ML20198J374
| ML20198J374 | |
| Person / Time | |
|---|---|
| Issue date: | 08/15/1997 |
| From: | Hoyle J NRC OFFICE OF THE SECRETARY (SECY) |
| To: | Callan L NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| Shared Package | |
| ML20008B465 | List:
|
| References | |
| FRN-62FR47588, RULE-PR-50 AF41-1-048, AF41-1-48, SECY-97-102-C, NUDOCS 9710160139 | |
| Download: ML20198J374 (104) | |
Text
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Lieberman, OE August 15, 1997 Collins, NRR sacarT w
'Paperiello, NMSS Bangart, SP Halman, ADM Galante CIO
_ MEMORANDUM TO:
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Joseph Callan Executive Director for Operations FROM:-
LJohn C. Hoyle QA -- W
SUBJECT:
STAFF REQUIREMENTS - COMSAJ-97-009 -
ADDITIONAL COMMENTS ON SECY-97-102
-PROPOSED RULE ON' FINANCIAL ASSURANCE REQUIREMENTS FOR DECOMMISSIONING OF NUCLEAR POWER REACTORS The Commission has approved-the-attached changes to the proposed decommissioning rule which was approved by the Commission in an
-SRM dated June 30, 1997.
These changes should be incorporated in the proposed rulemaking.
(BBC)
(SECY Suspense:
P'20/97}
9500112 RES (08/a/9/)
o i cc:
Chairman Jackson Commissioner Dicus Commissioner Diaz Commissioner McGaffigan OGC CIO i
6 9710160139 971003 PDR PR j
so 62FR47588 PDR l
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6 ADDITIONAL INPUT TO PROPOSED DECOMMISSIONING RULE 1.
Delete enrrent response to C.6.
(ton 4 lines of n.
- 35) and reolace with the followina:
Resoonse.
The Commission continues to be concerned with the availability and efficacy of financial assurance mechanisms for decommissioning for those licensees whose rate regulatory oversight by FERC or the State PUCs is substantially reduced or eliminated.
Under the NRC's current regulations (and as proposed to be modified in this rule), liccnsees who no longer meet the definition of " electric utility" may use financial assurance mechanisms for decommissioning as defined in 10 CFR 50.75 (e) (2),
including (i) prepayment; (ii) an external sinking fund coupled with a surety method or insurance; (iii) a surety method, insurance, or other guarantee method, including parent company e
guarantees and self guarantees coupled with financial tests; and (iv), in the case of Federal, State, or local government licensees, a statement of intent.
The Commission is concerned that these financial assurance
-mechanisms may not be avnilable to some licensees and is thus asking for additional comment on alternative methods of financial assurance.that would provide assurance equivalent to that already provided under the Commission's regulations.
For example, in the adv.nce notice of proposed rulemaking, the Commission raised the issue of whether requiring the acceleration of decommissioning funding over a shorter period of time (e.g.,
10 years) than the period of the operating license would provide an equivalent level of assurance to current allowed mechanisms.
As discussed above, most commenters stated their opposition to accelerated decommissioning funding.
However, this opposition appeared to be predicated on the assumption that the NRC would re accelerated funding for all power reactor licensee' quire s, and not only those who no longer met the definition of " electric utility."
Thus, the Commission is asking for additional comments on whether this, or some other equivalent assurance mechanism, should receive additional consideration-in this rulemaking for those entities which would not-be classed as " electric utilities."
2.
Amend response to C.9.
(ton of n.
43) to read as follows:
Response.
The Commission believes that additional consideration of accelerated decommissioning funding or other alternative financial assurance mechanisms may be warranted, as discussed in its response at C.6.
In addition, it should be pointed out that the Commission enters bankruptcy proceedings to protect the integrity of the decommissioning funding, as suggested by a commenter....
I
t ATTACHMENT 2 MARKED UP PAGES OF FEDERAL REGISTER NOTICE
comments have nc' 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.
The comments received and the NRC staff's independent review of deregulation activities also indicate that NRC power reactor licensees are likely to have sufficient notice of changes in their' regulatory regimes so as to be able to secure necessary financial assurance for decommissioning should they no longer qualify, in whole or in part, as electric utilities.
(The staff notes that most, if not all, PUCs and FERC are addressing decommissioning funding assurance in their deregulatory initiatives.) 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 Congress.
B. STPANDED 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.
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-bypassable customer fees, including securitization, exit fees) may be different from current.
,e.
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 utility shareholders rather than customers unless there is a compelling case otherwise.
Resoonse. The Commission does not see a need to modify its position that its regulations need to be modified at this time to address the changing regulatory situation for power reactor licensees because of the comments received.
Specifically, the Commission agrees with the commenters who hold the view that regulators are likely to allow prudently incurrad 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 beyond the NRC's sphere of regulation.
Examples include having the NRC identify poorly run plants, requiring the plants to be sold and for the Federal Government to be the purchaser of last resort and even run the plants if necessary.
The NRC has addressed the issue of stranded decommissioning costs-elsewhere in this notice. However, the NRC is aware that stranded costs, insofar as their recovery affects a licensee's-ability to obtain sufficient funds to protect public health and safety, must be addressed to ensure that they are being adequately handled.
Further, States are considering a number of options for assessing non-bypassable charges to recover decommissioning costs, as well as other stranded costs.
One such option is "securitization," l
,4 i
which entails 1 financing the recovery of stranded costs through issuance of bonds whose principal and interest would be repaid by an irrevocable, non-
{
I bypassable charge set by State statute on an electric utility's distribution
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customers.
Because the income stream to repay the bonds would be securitized by-_the irrevocable, non-bypassable charge, the bonds would be highly rated and would thus require a lower interest rate than riskier _ debt. Also, these
.securitized bonds would not be'part of the utility's capital structure, and so would not reflect the nigher cost of equity capital.
The spread in interest i
cost between highly rated securitized debt and lower rated utility capital that includes bath debt and equity makes securitization attractive to many states.
The NRC believes that.securitization has the potential to provide an
- acceptable method of decommissioning funding assurance, although other mechanisms that involve non-bypassable charges provide comparable levels of assurance and should not be' excluded from consideration by State authorities.
As stated in the NRC's " Draft Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry" September 23, 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 protect 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 Utility Commissioners (NARUC), FERC, and the Securities and Exchange ComnNon (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.
NEl 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. NEl also supported NRC requirements for financial assurance, such as those currently found in 10 CFR 50.75.
Five commenters stated that they explicitly adopted u.a NEI position.
BesDonse. The Commission recognizes the importance of decommissioning funding ar.surance for prematurely shutdown plants and believes that its current case-specific approach, outlined in i 50.82, strikes the best balance between level cf assurance and cost. The alternative of requiring act.elerated fundiN for all plants over a defined period, to cover the possibility of premature shutdown at some plants,-would be too arbitrary and would lead to wide variations in impacts on licensees.
Accelerated funding results in the inequitable inter-generational problem of the present generation paying for the decommissioning costs, while the future generation may receive the benefits of future elcctricity generation without incurring the costs of decommissioning. Alths. ugh the Ccmmission is not proposing to expressly require accelerated funding to address premature shutdo.as, to the extent that-licensees no longer qualify, in whole or in part, as electric utilities, they
. will, in effect, have to " accelerate" funding by getting "up-front" forms of financial assurar.ce. The statf expects, howaver, that PVCS and FERC will address decommissioning funding through cost recovery mechanisms.
The Commission is aware thTt some plants have not operated for the full 40 years.
However, it is likely that some plants will continue operating for the full 40 _
i entities that have been authorized by a State PVC, FERC, or other governing entity to recover decommissioning costs from customers. Two commenters expected plants to remain subject to State PVC jurisdiction, and therefore to satisfy the regulatory definition. Another argued that if a portion of a vertically integrated company i subject to cost recovery pricing, the definition is satisfied. Two said that if a plant sets its own rates for electricity, the definition is satisfied.
One commenter rejected the NRC's emphasis on an operator's satisfying the definition of utility, and argued that the emphasis should be on the financial viability of the entity responsible for decommissioning the unit.
Response.
Consistent with the position taken in the ANPR, the NRC is proposing to revise its definition of " electric utility" to introduce additional flexibility to address potential impacts of electric industry deregulation. The Commission notes th d the key component of the revised definition is a licensee's rates being established either through cost-of-service mechanisms or through other non-bypassable charge mechanisms, such as wire charges, non-bypassable customer fees, including securitizuion or exit fees, by a rate-regulating authority.
Several States are considering deregulation of future operations of nuclear. power plants so 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 that 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 rc9ulations to which those.
funding is provided. Accelerated funding, in the view of some commeaters, could not be accomplished through rate increases and would have to be paid by licensees' stockholders. One commenter argued that utility shareholders t
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 problems for licensees and could result in increased borrowing to cover cash outlays. Accelerated funding could lead to the shutdown of marginal facilities, which would be contrary to the intent of the 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.
Resoonse. The Commission continues to be concerned with the availability and efficacy of financial assurarce mechanisms for decommissioning for those licensees whose rate regulatory oversight by FERC or the State PUC's is substantially reduced or eliminated. Under the NRC's current regulations (and as proposed to be modified in this rule), licensees who no longer meet the definition of " electric utility" may use financial assurance mechanisms for decommissioning as defined in 10 CFR 50 '5(e)(2),
including (1) prepayment; (ii) an external sinking fund coupled with a surety method or insurance; (iii) a surety method, insurance, or other guarantee method, including parent company guarantees and self guarantees coupled with financial tests; and (iv),-in the case of Federal, State, or local licensees, a statement of intent..
g_
The Comission is concerned that these financial assurance mechanisms may not be availaMe to some licensees and is thus asking for additional coment on alternative methods of financial assurance that would provide assurance equivalent to that already provided under the Comission's regulations.
For example, in the advance notice of proposed ruinmaking, the Comission raised the issue of whether requiring the acceleration of decomissioning funding over a shorter period of time (e.g.,10 years)- than the period of the operating license would provide an equivalent level of assurance to current allowed mechanisms. As discussed above, most commenters stated their opposition to accelerated decomissioning funding.
However, this opposition appeared to be predicated on the assumption that the NRC would require accele ited funding for all power reactor licensees, and not only those who no 1onger met the definition of " electric utility." Thus, the Comission is asking for additional coments on whether this, or some other equivalent assurance mechanism, should receive additional consideration in this rulemaking for those entities which would not be classified as " electric utilities."
C.7 Potential Shortfalls 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.
None, however, clearly identified a source of funding to make up the
ortf all.
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, I
36 -
i
...-.....-----...a6
None of the comenters recommended increasing contingency factors to provide for potential-shortfalls far in the future. Several argued that contingency. facters are intended to address " unforeseeable cost elements" or t
that contingencies are inappropriate for some other reason. The size of such contingencies would be too arbitrary.
In addition, some State PUCs would not
~~
apply larger contingencies, particularly 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 NEl in taking a position against the use of contingencies to address the problem of potential shortfalls occurring far in the future.
Resoonse. The Coinmission 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, tne Commission has the authority to
- require power reactor licensees to submit their current financial assurance mechanisms for NRC review, revision as necessary, and approval. The Commission reserves the right-to take the following steps in order to assure a licensee's adequate accumulation of decommissioning funds:
review, as needed, the rate of accumulation o' decommissioning funds; and either independently or
'in cooperation with either the FERC and the State PUC's, take additional actions as appropriate on a case-by-case basis, including modification of a licensee's schedule for accumulation of decommissioning funds, i.
('.
l approaches, either based on 10 CFR 50.75 or on options that have not yet been recognized.. A PUC comenter asked NRC to work collaboratively with States to explore, as hecessary,-alternative financial assurance mechanisms in the event that privately owned nuclear generators are no longer regulated.
.0ae comenter suggested that NRC's support for existing Federal obligations to provide a national nuclear fuel repository would also contribute-to the financial assurance of responsible nuclear decomissioning. -
- Another called for financial assurance to be mandated at-the Federal level, and a third said NRC should consider whether DOE responsibility can be developed for providing solutions to decomissioning.
Four comenters said no other options were necessary.
They reasoned that current options are sufficient irrespective of PUC or FERC oversight, regulatory oversight is unlikely to be :urtailed, and FASB standards and competitive pressures will provide sufficient assurance.
Response. The Comission believes'that additional consideration of accelerated decommissioning funding or other alternative financial assurance mechanisms may be~ warranted, as discussed in its response'at C 6.
In.
addition, it should be pointed out that the Comission enters bankruptcy proceedings to protect the integrity of the decommissioning funding, as suggested by' a comenter. Also, the Commission-is proposing use of the FASB standard as a means for the reporting decommissioning obligations.
- Further, 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 decomnissioning under deregulation.
Further, the._
4
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 that the timing 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 NRC by September 30 of the following year.
Two commenters stated that interim reporta could be required for significant events (e.g.,
merger, acquisition, financial deterioration). This commeater also suggested that limited or negative growth of the fund in a given year due to overall market conditions should agi automatically trigger adjustments to funding levels but rather that a 3-to 5-year time frame should be used.
Resoonse. The Commission is proposing that every licensee submit its initial report on the status of decommissioning funds to the NRC within 9 months after the effective date of this rule, and at least once every 2 years thereafter. Annual submission is not being proposed as an option because the NRC believes it can adequately review licensee financial assurcnce status for decommissioning biennially while reducing licensee reporting burden. However, the licensee (s) of any plant that is within 5 years of its planned end of operation would be required to submit its report annually.
G.
C0 H NTS ON TOPICS NOT SPECIFICALLY RAISED IN THE ANPR Commenters suggested several a tions that NRC had not asked about specifically in the ANPR.
First, a commenter stated that NRC should require sites to be decommissioned to " green field" status, consistent with FERC guidelines..,
A
e (ii) External sinking fund. An external sinking fand is a fund establi'hed and maintained by setting funds asido periodically in an account segregated from licensee assets and outside the licensee's administrative control in which the total amount of funds would be sufficient to pay decomissioning costs at t% time termination of operation is expected. An external sinking fund may be in-the form of a trust, escrow account, government fund, certificate of deposit, or deposit of government securities.
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 decomissioning period, if the licensee's rate-setting authority
-does not authorize the use of another rate.
i (3) For an electric utility, its rates must be sufficient to recover the cost of the electricity it generates transmits, or distributes. These rates 'must be established by a regulatory authority such that they are sufficient for the' licensee to operate, maintain, and decomission its plant safely. The Comission reserves the right to take the following steps in order to-assure a~ licensee's adequate accumulation of decommissioning funds:
review, as needed, the rate of accumulation'of decommissioning funds; and
_either independently or in cooperation with either the FERC and the State 4
PUC's, take additional actions as appropriate on a case-by-case basis, including modification of a licensee's schedule for accumulation of decommissianing funds.
Acceptable methods of providing financial assurance for decommissioning for an electric utility are-4 (f)(1) Each power reactor licensee shall report to the NRC within 9 months after (the effective date of this rule), and at least once every 2 years thereafter on the status of its decommissioning funding for each reactor' facility or part of a reactor facility that it owns. The information in this report must include, at a minimum: the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c); the amount accumulated to the date of the report; a schedule of the annual amounts remaining te be collected; 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; and any modifications occurring to a licensee's current trust agreement since the last submitted report. Any licensee for a plant that is within 5 years of the projected end of its operation shall s.;bmit such a report annually.
Dated at Rockville, Maryland, this day of
, 1997.
For the Nuclear Regulatory Commission.
John C. Hoyle, Secretary of the Commission.,
4
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94 ep ATTACHMENT 3 CONGRt!SSIONAL LETTERS
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NUCLEAR REGULATORY COMMISSION WASHINGTON D.C. 3044A001 k...../
g The Honorable Dan Schaefer, Chairman Subcomittee on Energy and Power Comittee on Comerce United States House of Representatives Washington, DC 20515
Dear Mr. Chairman:
In the near future, the Nuclear Regulatoi Commission (NRC) intends to publish in the Federal Reaister the enclosed prop,osed 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 31 ants. This is being done in response to the anticipated deregulation of tie power generating industry. The ptoposed action would revise the definition of " electric utility" contained in 10 CFR 50.2, would add a definition of " Federal licensee" to address the-issue of which licensees may use statements of intent, and would require licensees to periodically rerort on the status of their decomissioning funds and changes in their external trust agreements.
Lastly, 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 F
a
The Honorable Dan Schaefer. Chairman Subcomittee on Energy and Power Comittee on Comerce United States House of Representatives Washington, DC 20515
Dear Mr. Chairman:
In the near future, the Nuclear Regulatory Comission (NRC) intends to publish in the Federal Reaister 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
-decomissioning of nuclear power )lants. This is being done in response to the anticipated deregulation of tie power generating industry.
The proposed action would revise the definition of " electric utility" contained in 10 CFR 50.2, would add a definition of " Federal utility" to address the issue of which licensees may use statements of intent, and would require. licensees to periodically report on the status of their decomissioning funds and changes in their external trust agreements.
Lastly, 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 Commission is issuing the proposed rule for public comment, Sincerely.
Dennis K. Rathbun, Director Office of Congressional Affairs
Enclosure:
1 Federal Register Notice
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he Honorable Dan Schaefer,-Chair,ian Su ittee on Energy and Power Committ on Comerce United St es House of Representatives Washington, 20515
Dear Mr. Chairman:
In the near future, the uclear Regulatory Comission (NRC) intends to publish in the Federal Register t enclosed proposed amendment to the Comission's rules in 10 CFR Part 50. Th proposed rule is being developed to amend the NRC's regulations relating to nancial assurance requirements for the decomissioning of nuclear power lants. This is being done in response to the anticipated deregulation of th ower generating industry.
The proposed action would revise the definition o " electric utility" contained in 10 CFR 50.2, and require licenset.s to riodically report on the status of their decommissioning funds and funding r the management of their irradiated fuel.
Lastly, the Comission is proposing o allow licensees to take credit for the earnings on decommissioning trust f ds from the time of the funds' collection through the decommissioning period, e
The Commission is usuing the proposed rule for blic coment.
Sincerely, Dennis K. Rathbun, Director Office of Congressional Affai
Enclosure:
Federal Register Notice cc:- Representative Ralph Hall Distribution:
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The Honorable James M Inhofe, Chairman Subconnittee on Clean Air, Wetlands, Private Property and Nuclear Safety Connittee on Environment and Public Works United States Senate Washington, DC 20510
Dear Mr. Chairman:
In the near future, the Nuclec Regulatory Connission (NRC) intends tu publish in the Federal Reaister the enclosed proposed amendment to the Connission'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 )lants, This is being done in response to the anticipated deregulation of tie power generating industry. The proposed action would revise the definition of " electric utility" contained in 10_CFR 50.2, _would add a definition of " Federal licensee" to address the issue of which licensees may use statements of intent, and would require licensees to periodically report on the status of their deconmissioning funds and changes in their external trust agreements.
Lastly, the Conclssion is proposing to allow licensees to take credit for the earnings on decommissioning trust funds from the time of the funds' 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
F The Honorable James M. Inhofe, Chairman Subcomittee on Clean Air. Wetlands, Private Property and Nuclear Safety Committee on Environmant 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 Eederal Reaister 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 decomissioning of nuclear power )lants.
This is being done in response to the anticipated deregulation of tle power generating industry.
The proposed action would revise the definition of " electric utility" contained in 10 CFR 50.2, would add a definition of " Federal licensee" to address the issue of which licensees may use statements of intent, and would require licensees to periodically report on the status of their decomissioning funds and changes in their external trust agreements. Lastly, the Comission is proposing to allow licensees to take credit for the earninas on decomissioning trust funds from the time of the funds' collection through the decommissioning period.
The Comission is issuing the proposed rule for public comment.
Sincerely, Dennis K. Rathbun, Director Office of Corigressional Affairs
Enclosure:
Federal Register Notice cc: Senator Bob Graham Distributica:
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4 The-orable James M. Inhofe, Chairman Subcomm tee on Clean Air, Wetlands, Private Propert nd Nuclear Safety Comittee on nvironment and Public Works
. United States ate Washington, DC 10
Dear Mr.- Chaircan:
In the near future, the N lear Regulatory Commission (NRC) intends to publish-in the Federal Register the nelosed proposed amendment to the Commission's rules in 10 CFR Part 50.
Thi roposed rule is being developed to amend the NRC's regulations relating to.f ncial assurance requirements for the decommissioning of-nuclear power ants.
This is being done in response to the anticipated deregulation of the ower generating industry.
The proposed action would revise the definition o " electric utility" contained in 10 CFR 50.2, and require licensens to riodically report on-the status of their. decommissioning funds and funding for thef iagement of their irradiated fuel.
Lastly, the Commission is proposi to aluw licensees to take credit for the earnings on decommissioning trust unds from the time of the funds' collection through the decommissioning per d.
The Commission is issuing the proposed rule f public comment.
Sincerely, I
Dennis K.-Rathbun, Direct Office of Congressional Af irs
Enclosure:
- Federal Register Notice cc: -Senator Bob Graham Distribution:
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OFFICIAL RECORD LOPY (RES File Codel RES:
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ATTACHMENT 4 PUBLIC ANN 0tjNCEMENTS
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NRO PROPOSES CHANGES IN DECOMMISSIONING FUNDING RULE The Nuclear Regulatory Commission is proposing to amend its regulations on decommissioning funding to reflect conditions expected from deregulation of the electric power industry.
-NRC is seeking-public comment on the proposed rule change, which-would amend the current regulation which was adopted in 1988 before the current moves for deregulation began.
Deadline for submission of comments is-The amended rule would:
Revise'the' definition of an " electric utility" to
^ reflect changes caused by restructuring within the industry.
Define a " Federal licensee" as any. licensee which has the full faith and credit backing of the United States government.
Only such licensees could use statements oof intent-to meet decommissioning-financial assurance requirements for power. reactors.
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. Require nuclear power plant licensees to report to NRC e
on the status of their decommissioning funds within 9 months after the effective date of this rule and at
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e least once every 2 years thereafter, and annually within 5 years of the planned end of operation.
NRC's present rule contains no such requirement because state and Federal rate-regulating bodies actively monitor these funds.
A deregulated nuclear utility would have no such monitoring, Permit nuclear licensees to take credit on earnings for o
prepaid decanmissioning trust funds and external sinking funds from the time the funds are set aside through the end of the decommissioning period.
The present rule does not permit such credit because it is assumed that inflation and taxes would erode any.,
investment return.
NRC has decided, however, that this position is net borne out by historical performance of inflation-adjusted funds invested in U.S. Treasury instruments.
Further details are available in a notice published in the edition of the Federal Register.
Comments should be mailed to:
The Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention:
Docketing and Service Branch.
Comments also may be delivered to NRC's headquarters offices at 11555 Rockville Pike, Rockville, Maryland, between 7:30 a.m. and 4:15 p.m. on Federal workdays.
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In preparing this proposed rule amendment, NRC has considered 650 comments received in response to an advance notice of proposed rulemaking on this subject published in April of last year.
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ATT/C'iAENT 5 DRAFT REGULATORY ANALYSIS
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l REGULATORY ANALYSIS ON DECOMMISSIONING FINANCIAL ASSURANCE IMPLEMENTATION REQUIREMENTS FOR NUCLEAR POWER REACTORS Draft Report for Comment U.S. Nuclear Regulatory Commission Office of Nuclear Regulatory Research
i REGULATORY ANALYSIS ON DECOMMISSIONING FINANCIAL ASSURANCE IMPLEMENTATION REQUIREMENTS FOR NUCLEAR POWER REACTORS Draft Report for Comment Regulation Development Branch Division of Regulatory Applications Office of Nuclear Regulatory Ib. search U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 4
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CONTENTS Past l. INTRO D U CTI O N............................................................... I 1.1 Statement of the Problem and Objective of the Rulemaking......................
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1.2 Current Regulation of Decommissioning Financial Assurance........._............ 2 2.
IDENTIFICATION AND PRELIMINARY ANALYSIS OF A LTERNATIVE APPRO ACH ES................................,............ 5 2.1 Need for Fully-Funded Assurance Due to Deregulation........................... 6 2.1.1 Opt ion A 1 : No acticn............................................. 6 4
2.1.2 Option A 2: Revise the regulatory definition of"clectric utility" to clarify that it excludes entitles that are no longer able to recover costs through regulated rates, fees, or mandatory charges..................................... 7 1
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. 2.2 Credit for Earnings on Decommissioning Funds................................ 7 2.2.1 Option B 1 : No action............................................. 8 2.2.2 Option B 2: Allow credits for earnings during safe storage and'an assumed 2 percent real rate of return................,........................ 9 2.3 Monitoring Fund Balances through Reporting................................
10 2.3.1 Opt ion C 1 : No ac t ion............................................. 10 2.3.2 Option C-2: Implement a periodic reporting requirement.................. Ii 2.4 Use of Statements ofintent by Power Reactor Licensees.,.......................
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2.4.1 Option D-1 : No action............................................ 1 i
. 2.4.2 Option D-2: Clarify which licensees may use statements ofintent by defining the term " Federal licensee"........................................
12 2.5 ' - Additional Review of Decommissioning Financial Assurance Mechanisms..........
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- 2.5.1.
Option E-1 : No action............................................
13 2.5.2 Option E.2: Require periodic submission of any modifications to external trust agreements (and other financial assurance mechanisms) for detailed N RC rev i ew...............,...................................,. 13 f
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CONTENTS (continued)
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15 3.1 Identification of A ffected Attributes..........................................
15 3.2-Research and Evaluation ofinformation on Selected Attributes...................
19 3.2.1 Decommissioning Cost Estimates Used as Basis for External Sinking Funds.
19 3.2.2 Projected Funding Status of External Sinking Funds..................... 21 3.2.3 Reporting on Status of Decommissioning Funds....................,... 21 3.2.4 Availability and Security of Financial Assurance Mechanisms to Supplement or Replace External Sinking Funds.......................... 30 3.2.5 Potential Industry Restructuring.,,.................................. 36 3.3 M od el Des ign........................................................... 3 8 3.3.1 Development of the Database...................................... 39 3.3.2
. Modeled Scenarios............................................... 4 0 3.3.3 Modeling of Regulatory Options.................................... 41
-3.3.4
.A s su m pt i on s.................................................... - 4 8 3.4 R e s u l ts................................................................ 4 9 3.4.1 Estimated Values and impacts of 0ptions A-1 and A 2.................. 50 3.4.2 Estimated Values and Impacts of Options B-1 and B-2,,................. 52 3.4.3 Estimated Values and Impacts of Options C-1 and C-2.......,........... 55 3.4.4 Estimated Values and impacts of Options D-1 and D-2.................. 57 3.4.5 Estimated Values and Impacts of Options E-1 and E-2................... 60
- 4. B A C K FIT AN A LYS I S......................................................... 63 5; D ECISION RATIONALE...................................................... 65
- 6. I M PLE M E NTATIO N........................................................... 69 Page vill
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- 1. INTRODUCTION NRC has initiated a rulemaking to address concerns related to its financial assurance requirements for nuclear power reactors. As discussed in detail below, most of these concerns are the result 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 8,1996). NRC has reviewed these comments and is studying a number of regulatory options. This document presents NRC's Regulatory Analysis of these optioas.
The 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 information on the current regulation of financial assurance for decommissioning costs of power reactors.
1.1 o atement of the Problem and Objective of the Rulemaking NRC's decommissioning financial assurance requirements for nuclear power reactors are based on 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 utilities 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 numerous 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 recovery 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 restructur ng, increasing competition may force integrated power systems to separate (or "disaggregate") their systems into functional areas. Thus, some licensees may divest electrical generation asects, such as power reactors, from transmission and distribution assets by forming separate subsidiaries o. even separate companies for generation. Disaggregation may involve utility restructuring, mergers, and corporate spin offs that lead to changes in owners or operators oflicensed 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 Page1
w construct, operate or own its power reacter, as well as to necumulate adequate funds to ensure e
decommissioning at the end of reactor life.'
%w; As the electric utility industry mos es from an envirenment of substan ial economic regulation to one ofincreased competition, NRC is conc erned about the impacts of restructuring and rate deregulation.
Approval of organizational and rate der 7ulation changes by other regulators may occur rapidly and without NRC's knowledge. The degree mi pace of such changes could affect the factual underpinniry of NRC's previous conclusions that power reactor licensecs can reliably accumulate adequate innds for operations and deconomissioning over the operating lives of their facilities.
The meia objective of t'ic cucrent ralemaking is to modify NRC's regulatory fra. mew ensure that deregulatory activities in the electric utility industry do notjeopardize NRC lier financial assurance for decommissioning. The iulemaking would accomplish this by claril additional financial assuiances for decomtr issioning are required from any power reactor lii
. e that
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loses the ability to recover decommissionir1g 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 liensee, l'inally, the current 4
rulemaking also v ould update the financia! 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 decomm!ssioning costs.
g 1.2 Current Regulation of Decomraissioning Financial Assurance NRC requirements pertaining to financial assurance for the decommissioning of nuclear power reactors s contained in UI CFR 50.75. Ai. 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) states that the NRC req uirements "are in addition to, and not substitution for, (these) otner requirements."
Additional gaidelines for NRC licensees are prvdded in NRC's Regadaiory Guide L /59,2 and in a related Standsrd Review Plan (SRP).2 Under 50.75(b) licensees must demonstrate decommissioning tinancial aswance in an amount at least equal to either a minimum " certification" amoum (based on a formula specified at Q50.75(c)) or a facility-specific decommissionina, estimate (provided that the estimate it at least as great as the applicable certification amount). Licensees are required to update annually the minimum amount of decommissioning assurance required ur. der the certification formula in 50.75(c) by applying an inflation-factor that is also described in 50.75(c). Licensees are not required to file this adjustment with NRC, howeverc Pursuant to 50.75(a), licensees are required to adjust collections from ratepayers in coordination with the appropriate PUCs or FERC.
' In 1984, NRC eliminated financial qualifications reviews at the operating license stage for those licensees
- thu met the defirftion of" electric utility." This decision was based on NRC's assumption that "the rate process q
assures that funds needed for safe op+ ration wih be made available to regulated electric utilities"(49 FR 35750, September 12, 1984).
- Regulatory Guide 1.159, " Assuring the Availabiliv ofFundsfor mmmissioning Nuclear Reactors, " U.S.
Nuclear Regulatory Commi sion, Office of Nuclear Regulatory Research, August 1990.
' Dmft Standard Review Plan on Power Reactor Licensee financial Quahficariam and Decommissionmg Financid Assurance, U.S. Nuclear Regulatory Commission. Office of Nuclear Regulatory Research, Septemoer 1996.
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Financias assurance must be demons: rated using one of the financial mechanisms described in QS0.75(e). These mechanisms include " prepayment" mechenisms (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.4 Prepayment mechanisms, in the case of non-electric utility licensees, must be either fully funded or, if being funded gradually in an external sinking fimd, must be coupled with another mechanism (e.g., a surety bond) so that the total assurance provided by the licensee is at least equal to the required level of coverage.
In the case of electric utility licensees, however, external sinking funds are not required to be coupled with another financial assurance mechanism Thus, electric utility licensees are not required to demonstrate the full minimum amount of decommissioning coverage (i.e., the full certification amount) until contributions to the extemal sinking fund cease at the end of the operating license. Npr ~ -illed this difference in treatment between electric utility licensees and non-electric utility licenscu a the ability of the electric utilities to collect funds through the rate-making process and on the ad. led overs ght provided by FERC and PUCs.
Payments to m external sinking fund (regardless of whether or not the licensee is an electric utility) must be made annually in amounts that will result in full funding by the time the facility ceases operation. Although NRC allows licensees ta account for future earnings (i.e., until the reactor shuts uown) on decommissioning trusts w hen calet.lating annual contributions to extem.1 sinking funds and prepayment amoums, this position is not reflected in regulations, but rather in guidance (i.e., in Regidatory Guide 1.139 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. Ilowever, 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).
In practice, virtually all non-Federal government electric utility licensees are believed to use external sinking funds based on trusts.5 NRC requirements provide that trusts (or any mechanism used as an external sinking fund) must be segregated from licensee assets and outside the licensee's administrative control.' Investment guidelines and other restrictions affecting trustees and/or licensees are not specified in NRC regulations. Ilowever, NRC guidance does (1) provide suggested investment
- Under 10 CFR 50. 75(e)(2)-(3), statemer,ts ofintent are allowable mechanisms for Federal governmens electric utility licensees, and for Federal, State, and local government non-electric utility licensees.
' In 1990, NRC reviewed the financial mechanisms originally submitted by licenstes to comply with the then-new decommissioning financial assurance requirements. Most of these mechanisms were trusts, but the subm.stals also included three sinking funds based on escrows, one prepaid escrow, one " restricted deposit agreement," and one " city sinking fund." More recent information on mechtnisms being used by licensees is not available.
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guidelines,'(2) specify trustee qualifications,' and (3) state that licensees may make withdrawals from the fund only to pay for decommissioning activities.'
Regulatory Guide 1.li9 offers detailed model wording for tmst agreements (including numerous conditions that provide additional protections on behalf of NRC's interests) but states that this wording may be modined "as a 'icensee's specinc situation warrants [provided that the agreement) complies with applicable state law.. " Licensees submitted Onancial mechanisms for NRC's review one time (in 1990). Regidatoc Guld 1.159 states that iflicensees "cither change or signi6cantly modify the funding method," they must subm
- the changes or modi 6 cations to NRC within a " reasonable time."" Licensees must also maintain an existing method of financial assmance "until the licensee has instituted a new method.""
NRC doet not require licensees to report periodically on the status of their decommissioning
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funds. Rather, NRC views licensee compliance with the funding assurance requirements as a matter to be determined through the inspection process when necessary, as well as through monitoring by State PUCs and FERC of decommissioning funds oflicensees under theirjurisdiction 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 rulernaking, were researcha as part of this Regulatory Analysis and are discussed in Section 3.2.3.
' Regulatory 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. Licensees not eligible or willing to use decommissioning trusts established under IRS Code Section 468 A or not subject to PUC or FERC jurisdiction should limit trust investments to " investment-grade" securities.
Investment-grade bonds and preferred stocks are those rated at least "BBB" or equivalent by a national rating service. Speculative asues of common stocks should be avoided."
- Regulatory Guide 1.159, p.14, states that "I'he trustee of a fund should be an appropriate Sate or Federal govemment agency or an entity that has the authority to act as a trustee and whose trust operations are regulated or examined by a State or Federal agency."
- SRP, p. 27. Many licensees that have established decommissioning trust funds for their power reactors are making deposits into their trust accounts both for decommissioning costs as delined under g50.2 and for other decommissioning-associated costs such as interim spent fuel management and storage and "greenfield" costs.
RegulatorfGuide 1.159, Section 2.1.6.1, p.13. The SRP(in Section Ill.2.d) notes that licensees are also required to submit these changes and.nodifications to NRC in accordance with 10 CFR 50.9. (i') CFR $0.9 requires licensees to notify NRC within 2 working days if the licensee identifies information having a significant implication for public health and safety or common defense and security, unless this information is covered by other reporting or updating requirements.) it is unclear whether licensees have been submitting modifications of financial mechanisms to NRC for review.
" Regulatory Guide 1.159, Section 2.1.6.1, p.13.
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- 2. IDENTIFICATION AND PRELIMINARY ANALYSIS OF ALTERNATIVE APPROACllES The Rulemaking Plan for this rulemaking identified three specific options, and three corresponding no-action alternatives, to address the issues discussed in Section 1.1:
Issue A.
Is fully-funded assurance needed due to deregu'ation?
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 al;ow credit for earnings during safe storage periods?
Option B-1: No action option.
Option 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 fund balances through regular periodic reporting?
Option C-1: No action option.
Option C-2: Implement a periodic reporting requirement.
hRC's April 1996 ant'R also drew attention to other issues that had not been emphasized in the Rulemaking Plan. These issues involve (1) the use of statements ofintent by power reactor licensees, and (2) further review of decommissicaing financial assurance mechanisms. The following options (and their corresponding no-action alternatives) have been added to this Regulatory Analysis to address these issues:
Issue D.
Should NRC allow use of statements of iatent by power reactor licensees?
Option D-1: No action op: ion.
'3 4 3 D-2: Clarify which licensees may use statements ofintent by defining the term " Federal licensee."
Issue E.
Should NRC conduct tidditional review of decommissioning financial assurance mechanisms?
Option E-1: No action option.
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Option E-2: Require periodic submission ofany modifications to external trust agreements (and other financial assurance mechanisms) for detailed NRC review.
The remainder of this section presents a preliminary analysis of each of these options. The purposes of this discussion are to highlight the purpose of each regulatory revision, and to clarify what each option is and how it might work. Additional ana!ysis of these options is presented in Section 3 of this Regulatory Analysis.
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, NRC's financial assurance requirements for electric utility licensees (relative to non-electric utility licensees), as 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 no* meet the definition of an electric utility may use an external sinking fund only if the amount remaining unfunded in the external sinking fund is assured using an additional financial assurance mechanism (e.g., a surety bond or letter of credit). In contrast, licensees that meet the definition ofelectric utility may use an external sinking furd without providing any additional financial assurance for amounts not yet funded. As discussed in Scetion 1, NRC found this distinction reasonable because electric utilities historically have been able to collect needed funds through a regulated rate-making process and because of t' e additional oversight role provided b. 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 deregulation in the ciectric utility industry, however, licensees in the future may recover costs not through rates but through other mandatory mechanisms (e.g., access fees, exit fees, line charges) established by their rate regulators. Although NRC believes these licensees can recover costs and should be con;idered electric utilities, NRC's current definition of"electri: utility" could be interpreted otherwise. In addition, NRC is concerned that other licersees may be able to qualify as electric utilities under NRC's current definition despite being deregulated with respect to the recovery of prudently-incurred costs 10 CFR 50.2 defines " electric 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 generation or distribution subsidiaries, p iblic 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 utility." (italics added)
Public comments received in response to NRC's April 8,1996, ANPR suggest that some licensees interpret NRC's current definition, because of the phrase "either directly or indirectly, through
, established by the entity itself," to encompass even non-regulated or fully deregulated entities that rt are free to set their own prices in the marketplace. This interpretation would, in effect, allow all licensees to qualify as electric utilities and, in turn, allow all licensees to use external sinking funds Page 6
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without combining them with other financial mechanisms. NRC, however, had included in its definition -
the phrase "either directly or indirectly, th'ough rates established by the entity itself" merely to allow the definition to encompass those entities, such as some publicly-owned utilities, that regulate their own rates through a process that is open to public participation and scrutiny. Beceuse all NRC power reactor licensees are, currently, regulated to allow recovery of costs, this potential misinterpretation of the definition is of concem only to the extent that deregulation affects licensees in the future.
- Under Option A 1, the'lefinition of" electric utility" would remain as stated above. Depending on the outcome of deregulatic i, some licensees inappropriately believ they no longer meet the definition and, consequently, obtain more costly financial assurance mechanisms. Other licensees may continue to meet the definition of electric utility despite being deregalated with respect to the recovery of
. prudently-incurred costs (i.e., despite having reduced recourse to decommissioning cost recovery through -
rates approved by PUCs or FERC). Such licensees might use external sinking funds to demonstrate financial assurance for decommissioning without also providing an additional financial mechanism to -
_ cover unfunded costs. This would be contrary to the assumptions underlying NRC's rationale for treating regulated electric utilities differently from other NRC licensees, and could result in shortfalh a l
funding for decommissioning if these licensees go bankrupt or their reactors close prematurely.
~2,1.2 Option A-2:
Revise the regulatory definition of" electric utility" to clarify that it
- excludes entitles that are no longer able to recover costs through regulated rates, fees, or mandatory charges i
Under this option, NRC would revise the definition of" electric utility" found in 10 CFR $0.2 to read as follows:
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 e
autho&, such that the rates are sufricient for the licensee to operate, maintain, and decommission its nuclear plant safely. Rate
- may be established by a regulatory authority either directly through traditional" cost of service" regulation or indirectly through another non-bypassable charge mechanism. An entity whose rates are established by a regulatory authority by mechanisms that cover only a portion ofits costs
- will be considered to be an " electric utility" only for that portion of the costs that are collected in this manner. 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."
NRC believes this definition clarifies its intention that only licensees capable of recovering costs through regulated non bypassable rates, fees, and mandatory charges be considered electric utilities eligible for differential tu.atment 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 licensees that 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 fund or prepayment mechanism, regardless of whether or not the licensee is an electric utility. The options Page 7 s
_ impact how much money licensees must contribute into their funds by restricting their assumptions regarding future earnings.
2.2.1 Option B-1: No acthn 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 fcr 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 tennination of operation is expected." Given that external sinking funds are required to be fully-funded by the time facilities sre 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., retums 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 camed by shutdown, may force licensees to collect more funds from ratepayers than is absolutely necessary, given the potential for accrual ofinterest in the safe storage period. This, they argue, would result in an unwarranted expense to licensees, their ratepayers, or their stockholders, and it could create inequities between generations of ratepayers.
With respect to the return that ;icensees shouki assume 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 ofinvestment, but does not establish an upper limit for assumed rates of retum. In practice, licensees assume a wide range of projected eamings rates, and many licensees assume rates that are fairly high (e.g., real rates of 6 to 8.7 percent)." (For example, a real rate
- Regulatory Guide 1.159, p.14.
" In contrast, insufficient returns camed on decommissioning funds pnor to the safe storage period are of less concern, The reason for this is that licensees' nuclear power reactors would still be generating revenue in this situation. Therefore, licensees would be better able /all else equal) to make up the difterence with added contributions to the fund.
" AnnualSurvey ofNuclear Decommissioning Cost Ecimates and Fanding Policies. Public Utility Survey, Table 32. Goldman Sachs, August 1995.
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of 8.7 percent exceeds the historical average real rate of return of 6.9 percent for a portfolio invested 100 percent in large company common stocks.")
Under Option B-1, licensees using external sinking funds, when calculating annual contributions, would continue to account for future earnings projected through the end of the expected termination of operations. Licensees using the safe storage method of decommissioning still would not be allowed to take the safe-storage period iato account in their annual funding calculations. This option would also take no action to further restrict licensees' eamings rate assumptions for purposes of ealculating annual contributions to sinking funds. Prepayment mechanisms also would be unaffected by this option.
2.2.2 Option B-2:
Allow credits for earnings during safe sierage and an assumed 2 percent real rate of return Under Option B 2, licensees using external sinking funds, when calculating annual contributions, would account for beth (1) future decommissioning fund earnings projected through the end of the expected termination of operations, and(2) future returns expected to be earned during the safe storage period,if the particular nuclear power reactor will use this method of decommissioning. The final annual contribution would still have to be made prior to temiination of operations at the facility, but the balance in the decommissioning fund would then continue to grow during safe storage until it is fully funded by the time of decommissioning. Option 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 stortge, in those cases w here a regulator (e.g., FERC) does not approve the assumed earnings rate.
Also under this option, licensees usingprepayment mechanisms could reduce the amount that they must piepay to account for future carnings. As in the case oflicensees using, external sinking funds, licensees using prepayment mechanisms would be allowed to take credit for earnings expected to accrue from the time of prepayrnent, through safe store,e, 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 assumed earnings rate would also be restricted to a real rate of return of 2 percent in cases 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 NkC. In many cases, however,2 percent is less than the rate currently assumed by licensees." To the extent that earnings in a given year prove to be higher than 2 percent, the balance of the fund will be greater than anticipated. Licensees may take this higher balance iato account in calculating subsequent contributions to their sinking funds. This means the size of subsequent contributions will decrease, even though these sub equent contributions will still be based on a 2 percent eamings assumption. (Similarly, if the actual real rate of return proves to be less than the assumed 2 percent rate, the size of subsequent contributions will increase, even though they will still be based on a 2 percent earnings assumption.)
e
" Stocks. Ewnds, Bills andInflation 1995 Yearbook: Ala ket Resultsfor 1926-1994. Table 6-7, Ibbotson Associates,1995.
Although actual returns may exceed 2 percent on average, rates in the short term (e.g., the 5 or 10 years prior to decommissioning) may be. below average (oi even negative).
" The average rate currently asst ned by licensees is 3.7 percent.
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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 ofinterest. For two reasons, however, this option seems unlikely 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 determination of decommissioning methods only 5 years prior to termination of operations? If safe storage is Mected at that time, the benefit of this option would be fairly small because the decommissioning fund would already be largely funded.
Second, the application of this option to prepayment mechanisms (the costliest method of financial assurance) is un'ikely 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 potentially greater concern, however, is that the option provides 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, the invested decommissioning funds will not have adequate time to generate the needed funds. Second, realized rates et return must equal or exceed the assumed rate. This risk is reduced substantially for affected licensees by limiting the assumed rate to 2 percent.
Third, funding contributions calculated by licensees must account for the added costs (e.g., security) of a safe storage decommissioning relative to the lower cost of a prompt decommissioning. In particular, contributions based on NRC's certification amounts would be inadequate because the certification amounts assume prompt decommissioning If safe storage costs are not reflected in the fund con.eibutions, then actual spending on safe storage costs could result in inadequate funds remaining for the actual decommissioning.
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 includi.ig, 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 external s;aking funds in this case only by coupling them with another financial mechanism (e.g., a surety bond, letter of credit, or parent company guarantee) to cover costa that are not yet funded by the sinking fund. This option may have greater impact on non-power reactor licensees, who at:cady are ineligible to use external sinking funds except in combination with another fmancial mechanism.
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i 23.1 Option C-1: No action NRC has not deemed it necessary to monit.r licensee compliance with the current decommissioning funding assurance requirements. Currently, NRC views licensee compliance with the funding assurance requirements as a matter to be determined through the inspection process when
. necessary. NRC has also relied on FERC's and PUCs' monitoring of the decommissioning funds of licensees that fall under the:rjurisdiction (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.
2J.2 Option C-2: Implement a periodic reporting requirement NRC is concerned that rapid changes (e.g., divestitures and restructuring) in the electric utility industry 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 thejurisdiction and oversigt.t of FERC or PUCs.
Option C-2 would require all power reactor licensees to report to NRC within 9 months aller the effective date of the rule and at least once every 2 years thereafler on the status of their decommissioning funding. Licensees for 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. Reports would also need to include the following:
The amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.Mc);
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 tmst Omds, and rates of other factors (e.g.,
discount rates) used in funding projections.
This option would enable NRC to establish a stronger 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 ofinformation 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 put poses, such as evaluating licensee notifications of r.: structuring and responding to related information requests from Congress and media organizations (over the past few years, NRC has been unable to fulfill such requests).
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l-2.4 Use of Statements ofIntent by Power Reactor Licensees Options D-1 and D 2 address tM issue of whether statements of inten. should continue to be allowed as an acceptable financial mechanism for power reactor licensees.
2.4.1 Option D-1: No action NRC regulations currently allow " Federal government licensees" that are electric utilities to use statements ofintent to satisfy the financial assurance requirements of 10 CFR 50.75. In addition, all
" Federal, State, and local government licensees" under Part 50 that are not electric utilities may also use statements ofintent for Snancial assurance purposes. Statements ofintent document a licensee's intention to request suf6cient 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 ofintent to assme their decommissioi.ing costs, the only power reactors eligible to use statements ofintent are those owned by the Tennessee Valley Authority (TVA), a quasi-Federal entity that qualifies as an electric utility. TVA ir. in fact, the only power reactor licensee with decommissioning costs currently covered by statements ofintent. Other governmental power reactor licensees, such as public utility districts, are ineligible to use statements ofintent because they are not Federal licensees.
Under Option D 1, TVA could continue to use statements ofintent to demonstra.e fmancial assurance for decommissioning of its power reactors. The assurance provMed by this option would continue to rely largely on the presumed financial backing of TVA by the Federal govemment.
2.4.2 Option D-2:
Clarify which licensees may use statements ofintent by defining the term
" Federal licensee" Recently, a report by NRC's inspector General raised the question of whether TVA shou'.d be allowed to use a statement ofintent, as allowed by 10 CFR 50.75(e)(3)(iv) 2 in particular, the report (1) raised concerns regarding TVA's financial condition, (2) noted that TVA's deb:s are neither obligations of the Federal government nor are they backed by the Federal government, and (3) questioned whether the Federal government would actua!;y pay for TVA's decomm;ssioning costs should the need arise.
The report also indieeted that although TVA had established a $261 million internal d: commissioning ftmd as of January IW6 (funded by ratepayers and earnings on invested funds), TVA later had depleted
. the fund completely (although it eventually re-funded into the fund all amounts collected from ratepaveis). In addition, some commenters on NRC's April 8,1996, Advanced Notice of Proposed Rulemaking (ANPR) stated that TVA's use of costless statements ofintent will give TVA a competitive advantage over other competitors in the increasingly campetitive energy marketplace.
- Audit Report: NRC's Decommissioning Financial Assurance P.equirementsfo.- Federal Licemees May Not Be Suffcient, O"3/95A-20, U.S. Nuclear Regulatory Commission, Office of the inspector General. April 3,1996 Page 12 l
l
I Option D 2 would define the term " Federal licensee" to mean "any NRC licensee that has the full faith and credit backing of the United States government," thereby addressing the concerns raised by the NRC Inspector General and the commentets on the ANPR. Licensees that did not meet this test p
would be allowed to use any of the other financial mechanisms acceptable under the regulations. We have a3sumed for the purposes of thir analysis that TVA would not meet the definition of a Federal iicensee. Ilowever, assum:ng it continues to meet the definition of electric utility, TVA could establish an external sinking fund using funds now held internally.
2.5 Additional Review of Decommissioning Financial Assurance Mechanisms
. Options E-1 and E-2 discuss concerns that ongoing deregulation of the electric utility industry may expose weaknesses present in licensees' decommissioning Snancial assurance mechanisms. These concems could be addressed through additional review of the Gnancial mechanisms used by licensees.
2.5.1 Option E-1. No action
- Power reactor licensees were required to submit financial assurance mechanisms (e.g., trust agreements, escrow agreements, statements ofintent) for NRC's review and approval only once, when the Gnancial assurance requirements first took effect in 1990. The submitted trust and escrow inechanisms were required to comply with several general conditions established principally in NRC guidance. Although NRC guidance provided licensees with detailed model wording for mechanisms (including tru t agreements and escrow agreements) that included numerous additional conditions
. protective of NRC's interests, licensees were neither required nor expected to use the model wording.2i Since 1990, power reactor licensees (according to NRC guidance) have had to submit to NRC x within a " reasonable time" any changes or "significant modifications" to "the funding method."
Licensees have aiso been directed that they must maintain an existing method of financial assurance "until the licensee has instituted a new method."
NRC believes that the present requirements, as implemented, currently are sufficient to ensure that funds deposited in the decommissioning trusts or escrows of electric utilities will be available when needed to pay for decommissioning. This position is based largely on the belief that FERC and State PUCs currently provide significant regulatory oversight over decor.imissioning funds. NRC's beliefis' also based on the considerable market power that, to date, has ensured the financial viability of electric utilities and limited the likelihood that they might ultimately be unable to pay their obligations.
Option E-1 would not change the requirements, guidance, or review procedures applicable to decommissioning financial assurance mechanisms.
2.5.2 Option E-2:
Require periodie submission of any modifications to external trust agreements (and other financial assurance mechanisms) for detailed NRC review NRC is concerned that ongoing deregulation and restrue:uring in the. electric utility industry may render the current financial assurance requirements, as implemented, inadequate to ensure the continued 2' Licensees were expected to modify the wording "as a licensee's specific situation warmats (provided that the mecha+m] complies with applicable state law.." (Regulatory Guide !./59, p.14)
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availability of funds that have already been deposited in decommissioning trusts or escrows. This concern is driven by several factors related to the deregulation of the electric utility industry, First, deregulation may lead to a diminished or non existent oversight role for FERC and State PUCs over these decommissioning funds. Second, deregulation is intended to increue competition, and therefore seems certain to reduce the considerable market power that has until now ensured the nnancial viability of electric utilities. Third, deregulation may lead to signiGcant corporate restructurings. As a result, financial mechanisms currently in place are likely in many cases to be amended, either to reflect new ownership or for a number of other potentially significant purposes (e.g., to clarify and limit the potential li tbility of various parties for decommissioning). In other cases, trusts or escrows might be terminated in response to changes in corporate structures or financial demands.22 These factors reduce the level of confidence that, in the future, existing trusts and escrows will work as intended. Put another way, the finecial mechanisms of power reactor licensees might pose a higher risk of failing than they would if no changes had occurred to the licensees' competitive situation and its FERC/PUC oversight status.23 It is a!so uncertain whether licensees, even in the current regulatory environment, have been complying with the guidance that they should submit changes or
- modifications of funding methods to NRC. If they have not, then NRC will not have conducted any review of some mechanisms now in t'.: -
Since NRC's 1990 review of the financial mechanisms submitted by power reactor licensees, NRC has gained considerable experience reviewing decommissioning financial assurance mechanisms submitted by materials licensees. Materials licensees are not generally subject to non-NR' regulations C
- affecting decommissioning, and they generally do not have market power like that of today's electric utilities. For this reason, NRC's experience with materials liteasecs may be pertinent to a deregulated and restructured electric industry.
- Decommissioning costs of materials licensees are typically several orders of magnitude less than decommissioning costs of power reactors. M, 'rtheless, materials licensees' financial assurance mechanisms. like those of power reactor licensees, are governed by several general conditions established primarily in NRC guidance. This guidance also provides detailed model wording for financial mechanisms. Although use of the model wording is not required, NRC has found it valuable to conduct a highly detailed review oflicensees' financial mechanisms relative to the model wording.
Relatively few mechanisms submitted by materials licensees are accepted by NRC without significant revisions, and all mechanisms must include a number ofimportant protections to NRC's interests.24 22 In the event that a corporate restructuring results in a change oflicensee, the former licensee may neglect to follow (or may elect not to follow) NRC guidance, which states that "an existing method of financial assurance is to be mahtained until the licensee has instituted a new method." (Regulatory Guide /.159, p.13) 23 A financial assurance mechanism is said to" fail" when it is not capable of providing funds when needed for the purposes intended. Failure of a decommissioning trust, for example, might occur for a wide variety of reasons, including (1) funds have teen inappropriately removed from the trust for unintended uses (e.g., non-decommissning expenses of the licensee or trustee),(2) funds are tied up a result oflegal disputes involving the trustee and/or the licensee and/or NRC and/or other creditors, (3) NRC cannot access the funds in the event of the default of the licensee,(4) funds have been lost through mismanagement or fraud on the part of the trustee or licensee, and (5) the trust is inadequately funded.
2* For example, materials licensees' decommissioning tn q and escrow agreements must, like the model (continued...)
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I s,
Under Option E-2, NRC would require power reactor licensees to submit any modi 6 cations to their current financial assurance mechanisms for NRC's review and revision at least once every 3 years and annually within 5 years of the projected end of operations, in light of potential changes in the electric utility industry's regulatory environment. Modifications to financial assurance mechanisms would ideally be submitted with the reports required under Option C-2.
(... continued) wording, ensure that they cannot b-amended to add provisions that are unacceptable to NRC. The relevant provisions in acceptable mechanisms submitted by licensees may differ from the mode! wording in how they are worded and even in how they work, but the protection of NRC's interest must be present and etTective.
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- 3. ANALYSIS OF VALUES AND IMPACTS This section examines the values and impacts expected to result from NRC's rulemaking, and is presented in four subsections. Section 3.1 identifies attributes that are expected to be affected by the rulemaking. Section 3.2 discusses research and analysis on several topics that can affect the assessment of regulatory options. Section 3.3 describes he analytical model used to quantify values and impacts.
Finally, the proposal's effects on values and impacts are presented in Section 3.4.
3.1 Identification of Affected Attributes This section identines 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 classiGed as
" attributes," using the list of piential attributes provided by NRC in Chapter 5 ofits Reg:datory Analysis Technical Evaluation Handbook." Each attribute listed in Chapter 5 was evaluated, and ihe basis for selecting those attributes expected to be affected by the proposed action is presented in the balance of t
this section.
The proposed requirements would revise the financial assurance requirements that support facility decoinmissioning requirements. The Gnancial assurance requirements are designed to ensure that funds are available when needed to pay for necessary decommissioning activities. They do not create or denne 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 Gnancial assurance requirements L,i to the decommissioning r.quirements that the assurance requirements support. The attributes in this group include:
Public Health (Accident)-- No changes to radiation expos cres to the public within 50 miles of a facility are expected due to changes in accident frequencies or accident consequences associated with the proposed action because the action is not designed or expected to address accident frequency or consequences.
Public Health (Routine)-- 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 munner that could re.sult 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 designed or expected to affect accident frequency or consequences.
Occup#onal 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
" Regulatory Analysis TechnicalEvaluation Handbook, Draft Report, NUREGIBR-0184,0(fice of Nuclear Regulatory Research, August 1993.
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facility operations in any manner that could result in radiation exposures to workers.
Offsite Property -- No changes to monetary effects on offsite property, either through changes in accident frequency and consequences or in other dirc,:t 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 are considered an attribute of the decommissioning requirements and not of the decommissioning
- financial assurance requiremems.
Onsite Property -- No changes to monetary effects on onsite property, either through chan;es in accident frequency and consequences or in other direct or indirect forms, are expected to be associated with the proposed action. The actica is not designed or expected to affect the need for replacement power, decontamination, or refurbishment costs. Althougl. decommissioning affects onsite property the proposed action does not revise technical standards or requirements for uecommissioning. The proposed action is intended to affect the adequacy of funds provided by power reactor licensees 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 property.
. Antitrust Considerations -- The proposed action is not expected to have any antitrust efrects.
Safeguards and Security Considerations -- The proposed action is not expected to have any etTect 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 environmental considerations.
The proposed regulatory actions are expected to insolve the following attributes:
Industry implementation -- No added industry implementation costs would be created by the no-action options (Options A-1, B-1, C-1, D-1, and E-1). The proposed rule changes would result in both costs and savings for licensees.
Specifically, industry implementation 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 definition of electric utility would avoid 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 identify a willing provider of such a mechanism, and to demonstrate to NRC that such a mechenism had been obtained.
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Under Option C-2: Licensees required to prepare and submit periodic reports on decommissioning fund status to NRC could incur implementation costs to set up systems to ensure that they have adequate internal reporting procedures to collect and submit the required information.
Under Option D-2: Licensees that cannot make use of the statement of -
intent as an allowable Gnancial 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 ofimplementation costs not addressed in this analysis is the cest, 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.
Under Option E-2: Licensees required to submit modifications to.
external trust agreements and other financial assurance mechanisms on a periodic basis would incur cJditional implementation costs. A possible offsetting cost not addressed in this analysis is the cost of securing performance of the commianents represented by the financial mechanisms that would be avoided by early correction of errors and omissions.
Industry Operation -- No added industry operation costs or savings would be created by the no-action options (Options A-1, B-1, C-1, D-1, and E-1). The proposed rule changes would result in both costs and savings for licensees.
Specifically, industry operation costs r.nd savings would result in the following situations:
Under Option A-2: Given certain assumptions regardig the nature of-deregulation, licensees no longer meeting NRC's current definition of electric utility would avoid the costs of maintaining a prepayment mechanism or a surety, insurance, or guarantee n.echanism, such as payments, fees, and other expenses. The size of these cost savings could vary, depending on the type o mechanisms that would have been used r
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 eamings rate to 2 percent.
Under Option C-2: Licensees required to report periodically on decommissioning fund status to NRC would incur costs to prepare and
. submit wch reports.
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Under Option D 2: Licensees that cannet make us of the statement of intent as an allowable financial assurance mechanism would incur costs to maintain replacement financial assurance mechar. isms (e.g., surety bond or letter of credit fees, opportunity costs of prepayments). Under the regulatory proposal, only the Tennessee Valley Authority would face these expenses.
Under Option E-2: Licensees required to submit modifications to external trust agreements and other financial essurance mechanisms to NRC every 3 years wou d incur periodic costs to submit such modifications.
NRC Implementation -- No added NRC implementation costs or savings would be created by the no-action options (Options A-1, B-1, C-1, D-1, and E-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, C-2, and E 2, NRC would be rec,uired to develop or revise a Regulatory Guide or Branch Technical Position similar to Regulatorv Guide 1.159.
NRC Opera
- ion -- No added NRC operation costs or savings would be created by the no-action options (Options A-1, B-1, C-1, D-1, and E-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 i.' order to assess the status oflicensees 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 N
statements ofintent.
Under Option E-2: NRC would conduct a detailed review and analysis of submitted modifications to financial assurance external trust agreemems and other financial assurance mechanisms to identify errors, omissions, or other problems and follow up to ensure their correction.
5 Regulatory Efficiency - The proposed requirements would result,in part,in
+
enhanced regulatory efficiency, 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 Page 19 j
alternatives, Under other options, regulate y ef0ciency may be affected as
- \\
follows:
.A Under Option A-2: NRC will enhance regulatory efficiency through the.
proposed action by ensuring that decommissioning 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 fmancial assurance shortfalls in a more timely way; and respond to public inquiries about the status of decommissioning funding with detailed and complete information.
Under Option D-2: Clarifying which licensees may use statements of intent by defining the term " Federal licensee" would eliminate a potential future source of delay arising from disputes over whether the Federal government has assumed responsibility for decommissioning costs that may cause potential health and safety problems.
Under Option E-2: Detailed review of moditications to financial assurance mech nisms could eliminate a source of delay or failure of financial assurance arising from errors and omissions in the documents that may cause potential health and safety problems.
3.2,
Research and Evaluation ofInformation on Selected Attributes This section presents the results of background research into several topics that can affect the assessment of the regulatory options, either through qualitativejudgments about the feasibility of implementing certain options or by the guidance this research and evaluation provides for the design of l
th: quantitative modeling of the options.
1 3.2.1 - Decommissioning Cost Estimates Uwi as Basis for External Sinking Funds NRC regulations at 10 CFR 50.75(b) establish minimum acceptable levels of financial assurance
. for nuclear power reactors based on the type of reactor (i.e, PWR, BWR) and its power level (in MWt).
I Although these " certification amounts" are stated in 1986 dallars, the regulations require licensees to i
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 levcis on an amount that may be
- higher, but not lower, than the arplicable inflation-adjusted certi0 cation amount.
' This study calculated the applicable certification amounts (updated to 1994) for substantially all -
nuclear power reacters currently operating. The analysis then compared these certification amounts to -
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the cost estimates reportedly in use in 1994 by operating and non operating licensees." The reported estimates were then classified as less than, consistent wnh, or greater than the applicable certification amount. (Because the regulatory formula for updating certification amounts is fairly complex, licensee estimates were classified as " consistent with" the certification amounts if they were within 5 percent of the applicable certification amount.)
The results of this analysis, displayed graphically in Exhibit 3-1, sugge.a that current NRC certification amounts do not usuahy serve as the basis for funding levels:
Exbibit 3-1 Distribution of Utilities by Difference Between Certification Amounts and Costistimates Cost retimate 1.ess than Certmcation Amount 1, gj; lY.
s
- L..
d32%
n%
wm.
22%
Cost Estimate Within 5% of Certification g
Amount m
Cost Estimate Esceeds Certification Amount by More than 5%
As Exhibit 3-1 illustrates:
Only about 22 percent oflicensees report cost estimates within 5 percent of the inflation-adjusted certification amounts. Any licens,;es using accur.te certification amounts should be among these 22 percent, along with licensees that prepared site-specific cost estimates that happen to be close to the applicable certification amount.
Almost half oflicensees,46 percent, report cost estimates greater than the certification amount. These cost estimates suggest the use of a facility-specific estimate that exceeds the certification amount. It is also possible, however, that
" This analysis is based primarily on 1994 data reported in AnnualSurg ofNuclear Decommissioning Cost Estimates andFunding Policies, Public Usility Survey, Goldman Sachs, August 1995. In the case of a few licensees that were considered in this xegulatory Analysis, how ever, the AnnualSurvey 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 many of the other licensees indicated that the 10K data were consistent with (and probably the source for) the data included in the Goldman Sachs report.
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cost estimates in this group mrty include costs of non-radiological work (which is not required by NRC) in addition to the certi0 cation amount or, alternatively, in addition to a decommissioning cost estimate that may be h6her or lower than the certi0 cation amount. (in fact, of 22 States where PUCs are known to require utilities to prepare cost estimates,18 allow non-radiologica!"greenfield 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 licensees' non-compliance with 10 CFR 50.75(b). These amounts could be due to low site-specific cost estimates or to certi0 cation amounts that are not fully adjusted for innation, in general, these findings suggest that a significant m.ijority oflicensees (probably more than 78 percent) prepare facility-speci0c cost es:imates and use these estimates to determine the required level of Snancial assurance.
3.2.2 Projected Funding Status of External Sinking Funds This section reports on the adequacy of the amounts currently being collected in external decommissioning funds under NRC's current regulations. To comply with NRC requirements external sinking funds must be fully funded by the time the associated nuclear power reactor shuts down. This study examined licensees' current decommissioning fund balances for their reactor (s) and their annual contributions to those funds. It then projected fund levels at the time of each reactor's license expiration, and evaluated the projected level relative to the required amount of financial assurance." This analysis assumes that decommissioning costs remain constant (in in0ation adjusted dollars), that licensees continue 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 being assumed by each licensee."
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 unfunded at license expiration, out of the more than $37 billion in total decommissioning costs for all nuclear power reactors. Underfunding could be higher iflicensees are unable to earn their assumed real rates on invested decommissioning funds.
3.2.3 Reporting on Status of Decommissioning Funds
" Nuclear Decommissioning Accounting Briefing Paper Presented to the Committee on Finance and Technology By thestagSubcommittee on Accounts, National Association of Regulatory Utility Commissioners, July 1994.
" The requiree xnount of financial assurance is assumed to be the higher of the licensee's reported decommissioning cost estimate or the appropriate certification amount for the reacter as called for under 10 CFR 50.75(c).
" Real rates assumed by licensees range from 0-8.7 percent, with an average rate of 3.7 percent. Source:
AnnualSurny, Goldman Sachs,1995.
Page 22
Licensees currently are not required by 10 CFR Part 50 to prepare and submit reports on decommissioning fund status to NRC following the submission of the initial decommissioning report specified in 10 CFR 50.33(k) indicating how reasonable assurance will be provided that funds will be available to decommission the facility. Section 50.75 (" Reporting and recordkeeping for decommissioning planning") requires licensees to keep recor6 ofinformation important to the safe and effective decommissioning of the facility in an identificble 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 Exhibit 3 2 Projected Funding at Time of License Expiration (aggregate for all utilities in baseline, current regulations) k Unfunded 7.3 %
S34,500M Funded in ExternalTrust 92.7*/.
decommissioning to demonstrate that a reasonable level of assurance will 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 Accountmg Standards Board (FASB) and rules pertaining to Federal taxation lead to the collection and reporting ofinformation 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 !:censees to satisfy NRC reporting requirements or can be used to substitute for such reporting requirements.
Page 23 l
FERC Reporting FERC'sjurisdiction extends to the interstate transmission and delivery of electric power. Under rules promulgated by FERC on June 30,1995, utilities that are subject to FERCjurisdiction
(" Commission-jurisdictional") are required to set up trust funds to provide for the decommissioning of their nuclear power plants. FERC uses both the rbrase " nuclear power plant" and the phrase " nuclear unit," without stipulating if funds must be plant-specific or reactor-specific (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 specified by FERC. (Such funds 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 both qualified and non-qualified funds with respect to its interest in the same nuclear plant.) Utilities are required to deposit a. 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:
the nuclear unit's description and locatien; the expected remaining useful life of the unit; the expected decommissioning plan; the utility's liquidity needs once decommissioning begins; and any other information that the fund's investment manager would neef a 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 from its trustec(s). The rule requires submission "by April 1, 1996 and by March 31 of each year thereafler, a copy of the financial report furnished to the utility by the Fund's Trustee...." The 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, i cluding amounts received from the utility, purchases and sales ofinvestme..ts, gains and losses from investment activity, disbursements from the fund for decommissioning activity and payn ent of fund cxpenses, including taxes; and Fund assets and liabilities at the end of the period.
The 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.
Pege 24 1
_ _ _ ______.___i
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 ofinformation that would be needed for satisfying an NRC reporting requirement should already be collected for purpc ses of preparing the FERC report. FERC annual report information could provide inputs for even the biennial reports being proposed.
For some licensees, however, the FERC reporting requirement may not continue to exist after deregulation. A company engaged exclusively in generation, separate 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.
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 proportion of the plant's decommissioning costs. Therefore, the reports will not be likely to include information that is fully adequate for NRC's purposes, because 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 several reports.
The extent of compliance with FERC reporting requirements over an extended period cannot yet be estimated, since the initial reports were required to be submitted by April 1,1996. FERC has found that the initial group of reports presented some problems. Some utilities presented information only on their
" Commission jurisdictional" decommissioning fands; others apparently provided information on all of their decommissioning financial assurance, whether required 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 determined because FERC's requirements have only recently been implemented.
FERC has concluded that requiring mnual reports will provide " greater flexibility" for monitoring funds, suggesting that every report might not be reviewed every year. In addition, FERC has not made the reports part of the structured format for its electronic filing requirements.
In summary, FERC reports provide a good model for the types ofinformation that could be secured from NRC licensees on a periodic basis. FERC's reporting system cannot be expected, however, Page 25 l
j 4
i h
' to provide a fully adequate source ofinformation that could substitute for reports to NRC because l
~ : FERC'sjurisdiction is limited and deregulation might end FERC'sjurisdiction over NRC licensees, and l
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 financial assurance.. The scope, level of detail, the frequency cSeporting, and the degree of scrutiny of the reports by the various PUCs, however, can differ substantially from State to State. In July 1994, the staff
( subcommittee on accounts of the committee on finance and technology of the National Association of
' Regulatory Utility Commissioners (NARUC) presented the results of a survey of State PUCs examining how nuclear decommissloning cost estimates were currently being treated and the review given those t
- estimates by State PUCs.
Ac:ording to the NARUC survey," the level and frequency of scrutiny given by PUCs to cost
- estimates is not r 1rticularly high. Although site-specific cost estimates are more frequently used than U
l NRC certification amounts in the reporting States, most of the PUCs in those States conduct somewhat
- infrequent reviews of the cost estimates. Three State PUCs reported in 1994 that they had not yet reviewed cost estimates; six PUCs reviewed every 3 years; three every 4 years; and two every 5 years.
f At least thirteen State PUCs reviewed cost estimates only as part of a rate case.
- Some State PUCs clearly require a detailed study of expected decommissioning costs to bc
- performed frequently. Texas law, for example,~ specifies that electric utilities at: 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 notice ~and an
' opportunity for public comment are frequently provided for such decommissioning cost update 3. New Jersey, for example, requires updates every 5 years, offers a 60-day public comment period on the updates, and may, if necessary, convene a formal proceeding to review the present funding level (N.J.A.C.14:5A-3.1 and 3.2). Illinois, in contrast, considers the status of decommissioning funds not to U
- be public information. Connecticut (which did not respond to the NARUC survey) first required submission of a decommissioning funding plan ~ as of January 1,1993, with updates every 5 years, or
!more frequently ifit finds that more frequent review is desirable. The State PUC is required to hold a publipearing on the plan. Tbc Connecticut PUC is emr wered to review the estimated date of closing of the nuclear power generating facility, the estimated cost of decommissioning, the reasonableness of the method selected for cost estimate purposes, and the adequacy of plans for financing the decommissioning and any shortfall resulting from premature closing. After conducting'a review, the PUC may, after a hearing, order any char ges to the decommissioning tinancing plan that it deems necessary to ensure that the esthnated time of closing and estimated cost of decommissioning the facility are reasonable; that the licensee and owners can adequately fund the decommissioning; that plans for financing any shortfall resulting from a premature closing are adequate and reasonable; and that the 9 Nuclear Decommissioning Accounting Briefing Paper Presented to the Committee on Finance and Technology By the StafSubcommittee on Accounts, National Association of Regulatory Utility Commissioners, July 1994, The' survey cons 4ted of a written questionnaire containing sixteen questions, submitted to each of the fifty 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 regulated utilities with nuclear power
. p! ants in the Sute.--The survey's results thus represent about 75 percent of the pertinent PUCs.
Page 26
4 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 NARUC in its sun ey 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 Revenue Service's 468 A requirements gave for the use of external funds). (NARUC did not examine whether each owner of a utility had set up its own 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. At least twelve States reported that they 66 not review the performance of the trust fund investments on a 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 of trust assets semi-annually, but because the trust funds were relatively small and because oflimited staff resources, they were not being closely monitored. Three more States reviewed every 3 y ears, and two more every 5 years. Two States reported that they reviewed fund performance during rate actions. Even for those States that reported reviewing the performance of the external sinking funds, the NARUC survey provided no infonnation 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 reviewed 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 investments that could be included with a particular investment manager). New York, which did not itself place any restrictions on investments, noted that the IRS imposed investment restrictions for quali6 cation as a nuclear decommissioning fund under 468A. Twenty-one State PUCs reponed that they did not " approve or oversee the selection" of the decommissioning fund's trustee and investment manager, while Illinois reported that the PUC approved trustee selection only, in summary, because of the variatio..s in scope, frequency, and level of review given reports by utilities to State PUCs, such reports cannot be expected to provMe a fully adequate source ofinformation that could substitute for reports to NRC. Furthermore, following deregulation, any,uclear power generators that no longer fall under the jurisdiction of State PUCs might not be required to continue reporting to the PUCs.
FASB Reporting Standards The Financial Accounting Standards Board (FASB)is currently finalizing financial accounting standards for obligations that are incurred for the closure or removal of long-lived assets, such as nuclear reactors. On February 7,1996, FASB issued an exposure drail(No.158-B) for comment. Although the 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 and measuring closure or removal obligations (decommissioning of nuclear facilities is explicitly included in the scope of the standard), methods of account;ng, and standards on reporting and disclosures.
Page 27
Under the proposed FASB standard, an entity that reports a liability for its decommissioning obligations should disclose the following information (in this description, the word " decommissioning" 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 assets; The liability for decommissioning (stated as the present value of the estimated future cash outflows required to satisfy the obligation) must be recognized in the entity's financial statements, eith r 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 outflows and the liability must be recognized in the financial statements. These include:
The current cost estimate for decommissioning:
The estimated long-term rate ofinflation used in computing the liability; The estimated total future cost of decommissioning:
The discount rate (s);
The general estimated timing of decommiss:oning activities; The funding policy for decommissioning; The fair value of assets, if any, dedicated to satisfy the decommissioning obligations; 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; The individual compoi,ents of the costs of decommissioning 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) ard the total of those costs; and The caption or captions in the statement of operations in which :he costs listed immediately above are aggregated if those costs have not been presented as a separate caption or reported parenthetically on the face of the statement.
The FASB's goal, in seeking these disclosures, is to ensure that companies " provide information that will be useful in understanding the effects of closure or removal obligations on a particular entity...
Page 28
" The disclosures can be prepared, in the Board's opinica,"without encountering undue complexities or significant incremental costs."3' Several important additional points should be noted concerning the FASB standards:
FASB states that the costs to store spent nuclear fuel that are incurred after closure of a nuclear power plant until the sprnt fuel is ready for final storage should be included in the liability recognized pursuant to the standard.
Ilowever, the costs of temporary storage of spent fuel that result from the absence of a facility for final storage of the spent fuel should not be included.
Unless fuel storage costs are reported separately, which the FASB standards would not require, distinguishing them from decommissioning costs for NRC's analysis would be difficult.
The draft standard does not change the existing general principle that trust funds established for nuclear decommissioning are not eligible for offsetting against the liability for decommissioning on the financial statement. FASB explained that offsetting trust funds set up for decommissioning against the decommissioning obligation for nuclear plants had been held in a 1996 FASB orinion to be inappropriate because the right of offset is not enforceable at law and the payees for costs of decommissioning activities generally have not been identified at the reporting date. Ilowever, FASB asked for comments on :his point in the 1996 Exposure Draft.32 FASB intends the standard to apply to rate-regulated entities, such as utilities subject to State PUCs or FERC, as well as to non-regulated companies.
The FASB standard would apply to financial statements. Firms that are not publicly held or traded on public exchanges will not be obligated to adopt FASB accounting principles, although they could do so.
Although the draft standard refers to "an entity," the standard apparently would allow an affiliated group of firms (c.at prepares a consolidated financial report to disclose consolidated information about the group's decommissioning obligations, as long as the report addressed differences in timing and discount rates applicable to separate facilities.
In summary, although the FASB standards, if approved, will help to establish uniform standards for financial reports by publicly traded businesses, they may not directly provide that information in a format that is uniformly well-suited to NRC's use because information on more than one reactor < r even more than one affiliated subsidiary m" s consolidated. Nevertheless, licensees may readily be able to
" financial Accounting Standards Board, &posure Draf: ProposedStatement ofFinancial Accounting Standards, Accountingfor Certain Liabihties Related to Closure or Removal ofLong-Lived Assets, No. I 58-B, February 7,1996,199, p. 32.
22 /d, T84, p. 28.
Page 29
. - - -. _. - -. -. -.. ~ - -.. ~
i fcomply with NRC's reporting requirements iflicensees must collect non-consolidated information as a
-prerequisite to meeting the FASB standards.
1 Tax Reports For a number of reasons, detailed below, tax reports for a qualified Nuclear Decommissioning Reserve Fund or for a non-qualified 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 supplement information reported by a licensee.
Such tax reports could involve (a) reports on payments into a fund, (b) reports on the current size of the
' fund, and (c) reports on income to and/or expenditures from a fund.
Section 468A Nuclear Decommissioning Reserve Fund Renarts if a licensee elects to set up a Nuclear Decommissioning Reserve Fund under Q468A of the Internal Revenue Code, payme,ts into the fund are deductible in that tax year (in contrast to the general rule that payments to such a trust are not deductible). Therefore, the tax code includes explicit rules respecting such payments. The' amount that the licensee may pay into the fund is limited to the lesser of either (1) the amount of nuclear decommissioning costs which is included in the taxpayer's cost of service for ratemaking purposes for that taxable year, or (2) an amount (the " ruling 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 income of a Nuclear Decommissioning Reserve Fund is taxed (at a rate of 20 percent) so reports ofincome must be made, in general, amounts distributed from the fund to pay for decommissioning are to be included in the gross income of the taxpayer, but expenditures froni the fund to accomplish decommissioning are also treated as deductible costs to the taxpayer. Thus, the IRS requires reports of earnings and distributions from the fund.
The following points address the usefulness of these tax filings as a source of potential information on the size and adequacy of the decommissioning financial assurance:
.(1)
Section 468A apparently allows a tr.xpayer 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 Q468A(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 thereof." 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
- 468A(e)(1) cited above is ambiguous, it would probably say "with respect to all Page 30
nuclear 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 plant, Section 468A apparently requires each of them to set up a separate 1
Decommissioning Fund for their shares of the decommissioning costs.
information collected from several taxpayers might be necessary to develop a complete report on the status of all funds pertaining to a particular plant.
(4)
Contributions to decommissioning funds must be made within the tax year, including a period extending 2% months aller 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 ;ummary data more difficult to put together, (5)
The Internal Revenue Service has the authority to review and revise the schedule of ruling amounts "at least once during the useful life o'the nuclear powerplant (or, more frequently, at the request of the taxpayer)"(26 USC 468A(d)(3)). A taxpayer who could derive no additional tax bene 0ts from larger deductions might not request the Service to amend the schedule of ruling amounts, even if h
its decommissioning cost estimate increased.
Grantor Trust Reports 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 Reseye fund under 468A),
NRC's Regulatory Guide 1.159 does "not require that an exte nal trust fund be established as a separate tax paying entity. Thus, a grantor trust may be used"(p.1.159-4). Payments into such a fund would not 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 escrow) are 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 that "the Trustee [or escrow agent) shall.. furnish to the Grantor a statement confirming the value of the Trust," also offers the alternatives of monthly, quarterly, or annually for the frequency of such reports. Ilowever, NRC also states that " Licensees may add, delete, or modify sample provisions as their circumstances warrant"(p.
B-1). Thus, licensees apparently could specify longer than annual periods between reports.
Trustees of grantor trusts are required by IRS rules to submit to the grantor annual statements showing all items ofincome, deduction, and credit of the trust for the taxable year so that the grantor can tse the items into account in computing its own taxable income and credits. The rules specifically provide that the trustee of a grantor trust is not required to file any type of return with th,: IRS (26 CFR 1.671-4). Thus, licensees who have set up grantor trusts will receive annual reports of certain information from the trustee, even if no full accounting is prepared by the trustee on an annual basis.
3.2.4 Availability a d Security of Financial Assurance Mechanisms to Supplement or Replace External Sinking Funds Page 31
NRC's financial aswrance regulations in 10 CFR 50.75 currently distinguish between two categories oflicensees, "an electric utility" and "a licensee other than an electric utility." The financial assurance mechanisms authorized for use by each differ. Under 50.75(e)(3), an electric utility may provide financial assurance for decommissioning by means of(l) prepayment,(2) an external sinking fund in which dep, sits are made at least annually until it has built up to the appropriate amount,(3) a surety method or insurance, and (4) for Federal government licensees, a statement ofintent. Under l50.75(e)(2), a licenue other than an electric utility may provide financial assurance for decommissioninF y means of(l) prepayment,(2) an exterr.al sinking fund,(3) a surety, insurance, or b
other guarantee method, including a parent company guarantee or (4) for Federal, State, or local government licensees, a statement ofintent. A 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 fehat builds up over time; licensees that are not electric utilities must couple their external sinka E ;d with a surety method or insurance, the value of which may decrease by the amount being accumuiated in the sinking fund.
Although the regulatory proposal would amend the definition of" electric utility," the definition would continue to require that such an entity must recover its costs through rates or other mandatory 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 utility" if their access to funds through regulated ratemaking is limited or ended. Such licensees would then be required to couple existing external sinking funds with another financial assurance mechanism.
Option A-2 suggests that such mechanisms could include prepayment, a surety bond, a letter of credit, or any other method currently allowed in %50.75(e)(1)(iii). NRC's Rulemaking Plan also suggested that NRC might consider a certification to NRC from the ratemaking authority that all unfunded decommissioning 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 by licensees that are no longer defined as " electric utilities" 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 categories of mechanisms (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 utilities and/or nuclear power generators).
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 financial mechanisms, such as letters of credit and lines of credit, to nuclear reactor licensees that are required to obtain such mechanisms to demonstrate financial assurance for the difference between their external sinking funds and the full amount of required assurance if the licensee no longer qualifies as an
" electric utility." These limits may be created by the possibility, on the one hand, that the nuclear reactor-licensees will no longer have recourse to the asset base of 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 subsidiaries to operate nuclear power plants. These subsidiaries may be separated from affiliates providing bulk transmission servicas and Page 32
distribution to end-use customers, with the corporate groap owned by a common parent." NRC has received commitments that licensees will notify NRC when signi6 cant asscts 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 asset bases, potentia!!y consisting primarily of the nuclear generating plant and contractual commitments for sales of power, while other signincant assets are owned by the generating subsidiary's parent company or other af61iates.
At the same time, the providers of financial 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 mechanism? sssuring the very large decommissioning costs of nuclear generating facilities. Generating subsidiaries without access to d
substantial assets may Gnd it difficult to provide the necessary collateral.
Availability and Security of Insurance Decommissioning insurance is not likely to be available from a traditional insurer. However, licensees may seek to demonstrate financial assurance using decommissioning insurance purchased from a " captive" insurer. (A captive insurance company is de6ned as a separately incorporated insurance company that is owned by the party (ies) that it insures.) For example, as electric utilities divest nuclear power generation facilities into separately incorporated subsidiaries, the parents of the corporate groups may set up captive insurance companies to provide Unancial assurance to the nuclear generation subsidiaries or a subsidiary may even set up its own captive. Currently,10 CFR Part 50 does not specify any requirements that must be satisfied by companies insuring decommissioning costs for NRC licensees, 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"({2.3.3). Regulatory Guide 1.159 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 licensee default."
The degree of regulatory scrutiny afforded a captive insurer before licensing is usually not as high as the scrutiny afforded other types ofinsurers. Although captive insurers may be subject to certain state regulations and licensing requirements, several States have special licensing laws applying to captives that 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. The captive's financial strength thus is linked closely to the financial strength ofits parent.
Captive insurers also can be domiciled outside the United States. In fact, the majority of captive domiciles are located "off-shore," primarily in the Caribbean. For domestic captives, Vermont is home
" Consolidated Edison, for example, has notified the New York PUC that it is proposing to unbundle its generation company from its transmission and distribution assets. NRRI," Status of Electric Industry Restructuring," December 3,1996.
Page 33
to nearly 70 percent of alicaptives licensed in the U.S., llawaii 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 business with its corporate affiliate 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 financial situation by the National Association ofInsurance Commissioners (NAIC) would be sufficient for it to obtain approval to provide excess or surplus lines coverage as an alien insurer, if the captive does not sell coverage to any entities other than its affiliate (s).
ikcause captive insurance companies rely upon the assets of their parents or afGliates in the same corprate group, a captive insurer will not afford the same degree of assurance as an independent third party source ofinsurance. 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 guarantee or even the assurance that would be provided by a so-called cross-stream guarantee (a guarac T of one subsidiary in a corporate group by another subsidiary in that corporate group).
Availability and Security of Certifications from FERC or State PUCs in its Advance Notice of Proposed Rulemaking on Financial Assurance Requirements for Decommissioning Nuclear Power Reactors (61 FR 15427, April 8,1996), NRC raised the possibility of relying on certifications from State PUCs and/or FERC pertaining to licensees that had formerly been fully subject to ratemaking but that, due to deregulation, now had limited access to funds from ratepayers. This PUC/FERC certification would provide assurance to NRC that all unfunded 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 certifications:
Neither FERC's current commissioners nor the current members of State PUCs can completely bind their successors. The actions of current commissioners create precedents and expectations that are frequently difficult to overturn, but changed political or economic conditions could lead in the future to abrogations of certifications, and NRC would be unlikely to have any effective method of enforcing them.
Thejurisdiction (and even the continued existence) of FERC or State PUCs in 4
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 ta set access fees, system exit fees, or other similar charges high enough to fund
" Captive insurance Company Directory 1996, Tillinghast-Towers Perrin.
Page 34
decommissioning, as well as other costs that might be addressed through such mandatory fees. Without new Federal legislation, NRC would not have the power to force FERC or State PUCs to implement certiGcation commitments.
1 Finally, unlike other financial assurance alternatives, such certincations 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 I
evidence that States ta.: planning to seek such certification authority as part of their deregulation activities."
Availability and Security of Statements of Intent The proposed amendments to 10 CFR 50.75 would limit the use of statements ofintent by Federal Part 50 licensees by defining the term " Federal licensee." Some of the same issues raised by certincations by State PUCs also arise with statements ofintent.
As it was proposed in 1985, the statement ofintent was "a certification that the appropriate j
government entity will be a guarantor of decommissioning funds"(50 FR 5619, February 11,1985, l
emphasis supplied). Although the supplementary information to the final rule discussed the statement of l
intent in terms of a " guarantee that a government agency will assume Gnancial responsibility for decommissioning the facility"(53 FR 24036, June 27,1988), the rule language provides only that the statement ofintent must be a statement "containing a cost estimate for decommissioning, and indicating that funds for decommissioning will be obtained when necessary." (53 FR 24050, June 27,1988, currently codined in 10 CFR 50.75)
Regulatory Guide 1.159 further specifies that the statement of intent must contain "an indication that funds for decommissioning will be requested and obtained sufHeiently in advance of decommissioning to prevent delay of required activities? Regulatory Guide 1.159 also provides slightly more detail about who may sign a statement ofintent, specifying that it must contain " Evidence of the authority of the official of the government entity to sign the statement ofintent."
The statement ofintent coulo present the following issues:
Persons signing the statement ofintent may be unable to bind their governmental entities over time. While their commitments may create a precedent and expectation that funds will be soeght, the commitments cannot be binding on their successors or governmental superiors under different political or economic conditions. Federal statutes, such as the Anti DeGeiency Act, prohibit certain types of financial commitments. For States, the legal and financial relationship between the entity on whose behalf the statement ofintent is being issued and the State may not create any binding obligation on the part of the State. State
" See, for example, Pennsylvania Public Utility Commission, Report and Recommendation to the Governor andGeneral Assembly on Electric Competition, July 1996; State of New York Public Service Commission, Opinion and Order Regarding Competitive Opportunitiesfor Electric Service. Opinion No. 96-12, Cases 94-E-0952 et al.,
May 20,1996; and NARUC, Summary ofEach State's Restructuring Activities, March 1,1996, none of w hich identines any ongoing attempts to secure approval from State I:gislatures for State PUC certifications.
Page 35
laws generally create precise standards defining when obligations of related or subsidiary entities are obligations of the State, and prohibiting the creation otherwise of any debts, liabilities, loans, or pledges of credit of the State. This j
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 ofintent may in fact lack the authority to make a commitment. States in some cases have enacted statutes similar to the Fedcral Anti-Deficiency Act, prohibiting officials from entering into financial commitments outside the legislative appropriation and allocation process.
The commitment provided may, in fact, resemble a weak self guarantee.
Statements ofintent signed by officials (e.g., trustees executive officers, financial officials, or administrators) of the entity required to provide financial assurance that they will provide funds, reallocate funds, or seek and secure funds when necessary, do not appear to represent the same degree of assurence as financial mechanisms issued by third-party providers such as banks and surety companies oc the assurance provided by a licensee that has obtained a written guarantee from a parent or passed a test for self-guarantee. No such test must be passed to use the statement ofintent.
TVA points to a number of reasons why its commitment to fund
=
decommissioning when necessary is supported by its legal or financial situation. TVA is a corporate agency that is Molly 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 indicated that it may decline Congressional funding for certain programs in the future. Income from the TVA power program comes from the generation, transmission, and sale of electricity.
(In 1994, gross generation was approximately 70 percent coal,16 percent hydro, and 14 percent nuclear.) Although the service area of TVA is defined by law, competition in the electric power market can occur from c'her electric utilities and from the natural gas industry. TVA considers itself to be required by Federal law to set its electric power rates high enough to produce revenues sufficient to meet operating expenses, including expenses of decommissioning TVA's nuclear units. TVA's 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 judiciary, although TVA's power system budget is sent to the President and Congress for informational purposes. TVA has sought to protect its revenue stream from power generation through the execution of requirements contracts with its distributor wholesale customers that contain rolling 10-year minimum termination provisions, and in FY 1995 about 87 percent ofits total power revenues were received from such contracts.
Currently, one municipal customer accounts for approximately 9 percent of total 36 " Decommissioning Funding Assurance Requirements Affecting TVA as a Federal Govemment Licensee,"
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."
Page 36
power sales and four other municipal customers account for an additional T percent of total power sales. All five of these customers have contracts that n; no event would terminate in less than 10 years.- TVA has the authority to issue i
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. TVA's bonds i
currently have a very high (AAA) rating." Finally, TVA's decommissioning obligations, although large, represent a comparatively small propo-tion ofits -
annual operating revenues of over $5 billion, and TVA has established a -
decommissioning investment fund of over $350 million.
- Availability of Parent Guarantees and Self-Guarantees Reliance on a parent company guarantee or a self guarantee through passing a financial test i
. similar in scope te N test contained in 10 CFR Part 30, Appendices A and C, to ensure power reactor licensee decommissioning would pose a number of potential issues, such as the following:
A utility that has spun offits nuclear power 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 subsidiary is to shield the transmission and distribution components and/or the j
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 4
Appendix A may not be an appropriate measure ofits financial ability to do so.
That financial test was initially developed more than two decades ago to y
l measure the financial ability of waste management firms to assure costs that are g
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 ofutilities.
A self-guarantee by a nuclear generating firm responsible for substantial unftmded decommissioning costs would pose particular problems. The firm's i
large liabilities might make it. unable to satisfy the current financial test for self-guarantees in 10 CFR Part 30 Appendix C. In addition, such licensees are poor i
candidates for self-guarantees if they do not have significant unencumbered assets in addition to the nuclear plant that itselfis creating the decommissioning obligation.
i 3.2.5 _ PotentialIndustry Restructuring
- Economic deregulation and restructuring in the electric utility industry, which is expected to lead to increased competition in the industry, may have, as one of its consequences, the disaggregation of
" Moody's Investor Services and Standard & Poor's ratings for TVA are highly dependent on TVA's status as l
an agency of the U.S. govemuent.
l Page 37 r
integrated power systems into their ftmetional components. In particular, electrical generation may be separated from transmission and distribution, either by being spun ofTinto 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 wkre 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 deregulation, summaries of the status of deregulation across the country, and commentary by industry represantatives, however, was used to develop the modeling scenarios described in Section 3.3.2.
Phase-In Periods for Deregulation State PUCs, legislators, consumer and business groups, and utilities have all proposed a broad range of time periods within which electrical industry deregulation could be carried out, and there is some possibility that Federal legislation could preempt State timetables. The pace of future deregulation will in 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 deregulation, with phase-in periods as short as 3 to 5 years; residential and small commercial consumers supptrt a variety of timetables; and some utilities urge delaying action until several outstanding issues have been resolved.3' In 1996 the New l
York State PUC adopted early 1997 as its goal for wholesale competition and early 1998 as its goal for l
getting retail access underway." A law restructuring California's electric industry was passed and signed j.
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." The Pennsylvania PUC in July 1996 recommended a phase-in plan leading to full retail access to competitive generation by 2004,48 and Commonwealth Edison and several other major utilities and industry groups have proposed draft I
legislation to the Illinois PUC that would provide direct access for residential customers by 2005.42 In contract, 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 retail level. Many of these States are in the initial stages ofinvestigat ng the issue. Fewer than six have concluded that deregulation i
would Itat be desirable in the State, according to surveys undertaken by NARUC and NRR1, but a
" State of New York Public S:rvice Commission, Opinion No. 96-12, Cases 94-E-0952 s.t al., in the Afatter of Competitive Opportunities Regarding Electric Service: Opinion and Order Regarding Competitive Opportunities for Electric Service, May 20,1996, pp.15 I 8.
" Id. p. 72.
- The New York Times,"The Nuclear Power Puzzle: Deregulation Raises Questions Over Construction Debt,"
Dl, D3, January 3,1997.
- Pennsylvanla Public Utility Commission, Report and Recommendation to the Governor and General Assembly on Electric Competition (From the Investigation into Retail Competition at Docket No, I-940032), July 1996,p.27.
" NRRI," Status of Electric Industry Restructuring," December 3,1996, p.16; The New York Times, January 3, 1997.
Page 38
.l
-l number of other States are proceeding slowly and haltingly.42 The States that are hesitant about
- deregulation tend to_ be less populated and urbanized, located in the South, Northw est, Southwest, and Midwest.
Although a number of utilities and State PUCs that commented on NRC's Advance 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 industry restructuring and deregulation.
i State PUC Plans to Address Decommissioning Costs During Deregulation j-No attempt was made to obtain detailed infonnation about the precise plans for dealing with 6
decomminioning costs of each State PUC or State legislature that is investigating deregulation or developing detailed deregulation proposals, in a number of States where deregulation is likely to occur, j
or is underway, it is still too early to specify exactly how decommissioning costs will be addressed. In l
New York, for example, mandatory access fees or distribution charges are under consideration, but the i
State PUC expects to reassess its initial rate structure after the competitive market has been in effect for a j
few years 'd The California PUC's decision on electric utility restructuring provides utilities 100 percent iT recovery of their transition costs, including the difference between the book value and the market value of their generation assets and costs of regulatory obligations,45 and legislation enacted in September 1996 also provides for recovery of stranded investments." Both California and the Pennsylvania PUC, which apparently modeled its deregulation plan closely on California's, have proposed using Competition i
Transition Charges to recover stranded costs (including about $14 billion of nuclear stranded 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 j
other non-bypassable fees, will be developed and used to enable prudently-incurred stranded costs to be i
recovered, although the mechanisms used will differ from jurisdiction tojurisdiction.
l
[
Utility Restructuring and Premature Closure The National Regulatory Research Institute has collected information about restructuring of the j.
electric industry that, among other topics, notes instances when utilities have submitted plans to their 3
State PUCs that include divestitures or spinoffs of generating assets; utility mergers; and other similar 41 actions. This information, which is incomplete, suggests that a moderate degree of such activity is
= currently underway, although all ofit does not involve nuclear generating facilities. The following l-summary provides examples of the types of activities that are occurring. In California, Pacific Gas &
d' NARUC," Summary of Each State's Restructuring Activities (3/1/96)"; NRRI," Status of Electric Industry Restructuring," December 3,1996.
- State of New York Public Service Commission, Opinion No. 96-12, Cases 94 E-0952 gul. In the Matter of Competitive Opportunities Regarding Electric Service. Order and Opinion Regarding Competitive Opportunitiesfor Electric Service, May 20,1996, pp. 52-53.
NARUC," Summary of Each State's Restructuring Activities (3/1/96)."
" NRRI," Status of Electric Industry Restructuring," December 2,1996, p. 7.
NRRI," Status of Electric Industry Restructuring," December 3,1996.
Page 39
Electric his filed plans to divest 3000 MW of gas-fueled plants over a 2 year period. Because of the -
transmission pricing provisions in California's restructuring bill, signed in E ptember 1996, purchases of out of State power are expected that would lead to the closing of California plants, and California's 1 deregulation plans include substantial closures of fossil-fueled plants. In the Washington, D.C, area, PEPCO and Baltimore Gas and Electric have filed an application for merger. In Georgia, SPA has proposed to sell some ofits generating facilities. In Kansas, Kansas City Power and Light sought unsuccessfully to merge with Utilicorp in 1995-96. In Massachusetts, the New Englaad Electric System-has proposed full divestiture ofits generating assets in Massachusetts, New ilampshire, and Rhode Island. In Michigan, the legislative study group on deregulation studied the possibility of a merger between Northern States Power and Wisconsin Energy. In Missouri, Union Electric and Central lilinois Power have merged, in New York, Consolidated Edison proposed a corporate restructuring in October 1996 that would create an unregulated generation company and a regulated transmission and delivery
^
company out of the existing utility. In addition, Long Island Lighting Company (Lilco) is reeking to merge with Brooklyn Union Gas, in an arrangement in which the Long Island Power Authority would assume Lilco's debt for the Shoreham nuclear plant."
The information summarized above, although incomplete and qualitative in nature, provides support for the assumption in the scenarios described below, particultrly the " managed deregulation" scenario, that full retail deregulation is unlikely in the immtdiate future in all States but will occur within I
about a decade; that recovery of decommissioning costs will occur through measures implemented by State PUCs or similar regulatory agencies; and that generation facilities will not uniformly or completely be spun offinto separately-incorporated entities susceptible to premature 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 desc.ibes the general methods 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 key assumptions.
3.3.1 Development of the Database To help quantify the effects of the proposed rule, a database was developed containing 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, operatirig status, operating license expiratiori date, and licensed MWt.
- The New York Times," Bonus for Lilco Stockholders if State Takes Over Debt," January 1,1997, p. 45.
- Nuclear Regulatory Commission Information Digest, NUREG-t 350, Volume 7, U.S. Nuclear Regulatory Commission, Office of the Comptroller, March 1995.
Page 40 a-
- AnnualSurvey ofNuclear Decommiss'uning Cost Estimates and Funding e.
Policies, Public Utility Survey." Tbe AnnualSurvey teports the foilowing.
. 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 of estimated decommissioning costs for the_ unit, total estimated -
9 decommissioning costs for the unit,- license expirdon date, expected year
~ decommissioning will commence, the amount of funds set aside in external.
i decommissioning funds (yali0ed and non-qualified) as of year end 1994, the 1994 contribution to external decommissioning funds, and the assumed rate of
- earnings on collected decommissioning funds."
p Licensee Annual Financial Statementsfrom SEC Form 10K Filings and i
AnnualReports. For a few Iicensees, the AnnualSurvey data were incomplete.
L For these licensees, the necessary data were obtained from licensee SEC Form 10K filings or from the Gnancial statements included in licensee annual reports.
L (A broader review of the annual Onancial statements of many licensees suggests that the Gnancial statement data are consistent with, and pesibly the source for, the data included in the AnnualSur"cy report.) Form 10K Slings and annual reports also provided data on licensees' operating revenues and total assets.
Nuclear Plant Owners and Operators." This document was used to confirm licensee ownersh_ip for individual power reactors.
The database also includes information on each reactor's certification amount. These amounts
_.were calculated using information on unit type (i.e., PWR or BWR) in accordance with 10 CFR 50.75(c)(1). To account for inflation since 1986, these amounts were then adjusted using the adjustment formula speci0ed in 10 CFR 50.75(c)(2), along with data from NRC's Report on Wasic BurialCharges" and regional data on labor rates and energy prices from the U.S. Department of1.a? or, Although the database accounts for all operating nuclear power reactors," it does not account for 100 percent ownership of all reactors (due to data limitations) but rather accounts for approximately 88 percent ownership. As a result, the analysis will proportionately understate all aggregated results (i.e.,
y AnnualSurvey ofNuclear Decommissioning Cost Estimates and Funding Policies, Public Utility Survey,.
. Goldman Sachs, August 1995, Table 32 (A more recent version of this survey is not currently available.)
" in some cases where data are reported on an aggregated basis (e.g., total decommissioning funds collected for allthe reactors owned by the company), the data were apportioned to individual units in proportion to the amount ofeach facility's certification level and the percentage of operating life remaining.
" Nuclear Plant Owners and Operators (Attachment 2 to SECY-94-280), U.S. Nuclear Regulatory.
. Commission. November 18,1994,
" Report on Wa te Burial Charges: Escalation ofDecommissioning Waste Disposal Costs at Low-level Waste Burial Facilities. Rev. 5, NUREG-1307, U.S. Nuclear Regulatory Commission, Office of Nuclear Regulatory Research, August 1995.
' " Reactors of the Tennessee Valley Authority, however, are analyzed only with respect to Options D-1 and D-2.
Page 41
total results for all licensees) that are stated in dollars (as opposed to percent). Also, if the licensees in the missing 12 percent are financially smaller than other licensees, then the results of the analysis may be biased toward larger licensees.
Note: Because the most recent decommissioning funding data available were stated in 1994 dollars, other amounts used in the analysis were converted to 1994 dollars as necessary Conversions of financial data were based on inflation factors derived from GDP deflators. Decommissioning certification amounts and cost estimates were adjusted using the formula speci6ed in 10 CFR 50.75(c)(2)." Therefore, all dollar values reported in this study are 1994 dollars.
i 3.3.2 Modeled Scenarios -
The analysis builds on the database described above to model each option under three alternative l
scenarios that differ regarding their assumptions about the deregulation of the electric utility industry.
Despite signi6 cant study of deregulation issues by FERC, PUCs, industry groups, and others, it remains uncertain how deregulation will eventually unfold, which set of companies and facilities will be affected, and, in particular, what the implications will be for nuclear power plant decommissioning costs.
i 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 simpli6 cations of reality. They consider aspects of deregulation that are most relevant to deco;nmissioning Onancial assurance. They 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 attempt 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 significant.
assumptions about deregulation with complex models that examine the competitivenas of'.he costs of power generation at different facilities. Such an analysis was beyond the scope of this strdy. 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 rulemakiag. Similarly, the analysis does not attempt to model the restructuring that may occur as a result ef <ieregulation, and which might consolidate or disperse ownership of power reactors among current licensees or entities that are not currently licensees.
No Retall This scenario assumes deregulation at the wholesal: levci Deregulation consis'ent with FERC rulemakings, but at the retail level assumes remlatory conditions as they exist today (i.e., prior to deregulation).
" in a few cases, decommissioning co t estimates were stated in future dollars. These 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. Gross Domestic Product (GDP) deflators over the period 1986-1995 (as reported in the U.S. Department of Commerce publication Economic Indicators).
For example, premature closures that occur prior to the effective date of NRC's rule would reduce the number of licensees affected by the rule, thereby reducing the values and impacts of the rule.
Page 42
Managed This is perhaps the deregulatory scenario that is most likely to Deregulation come to pass (see Section 3.2.5). The specific details would likely vary by region or State (or both), and might even include traditional regulation of utilities in some areas. Where deregulation is implemented, however, the managed deregulation scenario assumes that reF'ilators will allow all current electric I
utility licensees (or, in the event of restructuring, their power reactor licensee successors) to recover all costs prudently iacurred, including future decommissioning costs associated with power reactors buih prior i
to deregulation. Costs may be recovered either directly through traditional " cost of service" regulation or indirectly through non-bypassable mechanisms such as mandatory transmis ion access fees, system exit fees, and distribution line charges.
Reactor decommissioning c:rn would not be " stranded" under this scenario. ~ror modeling purposes, dereplation is assumed to occur (simultaneously for all licensees) in 2006,10 years af er NRC's Advanced Notice of Proposed Rulemaking for the curren; rule.
Stranding Under stranding deregulation, licensees are assumed to be Deregulation completely deregulated with respect to cost recovery through rates, charges, and exit fees. Upon the arrival of deregulation, i
regulators would no longer be in position to assure that licensees can recover any unfunded decommissioning costs. (Thus, such costs 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 any 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 bound the analysis in terms of the range of values and impacts of the rule.
3.3.3 Modeling of Regulatory Options This section describes how each pair of options has been modeled to quantify vak, and impacts associated with the options' financial assurance implications Before beginning the se*;. cil 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 scenarios). Second, although the issue of premature closures of nuclear power reactors in general has not been analyzed in this study, this analysis does consider whether the rulemaking itselfis likely to lead to any premature closures. To accomplish this, the model calculates incremental licensee financial essarance costs assuming that each licensee continues to operate as s viable entity and can continue to comply with applicable financial assurance requirements; these cost results will be used later to assess the likelihood of premature closures due to the current rulemaking (see Section 3.4).
Page 43
i 1
Options A-1 and A-2 Under NRC's current regulations and current definition of electric utility, non-electric utility licensees may not use external sinking funds "nless the external sinking funds are coupled with other financial mechanisms to assure the unfunded portions of their sinking funds." NRC believes that, at this time, all power reactor licensees mect the current definition of electric utility. As a result of deregulation, however, liceasees may evolve into entities that will not qualify as electric utilities under the current definition ba 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 Option A-1, the no-action alternative, the model assumes that such partially deregulated licensees would cease to be electric utilities and would have to immediately obtain additional financial assurance for all amounts not yet funded. (It is worth noting that NRC's current definition (and hence Option A-1) could be interpreted to consider such entities to be electric utilities, in which case no additional assurance would be required.
The model applies the interpretation that they would not meet the definition, however, because this interpretation is more consistent with NRC's inclination to revise the dermig a prior to deregulation.)
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 non-bypassable 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 cunent deOnition of electric utility (under Option A-1) or the proposed definition of electric utility (under Option A-2), throughout the operating life, shutdown, and decommissioning of their facilities.
Under the managed deregulation scenario, the model assumes that all licensees 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 not 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 unfimded portion of their sinking fund," and (2) obtaining a letter
~
of credit or surety bond on the same unfunded portion," The cost of 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
" The unfunded portion of a sinking fund is assumed to equal the amount projected to remain unfunded (i.e.,
afler accounting for projected earnings on funds invested as of the time the licensee ceases to be an electric utility) at the time oflicense expiration, as opposed to the total unfunded amount at the time the licensee ceases to be an electric utility, in other words, licensees are given credit for future earnings on funds coitected to date.
" Prepayment is the most costly method of financial assurance. Therefore, licensees are unlikely to use prepayment unless other mechanisms are unavailable or unless, in the case of surety bonds and letters of credit, the amount of collateral required approaches the prepayment amount.
" Based on the research and analysis discussed in Section 3.2.4, other financial mechanisms (e.g., parent guaranteet, insurance) are assumed to be unava lable.
2 Page 44
opportunity cost by, first, calculating the present value" to the licensee ofits unfunded decommissioning costs and, second, subtracting this value from the prepayment amount. The cost of financial assurance using lette:s of credit and surety bonds equals the present value of the annual fees (assumed to be 1.5 percent of the face value of the credit or bond).
Option A-2, in contrast, would allow licensees to avoid the costs arising under Option A 1 by letting them continue to use external sinking funds in the ma..
r that they are currently used.
In the stranding deregulation scenario, licensees will, subsequent to deregulation, fail to meet either the current definition of electric utility (under Option A 1) or the proposed definition of electrie utility (under Option A-2). Consequently, licensees will not be allowed to use external sinking funds except in combination with other financial mechanisms. This situation is analogous to, and has been 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 require modeling:(1) the allowance of additional funding credits for earnings during the safe storage period on prepayment mechanisms and external sinking funds, and (2) the use of an assumed 2 percent real rate of return. Each of these features affects
~
licensees' calculation of annual contributions to decommissioning funds, thereby generating costs or savings that are attributable to the option:
Credit for Earnings Durine Safe Storagg, Currently, the total amount of licensces' sinking funds must be sufficient at the time of reactor shutdown to pay for estimated decommissioning costs at that time. Annual cuatributions to the fund must be 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 shutdown. The funded amount at shutdown, however, would have to be sufficient such that, with carnings on the funda (at the assumed rate of return) during safe storage, it wouid provide adequate funds to pay for decommissioning activities. This additional earnings credit rould reduce the annual contributions made by licensees, thereby
[
generating savings attributable to the rule. A similar credit would be allowed for prepayment mechanisms.
Assumed 2 nercent Real Rate of Return. The proposed 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 thejurisdiction of a regulatory authority and, therefore, that all rate of return assumptions currently in use by licensees meet with the approval of the applicable regulatory authority.
" Unless otheiwise noted, all present value calculations were made usirg a discount rate of 7 percent, in accordance wim NRC's Regulatory Andysis Technical baluation Handbook, August 1993, page B-2.
Page 45
Therefore, it follows that, in the no retail deregulation scenario, the 2 percent provision will not apply to any licensees. Similarly, it will not apply under the managed deregulation scenario because regulators will continue providing oversight of the assumed earnings rate. Under :he stranding deregulation scenario, licensees' earnings rate assumptions no longer fall under the jurisdiction of an appropriate regulatory authority, and licensees also cease to meet NRC's dennition of electric utility, in these cases, NRC regulations will not permit continued use of an external fund (unless coupled with another financial mechanism). Thus, the assumed earnings rate of 2 percent would be applied by the model only in calculating amounts not yet funded by the sinking fund (allowing for earnings of 2 percent) and by licensees using prepayment mechanisms to assure such unfundal amounts.62 Options B-1 and B 2 are modeled as follows. First, to avoid mis-stating impacts in cases where 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 sufficient (with interest at an assumed pre-tax rate of return of 4.3 percent)" to fully fund the external sinking 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. (Consistent with IRS rules applicable to " qualified" decommissioning 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.
Assumed earnings rates are not revised to 2 percent because, as discussed above, licensees temain as regulated electric utilities at least until 2006 under all scenarios. Therefore, annual contributions q
beginning in 1998 decrease for all licensees that have reported plans to delay commencement of decommissioning activities beyond the expiration of their operating license (even if the licensees have not specified that the delays are the consequence of selecting the safe storage method of
To meet NRC's definition of electric utility, licensees must be able to recover the costs of decommissioning 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. Because regulatory authorities such as FERC and State PUCs are responsible to their ratepayers, it seems unlikely that they would then give up oversight over monies collected in advance from the ratepayers to pay for decommissioning.
62 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-tax real rates of retum on decommissioning funds will average 43 percent annually. This rate represents the historical average real rate on an investment portfolio that evenly balances high quality stoC s and bonds. (This portfolio is representative of the actual investment policies applied to external decommissioning trusts, as reported in AnnedSurvey ofNaclear Decommissioning Cost Estimates andFundmg Policies. Public Utility Surver, Goldman Sachs, August t995, Table 31.) The average real rate of return for long-term govemment bonds is 1.7 percent, and the average real rate of r: turn on large company stocks is 6.9 percent. Thus,43 percent equals the average rate on a hypothetical portfolio consisting of 50 percent long-term govemment bonds and 50 percent large company stocks. (Interest rates are historical geometric means as reported in Stocks. Bonds. Bills andinflation 1995 Yearbook: Market Resultsfor 1926-199-f Table 6-7, Ibbotson Associates, Chicago, IL,1995.)
s Page 46 L
decommissioning)." Under the no retail deregulation and managed deregulation scenarios, each licensee continues these contributions until license expiration. Savings to licensees /ratepayers equa! the present value of the reduced annual payments that result from the option.
Under the stranding deregulation scenario, however, licensees are assumed to obtain a
. prepay ment mechanism or a letter of credit or surety bond in 2006 to assure any costs not yet assured by the sinking fund. Prepayment amounts would be calculated to reflect both the safe stoinge earnings credit and the 2 percent earnings assumption. Because currently-reported safe storage periods are typically very brief(see previous footnote) and currently-reported earnings assumptions are, on average, higher than 2 percent, Option B-2 generates net costs under this scenario.
Options C-1 and C-2 Option C-1 would not :mpose a new reporting requirement, and NRC's ability to monitor funding would not improve. The model assumes that, under Option C-1, any underfunding that is currently projected (see Section 3.2.2) will not be corrected prior to decommissioning.
i Option C-2 would require licensees to report periodically to NRC on the status of their decommissioning funds. NRC would use the data to ensure that licensees' external sinking funds are adequately funded by the time required. NRC's specific methods for making use of the data might t
WS d include the following: 3(gy y p '.
J j,l!'
j: M v.
Benchmarkmg.yNRC could ensure, at the time of each periodic report, y.
that each external sinking fund was appropriately funded. For example, 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 contributiori yq/dp 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 fj, yf j
decommissioning costs. Under a more lenient benchmark;NRC might 'N
\\
require action of the licensee only if the fund is not within some speci6ed percentage of expected funding (e.g., within 5 percent of the f
30 percent funding level). This more lenient benchmark may pose
~
considerable risk, however, because even a small percentage of decommissioning costs can represent a s ery signincant underfanding problem, particularly if the facility life is almost over and the underfunding must be corrected immediately or in a short amount of time.
Case-by-case reviews. NRC might choose to focus its attention only on a specific subset oflicensees (e.g., those closest to decommissioning, those that have relatively poorer funding status than other licensees,
" Many licensees currently report plans to delay commencen ent of decommissioning activities beyond the expiration of their operating licenses. The reported delays, however, are typically fairly b.ief(e.g., less than 5 years). Licensees may yet elect to extend their safe storage periods as allowed by NRC regulations.
Page 47
1 those undergoing corporate restructuring, those in questionable financial condition, those having operational dif6culties).
The analysis assumes that, under either of these methods, NRC's review of reports would be adequate both to ensure that licensees' cost estimates are et least as great as the appropriate certification i
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 media inquiries).
j 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' facilities, and also reduce the corresponding burden on licensees to prepare for the inspection, assist i
NRC personnel, and respond to inspection results.
Options D-1 and D 2 Currently Federal licensees that are electric utilities may use statements ofintent, though there is only one power teactor license, the Tennessee Valley Authority (TVA), that the NRC has considered to fall within this category. Consequently, modeling of Options D-1 and D-2 was speci6c to TVA.
Under Option D-1, TVA would continue.o use statements ofintent to demonstrate financial assurance. NRC would bear ti.e risk described in the report from the Inspector General, i.e., that the statements ofintent may not provide any meaningful financial assurance." Option D-1 results in no change from the status quo, and therefore it generates no inuemental costs or savings.
Option D-2 would eliminate statements ofintent as an acceptable financial mechanism for use by electric utilities unless they also meet the definition of" Federal licensee," which the NRC is proposing for inclusion in its regulation. Under Option D-2, this analysis assumes that TVA's use of statements of intent, 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 signi6 cant annual payments into the fund, these payments are not costs of the rulemaking. Rather, these are advance payments for decommissioning activities for which the licensee is already responsible. Because Option 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 percent discount rate) ofits future de:ommissioning costs and, second, subtracting this value from the present value of the annual contributions required (assuming level payments, a 4.3 percent assumed pre tax rate of return, and a 7 percent discount rate).
- Audit Report: NRC's Decommissioning Financial Assurance Requirementsfor Federal Licensees May Not Be Sugicient. OlG/95 A-20, U.S. Nuclear Regulatory Commission, Office of the Inspector General, April 3,1996.
- This is consistent with the fact that all or virtually all non-Federal electric utilities, w ho are ineligible to use statements ofintent, have selected extemal sinking funds to demonstrate financial assurance for decommissioning.
Page 48
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 s i that, with assumed earnings (of 43 percent), the fund grows to the full decommissioning cost by the time oflicense expiration. To address the possibility that NRC may apply Option B-2's 2 percent earnings assumption along with Option D-2, the model repeats the calculation just described, but the prepayment amount is calculated under the 2 percent earnings assun ption." The financial assurance cost to TVA, calculated for each earnings assumption, is the opportunity cost of paying for decommissioning prior to the commencement of decommissioning (see discussion in the preceding paragraph).
Options E-1 and E-2 Option E-1 is the no-action alternative. Under Option E-2, NRC would require power reactor licensees to submit periodically any modi 0 cations to their currently effective Gnancial mechanisms for NRC's review in light of potential changes in the electric utility industry's regulatory environment.
These options address the possibility that certain provisions or flaws m licensees' decommiss'oning trust or escrow agreements could cause the mechanisms to wholly or partially fail. (A Gnancial assurance mechanism is said to " fail" when it is not capable of providing decommissioning funds when needed.)
l By reviewing specific modincations to Unancial mechanisms and requirin<; revisions to problematic l
provisions, Option E-2 can impact the amount of funds the mechanisms will provide for i
decommissioning.
Option E-2 would generate ;.. ministrative burdens both for licensees and for NRC, but it would 7
}
provide the benefit ofincreasing the efective levelof financial assurance that licensees already have m place without increasing the actuallevel of or the annua l contributions to external sinking funds. Under Option E-1, there would be no added administrative burden, but the amount of financial assurance ultimately available for decommissioning could be less than anticipated.
Options E-1 and E-2 were modeled as follows. For a given licensee, the Gnancial assurance risk is assumed to equal the decommissioning cost estimate times thejoirit probability that (1) the licensee's trust or escrow agreement contains a potentially " critical" flaw (i.e., a provision that circumvents or leaves open the future circumvention of protections important to NRC's interests), and (2) the licensee seeks to use funds for non-decommissioning purposes. In a highly-compe:itive environment, for example, officials at newly-deregulated electricity generating companies msy succumb to temptation to
" borrow" capital from a large decommissioning fund. One NRC licensee, the Tennessee Valley Authority, did in fact recently tap into internal decommissioning funds to pay off e significant amount of debt. (Internal decommissioning funds are similar to flawed trust and escrows in: that they are not governed by effective restrictions on the use of funds.) bimilar problems have been encountered with corporate pension funds that firms have used to pay operating expenses.
Based on experierce reviewing hundreds of financial assurance mechanisms submitted by NRC's materials licenses s (initial submissions as well as subsequent iterations) that were
- veloped using guidance similar to the guidance available to Part 50 licensees, the probability that a given trust or escrow agreement contains a critical Daw is estimated to be in the range of 50 percent. The probability that the licensee and/or trustee might intentionally or inadvertently take advantage of the flaw and use the funds inappropriately is much more difficult to estimate, but will probably vary by scenario. For
" Due to lack of information on whether TVA will use the safe storage method of decommissioning at its reactors, the modeling for Option D does not account for Option B's credit for earnings du:-ing safe storage.
Page 49
_~-.
purposes of this analysic, the probabilities are estimated as follows: 0 percent under the no retail deregulation scenario (i.e., current regulation oflicensees by FERC and PUCs),5 percent under the more competitive managed deregulation scenario (i.e, no stranded decommissioning costs but diminished regulation), and 10 percent under the most competitive stranding deregulation scenario. These probabilities attempt to recognize the impact ofincreased competition on licensees' need for both working capital and investment capital.
3.3.4 Assumptions Several assumptions are worth noting. First, with the exception of Options D-1 and D-2, which affect only oue licensee, the model assumes that all licensera are regulated in an identical fashion by FERC, PUCs, and other regulators as applicable, and will continue to be regulated, or deregulated, in an identical fashion under the managed deregulation scenario and/or the stranding deregulation scenario. In reality, deregulation is not likely to affect every single licensee in the same way or to take effect at the same time (in 2006) for all licensees. This assumption tends to overstate the effect of each option relative to the alternative option and it imbues an "all or nothing" quality to the results. The approach is effective in showing how NRC's options will function under each of the three regulatory scenarios (i.e.,
no retail deregulation, managed deregulation, and stranding deregulation) and seems reasonab!e in the absence of more sophisticated analysis of the substantial uncertainty surrounding future deregulation and how electric 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 in 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 closures of nuclear 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 ta total financial assurance levels and, in particular, annual contributions to external sinking tunds. This assumption serves to isolate the effects of each option without the obfuscatory effects of overfunding or underfunding. This assumption was implemented by adjusting the size of licensees' projected annual contributions to external sinking funds to be the precise amount needed to achieve the appropriate funding level (assuming a 4.3 percent real rate of return on the funds).
Fourth, in calculating the portion of a newly-deregulated licensee's decommissioning cost that, at the time of deregulation in 2006, is unassured by the licensee's external sinking 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., until license expiration) on the amount of funding as of 2006. This assumption seems consistent with NRC's current policy of allowing electric utilities to take credit for earnings on their external sinking funds. Neither NRC regulations or guidance, however, explicitly state whether NRC would allow credits in the situation described above. If NRC would not allow such credits, then the results will understate costs of financial assurance 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 credit to cover amounts that are not assured by their sinking funds at the time of deregulation assumes that licensees will not continue to make annual contributions to the sinking funds. This assumption was Page 50
used to 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 for 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, the reported decommissioning costs. If these reported costs are low, the analysis will tend to understate all results.
l Finally, the following assumptions were used in the analysis of impimentation and operation costs under cach of the options: (1) Wage rates for NRC staff and licensee su were calculated from 1996 wage rates developed by NRC for use in regulatory analysis of $67.50 per hour for NRC staff and
$72.72 for licensee staff. The 1996 wage rates were, nyerted to 1994 dollars to be compatible with the use of 1994 dollars in the balance of the analysis. The rates used (in 1994 dollars) were $64.55 for NRC staff and $69.54 for licensee staff. (2) The number oflicensees used was 132, and was derived from the inforration in Nuclear Plant Owners and Operators (Attachment 2 to SECY-94 280), November 18, 1994. (3) The initial reports required under Option C were assumed to be submitted by all licensees in 1999, with subsequent reports being submitted every 2 years thereafler through 2019. (4) Follow up, l
when conducted, was assumed to be effective after one iteration. For example, follow-up for the reports submitted in 1999 was assumed to be effective for the reports submitted in 2001, and no follow up was assumed for the 2001 report or subsequent reports. (5) Review of submissions under Option A was assumed to take place at deregulation, assumed to be in 2006. (6) Review of modiGeations to Dnancwl assurance mechanisms under Option E was assumed to require a complete and detailed review of each j
mechanism currently in use, with one-third of mechanisms being submitted and reviewed in each of 1999,2000, and 2001, and with follow up for each mechanism in the year after its initial review. For this analysis, the level of effort required oflicensees and NRC in submitting and reviewing subsequent modi 6 cations is assumed to be minimal. (7) 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 benents) of the rule are calculated as any increase in the amount of Gnancial assurance provided by an option and any cost savings to NRC or industry resulting from an option. Impacts are calculated as any decrease in the amount of Gnancial assurance and any costs resulting from the option. Costs and savings include those related to Gnancial 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 Snancial mechanisms, review of Gnancial mechanisms, guidance development, recordkeeping).
Before reviewing the values and impacts of each option, it is worth noting several points to place these results in the appropriate context. The three modeled scenarios (i.e., no retail deregulation, managed deregulation, and stranding deregulation) are necessarily simplincations 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 demonstrates the possible outcome to NRC if other regulators (i.e., FERC and PUCs) cease to be relevant. In general, the model's identical treatment oflicensees under the various scenarios tends to overstate the effects of each option relative to the alternative 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 Page 51
sophisticated analysis of the substantial uncertainty surrounding future deregulation and how electric utilities might evolve. Ongoing deregulation is likely to result in a blend of these and other scenarios.
Consequently, actual values and impacts are likely to fall in between the 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 consid-the possibi;ity that 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 comply with applicable financial assurance requirements. The resulting costs were then compared to licenst Snancias data. Based on this analysis, it appears that the ieremental costs generated by this rulemaking are unlikely to lead to premature closures 'i.e., not accoun'ing for the unknown effect of deregulation and increased competition). Accepting this prel;minary conclusion that this rulemaking will not itself generate premature closures, the analysis focusr.s on how NRC's financial asswace program can best prepare for the uncertainties of deregulation.
3.4.1 Estimated Values and Impacts of Options A-1 and A-2 The discussion of values and impacts is divided into two subsections. The first subsection addresses Snancial assurance values and impacts. The secoid subsection addresses implementation and l
operatian values and impacts.
Financial Assurance Values and Impacts In the no retail deregulation scenario, licensees would meet NRC's current dennition of electric utility as well as its proposed de6nition of electric utility. Consequently, licensees would contmue using external sinking funds under Option A-1 and Option A-2. Therefore,in this scenario, neither option would generate any financial assurance costs or savings.
Under managed deregulation, all licensees are assumed to meet the proposed e (inition of electric utility, but not the current de6nition. Therefore, under the no-action option (Option A-1),
licensees are not allowed to continue using an external sinking fund unless another Snancial mechanism is also used to assure amounts not yet funded. The cost for all licensees to obtain another mechanism to assure the unfunded decommissioning costs is estimated at between $70L$1,051 million, depending on whether licensees can obtain surety bonds or letters of credit or w hether they must instead use prepayment mechanisms." This cost is attributable to deregulation rather than to the rule. Selection of Option A-2 would mean these costs are never incurred, thereby generating savings of $704-$1,051 million.
Under stranding deregulation, all licensees are considered unable to mee: either the current or the proposed definiticn of electric utility. Therefore, under either option, licensees would incur costs of obtaining another n echanism to assure their unfunded decommissioning costs. These costs, fo all licensees, are estimated at between $704-$1,051 million (the same as in the managed deregulation scenario), depending on w hether licensees can obtain surety bonds or letters of credit or whether they must instead use prepayment mechanisms. Again, however, these costs are attributable to deregulation rather than to tue rule.
" Further details on modeling assumptions are provided in Section 3.3.3.
l Page 52
4 These results are sensitive to the assumption that deregulation occurs in 2006. Specifically, the
. savings generated by Option A-2 under managed deregulation would be much higher ($1,704-$2,375
. million) if deregulation o: curred in 2001. Conversely, savings would be much lower d250-$400 million) if deregulation occurred in 2011.
In all scenarios, licensees are assumed to comply with NRC's financial assurance requirements even if they no longer meet the definition of electric u*ility (current or proposed) and must 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 ofimpacts above), but they i
. ould provide the same level of financial assurance.
w These values and impacts are summarized in Exidbit 3 3.
i.
Exhibit 3-3 l
Financial Assurance Values and Impacts Under Options A-1 and A-2 l
I 1-No Retail Managed Stranding Deregulation Deregulation Deregulation Option A 1: No action W
Values / Impacts Option A 2: Revise definition of utility Values Decrease in financial assurance l
costs
$704M.$1,051M i
Implementation and Operation Values and Impacts The implementation and operation costs that could rr7 ult from Option A are described in Exhibit 3-4. Under Option A-1, NRC would continue to rely on review oflicensees' financial assurance status by State PUCs and FERC and would incur no additional burden, even for licensees that no longer
- meet the current or proposed definition of utility. Under Option A-2. NRC would need to prepare a
-component of guidance for licensees similar to Regulatory Guide 1.159 explaining the new definithi of j
." utility" and specifying the actions that licensees that do not meet the new definition will have to take.
Such guidance would be needed even if, in fact, no licensees cease to be regulated as utilities, besause NRC cannot know in advance that this will occur. Under both the mannged deregulation and the 4
stranding deregulation scenarios of Option A-2, the analysis assumes that NRC carries out a review of the financial assurance submissions prepared by licensees that no longer meet the definition of utility 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 4
i Page 53 i
rr
, ~,.
k k
I would begin with the onset of dereguladoa, essumed to be in 2006. Two alternatives were ex mined for this review:
Under the first alternative, the review would be limited to a check of the i
Ley elements of the submission, at about two hours per submission, with i,
follow up only in a few cases of very serious errors or omissions.
Under the opposite alternative, the review would be a detailed examination of the text of the submitted financial mechanisms, requiring up to 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> to complete. Follow up could be required for an estimated 50 percent of the submissions requiring up to an additional 49 i
- hours, i
Licensees w ere assumed to require up to 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> to prepare submissions for either a limited or a detailed tr"~
Inihe case of a detailed review, licensees could require up to an additional 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> to j
respond to s :slems, i
4 Exhibit 3 4
)
iniplementation and Operation Costs Under Options A 1 and A 2 4
No Retall Managed Stranding i
Deregulation Deregulation Deregulation Option A 1: No action NRCllicemecs l
l Op n A 2: Revise definition of utility NRC l
preparation of part of new Regulatory
$10,000
$10,000
$10,000 Guide Review of submissions and follow-up
($9,900-$285,100)
Licen;ts i
. Submission fcr review
($93.500-
$307.200) a I
3.4.2 Estimated Values and Impacts of Options li 1 e
.-2 Financial Assuranee Values and impacts l
T I'
Page 54
~..
in the no retail deregulation scenario, under Option 18 2, licensees can reduce annual contributions to external sinking funds due to the additional carnings credit allowed 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 e rdit during the safe storage period." These savings would not be incurred under Option 11 1.
The estimated impacts of Option 112 under managed deregulation are the same as in the no retail dcregulation scenario, assuming that NRC also implements Option A-2.*
Under the standing deregulation scenario, howes er, the impacts of Options 112 would differ, in particular, savings from the allowance of credits for carnings during safe storege ($322 million) we ild, in aggregate, be outweighed by the new costs to licensees of having to apply NRC's 2 percent earnings assumption 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 contributions for those licensees that currently assume a higher rate, and dect:ased contributions for licensees that currently assume a lower rate. The overall eficct, however, is an increase in costs to licensees because the average real rate assumed by licensees is 3.7 percent.) The costs to licensees of Option 112 assuming stranding deregulation are estimated at between $323-$1,511 million, depending en w hether licensees can obtain surety bonds or letters of credit or whether they most instead use prepayment mechanisms." Selection of Option 11-1 would result in no costs being incurred.
These results are sensitise to the assumption that deregulation occurs in 2006. Specifically, if deregulation occurred in 2001, the savings generated by Option Il 2 under stranding deregulation would be lower ($14I million) and the costs would be higher ($539 $2,946 million). Conversely, if deregulation occurred in 2011, savings would be higher ($450 million) and costs would be lower ($150
$640 million).
These values and impacts are summarized in thhibit 3 5. Licensees are assumed to comply with NRC's financial assurance requirements regardless of w hether 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 oversee their assumed rates of return). Therefore, Options 11 1 and ll 2 may affect costs or savings to licensees (see discussion ofimpacts above), but they would provide the same level of financial assurance.
" Licensees are required to make a preliminary determination of decommissioning methods only 5 years prior to l
termination of operations. Many licensees currently report plans to delay decommissioning activities beyond the expiration of their operating licenses. The reported delays, how ever, are fairly brief(e.g., less than 5 years).
i l
- If NRC were to implement Option A 1 however, then the values and impacts of Options 11-1 and 11-2 under managed deregulation would be the same as under the stranding deregulation scenario (as discussed above).
" Further details on modeling assumptions are provided in Section 3.3.3.
Page 55
?
i Exhibit 3 5 Financial Ansurnmec Values and Impacts Under Options H 1 and Ib2 No Metail Managed Stranding Deregulation Deregulation Deregulation option B l: No action l'alueWimpacts i
Option D 2: Allow credit for earnings during safe storage and an assumed 2 percent real rate of returti(assuming Option A.2 is also implemented) l'alues
. Decreasein financialassurance
$481M
$481M
$322M costs impacts
. Increase in financial assurance
$323M $1,$1IM Costs l
Implementation and Operation Values and Impacts Except for preparation of the component of guidance addressing the rules on calculation of annual centributions to decommissioning funds, there are no additional implementation and operation costs that result from either Option B-1 or Option B 2. Although Option B 2 would require licensees to recalculate the size of annual contributions to sinking funds (or prepayment mechanisms) in the year the rule takes effect (or when deregulation occurs), licensees are assumed to already calculate such contributions each year (i.e., under Option B 1). iJo additional burden would be.mposed on NRC f
bu ause NRC does not review licensees' calculation of annual contributions, hhibit 3 6 summarizes the implementation and operation costs for NRC and licensees of Option B.
i I-4 ~
v 8
Page 56
- c.s.-
,. ~. _ _ _ _ _. _ _ _ - _ _ _ _
Exhihlt 3 6 Implementation and Operation Costs Under Options H 1 and H 2 i
No Retail Managed Stranding Deregulation Deregulation Deregulation Option D l: No action f
NRCulicensees Option 112: Allow credits for camings during safe storage and an assumed 2 percent real rate of retum NRC preparation of part of new Regulatory
$4,000
$4,000
$4,000 Guide 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 uses 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 discussion 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 implemented) would vary depending on the level of oversight NRC provides during the transition to other financial mechanisms, in general, 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 Option 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 current financial assurance requirements. The values and L
impacts of Options C 1 and C 2 are summarized in Exhibit 3 7.
4 i-i 1
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_ _.__ _ _ m _ _.
C k
Exhibit 3 7 l
Financial Assurance Values and impacts Under Options C 1 and C 2 4
No Retail Managed Stranding Deregulation Deregulation Deregulation
}
I Option C 1: No action ValueWimpacts 4
Option C 2: Reports used to ensure
]
adequate funding Values Increase in financial assurance
$2,700M
$2,700M ss2,700M l
coverage levels i
implementation and Operation Valucs and impacts I
Under Option C 1, the no action alternative, no additional implementation and operation costs would be incurred by NRC or licensees. Licensees wouH continue, as they do under the current rule, not to be required to report on the status of their decommissioning funds until approximately 5 years before the projected end of operation (10 CFR 50.75(f)). Records of the cost estimate or certification amount and of the funding mechanism used for assuring funds also would continue to be kept in an identified -
location where they may be reviewed in t'e inspection process if necessary.
Option C-2, in which licensees would be required to submit periodic reports on decommissioning fund status, will impact NRC lmplementation and operation and industry implementation and operation.
Option C 2 would substantially eliminate implementation and operation costs, both to NRC and to 4
[
licensees, associated with compliance inspections that may otherwise be required under Option C l.
I NRC implementation and operation costs are expected to include development of a component of a Regulatory 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); development and implementation of a report tracking system; and review and analysis of reports beginning in 1999.
1' The analysis assumes NRC would follow-up on about 50 percent of the reports received in 1999.
The frequency of follow up necessary was assumed to be rero after the initial series of reports, Industry implementation and operation costs are expected to include development of procedures i
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; 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 submitted, generally consisting of a telephone inquiry with follow up letter, if NRC uses the reports to ensure adequate funding.
4 0
+
Page 58
... ~
. - ~
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[k n:
N.
Ihhibit 3 8 summarires implementation and operation costs of Options C 1 and C 2, Eshlble 3-8 Implementation and Operation Costs Under Options C-1 and C 2 No Retail Managed Stranding Deregulation Deregulation Deregulation Option C 1: No action NRCilicensees Option C 2: Reports used to ensure t
adequate funding NRC Preparation of part of
$3,900
$3,900
$3,900 Regulatory Guide
- Development and implementation of a report
$2,600
$2,600
$2,600 tracking system Detailed review of reports to serify adequacy of funding and
$i29,300
$129,300
$129,300 follow-up Licensees Reporting and follow up
$437,000
$437,000
$437,000 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 ofintent by Federal nuclear power reactors. Significant questions have arisen, however, regarding the security of funds assured by statements ofintent (see related discussion in Sections 2.4 and 3.3.3). Consequently, under Option D 1, the $1.66 billion in fmancial assurance that statements ofintent were providing may be, in effect, unassured. Option D-2 (under all scenarios) would eliminate the statement ofintent as an acceptable mechanism for electric utilities unless they also qualify as " Federal licensees." This would requiie the one licensee that currently uses statements of intent, TVA, to obtain alternative financial assurance (e.g.,
external sinking funds) for the full amount of its decommissioning obligations (i.e., approximately $1.66 billion)in order to comply with current NRC financial assurance requirements.
Page 59
1 in the no retail deregulation scenario, TVA would incur no costs under Option D-l. Under Option D 2, however TVA would have to establish an a ternative financial mechanism, The cost of this t
assurance equals the opportunity cost to TVA of committing decommissioning funds to its external sinking funds before the commencement of decommissioning. This cost is estimated at $124 million."
The estimated impacts under nunaged deregulation are the same as in the no retail deregulation scenario, because TVA is likely to continue io qualify as an electric utility (and hence to be allowed to continue to use external sinking funds) even under managed deregulation.
Ilecause of TVA's unique status among electric utilities, it is unclear w hether stranding deregulation would have the same efTect 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 obtain alternatise assurance for amounts not yet funded. This cost of Option D 2 is estimated at $153 243 million," depending on whether NHC has also implemented Option 112. (Option D-2 costs are higher if Option 112 has been implemented because TVA would then be limited to an assumed earnings rate of 2 percent.) Under Option D 1, TVA would continue using statement, of intent and would incur no financial assurance costs.
These values and impacts are summarized in Exhibit 3-9.
" This excludes the opportunity costs to TVA related to $365 million that it has already contributed to extemal decommissioning trusts.
" This assumes TVA prepays remaining decommissioning costs in the year 2006. TVA's costs wonld decrease ifit is able to obtain and use a surety bond or letter of credit instead of a prepayment mechanism.
l Page 60
Exhibit 3 9 Financial Asserance Values and Impacts Under Options D 1 and D 2 No Retail -
Managed Stranding Deregulation Deregulation Deregulation Option D-1: No action Vahn/ Impacts 1
Option D-2: Clarify whi:h licensees are eligible to use statements ofintent by l
denning the term " Federal licensee" l
l'alues l
Increase in financial assurance
$1,663M
$1,663M
$1,663M coverage levels impacts Increase in financial assurance
$124M
$124M
$153M.$243M Costs Implementation 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 implementation and operation costs for NRC or for the licensee, TVA, because TVA would continue to be able to use the statement ofintent. Under Option D 2, NRC was assumed to incur costs to review the new financial assurance arrangements submitted by TVA to replace the statement ofintent. 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 financial assurance to replace the statement ofintent, 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.
Page 61
Exhibit 3-10 Implementation and Operation Costs Under Opticas D 1 and D-2 No Retall Managed Stranding Deregulation Deregulation Deregulation Option D-1: No action 4
NRC/ Licensees i
Option D-2: Clarify which licensees are eligible to use statements of intent by defining the tenn
" Federal licensee" A
NRC Review replacement financial
$2.600
$2,600
$2,600 assurance Licensees Secure and submit replacemeat
$4,200
$4,200
$4.200 financial assurance 4
b 3.4.5 Estimated Values and Impacts of Options E-1 and E-2 Finanelal Assurance Values and impacts Under Option E 1, the amount of financial assurance ultimately available at the time of decommissioning may be less than anticipated because the terms of the financial mechanism are assumed not to adequately protect NRC's interests. Under Option E 2, NRC would seek to minimize the risk ofinadequate financial mechanisms by (1) requiring licensees to submit periodically any modi 0 cations to their financial mechanisms to NRC for a detailed review, and (2) requiring revisions as needed to climinate problematic provisions in the mechanisms. For a variety of reasons discussed in Section 2.5 and Section 3.3.3, flawed financial mechanisms are unlikely to actually fail until and unless deregulation occurs. Thus, in the no retail deregulation scenario, there is no difference in the value of licensees' financial assurance regardless of whether Option E 1 or Option E-2 is implemented.
- As deregulation and increasing competition occur, however, the risk associated with flawed mechanisms becomes more significant. Under managed deregulation, the effective level of financial
' assurance provided by licensees is estimated to be in the range of $930 million less than the nominal value of that assurance due to the potential use by licensees of flawed financial mechanisms. Under stranding deregulation, the efrective level of financial assurance is estimated to be in the range of $1,860 million less than the nominal value of that assurance, in order to ensure that benefits are realized under this option, NRC would need to conduct, in the Grst reporting period, a complete and detailed review of each mechanism currently in use.
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There are no additional unancial assurance costs (i.e., fees on surety bonds or letters of credit, or opportunity costs of funded amounts) estimated to result from either Option E-1 or Option E 2 because neither the amount nor the method of licensees' financial assurance demonstrations is assumed to change under either option. Rather, under Option E 2, licensees will work with NRC to perfect their current financial mechanisms (see implementation and operation discussion below).
These values and impacts are summarized in Exhibit 3-11.
Eshibit 311 Finanelal Assurance Values and Impacts Under Options E-1 and E 2 No Retail Managed Stranding Deregulation Deregulation Deregulation Option E 1: No action l'alues/ Impacts Option E 2: Require modi 0 cations to mechanisms to be submitted periodically for detailed review I'alues Increase in financial assurance
$930M
$1,860M coverage levels Implementation and Operation Values and Impacts Option E 1, the no-action alternative, would involve no implementation and operation costs for NRC or licensees. Option E 2 involves a detailed review by NRC of any modi 0 cations to the currently existing financial assurance mechanisms, with examination of the modined text of trust funds or other financial instruments, investigation of the current levels of funding, and follow up to ensure licensees with problems understand and correct the deficiencies in their financial assurance. This option would inwive costs to NRC. Licensees would also incur costs to prepare periodic submissions of any modifications to their current mechanisms and respond to follow up from NRC. Exhibit 3 12 summarizes the estimated costs of this option.
Page 63
}
.. - _.... -... -. ~.. - -
. - ~. -... -.
- _ _ ~ - - _.
]
Eshibit 312 Implementation and Operation Costs Under Options E.1 and E 2 No Retail Managed Stranding Deregulation Deregulation Deregulation Option E 1: No action NRC/ Licensees Option E 2: Require modifications to mechanisms to be submitted periodically for detailed teview NRC 4
Detailed review and follow up
$500,000
$500,000
$500,000 Licensees Preparation _of submission of modifications to current financial ast,urance and follow up
$525.000
$$25,000
$525,000 to resolve problems Page 64
4, IIACKFIT ANALYSIS The regulatory analysis for the proposed rule also constitutes the documentation for the evaluation of backfit requirements, and no separate backfit analysis has been prepared. As defined in 10 CFR 50.109, the backGt rule applies to " modi 0 cation of or addition to systems, structures, components, or design of a facility; or the design approval or manufacturing license for a fadlity; or the procedures or organization required to design, construct or operate a facility.... " resulting from new or amended provisions in Commission rules. Such backfitting can be plant specine or apply to multiple facilities
(" generic backfitting").
The proposed amendments to NRC's requirements for the financial assurance of decommissioning of nuclear power plants address generic requirements. The proposal would revise the definition of"clectric utility," add a dennition of'Tederal licensee," and add several associated Jelinitions that are generic in nature; amend generically the requirements pertaining to the use of prepayment and external sinking funds; and impose generic new reporting requirements for power reactor licensees on the status of decommissioning funding that specify the timing and contents of such reports.
l l
NUREG 1409, NRC's Backfitting Guidelines, lists several criteria (provided below in italics) for determining whether a panicular proposed rule falls within the scope of the backGt rule. The criteria, proposed actions, and a description of w hether the actions meet each criterion follow:
The positions or requirements would bring about improvements in safety of nuclear power reactors.
The current proposal would enhance the safety provided by NRC's reactor decommissioning requirements, by helpag to ensure that the reactor decommissioning is adequately Onanced and that delays or shortfalls do not occur in the funding of decommissioning that.could create threats to health or safety.
The positions or requirements impose changes in hardware, procedures, or organi:ation ofnuclear power reactors.
The current proposal would require no changes in hardware or organization of nuclear power reactors. Ilowever, the proposal could result in changes in the procedures for operation of facilities in that (1) external sinking funds, by tnemselves, would not remain as an acceptable decommissioning funding option for those licensees that no longer meet the definition of" electric utility,"(2)
TVA might no longer qualify for use of a statement of intent, and (3) a specined rate of return on decommissioning funds during operation and the decommissioning period would be used in the absence of a different rate approved by a PUC or FERC.
I The backfit rule doss not cover NRC actions that merely request information and do not impose changes in har dware. procedures, or organi:ation.
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~_ _. _ _ __
The current proposal includes revisions to reporting requirements that constitute a request for information.
The backpt rule does not apply topurely administrative matters.
The proposed rule is not purely administratise. It involves changes to the jurisdictional definitions penaining to licensees and also affects the regulatory options available to licensees.
The NRC has determined that the proposed action is a backfit for the reasons described above, llowever, in order for NRC to maintain assurance of adequate funding during the changing uncertainties of deregulation, this action is an " adequate protection" backfit. Consequently, the proposed change to the regulations is required to satisfy section 50.109(a)(5) and a full backfit analysis is not required pursuant to section 50.109(a)(4)(ii).
4 Page 66
- 5. DECISION RATIONALE 1.
Option A 2 would revise the definition of" electric utility," whicl> specifies when nuclear power reactor licensees may use an external sinking fund that builds up to the required level of decommissioning funding, and when such owners must provide ".up-front" financial assurance for the full amount of decommissioning. Under Option A 2, entities that no longer qualify as " electric utilities" because they are no longer able to recover the cost of decommissioning through electricity rates or mandatory fees will be required to notify NRC of the change in their situation and to provide financial assurance 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 can recover costs of decommissioning through rates, but which are receiving decommissloning funds through non bypassable system exit fees, line charges, or other means established in the course ofindustry deregulation, would still be required to incur costs, in total, of up to $704 million to
$1,051 million (or more if deregulation occurs prior to 2006) for establishing financhl assurance to supplement their 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.) Option A 2 therefore isjustified 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 fees.
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 allow 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 established in the course of industry deregulation.
3.
For the reasons stated in (1) and (2) above, Option A 2 is superior to Option A 1, the no-action alternative.
4.
Option B 2, allowing licensees credit for carnings 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 conditions licensees could continue to use their own assumed rates of return (which may be reviewed and approved by State PUCs and/or FERC) until funds are spent on decommissioning. 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.
Page 67
5.
Option B 2 would result in net costs to nuclear reactor licensees under scenarios where licensees may not continue to use their own assumed rates of return but must instead use the required 2 percent rate of return established under Option B 2. In this case, the savings resulting from the extended earnings credit described in (4) would, on balance fcr all licensees, be offset by higher costs associated with the 2 percent earnings assumption. Specifically, if nuclear reactor licensees cease to qualify as utilities under the definition in Option A 2 because after deregulation they cannot receive decommissioning funds from rates or mandatory fees (and therefore are presumed not to be supervised by State PUCs and/or FERC). Option B 2 would limit them to an assumed 2 percent rate of return prior to safe storage as well as during th: safe storage period.
The net effect of the 2 percent rate and the extended earnings credit could incrtase financial assurance costs by $1 million 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 assumption 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 B 2 ($1 million to $1,189 million). The net costs will vary, depending on w hether the licensees use prepayment 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 estimated real rates of return the licensecs had previously been using for their external 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 State PUCs and/or FERC.
Ilowever, both components of the increased wsts wi!! reduce the potential for significant underftmding of decommissioning.
7.
Option C 2, requiring periodic reports by licensees to NRC on the status of decommissioning financial assurance, would allow NRC to address whether adequate dacommissioning funds have been set aside to date. Option C-2 would impose implementation and operation costs en NRC and licensees (Exhibit 3 8). Ilowever, a reporting requirement coupled with strong follow-up action to address any cases of underfunding identified through the analysis of the reports received could result in avoidance of up to $2,700 million in unfunded decommissioning that could be experienced under the no-action alternative or if a reporting requirement is coupled with limited follow-up(Exhibit 3 7).
8.
Option C 2 also hts non-quantinable benefits for regulatory efficiency, because it would allow NRC to develop and provide to Congress and the public detailed infonnation about the current status of d: commissioning funding.
l 9.
For the ressons stated in (7) and (8) above, Option C-2 is superior to Option C 1, the no-action alternatise, 10.
Option D-2, defining the term " Federal licensee" to restrict the use of statements of intent by Federal power reactor licensees, would require TVA and NRC to incur limited r
(
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implementation costs to secure and apprave an alternative financial mechanism. TVA also would be required to incur costs of from $124 million to $243 million to provide alternative financial assurance, depending on the type of assurance that is used.
Ilowever, qualitative analysis suggests (Section 3.2.4) that the statement ofintent has inherent Haws that make it a weak fonn of Snancial assurance, it may provide only a promise by the licensee to seek and obtain funds at some future time when they are f
needed. TVA's statement ofintent apparently was not the equivalent of a parent guarantee provided by the Federal government; NRC's Office ofInspector General has uncovered reasons to believe that the Federal government does not in fact intend to provide any guarantee that it will provide funding for TVA's decommissioning costs.
TVA's statement ofintent thus most closely resembles a self guarantee, based on its j
commitment to set rates or issue bonds, no'as, or other indebtedness sufficient to provide finds for decommissior.ing. Option D 1, the no action attemative, represents the situation if TVA cannot meet this self guarantee commitment. Under Option D 1, unfunded decommissioning costs of up to $1,663 million could be incurred. Option D-2 therefore is the preferable alternative.
11.
Option E-2 would involve a detailed examination of changes to licensees' financial assurance arrangements, particularly any modifications to their financial assurance mechanisms such as trust funds and other contractual instruments, that were last examined in 1990 when they were initially set up. Under Option E 2, both NRC and licensees would incur implementation costs to conduct and follow up on such an c:. amination, primarily in the first reporting period after the rulemaking. Ilowever, flaws in financial assurance mechanisms putting at risk'the ability of NRC to draw on the funds when necessary are expected to become more critical as the electric utility industry is deregulated, due to increased pressures on working capital and investment capital of finns in a competitive environment, and the possibility that such capital might be taken from funds supposedly set aside for decommissioning. The estimated shortfalls in decommissioning funds that could result from Option E-1, the no-action alternative, are sensitive to estimates concerning the proporton of imm,J:' assurance mechanisms that currently contain or may in the future contain problematic provisions, and the estimates of the proportion of cases in uhich attempts might be made to use the funds for other purposes. NRC has obtained information, based on experience in review of financial assurance mechanisms by non-reactor licensees, that approximately half of all unreviewed mechanisms may contain flaws; NRC has no information about use of decommissioning funds for other purposes. NRC and licensees could incur combined implementation costs for a detailed review of modifications to mechanisms with follow-up of approximately $1.0 million (Exhibit 3-12). Such a review could avoid unfunded decommissioning costs of from $930 million to $1,860 million (Exhibit 3 1I).
Page 69
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t 1
i f
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i 4
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4 Page 70
- 6. IMl'LEM ENTATION This action would be enacted through a Proposed Rule Notice and public comment and a Final Rule, with promulgation of the Final Rule by 1998. Implementation can begin immediately following the enactment of the final rulemaking. No impediments to implementation of the recommended alternatives have been identified. Regulatory Guides for licensees would be required to provide an explanation of the regulatory requirements and methods for applying NRC's assumed 2 percent real rate of return, the periodic reporting requirements, and the requirements for regulatory compliance for licensees that no longer satisfy the definition of"clectric utility" or " Federal licensee "
Page 71 E
-o
'4 DOCKETED
[7590 01 P3SNRC NUCLEAR REGULATORY COMMISSION 10 CFR Part 50 RIN 3150-AF41 0FFICE Of SECRETARY
~
DOCKETlhG & algylcr Financial Assurance Requirements for MANM Decommissioning Nuclear Power Reactors AGENCY:
Nuclear Regulatory Commission.
DOCKET NUMBER PROPOSED RULE PR 5o ACTION:
Proposed rule.
[kR/gy75gg)
SUMMARY
- The Nuclear Regulatory Commission (NRC) is proposing to amend its regulations on financial assurance requirements for the decommissioning of nuclear power plants.
The proposed amendments are in response to the potential deregulat'on of the power generating industry and respond to questions on whether current NRC regulations concerning decommissioning funds and their financial mechanisms will need to be modified. The proposed action would require power reactor licensees to report periodically on the status of their decomissioning funds and on the changes in their external trust agreements.
Also, the proposed amendment would allow licensees to take credit for the earning on decommissioning trust funds.
DATE:
Submit comments by P = rt e date tc l h 75 d.ys pubH; ccsent'r M d Q, 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.
, qiLk iOY -^ fff
o ADDRESSES: Mail comments to:
The Secretary of the Commission. U.S. Nuclear Reg.ilatory Comission, Washington, DC 20555-0001. Attention: Rulemakings and YdjubickionsStaff.
'b^
Deliver comments to:
11555 Rockviile Pike. Rockville, Maryland, between 7:'30 am snd 4:15 pm, Federal worLdays.
5.xam%e ccpies of coments received at: The NRC Public Document Room.
2120 L Strest NW. (Lower Lovel). Washington, DC.
l FOR FURTHER INFORMATION CONTACT:
Brian J. Richter, Office of Nuclear Regulatory Research. U.S. Nuclear Regulatory Comission. Washington, DC 20555-0001 telephone (301) 415 6221. e mail bjr@nrc. gov.
SUPPLEMENTARY INFORMATION:
I
Background
The NRC published an advance notice of proposed rulemaking (ANPR) for
" Financial Assurance Requirements for Decomissioning Nuclear Power Reactors" on April 8, 1996 (61 FR 15427).
The NRC was seeking coments on its proposal to amend 10 CFR 50.2. 50.75, and 50.82 to require that electric utility reactor licensees provide assurance that the full estimated cost of decomissioning their reactors will be available through an acceptable guarantee mechanism if the licensees are no longer subject.to rate regulation by State public utility comissions (PUCs) or the Federal Energy Regulatory Commission (FERC) and do not have a guaranteed source of income. The proposed amendments would also allow licensees to assume a positive real rate of return.
on decomissioning funds during the safe storage period.
Lastly, a periodic reporting requirement would be established.
The ANPR specifically requested coments on the above amendments and on six areas of cor. sideration for decomissioning:
1.
The timing and extent of deregulation of the electric utility l
industry:
i 2.
Stranded costs; i
3.
Financial qualifications and decomissioning f iding assurance for nuclear power plants:
4.
Decomissioning funding assurance for a Federal Government licensee:
5.
The status of decomissioning trust funds during the safe storage period: and 6.
Reporting on the status of decomissioning funds.
In response, the NRC received 650 coments from 42 commenters, and the comenters have been classified into 4 groups. The largest group of respondents was utilities and utility groups (28 comenters), followed by public utility comissions and related organizations (9 comenters).
Two public interest groups submitted comments, as did a group of 3 commenters referred to as "other."
1 The discussion of the comen's rm1ved is presented by general coment area and specific questions posed within each area. The questions appaar in 1
the order as presented _in the ANPR followed by the Commission's responses. r E
y
Discussion of Comments A.
TIMING AND EXTENT:OF ELECTRIC UTILITY INDUSTRY DEREGULATION A.1 Likely Timetable On the issue of the timing and extent of deregulation, most comenters 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 comenters did not take a position on the timing issue. Seven comenters stated that the timing of deregulation could not be predicted.
Several comenters stated only that they took the same position as the Nuclear Energy Institute (NEI), an organization that represents many nuclear utilities.
NEI 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.
A.2 Restructurina or Dereaulation Scenario Phases of Dereaulation. Several comenters 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 by undertaking cost reductions (e.g., workforce reductions, contrau+ -
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 l
competitive electricity business.
The pace of deregulation, according to one comenter. 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 commenters expect that electricity prices from generators will ultimately be largely deregulated or unregulated.
One comenter stated that generation of electricity will become partially deregulated, but may not be fully deregulated if reliance on market forces does not adequately ensure safe and reliable generation supplies.
Nine commenters expect that transmission rates will remain subject to Federal Energy Regulatory Commission jurisdiction.
Regional power markets (RPM) and independent system operators (150) (discussed below) would also fall under FERC jurisdiction, according to one commenter. Ten commenters anticipate that distribution (retail) rates-are likely to remain subject to Statejurisdiction. One of these comenters stated that distribution rates may be regulated under a price cap or incentive-based regulation.
2 Retail wheeling and pool-based pricing will nrovide market pricing at all levels, including the retail level, according to one commenter. Three
-commenters believe that retail wheeling 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 end environmental regulation.
Resultina Business and Industry Structure. Although one commenter stated that NRC should abandon any attempt to 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, Many, and perhaps all, transmission systems operated on a State wide or o
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 (PMEs) for competitive generation will accept bids from all generators that want to participate 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 allowcd.
Different treatment for nuclear generation than for other types of l
utility-owned generation.
Even if nuclear generation is permitted to compete in an open market, some regulatory mechanisms may remain in 2Retail 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. _ _,. - _ _
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.
e Continued economic viability for nuclear generation for many years as a result of marginal costs that are quite low. Another comenter 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 decommissioning and the disposal of high level nuclear wastes.
This co rnenter stated that neither NRC rulemakings nor short-term passage of time will resolve these issues.
A third comenter asserted that competitive pressures will lead to the early retirement of some nuclear-plants.
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 decomission nuclear plants.
Another comenter suggested that if the NRC chooses to proceed with a rulemaking, the rule should accomodate both nuclear units subject to traditional regulation and nuclear units in the competitive markets.
A.3 Differences in State Policies and Imolications Commenters expressed viewpoints on the likely differences in State deregulatory efforts and policies. One commenter declared.that all States will ultimately undergo restructuring and deregulation in some form.
Nine -
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comanters, however, suggested that some States may reject restructuring entirely, regardless of what other States do.
Four comenters feel that States will possibly or probably be compelled 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 factors provide an advantage to States that foster competition (by allowing indig'enous utilities to gain strength by acquiring market share) States that resist -
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 reciprocal access being provided to in-State utilities seeking to enter the State that does not provide competition.
l Three commenters remarked that reform may proceed at different speeds in different States because of local market and political pressures.
One of l
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4 these commenters recomended 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 economic issues in a variety of ways.
Another comenter stated that a hybrid system could exist fo some time. A third comenter reported that. while a hybrid system could probably exist it may not result in the least expensive electricity.
Unde. 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 1
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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 comenters 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.
One comenter expressed concern that deregulation and reduced oversight
- at the State level may reduce the certainty that out-of-State partial owners of nuclear-facilities will collect and expend decomissioning funds.
Response. The above questions are posed for coment so the NRC could obtain estimates on the timing of deregt lation, phases, and possible different approaches that may be used in how Stc ces would address deregulation. These comments are being grouped under one response as they all contribute to whether the Comission should proceed with a proposed rule now. While tr.e responses to this set of questions ran the gamut of opinion on this issue, the - -
coments have not caused the Comission to change its position that it must act now to be 1'n 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 decomissioning.
The comments received and the NRC staff's independent review of deregulation activities also indicate that NRC power reactor licensees are likely to have sufficient notice of changes in their regulatory regimes so as to be able to secure necessary financial assurance for decomissioning should they no longer qualify in whole or in part, as electric utilities.
(The staff notes that most. if not all, PUCs and FERC are addressing decomissioning funding assurance in their deregulatory initiatives.) Hence, these coments reinforce i
the Comission's position that a rule is necess6ry and timely given electric utility restructuring and the deregulation legislation being proposed or enacted in several States and by Congress.
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 decomissioning costs.
Following are viewpoints typical of these coments.
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-bypassable customer fees, including securitization, exit fees) may be different from current l t
mechanisms, but the Erobability of recoverability under these mechanisms is no less than it would hue been under conventional regul tion The mechanism
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chosen, and its associated equitable allocation of cost responsibility between customers and shareholders, will be determined thrcugh the inevitable give and take of the restructuring process, if one is implemented.
FERC. in Order 883. April 24, 1996, effectively established a precedent that, for electric salet 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 or may become stranded as a result of moving to a competitive market. Although the FERC order pertains to wholesale markets, most believe 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.
Evan 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.
However, other commenters expressed some uncertainty.
Some commenters thought cost recovery was appropriate, but did not address its likelihood.
In some cases, comenters advocated specific NRC action to address the situation.
One commenter stated it is premature to speculate as to who will ultimately bear the responsibility for stranded costs (estimated between $7 3
4 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, because potential retail i
l 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 may 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 i
will be treated as State PUCs define policy for restructuring, FERC and some 4
State PUCs already have proceedings under way to determine the amount and 1
means of stranded cost recovery, There 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 l
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.)
l One PUC does not accept that any source of electrical generation is "non-competitive" per se, and thus does not accept that nuclear plants are
' non-competitive because of high construction costs.
It is premature, an oversimplification of a complex issue, and a potential disincentive to mitigate costs to label any type of generation non-competitive at this early l
stage in restructuring.
Even if nuclear generation is sold at less than current combined fixed and variable costs, the market price 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 fnquire 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 among all customer classes that benefit from the continued operation of the unit.
If the unit is not necessary, it should be removed from service.
I The individual State comissions will have to decide who should beu the cost
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to prematurely shut down as opposed to decommission, an uneconomic plant, A commenter stated that the treatment accorded stranded investment or I
costs may vary from jurisdiction to jurisdiction and few generalizations are i
possible. The NRC should not become embroiled in individual rate proceedings n
or debates about particular cost recovery mechanisms, but should instead f
define a clear policy that, from a public health and safety perspective, licensees must-be allowed to maintain an adequate financial posture to support f
ongoing safe operation and decommissioning.
The NRC's policy statementz l
should be a strong statement of its expectations.
NRC should participate in f
the NARUC Tubcommittee addressing restructuring.
l Some commenters stated that decommissioning obligations are 4
qualitatively.different from other stranded costs.
FERC has not yet adopted a mechanism that provides for recovery of + commissioning costs.
Order 888 provides for recovery of wholesale stranded costs through the " revenues lost" approach. However, this approach only accounts for and allows recovery of fixed costs already incurred by utilities and does not address costs that must be collected in the future. A better solution'is for the Federal. Government 2Spg Draft Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility-Industry. (61 FR 49711: September 23.
j-1996).
l :
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4 to assure the continuing recovery of decomissioning costs in utility rates.
through non-bypassable fees to be paid by utility customers leaving the system, or through other surcharges tied to the use of transmission facilities.
The NRC should support cost recovery initiatives and help educate State commissions on the importance of ensuring continued full collection of decommissioning costs.
Another commenter noted that the best ultimate assurance of the collection of the cost of decommissioning is the ability of the plant to operate at sufficiently low marginal costs to collect decommissioning costs in gross margins. The NRC could improve the likelihood of this outcome by (1) encouraging the IRS to allow payments for decommissioning costs to be generally deductible rather than deductible only if they are ordered by a regulatory agency and (2) strengthening utilities' efforts to recover stranded costs. As plants are further depreciated and the cost of nonnuclear generation escalates, existing plants will become more competitive.
Some commenters asserted that in the process of identifying well-run plants and seeking the sale or closing of the not-well-run plants, the problem of who should pay for unrecovered costs must be addressed.
To the extent that the nonsalability is caused by problems created by poor management, the seller is responsible.
If the NRC or another agency would undertake a program to address the problem of poorly performing nuclear plants and encourage continued maintenance of efficiently operated 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, 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
. to recommend an orderly plan for the disposition.of those few plants and operators who w'ill 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.
utility shareholders rather than customers unless there is a compelling case otherwise.
Response. The Commission does not see a need to modify its position that its regulations need to be modified at this time to address the changing regulatory situation for power reactor licensees 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 beyond the NRC's sphere
, of regulation.
Examples include having the NRC identify poorly run piants, requiring the plants to be sold and for-the Federal Government.to be the
-purchaser of last resort and even run the plants if necessary.
The NRC has addressed the issue of stranded decomissioning costs elsewhere in this notice.
However the NRC is aware that stranded costs, insofar as their recovery affects a licensee *s ability to obtain sufficient -
funds to protect public health and safety, must be' addressed to ensure that they are being adequately handled.
Further. States are considering a number of_ options for assessing non-bypassable charges to recover decommissioning costs.'as well as other stranded costs. One such option is "securitization."
4 i
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1 which entails financing the recovery of stranded costs through issuance of bonds whose principal and interest would be repaid by an irrevocable, non-bypassable charge set by State statute on an electric utility's distribution customers.
Because the income stream to repay the bonds would be securitized by the irrevocable, non-bypassable charge, the bonds would be highly rated and would thus require a lower interest rate than riskier debt. Also, these securitized bonds would not be part of the utility's capital structure, and so would not reflect the higher cost of equity capital.
The spread in interest cost between highly rated securitized debt and lower rated utility capital that includes both debt and equity makes securitization attractive to many states. The NRC believes that securitization has the potential to provide an acceptable method of decommissioning funding assurance, although other mechanisms that involve non-bypassable charges provide comparable levels of assurance and should not be excluded from consideration by State authorities.
As stated in the NRC's " Draft Policy Statement on the Restructuring and Economic Deregulation of the Electric Utility Industry" September 23, 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 1;censee's financial situation when these actions are warranted to protect 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 Utility Comissioners (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 _
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l requirements of this rulemaking are seen by the NRC as a vehicle for the Comission to monitor this potential concern.
C.
NUCLEAR FINANCIAL QUALIFICATIONS AND der 0MMISSIONING FUNDING ASSURANCE C.1 Fundina Assurance if Plants Shut Down Prematurely Most comenters accepted the premise of.the question, whether costs of a i
shortfall in decomissioning funding of a prematurely shut down plant could be passed along to ratepayers. This conclusion was based in part on past l
experience and in part on a belief that State PUCs will develop methods to ensure that decomissioning costs are covered. Several comenters 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 decomissioning, but if the management were not deemed responsible State PUCs would find methods to have the ratepayers provide the funds.
Comenters noted that, in the past, decomissioning costs had been recovered for prematurely f
closed reactors (e.g., Dresden 1. Fort St. Vrain San Onofre Unit 1. Trojan, Yankee Rowe).
In a transition from full regulation to full competition, one commenter suggested a window to allow continued or possibly accelerated recovery. Another comenter said that a surcharge might be placed on customers, Under competition, recovery could be made through other revenue streams of the licensee, a non-bypassable fee, or debt or equity of the licensee.
Two other comenters 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 I l
l responsible for providing decomissioning 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 denomissioning 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, decomissioning might be accorded special treatment.
One commenter argued that the solution to premature shutdown was for NRC to require assurance for decomissioning costs prior to approving reorganizations or liccase transfers.
Potential funding shortfalls should be addressed, another argued. on a ca'e-by-case basis, and might be avoided by sale of 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 comenters, such funding 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 comenter 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 decomissioning costs of over a 40-year operating life ma. be unrealistic. i
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 f
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.
I Response.
The Commission recognizes the importance of decommissioning funding assurance for prematurely shutdown plants and believes that-its current case-specific approach, outlined in S 50.82, strikes the best balance between level of assurance and cost.
The alternative of requiring-accelerated funding for all plants over a defined period, to cover the possibility of premature shutdown at some plants, would be too arbitrary and would lead to wide-variations in impacts on licensees. Accelerated funding results in the inequitable inter-generational problem of the present generation paying for
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the decommissioning-costs, while the future generation may receive the j
benefits'of future electricity generation without incurring the costs of
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' decommissioning. Although the Commission is not proposing to expressly require accelerated funding to address premature shutdowns, to the extent that licensees no longer qualify, in whole or in part, as electric utilities, they will, in effect, have to " accelerate" funding by getting "up-front" forms of-financial assurance. The staff expects, however, that PUCs and FERC will address decommissioning funding through cost recovery mechanisms. The
- Comission is aware that some plants have not operated for the full 40 years.
However, it is likely that some plants will continue operating for the full 40 s J e
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i years and beyond.
Therefore, the Commission.does not believe any change is required for the planned 40-year life, o
C.2 When Does an Ooerator Cease To Be a Utility On the question of when an operator of a nuclear power plant ceases to 4
be a " utility" as defined in 10 CFR 50.2 seven comenters interpreted the definition strictly and concluded that, if an operator ceases to satisfy the terms of the definition, the operator is no longer a " utility." Several l
commenters used almost the same formula:
an operator would cease to be a i
' " utility" when it ceases to provide service to retail or wholesale customers j
at rates.sC by a separate regulatory authority.
One comenter supported a 4
clarification of NRC's regulations that would establish its continued ability to requit proper accumulation of decommissioning funds.-while two argued that the NKL should relax its definition to cover entities that purchase electricity and recover the costs from rates charged customers or from other revenue guarantees. Another comenter 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 the 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.
l Other comenters 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 t ;.
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entities that have been authorized by a State PUC, FERC, or other governing entity to_ recover decommissioning costs from customers. Two comenters expected plants to remain subject to State PUC jurisdiction, and therefore to satisfy the regulatory definition. Another argued that if a portion of a vertically integrated company is subject to cost recovery pricing, the definition is satisfied. Two.said that if a plant sets its own rates for electricity, the definition is satisfied.
One commenter rejected the NRC's emphasis on an operator's satisfying the definition of utility, and argued that the emphasis should be on the financial viability of the entity responsible for decommissioning the unit.
Resoonse.
Consistent with the position taken in the ANPR, the NRC is proposing to revise its definition of " electric utility" to introduce additional flexibility to address potential impacts of electric industry deregulation.
The Commission notes that the key component of the' revised definition is a licensee's rates being established either through cost-of-service mechanisms or through other non-bypassable charge mechanisms, such as wire charges. non-bypassable customer fees, including securitization or exit fees, by a rate-regulating authority.
Several States are considering deregulation of future operations of nuclear power plants so 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 that 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 Comission's regulations to which those
i portions of costs pertain.
For example, if a licensee were able to collect 40 percent of its decomissioning costs through rate-regulated activities, such as traditional cost of service regulation or use cf non-bypassable charges, the remaining 60 percent of the costs would need to be accounted for in a manner consistent with methods acceptable for a licensee other than an electric utility.
In this proposed rule, the definitions of several relevant terms are also provided for the first time in S 50.2.
It is noted that some commenters misinterpreted the intent of the existing definition of " electric utility" with respect to entities that e.stablish 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 and other costs. This is consistent with the NRC's draft policy statement.
C.3 Assurance 00tions 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 rote-setting State or Federal body.
Full Uo-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 _______ ______ _ __________________ - _____________ -
comenters reminded NRC that' deregulation does not inherently mean a total lack of regulation er a lack of cost recovery.
One commenter believed NRC should, at the time _of restructuring, require only an assurance level comensurate 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 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 comenters, and others, 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 decc..nissioning in contracts for the plant's output or in the transmission or distribution charges of the licensee or its affiliate if the charges are assigned to the licensee or its decomissioning fund and exit fees charged against customers leaving the system. A few comenters 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
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E others would allow assurance through a plan for gradually recovering decommissioning funds via rates and prices, even for dereguiated entities.
E Others argued that_NRC should offer the utilities flexibility and that each situation should be assessed on a case-by-case basis if and when it occurs.
4 i
Timina of Rulemakina.
With regard to the timing of the-rulemaking, a few commenters support prompt NRC regulatory action to ensure that-adequate financial assurance is in place prior to restructuring, before waiting further.
I to learn exactly how the industry will develop.
Several other commenters.
however, believe that rulemaking is premature until more is known about 2
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 nuclear 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.
Added Assurances for Safe Ooeration and Decommissionina.
Many comenters voiced opposition to the ANPR's query regarding whether the NRC
- should require additional assurance for adequate funds for safe operation and decommissioning in anticipation of deregulation.
One commenter argued that _
additional assuranc'.ts in this area may not add to or strengthen the obligation already imposed by the terms and ccnditions of the license.
Others reasoned it unnecessary. given other existing.NRC requirements and FERC's framework for recovery of stranded costs, including decommissioning.
Only one comenter supported additional assurance for safe operation and decommissioning in anticipation of deregulation.
3 Joint liabilitv.
In response to the ANPR's query regarding newly created organizations or holding companies being held jointly liable for 4
decommissioning costs, four commenters supported the idea because of the added assurance it would provide. Three commenters would consider requiring joint
' liability on a pro rata basis, possibly taking into account the remaining years of licensed life. One commenter cautioned that jointly liable parties may disagree on decommissioning methods (e.g.. prompt vs. deferred) because of the cash flow implications.
Numerous other comenters 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 tI these commenters suggested that joint liability could be acceptable if it were an optional method of financial assurance.
One comenter stated that new owners and operators should have to assume the responsibilities and liabilities of the previous owners and operators.
'The concept of joint liability is defined in Black's Law Dictionary (4th Ed.) as:
One wherein joint obligor has right to insist that co-obligor be joined as a codefendant with him. that is, that they be sued jointly.
Another' stated that the financial assurance obligation should follow the owners and operators, whether regulated or unregulated, who have incentives to i
properly manage'and operate the units.
Imoacts.
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 reorganization, aggravate potential stranded investment create additional problems for utilities, ratepayers, or taxpayers at a time when competitive forces are already causing economic concerns.
Examples of such p'roblems would include the difficulty for affiliated businesses to raise 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 premature shutdown.
Response. The Commission is addressing most of these coments by revising the definition of " electric utility" and by instituting a reporting requirement. As to the issue of requiring full up-front funding in advance of deregulation, the-Commission agrees with the commenters that such a requirement would be overly burdensome if applied to all licensees. However.
given the proposed change to the definition of " electric utility" in 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 decomissioning funding assurance requirements of S 50.75(e)(2) unless that licensee can otherwise conclusively demonstrate a - ___
government-mandated, guaranteed revenue stream for all unfunded decomissioning obligations.
The options contained in that section include I
prepayment: an external sinking fund coupled with a surety method or insurance for any unfunded balance; or a surety method, insurance, or other guarantee method.
The Comission emphasizes that the changes to the definition of
" electric utility" introduce additional flexibilitv to address deregulatory developments. Thus, the NRC would expect licensees to be ELr_e likely to continue to qualify, in whole or in part, as electric utilities under the revised definition. Although licensees who no longer qualify, in whole or in part, as electric utilities could encounter difficulties in securing alternative decomissioning funding experience to date indicates that PUCs and FERC are addressing decomissioning costs through various recovery mechanisms.
The timing of the rulemaking was addressed in the response to coments in section A of this notice. Any additional rulemaking in this area would result from experience gained from industry and regulatory actions.
As several of the comenters stated, the NRC has the authority to approve or disapprove any transfer of. license related to a merger or reorganization.
Section 184 of the Atomic Energy Act of 1954, as amended, and 10 CFR 50.80 provide that control over a license may not be transferred, directly or indirectly, unless the Comtr..ssica consents to such transfer in writing.
The regulations do not explicitly impose joint liability on co-owners and co-licensees. As stated by some comenters, joint liability may create problems with respect to potential disagreement on decomissioning methods, the inhibition of flexibility, the weakening of competitive position and the difficulty in implementation.
Also, as some noted, joint liability may not be
[
needed. The new owners and' operators should assume the obligation to safely operate.the facility and assure adequate funding for decommissioning, as they have the incentives to properly manage and operate the units.
More
^
importantly, however, is the fact that with the proposed modified definition of " electric utility." restructured entities would either have to have
- [
adequate coverage of decommissioning funding obligations through some non-bypassable cost recovery mechanism or would be required to provide the types j
of up-front assurance described in S 50.75(e)(2). Those licensees who remain i
utilities would have the funding assurance provided through being rate-regulated under S 50.75(e)(3). The Comission considers this level of i
assurance to be adequate and therefore sees no need to impose an additional
[
regulatory obligation of joint liability on co-owners or co-licensees.
[
Lastly, with respect to the question of impacts, the Comission has considered the comments relating to potential impacts in arriving at the positions taken.
The Commission understands that financial assurance would place a burden on licensees that may affect their competitiveness in a deregulated environment. The Comission 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 accomodate 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 difficult to both finance up-front decomissioning funding and operate a nuclear power plant safely.
These newly formed companies may not be good candidates for nuclear power plant ownership. -
~
J C;4L Financial Test Qualifications About half the commenters flaily opposed requiring licensees--to demonstrate financial assurance by satisfying minimum standards of _ net worth, cash flow, or other fin 6ncial measures.
Many.of the commenters, including-NEI and four commenters who adopted the NEI position, argued that such a test was not necessary or appropriate.
If NRC is concerned about the financial condition of a particular licensee.
three comenters said, an individualized case-by-case review would be more appropriate.
Some comenters said that financial measures appropriate for investor-owned utilities would at 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 assets in the nuclear generating-facility, they cannot meet a test with a tangible net worth requirement of ten times the current decomissioning costs.
but this does not mean that they cannot satisfy their financial obligations.
A non-bypassable charge 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 among owners, and should not discriminate against one class of owners, and should not be applied as a static one-time requirement.
Other suggestions included a requirement that a firm demonstrate that it had
" ample Mrgins, subsequent to restructuring" to cover funding contributions or to cover decommissioning costs in the event of a premature shutdown. Another
' suggested cisclosure standards, developed through the Financial Accounting
. Standards Board, for use in annual reports and 10-K filings, that would be reviewed by Federal regulators..Still another argued that ceasures of market 4
29 i
4
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 abiiity to support decommissioning along with an assessment of the utility's competitive situation.
Determining whether a utility had minimufn cash flow sufficient to maintain its plants in a non-operating, interim stage prior to decommissioning. and the period of time the utility could sustain such cash flows, was suggested by one comenter, One comenter suggested using a financial test as an indicatcr, from which 'a Federal agency could-determine that the utility needed assurance of continued rate recovery of the decomissioning obligation.
Only two commenters endorsed a test of financial stability as a financial test qualification. One pointed to assets sufficient to fund an imediate decomissioning, or a minimum level of financial stability (measured through investment grade securities) or insurance. or a surety to cover decomissioning costs as three potentially acceptable mechanisms. The other 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 r'equirement.
Response.
With the proposed revision of the definition of " electric
. utility," licensess who no longer meet the new definition will need to comply
-with the requirements of 5 50.75(e)(E). which describes the acceptable methods of financial assurance for decommissioning for a licensee other than an electric utility. These methods are flexible and contain at least four major categories of acceptable methods to ensure funding for decomissioning as __
.... _ _. -. - - - ~. - -
identified in the previous responce.
Few commenters offered insights on other potential test qualifications, although several-stated that the financial structure of utilities means that meeting the criteria in 10 CFR Part 30 could be problematic.
The NRC would need to conduct additional research and analysis to determine which additional financial measures would be most useful and appropriate if a financial test requirement for parent or self-guarantee were pursued.
Criteria could be identified and thresholds developed, but -
evolution of the industry might mear that the criteria would become outdated and misleading relatively quickly.
Hence, the Comission will continue to evaluate this issue, but is not presently offering any changes to its financial test criteria.
C5 PUC/FERC Certification Only two commenters gave unequivocal support to the idea of requiring i
PUC/FERC certification. One encouraged NRC to undertake direct dialogue ou i
certifications 'with the appropriate PUCs and FERC: the other stated that PUCs and FERC must undertake such certifications and that NRC should impress upon them the importance of doing so. A few PUCs, in the opinion of this l
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 decomissioning funding problem in the transition to competition, with or without certification, but one went on to say that certification would probably be unnecessary. Of these, six adopted the NEI position, which was that without new Federal legislation it would be difficult to require legally binding certification l
from PUCs or FERC.
Requiring a licensee to obtain such certification would,
place it.in noncompliance, with no way of achieving compliance.
If a licensee did obtain certification, however, NEI 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 decomissioning funds.
NARUC and several PUCs either opposed the idea or expressed strong reservations about it.
NARUC noted first that no current commission can bind a future commission at either the Federal or State level.
However. NARUC was confident that State PUCs would examine the causes of underfunding, if it occurred, and seek remedies.
A PUC stated that it might not have the authority to certify that nuclear plant licensees under its jurisdiction would be allowed to collect decomissioning funds through rates after restructuring, and 'nther PVC similarly stated that it could not give a blanket guarantee that all licensees would be allowed to collect revenues to complete decomissioning funding. A third PUC stated that no current comission could legally bind a future comission, so it could not identify an effective form of certification. Another PVC also expressed doubt about how certification woulu change current procedures, in which PUCs can adjust rates based on the cause for and the prudence of the underfunding.
A different PVC noted that, in the past, ratemaking authorities had allowed recovery and expected them to act in the future in the same way, but could not be certain that they would issue certifications. Another PUC stated that it already has and would maintain authority to ensure that utilities collect sufficient funds for decomissioning.
One comenter pointed out that FERC has jurisdiction only over rates for wholesale sales of power. Over 80 percent of decomissioning costs are recovered through rates for retail power sales, over,
l 1
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 competition and evolving antitrust law. A
-public interest group had questions about whether PUCs and FERC could certify, but in any case thought NRC should concentrate instead on the licensees.
Another commenter noted that since a significant portion 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 coul' be the basis of an action by a PUC to modify the rates.
The final set.of comenters argued that the question of certification was one that the PUCs and FERC should determine.
Response.
The Comission does not plan to implement certification by the State PUC's or FERC because of the reasons given in many of the comments outlined above.
Although " certification" initially appeared to the NRC to be an option meriting further consideration, since experience to date has indicated that PUCs and FERC are addressing decommissioning funding assurance through more viable mechanisms, the NRC is not pursuing this option further.
C.6 Imoact of Accelerated Fundino 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 funding would not create a large financial burden on either licensees or ratepayers. The Public Utility Comission of Texas reported analysis for three Texas 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 their decomissioning 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 funding noted that unless the Internal Revenue Service changed its rule on the deductibility of payments into the decomissioning trust fund, the accelerated payments would not be deductible. The NRC was urged to encourage the IRS to change the rule.
L Almost three-quarters of the commenters opposed accelerated funding of
' decommissioning. Their arguments against the idea stressed (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 supply in an accelerated payment would depend on the age of the plant and the amount it had previously paid in the its decomissioning fund. The financial marketplace, rather than regulation, should determine the speed with which :
. m..
')r I
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 sharaholders-should bear the burden of decomissioning costs, but would not do so under accelerated funding.
Other commenters argued that accelerated funding would
~
shift the costs of decomissioning onto current ratepayers from future ratepayers.
Commenters believed accelerated funding would lead to cash flow problems for licensees and could result in increased borrowing to cover cash outlays. Accelerated funding could lead to the shutdown of marginal l
facilities. which would be contrary to the intent of the policy and lead to additional shortfalls of decommissioning funding.
One comenter argued that the amount of decomissioning-funding that will ultimately be required is too uncertain to be collected through accelerated funding.
Resoonse. The Commission continues to be concerned with.the availability and efficacy of financial assurance mechanisms for i
decomissioning for those licensees whose rate regulatory oversight by FERC or the State PUC's is substantially reduced or eliminated.
Under the NRC's
. current regulations (and as proposed to be modifiea in this rule). licensees who no longer meet the definition of " electric utility" may use fincncial assurance mechanisms for decomissioning as defined in 10 CFR 50.75(e)(2),
includ'ng (1) prepayment: (ii) an external sinking fund coupled with a surety method or insurance: (iii) a surety method, insurance, or other guarantee method. including parent company guarantees and self guarantees coupled with
\\
financial tests: and (iv) in the case of Federal, State, or local licensees, a statement of. intent..
The-Commission is concerned th'at these financial assurance mechanisms may not be available to some licensees and is thus asking for additional comment on alternative methods of financial-assurance that would provide assurance equivalent to that already provided under the Commission's egulations.
For example, in the advance notice of proposed rulemaking, the 3
Commission raised the issue 'of whether requiring the acceleration of decommissioning funding over a sho'rter period of-time (e.g.,10 years) than l
the period of the operating license would provide an equivalent level of assurance to current allowed mechanisms. As discussed above, most commenters l
stated their opposition to accelerated decommissioning fundir).
However, this j
opposition appeared to be predicated on the assumption that the NRC would i
_ require accelerated funding for all power reactor licensees, and not only those who no longer met the definition of " electric utility." Thus, the Commission is asking for additional coments on whether this, or some ^5er equivalent assurance mechanism, should receive additional consideration in this rulemaking for those entities which would not be classified as " electric
-utilities."
C,7 Potential Shortfalls-from Underestimates of Costs Comenters suggested a range of responses to decommissioning shortfalls occurring as many as 50 years into the future, after a period of safe storage.
None, however, clearly identitwd 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, inclu:ing accumulated industry experience. -
4-l application of new technologies, and reductions in the ultimate disposal volumes of decommissioning wastes.
They also suggested that periodic re-estimates of decommissioning costs and adjustments to the rate of 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.~ggested that the NRC should 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 five years with more frequent reviews as license termination approaches.
The Utility Decomissioning Group predicted that shortfalls would be unlikely to arise suddenly or to be drastic. Two utilities also suggested that periodic reviews of cost estimates. coupled with increased collections as necessary.
L would remedy underfunding. Two other commenters made only the general statement that current procedures would be adequate, and any shortfalls should
- be handled through appropriate funding mechanisms.
'Some commenters recognized that the problem of underfunding arising
' after the safe storage period could 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 solution would be to delay decommissioning activities to allow the decommissioning fund to accumulate 9dditional 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 strategy that W ald ensure that the decommissioning fund earned at least the rate of inflation measured by the consumer price index (CPI), and that NRC could require the-utility to place additional money into the fund if necessary.
Several comenters recommended approaches to the problem that inv01ved PUCs. Two suggested that underfunding would be remedied by application to the PUC. One suggested such PUC 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 shcrtfall would not occur until after several-years of competition. This-comenter suggested that a wires charge =could be used to ensure that such shortfall $ did not occur.
Diree comenters 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 comenters argued that the causes of the shortfall 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 decomissioning funds are insufficient. Alternatively, if the utility management is not responsible, customers should
Dear 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. 1
None of the comenters recommended increasing contingency factors to provide for potential shortfalls far in the future.
Several argut.d that contingency factors are intended to address " unforeseeable cost elements" or that contingencies are inappropriate for some other reason.
The size of such contingencies would be too arbitrary.
In addition, some State PUCs would not apply larger contingencies, particularly since the current cost estimates already contain a significant contingency factor.
Finally, one comenter argued that larger contingencies would lead to over collection and distortion of prices for electricity.
Seven comenters joined NEI in taking a position against the use of contingencies to address the problem of potential shortfalls occurring far in the future.
Response. The Comission sees its proposed reporting requirement as a way to keep informed of licensees' decomissioning funding status and potential underestimates of cost, Howevt.. the Comission has undertaken a study to analyze the actual costs incurred by the p wer reactor licensees that are in the process of decomissioning, and the Comission will act accordingly after studying those results.
Further, the Comission has the authority to require power reactor licensees to submit their current financial assurance mechanisms for NRC review, revision at necessary, and approval.
The Comission reserves the right to take the following steps in order to assure a licensee's adequate accumulation of decomissioning funds:
review, as needed.
i the rate of accumulation of decomissioning funds; and either independently or in cooperation with either the FERC and the State PUC's, take additional actions as appropriate on a case by-case basis. including modification of a lleensee's schedule for accumulation of decomissioning funds.
39 -
C,8 Caotive Insurance Pool The idea 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 that, in fact, the mechanism would more nearly resemble a mutual insurance pool, and listed a number of factors.
including the size of premiums, when deregulation occurred, Federal mandates, the ability to recover costs, and the attitude of participants, that would determine success.
Several commenters responded that if such a pool could be developed, it would be a useful or constructive mechanism.
NEI and six comenters taking the same position expressed doubts about the usefulness of such a pool, but suggested that the industry should examine it.
They argued that in addition to an insurance pool, NRC_should also consider approving self-insurance as an option.
Almost half the commenters expressed strong doubts about the insurance concept.
No such product currently exists, 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.d 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 is not mandatory, then the worst risks will 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 until 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, once a loss has occurred, and the intentional destruction of property.
U.S. Nuclear Regulatory Comission, " Design, Costs, and Acceptability of an Electric Utility Self-Insurance Pool for Assuring the Adequacy of Funds for Nuclear Power Plant Decomissioning Expense," NUREG/CR-2370. Dect ber 1981.
i - -
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 settirig would be difficult because of the possibility that 'Jtilities that had been prepared to pay their decomissioning costs would be reluctant to subsidize utilities that had not, 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 decomissioning costs through rates in reliance on the pool. Some utilities might underestimate their decomissioning costs, to keep their premiums low. A pool would increase costs of electricity because, in addition to decomissioning costs, insurance premiums would need to be recovered, Finally, one serious decomissioning shortfall might deplete the t
pool.
Other comenters stated flatly that they opposed the concept.
Several said that it raised the problem of insuring against an event 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 decomissioning assurance, burdening responsible utilities with high insurance premiums.
Some comenters argued that licensees demonstrating strong financial capatility should not be required to participate.
Reinsurance and diversification to larger pools would make better policy, in the view of one commenter, Resoonse. The Comission recognizes the problems associated with the concept of a captive insurance pool as identified by the above commenters, and,
believes that they are serious enough to eliminate this option from further consideration. The Comissio'i is also of the opinion that those in favor of this option do not offer sufficient evidence that the identified problems can be overcome.
C.9 Other Ootions for NRC in Case of limited Role for PVC or FERC Comenters suggested a wide variety of financial assurance options for NRC to consider if PUC or FERC oversight is limited or eliminated. One 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 fin 6ncial strength such as ownership of other revenue-producing assets (e.g..
electricity transmission and/or distribution and/or natural gas operations).
Another relevant factor could be whether the licensee has insurance for premature decomissioning caused by an accident. One comenter stated its opposition to the use of surety bonds and insurance because of cost and limited availability.
Two utility comenters suggested that regulatory approaches include mandated or allowed stranded cost recovery through a charge on distribution or transmission or some other charge on all electric power or energy sales.
regulatory certification that such costs will be recovered, and other arrangements involving regulatory control such as priority dispatch for nuclear units. Another comenter suggested that NRC could request FERC to clarify Order No. 888 to make certain that competitive access or other transmission charges intended to recover stranded ccsts also include a load-proportionate contribution to fund decomissioning costs.
Another comenter.
--.._-.--.___.m_
9 stated that NRC and FERC should urge Congress to adopt stranded cost legislation that will ensure recovery of decomissioning costs as the most prudent solution.
The comenter specifically advocates a wires charge that would include decomissioning costs.
One commenter asked NRC to consider its actions in the event that a licensee enters into bankruptcy.
In such a case, the NRC could enter the proceeding and argue that full funding for decomissioning must be fulfilled as the first priority.
The comenter also asked NRC to consider proposing legislation that would amend the Bankruptcy Code to give first priority to nuclear decomissioning costs, as the Supreme Court has already held for hazardous waste cleanup costs.
NEI and several other commenters raised the possibility that NRC could 5
rely on the Financial Accounting Standards 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 comenter, 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 strength of the utility, the size c:' the remaining unfunded obligation, the age of the plant, and other factors 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 comented 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.
43 -
t approaches, either 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 mechanisms 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 responsible nuclear decomissioning.
Another called for financial assurance to be mandated at the Federal level, and a third said NRC should consider whether DOE responsibility can be developed for providing solutions to decomissioning.
Four commenters said no other options were necessary.
They reasoned that current options are sufficient irrespective of PUC or FERC oversight.
regulatory oversight is unlikely to be curtailed. and FASB standards and competitive pressures will provide sufficient assurance.
Response.
The Comission believes that additional consideration of accelerated decommissioning funding or other alternative financial assurance mechanisms may be warranted, as discussed in its response at C.6.
In addition, it should be pointed out that the Comission enters bankruptcy proceedings to protect the integrity of the decomissioning funding, as suggested by a commenter. Also, the Commission is proposing use of the FASB standard as a means for the reporting decommissioning obligations.
- Further, 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 decomissioning under deregulation.
Further, the
j-proposed reporting requirement will provide the NRC with the opportunity to be l
informed on the,,tatus of licensees' financial assurance for decommissioning.
i D.
Federal Government Licensee Use of Statement of Intent j
Slightly fewer than half of the comenters (20 commenters) expressed an opinion on this question.
Almost all comenters took the position that Federal licensees should be treated in the same way as non Federal licensees.
i NE! argued that regardless of who owns the plant, a number of options for 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 i
regaired to set aside funds rather than rely on statements of intent.
Several j
commenters pointed out that different treatment for Federal licensees could l
create competitive advantages for the Federal licensees.
NRC should ensure that the playing field remained level.
One licensee argued that if a financial assurance option, such as a statement of intent, meets NRC's criteri 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 means that the taxpayers are providing the assurance.
One licensee questioned the long-term
.rinancial condition of the Tennessee Valley Authority (TVA).
One commenter argued that use of tax exempt bonds provides a similar competitive advantage-l 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 I E m
._.7-7 --
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to use an external trust. "all requirements" contracts, and its power to issue indebtedness to ensure its decomissioning costs.
Response.
The NRC's Office of the Inspector General published an Audit Report. "NRC's Decommissioning Financial Assurance Requirements for Federal Licensees May Not be Sufficient." OlG/95A-20. dated April 3.1996.
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 be 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 report also found "...that.'although not required. TVA has established a fund dedicated to meet its decomissioning obligations.
However, because this is an internal fund it can be used for other purposes.
In fact. TVA had at one time temporarily depleted its decommissioning fund."
The majority of those who comented were opposed to allowing the TVA's use of a statement of intent, their reason basically being that all licensees should have the same " level playing field." The Commission, however, does not believe that the elimination of the statement of intent option for a Federal licensee can be justified on a public health and safety Dasis. The Comission believes that the risk of a Federal licensee not being able to fund its decomissioning expenses is remote, as the Comission is proposing to define a
" Federal licensee" as having the full faith and credit backing of the Federal Government. The Comission considers the issue of whether TVA qualifies for the use of a statement of intent to be distinguishable from the question of l
whether other " Federal licensees" should have this option.
Further the Comission does not believe it to be in the public interest to foreclose the possibility of a future licensee with the full faith and credit backing of the i
Federal Government using a statement of intent. Hence. the Comission does not propose to eliminate the statement of intent as an option for Federal licensees. but realizes that this propased definition may result in the TVA no longer being able to meet NRC's definition of
- Federal licensee."
E.
TRUST FUND EARNINGS CREDIT FOR EXTENDED SAFE STORAGE PERIOD Two comenters opposed credits 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 decomissioning.
Seventeen commenters. however supported allowing credit for earnings on funds during extended storage periods.
Some of these commenters argued that if credits for earnings are not allowed. more funds than necessary would be collected thereby generating unwarranted expense for licensees and customers and possibly intergenerational inequities.
An additional eight comenters supported allowing earnings credits, not only for the extended safe storage period but also for other periods:
e The period before safe storage, when funds are accumulated; e The decomissioning period, when funds flow out of the trusts; and o 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 comenters understood that NRC's ANPR considered a net positive rate of return when assessing the status of decomissioning funding 4
- durina a SAFSTOR oeriod, and not that a licensee would be allowed to consider
- prospectively durina the license term the possibility of a net positive rate of return over some extended period following shutdown and prior to actual decommissioning. These comenters felt that it would be largely irrelevant to start-considering positive earnings during a SAISTOR period because, by the time of termination of operations. licensees should have already accumulated 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 decommiNoning funding program because the deductions will have value for those who assume the responsibility for decommissioning.
g
-Resoonse. The Comission is proposing to allow credit for earnings and believes that its existing implicit assumption of _ a zero rate of return is too conservative and not borne out by the data.
The Commission is proposing licensees may take credit using a 2 percent real rate of-return from the time i
of the funds' collection through the decomissioning period.
As stated below, this proposed action provides licensecs relief from current requirements with no adverse impact on public health and safety, licensees, or-NRC resources, and the proposed reporting requirements would allow the licensees'
- decomissioning funds to be monitored by the Commission.
E.1 Real Rate of Return l
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 l ;
ratetheycanjustifygiventheirspecificsituation.
Some of these comenters supported their positions by stating that licensees employ different investment strategies depending on factors such as the number of plants, when they expect to begin decomissioning, applicable State taxes, and whether the funds are in a qualified or nonqualified trust.
Another comenter suggested that plant-specific annualized rates could be justified based on historical data.
Considerable judgment will be needed to develop the rate, I
j 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 comenters 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 rate of 3 percent as reasonable and achievable with acceptable levels of investment risk (e.g., 50 percent equity, 50 percent fixed income). Another comenter 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.
1 Two comenters opposed the use of a positive rate assumption for earnings during extended safe stcrage. arguing that earnings assumptions could I
be manipulated and that earnings could otherwise act as a hedge against increases in the cost of decomissioning.
i Response.
Based on the NRC review of historical data, real (i.e.,
inflation adjusted, after tax) rates of return using U.S. Treasury issues have been on the order of 2 percent. Therefore, 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. The NRC acknowledges that the historical data is subject to some degree of interpretation, and that a 3 percent real rate may be viewed by some as a " reasonable" measure for this parameter.
While some may propose use of higher values-based on other types of investments, the Comission believes the proposed value represents as close to a " risk free" return as possible and has increased confidence that the 2 percent value can be consistently achieved.
Higher earnings amounts will be allowed during the period of reactor operation if specifically approved by a rate-setting authority.
To the extent that earnings in a given year prove to be greater than 2 percent, the balance of the fund will be greater than anticipated.
Licensees may take this higher balance into account in calculisting subsequent contributions to their sinking funds.
This means the size of subsequent contributions will decrease, even though these subsequent contributions will still be based on a 2 percent earnings assumption.
If rates turn out to be lower than this.10 CFR-50.82 already provides that licensees are to adjust decomissioning funds during
-safe storage to reflect changes in cost estimates. Thus, there is little risk that there will be major shortfalls in decomissioning funds. Further, the proposed reporting requirements will allow the licensees' decomissioning funds to be monitored by the Comission.
E.2 ADorooriate 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:
e The period before safe storage, when funds are accumulated, o The decomissioning period, when funds flow out of the trusts.
e 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 decomissioning cost estimate.
Four commenters, all PUCs or PUC groups.. felt NRC should leave the issue of the length of the period to the States.
Only two commenters suggested that credit be limited-to a fixed number of years.
One of these suggested 10 years. The other proposed a maximum of i
2n years, and a minimum of 5 years.
Two comenters opposed the use of positive earnings assumptions during Any period, arguing that earnings assumptions could be manipulated and that earnings could otherwise act as a hedge against increases in the cost of
- decommissioning.
Response. The Comission proposes to allow licensees to take credit for earnings on external sinking funds from the time of the funds' collection through the decomissioning period.
Because the NRC is requiring the funding.
it is reasonable for the NRC to provide for a positive rate of return on the colk.cted funds, where justified.
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 decomissioning period.
Again, the proposed reporting requirement provides the NRC with the ability to monitor licensees' decomissioning funds.
Lastly, tnis proposed action provides licensees relief from current requirements with no adverse impact on public health and safety, licensees, or NRC resources.
F.
REPORTING ON THE STATUS OF DECOMMISSIONING FUNDS Many comenters 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 deregulation to correct the flawed assumption that PUCs and FERC actively monitor-decomissioning funds. The comenter stated that PUC and FERC monitoring efforts are, in most cases, limited in scope and may take place infrequently (i.e., when a rate case is filed).
Each PUC is generally concerned only about its jurisdictional portion of the decomissioning funds. - - - _ - - _ _ - - _ - _ _ _ - _ - _ - _ - _ _ _ _
and FERC's jurisdiction is limited to only the wholesale portion of a company's sales. Moreover, many States do not have jurisdiction over 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 decomissioning.
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 I'UC oversight is limited or eliminated. NRC should assume oversight of decommissioning funds.
Response. The Comission is proposing that a periodic reporting requirement be implemented so that the Commission has appropriate assurance that licensees are collecting their required decomissioning funds. The benefits of obtaining this information through a reporting requirement, in terms of both determining licensee compliance with NRC decomissioning funding regulations and responding to Congressional and other requests, outweigh the minimal impact of the requirement and vnuld be less burdensome to licensees and the NRC than relying on the existing NRC inspection process.
F.1 Contents Three comenters stated that reporting requirements would be unobjectionable if they were minimal and limited to material of the nature _
4 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 remost of long-lived assets.
Five comenters 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 i
facility has multiple owners, one consolidated report would be prepared with separate data for each owner attached.
On the other hand, one commenter l
argued that reports should be based on the licensee's interest in the nuclear unit and D01 on a total unit basis.
Dre group of. innenters stated that NRC could make the annual reports fron.' plant operators available to the public, which would be consistent with the availability of information required under proposed FASB standards.
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 the following general headings: Decomissioning Costs and Activities. Contributions Trust Status _and Activity. Other Financial Information, and several Hiscellaneous Items.
Respen_se. The Commission is in the process of issuir.g a draft regulatory guide on this proposed requirement which would endorse FASB draft standard No. 158-B, " Accounting for Certain Liabilities Related to Closure or Removal of_ Long-Lived As ets." The NRC is endorsing this draft FASB standard as a means of providing guidance for licensees to comply with those_ portions 54 -
f I
of the NRC'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 oro - to remain consistent with generally accepted accounting principles. The NRC believes that the FASB standard would, if adopted, provide the required information.
However, because of the ambiguity in the FASB standard with respect to whether the required information will be reported on a per-unit basis, the NRC has defined its reporting requirement to include such per unit information.
The NRC has reviewed the proposed contents of the reports on decomissioning funds to ensure that the needs of the agency are balanced versus the time constraints of the licensees in assembling the reports. The Commission is also proposing to require that any modifications to a licensee's external trust agreement also be reported.
F.2 Freauency Several comenters stated that licensees should report on the status of decomissioning 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 more frequently than every 3 to 5 years.
NEI noted that SEC rules and proposed FASB standards require utilities to disclose the decommissioning costs in financial statements.
Two comenters suggested reporting at 5-year intervals.
One of these suggested that interim status reports _could be required on an annual basis.
One commenter stated that NRC should require no more frequent reporting beyond FASB requirements.
Another commenter stated that reports should be no less frequent than specified by the Securities and Exchange Act of 1934..
e i
I
'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 that the timing of required reports 3
should parallel that of other reports such as FERC Form 1. SEC 10 K and annual financial reports.
Similarly, tw comenters felt that annual reports i
should be caused by NRC by September 30 of the following year. Two comenters l
stated that interim reports could be required for significant events (e.g.,
j merger, acquisition, financial deterioration).
This commenter also suggested i
that limited or negative growth of the fund in a given year due to overall market _ conditions should nat automatically trigger adjustments to funding i
levels but rather that a 3 to 5-year time frame should be used.
4 j
Response.
The Commission is proposing that every licensee submit its j
initial report on the status of decomissioning funds to the NRC within 9 months after the effectise date of this rule, and at least once every 2 years thereafter.
Annual submission is not being proposed as an option because the NRC believes it can adequately review licensee financial assurance status for decommissioning biennially while reducing licensee reporting burden. However, the licensee (s) of any plant that is within 5 years of its planned end of operation would be required to submit its report annually.
J G.
COMMENTS ON TOPICS NOT SPECIFICALLY RAISED IN THE ANPR Comenters suggested several actions that NRC had not asked about specifically in the ANPR. First, a comenter stated that NRC should require sites-to be decommissioned to " green field" status, consistent with FERC guidelines. -
Resoonse.
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 longer a health and safety concern preventing the NRC license from being terminated.
A comenter suggested the imposition of a mandatory insurance requirenient for licensees to cover fund shortfalls at the time of premature decommissioning in States where accelerated collectivn from ratepayers and intergenerational subsidies are not allowed.
l Resoonse. 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 " Draft Policy 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 hetlth and safety." The Comission believes that there are enough alternatives available to address the potential problems caused by premature decomissioning so that mandatory insurance would not be required.
One comenter stated that the requirements for subaccounts should be waived. Their position is that licensees that have contributed monies to a single trust fund for multiple decommissioning-related purposes be required simply to demonstrate to the NRC that there are or will be sufficient assets in the trust fund, in the aggregate, to pay for the NRC-defined _
decommissioning cost of the nuclear unit and for any other demissioning-related purposes identified in the trust agreement.
Resoong. The Comission is not concerned with the details of how a licensee keeps accounts for decomissioning as long as a licensee is able to demonstrate, on a per-unit basis, the amount of funds identified and available for the required decommissioning purposes. Thus, the Comission accepts the commenter's position in general, although it notes that there is no current requirement, only guidance, relating to the use of subaccounts.
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 plants were financed with bond indentures or other instruments that limit the owner's ability to sell the plant or impose conditions on such sales, these restrictions would need to be identified in the process of identifying well-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 decomissioning fees that _have been collected.
The Federal Government would restart ar.y plant it believes can continue as a source of power and will decomi.ision the others from public funds.
1..
Resoonse. The Comission does not see its position as one to force a licensee to sell its plant. While the NRC does aggressively attempt to identify poorly performing plants through such processes as the " Watch List,"
the decision as to whether another entity should become the operator of a l
facility is for the owners of that facility to make. Although the NRC would have to approve any transfer of control over any pcwer plant license under Section 188 of the Atomic Energy Act and 10 CFR 50.80. the NRC is reluctant to become invtived in the business decision making processes of the licensees on such matters.
As to the NRC taking over poorly performing plants, the Atomic Energy Act confers "takeoter" aethority on the NRC only in extremely limited circumstances. Sgg Section 108 of the Atomic Energy Act (42 U.S.C. 2138) limiting such authority to circumstances where "...the Congress declares that a state of war or national emergency exists...."
A commenter stated that the NRC should develop a reliable,' sound
)
estimate (or inethod of estimating) decommissioning costs, and should upde'e the estimates or a regular basis to incorporate technological and other changes.
Resoonse.. The Comissf on is planning to revise it.. estimates of decommissioning costa after it obtains actual plant-specific data from ongoing decommissioning projects.
l Another commenter stated that NRC should sponsor technical conferences on decommissioning so the pace of technological resolutinns for cleaning up and decommissioning plants could be increased.
Resoonse. While the proposed action is not a suggested rulemaking, the 4
Commission is taking the suggestion under consideration..However, the l
Commission is aware of a number of deregulation and decommissioning conferences that have been held or are being planned.
l A commenter stated that the NRC should ask separately about other financial issues because changes to the definition of " electric utility" could have implications in contexts other than decomissioning, such as general 1
financial qualifications reviews fnr initial licensing and related license amendments, from which utilities are now 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 Part 50 to be consistent with the proposed change in the definition of "electr'ic utility."
A commenter stated that NRC should delay action as the Texas PUC has initiated three regulatory investigation projects focusing on the restructuring 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.
Resoonse.
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 Comission wishes to prepare for any new types of nuclear power generating licensees resulting from the 4
4 States' actions.
However, the Commist..on is well aware that this proposed rulemaking may not be the last action for it to undertake in this area.
One commenter stated that the Comission should support revisions to Internal Revenue Code Section 468A regarding deductibility for contributions to an external fund.
Response. The comenter does not make a suggestion as to what should be done in this rulemaking.
Rather, the suggestion goes to questions regarding consideration of w'1 ether any changes to the U.S. Code are needed to address decommissioning financial assurance, in particular any changes to the Bank-ruptcy Code. This matter will be addressed separately by the NRC as part of its input to an inter agency review process for the development of proposed legislation.
Lastly, a commenter stated that the NRC should hold all licensees to the same high standard for assurance of decommissioning funds.
Previously, the NRC had one standard for non-utility licensees and 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.
hesoonse. The Comission 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 Comission believes that those entities that no longer meet the proposed definition should be requirect to meet the more " strict" standards.
The Comission also believes that most power reactor licensees would be allowed to fund decomissioning costs through non bypassable charges.
To sumarize, the Comission's underlying philosophy of financial assurance for decomissioning is unchanged.
Basically those licensees that remain " electric utilities" by the Comission's revised definition should follow the same financial assurance regulations as before.
However, the Commission believes that this proposed rulemaking provides for adequate protection in the face of a changing environment that was not envisioned when i
the existing rule was originally written.
Further with deregulation, the Comission does not believe that it would be able to identify all the potential types of licensees to which it will be exposed.
Therefore, new and unique restructuring proposals will necessarily involve ad hoc reviews by the NRC.
Further, the Comission will exercise direct oversight of such reviews to maintain consistent kRC policy toward new entities.
In addition to the proposed definition revisions, the Comission is proposing two other modifications. The first is to require power reactor licensees to periodically report on the status of their decomissioning funds and changes to their external trust agreements.
Second, the Comission is proposOg to allow licensees to take credit for the earnings on decomissioning trust funds. The Comission does not see the need to take actions proposed by some comenters that would, in its view, strain licensees unnecessarily, because of licensees
- competing needs.
SECTION BY SECTION DESCRIPTION OF CHANGES 10 CFR Part 50 Section 50.' is amended to revise the definition of " electric utilit"'
in response to deregulation of the electric generating industry. The ser cion also is amended by the insertion of definitior.s of previously undefined terms that aid in the understanding of the NRC's rulemaking position.
Further.
(
" Federal licensee" is defined, so that the characteristics of a licensee that may make use of a statement of intent as a mechanism to satisfy financial assurance requirements for decommissioning is clarified.
Sections 50.43, 50.54, 50.63. 50.73, and 50.75 are amended to replace the term " licensees" or a similar term depending on the context for the term " electric utility" to be corsistent with the proposed changes to 10 CFR 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 ccmmercial power generaMon facility.
Section 50.54(w) is amended by requiring that power reactors, as opposed to electric utilities, obtain insurance in the manner prescribed.
Section 50.63 is amended so that licensees, as opposed to the originally used term utilicies, are required to provide specific material for NRC review relating to reactor core and associated systems, Section 50.73 is amended to refer to " licensee" rather than " utility" personnel in stating the information required to be reported regarding personnel errors related to matters requiring a Licensee Event Report.
Section 50.75 is amended in three paragraphs to include the definitional change iri the reporting and recordkeeping for decomissioning planning, '
+
Section 50.75 also is amended to allow licensees to take 2 percent credit on earnings for prepaid trust funds and external sinking funds, to institute a reporting requirement for licensees on the status of their decommissioning funding and on chrnges to licensees' external trust agreements.
Electronic Access Comments may be submitted electronically in either ASCII text or Wordperfect foncat (version 5.1 or later), by calling the NRC Electronic Bulletin Board (BBS) on FedWorld. The bulletin board may be accessed using a personal computer a modem. and one of the commonly 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 on the bulletin board.
It using a personal computer and modem, the NRC rulemaking subsystem on FedWorld can be accessed directly by dialing the toll free rumber 1-(800) 303-9672. Communication 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 Henu" option from the "NRC Main Henu." Users will find the "FedWorld Online User's Guides" particularly helpful.
Many NRC subsystems and data bases also have a " Help /Information Center" option thet 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.
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4 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 Hall." 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 typing "/go nrc" at a FedWorld comand line.
If you access NRC from l
FedWorld's main nene. you may return to FedWorld by selecting the " Return to FedWorld" option from the NRC Online Mair. Menu.
However. if you access NRC at I
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 system.
i 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 Henu.
You may also access the NRC's interactive rulemaking web site through the NRC home page (http://www.nrc. gov).- This site provides the same access as the FedWorld bulletin board, including the facility to upload coments as files (any format) if your web browser supports that function.,
I For more information on NRC bulletin boards call Mr. Arthur Davis.
Systems Integration and Development Branch NRC..wnington, DC 20555, telephone (301) 415-5780: e mail AXD3@nrc. gov.
For information about the interactive rulemaking site, contact Ms. Carol Gallagher, (301) 415-6215:
e mail CAG@nrc. gov.
Finding of No Significant Environmental Impact: Availability The NRC is proposir.g to amend its regulations on financial assurance requirements for the decommissioning of nuclear power plants.
The proposed amendments are in response to the likelihood of deregulation of the power generating industry and resulting questions on whether current NRC regulations concerning decommissioning funds and their financial mechanisms will need to be modified. The proposed action vnuld revise the definition of "elet'.ric utility" contained in 10 CFR 50,2 would add a definition of " Federal licensee" to address the issue of which licensees may use statements of
. intent, and would require power reactor licensees to report periodically on the status of their decomissioning funds and on the changes in their external trust agreements.
Also, the proposed amendments would allow licensees to take credit for the earning on decomissioning trust funds.
These proposed changes could have the following effects on nuclear power reactor licensees:
(1) potentially requiring licensees who have been
" deregulated" to secure decomissioning financial assurance instruments that provide full current coverage of projected decomissioning costs (2) limiting the types of licensees that can qualify for the use of Statements of Intent to satisfy decomissioning financial assurance requirements. (3) requiring 66 -
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periodic reporting on the status of their accumulation of decommissioning
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funds, thus leading to the potential for the NRC to requb some remedial action if the licensee's actions are inadequate, and (4) permitting licensees to assume a real, %e of return of two percent per annum, or such other rate as is permitted by a Public utility Commission or the Federal Energy Regulatory Commission, on their accumulated funds. These actions are of the type focused upon financial assurances and mechanisms to assure funding for decomissioning and are 1ot actions that would have any effect upon the human environment.
Neither this action nor the alternatives considered in the Regulatory Analysis supporting the proposed rule would lead to any increase in the effect on the environment of the decommissioning activities considered in the final rule published on June 27, 1988 (53 FR 24018), as analyzed in the Final Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities (NUREG nS86. August 1988).'
Promulgation of these rule changes would not introduce any impacts on
(
l the environment not previously considered by the NRC. Therefore, the I
Commission ha d! # ned, under the Natibial Environmental Policy Act of 1969, as amended, and the Commission's regulations in subpart A of 10 CFR Part 51, that this rule, if adopted, would not be a major Federal action significantly affecting the quality of the human environment and, therefore, an environmental impact statement is not required.
No other agencies or persons were contacted in reaching this determination, and the NRC staff is
' Copies of NUREG-0586 are available for inspection or copying for a fee 4
from the NRC Public Document Room at 2120 L Street NW.
(Lower Level)
Washington, DC 20555-0001: telephone (202) 634-3273: fax (202) 634-3343.
Copies may be purchased at current rates from the U.S. Government Printing Office, P.O. Box 370892, Washington, DC 20402-9328: telephone (202) 512-2249:
or from the National Technical Information Service by writing NTIS at 5285 Port Royal Road, Springfield VA 22161.
t E e-
.--,-c
not' aware of any other documents related to co wideration of whether there l
would be any environmental impacts' of-the propose 1 action. The foregoing constitutes the environmental assessment and finding of no significant impact F
for this proposed rule.
I Paperwork Reduction Act' Statement 4
This proposed rule amends information collection requirements that are i
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 l
approval of the information collection requirements.
The public reporting burden for this information collection is estimated to average 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the i
data needed, and completing and reviewing the information collection. The U.S. Nuclear Regulatory Commission is seeking public comment on the potential impact 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 NRC 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?
Send comments on any aspect of this proposed information collection, including suggestions for reducing the burden, to the Information and Records Managernent Branch (T-6 F33)._ U.S. Nuclear Regulatory Commission. Washington.
DC 20555-0001, or by Internet electronic mail at BJSl@NRC. GOV; and to the Desk Officer. Office of Information and Regulatory Affairs NE0B-10202 (3150-l 0011). Office of Management and Budget. Washington, DC 20503.
l 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-j Register).
Comments received after this date will be 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 may 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.
Regulatory Analysis The Comission has prepared a draft regulatory analysis on this proposed regulation. The analysis examines the costs and benefits of the alternatives considered by the Comission. 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 Comission.
Washington, DC 20555-0001, telephone (301) 415-6221, e-mail bjr@nrc. gov.
The Comission requests public cumment on the draft analysis.
Coments on the draft analysis may be submitted to the NRC as indicated under the ADDRESSES heading.
Regulatory Flexibility Certification In accordance 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 Comission 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 licensing, operation, and decomissioning of nuclear power plants.
The companies that own these plants do not fall in the scope of the definition of i
1 "small entities" set forth in the NRC's size standards (10 CFR 2.810).
~ l-
Backfit Analysis The regulatory analysis for the proposed rule also constitutes the documentation for the evaluation of backfit requirements, and no separate 1
backfit analysis has been prepared.
As defined in 10 CFR 50.109, the backfit rule apphes to
... modification of or addition to systems, structures, components. or design of a facility: or the design approval of manufacturing license for a facility; or the procedures or organization required to design, construct, or operate a facility; any of which may result from a new or amended provision in the Commission rules or the imposition of a regulatory staff position interpreting the Commission rules that is either new or different from a previously applicable-staff position....
The proposed amendments to NRC's requirements for the financial l
assurance of decommissioning of nuclear power plants would revise the
' definition of " electric utility," define " Federal licensee " and add several associated definitions: add new reporting requirements pertaining to the use of prepayment and external sinking funds: impose new reporting requirements for. power reactor licensees on the status of decommissioning funding that specify the timing and contents of such reports:' and permit power reactor licensees to take credit for a 2 percent annual real rate of return on funds set aside for decommissioning from the time the funds are set aside through the end of the decomissioning-period. These proposed actions are necessary
- to ensure that nuclear power reactors provide for adequate protection of the health and safety of the public in the face of a changing environment not
-envisioned when the reactor decommissioning funding regulations were promulgated.
~Although some of the changes proposed to the regulations are reporting requirements, which are not covered by tne backfit rule, other elements in the -
proposed changes could be considered backfits because they would modify or clarify procedures with respect to (1) acceptable decommissioning funding options under various scenarios. (2) what licensees may use statements of intent 'and (3) permitted credit for real rates of return on funds set aside for decommissioning. The NRC has determined to treat this action as an adequate protection backfit, because the action is necessary for the NRC to maintain assurance of adequate funding for power plant decommissioning, particularly in the face of the uncertainties associated with electric utility restructuring and deregulation.
Accordingly, these proposed changes to the regulations are required to satisfy 10 CFR 50.109(a)(5) and a full backfit analysis is not required pursuant to 10 CFR 50.109(a)(4)(ii).
List of Subjects in 10 CFR Part 50 Antitrust. Classified information. Criminal penalties. Fire protection.
Intergovernmental relations. Nuclear power plants and reactors Radiation protection. Reactor siting criteria. Reporting and,recordkeeping requirements.
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. 553, the NRC is proposing to adopt the following amendments to 10 CFR Part 50.
PART 50--DOMESTIr LICENSING OF PRODUCTION AND UTILIZATION FACILITIES 1.
The authority citation for Part 50 continues to read as follows: -. -
O 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 emended (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 (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 U.S.C. 2235). Sections 50.33a. 50.55a and Appendix 0 also issued under sec. 102. Pub. L.91-190. 83 Stat. 853 (42 U.S.C. 4332) Sections 50.34 and 50.54 also 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 L(42 U.S.C 2237).
I 2.
In Section 50.2 the definition of Electric Utility. is revised and the definitions of Cost of service reaulation. Federal licensee, and Non.
bvoassable charaes are added in alphabetical order to read as follows:
S-50.2 Definitions.
-.... ~ -
i-l Cost of service reaulat M means the traditional system of rate regulation in which a rate regu'tatory 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.
j Electric utility means any entity that generates, transmits, or distributes electricity and that recovers the cost of this electricity through ra es'es at blished by_a regulatory authority, such that the rates are t
sufficient for the licensee to operate, maintain. and decommission its nuclear i
plant safely.
Rates must be established by a regulatory authority either directly through traditional cost of service regulation or indirectly through another non-bypassable charge mechanism.
An entity whose rates are established by a regulatory authority by mechanisms that cover only a portion of its costs will be considered to be an " electric utility" only for that portion of the costs that are collected in this manner.
Public utility districts, municipalities, rural electric cooperatives, and Stzte and Federal agencies. _ including associations-of any of the-foregoing, that establish their-own rates are included within the meaning of " electric utility."
4 Federal licensee means any NRC licensee that has the full faith and credit backing of the United States Government.._-
4 2
Non-bvoassable'charaes means those charge'. imposed by a governmental authority which affected persons or entities are required to pay to cover costs associated with operation.. maintenance, and decommissioning of a nuclear power plant. Affected individuals and entities would be required to pay those charges over an established time period.
4 3 In Section 50.43, paragraph (a) is revised to read as follows:
3 50.43 ' Additional standards and orovisions affectina class 103 licenses for commercial oower.
-(a)
The Commission will give notice in writing of each application to i
such regulatory agency or State as may have jurisdiction over the rates and services incident to the proposed activity: will publish notice of the application in such trade or news publications astit deems appropriate to give l
reasonable notice to municipalities, private utilities, public bodies, and cooperatives which might-have a potential interest in such utilization or production facility: and will publish notice of the application once each week for 4 consecutive weeks in1the Federal Register.
No license will be issued by the Commission prior to the giving of such notices and until 4 weeks after the last publication in the Federal Register.
n
t i
- 4. In Section 50.54, the introductory text of paragraph (w) is revised to read'as-follows:
p S 50.54 Conditions of licenses.
(w)_
Each power reactor licensee under this part for a production or utilization facility of the type described in Sections 50.21(b) or 50.22 shall take reasonable steps to obtain insurance available at reasonable costs and on reasonable terms from private' sources or to demonstrate to the satisfaction of-the Commission that it possesses an equivalent amount of protection covering the licensee's obligation.-in the event of an accident at the licensee's reactor. to stabilize and decontaminate the reactor and the reactor station site at which the reactor experiencing the accident is located. provided that:
~5. In Section 50.63, paragraph (a)(2) is revised-to read as follows:
s 50.63 Loss of alternatina current oower.
-(a)-
(2)1The reactor core and associated coolant, control and protection systems, including station batteries and any other necessary support systems.
must provide sufficient capacity and capability to ensure that the core is cooled and appropriate containment integrity is maintained in the event of a station blackout for the specified duration.
The capability for coping with a station blackout of specified duration shall be determined by an appropriate coping analysis.
Licensees are expected to have the baseline assumptions, analyses, and related information used in their coping evaluations available for NRC review.
6.
In Section 50.73. paragraph (b)(2)(ii)(J)(2)(ly) is revised to read as follows:
6 50.73 Licensee event reoort system.
(b) *
(2) *
(ii)
(J)
(2)
(ly) The type of personnel involved (i.e.. contractor personnel.
-licensed operator. nonlicensed operator. Other licensee personnel.)
7.
In Section 50.75, paragraphs (a)
(b). (d). (e)(1)(1). (e)(1)(ii),
(e)(3) are revised and paragraphs (f)(1), (2), and (3) are redesignated as paragraph (f)(2). (3), and (4) and a new paragraph (f)(1) is added to read as follows:
4 6 50.75 Reoortina and recordkeeoina for decommission 1;q olannino.
(a)
This section establishes requirements for indicating to NRC how reasonable assurance will be provided that funds will be available for decorrnissioning.
For pmer reactor licensees it consists of a step-wise procedure as provided in paragraphs (b). (c). (e), and (f) of this section.
Funding for decommissioning of electric utilities is also subject to the regulation of agencies (e.g., Federal Energy Regulatory Commission (FERC) and State Public Utility Commissions) having jurisdiction over rate regulation.
The requirements of this section in particular paragraph (c), are in addition to, and not substitution for, other requirements and are not intended to be used, by themselves, by other agencies to establish rates.
(b)
Each power reactor applicant for or holder of an operating license for a production or utilization facility of the type and power level specified in paragraph (c) of this section shall submit a decomissioning report, as required by 10 CFR 50.33(k) of this part containing a certification that financial assurance for decommissioning will be provided in an amount which may be more but not less than the amount stated in the table in paragraph (c)(1) of this section, adjusted annually using a rate at least ec,ual to that stated in paragraph (c)(2) of this section, by one or more of the methods described in paragraph (e) of this section as acceptable to the Commission.
The amount stated in the applicant's or licensee's certification may be based,
on a cost estimate for decomissioning the facility. As part of the certification, a copy of the financial instrument obtained to satisfy the requirements of paragraph (e) of this section is to be submitted to NRC.
(d)
Each non-power reactor applicant for or holder of an operating license for a production or utilization facility shall submit a decomissioning report as required by 10 CFR 50.33(k) of this part containing a cost estimate for decommissioning the facility, an indication of which method or methods described in paragraph (e) of this section as acceptable to the Comission will be used to provide funds for decomissioning, and a description of the means of adjusting the cost estimate'and associated funding level periodically over the life of the facility.
(e)(1)
(i)
Prepayment.
Prepayment is the deposit prior to the start of operation into an account segregated from licensee assets and outside the licensee's administrative control of cash or liquid assets such that the amount of funds would be sufficient to pay decomissioning costs.
Prepayment may be in the form of a trust, escrow account, government fund, certificate of deposit, or deposit of government securities. A licensee may take credit on earnings on the prepaid decommissioning trust funds using a 2 percent annual real rate of return from the time of the funds' collection through the decomissioning period, if the licensee's rate-setting authority does not authorize the use of another rate.
(ii)
External sinking fund.
An external sinking fund is a fund established and maintained by setting funds aside periodically in an account segregated from licensee assets and outside the licensee's administrative control in which the total amount of funds would be sufficient to pay decommissioning costs at the time termination of operation is expected. An external sinking fund may be in the form of a trust, escrow account, government fund, certificate of deposit or deposit of government securities.
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.
+
a (3) For an electric utility.1ts rates must be sufficient to recover the cost of the electricity it generates, transmits, or distributes.
These rates must be established by a regulatory authority such that they are sufficient for the licensee to operate, maintain, and decommission its plant safely. The Commission reserves the right to take the fcilowing steps in order to assure a licensee's adequate accumulation of decomissioning funds:
review. as needed, the rate of accumulation of decommissioning funds: and either independently or in cooperation with either the FERC and the State PUC's, take additional actions as appropriate on a case-by-case basis, including modification of a licensee's schedule for accumulatina of decomissioning funds.
Acceptable methods of providing financial assurance for decomissioning for an' electric utility are-
-i (f)(1)
Each power reactor licensee shall report to the NRC within 9 months after [the effective date of this rule). and at least once every 2 years thereafter on the status of its decommissioning funding for each reactor facility or part of a reactor facility that it owns.
The information in this report must include. at a minimum: the amount of decommissioning funds estimated to be required pursuant to 10 CFR 50.75(b) and (c); the amount accumulated to the date of the report; a schedule of the annual amounts remaining to be collected; 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:
and any modifications occurring to a licensee's current trust agreement since the last submitted report. Any licensee for a plant-that is within 5 years of the projected end of its operation shall submit such a report annually.
Dated at Rockville. Maryland, this day of September, 1997.
For the Nuclear Regulatory Commission.
John C// Hoyle.~
/
Secretary of the Commission.