United States General Accounting Office

GAO Report to Congressional Requesters

May 1999 NUCLEAR

REGULATION

Better Oversight

Needed to Ensure

Accumulation of Funds

to Decommission

Nuclear Power Plants

GAO/RCED-99-75

GAO United States

General Accounting Office

Washington, D.C. 20548

Resources, Community, and

Economic Development Division

B-281946 

May 3, 1999

The Honorable John D. Dingell

The Honorable Ralph M. Hall

The Honorable Edward J. Markey

House of Representatives

This report responds to your request that we review the adequacy of electric utilities’ efforts to

accumulate funds to eventually decommission their nuclear power plants after the plants have

been permanently shut down.

Unless you publicly announce its contents earlier, we plan no further distribution of this report

until 20 days after the date of this letter. At that time, we will send copies to the appropriate

congressional committees; the Honorable Shirley Ann Jackson, Chairman, Nuclear Regulatory

Commission; and the Honorable Jacob J. Lew, Director, Office of Management and Budget. We

will make copies available to others upon request. Please contact me at (202) 512-8021 if you or

your staff have any questions. Major contributors to this report are listed in appendix III.

(Ms.) Gary L. Jones

Associate Director, Energy, Resources,

 and Science Issues
Executive Summary

The estimated cost to dismantle all of the commercial nuclear power

plants in this country, dispose of the resulting radioactive waste, and clean

up the plant sites is about $30 billion dollars (in 1997 present-value costs),

of which, about $14 billion is currently unfunded. This process, called

decommissioning, is necessary because, following the retirement of a

nuclear power plant and the removal of the plant’s spent (used) fuel, a

significant radiation hazard remains. Utilities licensed by the Nuclear

Regulatory Commission (NRC) to own and operate nuclear power plants

collect money from their electricity customers to be used for

decommissioning. In recent years, the Federal Energy Regulatory

Commission and at least 18 states have enacted legislation or issued

regulations promoting competition within their electricity industries.

Competition, according to NRC, could result in economic pressures to cut

costs or electricity rates, thus affecting the availability of funds for

decommissioning.

Concerned about the potential cost to decommission nuclear power plants

and the implications of competition within the electricity industry, the

congressional requesters of this report asked GAO to determine if (1) there

is adequate assurance that NRC’s licensees are accumulating sufficient

funds for decommissioning and (2) NRC is adequately addressing the

effects of electricity deregulation on the funds that will eventually be

needed for decommissioning.

To address the first issue, GAO compared, for 76 licensees owning 118

nuclear plants, the amount of decommissioning funds that each licensee

actually accumulated through 1997 with the expected amount. Making

these comparisons required GAO to assume future economic and plant

operating conditions. GAO made baseline, or most likely, assumptions and

then, using more pessimistic and more optimistic assumptions, tested the

effects of changes in these assumptions on the results.

Background From 1959 through March 1999, a total of 125 nuclear power plants were

licensed to operate. Currently, there are 104 plants with operating licenses.

While NRC has the authority to require its licensees to assure that they will

have sufficient funds for the eventual decommissioning of their nuclear

power plants, it does not have the authority to directly regulate the

economic affairs of its licensees. Most of these licensees are

investor-owned utilities who generate electricity from a variety of sources,

including coal, gas, and hydropower and whose economic activities have

traditionally been regulated by state utility commissions and the Federal

Page 2 GAO/RCED-99-75 Nuclear Regulation
Executive Summary

Energy Regulatory Commission. Thus, licensees’ financial plans for

decommissioning are subject to the review of and approval by state utility

commissions as a part of the economic regulation of licensees’ electricity

generating and delivery systems. Traditionally, through the regulation of

electricity rates, the utility commissions allowed the licensees to include

charges for eventual decommissioning. Portions of the charges that

licensees’ customers pay for their electricity are earmarked for deposit

into funds that may be used only to pay decommissioning costs. Until

decommissioning occurs, the money in these funds is invested to earn

income.

By July 1988, when NRC began requiring licensees to provide specific

assurances that funds would be available to decommission their plants,

114 plants were already licensed to operate. At that time, NRC required

licensees to provide “reasonable assurance” that sufficient funds would be

available to decommission their nuclear power plants. Licensees must use

a formula contained in NRC’s regulation to calculate the minimum amounts

of funds to be accumulated over the operating life of each of their plants.

To provide this assurance, practically all licensees agreed to establish

externally-managed sinking funds to accumulate funds for

decommissioning.1

 Money collected from customers for decommissioning

would be deposited in these funds, invested to earn income, and then

made available when needed to pay decommissioning costs.

Results in Brief Although the estimated cost to decommission a nuclear power plant is on

the order of $300 million to $400 million in today’s dollars, NRC does not

know if licensees are accumulating sufficient funds for this future

expense. GAO’s analysis showed that, under likely assumptions, 36 of 76

licensees had not accumulated sufficient decommissioning funds through

1997. However, all but 15 of these 36 licensees appeared to be making up

their funding shortfalls with recent increases in the rates that they are

accumulating decommissioning funds. Using more pessimistic and

optimistic assumptions would increase or decrease the number of

underfunded licensees, respectively. For example, some experts anticipate

that the deregulation of the electricity industry will result in the retirement

of some nuclear power plants before sufficient funds to decommission the

plants have been accumulated. Although utility commissions have

permitted licensees to continue charging their customers for the costs of

1

The Tennessee Valley Authority elected to provide, as permitted by NRC’s regulations, a statement of

intent to fulfill its financial obligations to decommission its six nuclear power plants. However, in

December 1998, the Authority notified NRC that it had begun to use external sinking funds.

Page 3 GAO/RCED-99-75 Nuclear Regulation
Executive Summary

decommissioning prematurely retired plants, this financial safeguard

could be affected by states’ efforts to deregulate the electricity industry.

To address the movement toward deregulating the electricity industry, in

November 1998 NRC began requiring its licensees to provide additional

financial assurances if the Federal Energy Regulatory Commission and/or

state utility commissions will no longer guarantee, through the regulation

of electricity rates, the collection of sufficient funds for decommissioning.

However, one additional form of financial assurance—the early payment of

decommissioning costs—may not be practicable or affordable. Also, NRC

considered requiring licensees to accelerate decommissioning funding as a

hedge against the premature retirement of plants but rejected the concept

because of possible adverse effects on licensees’ finances. On the other

hand, NRC’s alternative methods to the collection of decommissioning

funds earlier essentially rely on the continued financial health of the

licensee or its parent company. Thus, the effectiveness of NRC’s 1998

regulatory changes will likely depend on how vigorously NRC monitors the

financial health of its licensees. In this regard, licensees must now provide

financial reports every 2 years to NRC so it can monitor financial

assurances for decommissioning. However, NRC did not establish

thresholds for clearly identifying acceptable levels of financial assurances

or establish criteria for identifying and responding to unacceptable levels

of assurances.

Principal Findings

Regulatory System Did Not

Ensure Adequate Funding

Under its 1988 regulations, NRC did not require licensees to periodically

report balances in their decommissioning funds and the rates at which

they were accumulating additional funds. GAO’s comparison between

actual and expected fund balances at the end of 1997 showed that, under

baseline assumptions, 36 of 76 licensees had not yet accumulated the

expected level of funds. These assumptions addressed such factors as the

initial decommissioning costs, cost-escalation rates, net earnings on the

investments of licensees’ decommissioning funds, and the operating life of

plants. Under pessimistic and optimistic assumptions, 72 and 8 licensees,

respectively, have not accumulated the expected levels of funds.

Although a licensee might have collected less than the expected funds for

decommissioning through 1997, increasing the annual amounts collected

Page 4 GAO/RCED-99-75 Nuclear Regulation
Executive Summary

in 1998 and subsequent years may enable the licensee to accumulate

sufficient funds by the time the licensee retires its plants. GAO compared

the amounts that licensees collected in 1997 with the annual average of the

present value of the amounts that they would have to accumulate each

year over the remaining life of their nuclear plants to have sufficient funds

to decommission their plants. GAO’s results suggest that, under the baseline

assumptions, most licensees have recently increased funding to make up

earlier funding shortfalls. For example, only 17 licensees, including 15 that

had not collected sufficient funds through 1997, are not yet collecting the

amounts that they will need to collect each year to meet their

decommissioning obligations. Under pessimistic and optimistic

assumptions, 66 and 4 licensees, respectively, are not collecting funds at

sufficient rates. Currently, 21 nuclear power plants have been retired

prematurely, and the deregulation of the electricity industry is expected to

increase this number. Moreover, 19 of 26 plants that one investment house

considers as candidates for early retirement are owned by licensees that

have not accumulated decommissioning funds at the expected levels. To

date, utility commissions have permitted licensees to continue collecting

decommissioning funds from their customers even if their plants have

been retired early. Also, bankruptcy courts have allowed licensees to

continue accumulating decommissioning funds after they filed for

bankruptcy.

Adequacy of Assurance

Depends on Financial

Reviews

In anticipation of the electricity industry’s deregulation, in November 1998,

NRC began requiring that, when the collection of decommissioning funds is

no longer guaranteed by the regulation of electricity rates, licensees must

provide added assurance through a variety of means that they will meet

their decommissioning obligations. The prepayment of expected

decommissioning costs, the purchase of surety instruments, and/or the

purchase of insurance are methods acceptable to NRC for providing added

financial assurance. Licensees owning nuclear power plants have not used

these methods; however, and both NRC and industry representatives said

that these types of up-front payments might not be available or might be

prohibitively expensive.2

 Other methods are self guarantees and

guarantees by parent companies. Guarantees must be backed by specified

financial tests, such as a parent company’s having net working capital,

tangible net worth, and assets located in the United States worth at least

six times the amount of decommissioning funds that would be needed.

2

According to NRC, the terms of three recent sales of nuclear power plants have included the

prepayment of all estimated decommissioning costs and, in its view, will likely be the preferred means

of assuring that decommissioning funds are available for future sales transactions.

Page 5 GAO/RCED-99-75 Nuclear Regulation
Executive Summary

NRC elected not to address the likelihood of premature plant retirements

because, in its view, a few premature closures do not justify requiring all

licensees to accelerate the collection of their decommissioning funds. NRC

intends to continue its practice of addressing early plant retirements on a

case-by-case basis. Also, at NRC’s request, the administration included a

provision in its 1999 proposed bill on the deregulation of the electricity

industry that would give priority to funding decommissioning in

bankruptcy proceedings.

NRC also began requiring licensees to report financial information on

decommissioning funds every 2 years beginning by the end of March 1999.

Each licensee must report the amounts of decommissioning funds

accumulated, expected to be needed at a plant’s retirement, and remaining

to be collected each year. The reports must state the licensee’s

assumptions for escalating decommissioning costs, estimating the fund’s

earnings, and discounting projections for the fund. After reviewing the

initial reports from licensees, NRC intends to consider the need for further

rulemaking in this area.

The new financial-reporting requirements should provide NRC with the

information to address such issues as the rates at which licensees are

accumulating decommissioning funds, the effect of the electricity

industry’s deregulation on financial assurances for decommissioning, and

the possibility of the additional early retirements of uneconomical plants.

However, NRC has not explained how it intends to act on the reported

financial information. For example, NRC has not established criteria for

requiring a licensee to change how it accumulates funds or to provide

additional assurance that funds will be available. Instead, NRC stated that it

will consider issuing additional guidance after licensees have submitted

their initial reports.

Recommendations To provide for the logical, coherent, and predictable oversight of licensees’

financial assurances for decommissioning their nuclear power plants, GAO

recommends that the Chairman, NRC, provide licensees and the public with

information on the (1) objectives of, scope of, and methods used in NRC’s

reviews of licensees’ financial reports; (2) thresholds for identifying, on

the basis of these reviews, acceptable, questionable, and unacceptable

indications of financial assurances; and (3) criteria for actions to be taken

on the results of these reviews.

Page 6 GAO/RCED-99-75 Nuclear Regulation
Executive Summary

Agency Comments

and GAO’s Evaluation

GAO provided NRC with a draft of this report for review and comment. NRC

said that GAO’s recommendations merit serious consideration but

disagreed on the timing of their implementation. NRC’s position is that it

should not act unless it determines, on the basis of licensees’ initial status

reports, that problems exist with licensees’ financial assurances for

decommissioning. However, GAO believes that a more proactive approach

is needed to inform licensees and the public about NRC’s expectations

about financial assurance. As a result, GAO made no changes to the

recommendations.

NRC also made several comments on the complex changes that are

occurring in the electric utility industry and the interactions among NRC,

utility commissions, and the nuclear power industry. Where appropriate,

GAO incorporated these comments into the text of the report. NRC’s

comments and GAO’s response are discussed at the end of chapter 3 and in

appendix II.

Page 7 GAO/RCED-99-75 Nuclear Regulation
Contents

Executive Summary 2

Chapter 1 

Introduction

10

Regulatory Challenges to Decommissioning Nuclear Power

Plants

10

Deregulation of the Electricity Industry 13

Objectives, Scope, and Methodology 14

Chapter 2 

NRC’s System Did Not

Ensure That

Licensees Were

Accumulating

Adequate

Decommissioning

Funds

16

Rates at Which Decommissioning Funds Are Being Accumulated 17

Plant Operating Life’s Effect on Decommissioning Funding 19

Effects of Cost Uncertainties on Rate of Fund’s Accumulation 24

Chapter 3 

Effectiveness of

Amendments to

Financial Assurance

System Will Depend

Upon Financial

Reviews by NRC

28

NRC Amends Decommissioning Financial Assurance Regulations 28

NRC Did Not Address Early Plant Retirements or Bankruptcy in

Its Amended Regulations

32

Conclusions 34

Recommendation 34

Agency Comments and Our Evaluation 34

Appendixes Appendix I: Scope, Methodology, and Results of Analyses of

Licensees’ Decommissioning Funds

36

Appendix II: Comments From the Nuclear Regulatory

Commission

55

Appendix III: Major Contributors to This Report 62

Related Products 64

Tables Table 2.1: Retired Commercial Nuclear Power Plants 20

Page 8 GAO/RCED-99-75 Nuclear Regulation
Contents

Table 2.2: Nuclear Power Plants Identified by Standard & Poor’s

as Candidates for Early Retirement

22

 Table I.1: Licensees With More Than or Less Than Expected

Fund Balances (by Percentage Above or Below), as of

December 31, 1997

45

 Table I.2: Licensees That Accumulated More or Less Funds (by

Percentage Above or Below) in 1997 Than the Annual-Average of

the Present Value of the Future Amounts Required

51

Abbreviations

DOE Department of Energy

EIA Energy Information Agency

EPA Environmental Protection Agency

FERC Federal Energy Regulatory Commission

GAO General Accounting Office

GDP gross domestic product

NRC Nuclear Regulatory Commission

Page 9 GAO/RCED-99-75 Nuclear Regulation
Chapter 1 

Introduction

The electricity industry is the largest industry in the United States.

According to the Department of Energy’s (DOE) Energy Information

Administration (EIA), the industry had total assets worth about $700 billion

in 1993 and has revenues of about $200 billion annually.

Nuclear power plants have provided about 20 percent of the nation’s

electricity in recent years. Most nuclear power plants are owned and

operated by investor-owned utilities. Investor-owned utilities comprise

only about 8 percent of the nation’s 3,200 electric utilities but generate and

sell over 75 percent of the electricity. One such utility—the

Commonwealth Edison Company—received the former Atomic Energy

Commission’s first license to operate a civilian nuclear power plant almost

40 years ago. Since then, the Atomic Energy Commission and its successor

regulatory agency—the Nuclear Regulatory Commission (NRC)—have

issued operating licenses for a total of 125 plants. Twenty-one of the plants

licensed to operate have been permanently retired, leaving 104 with

operating licenses.

The Atomic Energy Act of 1954, as amended, and the Energy

Reorganization Act of 1974, as amended, require NRC to, among other

things, protect the radiological health and safety of the public. Under this

mandate, NRC licenses nuclear power plants to operate for up to 40 years

and continually regulates the utility-licensees’ operation of these plants. In

addition, NRC permits utilities to seek license extensions of up to 20 years.

Regulatory Challenges

to Decommissioning

Nuclear Power Plants

Decommissioning a nuclear power plant involves dismantling the

structures and equipment at the plant, properly disposing of the resulting

radioactive and other wastes, and then ensuring that the plant site

complies with applicable environmental standards. Decommissioning

involves a combination of technical, financial, and regulatory challenges.

For example, the nuclear reactor vessel, other plant components, and

concrete surfaces of various rooms in the plant are radioactive or

contaminated with radioactive material. Therefore, the processes of

maintaining the plant in a safe condition prior to dismantling it and

disposing of the resulting radioactive wastes requires constant attention to

protecting workers and the public from exposure to radiation.

The interval of time between the initial operation of a plant and its

eventual dismantling also presents challenges to licensees and NRC. This

interval can be as short as a few years if a plant is retired earlier than

expected and dismantled shortly thereafter or as long as 40 to 60 years if a

Page 10 GAO/RCED-99-75 Nuclear Regulation
Chapter 1 

Introduction

plant operates for an extended license period.1 In lieu of dismantling a

plant immediately after its retirement, a utility may instead elect to

decommission a plant by placing the plant in safe storage before

dismantling it, as long as the entire decommissioning process is completed

within 60 years. This feature of NRC’s regulation allows utilities to defer

dismantling a retired plant if they (1) are awaiting the retirement of a

colocated plant, (2) need to give DOE time to remove all of the spent (used)

fuel from the plant, and (3) need to allow the radioactivity in the plant to

decay before dismantling the plant, among other things.

Finally, the financial aspects of decommissioning also present challenges

to utility-licensees. For example, although actual decommissioning

experience is limited, decommissioning a single plant is expected to cost

hundreds of millions of dollars. NRC does not have the authority to regulate

the manner in which licensees recover from their customers the costs of

constructing, operating, and decommissioning nuclear power plants. Most

licensees are investor-owned utilities that traditionally have been provided

a monopoly within their service areas. In return, these utilities built

generating plants, including nuclear, coal, gas, and hydro power plants,

and transmission and distribution facilities to provide electricity for all of

the existing and future customers within their service areas. Under this

traditional “cost-of-service” regulation, state public utility commissions

approved electricity rates that reflected the utilities’ costs of building and

operating their electricity systems and approved the financial returns on

these investments. Similarly, the interstate aspects of the electric utility

industry, including financial transactions, wholesale rates, and

interconnection and transmission arrangements, are regulated by the

Federal Energy Regulatory Commission (FERC). In this context, utilities’

proposed arrangements to finance the decommissioning of their nuclear

plants are a part of their financial operations that are subject to review and

approval by their respective state public utility commissions and FERC.

2

NRC’s authority to require utilities to accumulate funds to decommission

their nuclear power plants is derived from its responsibilities under the

Atomic Energy Act of 1954, as amended, to regulate the safety of nuclear

power. Until 1988, NRC required licensees to certify that sufficient financial

resources would be available when needed to decommission their nuclear

1

NRC’s regulations permit a licensee to complete decommissioning beyond 60 years if other factors

affect the licensee’s capability to carry out decommissioning, such as the unavailability of capacity to

dispose of radioactive waste.

2

Other utilities, such as the Tennessee Valley Authority, are publicly owned, rather than

investor-owned. These utilities are either economically self-regulating or subject to other constraints

on their financial affairs.

Page 11 GAO/RCED-99-75 Nuclear Regulation
Chapter 1 

Introduction

power plants but did not require these licensees to make specific financial

provisions for decommissioning. On July 26, 1988, NRC’s original

regulations on the technical and financial aspects of decommissioning

became effective. By then, NRC had licensed 114 plants to operate.

NRC’s 1988 regulations provided utilities with the following options for

providing decomissioning financial assurance:

• The prepayment of cash or liquid assets into an account segregated from

the licensee’s assets and outside the licensee’s administrative control.

Prepayment may be made in the form of a trust, escrow account,

government fund, certificate of deposit, or deposit of government

securities.

• External sinking funds. These types of funds are established and

maintained through the periodic setting aside of funds in an account

segregated from the licensee’s assets and outside the licensee’s

administrative control. An external sinking fund may be in the same forms

permitted for prepayment.

• A surety method or insurance. A surety method may be in the form of a

surety bond, letter of credit, or line of credit payable to a trust established

for decommissioning costs.

• For “federal licensees,” such as the Tennessee Valley Authority, a

statement of intent that decommissioning funds will be obtained when

necessary.

NRC recognized both the uncertainty over decommissioning costs and the

authority of public utility commissions and FERC to regulate the economic

affairs of utilities. Therefore, NRC approached the regulation of the

financial aspects of decommissioning by requiring utilities to provide

“reasonable assurance” that sufficient funds would be available to

decommission their nuclear power plants when the plants are permanently

shut down. Among other things, NRC required, by July 27, 1990, each holder

of an operating license to (1) certify that the licensee would provide the

required financial assurance for decommissioning; (2) calculate, using a

formula contained in NRC’s regulations, the minimum amount (expressed

in current-year dollars) that utilities would accumulate for

decommissioning their plants by the time they expect to retire them;3

 and

(3) provide a copy of the financial instrument(s) executed to provide the

required financial assurance. Essentially all utilities have elected the

option of establishing external sinking funds to finance future

3

The amount stated in the certification may also be based on a site-specific cost estimate for

decommissioning the plant as long as the site-specific amount exceeds the amount calculated using

NRC’s formula.

Page 12 GAO/RCED-99-75 Nuclear Regulation
Chapter 1 

Introduction

decommissioning costs.4 A portion of the charge that utilities’ customers

pay for their electricity is earmarked for deposit in these funds, and the

funds are invested to earn income.

In its regulations, NRC deferred to utilities and their rate regulators the

details of collecting the required decommissioning funds. NRC requires only

that the amount actually accumulated by the end of a plant’s operating life

equals the projected cost to decommission the plant. About 5 years before

the projected end of plant operations, NRC requires a utility to submit a

preliminary decommissioning cost estimate that includes an up-to-date

assessment of the major factors that could affect the cost to

decommission its plant. Also, if necessary, the cost estimate shall include

plans for adjusting needed funds for decommissioning to demonstrate that

a reasonable level of assurance will be provided so that funds will be

available when needed to cover the cost of decommissioning. Finally, not

later than 2 years after a plant has been permanently shut down, the utility

must submit to NRC a decommissioning report that includes, among other

things, a site-specific decommissioning cost estimate.

Deregulation of the

Electricity Industry

After about 10 years of experience with NRC’s 1988 decommissioning

regulations, the electricity industry has begun to change in ways that have

prompted NRC to reassess the adequacy of its regulations governing

nuclear power plants, including financial assurances for decommissioning

retired plants. Over the next 10 years or so, many states are expected to

replace their traditional systems of economic regulation of monopolistic

electric utilities with more-competitive, less-regulated environments

mainly for the generation of electricity but, to a lesser degree, for the

transmission and distribution of electricity as well. Competition, according

to NRC, could result in economic pressures that will affect the availability

of adequate funds for decommissioning and how utilities address

maintenance and safety in nuclear power plant operations.

Currently, the Congress is considering a number of bills to restructure the

retail electricity industry to promote a more efficient and market-driven

industry. Also, as of September 1997, 49 states had considered reforming

their retail electricity markets. As of June 1, 1998, FERC and at least 18

states had either enacted legislation or issued comprehensive regulatory

4

The principal exception is the Tennessee Valley Authority, which elected to use the statement of

intent available to federal licensees for its six nuclear power plants that have been licensed to operate.

In December 1998, the Authority told NRC that it had begun to use external sinking funds because it

was no longer eligible to use a statement of intent.

Page 13 GAO/RCED-99-75 Nuclear Regulation
Chapter 1 

Introduction

orders implementing plans to restructure the industry.5 In California, for

example, a plan to produce competitive electricity markets and allow

consumers to choose their electricity supplier went into effect in

March 1998. Also, some of these initiatives would encourage or require the

restructuring of the affected electricity industry. Specifically, utilities that

have traditionally generated, transmitted, and distributed electricity would

be encouraged or required to separate the operation of electricity

generation systems from the operation of transmission and distribution

systems.

Objectives, Scope,

and Methodology

Concerned about the potential costs to decommission nuclear plants and

the implications of a competitive electricity environment on the ability of

plant owners to finance decommissioning projects, the congressional

requesters of this report asked us to determine if (1) there is adequate

assurance that NRC’s licensees are accumulating enough funds to

decommission their nuclear power plants when the plants are retired and

(2) NRC is adequately addressing the effects of electricity deregulation on

the funds that will eventually be needed for decommissioning.

To address both of our objectives we met with, and obtained

documentation from, officials of the following organizations:

• NRC, Rockville, Maryland.

• Nuclear Energy Institute, Washington, D.C. (The Institute represents the

nuclear industry, including utilities that operate nuclear power plants.)

• National Association of Regulatory Utility Commissioners. (The

Association represents public utility commissions and other state-level

rate-setting entities.)

• National Nuclear Safety Network (a public interest organization).

• public utility commissions of Oregon (Salem), Maryland (Baltimore), and

New Hampshire (Concord).

• Portland General Electric (Portland, Oregon); Commonwealth Edison

(Chicago, Ill.); Office of Consumer Advocate (Concord, NH.); and Moody’s

Investors Service (New York, N.Y.).

To address the adequacy of assurance that NRC’s licensees are

accumulating enough decommissioning funds, we also met with, and

obtained documentation from, TLG Services, Inc., which prepares

decommissioning cost estimates for owners/licensees of nuclear power

5

The 18 states are Arizona, California, Connecticut, Illinois, Maine, Maryland, Massachusetts, Michigan,

Montana, Nevada, New Hampshire, New Jersey, New York, Oklahoma, Pennsylvania, Rhode Island,

Vermont, and Virginia.

Page 14 GAO/RCED-99-75 Nuclear Regulation
Chapter 1 

Introduction

plants and Dr. Bruce Biewald, a consultant to groups that participate in

state public proceedings on setting electricity rates, including charges for

decommissioning. We also analyzed whether licensees or their parent

companies have (1) accumulated decommissioning funds at a rate

consistent with the percentages of their reactors’ operating life already

used up (i.e., the fund for each reactor should equal this percentage times

the present value of its future decommissioning cost) and are (2) currently

(viz., 1997) adding enough money to their decommissioning funds (i.e.,

assuming that contributions in future years will increase at the funds’

after-tax rate of return) to accumulate sufficient funds to decommission

their plants when they are retired. The scope and methodology that we

used in these two analyses are discussed in appendix I. To address

whether NRC is adequately considering the effects of electricity

deregulation on the funds that will eventually be needed for

decommissioning, we also obtained and reviewed public comments on

NRC’s advance notice of proposed rulemaking for decommissioning

financial assurances and on the subsequent proposed rule.

We conducted our review from October 1997 through March 1999 in

accordance with generally accepted government auditing standards.

Page 15 GAO/RCED-99-75 Nuclear Regulation
Chapter 2 

NRC’s System Did Not Ensure That

Licensees Were Accumulating Adequate

Decommissioning Funds

We analyzed the status of decommissioning funding as of December 31,

1997, (the year of the most recent data available) for 76 licensees that own

all or part of 118 operating and retired nuclear power plants. We

performed this analysis because NRC had not, for its own regulatory

purposes, systematically collected and analyzed information on its

licensees’ decommissioning funds. Our analysis showed that, under likely

assumptions about future rates of cost escalation, net earnings on the

investments of funds, and other factors, 36 of the licensees had not

accumulated funds at a rate that is sufficient for eventual

decommissioning.1

 Under these conditions, these licensees will have to

increase the rates at which they accumulate funds to meet their future

decommissioning financial obligations. Under more pessimistic

(unfavorable) and more optimistic (favorable) assumptions, 72 and 8

licensees, respectively, had not accumulated funds at a sufficient rate.

We also analyzed whether licensees had recently increased the amount of

funds that they had collected to make up for under-collections in earlier

years. For this analysis, we compared the amounts collected in 1997 with

the annual average of the present value of the amount of funds needed to

meet licensees’ funding obligations when their plants’ licenses expire. We

found that, under likely assumptions, 17 companies collected less funds in

1997 than they need to collect each year over their plants’ remaining

operating life. The 17 companies included 15 companies that had not

collected sufficient funds through 1997. Under more pessimistic and

optimistic assumptions, 66 and 4 licensees, respectively, need to increase

the amount of funds that they collect in future years.

Our funding analysis generally assumes that nuclear power plants would

operate for their current licensed operating period—usually 40 years—and

that the licensees will remain financially solvent. No plant, however, has

yet operated for the full period of its operating license, and electricity

deregulation is expected to cause or contribute to more premature plant

retirements. Furthermore, 19 of 26 plants that one Wall Street firm

considers at risk for early retirement are owned, in whole or in part, by

companies that have been slow to accumulate funds to decommission

their plants. So far, however, neither early plant retirements nor licensee

bankruptcies have adversely affected decommissioning. Economic

1

Other factors that we considered in our analysis included initial decommissioning cost estimates,

plants’ operating periods, and the use of decommissioning funds for cleanup activities related and

unrelated to radiation. (NRC requires licensees to accumulate funds to pay designated

radiation-related costs only, but licensees may need to incur other costs, such as the costs to manage

spent fuel, dismantle nonradioactive structures, and restore the site to “green field” condition, in the

process of decommissioning their plants.)

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regulators have allowed utilities to charge their customers rates that

included amounts for decommissioning plants that were retired early, and

courts have permitted the continued accumulation of decommissioning

funds during bankruptcy proceedings.

From 1990 through 1997, most licensees’ estimates of the costs to

decommission their plants have increased rapidly. Likewise, the utilities’

periodic calculations, using a formula contained in NRC’s regulations, of the

minimum amount that they must accumulate in their decommissioning

funds generally have been escalating more rapidly (particularly in recent

years) than the site-specific cost estimates. Also, there are uncertainties

over what the actual decommissioning costs might be. For example, the

eventual resolution of a protracted dispute between NRC and the

Environmental Protection Agency (EPA) over appropriate radiation

standards for decommissioned sites could affect final decommissioning

costs.

Rates at Which

Decommissioning

Funds Are Being

Accumulated

NRC requires licensees using external sinking funds for decommissioning

financial assurance to deposit funds collected for decommissioning into

their funds each year. For two reasons, however, NRC does not know if

licensees are accumulating decommissioning funds at rates that will

provide enough funds to decommission their plants when the plants have

been retired. First, NRC leaves the amounts to be put aside up to licensees

and their public utility commissions. Second, until recently, NRC has not

required that licensees report on the status of their decommissioning

funds.2

We analyzed the status of decommissioning funds, as of the end of 1997,

for 118 operating and retired nuclear plants owned by 76 licensees (or the

parent companies of subsidiaries that are the legal owners of the plants).

In our first analysis, we compared the total amount of each licensee’s

decommissioning funds with the expected amount of funds that should

have been accumulated by that date. To determine the expected amount,

we assumed that licensees would accumulate increasing (but constant

present-value) amounts annually. Once in the fund, each yearly

contribution would continue to grow at the fund’s after-tax rate of return.

The sum of these annual amounts, plus the income earned on the

investments of the funds, would equal the total estimated

decommissioning costs when the licensees’ plants’ operating license

2

In November, 1998, NRC began requiring each licensee to report financial information, including the

status of its decommissioning funds, every 2 years. The first licensee reports were due by the end of

March 1999.

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expires. For example, at the end of 1997, a licensee’s decommissioning

fund for a plant that had operated half of a 40-year license period (begun

in 1977) should equal one-half of the present value of the estimated cost to

decommission the plant beginning after 2017. This expected level of

funding is not the only funding stream that could accrue to equal future

decommissioning costs but provides us with both a common standard for

comparisons among licensees and, from an equity perspective among

ratepayers in different years, a financially reasonable growing

current-dollar funding stream over time. Appendix I describes our

methodology, assumptions, and results for each of the 76 licensees.

Performing this analysis required that we make assumptions about future

economic and plant-operating conditions. Key assumptions included initial

decommissioning cost estimates, rates of cost escalation, net earnings on

the investments of funds (discount rate), plant-operating periods,3

 and the

use of decommissioning funds for both radiation- and

non-radiation-related decommissioning activities.4

 Because of the inherent

uncertainty associated with assuming future conditions over many years,

we used assumptions of the most likely future conditions to develop a

baseline scenario. And, to bound the results of the baseline scenario, we

developed pessimistic and optimistic scenarios using unfavorable and

favorable economic and plant-operating conditions, respectively.

For our baseline scenario, 36 of the 76 licensees (47 percent) had not

accumulated funds at a rate that is sufficient for eventual

decommissioning. Under these conditions, these licensees will have to

increase the rates at which they accumulate funds to meet their future

decommissioning financial obligations. Changing assumptions to reflect

the pessimistic and optimistic scenarios, greatly affects the adequacy of

the licensees’ funding. Under pessimistic and optimistic assumptions, 72

(95 percent) and 8 (11 percent) licensees, respectively, had not

accumulated funds at a sufficient rate for eventual decommissioning.

The fact that a licensee might have collected funds for decommissioning at

a lesser rate than the expected rate does not, by itself, mean that the

licensee will not meet its financial obligations by the time it retires its

3

Specifically, for the baseline scenario, only six currently-operating nuclear power plants are assumed

to be retired early (from 1998 to 2001). In the optimistic scenario, no currently operating plants close

early. In the pessimistic scenario, however, these 6 plants plus 20 other plants are assumed to close

early (in 2002).

4

In the baseline scenario, we assumed that 86 percent of each licensee’s decommissioning fund was

available to pay decommissioning costs as defined by NRC. In the pessimistic scenario, 82 percent and,

in the optimistic scenario, 100 percent of the fund was assumed to be available.

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plants. By increasing their rates of collection, these licensees can still

accumulate the funds that are necessary. Therefore, to obtain insights on

whether licensees are now collecting funds at adequate rates, we

undertook a second analysis. We compared the available amounts that

each licensee collected in 1997 with the average yearly present value of the

amounts that the licensees would have to accumulate each year over the

remaining life of their plants to have enough decommissioning funds upon

the retirement of the plants. This analysis assumes that the licensees will

increase their yearly future funding at the after-tax rate of return on the

investments of their funds. And, once in the fund, these yearly

contributions will grow at this same rate. Our analysis shows these results

for the baseline (most likely), pessimistic, and optimistic scenarios.

For the baseline, the results show that only 17 of 76 licensees (22 percent)

were not yet collecting the amounts that they will need to meet their

decommissioning obligations. Thus, while 47 percent of the licensees had

less than expected levels of funds at the end of 1997, only 22 percent did

not appear to be currently on track, as represented by the funds that they

collected in 1997, to eventually meet their decommissioning financial

obligations. In other words, while licensees might not have funded

sufficiently in the early years of their plants’ operating life, our results

suggest that most licensees have recently increased funding to make up

the funding shortfalls from earlier years. But if conditions deteriorate from

those assumed in our baseline scenario, as represented by the pessimistic

scenario, 66 licensees (87 percent) under-collected funds in 1997.

Conversely, under the optimistic scenario, only 4 licensees (5 percent) are

currently accumulating funds too slowly.

Plant Operating Life’s

Effect on

Decommissioning

Funding

If a nuclear power plant is retired prematurely, sufficient funds may not

have been collected by the retirement date to pay all decommissioning

costs. To date, 21 plants have been retired before their licenses expired. So

far, however, public utility commissions have permitted licensees to

continue collecting the funds for decommissioning from the licensees’

electricity customers after these plants were retired.

Twenty-One Plants Were

Retired Early

To date, no plant has operated for its full licensed operating life, and 21

plants have been retired before their operating license would have

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expired.5 (See table 2.1.) Two of the 20 plants operated for as long as 25

years. Fifty-two of the 104 plants that are currently licensed to operate

have operated from 20 to 30 years.

Table 2.1: Retired Commercial Nuclear

Power Plants Plant’s name State Retirement date Years operated

GE VBWR Calif. Dec. 1963 6

Pathfinder S.D. Sept. 1967 4

Fermi 1 Mich. Sept. 1972 9

Indian Point 1 N.Y. Oct. 1974 13

Peach Bottom 1 Pa. Oct. 1974 9

Humboldt Bay 3 Calif. July 1976 14

Dresden 1 Ill. Oct. 1978 19

TMI-2a Pa. Mar. 1979 1

La Crosse Wis. Apr. 1987 20

Fort St. Vrain Colo. Aug. 1989 16

Shorehamb N.Y. June 1989 0

Rancho Seco Calif. June 1989 15

Yankee Rowe Mass. Oct. 1991 28

San Onofre 1 Calif. Nov. 1992 26

Trojan Oreg. Nov. 1992 17

Haddam Neck Conn. Dec. 1996 30

Big Rock Point Mich. Aug. 1997 34

Maine Yankee Maine Aug. 1997 25

Zion 1 Ill. Jan. 1998 24

Zion 2 Ill. Jan. 1998 24

Millstone 1 Conn . July 1998 27

aTMI-2 (Three Mile Island Unit 2) operated just over 1 year before incurring an accident that

resulted in the plant’s retirement.

bOver a calendar period of approximately 2 months, the Shoreham plant was operated for the

equivalent of 2 full-power days. The plant was only operated for low-power testing purposes and

was then permanently shut down.

Nine commercial nuclear power plants were permanently shut down

before NRC issued its original decommissioning regulations. Eight of these

retired plants are in safe storage. The ninth plant (Pathfinder), which was

a small demonstration plant, has been decommissioned. Twelve

5

NRC generally licenses nuclear power plants to operate for a maximum of 40 years. It also permits

utilities to seek license extensions of up to 20 years. In 1998, Baltimore Gas and Electric and Duke

Power became the first licensees to file applications for license extensions. The extensions were filed

for the former’s Calvert Cliffs units 1 and 2 and the latter’s Oconee units 1, 2, and 3.

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commercial nuclear power plants have been retired since NRC issued its

decommissioning financial assurance regulations. Four of these plants are

in safe storage. Two plants—Fort St. Vrain and Shoreham—have been

decommissioned. Five plants are currently being dismantled, and the

owner of one plant has not yet decided whether to dismantle the plant

soon or put it in safe storage.

The five plants that are now being dismantled—Big Rock Point, Haddam

Neck, Maine Yankee, Trojan, and Yankee Rowe—were retired before their

owners had accumulated sufficient funds to decommission them. For

example, the Trojan plant was retired in 1992 after 17 years of operation.

At that time, the plant’s licensees estimated that decommissioning the

plant would cost $198 million (in 1993 dollars). However, the licensees had

accumulated only $43 million, or 22 percent, of that amount. The Maine

Yankee plant was permanently shut down in 1997 after 24 years of

operation. When the plant was retired, the licensee had accumulated

$188 million for decommissioning. That amount was only 53 percent of the

$357 million (in 1997 dollars) that the licensee estimated would be needed

to decommission the plant. In both of these cases, as well as in other

states where retired nuclear plants are located, public utility commissions

are permitting the licensees to continue collecting decommissioning funds

from their customers even if their plants were retired early.

Experts Expect More Early

Plant Retirements

Industry experts, such as major financial institutions, and DOE’s Energy

Information Administration anticipate that the deregulation and

restructuring of the electricity industry could result in the early retirement

of from 9 to 40 percent of the nation’s nuclear power plants because these

plants may not be competitive with other sources of electricity. In

April 1998, Standard & Poor’s predicted that poor economics would cause

the early retirements of six plants by 2001.6

 (See table 2.2.) The company

also concluded that another 20 units are “at risk” through 2020 for early

retirement on the basis of expected poor operating and economic

performance over the remainder of the plants’ license. According to the

company, in a competitive market, plant owners will attempt to improve

profitability; however, the vulnerability of these plants to unscheduled

outages may squeeze operating margins and cause the plants to lose their

long-term value.

6

“World Energy Service: U.S. Outlook,” DRI, Standard & Poor’s/DRI (Apr. 1998). Standard &

Poor’s/DRI provides historical analysis and forecasts of energy balances for over 60 countries around

the world.

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Table 2.2: Nuclear Power Plants

Identified by Standard & Poor’s as

Candidates for Early Retirement

Predicted At-risk

Millstone 1,a Conn. Beaver Valley 1, Pa.

Millstone 2, Conn. Crystal River 3, Fla.

Dresden 2, Ill. Duane Arnold, Iowa

Dresden 3, Ill. Fermi 2, Mich.

Oyster Creek, N.J. Fitzpatrick, N.Y.

River Bend, La. Fort Calhoun, Nebr.

Ginna, N.Y.

Indian Point 3, N.Y.

Nine Mile Point 1, N.Y.

Palisades, Mich.

Perry, Ohio

Pilgrim, Mass.

Point Beach 1, Wis.

Point Beach 2, Wis.

Quad Cities 1, Ill.

Quad Cities 2, Ill.

Robinson 2, S.C.

Salem 1, N.J.

Salem 2, N.J.

Sequoyah 1, Tenn.

aThe plant was retired in 1998.

In commenting on our report, NRC pointed out that one plant that Standard

& Poor’s listed as “at risk” for premature retirement—Pilgrim—is in the

process of being sold. The prospective buyer, NRC added, intends to

operate the plant for its full license term and will consider seeking a

license extension for the plant. This example, NRC said, serves to illustrate

both the speculative and controversial nature of projecting the premature

retirements of nuclear power plants.

Other experts, however, have reached conclusions that are similar to

Standard & Poor’s. For example, in January 1999, Synapse Energy

Consultants, Inc., a firm that often testifies in electricity rate proceedings

conducted by state public utility commissions, concluded in a report that,

depending upon the assumptions used, from 20 to 90 nuclear power plants

may be retired early. The most likely case, according to the authors of the

report, is that 34 plants will be retired early. Nineteen of the 26 plants that

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Standard & Poor’s predicts may be retired early are also included in

Synapse’s list of 34 plants that it believes may be retired early.

Compounding the risk that more nuclear power plants may be retired

prematurely is the possibility that the licensees that own these plants may

have, so far, under-accumulated funds to decommission these plants. For

example, 19 of the 26 plants that may be retired early, according to

Standard and Poor’s predictions, are owned, in whole or in part, by 14

licensees that have not accumulated sufficient decommissioning funds,

according to our analysis. Additional predictions of more early plant

retirements have also been made. For example, in December 1997, EIA

projected that 24 nuclear plants would retire as early as 10 years before

their license expires.7

 In 1995, Moody’s concluded that at least 10 nuclear

plants may be closed for economic reasons if the generation of electric

power is completely deregulated.8

 One year later, Moody’s downgraded

the bond ratings of 24 electric utilities that operate nuclear plants. Again,

in 1997, Moody’s said that the frequency that certain nuclear plants tend to

require expensive capital additions to comply with their operating license

increases the likelihood of even more early plant retirements.

The premature retirement of the Zion-1 and Zion-2 nuclear power plants in

January 1998 illustrates the effect of deregulation on power plant

economics. The Commonwealth Edison Company determined that the

plants could not generate electricity at competitive prices in the

deregulated environment. Therefore, the utility decided to retire both

plants after about 24 years, or 60 percent, of their licensed operating life.

When the plants were permanently shut down, the utility had put aside

$362 million, or less than 43 percent of the $834 million estimated to be

needed to decommission the two units. According to officials of

Commonwealth Edison, however, under Illinois law the utility is

authorized and directed to include in the rates that it charges its electricity

customers amounts for the necessary and prudent decommissioning costs

for these plants.

A Few Licensees Have

Declared Bankruptcy

In addition to early plant retirements, licensees of nuclear power plants

have declared bankruptcy in a few cases. So far, the continuing availability

of decommissioning funding has been protected in these cases. For

example, the Cajun Electric Cooperative owned 30 percent of the River

7

See Annual Energy Outlook 1998 With Projections to 2020, (EIA).

8

Special Comment: “Stranded Cost Will Threaten Credit Quality of U.S. Electrics,” (Moody’s Investors

Service).

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Bend, Louisiana, plant. The Cooperative went bankrupt in 1994, and a

bankruptcy settlement was approved on August 26, 1996. The settlement

provided for the transfer of $125 million to an external trust to satisfy

Cajun’s share of River Bend’s estimated decommissioning cost of

$419 million (in 1996 dollars). But the settlement left the successor to

Cajun’s share of the plant open. The court order provided that the

bankruptcy trustee and parties to the settlement were to take all necessary

and appropriate actions to consummate the settlement by June 1, 1997,

including finding a buyer for Cajun’s share of River Bend. On

November 28, 1997, NRC’s staff approved the transfer of Cajun’s portion of

River Bend’s license to Entergy Gulf States, Inc., which is now the sole

owner of this plant. NRC’s staff concluded that Entergy Gulf States was

financially qualified to contribute appropriately to the plant’s

decommissioning.

Another bankruptcy case involved the El Paso Electric Company, which

owns 16 percent of the three-unit Palo Verde Nuclear Generating Station in

Arizona. The company filed for bankruptcy protection in 1992, primarily

because of excess generating capacity and insufficient rates to cover the

costs of power. The settlement of the bankruptcy filing became effective in

1996, at which time, the company emerged with reduced debt and a

stronger financial position. During the bankruptcy proceeding, according

to an NRC official, the company continued to make its required

decommissioning payments.

Effects of Cost

Uncertainties on Rate

of Fund’s

Accumulation

For our funding analyses, we assumed, among other things, that current

estimates of decommissioning costs are accurate. Because actual

decommissioning experience is limited, however, actual costs could be

lower or higher. From 1990 through 1997, cost estimates increased rapidly

for both site-specific studies by licensees and calculations using NRC’s

cost-estimating formula. Moreover, uncertainties about the actual scope of

decommissioning affects costs. Utilities, for example, sometimes consider

the cost to empty a spent fuel storage pool (to permit dismantling a retired

plant) as a decommissioning cost. NRC, however, excludes the cost of

emptying the storage pool from the scope of its formula for estimating

decommissioning costs. The storage of spent fuel in facilities outside of

the plant’s storage pool, and the cost of such storage, are addressed in

parts of NRC’s regulations that are not directly related to decommissioning.

In addition, the eventual resolution of a protracted dispute between NRC

and EPA over appropriate radiation standards for decommissioned sites

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could affect the scope of decommissioning and, therefore, total

decommissioning costs.

Decommissioning Cost

Estimates Are Increasing

Cost estimates since 1990, developed through both NRC’s formula and

licensees’ site-specific cost estimates, show that both estimates have

increased. Although NRC has not routinely monitored the amounts of

decommissioning funds that its licensees have been accumulating, its 1988

regulations required licensees to annually calculate the minimum amount

of funds that must be accumulated to pay future decommissioning costs.

For each plant using NRC’s mathematical formula, the utility must make an

initial calculation in 1986 dollars that is based on the size and type of plant.

Then, the utility must escalate the initial calculated value to that of the

current year on the basis of prescribed escalation factors. Also, to support

proposed charges to electricity customers, plant owners periodically

develop detailed estimates of the cost to decommission their specific

plants and submit the estimates to their public utility commission

regulators. In the absence of significant actual experience, site-specific

estimates of decommissioning costs provide the best check on the

reasonableness of NRC’s formula for calculating potential decommissioning

costs.

Since 1990, decommissioning cost estimates prepared on a site-specific

basis and calculated using through NRC’s formula have increased

substantially. For example, site-specific cost estimates (excluding costs

that licensees may incur during decommissioning, such as spent fuel

storage costs, that NRC does not consider to be decommissioning costs)

have increased, on average, at a rate of about 6.6 percent per year. One

reason for this increase is the expansion of the scope of decommissioning.

The estimates made through NRC’s formula are now, on the average, about

one-third higher than the site-specific estimates for the same plants. The

main reason for this condition is that the waste disposal part of NRC’s

formula was not designed to reflect licensees’ efforts to reduce the volume

of waste from decommissioning in response to increasing prices for

disposal that have traditionally been based on waste volume. In

December 1998, NRC corrected this weakness, which brought calculations

through its formula more in line with licensees’ site-specific cost

estimates.

Uncertainty Related to

Spent Fuel Management

Costs

Largely because DOE is not taking spent fuel from licensees’ nuclear power

plants, licensees that intend to immediately dismantle their retired plants

must store their spent fuel outside of their plants. For the purpose of

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estimating and accounting for decommissioning costs, some licensees

treat storage costs related to the retirement of their plants as

decommissioning costs. The inclusion by licensees of these storage costs

in their decommissioning costs is a major reason why licensees’ cost

estimates have increased in recent years. A second reason is that licensees

may include the cost to dismantle nonradioactive structures, such as

administrative buildings, in their estimates of decommissioning costs.

In contrast, NRC excludes both spent fuel management costs and

non-radioactive-related cleanup costs from its formula for calculating the

funds that licensees must accumulate to decommission their nuclear

power plants. NRC’s reasons for excluding these types of costs are that it

(1) regulates independent spent fuel storage facilities (facilities that are

separate from the spent fuel pool, which is an integral part of a nuclear

power plant) under regulations that are separate from those applicable to

the construction, operation, and decommissioning of nuclear power plants

and (2) only regulates the possession, use, and disposal of radioactive

materials. Nevertheless, spent fuel management costs have been and will

continue to be a real cost for utilities that choose to immediately dismantle

their retired plants. For example, in 1995 the licensee for the retired

Trojan plant in Oregon estimated that spent fuel management costs to

construct, operate, and maintain a dry storage facility at that plant would

cost about $102 million (in 1993 dollars).

Uncertainty Related to

Standards for Residual

Radiation

Uncertainty over the standards for residual radiation that utilities will have

to meet in cleaning up the sites of their retired nuclear power plants

affects the accuracy of the current estimates of future decommissioning

costs.

EPA is responsible for setting acceptable radiation limits outside of the

boundaries of nuclear facilities and for developing residual radiation

standards to protect the health and safety of the public and to protect the

environment. EPA has been responsible since 1970 for establishing

radiation standards for all aspects of decommissioning, including

acceptable levels of residual contamination. To date, however, EPA has not

issued such standards.

In the absence of EPA standards, NRC, which is responsible for regulating

the level of radiation within plant boundaries, issued, on July 21, 1997, its

final radiological standard for license termination. The standard states

that:

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“A site will be considered acceptable for unrestricted use if the residual radioactivity that

is distinguishable from background radiation does not exceed 25 [millirem9

 ] per year,

including that from groundwater sources of drinking water, and that the residual

radioactivity has been reduced to levels that are as low as reasonably achievable.”

EPA does not agree with NRC’s standard. In fact, the disagreement between

the two agencies has been characterized by both its length and its

acrimony. EPA started to develop residual radiation standards in 1984 but

has not yet finalized these standards. Nevertheless, EPA’s position is that

NRC’s licensees should be required to decontaminate nuclear plant sites to

a residual radioactivity level of 15 millirems per year and to limit the

exposure to an individual from his/her consumption of groundwater to 4

millirems per year. Most recently, EPA’s administrator stated that the

agency would apply the Comprehensive Environmental Response,

Compensation, and Liability Act of 1980 to sites that are being

decommissioned if NRC and EPA do not reach an agreement on applicable

standards. Also, in April 1998, one of NRC’s commissioners publicly

commented that the impasse between EPA and NRC over appropriate

radiation protection standards may have to be resolved by the Congress.

In fact, to resolve this disagreement, NRC has sought legislation that would

eliminate the overlap in the standard-setting authority of NRC and EPA.

Currently, NRC’s licensees are using NRC’s regulations and related guidance

on decommissioning the sites of retired nuclear facilities to plan and/or

implement the decommissioning of their nuclear power plants and related

nuclear fuel facilities. If, however, EPA’s residual radiation standards are

ultimately used in lieu of NRC’s standards, licensees may have to perform

additional cleanup when decommissioning their nuclear plant sites. If this

occurred, it would increase decommissioning costs, but by how much is

uncertain. According to both NRC and EPA officials, retroactively applying

more stringent EPA standards to nuclear plant sites that have already been

decommissioned according to NRC’s standards could be very costly.

9

The level is small when compared to the average level of natural background radiation in the United

States, which is about 300 millirem/year.

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Financial Reviews by NRC

Late in 1998, NRC amended its decommissioning regulations in anticipation

of the deregulation and restructuring of the electricity industry. The

amended regulations do not allow licensees to rely exclusively on their

external sinking funds to ensure that funds are available for

decommissioning if its regulators no longer guarantee that moneys can be

collected from the licensees’ customers through electricity rates. In such a

case, NRC now requires a licensee to provide additional financial assurance

for the portion of the licensee’s estimated decommissioning cost that

would not be guaranteed. There is, however, uncertainty over the

availability and affordability of some of these additional options for

providing financial assurance. NRC will also now require licensees to

periodically report financial information on decommissioning; however,

NRC did not specify how it would use this information.

NRC Amends

Decommissioning

Financial Assurance

Regulations

Effective November 23, 1998, NRC amended its decommissioning financial

assurance regulations out of concern that the deregulation and

restructuring of the electricity industry could reduce confidence that the

owners of nuclear power plants will be able to accumulate sufficient funds

to decommission their plants. The new regulations provide that, to the

extent that the collection of estimated decommissioning costs from

customers is no longer guaranteed, a licensee may not exclusively rely on

external sinking funds to provide adequate financial assurance of

decommissioning. For any portions of decommissioning costs for which

the collection of funds is not guaranteed, licensees will have to provide

one or more additional types of financial assurance.

Additional Methods of

Financial Assurance

Electric utilities have almost exclusively relied on the collection of fees

from their electricity customers, deposited into externally managed

sinking funds, to provide decommissioning financial assurance. In

anticipation of electricity deregulation initiatives, NRC, in September 1998,

amended its regulations (effective in Nov. 1998) to address situations in

which a licensee’s continued collection of decommissioning fees from its

electricity customers may no longer be guaranteed by the economic

regulation of electricity rates. To the extent that the collection of

decommissioning funds is no longer guaranteed, a licensee may provide

up-front financial assurance. The options available to licensees include the

prepayment of the estimated decommissioning cost or purchase of surety

bonds or insurance to cover decommissioning costs. The assurances may

also be in the form of guarantees of payments by the licensees or, as

appropriate, their parent company, provided that such guarantees are

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accompanied by the passing of specified financial tests. Both NRC and the

nuclear industry have expressed concern about whether these up-front

payment methods would be affordable for licensees. However, in

commenting on our draft report, NRC stated that the terms for the recent

sales of the Three Mile Island Unit 1, Pilgrim, and Seabrook (partial sale)

nuclear power plants have included the prepayment of all estimated

decommissioning costs. NRC added that it believes that the prepayment

option will likely be the preferred means of assuring decommissioning

funds in future sales transactions.

When NRC published its proposed amended regulations for public

comment in September 1997, it expressed concern that surety instruments

and insurance may not be available to some nuclear power plant licensees;

therefore, NRC specifically asked for comments on this issue. In response,

some commenters said they were concerned about the feasibility of the

up-front methods (prepayment, surety instruments, and insurance) for

assuring decommissioning funding. For example, the Edison Electric

Institute, which represents electric utilities, stated that it could be difficult,

if not impossible, for licensees to provide such assurances. Also, seven

licensees jointly stated that these funding methods would bar prospective

new owners from purchasing interests in nuclear power plants. The seven

utilities added that the (then) proposed regulations could impose a

financial burden that would likely prevent the sale of a nuclear plant.

Finally, the utilities stated that (1) it is uncertain if an insurance product or

a surety bond could be procured to secure a nonelectric utility’s share of

decommissioning costs, and (2) the cost of procuring such a bond could

potentially exceed the cost of prepaying decommissioning expenses.

The difficulty in obtaining a surety bond or insurance product is illustrated

by the experience of one of NRC’s licensees. Great Bay Power Corporation,

which owned 12 percent of the Seabrook nuclear power plant in New

Hampshire, was formed out of bankruptcy proceedings involving four

former part-owners of the Seabrook plant. NRC concluded that Great Bay,

as a part owner of the plant, did not appear to meet the definition of an

“electric utility” because its ability to collect funds for decommissioning

from its electricity customers was not guaranteed by the traditional

regulation of electricity prices.1

 Therefore, according to NRC’s regulation,

Great Bay could not rely exclusively on external sinking funds to provide

decommissioning financial assurance. Although NRC gave Great Bay until

July 1998 to obtain a surety bond or other financial guarantee to fulfill its

1

According to Great Bay, it has always believed and continues to believe that it is an “electric utility”

under the definition contained in NRC’s decommissioning regulations.

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decommissioning obligations, the company was unable to obtain such a

guarantee. Out of concern for the possible bankruptcy of Great Bay if NRC

were to mandate that the company prepay its decommissioning obligation,

the state of New Hampshire, in June 1998, passed legislation that would

make the co-owners of Seabrook proportionately responsible for making

Great Bay’s decommissioning payments if the company defaults on this

obligation. According to NRC, this approach qualifies as an acceptable

“other method” of providing decommissioning financial assurance.

In addition to the traditional financial assurance methods discussed above,

NRC adopted other methods that licensees may use to provide

decommissioning financial assurance.

• Other guarantee methods, including parent company guarantees and

self-guarantees coupled with financial tests. For parent company

guarantees, a licensee’s parent company must, among other things, have

net working capital, tangible net worth, and assets located in the United

States worth at least six times the amount of decommissioning funds being

assured by the parent company for all of its nuclear power plants. Tangible

net worth must exclude the net book value of the nuclear unit(s). For

self-guarantees, tangible net worth and assets located in the United States

must be 10 times the amount of the decommissioning funds being assured.

• Contractual obligations of a licensee’s customers to purchase enough

electricity to provide the licensee’s total share of uncollected funds for

decommissioning.

• Any other method, or combination of methods, that provides, as

determined by NRC upon its evaluation of the specific circumstances,

assurance of decommissioning funding equivalent to that provided by the

other acceptable methods.

These methods are similar to financial assurance methods that NRC

permitted in its 1988 decommissioning regulations for other types of

licensees, such as operators of nuclear fuel facilities.

NRC Adopts Financial

Reporting Requirements

Prior to November 1998, NRC had reserved the right to inspect licensees’

decommissioning fund arrangements and status. Under the 1998

amendments, NRC also explicitly reserved the right to take additional

action, either independently or in cooperation with economic regulators.

These actions could include modifying a licensee’s schedule for

accumulating additional funds. In addition, NRC’s 1998 decommissioning

regulations required licensees, beginning by the end of March 1999, to

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report to NRC, every 2 years, certain financial information that would

ensure that licensees are collecting their required decommissioning funds.

Information that must be provided in licensees’ financial reports includes

(1) the amount of decommissioning funds estimated to be required

according to NRC’s formula; (2) the funds accumulated as of the end of the

year prior to the report date; (3) the annual amounts remaining to be

collected; (4) the assumptions used to escalate decommissioning costs,

project rates of earnings on investments of external sinking funds, and

discount funding projections; and (5) modifications to external sinking

fund agreements. Utility representatives have not opposed financial

reporting. For example, the Edison Electric Institute told NRC that periodic

reporting on the status of external sinking funds for decommissioning is

appropriate. In addition, in commenting on the proposed regulations, a

group of seven utilities stated that a comprehensive reporting requirement

is long overdue and is particularly appropriate, given that economic

regulators have not been actively monitoring the status of licensees’

external sinking funds on an ongoing basis.

When NRC published its final regulations, it stated that, after licensees have

submitted their initial reports by the end of March 1999, it would review

the reports and consider whether to issue additional guidance on the

format and content for subsequent licensee reports. Also, in June 1997,

when NRC’s commissioners approved the proposed regulations for public

comment, the commissioners stated that after NRC’s staff has reviewed

licensees’ initial reports, the staff should advise the commissioners on the

need for further rulemaking. When NRC issued the 1998 amendments to its

decommissioning regulations, however, it did not explain when and how it

intends to act on the financial information reported by individual licensees

if that information does not clearly demonstrate that an individual licensee

is accumulating decommissioning funds at a satisfactory rate.

The lack of any criteria for acting on licensees’ decommissioning financial

reports contrasts with the agency’s ongoing efforts to establish a more

objective, understandable, and predictable approach to safety oversight of

nuclear power plants. According to NRC, an independent regulatory

oversight process is based on unbiased assessments of licensees’

performances; logical, coherent, and predictable actions by NRC; clear ties

to NRC’s regulations and goals; and opportunities for public awareness of

process results. The new safety oversight process should, according to

NRC,

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• allow for the integration of various information sources relevant to a

licensee’s safety performance,

• make objective conclusions regarding the significance of the integrated

performance information,

• take actions based on these conclusions in a predictable manner, and

• effectively communicate these results to the licensees and to the public.

Therefore, NRC is in the process of establishing a new oversight approach

in which it will, among other things, use indicators of nuclear power

plants’ performance to establish thresholds for clearly identifying

acceptable levels of performance. In conjunction with this, NRC plans to

establish criteria for identifying and responding to unacceptable licensee

performance.

A similar approach in the area of providing adequate financial assurances

for decommissioning would appear to offer the same benefits of

objectivity and predictability that NRC seeks in its safety oversight of

nuclear power plants.

NRC Did Not Address

Early Plant

Retirements or

Bankruptcy in Its

Amended Regulations

NRC’s new financial assurance regulations do not address the option of

accelerating the rate at which licensees must accumulate

decommissioning funds on the basis of the actual longevity of plants. NRC

rejected this option because it believes that some plants will probably

continue operating for their licensed operating period of up to 40 years

and, with license extensions, beyond 40 years. Therefore, NRC said,

requiring all licensees to accelerate their accumulation of

decommissioning funds because of some premature plant retirements

would be arbitrary and lead to widely varying effects on licensees. Thus,

NRC intends to continue its practice of addressing early plant retirements

on a case-by-case basis. NRC’s position, as expressed in the supplementary

information accompanying the publication of its amended

decommissioning regulations, is that accelerated funding is inequitable.

NRC believes that accelerated funding places too much of the financial

burden on current utility ratepayers and a lesser burden on ratepayers in

the later years of a nuclear power plant’s operation. However, when

licensees have retired plants before the plants’ operating license expired,

the licensees’ electricity customers have had to pay decommissioning

costs for plants from which they no longer receive electricity. The Trojan,

Maine Yankee, and Zion cases, discussed earlier, demonstrate this fact.

During the years that the Trojan and Zion plants operated, the respective

licensees’ customers paid for less than half of the costs to decommission

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the plants. The customers of the Maine Yankee plant paid for 53 percent of

the decommissioning cost. Now, although these retired plants no longer

generate electricity, the current and future customers of the licensees will

pay the remaining decommissioning costs without receiving comparable

benefits from the plants.

NRC elaborated on its reasons for opposing accelerated decommissioning

funding in its comments on our draft report. NRC said that requiring

accelerated funding for decommissioning would cause substantial cost

increases to be incurred by either licensees’ stockholders or their

ratepayers. Also, there would be a myriad of difficulties in determining the

appropriate rate of acceleration; for example, at what rate should the

collection of funds be accelerated? These issues, NRC added, were

considered in its evaluation of accelerated funding as part of its process of

amending its decommissioning regulations. NRC concluded that

accelerated funding does not provide sufficiently increased

decommissioning funding assurance commensurate with its potential cost

impacts.

State legislatures, state public utility commissions, and FERC appear to be

addressing assurances for decommissioning funding in their electricity

deregulation initiatives. Utility officials in Illinois, New Hampshire, and

Oregon, for example, pointed out that laws in those states provide for the

collection of necessary and prudent funds for decommissioning nuclear

power plants regardless of whether the plants operate until their current

licenses expire or are retired prematurely. Thus, licensees have continued

collecting from electricity customers the fees earmarked for

decommissioning three prematurely retired plants in Illinois and one in

Oregon. Similar examples are occurring in California and Massachusetts.

With respect to the bankruptcy of licensees, New York’s Public Service

Commission, in commenting on NRC’s proposed amendments to its

decommissioning regulations, urged NRC and states to consider proposing

legislation that would make decommissioning liabilities a first priority in

the event of the bankruptcy of a private nuclear facility owner. Current

bankruptcy law does not make the subject of nuclear decommissioning

costs a priority, but NRC has said it does enter bankruptcy proceedings to

protect the integrity of decommissioning funding. Moreover, at NRC’s

request, the Administration included a provision in its 1999 electricity

deregulation bill that would give priority to funding decommissioning of

nuclear power plants in bankruptcy proceedings involving licensees.

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Conclusions Several factors have come together at this time that make it imperative for

NRC to ensure that its licensees accumulate sufficient funds to

decommission their plants regardless of when they are permanently shut

down. Specifically, some licensees have not set aside sufficient amounts of

funds for decommissioning, and there is uncertainty over the availability

and affordability of the up-front payment methods of providing financial

assurance. With electricity deregulation emerging, the possibility exists

that a licensee may, in the future, prematurely retire a plant and be faced

with paying the remaining decommissioning funds from its own resources.

The ability of the licensee to do so might then depend upon its overall

financial condition. Thus, self-guarantees that decommissioning funds will

be available are only as good as the financial condition of the licensee.

(We recognize that to date, early plant retirements have not resulted in a

shortfall in decommissioning funds because regulators have allowed

licensees to continue collecting funds after plants have been retired.)

To NRC’s credit, it recognized its need to increase its oversight of

decommissioning financial assurance when it modified its

decommissioning regulations by requiring licensees to provide financial

reports every 2 years. NRC did not, however, explain what it intends to do

with these reports. For example, NRC did not establish the thresholds for

clearly identifying acceptable levels of financial assurances or establish

criteria for identifying and responding to unacceptable levels of

assurances. In the absence of such explanations, there is no logical,

coherent, and predictable oversight of licensees’ financial assurance for

decommissioning their nuclear power plants.

Recommendation After NRC reviews licensees’ initial reports on decommissioning financial

assurances, we recommend that the Chairman, NRC, provide licensees and

the interested public with information on the (1) objectives, scope, and

methodologies of NRC’s reviews of the reports; (2) thresholds for

identifying, on the basis of these reviews, acceptable, questionable, and

unacceptable indications of financial assurances; and (3) criteria for the

actions to be taken on the results of these reviews.

Agency Comments

and Our Evaluation

We provided NRC with a draft of our report for review and comment. NRC

said that our recommendation merits serious consideration with respect to

its future uses of licensees’ biennial reports on decommissioning funds.

NRC added, however, that it is premature to expend significant staff

resources on establishing thresholds for identifying problems with

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licensees’ financial assurances for decommissioning until NRC knows, on

the basis of its reviews of the initial status reports from licensees, that

such problems exist. Thus, NRC differs with us not on the substance of our

recommendation but on the timing of its implementation. NRC’s position is

that it does not need to establish performance thresholds unless actual

performance problems exist. In our opinion, a proactive, rather than

reactive, approach would more appropriately provide licensees and the

public with a more complete understanding of NRC’s expectations in the

area of financial assurance for decommissioning.

NRC also stated that our report does not adequately represent the complex

changes that are occurring in the electric utility industry and the

interactions among NRC, state public utility commissions and FERC, and the

nuclear power industry. According to NRC, a host of complex, interrelated

variables must be analyzed before any threshold for determining funding

shortfalls can be established. These variables include, NRC added, (1) the

actual rates that licensees are accumulating for decommissioning funds,

(2) the stated intents of rate regulators (such as state public utility

commissions) on allowing the ultimate collection of decommissioning

funds, (3) the provisions for decommissioning funding in state

deregulation initiatives, and (4) for licensees no longer subject to the

traditional regulation of their electricity rates, the extent to which the

future collection of decommissioning funds may be based on

non-bypassable wire charges. Where appropriate, we have either added

NRC’s comments to, or revised the text of, our report. The full text of NRC’s

written comments and our response appear in appendix II.

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Scope, Methodology, and Results of

Analyses of Licensees’ Decommissioning

Funds

This appendix describes the scope, methodology, and results of our

analyses of the following two questions:

• When such economic factors as inflation, interest, and others are taken

into account, have licensees accumulated decommissioning funds at a rate

consistent with the expended portions of the licensed operating life of

their nuclear power plants?

• Are licensees currently adding moneys to their decommissioning funds at

the rates necessary to have sufficient funds available to decommission

their plants when the plants are retired?

The answer to the first question provides a backward look at the funding

issue; in contrast, the answer to the second question provides a look

forward. Together, the answers to these two questions answer the more

general question of whether or not the Nuclear Regulatory Commission’s

(NRC) licensees are accumulating decommissioning funds at growth rates

that, if maintained, should provide sufficient funds to decommission their

nuclear power plants when the plants are retired.

Have Licensees

Accumulated

Decommissioning

Funds at Rates

Consistent With the

Expended Portions of

the Licensed

Operating Life of

Their Plants?

For each licensee owning one or more nuclear power plants, we

calculated the respective amount of funds that the licensee would be

expected to have accumulated over the expended portion of each plant’s

operating life. We then compared the actual funds accumulated by the

licensee with the sum of these expected amounts. In a hypothetical case, a

licensee might have begun operating a plant on December 31, 1974, with a

40-year operating license expiring at the end of 2014. By the end of

1997—an operating period of 23 years—the licensee would be expected to

have collected 23/40ths of the present value of the estimated cost to

decommission the plant upon its retirement. The balance of the

decommissioning funds would be collected over the remaining 17 years of

the plant’s operation.1

In this hypothetical example, the amount of moneys collected from

ratepayers each year is typically invested to earn income until the fund is

needed to pay decommissioning costs. This rate of interest, or the

discount rate, is the assumed annual-average after-tax rate of return on the

fund’s financial assets. In effect, each annual contribution to the

decommissioning fund would ideally be 1/40th of that year’s present value

of the estimated future decommissioning cost (in 2014 current dollars)

1

How a licensee would be expected to accumulate such moneys in future years constitutes our second

analysis, which is discussed later in this appendix.

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because that sum would be invested and would grow over the remaining

life of the plant to equal 1/40th of that future cost. This future cost is

estimated by “inflating” an initial decommissioning cost estimate by an

assumed annual-average cost-escalation factor from the year of the cost

estimate to the final year of the plant’s operating license.

It was not practicable for us to obtain plant-specific information on the

status of decommissioning funds for use in our analysis. Plant-specific

information was not readily available because NRC has not systematically

collected this type of information. Also, licensees’ published financial

statements do not always contain plant-specific financial information on

decommissioning, and time and resource constraints precluded us from

collecting this information from each licensee.

We were, however, able to collect information on the status of

decommissioning funds at the corporate level. This information enabled us

to analyze the status of each licensee’s efforts to accumulate funds to

decommission all of the nuclear power plants for which it had an

ownership interest. Specifically, the financial firm of Phoenix, Duff &

Phelps had compiled, as of the end of 1997, information on the status of

decommissioning funds on a company-by-company basis for 76 licensees

(or parent companies of licensees) owning all or parts of 118 operating

and retired plants.2

 For each licensee, the compilation showed the balance

of decommissioning funds for all of its plants on December 31, 1997, and

the total payments into the funds for 1997.

Because many nuclear power plants are owned by more than one licensee,

we obtained information from NRC on the ownership of each plant and

used this information to apportion the estimated cost to decommission a

plant among the plant’s owners. In addition, licensees’ decommissioning

funds may contain funds to be used for managing spent fuel during the

dismantling of a plant and/or for nonradiological cleanup activities that are

not regulated by NRC. Therefore, it was necessary for us to adjust fund

balances and payments in 1997 into the fund to reflect the inclusion of

funds for cost activities that NRC does not include within the scope of

decommissioning.

In summary, for our first analysis, to determine if licensees have

accumulated decommissioning funds at rates consistent with the

2

From discussions with officials of Phoenix, Duff & Phelps and subsequent selective verification, we

confirmed that the information on each company was derived from published financial statements.

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expended portions of the licensed operating life of these plants, we

constructed a spreadsheet simulation model as follows for each licensee:

• We listed the operating license issue and expiration year, and its

ownership share, for each of the licensee’s nuclear power plants

(reactors).

• Using a recent estimate of the cost to decommission each plant, the year

of this estimate, and a selected cost-escalation rate, we escalated this

initial cost to the year that the plant would be retired (usually at the

expiration of its operating license).

• At the end of the current year (1997), for each plant, we calculated the

present value of its future decommissioning cost and multiplied this result

by the fraction of the license period already used up. This calculation

represents the level of funds (for the plant) that ideally should have been

accumulated by the end of 1997 (the expected amount). (As a result of

continuing this process in future years, the fund balance would equal the

estimated decommissioning cost when the plant is retired.)

• For each licensee, we summed these expected fund amounts (as of the

end of 1997) for each of its plants and compared this sum with the total

amount of the licensee’s decommissioning funds at that point in time. If

the funds actually accumulated are less than the expected amount, then

the licensee has been accumulating funds at a rate insufficient to

decommission its plants. Fund balances that exceeded the expected levels

had the opposite effect.

Key Factors in the Analysis In our first spreadsheet simulation model, our analysis uses five key

factors, or assumptions, whose assigned values can affect the results.

These factors are (1) the initial estimated cost to decommission a nuclear

power plant, (2) the cost-escalation rate, (3) the after-tax rate of return on

the fund’s assets (discount rate), (4) the expected operating life of each

plant, and (5) the portion of a licensee’s decommissioning fund that is

available to pay decommissioning costs as defined in NRC’s regulations. An

analysis of possible conditions tens of years into the future is inherently

uncertain. Therefore, we assigned likely future values to the five key

factors (assumptions) to develop a baseline (most likely) scenario.3

 Then,

to reflect the range of unfavorable and favorable conditions that licensees

3

We also performed simulation sensitivity analysis on these five factors using this baseline scenario.

Changing the values of each of these factors, one at a time, changes the results of the analysis. For

example, the cost-escalation rate was increased and decreased by 1 percentage point, the after-tax rate

of return was increased and decreased by 1 percentage point, the life of plants was decreased and

increased by 2 years, and so on. These sensitivity results yielded values that we had expected, but

these results are not presented in this report.

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might face, we bounded the baseline values with pessimistic and

optimistic values for each of the five factors. (The specific values we used

for our baseline, pessimistic, and optimistic assumptions are discussed

below.) Our pessimistic scenario reflects these pessimistic values, such as

a low after-tax rate of return and a high rate of cost escalation, and would

negatively affect the accumulation and measured sufficiency of

decommissioning funds. Our optimistic scenario, reflecting optimistic

values, would have the opposite effect. Because all of the assumptions are

pessimistic for the pessimistic scenario and optimistic for the optimistic

scenario, our model’s results for each of these two scenarios can be

considered as extreme in both the pessimistic and optimistic directions,

respectively.

Initial Decommissioning Cost

Estimates

In our baseline and optimistic scenarios, we used, where available,

licensees’ most recent site-specific estimates of the costs to decommission

each of their nuclear power plants. We used the site-specific estimates for

91 of the 118 plants that were prepared for the licensees by TLG Services,

Inc.. According to senior officials of this firm, these cost estimates

typically include the costs that NRC does not include within the scope of

decommissioning. These types of costs include costs to manage spent fuel

at retired plants and the costs to dismantle structures that are not

contaminated with radioactivity. At our request, TLG Services, Inc.,

separated out, where possible, these two portions of the cost estimate for

each plant. We used only the NRC-qualified portions of the site-specific cost

estimates for these 91 plants. Also, using TLG Services’ cost estimates

across all 91 plants and all years for which the firm made cost estimates

for these plants, we estimated for an average plant, the percentages of the

total decommissioning cost estimate represented by (1) decommissioning

costs, as defined by NRC; (2) spent fuel management costs; and (3) the

costs to dismantle nonradioactive structures and restore the site.

NRC-qualified decommissioning costs represented about 82 percent of TLG

Services’ total site-specific decommissioning cost estimates. Spent fuel

management costs were about 5 percent, and non-radiation-related costs

about 13 percent of these total cost estimates. However, the officials of

TLG Services said that these cost data and, therefore, our percentage

estimates from these data should be considered as approximations.

For each of the remaining 27 plants, we calculated, using NRC’s generic

cost-escalation formula, the estimated decommissioning cost (in

1997) that determines the minimum level of funds that NRC requires the

plant’s licensee to have accumulated by the time the plant’s license

expires. NRC’s formula overstated low-level waste disposal costs, but NRC

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recently corrected this problem for 1998. Therefore, we also used NRC’s

recent waste burial correction for 1998 in calculating the estimated

decommissioning cost for each of the 27 plants in 1997. For both the

site-specific and generic-formula procedures, the costs are estimates of

what it would cost to decommission a plant in the year that the estimate

was prepared. Thus, these estimates represent “initial” decommissioning

cost estimates that we escalated to the years that the plants’ licenses

expire.

In our pessimistic scenario, we used NRC’s generic cost-escalation formula

to calculate, for each of the 118 plants, the decommissioning cost

estimates in 1997 and then escalated these cost estimates to the year of the

license’s expiration for each plant. (Here, we did not use NRC’s waste burial

correction for 1998 for these 1997 estimates.) We selected this approach

because before NRC corrected the weakness in its formula for this

calculation, calculations that were used in the formula generally produced

results that were, on average, about one-third higher than TLG Services,

Inc.’s, site-specific cost estimates for the same year.

Annual Average

Cost-Escalation Rate

Our analysis required that we estimate the costs to decommission nuclear

power plants at the end of their license expiration year. Therefore, we

escalated the “initial” cost estimates from their values when they were

prepared to forecast what the current-dollar cost might be at the end of

each plant’s life span. (For all plants that are already retired but not yet

decommissioned, the “future” decommissioning costs are for the current

year [1997].)

Our estimate of an annual average cost-escalation rate reflects two

conditions: price inflation and changes in the scope and/or technology of

decommissioning. The effect of price inflation on increasing future

current-dollar costs is self-evident. Changes in the scope and/or

technology of decommissioning could either increase or decrease future

decommissioning costs. For example, future costs will decrease if more

efficient technologies are used in the decommissioning process but will

increase if experience shows that more activities must be performed.

In the site-specific cost information for the 91 nuclear power plants that

TLG Services, Inc., provided us with, the company had prepared more than

one site-specific cost estimate for 43 plants. Therefore, for each of the 43

plants, we calculated the annual average cost-escalation rate from the year

of the earliest cost estimate to the year of the most recent cost estimate.

We used only the costs identified by TLG Services as being within the

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scope of NRC’s decommissioning regulations. We then calculated the

simple average of the 43 annual-average cost (estimation) increases. The

calculated average was 6.6 percent.

For our annual-average cost-escalation rate assumption, we used the

following methodology to estimate an upper-bound, middle, and

lower-bound rate for the pessimistic, baseline (most likely), and optimistic

scenarios, respectively. For the 1990 through 1997 period of the

site-specific estimates, we calculated a broad-based measure of inflation

during the period using the Gross Domestic Product (GDP) Implicit Price

Deflator data contained in the February 1998 Economic Report of the

President. Inflation over this period was at an annual-average rate of about

2.5 percent. Thus, over the period, TLG Services’ cost estimates escalated,

on average, at a rate about 4 percentage points (6.6 percent minus

2.5 percent) above the rate of inflation. By averaging forecast data from

Standard & Poor’s/DRI and WEFA Group for the 1997 through 2018 period,

we estimated that the GDP price deflator would grow over this period (the

approximate average life expectancy of a nuclear plant) at an

annual-average rate of 2.5 percent.

We assumed that this historical 4-percentage-point margin in the rate of

increase in estimated decommissioning costs above the forecast rate of

inflation would represent our worst case in cost escalation. This is

because many experts believe that increased decommissioning experience

will help to reduce substantially the future growth in decommissioning

costs. Therefore, for our pessimistic scenario, we assumed a

cost-escalation rate of 6.5 percent—the 2.5-percent forecast inflation rate

plus the full 4-percent margin. For the baseline scenario, we assumed a

mid-point rate and reduced this margin to 2.5 percent, for a 5-percent

annual average cost-escalation rate. For the optimistic scenario, we

assumed a 1-percent margin, for a 3.5-percent annual average

cost-escalation rate. For our optimistic case, we believe that this

3.5-percent rate-assumption represents a reasonable lower bound because

decommissioning costs include a large portion of services, and services

generally have higher inflation rates than those of the GDP deflator.

After-Tax Rate of Return

(Discount Rate)

Traditionally, regulated utilities were required to invest their funds

conservatively in federal, state, and local securities. In recent years,

however, utilities have been permitted to invest some of their funds in

higher-risk, but potentially more profitable, financial instruments. From a

review of eight licensees’ recent financial statements, we determined that

the after-tax rate of earnings from investments of decommissioning funds

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Analyses of Licensees’ Decommissioning

Funds

varied from 5.5 to 7.3 percent. About 6 percent or slightly above was

typical. Therefore, we assumed an after-tax rate of return on fund assets of

6.25 percent for our baseline scenario and rates of 5.5 and 7 percent,

respectively, for our pessimistic and optimistic scenarios. In the baseline,

the licensees’ effective (with respect to their own decommissioning costs)

real after-tax rate of return is, therefore, 1.25 percent (6.25 percent minus a

5.0-percent cost-escalation rate) and in the optimistic scenario, the real

rate of return is 3.5 percent. In the pessimistic scenario, this real rate is

negative, (–1 percent).4

 For a given plant’s license expiration year, the

larger the real after-tax rate of return, the better will be our measures of

funding sufficiency for the licensee of this plant.

Nuclear Plant’s Operating Life Various experts believe that some nuclear power plants will not operate

for the full length of their operating licenses because of, for example, the

expected introduction of competition into the electricity markets.

Conversely, two licensees have filed applications with NRC to extend the

operating life of five plants, and other licensees may also seek license

extensions. Because of this uncertainty, we included in our analysis the

ability to reduce (or increase) each plant’s life. A decrease in the expected

life of a plant would require the licensee to increase the rate that it

accumulated funds over the shortened life of the plant, and, conversely, an

increase in the operating life would reduce the amount of funds needed to

be put aside each year.5

Our baseline scenario assumes that all plants operate for their licensed

periods except for six plants that Standard & Poor’s/DRI6

 projects will be

retired early.7

 For our pessimistic scenario, we assume that these six

plants plus each of 20 other plants characterized by Standard & Poor’s/DRI

as “at risk” of early retirement will permanently shut down in 2002.8

 For

our optimistic scenario, we assume that each plant will operate for its

4

A negative real rate means that a licensee’s plant decommissioning costs will increase faster than the

licensee’s after-tax fund earnings.

5

Strictly speaking, a decrease in the expected life of a plant would increase the present value of that

plant’s future decommissioning cost only when the licensee’s after-tax real rate of return is positive. If

it is negative, as in our pessimistic scenario, this total present-value cost is actually decreased when

the expected license expiration year is made earlier. However, even with this lower present-value cost,

that cost must be paid for over fewer years. Thus, the present-value cost per year would still be higher

over these fewer years.

6

World Energy Service: U.S. Outlook, Standard & Poor’s/DRI (Apr. 1998), p. 25, tables 5 and 6.

7

One of the six plants—Millstone 1 in Connecticut—was retired in 1998.

8

These extra 20 “at-risk” plants are listed in chapter 2 (table 2.2).

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licensed operating life. (We implicitly assume that any increases in a

plants’s life will be offset by decreases in the life of other plants.)

Portion of Funds Available for

NRC-Defined Costs

As discussed above, licensees’ decommissioning costs can encompass not

only costs that are within the scope of NRC’s definition of decommissioning

but also spent-fuel management costs and nonradiological costs.

Licensees, however, may accumulate funds for all of these types of costs

in their decommissioning funds because, from the licensees’ point of view,

all of these types of costs may be essential to decommissioning their

plants. Our analysis included only those costs that are within the scope of

decommissioning as defined by NRC. Therefore, in our three scenarios, we

varied the percentage of each licensee’s decommissioning fund that would

be available to pay for NRC-defined decommissioning costs.

For our optimistic scenario, we assumed that all of each licensee’s

decommissioning fund is available to pay NRC-defined decommissioning

costs. The expenditures for spent-fuel management and other

nonradiological decommissioning costs must therefore come from other

sources. For our baseline scenario, we assumed that all of the licensee’s

decommissioning fund would be used to pay for decommissioning costs as

defined by NRC and for nonradiation costs. As discussed earlier, these

types of costs represent 82 and 13 percent, respectively, of the total

estimated cost to decommission an average plant. We assumed that

spent-fuel management costs, which make up the remaining 5 percent of

the average plant’s decommissioning cost, would be paid from some other

source of funds. Under these assumptions, 86 percent (82 percent divided

by 95 percent) of the decommissioning fund would be used to pay

decommissioning costs as defined by NRC and the remaining 14 percent

(13 percent divided by 95 percent) of the fund would be used for

non-radiation-related costs.

For our pessimistic scenario, we assumed that each licensee would pay for

all three of these types of costs from its decommissioning fund. Thus, we

assumed that the percentage of a licensee’s fund available to pay for

NRC-definition costs would equal the percentage of NRC-definition costs

that we estimated for total decommissioning costs, or about 82 percent. To

compute each of our above estimated percentages, we used the

decommissioning cost data derived from TLG Services’ breakdown of

site-specific cost estimates into the NRC-related, spent fuel management,

and nonradiological portions. Finally, for 15 of the 76 licensees, the

information we obtained from Phoenix Duff & Phelps disclosed that the

balances in the licensees’ decommissioning funds at the end of 1997

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included amounts actually held in internal reserve accounts rather than in

externally managed funds restricted for eventual use in decommissioning

their plants. For our analysis, we included these internal reserves in our

totals for the decommissioning funds for each of these licensees.

Fund Balance Adequacy

Analysis: Results

Table I.1 shows the results of our first spreadsheet analysis of each of the

76 licensee’s decommissioning fund balances as of the end of 1997. The

table shows whether these fund balances are more or less than the

amounts that the licensees would have been expected to accumulate by

then—namely, for each plant, the percentage of life used multiplied by the

present value of the plant’s future decommissioning cost. The table shows,

for our three scenarios, the percentage that each licensee is above or

below its expected fund level. As the table shows, there is a wide range of

results for each individual licensee among the baseline, pessimistic, and

optimistic scenarios and among all licensees within each scenario. The

results for the baseline scenario should be viewed as the most likely

outcomes, and the results in the pessimistic and optimistic scenarios

should be viewed as lower and upper bounds, respectively. Not all of the

five key factors would likely be simultaneously pessimistic, and not all

likely simultaneously optimistic. Therefore, the most likely results will lie

much closer to our baseline results than to those of either of our two

extreme scenarios.

Given the inherent uncertainty embodied in this analysis and the various

assumptions employed, the results are best used as a general guide to the

relative positions of the 76 licensees in accumulating decommissioning

fund balances by December 31, 1997. In the baseline scenario, 36 of the 76

licensees had not accumulated funds at a rate that is sufficient for eventual

decommissioning. In addition, in table I.1, the eight licensees showing

available fund balances at less than their expected levels even under the

optimistic scenario are a cause for concern because future conditions will

likely be worse than those assumed in the optimistic scenario. Conversely,

the four licensees showing fund balances above their expected levels, even

in the pessimistic scenario, suggest that these licensees may be able to

reduce their funding in the future because conditions are likely to be

better than those assumed in the pessimistic scenario.

For all 76 licensees combined, licensees have accumulated, on average,

only 3 percent less than their expected amounts in our baseline (most

likely) scenario. The present value of the total future decommissioning

costs for all licensee plants is $30 billion. Because all of the five key

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factors, or assumptions, are pessimistic in the pessimistic scenario and all

are optimistic in the optimistic scenario, the results are much worse and

better, respectively, in these other two scenarios. In the pessimistic

scenario, licensees, on average, have balances that are 57-percent below

their expected levels and have a present value of total future

decommissioning costs of $67 billion. In the optimistic scenario, licensees,

on average, have balances that are 63-percent above their expected levels

and have total present-value costs of $20 billion.

Table I.1: Licensees With More Than or

Less Than Expected Fund Balances

(by Percentage Above or Below), as of

December 31, 1997

Scenario

Licensee Baseline Pessimistic Optimistic

American Electric Power ++ • • ++++

Atlantic Energy + • • ++++

Baltimore Gas & Electric • • • • • +

Boston Edison • • • • +

Carolina Power & Light • • • • +++

Central and Southwest ++ • • ++++

Central Hudson Gas & Electric +++ • • ++++

Central Iowa Power Corporation • • • • • • • •

City of Austin +++ • • ++++

City of San Antonio +++ • ++++

CMS Energy • • • • +

Commonwealth Edison • • • • • +

Connecticut Yankee Atomic Power

Corporation • • • ++

Consolidated Edison • • • • • •

Corn Belt Power Cooperative • • • • ++

Delmarva Power • • • • +++

Detroit Edison • • • • • •

Dominion Resources ++++ • • • ++++

DQE, Inc. • • • • • +

Duke Power Company + • • • ++++

El Paso Electric + • • ++++

Entergy • • • • ++++

First Energy • • • • +++

Florida Municipal Power Agency ++ • • • ++++

Florida Progress +++ • • ++++

FPL Group +++ • ++++

GPU • • • • • •

Houston Industries ++++ • ++++

(continued)

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Scenario

Licensee Baseline Pessimistic Optimistic

IES Utilities • • • • ++

Illinois Power • • • • • +++

Kansas City Power & Light • • • • ++++

Long Island Lighting ++ • • • ++++

Los Angeles Department of Water and Power ++++ ++ ++++

Madison Gas & Electric +++ • ++++

Maine Yankee • • • • • • •

MidAmerican Energy • • • • ++

Municipal Electric Authority-GA. + • • • ++++

Nebraska Public Power Company • • • • ++

New York Power Authority +++ • • ++++

New York State Electric & Gas • • • • ++++

Niagara Mohawk + • • • +++

North Carolina Electric Corporation ++++ • ++++

North Carolina EMPA • • • • • +

North Carolina Municipal Power ++++ ++ ++++

Northeast Utilities • • • • • •

Northern States Power + • • • +++

Oglethorpe Power • • • • ++

Old Dominion Electric Cooperative ++++ • • ++++

Omaha Public Power District + • • • +++

Orlando Utilities Commission ++ • • ++++

Pacific Gas & Electric ++++ • ++++

PECO Energy • • • • • • • •

Pennsylvania Power & Light • • • • • +++

Piedmont Municipal Power Agency ++ • • • ++++

Pinnacle West • • • • ++++

PS Enterprise Group + • • • ++++

Public Service of New Mexico + • • • ++++

Rochester Gas & Electric • • • • ++

Salt River Project +++ • ++++

Saluda River Power ++++ • ++++

San Diego Gas & Electric ++++ +++ ++++

Scana Corporation • • • • +++

Seabrook • • • • • ++

South Carolina Public Power +++ • • ++++

Southern California Edison +++ + ++++

Southern Company • • • • +++

(continued)

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Scenario

Licensee Baseline Pessimistic Optimistic

Tennessee Valley Authority • • • • • +

Texas Utilities ++++ • • ++++

Union Electric Company + • • • ++++

Vermont Yankee + • • • +++

Washington Public Power • • • • • +

Western Resources • • • • • +

Wisconsin Energy ++ • • • ++++

Wisconsin Public Service +++ • ++++

WPL Holdings ++ • ++++

Yankee Atomic • • • • • • • • •

Legend

“+” means that fund balance was 1 to 25 percent more than expected.

“++” means that fund balance was 26 to 50 percent more than expected.

“+++” means that fund balance was 51 to 100 percent more than expected.

“++++” means that fund balance was over 100 percent more than expected.

“•“ means that fund balance was 1 to 25 percent less than expected.

“• •” means that fund balance was 26 to 50 percent less than expected.

“• • •” means that fund balance was 51 to 100 percent less than expected.

Are Licensees Now

Accumulating Funds

at Sufficient Rates to

Pay Unfunded

Decommissioning

Costs?

To answer this second question, we performed a second analysis using

another spreadsheet simulation model that is similar to and is linked to

our first model. We applied our second analysis for all three scenarios:

pessimistic, baseline, and optimistic. In this second model, we used the

same assumptions and the same basic analytic approach that we described

previously for the first model. Unlike the first question and related model,

which address the adequacy of the accumulation of decommissioning

funds by the end of 1997, this question and related model focus on future

performance. Specifically, we compared each licensee’s available

contribution9

 to its decommissioning fund in 1997 with the annual average

9

For each licensee, the available contribution—meaning funds available to pay NRC-defined

decommissioning costs—is calculated in the same way as in our first analysis. For the optimistic

scenario, the available contribution in 1997 is the actual contribution; for the baseline scenario,

86 percent of the actual contribution; and for the pessimistic scenario, 82 percent of the actual

contribution.

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present-value of the future amounts that the licensee needs to contribute

each year until its last plant has been retired.10

The comparison above is a simplified measure of the adequacy of a

licensee’s 1997 contribution. We compared the available portion of this

contribution with hypothetical future contributions in 1998 through the

final year of the licensee’s last plant to be retired. We assumed that these

expected future contributions will grow at the licensee’s after-tax rate of

return on its decommissioning fund. This measure of funding adequacy for

1997 was simplified so that we could easily list the model results for each

of the 76 licensees. In general, however, the expected future funding

stream for each of the 76 licensees is more complex than is assumed in the

simplified results and follows a different “sawtooth-shaped” pattern for

each licensee.

To undertake this analysis, we first listed the licensee’s plants, beginning

with the first plant to be retired and successively listed plants until the

licensee’s last plant to be retired. For example, if the earliest retirement of

a licensee’s two plants is a plant to be retired in 2007, this plant requires

future funding to pay for the unfunded portion of its future

decommissioning cost. The algorithm in our second simulation model

accounts for this unfunded amount over the next 10 years, starting with

1998. As with the analysis in our first model, the expected contribution

each year for this plant should equal 1/10th of that year’s present value of

the unfunded portion of the future decommissioning cost for this plant.

These yearly contributions will increase in current dollars at the fund’s

after-tax rate of return. Once in the fund, each of these expected future

amounts will continue to grow in current dollars at that same rate until the

expiration of the plant’s license. At the end of 2007, these 10 payments will

have grown in sum to exactly equal the unfunded portion; the licensee’s

future payments for this plant then drop to zero.

Furthermore, if this licensee’s second plant is to be retired in 2017, similar

future funding for it will proceed over 20 years—from 1998 through 2017.

Because we assumed in our example that the licensee’s fund balance in

1997 could pay for only part of the future decommissioning cost for the

first plant—hence, our “unfunded portion” for this first plant—the future

funding for this second plant must pay for all of its future

10For those licensees whose contribution to their fund was less in 1997 than in 1996, the results of our

second analysis are somewhat too negative, since these licensees did contribute more in 1996.

However, for most licensees, the contributions in 1997 were either greater than or equal to the

contributions in 1996.

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decommissioning costs from 1998 through 2017.11 Thus, this licensee’s

combined expected future payment stream in current dollars for both

plants grows at the after-tax rate of return until 2007. The stream then

drops in 2008 because the first plant will have been fully funded but will

then grow at the after-tax rate of return until 2017. In 2018, the unfunded

balance will decline to zero, and funding will cease.

Because of the volume of these calculations for 76 licensees, for our

baseline, pessimistic, and optimistic scenarios, respectively, we present,

for each licensee, simplified results for this second analysis. For each

licensee, we compared the available portion of its 1997 contribution to its

fund with the annual average of the present value of its total unfunded

future decommissioning cost. This total present-value cost equals the total

present value of the licensee’s required future payments to fund

decommissioning for all of its plants. For example, in the hypothetical

case discussed above, if the present value of the unfunded future cost

were $200 million, then the annual-average future payment in

present-value over 20 years would be $10 million.12 And if this licensee had

funded $10 million in 1997, it would be on track to meeting its

decommissioning obligations by 2017. If its 1997 payment were below

$10 million, it would have to increase its future yearly funding amounts by

more than the fund’s after-tax rate of return. Conversely, if its 1997

payment were above $10 million, it could increase its future payments by

less than the after-tax rate of return to achieve the funds needed to

decommission its plants.

For licensees owning only one plant having an unfunded portion of its

decommissioning cost or owning multiple plants with unfunded portions

that are to be retired in the same year, our simplified analysis yields results

exactly the same as our algorithm results. In these cases, the

sawtooth-shaped future funding pattern does not result, and the expected

future funding should grow steadily at the fund’s after-tax rate of return

over the life of its last plant to be retired. But, for licensees with the more

typical sawtooth-shaped expected funding patterns, as in our example, our

11Simply put, for each licensee, to compute the expected future funding stream, the algorithm looks at

the first plant to be retired and calculates whether the licensee has accumulated enough money to pay

for decommissioning this plant. In our example, it did not, so there was an unfunded portion. The

algorithm then funds this unfunded portion over the remaining 10 years for this plant. Because the first

plant had an unfunded portion, the algorithm then “knows” that the second plant will require full

funding; that is, no fund balances are remaining for funding this second plant. This second plant is then

fully funded over its remaining 20 years. For licensees with more than two plants, the algorithm

proceeds and asks these same questions for each successive plant and funds each plant accordingly

until there are no more plants remaining for the licensee.

12The total future decommissioning cost in 2017 current dollars would be the future cost of

$200 million in 20 years or $672 million at our baseline-assumed after-tax rate of return of 6.25 percent.

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simplified analysis effectively “transforms” such multiplant licensees into

one-plant companies. The present values of unfunded costs for these

multi-plant licensees are the same as for this single-plant licensee;

however, this “transformed” company with multiple plants has effectively

“postponed” accumulating enough money to pay its decommissioning

costs until the last plant owned by the licensee has been retired. In such

cases, the algorithm’s expected future funding will be higher in the early

years but lower in the later years than the funding implied by our

simplified analysis. In the early funding years, our simplified results for

these licensees will therefore be better than is warranted by their

algorithm results.

Current (1997) and Future

Funding Adequacy

Analysis: Results

Table I.2 shows, for our baseline, pessimistic, and optimistic scenarios, the

results of our analysis of whether each of the 76 licensees is currently on

track to accumulate sufficient funds in the future to decommission its

nuclear power plants. The table shows, for each licensee, whether its

funding in 1997 for NRC-defined decommissioning costs was more or less

than the annual-average present value of its total unfunded future

decommissioning costs for all of its plants.

Our analysis of the second question shows a wide range of results among

the three scenarios for each individual licensee and among all licensees

within each scenario. As with the first analysis, the results for the

pessimistic and optimistic scenarios should be viewed as extreme lower

and upper bounds, whereas the baseline scenario indicates the most likely

results.

For all 76 licensees combined, in 1997 licensees contributed, on average,

46 percent above the expected level of funds in the baseline scenario. This

percentage is associated with a $14 billion present value of unfunded

future decommissioning costs. Recall that the average available fund

balance for all licensees at the end of 1997 was about 3 percent less than

the expected balance. Therefore, these two results suggest that licensees

have currently increased the rates at which they are accumulating funds to

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offset previous underfunding.13 Viewed as a lower bound, in the

pessimistic scenario, licensees, on average, contributed funds in 1997 at 60

percent below the expected amount (with a $51 billion present value of

unfunded cost). Viewed as an upper bound, in the optimistic scenario, the

licensees contributed funds in 1997 at 262 percent above the expected

amount (with a $1 billion present value of unfunded cost).

For all three scenarios, most licensees’ funding in 1997, relative to their

expected levels, was better than their respective funding up until the end

of 1997. In the baseline scenario, only 17 of the 76 licensees had not added

sufficient funds in 1997 for eventual decommissioning. Nonetheless, the

fact that four licensees contributed funds in 1997 below their expected

levels in our optimistic scenario (see table I.2) may be cause for concern.

Conditions may be worse than those assumed in that scenario. This is

particularly so if retail competition in the electricity markets lowers

electricity rates and profits. Conversely, the fact that 10 licensees

contributed funds above their expected amounts in 1997 in the pessimistic

scenario suggests that these licensees may be able to reduce their funding

in the future because future conditions will likely be better than those

assumed under this scenario.

Table I.2: Licensees That Accumulated

More or Less Funds (by Percentage

Above or Below) in 1997 Than the

Annual-Average of the Present Value

of the Future Amounts Required

Scenario

Licensee Baseline Pessimistic Optimistic

American Electric Power ++++ • • ++++

Atlantic Energy ++++ + ++++

Baltimore Gas & Electric +++ • • • ++++

Boston Edison + • • • ++++

Carolina Power & Light +++ • • • ++++

Central and Southwest + • • • ++++

Central Hudson Gas & Electric +++ • • • ++++

Central Iowa Power Corporation • • • • • • • •

City of Austin ++++ • • ++++

(continued)

13As stated earlier, for many licensees our simplified results from the second analysis will be better

than are warranted by our algorithm results. However, this simplification improves the results

substantially for only a few of the 76 licensees. For example, for only three licensees in the baseline

scenario do their 1997 contributions (1) fall short of the present value of their 1998 ideal contributions

but (2) exceed the annual-average present-value of their future contributions. Thus, our results listed

in table I.2 for the adequacy of future funding may be too favorable for Commonwealth Edison, Detroit

Edison, and Northeast Utilities. These types of licensees have plants with unfunded future

decommissioning costs whose licenses will expire early in the future but have other unfunded plants

whose licenses will expire much further in the future. The percentage that the 1997 contribution falls

short of the algorithm’s 1998 contribution reflects this need for an early accumulation of funds to pay

for those plants to be retired relatively early.

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Scenario

Licensee Baseline Pessimistic Optimistic

City of San Antonio ++++ • • ++++

CMS Energy ++++ • • • ++++

Commonwealth Edison ++ • • • ++++

Connecticut Yankee Atomic Power

Corporation ++++ • • ++++

Consolidated Edison ++ • • • ++++

Corn Belt Power Cooperative + • • • ++++

Delmarva Power +++ • • • ++++

Detroit Edison ++++ • • • ++++

Dominion Resources ++++ • • • ++++

DQE, Inc. +++ • • ++++

Duke Power Company ++++ • • ++++

El Paso Electric +++ • • ++++

Entergy ++++ • • ++++

First Energy ++ • • • ++++

Florida Municipal Power Agency • • • • ++++

Florida Progress ++++ • • • ++++

FPL Group ++++ ++ ++++

GPU • • • ++++

Houston Industries ++++ + ++++

IES Utilities • • • • ++++

Illinois Power • • • • • +++

Kansas City Power & Light • • • • ++++

Long Island Lighting +++ • • • ++++

Los Angeles Department of Water and Power ++++ ++++ ++++

Madison Gas & Electric ++++ +++ ++++

Maine Yankee • • • • • • • • •

MidAmerican Energy +++ • • • ++++

Municipal Electric Authority-GA. ++ • • • ++++

Nebraska Public Power Company ++++ • • ++++

New York Power Authority ++++ • • • ++++

New York State Electric & Gas ++ • • • ++++

Niagara Mohawk ++++ • ++++

North Carolina Electric Corporation ++++ • • ++++

North Carolina EMPA • • • • • • +

North Carolina Municipal Power ++++ • • ++++

Northeast Utilities ++++ + ++++

Northern States Power ++++ • • • ++++

(continued)

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Scenario

Licensee Baseline Pessimistic Optimistic

Oglethorpe Power • • • • • • •

Old Dominion Electric Cooperative ++++ • • • ++++

Omaha Public Power District ++++ • • • ++++

Orlando Utilities Commission ++++ • ++++

Pacific Gas & Electric ++++ • ++++

PECO Energy • • • • • +

Pennsylvania Power & Light • • • • • ++++

Piedmont Municipal Power Agency ++ • • • ++++

Pinnacle West +++ • • ++++

PS Enterprise Group +++ • • ++++

Public Service of New Mexico +++ • • ++++

Rochester Gas & Electric ++++ • ++++

Salt River Project ++ • • • ++++

Saluda River Power ++++ • ++++

San Diego Gas & Electric ++++ ++++ ++++

Scana Corporation • • • • ++++

Seabrook ++++ • • ++++

South Carolina Public Power ++++ • • • ++++

Southern California Edison ++++ ++++ ++++

Southern Company +++ • • ++++

Tennessee Valley Authority • • • • • • ++

Texas Utilities ++++ • • • ++++

Union Electric Company • • • • ++++

Vermont Yankee ++++ • • • ++++

Washington Public Power • • • • ++++

Western Resources • • • • • • +

Wisconsin Energy ++++ • • • ++++

Wisconsin Public Service ++++ ++++ ++++

WPL Holdings ++++ +++ ++++

Yankee Atomic • • • • • • • • •

(Table notes on next page)

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Legend:

“+” means that the licensee accumulated from 1 to 25 percent more funds in 1997 than the

annual average of the present value of the amounts required in 1998 and each subsequent year

until the licensee’s last plant is retired.

“++” means that the licensee accumulated from 26 to 50 percent more funds in 1997 than the

annual average of the present value of the amounts required in 1998 and each subsequent year

until the licensee’s last plant is retired.

“+++” means that the licensee accumulated from 51 to 100 percent more funds in 1997 than the

annual average of the present value of the amounts required in 1998 and each subsequent year

until the licensee’s last plant is retired.

“++++” means that the licensee accumulated over 100 percent more funds in 1997 than the

annual average of the present value of the amounts required in 1998 and each subsequent year

until the licensee’s last plant is retired.

“•“ means that the licensee accumulated from 1 to 25 percent less funds in 1997 than the annual

average of the present value of the amounts required in 1998 and each subsequent year until the

licensee’s last plant is retired.

“• •” means that the licensee accumulated from 26 to 50 percent less funds in 1997 than the

annual average of the present value of the amounts required in 1998 and each subsequent year

until the licensee’s last plant is retired.

“• • •” means that the licensee accumulated from 51 to 100 percent less funds in 1997 than the

annual average of the present value of the amounts required in 1998 and each subsequent year

until the licensee’s last plant is retired.

Page 54 GAO/RCED-99-75 Nuclear Regulation
Appendix II 

Comments From the Nuclear Regulatory

Commission

Note: GAO comments

supplementing those in the

report text appear at the

end of this appendix.

Page 55 GAO/RCED-99-75 Nuclear Regulation
Appendix II 

Comments From the Nuclear Regulatory

Commission

See comment 1.

Now on p. 34.

See comment 2.

Page 56 GAO/RCED-99-75 Nuclear Regulation
Appendix II 

Comments From the Nuclear Regulatory

Commission

Now on p. 30.

See comment 3.

Now on p. 5.

See comment 3.

Now on p. 22.

Page 57 GAO/RCED-99-75 Nuclear Regulation
Appendix II 

Comments From the Nuclear Regulatory

Commission

See comment 3.

Now on pp. 32 and 33.

See comment 4.

Page 58 GAO/RCED-99-75 Nuclear Regulation
Appendix II 

Comments From the Nuclear Regulatory

Commission

Now on p. 41.

See comment 5.

Page 59 GAO/RCED-99-75 Nuclear Regulation
Appendix II 

Comments From the Nuclear Regulatory

Commission

The following are GAO’s comments on the Nuclear Regulatory

Commission’s letter dated March 26, 1999.

GAO’s Comments 1. NRC commented that, although our statement that it did not establish

thresholds related to unacceptable levels of financial assurances is true,

the statement does not reflect NRC’s stated intent to examine the results of

the initial licensee’s financial reports before determining an appropriate

course of action. We did, however, recognize NRC’s intention in our report.

Moreover, both our draft and final report preface our recommendations

with the statement that NRC should act after reviewing licensees’ initial

reports. Accordingly, we did not revise this aspect of our report.

2. NRC stated that, as long as a rate regulator (such as a state public utility

commission) is providing for the ultimate recovery of decommissioning

costs from ratepayers, our assertion that under-funding is occurring is

incorrect, because the reasonable assurance of future funding has been

identified. NRC’s comment is misleading. We recognize in our report that,

as a matter of policy, NRC defers the establishment of the details of

licensees’ decommissioning funding to rate regulators as long as those

details would lead to the accumulation of at least the amounts calculated

in NRC’s formula by the time plants’ operating licenses expire. We did not

assert, as NRC stated, that any licensee was underfunded in the sense of not

being in compliance with the regulatory requirements of NRC or its rate

regulators. What we did say was that to have “sufficient” or “expected”

amounts of funds, licensees would need to accumulate increasing (but

constant present-value) amounts annually and that the sum of these

annual amounts, plus earned income, would equal the total estimated

decommissioning costs when the licensees’ plants’ operating license

expires. Therefore, we did not revise our report.

3. We added additional material to our report in response to NRC’s

comment.

4. NRC characterized as “erroneous” our assertion that of its safety

oversight initiative for nuclear power plants reflects NRC’s lack of criteria

for acting on licensees’ decommissioning financial reports. NRC said the

safety oversight initiative is directed to actual safety requirements and not

to the reports that provide NRC with information on how licensees are

complying with those requirements. NRC’s comment too narrowly

describes the scope of its safety oversight initiative. In particular, the

comment is silent on the initiative’s efforts to develop improved

Page 60 GAO/RCED-99-75 Nuclear Regulation
Appendix II 

Comments From the Nuclear Regulatory

Commission

assessment methods, such as integrating data on licensees’ performances

and the results of NRC’s inspections, determining appropriate actions by

NRC on the basis of assessment results, and communicating results to

licensees and the public. Our assertion was intended to illustrate the fact

that, although NRC has begun requiring biennial financial reports, it has not

publicly stated what actions it would expect to take if the information in a

licensee’s report indicates that the licensee may not be meeting NRC’s

financial assurance requirements for decommissioning. Therefore, we did

not revise our report.

5. NRC stated that the “optimistic” after-tax rate of return on investments

of decommissioning funds could be 8 or 9 percent, rather than the

7-percent rate of return that we used, because the historic long-term rate

of return on stocks has been about 10 percent before taxes. Predicting the

rate of return on investments for 20 years or more into the future is

essentially speculative. We chose the 7-percent rate for our optimistic case

because regulated utilities were traditionally required to invest

conservatively in government securities and only recently have been

permitted to invest some of their funds in higher-risk, potentially more

profitable, financial instruments. In this regard, NRC’s guidance for its staff

on evaluating a licensee’s decommissioning funding assurances notes that

“. . .corporate or municipal bonds or preferred stocks should be rated at

least ‘BBB’ by Moody’s or an equivalent rating by another bond rating

agency.” The guidance also states that (1) although NRC does not explicitly

prohibit investments in common stocks, speculative issues should be

avoided and (2) as long as the fund is invested in a diversified portfolio,

losses in any one issue of stocks, bonds, or other investments should not

significantly affect the value of the decommissioning fund. A diversified

portfolio would contain bonds and preferred stocks, as well as common

stocks. Such a portfolio would likely achieve a lower after-tax rate of

return in the long run than the return on a portfolio containing only

common stocks. This portfolio would, however, have the benefit of a

lower market risk. In any case, our assumption of a 7-percent rate of

return is just one of the optimistic assumptions used in our optimistic

scenario. In this scenario, we assume optimistic values for all five of our

key assumptions. Therefore, the results for each licensee should be viewed

as very optimistic upper bounds.

For these reasons, we continue to believe that our use of an after-tax rate

of return of 7 percent for our optimistic scenario is appropriate and

therefore did not revise our report.

Page 61 GAO/RCED-99-75 Nuclear Regulation
Appendix III 

Major Contributors to This Report

Resources,

Community, and

Economic

Development

Division, Washington,

D.C.

Mr. Dwayne E. Weigel, Assistant Director

Mr. Philip A. Olson, Evaluator-in-Charge

Mr. John E. Bagnulo, Senior Evaluator

Ms. Mehrzad Nadji, Assistant Director for Economic Analysis

Mr. Daniel G. Williams, Senior Economist

Ms. Doreen S. Feldman, Assistant General Counsel

Ms. Susan W. Irwin, Senior Attorney

Ms. Delores A. Hemsley, Administrative Operations Assistant

Page 62 GAO/RCED-99-75 Nuclear Regulation
Page 63 GAO/RCED-99-75 Nuclear Regulation
Related Products

Nuclear Regulation: Slow Progress in Identifying and Cleaning Up NRC’s

Licensees’ Contaminated Sites (GAO/RCED-95-95, Apr. 24, 1995).

Nuclear R&D: Research Efforts Under Way to Support Nuclear Power

Plant License Renewal (GAO/RCED-91-207, Sept. 25, 1991).

Nuclear Research and Development: Shippingport

Decommissioning—How Applicable Are the Lessons Learned?

(GAO/RCED-90-208, Sept. 4, 1990).

Nuclear R&D: Usefulness of Information From Shippingport

Decommissioning for Rancho Seco (GAO/RCED-90-171, June 7, 1990).

Nuclear Regulation: NRC’s Decommissioning Procedures and Criteria Need

to Be Strengthened (GAO/RCED-89-119, May 26, 1989).

Nuclear Regulation: License Renewal Questions for Nuclear Plants Need

to Be Resolved (GAO/RCED-89-90, Apr. 3, 1989).

Nuclear Regulation: NRC’s Decommissioning Cost Estimates Appear Low

(GAO/RCED-88-184, July 29, 1988).

(141109) Page 64 GAO/RCED-99-75 Nuclear Regulation
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