ML20211M980
| ML20211M980 | |
| Person / Time | |
|---|---|
| Issue date: | 03/10/1997 |
| From: | Morrison D NRC OFFICE OF NUCLEAR REGULATORY RESEARCH (RES) |
| To: | Collins S, Lieberman J, Paperiello C NRC (Affiliation Not Assigned), NRC OFFICE OF ENFORCEMENT (OE), NRC OFFICE OF NUCLEAR MATERIAL SAFETY & SAFEGUARDS (NMSS) |
| Shared Package | |
| ML20008B465 | List:
|
| References | |
| FRN-62FR47588, RULE-PR-50 AF41-1-020, AF41-1-20, NUDOCS 9710150214 | |
| Download: ML20211M980 (171) | |
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*, UNITED STATES -
)p { NUCLEAR REGULATORY COMMISSION j t WASHINGTON. D.C. 20566-0001 49 go March 10, 1997 ,
l 1 , MEMORANDUM T0: Samuel J. Collins, Director Office of Nuclear Reactor Regulation -
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Carl J. Paperiello, Director Office of Nuclear Material Safety j and Safeguards l James Lieberman, Director l Office of Enforcement l l Richard L. Bangart, Director L Office of State Programs William J. Olmstead, Associate General Counsel for Licensing and Regulation Office of the General Counsel David L. Meyer, Chief Rules Review and Directives Branch Office of Administration Brenda Jo. Shelton, Chief Information and Records Management Branch Office of Information Resources Management Ronald M. Scroggins, Acting Chief Financial Officer Anthony J. Galante Chief Information Officer . FROM: David L. Morrison, Director / Office of Nuclear Regulatory Researc /* ,//h'A
SUBJECT:
OFFICE REVIEW ANC CONCURRENCE ON A PROPOSED RULE - FINANCIAL ASSURANCE REQUIREMENTS FOR DECOMMISSIONING NUCLEAR POWER REACTORS Your concurrence is requested on the attached Commission Paper. The following is a summary of this reques~c: 1.
Title:
Proposed Rule on Financial Assurance Requirements for Decommissioning Nuclear Power Reactors
- 2. RES Task leader: Brian J. Richter (415-6221) 9710150214 971003 PDR PR 50 62FR47588 PDR U .
\_
l l Eamuel J- Collins et al. 3. Cogniunt Individuals: HRR - Robert S. Wood (415-1255) NMSS - Timothy C. Johnson '(415-8538) OGC - Stephen H. Lewis (415-1684)
- 4. Requested Action: Review cnd concurrence in Comm;ssion Paper.
- 5. Reauested Completion Date: April 4, 1997
- 6. Backqround,: This proposed rule is being developed to amend the NRC's regulations relating to financial assurance requirements for the decommissioning of nuclear power plants. This is in response to the
, anticipated deregulation of ihn power generating industry. The proposed i action would revise the definition of " electric utility" contained in 10 CFR 50.2 and would require power retetor licensees to periodically report on the status of their decommissioning funds and funds for managtig their irradiated fuel. Also, the staff is proposing to allow licensees to take credit for the earnings on decommissioning trust funds. The SECY suspense date is April 21. 1997.
- 7. Resources to implement this rulemaking have net been included in the Internal Program /BLdget Review FY 1995-1999. Additional resources would oe required for review of the reports required by this rule. Capies of this concurrence package have been forwarded the Controller for coordi-nation of resource issues per the ED0 memorandum of June 14, 1991, ACRS, ACNW and the IG for information.
Attachment:
( Commission Paper w/encls, cc w/ attachment: R. M. Scroggins, OC H. T. Bell, IG J. Larkins, ACRS & ACNW DISTRIBUTION: Central f/c RAuluck Cognizant Individuals RDB r/f LRiani EJordan, OEDO CGallagher FCostanzi DPr ediola Dross, CRGR D0CUMENT NAME: _ 0:\ RICHTER \DERE7\ CONCUR
- See previous concurrence CF Y N PDR Y N To receive a copy of this document, indicate in the box: "C" - Copy without
. attachment / enclosure "E" - Copy with attachment / enclosure "N" - No copy 0FC RDB:DRA RDB:DRA } D:DRA w D:RES [1 NAME BRichter:ayw TMartin BMorris M DMorriNn#
DATE 02/27/97* 02/27/97* 3/1/97 3 //0/97 0FFICE RECORD COPY M FILE CODE:
. /
Samuel J. Collins et al. l 3. E.qgnizant . Individuals: NRR - Robert S. Wood (415-1255) i NMSS - Timothy C. Johnson (415-8538) - OGC - Stephen H. Lawis (415-1684) j 4. Reauested Action: Review and concurrence in Commission Paper.
- 5. Reauested Comoletion Date: March 14, 1997
- 6. PackarogrLd : The Nuclear Regulatory Commission l amend its regulations on financial assurance req (NRC) is uirements forproposing the to I decommissioning of nuclear power plants. The potential deregulation of the )ower generating industry has raised qmstions with respect to whetier current NRC regulations concerning decommissioning funds and their financial mechanisms will need to be modtfied. Additionally, the NRC is proposing a requirement that power reactor licensees report periodically on the status of their decommissioning funds and on the funding for the management of their irradiated fuel. The SECY suspense date is March 21, 1997.
- 7. Resources to implement this rulemaking have not been included in the Internal Program / Budget Review FY 1995-1999. Additional resources would be required for its implementation. Copies of this concurrence package have been forwarded the Controller for coordination of resource issues per the EDO metorandum of June 14, 1991, ACRS, ACNW and the IG for information.
Attachment:
Commission Paper w/encls, cc w/attechnent: R. M. Scroggins, OC H. T. Bell, IG J. Larkins, ACRS & ACNW DISTRIBUTION: Central f/c RAuluck Cognizant IMividuals RDB r/f LRiani EJordan, OEDO CGallagher FCostanzi DMendiola Dross, CRGR DOCUMENT NAME: 0:\ RICHTER \DEREG\ CONCUR CF Y N ,. PDR Y N To receive a copy of this document, indicate in the box: "C" = Copy without attachment / enclosure "E" = Copy with attachment / enclosure "N" - No copy 0FC RDil$RA b RDB:DRA D:DRA l D:RES NAME BR b r:ayw TMartin D BMorris DMorrison DATE 4 M_7/97 & /M/97 / /97 / /97 0FFICE RECORD COPY REs^ FILE CODE:
l l l 1 l FOR: The Commissioners l l FROM: L. Joseph Callan Executive Director for Operations
SUBJECT:
PROPOSED RULE ON FINANCIAL ASSURANCE REQUIREMENTS FOR DECOMMISSIONING NUCl. EAR POWER REACTORS PURPOSE: To request Commission approval to publish in the Federal Beaister a proposed rule on financial assurance requirements for decommissioning nuclear power reactors.
SUMMARY
This proposed rule is being developed to amend the NRC's regulations relating to financial assurance requirements for the decommissioning of nuclear power plants. This is in response to the anticipated deregulation of the power generating industry. The proposed action would revise the definition of
" electric utility" contained in 10 CFR 50.2 and would recuire power reactor licensees to periodically report on the status of their cecommissioning funds and funds for managing their irradiated fuel. Also, the staff is proposing to allow licensees to take credit for the earnings on decommissioning trust funds.
BACKGROUND: The staff submitted an advance notice of proposed rulemaking (ANPR) on financial assurance requirements for decommissioning nuclear power reactors (SECY-96-030) to the Commission on February 8, 1996. A staff requirements memorandum (SRM) on the same topic was issued on March 27, 1996, which approved publication of the ANPR with the addition of some items to be addressed through public comment (Enclosure 1). A revised ANPR based on the CONTACT: Brian J. Richter, RES (301) 415-6221
. s
l 1he Comm%sioners 2 l Commission's coments was published in the Federal Register (61 FR 15427) on April 8, 1996, The attached Federal Register notice (FRN) on the proposed rule responds to the coments received on the ANPR and submits the proposed t amendments (Enclosure 6). . l The ANPh requehi public comment on a specific proposal to amend il 50.2, 50.75, and 50.82 and requested comment on six areas of consideration for decommissioning: (1) the timing and extent of deregulation of the electric utility industry -(2) stranded costs (3) financial qualifications and decommissioning funding assurance for nuclear pcwer plants, (4) decommissioning funding assurance for a Federal Got rnment licensee,- (5) thn status of decommissioning trust funds during the safe 4torage period,
.and (6) reporting on the status of decommissioning funds.
DISCUSSION: Approximately 650 comments on the ANPR were received from 42 respondents. The commenters included 9 pubite utility commissions and organizations, 2 public interest groups, 28 utilitics and utility groups, and 3 classified as "other." Comments were requested on the specific proposal to amend il 50.2, 50.75, and
$0.82 to require that nuclear power reactor licensees provide assurance that the full estimated cost of decommissioning will be available through an acceptable guarantee mechanism if the licensees are no longer subject to rate regulations by State public utility corporations (PUCs) or the Federal Energy Regulatory Commission (FERC) and do not have a guaranteed source of income.
The amendment would also allow licensees to assume a positive real rate of return on decommissioning funds during the safe storage period. Lcstly, a periodic reporting requirement would be established. With respect to the proposed amendments, the staff was concerned by the possibility that the existing definition of " electric utility" in i 50.2 would causo problems if left intact during deregulation of the electric utility industry. As a result, a revised definition is being proposed for i 50.2 and the relevant sections of Part 50 that refer to the words " electric utility" or
" utility" are also being modified. The staff notes that the key component of the revised definition is a licensee's rates being, established by a rate-regulating authority. Further, should a licensee be under the jurisdiction of such an authority for only certain components of the licensee's cost of operation (e.g.. transmission access fees, system exit fees), the licensee would be considered to be an " electric utility" only for that part of the Commission's regulations to which those components pertain.
Another deregulation-related item that was included in the Commission's SRM relates to decommissioning funding assurance for a Federal Government licensee. Section 50.75(e)(3)(iv) states that an electric utility that is a Federal Government licensee need only provide assurance in the form of a statement of intent indicating that decommissioning funds will be obtained 1 l
( The Coinmissioners 3 when necessary. The Office of the Inspector General published an audit report' on this topic on April 3,1996, indicating that they found that such use of a letter on intent was questionable. Similarly, most of the comments received stated that the statement of intent should be eliminated as an option for any Federal licensee so that all licensees would be playing on a level field. The staff is of the opinroh that eliminating the statement of intent option for reasons of economic " fairness" is not within the Commission's. purview and further believes that any modification would result in a backfit that might not be justifiable, given that the risk of a Federal licensee not ( being able to fund its decommissioning expenses would be extremely small. Hence, the staff is recommending no change to 10 CFR 50.75(e)(3)(iv). l The ANPR also addressed the status of decommissioning funds during the extended safe storage period. Specifically, it asked whether licensees should be allowed to take credit for earnings on the decommissioning trust funds - during the safe storage period, what time periods NRC should allow licensees to use in estimating the credit for earnings, and what real rate of return should be allowed by the NRC. In response, the staff is proposing to allow credit on earnings from the time the funds are collected through the decommissioning period at a real rate of 2 percent. However, higher earnings amounts all be allowed during the period of reactor operation if specifically determined by a rate-setting authority. With respect to the reporting requirement, the staff is proposing that each licensee report on the status of its decommissioning funding for each power reactor at least once every three years, unless the reactor is within 5 years of the projected end of its operation, in which case it must submit a report annually. Besides seeking comments on the above, the ANPR specifically asked for e m ents on six areas of consideration,
- 1. The first area of consideration related to the timing and extent of deregulation, scenarios for deregulation, and the industry structure as a result of deregulation. On the issue of timing, commenters' predictions varied from as soon as 1998, to within 5 years, to a considerable length of time. As far as thoughts on a restructuring or deregulation scenario, individual commenters had some specific thoughts, but msny commenters said there was significant uncertainty with respect to the breadth, timing, and implementation details of the new competitive electric business. As one commenter noted, the pace of deregulation will be set by Federal and State legislation. Commenters, in general, state.1 that the ultimate extent of deregulation will be the deregulation of electricity generation, but not transmission and distribution rates. With regard to resulting industry structure as a consequence of deregulation, there were diverse views, but as
'U.S. Nuclear Regulatory Commission, Office of the Inspector General, "NRC's Decommissioning Financial Assurance Requirements for Federal Licensees May Not be Sufficient," OlG/95A-20, April 3, 1996.
The Comnissioners 4
- ome commenters advised that the NRC should abandon any attempt to anticipate market structure and any rule should accommodate nuclear reactors subject to traditional-regulation and reactors in the new competitive markets. The last subset question in this area of the ANPR focused on the differences in State
. policies and implications. Again answers varied, but if one can draw an inference from present conditions, it~ appears that reform may proceed at different speeds in different States because of local market and political pressures.
- 2. The second area of consideration in the ANPR was stranded costs at nuclear power plants. Many commenters thought regulators woulJ allow prudently' incurred stranded costs to be recovered in some manner, especially decommissioning costs. However, the NRC is aware that stranded costs must be addressed to ensure that they are being adequately handicd and that licensees are not so financially affected as to put public health and safety in danger.
Subsequent to the publication of the ANPR, the NRC published its " Draft Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry," September 23, 1996 (61 FR 49711). It stated:
"Notwithstanding the primary role of econonic regulators in rate matters, the NRC has authority under the Atomic Energy Act of 1954, as amended, (AEA) to take actions that may affect a licensee's financial situations when these actions are warranted to protect public health and safety." The policy also goes on to explain that, in the future, the NRC will consult more closely with the National Association of Regulatory Utility Commissioners (NARUC), FERC, and the Securities and Exchange Commission so that the NRC may express its positions on safety and encourage the various regulatory bodies to continue to allow adequate expenditures for plant safety. l.astly, the proposed reporting requirements addressed below are seen by the staff as vehicles for the Commission to keep abreast of this potential problem. With the issuance of the draft policy statement, the staff considers the stranded cost question resolved and sees no need to take further action.
- 3. The third area of consideration in the ANPR was financial qualifications and funding assurance for decommissioning nuclear power plants. There were 9 Oub-questions under this heading, covering funding assurance to cover premature shutdowns, s plant operator that ceases to be a utility, a variety of assurance options, financial test qualifications, PUC/FERC certification, the impact of accelerated funding, potential shortfalls because of underostimated costs, a captive insurance pool, and other NRC options in the case of a limited role for the FUCs or FERC. Again, the proposed reporting requirements addressed below are seen by the staff as a vehicle for the NRC to' keep informed of licensees' dec.ommissioning funding assurance without adding any of the above requirements. Should the staff become aware of potential shortcomings as a result of the reporting requirements, necessary rulemakings will be proposed.
While " benchmarking" is not addressed in this rulemaking or in the ANPR, it is relevant to several of the comment areas and the staff wishes to raise the issue to the Commission. Benchmarking in this context refers to the amount of fanding for decommissioning that the NRC believes a licensee should possess at
The Commissioners 5 given points in a nuclear power plant's operational life. For example, the NRC may require licensees to have ac;:umulated 25 percent of their decommissioning funds (less the credit for earnings on decommissioning funds as allowed by this proposed rulemaking) by the end of the tenth year of a plant's operation. . , The present requirements in this area stipulate that the licensees are to provide the funds for decommissioning, but are not required to provide a specified amount each year. However, licensees are required in i 50.75(b) to annually revise the total amount of funds they need for decommissioning. The reporting requirements promulgated in this proposed rule will result in a detailed understanding of contributions by licensees relative to the life of their plants. A significant variability in these contributions or possible shortfalls in the amounts may result in a need for future rulemaking to address benchmarking as a regulatory requirement. A potential problem with benchmarking is that it would require licensees to base decommissioning estimates on the dated equations in 6 50.75(c), which some commenters considered overestimates. These decommissioning esti mates are currently being evaluated as part of a rulemaking effort that is cur ently on hold pending accumulation of actual decommissioning cost data. The staff intends to address the issue of benchmarking as part of that future rulemaking. Additional information on funding will also be available as a result of this proposed rulemaking's reporting requirement.
- 4. The fourth area of consideration is decommissioning funding assurance for a Federal Government licensee. Almost all commenters took the position that Federal licensees should be treated in the same way as non-Federal licensees.
The general consensus was that different treatment for Federal licensees could create competitive advartages for the Federal licensees and that NRC should ensure that the " playing field" remained level. Only TVA took the position that ample reasons exist for continuing the use of statements of intent as provideo under the current regulations. However TVA also provided an extended description of the steps it has taken to use an external trust, "all requirements" contracts, and its power to issue indebtedness to assure its decommissioning costs. Another factor that was considered in this decision is the previously referenced Office of the Inspector General's Audit Report.* The report found that "...NRC's decision to allow Federal licensees to use a statement of intent...was based primarily on the assumption that the Federal Government would pay the financial obligations of the lone Federal licensee....should it b6 unable to do so. However based on our review of the U.S. Code and discussions with officials from the Department of the Treasury, the Office of Management and Budget and TVA, we believe NRC's assumption is questionable." The staff responded in the report stating: "TVA has a large, exclusive franchise area that has been granted by the Federal government since TVA's forma:lon in 1933. ...This franchise virtually guarantees that TVA will receive extensive revenues from the sale of electricity (at rates it has the p wer to set) for the foreseeable future. Even in the remote case where TVA defaulted on its bonds, revenues from electricity sales would not cease." The staff s position is to not eliminate the special status afforded to Federcl
l The Commissioners 6 l l licensees, as the elimination would place an unjustifiable burden on any Federal licensee, given the very small risk of a Federal licensee not being 4 able to meet its decommissioning costs. l S. The status of decommissioning trust funds during the safe storage period was the next area of consideration. The majority of commedes. w ported allowing credit for earnings on funds during extended storage periods. Some argued that if credits for earnings were not allowed, more funds than necessary would be collected, thereby generating unwarranted expense to licensees and customers and possible intergenerational inequities. Still others in support of credit for earnings stated that this should cover not only the extended safe storage period, but other periods as well. The staff proposes to allow licensees to take credit for earnings on external sinking funds from the time of the funds' collection through the decommissioning period. The proposed reporting requirement would provide the NRC with the ability to monitor licensees' decommissioning funds. A related option was for the NRC to specify a rate of return for licensees to use in calculating their earnings. Commenters suggested the usc of variable rates of return dependent upon what the licensees were able to justify given their earnings history, rates tied to bond rates, or ro.tes established by States. The staff proposes use of a 2 percent real rate of return. The staff now recognizes that its implicit use of a zero real rate of return was too conservative. Historically, real (i.e., inflations adjusted, after tax) rates of return using U.S. Treasury issues have been around 2 percent, so the staff proposes to allow licensees to use this rate in their calculations. If rates actually are lower than this, 5 50.82 provides that licen nes are to adjust decommissioning funds during safe storage to reflect changes in cost estimates.
- 6. Reporting on the status of the decommissioning funds was the lest area of consideration. While most commenters supported a reporting requirement, there was concern with content, frequency, and possible duplication of effort. The staff proposes a reporting requirement that would have Itcensees submit a report once every 3 years, and annually within 5 years of the planned end of operation. To make the report as simple as possible for the licensees to ,
comply with, the staff plans to issue a regulatory guide that would endorse the Financial Accounting Standards Board * (FASB) standard No.158-B,
" Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets," which is stiil in draft form. The staff plans to endorse this FASB standard as a means of providing guidance to licensees on complying with those portions of the NRC's regulations regarding licensee reporting on the status of its decommissioning funding. Licensees are to comply with the FASB standard once it becomes final in order to remain consistent with generally accepted accounting principles. The staff has reviewed the proposed contents
'FASB is a private body that establishes authoritative financial accounting and reporting standards.
l l The Commissioners 7 of the reports on decommissioning funds to ensure that the needs of the NRC are balanced versus the time constraints of the licensees in assembling them. ; The Federal Register notice also add:csses comments received , topics not
-specifically addressed in the ANPR. l
--j COORDINATION:
The Orfice of the General Counsel has no legal objection to this paper. The Office of the Chief Financial Officer, the Office of the Chief Information Officer,-and the Office of Congressional Affairs concur with the contents of this paper. RECOMMENDATION; That the Commission:
- 1. Approve the Notice of Proposed Rulemaking (Enclosure 2) for publication.
- 2. Certify that this rule, if promulgated, will not have a negative economic impact on a substantial number of small entities in order to satisfy requirements of the Regulatory Flexibility Act, 5'U.S.C. 605(b).
- 3. Note:
a.- The rulemaking would be published in the federal Reaister for a 75-day public comment period; b.- A draft regulatory analysis (Enclosure 3) will be available in the Public Document Room;
- c. The Chief Counsel for Advocacy of the Small Business Administration will be informed of the. certification regarding economic impact on small entities and the raasons for it as required by the Regulatory Flexibility Act;
- d. TMs proposed rule amends information collection reoutrements that are subject to the Paperwork Reduction Act of 1980 (44 U.S.C.
3501 et seq.). This rule is being sent to the Office of Management and Budget for_ review and approval of the paperwork requirements;
- e. A public announcement (Enclosure 4) will be issued;
- f. The appropriate Congressional committees will be informed (Enclosure 5);
- g. It is estimated that this proposed action would result in an additional annual NRC burden of approximately one staff-week; and
1 1 The Commissioners 8 h.- Copies of the Federal Register Notice of proposed rulemaking will
+ be distributed to all power reactor licensees. The notice will be sent to other interested parties upon request.
I I L. Joseph Callan ; Executive Director j for Operations ; Enclosuresi !
- 1. SkM dtd 3/27/96 (w/o attachment) '
1
- 2. Federal Register Notice '+ disk :
- 13. Draft Regulatory Analysis
- 14. Draft'Public Announcement (To Be Prepared-By OPA)
- 5. Draft Congressional Letters
- 6. ANPR dtd 4/8/96 j 1
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. _ _ _ _ , _ . - . . . . . .. ~ .__ .-.,._. ___..-._._ .. ,,_ . ._ .__.._.._...,_,_,._...___,_,m..._...._
f l I l ENCLOSURE 1 SRM DTD MARCH 27,1996
.l 5
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UNITED STATES E'
,' NUCLE AR REGULATORY COMMISSION REVISED f% a y W ASWNG10N. D C. 20LLS ;
/ .
March 27 l996 I OFFICE OF THE S[Cil[T A R Y MEMORANDUM TO: James M. Taylor , , . , Exec t ve Director for Operations b FROM: Jol C. Ho le, Secretary
SUBJECT:
S AFF REQUIREMENTS - SECY-96-030 - ADVANCE NOTICE OF PROPOSED RULEMAKING - NUCLEAR POWER REACTOR DECOMMISSIONING FINANCIAL ASSURANCE IMPLEMENTATION REQUIREMENTS The Commission has approved publication of the Advt.nccd Notice of Proposed Rulemaking with the addition of some items concerning the last two issues in the paper to be addressed through public comment, such as the following two examples:
- 1) The rate of return or time period to be assumed for the decommissioning funds.
- 2) The periodicity of reporting and the amount of information to be included on the status of the decommissioning funds.
The vederal Register notice should also be edited to include the following-inserted text:
- p. 5 (new i before last 1):
In addition, 5 50.75 (e) (3) (iv) provides that an electric utility which is a Federal government _ licensee need only provide assurance in the fonn of a statement of intent indicating that decommissioning funds will be obtained when necessary.
- p. 11 (new i D and relabel remaining is 'as E-F) :
Section 50.75 (e) (3) (iv) provides that an electric utility which is a Federal government licensee need only provide assurance in the form of a statement of intent indicating SECY NOTE: THIS SRM, SECY-96-030, IdID THE VOTE SHEETS OF ALL COMMISSIONERS WILL BE MADE PUBLICLY AVAILABLE 5 WORKING DAYS FROM THE DATE OF THIS SRf' A
%' ve a ,\v . 3u
/ , mp / < ff lV
4 l l l that decommissioning funds will be obtained when necessary. Since a Federal utility licensee will likely be confronted with many of the same new competitive pressures as non-federal ut.ilities,L the" question arises, should the regulations continue'to permit the provision of a. statement of-intent;as;theimethod byiwhich!these licensees provide financial assurance 1forTdecommissioning. There'is, for example;7 no Federa1Llaw(whichic16arlyjprovides'thttfthe ' i Federal (government 2would Aut.hority's ' financiali:fdeb;payA the iTennessee tValley"'oomi'ssibningToblig'ation s be un'able;to4do,soiJDoesKthieffact'orNany-other! factors' ' i militatefforforjagainst?allowingifedefal utility licensoes to i continue ito ?usti< stat,ementa tof d intentx as ; the . me thod, by 7 which financial-lassurancejfor(decommis'sioning istprovidedJ The attached public announcement should be substituted for the announcement proposed in the paper.. (EDO) (SECY Suspense: 3/30/96)
Attachment:
As stated cc i- Chairman Jackson Commissioner Rogers Commissioner Dicus OGC OCA OIG Office Directors, Regions, ACRS. ACNW, ASLBP (via E-Mail) 4 Il
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,e-i e ENCLOSURE 2 ,
FEDERAL REGISTER NOTICE 1
- -~ ~ -. - , --- -. . -, , - - .,- . . . _.. --_- ,.- n.. - - - ...-. .
l [7590-01-P] NUCLEAR REGVLATORY COMMISSION l 10 CFR Part 50 RIN 3150-AF41
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Financial Assurance Requirements for Decommissioning Nuclear Power Reactors l l AGENCY: Nuclear Regulatory Commission. ACTION: Proposed rule.
SUMMARY
- The Nuclear. Regulatory Commission (NRC) .is proposing to amend its regulations on financial assurance requirements for the decommissioning of nuclear power plants. The potential deregulation of the power generating industry has raised questions with respect to whether current NRC regulations concerning decommissioning funds and their financial mechanisms will need to be modified. Additionally, the NRC is proposing a requirement that power -
reactor licensees report periodically on the status'vi their decomissioning funds and on the funding for the management of their irradiated fuel. DATE: Submit concents by (insert a date to allow 75 days public coment)
, 1997. Coments received after this date will be
, considered if-it is practical to do so, but the Commission is able to assure
, consideration only for comments received on or before this date.
ADDRESSES: Lil comments to: The Secretary of the Comnission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001,= Attention: Docketing and Service. Branch.
_ _ _ _ . . _ _ _ _ ._. _ _ _-- _ _ __. _ __.- ___ ~ . - _ , _ _ _ i i Deliver comments to: 11555 Rockville Pike, Rockville, Maryland, between 7:45 a.m. and 4: 15 p.m., Federal workdays. Comments may be submitted electronically, in either AScil text or ; Wordperfect format (version 5.1 or later), by calling the NRC Electronic Bulletin Board (BBS) an FedWorld. The bulletin board may be accessed using a personal computer, a modem, and one of the commonly available communications software packages, or direct 1y via Internet. Background documents on the advance notice of proposed rulemaking are also available, as practical, for downloading and viewing on the bulletin board. If using a personal computer and modem, the NRC rulemaking subsystem on FedWorld-can be accessed directly by dialing the toll free number 1-(800) 303-9672. Communication _ software parameters should be set as follows: parity to none, data bits to 8, and stop hits to 1 (N,8,1). Using ANSI or VT-100 terminal emulation, the NRC rulemaking subsystem can then be accessed by selecting the " Rules Menu" option from the "NRC Main Menu." Users will find the "FedWorld Online User's Guides" particularly helpful. Many NRC subsystems and data bases also have a " Help /Information Center" option that is tailored to the particular subsystem. The NRC subsystem on FedWorld can also be accessed by a direct dial phone number for the main FedWorld BBS, (703) 321-3339, or by using Telnet via t Internet: fedworld. gov. If using (703) 321-3339 to contact FedWorld, the NRC subsystem will be accessed from the main FedWorld menu by selecting the
" Regulatory, Government Administration and State Systems," then selecting
" Regulatory Information Mall." At-that point, a menu will be displayed that has an option "U.S. Nuclear Regulatory Commission" that will take you to the NRC Online main menu. The NRC Online area also can be accessed directly by
[ l typing "/go nrc" at a FedWorld command line, if you access NRC from ! FedWorld's main menu, you may return to FedWorld by selecting the " Return to ] FedWorld" option from the NRC Online Main Menu. However, if you access NRC at ; FedWorld by using NRC's toll-free number, you will have full access to all NRC ! systems, but you will not have access to th'e main FedWorld system." If you contact FedWorld using Telnet, you will see the NRC area and ; menus, including the Rules Menu. Although you will be able to download documents and leave messages, you will not be able to write comments or upload files (comments). If you contact FedWorld using FTP, all files can be accessed and downloaded but uploads are not allowed; all you will see is a list of files without descriptions (normal Gopher look). An index file listing all files within a subdirectory, with descriptions, is available. There is a 15-minute time limit for FTP access. Although FedWorld also can be accessed through the World Wide Web, like FTP.that mode only provides access for downloading files and does not display the NRC Rules Menu. For more information on NRC bulletin boards call Mr. Arthur Davis, , Systems Integration and Development Branch, NRC, Washington, DC 20555, telephone (301) 415-5780; e-mail AXD30nrc. gov. Examine copies of comments received at: The NRC Public Document Hoom, 2120 L Street NW. (Lower Level), Washington, DC. FOR FURTHER INFORMATION CONTACT: Brian J. Richter, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, telephone _(301) 415-6221, e-mail bjr9nrc. gov.
i SUPPLEMENTARY INFORMATION: ,
Background
t The NRC published an advance notice of proposed rulemaking (ANPR) for
" Financial Assurance Requirements for Decommissioning Nuclear Power Reactors" (61 FR 15427), on April 8, 1996. The NRC was seeking comments on its proposal to amend il 50.2, 50.75, and 50.82 to require that electric utility reactor i
licenseos provide assurance that the full estimated cost of decommissioning their reactors will be available through an acceptable guarantee mechanism if the licensees are no longer subject to rate regulation.by State 'public utility commissions (PUCs) or the Federal Energy Regulatory Commission (FERC) and do not have a guaranteed source of income. The amendments would also allow licensees to assume a positive real rate of return on decommissioning funds during the safe storage period. Lastly, a periodic reporting requirement
'would be established.
The ANPR specifically asked for comments on the above amendments and on-six areas of consideration for decommissioning: (1) the timing and extent of deregulation of the electric utility industry, (2) stranded costs. (3) financial qualifications and decommissioning funding assurance for nuclear power plants, (4) decommissioning funding assurance for a Federal Government licensee, (5) the status of decommissioning trust funds during the safe storage period, and (6) reporting on the status of decommissioning funds. In response, the NRC received 650 comments from 42 commenters, and the commenters have been classified into 4 groups. The largest group of respondents was utilities and utility groups (28 commenters), followed by public utility
1 l commissions (PUCs) and related organizations (9). Two public interest groups submitted comments, as did a group of 3 commenters referred to as "other." The discussion of the comments received is presented by general comment area and specific questions posed within each area. The questions appear in the order as presented in the ANPR, followed by the Commission's responses. Response to Comments 1 A. TIMING AND EXTENT OF ELECTRIC UTILITY INDUSTRY DEREGULATION A.1 Likely Timetable On the issue of the timing and extent of deregulation, most commenters addressed only the timing question. If commenters also discussed the question of extent, they generally only distinguished between deregulation of the wholesale market and deregulation of retail power sales, although timing estimates usually referred to retail deregulation. Almost half of the commenters did not take a position on the timing issue. Seven commenters stated that the timing of deregulation could not be predicted. Several commenters stated only that they took the same position as the Nuclear Energy Institute (NEI), an organization that represents many nuclear utilities. NEl estimated that about ten years would be necessary to bring about restructuring and deregulation. A few commenters suggested that from five to ten years would be sufficient. Two commenters pointed to events in States that were scheduled to occur as early as 1998 and others predicted significant deregulation within five years or less or " rapidly " Two commenters suggested that deregulation would take place slowly and require a considerable time to complete. h\
l A.? Restructurina or Deregulation scenario Phases of Deregulation. Several commenters stated that an initial phase of deregulation of the generation or wholesale electricity market has already ( begun and is likely to continue. Utilities are now preparing for deregulation f .
- l. by undertaking cost reductions (e.g., workforce reductions, contract renegotiations, regulatory asset reductions, operating cost reductions),
strategic alliances and mergers, and expansion into unregulated venues. Five comenters expressed their belief that a second deregulatory phase would follow and lead to the restructuring of the transmission sector and to retail competition. However, many comenters noted that significant uncertainty exists regarding the breadth, timing, and implementation of the new competitive electricity business. The pace of d3 regulation, according to one commerter, will be set by Federal and State regulation. One commenter stated'that competition would be phased in slowly with existing generation assets being "kept whole" through standard regulated rates. Ultimate Extent of Rate Reaulation or Dereaulation. Four comenters expect that electricity prices from generators will ultimately be largely deregulated or unregulated. One comenter stated that generation will become partially deregulated, but may not be fully deregulated if reliance on market forces does n'ot adequately ensure safe and reliable generation supplies. Nine comenters expect that transmission rates will remain subject to Federal Energy Regulatory Commission-(FERC) jurisdiction. Regional power markets (RPM) and .. dependent system operators (150) (discussed below) would also fall under FERC jurisdiction, according to one come6ter. Ten comenters anticipate that distribution (retail) rates are likely to remain subject to i m J
4 Statejurisdiction. One of these commenters stated that distribution rates rc.ay be regulated under a price cap or incentive-based regulation. Retail wheeling and pool-based pricing' will provide market pricing at j all levels, including the retail level, according to one commenter. Three commenters believe that retail wiieeling will become widespread. One commenter indicated that nuclear power plants and non-utility .
, generators, even if released from rate regulation by States or FERC, may remain under some forms of regulation, including State and Federal siting and-l environmental regulation. ,
Resultino Business and Industry Structure Although one commenter stated that NRC should abandon any attempt to 4 anticipate market structure, other commenters suggested that the following features might characterize the industry subsequent to deregulation and , restructuring: e -Functional unbundling which is the divestiture of generation, transmission, or distribution systems. e Mr.ny, and perhaps all, transmission systems operated on a State-wide or . ' region-wide basis. An 150 will operate the system,. coordinating energy , production and delivery with demand and provide a pool-based spot market price for energy. RPMs or power market exchanges (PHEs) for competitive ; generation will accept bids from a': generators that want to participate
' Retail wheeling refers to the selling of bulk power to a retail customer by way of a third party's transmission system. Pool-based pricing is a pooling of electricity produced by various generators for resale to consumers.
in the market, establish the clearing price, and determine the sequence of generator dispatch. Bilateral contracts for the direct purchase of . power will also be allowed, e Different treatment for nuclear generation than for other types of ( utility-owned generation. Even if nuclear generation is permitted to compete in _ an _open market, some regulatory mechanisms may remain in ; place to ensure that nuclear-related costs (safety, security, waste disposal, decommissioning) are recovered by some means other than the market price of power. One of these commenters stated that regulated , local distribution companies would end up owning nuclear generating plants. .o Continued economic viability for nuclear generation for many years as a result of marginal costs that are quite low. Another commenter argued, however, that there is no obvious deregulated market for many or most existing nuclear power plants because of the uncertainty of the costs of ds...amissioning and the disposal of high-level nuclear wastes. This commenter stated that neither NRC rulemakings nor short-term passage of time will resolve these issues. A third commenter asserted that competitive pressures will lead to the early retirement of some nuclear pl ants . One commenter argued that, given the changes under consideration and already under way, it is no longer credible to assume that utilities can always raise rates or otherwise recover whatever costs are needed to safely operate and decommission nuclear plants. Another commenter suggested that if
I the NRC chooses to proceed with a rulemaking, the rule should accommodate both nuclear units subject to traditional regulation and nuclear units in the competitive markets. 1
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A.3 Differences in State Policies and Implications l Commenters expressed viewpoints on the likely differences in State i deregulatory efforts and policies. One commenter declared that all States will ultimately undergo restructuring and deregulation in some form. Nine commenters, however, suggested that some States may reject restructuring
-entirely, regardless of what other States do.
Four commenters feel that States will possibly or probably be c.cinelled by competitive forces to deregulate, particularly if neighboring States do so. One of these commenters added that States within a geographic region (where there are no physical barriers to electric transmission) are likely to migrate to a similar industry structure, either as a result of Federal legislation or
-market. pressures. Two other commenters provided examples of market or political pressures that could affect neighboring States' decisions to deregulate, One commenter stated that some regulators in States that already enjoy low-cost electric service appear reluctant to endorse' competition because of
, concerns that indigenous utilities will seek to sell power to the external market where' profit margins could be greater. Should market factori provide an advantage to States that foster competition (by allowing indigenous utilities to gain strength by acquiring market share), States that resist
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competition could put their utilities at a disadvantage. While State regulators may elect to defer the decision on competition, economic or social pressures could influence that decision. Another commenter indicated that States implementing retail competition may face the risk that a utility in a neighboring State could obtain open access without reciprccal access being provided to in-State utilities seeking to enter the State that does not provide competition. Three commenters remarked that reform may proceed at different speeds in different States because of local market and political pressures. One of , these commenters recommended that NRC accommodate the varied pace to avoid hindering or forcing transitions. In response to the ANPR's query regarding " hybrid" systems, one commenter believes that a hybrid system of regulation is likely to emerge as States deal with ecoriomic issues in i. variety of ways. Another commenter stated that a hybrid system could exist for some time. A third commenter reported that, while a hybrid system could probably exist, it may not result in the least expensive electricity. Under a hybrid system, industry structure may vary from region to region. Other commenters, however, felt that a hybrid system is unlikely to prevail. They stated that a hybrid may be operationally cumbersome or even unworkable because the markets are not defined by State boundaries and because the grid is highly integrated and interdependent. One of these commenters also stated that a patchwork or hybrid system may reduce the opportunities to market some nuclear generation. Three commenters said they could not predict whether a hybrid system can exist or how one State's policies will affect its neighbors.
4 l l One commenter expressed concern that deregulation and reduced oversight ! l st the State level may reduce the certainty that out-of-State partial owners I
. I of nuclear-facilities will collect and expend decommissioning funds. i Response. The above questions were posed for comment so the NRC could obtain estimates on the timing of deregulation, phases, and possible different approaches that may be used in how States would address deregulation. These comments are being grouped under one response as they all contribute to whether the Commission should proceed with a proposed rule now. While the responses to this set of questions often ran the gamut of opinion on this issue, the comments have not caused the Commission to change its position that it must act now to be in a position to respond to the upcoming changes in the electric utility environment that could affect protection of public health and safety. Increased competition could result in economic pressures that affect how licensees address maintenance and safety in nuclear power plant operations, as well as the availability of adequate funds for decommissioning.
Hence, these comments reinforce the Commission's position that a rule is necessary and timely, given electric utility restructuring and the deregulation legislation being proposed or enacted in several States and by FERC. B. STRANDED COSTS Many commenters expressed the view that regulators are likely to allow prudently incurred stranded costs to be recovered in some manner. Many of these commenters felt this was particularly true for prudently incurred decommissioning costs. Following are viewpoints typical of these comments. I The probability is high that regulatory mechanisms will be developed to replace cost recovery procedures established through " traditional" regulatory procedures. These mechanisms-(e.g., wire charges, non-Dypassable customer fees, exit fees) may be different from current mechanisms, but the probability ofrecoverabilityunderthesemechanismsisnolessthanitwouldiiavebeen under conventional regulation. The mechanism chosen, and its associated equitable allocation of cost responsibility between customers and shareholders, will be determined through the inevitable give and take of the restructuring process, if one is implemented. FERC, in Order 888, April 24, 1996, effectively established a precedent that, for electric sales under FERC jurisdiction, there will be full recovery of all costs that were prudently incurred based on an expectation of serving customers in the future but have become stranced as a result of moving to a competitive market. Although the FERC order pertains to wholesale markets, most believr. the precedent has been set and the same standard will apply to stranded costs that result from retail competition, it is reasonable to assume that legislators and generators will take distinct precautions in relation to nuclear generation. Even if nuclear plants are permitted to compete on the same basis as other baseload generation, regulatory mechanisms must be in place to ensure that certain costs (safety, security, waste disposal, and plant decommissioning) are recovered by some means other than the market price of power. Plausible mechanisms that regulators could use to recover costs include competition transition charges and non-bypassable charges. One utility fully expects that there would be 100 percent recovery of nuclear stranded costs in a restructured electric industry. i l l Other commenters expressed some uncertainty, however. Some commenters ; thought cost recovery was appropriate, but did not address its likelihood. In some cases, commenters advocated specific NRC action to oddress the situation. One commenter stated it is preniature to speculate as to who will ultimately hear the responsibility for stranded costs (estimated between $7 and $17 billion in New Jersey alone). While FERC Order 888 addresses this issue for the wholesale market, that decision remains open to legal challenges that may affect its final outcome. Moreover, since potential retail stranded ; costs are orders of-magnitude larger than wholesale stranded costs, a different solution to this issue for retail competition may ultimately be : deemed appropriate. Where stranded costs nay be determined to be recoverable, it is conceivable that those costs will be recovered through some form of non-bypassable " wire" charge. The commenter further stated that it is not clear how construction costs will'be treated as State PUCs define policy for restructuring. FERC and some State PUCs already have proceedings under way to determine the amount and means of stranded cost recovery. Tnere is also the possibility of Congressional action. NRC should take a proactive position with FERC and State regulators that potential stranded costs, including those that may be related to specific decommissioning cost obligations, should be recovered by the electric utility as part of their rates. (Several other commenters also
-suggested that-NRC should aggressively lobby FERC and/or PUCs to allow
, utilities to recover stranded decommissioning costs.)- One PUC does not accept that any source of generation is "non-l competitive" per se; and thus does not accept that nuclear plants are non-competitive because of high construction costs. It is premature, an L .-. - -. . .
oversimplification of a complex issue, and a-potential disincentive to mitigate costs to label any type of generation non-competitive at this early stage in restructuring. Even if nuclear generation is sold at less than current combined fixed and variable costs, te market pr' e will probably exceed the variable component, so there will be some recovery of fixed costs. Costs that are not recoverable could be the subject of Federal or State stranded cost proceedings. federal and State authorities must inquire whether the unit is necessary to-the continued safe and reliable operation of the interconnected grid, and if the answer is yes, a proration of the costs may be necessary anong all customer classes that benefit from the continued operation of the unit. If the unit is not necessary, it should be removed from service. The individual State commissions will have to decide who should bear the cost to prematurely shut down, as opposed to decommission, an uneconomi'c plant. A commenter stated that the treatment accorded stranded investment or costs may vary from jurisdiction to jurisdiction and few generalizations are possible. The NRC should not become embroiled in individual rate proceedings or debates about particular cost recovery mechanisms, but should instead define a clear policy that, from a public health, and safety perspective, licensees must be allowed to maintain an adequate financial posture to support ongoing safe operation and decommissioning, The NRC's policy statement' should be a strong statement on its expectations. NRC should participate in ! the'NARUC subcommittee addressing restructuring. '
'See Draft Policy Statement on the Restructuring and Economic ,
Deregulation of the Electric Utility Industry, 61 Fed. Req. 49711, September 23, 1996.
Some commenters mstated that decom i ssioning obligations are qualitatively ditferent from other st randed costs. mechanism that provides for recovery FERC has not yet adopted a of decommissioning costs. provides for recovery of wholesale Order 888 approach. However, this approach only accountstranded costs s fixed costs already incurred by utili s for and allows recovery for be collected in the future. ties and does not address a must costs th t to assure the continuing recoverA better solution overnment is for the Federal through non-bypassable fees to by of decommissioning y rates, costs in utilit system, or through othere surcharges ti de paid e by utility customer \ facilities. The ?lRC should support cost recoveto the use of transm State commissions on the importancry initiatives and help educate decommissioning costs. e of ensuring continued full collecti on of Another commenter noted that the b collection of the cost of decommissi est ultimate assurance of the operate at sufficiently low marginal oning is the ability of the plant to gross margins. The NRC could improve the likeliho o s in dcosts to colle encouraging the IRS to allow 1.ayment of this outcome by (1) generally deductible rather than deds for decommissioning costs to be regulatory agency and (2) strengthe iuctible only if they are ordered by a costs. As plants are further depreciatedn ng utilities'randed efforts to recover st generation escalates, existing pla a t nd the cost of nonnuclear . e Some commenters asserted that in s will become more competitive and seeking the sale or closingn the process of identifying well-run of who should pay for unrecovered of the cnet-well-run plants, the probl em the nonsalability is due oto prostsbl mu:4 de addressed. ems created by poor To the extent that management, the seller is p.- .-_ -
responsible, if the NRC or another agency would undertake a program to address the problem of poorly performing nuciear plants and encourage continued maintenance of efficiently onerated plants, many of the questions asked by the ANPR might find answers. Timeliness in identifying poorly performing plants is critical because while the industry is reforming itself,
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the ability to affect the inventory of nuclear plants is at its highest level. , Once plants have been evaluated, the NRC should be prepared with a task force J to recommend an orderly plan for the disposition of those few plants and operators who will not be recommended for further operations. A few commenters believed that the full burden of covering the costs, including decommissioning costs, of uneconomic nuclear plants should fall on l utility shareholders rather than customers unless there is a compelling case i otnerwise. Response. The Commission did not see a need to modify its position because of the comments received. Specifically, the Commission agrees with the commenters who hold the view that regulators are likely to allow prudently. incurred stranded costs to be recovered in some manner and do not see a need to interfere in the financial regulation of nuclear power plants with respect to the question of stranded costs. Some of the comments, in which actions were proposed for the NRC's involvement with respect to stranded costs, were not only problematic but were beyond the NRC's sphere of regulation. However, the NRC is aware that stranded costs, insofar as their recovery affects public health and safety, must be addressed to ensure that they are being adequately
' handled. As stated in the NRC's " Draft Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry" of September 23,
- p. e 1996 (61.FR 49711): "Notwithstanding-the primary role of economic regulators in rate matters, the NRC has authority under the Atomic Energy Act of 1954, as amended, (AEA) to_ take actions that may affect a licensee's financial situation when these actions are warranted to protsct public health and safety." The policy also goes on to explain that the NRC will work and consult more closely in the future with the National Association of Regulatory 4
Utility Commissioners (NARUC), FERC, and the Securities and Exchange Commission (SEC) so that the NRC may express its positions on safety and ' encourage the various regulatory bodies to continue their allowances of adequate expenditures for plant safety. Lastly, the proposed reporting requirements addressed below are seen by the NRC as a vehicle for the - Commissinn to keep atop this potential p; >blem. C. NUCLEAR FINANCIAL QUALIFICC. IONS AND DECOMMISSIONING FUNDING ASSURANCE C.1 Funding Assurance if Plants Shut Down Prematurely Most commenters accepted the premise of the question, whether costs of a shortfall in decommissioning funding of a prematurely shut down plant could be passed along to ratepayers. - This conclusion was based in part on past experience and in part on a belief that State PUCs will develop methods to L -ensure that decommissioning costs are covered. Several commenters said that recovery' from ratepayers or shareholders would depend on the plant ! management's responsibility for the premature shutdown: if management were deemed responsible, efforts would be made to have the shareholders pay for decommissioning; but if the management were not deemed responsible; State PUCs would find methods to have the ratepayers provide the funds. Commenters noted
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that in the past,- decommissioning costs had been recovered for prematurely closed. reactors (e.g..-Dresden 1. Fort St. Vrain, San Onofre Unit 1 Trojan, YabkeeRowe).In a transition from full regulation to full competition, one-commeniersuggesteda-windowtoallowcontinuedorpossiblyaccelerated-recovery. Another said that a surcharge might be placed on customers. Under tompetition, recovery could be made through other revenue streams of the I licensee, a non-bypassable fee, or debt or equity of the licensee. Two other commenters suggested that transmission charges would be the most likely source - !
.of funding.
_ Retained earnings of the utility were suggested as a source of funds. Two commenters expected shareholders to be-responsible for providing decommissioning funds in cases of premature shutdown. Two commenters, including one PUC, conceded that PUCs might not have jurisdiction to require funding from ratepayers. .Under such circumstances, one PUC stated, funding of decommissioning would be-greatly dependent on the financial viability of the regulated firm. The risk of recovery would rest squarely on its shareholders. If the shareholders could not pay, the liability would then transfer to taxpayers. For this reason, the commenter suggested, decommissioning might be accorded special treatment. One commenter argued that the solution to premature shutdown was for NRC to require assurance for cecommissioning costs prior to approving reorganizations or license transfers. Potential funding shortfalls should be addressed, another argued, on a case-by-case basis, and might be avoided by-sale ofj the nuclear. plant to an entity better able to manage it effectively. Two others suggested that a proper funding mechanism would have to be identified and put-into place at shutdown, without further specifying what that mechanism could be. In the opinion of one of these commenters that could be a difficult problem because currently, on an aggregate basis, utilities' decommissioning costs are'only about 25 percent funded (about $9 billion out of;$35 billion) - although plants are at about 43 percent of their aggregate service. lives. Early underfunding could force high back-end funding, . making. the plants uncompetitive. A commenter stated that, contrary to the planned 40-year operating life of nuclear power plants, material and operating evidence suggests plants' operating lives are closer to 15-25 years. Hence, the plan to recoup y decommissioning costs of over a 40-year operating life may be unrealistic. 4 L NEI took the position that the source of funds to shut down a' plant prematurely would be different from company to company and'would have to come from other ongoing revenue streams of the company or from alternative sources such as transmission or distribution charges, exit fees charged customers
-leaving the system, or other regulatory charges. NEI also supported NRC requirements for financial assurance, such as-those currently found in 10 CFR 50.75. Five commenters stated that they explicitly adopted the NEI position.
Response. 'The Commission recognizes the importance of decommissioning funding _
- assurance for? prematurely-shutdown plants and believes that its current case-specific approach, outlined in 5 50.82, strikes- the best.. balance between level-of assurance and cost. With respect to the comment that plants do not operate
- for the full 40 years, the Commission is aware of such plants. However, it is
-likely that some plants will' continue operating for the full-40 years, and some beyond. Therefore, the Commission does not believe'any change is required for the planned 40-year life.
C.2 When Does an Operator cease To Be a Utility
,0n the question of when an operator of a nuclear power plant ceases to be a " utility" as defined in 10 CFR 50.2, seven commenters interpreted the 4
-definition strictly and concluded that, if an operator ceases to satisfy the terms of the definition, the operator is no longer a " utility." Several commenters used almost the same formula: an operator would cease to be a
" utility" when it ceasas to provide service to retail or wholesale customers at rates set. by a separate regulatory authority. One commenter supported a
- clarification of NRC's regulations that would establish its continued ability to require the proper accumulation of decommissioning funds, whila two argued
.that the NRC should relax its definition to cover entities th:t purchase
! . electricity and recover the costs from rates charged customers or from other revenue guarantees. Another commenter argued that NRC should seek additional assurance in advance of deregulation. NEI stated the contrary argument, noting that it is not apparent that any licensee will fall outside the definition of " utility" in tha near future,
'even after restructuring. NEI argued that as long as a licensee has adequate cost-recovery mechanisms under the authority of State or Federal regulations,
-it should continue to be considered a utility.
=0ther commenters argued that-even after deregulation the price charged for electricity will be established by the regulatory process or in other ways that.will mean a nuclear plant will continue.to be an " electric utility." One stated that the term " electric utility"~ should be construed to include all entities that have been authorized by a State PUC, FERC, or other governing entity to recover decommissioning tosts from customers. Two commenters expected plants- to remain subject to State PVC jurisdiction, and therefore to
)
4 s Jsatisfy the regulatory ~ definition. Another argued that if a portion of a vertically integrated company is-subject 1to cost recovery pricing the d
' 1 definition is satisfied. -
Two said that .if a plant sets its own rates for-1 electricity _the definition _is satisfied. One commenter rejected the NRC's emphasis on an operator's satisfying l l
- the-definition of _ utility, and argued that- the emphasis _ should be on the 1
financial viability of the entity responsible for_ decommissioning. the unit. _ i Response. Consistent with the position taken in_the ANPR, the NRC is proposing to revise its definition of " electric utility."- The Commission-notes _ that the key component of--the revised definition is a licensee's rates-
-being established through cost-of-service mechanisms by a rate-regulating authority. Several' States are consioering deregulation of future operations of nuclear power plants such that revenues will not be determined by ' cost-of-service but by market-set prices. Should a. licensee be under the jurisdiction-of a_ rate-regulating authority for only a portion of the licensee's cost of operation, covering only a corresponding portion of-the decommissioning costs-Lthat are recoverable by rates set by. a rate-regulating authority,_ the licensee will be-considered to be an " electric utility" only for that part of the
. Commission's regulations to which those components pertain. For example, if a licensee were able to collect 40 percent of its decommissioning costs- through rate-regulated activities, the remaining f) percentlof-the costs would need to be accounted for in a manner consistent d'th methods acceptable for a licensee other than an electric utility. Similarly, a licensee who collects non-decommissioning operation costs, not collected through these or similar-mechanisms ' authorized by a rate-resulating authority,'would not be considered s.
an " electric utility" for the purposes of financial q'ualifications to operate the facilities. In this proposed rulemaking, the definitions of several ! relevant terms-are also provided for the first time in 5 50.2. It is noted that some commenters misinterpreted _ the intent of the existing definition of " electric utility" with respect to entities that establish rates themselves. As stated in the_ proposed definition, those entities include 'only public utility districts, municipalities, rural electric cooperatives, and State and Federal agencies. Therefore, the proposed definition is being proffered as clarification and to show the continued importance the NRC places on the role of regulatory authorities in the setting of electric utilities' rates with respect to the collection of funds for decommissioning. This is consistent with the NRC's draft policy statement. C.3 Assurance Options The following topics were discussed by commenters in response to the ANPR's questions relating to the options to be considered if an electric utility found itself operating a reactor that was no longer regulated by a rate-setting State or Federal _ body. Full Up-Front Assurance-Most commenters opposed requiring all nuclear plants to provide full up-front assurance, often arguing that it is unnecessary or that it is overly burdensome to nuclear plant owners. Many commenters reminded NRC that deregulation does not inherently mean a total lack of regulation or a lack of cost recovery. One commenter believed NRC should, at the time of restructuring, require only an assura..ce level commensurate with the completed percentage of the operating life of the plant. One commenter opposes advance funding on the grounds that doing so would incorrectly view all properly executed reorganizations as resulting in successor operators being unqualified I to ensure decommissioning compliance. ' One commenter believes that assurance should be provided before licensees are exposed to the full pressures of competition (3-5 years). Two commenters supported the idea of requiring assurance prior to NRC's approval of reorganizations that transfer control of a nuclear plant. Many commenters favor requiring reasonable financial assurance for entities that cease to be rate-regulated utilities. Many of these commenters, and other3, view NRC's current regulations as basically adequate to address these situations, although the regulations might expand upon the allowable methods of assurance. Additional Financial Assurance Methods Additional financial assurance methods suggested include continued rate-regulating entity determinations, an appropriate charge for decommissioning in contracts for the plant's output or in the transmission or distribution charges of the licensee or its affiliate if such charges are assigned to the licensee or its decommissioning fund, and exit fees charged against customers leaving the system. A few commenters would include any insurance for premature decommissioning caused by an accident. One commenter would allow utilities to establish any method that may be developed, including methods requiring approval of PUCs or FERC. Two others would allow assurance through a plan for gradually recovering decommissioning funds via rates and prices, even for deregula.ted entities. Others argued that NRC should offer the
. utilities flexibility and that each situation should be assessed on a case-by-case ba:is if and when it occurs.
4 Timing of Rulemaking With regard to ti;e timing of the rulemaking, a few commenters support prompt NRC regulatory actie to ensure that adequate financial assurance is in
- place prior to-restructuring, befoie waiting further to learn exactly how the industry will develop. Several other commenters, however, believe that rulemaking-is premature until more is known- about restructuring. Several commenters- suggested that NRC already has the authority to approve or disapprove any transfer of. license related to a merger or reorganization. Two commenters stated that NRC should evaluate the regulations only after further studies that (1) identify those nucles plants that are not likely to survive
'the imposition of competitive forces (i.e., those plants that are not run efficiently or that cannot be made to run well), or (2) develop quantitative measures for assessing the adequacy of decommissioning funds and rates of accrual. New rules, according to one commenter, should be timed to enable utilities to take advantage of stranded cost recovery. ,
4 Added Assurances for Safe Operation and Ottommissionina
. Many commenters voiced opposition to the INPR's query regarding whether the NRC.-should require additional assurante for adequate funds for safe operation and decommissioning in anticipation of deregulation. One commenter argued that additional assurances in this araa may not add to or strengthen the obligation already imposed by the terms and conditions of the license.
Others reasoned it unnecessary, given other existing NRC requirements and
1._
;FERC's framework for recovery of stranded costs -including decommissioning.
_0nly one-'commenter supported additional assurance for' safe operation and idecommissioning in anticipation of deregulation. Joint ~ Liability'- In response to the ANPR's query regarding newly created organizations or
- holding companies being held Jointly liable'for decommissioning costs,- four commente'rs supported the idea because of the added assurance it would provide.
- Thiree commenters would consider' requiring joint liability on a pro rata basis,
}- possibly taking -into account the remaining jears of licensed life. One-
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commenter cautioned .that jointly liable parties maTdisagree on
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s _ decommiesioning methods (e.g., prompt vs. deferred) because of the cash. flow
' impl icati_ons .-
p -Numerous'other commenters opposed the idea of' joint liability, arguing that it was unnecessary, would inhibit flexibility, would weaken competitive _ position, or would undermine the separate corporate identity or the
. responsibility of-the individual entities. Some of these commenters suggested f that joint-liability could be' acceptable if it were an ohtional method of
~ financial assurance.
-One commenter stated that new owners and operators should have to assume
/ the_rbsponsibilities and liabilities of the previous owners and opera % rs.
< Another stated that the financial assurance obligation should follow the w
- ' Joint liability refers to the concept of joint and several liability which is defined:in Black's Law Dictionary _ (4th Ed.) as:
w A liability is said to be joint and several when the creditor may sue one or more of the parties to s'Jch liability -separately, or all of= them together at his' option. Dicey, Parties 230, 4
M 7-owners and operators, whether regulated or unregulated, who have incentives to properly 1 manage' and operate the units.- Impacts-Many commenters claimed that requiring full up-front assurance would-be overly burdensome to_ nuclear ~ plant owners. Others argued that additional
. assurances could inhibit _ competitiveness relative to nonnuclear facilities,
-impede reorganizaticn, aggravate potential stranded investment, or create sdditional problems-for utilities,~ratepayers, er taxpayers at a time when Ecompetitive- forces'are already caesing ecoromic concerns. Examples of such problems would include the difficulty for affiliated ' businesses'to raise L
- capital, or the need for affiliated entities to charge more _for its services reducing its competitive position in the' industry. Some commenters argued-these effects could reduce the likelihood that decommissioning will be fully
_ funded; or could increase the likelihood of prematura shutdown. Response. The Commission is addressing most of these comments by revising.the idefinitio'n of " electric utility" nd by instituting a reporting -requirement. As to :the issue of requiring ful' up-front funding in advance of deregulation, the Commission agrees with the commenters that such a requirement would be-overly bitrdensome. However, given the proposed definition of " electric
- ' utility" cin this action, any licensee.no longer overseen by a rate-setting regulatory authority, i.e. ,' a licensee other than an electric utility, would need to comply with the decommission b3 funding assurance requirements of
-l50.75(e)(2)'. The options contained in that section include prepayment, an external sinking fund coupled with a surety method or insurance for any 7
-unfunded balance; or;a surety method, insurance, or other guarantee method.
The timing--of the-rulemaking was addressed;in the response to comments in section A of this notice. ' Any additional rulemaking in tais area would -result-from experience-gained from industry and regulatory actiont As several of ,
.the;commenters stated, the-NRC~has the authority to approve or disapprove ahy transfer of license:related to a merger or reorganization. Se-tion 184 of the l
Atomic Energy Act of 1954, as amended,.and 10 CFR 50.80 provide that'no l license-will be transferred, directly or indirectly, unless the Commissioni i consents to such transfer in writing. The regulations do not explicitly impose joint liability on co-owners
;and co-licensees. --As stated by some commenters, joint liability may create-
-problems with' respect to potential ' disagreement on decommissioning methods,
-the. inhibition'of flexibility, the weakening of competitive position, and the difficulty in implementation. Also, as some noted, joint liability may not be l' needed. The new owners and operators sho'uld assume the obligation as they have the incentives to properly manage and operate.the units. More i importantly,-however, is the fact that with the proposed definition of
'" electric. utility," non-utilities.would be' required to provide the types of up-front assurance described in 1 50.75(e)(2) and utilities would have-the funding assurance provided through being rate-regulated under 5 50.75(e)(3).
The Commission cons n'ers this level of assurance to be adequate and therefore sees no 'need to impose an additional regulatory obligation of joint and _ several liability on co-owners or co-licensees.
- Lastly, with respect to the question-of impacts, the Commission has considered the comments relating to potential impacts in arriving at the positions taken. The-Commission anderstands that financial assurance would
place:a burden on-licensees that may_ affect their competitiveness in'a;
-deregulated environment.- -The Commission has-chosen-to take an approach that' would create no additional financial impact over present regulations' for
~
electric utilities and has also expanded the definition of electric utility to accommodate types of rate. regulation not previously anticipated. There are'
-also sufficient existing options to demonstrate financial assurance for non-
- electric utilities. Entities without adequate financial capital may find It difficuit to both finance up-front decommissioning funding and operate a-7
-nuclear- power plant safely. - Such. companies may not be good candidates for nuclear power-plant ownership: _The Commission = weighed the factors and
'~ ~
' determined-that financially qualified entities should b'e'all' owed to operate nuclear power plants and as a result the Commission proposes this rule.
C.4 Financial Test Qualifications About half the commenters flatly opposed requiring licensees to demonstrate financial _ assurance by satisfying minimum standards of net worth, _ cash; flow, or other financial measures.
~
Many'of the concenters, including NEl' and four commenters who adopted the NEl-position, argued that such a test-was not necessary or appropriate, if NRC is concerned about the financial condition of a particular licensee,
# three .commenters1said, an individualized case-by-case review would be more appropriate. . Some commenters said that finar.cial- measures appropriate for investor-owned utilities would not be useful for cooperatives, or for utilities that do not have parent companies. Because generation and
- transmission-companies typically are highly leveraged, with many of their 1
assets in the nuclear generating facility, they cannot meet a test with a
m
-tangible net' worth requirement'of ten times the current deccmissioning costs,
--but this-does net mean that they.-cannot satisfy their financial obligations. j
~
- A non-bypassableLcharge was _ suggested as=an alternative.
Some commenters suggested that_NRC should adopt more than one alternative test,. none of which would be mandatory. Any-alternative adopted-
-should be consistent aniong owners, and should not' discriminate against onc :
class 'of owners, and should not be applied as a static one-time requirement. Other suggestions 11ncluded a r quirement that a-firm demonstrate that it had
'" ample margins, subsequent to rostructur_ing" to cover-funding contributions or 'to cover decommissioning costs-in the event of a premature shutdown. Another ' suggested dis' closure standards; developed' throi16 tIIe Financial Accounting Standard: Board,--for use in- annual: reports and 10-K filings, that would be reviewed by Federal- regulators. Still another argued that measures of market value and cash-flow, rather than net worth, were appropriate in _a competitive environment, -and that the ratio of available cash: and cash equivalents to
- unfunded decommissioning requirements would be the best measure of ability to
-support decommissioning,-aiong with an assessment of the utility's competitive situation' -- Determining whether -a utility had minimum cash flow sufficient to maintain its plants in a non-ooerating, interim stage ; prior to-
. decommissioning, and the period--of time the utility could sustain such casu
-flows, was suggested by one commenter, c0ne commenter suggested using a financial test as. an indicator, from
~
which a-Federal' agency could determine- that the utili_ty needed assurance of continued rate recovery of the decommissioning obligation. Only two commenters endorsed a test of financial stability as a financial = test qualification. One pointed to assets sufficient to fund an
?immediate'decommit sioning,ior a minimum level of financial stability. (measured 1
--through-investmentgrade-~seceitjes)orinsurance,or--asuretytocover
~
-decommissioning costs as three potentially acceptable mechanisms. The other ]
1 1 approved of parent or self-guarantees, but noted that _ generators with nuclear - facilities might~have_ difficulty meeting the financial test criteria', including the-investment grade bond rating requirement. i l i Response. IWith the_ proposed revision of the definition of " electric utility," l ' licensees who no longer meet the new definition will need to comply with the requirements 'of i 50.75(e)(2), which describes the acceptable methods of- , fiNaYcial' assurance for decommissioning for a license'e other than an electric utility. These methods are flexible and contain at least four major
- categories' of acceptable funding for decommissioning as ident)fied in the previous response. Few commenters effered insights on other potential test
. qualifications, although several stated that the financial structure of utilities-means- that. the criteria in -10 CFR Part ~30 could be problematic. The NRC would need to conduct additional research and analysis to dete'rmine which additional financial measures would be most useful and appropriate if a-
' financial-test requirement for self-guarantee were pursued. Criteria could be identified- and thresholds developed, but evolution of the industry might mean
- that the criteria would become outdated and misleading relatively quickly.
Hence, the Commission does not plan to pursue this issue at this time. C.5 PUC/FERC Certification Only two.commenters gave unequivocal support to the idea of requiring PUC/FERC certification. One encourard NRC to undertake-direct dialogue on w s. certifications with the appropriate PUCs and FERC; the other stated that PVCS and FERC must undertake such certificatici and that NRC should impress upon
-them the importance of doing so. A few PUCs, in-the opinion of onis d
commenter,-such as California and New York, had already recognized the need to
-provide this assurance during restructuring. Two other commenters expressed-optimism that State regulators would resolve the decommissioning funding problem in the transition to competition, with or without cartification, but ;
I L one went on to say that certification would probably be unnecessary.- Of-L
-these, six adopted the NEI position, which was that without new. Federal legislation it would be difficult to require _ legally binding certification i from PUCs or FERC. Requiring a licensee to obtain such cert'ification would place it in noncompliance, with no way of achieving compliance. -If a licensee did obtain certification, however, NEl suggested-that it be allowed to satisfy the financial assurance ' requirements using that. mechanism.
Two commenters opposed to certification argued that it would be counter-productive because the utility would have~no incentive to maintain. adequate decommissioning funds. .NARUC and several-PUCs either. opposed the idea or expressed strong reservations about it, NARUC noted first that no current
-e - commission can bind :a future commission at either the Federal or State level .
However,;NARUC was-confident that: State PUCs would-examine th. .auses of underfunding,;if it occurred,- and seek remedies. A PUC stated that it might. not hav'e the authority to certify that nuclear plant licensees under its jurisdiction would be allowed to collect decommissioning funds through rates af ter _ restructuring, and another PVC .similarly stated that it _could not give a blanket guarantee that all' licensees would be allowed to collect revenues to complete decommissioning funding. A third PUC stated that no current
commission could legally bind a future commission, so it could not identify an effective form of certification. Another PVC also expressed doubt about how certification would change current procedures, in which PUCs can adjust rates based on the cause for and the prudence of the underfundh,g. A different PUC noted that, in the past, ratemaking authorities had allowed recovery and expected them to act in the future in tte same way, but could not be certain that they would issue certifications. Another PVC stated that it already has and would maintain' authority to ensure that- utilities collect sufficient funds for decommissioning. One commenter pointed out that FERC has jurisdiction only over rates for wholesale sales of power. Over 80 percent of l decommissioning costs are recovered through rates for retail power sales, over which PUCs have jurisdiction. Relying on State regulators would be particularly problematic for multi-State utilities. Another commenter stated that within five years the' issue would become moot and certification would become impractical because of competiticn and evolving antitrust law. A public interest group had questions about whether Puts and FERC could certify, but in' any case thought NRC should concentrate instead on the licensees. Another commenter noted that since- a significant pot'. ion of nuclear licensees' business are not FERC-regulated, FERC certification would have no relevance to them. One commenter suggested procedures through which NRC could interact with State PUCs and FERC; the NRC could determine that a utility's rate of recovery for decommissioning was insufficient, and that determination could be the basis.of an action by a PUC to modify the rates. The final set of commenters argued that the question of certification was one that the PUCs and FERC should determine.
Response. The Commission sees no need to implement certification by the State PUC's or FERC because of the reasons given in many of the comments outlined above. Especially problematic is the case that a current utility commission cannot bind a future utility commission on an action such as this. C.6 Impact of Accelerated Funding , 1 Only a small number of commenters supported the idea of accelerating ' funding of decommissioning costs. Two expressed general support. Two provided quantitative analyses that suggested that the impact of accelerated I funding would not create a large financial t;urden on either licensees or ratepayers. The Public Utility Commission of Texas reported analysis for three T'"'as plants that suggested that, for a ten-year recovery period, electric base rates would need to be increased by about 0.5 percent and the fund earnings would be increased by about 50 percent. For a five-year recovery period, rates would increase by about 1 percent; total life-of-facility contributions by customers would be decreased by about 55 percent, in addition to arguments that the burden would not be great, another argument-made in support of accelerated funding was that, after funding was completed, the licensees who had paid up thir decommissioning funds would be in a better competitive position. Commenters also argued that earnings from the accelerated funding, because they would have a longer time to earn interest, would grow substantially and provide a gain to the licensees that they would not otherwise obtain. Licensees both supporting and opposing accelerated fundina noted that \- unless the Internal Revenue Service changed its rule on the deductibility of payments into the decommissioning trust fund, the accelerated payments would
..a , . . .
_.not be deductible. The NRC was urged to' encourage the IRS to change the rule
~
-;Almost-three-quarters of the commenters opposed accelerated funding of 3 decommissioning. Their: arguments:against the idea.stressea (1) that it would adversely impact the competitive situation of nuclear licensees and (2) that it_ would be inequitable because the amount that each plant would have to-1 I supply--in an accelerated payment would depend on the age of the pient and the amount it had previously paid in the its decommissioning fund. The financial l , -marketplace, rather than regulation, should determine the. speed with which funding is provided. -Accelerated funding, in the view of some commenters, could not be accomplished through rate increases and would have to be paid by licensees' stockholders. One commenter argued that utility shareholders should bear the burden of decommissioning costs, but would not do so under accelerated funding. Other commenters argued that accelerated funding would shift the costs of decommissioning onto current ratepayers from future-
-ratepayers. . Commenters believed accelerated funding would lead:to cash flow l problems for licensees and could result in increased borrowing;to cover cash <
outl ays. Accelerated funding could lead to the shutdown of marginal facilities, which would be. contrary to the intent of thel policy and lead to additional shortfalls of. decommissioning funding.- One commenter argued that the amount of decommissioning funding that will ultimately be. required is too uncertain to be collected through accelerated funding. o
= Response. The Commission does not-see any need to require accelerated-funding and agrees with the comments of those who-oppose such action.-
_ 34 _
1 [-
. C.7 L PotentialLShortfalls from Underestimates of Costs Commenters suggested a range of responses to decommissioning shortfalls) occurring as many as 50 years into the_ future, after-a period of safe storage.
l
- None, however, clearly identified a source of funding to make up the shortfall.
NEI and eight additional commenters argued that there is a reasonable-probability that future cost estimates could-decrease rather than increase because of 'several factors, including accumulated industry experience,- application of 'new technologies, and reductions in the ultimate disposal
= volumes of decommissioning wastes. They also suggested that periodic
~
re-estimatesofdecommissioningcostsandacjustmentstotherateof collection-to reflect these re-estimates, both during operation and ;in the
. post-operation phase, could resolve the problem.
Several other commenters emphasized solutions that involved cost ,
. estimates. One-PUC suggested that the NRC shou'id allow utilities to use State-required facility-specific cost-estimates if.they were higher than NRC:
estimates = Two others suggested that-NRC should review cost estimates every ifive years, with more frequent-reviews-as license termination approaches. The-Utility. Decommissioning . Group predicted that. shortfalls would be unlikely to arise suddenly or'to b'a drastic. Two utilities also suggested that periodic reviews of cost estimates, coupled with incr_ eased collections as necessary, Jwould remedy underfunding. Two other commenters made only the general statement that current procedures would. be adequate, and any--shcrtfalls should
.be handled through' appropriate fundina mechanisms.
--Some commenters recognized that the problem of underfunding arising afte' the. safe storage period cou'd be serious. One public interest group did-not;suggest any_ remedy,- stating.only that NRC could be virtually certain that
-the: funds accumulated for decommissioning would be insufficient. A utility:
suggested that the_only salution would be to delay decommissioning activities I
.to-allow the decommissioning fund to. accumulate additional earnings and to
- modify the decommissioning. plans to reduce cash flow needs. Another suggestion was that NRC-could require every licensee to adopt an investment strategyLthat would ensure that the decommissioning fund earned.at least the rate of inflation measured by-the CPI, and that NRC could require the utility l
l ' to; place-additional money into the-fund if necessary. Several commenters recommended approaches to the_ problem that involved =- 4
^
PUCs. Two suggested that-underfunding would be remedied by application to the '" PUC. One suggested such PVC involvement would occur after the shortfall was-identified,-- the other suggested that PUCs would take potential shortfalls into account prior _ to utility restructuring 'and that-the shortfall would not occur-L: until after several-years of competition. This commenter suggested that a wires charge-'could be used to ensure that such shortfalls:did not- occur. Three commenters said that NRC should intervene with State PUCs to ensure'that shortfalls do not occur,- either immediately or when-the underfunding was recognized. A few commenters argued that the causes of the shortf all should be . identified. -If the plant's management was- responsible, the additional decommissioning' costs should be recovered from stockholders. NRC- could require additional contributions if the invested decommissioning funds are
' insufficient. LAlternatively,_if the utility management is not' responsible, customers'should bear the additional cost. 'However, as one PUC noted, underestimates that are not identified until far into the future could become a- social problem. - If the underestimate is not identified until after the
=
plant is removed from service, no ratepayers will be required to provide additional funding. If the company still exists and is solvent, shareholders may be held accountable, but only to the point- of insolvency. Gross underestimates could very well bankrupt the company and place a significant burden on regulators and legislators to step in to fund completion of the decommissioning. None of the commenters recommended increasing contingency factors to provide for potential shortfalls far in the future. Several argued that contingency factors are intended to address "unfor.; seeable cost elements" or that contingencies are-inappropriate for some other reason. The size of such
~ ~
l contingencies would be tco arbitrary, ln additio E some State PUCs would not apply larger contingencies, p.rticularly since the current cost estimates already contain a significant contingency factor. Finally, one commenter argued that larger contingencies would lead to over-collection and distortion of_ prices for electricity. Seven commenters joined NEI in taking a position against-the use of contingencies to address the problem of potential shortfalls occurring far in the future. 4 i Response. .The Commission sees its proposed reporting requirement as a way to keep informed of licensees' decommissioning funding status and potential underestimates of cost. However, the Commission has undertaken a study to analyze the actual costs incurred by the power reactor licensees that are in the process of decommissioning, and the Commission will act accordingly after studying those results. Further, the Commission has the ability to require power reactor licensees to submit their current financial assurance mechanisms for NRC review, revision as necessary, and approval.
C.8 CaptivAInsurancePool-The11 dea of setting;up a captive insurance pool to pay unfunded decommissioning-costs did not obtain' strong support. A few commenters endorsed it, with qualifications. One said t' hat, in fact, the mechanism would -
- more nearly resemble a mutual _ insurance pool, and listed a--number cf factors.- I including the size of premiums, when deregulation occurred, Federal mandates, the abilits to recover costs, and the; attitude of participants, that would
! determine . success. Several commenters responded that if such a pool could be
~
1
-developed,;it would a useful or constructive mechanism. -i NEI and six commenters taking the same position expressed doubts about thelefulnessofsuchapool,butsuggestedth'attheindustryshouldexamine it. They argued that in addition to an insurance pool, NRC should also
_ consider approving self-insurance as an option. i Almost half the commenters expressed strong doubts' about the insurance
' concept. .No such product currently extsts, and insuring against shortfalls in funding a known and~ planned- event would be a- novel concept, open to problems of adverse selection and moral hazard'. - Some commenters said it would be
-difficult to underwrite, and wondered whether in a competitive-environment-one company would be interested in supporting the financial' obligations of its
'"If the risk of the insurable event varies between potential buyers, if the buyers know their risk level better than the insurer, and if the coverage isinot-mandatory, thenithe worst risks w;11 tend to buy the most insurance.
As-a result - the loss experience will tend to be higher than expected,
- premiums will-increase, the:best risks will leave the-programs, and the process can cycle on itself unti_1 only the worst risks are left." This
-phenomenon is known as adverse selection. Moral hazard is defined as.a .
general laxity in loss prevention, laxity in cost control,Jonce 'a loss has occurred, and the intentional destruction of property. U.S. Nuclear-Regulatory Commission, " Design, Costs, and Acceptability of an Electric Utility Self-Insurance Pool for Assuring-the Adequacy of Funds for Nuclear Power P,lant Decommissioning Expense." NUREG/CR-2370, December 1981. competitors. A cross-subsidy of this sort, one said, was what deregulation was being undertaken to eliminate. Participation also might be affected by the policies of individual State PUCs. Premium setting would be difficult ; 1 because of the possibility that utilities that had been prepared to pay their l decommissioning costs would be reluctant to subsidize utilities that had nc+, and because premiums, to provide sufficient coverage, might need to be large. The pool could face the problem of motivating utilities to close plants when it would otherwise not be economic to do so, or motivating State PUCs to disallow the recovery of decommissioning costs through rates in reliance on the pool. Some utilities might underestimate their decommissioning costs, to keep their premiums low. A pool would incrdse costs of electricity because, in addition to decommissioning costs, insurance premiums would need to be recovered. Finally, one serious decommissioning shortfall might deplete the l pool. Other commenters stated flatly that they opposed the concept. Several said that it raised the problem of insuring against an ever.t that a facility could choose to create (the moral hazard problem). An insurance pool would create, at the least, an incentive for less responsible utilities to underfund their decommissioning assurance, burdening responsible utilities with high insurance premiums. Some commenters argued that-licensees demonstrating strong financial capability should not be required to participate. Reinsurance and diversification to larger pools would make better policy, in the. view of one commenter. Response. The Commission recognizes the problems associated with the concept of a captive insurance pool as tentified by the above commenters. Any one of
. _ . . _ _ . - _ _ _ _ _ - _ . . ~ _ . _ . _ __ .. ..-___ _ _ _ . _ -_
[ I the identified problems-is serious-enough to eliminate:this option from ,
< further consideration.-- The Commission is also of the' opinion that those _in: 2 LfavorLof this option do not-offer sufficient evidence that~the identified" 2
problems can be overcome.:
- C.9 Other Options for NRC in Case of- Limited Role for PUC or FERC'- -i Commenters suggested a wide variety of financial assurance options for-
-NRC to consider _if.PVC or FERC oversight is limited or eliminated. :0ne.
utility suggested-that financial assurance requirements should be focused on:
'the financial viability of the responsible entity. Other utilities suggested,-
~ "
- 'as nonregulatory showings, self-guarantees or other _ tests of-financial strength such'as ownership.of other revenue-producing' assets (e.g.,
c
-electricity transmission--and/or distribution' and/or natural. gas operations).
= Another relevant factor could be whether the licensee has insurance for
- premature decommissioning _ caused-by an accident. One commenter stated-its-opposition-to the.use ofhsurety: bonds and insurance.because of cost and ilimited availability.
Two utility commenters suggested that- regulatory approaches include mandated or allowed stranded cost recovery through a charge on distribution or
'tru.smission or- some ;other charge on all electric' power or energy sales, _
regulatory certification that such costs will be. recovered, and other 1 arrangements involving regulatory control such as. priority dispatch for-nucle'ar units; : Another _commenter suggested that NRC could request FERC to ' clarify Order No. 888 to make certain that competitive access or other-i transmission charges intended to. recover- stranded costs also include a load
.. proportionate contribution to fur.d decommissioning costs. Another commenter
stated that NRC and FERC should urge Congress to adopt stranded cost legislation that will ensure recovery of decommissioning costs as the most prudent solution. The commenter specifically advocates a wires charge that would include decommissioning costs. , One commenter asked NRC to consider its actions in the event that a _ licensee enters into bankruptcy. 11. such a case, the NRC could enter the proceeding and argue that full funding for decommissioning must be fulfilled as the first priority. The commenter also asked NRC to consider proposing legislation that would amend the Bankruptcy Code to give first priority to nuclear decommissioning costs, as the Supreme Court has already held for l hazardous waste cleanup costs. l l NF! and several other commenters raised the possibility that NRC could 5 rely on the Financial Accounting St'andards Board's (FASB) financial disclosures for information in assessing the nature, timing, and extent of the company's commitment of its future resources. According to one commenter, NRC should evaluate each utility's particular situation on a case-by-case basis to . determine the degree of assurance needed depending on the financial strengtt. of the utility, the size of the remaining unfunded obligation, the age of the plant, and other f actors as may be appropriate to the specific situation. Another believes NRC could retain control through licensing constraints and financial evaluations made when NRC approves transfers of assets and licenses. A number of utilities commented that NRC need not identify all options immediately, but could ultimately authorize a. number of alternative
'The Financial Accounting Standards Board is a private body that establishes authoritative financial accounting and reporting standards in the United States.
b approachesJeither based on 10 CFR 50.75 or on options;that'have not yet-been recognized._.A.PUC commenter asked NRC to work;collaboratively with States to explore, as.-necessary,- alternative financial assurance meunanisms in the event that privately owned nuclear-generators are no longer regulated. One.commenter suggested that NRC's' support-for' existing Federal , obligations _ to provide a national nuclear fuel repository _ would also i
. contribute to the financial assurance of resporsible nuclear decommissioning.
L Another called for financial assurance to be mandated = at the Federal level, D 'and a third'said NRC. should consider whether DOE: responsibility can be developed for providing solutions to decommissioning.
-Four commenters said no other options were nec~essary. They reasoned that current options are sufficient irrespective of PVC or FERC_ oversight, regulatory oversight is unlikely to be curtailed, and FASB standards' and competitive pressures will provide' sufficient assurance.
Response. The Commission agrees with the last four commenters who said no other_ options were necessary and hence 'no modification to the regulations is trequired onlthe Commission's part because of these comments. The Commission
- believes that the proposed change to the definition of " electric utility" will
- be adequate to address all- contingencies with respect to financial assurance
- for_ decommissioning under' deregulation. - Further, the proposed reporting ' t requirement will provide the NRC with- the opportunity to be informed on the status 'of licensees'; financial assurance for; decommissioning.
l l D. Federal Gcvernment Licensee tise of Statement of Intent
. Slightly fewer than half of the commenters (20 commenters) expressed an opinion on this question. Almost all commenters took the posit bn that Federal licensees should be treated in the same way as non-Federal licensees.
NEl argued that regardless of who owns the plant, a number of options for i financial assurance should be allowed, and the current options should continue ( to be permitted. One commenter stated clearly that because Federal licensees were expected to face the same problems as other licensees, they should be required to act aside funds rather t!. rely on statements of intent. Several commenters pointed out that different treatment fe Federal licensees could create competitive advantages for the Federal licensees. NRC should ensure that the playing field remained level. One licensee argued that if a j financial assurance option, such as a statement of intent, meets NRC's criteria, it should be available for use by all licensees. Others took the position that the statement of intent should not be allowed, because it does not provide any assurance. Its use by Federal licensees maans that the taxpayers are providing the assurance. One licensee questioned the long-term financial condition of TVA. One commenter argued that use of tax exempt bords provides a similar competitive advantage to those licensees who can issue them. Only TVA took the position that ample reasons exist for continuing the use of statements of intent as provided under the current regulations. However, TVA also provided an extended description of the steps it has taken to use an external trust, "all requirements" contracts, and its power to issue indeb'.edness to ensure its decommissioning costs.
% _.+
I Response. The NRC's Office of the Inspector General published an Audit Report, *NRC's Decommissioning Financial Assurance Requirements for Federal Licensem. May Nct be Sufficient," OlG/95A-20, dated April 3, 1996. The report l' found that "...NRC's decision to allow Federal licensees to use a statement of l intent...was based primarily on the assumption that the Federal Government would pay the financial obligations of the lone Federal licensee....should it 1 be unable to do so. However, based on our review of the U.S. Code and i j discussions with officials from the Department of the Treasury, the Office of Management and Budget and TVA, we believe NRC's assumption is questionable." The report also found "...that, although not required, TVA has established a fund dedicated to meet its decommissioning'obTigatioris~. However, because this is an internal fund it can be used fer other purposes. In fact TVA had at one time temporarily depleted its decommissioning fund." While the majority of those who commented were opposed to allowing the TVA's use of a statement of intent, their reason was basically that all licensees should have the same " level playing field." This argument and those relating to economic regulation in general do not fall within the Commission's purview. Further, the Commission does not believe that the alimination of the statement of intent option can be justified as its elimination would result in an undue burden without any commensurate improvement in public health and safety. The Commission believes thst the risk of a Federal licensee not being able to fund its decommissioning expenses is remote. The Federal licensee has an exclusive franchise that guarantees revenues from the sale df electricity for the foreseeable future. Should the Federal licensee have future financial difficulties, it will still have substantial revenues from its sale.of x
I electricity from other than nuclear sources that may be used for
~ decommissioning. Hence, the Commission does not propose _to eliminate the j statement of intent as an option for federal licensees. l f
E. TRUST FUND EARNINGS CREDIT FOR EXTENDED SAFE STORAGE-PERIOD 3 Two con.menters opposed credits for earnings during extended safe ; storage, arguing that earnings assumptions could be manipulated and that . : i earnings could otherwise act as a hedge against increases in the cost of 2
, decommissioning. Seventeen commenters 'however, supported allowing credit for .l
- earnings on funds during extended storage periods, Some of these commenters
~
argued that'if credits for earnings'are not alloweE more funds than necessary would be collected, thereby generating unwarranted expense for licensees and i customers and possibly intergenerational inequities, An additional eight commenters supported allowing earnings credits, not , only for the extended safe storage. period, but also for other periods. l e The period before safe storage, when funds are. accumulated; e The decommissioning period, when funds flow out of the trusts; and , e Both the accumulation and outflow periods. ;
~
'Three commenters expressed the opinion that States should decide whether -
or not to allow credit for projected earnings. One group of commenters understood that NRC's ANPR considered a net i positive rate of return when assessing the status of decommissioning funding ; l, durina a SAFSTOR oeriod, and not that_a licensee would be allowed to consider prospectively durina tne license term the possibility of a net positive rate ; i of' return over some extended period following shutdown and prior to actual j i decommissioning. These commenters felt that it would be largely irrelevant to - i l
- _ . . _ . _ . . _ ~ - - - . . _ . . - - _ . _ _ _ _ - . . _ . . . _ . . . ..._ .___ _ ._ _ _ _ _
start considering positive earnings during a SAFSTOR period because, >y the time of termination of operations, licenseet should have already acctmulated sufficient funds to pay for decommissioning. Another commenter disagreed with the position that excludes the benefit of future tax deductions (i.e., in "non-qualified" trust accounts) in determining the adequacy of a licensee's decommissioning funding program because the deductions will have value for whomever assumes the responsibility for decommissioning. Fesponse. The Commission is proposing to allow credit for earnings and be17evesthatitsexistingimplicitassumptionofazerorateofreturnistoo conservative and not borne out by the data. The Commission is proposing licensees may take credit using a 2 % real rate of return from the time of the funds' collection through the decommicsioning period, As stated below, this proposed action provides licensees relief from current requirements that have no adverse impact on public health and safety, licensees, or NRC resources, and the proposed reporting requirements would allow the licensees' decommissioning funds to be monitored by the Commission. E.1 Real Rate of Return Five commenters took the position that NRC should not specify a single allowable rate of return, but should allow licensees to take credit for any rate they can justify given their specific situation. Some of these commenters supported their positions by stating that licensees employ different investment strategies dep:nding on factors such as the number of plants, when they expect to begin decommissioning, applicable State taxes, and m-
whether the funds are in a qualified or nonqualified trust. Another commenter suggested that plant-specific annualized rates could be justified based on historical data. Considerable judgment will be needed to develop the ratc. argued one utility group, but no more judgment than is needed in developing decommissioning cost estimates. Three commenters suggested that NRC use long-term, historical rates for the asset allocation employed, adjusted by the long-term, historical inflation rate. Six commenters stated that NRC should not specify a single allowable rate of return, but should define the basis on which licensees may select an appropriate positive real rate. Four commenters expressed the view that States should decide the rate, and a fifth commenter thought either States or FERC should decide the rate. Another commenter thought the rate should be determined by an (unidentified)
" acceptable third party."
One commenter suggested an after-tax iate of 3 percent as reasonable and achievable with acceptable levels of investment risk (e.g., 50 percent equity. 50 percent fixed income). Another commenter proposed a rate of 3 percent because that rate is the historical real return on Treasury bonds. One commenter felt NRC should float the values based on contemporary 30-year Treasuries. Two commenters opposed the use of a positive rate assumption for earnings during extended safe storage, arguing that earnings assumptions could be manipulated and that earnings could otherwise act as a hedge against increases in the cost of decommissioning.
,47 -
Response. The Commission proposes to use a 2 percent real rate of return throughout the decommissioning collection period as a default earnings amount and in the safe storage period as a specified amount. Given that historically, real (i.e., inflation adjusted, af ter tax) rates of return using U.S. 1reasury issues have been around 2 percent, the Commission proposes to ! allow licensees to use this rate in their calculations. While some may pripose use of a higher value based on other types of investments, the s.s -ission believes the proposed value retresents as close to a " risk free" return as possible. Higher earnings amounts will be allowed during the period of reactor operation if specifically determined by a rate-setting authority, if rates turn out to be lower than this 5 50 A2"already provides that licensees are to adjust decommissioning funds during saf e storage to reflect ( I changes in cost estimates. Thus, there is little risk that there will be major shortfalls in decommissioning funds. Further, the proposed reporting requirements will allow the licensees' decommissioning funds to be monitored by the Commission. E.2 Appr_opriate Time Period Twelve commenters expressed the view that credit for projected earnings should be allowed over the full length of the extended safe storage period. An additional eight commenters also thought credit should be allowed for earnings projected over additional periods:
- The period before safe storage, when funds are accumulated, e The decommissioning period, when funds flow out of the trusts, o Both the accumulation and outflow periods.
Two more would allow commensurate credit for a period with site-specific schedules for funding and decommissioning. Another commenter noted that considerable judgment would be needed to determine the appropriate time period, but no more than would be needed to develop the decommissioning cost estimate. Four commenters, all PUCs or PVC groups, felt NRC should leave the j issue of the length of the period to the States. l l l Only two commenters sugge:ted that credit be limited to a fixed number 4 of years. One of these suggested 10 years. ' The other proposed a maximum of 20 years, and a minimum 'of 5 yea'rsr 8 ' ;.
' ,s.
.- Two commenters opposed the use of positive earnings assumptions during !
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1 e any period, arguing -that earnings assupp't'io'n's could be manipulated and that !
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- =** Jarnipgs could'6thfrwise act-as a hedge.agaiiEs;, t increases in the cost o'
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Response. The Commission proposes to allow licensees to take credit for earnings on external sinking funds from the time of the funds' collection
'# Because'the NRC is requiring the funding, through the decommissioning period.
it is appropriate foF tha NRC to provide for a positive rate of return on the collected funds. Further', the NRC is proposing a longer period in which credit should be allowed for earnings .because the justification for allowing a positive rate.of return over the safe storage period also holds for allowing credit from the time of fund collection through the decommissioning period. Again, the proposed reporting requirement provides the NRC with.the ability to monitor licensees' decommissioning ftinds. Lastly, this proposed action providesikcenseesrelieffromcurrentrequirementswithnoadverseimpacton pub 1'ic heal't h and 'skfely, licensees, 6r?NRC resources.
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l' F. REPORTING ON THE STATUS OF DECOMMISGIONING FUNOS Many commenters supported a reporting requirement in light of concerns
---about decommissioning funding. Some of these felt that NRC should require
___relatively comprehensive reports because NRC's- authority extends beyond that of.FERC and the States, and because FERC and the States do not always require uniform information to be submitted at regular intervals.- One commenter
-stated that an NRC regulatory amendment is needed even in the absence of Lderegulation to correct the flawed assumption that PUCs and FERC actively-monitor decommissioning' funds.- The commenter stated that PVC and FERC monitoring efforts are, in most cases, limited in scope and may take place
._ ' ^
_infr'equently (i.ec, wh'en a rate caseTis filed). ' EEn PVC is generally concerne:! orilj abtfut'h itslurisdictional portion of the decommissioning funds, and FERC'ijurisdiction=is limited to only the wholesale portion of a ; company's sales. Moreover, many States do not have jurisdiction over 4 municipal and cooperative agencies, some of which are owners or partial owners of- nuclear plants. Therefore, the NRC may be the only regulating agency that can provide!an effective and timely monitoring function for all the funds
-required for decommissioning.
Three commenters opposed a reporting requirement as unnecessary, while two ~others believed such a requirement _was premature and could conflict with or be duplicative of information that may-be required by forthcoming FASB standards. Two commenters stated that NRC requirements should not duplicate
~
-requirements of States or FASB. Lastly, a commenter stated that if PVC oversight.is limited or eliminated, NRC should assume oversight of
- decommissioning funds.
e
Response. The Commission is proposing that a periodic reporting requirement be implemented so that the Commission has appropriate assurance that licensees are collecting their required decommissioning funds. The benefits of obtaining this information through a reporting requirement, in terms of both determining licensee compliance with NRC decommissioning funding regulations and responding to Congressional and other requests, outweigh the minimal impact of the requirement and would be less burdensome to licensees and the NRC than relying on the existing NRC inspection process. F.1 Contente Three commenters stated that reporting requirements would be unobjectionable if they were minimal and limited to material of the nature historically provided to State regulators or in other financial reports. Similarly, others stated that NRC should rely on the same information as will be required by the proposed FASB statement regarding accounting for certain liabilities related to closure or removal of long-lived assets. Fivc, commenters agreed with the NEl that reports should be kept as simple as possible. One commenter stated that comprehensive reports should be prepared for each facility, integrating information for all owners. Thus, if a facility has multiple owners, one consolidated report would be prepared with , separate data for each owner attached. On the other hand, one commenter argued that reports should be based on the licensee's interest in the nuclear unit and not on a total unit basis. 4 One group of commenters stated that NRC could make the annual reports from plant operators available tn the public, which would be consistent with the availability of information required under prooosed FASB standards.
l A PUC stated that New Jersey's reporting rules may be adequate for NRC's purposes. Suggested contents for the reports included 50 items under ine following general headings: Decommissioning Costs and Activities Contributions, Trust l Status and Activity, Other Financial Information, and several Miscellar.eous items. 4 Response. The Commission is in the process of issuing a draft regulatory guide on this proposed requirement wiiich would endorse FASB draft standard No.158-B, " Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." The NRC is endorsing this draft FASB' standard as a means of providing guidance for licensees to comply with those portions of the Commission's regulations regarding a licensee's reporting on the status of its decommissioning funding. Licensees would comply with the FASB standard once it becomes final in order to remain consistent with generally accepted accounting principles. The NRC has reviewed the proposed contents of the reports on decommissioning funds to ensure that the needs of the agency are balanced versus the time constraints of the licensees in assembling them. F.2 Frequency Several commenters stated that licensees should report on the status of decommissioning funds on an annual basis. Others believed reports should be required no more frequently than annually. NEl stated that NRC should not require licensees to' report on the status of their decommissioning funds any
I 1 more frequently than every 3 to 5 years. NEl noted that SEC rules and proposed FASB standards require utilities to disclose the decommissioning costs in financial statements. Two commenters suggested reporting at 5-year intervals. One of these suggested that interim status reports could be required on an annual basis. l One commenter stated that NRC should require no more frequent reporting j beyond FASB requirements. Another commenter stated that reports should be no less frequent than specified by the Securities and Exchange Act of 1934.
-One commenter suggested that NRC consider more-frequent reporting for plants approaching the end of commercial operation and for plants experiencing
~
operating problems. One commenter stated thaIIh'd tinit'ng of required reports should parallel that of other reports such as FERC Form 1, SEC 10-K, and annual financial reports. Similarly, two commenters felt that annual reports should be caused by NRr by September 30 of the following year. Two commenters stated that interim reports could be required for significant events (e.g., merger, acquisition, financial deterioration). This commenter also suggested that limited or negative s owth of the fund in a given year due to overall market conditions should not automatically trigger adju nents to funding levels but rather that a 3- to 5-year time frame should be used. Response. The Commission is proposing that every licensee submit its report on the status of decommissioning funds to the NRC at least once every 3 years. Annual submission is not t,eing proposed as an option because the NRC believes it can adequately review licensee financial assurance status for decommissioning triennially while reducing licensee reporting burden.
_ _ . . _ . . . . _ . - . _ . _ - . . _ _ _ . _ . _ __._____._.._..__.__.m... J *I However,-any plant that is within 5 years of its planned end of operation t t would submit-its report ~ annually. i
- G. COMMENTS ON TOPICS NOT SPECIFICALLY RAISED IN THE ANPR !
Commenters suggested several' actions tha't NRC had not asked about specifically in-the'ANPR. First, a commenter stated that NRC should require 1 i
-sites to be decommissioned to " green field" status, consistent with FERC-
- guidelines. i Response. The Commission's position is that once radioactive contamination of the reactor facility is removed to a level acceptable to the NRC, there is no 1
longer a health and safety concern preventing the NRC license from being terminated. A commenter suggested the imposition of a mandatory insurance requirument for licensees to cover fund shortfalls at the time of premature-
. decommissioning in States where accelerated collection from ratepayers and 1
'intergenerational subsidies are not allowed. .
Response. The-Commission does not agree with the commenter on the need for mandatory-insurance. As stated in the response to comments on Stranded Costs, Section B, the previously referenced "Draf t Pol' icy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry" . stated that the NRC has the authority "to take actions that'may affect a licensee's-financial situation when these actions are warranted to protect public' health and safety." The.Commi.sion believes that there are enough
- 54 - .
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- - . . _ ..__.a..,_.,:.
._ . . _ _ _ _ . . _ . _ ~- .. - --
-l i alternatives available to address the potential problems caused by premature : i decommissioning so that mandatory insurance would not be required. ! i I 4 I One commenter stated that the requirements for subaccounts should be )
- waived. Their position is that licensees that have contributed monies to-a i
, single trust fund for multiple decommissioning-related purposes be required 3-simply to demonstrate to the NRC that there are or will be sufficient assets - i
- in the_ trust . fund, in _the .aggreghte, to pay for= the NRC-defined 3 a _
l decommissioning cost of_the nuclear unit and for any other decommissioning-j _ related purposes -identified in -the: trust agreement. 4 i ' Response. .The Commission is not as concerned'with the details of how a i licensee keeps accounts for decommissioning as much as that a licensee should ; i be able to demonstrate to the Commission the amount'of funds identified and available for the required decommissioning purposes. Thus, the Commission 7 accepts the commenter's position in general, although it notes that there is jl
- no current requirement, only guidence, relating toithe use of subaccounts.
i I A commenter stated that NRC should undertake as a priority task-the identification of nuclear plants that do not perform well. For plants with performance problems, NRC .should take. aggressive steps to persuade the operator to sell the plant to another operator at a: price that recognizes its market value- or to terminate the-license. In some cases, particularly when 9 plants were- financed with bond indentiires or other instruments that limit the t owner's' ability to sell = the plant or impose conditions on such sales, these restrictions would need to be identificd in the process of identifying well-r
- - .2._.-_._._,_ ...-.,._..__.-_.a .2.u,.___,_ ___ . _ _ _ _ _ _ . - , . . _ _ . . _ . . . , - . .._
run plants. Further, the commenter states that if the plant does not produce a price acceptable to the operator, the Federal Government will offer a price that will provide the operator with some fraction of the purchase price and take over control and ownership, including any decommissioning fees that have j been collected. The Federal Government would restart any plant it believes can continue as a source of power and will decommission the others frcm public funds. 1 Response. The Commission does not see its position as being one to be able to force a licensee to sell its plant, neither is it mandated to purchase nor operate nuclear power plants. A commenter stated that the NRC should develop a reliable, sound estimate (or method of estimating) decommissicning costs, and should update the estimates on a regular basis to incorporate technological and other changes. Response. The Commission is planning to revise its estimates of decommissioning costs af ter it obtains more real world" data from ongoing decommissioning projects. ! Another commenter stated that NRC should sponsor technical conferences on decommissioning so the pace of technological resolutions for cleaning up and decommissioning plants could be increased. Response. While the proposed action is not a suggested rulemaking, the Commission is taking the suggestion under consideration. However, the Commission is aware of a number of deregulation and decommissioning conferences that have been held or are being planned. l l A commenter stated that the NRC should ask separately about other i j financial issues because changes to the definition of " electric utility" could have implications in contexts other than decommissioning, such as general financial qualifications reviews for initial licensing and related license amendments, from which utilities are nes exempted. Response. While the Commission is not presently asking questions on other financial issues, it is attempting to address the concerns by proposing revisions to paragraphs of Part 50 to be consistent with the proposed change in the definition of " electric utility." A commenter stated that NRC should delay action as the Texas PVC has initiated three regulatory investigation projects focusing on the restrutturing and partial deregulation of the electric industry in that State. Further, the State has not developed a formal policy on many of the issues set forth in the ANPR. Response, it is because of the number and variety of State actions being proposed in the areas of deregulation and restructuring that the Commission is proposing this rulemaking now. The Commission wishes to prepare for any new
-types of nuclear power generating licensees resulting from the States'
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g .
f actiens. However, the Commission is well aware that this proposed rulemaking will probably not be the last action for the Commission to undertake in this i area. 1 One commenter stated that the Commission should support revisions to Internal Revenue Code i 468A regarding deductibility for contributions to an external fund. Response. This request is not within the Commission's purview. Lastly, a commenter stated that the NRC shouTd hold all licensees to the j same high standard for assurance-of decommissioning funds. Previously, the NRC had one standard for non-utility licensees :nd a much more lenient standard for rate-regulated utilities. NRC must establish strict.and thorough standards for the collection, investment, segregation, and reporting of decommissioning funds and those standards must apply to all licensees, including those that have traditionally been considered regulated utilities. Response. The Commission position is that it is not necessary to impose any additional decommissioning funding requirements on those entities that meet
-the proposed definition of " electric utility " However, as explained above, the Commission believes that those entities that no longer meet the proposed definition will need the more " strict" standards.
i To summarize, the Commission's underlying philosophy of financial assurance for decommissioning is unchanged. Basically, those licensees that remain." electric utilities" by the Commission's revised definition should ' 1
~ folicw the same financial ~ assurance regulations as before. However, with deregulation, the-Commission does not believe tnat it would be able to identify all! he t potential types of licensees to which it will be exposed.
Therefore, new and unique restructuring proposals will necessarily involve ad 1 hoc reviews by the NRC. Further; the Commission will exercise direct oversight of such reviews to maintain. consistent-NRC policy toward'new entities. In addition to-the proposed definition revisions, the Commission is proposing two other modificat .ons. The first is to ' require power reactor icensees to periodically re' port on the status of their decommissioning funds and funding for the management of.its irradiated fuel. Second, the Commission is' proposing to allow licensees to take credit for the earnings on decommissioning trust funds. The' Commission does not see the need to take actions proposed by some commenters that would, in the Commission's view, strain licensees unnecessarily, because of licensees' competing needs. SECTION-BY-SECTION DESCRIPTION OF CHANGES 10 CFR.Pirt 50 Section 50.2 is amended to revise the definition of " electric utility"
;i.n response to deregulation of the-electric generating industry. The section is also amended by.the insertion of definitions of. previously undefined terms 5that. aid in understanding the revised definition of " electric utility."
Sections 50.43, 50.54, 50.63, 50.73, and 50.75 are amended to accommodate the revised definition of "elec+.ric utility" in Section 50.2. Section 50.43 is amended so States are added to regulatory agencies as those entities to which the Commission will give notice of application for a class 103 license for a cc m ercial power gcneration facility. Section 50.54 is amended in paragraph (w) by calling for power reactors, as opposed to electric utilities, to obtain insurance in the manner prescribed. This section is also amended in paragraph bb) to account for the nev reporting requirements. Section 50.63 is amended so that licensees, as opposed to the originally used utilities, are required to be able to provide specific material for NRC review relating to reactor core and associated systems. Section 50.73 is amended to clarify the type of personnel involved in a Licensee Event Report. Section 50.75 is amended in three paragraphs to account for the definitional change in the reporting,and reccrdkeeping for decommissioning planning. Section 50.75 is also amended to allow licensees to take 2 percent credit on earnings for prepaid trust funds and external sinking funds, and to institute a reporting requirement for licensees on the status of their decommissioning funding. Environmental Impact: Categorical Exclusion The NRC has determined that this proposed regulation is the type of action described as a categorical .xclusion in 10 CFR 51.22(c)(10)(i).
i i Therefore, r.either an environmental impact statement nor an environmental l assessment has been prepared for this proposed regulation. 1 Paperwork Reduction Act Statement This proposed rule amends information collection requirements that are subject to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). This rule has been submitted to the Office of Management and Budget for review and approval of the information collection requirements. The public reporting burden for this information collection is estimated f toaverage2hoursperresponse,includingthetide~forreviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the information collection. The U.S. Nuclear Regulatory Commission is seeking put'lic comment on the potential iriipact of the information collections contained in the proposed rule and on the following issues:
- 1. Is the proposed information collection necessary for the proper performance of the functions of the 14RC, including whether the information will have practical utility?
- 2. Is the estimate of burden accurate?
- 3. Is there a way to enhance the quality, utility, and clarity of the information to be collected?
. . - ~ ._. --- -- . . ,. - .. - . . - - . - _ - . - _ .
- 4. How can the burden of the information collection be minimized, including the use of automated collection techniques? ,
l I-Send comments on any aspect of this proposed information collection, f including suggestions for reducing the burden, to the Information and i Records ManLgement Branch (T-6 F33), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet electronic mail at BJS10NRC.G0V; and to the Desk Officer, Office of Information and Regulatory Affairs, NE0B-10202, (3150-0011). Office of Management and Budget, Washington, DC 20503. Comments to OMB on the information collections or on the above issues ! should be submitted by (insert date 30 days after publication in the Federal Reaister). Comments received after this date will ba considered if it is practical to do so, but assurance of consideration cannot be given to comments received after this date. Public Protection Notification The NRC T1y not conduct or sponsor, and a person is not required to respond to, an information collection unless it displays a currently valid OMB control number. l-1 l-l 1
- - - - -~ v
Regulatory Ana', sis The Commission has prepared a dra, regulatory anaiysis on this proposed regulation. The analysis examines the co..s and benefits of the alternatives considered by the Commission. The draft analysis is available for inspection in the NRC Public Document Room, 2120 L Street NW. (Lower Level), Washington, DC. Single copies of the analysis may be obtained from Brian J. Richter, Office of Nuclear Regulatory Research, U.S Nuclear Regulatory Commission. Washington, DC 20555-0001, telephone (301) 415-6221, e-mail bjrenrc. gov. The Commission requests public comment on the draft analysis. Comments on5he draf t analysis may be submitted to the NRC as indicated under the ADDRESSES heading. Regulatory Flexibility Certification in accornance with the Regulatory Flexibility Act _of 1980 (5 U.S.C. 605(b)) as amended by the Small Business Regulatory Enforcement Fairness Act of 1996, Pub. L. No. 104-121 (March 29, 1996), the Commission certifies that this rule will not, if promulgated, have a significant economic impact on a substantial number of small entities. This proposed rule affects only the lf;ensing, operation, and decommissioning of nuclear power plants. The
-companies _that own these plants do not fall in the scope of the definition of "small entities" set forth in the Regulatory Flexibility Act or the Small Business Size Standards set out in ranulttions issued by the Small Business Administration at 13 CFR Part 121.
Backfit Analysis ; r The regulatory analysis for-the proposed rule'also constitutes the documenta' tion for the evaluation of backfit requirements, and no separate backfit analysis has-been prepared. As defined in 10 CFR 50.109,- the backfit j rule applies to " modification of or an addition to systems, structures, l components, or design of a facility; or the design-approval of manufacturing
~
- license for a facility;.or the procedures or organization required to design, const. + or operate a facility...." resulting from new or amended provisions in timmissici rules. Such backfitting can be plant-specific or apply to multiple facilities (" generic backfitting"). l l ~The proposed amendments to NRC's requirements for-the financial assurance of decommissioning of nuclear power plants address generic L
i - requirements. The proposal-would revise the definition of " electric. utility" and add.several associated definitions that are generic in nature; amend
- generically new reporting requirements pertaining to ;the use of prepayment and .
b external sinking funds; and enact generic new reporting requirements for power , reactor licensees on the status of decommissioning funding that specify the i [ timing and contents of such reports. ! The NRC has determined that the backfit rule, 10 CFR 50.109, does not apply to this proposed rule, and therefore, that a backfit analysis is not f- required for this proposed rule, be::u:e these. amendments do not involve any - ! provisions which would impose backfits as defined in 10 CFR 50.109(a)(1). L 4 5 (- e..4.- m..-.. - --,-_--.,ee, . .,.~,..-% .w.-v%-.=e.,, _ . y,w.-,.--.gmn.. .,--=.,,e.y
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i List of Subjects in 10 CfR Part 50 Antitrust, Classified information, Criminal penalties, Fire protection, I Intergovernmental relations, Nuclear power plants and reactors, Radiation _. protection, Reactor siting criteria, Reporting and recordkeeping requirements. l l for the reasons set out in the preamble and under the authority of the Atomic Energy Act of 1954, as amended, the Energy Reorganization Act of 1974. as amended, and 5 U.S.C. 552 and 553, the NRC is proposing to adopt the following amendments to 10 CfR Part 50. PAP.T 50--00MESTIC LICENSING OF PRODUCTION AND UTillZATION FACILITIES
- 1. The authority citation for Part 50 continues to read as follows:
AUTHORITY: Sets. 102, 103, 104, 105, 161, 182, 183, 186, 189, 68 Stat. 936, 937, 938, 948, 953, 954, 955, 956, as amended, sec. 234, 83 Stat. 1244, as amended (42 U.S.C. 2132, 2133, 2134, 2)?5, 2201, 2232, 2233, 2236, 2239, 2282); secs. 201, as amended, 202, 206, 88 Stat. 1242, as amended, 1244, 1246 (42 U.S.C. 5841, 5842, 5846). Section 50.7 also issued undt Pub. L. 95-601, sec. 10, 92 Stat. 2951 (42 U.S.C. 5851). Section 50.10 also issued under secs. 101, 185, 68 Stat. 955 as amended (42 U.S.C. 2131, 2235), sec. 102, Pub. L. 91-190, 83 Stat. 853 (42 U.S.C. 4332) . Sections 50.13, and 50.54(dd), and 50.103 also issued under sec. 108, 68 Stat. 939, as amended (42 U.S.C. 2138). Sections 50.23, 50.35, 50.55, and 50.56 also issued under sec. 185, 68 Stat. 955 (42
l t U.S.C. 2235). Sections 50.33a, 50.55a and Appendix Q also issued under sec. 102, Pub. L. 91-190, 83 Stat. 853 (42 U.S.C. 4332). .>ections 50.34 and 50.54 also issued under sec. 204, 88 Stat.1245 (42 U.S.C. 5844). Sections 50.58, l l 50.91, and 50.92 also issued under Pub. L. 97-415, 96 Stat. 2073 (42 U.S.C. 2233) Section 50.78 also issued under sec. 122, 68 Stat. 939 (42 U.S.C. 1 2152). Sections 50.80 - 50.81 also issued under sec. 184, 68 Stat. 954, as l amended (42 U.S.C. 2234). Appendix F also issued under sec. 187, 68 Stat. 955 (42 U.S.C 2237). i
- 2. Section 50.2 is amended by revising the definition of electric utilityandinsertingthedefinitionsoftransmiss5naccessfees,systemexit fees, distribution line charges, and " cost of service" regulation.
Electric utility means any entity that generates, transmits, or distributes electricity and that recovers the cost of this electricity through rates established by a regulatory authority, such that the rates are sufficient for the licensee to operate, maintain, and decommission its nuclear Q plant safely. Rates must be establishe by a re ulatory authority either h , 4 hidst t nn-OQ t>%Nb P'! l5 F directly through traditional "cust of service" regula' tion or indirectly h sms s"rh t & - 4 ' ""
- n icc>, 3.y n c m us.5 iees, u N / mag;7 3 C" " # -., %o entity whose rates are established by a regulatory authority by Umechanisms that cover only a portion of the cost j
of decommissioning will be cons,idered to be an " electric utility" only foi deep wu u p' ' tha,t portion of the decontainat4en' Costs that are collected in this manner. Similarly, a licens e who collects non-decommissioning operation costs, not collected th ghtjese ar-m u zed by a rate-regulating p agy .8
authority, would nat be considered an " ele 6r c tility" for the purposes of x ' x ., financial qualifications' to operate 'the facilities. Public utility districts, municipalities, rural electric cooperatives, and State and federal agencies, including associations of any of the foregoing, that establish their own rates are included within the meaning of " electric utility."
" Cost of service" regulatfon is the traditional system of rate regulation in which a rate regulatory authority allows an electric utility to charge its customers all reasonable and prudent costs of providing electricity services, including a return on the investment required to provide such services.
N' M Distribution line charges are those charges or fees levied e of the 'stribution system by an electricity supplier. /
,/
Syste exit fees are those charges or fees ,for the generation, transmission, o distribution costs incurre,d"b an electric services provider
/
to a customer who no anger intends ,t.o' purchase electric services from that provider, j
/
Transmission ,aicess fees ar those charges or fees for the use of a
/
transmis s1 stem by electricity gen - tors.
- 3. Part 50 is amended by revising the following paragraphs as a result of the amending of the definition of " electric utility."
5 50.43(a) In the first sentence, insert the words "or State" after: The Connission will give notice in writing of each application to such regulatory agency... i 50.54(w) replace "Each clectric utility licensee. . ." with "Each power reactor licensee..." i 50,54(bb) add the following: Each power reactor licensee shall report to the NRC at least once every 3 years on the status of its funding for the management of its irradiated fuel l at the reacter following permanert cessation of operation of the reactor. Any licensee for a plant that is within 5 years of the projected end of its operation shall submit such a report annually. 5 50.63(a)(2) replace " Utilities. . ." with "Litensees. . . " in the last tentence. 5 50.73(b)(2)(ii)(J)(2)(fv) modify to read as: "The type of personnel involved (i.e., contractor personnel, licensed operator, nonlicensed operator, other licensee personnel .)" i 50.75(al in the second sentence replace "For electric utilities. . ." with "For power reactor licensees..." 5 50.75(b) replace " power reactor" for electric utility" in the first sentance, t w
l l ) [ l 50.75(d) replace "Each non-electric utility applicant.. ." with "Each non-powe,r reactor applicant..."
- 4. With respect to the status of decommissioning trust funds during safe storage period:
l Part 50 is amended by adding the following to i 50.75(e)(1)(1).
-A licensee may take credit on earnings on the prepaid dectomissioning trust funds using a 2 percent annual real rate of return from the time of the funds' collectio'n through the decommissioniag [eriod, if the licensee's rate-setting authority does not authorize the use of another rate.
Part 50 is amended by adding the following to i 50.75(e)(1)(ii). A licensee may take credit for earnings on the external sinking funds using a 2 percent annual real rate of return from the time of the funds' collection through the decommissioning period, if the licensee's rate-setting authority does not authorize the use of another rate. 1 5 With respect to reporting requirements: 4 in i 50.75(f). paragraphs (1). (2), and (3) are redesignated as paragraphs (2). (3), and (4), respectively, and a new paragraph (1) is_._added to read as follows: , (1) Each puwer reactor licensee shall report to the NRC at least once every 3 years on the status of its decommissioning funding for each reactor or part thereof that'it owns. The information in this report shall include, at a minimum: whether the licensee meets the definition of " electric utility" contained in-i 50.2 and the basis for supporting that classification; the amount of decommissioning' funds estimated to be required pursuant to 10 CFR , 50.75(b) and (c); the amount accumulated to the date of the repor' a schedule of the annual amounts remaining to be collected; and the assumptions used regarding rates of escalation in decommissioning costs, rates of earnings in decommissioning trust funds, and rates of other factors (a.q., discount rates) used in funding projections. Any licensee for a plant that is within 5 years - of the projected end of its operation shall submit such a report annually. a Dated at Rockville, Maryland, this day of _ , 1997. For the Nuclear Regulatory Commission. j John C. licyle, Secretary of the Commission. L ENCLOSURE 3 l REGULATORY ANALYSIS 4
\
REGULATORY ANALYSIS ON l DECOMMISSIONING FINANCIAL ASSURANCE IMPLEMENTATION REQUIREMENTS FOR NUCLEAR POWER REACTORS Draft Report for Comment l U.S. Nuclear Regulatory Commission l Office of Nuclear Regulatory Research
REGULATORY ANALYSIS ON DECOMMISSIONING FINANCIAL ASSURANCE IMPLEMENTATION REQUIREMENTS FOR NUCLEAR
- POWER REACTORS l
1 Draft Report for Comment i i i Regulation Development Branch Division of Regulatory Applications Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001
ABSTRACT I [reseried] l Drqft Pagev
CONTENTS
-Page I
- 1. INTRODUCTION . . . . . . . . . . . .... .... . .. .. .. . ........
Statement of the Problem and Objective of the Rulemaking . ... .. ..... . I 1.1 1.2 Current Regulation of Decommissioning Finan:ial Assurance . ...... ..... . .2 l
- 2. IDENTIFICATION AND PRELBfINARY ANALYSIS OF ALTERNATIVE APPROACIIES . . . . . . . . . ..............,........ . .5 1 l
6 2.1 Need for Fully-Funded Assurance Due to Deregulation . . . . . . . . . . . . . . . . . . . . . . 6 2.1.1 Option A-1: No action . . . . . ........ ............. ......... l 2.1.2 Option A-2: Revise the regulatory definition of " electric utility" to clarify that it excludes entities that are no longer able to recover costs through regulated rates, fees, or mandatory charges . . . ...... . ..... ......... . .7 i 7 2.2 Credit for Earnings on Decommissioning Funds . . .. ... ... 8 2.2.1 Option B.1: No action . . . . .. .. , . ........ 2.2.2 Option B-2: Allow credits for earnings during safe storage and an assumed 2 percent real rate of return . .... ....... .. .......... ..., . 9 Monitoring Fund Balances through Reporting ..,.. 10
. 2.3 .. ... . ... . ...
.1I 2.3.1 Option C-l: No action . . . ..., ... ... .
2.3.2 Option C-2: Implement a periodic reporting requirement . . . Ii 2.4 . Use of Statements of Intent by Power Reactor Licensees .. ... . . .. .. . . . . . 12 12 2.4.1 Option D-1: No action . . . . ...... . . .. .... 2.4.2 Option D-2: Eliminate the statement of intent as an allowable mechanism
. . .. .. . ..... .. .., 12 for power reactor licensees .
- 3. ANALYSIS OF VALUES AND IMPACTS . . ... . .. . .. . ..... . 15
- 3.1 identification of Affected Attributes . . . . .. .. . .. ... . . . . 15 3.2 Research and Evaluation of Information on Selected Attributes . . . . .. . .. . . . 19 3.2.1 Decommissioning Cost Estimates Used as Buis for External Sinking Funds . . . 19 Draft Page vii as
CON 1TNTS (continued) l'ase
. ... ..........21 3.2.2 Project-d Funding Status of External Sinking Funds
.......,.... . . . 22 3.2.3 : Reporting on Status of Decommissioning Funds -
-3.2.4 Availability and Security of Financial _ Assurance Mechanisms to.................30.
Supplement or Replace External Sinking Funds . . .
. . 36
-3.2.5 Potential industry Restructuring . . . . . ......................
........... . . 39 3.3 Model De sign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
39' 3.3.1 - Development of the Database . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 41 3.3.2 - Modeled Scenarios . . . . . . . . . . . .........................
..... ...... . . . . . . . . . 42 3.3.3 . Modeling of Regulatory Options . . . . . . . .
^
3.3.4 - Assumptions' . . . . .. ... .. .. .... . ................48 3.4 : ' Results . . . . . . . . ........ ... ... .. . .....................49 50
-3.4.1 . Estimated Values and Impacts of Options A-t and A-2 . . . . . . . . . . . . . . . . .
..........,....53 3.4.2 Estimated Values and Impacts of OptMns 11 1 and B-2 ,
............ . . 55 3.4.3 Estimated Values and impacts of Opuons C-1.vd C-2
..... ..... .. . 57 3.4.4 Estimated Values and impacts of Op6ons D-l and D-2
... ....... .. . 61
- 4. BACKiTI' ANALYSIS . . . . . . . .
, . . . ............. . . 63
- 5. - DECISION RATIONAIE ....... ..
... . .......... .... . . 67
- 6. IMPLEMENTATION . . ... .. . . ,,
... ... .. ..... .... . . . 67 6.1- Implementation Schedule . .
Draff Page viii b -- - - _____ ______ - _ _ ________.____
- 1. INTRODUCTION I
NRC has initiated a rulemaking to address concerns related to its financial assurance requiremer ts for nuclear power reactors. As discussed in detail below, most of these concerns a.e the restdt of ongoing deregulatory activities in the electric utility industry. In April 1996, NRC published an Advance Notice of Proposed Rulemaking (ANPR) requesting comments on several issues related to deregulation and NRC's financial assurance requirements (61 FR 15427, April 8.- 199ti). NRC has reviewed these comments and is l studying a number of regulatory options. This document presents NRC's Regulatory Analysis of these options.
'Inc remainder of this introduction is divided into two sections. Section 1.1 states the problem and the objective of the rulemaking. Section 1.2 provides background inforrntion on the current regulation of financial assurance for decommissioning costs of power reactors.
1.1 - Statement of the Prablem and Objective of the Rulemaking NRC's decommissioning financial assurance requirements fer nuclear power reactors are based on i. the premise that the reactors are owned by regulated or self-regulating entities that recover their costs through a rate-setting process overseen by the applicable regulating body. Consequently, NRC defined the
. term " electric utility," in 10 CFR 50.2, in a manner that includes investor-owned utilities, public utility -
districts, municipalities, rural electric cooperatives, and State and Federal agencies. Typically such entities are regulated by State public utility commissions (PUCs) and/or the Federal Energy Regulatory Commission (FERC). Some publicly-owned uti;ities regulate their own rates through a process that is open to public participation and scrutiny. These regulatory processes effectively ensure that utilities can recover all costs that are prudently incurred, including reactor decommissioning costs. . in recent years, however, various parties have called for the electric utility industry to be deregulated just as the natural gas and telecommunication industries were recently deregulated. FERC and numero .e States have begun to study deregulation issues and, in some cases, have initiated deregulatory rulemakings. Many significant issues related to deregulation have yet to be resolved, however, including
- issues that will have considerable impact on NRC power reactor licensees, such as re 'overy or non-recovery of decommissioning costs. Consequently, it is possible that regulatory bodies may, in the future, be unable to ensure that utilities can recover decommissioning costs, in this more competitive environment, some utilities may not even remain financially viable, which could also jeopardize funding for decommissioning.
During the forthcoming period of economic deregulation and industry restructuring, increasing
- competition may force integrated power systems to separate (or "disaggregate") their systems into functional areas. Thus, some licensees may divest electrical generation assets, such as power reactors, from transmission and distribution assets by forming separate subsidiaries or even separate companies for generation. Disaggregation may involve utility restructuring, mergers, and corporate spin-offs that lead to changes in owners or operators of licensed power reactors and may cause some licensees, including
- owners, to cease being an " electric utility" as defined in 10 CFR 50.2. Such changes may also affect the licensing basis under which NRC originally found a licensee to be financially qualified to construct, Drg/l Page 1
operate or own its power reactor, as well as to accumulate adequate funds to ensure decommissioning at the end of reacter life.' As the electric utility industry moves from an environment of substantial economic regulation to one of increased competition, NRC is concerned about the impacts of restructming ar.' ate deregulation. Approval of organizational and rate deregulation changes by other regulators may occur rapidly and without NRC's knowledge. The degree and pace of such changes could affect the factual underpinnings of NRC's previous conclusions that power reactor licensees can reliably accumulate adequate funds for operations and decommissioning over the operating lives of their f.cilities. The main objective of the current rulenuking is to modify NRC's regulatory framework to help ensure that deregulatory activities in the electric utility industry do not jeopardize NRC licensees' financial assurance for decommissioning. 'Ihe rulemaking would accomplish this by clarifying that additional financial assurances for accommissioning are required fum any power reactor licensee that loses the ability to recover decommissioning costs through regulated rates and fees or other mandatory charges established by a regulatory body. The rulemaking would also establish a reporting requirement to allow NRC to monitor the decommissioning funding status of each licensee. Finally, the ,urrent rulemaking also would update the financial assurance requirements to modify funding requirements to allow licensees to account for anticipated trust fund earnings from the time funds are deposited until withdrawn to pay decommissioning costs. 1.2 Current Regulation of Decommissioning Financial Assurance NRC requirements pertaining to financial assurance for the decommissioning of nudear power reactnrs are contained in 10 CFR 50.75. As noted in NRC's regulations, funding for decommissioning of electric utilities is also subject to the regulation of FERC and State PUCs. Section 50.75(a) state; that the NRC requirements "are in addition to, and not substitution for, [thesej other requirements." Additional guidelines for NRC licensees are provided in NRC's Regulatory Guide 1.159,2 and in a related Standard Review Plan (SRP) ' Under $50.75(b), licensees must dernonstrate decommissioning financial assurance in an amount at least equal to either a minimum " certification" amount (based on a formula specified at b50.75(c)) or a facility-specine decommissioning estimate (provided that the estimate is at least as great as the applicable certification amoun0 Licensees are required to update annually the minimum amount of decommissioning assurance required under the certification formula in 550.75c by applying an inflation-factor that is also described in %50.75(c). Licensees are not required to file this adjustment with NRC. however. Pursuant to 550.75(a), licensees are required to adjust collections from ratepayers in coordination with the appropriate PUCs or FERC.
' lo 1984 NRC eliminated nuancial qualifications reviews at the operating license stage for those licensees that met the definition of "c'ectric utility." This decision was based on NRC's assumption that "the rate process assures that funds needed for safe operation wi'.1 be made available to regulated elecuic utilities" (49 FR 35750, September 12, 1984).
- Regulatory Guide 1.139, " Assuring the Availability of Fundsfor Decommissioning Nuclear Reacts.rs," U.S.
Nuclear Regulatory Commission, Office of Nuclear kegulatory Research, August 1990. ,
- Draft Standard Review Plan on Power Reactor Liceruee Financial Qualifications and Decommissioning Financial Assurance, U.S. Nuclear Regulatory Commission, Office of Nuclear Regulatory Research, September 1996.
- Draft Page 2
Financial assurance must be demonstrated using one of the Gnancial mechanisms described in 150.75(e). 'these mechanisms include " prepayment" mechanisms (trust funds, escrow accounts, government funds, certificates of deposit, deposits of government securities), external sinking funds, surety bonds, letters of credit, lines of credit, insurance, and statements of intent.' Prepayment it.echanisms, in the case of non-electric utility licensees, must be either fully funded or, if being funded gradually in an external sinking fund, must be coupled with another mechanbm (e.g., a surety bond) so that the total assurance pravided by the licensee is at least equal to the required level of coverage. 1 In the case of electric utility licensees, however, external sinking funds are not requited to be coupled with another financial assurance mechanism. Tht s, electric utility licensees are not required to demonstrate the full minimum amount of decommissionin); coverage (i.e., the full certification amount) , l j until contributions to the external sinking fund cease at the end of the operating license. NRC justified this difference in treatment between electric utility licensees and non-electric utility licensees on the ability of l I the electric utilities to collect funds through the rate-making process and on the added oversight provided by FERC and PUCs. Payments to an external sinking fund (regardless of whether or not the licensee is an electric l l utility) must be made annually in amounts that will result in full funding by the time the facility ceases operation. Although NRC allows licensees to account for future earnings (i.e., until the reactor shuts down) on decommissioning trusts when calcul& ting annual contributions to external sinking funds and prepayment amounts, this position is not reflected in regulations, but rather in guidance (i.e., in Regulamry Guide 1.159 and the SRP). The guidance states that assumed rates of return should " reasonably approximate" the historical real rate of earnings obtained by a given type of investment, but it does not establish an upper limit for assumed rates of return. However, NRC does not allow licensees to take credit for earnings on the funds while reactors are in extended safe storage (i.e., after the permanent shutdown of the reactor), -l In practice, virtually all non-Federal government electric utility licensees are believed to use external sinking funds based on trusts.' NRC requirements provide that trusts (cr any mechanism used as an c.xternal sinking fund) must be segregated from licensee assets and outside the licensce's administrative control.' investment guidelines and other restrictions affecting trustees and/or licensees are not specified in NRC regulations. However, NRC guidance does (1) provide suggested investment guidelines,'(2)
- Under 10 CFR 50 75(e)(2)-th, .,tatenients of intent are anowable mechanisms for Federal government electric utility licensees, and for Federal, State, and local govemment non-electric utility licensees.
- In 1990, NRC reviewed the financial mechanisms originally submitted by licensees to comply with the then-new decommissioning financial assurance requirements, hiost of these mechanisms were trusts, but the submittats also included three sinking funds based on escrows, one prepaid escrow, one " restricted deposit agreement," and one
" city sinking fund." h1 ore recect information on mechani. ms being used by licensees is not availabis.
- 10 CFR 50.75(e)(1)(iit
' Replatory Guide 1,159, p.14, states that " Any trust investments complying with IRS Code Section 468A or with approval of or guidance from a utility's State PUC, other State agency, or from FERC would be acceptable to NRC staff.1.icensees not eligible or willing to use decommissioning trusts established under IRS Code Section 468A or not subject to PUC or FERC jurisdiction should limit trust investments to " investment-grade
- securities.
Investment grade bonds and preferred stocks are use rated at least "BBB" or equivalent by a national rating service. (Continued. . .) Draft Page 3
specify trus'.ee qualifications,' and (3) state that licensees may make withdrawals from the fund for decommissioning activities.' Regulatory Guide 1.159 offers detailed model wording for trust agreements (including numerous conditions that provide additional protections on behalf of NRC's interests) but states that this wording be modified "as a licensee's specific situation warrants (provided that the agreement] complies with applicable state law . . ." Licensees submitted financial mechanisms for NRC's review one time (in 1990). Regulatory Guide 1.159 states that if licensees "either change or significantly modify the fun Licensees method," they must submit the changes or modifica' ions to NRC within a
- reasonable time.#'
must also maintain an existing method of financial assurance until the licensee has instituted a new method."" NRC does not require licensees to report periodically on the status of their decommissioning funds. Rather, NRC views licensee compliance with the funding assurance requirements as a matter to determined through the inspection process when necessary, as well as through monitoring by State PUC and FERC of decuinmissioning funds of licensees under their jurisdiction as part of their rate regulatory responsibility. Reporting requirements of FERC and PUCs, along with other FERC and PUC requirements related to NRC's current rulemaking, were researched as part of this Regulatory A and are discussed in Section 3.2.3. (.. . continued) Speculative issues of common stocks should be avoided."
' Regulatory GuMe 1.159, p.14, states that "The trustee of a fund shoukt be an appropriate State or F
. government agency or an entity that has the authority to act as a trustee ard whose tnut operations examined by a State or Federal agency."
" SRP, p. 2*I. Many licensees that have established decommissioning (nnt furds for their power reactors are making deposits into their trust accounts both for decommissioning costs as definal under 650.2 and for o decommissioning-associated costs such as interim spent fuel management ard storage and "greenfield" costs.
'* Regulatory Guve 1.159, Section 2.1.6.1, p.13. The SRP (in Section Ill.2.d) inotes that licensees ar required to submit these changes and modifications to NRC in accordance with 10 CFR 50.9. (10 CF licensees to notify NRC within 2 working days if the licer e iden'ifies information having a significant impli for public health and safety or common defense and security, unless this information i is covered b updating requirements.) It is unclear whether licensees have been submitting modifications of I'ma to NRC for review.
" Regulatory Gude 1.159, Section 2.1.6.1, p.13.
Draft Page 4
= -
- 2. IDENTIFICATION AND PRELIMINARY ANALYSIS OF ALTERNATIVE APPROACIIES The Rulemaking Plan for this rulemaking identified thrw specific options, a.d three correspond ,
no-action alternatives, to address the issues discussed in Sectior. i. fi Issue A. Is fully funded assurance needed due to deregulation? Option A 1: No action option. Option A-2: Revise the regulatory definition of " electric utility" to clarify that it excludes entities that are no longer able to recover costs through regulated rates, fees, or mandatory charges. Issue B. Should NRC allow credit for earnings during safe storage periods? Option B-1: No action option. Optiort B-2: Allow licensees to assume a positive real rate of return on decommissioning funds from the time contributed until the time withdrawn to pay for decommissioning. Issue C. Should NRC monitor rund balances through regular periodic reporting? Option C-1: No action option. Option C-2: Implement a periodic reporting requirement. NRC's April 1996 ANPR also drew attention to the use of statements of intent by power react >
. licensees. The following option (and its corresponding no-action alternative) has been added to Regulatory Analysis to address this issue:
Issue D. Should NRC allow use of statements ofintent by power reactor licensees? Option D-1: No action option. Option D-2: Eliminate the statement of intent as an allowable mechanism for power reactor licensees.- The remainder of this section presents a preliminary analysis of each of these options. The purposes of this discussion are to highlight the purpose Regulatory Analysis. Drg/l Page 5
2,1 Need for Fully-Funded Assurance Due to Deregulation Options A 1 and A-2 address NRC's concern that, as a result of ongoing deregulation, fmancial assurance requirements for electric utility licensees (relative to non-electric utility licensees), a currently defined, may no longer be appropriate, at least in some instances. 2,1,1 Option A 1: No action Under NRC's current requirements, power reactor licensees that do not meet the definition cf electric utility may use an external sinking fund only if the amount remaining unfunded in the e sinking fund is assured using an additional financial assurance mechanism (e.g., a sure credit). In contrast, licensees that meet the definition of electric utility may use an external without providing any additional financial assurance for amounts not yet funded. As discussed in Section I, NRC found this distinction reasonable because elect & utilities historically have been able collect needed funds through a regulated rate-making process and because of the additional o previded by FERC and PUCs. NRC continues to believe this approach is reasonable for licensees that continue to recover prudently-incurred costs through a regulated ratemaking process. Due to the ongoing de electric utility industry, however, licensees in the future may recover costs not through rates bu other mandatory mechanisms (e.g., access fees, exit fees, line charges) established by their ra Although NRC believes these licensees can recover costs and should t ,: considered ele current definition of " electric utility" could be interpreted otherwise. In addition, NRC is concerned other licensees may be able to qualify as electric utilities under NRC's current definition despite tv deregulated with respect to the recovery of prudently-incurred costs. 10 CFR 50.2 defines " e utility" as follows: Electric utility means any entity that generates or distributes electricity and which recovers the cost of this electricity, either directly or indirectly, through rates established by the entity itselfor by a separate regulatory authority. Investor-owned utilities, including generaCon or distribution subsidiaries, public utility districts, municipalities, rural electric cooperatives, and St:,te and Federal agencies, including associations of any of the foregoing, are included within the meaning of " electric utility " (italics added) Public comments received in response to NRC's April 8,1996, ANPR suggest that some licensee interpret NRC's current definition, because of the phrase "eithe to set their own prices in the marketplace. This interpretation would, in effect, allow au licensees to qualify as electric utilities and, in turn, allow all licensees tohuse" external ither sinking fund them with other financial mechanisms. NRC, however, had included in its definition the p rase e directly or indirectly, through rates established by the entity itself" merely to allow the defmitio encompass those entities, such as some publicly-owned utilities, that regulate their own r process that is open to public participation and scrutiny. Because all NRC power reactor licen currently, regulated to allow recovery of costs, this potential misinterpretation of the defm concern only to the extent that deregulation affects Pensees in the future. Under Option A-1, the definition of " electric utility" would remainiias stated d above. De the outcome of deregulation, some licensees irappropriately believe they no longer meet the de Drqft , Page 6 {
consequently, obtain more costly financial assurance mechanisms. Other licensees d may continue to m the definition of electric utility despite being deregulated with respect to the recovery of prudently-incurre costs (i.e., despite having reduced recourse to decommissioning cost recovery through rates appr PDCs or FERC). Such licensees might use external sinking funds to demonstrate financial assurance ; decommissioning without also providing an additional financial mechanism to cover unfunded costs would be contrary to the assumptions underlying NRC's rationale for treating regulated electric utilitie diffecently from other NRC licensees, and could result in shortfalls in funding for decommissionin
- these licensees go bankrupt or their reactors close prematurely.
Revise the regulatory definition of " electric utility" to clarify that it excludes 2.1.2 Option A-2: entities that are no longer able to recover costs through regulated rates, fees, or mandatory charges L Under this option, NRC would revise the definition of " electric utility" found in 10 CFR 50.2 to read as follows: Electric utility means any entity that generates, transmits, or distributes electricity and which reovers the cost of this electricity through rates established by a regulatory authority, such that the rates are sufficient for the licensee to operate, maintain, and decommission its nuclear plant safely. Rates may be established by a regulatory authority either directly through traditional " cost of service" regulation or indirectly through mechanisms such as mandatory transmission access fees, system exit fees, or distribution line charges. Any entity whose rates are established by a regulatory authority by these mechanisms for only a portion of that entity's cost of operation (e.g., only for decommissioning costs) will be considered to be an " electric utility" only fer that part of the Commission's regulations to which the mechanisms pertain. Public utility districts, municipalities, rural electric cooperatives, and State and Federal agencies, including 3d within the associations of any of the foregoing, that establish their own rates, are inc, meaning of "electrie ut!!ity " NRC believes this defmition clarifies its intention that only licensees capable of recovering costs
. through regulated rates, fees, and mandatory charges be considered electric utilities eligible for treatment under the financial assurance requirements. Use of the revised definition would reduce the risk
- that decommissioning costs may go unfunded due to bankruptcies or premature closures of heensees tha are no longer electric utilities.
2,2 - _ Credit for Earnings on Decommissioning Funds
. Options B-1 and B-2 affect potentially any Part 50 licensee that uses an external sinking fun pregyment mechanism, regardless of whether or not the licensee is an electric utility. The opt how much money licensees must contribute into their funds by restricting their assumptions regarding future earnings.
Drg/t Page 7
2.2.1 Option B-1: No action NRC guidance allows licensees to account for future earnings (i.e., earnings to be accrued until the reactor shuts down) on external decommissioning sinking funds when calculating annual contributions." (Users of prepayment mechanisms, such as funded trust funds, may also take credit for future earnings.) NRC regulations (10 CFR 50.75(e)(1)(ii)) state that contributions to external sinking funds must be made periodically such that "the total amount of funds would be sufficient to pay decommissioning costs at the time termination of operation is expected." Given that e:;ternal sinking funds are required to be fully-funded by the time facilities are expected to be permanently shut down, licensees are currently precluded from considering any investment returns they might expect to earn while their reactors are in extended safe storage (i.e., after the permanent shutdown of the reactor but before the commencement of decommissioning). This is a conservative funding approach for two reasons. First, by requiring the last financial assurance contribution to occur prior to facility shutdown, there are no subsequent financial assurance contributions that would depend on licensees' abilities to continue as viable entities after their nuclear plants have been shut down. Second, by not allowing any credit for projected earnings during a safe storage period, there is less likelihood that poor investment returns (i.e., returns lower than those projected by the licensee in calculating financial assurance payments) would significantly impact decommissioning funding." Some licensees, however, have argued that they are able to earn a positive real rate of return on their decommissioning funds during safe storage, and that NRC, by requiring all decommissioning funds to have been collected or earned by shutdown, may force licensees to collect more funds froia ratepayers than is absolutely necessary, given the potential for accrual of interest in the safe storage period. This, they argue, would result in an u;. warranted expense to licensees, their ratepayers, or their stockholders, and it could create inequities between generations of ratepayers. With respect to the return that licensees should assurne when accounting for future investment income earned on decommissioning funds set aside during the operating life of the facility, Regulatory Guide 1.159 states that assumed rates of returns should " reasonably approximate" the historical real rate of earnings obtained by a given type of investment, but does not establish an upper limit for assumed rates of return. In practice, licensees assume a wide range of projected earnings rates, and many licensees assumr rates that are fairly high (e.g., real rates of 6 to 8.7 percent)." (For example, a real rate of 8.7 percent
Regulatory Guide 1.159, p.14.
" In contrast, insufficient returns earned on decommissioning funds pr or to the safe storage period are of less concern. The reason for this is that licensees' nuclear power reactors would stillbe generating revenue in this situation. Therefore, licensees would be better able (all else equal) to make up the difference with added contributions to the fund.
" Annual Survey of Nuclear Decommissioning Ca,. Estimates and Funding Policies, Public Utility Survey, Table 32. Goldman Sachs, August 1995.
Draft Page 8
! exceeds the historical average real rate of return of 6.9 percent for a portfolio invested 100 percent in
.large company common stocks.") l Under Option B-1, !icensees using external sinking funds, when calculating annual contributions, would continue to account for future earnings projected through th e end of the expected termination of operations. - Licensees using the safe storage method of decommissioning still would not be allowed to take 1e safe-storage period into account in their annual runding calculadons. This option would also take no l action to further restrict licensees' earnings rate assumptions for purposes of calculatmg annual contributions to sinking funds. Prepayment mchanisms also would be unaffected by this option.
2,2,2 Option B-2: Allow credits for earnings during safe stcrage and an assumed 2 percent real rate of return l' Under Option B 2, licensees using external sinking funds, when calculating annual cont'ributions, woula account for both (1) future decommissioning furri earnings projected through the end of the expected termination of operations, and (2) future returns expected to be earned duing the safe storage period,if tne particular nuclear power reactor will use this method of decommissioning. The final annual contribution would still have to be made prior to termination of operations at the facility, but the balance in the decommissioning fund would then continue to grow during safe storage unul it is fully funded by the time of decommissioning. Optica B-2 would also restrict the assumed earnings rate on external sinking funds to a real rate of return of 2 percent, regardless of whether or not a licensee will use safe stor,.ge, in those cases where a regulator (e.g., FERC) does not approve the assumed earnings rate. Also under this option, licensees using prepayment mechanisms could reduce the amount that they must prepay to account for future earnings. As in the case of licensees using external sinking funds, licensees using prepayment mechanisms would be allowed to take credit for earnings expected to accrue from the time of prepayment, through safe storage, until funds are withdrawn to pay for decommissioning. Thus, like an external sinking fund, a prepayment mechanism would not be adequate in amount to pay for decommissioning until sufficient earnings accumulated over the life of the facility and over its safe storage period. The ar,sumed earnings rate would also be restricted to a real rate of return of 2 percent in ca-es where a regulator does not approve the assumed earnings rate. The 2 percent real rate of return is a conservative assumption that provides reasonable protection to NRC." In many cases, however,2 percent is less than the rate currently assumed by licensees." To e the extent that earnings in a given year pro,e to be higher than 2 percent, the balance of the fund will be greater than anticipated. Licensees may take this higher balance into account in calculating subsequent contributions to their sinking funds. This means the size of subsequent contributions will decrease, even though these subsequent centributions will still be based on a 2 percent earnings assumption. (Similarly, if the actual real rate of return proves to be less than the assumed 2 percent rate, the size of subsequent 1 contributions will increase, even though they will still be based on a 2 percent earnings assumption.) [
" Stocks, Bonds, Bills and inflation 1995 Warbook: Market Resultsfor 19261994, Tabte 6-7, tbbotson Associates,1995.
Ahhough actual returns may exceed 2 percent on nerage, rates in nie short term (e.g., the 5 or 10 years prior to decomminioning) may be below average (or even negative).
" The average rate currently assum.xi by licensees is 3."i ;4rcent.
Drgft Page 9
Thus, regardless of whether actual returns are greater or less than 2 percent, the amount ultimately collected from ratepayers and placed in the sinking fund should be appropriate. This option would allow licensees to collect no more funds from ratepayers than is absolutely necessary given the potential for accrual of interest. For two reasons, however, this option seems un to significantly impact most licensees.
- First, licensees can take best advantage of this option only if they pre-select the safe storage method of decommissioning relatively early during the funding period. Currently, however, licensees are required to make a preliminary l
determination of decommissioning methods ody 5 years prior to termination of operations." If safe storage is elected at that time, the benefit of this option would ( be fairly small because the decommissioning fund would already oc largely funded.
- Second, the application of this option to prepayment mechanisms (the costliest method of financial assurance) is unlikely to have any impact on nuclear power reactor licensees because licensees will not use this prepayment method until deregulation results in their no longer meeting the definition of electric utility (in which case they would become ineligible to use external sinking funds).
A pota.ntially greater concern, howes er, is that the option provi/'s adequate financial assurance only under three conditions. First, the reactor must not close prematurely and the safe storage period must last as long as anticipated. Otherwise, tl.e invested decommissioning funds will not have adequate time to generate the needed funds. Second, realized rates of return must equal or exceed the assumed rate. T risk is reduced substantially for affected !!censees by limiting the assumed rate to 2 percent. Bird, funding contributions calculated by licensees must accour for the dded costs (e.g., security) of a safe storage decommissioning relative to the lower cost of a prompt decommissioning. In particular, contributions based en NRC's certification amounts would be inadequate because the certification amounts assume prompt decommissioning. If safe storage costs are not reflected in the fund contributions, then actual spending on safe storage costs could result in inadequate funds remaining for the actual decommissioning. L 2.3 Monitoring Fund Balances through Reporting Options C-1 and C-2 address NRC's ability to monitor the status of power reactor licensees' decommissioning funding including, in particular, their progress in funding external sinking funds.
" This study could identify only three operating nuclear plants that have already elected safe storage as the method of decommissioning.
" Licensees could continue using extemal sinking funds in this case only by couplir - them with another financial mechanism (e.g., a surety bond, letter of credh, or parent company guarantee) m cover costs that are not yet funded by the sinking fund. This option may have greater impact on non-power reactor licensees, who already are ineligible to use external sinking funds except in combination with another fir *ncial mechanism. ._
Draft Page 10 4
2.3.1 Option C it _ No action NRC has not deemed it necessary to monitor licensee compliance with the current decommissioning funding assurance requirements. Currently, NRC views licensee compliance with the funding assarance requirements as a matter to be determined through the inspection procos when necessary. NRC has also relied on FERC's and PIICs* moni:aring of the decommissioning funds of licensees that fall under their jurisdiction (i.e., as part of their rate regulatory responsibility). This option would continue NRC's current practice of not requiring licensees to report on the status of their decommissioning funds. I !- 2.3.2 Option C-2: Impkment a periodic reporting recuiremeni NRC is concerned that rapid changes (e.g., divestitures and restructuring) in the electric utility indusvy due to deregulation will make it difficult to monitor decommissioning funding effectively under its current approach. In particular, NRC's current practices may not provide sufficiently consistent, regular, and comprehensive information for all licensees. NRC also is concerned that its licensees may at some
- point no longer fall under the jurisdiction and oversight of FERC or PUCs.
Option C-2 would require all power reactor licensee < to report to NRC at least once every 3 years on the status of their decommissioning funding. Licensees far plants within 5 years of the projected end of operations would have to report annually. Reports would need to state whether the given licensee meets the definition of " electric utility" in 10 CFR 50.2 and, if so, provide supporting evidence of this assertion. i Reports would also need to include the following:
* 'Ihe amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(c);
- The amount accumulated to the date of the report;
- A schedule of the annual amounts remaining to be contributed; and
- The assumptions used regarding rates of escalation in decommissioning costs, rates of earnings in decommissioning trust funds, and rates of other factors (e.g.,
discount rates) used in funding projections. This option would enable NRC to establish a shanger oversight role as necessary in the event that the oversight currently provided by FERC and State PUCs diminishes or ceases. Licensee reports also would provide NRC with a consistent, regularly-updated set of information from all licensees. Information in the reports could be used on a case-by-case basis as appropriate. For example, these reports would allow NRC to identify licensees that are not funding their sinking funds at an adequate pace and to take appropriate follow-up action. This information could also prove useful for other purposes, such as evaluating licensee notifications of restructuring and responding to related information requests from Congress and media organizations (over the past few years, NRC has been unable to fulfill such requests). Draft Page 11
2.4 Use of Statements of Intent by Power Reactor Licensees Options D 1 and D-2,.ddress the issue of whether statements of intent should continue to be allowed as an acceptable financial mechanism for power reactor licensees. 2.4.1 Option D 1: ho action NRC regulations currently allow Federal power reactor licensees meeting the definition of electrie utility to use statements ofintent to satisfy the financial assurance requirements of 10 CFR 50,75. In addition, all Federal, State, and local government Part 50 licensees that are not electric utilities may also use statements of intent for financial assurance purposes. Statements of intent document a licensee's intention to request sufficient funding from the appropriate governing body far enough in advance of decommissioning to avoid delays in conducting decommissioning activities. Thus, statements ofintent do not set aside any monies for decommissioning in the manner of prepayment mechanisms or sinking funds, nor do they provide a legally enforceable " guarantee" in the manner of surety bonds, letters of credit, or parent company guarantees. Nevertheless, NRC regulations allow the use of statements of intent by government licensees in recognition of the unique characteristics of governmental bodies, Although numerous Part 50 licensees (non-power reactors) currently use statements of intent to assme their decommissioning costs, the only power reactors eligible to use statements ofintent are those owned by the Tennessee Valley Authority (TV A), a quasi-Federal entity that qualifies as an electric utility. TV A is, in fact, the only power reactor licensee with decommissioning costs currently covered by statements of intent. Other governmental power reactor licensees, such as public utility districts, are ineligible to use statements of intent because they are not Federal licensees. Under Option D-1, TVA could continue to use statements of intent to demonstrate financial assurance for decommissioning of its power reactors. The asstirance provided by this option would continue to rely largely on the presumed financial backing of TV A by the Federal government. 2.4.2 Option D-2: Eliminate the statement of intent as an allowable mechanism for power reactor licensees Recently, a report by NRC's inspector General raised the question of whether TV A should be allowed to use a statement of intent, as allowed by 10 CFR 5035(e)(3)(iv).2" la particular, the report 0) raised concerns regarding TV A's financial condition, (2) noted that TV A's debts are neither obligations of the Federal government nor are they backed by the Federal government, and (3) questioned whether the Federal government would actuauy pay for TV A's decommissioning costs should he need arise. The te prt also indicated that although TV A had established a $261 minion internal d :ommissioning fund as of January 1996 (funded by ratepayers and earnings on invested funds), TV A later nad depleted the fund completely (although it eventually re-funded into the fund all amounts conected from ratepayers). In addition, some commenters on NRC's April 8,1996, Advanced Notice of Proposed Rulemaking (ANPR) stated that TV A's use of costless statements of intent will give TV A a competitive advantage over other competi tors in the increasingly competitive energy marketplace.
** Audit Repon: NRC's Decommissioning Finan,:i i Assurance Requirementsfor Federal Licensees May Not Be Sugicient. OlG!95A-20, U.S. Nuclear Regutatory r c.nnussion, Office of the inspector General, April 3,1996.
Draft Page 12 l 1
Op6on D-2 would climinate the use of statements of intent by any power reactor licensee, thereby addressing the concerns raised by the NRC Inspector General and the commenters on the ANPR.
- Affected licensees (i.e., TVA) would be allowed to use any of the other financial mechanisms accep'able unoer the regulations. In particular, assuming it continues to meet the definition of electric utility. TVA could establish an external sinking fund using funds now held !nernally, l
i Drqft Page 13
i
- 3. ANALYSIS OF VALUES AND IMPACTS _ j
! This section examines the values and impacts expected to result from NRC's rulemhking, and is l presented in four subsections. Section 3.1 identifies attributes that are expected to be aficcted by the rulemakirig. Section 3.2 discusses research and analysis on several topics that can affect the assessment of
- regulatory options. Section 3.3 describes the analytical model used to quantify values and impacts. . Finally,= nroposal's effects on values and impacts are presented in Section 3,4. - 3,1- Idendcation of Affected Attributes L
L This section identifies and describes the factors within the public and private sectors that the regulatory alternatives (discussed in Section 2) are expected to affect. These factors were classified as
' " attributes," using the list of potential attributes provided by NRC in Chapter 5 of its Regulatory Analysis . Technical Emluation Handbook. Each attribute listed in Chapter 5 was evaluated, and the basis for
- selecting those attributes expected to be affected by the proposed action is presented in the balance of this
. section.
The proposed requirements would revise the financial assurance requirements that support facility
^ decoramissioning requirements. The filancial assurance requirements are designed to ensure that funds are available when needed to pay for necessary decommissioning activities. They do not create or define the decommissioning activities themselves. Therefore, some of the following attributes either are not consequences of the proposed action or are potential secondary consequences properly attributable not to the financial assurance requirements but to the decommissioning requirements that the assurance requirements support. The attributes in this group include:
* -- Public Health (Accident) -- No changes to radiation exposures to the public within 50 miles of a facility are expected due to changes in accident frequencies or accident consequences associated with the proposed act:on because the action is not designed or expected to address accident frequency or consequences.
*. Public Health (Routinei -- No changes to radiation exposures to the public'during
- normal facility operations are expected to be associated with the proposed action because the action does not affect routine facility operations in any manner that could result in radiation exposures to the public.
+ Occupational Health ( Accident) -- No changes to health effects, both immediate and long-term, associated with site workers as a result'of changes in accident frequency or accident mitigation are expected to be associated with the proposed action because the action is not designad or expected to affect accident frequency or consequences.
~ Regulatory Analysis Technical Evaluatior 'lamtbook, Draf Report, NUREGIBR4)\84, Office of Nuclear Regulatory Research, August 1993.
Draft Pag: 15
- Occupational Health (Routine) -- No changes to radiological exposures to workers during normal facility operations are expected to be associated with the proposed action because the action is not designed or expected to affect routine facility operations in any manner that could result in radiation exposures to workers.
- Otisite Property -- No changes to monetary effects on offsite property, either through changes in accident frequency and consequences or in other direct or indirect forms, are expected to be associated with the proposed action. The action is not designed or expected to affect accident frequency or consequences. Effects on offsite property resulting from decommissioning se considered an attribute of the decommissioning requirements and not of the decommusioning financial assurance requirements.
f
- Onsite Property -- No changes to monetary effects on onsite property, either i
through changes in accident frequency and consequences or in other direct or indirect forms, are expected to be associated with the proposed action. The action is not designed or expected to affect the need for replacement power, decontamination, or refurbishment costs. Although decommissioning affects onsite property, the proposed action does net revise technical standards or requ'zements for decommissioning. The proposed action is intended to affect the adequacy of funds provided by power reactor license s to pay for decommissioning, but funds not provided by licensees for decommissioning are expected to be provided from other sources (e.g., taxpayers). Therefore the proposed action is not expected to have monetary effects on onsite propery.
- Antitrust Considerations - The proposed action is not expected to have any antitrust effects. s
+ Safeguards and Security Considerations -- The proposed action is not expected to have any effect on the existing level of safeguards and security.
+ Environmental Considerations -- The proposed action is not expected to have any effect on the existing level of protection of eauronmemal considerations.
The proposed regulatory actions are expected to involve the following attributes:
- industry implementation - No added indunty implementauon costs would be created by the no-action options (Opdons A-1, B-1, C-1, and D-1). The proposed rule changes would result in both costs and savings for licensees Specifically, s in the following industry implementation costs and savings would result situations:
y
- Under Option A-2: Given certain assumptions regarding the nata e of .
deregulation, license s no longer meeting NRC's current definitio. of electric utility would c. void the costs of obtaining a prepayment mechanism or a surety, insurance, or guarantee mechanism, as well as the implementation costs associated with the need to search for and Draft Page 16 i l -_ _ _ _ _ _____ .
identify a willing provider of such a mechanism, and to demonstrate to I- NRC that such a mechanism had been obtained.
-- Under Option C-2: Licensees requiied to prepare and f.ubmit periodic reports on decommissioning fund status to NRC could inct.r implementation costs to set up systems to ensure that they have adequate internal reporting procedures to collect ar.d submit the required i
information, t
-- Under Option D-2: Licensees that cannot make use of the statement of f
l intent as an allowable financial assurance mechanism would incur ! implementation costs, such as costs to find a provider of a replacement financial assurance mechanism and costs to set up a replacement mechanism. A possible category of implementation costs not addressed in this analysis is the cost, potentially high, to secure compliance with the commitment represented by the statement of intent (e.g., meetings with Treasury and OMB staff, Congressional testimony) that licensees would not incur if they make use of other mechanisms.
- Indastry Operation -- No added industry operation costs or savings would be created by the no-action options (Options A 1, B-1, C-1, and D-1). The proposed rule changes would result in both costs and savings for licensees. Specifically.
f l industry operation costs and savings would result in the following situations:
-- Under Option A-2: Given certain assumptions regarding the nature of deregulation, licensees no longer meeting NRC's current definitio:t of electric utility would avoid the costs of maintaining a prepayment mechanism or a surety, insurance, or guarantee mechanism, such as paymer..s, fees, and other expenses. The size of these cost savings could vary, depending ott the type of mechanisms that wauld have been used in the absence of a rule change and the number of years that the licensee would have been required to maintain such mechanisms.
-- Under Option B-2: Licensees would incur savings if the size of their annual contributions decreases due to the credit for earnings during safe storage. Licensees might also incur costs (savings)if, as a consequence of deregulation, they reduce (increase) their assumed earnings rate to 2 percent.
- Under Option C-2: Licensees required to report every 3 years on decommissioning fund status to NRC would incur p:riodic costs to prepare and submit such reports.
- Under Option D-2: Licensees that cannot make use of the statement of intent as an allowable financial assurance mechanism would incur costs to maintain replacement financial assurance mechanisms (e.g., surety bond or letter of credit fees, opportunity costs of prepayments). Under the Draft Page 17
regulatory proposal, only the Tennessee VDiey Authority would face these expenses.
- NRC Implementation -- No added NRC implementation costs or savings would be created by the no-action options (Options A-1, B-1, C-1, and " 1). NRC would be expected to incur costs to put the proposed actions into operation. Specifically, NRC would incur implementation costs in the following situations:
-- To implement Options A-2, B-2, and C-2, NRC would be required to develop or revise a Regulatory Guide or Branch Technical Position similar to Regulatory Guide 1.159.
- NRC Operation -- No added NRC operation costs or savings would be created by the no-action options (Options A-1, B 1, C-1, and D-1). The proposed rule changes would result in both costs and savings for NRC. Specifically, NRC operational costs and savings would result in the following situations:
- Under Option A-2: Given certain assumptions regarding the nature of deregulation, NRC would avoid the costs of reviewing submitted mechanisms from licensees that cease to qualify as utilities under NRC's current definition of electric utility.
-- Under option C-2: NRC would need to review periodic reports in order to assess the status of licensees and ensure that they either continue to be regulated electric utilities or, if unregulated, that they have submitted acceptable alternative financial mechanisms.
-- Under Option D-2: NRC would incur costs to review replacement financial assurance mechanisms submitted by licensees formerly using statements of intent.
- Regulatory Ef6ciency -- The proposed requirements would result,in part, in enhanced regulatory effici:ncy, particularly in the avoidance of delays in decommissioning due to the lack of available funds that could cause potential health and safety problems. No change would be expected under the no-action alternatives. Under other options, regulatory efficiency may be affected as follows:
-- Under Option A-2: NRC will enhance regulatory ef6ciency through the proposed action by ensuring that decommissicaing can be carried out in a safe and timely manner and that lack of funds does not result in delays that may cause potential health and safety problems.
-- Under Option C-2: NRC will be able to track licensees
- financial assurance for decommissioning and monitor funds; obtain actions from
" licensees to correct financial assurance shortfalls in a more timely way; and respond to public inquiries about the status of decommissioning funding with detailed and complete information. Draft Page 18
' -- Under Option D-2: Prohibiting the use of statements of intent by Federal l_icensees would eliminate a potential futu e source of delay arising from disputes over whether the Federal goverruent has assumed responsibility l ;
for decommissioning costs that may cause potential health and safety l problems. 3.2 - Research and Evaluation of Information on Se:ected Attributes l This section presents the results of background research into several topics that can affect the l assessment of the regulatory options, either through qualitative judgments about the feasibility of l implementing certain options or by the, guidance this research and evaluation provides for the design of tn
~
quantitative modeling of the options. 3.2.1 Decommissioning Cost Estimates Used as Basis for External Sinking Funds NRC regulations at 10 CFR 50.75(b) establish minimum acceptable levels of financial assurance l or nuclear power reactors based on the type of reactor (i.e., PWR, BWR) and its power level (in MWO. Although these " certification amounts" are stated in 1986 dollars, the regulations require licensees to update the amounts annually using a specific formula provided in the regulations. The regulations also allow nuclear power reactor licensees to base their financial assurance levels on facility-specific
- decommissioning cost estimates, provided that the estimates are at least as great as the current certification amounts. Thus, licensees must base financial assurance levels on an amount that may be higher, but not lower, than the applier.ble intiation-adjusted certification amount.
This study enulated the applicable certification amounts (updated to 1994) for substantially all nuclear power reactors currently operating. The analysis then compared these certification amounts to the ' cost estimates reportedly in use in 1994 by operating and noneperating licensees." The reported estimates were ther. classified as less than, consistent with, or greater than the applicable certification amount. (Because the regulatory formula for updating certification amounts is fairly complex, licensee li ble estimates fh were classified as " consistent with" the certification amounts if thev were within 5 percent o t e app ca certification amount.) The results of this analysis, displayed graphically in Exhibit 3-1, suggest that current NRC certification amounts do not usually serve as the basis for funding levels:
" This analysis is based primarily on 1994 data reported in Annual Survey of Nuclear Decommbsioning Cost Estimates and Fu*nding Policies, Public Utility Survey, Gotaman Sachs, August 1995, la the case of a few licensees that were considered in this Regulatory Analysis, however, the Annual Survey did not provide any data. For these licensees, the necessary data for the same point in time were obtained from licensee SEC Form 10K filings or from the financial statements included in licensees' annual reports. Additional review of 10K forms for nuny of the other Licensen indicated that the 10K data were consiste with (and probably the source for) the data included in the Goldman Sachs report.
Drpft Pagt 19
Exhibit 3-1 Distribution of Utilities by Difference Between l ' Certification Amounts and Cost Estimates
- Cast EstNate f.ess than Certification Am ount 32%
Cost Estimate 22 % Whhin 5% of Certification Amount Cost Estimate Esceeds Certification Amount by More than 5% As Exhibit 3-1 illustrates:
- Only about 22 percent of licensees report cost estimates within 5 percent cf the inflation-adjusted certification amounts. Any licensees using accurate certification amounts should be among these 22 percent, along with li:ensees that prepared site-specific cost estimates that happen to be close to the applicable certification amount.
- Almost half of licensees,46 percent, report cost essmates greater than the certification amount. These cost estimates suggest the um of a facility-specitic estimate that exceeds the certification amount. It is also passible, however, that cost estimates in this group may include ecsts of non-radiciogical work Shich is
- not required by NRC)in addition to the certitbtion amoum or, alternatively, in addition to a decommissioning cost estimate that may be higher or lower thsn the certification amoum. (In fact, of 22 States where PUCs are known to require utilities to prepare cost estimates,18 allow non-radiological "greenfi:ld costs" to be included.)"
- A full 32 percent of licensees report amounts that are more than 5 percent less than the applicable minimum certification amount. These cost estimates, if accurate, would seem to indicate licensecs' non-compliance with 10 CFR 50.75(b). These amounts could be due to low site-specific cost estimates or to certification amounts that are not fully adjusted for inflation.
" Nuclear Decommissioning Accounting Briefing Paper Presented to the Committee on Finance and Technolo By the Stagsubcomminee on Accounts. National Association af Regulatory Utility Commissioners, July 1994 Drqll Page 20
a 1 in general, these findings suggest that a significant majority of licensees (probably more tha 4 percent) prepare facility-specific cost estimates and use these estimates to determine the requ fmancial assurance. 4' 3.2.2 Projecleo funding Status of External Sinking Funds j This section reports on the adequacy of the amounts curready being collected in external decommissioning funds under NRC's current regulations. To comply with NRC requirements external i sinking funds must be fully funded by tlie time the associated nuclear power reactor shuts down. This study examined licensees' current decommissioning fund balances for their reactor (s) and their a l contributiore to those funds. It then projected fund levels at the time of each reactor's license expira' ion, ? and evaluated the projected level relative to the required amount of financial assurance.** This analysis assumes that decommissioning costs remain constant (in inflation-adjusted dollars), that licensees cortinue making annual contributions that are equal to their current annual contributions (in inflation-adjusted dollars), and that the real earnings rate on invested funds each year equals the real rate that is currently l' being assumed by each licensee." s ' The results of this analysis, displayed graphically in Exhibit 3-2, indicate that approximately 7 percent - or more than $2.7 billion - of decommissioning costs will be untundea at license expirat of the more than $37 billion in total decommissioning costs for all nuclear power reactors. Underfunding could be higher if licensees are unable to earn their assumed real rates on invested decommissi I Exhibit 3-2 Projected Funding at Time of License Expiration 3 (aggregate for all utilities in baseline, current regulations) Unfunded 7.3 % Fundedin Esternal Trust 92.7 %
" The required amount of financial assurance is assumed to be the higher of the licensee's reporte decommissioning cost estimate or the appropriate certification amount for the reactor as called for u 50.75(c).
" Real rates assumed by licensees range from 0-8.7 percent, with an average rate of 3.7 percent. Source:
f Annual Survey, Gok! man Sachs,1995. i Draft Page 21 I l
l 3.2.3 Reporting on Status of Deconmiissioning Funds i Licensees currentj are not required by 10 CFR Part 50 to prepare and submit reports on decommissioning fund status to NRC following the submissicn of the initial decommissioning report specified in 10 CFR 50.33(k) indicating how reasonable assurance will be provMed that funds will be available to decommission the facility. Section 50.75 (" Reporting and recordkeeping for decommissioning planning") requires licensees to keep records of information important to the safe and effective decommissioning of the facility in an identifiable location until the license is terminated. Such records include records of the cost estimate performed for the decommissioning funding plan or of the amount certified for decommissioning and records of the funding method used for assuring funds. Section 50.75(f) provides that at or about 5 years prior to the projected end of operation the licensee must submit a preliminary decommissioning plan containing a cost estimate for decommissioning and an up-to-date assessment of the major technical factors that could affect planning for decommissioning. The section also provides that "If necessary, this submittal shall also include plans for adjusting levels of funds assured for decommissioning to demonstrate that a reasonable level of assurance wiil be provided that funds will be available when needed to cover the costs of decommissioning." Section 50.75 also notes explicitly that funding for decommissioning of electric utilities is also subject to the regulation of agencies such as the Federal Energy Regulatory Commission (FERC) and State public utility commissions (PUCs). In addition, NRC has noted elsewhere that accounting standards, such as the standards of the Financial Accounting Standards Board (FASB) and rules pertaining to Federal taxation lead to the collection and reporting of information by licensees on the status of their financial assurances for decommissioning. This section examines the extent to which the information prepared by licensees for any or all of the purposes described above are likely to provide information that can be used by licensees to satisfy NRC reporting requirements or can be used to substitute for such reporting requirements. FERC Reporting FERC's jurisdiction extends to the interstate transmission and delivery of electric power. Under rules promulgated by FERC on June 30,1995, utilities that are subject to FERC jurisdiction (" Commission-jurisdictional") are required to set up trust funds to provide for the decommissioning of their nuclear power plants. FERC uses both the phrase "nudear power plant" and the phrase " nuclear unit," without stipulating if funds must be plant-specific or reactor-speciftc. (Plant-specific reporting could combine information about more than one reactor.) FERC's rules provide that if a public utility has elected to provide for the decommissioning of a nuclear power plant through a nuclear plant decommissioning fund, that fund must meet certain criteria specirted by FERC, (Such fundt, may be, but are not required to be, " qualified" Nuclear Decommissioning Reserve Funds under 26 USC 468A (the Internal Revenue Code). A utility may establish bot qualified and non-qualified funds with respect to its interest in the same nuclear plant.) Utilities are required to deposit at least quarterly all amounts included in Commission-jurisdictional rates to fund nuclear power plant decommissioning. The utility is required to provide the fund's investment manager with essential information about the nuclear unit, including the following: Drqft Page 22
*. the nuclear unit's description and location:
- the expected remaining useful life of the unit; j i
a the expected decommissioning plan; i a the utility's liquidity needs once decommissioning begins; and l
- any other information that the fund's investment manager would need to construct and maintain a sound investment plan.
The utility is mandated by FERC rules to submit annual reports to FERC, suggesting that FERC expects the utility to receive annual reports ficm its trustee (s). The rule requires submission "by April 1. 1996 and by March 31 of each year thereafter, a copy of the financial report furnished to the utility by the Fund's Trustee. . . ." ne information reported to FERC must include the following:
- Fund assets and liabilities at the beginning of the period;
- Activity of the fund during the period, including amounts received from the utility, purchases and sales of investments, gains and losses from investment activity, disbursements from the fund for decommissioning activity and payment of fund expenses, including taxes; and
?
- Fund assets and liabilities at the end of the period.
*1he rules explicitly state, however, that the report "should not include the liability for decommissioning" in its description of fund liabilities, because FERC considers the decommissioning expense to be a liability of the utility and not of the fund.
The usefulness of the FERC reporting requirements as a model for potential NRC reporting requirements pertaining to the amount and adequacy of decommissioning financial assurance or as a substitute for them is affected by the following factors:
- The FERC standards provide support for the conclusion that even a requirement that annual reports be submitted by licensees would not create a large additional reporting burden on those licensees that are already required to report to FERC.
Moreover, all of the key items of informafion that would be needed for satisfying an NRC reporting requirement should already be collected for purposes of preparing the FERC report. FERC annual report information could provide inputs for even the triennial reports being proposed.
- For some licensees, however, the FERC reporting requirement may not continue to e.-ist after deregulation. A company engaged exclusively in generation, separm from companies engaged in wholesale transmission or end-user distribution, would probably no longer fall under FERC jurisdiction and therefore would not be required to prepare FERC reports.
Drqft Page 23
. - - - . -. ~ - .-. - -. . ._-
- FERC reporting will address only that component of decommissioning that is Commission jurisdictional." If only a portion of a plant's power is sold at wholesale, FERC will have jurisdiction only over that pioportion of the plant's decommissioning costs. Therefore, the reports will not be likely to include information that is fully adequate for NRC's purposes, becaue they will not cover the full amount of the plant's decommissioning obligation.
- For utilities owned by more than one company, a separate report may be prepared by each company's trustee. The full picture of the FERC " Commission-
' jurisdictional" decommissioning funding for a plant might need to be put together from everal reports.
- The extent of compliance 'vith FERC reporting requirements over an extended period carmot yet be estimated, since the initial reports were required to be submitted by April 1,1996. FERC has found tht the initial group of reports presented some problems. Some utilities presented information only on their "Comrnission jurisdictional" decommissioning funds; others apparently provid*A information on all of their decommissio:Jng fmancial assurance, whether requa i by FERC or by NRC. Some utilities provided information about every transaction entered into with respect to their decommissioning funds over the preceding year, while others provided more summary information.
- The level of review and scrutiny given these reports by FERC cannot yet be determir* j because FERC's requirements have only recently been impletuented.
FERC has concluded that requiring annual reports will provide " greater flexibiiity" for monitoring funds, suggesting that every report might not be reviewed every year. In addition, FERC has not made the reports part of the structm torns for its electronic filing requirements. In summary, FERC reports provide a good mov A for the types of it formation that could be secured from NRC licensees on a periodic basis. FERC's reporting system cannot be expected, however, to provide a fully adequate source of information that could substitute for reports to NRC because jurisdiction is limited and deregulation might end FERC's jurisdiction over NRC licensees, and because FERC reports cover only a portion of the complete decommissioning obligation, Reporting to State PUCs All State PUCs require some type of reporting on the status of decommissioning fmainial assurance. The scope, level of detail, the frequency of reporting, and the degree, of scrutiny of the reports by the various PUCs, however, can dif'er substantic.lly from State to State in July 1994, the suff subcommittee on accounts of the committee on finance and technology of the National Association of Regulatory Utilay Commissioners (NARUC) presented the results of a survey of State PUCs examining how nuclear decommissioning cost estimates were currently being treated and the review given those estimates by State PUCs. Draft Page 24
According to the N ARUC survey.2* the level and frequency of scrutiny gisen by PUCs to cost estimates is not particularly high. Although site specine cost estimates are more frequently used than NRC certi6 cation amounts in the reporting States, most of the PUCs in those States conduct somewhat l infrequent reviews of the cost estimates. nree State PUCs reported in 1994 that they had not yet reviewed cost ..timates; six PUCs reviewed every 3 years; three every 4 years; and two every 5 years. At least thirteen State PUCs reviewed cost estimates only as part of a rate case. l Some State PUCs clearly require a detailed study of expected decommissioning costs to be performed frequently. Texas law, for example, specifies that electric utilities are required to perform or update a study of the decommissioning costs of each nuclear generating unit that it owns or in which it leases an interest at least every 5 years (Substantive Rule 23.21(b)(1)(F)). Public nodce and an opportunity for public comment are frequently provided for such decommissioning cost updates. New Jersey, for example, requires updates every 5 years, offets a 60-day public comment periad on the undates, and may, if necessary, convene a formal proceediu to review the present funding level (N.J.A.C.14:5A-3.1 and 3.2). Illinois, in contrast, considcrs the status of decommissioning funds not to be public information. Cc,nnecticut (which did not respond to the N ARUC surveg Grst required I submission of a decommissioning funding plan as of January 1,1993, with updates every 5 years, or more frequently if it finds that more frequent review is desirable. The State PUC is required to hold a public hearing on the plan. The Connecticut PUC is empowered to review the esumaed date cf closing of the ! nuclear power generating facility, the estimated cost of decommissioning, the reasonableness of the method I selected for cost estimate purposes, and the adequacy of plans for Gnancing the decommissioning and any shortfall resulting from premature closing. After conducting a review, the PUC may, after a hearing, order any changes to the decommissioning Onancing plan that it deems necessary to ensure tnat the estimated time of closing and estimated cest of decommissioning the fawility are reasonable; that the licensee and owrers can adequately fund the decommissioning; that plans for financing any shortfall resultin a; from a premature closing aN adequate and reasonable; and that the owners are legally bound. Michigan's procedures call for review of cost estimates every 3 years, and the PUC reviews the adequacy of funding for decommissioning in the course of ratemaking actions. The information collected by N ARUC in its survey indicated that all or almost all of the utilities with nuclear power plants were relying on external sinking funds to demonstrate Gnancial assurance for decommissioning (with some noting the incentive that the Internal Pevenue Service's $468 A requiremems gave for the use of external fundst (N ARUC did not examine whether each owner of a utility had sat up its oven sinking fund, and, if so, State PUCs reviewed each fund separately.) However, the survey also suggested that there was not a high degree of PUC oversight of those external sinking funds. Atleast twelve States reported that they did not review the performance of the trust fund investments on r routine or periodic basis. Maryland, for example, did not claim, to do annual reviews, stating that "no performance review is done of the trust fund except for the cursory review based on annual reporting,." Only four States reported annual reviews, with two more reviewing even more frequently (monthly and quarterly). Texas reported that companies were required to report fund balance, deposits, and breakdown
" Nuclear Dewmmissioning Acc<wntmg Briefing Paper Presented to the Canminee on Fin mce and Technology By the Staf Subcomminer on Accounts, hational Association of Regulatory Utility Conunissioners, July 1994. The survey consisted of a written questionnaire containing sixteen questions, submitted to each of the Gfly States and the District of Columbia. Thirty-three responses were received. Within this group, only five State PUCs reported that none of their regulated utilities had ownership or responsibility over any portion of a nuclear power plant, of the 18 non-responding PUCs, nine could be expected to have regula;ed utilities with nuclear power plants in the State. The survey's results thus represent about 75 percent of the pertinent PUCs, Draft Page 25
of trust assets semi ennually, but bacause the trust funds were relatively small and because of limited staff resources, they were not being closely monitored. ' Three more States reviewed every 3 years, and two more every 5 years. Two States reported that they reviewed fund performance during rate activia. Even for those States that reported reviewing the performance of the external sinking funds, the NARUC survey presided no information about whether the State PUC checked to ensure that annual contributions were being made in the correct amounts. There was no suggestion that the PUCs carefully rev!ewed the text of the external trust fund agreements, to ensure that_ they did not contain provisions threatening the security of the assurance being provided. At least sixteen State PUCs reported that they did not impose investment restrictions on the decommissioning funds (although at least one State that did not impose restrictions did place a cap on the market value of investrnents that could be included with a particular investment manager). New York, which did not itself place any restrictions on investments, noted that the IRS impond investment restrictions for quill 6 cation as a nuclear decommissioning fund under $468A. Twenty-one State PUCs reported that they did not " approve or oversee the selection" of the
. decommissioning fund's trustee and investment manager, while Illinois reported that the PUC approve,I
. trustee selection only.
In summay, because of the variations in scope, frequency, and level of review given reports by utilities to State PUCs, such reports cannot be espected to provida a fully adequate source ofinformation that could substitute for reports to NRC. Furthermore, following deregulation, any nuclear power generators that no longer fall under the jurisdiction of State PUCs might not be required to continue reporting to the PUCs. FASR Reporting Standards The Financial Accounting Standards lloard (FASB)is currently finalizing Snancial accounting standards for obligations that are incurred for the closure or removal oflong-lived assets, such as nuclear reactors. On February 7,1996, FASB issued an exposure draft (No.158-B) for comment.- Although the 4 final statement of financial accounting standards on this topic has not yet been released, it appears that the final standard will substantially resemble the exposure draft. The draft includes standards for recognizing i and measuring closure or removal obligations (decommissioning of nuclear facilities is eaplicitly included F in the scope of the standard), methods of accounting, and standards on reporting and disclosures.
. Under the proposed F ASB standard, an entity that reports a liability for its decommissioning obligations should disclose the following information On this description, the word "decommsloning" has been substituted for the term " closure or removal obligations" used in the proposed standard);
- A description of the obligation and of the related long lived assetsi
* . The liability for decommissioning (stated as ht e present val ue ofh t e est imatd e ,
future cash outuows required to satisfy the obligation) must be recognized in the , entity's financial statements, either on the face of the statement of financial position or in the notes to the financial statements; .
+ All assumptions that are critical to estimating the future cash outuows and the ;
liability must be recognized in the financial statements. These include: , I 4 Drgft Page 26 1
--. -- ,C_.---_. mms .-,4-,,, -
,,,,_,,--.,,,,,,____,,,,_,.,-,,m--.m-,,,_,,,.-._.,,,,
.. The current cost estimate for decommissioning;
- The estimated long-term rate of inflation used in computing the liaNlity.
- The estimated total future cost of decommissioning; l
-- The discount rate (s);
- The general estimated timing of decommissioning activities;
- The funding policy for decommissioning; l + The fair value of assets, if any, dedicated to satisfy the decommissioning l
obligations; f
- The effects on the reported liability and capitalized costs of decommissioning activities resulting from changes in the current reporting period in the estimated ,
future costs of decommissioning; j l i l
+ The individual components of the costs of d: commissioning recognized in the statement of operations (depreciation, changes in the present value of the liability
{ due to the passage of time, and investment earnings on any dedicated assets) and the total of those costs; and
. The caption or captions in the statement of operations in which the costs listed immediately above are aggregated if those costs have not been presented as a i
separate caption or rep tied parenthetically on the face of the statement. The F ASB s goal, in seeking these disclosures, is to ensure that companies " provide information .; that will be usefri in understanding the effects of closure or removal obligations on a particular entity . , " ne disclosures can be prepared, in the Board's opinion, 'without encountering undue complexities or l signifiant incremental costs."" Several important additional points should be noted concerning the FASB standards:
- F ASB states that the costs to store spent nuclear fuel that are incurred after closure of a nuclear power plant until the spent fuel is ready for Gnal storage should be included in the liability recognized pursuant to the standard, However, the costs of temporary storage of spent fuel that result from the absence of a facility for Gnal storage of the spent fuel should not be included. Unless fuel storage costs are reported separately, wlich the FASB standards would not require, distinguishing them from decommissioning costs for NRC's analysis would be dif6 cult.
Financial Ae >unting Starmintos Dontd. Exposure Draft: l'ruposed Stasement <f Financial Accounting Standards, Accoantingfor Certain Liabilities RelavJ so Closure or Removal oflong-Lived Assets, No. t$S-fl, Februnry 7,1996,199, p. 32.
Drqft Page 27
+
The draft standard does not change the existing general principle ti.at trust funds established for nuclear decommissioning are not eligible for offsetting against the liability for decommissioning on the financial statement. FAS8 explained that offsetting trust funds set up for decommissioning against the decommissioning obligadon for nuclear plants had been held in a 1966 FASB opinion to be inappropaate because the right of offset is not enforceable at law and t!,e payees for costs of decommissioning activities generally have not been identided at the reporting date. However, FASH asked for comments on this point in the 1996 ! Exposure Draft." !
/
+ FASB intends the standard to apply to rate-regulated entities, such as utilities j subject to State PUCs or FERC, as well as to non-regulated companies, i
+ The FASH standard would apply to 6nancial statements. Firms that are not i publicly held or traded on public exchanges will not be obligated to adopt FASD accounting principles, although they could do so.
+ Although the draft standard refers to "an entity," the standard apparently would allow an af61iated group of Srms that prepares a consolidated Gnancial report to disclose consolidated information about the gioup's decommissioning obligations, as long as the report addressed differences in timing and discount rates applicable to separate facilities.
In summary, although the F ASil standards, if approved, will help to establish unifarm sta for fmancial reports by publicly traded businesses, they may not directly provide that information in format that is uniformly well-suited to NRC's t:se because information on more than one teactor or even , more than one af61iated subsidiary may be comolidated. Nevertheless, licensees may readily be able comply with NRC's reporting requirements .f ticensees must collect non-consolidated information prerequisite to inecting the FASil standards. Tax Reports For a number of reasons, detailed below, tax reports tot a quali6ed Nuclear Decommissioning Reserve Fund or for a non-qualined grantor trust do not appear likely to provide information that a licensee could submit to NRC without extensive revisions to satisfy the proposed reporting requirement, or that NRC could use without extensive analysis to supplemera information reported by a liccuee. Suc on the current sire of the fund, and reports could involve (a) reports on payments into a fund, (b) report
- reports on income to and/or expenditures from a fund.
Section 468A Nuclear Decommissioning Reserve Fund Repons if a licensee elects to set ur a Nuclear Decommissioning Reserve Fund under $468A of the internal Revenue Code, payments into the fund are deductible in that tax year (in contrast to the rule thst payments to such a trust are not deductible). Therefore, the tax code includes explicit respecting such payments. The amount that the licens,/c may pay into the fund is limited eithtr (1) the amount of nuclear decommissioning costs which is included in the taxpayer's cos
" 1d.,184, p. 28.
Drpft Page 28
for ratemaking purposes for that usable year, or (2) an amount h" li (t e ru ng amount") specified on a schedule developed by the IRS that essentially provides for level funding of the amount remaining to be paid when the fund is established and the schedule is prepared. Gross .acome of a Nuclear Decommissioning Reserve Fund is taxed (at a rate of 20 percenti so reports of income must be made. In general, t.mqunts distributed from the fund to pay for decommissioning are to be included in the gross income of the apayer, but expenditures from the fund accomplish decommissioning are also treated as deductible costs to the taxpayer. Thus, the IRS reports of earnings and distributions from the fund. The following points address the usefulness of these tax filings as a source of potential informati on the size and adequacy of the decommissioning fmancial assurance: (1) Cection 468A apparently allows a taxpayer with a power plant containing more than one nuclear reactor to use the same Nuclear Decommissioning Reserve Fund for the entire plant. The Code states in 6468A(e)(1) that "Each taxpayer who elects the application of this section shall establish a Nuclear Decommissioning Reserve Fund with respect to each nuclear powerplant to which such election applies." Section 468A(f) also specifies that "the term ' nuclear powerplant' includes any unit theicof." Section 468A(e)(4)(A) says that the fund may be used for " satisfying, in whole or part, any liability of any person contributing to the Fund for the decommissioning of a nuclear powerplant (or unit thereof)." Thus, tax-related information provided by a taxpayer owning a plant with more than one reactor might not provide usefully disaggregated data about decommissioning funds with respect to particular reactors. (2) Section 468A apparently requires a taxpayer with several powerplants to set up a separate Decommissioning Fund for each plant. Although the phrase in 646BA(c)(9 cited above is ambiguous, it would probably say "with respect to all nucleat powerplants to which such election applies" if a single consolidated fund were permissible. (3) If several taxpayers are jointly responsible, through co-ownership, for a nuclear plam, Section 46BA apparently requires each of them to set up a separate Decommissioning Furd for their shares of the decommissioning costs. Information collected from severai taxpayers might be necessary to develop a complete report on the status of all funds pertaining to a particular plant. Contributions to decommissioning funds must be made within the tax year, (4) including a period extending 2% months after the end of the tax year. Thus, taxpayers with different taxable years could make payments into their decommissioning funds at different times, even with respect to the same co-owned plant, over a 14% month period, making comprehensive summary data more difficult to put together, The Internal Revenue Service has the authority to review and revise the schedule (5) of ruling amounts "at least once during the useful life of the nuclear powerplant (or, more frequently, at the request of the taxpayer)" (26 USC 468A(d)(3)). A a Drpft Page 29
1 i taxpayer who could derive no additional tax benents from larger deductions might not request the Service to amend the schedule of ruling amounts. even ifits decommissioning cost estimate increased. Grantor Trust Repons if a licensee elects to set up an external sinking fund segregated from its assets and outside its administrative control (but not qualified as a Nuclear Decommissioning Reserve fund under f4M), NRC's Regulatory Guide 1.159 does "not require that an external trust fund be established as a s tax paying entity. Thus, a grantor trust may be used" (p.1.159-4). Payments into such a be deductible in that tax year, so reports to or by the IRS involving payments would not need to be prepared. Regulatory Guide 1.159 specifies that annual reports of the current status of a trust (or escroe ar desirable. The language provided for.the trust (as well as the escrow agreement) in Regulatory Guide 1.159 is entitled " Annual Valuation." The suggested language, which specifies th;t "the Trustee for escrow agent) shall . . . furnish to the Grantor a statement confirming the value of 'he Trust," als i the alternatives of monthly, quarterly, or annually for the frequency of such reports. However, NRC al states that " Licensees may add, delete, or modify sample provisions as their circumstances warrant" l l). Thus, licensees apparently could specify longer than annual periods between reports. 1 I Trustees of grantor trusts are required by IRS rules to submit to the grantor annual statements ! showing all items of income, deduction, and credit of the trust for the taxable year so that the grantor ca take the items into account in computing its own taxable income and credits. The rules specifically' that the trustee of a grantor trust is not required to file any type of return with the IRS (26 CFR 11.67 Thus, licensees who have set up grantor trusts will receive annual reports of certain information fr! uustee, even if no full accounting is prepared by the trustee on an annual basis. 3.2.4 Availability and Security of Financial Assurance MedianLuns to Supplement or Replace External Sinking Funds NRC's Gnancial assurance regulations in 10 CFR 50.~15 currently distinguish between two
. categories of licensees. "an electric utility" and "a licensee other than an electric utility " The financia assurance mechanisms authorized for use by each differ. Under 650.75(c)(3), an electric utility may provide financial assurance for decommissioning by mer.ns of (1) prepayment, (2) an external in which deposits are made at least annually untilit has built op to the appropriate amount,(3) a surety method or insurance, and (4) for Federal government licensees, a statement of intent (although the proposal contaim a measure to climinate the use of statements of intent). Under 650.75(e)(2), a lic other than an electric utility may provide Gnancial assurance for decommissioning by means of(1) prepayment, (2) an external sinking fund, (3) a surety, insurance, or other guarantee method, in parent company guarantee or (4) for Federal, St.te, or local government licensees, a statement of in '
(although the proposal contains a measure that would limit statements of intent to non-power reactors key distinction in the current rule is made between electric utility licensees and licensees that are not '. electric utilities with respect to the external sinking fund option. Electric utilities are allowed to use an external sinking fund that builds up over time; licemees that are not electric utilities must couple their externa' d g fund with a surety method or insurance, the value of which may dec> cease by he amount mutated in the sinking fimd. beint Drt$ Page 30
Although the regulatory proposal would amend 'he de6nition of "electrie utility," the dennition would contmue to require that such an entity must recoser its costs through rater or other mandstory charges established by a regulatory authority. One effect of deregulation of the electric power industry, therefore, could be the shift of some nuclear power generator licensees out of the category of " electric 1 utility" if their access to funds through regulated rateraaking is limited or ended. Such licensees would then be required to couple existing external sinking funds with another Snancial assurance mechanism. ( Option A 2 suggests that such meenanisms could include prepayment, a surety bond, a letter of credit, or l any other method currently allowed in 650.75(e)(1)(iii). NRC's Rulemaking Plan also suggested that NRC might consider a certification to NRC from the ratemaking authority that all unfunded decommissionine obligations will be collected in rates, or a parent company gu arantee or self-guarantee. l This section addresses qualitative issues ass %1ated with the use of these Snancial mechanisms by licensees that are no longer defined as " electric stilitie " in the context of Option A 2. In particular, it discusses issues relating to the availability of certain categories of financial mechanisms (e.g., surety, insurance, and guarantee mechanisms); problems ofimplementation and security associated with certain l categories of mecbrdsms (e.g., certifications from state PUCs and statements ofintent); and issues relating to the development and implementation of certain categories of mechanisms not now in existence (e.g., parent company and self guarantees for electric utilitie! md/or nuclear power generators). Availability of Surety and Third-Party Guarantee Mechanisnts There are likely to be limits on the availability of surety bonds and other third-party guarantee finaacial mechanismr, such as letters of credit and lines of credit, to nuclear reactor licensees that are regtured to obtain such mechanisms to demonstrate financial assurance for the difference between their external sinking funds and the full amount of required assursnee if the licensee no longer quali6es as an
" electric utility." These lirnits may be created by the possibility, on the one hand, that the nuclear reactor licensees will no longer have recourse to the asset base or the utility, and that, on the other hand, providers of such financial mechanisms will require high levels of collateral and security before they will make such mechanisms available.
NRC has noted that electric utilities may create generating subsdiaries to operate nuclear power plants. These subsidiaries may be separated from af61iates providing bulk transmission iervices and distribution to end-use customers, with the corporate group ow ned by a common p rent." NRC has neceived commitments that licensees will notify NRC when significant assets are transferred from a licensee to its non licensed parent company. However, trends in deregulation and utility reorganization may cause power reactor licensees to have smaller asse' bases, potentially consisting primarily of the nuclear generating plant and contrachtal commitments for sales of power, while other significant assets are owned by the generating subsidiary's parent company or other affiliates. At the same time, the providers of Gnancial mechanisms such as surety bonds and letters of credit have frequently required collateral for a portion or the full amount of the mechanism, and there is no reason to expect that they will relax this requirement for mechanisms assuring the very large decommissioning costs of nuclear generating facilities. Generating subsidiaries without access to substantial assets may find it difficult to provide the necessary collateral.
" Consolidated Edison, for example, has notified the New York PUC that it is proposing to smburdle its genere6on company from its transmission ard dis:"bution assets. NRR1, " Status of Electric industry Restructuring,"
December 3,1996. Drqft Page 31
j I Availability and Security of Imurance Decommissioning insurance is not likely to be available h d from a from a traditiona licensees may seek to demonstrate financial assurance d msurance using decommissioni
" captive" insurer. ( A captive insurance company l i tilitiee is defined divest nuclear as a separately inc company that is c,wned by the party (ies) that it insures.) fh For example, as e ectr c u rporate groups powed generation facilities into separately incorporated l neration subsidiaries, the pa may set up captive insurance companies e provide Anancial assurance to the n subsidiaries or a subsidiary may even set up itsi iown captive. Cursently,10 sts for NRC licensees, latory any requirements that must be33satisfied by companies ins ld be similar to surety authorities to transact business as an insurer in one h ld theor more States" (#2 states that insurance used to provide financial assuran licensee default." l high The degree of regulatory scrutiny afforded a captive b ubject to certain state insurer before licen as the scrutiny afforded other types of insurers. Although l lyingcaptive to captives insurers that may e s ith respect to regulations and licensing requirement i l l
, several ired, captive insurers States{ ha minimum capitalization requirements, in addition to h the levels of capitalizat on requthan (
are frequ:ntly allowed to capitalire their operations t using a letter of credit rat erch a lett securities. In addition, the captive's parent supplies the collateral t to suppor su captive's financial strength thus is linked closely to the 6nancial f tive strength of its p ti home to domiciles are located "off-shore," 12 percent, and primarily Colorado,5 in the C nearly 70 percent of all captives licensed in the U.S., Hawaii has about percent." f Even a captive registered outside " li i therer"United in the State States where themay be admitted fo of the company's Gnan:ial transacting business with its corporate afnliate as a so called i a en nsu af6liated company is located. Under some State alien insurer statutes, rev ewN AIC) woul if the captive does not seu situation by the National Association of Insurance Commissioners i ( obtain approval to provide excess or surplus lines coverage as an alien nsurer, coverage to any entities other than its af611 ate (s). nBatesin the same Because captive inst w;e companies rely upon the assets of their parents h esembling the corporate group, a captive insurer will not afford the s ided by a parent company m guarantee (a guarantee assurance provided by a surety, more closely resembles the assurance prov guarantee or even the assurance that would be provided by a so-called cross-te group). of one subsidiary in r. corporate group by another subsidiary in that corpora
" Caprive larance Company Directory 19% Tillinghet Towers Perrin.
Drqft Page 32 _ ~ ~ ~ - - - - - - - - - - - ____ __ ~ ~ ~ ~ ~ - ' --
Although the regulatory proposal would amend the defmition of " electric utility," the defini would sontinue to require that such an entity must recover its costs through rates or other mandatory charges established by a tegulatory authority. One effect of deregulation l i of the electric po therefore, could be the shift of some nuclear power generator licensees out d of the category of "e ect utility" if their access to funds through regulated ratemakinghi is limited or ended. Such lic then be required to couple existing external sinking funds with another Gnancial assurance mec an sm. Option A-2 suggests that such mechanisms could include might consider a certi6 cation to NRC from the ratemaking authority that all unfunded dec obligations will be collected in rates, or a parent company guarantee or self guarantee. This section addresses qualitative issues associated with the use of these financial mechanisms l licensees that are no longer defined as " electric utilities" in the context of Option A 2, in particula l discusses issues relating to the availability of certain categories of fmancial mechanisms (e.g., surety, i insurance, and guarantee mechanisms); problems of implementation and security associated wit categories of mechaams (e.g., certi6 cations from state PUCs and statements of iment); and relating to the development and implementation of certain categories of mechanisms not now (e.g., parent company and self guarantees for electric utilities and/or nuclear power generators) i Availability of Surety and Third Party Guarantee Mechanisms There are likely to be limits on the availability of surety bonds and other third-party guarantee Anancial mechanismr, such as letters of credit and lines of credit, to nuclear reactor licensees that ar required to obtain such mechanisms to demonstrate fmancial assurance for the differenc external sinking funds and the full amount of required assurance if the licensee no longer qualifies
" electric uSlity." These limits may be created by the possibility, j of such fmancial mechanisms will require high levels of collateral and security before they will m mechanisms available.
NRC has noted that electric utilities may create generating subsidiaries to operate nuclear powet plan;s. These subsidiaries may be separated from afRliates providing bulk transnnssion distribution to end-use customers, with the corporate group owned redby a acommon parent? NRC has from received commitments that licensees will notify NRC when signincant assets are trans licensee to its non-licensed parent company. However, trends in dereguladon and unuty reorgardr may cause power reactor licensees to have smaller asse' bases, potentially consisdng prim nuclear generating plant and contractual commitments for sales of power, winie odier significant ass owned by the generating subsidiary's p. tent company or other affiliates. At the same time, the providers of financial mechanisms such as surety lxmds and letters of c have frequendy required collateral for a portion or tho full amount of the mechanism, and there reason to expect that they will relax this requirement for mechanisms assuring the very large decommissioning costs of nuclear generating facilities. Gererating subsidiaries without access to substantial assets may Gnd it difncult to provide the necessary collateral.
" Consolidated Edison, for example, has notified the New York PUC that it is proposing i '
to unbundle its genere6on company from its transmission and disHbution assets. NRR1, " Status of Electric Indus December 3,1996. Drqft Page 31 a
-- ------ - - . - - - - - - - - - .- ~. .-
Availability and Security of Insurance l Decommissioning insurance is not likely to be available from a traditional insurer. However. , licensees may seek to demcnstrate financial assurance using decommissioning insurance purchase :
" captive" insurer. (A captive insurance company is detined as a separately incorporated msurance company that is c,wned by the party (les) that it insures.) For example, as electric utilitiec divest nuc power generation facilities into ser ,rately incorporated subsidiaries, the parents of the corporate groups l
may set up captive insurance companies to provide financial assurance to the nuclear generation 1 subsidiaries or a subsidiary may even set up its own captive. Currendy,10 CFR Part 50 does not specii any requirements that must be satis 6ed by companies insuring decommissioning costs for NRC license but Regulatory Guide 1,159 states that the insurance company *must be licensed by State regulatory authorities to transact business as an insurer in one or more States" (12.3.3). Regulatory Culde 1./$9 also states that insurance used to provide financial assurance for decommissioning "would be similar to surety bonding , . , in that it would guarantee that decommissioning costs will be paid to a trustee should the
!!censee default."
The degree of regulatory scrutiny afforded a captive insurer before licensing is usually not as high l as the scrutiny afforded other types of insurers Although captive insurers may be subject to certain state regulations and licensing requirements, several States have special licensing laws applying to captives thaf are somewhat less stringent than those applied to commercial insurers, particularly with respect to minimum capitalization requirements; in addition to the levels of capitalization required, captive insurers are frequently allowed to capitalize their operations using a letter of credit rather than with cash and/or securities. In addition, the captive's parent supplies the collateral to support such a letter of credit. De
- captive's financial strength thus is linked closely to the financial strerath of its parent.
Captive insurers also can be domiciled outside the United States. In fact, the majority of captive l domiciles are located "off shore," primarily in the Caribbean. For domestic captives, Vermont is home to nearly 70 percent of all captives licensed in the U.S., Hawaii has about 12 percent, and Colorado,5 percent." Even a captive registered outside the United States may be admitted for the limited purpose of transacting b.isiness with its corporate af61iate as a so called " alien insurer" in the State where the affiliated company is located. Under some State alien insurer statutes, review of the company's finan:ial situation by the National Association of insurance Commissioners (N AlC) would be suf6cient for it to obtain approval to provide excess or surplus lines coverage as an alien insurer, if the captive does not sel *
- coverage to any entities other than its affiliate (s).
Because captive insurance companica rely upon the assets of their parents or af61iates in the same corporate group, a captive insurer will not afford the ame degree of assurance as an independent third - party source of insurance. The assurance provided by a captive insurer, rather than resembling the ( assurance provided by a surety, more closely resembles the assurance provided by a parent company i guarantee or even the assurance that would be provided by a so-called cross-stream guarantee (a guarantee
- of one subsidiary in r. corporate group by another subsidiary in that corporne gsaup).
" Captive fraurance Company Directory 19% Tillinghast-Towern Perrin.
Drqft 1 Page 32 L I
Asailability and Security of Certificatioits from FERC or State PUCs in its Advance Netice of Proposed Rulemaking on Financial Assurance Requirements for Decommissioning Nuclear Po ver Reactors (61 FR 1547, April 8,1996), NRC raised the possibility of relying on certiLations from State PUCs and/or FERC pertaining to licensees that '1ad formerly be subject to ratemaking but that, due to deregulation, now had limited access to funds from ratepayers s PUC/FERC certification would provide assurance ta NRC that WI imfunded decommissioning obligations of the licensee would be collected (possibly through transmission access fees, system exit fees, distribution line charges, or other similar mechanisms). NARUC and a number of State PUCs have raised several arguments against the feasibility or desirability of such certi6 cations: s Neither FERC's current commissioners nor the current members of State PUCs can completely bind their sue,;essors. *lhe actions of current commissioners create precedents and expectations that are frequently dif6 cult to overturn, but changed political or economic conditions could icad in the future to abrogations of certifications, and NRC would be unlikely to bave any effective method of enforcing them.
- The jurisdiction (ard even the continued existence) of FERC or State PUCs in their current form might change in the future, and certifications would not outlast the entities giving the certification.
- The certification commitment that FERC or State PUCs would establish mechanisms sufficient to fund all unfunded decommissioning obligations might not be implemented. State PUCs, in particular, could face tensions between '
' accomplishing retail electric rate reductions through deregulation and the need to set access fees, system exit fees, or other similar charges high enough to fund decommissioning, as well as other costs that might be addressed through such mandatory fees. Without new Federallegislation, NRC would not have the power ' to force FERC or State PUCs to implement certi6 cation commitments.
- Finally, unlike other Gnancial assurance ahernatives, such certi6 cations are not an option that most utilities or power reactor owners or operators can obtain in the marketplace. Federal or State legislation would probably be needed to allow FERC or State PUCs to provide such commitments. There is little or no evidence that States are planning to seek such certification authority as part of their deregulation activities,"
" See, for exampte, Pennsylvania Public Utility Commission, Repon and Recommendation to th General Assembly on Electric Competitson, Juty 19% State of tiew YosL Po6 tic Service Canuni Order Regarding Competitive Opportunitiesfor Electric Service, Opinion No. % 12, Cases 94-E-095 20, 1996; and NARUC, Summary of Each State's Resar cturing Activities, March 1,1996, none of which iden any ongoing attempts to secure approval from State legislatures for State PUC certifications.
Drqft Page 33 I
l Availshitity and Security of Stctements of Intent T The proposed amendments to 10 CFR 50.75 would limit the use of statements ofintent, , withdrawing the possibility of using them from electric utilities (by ren aving 650.75(e)(3)(iv power reactor licensees, while retaining the possibility of use of statements of intent by no licensees (by amendir.g 650.75(e)(2)(iv). Some of the same issues raised by certi6 c also arise with statements of intent. f As it was proposed in 1985, the statement of intent was "a certifintion 11, 1985, that the appropria i governt.sent entity will be a guarantor of decommissioning funds" (50 TR S619, February emphasis supplied). Although the supplementary infcrmatien to the final rule discuss intent in terms of a " guarantee that a government agency will assume financial responsibility for decommissioning the facility" (53 FR 24036, June 27,1988), the rule language provides only th statement of intent must be a statement "containing a cost estimate for decommissioning', and that funds for decommissioning will be obtained when necessary " (53 FR 24050, June 27,1988, . currently codified in 10 CFR 50.75) > Regulatory Culde 1.159 further specifies that the statement of intent must contain "an , that funds for decommissioning will be requested and obtained sufficiently in advance of deco ' to prevent delay of required activities." Regulatory Guide 1.159 also provides slightly m uho may sign a statement of intent, specifying that it must contain " Evidence of the , ol the government entity to sign the statement ofintent." The statement of intent could present the following issues:
- Persons signing the statement of intent may be unable to bind their governmental entities over time, Mb their commitments may create a precedent and expectation that fue w,a be sought, the commitments cannot be binding on their successors or governmental superiors under different political or economic conditions, Federal statutes, such as the Anti-Deficiency Act, prohibit certain types of financial commitments. For States, the legal and fir,ancial relationship between the entity on whose behalf the statement of intent is being issued and the State may not create any binding obligation on the part of the State. State laws generally create precise standards defining when obligations of related or subsidiary entitles are obligations of the State, and prohibiting the creation otherwise of any debts, liabilities, loans, or pledges of credit of the State, This mechanism may, therefore, indicate only that the State is on notice that a claim -
may be asserted sometime in the future against it.
- Persons signing the statement of stent may in fact lack the au hority to make a commitment. States in some cases have enacted statutes similar to the Fed Anti-Deficiency Act, prohibiting officials from entering into fmancial commitments outside the legislative appropriation and allocation process.
+ The commitment provided may, in fact, resemble a weak self-guarantee.
Statements of intent signed by officials (e.g., trustees, executive officers, financial officials, or admmistrators) of the entig required to provide fmancial assurance that they will provide funds, reallocate funds, or seek and secure funds when Drpft Page 34
.A
necessary, do not appear to represent the same degree of assurance as unancial mechanisms issued by thitd party providers such as banks and surety companies or the assurance provided by a licensee that has obtained a written guarantee from a parent or passed a test for sel6 guarantee. No such test must be passed to use the statement ofintent.
- TVA points to a number of reasons why its committnent to fund decomndssioning l
I u hen necessary is supported by its legal or financial situation." TVA is a corporate agency that is wholly owned by the United States, and whose real property is held in title by the United States. Congressional appropriations are the primary source of funding for TVA's nonpower programs, although TVA has indictted that it may decline Congressional funding for certain programs in the
.- future, income from the TVA power program comes from the genere. tion, transmission, and sale of electricity. - (in 1094, gross generation was approximately 70 percent coal,16 percent hydro, and 14 percent nuclear.)
j Although the service area of TVA is defined by law, competition in the electric power market can occur from other electric utilities and from the natural gas l i industry. TVA considers itself to be required by Federallaw to set its electric power rates high enough to produce revenues suf6cient to meet operating , i ' expenses, including expenses of decommissioning TVA's nuclear units. TVA's 1 electric power rates are subject only to the authority of the TVA Board of Directors, and are not subject to review by State PUCs, FERC, Congress, or the judic.ary, although TVA's power syster* budget is sent to the President and Congress for informational purposes. 'fVA has sought'a protect its revenue stream from power generation through the execution of requirements contracts with its distributor wholesale customers that contain rolling 10-year minimum j 4 termination provisions, and in FY 1995 about 87 percent of its total power revenues were received from such contracts. Ct,rrently, one municipal customer _; accounta for approximately 9 percent of total power sales and fcnr other municipal custoiners account for an additional 20 percent of total power sales. All 6ve of these customers have contracts that in no event would terminate in less
- than 10 years. TV A has the authority ta issue debt instruments, and in FY 1994 had outstanding long-term debt of about $22 billion; however. TVA is currently taking steps to reduce its debt. TV A's bonds currently have a very high (AAA) rating." Finally. TV A's decommissioning obligations, ahhough large, represent a comparatively small proportion of its annual operating revenues of over
$5 billion, and TVA has established a decomndssioning investment fund of over
$350 million.
" " Decommission'mg Funding Assurance Requirements Affecting TVA as a Federal Government
- Licens:e," Enclosure, TVA Comments on NRC Advance Notice of Proposed Rulemaking, June 24.1996.
See also, Tennessee Valley Authority 1994 Annual Report, " Charting A Course for the 21st Century."
" Moody's investor Services and Standard & poors' ratings for TVA are highly dependent on TVA's
, status as an agency of the U.S. government.
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Availability of Parent Guarantees and Self Guarantees Reliance on a parent company guarantee or a self guaramee througn passing a financial test similar in scope to the test contained in 10 CFR Part 30, Appendices A and C, to ensure power reactor licensee decommissioning would pose a number of potential issues, su;h as the fccowing:
- A utility that has spun offits nuclear ptmer reactors into separately incorporated companies might be reluctant to issue a guarantee obligation for decommissioning those plants. One of the effects of creating a generating suMidiary is to shield the transmission and distribution components and,or the owner of the corporate group from direct liability for the generating subsidiary.
+ Even if a corporate parent or affiliate is willing to undertake a guarantee for its nuclear generating subsidiary, the financial test included in 10 CFR Part 30
' Appendix A may not be an appropriate measure of its financial ability to do so.
That financial test was initially developed more than two decales ago to measure the financial ability of waste management firms *.o assure costs that are substantially smaller than nuclear decommissioning costs are likely to be. Some of the elements of the test (e.g., the net worth requirement) would need to be escalated to reflect current dollars. The financial ratios when the test was developed were not considered appropriate for evaluating the financial structure of utilities.
- A self-guarantee by a nuclear generating firm responsible for substantial unfunded decommissioning costs would pose particular problems. The tirm's large liabilities might make it unable to sausfy the current financial test for self-guarantees in 10 CFR Part 30 Appendix C. In addition, such licensees are poor candidates for self-guarantees if they do not have significant unencumbered assets in addition to the nuclear plant that itself 's creating the decommissioning obligation.
3.2.5 PotentialIndustry Restructuring Economic deregulation and restructuring m the electrie u61ity industry, which is expected to lead to increased competition in the industry, may have, as one of its consequences, the disaggregation of integrated power systems into their functional components. In particular, electrical generation may be separated from transmission and distribution, either by being .cpun off into separate subsidiaries, sold, or merged into new entities, in some cases, particular generation plants may prove to be noncompetitive and be retired early. This industry restructuring, and possible plant closures associated with it, will be closely linked to the pace of deregulation. This analysis did not attempt to develop a precise forward looking estimate of how, when, and where industry deregulation will occur or of the number of utility restructurings or premature closures of generating plants that might be associated with deregulation. A review of typical State plans for dereguladon, summaries of the status of deregulation across the country, and commentary by industry representauves, however, was used to develop the modeling scenarios described in Section 3.3.2. l l Draft Page 36 l
l'hase In Periods for Deregulation I State PUCs, legislators, consumer and business groups, and utilities have all proposed a broad range of time periods within which electrical industry dereguiation could be carried out, and there is some ; possibility that r'ederallegislation could preempt State timetaNes. De pace of futu e deregulation willin part be determined by political as well as technical factors, varying from State to State. In New York, for example, large consumers of electricity favor rapid deregulauon, with phase in periods as short as 3 to 5 years; residential and small commercial consumers support a variety of timetables; and some utilities urge l delaying action until several outstanaing issues have been resolved." In 1996 the New York State PUC adopted early 1997 as its goal for wholesale competition and early 1998 as its goal for getting actail access underway," A law restructuring California's electric industry was passed and signed in late 1996, with implementation goals of January 1998, Several other States are seeking to deregulate, at least in the ! wholesale market, in the 1998 to 2001 period." Re Pennsylvania PUC in July 1996 recomn ended a phase-in plan leading to full retail access to competitive generation by 20N " and Commonwealth Edison and several other major utilhies and industry groups have proposed draft legislation to the Illinois PUC that would provide direct access for residential customers by 2005." 1 In cortrast, a survey undertaken by the National Regulatory Research Institute (NRRI) indicates that at least 27 States have no current plans to undertake deregulation at the retall level. Many of these States are in the initial stages of investigating the issue. Fewer than six have concluded that deregulation would act be desirable in the State, according to surveys undertaken by NARUC and NRRI, but a number of other States are proceeding slowly and haitingly." The States that are hesitant about deregulation tend to be less populated end urbanized, located in the South, Northwest, Southwest, and Midw:st. Although a number of utilities and State PUCs that commented on NRC's .sdvance Notice of Proposed Rulemaking stated that the likely timetable for deregulation could not be estimated, several ! others, including the Nuclear Energy Institute, projected that approximately a decade would be needed for i industry restructuring and deregulation.
- State of New York Public Service Commission, Opinion No. 96-12. Cases 94-E-0952 eLal., in the Matter of Competitive Opportunities RegarJing Electric &rvice, Opinion and Order Regarding Competitive Opportunitiesfor Electric Service, May 20,1996, pp.15-18.
"IJ.p.72.
- The New York Times '"Ibe Nuclear Power Puz.zle: Deregulation Raises Questions Over Construction Debt,"
Dl, D3, January 3,1997.
" Pennsylvania Public Utility Commission. Report and Recornmendation to the Governor and General Assembly on Electric Competition (From the Investigation into Retail Competition at Docket No. 1-940032), July 109b, p. 27.
" NRR1, " Status of Electric Industry Re.tructuring " December 3,1996, p.16; 7he New YotA 71mes, January 3,1997.
" NARUC, ' Summary of Each State's Restructuring Activities (3/1/96)"; NRRI,
- Status of Electric industry Restructuring," December 3,1996.
Drqft Page 37
~ .. . . ..
State PCC Plans to Address Deconunissioning Co3ta During Iktryulation l l No attempt was made to obtain detailed infoimation about the pie;i:e plans for dealing with decommissioning costs of each State PUC or State legislature that is incestigating deregulation or developing detailed deregulation proposals. In a number of States uhere deremdation is likely to occur, or is underway, it is still too early to specify exactly how decommissioning costs will be addressed. In New York, for example, mandatory access fees or distribution charges are under consideration, but the State l PUC expects to reassess its initial rate structure after the competitive market has been in effect for a few years.* ' He California PUC's decision on electric utility restructuring provides utilities 100 percent recovery of their transition costs, including the difference batween the book value and the market value of i their generation assets and costs of regulatory obligations," and legislation enacted in September 1996 also provides for recovery of stranded investments.'2 Iloth California and the Pennsylvania PUC, which apparently modeled its deregulation plan closely on California's, have proposed using Compe6 tion Transition Charges to recover stranded costs (including about $14 billion of nuclear stranied costs in California)." A majority of the commenters on NRC s Advance Notice of Proposed Rulemaking also predicted that regulatory mechanisms, such as mandatory wire charges / transmission charges, exit fees, or other non-bypassable fees, will be developed and used to enable prudently-incurrW . stranded costs to be recovered, although the mechanisms used will differ from jarisdiction to jurisdictien. Utility Restructuring and Premature Closure The National Regulatory Research Institute has collected information about restructuring of the electric industry that, among other topics, notes instances when utilities have submitted plans to their State PUCs that include divestitures or spinoffs of generating assets; utility mergers; and other similar actions. This information, which is incomplete, suggrts that a moderate degree of such activity is currently underway, although all of it does not involve nuclear generating facilities. The following summary provides examples of the types of retivities unt are occurring. In California, Pacific Gas & Electric has filed plans to divest 3000 htW of gas-fueled plants over a 2 year period. Because of the transmission pricing provisions in California's restructuring bill, signed in September 1996, purchases of out-of-State power are expected that would lead to the closing of California plants, and California's deregulation plans include substantial closures of fossil-fueled plams. In the Washington, D C. area, PEPCO and llattimore Gas and Electric have filed an application for mert,er, in Georgia, SPA has proposed to sell some of its generating facilities. In Kansas, Kansas City Power and L;ght sought unsuccessfully to merge with Utilicorp in 1995 %. In hiassachusetts, the New Englm) ELNuie System hu proposed full divestiture of its generating assets in hiassachusetts, New Hampshire, and Rhode island. In hiichigan, the legislative study group on deregulation studied the possibility of a energer between Northern States Power and Wisconsin Energy. In hiissouri, Union Electric and Central tilinois Power have merged. In New York, Consolidated Edison proposed a corporate restructuring in 0;tober 1996 that would create an unregulated
- State of New York Public Service Commission Opinion No. %-12, Cases 9&E-0952 cLal. In the Matter of Competitive Opportunities Regarding Electric Service, Order and Opinion Regarding Competitive opportunittafor Electric Service, May 20,1996, pp. 52 53.
" N ARUC, " Summary of Each State's Restructu. .g Activities (3/t/96)."
42 NRRI, ' Status of Electric Industry Restrucmring," *h.W 3, !"96, p. ~8
" NRRI, ' Status of Electric industry Restructuring," December 3,19^5.
Draft
- Page 38 l
1
l generation company and a regulated transmission and delivery company out of the existing utility. In addition, Long Island Lighting Company (Lilco) is seeking to merge with Brooklyn Union Gas, in an > arrangement in which the iong Island Power Authority would assume Liico's debt for the Shoreham nuclear plant." He information summarized above, although incomplete and qualitative in nature, provides i support for the assumption in the scenarios described below, part cularly the " managed deregulation" scenario, that full retail deregulation is unlikely in the immediate future in all States but will occur within about a decade; that recovery of decommissioning costs will occur through measures implemented by State PUCs or similar regulatory agencies; and that generation fa:ilities will not uniformly or completely be spun aff i.'to separately-incorporated entities susceptible to 3remature closure. 3.3 Model Design ) The results presented in this analysis (see Section 3.4) are based on quantitative analysis of cost and financial data for nuclear power reactors and their owners.- This section describes the general rnethods used to structure the analysis and calculate results. The discussion is divided into three parts. Section , 3.3,1 summarizes the development of the database used in the analysis. Section 3.3.2 describes the three basic scenarios that are modeled. Section 3.3.3 addresses how each regulatory option was examined within the model. Finally, Section 3.3.4 discusses a few kej assumptions, 3.3.1 Development of the Database To help quantify the effects of the proposed rule, a database was developed containing . f decommissioning cost data for nuclear power reactors and decommissioning funding data for the licensees that own these reactors. The database includes a variety of data from the following sources: ,
- Nuclear Regulatory Commission Information Digest.*' The information Digest
provided reactor specific information including unit name and type, location, , operating status, operating license expiration date, and licensed MWt. Annual Survey of Nuclear Decommissioning Cost Estimates and Funding ;
=
i i Policies, Pubuc Utility Survey ** The Annual Survey reports the following l information for most companies with full or partial ownership of one or more nuclear power reactor units unit name, percentage share ownership of each unit, share ot~ estimated decommissioning ccsts for the unit, total estimated decommissioning costs for the unit, license expiration date, expected year . decommissioning will commence, the amount of funds set aside in external decommissioning funds (qualified and non-qualified) as of year-end 1994, the
The New York 71mes
- Bonus for 1.ilco Stcckholders if State Takes Over Debt," January 1,1997, p. 45.
Nuclear Regulatory Commission information Digest, NUREG-1350, Volume 7, U.S. Nuclear Regulatory L Commission, Oftic- of the Comptrotler, March t995.
Annual Survey qf Nuclear Decommissionim Cost Estimates and Funding Policies, Public Utility Suney, Goldnutn Sachs, August 1995 Table 32. (A more recent version of this survey is not currently available.)
DrRO Page 39
e 1994 contribation to external decomminioning fum and tu usumed rate o earnings on collected decommissioning fundJ Licensee Annual Financial Statementsfrom SEC Fonn 10K Hlings an Reports. For a few licensees, the Annual Suewy data we incomplete licensees, the necessary data were obtained from licensee Sif form 10K f or from the financial statements ineluded in licensee annual reports. (A review of the annual financial statements of nuny licen*,m oggests that the financ;al statement data are consistent with, and powbly the <>urce for, th Form 10K filings aaJ annual reports also included in the Annual Survey report.) provided data on licensees' operating revenues and total assets. Nuchar Hant Owners and Operators." This document was used to confirm licensee ownership for individual power reactors. The database also includes informationi hon each reactor's cert 10 CFR were calculated using information on unit type (i.e., PWR or DWR) in accordance " wt 50.75(c)(1). To account for bflation since 1986, these amounts were then a formula specified in 10 CFR 50.75(c)(2), along wif.: data fiom NRC's Repo and regional data on labor rates and energy prices from the U.S. Department of La Although the database ac' counts for all operating nuclear power reac 100 percent ownership of all reactors (due to data limitations) l (i .e . , but ra percent ownership. As a result, the analysis willl proportionately if the licensees in the understate total results for alllicensees) that are stated in dollars (as biased toward larger licensees. Note: Because the niost recent decommissioning fuwung data available were s dollars, othet amounts used in the analysis were c
" In some cases where data are reported on i an aggregated rtion to the amount of basis (e.g.,
all the reactors owned by the company), the data werei apportional to mdistual umts n propo each facility's certification level and the pexentage of operating tife remain ng.
" Nuclear Plant owners and Operators (Attachment 2 to SECY-94 280L November 18,1994.
L l Waste
- Report on Waste Burial Charges: Escalation af Decommissioning l Waste D Burial Facilities. Rev. 5. NUREG-1307. U.S. Nu-lear Regulatory Commission, Off Research, August 1995.
i D-1 and
- Reactors of the Tennessee Valley Authority, however, are analyzed only with res D-2.
l Draft Page 40
l amounts and cost estimates were adjusted using the formula specified in 10 CFR 50.75(eX2)." Therefore, all dollar values reported in this study are 1994 dollars. 3.3.2 Modeled Scenarios The analysis builds on the database described above to model each option under three alternative I scenarios that differ regarding their assumptions about the deiep ,uion of the electric utility industry. Despite significant study of deregulation issues by FERC, PUCs. industry groups, and other3, it rem 4 in l uncertain how deregulation will evenually unfold, uhich set of companies and facilities will be affected. and, in particular, what the implications will be for nuclear power plant decommissioning costs. Consequently, the scenarios described below have been selected and designed to show the possible range of effects of each option. Like any models, they are useful simplifications of reality. They consider aspects of deregulation that are most relevant to decommissioning financial assurance, Ttey are not intended, however, to model or reflect other aspects of deregulation. in particular (and as discussed in Section 3.2.5), this analysis does not att:mpt to address the significant issue of premature closures of nuclear power plants as a result of deregulation (rather than as a result of NRC's rulemaking), or any corporate restructuring that may result. Other studies have analyzed issues related to deregulation-induced premature closures by combining signific mt assumptions about deregulation with complex models that examine the competitiveness of the costs of power generation at different facilities. Such an analysis was beyond the scope of this study. By excluding from the model the uncertain impact of deregulation on premature closures, this analysis may overestimate (but should not underestimate) the values and impacts of NRC's rulemaking." Similarly, the analysis does not attems to model the restructuring that may occur as a result of deregulation, and which might consolidate or disperse ownership of power reactors among current licensees or entities that are not currently licensees. This scenario assumes deregulation at the wholesale level consistent No Retail Deregulation with FERC rulemakings, but at the retaillevel assumes regulatory conditions as they exist today (i.e., pnot to deregulation). Managed This is perhaps the deregulatory scenario that is most likely to come Deregulation to pass (see Section 3.2.5). The specific details would likely vary by region or State (or bothh and might even include traditional regulation of utilities in some areas. Where deregulation is implementeo, however, the managed deregulation scenario assumes that regulators will allow all current electric utility licensees (or, in the event of restructuring, their power reactor licensee successors)
" in a few cases, decomm oning cost estimates were stated in future dollars, nese estimates were brought back to 1994 dollars using an annual rate of 3.26 percent, which is the average annual increase in the U.S.
Domestic Product (GDP) deflators over the period 1986-1995 (as reported in the U.S. Departmera of Commerce publication Economic indicators).
" For example, premature closures that occur prior to the effective date of NRC's rule woutd licensees affected by the rule, thereby reducing the values and impacts of the rule.
Drqft . Page 41
to recover all costs prudently incurred, including future decommissioning costs associated with power teactors built prior to deregulation. Costs may be recovered ePher directly through traditional " cost of service" reguhtion or indirectly through mechanisms such as mandatory transmission access fees, system exit fees, and distribution line charges. Reactor decommissioning costs would not be " stranded" under this seenario. For rnodeling purposes, deiegulation is assumed to occur (simultaneously for all ; licensees)in 2006,10 years after NPC's Advanced Notice of l Proposed Rulemaking for the current rule.
.Sinsseet Under stranding deregulation, licensees are assumed to be '
Deresulation ecmpletely deregulated with respect to cost recovery through rates, _ charges, and exit fees. Upon the arrival of deregulation, regulators
- would no longer be in position to, assure that licensees can recover any unfunded decommissioning costs. (Hus, such com would be
" stranded' due to deregulation.) For modeling purposes, deregulation is assumed to occur (simultaneously for all licensees) in 2006.
It bears repeating that these or ariy other scenarios are necessarily simplifications of the innumerable possible outcomes of the deregulatory process. However, these scenarios should adequately ' illustrate the effects of the various regulatory options as well as b und the analysis in terms of the range of values and impact of the rule. 3.3.3 Modeling of Regulatory Options , This section dAscribes how each pair of options has been modeled to quantify values and impacts , associated with the options' finar:ial assurance implicatioru. Ikfore beginning the sequential discussion of each option pair, however, several aspects of the modeling are noted here because they are generally applicable. First, the model assumes that deregulation affects every licensee in the same way and at the
- same time, in 2006 (see the previous discussion of the seen:.rio>t Second, ahhough the issus of premature closures of nuclear p~wer reactors in general has not been analyzed in this study, this analysis does consider whether the rulemaking itself is likely to_ lead to any premature cim.utes. To accomplish this, the model calculates incremental licensee Anancial assurance costs assuming that each licensee continues to operate as a viable entity and can continue to comply with applicable fmancial assurance requirements; these co? caults v.<ill be used later to assess the likelihood of premature closures due to the current rulemaking (see Section 3.4).
Options A-1 and A 2 Under NRC's current regulations and current definition of electric utility, nonalectric utility licensees may not use external sinking funds unless the external sinking funds are coupled with other Page 42
.a- .-. .. . . . . . . .. . . .-. . . . . - - . . .. .
financial mechanisms to assure the unfunded portions of their sinking funds." NRC believes that, at this time, all power reactor licensees meet the current definition of electric utility, As a result of deregulation, however, licensees may evolve into entities that will not qualify as electric utilities under the current definition but would be able, with the approval of FERC and'or PUCs, to recover the costs of decommissioning from ratepayers under the managed deregulation scenario. Under Opusn A-1, the no-l action alternative, the model assumes that such partially deregulated licensees would cease to be elect.ic utilities and would have to immediately obtain additional financial assurance for all amounts not yet j funded. (It is worth noting that NRC's current definition (and hence Option A l) could be interpreted to consider such entities to be electric utilities, in which case no additional assurance would be required. The l model applies the interpretation that they would not meet t u definition, however, because this interpretation is more consistent with NRC's inclination to revise the definition prior to deregulation.) l Option A-2, however, redefines the term " electric utility" to include partially deregulated licensees, if appropriate (i.e., if they recover costs directly through traditional " cost of service" regulation or indirectly through mechanisms such as mandatory transmission access fees, system exit fees, and distribution line charges), in the no retail deregulation scenario (i.e., the absence of deregulation) neither Option A 1 nor Option A 2 would have any cost or impact, Licensees would continue exactly as they are, meeting either the current deRnition of electric utility (under Optica A l) er the proposed definition of electric utility (under Option A-2), throughout the operating life, shutdou n, and decommissioning of their fecilities. Under the managed deregulation scenario, the model assumes that alllicensees meet NRC's proposed definition of electric utility (as discussed above), but do not meet the current definition.
- Under Option A-1, therefore, licensees will :.ot be allowed to use external sinking funds (except in combination with other financial mechanisms). Licensees are assumed to cease annual decommissioning trust contributions when they are deregulated in 2006 and to choose at that time between (1) prepaying the unfunded portion of their sinking fund," and (2) obtaining a letter of credia or surety bond on the same unfunded portion." The ecst ot financial assurance using prepayment is calculated as the licensee's opportunity cost incurred by putting aside money for decommissioning in advance of when the funds otherwise would have been required. The model calculates this opportunity cost by, first, calculating the
" The unfunded portion of a sinking fund is assumed to equal the amount projected to remain unfunded 0.e.,
after accounting for projreted earnings on funds invested as of the time the licensee ceasos to be an electric utilityJ at the time of license expiration, as opposed to the total un'unded amount at the time the licensee cer.ses to be an electric utility. In other words, licensees are given credit for future earnings on furxis collected to date.
" Prepayment is the most costly method of financial assurance. Therefore, licensees are unkkely to use prepayment urnu a other mechanisms are unavailable o unless, in the case of surety bonds and tetters of credit, t amount of coltateral required approaches the prepayment amount.
" Based on the research and analysis discust 4 in Section 3.2.4, other financial mechanisms (e.g., parent guarantees, insurance) are assumed to te unavailable.
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present value" so the licensee of its unfunded deconimwnmg costs and, second The con of Anancial subtracting this value from the prepayment amount. assurance using letters of credit and surety bonds equals the present v:lue of the annual fees (assumed to be 1.5 percent of the face value of the credit or bondt
- Option A 2, in contrast, would allow licensees to amd :he costs arising under Option A 1 by letting them continue to use exterral sinking funds in the manner that they are currently used.
In the stranding deregulation scenario, licensees will, subsequent to deregulation, fail to meet either the current de6nition of electric utility (under Option A 1) or the proposed definition of el utility (under Option A-2). Consequently,This licensees will not be allowed to use external si situation is analogous to, and has been except in combinat%n with other financial mechanisms. modeled the same as, Option A-1 under managed deregulation. Options B 1 and B-2 Two aspects of Options B 1 and B-2 rquire modeling: (1) the allowance of additional funding credits for earnings during the safi: storage period on prepayment mechanisms funds, and (2) the use of an assumed 2 percent real rate of return. Each of these features a calculation of annual contributions to decommissioning funds, thereby generating costs or savings attributable to the option:
- Credit for Earnines Durine Safe Storagt Currently, the total amount of licensees' sinking funds must be sufficient at the time of reactor shutdown to pay for estimated decommissioning costs at that time. Annual contributions to the fund must ce sufficient such that, with earnings on the fund during facility operation, the necessary value will be reached., Option B-2 would, in cases where >
decommissioning activities do not begin immediately with facility shutdown, permit the level of the decommissioning fund at shutdown to be less than the decommissioning cost estimate at shutdawn. He funded amount at shutdown, however, would have to be sufficient such that. with earnings on the funds (at the assumed rate of return) during safe storage,it would proside adequate funds to pay for decommissioning activities. His addmanal earnings credit would reduce the annual contributions made 3 b licensees, thereby generating savings attributable to the rule. A similar credit would be allow ed iot prepayment mechanisms.
- Assumed 2 nercent Real Rate of Return. The pops.ed rule would allow licensees to assume a real earnings rate of 2 percent, except where a regulatory authority (e.g., FERC or PUCs) specifically allows otherwise. NRC believes that all power reactor licensees currently fall under the jurisdiction of a regulatory a tthority and, therefore, that all rate of return assumptions currently in use by licensees meet with the approval of the applicable regulatory authority.
Therefore, it follows that, in the no retail deregulation scenario, the 2 percent provision will not apply to any licensees. Simits.tly, it will not apply under the
" Unless otherwise noted, mil present value cniculstions were made using a discount este of 7 percent, i accordnnce with NRC's Regulatory Analysis TechnLal Evaluation Handbook, August 1993, page B-2.
[ l Draft ! Page 44 l 1'
managed deregulation scenario because regulators will continue previding ! oversight of the assumed earnings rate." Under the stranding deregulation scenario, licensees' earnings rate assumptions no longer fall under the jurisdiction of an appropriate regulatory authority, and licensees also cease te meet NRC's definition of electric tulity. In these casds, NRC regulations will not permit continued use of an external fund (unless coupled with ancther financial t mechanism). Thus, the assumed earnings rate of 2 percent would be applied by I the model only in calculating amounts not yet funded by the sinking fund (allowing for earnings of 2 percent) and by licensees using prepayment rnechanisms to I assure such unfunded amounts." Options B-1 and B-2 are modeled as follows. First, to avoid mis-stating impacts in cases where j licensees are presently underfunding or overfunding their sinking funds, the analysis adjusts projected annual contributions oflicensees such that the contributions, if continued through the facility's operating life, would be suf6cient (with interest at an assumed pre-tax rate of return of 4.3 percent)" to fully fund the external enking fund without overfunding or underfunding. Next, the model calculates the value of each licensee's external sinking fund at the beginning of 1998, when the rule is presumed to take effect. Annual contributions prior to 1998 are asjust described, and the funds are assumed to earn a pre-tax return of 4.3 percent. (Consistert with IRS rules applicable to "oualified" decomm'.ssioning trusts, this analysis assumes a 20 percent tax on all fund earnings.) In 1998, the model assumes that all licensees will recalculate annual contributions to take advantage of the earnings credit allowed during safe storage. l Assumed earnings rates are not revised to 2 percent because, as discussed above, licensees remain as regulated electric utilities at least unti! 2006 under all scenarius. Therefore, annual contributions beginning in 1998 decrease for alllicensees that have reported plans to delay commencent of decommissioning activities beyond the expiration of their operating license (even if the licensees have not speci6ed that the delays are the consequence of selecting the safe storage method of decommissioning)." Under the no
" To meet NRC's delirition of electric utility, licensees must be able to recover the costs of decommissicaing through rates, fees, or charges established by their regulatory authorities. In setting these rates, fees, or mandatory charges, regulators would (at least implicitly) approve or accept an earnings rate assumption, llecause regulatory authorities such as FERC and State Pt'Cs are responsible to their ratepayers, it seems unlikely that they would then give up oversight over monies couetted in advance from the ratepayers to pay for decommissioning.
" In reality, licensees would also apply the 2 percent rate in calculating post-deregulation contributions to the sinking fund.
" This analysis has incorporated the relatively simple assumption that pre-tas real rates of return on decommissioning funds will average 4.3 percent annually. This rate represents the historical average real rate on an investment portfolio that evenly balances high quality stocks and bonds. (lhis ponfolio is representative of the actual investment policies applied to external decomm:ssioning trusts, as reported in Annual Surwy of Nuclear
- Decommissioning Cost Estimates and Funding Policies, PuMic Utility Survey, Goldman Sachs, Augu2t 1995, Table 31.) The average real rate of return for long-term government bonds is 1.7 percent, and the average real rate of return on large company stocks is 6.9 percent. Thus,4.3 percent equals the average rate on a hypothetical portfolio consisting of 50 percent long-term government bonds and 50 percent large company stocks. sinterest rates are historical geometric means as reported in Stocks, Bonds, Bills and inflation 1995 Yearbook: blarket Pesultsfor 1926-1994, Table tr7, Ibbotson Associates, Chicago, IL,1995.)
- Many licensees currently report plans to delay commencement of decommissioning activities beyond the expiration of their operating licenses. The reported delays, however, are typically fairly brief (e.g., less thar3 (continued...)
Draft Page 45
retail deregulation and managed deregulation scenarios, each li:ensee u t.rms these con license expiration. Savings to licensees /ratepayers equal the nt:sent nue M :he reduced an that result from the option. Under the stranding deregulation scenario, however, ,icensees are .mmed to obtain a prepayment
' mechanism or a letter of credit or surety bond in 2006 to assure any cca ao: set assured by the sin fund. Prepayment amounts would be calculated to rettect both the .afe comp earnings cr percent earnings assumption. Because currently-reportof safe sterage perufi ire typically previous footnote) and currently-reported earnings assumptioru ue, on a,e in , higher than 2 p Option B-2 generates net costs under this scenario.
Options C 1 and C 2 Option C 1 would not impose a new reporting requirement, and NRC's ability in monitor would not improve. The model assumes that, und:r Option C-1, any underfunding that is currently
, projected (see Section 3.2.2) will not be corrected prior to decommicsioning.
Option C-2 would require licensees to report periodically to NRC on the status of their t decommissioning funds. NRC would use the data to ensure that icensees' external sinking funds are adequately funded by the time required. NRC's specific methods for making use of the data . the following:
- Benchmarking. NRC could ensure at the time of each periodic report, that each external sinking fund was appropriately funded. For exarr;.e.
the fund associated with a facility that is 30 percent through its operating life should be 30 percent funded (including assumed earnings on the amount currently funded). If the fund is not 30 percent funded, NRC could require the licensee to either (1) make an additional contribution to catch the fund up to the benchmark, or (2) increase future annual contributions as necessary to ensure the fund reaches the full amount of decommissioning costs. Under a more lenient benchmark, NRC might require action of the licewe only if J c ntnd h rm uithin some speci6ed percentage of expected furding (e.g utNn 5 perant of the 30 percent
+ funding level). This more ler.ur. te cha ark w vse considerable risk, howeser, because even a sman Mtmuy .af & mraissioning costs can represent a very ugni6cani smJer6mbr.g pn4 is. nrticularly if the facility life is almost over and the unerftuur.g wM be corrected immediately or in a short amour.t of time.
- Case-by-case reviews NRC might choose to facus its attention only on a specinc subset of licensees (e.g., those closest to decommissioning, those that have relatively poorer funding status than other licensees, those undergoing corporate restructuring, those in questionable financial condition, ti.ose having operational dif6culties).
l (... continued) years). Licensees may yet elect to extend their safe storage periods as allo ed by NRC regulations. Dntft Page 46 1
The analysis assumes that, under either of these methods, NRC's review of reports uould be adequate both to ensure that licensees' cost estimates are at least as great as the appropriate certifi ation amounts, as required by 10 CFR 50.75, and to correct any underfunding problems by the time of decommissioning. NRC might also use the data for informational purposes (e g., to respond to , Congressional or meaia inquiries). The requirements would impose a reporting burden on licensees and a corresponding administrative burden on NRC to process the reports. They would also reduce the burden on NRC's inspectors at licensed facilities, who previously had to review analogous information at licensees' facilides, and also reduce the corresponding burden on licensees to prepare for the inspection, assist NRC perennel, and respond to inspection results. Options D 1 and D 2 r Currently, Federal licensees that are electric utilities may use statements of intent, though only the Tennessee Valley Authority (TVA) may actually meet this condition and does, in fact, use the statement of intent to demonstrate financial assurance for decommissioning. Consequently, modeling of Options D-l and D-2 was specific to TVA. Under Option D 1, TVA would continue to use staa:ments of intent to demonstrate financial assurance. NRC would bear the risk described in the report from the inspector General, i.e., that the statements of intent may not provide any meaningful financial assurance.*' Option D-1 results in no change from the statas quo, and therefore it generates na incremental costs or savings. Option D-2 would eliminate statements of intent as an acceptable financial mechanism for use by nuclear power reactors. Under Option D-2 TVA's use of statements ofIrant, which are virtually costless to TVA, would no longer be acceptable. Instead, TVA would have to obtain another financial mechanism. This analysis assumes TVA would establish an external sinking fund. Although TVA would be required to make significant annual payments into the fund, these payments are not costs of the rul-making. Rather, these are advance payments for decommissioning activities for which the licensee is already responsible. Because Optien D-2 results in the licensee paying these costs earlier than it would otherwise, the primary cost to the licensee consists of the opportunity cost of not being able to use the annual contributions from the time contributed until the time the funds otherwise would have been required. The model determines this opportunity cost by, first, calculating the present value to the licensee (assuming a 7 percer' discount rate) of its future decommissioning costs and, second, tubtracting this value from the present value of the annual contributions reqdited (assuming level payments, a 4.3 percent assumed pre-tax rate of return, and a 7 percent discount rate). Under the stranding deregulation scenario where TVA ceases to qualify as an electric utility in the _ year 2006, the model assumes that TVA prepays enough additional funds so that, with assumed eartungs
- (cf 4.3 percent), the fund grows to the full decommissioning cost by the time of license expiration. To address the possibility that NRC may apply Option B-2's 2 percent earn'mgs assumption along with Option
Audit Repon: NRC's Decommissioning Financial Assurance Requirementsfor Federal Licerures May Not Be Suficient, OlG/95A-20, U.S. Nuclear Regulatory Commission, Office of the inspector General, April 3,1996.
' This in consistent with the fact that all or Qually all non-Federal electric utilities, who are ineligible to use statements of intent, have selected eaternal sinking funds to demonstrate financial assurance for decommissioning.
Draft Page 47
~ _.
D 2, the model repeats the ' 'culation just described, but th: prepay ment wount is calculated un percent earnings assumption." ne fmancial assurance cos: to TVA. calculated for each earnin assumption,is the opportunity cost of paying for decommmiening prior to the commencement o decommissioning (see discussion in the preceding paragrapht 3.3.4 Assumptiorts Several assumptions are worth noting. First, with the exception of Opdons D-1 and D 2, which affect only one licensee, the model assumes that all licensees are regu'ated in an identical fashion b FERC, PUCs, and other regulators as applicable, and will continue to be regulated, or deregulated, in a identical fashion under the managed deregulation scenario and/or the stranding deregulation scenario, in reality, deregulatiou is not likely to affect every single licensee in the same way or to take effect same time (in 2006) for all licensees. This assumption tends to overstate the effect of each option relativ to the alternative option and it imbues an "all or nothing" quality to the results. He approach is effective in showing how NRC's options will function under each of the three regulatory scenarios (i.e., no reta deregulation, managed deregulation, and stranding deregulation) and seems reasonable in the ab more sophisticated analysis of the substantial uncertainty surrounding future deregulation and ho utilities might evolve. Nevertheless, ongoing deregulation is likely to be a blend of(at least) the three scenarios modeled in this analysis. Actual values and impacts, therefore, are likely to fall ia between the different amounts reported in this analysis. Second, the analysis implicitly assumes that no premature closures of reactors will occur as a result of restructuring or deregulation, This topic has not been analyzed in this study (see Section 3.3.2) although the analysis did consider whether the rulemaking itself would lead to any premature closur nuchar power reactor licensees (see Section 3.4). Third, with the exception of Options C 1 and C-2 (reporting requirements), the model assumes compliance of all licensees with respect to total financial assurance 'evels and, in particular, annual contributions to external sinking funds. This assumptian a;ves to isolate the effects of each option without the obfuscatory effects of overfunding or underfunding, His mumption wu implemented by adjusting the size of licensecs' projected annual contribunons to cerna suking hmJs to be the precise amount 4..', gueet au rate of return on the funds). needed to achieve the appropriate funding level (assuming a Fourth, in calculating the portion of a newly-dereguiated n:enwcN Jecommissioning cost that, at the time of deregulation in 2006, is unassured by the licenwe% e wrnal $inting fund and which must therefore be assured by a surety bond, letter of credit, or prepayment, the analysis gives credit to the licensee for future earnings (i.e., untillicense expiration) on the amoum of funding as of 2006. This assumption seems consistent with NRC's current policy of allowing electric utilities to take credit for carnings on their external sinking funds, Neither NRC regulations or guidance, however, explicitly sta whether NRC would allow :redits in the situation described above, if NRC would not allow such credits, then the results will understate costs of financial assuranc: in any option or scenario where licensees cease to meet the definition of electric utility. Fifth, the methodology used to estimate licensees' costs of using surety bonds and letters of credi to cover amounts that are not assured by their sinking funds at the time of deregulation assumes that
" Due to tack of information on whether TVA will use the safe storage method of decommissioning at its reactors, the modeting for Option D does not account for Option ll's credit for earnings during safe storage.
Drqft l i Page 48
- - - - .- - . - - _ ~ _ - - .
t t licensees will not continue to make annual contributions to the sinking funds. This assumption was used to f
- simplify the analysis. In reality, however, licensees may continue funding sinking funds each year and this, in turn, would reduce the fees that must be incurred far surety bonds and letters of credit. Thus, the cost results related to use of surety bonds and letters of credit are upper bound costs.
Sixth,' the analysis assumes the accuracy of the data described in Section 3.3.1 and, in particular, tne reported decommissioning costs. If these reported costs are low, the analysis will tend to understate all results. Finally, the following assumptions were used in the analysis of implementation and operation costs under each of the options: (1) Wage rates for NRC staff and licensee staff were calculated from 19% wage rates developed by NRC for use in regulatory anal', sis of $67.50 per hour for NRC staff and $72.72 for licensee staff. The 1996 wage rates were converted to 1994 dollars to be campatible with the use of , 1994 dollars in the balar- ' he analysis. The rates used (in 1994 dollars) were $64.55 for NRC staff and $69.54 for licenset ... (2) The number oflicensees used was 132, and was derived from the information in Nuclear Plant Owners and Operators (Attachment 2 to SECY 94-280), November 18, 1994. ' (3) Reporting requirements were assumed to become effective 1 year after promulgation of the regulation in 1998, with the first reports required to be submitted by one third of the licensees in each of 1999,2000, and 2001. 'Ihe requirement was assumed to end in 2017. -(4) Follow up, when conducted, was assumed to be effective after one iteration. For example, follow-up for reports submitted in 1999 was assumed to be effective for those licensees' next required report in 2002, and no follow up was assumed for the 2002 report or subsequent reports. (5) Review of >ubmissions under Option A was assumed to take place at deregulation, assumed to be in 2006. (6) All future costs were discounted to 1998, at a 7 percent discount rate. 3.4 Results This section describes the results of the value-impact analysis. The values (or benefits) of the rule are calculated as any increase in the amount of Snancial assurance provided by an option and any cost _ , i savings to NRC or industry resulting from an option. Impacts are calculated as any decrease in the amount
- of financial assurance and any costs resulting from the option. Costs and savings include those related to Onancial assurance costs (such as surety fees, letter of credit fees,'or the opportunity cost of prepaid decommissioning costs) and administrative burdens (such as reporting, preparation of Gnancial mechanisms, review of financial mechanisms, guidance development, recordkeeping).
Before reviewing the values and impacts of each option, it is s orth noting several points to place these results in the appropriate context The three modeled scenarios 0.e., no retail deregulation,
. managed deregulation, and stranding deregulation) are necessarily simpiincations of the many possible outcomes of the deregulatory process. These scenarios, however, were designed to highlight the effects of the various regulatory options on the range of values and impacts of the rule, For example it seems unlikely that the stranding deregulation scenario will come to pass for all licensees, but this scenario effectively de nonstrates the possible outcome 'to NRC if other regulators (i.e., FERC and PUCs) cease to be relevant, in general, the model's identical treatment of licensees under the various scenarios tends to overstate the effects of each option relative to the a'urnative option and to imbue an "all or nothing" quality to the results. Nevertheless, the approach is effective in showing how NRC's options will function under each of the three regulatory scenarios and seems reasonable in the absence of more 'ohisticated analysis of the substantial uncertainty surrounding future deregulation and how electric utilities might evolve.
Draft Page 49
Ongoing deregulation is libly to result in a bitnd of these and other scenarios. Consequently, actual values and impacts are likely to fall in between thc different amounts reported in this analysis. The analysis has not attempted to address the issue of reactors or licensees that may cease operations prematurely (see Section 3.3.2), but it does consider the possibi'ity Nt the rulemaking itself could lead to premature closures. To accomplish this, incremental costs of the rulemaking were calculated for each licensee under the assumption that each continues to operate as a viable entity and can continue to -omply with applicable financial awarance requirements. The resulting coc s were then compared to hcensee financial data. Based on this analysis, it appears that the incrementa costs generated by this rulemaking are unlikely to lead to premature closures (i.e., not accounting for the unknown effect of deregulation and increased competition). Accepting thi ireluninary conclusion that this rulemaking wih not itself genera'e premature closures, the analysis focus s on how NRC's financial assurance program can best prepare for the uncertaintics of deregulation. 3.4.1- Estimated Values and Impacts of Options A-1 and A-2 5 The discussion of values and impacts is divided into two subsections. The St subsection y addresses financial assurance values and impacts. The second st.osection addresses implementation and P operation values and impacts. Financial Assurance Values and Impacts in the no retail dereguin.on scenario, licensees would meet NRC's current def'mition of electric utility as well as its proposed definition of electric utility. Consequently, licensees would continue using external sinking funds under Option A-1 and Option A-2. Therefore, in this scenario, neither optior, would generate any financial assurance cow or sasings. Under managed deregulanon, all licensees are assumed to meet the proposed definition of electric utility, but not the current definition. Therefore, under the no-action option (Option A-1), licensees are not all;wed to continue usin,, an external sin ing fund unless another financial mechatusm is also used te assi.re amounts noi yet fund:d. The cost for all licensees to oNam another mechanism to assure the unfunded decommissioning costs is estimated at between $7N $1,051 mi'. lion, depenuing ois v,uether licensees can obtain rurety donds or letters of credit or whethec . hey must instead use prepayment mechanisms. 'This cost is sttributable to deregulation rather than to the rule. Selection of Option A-2 would mean these costs aie never incurred, thereby generatmg savings of $7M-$1,051 million. Under stranding deregulation, all licensees are considered unable to meet either the current or the proposed definition of electric utility. Therefore, under either option, licensees would incur costs of obtaining another mechanism to assure their unfunded decommissioning costs. These costs, for all licenseus, are estimated at between $704-$1,051 million (the same as in t% managed deregulation scenario), depending on whe01er licensees can obtain surety bonds or letters of credit or whether they must instead use prepayment mecaanisms. Again, however, these costs are attributable to deregulation rather , than to the rule. These results are sensitive te the assumpticc. : hat deregulation occurs in 2006. Specifically, the savings generated by Opdon A-2 under managed deregulation v ould be much higher ($1,704-$2,375
" Further details on modeling assumptions are provided in Section 3.3.3.
~ . _ .
Draft Page 50
million)if deregulation occurred in 2001. Conversely, savings would be much lower ($250-$400 million)
- if deregulation occurred in 2011.
in all scenarios, licensees are assumei to comply with NRC's financial assurance requirements even if they no longer meet the definition of electric utility (current or proposed) and mu . demonstrate
-- financial assurance using methods other than external sinking funds. These other methods would be more costly to licensees than would external sinking funds (see discussion of impacts above), but they would - provide the same level of firu.ncial assurance.
These values and impacts are summarized in Exhib t 3 3. l Exhibit 3-3 Financial Assurance Values and Impacts Under Options A 1 and A-2 No Retail M aaged Stranding Deregulation beregulation Deregulation Option A 1: No action Valuestimpacts - - Option A 2: Reviss definition of utility Values
- Decrease in financial assurance - $74tM-$1,051M -
costs implementation and Operation Values and Impacts The implementation t.nd opeiation costs that could result from Option A are described in Exhibit 3-4. Under Option A-1, NRC would condnue to rely on review of licensees' nnancial assurance status by State PUCs and FERC and would incur no additiorni burden, even for licensees that no longer meet the current or proposed definition of utilhy. Under Option A-2, NRC wouid need to prepare a component of guidance for licensees simitr.r to Regulatory Guide 1.159 explaining the new definition of
" utility" and specifying the actions that beensees that do not meet the new dennition will have to take.
i Such guidance would be needed even 2, in fact, no licensees cease to be regulated es utilities, because NRC cannot know in advance that this wil' occur. Ur. der both the managed deregulation and the stranding deregulation scenarios of Option A-2, the anat, tis assumes that NRC carries out a review of the financial assurance submissions prepared by licensees tr'at no longer meet the definition of t'.tility. In the most extreme case, no utilities would remain in regulated status, even in the managed deregulation scenario, and all reviews would be conducted by NRC rather than State PUCs or FERC, This review would begin with the onset of deregulation, assumed to be it. 2006. Two alternatives were examined for this review: Draft Page 51 1
Edibit 3-4 Implementation and Operation Costs Under Options A 1 and A 2 l Managed Stranding No Retail Deregulation Deregulation Deregulation Opthn A 1: No action NkCILicemees Option A-2: Revise definition of utilKy NRC
- Preparation of part of new Regulatory $10,000 $10,000
$10,000 Guide
- ($9,900-$285,100)
- Review of submissions and follow-up Liceures (593,500- '
- Subm.ission for review $30"1,200) k
- Under the first alternative, the review would be limited to a check of te key elements of the submission, *.ebut two hours per submissior., with follow-up only in a few cases of very serious errors or omisaans.
- Under the opposite alternative, the review would be a detal'-)
examination af the text of the submitted fmancial mechat..sms, cequiring up to 40 hours to complete. Follow-up could be required for an estimated 50 percent of the submissions requiring up to an additional 40 hours. Licensees were assumed to require up to 40 Lours to prepare submissions for either a limited or a detailed review. In the case of a c emiled review, licensees could require up m an additional 40 hours to respond to problems. Draft Page 52 .a l
3.4.2 > Estimated Values and impacts of Options B-1 and B 2 Financial Assurance Values and Impacts - In the no retail deregulation scenario. under Option B-2, licensees can reduce annual contributions to external sinking funds due to the additional earnings credit al! owed under this option.= The 2 percent return does not apply because licensees remain regulated utilities. The savings to licensees is estimated to be at least $481 million. Savings could be substantially higher iflicensees begin selecting the'SAFSTOR method of decommissioning early enough to take greater advantage of the earnings credit during the safe storage period. These savings would not be incurred under Option B-l.
'Ihe es*imated impacts of Option BJ under managed deregulation are the same as in the no retail deregulation scenario, assuming that NRC also implements Option A-2."
Under the standing' deregulation scenario, however, the impacts of Options B-2 would differ. In
- particular, savings from the allowance of credits for earnings during safe storage ($322 million) would, in aggregate, be outweigt ed by the new costs to licensees of having to apply NRC's 2 percent earnings assumpti on on amounts funded to date plus any additional prepayments made at the time of deregulation.
(Use of a 2 percent real rate of return would require increased annual contribunons for those licepsees that currently assume a higher rate, and decreased contribudons for licensees that currently assume a lower rate. The overall effect, however, is an iacrease in costs to licensees because the average real rate assumed by licensees is 3.7 percent.) The costs to licensees of Option B-2 assuming stranding deregulatioa
- are estimated at between $323-$1,51I million, depending on whether licensees can obtain surety bonds or letters c' credit or whether sey must instead use prepayment meenanisms. Selection of Option B-1 would result in no costs being incurred. q Thc:;c results are sensitive to the assumption that deregulation occurs in 2006. Specifically, if deregulation occurred _in 2001, the savings generated by Option B-2 under stranding deregulation would be lower ($141 tr.illion) and the costs would be higher ($539-52,946 million). Conversely, if deregulation -{
j
. occurred in 2011, savings would be higher ($450 million) and costs would be lower ($150-5640 million).
s
~ These values and impacts are summarized in Exhibit 3-5. Licensees are assumed to comply with NRC's financial assurance requirements regardless of whether or not (1) NRC allows credits for earnings during safe storage, or (2) licensees use the 2 percent earnings assumption required by NRC (i.e., in the event that FERC or PUCs no longer oversce their assumed rees of return). Therefore, Options B-1 and B-2 may affect costs or savings to licensees (see discussk.i of impacts above), but they would provide the
- same level of financial assurance.
*f Licensees are required to make a preliminary determination of hcommissioning methods only 5 years prior to termination of oper siotis Many licensees .irrently report plans to delay decommissioning activities beyond the expiration of their operating 1.icenses. Y rrt:orted delays, however, are fairly brief (e.g., less than 5 years).
"If NRC were to implement Option A-1, however, then the values and impacts of Options B-1 and B-2 under manag*d deregulation would be the same as under the stranding deregulation sceaario j 4 discussed above).
Further details on modeling assumptions are provided in Esctior. 3.3.3.
Draft Page 53 p
hnplementation and Operation Values and impacts Except for preparation of the component of guidance addressing the rules on calcula contributions to decommissioning funds, there are no additioral implementation and operation costs result from either Option B 1 or Option B-2. Although Option B-2 would require licensees to reca the size of annual contributions to sinking funds (or pn payment mecharusms) in the year the rule takes effect (or when deregulation occurs), licensees are ass imed to already calculate such contrib year (i.e., under Option B 1). No additional burden would be imposed on NRC because NRC review licensees' calculation of annual contributions. Exhibit 3-6 summarizes the implementation and operation costs for NRC and licensee: of Option B. Exhibit 3-5 Finar.cial Assurance Values and knpacts Under Options B-1 and B-2 I Stranding . No Retail Managed Deregulation . Deregulation Deregulation Option B-1: No act;on Values /inymcts Option B-2: Allow credit for earnings d during safe storage and an assumed 2 percent real rate of return (assuming Option A-2 is also implemented) Values . pggg g3329
- Decrease in fmancial assurance ggg
' Costs
' impacts ;
- Increase in financial assurance L - - $123M-51.51IM costs orgfr Page 54
Edibit 3-6 Implementation and Operation Costs Under Options B-1 and B-2 No Retail Managed Stranding Dereguhition Deregulation Deregulation
]
Option B-1; No action
~ NRC/ Licensees Option B-2: Allow credits for earnings during I safe storage and an assumed 2 percent real rate of return
~NRC' l - Preparation of part of new Regulcrory g g g Guide a
i
- i. Licensees
- Calculation of annual contributions to ,
sinking fund (or prepayment) 3.4.3 Estimated Values and Impacts of Options C-1 and C-2 Financial Assurance Values and Impacts Assuming that NRC usc:, the reports to address potential underfunding of external sinking funds, then Option C-2 would eliminate any underfunding of external sinking funds by the time of shutdown both under the no retail deregulation scenario and under the managed deregulation scenario, in this case, the value of Option C-2 would equal the amount of the corrected underfunding, or $2.7 billion (see disevssion in Section 3.2.2), impacts for Option C-2 under the stranding deregulation scenario (or for the managed deregulation scenario if Option A-1 is imph:mented) would vary depending on the level of oversight NRC provides during the transition to other nnancial mechanisms, in 3eneral, however, impacts would be reduced in these cases relative to the amounts already discussed (which assume either the no retail deregulation
~
scenario, or managed deregulation with Opt'or, A-2). Although financial assurance costs incurred by licensees would increase under_ Option C-2, the added costs would not be attributable to this rulemaking, but rather would be attributable to currect Snancial assurance requirements. The values and impacts or Options C-1 and C-2 are summarized in Exhibit 3-7, Drg/t Page 55
g Ediihit 3-7 Financial Assurance Values and Impacts Under Optionc C-1 and C 2 No Retail Managed Stranding Deregui4iion Dt regulation Deregulation
. n otion C-1: No action Values / impacts Option C-2: Reports used to enst.re adequate funding Values
- Increase in financial assurance $gg g7g coverage levels Implementation and Operation Values and Impacts Under Option C-1, the no-action alternative, no additional implementation and operation costs would be incurred by NRC or licensees. Licensees would continue, as they do under the current rule, not to be required to report on the status of their dect.mmissioning funds until approximately 5 years before tL:
projected end of operation (10 CFR 50.75(O). Records of the cost estimate or certification amount and of the funding mer' anism used for assuring funds also would continue to be kept in an identified location where they may be reviewed in the inspection process if necessary. Option C-2, in which licensees would b : quired to submit periodic reports on decommissioning fund status, will impact NRC implementation and operation and industry implemenntion and operation. Option C-2 would substantially eliminate implementation and operation costs, both to NRC and to licensees, associated with compliance inspections that may otherwise be required under Option C-l. NRC implementation and operation costs are expected to include development of a component of a Regtdatory Guide describing the reporting requirement (this will be part of a more extensive regulatory guide addressing each of the new actions included in the rule); devalopment and implementation of a report tracking system; and review and analysis of reports, beginning in 1999, i vear after promulgation of the rule for one-third of reporting licensees each year. The analysis assumes NRC would follow-up on about 50 percent of the reports received each year. The frequency of follow-up necessary was assumed to be zero after the ini tial series of reports. Industry implementation and operation costs are expected to include development of procedures to ensure that information required to be reported is collected and the report prepared in a timely manner, following promulgation of the regulation in 1998; recordkeeping, making use of existing records systems; report preparation, once every 3 years beginning in 1099; and report follow-up, to respond to NRC . inquiries concerning the contents of the report, assumed to occur for about 50 percent of the reports Draft Page 56
-- submitted, generally consisting of a telephotr inquiry with follow-up letter, if NRC uses the reports to ensure adequate funding.
Exhibit 3-8 summarices implernentation and operation costs of Options C-1 and C-2. Exhibit 3-8 Implementation and Operation Costs Under Options C-1 and C-2 No Retail Managed . Stramling Deregula; ion Deregulation Deregulation Opion C-1: No action l NRCil.iceruees - - Opion C-2: Reports used to ensure l _ adequate funding i NRC 1
- Preparation of part of Regulamry
. Guide 000 W W
- Detailed review of reports to
$128,770 $128,700 $128,770 verify adequacy of funding and follow-up ,
j
.xeruees
$444.455 $444,455 $444,455 Reponing and follow-up 3.4.4 Estimated Values and impacts of Options D-1 and D-2 Financial Assurance Values and impacts Option D 1 would allow the continued use of statements of intent by Federal nuclear power reactors. Significant questions have arisen, however, regarding the security at funds assured by statements of intent (see related discussion in Sections 2.4 and 3.3.3). Consequently, under Option D-1, the $1.66 billion in financial assurance that statements of intent were providing may be, in effect, unassured.-
Option D-2 (under all scenarios) would eliminate the statement of intent as an acceptable mechanism for power reactor licensees. This would require the one licensee tat currently uses statements of intent, TVA, to obtain alternative financial assurance (e.g., external sinking funds) for the full hmount of its decommissioning obligations (i.e., approximately $1.66 billion) in order to comply with current NRC financial assurance requirements. Dr<lft Page 57
i In the no retail deregulation scenario, TVA would incur no eosts under Option D-l. Under Option D-2, however TVA would have to establish an alternative financial mechanism. The cost of this assurance equals the opportunity cost to TVA of committing decommissioning funds to its external sinking funds befere the commencement of decommissioning. This cost is estimated at 5124 million." The estimated impacts under managed deregulation are the same as in the no retail deregulation scenario, because TVA is likely to continue to qualify as an electric utility (and hence to be allowed to continue to use external sinking funds) even under managed deregulation. Decause of TVA's unique status among electric utilities, it is unclear whether stranding deregulation would have the same effect on TVA as it would on other electric utilities. Assuming. however, that TVA funds an external sinking fund until 2006 but then no longer qualifies as an electric utility at that time, TVA would have to ebtain alternative assurance for amounts not yet funded. Th< cost of Option D-2 is estimated at $153-243 million," depending on whether NRC has also implemented Option B-2. (Option D-2 costs are higher if Option B-2 has been impkmented because TVA would then be limited to an assumed earnings rate of 2 percent.) Under Optiu. D-1, TVA would continue using statements of intent and would incur no financial assurance costs. These values and impacts are summarized in Exhibit 3-9. Implementatior, and Operation Values and Impacts Exhibit 3-10 summarizes the implementation and operation costs for Option D. Under Option D-1 there would be no impler.entation and operation costs for NRC or for the licensee, TV A, because TVA would continue to be able to use the statement of intent. Under Option D-2, NRC was assumed to incur costs c. review the new fmancial assurance arrangements submitted by TVA to replace the statement of intent. NRC costs could vary depending on the type of review and on whether follow-up is required, but should not exceed $2,600. The licensee would incur costs to set up a new method of fmancial assurance to replace the statement of intent, to prepare a submission to NRC demonstrating the new method, and potentially to respond to NRC's follow-up. These costs should not exceed $4,200.
" This exchides the opportunity costs to TV A relate 8 'o $365 millinn that it has already sontributed to external decommissioning trusts.
" T1us assumes TVA prepays remaining decomnissioning costs in the year 2006. TV A's costs would decrease if it is able to obtain and use a surety bond or letter of credit instead of a prepayment mechanism.
Draft Page 58
Edibil 3-9 Financial Assurance Values and Impacts Under Options D-1 and D-2 No Retail Slanaged Stranding Deregulation - Det.gulation Deregulation Option D 1: No action Values / Impacts . - Option D-2: Disallow use of statements of intent Values
- Increase in financial assurance $1,663ht $1,663h1
$1,663N1 l
coverage levels i impacts
- Increase in financial assurance gg743g $g743g $g53sg.$243st _
Costs Exhibit 3-10 i Impleinentation and Operation Costs Under Options D-1 and D-2 I No Retail 51anaged Stranding Deregulation Deregulation [ Deregulation { Opion D-1: No action
- NRC/ Licensees -
1 1 ! Option D-2: Prohibit use of statement of intent NRC.
- Review replacement fmancial I assurance sm $2.600 I
$2,600 Lice:uees
- Secure and submit replacement M,200 M ,200 M,200 nnancial assurance Drgft Pagt: 59
f 4 firaft ' Page 60 L
1
- 4. . HACKFIT ANALYSIS:
The regulatory analysis for the proposed rule also constitutes the documentation for the evaluatien of backfit requirements, and no separate backfit analysis i.as bcn prepared. As de'ined in 10 CFR
-- 50.109, the backfit rule applies to " modification of or addition to systems, structures, components, or design of a facility; or the design approval or manufacturing license for a facility; or the procedures or organizauon required to design, construct or operate a facility. .
" resulting froin new or amended provisionsin Commission rules. Such backfitting can be plant-specific or apply to multiple facilities
. (" generic backtitting").
l The proposed amendments to NRC's requiremerts for the financial assurance of decommissioning
. of nuclear power plants address generic requirements. The proponi would revise the definition of -
' "electic utility" and add several associated definitions that are generic in nature; amend generically the requiremer.ts pertaining to the use of prepayment and external sinking funds; and enact generic new l: reporting requirements for power reactor licensees on the status of decommissioning funding that specify
- the timing and contents of such reports..
l I
- NUREG-1409, NRC's Back/itting Guidelines, lists several criteria (provided below in italics) for .
l= determiriing whether a particular proposed rule talls within the scope of the bsckfit rule. The criteria, _ proposed acticns, and a description of whether the actions meet each criterion follow:
- lhe positions or requirements would bring abotdimprovements in safety ofnuclear power reacto.s. .
The current proposal would enhance the safety provided by NRC's reactor - decommissioning requirements, by helping to ensure that the reactor decommissioning is adequately tinanced and tiiat delays or shortfalls do not occur in the funding of decommissioning that could create threats to health or safety.
' I Tine positions or requtrements impose changes in hardware, procedures, or organi:ation of nuclear power reactors.
The current proposal would require no changes in hardware, precedures, or organization of nuclear power reactors.
'- The backfit rule does not cover NRC actions that merely request infounation and do not impose changes in hardware, procedures, or organi:ation.
The current proposal includes revisiens to reporting requirements that constitute a request for information.
- The backfit rule does not apply to purely administmtive matters.
The proposed rule is not purely administrative. It invokes chant,es to the jurisdictionak f.efinitions pertaining to licensees and also affects the regulatory options available to licensees. Draft Page 61 wr
NRC has determined that the backfit rule,10 CFR 50.109, does not apply to this proposed rule. A backfit analysis is not required for this proposed rule because these amendments do not involve any provisions that would impose backfits as defined in 10 CFR 50.109(axi). Drpft Page 62
- 5. DECISION RATIONALE
- 1. Option A-2 would revise the definition uf " electric utility," which specifies when nuclear power reactor licensees may use an external sinking fund that builds up *s the required level of decommissioning funding, and when such owners must provide financial assurance for the full amount of decommissioing. Under Option A-2, entities that no longer qualify as " electric utilities" because they are no longer able to recover the cost of decommi.,sioning through electricity rates or mandatory fees will be required to notify )
NRC of the change in their situation and to provide financial assurav for the full amount of their decommissioning obligation immediately. Without the change of definition that would be made under Option A-2, entities that no longer meet the existing definition of utility because they no longer ca-. recover costs of decommissioning through rates, but which are receiving decommissioning funds through mandatory system exit ses, line
- charges, or other means established in the course of industry deregulation, would still be l required to incur costs, in total, of up to $704 miliion to $1,051 million (or more if deregulation occurs prior to 2006) for establishing financial assurance to supplement their j external sinking funds (Exhibit 3-3). (Under both the old definition and the new definition, entities that cannot recover the costs of decommissioning through rates or mandatory fees will be required to provide full assurance immediately.) Opticn A-2 therefore is justified both as a cost saving measure and as a response to uncertainty about how electric industry deregulation will affect the recovery of decommissioning costs through rates and mandatory fen
- 2. Implementation and operation costs of reviewing financial assurance submissions by entities that no longer meet the revised definition of " electric utility," as well as industry costs to prepare the submissions, will be incurred only when electric industry deregulation occurs that affects a nuclear power reactor licensee, and only if that deregulation causes the licensee to cease to meet the definition of utility. Option A-2 would sllow NRC and licensees to avoid implementation and operation costs in cases where licensees are receiving decommissioning funds through mandatory system exit fees, line charges. or other means estaolished in the course of industry deregulation.
- 3. For the reasons stated in O) and (2) above, Option A-2 is superior to Option A-1, the no-action ahernative.
- 4. Option B-2, allowing licensees credit for earnings during safe storage but requiring use of an assumed real rate of return of 2 percent in cases where neither FERC nor PUCs approve of other assumed rates, would allow savings of $481 million (Exhibit 3-5) over Option B-1, the no-action alternative, if either no retail deregulation occurs or retail deregulation occurs that allows nuclear reactor licensees to continue to receive decommissioning funds through rates or mandatory fees described in Option A-2. Under those conditiora licensees could continue to use their own assumed rates of return (which are presumed to be reviewed and approved by State PUCs and/or FERC) until funds are spent on decommissioning. Savings could be subsumtially higher if licensees begin selecting the SAFSTOR method of decommissioning early enough to take greater advantage of the earnings credit during the safe storage period.
Draft Page 63 r
i l
- 5. Option B-2 would result in net costs to nuclear reactor licensees under scenarios w licensees may not continue to use their own assumed rates of return but must instead '
the required 2 percent rate of return established under Option B-2. In this case, the ) saviitgs resulting from the extended earnings credit described in (4) would, on bal all licensees, be offset by higher costs associated with the 2 percent earnings asstmption. ; Specifically, if nuclear reactor licensees cease to qualify as utFities under the d l Option A-2 because after deregulation they cannot receive decommissioning fund ' rates or mandatory fees (and therefore are presumed not to be supervised by State P and/or FERC), Option B-2 would limit them to an assumed 2 percent rate of return prio to safe storage as well as during the safe s. ora;;e period. The net effect of the 2 percent rate and the extended earnings credit could increase financial assurance costs by $1 to $1,189 million (or more if deregulation occurs prior to 2006), although these costs may be mitigated by additional savings as discussed in (4).
- 6. Option B-2 is superior to Option B-1, the no-action alternative, under any assurnpuon about the form of electric industry deregulation. If retail deregulation does not occur, or occurs in the form hypothesized in (4), licensees will realize substantial savings (at least
$481 million), if deregulation occurs in the form hypothesized in (5), licensees will incur net financial assurance costs under Option D-2 ($1 million to $1,189 million). The net costs will vary, depending on whether the licensees use p er.ayment or a third party financial assurance mechanism to provide financial assurance for the difference between their existing external sinking funds and the full amounts of financial assurance that they must provide. The net costs will also vary, depending on the difference between estim real rates of return the licensees had previously been using for their extenal sinking funds and the more conservative 2 percent rate that they will be required to use by Option B-2 if they are no longer under the supervision of Stw PUCs and/or FERC However, both components of the increased costs will reduce the potential for significant 'mderfun decommissioning.
- 7. Option C-2, requiring triennial reports by licensees to NRC on the status of decommissioning financial assurance, would allow NRC to address whether adequate decommissioning funds have been set aside to date. Option C-2 would impose implementation and cperation costs on NRC and licensees (Exhibit 3-8). However, a reporting requirement couplcd with strong fonow-up action to address any cases of underfunding identined through the analysis of the reports received could result in avoidance cif up to $2,700 minion in unftinded decommissioning that could be experienc under the no-action alternative or l' a teporting requirement is coupled with limited follow-up (Exhibit 3-7).
S. Option C-2 also has non-quantinable benefits for regulatory efficiency, because it allow NRC to develop and provide to Congress and the public detailed information about the current status of decommissioning funding.
- 9. For the reasons stated in (7) and (8) above, Option C-2 is superior to Option C-1, the no-action alternatiee.
- 10. Option D-2, elimination of the use of statements of intent by Federal power reactor licensees, would require TV A and NRC to incur limited implementation costs to secure Draft Page 64
and approve an altern; meial mechanism. TVA also would be required to incur costs of from $124 mi 1243 million to provide alternative fliuncial assurance,-
' oepending on the type 1 ance that is used. However, qualitative analysis suggests
- (Section 3.2A) that th '- ' :nt of it. tent has inherent flaws that make it a weak form of Anancial assurance. - I ovide only a promise by the licensee to seek and obtain
== - funds at some future t n they are needed. TVA's statement oi. intent apparently was not the equivalent - :ent guarantee piovided by the Federal government; NRC's-Office ofInspector G< is uncovered reasons to believe that the Federal government does not in fact intend : ide any guarantee that it will provide funding for TVA's
- decommissioning cost ~ 's statement of intent thus most closely resembles a self-guarantee, based on it - itment to set rates or issue bonds, notes, or other
~
indebtedness sufficien ide finds for decomrrissioning. Option D-1, the no-hetion alternative, represents ation if TVA cannot meet this self-guarsntee commitment. I1. Although it appears u: whether the Federal government will guarantee the payment - of TVA's decommissi >sts, a number of factors support the proposition that TVA l
-can successfully self-t l those costs.- These factors include a strong bond' rating and the poteatial ability to lditional debt if necessary; high operating revenue heavily derived from non-nue eration facilities; the authority to cet rates for electricity independently; and a i portivn of long-term requirements contracts that should l- :rosion ofits customer t'ase to existing competitors. On protect TVA against t '
l i-l to be the preferable alternative. balance. NRC finds ( i Drgft Page 65
e
- 6. BIPLEMENTATION-L6.1 -Implementation Schedule-This action would be enacted through a Proposed Rule No6ce and public comment and a Final Rule, with promulgation of the Final Rule by 1998. Implementation can begin immedia_tely following the cnactment'of the final rulemaking.' No irr: pediments to implementation of the recommended al+ernatises have been identified.' Regulatory Guides for licensees would be required to provide an explanation of the regulatory requirements and methods for applying NRC's ass 2med 2 percent real rate of return, the
~
triennial reporting requirements, and the requirements for reg,ulatory compliance for licensees that no
- longer satisfy the definition of' electric utilitp."
o lf
.c Page 67
b D GG D - ENCLOSURE 4 l l PUBLIC ANNOUNCEMENT
i d J 4 1 i i 1 i e i' s 0 I I e l ? 4 s i ENCLOSURE 5 .,s !, CONGRESSIONAL LETTERS i 4 4 4 o 4 e' l l l 1 l i l l l i
jweeg$* [ ,- , UNITED STATES 4 E NUCLEAR REGULATORY COMMISSION - if W ASHINGTON. D.C. 20555M1 ( *...* [ The Honorable Dan Schaefer, Chairman ~ Subcomittee on Energy and Power Comittee on Comerce - . United States House of Representatives l Washington, DC. 20515 l
Dear Mr. Chairman:
In the r. ear. future, the _ Nuclear Regulatory Commission (NRC) intends to publish in the Federal Reaister the enclosed proposed am.endment to the Comission's rules in 10 CFR Part 50. This proposed rule is being developed to amend the
' NRC's regulations relating to financial assurance requirements for the decomissioning of nuclear power plants. This is being done in response to the anticipated deregulation of the power generating industry. The proposed action would revise the definition of " electric utility" contained in l 10 CFR 50.2, and require licensees to periodically report on the statu.. of l- their decomissioning funds and funding for the management of their iriodiated fuel. Lastlf, the Comission 'is proposing to allow licensees to take credit for the earnings on decomissioning trust funds from the time of the funds' collection through the decomissioning period.
The Comission is issuing the proposed rule for public coment. Sincerely, Dennis K. Rathbun, Director Office of Congressional Affairs
Enclosure:
Federal Register Notice cc: Representative Ralph Hall l
f* *to 4 -__ 4 UNITED STATES , , .
. g- g_ NUCLEAR REGULATCRY COMMISSION o '# WASHINGTON. D.C. 20555-0001 4
9 . . . . . ,o The Honorable James M. Inhofe, Chairman Subcomittee on Clean Air, Wetlands, Private > Property and Nuclear Safety Comittee on Environment and Public Works United States Senate Washington, DC _20510-
Dear Mr. Chairman:
In the near future, the Nuclear Regulatory Comission _(NRC) intends to publish in the Federal Register the enclosed proposed amendment to the Comission's rules in 10 CFR Part 50. This proposed-rule is being. developed to amend the NRC's regulations relating to financial assurance requirements for the decommissioning of nuclear power plants. This is being done in response to-
-the ar.ticipated deregulation of the power generating industry, The proposed action would revise the definition of "e'iectric utility" contained in 10 CFR 50.2, and ' require licensees to periodically report on the status of their decomissioning-funds and funding for the management of their irradiated fuel. Lastly, the Commission .is proposing to allow licensees to take credit for the earnings on decommissioning trust funds from the time of the fcnds' collection through the decommissioning period.
The Commission is issuing the proposed rule for public comment. Sincerely, Dennis K..Rathbun, Director Office of Congressional Affairs-
Enclosure:
Federal Register Notice cc: Senator-Bob Graham
-,-----.--.-.-r_-- - , - - -- . - - ---- - ---
9 4 e 69 m h I i h I ( ENCLOSURE 6 ANPR DTD APRIL 8,1996 -
. ._ ____ . _ . _ ._._._.__ _ _~___
M d i.. [7590-01) ' NUCLEAR REGULATORY COMMISSION
- 10. CFR- 50.2, 50.75, and 50.82
~ ~ ' '
RIN 3150-AF41 4 ' Financial Assurance Requirements for Decommissioning Nuclear' Power Reactors r-n AGENCY:: Nuclear Regulatory Commission. ACTION: Advance notice ~ of proposed rulemaking.
- - R
SUMMARY
- The Nuclear Regulatory Commission is considering amending its
Jregulations relating to financial assurance requirements for the r
; decommissioning of nuclear power plants. Potential deregulation of.the power q
[ -generating industry has created uncertainty with: respect-to whether current i ? 4
- NRC regulations concerning decommissioning fund and the financial mechanisms ,
I
- will require a modification toLaccount;for utility reorganizations not-i-
Lcontemplated when current financial assurance requirem nts were promulgated.
-Additionally, the NRC is considering requiring power. reactor licensees to periodically-report on the status of their decommissioning funds. Allowing credit for.earningsoon decommissioning trust' funds during extended storage will also be considered. This advance notice of proposed rulemaking is issued to invite public comment on issues _ pertaining to the form and' content of the NRC's nuclear power reactor decommissioning financial assurance requirements as they relate to electric utility deregulation.
L . DATE: Submit- coments by (insert a date to allow 75 days public coment)-
, 1996. Coments received after this date will be considered if- lt is practical to do so, but the Comission is able to assure 1: consideration only for coments received on or before this date.
ADDRESSES: Mail consents to: The secretary of the Comission, U.S. Nuclear l Regulatory Comission, Washington, DC 20555, Attention: Docketing and Service Branch. Deliver coments to: 11555 Rockville Pike, Rockville, Maryland, between 7:45 a.m. and 4:15 p.m. Federal workdays. Comments may bd submitted electronically, in either ASCII text or Wordperfect format (version 5.1 or later), by calling the NRC E lectron ic Bulletin Board (BBS) on FedWorld. The bulletin board may be accessed using a personal computer,- a madero, and one of the comonly available comunications software packages, or directly via Internet. Background documents on the advance notice of proposed rulemaking are also available, as practical, for downloading and viewing en the bulletin board. If using a personal computer and modem, the NRC rulemaking subsystem on FedWorld can be accessed directly by dialing the toll free number
-(800) 303-9672. Comunication software parameters should be set as follows:
parity to none,. data bits to 8, and stop bits to 1 (N,8,1). Using ANSI or VT-100 terminal emulation, the NRC rulemaking subsystem can then be accessed by selecting the " Rules Menu" option from the "NRC Main Menu." Users will
- find the "FedWorld Online User's Guides" particularly helpful. Many NRC subsystems and data bases also have a " Help /Information Center" option that is tailorad to the particular subsyste .
2
The NRC subsystem on FedWorld can also be accessed by a direct dial or by using Telnet via phone number for the main FedWorld BBS, (703) 321-3339, Internet: fedworld. gov. If using (703) 321-3339 to contact FedWorld, 'he NRC subsystem will be accessed from the main FedWorld menu by selecting the " Regulatory, Government Administration and S 'te Systems," then selecting i " Regulatory Information Mall." At that point, a menu will be displayed that has an option "U.S. Nuclear Regulatory Comission" that will take you to the The NRC Online area also can be accessed directly by NRC Online nain menu. If you access NRC from ; typing "/go nrc" t a FedWorld comand line. FedWorld's main menu, you may return to FedWorld by selecting the " Return to FedWorld" option ' rom the NRC Online Main Menu. However, if you access NRC at FedWorld by using NRC's toll-free number, you will have full access to all NRC systems, but you will not have access to the main fedWorld systam. If you contact FedWorld using Telnet, you will see the NRC area and menus, including the Rules Menu. Although you will be able to download documents and leave message.s, you will not be able to write coments or upload files (coments). If you contact FedWorld using FTP, all files can be ac:essed and downloaded but uploads are not allowed; all you will see is a list of files without descriptions (normal Gopher look). An index file listing all files within a subdirectory, with descriptions, is available. There is a 15-minute time limit for FTP access. Although FedWorld also can be accessed through the World Wide Web, like FTP that mode only provides access for downloading files and does not display the NRC Rules Menu. 3
For more' information on NRC bulletin boards call Mr. Arthur Davis, Systems-Integration and Development Branch, NRC, Washington, DC 20555, telephone (301) 415-5780; e-mail AXD3@nrc. gov. Examine copies of coments received at: The NRC Public Document Room, 2120 L Street NW (Lower Level), Washington, DC. FOR FURTliiR INFORMATION CONTACT: Brian J. Richter, Office of Nuclear Regula-tory Research, U.S. Nuclear Regulatory Commission, Washington, DC 20555, telephone (301) 425-6221, e-mail bjrenrc. gov.
~
SUPPLEMENTARY INFORMATION: Background-Requirements pertaining to financial assurance for the decommissicning of _ nuclear power reactors are contained in 10 CFR 50.75. Under i 50.75(e)(3), the NRC allows power reactor licensees, who are defined as " electric u tilities"8 under i 50.2, to . set aside funds annually over the estimated life
-of the reactor for decommissioning. The NRC provided more flexiollity to its electric utility lycenses; than other licensees because electric utilities have existed in a highly structured environment regulated by State public
" Electric utility means any entity that generates or distributes elec-tricity and which recovers the cost of this electricity, either directly or indirectly, through rates established by the entity itself or by a separate regulatory authority. Investor-owned utilities, including generation or distribution subsidiaries, public utility districts, municipalities, rural electric cooperatives, and State and Federal agencies, including associations of any of the foregoing, are included within the meaning of ' electric utili-ty.'"-
l 4
~
utility commissions (PUCs) or the Federal Energy Regulatory Comission (FERC). Under i 50.75(e)(2), the NRC req ~uires licensees other than electric utilities to set aside an external sinking fund coupled with a surety method or insurance for any unfunded balance. However, with the advent of deregulation, the distinction between electric utility licensees and other licensees will
~'
likely be reduced or eliminated. Thus, the NRC needs to clarify the definition of " electric utility" and to require additional assurance of those licensees whose power reactor costs are no longer regulated. Typically, power reactor licensees place decomissioning funds in external trust or escrow accounts that are reserved for decomissioning activities.' Under the definition of external sinking fund, power reactor licensees must accumulate all the funds estimated to be needed for decomis-sioning by the time their facilities are permanently shut down. Although 5 50.75(e) also allows power reactor licensees to use surety bonds, letters of credit, and prepayment to provide funding assurance, virtually all power reactor licensees use the external sinking fund method of assurance. The intent of 5 50.75 is to provide reasonable assurance that funds for decomissioning will be available when necessary. The inability of the licensee to provide funding for decomissioning may adversely affect protection of public health and safety. Also, a lack of decomissioning funds Note: Many licensees that have established decomissioning trust funds for their power reactors are making deposits into their trust accounts both for decomissioning costs as defined under 5 50.2 and for other decomission-ing-associated costs such as interim spent fuel management and storage 'and
" green field" costs. The NRC allows licensees to deposit funds in the same trust account as long as the trust has sub-accounts that clearly delineate the purposes of the sub-account. A trust or sub-account e tablished to provide assurance of NRC-defined decomissioning costs should be stipulated to cover NRC-defined decomissioning costs befcre any other purpose.
5
is- a' financial risk to taxpayers (i.e., if the licensee cannot pay for
. decomissioning, taxpayers would ultimately pay the bill).
In a related issue,-when the Comission issued the decomissioning rule., the Comission believed that,_ for a regulated electric utility, an external q reserve account collected over the ~ estimated remaining reactor life would p'rovide ih'e necessary reasonable assurance. However, as a conservatism built into the rule, the NRC decided not to allow licensees to takscredit for earnings on their trust funds while_their reactors were in extended safe ! storage. Rather, the NRC assumed that during safe storage the rate of return-on external decomissioning trust funds would equal the decomissioning cost escalation rate. Thus, the after-tax, after-inflation earnings rate effectively would be zero. When the NRC promulgated the 1988 decomissioning rule, it did not require licensees to report periodically on the status of their decomissioning funds. NRC viewed licensee compliance with the funding
. assurance requirements as a matter to be determined through the inspection process when necessary. Also, the NRC recognized in the 1988 decomissionin0 rule the PUCs' and FERC's authority to set annual contribution rates to decomissioning funds and to establish investment and other management criteria for the funds. The Puts and FERC also actively monitor these decomissioning funds as part of their rate regulatory responsibility.
- Moreover, the Financial Accounting Standards Board (FASB), a national organization that sets account' i standards, recently initiated a review of reporting of decomissioning obligations on electric utility financial statements. Although FASB has not established a final standard, it appears that it will increase the level of detail on power reactor licensees' 6
- . - -. -. - . ~ - . _ -. - -.- . - - .- .- -
i a financial statements. if adopted, this standard would likely give the NRC and g others additional information' on the status of decommissioning runds, i However, the advent of deregulation, and consequently less oversight by FERC
- or by PUCs, makes it imperative that -the NRC have a source of information to L
monitor the status of decommissioning funds.
- Specific Proposal The Commission is considering amending 10 CFR 50.2, 50.75, and 50.82 to require that electric utility reactor licensees provide assurance that the
. full estimated cost of decommissioning will .be available through an acceptable l guarantee mechanism if the licensees are no longer subject to rate regulation The amendment by PUCs or FERC, and do not have a guaranteed source of income.
would also allow licensees to assume a positive real rate of return on decommissioning funds during the safe storage period. Lastly, a periodic reportirg requirement would be established. Specific Considerations Advice and recommendations on a proposed rule reflecting the foregoing . and any other points considered pertinent are invited from all interested - persons. Comments and supporting reasons are particularly requested on the following questions arranged by topic: 7
A. Timina and Extent of Electric Utility Industry Deregulation A.I. What is the likely timetable for industry restcucturing and deregulation? A.2. Will the electric utility industry go through several phases as it
~
responds to deregulation and other competitive pressures? If'so, whit will be the likely major changes in business structure that may occur in each phase? Will rates remain regulated at the retail distribution level, with deregulation cecurring for generation and transmission? Will retail wheeling become widespread and lead to deregulation of all sectors of the electric utility industry? Or will rates remain regulated at the retail distribution level, with deregulation occurring within the generation and transmission sectors? What will likely be the final structure of the electric utility industry, assuming either partial or full deregulation? A.3. Some states appear to oppose deregulation. Will they be-able to maintain their opposition if neighboring states deregulate? What will be the industry structure if some states deregulate more than others? Can a " hybrid" system exist effectively? B. Stranded Costs B 1. How will restructuring affect large baseload plants that currently receive rate relief to cover construction costs or have a portion yet to be phased into the rate base? Specifically, what is the probability that and degree to which these costs will be recoverable should a nuclear power plant be deemed to be non-competitive because of high construction costs? What will 8
l be the source of operating, maintenance, and capital improvement funds-should such a nuclear generator decide to continue operations? What will be the
' source of funds t( prematurely and safely shut down an unecoaomic plant? Are f transmission acce n or other surcharges to cover stranded costs likely?
C. Euclear Financial Qualifications and Decomissionino Fundino Assurance-C.1. If nuclear plants are shut down prematurely, how will licensees who can no longer pass costs through to ratepayers provide for a shortfall of decomissioning funds? C.2. At what point does an operator of a nuclear power plant cease to
'be a " utility" as defined in 10 CFR 50.2 of the NRC's regulations?
C.3. If an electric utility reorganizes itself, including divesting parts of itself, so that the remaining entity operating a reactor is no longer regulated by a rate-setting State or Federal body, or will cease to be regulated by a rate-setting State or Federal body if the reactor ceases operation, would it be appropriate to require financial assurance for the decomissioning costs in full prior to NRC approval of such reorganizations? Such assurance could take the form of self-guarantee, parent company guarantee, certification by the rate-regulating entity, or other fir,ancial surety mechanism to cover the-unfunded 'decomissioning costs. Should the NRC require additional assurance for adequate funds for safe operation and decomissioning in anticipation of deregulation? Should the NRC-require, as a condition of approval of certain reorganizations involving the transfer of control of a nuclear power plant, that newly created organizations or holding companies sign a binding agreement that holds them jointly liable for l i ' 9
'l decomissioning costs associated with that nuclear power plant? What would be
- the impact of such actions?
C 4. Should the _NRC require a licensee to provide a reaso..able assurance of the availability of funds for decomissioning by imposing a minimum level of net worth, cash flow, or other financial measure '(similar to 10 CFR Part 30, Appendices A and B)? If below the minimum levels, the licensee would no longer be allowed to accumulate decomissioning costs over
- remaining facility life, but would need a guarantee that funds would be 4
available for decomissioning through various financial measures. , What financial measures would be effective and reasonable?
'C.5. - Would PUCs and FERC be willing to certify that licensees under their jurisdictions, both electric utility and Part 50 licensees other than electric utilities, would be allowed to collect sufficient revenues through rates to complete decomissioning funding?
C.6. What would be the impact if the NRC required licensees to accelerate collection 'of decommissioning funris such that decomissioning funding for all plants would be. complete within 10 years (or some other time period)?- C.7. Assume that licensees'have accumulated funds that are determined to be adequate based on current estimates of decomissioning costs, if these estimates turn out to be low far in the future-(for example, if final dismantlement occurs after a 50 year safe storage period), how will
-underfunding be remedied? What measures should the NRC consider for obtaining assurance of funds for such situations? Should the NRC require larger contingency factors in estimates to cover such situations?
10
Would it be feasible for the nuclear industry to develop a captive C.B. i insurance pool to pay for decomissioning funding shortfa;1s that result from ) _ premature decomissioning? Could such a pool be structured similarly to
-Nuclear Mutual Limited (NHL) and Nuclear Electric Insurance Limited (NEIL),
who currently insure on-site property damage and replacemeni' power of membei
- utilities?
C.9. If PUC or FERC oversight is either substantially limited or eliminate / are there any other options for financial assurance of decomissioning that the NRC should consider? The preliminary views expressed in this notice may change in signt of coments received. In any case, there will be another opportunity for additional public coment in connection with any proposed rule that may be developed by the Comission. PART 50 - DOMESTIC LICENSING OF PRODUCTION AND UTIllIATION FACILITIES The authority citation for Part 50 continues to read as follows: AUTHORITY: Secs 102, 103, 104, 105, 161, 182, 183, 186, 189, 68 Stat. 936, 937, 938, 948, 953, 954, 955, 956, as amended, sec. 234, 83 Stat. 1244, as amended (42 U.S.C. 2132', 2133, 2134, 2135, 2201, 2232, 2233, 2236, 2239, 2282); secs. 201, as amended, 202, 206, 88 Stat. 1242, as amended, 1244, 1246 (42 U.S.C. 5841, 5842, 5846). Section 50.7 also issued under Pub. L. 95-601, sec.10, 92 Stat. 2951 as amended by Pub. L. 102-486, sec. 2902, 106 Stat 3123, (42 U.S.C. 5851). Section 50.10 also issued under secs. 101, 185, 68 Stat. 936, 955, as amended (42 U.S.C. 2131, 2235); sec. 102, Pub. L. 91-190, 83 11
Stat. 853 (42 U.S.C. 4332). Sections 50.13, 50.54(dd), and 50.103 also issued under sec. 108, 68 Stat. 939, as amended (42 U.S.C. 2138). Sections 50.23, 50.35, 50.55, and 53.56.also issued under sec. 185, 68 Stat. 955 (42 U.S.C. 2235). Sections 50.33a, 50.55a and Appendix Q also issued under sec. 102, Pub. L. 91-190, 83 Stat. 853 (42 U.S.C. 4332).. Sections 50.34 and 50.54 &lso issued
~
under sec. 204, 88 Stat. 1245 (42 U.S.C. 5844). Sections 50.58', 50.91, and 50.92 also issued under Pub. L. 97-415, 96 Stat. 2073 (42 U.S.C. 2239). Section 50.78 also issued under sec. 122, 68 Stat. 939 (42 U.S.C. 2152). Sections 50.80 - 50.81 also issued under sec.184, 68 Stat. 954, as amended (42 U.S.C. 2234). Appendix F also issued under sec.187, 68 Stat. 955 (42 U.S.C 2237). Dated at Rockville, Maryland, this day of , 1996. For the Nuclear Regulatory Commission. John C. Hoyle, Secretary of the Commission. 12 L
The Commissioners- 8
- h. Copies of the Federal Register Notice of proposed rulemaking will-be distributed to all power _ reactor licensees. The notice will be sent to other interested parties upon request.
L. Joseph Callan Executive Director i for Operations t '
Enclosures:
- 1. SRM dtd 3/27/96 (w/o attachment)
- 2. Federal Register Notice + disk 3._ Draft Regulatory Analysis
- 4. Draft Public Announcement (To Be' Prepared By OPA)
- 5. Draft Congressional Letters
- 6. ANPR dtd 4/8/96 RECORD NOTE: A draft copy of the proposed rule was sent to OIG for information on .
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'The Commissioners-8
- g. It.is estimated that this proposed action would re sit in an additional annual NRC burden of approximately on staff-week, i
- h. Copies' of- the Federal Registar Notice of prop ed rulemaking will be distributed to all- power reactor licensee . The notice will be sent to other interested parties upon requ t. ,
l 1 L. Jos h Callan ' l Execu ive Director f Operations
Enclosures:
- 1. SRM dtd 3/27/96 (w/o attachment)
- 2. Federal Register Notice + disk
- 3. Draft Regulatory Analysis
~4. Draft Public Announcement-(To Be Prepared By 0PA)
- 5. Draft Congressional Letters
-6. ANPR dtd 4/8/96 RECORD NOTE: A raft copy of the proposed rule was sent to O1G f r information on .
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