including a site-specific estimate as part of the PSDAR.).
29
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 operations. 103 As stated in the Application, § 50.82 includes no provision requiring the site-specific cost estimate to equal or exceed the generic formula amount.104 In contrast to a SSCE submitted under § 50.82 after shutdown, the purpose of the minimum formula in § 50.75 is to ensure during operations that licensees have a viable plan to accumulate funds . . . by the projected time of permanent cessation of operations.105 The text of § 50.75(b) itself is clearly limited to the certification that the licensee is collecting adequate funds based on the formula:
Each power reactor applicant for or holder of an operating license . . . shall submit a decommissioning report, as required by § 50.33(k). . . . [T]he report must contain a certification that financial assurance for decommissioning will be (for a license applicant), or has been (for a license holder), provided in an amount which may be more, but not less, than the amount stated in the table in paragraph (c)(1) of this section adjusted using a rate at least equal to that stated in paragraph (c)(2) of this section.106 That certification is not required during decommissioning, and there is no requirement in § 50.75 or elsewhere that a § 50.82 SSCE be more, but not less, than the formula amount.
103 See 10 C.F.R. § 50.82(a)(2); DCE, Table 5-1, at 46, n.1-2 (indicating that the starting fund value assumes
$13.3M in withdrawals by ENOI prior to closing, and the cost estimate only includes post-closing costs). At the time of the license transfer, Entergy had permanently defueled the facility and submitted the certificates required by 50.82(a)(1). Application at 3; Letter from ENOI to US NRC, Certifications of Permanent Cessation of Power Operations and Permanent Removal of Fuel from the Reactor Vessel, dated June 13, 2022 (ADAMS Accession No. ML22164A067).
104 Application at 18-19, n.1.
105 Reg. Guide 1.159, Rev. 2, at 8; See also 1996 Decommissioning Rule at 39,278 (For operating reactors, the amount of decommissioning funding required is generically prescribed in 10 CFR 50.75. Five years before license expiration or cessation of operations, a preliminary decommissioning plan containing a site-specific decommissioning cost estimate must be submitted and the financial assurance mechanism must be appropriately adjusted. (describing the original 1988 rule) (emphasis added)).
106 10 C.F.R. § 50.75(b) & (b)(1) (emphasis added).
30
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Indeed, the § 50.33(k) report referenced in the text of § 50.75(b) was a one-time submission made in 1990 by most operating licensees.107 Following this one-time certification, licensees were required to internally track the annually-escalating formula amount,108 but were not required to submit anything further to the NRC until 1999, when the Commission implemented the now-familiar biennial reports.109 While the text of § 50.75(b) has never been amended to apply the more, but not less, than requirement to any submission other than the § 50.33(k) report, the NRC has applied the annual adjustment requirement in § 50.75(b)(2)110 along with the biennial reporting requirement in § 50.75(f)(1) 111 to require operating licensees to certify, in their routine decommissioning funding reports, that they are accumulating sufficient funds to meet the escalated formula value through the expected shutdown date.112 107 10 C.F.R. § 50.33(k)(2). In fact, when HDIs predecessor, Consumers Power, submitted the 50.33(k) certification in July 1990, Consumers then-approved TLG cost estimate for ratepayer collection purposes was less than the NRC formula, and so Consumers could not make the certification required by 50.75(b)(1) in its initial 1990 filing. See Consumers Power, Certification of Financial Assurance for Decommissioning (July 26, 1990) (ADAMS Accession No. ML18057A356). Rather than seeking an exemption, Consumers commissioned a new TLG study that exceeded the formula and finally made its 50.33(k) certification in 1992 following approval by the Michigan Public Service Commission of the higher estimate. See Consumers Power, Revised Certification of Financial Assurance for Decommissioning (Jan. 10, 1992) (ADAMS Accession No. ML18057B482).
108 Assuring the Availability of Funds for Decommissioning Nuclear Reactors, Reg. Guide 1.159 (Aug.
1990), at 6 (ADAMS Accession No. ML013330279) (certification amounts [based on the formula] are to be adjusted annually based on 10 CFR 50.75(b) and (c)(2) and should be available for NRC inspection, as requested.).
109 10 C.F.R. § 50.75(f)(1); Financial Assurance Requirements for Decommissioning Nuclear Power Reactors, 63 Fed. Reg. 50,462, 50,482 (Sept. 22, 1998).
110 The amount to be provided must be adjusted annually using a rate at least equal to that stated in paragraph (c)(2) of this section. 10 C.F.R. § 50.75(b)(2).
111 Each power reactor licensee shall report . . . at least once every 2 years [] on the status of its decommissioning funding. . . . The information in this report must include, at a minimum, the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c); the amount of decommissioning funds accumulated. 10 C.F.R. § 50.75(f)(1).
112 Many licensees produce site specific cost estimates earlierduring operations and well ahead of shutdown and the NRC requirement to submit a cost estimatefor rate setting purposes or to address costs beyond the 50.2 definition of decommissioning. See Standard Format and Content of Decommissioning Cost Estimates for Nuclear Power Reactors, Reg. Guide 1.202 (Feb. 2005), at 9 (hereinafter Reg. Guide 1.202) (ADAMS Accession No. ML050230008) (If the cost estimate was prepared for the rate regulator, it may contain additional costs that the NRC does not consider part of the radiological decommissioning costs; however, the cost estimate is acceptable 31
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 While the formula was designed to ensure the licensee collected enough for decommissioning, it does not represent the actual cost of decommissioning for specific reactors.113 Rather than serving as a minimum threshold for the eventual cost estimates required to be developed and submitted to the NRC for decommissioning, it is a reference level established to assure that licensees demonstrate adequate financial responsibility that the bulk of the funds necessary for a safe decommissioning are being considered and planned for early in facility life. 114 As originally contemplated, licensees were only required to demonstrate decommissioning financial assurance via a step-wise process: (1) early in life licensees submitted a report certifying that they are collecting funds sufficient to meet the § 50.75(c) formula, and (2) much closer to shutdown, licensees would submit a site-specific cost estimate provided the costs are separated and easily distinguishable.); Standard Review Plan for DCE, NUREG-1713, at 14 (Other related but non-NRC decommissioning costs (spent fuel storage, site restoration, etc.) may be included in the cost estimate if desired; however, the cost of decommissioning, as defined by 10 CFR 50.2, should be listed separately.). In was in response to these voluntary (from the NRCs perspective) cost estimates produced during operations, which were prevalent in the industry when the NRC codified the 50.75(c) formula, that the more, but not less, than requirement in 50.75(b) was created. See Reg. Guide 1.202 at 4 ([A] power reactor licensee may submit a certification based on a site-specific cost estimate, which may be more (but not less) than the amount specified in 10 CFR 50.75(b)(1) when a higher funding level than 10 CFR 50.75(c) is desires. . . . Although this site-specific cost estimate is not the same site-specific cost estimate required by 10 CFR 50.85(a)(8)(iii), it should address many areas identified in Section 3 of this documents; however the level of detail will be less and the level of uncertainty may vary.).
At that time, many utilities had raised concerns that their rate setting authorities would treat the new NRC formula as a funding ceiling, and would not allow the utilities to collect rates based on higher cost estimates used in prudence proceedings or to account for costs beyond 50.2 decommissioning. General Requirements for Decommissioning Nuclear Facilities, 53 Fed. Reg. 24,018, 24,030-31 (June 27, 1988) (hereinafter 1988 Decommissioning Rule). To address their concern, the Commission revised the 50.75(b) language to clarify that the generic formula serves as a funding floor, which is not intended to bind ratemaking bodies and does not prevent site specific cost estimates from being done and amounts greater than the prescribed amount being estimated and used for financial assurance planning as long as the estimate exceeded the prescribed amount. Id. at 24030 (emphasis added).
113 General Requirements for Decommissioning Nuclear Facilities, 53 Fed. Reg. 24,018, 24,030 (June 27, 1988).
114 1988 Decommissioning Rule, 53 Fed. Reg. at 24030 (emphasis added).
32
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 based on relevant, up-to-date information including site specific factors as well as then current information on such issues as disposal of waste, residual radioactivity criteria, etc.115 Consequently, when licensees submit the PSDAR and associated cost estimate required by
§ 50.82(a)(4), they stop reporting to the formula and instead begin reporting against estimated to-go costs from the § 50.82 SSCE.116 There is no regulatory requirement that licensees certify, after submission of the PSDAR and § 50.82(a)(4) cost estimate, that they are collecting funds based on the formula. By that point, the formula has done its job and funding has been accumulated from power sales or ratepayer funding during operations.117 Such was true at Palisades. In the final § 50.75(f)(1) submittal for Palisades, ENOI reported the accumulation of $576 million through year-end 2021, which exceeded the formula requirement.118 To extend § 50.75(b) beyond a prospective funding benchmark and apply it to the decommissioning cost estimation process would defy the clear language of § 50.75(b) and the 115 Id. at 24,030-31.
[T]his estimate would be based on a then current assessment of major factors that could affect decommissioning costs and would include relevant, up-to-date information. These factors could include site specific factors as well as then current information on such issues as disposal of waste, residual radioactivity criteria, etc., and would present a realistic appraisal of the decommissioning of the specific reactor, taking into account actual factors and details specific to the reactor and the time period. Combination of these steps, first establishing a general level of adequate financial responsibility for decommissioning early in life, followed by periodic adjustment, and then evaluation of specific provisions close to the time of decommissioning, will provide reasonable assurance that the Commissions objective is met.
Id.
116 Compare 10 C.F.R. § 50.75(f)(1) to § 50.82(a)(8)(v). See also Staff Findings on the Table of Minimum Amounts Required to Demonstrate Decommissioning Funding Assurance, SECY-13-0066 (June 20, 2013), at 7 (hereinafter Table of Minimum Amounts, SECY-13-0066) (ADAMS Accession No. ML13127A234) (The current regulatory system provides for the cases where the cost estimate exceeds the minimum formula by requiring a SSCE five years before permanent shutdown, or within two years following a premature shutdown. The SSCE then becomes the amount of financial assurance the licensee must certify and provide. (emphasis added)).
117 Section 50.75(e) states that licensees obligation to accumulate prepaid funds is based on the time permanent termination of operations is expected. 10 C.F.R. § 50.75(e)(1)(i).
118 ENOI, Decommissioning Funding Status Report per 10 CFR 50.71(f)(1) and 10 CFR 50.82(a)(8)(v)
(Mar. 28, 2022), Encl. 1 (hereinafter ENOI, DFS Report (2022)) (ADAMS Accession No. ML22087A500).
33
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 mathematical logic of the decommissioning regulationsand would invalidate staffs precedent for granting exemptions authorizing use of decommissioning funds for activities beyond the § 50.2 definition of decommissioning. First, math: § 50.82 allows licensees to spend up to 23% of the formula amount ($115 million, for Palisades)119 before submitting the § 50.82(a)(8) SSCE.120 If § 50.75(b) applied to the § 50.82 SSCE, the allowance to spend nearly a quarter of the formula amount before submitting that SSCE would be illogical and would mean licensees had to accumulate an extra 23% beyond the formula.121 Second, precedent: It is commonplace for NRC to approve exemptions to § 50.82(a)(8)(i)(a) (limiting use of funds to § 50.2 decommissioning) when licensees have accumulated funds sufficient to cover the estimated costs of § 50.2 decommissioning, plus other costs like SNF management and/or site restoration. 122 Not surprisingly, in some cases there was a funding surplus precisely because § 50.2 decommissioning costs were lower than the formula funding threshold.123 To now apply § 50.75(b) beyond its text, to require licensees and NRC staff to use the formula as a threshold for § 50.2 decommissioning 119 ENOIs formula calculation submitted in March 2022 was $503.75 million (and $503.75 x 0.23 =
$115.9). ENOI, DFS Report (2022), Encl. 2.
120 See 10 C.F.R. § 50.82(a)(8)(ii).
121 Reactor Decommissioning Financial Assurance Working Group Final Report (Apr. 29, 2020), at 20-21 (ADAMS Accession No. ML20121A188).
122 See Regulatory Improvements for Decommissioning Power Reactors, 80 Fed. Reg. 72,358, 72,368 (Nov. 18, 2015) (describing that the NRC approve[s] exemptions from the requirements of §§ 50.82 and 50.75 allowing withdrawals to be made from decommissioning trust funds for spent fuel management in instances where the level of funding needed to complete decommissioning is not adversely affected).
123 See, e.g., Pilgrim Nuclear Power Station Exemption, Docket No. 50-293 (Aug. 22, 2019) (ADAMS Accession No. ML19192A086); Indian Point Nuclear Generating Station, Unit Nos. 1, 2, and 3 Exemption, Docket Nos. 50-003, 50-247, and 50-286 (Nov. 23, 2020) (ADAMS Accession No. ML20309A781); Oyster Creek Nuclear Generating Station Exemptions, Docket No. 50-219 (June 20, 2019) (ADAMS Accession No. ML19170A275);
Vermont Yankee Nuclear Power Station-Issuance of Exemption from 10 CFR 50.82(a)(8)(i)(A) (L-2018-LLE-0007) (Oct. 11, 2018) (ADAMS Accession No. ML18274A247); Safety Evaluation by the Office of Nuclear Reactor Regulation Zion Nuclear Power Station, Units 1 and 2, Docket Nos. 50-295 and 50-304, Request for Exemption from 10 CFR 50.82(a)(8)(i)(A) Use of Decommissioning Trust Funds for Management of Spent Fuel (July 21, 2014)
(ADAMS Accession No. ML14030A602).
34
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 costs would invalidate NRCs review and approval of these exemptions in this proceeding and others.
Even accepting arguendo the Commissions suggestion that [t]he regulations themselves leave unclear exactly when the formula ceases to apply,124 it is abundantly clear that an SSCE submitted under § 50.82(a)(8) is not subject to the more, but not less, than requirement of § 50.75(b). Indeed, after the SSCE is submitted, § 50.82(a)(8) requires an estimate of and financial assurance for an estimate of the cost to complete decommissioning,125 which obviously will not remain above the § 50.75(b) formula amount as decommissioning work, including initial planning, is performed. Further, the § 50.75(b) formula amount cannot serve as the basis for the SSCE, because it is not a site-specific value, and because it does not reflect actual, planned work activities that can be tracked to calculate the estimated cost to complete decommissioning. As the Commission has held, [i]n construing a regulations meaning, it is necessary to examine the agencys entire regulatory scheme. 126 Further, a basic tenet of statutory construction, equally applicable to regulatory construction, [is] that a statute should be construed so that effect is given to all its provisions.127 Interpreting § 50.75(b) as continuing to apply after a licensee submits its 124 Mem. and Order, CLI-22-08, slip op. at 42.
125 10 C.F.R. § 50.82(a)(8)(v)(B).
126 Florida Power & Light Co. (Turkey Point Nuclear Generating Units 3 and 4), CLI-20-3, 91 NRC 133, 141 (2020) (citing Northeast Nuclear Energy Co. (Millstone Nuclear Power Station, Unit 3), CLI-01-10, 53 NRC 353, 366 (2001)).
It is a fundamental canon of statutory construction that the words of a statute must be read in their context and with a view to their place in the overall statutory scheme. Davis v. Michigan Dept. of Treasury, 489 U.S. 803, 809 (1989). A court must therefore interpret the statute as a symmetrical and coherent regulatory scheme, Gustafson v. Alloyd Co., 513 U.S. 561, 569 (1995), and fit, if possible, all parts into an harmonious whole, FTC v. Mandel Brothers, Inc., 359 U.S. 385, 389 (1959).
FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120, 133 (2000).
127 Hydro Resources, Inc. (P.O. Box 777 Crownpoint, New Mexico 87313), CLI-06-11, 63 N.R.C. 483, 491 (2006) (quoting Silverman v. Eastrich Multiple Investor Fund, L.P., 51 F.3d 28, 31 (3d Cir. 1995).
35
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 SSCE would conflict with § 50.82(a)(8)(v)(B) and § 50.82(a)(8)(vi), and requiring that such a licensee continue to provide financial assurance based on the § 50.75 formula would render those provisions meaningless.
At the absolute latest, the formula ceases to serve as a regulatory minimum upon transition from § 50.75(f)(1) reporting (against the formula) to § 50.82(a)(8)(v) reporting (against the SSCE).
In fact, in the Reactor Decommissioning Financial Assurance Working Group report cited in the Order, the working group recommended that staff revise its guidance to clarify that the formula ceases to apply even earlierat permanent defueling, when the NRC license no longer authorizes operations.128 Regardless of the precise timing, the Working Groups recommendation is, of course, based on the reality that the NRCs regulations do not require a § 50.82 SSCE to meet or exceed the formula amount. The Standard Review Plan for Decommissioning Cost Estimates (SRP) likewise confirms this understandingonce the § 50.82 SSCE is submitted, the SRP treats the formula as merely a reference point, requiring adequate justification for a cost buildup lower than the formula amount but not an exemption.129 So too does staffs acceptance of other § 50.82 SSCEs that were lower than the § 50.75 formula.130 128 Working Group Report at 21.
129 Standard Review Plan for DCE, NUREG-1713, at 37 (cited at Mem. and Order, CLI-22-08, slip op. at 39). Indeed, the Order itself states that the minimum formula amount remains a benchmark to assess the acceptability of a site-specific decommissioning cost estimate that is submitted [under 50.82] with a PSDAR or within two years of permanent cessation of operations. Mem. and Order, CLI-22-08, slip op. at 39 (emphasis added).
130 See e.g., Pilgrim Nuclear Power Station DECON Site-Specific Decommissioning Cost Estimate (Nov.
16, 2018), attached to Letter from HDI to US NRC, Notification of Revised Post-Shutdown Decommissioning Activities Report and Revised Site-Specific Decommissioning Cost Estimate for Pilgrim Nuclear Power Station, Docket No. 50-293, dated Nov. 16, 2018 (ADAMS Accession No. ML18320A040); Schedule & Financial Information for Decommissioning, Encl. 1, Att. D, attached to Letter from ENOI to US NRC, Application for Order Consenting to Transfers of Control of Licenses and Approving Conforming License Amendments, Indian Point Nuclear Generating Units 1, 2 and 3, Docket Nos. 50-3, 50-247, 50-286 and 72-051, dated Nov. 21, 2019 (ADAMS Accession No. ML19326B953).
36
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Thus, consistent with the explicit language of § 50.75(b), the rulemaking history, and staffs guidance and precedent, the § 50.75(c) formula is not a regulatory minimum for a SSCE submitted under § 50.82 and, at most, merely serves as a reference point in assessing the reasonableness of those cost estimates.
: 2.        There are multiple other reasons that provide adequate justification for HDIs DCE falling below the formula amount.
While the Attorney General did not claim that the § 50.75(c) formula serves as a regulatory threshold, the Petition did challenge HDIs cost estimate as unreasonable because HDIs total number is lower than the formulas number.131 But, as explained above, the formula does not serve as a regulatory minimum that HDIs DCE must meet or exceed. It was meant as an easy way to assure money is on hand for decommissioning but is not and was never meant to be a proxy for a true cost estimate.132 Accordingly, NRC regulations do not require licensees to compare their § 50.82 site-specific cost estimates to the formula amount, or even continue to calculate the formula amount once the PSDAR is submitted.133 And, as the Commission confirmed by rejecting a nearly identical argument comparing HDIs DCE to a prior Palisades cost estimate,134 the pertinent question ultimately is not why HDIs cost estimate is less [than some other estimate] but whether the estimate is reasonable.135 131 Petition at 18-20.
132 1988 Decommissioning Rule, 53 Fed. Reg. at 24030.
133 See 10 C.F.R. § 50.82(a)(8)(v). As the Order states, NRC regulations do not address the content of the power reactor site-specific decommissioning cost estimate. Mem. and Order, CLI-22-08, slip op. at 45.
134 The Attorney General claimed that HDIs DCE is unreasonable because it is lower than a prior TLG study prepared for Palisades. See Petition at 12-14.
135 Mem. and Order, CLI-22-08, slip op. at 24 (emphasis added). With respect to the TLG study, the Commission concluded that the Attorney Generals focus on the two studies different bottom-line cost conclusions does not by itself raise a genuine dispute with the application because (1) HDI had no obligation in the application or the cost estimate to compare its results with the [TLG study], and (2) the Attorney General provides us with no basis to assume that the earlier study, although seventeen years old, reflects a more reliable decommissioning estimate 37
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Nevertheless, NRC staffs standard review plan requires adequate justification when a site-specific cost estimate falls below the § 50.75(c) formula amount.136 Applicants provided an explanation, which NRC staff found adequate in its approval of the Application. 137 The Application explained that the DCE, unlike the generic formula, is based on Palisades-specific cost buildup, taking into account the actual plant conditions and pricing data available at the estimation phase and excluding initial costs incurred by ENOI prior to license transfer.138 The DCE also explained that the Palisades estimate is based on actual contractor quotes and executed agreements for certain key scopes, including the major cost drivers of waste disposal and reactor segmentation.139 This justification is consistent with the Commissions own explanation when it codified the formula.140 It is consistent with NRC staffs understanding that a cost estimate is a more accurate representation of the licensees cost to decommission as compared to the NRC required for today than HDIs current estimate. Id. at 22-23. All of these same points are true of the Petitions comparison of HDIs DCE to the NRC formula, which presents the same bottom-line comparison without any detail. See Petition at 18-20.
136 Standard Review Plan for DCE, NUREG-1713, at 21.
137 Exhibit NRC-001, Safety Evaluation Related to Request for Direct and Indirect Transfers of Control of Facility Operating License DPR-6 for Big Rock Point and Renewed Facility Operating License DPR-20 for Palisades Nuclear Plant and ISFSI, at 11 (The NRC staffs review determined that this justification for the Palisades radiological decommissioning cost estimate being less than the minimum formula amount is adequate.) (hereinafter SER).
138 Application at 18, n.1; see also DCE at 46, Table 5-1, n.1.
139 Application at 18; DCE at 24.
140 Unlike the formula, which does not represent the actual cost of decommissioning for specific reactors but rather is a reference level, the site-specific cost estimate is meant to be based on then current information on such issues as disposal of waste, residual radioactivity criteria, etc., and would present a realistic appraisal of the decommissioning of the specific reactor, taking into account actual factors and details specific to the reactor and the time period. 1988 Decommissioning Rule, 53 Fed. Reg. at 24030.
38
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 minimum. 141 It is consistent with the international nuclear governing bodys guidance that because costs are site-specific, and generalizations or approximations from other facilities are usually inappropriate, . . . [a] reasonable degree of reliability and accuracy can only be achieved by developing decommissioning cost estimates on a case-by-case site-specific basis.142 And it is consistent with HDIs previous explanations provided in response to staffs questions on other cost estimates that were lower than the formula amount.143 As in this proceeding, in those cases, staff found HDIs summary-level justification of the lower cost estimate adequate,144 and has not, to date, required that licensees present a detailed comparison of their site-specific cost estimates to the escalated formula amount or the underlying technical and cost bases used to develop the NRC formula.145 141 Summary of Staff Review and Findings of the 2017 Decommissioning Funding Status Reports from Operating and Decommissioning Power Reactor Licensees, SECY-18-0078 (Aug. 6, 2018), at 3 (hereinafter Staff Review of 2017 DFS Reports, SECY-18-0078) (ADAMS Accession No. ML18096B523).
142 International Atomic Energy Agency, Financial Aspects of Decommissioning (2005) at 3 & 12 (available at https://www.iaea.org/publications/7337/financial-aspects-of-decommissioning).
143 See HDI Response to NRC Request for Additional Information (July 29, 2019), at E-1 to E-5 (ADAMS Accession No. ML19210E470); Letter from ENOI to US NRC, Application for Order Consenting to Transfers of Control of Licenses and Approving Conforming License Amendments Indian Point Nuclear Generating Units 1, 2, and 3, Docket Nos. 50-3, 50-247, 50-286 and 72-051, at 19, dated Nov. 21, 2019 (ADAMS Accession No. ML19326B953).
144 Safety Evaluation of Direct and Indirect Transfer of Renewed Facility Operating License to Holtec Pilgrim, LLC, Owner and Holtec Decommissioning International, LLC, Operator, Docket Nos. 50-293 and 72-1044 (Aug. 22, 2019), at 10-11 (ADAMS Accession No. ML19170A250); NRC-001, SER at 11. See also Standard Review Plan for DCE, NUREG-1713 at 20 (The SSCE submitted to the NRC may summarize the results of the detailed analyses with the underlying detail submitted as supplementary information. The summary data should be sufficiently detailed to demonstrate that the licensee has considered all significant decommissioning costs, and should reference the detailed cost estimate.). NRC staff did not issue an RAI in this proceeding to request any further information to compare HDIs estimate to the formula amount.
145 Nor has NRC issued any guidance for licensees or their own staff to explain how to go about performing such a comparison. In fact, over the years NRC has commissioned PNL to perform comparisons of the formula to actual decommissioning cost estimates and completed projects. See, e.g., Revised Analyses of Decommissioning for the Reference Pressurized Water Reactor Power Station (Final Report), NUREG/CR-5884 (Nov. 1995) (hereinafter Revised Analyses of Decommissioning a PWR, NUREG-5884) (ADAMS Accession No. ML14008A187);
Revised Analyses of Decommissioning for the Reference Boiling Water Reactor Power Station (Final Report),
NUREG/CR-6174 (July 1996) (ADAMS Accession No. ML14008A186); PNL, Assessment of the Adequacy of the 10 CFR 50.75(c) Minimum Decommissioning Fund Formula (Draft Report) (Nov. 2011) (hereinafter PNL, 39
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 The Attorney General did not challenge the adequacy of HDIs explanation or claim that additional detail was required.146 Rather, the Petition simply claimed (incorrectly) that the NRC formula understates actual decommissioning costs and, thus, HDIs estimate must be unreasonable because HDIs total number is lower than the formulas total number.147 Here the Commission directed the Parties to conduct an evidentiary hearing to obtain a more detailed or substantive explanation of the primary reasons that the cost estimate falls significantly below the formula amount.148 A granular or line item comparison between the formula number and the SSCE is not necessary to explain the difference here. The difference between HDIs DCE and the formula amount, which is approximately $30 million 149 when properly compared, is overwhelmingly explained by just one of the factors HDI identified in the DCE:
Adequacy of 10 CFR 50.75(c) (Draft) (2011)) (ADAMS Accession No. ML13063A190). In doing so, PNL has found that performing a detailed comparison between the formula amount and contemporaneous cost estimates is not possible, and only high level observations can be made. Id. at 4-27-28, 4-60-61, 4-70-71.
146 As explained in the Order, [t]o the extent that HDIs cost estimate may be missing details necessary for the Attorney General to meaningfully assess the HDI estimate, it was the Attorney Generals burden to identify any necessary missing information. Mem. and Order, CLI-22-08, slip op. at 24. The Petition also does not cite staffs standard review plan or any of the underlying cost studies used to develop the 50.75(c) formula. Only in its reply brief did the Attorney General claim that HDIs justification for a cost estimate below the formula is hardly a sufficient explanation. Reply in Support of the Michigan Attorney Generals Petition for Leave to Intervene and for a Hearing, Docket Nos. 5000000-155, 50-255, 72-007 and 72-043 (Mar. 29, 2021), at 16 (ADAMS Accession No. ML21088A436).
147 Petition at 20. The Commission has rejected similar arguments in the past. Indian Point, CLI-21-1, 93 NRC at 21-23; Pilgrim, CLI-20-12, 92 NRC at 366-70. NRC has accepted HDI cost estimates below the formula amount in prior proceedings as well. See NRC-001, SER at 11; Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Request for Direct and Indirect Transfers of Control of Renewed Facility Operating License No. DPR-35 and the General License for the Independent Spent Fuel Storage Installation from Entergy Nuclear Generation Company and Entergy Nuclear Operations, Inc. to Holtec Pilgrim, LLC and Holtec Decommissioning International, LLC (Aug. 22, 2019), at 10-11 (hereinafter Indian Point SER) (ADAMS Accession No. ML19235A300).
148 Mem. and Order, CLI-22-08, slip op. at 43.
149 Although the Commissions Order states the difference is $60 million, as discussed below, that was based on mistakenly comparing the DCE in 2020$ to the formula in 2021 dollars. HOL002, Pre-Filed Direct Testimony of Christopher F. Tierney, at 19.
40
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 And given that the balance of HDIs estimate is higher than the rest of the formula amount, 153 the formula comparison ultimately bolsters HDIs estimate given that it remains a benchmark to assess the acceptability of a site-specific decommissioning cost estimate.154 150 HOL003, Pre-Filed Direct Testimony of James B. Buckley, Jr., at 12-13; 151 HOL002, Tierney Test., at 22, Table 7.
152 To the extent that HDIs cost estimate may be missing details necessary for the Attorney General to meaningfully assess the HDI estimate, it was the Attorney Generals burden to identify any necessary missing information. Mem. and Order, CLI-22-08, slip op. at 24.
153 HOL002, Tierney Test., at 22, Table 7.
154 Mem. and Order, CLI-22-08, slip op. at 39.
41
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390
: a.      An understanding of the history and basis for the § 50.75(c) formula is necessary to understand how HDIs real world estimate diverges from the formula amount.
To understand how HDIs real world estimate diverges from the formula amount, we must examine the history and basis for the § 50.75(c) formula. It was created by PNL from a series of studies conducted in the 1970s and 1980s.155 At the time, no commercial large light water reactors had been decommissioned, so PNL began by developing a detailed cost estimate for a representative large commercial reactor.156 PNL chose the Trojan Nuclear Plant (Trojan) as the reference plant for a PWR (like Palisades), based on the assumption that Trojans site conditions and plant configurations were representative of most large, single-unit PWR sites. 157 PNL estimated that Trojan decommissioning would cost $103.5 million (1986 dollars) using the most expensive approacha third-party general contractor performing immediate dismantlement (DECON)plus a 25% contingency.158 For NRCs regulations, PNL rounded this number up to 155 1988 Decommissioning Rule, 53 Fed. Reg. at 24,030; HOL002, Tierney Test., at 10-13; Technology, Safety and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station, (Final Report),
NUREG/CR-0130, Vol. 1 (June 1978) (hereinafter Costs of Decommissioning a PWR, NUREG/CR-0130 (1978))
(ADAMS Accession No. ML19269E988); Technology, Safety, and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station, NUREG/CR-0130, Vol. 2 (June 1978), available at https://doi.org/10.2172/6596923; Technology, Safety and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station, NUREG/CR-0130, Add. 1 (Aug. 1979) (hereinafter Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 1 (1979)) (ADAMS Accession No. ML19208C415); Technology, Safety and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station, NUREG/CR-0130, Add. 2 (July 1983)
(ADAMS Accession No. ML20077J668); Technology, Safety and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station, NUREG/CR-0130, Add. 3 (Sept. 1984) (ADAMS Accession No. ML20093K364); Technology, Safety and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station, NUREG/CR-0130, Add. 4 (July 1988) (hereinafter Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988)) (ADAMS Accession No. ML20151R145).
156 1988 Decommissioning Rule, 53 Fed. Reg. at 24,028-29.
157 Costs of Decommissioning a PWR, NUREG/CR-0130 (1978), at 1-2.
158 Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 2.1. PNLs original cost buildup was in 1978 dollars, which PNL adjusted and escalated in several follow-on reports in the decade between completion of the original study and codification of the formula. See Decommissioning of PWR, NUREG/CR-0130, App. G (1978); Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 2.8. The study upon which the formula was based used present-day technology in 1978, but acknowledged that advances in technology would reduce decommissioning costs. Costs of Decommissioning a PWR, NUREG/CR-0130 (1978), at 2-3. Subsequent 42
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 add conservatism and set $105 million as the high-end of the formula for the largest PWRs like Trojan.159 To develop a generally-applicable formula that could be used for any PWR, PNL evaluated other plants to try to understand the impact of reactor-specific traits on total costs. 160 PNL ultimately assumed that total costs behave solely as a function of reactor component size and, thus, derived the simple linear equation in § 50.75(c)(1)(i) for estimating the costs of decommissioning a PWR based on its capacity: $(72.687+0.0088P), where P is the reactors capacity in thermal megawatts (MWt). 161 Like the high-end estimate codified in § 50.75(c)(1)(i), the capacity-scaling formula reflects the most expensive decommissioning option (DECON with a third-party decommissioning contractor) with a 25% contingency, and PNL rounded up the fixed coefficient for added conservatism, which is why the regulatory formula is $(75+0.0088P).162 studies identified three primary cost drivers, which led to the escalation formula, and the formula was applied in the 1988 addendum to the original study. Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 2.8-3.1. SAFSTOR as a decommissioning method cost less than DECON because the decay of radionuclides leads to less contamination during decommissioning. Costs of Decommissioning a PWR, NUREG/CR-0130 (1978), at 2-12; Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 4.2. Ultimately, the regulatory formula is based on DECON because immediate dismantlement (DECON) is generally the more expensive of the acceptable decommissioning possibilities, [and] if the funds for DECON are available, the other possibilities are also covered.
Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 2.8. Further, the estimated costs calculated in these studies include a 25% contingency, but provide no analytical basis supporting the application of this percentage. Decommissioning of PWR, NUREG/CR-0130 (1978), at 2-10; Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 2.2.
159 10 C.F.R. § 50.75(c)(1)(i); Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 6.2.
160 Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 1 (1979), Section 3.0.
161 Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), Section 6.1.
162 10 C.F.R. § 50.75(c)(1)(i) (emphasis added); Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), Section 6.1-6.2. PNL derived a separate, lower formula for utilities that directly manage decommissioning (as opposed to hiring an independent general contractor): 57.947 + 0.088P. Id. Throughout development of the process, PNL selected the most expensive option to ensure that the formula reasonably bounded all options. Id. at 2.8, 6.2-6.3.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 The resulting formula codified in § 50.75(c)(1)(i) provides a base value in 1986 dollars for any size PWR.163 To escalate the formula to future years, PNL had to derive the § 50.75(c)(2) formula to predict how the various cost categories in the Trojan estimate would escalate year over year. PNL determined that the cost buildup could be predicted by three primary cost drivers: (1) prevailing labor rates, (2) costs of energy (electricity and fuel oil), and (3) LLRW handling and burial charges by waste vendors.164 By reviewing the various categories in the original Trojan buildup and how they correlated to these underlying cost drivers, PNL determined that 64% of the total costs correlated with labor inflation indices, 14% correlated with energy costs, and 22%
correlated with waste burial charges.165 The regulatory formula in § 50.75(c)(2) differs from these percentages (the formula is 0.65L + 0.13E + 0.22B) slightly because PNL averaged the percentage breakdown for PWRs and boiling water reactors (BWRs) to further simplify the regulations. 166 To serve the regulatory function of the formulaan easily codified and administered metric that reasonably bounds decommissioning funding for all reactorsPNL necessarily made assumptions, added conservatism, and simplified the calculations in a way that now belies a line-item comparison back to the original 1978 Trojan cost buildup, which itself evaluated many alternatives that were not ultimately used to create the formula.167 Indeed, in its 2011 re-evaluation 163 10 C.F.R. § 50.75(c). PNL originally estimated Trojans costs in 1978 dollars but updated the costs to 1986 dollars to inform the NRCs 1988 rulemaking. That effort informed the 50.75(c)(2) escalation formula. Costs of Decommissioning a PWR, NUREG/CR-0130 (1978), at G-39; Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 1.1.
164 Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), Section 6.2.
165 Id. at 6.4. Of the 14% energy factor, 58% escalates with electric power and 42% with fuel oil. Reg. Guide 1.159, Rev. 2, at 9-10.
166 Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 6.4-6.5.
167 Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 6.2-6.3 (Since immediate dismantlement (DECON) is generally the more expensive of the acceptable decommissioning possibilities, if funds for DECON are available, the other possibilities are also covered.).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 report, PNL found that a detailed comparison of the actual [Trojan] decommissioning cost to the minimum decommissioning fund [formula] is not possible, and PNL could only make high level comparisons.168 Moreover, the formula was based on industry experience at the time, which was limited to the decommissioning of research and development-size reactors, not the large base-load power generation plants in use today.169 Likewise, the formula reflected the industrys understanding of decommissioning technology and processes in the 1970s.170 As PNL and other industry groups have detailed, the industry has developed a number of improvements since the 1970s, including bulk removal of irradiated components, improvements to primary system decontamination and removal of large components, and improved contracting practices.171 All of these factors have led the Commission to re-evaluate the accuracy of the formula over the years.172 NRC has commissioned PNL to perform detailed re-evaluations of the formula twice nowonce in the mid-1990s and again in 2009.173 Both times, PNL found that changes in nuclear industry practices, technology, regulatory landscape, and waste disposal options cumulatively resulted in significant differences between contemporaneous cost estimates and the 168 PNL, Adequacy of 10 CFR 50.75(c) (Draft) (2011), at 4-87.
169 Id. at 1-2.
170 Revised Analyses of Decommissioning a PWR, NUREG/CR-5884, at 1.1 (While the cost estimates from the PWR reports were escalated to 1986 dollars in subsequent addenda reports, the technical and regulatory bases for the analyses remained as developed in the original studies. (citations omitted)).
171 PNL, Adequacy of 10 CFR 50.75(c) (Draft) (2011), Section 2.4.
172 Revised Analyses of Decommissioning a PWR, NUREG/CR-5884, Vol. 1; Table of Minimum Amounts, SECY-13-0066; PNL, Adequacy of 10 CFR 50.75(c) (Draft) (2011).
173 See Revised Analyses of Decommissioning a PWR, NUREG/CR-5884; PNL, Revised Analyses of Decommissioning for the Reference Boiling Water Reactor Power Station (Final Report), NUREG/CR-6174, Vol. 1 (July 1996); PNL, Adequacy of 10 CFR 50.75(c) (Draft) (2011).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 1970s studies.174 Despite these findings and competing policy directives to change § 50.75(c) over the years, the Commission has thus far declined to amend the formula, on the basis that the regulation continues to serve its intended function: to provide a common minimum standard measurement, or reference level, for reasonable assurance of decommissioning funding, 175 even if the original analytical basis, which is not codified in NRC regulations or guidance, has aged.
The upshot from all of this is that NRC has developed a well-documented history of the changes to the nuclear industry that call into question the ongoing relevance of the formula itself and the 1970s cost estimate used to develop it. The Commission has nevertheless decided, to date, to retain the formula for policy reasons because it continues to serve its original purpose of 174 Revised Analyses of Decommissioning a PWR, NUREG/CR-5884, at xiv-xx; PNL, Adequacy of 10 CFR 50.75(c) (Draft) (2011), at 5-23 to 5-33.
175 Table of Minimum Amounts, SECY-13-0066, at 6. While this is the latest staff position on the issue, it bears noting that the agency has cycled considerable resources on this issue over the years, despite never taking any action to change the formula. See Rulemaking Plan for Amending Nuclear Power Reactor Decommissioning Financial Assurance Implementation Requirements, SECY-95-223 (Sep. 1, 1995), at 1 (ADAMS Accession No. ML20211M681) (recommending amendments to 50.75 because [r]ecent studies have shown that the present decommissioning cost requirements are outdated and not based on the most recent technology); Staff Requirements
- COMSECY-97-014 - Decommissioning Cost Requirements for Nuclear Power Reactors, COMSECY-97-251 (Jun.
30, 1997), at 1 (ADAMS Accession No. ML20141G451) (directing staff to expeditiously develop such a rule);
Proposed Rule on Nuclear Power Decommissioning Costs, SECY-97-251 (Oct. 24, 1997), at 1, (available at https://www.nrc.gov/reading-rm/doc-collections/commission/secys/1997/secy1997-251/1997-251scy.pdf)
(proposing amendments to 50.75 in light of PNLs studies that show the formula may not be representative of the current technology and site-specific data); Staff Requirements: SECY-97-251 - Proposed Rule on Nuclear Power Reactor Decommissioning Costs, SECY-97-251 (Feb. 5, 1998), at 1 (ADAMS Accession No. ML003752212)
(rejecting staffs proposed rule because the Commission is not convinced that recent generic estimates are accurate or supportable); Staff Requirements - SECY-06-0065 - Office of the Inspector General Recommendations on Decommissioning Funding Assurance, SECY-06-0065, at 1 (May 17, 2006) (ADAMS Accession No. ML061370418) (directing staff to review the formula used for decommissioning funding requirements and adjust it, if necessary). Notably, two of the current Commissioners recently directed staff again to study and revise the formula, to ensure it is more reflective of current cost considerations, because [r]eliance on the current minimum decommissioning formula, which has not been updated for 35 years, erodes public confidence in the NRC. Chairman Hanson, Notation Vote: SECY-18-0055, at PDF p.6 (Aug. 10, 2021) (ADAMS Accession No. ML21229A254). See also Commissioner Baran, Notation Vote: SECY-18-0055, at 12-13 (Aug. 9, 2021) (ADAMS Accession No. ML21230A313). Accordingly in the recent decommissioning proposed rule published in March 2022, NRC sough comments on whether to revise the 30-year old formula. Proposed Rule, Regulatory Improvements for Production and Utilization Facilities Transitioning to Decommissioning, 87 Fed. Reg. 12,254, 12,303 (Mar. 3, 2022).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 providing a rough, easily-administered metric to establish a predictable funding target for operating plants. The following sections illustrate how advancements in technology, differing industry business models, and actual decommissioning experience since the original 1970s PNL estimates used to derive the formula explain why HDIs SSCE is reasonable, despite falling below the formula.
: b. When properly compared, the difference between the formula and HDIs DCE is about $30 million in 2020 dollars.
Calculating the § 50.75(c) formula for Palisades is a simple exercise in algebra. First, costs are calculated in 1986 dollars in accordance with the following equation:
176 Palisadess thermal capacity is 2,565 MWt; therefore, the calculation of base costs for Palisades is $97.572  (in 1986 dollars). 177 Second, this base value is escalated to present-day dollars using the equation in § 50.75(c)(2):
178 176 10 C.F.R. § 50.75(c)(1)(i).
177 ENOI, Decommissioning Funding Status Report per 10 CFR 50.75(f)(1) and 10 CFR 50.82(a)(8)(v)
(Mar. 25, 2021) (hereinafter ENOI YE 2021 DFS Report) (ADAMS Accession No. ML21084A811).
178 Reg. Guide 1.159, Rev. 2, at 9-10.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Each of these factors are provided in ENOIs year-end 2021 report (the final § 50.75(f)(1) report required for Palisades and the report the Commission relied on in admitting this issue for hearing). They are L = 3.03, E = 2.93, and B = 12.793.179 Thus, the escalated value for Palisades is $503.749 million in 2021 dollars.180 Given the intentional simplicity of the formula, there is no detailed cost breakdown that can be derived from the single-number output. 181 NRC has not published any guidance for licensees or its own staff to conduct such comparisons. And while a bottom-line comparison between the formula amount and HDIs estimate is not particularly useful in evaluating the reasonableness of HDIs estimate, we still must ensure that we are comparing apples to apples.
Thus, it is important to define what is, and what is not, included in HDIs SSCE and the formula, respectively.
Initially, it is important to establish which formula calculation to use. Prior to the license transfer, ENOI annually calculated and submitted the formula amount in its § 50.75(f)(1) decommissioning funding reports. When HDI submitted the DCE in December 2020, the then-current ENOI report calculated the formula amount at $484.7 million (in 2019 dollars).182 In the 179 ENOI YE 2021 DFS Report, Encl. 2; U.S. Department of Labor, Bureau of Labor Statistics, Employment Cost Index, data for Series ID CIU2010000000230I, and CIU2010000000240I obtained from http://www.bls.gov/data; U.S. Department of Labor, Bureau of Labor Statistics, Producer Price Index - Commodities, data for Series IDs WPU0543 and WPU0573 obtained from http://www.bls.gov/data; Report on Waste Burial Charges (Final Report), NUREG-1307, Rev. 18, Table 2-1 (Jan. 2021) (hereinafter NUREG-1307, Rev. 18)
(ADAMS Accession No. ML21027A302) (value for a PWR in unaffiliated states).
180 As explained below, for meaningful comparison to HDIs DCE, the formula must be stated in 2020 dollars. ENOIs year-end 2020 report provides the escalation factors for the 2020 calculation (L = 3.03, E = 2.93, B =
12.793) for an escalated value of 486.7 million (in 2020 dollars). ENOI YE 2021 DFS Report, Encl. 2.
181 HOL002 Tierney Test., at 20. The formula does not represent the actual cost of decommissioning for specific reactors but rather is a reference level that governs licensee funding during operations. 1988 Decommissioning Rule, 53 Fed. Reg. at 24030.
182 ENOI, Decommissioning Funding Status Report, Docket Nos. 50-155, 50-3, 50-247, 50-286, 50-255, Encl. 5 (Mar. 26, 2020) (ADAMS Accession No. ML21084A811).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 18 months between submission of the DCE and the Commissions issuance of the Order, ENOI filed two more reports with an escalated formula value of $486.7 million (in 2020 dollars) and
$503.75 million (in 2021 dollars).183 ENOIs selection of the § 50.75(c)(2) formula adjustment factors and mathematical calculations based on those factors are not in controversy in this proceeding.
In its Order, the Commission compared this latest formula calculation from ENOIin 2021 dollarsto HDIs post-transfer estimate of license termination costsin 2020 dollarsthus arriving at a $60 million delta.184 This math requires some refinement.
First, Applicants agree that Palisadess total license termination costs (i.e., not SNF management and site restoration) are the appropriate category to compare to the formula amount.
The footnote to § 50.75(c) makes clear that the formula covers § 50.2 decommissioning costs and does not cover SNF management or site restoration costs. As explained in the DCE, costs categorized as license termination costs in DCE Table 5-1 are HDIs estimated costs of performing all remaining § 50.2 decommissioning activities following the license transfer.185 That number is $443.2 million, in 2020 dollars. As HDI explained in the Application and Table 5-1, that amount does not include an estimated $13.3 million for initial activities that ENOI funded prior to license transfer.186 Because the intent is to compare the total (not just remaining) estimated 183 ENOI YE 2021 DFS Report; ENOI, Decommissioning Fund Status Report per 10 CFR 50.71(f)(1) and 10 CFR 50.85(a)(8)(v) (Mar. 28, 2022) (hereinafter ENOI YE 2022 DFS Report) (ADAMS Accession No. ML22087A500). As the second revision of Reg. Guide 1.159 explains, the formula does not provide for estimates of future inflation but only of inflation that has already occurred, licensees should recalculate the certification amount each year using the previous years data, as described in 10 CFR 50.75(c)(2). Reg. Guide 1.159, Rev. 2, at 10.
184 Mem. and Order, CLI-22-08, slip op. at 40, n.142.
185 DCE at 18.
186 Application at 18, n.1; DCE at Table 5-1, n.1.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390
§ 50.2 decommissioning costs for Palisades to the NRC regulations projection of total § 50.2 decommissioning costs, both pre- and post-transfer costs should be included. Thus, HDIs total projected § 50.2 decommissioning costs are $456.5 million ($443.215 million + $13.3 million), in 2020 dollars.187 Second, of course, both sides of the comparison need to be in the same years dollars.188 So either HDIs estimate must be escalated into 2021 dollars to match the last ENOI filing the Commission relied on in the Order or the formula in 2020 dollars should be used. NRC regulations and guidance prescribe a specific method for escalating the formula, which ENOI already calculated to be $486.7 million (in 2020 dollars). 189 On the other hand, NRC regulations and guidance do not prescribe a particular method for escalating a site-specific cost estimate,190 and as PNL has explained, [c]onverting the reported decommissioning costs to current-year dollars is inherently difficult because not all cost categories will escalate at the same annual rates and even similar cost categories can escalate at different annual rates depending on factors such as the location of the plant and LLW treatment and disposal assumptions.191 Accordingly, escalating HDIs estimate into 2021 dollars would add subjective issues that would have to be resolved in this hearingwithout any relevance to the only question that actually matters in this proceeding:
187 HOL002 Tierney Test., at 18-19.
188 Id. at 17; 1988 Decommissioning Rule, 53 Fed. Reg. at 24,029 ([I]n any comparison of costs it is necessary to place the costs in the same years dollars in order to have a meaningful basis for comparison.).
189 ENOI YE 2020 DFS Report, Encl. 6.
190 HOL002 Tierney Test., at 17; see Reg. Guide 1.159, Rev. 2, Regulatory Position 1.4 (describing the optionality licensees have when adjusting their cost estimates to reflect inflation and technology changes or changes in plant status).
191 PNL, Adequacy of 10 CFR 50.75(c) (Draft) (2011), at 5-13.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 whether HDIs estimate is reasonable.192 Thus, the suitable comparison for present purposes is HDIs estimate of $456.5 million (in 2020 dollars) to ENOIs year-end 2020 calculation of the formula of $486.7 million (in 2020 dollars). 193 When properly compared, the difference between the formula and HDIs estimate is about
$30 million in 2020 dollars. HDIs estimate relative to the formula is consistent with, and in fact closer to the formula than, the gap between the formula and actual decommissioning costs at Trojan, which were $42 million lower (in 2010 dollars).194 Likewise, this difference is consistent with (and again closer to the formula than) prior estimates that have been accepted by NRC. For example, staff reviewed and approved a cost estimate that was $52 million lower than the formula for Indian Point 2 and an estimate that was $41 million lower than the formula for Pilgrim.195 Both of these estimates were submitted in the same context as the present DCEas part of a license transfer application that required review of financial qualifications by NRC staff and ruling on contentions by the Commission. While Applicants do not believe that comparisons between the total formula output and a site-specific cost estimate provides much, if any, insight into the reasonableness of the cost estimate, it is noteworthy that the Palisades DCE is not outside the norm of NRC-accepted estimates and completed decommissioning projects.
192 HOL002 Tierney Test., at 17.
193 HOL002 Tierney Test., at 19.
194 PNL, Adequacy of 20 CFR 50.75(c) (Draft) (2011), at Table 4.31.
195 Indian Point SER, at 19; Letter from Holtec to US NRC, Response to NRC Request for Additional Information, dated July 29, 2019 (ADAMS Accession No. ML19210E470).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Before moving on to explain the $30 million difference, Applicants briefly address the Attorney Generals argument from the Petition that only a subset of HDIs costs should be compared to the formula. The Petition asserts that the DCEs post-transfer radiological decommissioning costs of $443.2 million (in 2020 dollars) should be reduced by up to $86 million in dormancy costs and ISFSI demolition costs before comparison to the formula.196 The only explanation offered for why HDIs estimate should be reduced by this amount is the suggestion that these categories do not represent license termination activities.197 That is simply wrong.
Dormancy costs incurred between shutdown and active dismantlement are clearly within the § 50.2 definition of decommissioning, as are ISFSI radiological decommissioning costs and the pre-transfer planning costs that the Attorney General ignored.198 The Attorney General has offered no regulatory basis for parsing HDIs § 50.2 decommissioning costs to only compare some of them to the formula amount that, according to the regulation itself, is meant to account for activities related to the definition of Decommission in § 50.2.199
: c.      The $30 million difference between HDIs DCE and the formula is readily explained by a number of factors.
196 Capik Declaration at 8, n.23. While the Attorney Generals logic in reducing HDIs estimate is fundamentally flawed, Applicants also note that the Attorney General did not explain its math in reaching the conclusion that Holtecs license termination costs could be as small as $387.3 million. Petition at 19, n.54.
197 Petition at 19.
198 NUREG-0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities, Section 2.4.3 (Aug. 1988) (ADAMS Accession No. ML023470304).
199 10 C.F.R. § 50.75(c), n.1.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 i.
53
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 54
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 55
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 56
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 57
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 ii.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 iii.
The PNL estimates used to develop the formula included a 25% contingency factor across the boardabout $97 million in 2020 dollars. 228 That generic contingency factor was judged to be a reasonable cushion given the fact that the original cost buildup was completed in 1978 before any large light water reactors had been decommissioned and decades before most commercial reactors would begin the process. Even in 1995 when PNL reevaluated the formula, it decided the original 25% factor remained appropriate in light of the state of knowledge available 228 HOL002, Tierney Test., at 33.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 for a decommissioning project that is to take place 20 to 30 years in the future.229 But the inverse is true as well. As work scope, techniques, technology, and costs are better understood, contingency appropriately shrinks. Indeed, PNL noted that contingency amounts as low as 5%
would be expected for a project with sufficiently low uncertainty.230 While the Commission has separately directed HDI to provide additional evidence regarding development of its contingency factor, which is addressed in detail in section 2 below, for purposes of comparison to the formula, any analysis of project-specific risk and uncertainty provides a more robust analytical foundation for Palisadess contingency than the 25% buffer applied decades ago to a generic estimate. That formula amount was meant to serve as a baseline to capture plants with innumerable variations that cannot be accounted for in a generic estimate meant to bound them all. Even if HDIs contingency estimate is on the low end of industry experience, it is not outside the norm, as discussed in section 2, and it is certainly a more representative estimate of the risks and uncertainty at Palisades than the original 25% buffer added to PNLs original buildup as a conservatism in light of the vastly greater uncertainty applicable to that estimate.233 229 Revised Analyses of Decommissioning a PWR, NUREG/CR-5884, Vol. 2, Appendix B at p. B.37; HOL002, Tierney Test., at 33-34.
230 Revised Analyses of Decommissioning a PWR, NUREG/CR-5884, Vol. 2, Appendix B at p. B.37.
233 HOL002, Tierney Test., at 33-34 60
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 iv.      HDIs business model accounts for $28 Million of the difference.
As explained above, the formula is based on the most expensive means of performing decommissioning, as PNL determined in its original studies. That approach involves a utility (not experienced in decommissioning) hiring a third-party general contractor to manage decommissioning, which comes with added overhead and commercial costs of approximately
$28.4 million (in 2020 dollars).234 PNL did not consider the asset-transfer business model that has recently emergedwhere specialized vendors with expertise in key decommissioning workstreams and considerably lower overheads than vertically integrated utilities purchase a shutdown plant and NDT to self-perform decommissioning.235 Of course, even if that approach had existed, PNLs objective in selecting the utility plus contractor option was to pick the most expensive decommissioning approach to bound the other options.236 Similarly, PNL expected that the efficiency of decommissioning the reactors at a multiple-reactor station will improve after the first reactor is decommissioned due to the learning process. 237 But the studies did not contemplate the substantial benefit gained by one entity decommissioning multiple nuclear power plants and neither the original NRC generic formula, nor any subsequent studies, ever quantified the cost-reduction possible by a company, like Holtec, acquiring shutdown nuclear power plants and specializing in nuclear decommissioning.238 That 234 HOL002, Tierney Test., at 36.
235 Id.
236 Costs of Decommissioning a PWR, NUREG/CR-0130, Add. 4 (1988), at 2.8.
237 Technology, Safety and Costs of Decommissioning Nuclear Reactors at Multiple-Reactor Stations, NUREG/CR-1755 (Jan. 1982) at 8-19 (ADAMS Accession No. ML20086J438); HOL002, Tierney Test., at 14.
238 HOL002, Tierney Test., at 14.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 business model has provided HDI an invaluable learning curve in decommissioning projects, including estimating its actual costs.239 In short, none of the third-party costs assumed in the original formula are incurred under HDIs business model. Thus, the full $28.4 million of the general contractor costs embedded in the formula are altogether avoided in HDIs estimate.
: v.        Additional qualitative factors lend further credibility to HDIs estimate.
While it is not necessary to quantify all the differences between HDIs estimate and the formulas assumptions and technical bases, Mr. Tierneys testimony briefly summarizes additional factors, many of which PNL has documented in its reassessments of the formula, that further explain the information gap between a generic estimate with roots in the 1970s and a present-day site-specific cost estimate based on real-world experience and negotiations. 240 Those factors include improvements in decommissioning methods, more efficient tools than understood in the 1970s, use of concrete scabbing, chemical decontamination, and net fund growth during the dormancy period.241
: 3. HDIs estimate is reasonable, despite being $30 million lower than the formula.
As explained, the formula is a reference level for the amount of funding to plan for during operations. It is not a regulatory minimum that governs site specific cost estimates for decommissioning.
239 Id.; HOL004, Goulette Test., at 16-17.
240 HOL002, Tierney Test., at 38-39.
241 Id.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Thus, while HDIs total radiological decommissioning estimate is lower than the formula when compared in the aggregate, once the components of both are examined and compared, the formula ultimately bolsters the reasonableness of HDIs cost estimate.
C.      The Palisades DCE contingency amount is reasonable and accounts for the types of historically inevitable costs the Commission determined should be addressed by contingency at this stage of the project.
The third issue the Commission admitted for hearing relates to Holtecs contingency funding. The DCE includes a 12% contingency, which HDI assessed [b]ased on an evaluation of estimate uncertainty and discrete risk events, combined with experience gained through decommissioning efforts at Oyster Creek and Pilgrim, newly formed waste contracts, and contingency allowances used for other decommissioning projects. 242 The Attorney Generals Petition challenged 12% as too low, asserting that [n]o evidence was provided to support this
[contingency amount], and this level of contingency is not consistent with industry norms because the percentage is lower than other decommissioning projects, including other Holtec-owned sites. 243 While the Commission credited the Attorney Generals observation that Palisades contingency is lower than other projects, the Order clarified that the precise question . . .
242 DCE at 41.
243 Petition at 21.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 ultimately is not whether HDIs contingency allowance for Palisades is relatively lower than those of other analyses; rather, [t]he material issue is whether the 12% contingency level is unreasonably low or inadequate for Palisades project and could jeopardize the overall available funding for decommissioning and spent fuel management.244 The Commission thus directed Applicants to explain how they calculated and derived the 12% level applied for contingency and concluded that this amount for contingency is reasonably adequate for Palisades.245 While NRC has not published guidance for contingency calculations, the Commission explained in the Order that HDIs DCE must account for unforeseeable events that are almost certain to occur in decommissioning, but need not address potential but highly uncertain events or circumstances that may occur and increase costs.246 244 Mem. and Order, CLI-22-08, slip op. at 48.
245 Id. at 48-50 & 134.
246 Id. at 49-50, n.175.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Moreover, contingency is not the only means of addressing unforeseen costs in the DCE.
The DCE includes many conservatisms and additional sources of funding that serve the same function as contingencyto minimize the risk of a funding shortfall and to mitigate the severity of any potential funding shortfall.247 Regardless, the DCE accounts for the types of historically inevitable costs the Commission determined should be addressed by contingency at this stage of the project.
: 1.      Other than high-level requirements in staff guidance, there are no NRC guidelines for the methodology licensees should use to establish contingency, nor does the NRC impose a minimum amount of contingency that must be included in a § 50.82 cost estimate.
As the Order states, NRC regulations do not address the content of the power reactor site-specific decommissioning cost estimate. 248 However, NRC guidance requires that licensees include contingency as an allowance for unexpected costs, 249 and a brief discussion of contingency costs and the methods used to calculate them. 250 Like other elements of a site-specific cost estimate, a summary-level description of the contingency analysis is adequate for the NRC submittal.251 In fact, the Commission has rejected previous challenges to HDIs contingency 247 Mem. and Order, CLI-22-08, slip op. at 50.
248 Id. at 45.
249 Reg. Guide 1.159, Rev. 2, at 11.
250 See Reg. Guide 1.202 at 15 (ADAMS Accession No. ML050230008). The standard review plan likewise requires that licensees include [a] description of how the contingency costs are calculated. Standard Review Plan for DCE, NUREG-1713, at 27.
251 Standard Review Plan for DCE, NUREG-1713, at 20; Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generation Station, Units 1,2, and 3 and ISFSI), CLI-21-01, 92 N.R.C. 1, 23.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 amount on other projects, including arguments that HDIs summary-level explanation was insufficient.252 Beyond these high-level requirements in staff guidance, there are no NRC guidelines for the methodology licensees should use to establish contingency nor does the NRC impose a minimum amount of contingency that must be included in a § 50.82 SSCE.253 It bears noting that the Part 72 regulations applicable to ISFSI decommissioning require an adequate contingency factor,254 which NRC guidance has interpreted to mean 25%, unless the licensee justifies a lower amount.255 However, 25% is simply a number that the NRC has historically considered to be a reasonably adequate buffer for general application. NRC guidance does not provide a mathematic or methodological explanation for how it arrived at 25% as a reasonable numberother than the fact that it has been used for a long time.256 As noted above, the same 25% factor was used in development of the § 50.75(c) generic formula. Neither PNL nor NRC provided any analytical support for the 25% contingency in the published materials used to derive the NRC formula, but PNL later discussed this contingency level in the mid-1990s when NRC asked it to re-evaluate the formula. As explained in NUREG/CR-5884, contingency is a function of the degree of knowledge about the project, and 252 Entergy Nuclear Operations, Inc. (Pilgrim Nuclear Power Station), CLI-20-12, 92 N.R.C. 351, 369; Indian Point, CLI-21-01, 93 N.R.C. at 21-23.
253 Pilgrim, CLI-20-12, 92 N.R.C. at 360 (The NRC does not have a minimum contingency requirement for the site-specific estimate.).
254 10 C.F.R. § 72.30(b)(2).
255 Consolidated Decommissioning Guidance (Final Report), NUREG-1757, Vol. 3, Rev. 1 at A-25 (Feb.
2012) (hereinafter NUREG-1757, Vol. 3, Rev. 1) (ADAMS Accession No. ML12048A683). HDI applied 25%
contingency to the ISFSI decommissioning estimate. DCE at 41. That portion of the DCE is not at issue in this hearing.
256 See, e.g., NUREG-1757, Vol. 3, Rev. 1 at A-25 (citing Revised Analyses of Decommissioning Reference Non-Fuel-Cycle Facilities (Final Report), NUREG/CR-6477 (Dec. 2002) (ADAMS Accession No. ML030160573)
(applying a 25% contingency but providing no explanation of adequacy of this percentage)).
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[b]ecause of the varying circumstances that make a contingency necessary, a single standard rate is not appropriate for all situations.257 PNL explained further that contingency typically addresses Unforeseeable Elements of Cost such as: unexpected minor changes in scope[,] allowance for uncertainties in estimating methods[,] allowance for untried process[,] and unexpected job conditions.258 In light of the multitude of factors that can influence contingency, PNL found that contingency as high as 100% and as low as 5% could be reasonable, depending on the amount of planning and experience with execution techniques.259 Ultimately, PNL decided that continued use of the 25% factor was reasonable based on the state of knowledge available for a decommissioning project that is to take place 20 to 30 years in the future.260 Thus, apart from some high-level principles, NRCs use of a generic 25% factor does not provide guidance for how licensees should calculate contingency in a contemporaneous cost estimate based on real-time, site-specific information.
In fact, as Mr. Tierney explains in his testimony, by applying PNLs logic, it is expected that site-specific estimates prepared closer to decommissioning will have a higher degree of certainty and, thus, lower contingency. That much is demonstrated by the range of contingency factors in cost estimates accepted by NRC on other projects, as discussed in the Order and as 257 NUREG/CR-5884, Vol. 2 at B.35 and B.37 (Nov. 30, 1995) (ADAMS Accession No. ML14008A187).
258 Id. at B.37.
259 Id.
260 Id. This was still just a judgment call. PNLs justification was simply that 25% is considered by professionals in the field to be reasonable and realistic value for use in developing estimates of the possible financial exposure that will result from decommissioning. Id.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 summarized in Table 14 of Mr. Tierneys testimony, which have ranged from 12.9% to 18.2%.261 The cost estimates HDI submitted for other Holtec-owned plants were 15% for Oyster Creek, 17%
for Pilgrim, and 18% for Indian Point.262 HDI used the same methodology as those projects to establish the Palisades contingency amount at 12%. NRC staff has accepted HDIs contingency methodology in four DCEs, including after issuing an RAI on the Indian Point contingency calculation, in response to which HDI provided additional detail on its methodology263much of which is repeated in the testimony of Mr. Goulette.
As described in the DCE, HDIs methodology evaluates two types of unknowns: estimate uncertainty and discrete risk events. The DCE described these factors at a high level as follows:
Estimate Uncertainty Uncertainty in estimates is generally a function of the level of maturity in the project definition. Estimate uncertainty is also a function of various factors including:
Expected site conditions (physical and radiological)
Decommissioning processes and tools New and/or non-familiar technology 261 Mem. and Order, CLI-22-08, slip op. at 44-45; HOL002, Tierney Test, at 37.
262 Revised Post-Shutdown Decommissioning Activities Report and Revised Site-Specific Decommissioning Cost Estimate for Pilgrim Nuclear Power Station, Docket Nos. 50-219 and 72-15 (Sept. 28, 2018), at 43-46 (ADAMS Accession No. ML18275A116), attached to Letter from Holtec to US NRC, Notification of Revised Post-Shutdown Decommissioning Activities Report and Revised Site-Specific Decommissioning Cost Estimate for Oyster Creek Nuclear Generating Station, Docket Nos. 50-219 and 72-15, dated Sept. 28, 2018, (ADAMS Accession No. ML18275A116); Revised Post-Shutdown Decommissioning Activities Report and Revised Site-Specific Decommissioning Cost Estimate for Pilgrim Nuclear Power Station, Docket Nos. 50-293 and 72-1044 (Nov. 16, 2018), at 39-41 (ADAMS Accession No. ML18320A040), attached to letter from Holtec to US NRC, Notification of Revised Post-Shutdown Decommissioning Activities Report and Revise Site-Specific Decommissioning Cost Estimate for Pilgrim Nuclear Power Station, Docket Nos. 50-293 and 72-1044, dated Nov. 16, 2018, (ADAMS Accession No. ML18320A040); Post Shutdown Decommissioning Activities Report including Site-Specific Decommissioning Cost Estimate for Indian Point Nuclear Generating Units 1, 2, and 3, Docket Nos. 50-3, 50-247, 50-286 and 72-051 (Dec. 19, 2019), at 93-95 (ADAMS Accession No. 19354A698).
263 Letter from Holtec to US NRC, Response to NRC Request for Additional Information, dated Aug. 7, 2020 (hereinafter Indian Point Response to NRC RAI) (ADAMS Accession No. ML20220A666).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Complexity Labor skills and productivity Stakeholder/regulatory requirements Quality of cost estimating assumptions and data Experience and skill level of the estimator Pricing Estimating techniques Time and level of effort allowed to prepare the cost estimate and schedule Uncertainty Allowance is added to the decommissioning project baseline schedule and cost estimate to address the estimate uncertainty within the defined decommissioning scope of work and execution strategy. Uncertainty Allowance is included in the baseline cost and schedule to cover ill-defined work scope or elements of costs and schedules expected to be incurred, which cannot be explicitly foreseen or estimated because of a lack of complete, accurate or detailed information that can be available at this time.
Discrete Risk Events Discrete risks events on a project can be either threats or opportunities. Discrete risk events are considered a threat when the risk event may negatively impact the project baseline objectives, such as schedule delays and cost increases. Discrete risk events are considered an opportunity when the event may positively impact the project objectives, such as schedule and/or cost savings. Unlike uncertainty, discrete risk events may or may not occur.
Risk Allowance is funds added to the baseline schedule and estimate to account for discrete risk events (both threats and opportunities) that may or may not occur during the decommissioning project life cycle.264 The DCEs summary of the factors considered, and the summary of the methodology used to establish contingency is similar to the summaries provided in prior HDI cost estimates. Indeed, in ruling on a previous challenge to HDIs contingency in the Indian Point DCE, the Commission rejected a petitioners assertion that HDI did not provide enough information to show how it 264 DCE at 40-41.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 arrived at its 18% contingency allowance because the DCE did not include HDIs risk simulation analysis or list[] the discrete risk events underlying its analysis. 265 There, the Commission concluded that HDIs summary was sufficient because there is no NRC requirement that an applicant include this information.266 Here, however, the Commission explained that HDIs contingency should cover unforeseeable events that are almost certain to occur in decommissioning, based on industry experience. 267 While HDIs contingency should encompass these kinds of costs considered historically inevitable such as weather delays and tool breakage, [a]n acceptable contingency allowance [does] not need to include highly uncertain costs.268 Accordingly, HDIs DCE does not need to include surplus funds for possible but speculative events, because the latter are addressed by NRCs ongoing oversight of HDIs annual funding reports.269 As described in the next section and the testimony of Mr. Goulette, HDIs DCE encompasses the type of historically inevitable costs that must be addressed at this stage of the project. In fact, the DCE goes beyond the Commissions requirements and includes contingency funds for possible (but not inevitable) risks that may or may not occur and potential (but not inevitable) differences between HDIs assumptions in the DCE and the eventual project execution reality. Moreover, the DCE includes conservatisms and additional sources of funding beyond contingency that provide further margin to address unexpected costs, if necessary, throughout the 265 Indian Point, CLI-21-01, 93 N.R.C. at 23.
266 Id.
267 Mem. and Order, CLI-22-08, slip op. at 49 (citing ENOI, Site-specific Decommissioning Cost Estimate for Pilgrim Nuclear Station, at xii, attached to ENOI, Post-Shutdown Decommissioning Activities Report for Pilgrim Nuclear Station, dated Nov. 2018 (ADAMS Accession No. ML18320A034)).
268 Mem. and Order, CLI-22-08, slip op. at 49, n.174.
269 Id. at 50, n.175.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 project as HDI updates its estimate based on actual work progress, and the Commission oversees the adequacy of to-go funding to cover to-go costs.
: 2.      The DCE more than adequately addresses inevitable costs expected at this stage of the project.
As described in Mr. Goulettes testimony and accompanying exhibits, HDI calculated the 12% contingency through a rigorous, iterative process that involved input from project controls professionals, subject-matter experts in decommissioning, previous experience from other estimation efforts, actual work progress at Oyster Creek and Pilgrim, and input from site personnel at each of the Holtec-owned plants.
: a.      HDI added contingency funds to address uncertain risks.
270 HOL004, Goulette Test., at 5.
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271 72
 
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: b. HDI added contingency funds to address uncertainty in its estimation assumptions.
285 76
 
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Also, like HDIs risk allowance, estimation uncertainty is not required to be addressed in the up-front DCE. As the Commission explained, cost judgments that may have been reasonable earlier may need to be readjusted later with real-time information, but [t]he annual review process serves to monitor such expenditures and funding adequacy.292 Likewise, the Commission rejected the Attorney Generals claim that HDI must account for general cost overruns and risk of delay [that] exists in all decommissioning projects, due to unknown conditions.293 The Order states, [a]s to potential delays due to HDI identifying unknown conditions . . . it has been neither required nor customary for NRC site-specific decommissioning cost estimates to provide additional margins for uncertain events.294 291 Safety Evaluation by the Office of Nuclear Reactor Regulation Related to the Request for Transfer of Control of Provisional Operating License No. DPR-5, Renewed Facility Operating License Nos. DPR-26 and DPR-64, and the General License for the Independent Spent Fuel Storage Installation (Nov. 23, 2020), at 11 & 14 (ADAMS Accession No. ML20297A333); Indian Point Response to NRC RAI.
292 Mem. and Order, CLI-22-08, slip. op at 50, n. 175.
293 Petition at 24.
294 Mem. and Order, CLI-22-08, slip. op at 58.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 HDI conservatively added costs to the DCE to address the possibility that things will turn out less favorably than expected. But as the Commission has explained, that is not required in the up-front estimate. Thus, like HDIs risk allowance, the uncertainty allowance provides added margin to address possible future additional costs, should they arise over the course of the project.
c.
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: d.        The DCE also includes substantial additional margin to address uncertain costs during NRCs ongoing oversight of the project.
As the Order states, the material issue the Commission considered in admitting the Attorney Generals challenge for hearing is whether the 12% contingency level . . . could jeopardize the overall available funding for decommissioning and spent fuel management.309 308 Id. at 28-29.
309 Order, CLI-22-08, slip op. at 48.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Some of these factors are addressed in more detail in section 4, which addresses the closely-related point of HDIs means of adjusting funding during the dormancy period. The relevant point for purposes of the Attorney Generals challenge to HDIs 12% contingency is that contingency cannot be examined in a vacuum. The substantial layers of conservatism already in the DCE today go beyond NRC requirements and ensure that overall available funding is adequate to address the inevitable, expected costs of decommissioning Palisades, while also providing margin to address the possibility of unexpected cost increases throughout the NRCs ongoing oversight of the project.
310 Procedures for Analysis of Decommissioning Funding Assurance, LIC-205, Rev. 6 at 10.
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: e.      While not germane to the overall reasonableness of the DCE, a relatively lower Palisades contingency amount is reasonable and expected.
In light of the methodology that HDI used to establish the contingency in the DCE, the fact that Palisadess contingency is lower than the other three Holtec-owned projects is reasonable and to be expected.
At the end of the day, HDI calculated the 12% contingency using standard industry analytical methods, which NRC staff had reviewed and approved in three prior proceedings, which leverages the combined experience of HDIs specialized decommissioning organization and the experience gained estimating and executing three other decommissioning projects, and which encompasses the factors discussed in the Order and in PNLs assessment of contingency in the NRC formula. Moreover, the 12% cost contingency is by no means the only source of conservatism or additional funds available to address the kinds of expected, inevitable risks required to be included in the DCE.
311 HOL004, Goulette Test., at 5.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Accordingly, the conclusion in the DCE that a Contingency Allowance of 12 percent . . . reasonably bound[s] the universe of risks that are appropriate to be taken into account at the estimate phase is reasonable.313 D.        Holtec Palisades has multiple avenues for ensuring there will be sufficient funds available to make any needed adjustments over the dormancy period.
The final issue the Commission has admitted for hearing is whether Holtec Palisades314 has the ability to provide additional financial assurance as a means to adjust funding during the 10-year dormancy period proposed in the Application. Specifically, the Commissions Order directed Applicants to describe how they will ensure that sufficient additional funding will be available as a means to adjust funding if needed, and to address various particular points related to anticipated recoveries of SNF management costs from DOE. 315 As set forth below, Holtec Palisades has multiple avenues for ensuring there will be sufficient funds available to make any needed adjustments over the dormancy period.
: 1.      The need to show assurances only applies for the dormancy period.
Because Holtec Palisadess decommissioning schedule contains a 10-year period of storage or surveillance, NRC regulations require Holtec Palisades to provide a means of adjusting cost estimates and associated funding levels.316 While this requirement is intended to 312 Mem. and Order, CLI-22-08, slip op. at 48.
313 DCE at 41.
314 While HDI is the licensed operator, Holtec Palisades is the owner with ultimate payment obligations, the beneficiary of the trust fund, and the party to the DOE Standard Contract.
315 Mem. and Order, CLI-22-08, slip op. at 135.
316 10 C.F.R. § 50.82(a)(8)(iv).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 ensure that the appropriate amount of funding will be available to terminate the license,317 Holtec Palisades only needs to show it has the means to make such adjustments over the storage or surveillance period,318 that is the 10-year dormancy period from 2026 to 2036 proposed in the Application. In other words, the requirement is that Holtec Palisades show that, while in the storage phase (i.e., before decommissioning actually begins), it has the ability to adjust funding levels if estimates of those future decommissioning costs show a potential shortfall.
The Attorney Generals contention on this point, however, expressly focuses on adjustment of funding at the time of any overruns following the dormancy period. 319 The Commission likewise interpreted the Michigan AGs contention in this way, describing the argument as follows:
whether funds recovered from DOE in years past would still be available to adjust funding later in the event of a shortfall.320 Indeed, the criticism of Holtec Palisades here seems to be focused on if there are unanticipated decommissioning costs that will not be known until decommissioning is underway.321 Whether funding could be adjusted later in the event of an unanticipated overrun at that time is not the focus of 10 C.F.R. § 50.82(a)(8)(iv). Rather, the question is whether funding could be adjusted during the dormancy period. That is, if Holtec Palisadess decommissioning 317 Reg. Guide 1.185, Rev. 1, at 8. See also Pilgrim, CLI-20-12, 92 N.R.C. at 359-60 (Our financial assurance requirements, combined with our procedures for review of a license transfer application, help ensure that a license is not transferred to an entity that will be financially unable to maintain and decommission the reactor facility and associated ISFSI.).
318 10 C.F.R. § 50.82(a)(8)(iv).
319 Petition at 35 (arguing that following the dormancy period, the expected DOE recovery would largely be limited to the on-going costs of spent fuel management and even if retained would not offset any substantial overrun in decommissioning costs).
320 Mem. and Order, CLI-22-08, slip op. at 75.
321 Id. at 79.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 estimate322 changes during the dormancy period, could it adjust funding to account for that change as it approaches decommissioning?323 Particularly, given the fact the demonstration of reasonable assurance of financial qualification is flexible324 and is acceptable if it is based on plausible assumptions and forecasts,325 Holtec Palisades has made that showing here.
: 2.        Holtec Palisades has identified multiple means of adjusting funding in its filings.
: a.        There is a sufficient cushion in the NDT to cover any necessary funding adjustments.
Holtec Palisadess primary means of adjusting funding over the dormancy period is the significant cushion in the NDT, and the NRC has no requirement that prevents an applicant from relying on a single funding source.326 As shown in the DCE, in addition to the 12% contingency, Holtec Palisades conservatively estimates $19,788,000 will remain in the NDT at the completion of decommissioning.327 This alone is sufficient. Licensees satisfy NRC requirements [i]f the end-of-year trust fund balance is greater than or equal to zero at the end of the decommissioning period.328 Moreover, that remaining balance of $19.8 million is an intentionally conservative 322 Holtec Palisades is required to submit an annual revised decommissioning estimate and fund update. 10 C.F.R. § 50.75(f)(1); Id. § 50.82(a)(8).
323 As the Commission pointed out, [w]here decommissioning is projected to begin soon, and to be completed within several years, actual decommissioning costs also will be known relatively soon. Mem. and Order, CLI-22-08, slip op. at 79. This illustrates the temporal limitation of § 50.82(a)(8)(iv), which focuses not on actual overruns in the future, but on the estimates of those future costs.
324 Pilgrim, CLI-20-12, 92 N.R.C. at 368.
325 Indian Point, CLI 21-01, 93 N.R.C. at 29.
326 Mem. and Order, CLI-22-08, slip op. at 77.
327 HOL004, Goulette Test., at 21-22.
328 Procedures for NRCs Independent Analysis of Decommissioning Funding Assurance for Operating Nuclear Power Reactors and Power Reactors in Decommissioning, NRR Office Instruction, LIC-205, Rev. 6, § 4.3.6(B) at 11 (Apr. 3, 2017) (hereinafter Procedures for Analyses of Decommissioning Funding Assurance, LIC-205, Rev. 6) (ADAMS Accession No. ML17075A095).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 value.
9 3
329 330 Id.
331 Id.
332 Id.
333 Id.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Consequently, without adjusting any timelines or drawing funds from any other source, Holtec Palisades is well-positioned to address funding adjustments that may arise over the dormancy period.
: b.      Adjusting the decommissioning schedule to maximize the funds in the NDT is a further means of adjusting funding.
While the contingency plus more than $19 million cushion alone provides adequate assurance Holtec Palisades has the means to adjust funding levels as necessary, Holtec Palisades and HDI also have the ability to enlarge that cushion by adjusting its decommissioning schedule.
NRC regulations allow a licensee 60 years from shutdown to complete decommissioning activities. 334 Here, that means HDI and Holtec Palisades must complete decommissioning by 2082. As currently proposed, however, active decommissioning will begin in 2036 and will conclude in 2041.335 HDI estimates it will have over $350 million in the NDT when it begins SNF pickup activities and over $322 million when it starts active decommissioning.336 If at any time during the dormancy period that amount appears insufficient to cover to-go decommissioning and SNF management costs, HDI can extend the dormancy period to significantly reduce withdrawals from the NDT and allow earnings to accrue.
334 10 C.F.R. § 50.82(a)(3); Procedures for Analysis of Decommissioning Funding Assurance, LIC-205, Rev. 6, § 4.3.6(B) at 11.
335 See Application Att. E at 6.
336 See DCE, Table 5-1.
337 HOL004, Goulette Test., at 37.
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: c. Recoveries of SNF management costs provide further means of adjusting funding if necessary.
A further means by which Holtec Palisades proposes it could provide additional funding assurance during the dormancy period is through recoveries from DOE of SNF management costs.
Concerning this funding source, which was not taken into account in the DCE, neither the Attorney General nor the Commission in its order has suggested Holtec Palisades will not recover its anticipated approximately $160 million in SNF management costs. Instead, the sole concern raised has been whether those funds, once recovered, will be available when, and if, needed to adjust funding for the decommissioning. With that concern in mind, the Commission directed Applicants to address three points:
(1) whether any applicable DOE-related settlement agreement is in place; (2) the timetable on which the applicants would expect to file its DOE-related claims (including the respective estimated amounts in damages reasonably expected to be obtained); and (3) . . . approximately when and in what estimated amounts the DOE recoveries can reasonably be expected to be paid.345 Applicants address each in turn below. Again, however, the Attorney General focuses on the wrong periodafter the dormancy period. As the Commission noted in its Order, the Attorney General claims that the total DOE recovery during the license termination activities from 2036 through 2040 would be insufficient to adjust funding.346 The activities occurring from 2036 through 2040, though, are irrelevant to whether Holtec Palisades may use DOE recoveries to adjust funding if decommissioning estimates from 2026 through 2036 show a potential shortfall in the future.
: i. There is no DOE-related settlement agreement.
At this time, Holtec Palisades does not have a settlement agreement in place with DOE concerning the SNF management expenses.
345 Mem. and Order, CLI-22-08, slip op. at 81.
346 Id. at 75 n. 255.
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iii. Any DOE litigation recoveries would likely be received prior to the start of decommissioning.
The Attorney General seems to believe that receipts of DOE recoveries for SNF management costs are essentially instantaneous, as it equates the estimated recoveries for each year with the activities actually being performed that year.349 Yet, it is important to keep in mind that Standard Contract litigation takes years to resolve. 350 349 Petition at 35 ¶ 66.
350 A 2012 report from the Congressional Research Service noted, Of the 78 cases filed [from 1998 to]
February 2011 . . . [t]wenty-four remain[ed] pending. Congressional Research Service, R40996, Contract Liability Arising from the Nuclear Waste Policy Act (NWPA) of 1982, n. 6 (2012).
351 See Safety Evaluation by the Office of Nuclear Reactor Regulation and Office of Nuclear Material Safety and Safeguards Related to Request for Direct and Indirect Transfers of Control of Renewed Facility Operating License No. DPR-28 and the General License for the Independent Spent Fuel Storage Installation (Oct. 11, 2018), at 15 (hereinafter Vermont Yankee SER) (ADAMS Accession No. ML18242A639).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 if an updated to-go cost estimate shows that additional funding is needed for active decommissioning, there is no reason to think that those funds would not remain 93
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 available to cover the shortfall. In fact, as discussed in the next section, the Commissions regulations would require Holtec Palisades to demonstrate adequate funding.358 The anticipated surplus in the NDT, the ability to significantly extend the decommissioning timeline, and the anticipated recoveries from DOE are all adequate, available means by which Holtec Palisades can adjust funding if necessary.
: 3.        No license conditions are warranted.
Finally, a license condition requiring Holtec Palisades to deposit DOE recoveries into the NDT or to otherwise escrow the funds is not necessary. First, as set out above and in the Application, Holtec Palisades has means apart from the DOE recoveries by which it can address any necessary funding adjustments. This is not a situation, for example, where the NDT is projected to be insufficient to cover the estimated costs from the outset.359 NRC regulations and precedent are clear that a licensee may rely on prepaid funds in an NDT as a sole source of funding.
To read § 50.82(a)(8)(iv) in a way that requires additional funding commitments up front to cover the possibility of cost overruns would run contrary to NRC regulations and precedent. As the Commission previously explained, if 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 358 In addition to DOE litigation recoveries for Palisades, Holtec is also the holder of the Standard Contract for Big Rock. In fact, Palisades and Big Rock are covered by the same Standard Contract. HOL007, Palisades Standard Contract. As a result, DOE litigation recoveries for O&M costs at Big Rock, which total approximately $2.7 million per year, see Application Att. E at 8, are also available as supplemental funding to address any decommissioning cost overruns that Palisades might experience.
359 See Vermont Yankee SER at 13-15 (noting license conditions where there was estimated to be a $7 million shortfall between the decommissioning costs and the value of the NDT).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 previous year. The NRC therefore can track whether a licensees actual costs exceeded those that were predicted.360 Thus, those funds would be available to cover any funding adjustments to account for those costs.
Third, and perhaps most importantly, NRC regulations provide more than an adequate means to address funding issues. The Commissions present review of Holtec Palisadess financial qualifications will not be the only examination of [its] ability to pay for decommissioning and spent fuel management. 361 Rather, Holtec Palisades must continue, until the license is terminated to demonstrate annually that funding for both decommissioning and spent fuel management remains adequate.362 Should a major funding adjustment prove necessary at any point, this continual reporting will cause it to be identified and addressed on a regular basis.363 The Attorney Generals argumentthat, without a license condition, Holtec Palisadess DOE recoveries are ephemeral and should not be credited as a valid source of funds, should they be neededis based either on the belief that Holtec Palisades will intentionally divest itself of funds that may be required to satisfy its funding obligation or that a commitment to deposit funds into the NDT is necessary to ensure those. Both are wrong. Not only do they defy Commission 360 Indian Point, CLI 21-1, 93 N.R.C. at 43 (footnote omitted).
361 See Pilgrim, CLI 20-12, 92 N.R.C. at 361.
362 Id. at 360. See also 10 C.F.R. § 50.82(a)(8)(v) (requiring an annual financial assurance report); Pilgrim, CLI 20-12, 92 N.R.C. at 367 ([T]he NRC will . . . continuously oversee the adequacy of the decommissioning and spent fuel management funding until the license is terminated.).
363 Pilgrim, CLI 20-12, 92 N.R.C. at 376.
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 precedent that it will not assume a licensee will refuse to make additional financial commitments and, in so doing, would choose to violate NRC regulations, 364 but also actual experience on decommissioning projects.365 Moreover, consistent with its general oversight authority and the exemption granted by NRC staff from § 50.82(a)(8)(i)(A),366 NRC ostensibly has the authority to limit or revoke Holtec Palisadess exemption allowing use of NDT funds for SNF management and site restoration, thus ensuring that the full remaining balance is dedicated to § 50.2 decommissioning. In such an eventuality, Holtec Palisades would have a regulatory obligation to submit an alternative funding plan for the remaining SNF management costs.367 However, SNF funding plans acceptable under 10 C.F.R. § 50.54(bb) can be much more flexible than the radiological decommissioning funding methods prescribed in § 50.75(e)(1), and there is no reason to believe that Holtec Palisades would be unable to obtain a line of credit to bridge the gap until DOE recoveries are paid or simply provide the same revolving funding mechanism it is currently providing to cover Big Rock SNF management costs. 368 NRC regulations do not require any demonstration of funding for site 364 Pilgrim, CLI-20-12, 92 N.R.C. at 372.
365 See, e.g., Letter from ZionSolutions to US NRC, Report on Status of Decommissioning Funding for Shutdown Reactors, Docket Nos. 50-295 and 50-304, Att. 1, at 1 n.1, dated Mar. 26, 2020 (ADAMS Accession No. ML20097C644) (explaining that the plant owners parent company, EnergySolutions, will continue to fund additional decommissioning project activities using company cash reserves despite having no regulatory obligation to do so); id., Att. 1, at 2 (Energy Solutions has provided, and will continue to provide, to ZionSolutions funds necessary to complete decommissioning.).
366 Exemption, Holtec Decommissioning International, LLC, Palisades Nuclear Plan, Docket No. 50-255, (Dec. 13, 2021), at 4-5 (ADAMS Accession No. ML21286A506) (Based on the HDI SSCE and the cash flow analyses, use of a portion of the PNP DTF for spent fuel management and site restoration activities at PNP will not adversely impact HDIs ability to complete radiological decommissioning within 60 years and terminate the PNP license.).
367 See 10 C.F.R. § 50.54(bb); id. at § 50.82(a)(8)(vii)(C).
368 Holtec Palisades maintains an internal reserve fund, backed by a parent support agreement from Holtec International, to provide a revolving amount sufficient to cover annual ISFSI operating costs at Big Rock Point. See Application at 19; Letter from HDI to US NRC, Holtec Decommissioning International, LLC (HDI) satisfactory 96
 
CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 restoration costs,369 so if the NRC revoked HDIs exemption allowing use of NDT funds for those costs, HDI would have no obligation to the NRC to provide any replacement funding.
Therefore, in light of Holtec Palisadess multiple means of handling funding adjustments and the NRCs persistent oversight of Holtec Palisadess financial ability to complete decommissioning, there is no need for a special license condition. 370 V.      CONCLUSION For the reasons stated in the Application and above, the Commission should reject the Attorney Generals contentions and grant the Application without further condition or limitation.
documentary evidence required before the planned closing date of the purchase and sale transaction of Palisades Nuclear Plant and Big Rock Point Plant, Docket Nos. 50-255 and 50-155, Encls. 4 and 5, dated June 24, 2022 (ADAMS Accession No. ML22178A077).
369 Mem. and Order, CLI-22-08, slip op. at 10.
370 Cf. Indian Point, CLI 21-01, 93 N.C.R. at 17 (declining to impose a license condition requiring the licensee to replenish[ ] the trust with DOE recoveries).
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CONFIDENTIAL INFORMATION SUBMITTED UNDER 10 C.F.R. § 2.390 Respectfully submitted,
                                  /Executed in Accord with 10 C.F.R. § 2.304(d)/
Anne R. Leidich David R. Lewis PILLSBURY WINTHROP SHAW PITTMAN LLP 1200 Seventeenth Street, NW Washington, DC 20036 Telephone: 202-663-8707 Facsimile: 202-663-8007 anne.leidich@pillsburylaw.com david.lewis@pillsburylaw.com
                                  /Executed in Accord with 10 C.F.R. § 2.304(d)/
Susan H. Raimo ENTERGY SERVICES, LLC 101 Constitution Avenue, N.W.
Counsel for Entergy Nuclear        Washington, D.C. 20001 Operations, Inc.                  (202) 530-7330 and Entergy Nuclear Palisades, LLC  sraimo@entergy.com
                                  /Signed electronically by Alan D. Lovett/
Alan D. Lovett Jason P. Tompkins BALCH &BINGHAM LLP 1710 Sixth Avenue North Birmingham, AL 35203-2015 (205) 226-8769 (205) 226-8743 alovett@balch.com jtompkins@balch.com
                                  /Executed in Accord with 10 C.F.R. § 2.304(d)/
Jason Day General Counsel HDI 1 Holtec Boulevard Counsel for Holtec International  Camden, NJ 08104 and Holtec Decommissioning        (856) 797-0900 International, LLC                j.day@holtec.com 98}}

Revision as of 13:12, 15 November 2024

Applicants Redacted Initial Statement of Position on Michigan Attorney General Contentions
ML23004A082
Person / Time
Site: Palisades, Big Rock Point  File:Consumers Energy icon.png
Issue date: 11/18/2022
From: Day J, Leidich A, Doris Lewis, Lovett A, Raimo S
Balch & Bingham, LLP, Entergy Nuclear Operations, Entergy Nuclear Palisades, Entergy Services, Holtec Decommissioning International, Holtec, Pillsbury, Winthrop, Shaw, Pittman, LLP
To:
Atomic Safety and Licensing Board Panel
SECY RAS
References
License Transfer, RAS 56586, 50-255-LT-2, 50-155-LT-2, 72-007-LT, 72-043-LT-2, ASLBP 22-974-01-LT-BD01
Download: ML23004A082 (0)
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