Order Code RL33442
CRS Report for Congress
Received through the CRS Web
Nuclear Power: Outlook for New U.S. Reactors
May 31, 2006
Larry Parker and Mark Holt
Specialists in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress

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Nuclear Power: Outlook for New U.S. Reactors
Summary
Nearly three decades after the most recent order was placed for a new nuclear
power plant in the United States, several utilities are now expressing interest in
building a total of up to 20 new reactors. The renewed interest in nuclear power has
resulted primarily from sharply rising prices for natural gas, improved operation of
existing reactors, and uncertainty about future restrictions on coal emissions. A
substantial tax credit for nuclear generation provided by the Energy Policy Act of
2005 (P.L. 109-58) is also likely to improve the economic viability of qualifying new
reactors. New nuclear plant applications can also take advantage of amendments to
the Atomic Energy Act made in the early 1990s to reduce licensing delays.
Currently, there are 103 licensed power reactors at 65 plant sites in 31 states,
generating about one-fifth of U.S. electricity. Although no new U.S. reactors have
started up since 1996, U.S. nuclear electricity generation has since grown by more
than 20%. Much of this additional output resulted from reduced downtime, notably
through shorter refueling outages. Licensed commercial reactors generated electricity
at an average of 89.4% of their total capacity in 2005, after averaging about 75% in
the mid-1990s and about 65% in the mid-1980s.
Falling operating costs have helped renew the nation’s fleet of nuclear power
plants. From 1989 to 1998, 12 commercial reactors were closed before reaching the
end of their 40-year licenses. By the late 1990s, real doubt existed as to whether any
reactors would make it to 40 years. Since 2000, however, 39 commercial reactors
have received 20-year license extensions from the Nuclear Regulatory Commission
(NRC), giving them up to 60 years of operation, and more are pending.
The nuclear production tax credit in the Energy Policy Act could have a
significant impact on the economic viability of new nuclear power plants. Under
base case assumptions, nuclear is not competitive with either coal-fired or natural
gas-fired facilities. However, if new reactors are able to take full advantage of the
nuclear production tax credit, nuclear power appears competitive with either natural
gas-fired or coal-fired facilities.
Other factors will also be important in the commercial decision to invest in new
nuclear plants, such as fossil fuel prices and the regulatory environment for both
nuclear power and future fossil fuel-fired generation. If natural gas prices remain at
historically high levels, future nuclear plants will be more likely to be competitive
without federal tax credits. However, natural gas prices have been highly cyclical in
the past, raising the possibility that nuclear costs could be undercut in the future.
Any substantial mandatory greenhouse gas control program would probably
affect the cost of new coal-fired and natural gas-fired generation relative to nuclear
power, particularly if nuclear power is assumed to have no greenhouse gas emissions.
Continued delays in nuclear waste disposal facilities — forcing spent fuel to be
stored at plant sites — could also affect the decision to construct new reactors.
This report will not be updated.

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Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Current Status of U.S. Nuclear Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Federal Initiatives To Encourage New Nuclear Power Plant Construction . . . . . . 5
NRC Licensing Reform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
DOE Nuclear Power 2010 Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Energy Policy Act of 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Nuclear Production Tax Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Regulatory Risk Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Loan Guarantees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Analysis of New Nuclear Power Plant Construction . . . . . . . . . . . . . . . . . . . . . . 11
Base Case Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Base Case Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Impact of 2005 Energy Policy Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Volatile Natural Gas Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Greenhouse Gas Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Nuclear Waste . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
List of Figures
Figure 1. Net Nuclear Generation vs. Capacity, 1973-2004 . . . . . . . . . . . . . . . . . 4
Figure 2. Relationship Between Combined Licenses, Early Site
Permits, and Standard Design Certifications . . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 3. Natural Gas Prices Delivered to Electric Utilities . . . . . . . . . . . . . . . . 15
List of Tables
Table 1. Announced Nuclear Plant License Applications . . . . . . . . . . . . . . . . . . 2
Table 2. Projected 2015 Costs and Assumptions . . . . . . . . . . . . . . . . . . . . . . . . 12
Table 3. Projected 2015 Annualized Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Table 4. Projected 2015 Annualized Costs, Including Subsidized
Nuclear Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Table 5. Effect of Natural Gas Prices on Production Costs . . . . . . . . . . . . . . . . 15
Table 6. Per-Ton CO Permit Price Estimates for Greenhouse Gas Initiatives . 18
2
Table 7. 2015 and 2020 Projected Annualized Costs with Increased
Costs from Greenhouse Gas Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Table 8. Effect of Permit Prices/Carbon Tax on Electricity
Production Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

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Nuclear Power: Outlook for New
U.S. Reactors
Introduction
Construction of new nuclear power plants in the United States was almost
unimaginable during the 1980s and 1990s. Vague rumors about possible new
reactors would occasionally prompt a flurry of speculation, but they were invariably
unfounded. In fact, no reactor has been ordered in the United States since1978, and
that plant was later cancelled, as were all U.S. reactor orders after 1973. No U.S.
reactor has been completed since 1996 — the Tennessee Valley Authority’s Watts
Bar 1, which had been ordered in 1970.
Today, there are still no orders, but interest in new U.S. reactors is no longer
merely a rumor. In 2003, three utilities submitted applications to the Nuclear
Regulatory Commission (NRC) for early approval of potential future reactor sites
under a cost-shared program with the Department of Energy (DOE). In 2004, DOE
announced cost-sharing agreements with two industry consortia to apply for NRC
licenses to construct and operate new reactors. Since then, several more utilities have
announced plans to apply for reactor licenses (as shown in Table 1), totaling as many
as 20 new nuclear units. NRC Chairman Nils J. Diaz told the Senate Energy and
Natural Resources Committee at a May 2006 hearing that as many as five additional
license applications were under consideration, for a total of 25 reactors.1
The renewed interest in nuclear power has resulted primarily from sharply rising
prices for natural gas, improved operation of existing reactors, and uncertainty about
future restrictions on coal emissions. Until the recent price volatility, low fuel costs
had helped gas-fired power plants dominate the market for new baseload generation
since the late 1980s. Nuclear power’s relatively stable costs and low air emissions
may now appear more attractive, particularly combined with a substantial tax credit
for nuclear generation provided by the Energy Policy Act of 2005 (P.L. 109-58).
New nuclear plant applications can also take advantage of amendments to the Atomic
Energy Act made in the early 1990s to reduce licensing delays.2
In announcing the new reactor license applications, however, utilities have made
clear that they are not committed to actually building the reactors, even if the licenses
are approved. Large uncertainties about nuclear plant construction costs still remain,
1 Senate Committee on Energy and Natural Resources, “16 Utility Companies Plan 25 New
Nuke Plants Despite Uncertainty over Yucca Mountain,” Committee News Release, May
22, 2006.
2 Energy Policy Act of 1992, Title XXVIII, P.L. 102-486.

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along with doubts about progress on nuclear waste disposal and concerns about
public opposition. All those problems helped cause the long cessation of U.S. reactor
orders and will need to be addressed before financing for new multibillion-dollar
nuclear power plants can be obtained.
Table 1. Announced Nuclear Plant License Applications
Planned
Announced
Site
Application
Reactor Type
Units
Applicant
Date
Constellation
Calvert Cliffs (MD),
Energy
Nine Mile Point (NY),
2008-2009
Areva EPR
1-4
or others
Dominion
North Anna (VA)
3Q 2007
GE ESBWR
2
Duke Power
Cherokee (SC)
2007-2008
West. AP1000
2
Entergy
River Bend (LA)
2008
GE ESBWR
1
Florida Power and
Not specified
2009
Not specified
1
Light
NuStart
Grand Gulf (MS)
2007-2008
GE ESBWR
1
Bellefonte (AL)
2007
West. AP1000
1
Progress Energy
Harris (NC)
2007-2008
West. AP1000
2
Florida
2007-2008
West. AP1000
2
SCE&G/Santee
Summer (SC)
3Q 2007
West. AP1000
2
Cooper
Southern
Vogtle (GA)
2008
West. AP1000
2
Total units
17-20
Sources: Nucleonics Week, company news releases.
Federal energy policy may play a crucial role in determining whether the current
interest in new nuclear reactors leads to a significant expansion of the U.S. nuclear
power industry. Nuclear opponents have long maintained that nuclear power will
never be economically viable without federal subsidies and should be abandoned in
favor of safer alternatives. But supporters contend that nuclear power will be vital
in diversifying the nation’s future energy supply and reducing greenhouse gas
emissions, and that federal subsidies for at least the first few new reactors are
justified. The greenhouse gas issue has also prompted some environmentalists to
support nuclear power expansion.
This report includes analyses of the potential effect of the tax credit for nuclear
power provided by the Energy Policy Act of 2005 and possible competitive effects
of various proposals to limit greenhouse gas emissions. Under baseline assumptions,
the cost of electricity from new nuclear power plants is likely to be higher than power
generated by new coal- and natural gas-fired plants. The new nuclear tax credit
would more than offset that cost disadvantage, but it is limited to the first 6,000

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megawatts of new nuclear generating capacity — about four to six reactors. If the
tax credit results in new reactor construction, the next question will be whether
nuclear construction would continue without additional credits. Greenhouse gas
legislation could also be an important factor in nuclear power economics; analysis
shows that some proposals, if enacted, could push the cost of coal- and natural gas-
fired electricity above projected nuclear costs.
Current Status of U.S. Nuclear Industry
After the apparently successful commercialization of nuclear power in the
1960s, the Atomic Energy Commission anticipated that more than 1,000 reactors
would be operating in the United States by the year 2000.3 But by the end of the
1970s, it had become clear that nuclear power would not grow nearly that
dramatically, and more than 120 reactor orders were ultimately cancelled. Currently,
103 licensed power reactors operate at 65 plant sites in 31 states (not including the
Tennessee Valley Authority’s [TVA’s] Browns Ferry 1, which has not operated since
1985; TVA is spending about $1.8 billion to restart the reactor by 2007).
Despite falling short of some expectations, however, U.S. nuclear power
production has grown steadily since its inception and now exceeds electricity
generated from oil, natural gas, and hydro plants, and trails only coal, which accounts
for more than half of U.S. electricity generation. Nuclear plants generate more than
half the electricity in six states. The near-record 818 billion kilowatt-hours of nuclear
electricity generated in the United States during 20054 was more than the nation’s
entire electrical output in the early 1960s, when the first large-scale commercial
reactors were being ordered, and more than twice the 2005 total electrical generation
of Great Britain.5
As indicated in Figure 1, although no new U.S. reactors have started up since
1996, U.S. nuclear electricity generation has since grown by more than 20%.6 Much
of this additional output resulted from reduced downtime, notably through shorter
refueling outages, which typically take place every 18 months. Licensed commercial
reactors generated electricity at an average of 89.4% of their total capacity in 2005,
after averaging around 75% in the mid-1990s and around 65% in the mid-1980s.7
Reactor modifications to boost capacity have also been a factor in the continued
growth of nuclear power production. Since 1996, NRC has approved more than 60
requests for power uprates, totaling about 2,500 megawatts of electrical generating
3 Seaborg, Glenn T., The Plutonium Economy of the Future, Oct. 5, 1970, p. 7.
4 “World’s Nuclear Performance in 2005 Close to 2004’s,” Nucleonics Week, Feb. 9, 2006,
p. 1.
5 International Energy Agency, Monthly Electricity Survey, January 2006.
6 Energy Information Administration, International Energy Annual 2003, Table 2.7;
Nucleonics Week, op. cit.
7 Nucleonics Week, op. cit.; Nuclear Engineering International, November 2005, p. 37.

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capacity — about the capacity of two large reactors.8 The uprates largely offset the
closure of five poorly performing reactors, totaling 3,700 megawatts of capacity, in
1997 and 1998.9 Further uprate requests are pending.
Figure 1. Net Nuclear Generation vs. Capacity, 1973-2004
Source: Energy Information Administration.
Note: Generation is read on the left scale (in billion kilowatt-hours) and capacity (in
gigawatts) is on the right.
The improved operation of nuclear power plants has helped drive down the cost
of nuclear-generated electricity. Average operations and maintenance costs
(including fuel) dropped steadily from a high of about 3.5 cents/kilowatt-hour (kwh)
in 1987 to below 2 cents/kwh in 2001 (in 2001 dollars).10 By 2004 (the most recent
8 Nuclear Regulatory Commission, Power Uprates for Nuclear Plants, Fact Sheet, July
2004.
9 Nuclear News, “World List of Nuclear Power Plants,” March 2005, p. 59.
10 Uranium Information Centre, The Economics of Nuclear Power, Briefing Paper 8,
January 2006, p. 3.

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year available), the average operating cost was 1.7 cents/kwh11 — competitive with
coal- and natural gas-fired generation.12
Falling operating costs have helped renew the nation’s existing fleet of nuclear
power plants. From 1989 to 1998, 12 commercial reactors were closed before
reaching the end of their 40-year licenses — one of them, Oregon’s Trojan plant —
after only 15 years of operation.13 By the late 1990s, there was real doubt about
whether any reactors would make it to 40 years. Since 2000, however, 39
commercial reactors have received 20-year license extensions from NRC, giving
them up to 60 years of operation. License extensions for 12 more reactors are
currently under review, and many others are anticipated, according to NRC.14 The
license extension trend has been spurred partly by favorable rate treatment of nuclear
plants’ unrecovered capital costs (“stranded costs”) in states that have deregulated the
power generation sector.
Industry consolidation could also help existing nuclear power plants, as larger
nuclear operators purchase plants from utilities that run only one or two reactors.
Several such sales have occurred, including the March 2001 sale of the Millstone
plant in Connecticut to Dominion Energy for a record $1.28 billion. The merger of
two of the nation’s largest nuclear utilities, PECO Energy and Unicom, completed
in October 2000, consolidated the operation of 17 reactors under a single corporate
entity, Exelon Corporation, headquartered in Chicago. Exelon and New Jersey-based
Public Service Enterprise Group announced a merger on December 20, 2004, that
would boost the combined firm’s reactor fleet to 20.
Federal Initiatives To Encourage New Nuclear Power
Plant Construction
With the Energy Policy Act of 2005, the federal government has adopted
aggressive incentives for building new reactors — including tax credits, loan
guarantees, and compensation for regulatory delays. These incentives build on
previous regulatory and legislative initiatives, particularly a more streamlined NRC
licensing process and DOE’s Nuclear Power 2010 program to test that process.
NRC Licensing Reform
Until 1989, licensing a new nuclear power facility involved a two-step process:
(1) an NRC-issued construction permit that allowed an applicant to begin building
a facility and (2) an operating license that permitted the facility to generate electricity
11 Nucleonics Week, “U.S. Utility Operating Costs, 2004,” July 17, 2005, p. 14.
12 Energy Information Administration, Nuclear Power: 12 percent of America’s Generating
Capacity, 20 percent of the Electricity, July 17, 2003, at [http://www.eia.doe.gov/cneaf/
nuclear/page/analysis/nuclearpower.html].
13 Nuclear News, op. cit.
14 See [http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html]

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for sale.15 This procedure resulted in some celebrated cases in which completed or
nearly completed plants awaited years to be granted operating licenses — delays that
drove up the costs of the affected plants. In 1989, NRC issued regulations to
streamline this process in three ways:16
! The Early Site Permit Program allows utilities to get their proposed
reactor sites approved by the NRC before a decision is made on
whether or not to build the plant. These preapproved sites can be
“banked” for future use.
! Standard Design Certification for advanced reactor designs allows
vendors to get their designs approved by NRC for use in the United
States, so utilities can then deploy them essentially “off the shelf.”
! The Combined Construction and Operating License (COL) provides
a “one-step” approval process, in which all licensing hearings for a
proposed plant are expected to be conducted before construction
begins. The COL would then allow a completed plant to operate if
inspections, tests, analyses, and acceptance criteria (ITAAC) were
met. This is intended to reduce the chances for regulatory delays
after a plant is completed.17
The relationships among these three components are illustrated in Figure 2. A
COL application could reference a preapproved site and a certified plant design, so
that most siting and design issues would not need to be revisited. Upon completion,
the reactor could begin operating after NRC determined that the ITAAC had been
met. The overall goal of these reforms was to introduce as much regulatory certainty
into the process before a company has to make a major financial investment in a
project. However, the process has never been used, so it remains uncertain how
much time will be saved by referencing preapproved sites and certified designs, or
how difficult the ITAAC checkoff process might be.
The procedures envision a three-step decision-making process, allowing the
utility to make “go/no-go” decisions at several points before a major investment is
made in the project. The first step to building a new facility is to conduct utility level
project analysis, including needs assessment, scoping analysis, and identification of
siting issues. This is anticipated to take about 2-4 years, and some utilities have
already begun this process (see Table 1). Assuming the utility finds nuclear power
to be a viable option, it will have to address three issues in this pre-application
process. First, the utility will have to evaluate safety-related issues, such as seismic
and geologic data, population demographics, and potential consequences of
hypothetical accidents. Second, the utility will have to evaluate environmental
issues, such as maximum radiological and thermal effluents. Third, the utility will
15 10 CFR Part 50.
16 54 Federal Register 15372, Apr. 18, 1989.
17 After the combined license regulations were challenged in court, Congress endorsed the
procedure in the Energy Policy Act of 1992 (P.L. 102-486), Title XXVIII.

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have to address emergency planning issues, such as evacuation routes. The utility
may use NRC early site permit process to conduct this evaluation but is not required
to do so.
Figure 2. Relationship Between Combined Licenses, Early
Site Permits, and Standard Design Certifications
Source: NRC.
Assuming the utility finds the site suitable and the project potentially
economical, it submits the above information, along with further details, to the NRC
to obtain a COL. The licensing process is estimated by NRC to take at least three
years.18 The additional information that the utility must submit includes financial
data, justification for the capacity addition, and complete details on reactor design.
On this last point, the utility is likely to reference a standard design certification but
is not required to do so. The utility must also provide the ITAAC for the eventual
NRC approval to operate the plant. The NRC reviews the application, holds
hearings, and makes a decision on granting the COL.
Finally, the utility must decide whether to build the power plant. Current
projections of nuclear power construction schedules assume that a plant can be built
in 5-7 years. At the end of construction, the NRC verifies that the new plant meets
the ITAAC in the COL and the facility is allowed to operate. Overall, the process is
anticipated to take 10-15 years.
18 Knapik, Michael, and Jenny Weil, “Diaz: Eight Years, at Best, to License, Build New Unit
if Application High Quality,” Inside NRC, Nov. 14, 2005, p. 1.

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If this streamlined process works as intended, it may remove some of the
previous regulatory uncertainty surrounding new nuclear plant construction and make
financing of such projects more feasible. This is particularly true for the roughly half
of the states that have restructured their electricity markets, thus resulting in utilities
employing project financing rather than more traditional funding. With project
financing, the proposed developer of a power plant seeks financing for the project
using only the project as recourse for the loan, as opposed to securing the loan with
the larger holdings of the utility itself. With the project being the only collateral,
Wall Street looks very closely at the risk profile of the project in determining whether
to finance it and on what terms. The nuclear industry and the NRC hope that the new
licensing process will help improve the risk profile of new facilities by increasing the
certainty that a plant will be built expeditiously and begin operations in a timely
manner. It is also possible that an increase in nuclear power plant permit applications
could make the new process more routine, shortening approval time (as has happened
with licensing renewal requests for existing facilities, which are now generally
approved in about 18 months).
However, there are several reasons to believe that the slower end of the 10-15
year range is more likely, at least in the short-term. First, this is an untried process,
as noted above. Uncertainties include some time-honored ones, such as the
environmental impact statement and safety evaluation report, as well as new issues
presented by the new procedures, such as NRC’s certification of a utility’s ITAAC.
Second, public input is likely to be vigorous. Initial efforts by utilities to obtain early
site permits have been slowed by substantial public comments on each permit
request. Third, the new procedures do not prevent state intervention into the process,
particularly where traditional rate-making authority remains. States can be very
resourceful in delaying nuclear power when they so choose. The classic example is
the Shoreham nuclear power station, which was competed and licensed but never
began commercial operation because of the sustained opposition from the state of
New York.
Finally, judicial intervention is not unusual when opposition interest groups
attack permits, environmental impact statements, and other regulatory decisions in
attempts to forestall construction and operation. When existing nuclear plants were
licensed, opposition often focused on the potential for reactor accidents. In the post-
9/11 environment, concerns about terrorist attacks are likely to be raised as well.19
DOE Nuclear Power 2010 Program
Because no early site permits or COLs had ever been sought, DOE in 2002
initiated the Nuclear Power 2010 Program to demonstrate those processes, offering
to pay up to half the licensing costs incurred by industry applicants. The program’s
original goal was to pave the way for deployment of at least one new nuclear power
plant by 2010 and thus reduce regulatory uncertainty for further license applicants.
19 For more information on nuclear plant security, see CRS Report RS21131, Nuclear Power
Plants: Vulnerability to Terrorist Attack, by Carl Behrens and Mark Holt, Aug. 9, 2005.

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Although the program’s original goal of deploying a reactor by 2010 will not be
achieved, industry interest in the effort has been substantial. Under the program,
three utilities applied to NRC in 2003 for early site permits to build new reactors at
existing plants in Illinois, Mississippi, and Virginia. NRC anticipates final action on
the applications by 2007.20
Two industry consortia will continue to receive DOE assistance over the next
several years to apply for COLs and conduct “first of a kind engineering” for new
nuclear power plants, although they have not committed to ordering the reactors if
the licenses are issued. DOE awarded the first funding to the consortia in 2004.
DOE assistance under the program, including the early site permits, is planned to
reach a multiyear total of about $550 million. The two consortia receiving COL
assistance under the Nuclear Power 2010 program are
! A consortium led by Dominion Resources that is preparing a COL
for an advanced General Electric reactor (after originally considering
a Canadian design). The proposed reactor would be located at
Dominion’s existing North Anna plant in Virginia, where the
company is seeking an NRC early site permit with DOE assistance.
! A consortium called NuStart Energy Development, which includes
Exelon and several other major nuclear utilities. The consortium
announced on September 22, 2005, that it would seek a COL for a
Westinghouse design at the site of TVA’s uncompleted Bellefonte
nuclear plant in Alabama and for a General Electric design at the
Grand Gulf plant in Mississippi.
Energy Policy Act of 2005
Nuclear Production Tax Credit. The most direct nuclear incentive
provided by the Energy Policy Act is a 1.8 cents/kwh tax credit for up to 6,000
megawatts of new nuclear capacity for the first eight years of operation, up to $125
million annually per 1,000 megawatts. An eligible reactor must be placed into
service before January 1, 2021. As discussed below, this credit is expected to
significantly improve the projected economic viability of proposed nuclear power
plants.
A major factor in determining the potential impact of the nuclear production
credit is the allocation of the credit among eligible reactors. Under the Energy Policy
Act, the 6,000 megawatts of capacity that could receive the credit is to be allocated
by the Secretary of the Treasury in consultation with the Secretary of Energy. The
Internal Revenue Service issued interim guidance on May 1, 2006, that would
provide the tax credit to electricity generated by any reactor that (1) applied for an
NRC combined license by December 31, 2008; (2) began construction before January
1, 2014; and (3) was certified by DOE as meeting eligibility requirements.21
20 See [http://www.nrc.gov/reactors/new-licensing/esp.html].
21 Internal Revenue Bulletin, No. 2006-18, May 1, 2006, p. 855.

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Under the guidance, if license applications with more than 6,000 megawatts of
eligible nuclear capacity are received by December 31, 2008, the 6,000-megawatt cap
will be allocated proportionally among the eligible plants. Therefore, if 12,000
megawatts of new nuclear capacity met the application deadline and eventually went
into operation, then only half the electrical output of each reactor would get the tax
credit. If license applications by December 31, 2008, totaled less than 6,000
megawatts, then additional reactors would become eligible until the limit is reached,
according to the IRS guidance.
The deadline for automatic eligibility for the tax credit appears to provide a
strong incentive for nuclear plant applicants to file with NRC by the end of 2008,
which is sooner than some of the anticipated filings shown in Table 1. However, if
most of those reactors were to become eligible for the credit, the credit’s effect could
be diluted to the point where it would no longer provide a sufficient construction
incentive.
The credit would most dramatically affect nuclear plant economics if 100% of
a reactor’s output were eligible; however, if each new nuclear unit were to receive
the credit for all its electrical generation, then only four or five reactors (ranging from
1,200-1,500 megawatts) could be covered within the 6,000-megawatt limit. Because
reactor designs from three different companies are currently under consideration,
only one or two units of each design might be constructed under this scenario. That
might not be enough to reduce costs through series production to the point where
further units — ineligible for tax credits — would be economically viable on their
own.
Regulatory Risk Insurance. Continuing concern over potential regulatory
delays, despite the streamlined licensing system now available, prompted Congress
to include an insurance system in EPACT that would cover some of the costs of such
delays. The regulatory delay insurance, called “Standby Support,” would cover the
principal and interest on debt and extra costs incurred in purchasing replacement
power because of licensing delays. The first two new reactors licensed by NRC that
meet other criteria established by DOE could be reimbursed for all such costs, up to
$500 million apiece, whereas each of the next four newly licensed reactors could
receive 50% reimbursement of up to $250 million.
DOE announced an interim final rule for the Standby Support program on May
8, 2006.22 Criteria established by the rule for receiving coverage under the program
include the issuance of a COL, a detailed construction schedule, and a detailed
schedule for completing the inspections, tests, analyses, and acceptance criteria
required for reactor operation to begin. Coverage is to be provided for delays caused
by NRC’s failure to follow its own rules (if any) in reviewing a reactor’s ITAAC,
NRC’s failure to meet DOE-approved ITAAC schedules, NRC pre-operational
hearings, and litigation.
22 Published in the Federal Register, May 15, 2005, p. 28200.

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CRS-11
Standby Support coverage is not provided for delays caused by “failure of the
sponsor to take any action required by law, regulation, or ordinance.”23 This includes
delays caused by NRC orders to re-conduct ITAAC or to correct pre-operational
deficiencies found by NRC. However, the program does cover delays caused by
licensing-related litigation in state, federal, or tribal courts, even if a court rules
against a nuclear plant sponsor.24
The Standby Support program is intended to reduce uncertainty about the COL
licensing process that may pose an obstacle to nuclear plant orders. Because the first
two reactors would presumably face the most uncertainty about the untried process,
they would receive the most coverage. It is apparently hoped that the licensing
experience of the first two reactors would provide enough confidence for the next
four to proceed with half the coverage, and then for additional reactors to be built
with no regulatory risk insurance.
Loan Guarantees. New nuclear power plants are eligible for federal loan
guarantees authorized by EPACT for energy projects that reduce air emissions, a
criterion that includes new clean coal projects. The loan guarantees may cover up to
80% of a plant’s estimated cost. If a borrower defaults, DOE is to pay off the loan
and can either (1) take over the project for completion, operation, or disposition or
(2) reach an agreement with the borrower to continue the project. To prevent default,
DOE may make loan payments on behalf of the borrower, subject to appropriations
and an agreement by the borrower for future reimbursement.
Because it is generally believed that Wall Street continues to view new
commercial reactors as financially risky, the availability of federal loan guarantees
could be a key element in attracting funding for such projects and reducing financing
costs. The federal government would bear most of the risk, facing potentially large
losses if borrowers defaulted on reactor projects that could not be salvaged. Loan
guarantees may be especially important for nuclear projects undertaken by
deregulated generating companies as opposed to traditionally regulated utilities,
which can recover their regulator-approved capital costs from ratepayers.
Analysis of New Nuclear Power Plant Construction
Base Case Assumptions
To examine the potential competitive position of new nuclear plants, the future
market price for electricity must be estimated. In the long run, the marginal cost of
bringing on new electric generating capacity will tend to be set by the cost of the least
expensive newly constructed generating plant. To understand the potential
competitive position of nuclear power, CRS constructed an illustrative example
involving four hypothetical powerplants: a conventional pulverized coal-fired
23 Ibid., p. 28220.
24 Telephone conversation with Marvin Shaw, DOE Office of General Counsel, May 16,
2006.

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CRS-12
facility, an advanced coal-fired facility based on integrated gasification combined-
cycle (IGCC) technology, an advanced natural gas-fired combined-cycle facility, and
an advanced nuclear power facility. The illustrative examples permit a consistent set
of assumptions to use for the analysis.
Table 2. Projected 2015 Costs and Assumptions
(2004$)
Advanced
Advanced
Advanced Coal
Assumption
Coal Plant
Natural Gas
Nuclear Power
Plant
GCC
Plant
Capital costs
$1,217/kw
$1,386/kw
$555/kw
$1,913/kw
Construction
4 years
4 years
3 years
6 years
schedule
Fixed O&M
$25.07/kw-year
$35.21/kw-year
$10.65/kw-year
$61.82/kw-year
costs
Variable O&M
0.418 0.265 cents/kwh 0.182 cents/kwh 0.045 cents/kwh
costs
cents/kwh
Fuel costs
$1.40/million
$1.40/million
$5.08/million
$0.66/million
Btu
Btu
Btu
Btu
Heat rate
8,661 Btu/kwh
7,477 Btu/kwh
6,403 Btu/kwh 10,400 Btu/kwh
Capacity factor
90%
90%
90%
90%
Real capital
13.4%
13.4%
13.4%
13.4%
charge rate
Date project
2015
2015
2015
2015
initiated
Sources: DOE/EIA, Assumptions to the Annual Energy Outlook 2006 (March 2006); EPA,
Standalone Documentation for EPA Base Case 2004 (September 2005).
Assessing the competitiveness of future nuclear power plants requires numerous
assumptions about future economic, financial, and policy conditions. Based on 2015
as the benchmark year for constructing a new power plant, the major assumptions of
the analysis are identified in Table 2. Most of the assumptions below are from the
Energy Information Administration (EIA) and reflect costs and technical performance
anticipated by EIA for projects initiated in 2015.25 The real capital charge rate is
from the Environmental Protection Agency’s Integrated Planning Model (IPM).26
Calculations were done by CRS and are in constant 2004 dollars.
25 Energy Information Administration, Assumptions to the Annual Energy Outlook — 2006
(With Projections to 2030), March 2006, pp. 71-87, at [http://www.eia.doe.gov/oiaf/aeo/
assumption/pdf/electricity.pdf]. The term “initiated” is not defined.
26 The real capital charge rate is calculated based on a 6.74% discount rate. For a full
discussion, see Environmental Protection Agency, Standalone Documentation for EPA Base
Case 2004 (V.2.1.9) Using the Integrated Planning Model (September 2005), chapter 7, at
[http://www.epa.gov/airmarkets/epa-ipm/bc7financial.pdf].

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CRS-13
Base Case Results
Assuming that by 2015 the subsidies contained in the 2005 Energy Policy Act
are no longer available for new nuclear power construction, Table 3 indicates that
under EIA’s assumed 2015 natural gas price scenario, conventional coal-fired and
advanced combined-cycle natural gas-fired facilities would be in a virtual dead-heat
as the choice for new construction. CRS estimates the annual costs on a levelized
basis for new coal-fired or natural gas-fired facilities to be within one mill per
kilowatt-hour (kwh) under EIA’s estimated 2015 natural gas prices. Advanced coal-
fired technology is projected to be competitive with both pulverized coal combustion
and natural gas combined-cycle technology by 2015.
Without the production tax credit contained in the 2005 Energy Policy Act, a
nuclear facility is not competitive with either coal-fired or natural gas-fired facilities
under base case assumptions. Based on the assumptions above, CRS estimates that
the break-even point for nuclear power capital costs versus coal-fired facilities in
2015 is about $1,370 per kilowatt (kw) of capacity. This is substantially below the
EIA projected cost of $1,913 per kw and is even below the vendors’ estimate of
$1,528 per kw (2004).27 Under base case conditions, it seems unlikely that a new
nuclear power plant would be constructed in the United States, barring a sustained,
long-term increase in natural gas prices and the creation of a substantial, mandatory
greenhouse gas reduction program that would increase coal-fired and natural gas-
fired generating costs.
Table 3. Projected 2015 Annualized Costs
(2004$)
Advanced
Advanced
Pulverized
Advanced
Natural Gas
Nuclear Power
Coal Plant
Coal Plant
GCC
Plant
Cents per kwh
4.5
4.6
4.6
5.6
Source: CRS calculations based on Table 2 assumptions.
Impact of 2005 Energy Policy Act
However, if one assumes that the production tax credit contained in the 2005
Energy Policy Act is available to facilities that begin construction in 2015 (the base
year in the analysis), the story is different. As indicated in Table 4, the production
tax credit contained in EPACT is sufficient to make nuclear power competitive with
either natural gas-fired or coal-fired facilities. The advantage provided to nuclear
power by the production tax credit is not definitive; however, it appears sufficient to
allow a decision on constructing a nuclear power station to move beyond initial
economic considerations to examining other relevant factors, such as fossil fuel
27 Energy Information Administration, Assumptions to the Annual Energy Outlook — 2006
(With Projections to 2030), (March 2006) p. 86, at [http://www.eia.doe.gov/oiaf/aeo/
assumption/pdf/electricity.pdf].

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CRS-14
prices and the regulatory environment for both nuclear power and future fossil fuel-
fired generation.
Table 4. Projected 2015 Annualized Costs, Including Subsidized
Nuclear Power
(2004$)
Advanced
Advanced
Advanced
Nuclear Power
Pulverized
Advanced
Natural Gas
Nuclear
Plant with
Coal Plant
Coal Plant
GCC
Power Plant
Production
Credit
Cents
per
4.5
4.6
4.6
5.6
4.2-4.7a
kwh
Source: CRS calculations based on Table 2 assumptions.
a. Range reflects uncertainty with future inflation and construction times and dates, which
affect the real value of the production credit.
Sensitivity Analysis
Volatile Natural Gas Prices. The recent rise in natural gas prices and the
country’s two-decade reliance on natural gas for new electric generating capacity
have raised concern that the country is becoming too dependent on natural gas for
electricity. Currently, about 22% of the country’s electric generating capacity is
natural gas-fired, compared with about 7% two decades ago. This situation raises at
least two questions: (1) whether the recent rise in natural gas prices is a harbinger of
future prices or just another peak in the historic boom-bust cycle of U.S. natural gas
prices, and (2) whether nuclear power is an alternative generating option that the
federal government should subsidize to help address question number one.
The potential for increased natural gas prices has been illustrated by recent
events. However, power plants are long-lived facilities with lifetimes estimated at
around 65 years, although current maintenance practices can extend that life almost
indefinitely. In the emerging competitive environment for new power plant
construction, the financial investment lifetime may be on the order of 20 years. This
shorter time frame to recover a power plant investment reflects the uncertainty
existing in the electricity market.28
Twenty years is a long time in the natural gas and coal markets. Figure 3 charts
natural gas prices to electric utilities during the 38 years from 1967 to 2005.
Converted to real 2000 dollars using the Implicit Price Deflator, the chart indicates
that natural gas prices have generally stayed under $4.50 per thousand cubic feet
(mcf) until 2003. It is uncertain how long current relatively high prices may
28 See Environmental Protection Agency, Analyzing Electric Power Generation under the
CAAA, Office of Air and Radiation (March 1998), p. A2-12.

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CRS-15
continue. As indicated in Table 2, EIA projects 2015 natural gas prices at $5.08 in
2004 dollars — above the levels of the 1990s, but below the prices of the last two
years.
Figure 3. Natural Gas Prices Delivered to Electric Utilities
Source: Energy Information Administration, data available at [http://www.eia.doe.gov/
emeu/aer/txt/stb0608.xls].
To illustrate the sensitivity of natural gas-fired electric generation to natural gas
prices, Table 5 provides estimates of generation costs for a range of natural gas
prices. Based on these calculations, the breakeven point for unsubsidized nuclear
power versus natural gas-fired facilities would be $6.65 /MMBtu (2004$). Thus, if
the current level of natural gas prices continues in the long-term, nuclear power may
not need any subsidies by the year 2015 to compete with natural gas-fired facilities.
Table 5. Effect of Natural Gas Prices on Production Costs
(2004$)
Natural Gas Price (delivered, $/MMBtu)
Production Costs (cents/kwh)
3.08
3.3
4.08
4.0
5.08
4.6
6.08
5.2
7.08
5.9
Source: CRS calculations based on Table 2 assumptions.
As noted above, the economic question raised by this analysis is whether the
current upturn in natural gas prices a relatively short-term phenomenon, or does it
reflect a new long-term premium for natural gas, based on its environmental and
technological advantages and future availability? If the former, then building new
nuclear powerplants would be a questionable venture economically, unless its capital

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CRS-16
costs could be reduced substantially. If the latter, nuclear power construction could
become attractive in the future if prices persist at above about $6.65 per mcf (2004$).
However, it should be noted that volatile natural gas prices do not have any
direct effect on generating costs from coal-fired facilities. Unlike natural gas prices,
coal prices have been on a slow, steady decline for 30 years. The increasing share of
coal being supplied by large, low-cost strip-mine operations in the West has
contributed to a long-term downward trend in coal prices. Coal prices have risen in
the past couple of years as demand has increased; however, with abundant reserves,
a sustained increase would seem problematic.
Greenhouse Gas Control. Any substantial mandatory greenhouse gas
control program would probably affect the cost of new coal-fired and natural gas-
fired generation. In all current proposals before the Congress, nuclear power is
assumed to have no greenhouse gas emissions. This “green” nuclear power argument
has gotten some traction in think tanks and academia. As stated by MIT in its major
study The Future of Nuclear Power: “Our position is that the prospect of global
climate change from greenhouse gas emissions and the adverse consequences that
flow from these emissions is the principal justification for government support of the
nuclear energy option.”29 The industry also has been attempting to promote nuclear
power as one solution to rising greenhouse gas emissions.30 A few well-known
environmentalists have expressed public support for nuclear power as part of the
response to global climate change, although no major environmental group as yet has
publically adopted that position.31
Despite strong Administration opposition to mandatory greenhouse gas
reduction programs, a number of congressional proposals to advance programs
designed to reduce greenhouse gases have been introduced in the 109th Congress.32
None of these proposal have passed either house of Congress. The first effort to pass
a mandatory greenhouse gas reduction program failed in 2003 on a 43-55 vote in the
Senate. A similar effort was defeated in 2005 during the debate on the Energy Policy
Act of 2005 on a 38-60 vote. This second, less favorable vote reflects the changed
votes of four Senators who reportedly objected to the addition of nuclear power
incentives to the 2005 version of the proposed legislation.33 The proposals would
have placed a cap on U.S. greenhouse gas emissions based on a 2001 baseline. The
29 Interdisciplinary MIT Study, The Future of Nuclear Power, Massachusetts Institute of
Technology, 2003, p. 79.
30 See the Nuclear Energy Institute (NEI) website at [http://www.nei.org/index.asp?catnum=
1&catid=11].
31 Patrick Moore, “Going Nuclear,” Washington Post, Apr. 16, 2006, p. B1.
32 See CRS Report RS22076, Climate Change: Summary and Analysis of the Climate
Stewardship Act (S. 342, S. 1151, and H.R. 759), by Larry Parker and Brent Yacobucci, and
CRS Report RL32755, Air Quality: Multi-Pollutant Legislation in the 109th Congress, by
Larry Parker and John Blodgett.
33 Ben Evans and Catherine Hunter, “Senate Rejects Global Warming Amendment,” CQ
Today, June 22, 2005.

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CRS-17
cap would have been implemented through a tradeable permit program to encourage
efficient reductions.
However, concern that global climate change should be addressed by the
Congress led 13 Senators to introduce S.Amdt. 866 — a Sense of the Senate
resolution on climate change — during the debate on the Energy Policy Act of 2005.
The resolution finds that (1) greenhouse gases are accumulating in the atmosphere,
increasing average temperatures; (2) there is a growing scientific consensus that
human activity is a substantial cause of this accumulation; and (3) mandatory steps
will be required to slow or stop the growth of greenhouse gas emissions. Based on
these findings, the resolution states that it is the sense of the senate that the Congress
should enact a comprehensive and effective national program of mandatory, market-
based limits and incentives on greenhouse gases that slow, stop, and reverse the
growth of such emissions. This should be done in a manner that will not significantly
harm the U.S. economy and will encourage comparable action by other countries that
are our major trading partners and contributors to global emissions. The resolution
passed by voice vote after a motion to table it failed on a 43-54 vote.
Currently, there are four proposals in varying degrees of completeness before
the 109th Congress. They are as follows:
! S. 2724 (Senator Carper).34 Would create a cap-and-trade permit
program to reduce emissions of sulfur dioxide, nitrogen oxides,
mercury, and carbon dioxide from electric generating facilities
greater than 25 Mw. The CO cap would be set in two phases, with
2
affected facilities required to reduce emissions to 2006 levels by
2010, and then further reduce emissions to 2001 levels by 2015.
! NCEP Recommendation (draft legislation prepared by Senator
Bingaman).35 Would create an economy-wide tradeable permit
program to begin limiting greenhouse gases. The proposal would
mandate an accelerated reduction in the country’s greenhouse gas
intensity: Between 2010 and 2019, the proposal would require a
2.4% annual reduction in greenhouse gas emissions per dollar of
projected gross domestic product (GDP). After 2019, this reduction
would increase to 2.8% annually. The program would include a
cost-limiting safety valve that allows covered entities to make a
payment to DOE in lieu of reducing emissions. The initial price of
such payments would be $7 per ton in 2010, rising 5% annually
thereafter.36
34 For more on S. 2724, see CRS Report RL32755, Air Quality: Multi-Pollutant Legislation
in the 109th Congress, by Larry Parker and John Blodgett.
35 For more on the proposal, see CRS Report RL32953, Climate Change: Comparison and
Analysis of S. 1151 and the Draft “Climate and Economy Insurance Act of 2005,” by Brent
Yacobucci and Larry Parker.
36 For a discussion of safety valves, see CRS Report RS21067, Global Climate Change:
Controlling CO Emissions — Cost-Limiting Safety Valves, by Larry Parker.
2

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CRS-18
! S. 1151 (Senators McCain and Lieberman).37 Would create an
economy-wide cap-and-trade program to reduce emissions of six
greenhouse gases to their 2000 levels by the year 2010. The flexible,
market-based program would permit participation in pre-certified
international trading systems and a carbon sequestration program to
achieve part of the reduction requirement. The bill excludes
residential and agricultural sources, along with entities that do not
own a single facility that emits more than 10,000 metric tons of CO2
equivalent annually.38
! S. 150 (Senator Jeffords).39 Would create a cap-and-trade permit
program to reduce emissions of sulfur dioxide, nitrogen oxides, and
carbon dioxide, along with unit-by-unit controls on mercury
emissions from electric generating facilities 15 Mw or greater. The
CO cap would require affected entities to reduce their emissions to
2
1990 levels by 2010.
Table 6 indicates projected trade permit prices for the four proposals currently
being discussed. As indicated, S. 2724 is estimated to have the lowest price, while
S. 150 is projected to have the greatest. This differential reflects both the stringency
of the various proposals and their scope (economy-wide versus electric generation
only). The reader should note that the estimates come from a variety of sources, and
significant uncertainty surrounds the actual cost of any greenhouse gas initiative
(except for the NCEP proposal, which includes a safety valve that limits the upper
price range on permits).
Table 6. Per-Ton CO Permit Price Estimates for Greenhouse
2
Gas Initiatives
(in 2004$/metric ton of CO )
2
Year
S. 2724a
NCEP
S. 1151
S. 150
Recommendations
2015
$1.2
$5.9
$11.7
$25.8
2020
$2.5
$7.7
$14.9
$33.1
Sources: For S. 843 and S. 150: EPA, Office of Air And Radiation, Multi-Pollutant
Analysis: Comparison Briefing (October 2005); for NCEP Recommendations: The National
Commission on Energy Policy, Ending the Energy Stalemate: A Bipartisan Strategy to Meet
America’s Energy Challenges (December 2004); for S. 1151: Sergey Palsev, et al.,
Emissions Trading to Reduce Greenhouse Gas Emissions in the United States: The McCain
37 A House version of the bill, H.R. 759, has been introduced by Representatives Gilchrest
and Olver.
38 For more on the bill, see CRS Report RS22076, Climate Change: Summary and Analysis
of the Climate Stewardship Act (S. 342, S. 1151, and H.R. 759), by Larry Parker and Brent
Yacobucci.
39 For more on S. 150, see CRS Report RL32755, Air Quality: Multi-Pollutant Legislation
in the 109th Congress, by Larry Parker and John Blodgett.

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CRS-19
Lieberman Proposal [S. 139], Report No. 97 (June 2003). Estimates converted into 2004$
using the GNP Implicit Price Deflator.
a. S. 2724 estimates based on analysis of S. 843 introduced in 108th Congress. The later
deadlines in S. 2724 would probably result in slightly lower cost estimates than those
presented here, all else being equal.
Table 7 indicates the effect that the four proposals would have on 2015 and
2020 generation costs by fuel source. As indicated, the first two proposals, S. 2724
and the draft proposal based on the NCEP recommendations, would have a minimal
effect on fuel choice in 2015 and 2020, all else being equal. The third bill, S. 1151,
would pull nuclear power even with its coal-fired competition, but not decisively.
The fourth, S. 150, would provide the greatest advantage to nuclear power. It is also
the proposal that most resembles the requirements of the Kyoto Protocol (as least for
electric generation).
To quantify the potential effect of permit prices (or an equivalent carbon tax) on
fuel source for future electric generating capacity, Table 8 provides the effects of a
range of permit prices/carbon taxes on new electric generating cost under base case
conditions. As indicated, the breakeven point for nuclear power versus natural gas-
fired facilities is about $30 a metric ton (2004$); the breakeven point for nuclear
power versus coal-fired facilities is about $15 a metric ton (2004$). Thus, over time,
nuclear power could provide a form of safety valve for electric generation, if permit
prices or a carbon tax became a permanent part of the electricity supply environment.
Table 7. 2015 and 2020 Projected Annualized Costs with
Increased Costs from Greenhouse Gas Legislation
(cents per kwh, 2004$)
Advanced
Pulverized
Advanced Coal
Natural Gas
Advanced
Coal Plant
Plant
GCC
Nuclear
Power
Plant
2015
2020
2015
2020
2015
2020
S. 2724a
4.6
4.7
4.7
4.8
4.6
4.7
5.6
NCEP
4.9
5.1
5.0
5.1
4.8
4.9
5.6
Recommendations
S. 1151
5.4
5.7
5.4
5.6
5.0
5.1
5.6
S. 150
6.5
7.1
6.4
6.9
5.5
5.7
5.6
Source: CRS calculations based on Table 6 estimates and Table 2 assumptions.
a. S. 2724 estimates based on S. 843 introduced in 108th Congress. The later deadlines in S. 2724
would probably result in slightly lower cost estimates than those presented here, all else being
equal.

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CRS-20
Table 8. Effect of Permit Prices/Carbon Tax on Electricity
Production Costs
Permit Price or
Carbon Tax
Natural Gas
Conventional Coal
Advanced Coal
(2004$/metric ton
(cents/kwh)
(cents/kwh)
(cents/kwh)
of CO )
2
$5
4.8
4.9
5.0
$10
4.9
5.3
5.3
$15
5.1
5.7
5.7
$20
5.3
6.1
6.0
$25
5.4
6.5
6.4
$30
5.6
6.9
6.7
$35
5.8
7.3
7.0
$40
6.0
7.7
7.4
Source: CRS calculations based on Table 2 assumptions.
Nuclear Waste. Highly radioactive spent nuclear fuel produced by nuclear
reactors poses a disposal problem that could be a significant factor in the
consideration of new nuclear plant construction. The Nuclear Waste Policy Act of
1982 (NWPA, P.L. 97-425) commits the federal government to providing for
permanent disposal of spent fuel in return for a fee on nuclear power generation. The
schedule for opening the planned national nuclear waste repository at Yucca
Mountain, Nevada, has slipped far past NWPA’s deadline of January 31, 1998,
however, and it is currently unknown when disposal will begin.
In the meantime, more than 50,000 metric tons of spent fuel is being stored in
pools of water or shielded casks at nuclear facility sites.40 NWPA limits the planned
Yucca Mountain repository to the equivalent of 70,000 metric tons of spent fuel.
Because U.S. nuclear power plants discharge an average of 2,000 metric tons of spent
fuel per year, the Yucca Mountain limit is likely to be reached before any new
reactors begin coming on line.
Therefore, even if Yucca Mountain eventually begins operating as planned, it
is unclear what ultimately would be done with spent fuel from new nuclear power
plants under current law. In the near term, continued storage at reactor sites and
interim storage at central locations would be the most likely possibilities. The
primary long-term options include lifting the statutory cap on Yucca Mountain
disposal, developing additional repositories, and reprocessing spent fuel for reuse of
plutonium and uranium. The Bush Administration’s Global Nuclear Energy
Partnership proposal, unveiled in February 2006, envisions reprocessing as a way to
reduce the amount of long-lived plutonium and highly radioactive cesium and
40 See CRS Report RS22001, Spent Nuclear Fuel Storage Locations and Inventory, by
Anthony Andrews, Dec. 21, 2004.

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CRS-21
strontium that would need to be placed in Yucca Mountain, thereby expanding its
disposal capacity.41
The extent to which the nuclear waste issue could inhibit nuclear power
expansion is difficult to assess. NRC has determined that onsite storage of spent fuel
would be safe for at least 30 years after expiration of a reactor’s operating license,
which was estimated to be as long as 70 years. As a result, the Commission
concluded that “adequate regulatory authority is available to require any measures
necessary to assure safe storage of the spent fuel until a repository is available.”42
Therefore, NRC does not consider the lack of a permanent repository for spent fuel
to be an obstacle to nuclear plant licensing. However, the Administration was
concerned enough about repository delays to include a provision in its recent nuclear
waste bill to require NRC, when considering nuclear power plant license
applications, to assume that sufficient waste disposal capacity will be available in a
timely manner.43
At least seven states — California, Connecticut, Kansas, Kentucky, Maine,
Oregon, and Wisconsin — have specific laws that link approval for new nuclear
power plants to adequate waste disposal capacity. The U.S. Supreme Court has held
that state authority over nuclear power plant construction is limited to economic
considerations rather than safety, which is solely under NRC jurisdiction.44 No
nuclear plants have been ordered since the various state restrictions were enacted, so
their ability to meet the Supreme Court’s criteria have yet to be tested.
The nuclear waste issue has also historically been a focal point for public
opposition to nuclear power. Proposed new reactors that have no clear path for
removing waste from their sites could face intensified public scrutiny, particularly at
proposed sites that do not already have operating reactors.
41 See the Department of Energy website at [http://www.gnep.energy.gov].
42 NRC, Waste Confidence Decision Review, 55 Federal Register 38472, Sept. 18, 1990.
The 1990 decision was reaffirmed by NRC on November 30, 1999, and NRC denied a
petition to amend the decision August 10, 2005.
43 S. 2589, introduced by Senator Domenici by request.
44 Wiese, Steven M., State Regulation of Nuclear Power, CRS Report prepared for the
House Committee on Interior and Insular Affairs, Dec. 14, 1992, p. 18.

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