Nuclear Regulation: Better Oversight Needed to Ensure Accumulation of
Funds to Decommission Nuclear Power Plants (Chapter Report, 05/03/99,
GAO/RCED-99-75).
Pursuant to a congressional request, GAO provided information on the
potential cost to decommission nuclear power plants and the implications
of competition within the electricity industry, focusing on whether: (1)
there is adequate assurance that the Nuclear Regulatory Commission's
(NRC) 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.
GAO noted that: (1) 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; (2) GAO's analysis showed
that, under likely assumptions, 36 of 76 licensees had not accumulated
sufficient decommissioning funds through 1997; (3) 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; (4) using more pessimistic and optimistic
assumptions would increase or decrease the number of underfunded
licensees, respectively; (5) although utility commissions have permitted
licensees to continue charging their customers for the costs of
decommissioning prematurely-retired plants, this financial safeguard
could be affected by states' efforts to deregulate the electricity
industry; (6) 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 or state utility commissions will no longer
guarantee, through the regulation of electricity rates, the collection
of sufficient funds for decommissioning; (7) however, one additional
form of financial assurance--the early payment of decommissioning
costs--may not be practicable or affordable; (8) 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; (9) 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; (10) thus, the
effectiveness of NRC's 1998 regulatory changes will likely depend on how
vigorously NRC monitors the financial health of its licensees; (11) in
this regard, licensees must now provide financial reports every 2 years
to NRC so it can monitor financial assurances for decommissioning; and
(12) 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.
--------------------------- Indexing Terms -----------------------------
REPORTNUM: RCED-99-75
TITLE: Nuclear Regulation: Better Oversight Needed to Ensure
Accumulation of Funds to Decommission Nuclear Power
Plants
DATE: 05/03/99
SUBJECT: Licenses
Reporting requirements
Future budget projections
Electric utilities
Regulatory agencies
Nuclear powerplants
Nuclear reactors
Nuclear waste disposal
Obsolete facilities
Utility rates
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NUCLEAR REGULATION: Better Oversight Needed to Ensure Accumulation
of Funds to Decommission Nuclear Power Plants GAO/RCED-99-75
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/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
GAO/RCED-99-75 Nuclear Regulation Page 2
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.
GAO/RCED-99-75 Nuclear Regulation Page 3
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
GAO/RCED-99-75 Nuclear Regulation Page 4
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.
GAO/RCED-99-75 Nuclear Regulation Page 5
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.
GAO/RCED-99-75 Nuclear Regulation Page 6
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.
GAO/RCED-99-75 Nuclear Regulation Page 7
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
GAO/RCED-99-75 Nuclear Regulation Page 8
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
GAO/RCED-99-75 Nuclear Regulation Page 9
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
GAO/RCED-99-75 Nuclear Regulation Page 10
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.
GAO/RCED-99-75 Nuclear Regulation Page 11
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.
GAO/RCED-99-75 Nuclear Regulation Page 12
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.
GAO/RCED-99-75 Nuclear Regulation Page 13
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.
GAO/RCED-99-75 Nuclear Regulation Page 14
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.
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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- 2 a Pa. Mar. 1979 1 La Crosse Wis. Apr.
1987 20 Fort St. Vrain Colo. Aug. 1989 16 Shoreham b 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 a TMI- 2 (Three
Mile Island Unit 2) operated just over 1 year before incurring an
accident that resulted in the plant's retirement. b Over 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.
a The 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 [millirem 9 ] 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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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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Appendix I 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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of 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/ DRI
6 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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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
contribution 9 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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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
10 For 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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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
11 Simply 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.
12 The 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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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)
13 As 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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Licensees' Decommissioning Funds
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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Appendix I Scope, Methodology, and Results of Analyses of
Licensees' Decommissioning Funds
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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Licensees' Decommissioning Funds
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.
GAO/RCED-99-75 Nuclear Regulation Page 54
Appendix II Comments From the Nuclear Regulatory Commission
Note: GAO comments supplementing those in the report text appear
at the end of this appendix.
GAO/RCED-99-75 Nuclear Regulation Page 55
Appendix II Comments From the Nuclear Regulatory Commission
See comment 1. Now on p. 34.
See comment 2.
GAO/RCED-99-75 Nuclear Regulation Page 56
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.
GAO/RCED-99-75 Nuclear Regulation Page 57
Appendix II Comments From the Nuclear Regulatory Commission
See comment 3. Now on pp. 32 and 33.
See comment 4.
GAO/RCED-99-75 Nuclear Regulation Page 58
Appendix II Comments From the Nuclear Regulatory Commission
Now on p. 41. See comment 5.
GAO/RCED-99-75 Nuclear Regulation Page 59
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
GAO/RCED-99-75 Nuclear Regulation Page 60
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.
GAO/RCED-99-75 Nuclear Regulation Page 61
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
GAO/RCED-99-75 Nuclear Regulation Page 62
GAO/RCED-99-75 Nuclear Regulation Page 63
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) GAO/RCED-99-75 Nuclear Regulation Page 64
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