Order Code RL33442
CRS Report for Congress
Received through the CRS Web
Nuclear Power: Outlook for New U.S. Reactors
Updated November 6, 2006
Larry Parker and Mark Holt
Specialists in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
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 30 new reactors. The renewed interest in nuclear power has
resulted primarily from higher prices for natural gas, improved operation of existing
reactors, and uncertainty about future restrictions on coal emissions. A substantial
tax credit and other incentives for nuclear generation provided by the Energy Policy
Act of 2005 (P.L. 109-58) are 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 and operable 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 economic viability of 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, there was
real doubt that any reactors would make it to 40 years. Since 2000, however, 44
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.
Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Current Status of U.S. Nuclear Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Federal Initiatives To Encourage New Nuclear Power Plant Construction . . . . . . 6
NRC Licensing Reform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
DOE Nuclear Power 2010 Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Energy Policy Act of 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Nuclear Production Tax Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Regulatory Risk Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Loan Guarantees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Analysis of New Nuclear Power Plant Construction . . . . . . . . . . . . . . . . . . . . . . 13
Base Case Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Base Case Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Impact of 2005 Energy Policy Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Volatile Natural Gas Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Greenhouse Gas Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Nuclear Waste . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
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 . . . . . . . . . . . . . . . . 16
List of Tables
Table 1. Announced Nuclear Plant License Applications . . . . . . . . . . . . . . . . . . 2
Table 2. Projected 2015 Costs and Assumptions . . . . . . . . . . . . . . . . . . . . . . . . 14
Table 3. Projected 2015 Annualized Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Table 4. Projected 2015 Annualized Costs, Including Subsidized
Nuclear Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Table 5. Effect of Natural Gas Prices on Production Costs . . . . . . . . . . . . . . . . 17
Table 6. Per-Ton CO Permit Price Estimates for Greenhouse Gas Initiatives . 20
2
Table 7. 2015 and 2020 Projected Annualized Costs with Increased Costs
from Greenhouse Gas Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Table 8. Effect of Permit Prices/Carbon Tax on Electricity Production Costs . . 22
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 since 1978, 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 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, nearly a dozen more
utilities and other companies have announced plans to apply for reactor licenses (as
shown in Table 1), for a total of 33 new nuclear units. According to NRC, two
unannounced applications are also in preparation.1
The renewed interest in nuclear power has resulted primarily from higher 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 electric generation
capacity 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 and other incentives 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,
along with doubts about progress on nuclear waste disposal and concerns about
1 Nuclear Regulatory Commission, Semiannual Update of the Status of New Reactor
Licensing Activities, August 2006.
2 Energy Policy Act of 1992, Title XXVIII, P.L. 102-486.
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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 is likely to be obtained.
Table 1. Announced Nuclear Plant License Applications
Announced
Site
Planned
Reactor Type
Units
Applicant
Application
Date
Amarillo Power
Not specified
2007
GE ABWR
2
Constellation
Calvert Cliffs (MD)
4Q 2007
Areva EPR
1
Energy (Unistar)
Nine Mile Point (NY)
1st half 2008
Areva EPR
1
Not specified
4Q 2008
Areva EPR
3
Dominion
North Anna (VA)
Nov. 2007
GE ESBWR
1
Duke Power
Cherokee (SC)
2007-2008
West. AP1000
2
Entergy
River Bend (LA)
May 2008
GE ESBWR
1
Exelon
Texas
Nov. 2008
Not specified
2
FPL
Not specified
2009
Not specified
1
NRG Energy
South Texas Project
2007
GE ABWR
2
NuStart
Grand Gulf (MS)
Nov. 2007
GE ESBWR
1
Bellefonte (AL)
Oct. 2007
West. AP1000
2
Progress Energy
Harris (NC)
Oct. 2007
West. AP1000
2
Florida
July 2008
West. AP1000
2
SCE&G
Summer (SC)
3Q 2007
West. AP1000
2
Southern
Vogtle (GA)
Mar. 2008
West. AP1000
2
TXU
Comanche Peak (TX)
4Q 2008
Not specified
2
Texas
4Q 2008
Not specified
2
Texas
4Q 2008
Not specified
2
Total Units
33
Sources: NRC, Nucleonics Week, Nuclear News, Nuclear Energy Institute, company news
releases.
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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
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 those early 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
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.
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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
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.
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
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.
The improved operation of nuclear power plants has helped drive down the cost
of nuclear-generated electricity. Average operations and maintenance costs
(including fuel but excluding capital costs) 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 2005, the average operating cost was 1.7 cents/kwh.11
Falling operating costs have improved the outlook for 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 — California’s Rancho Seco plant
and Oregon’s Trojan plant after only 14 and 16 years of operation, respectively.12 By
the late 1990s, there was real doubt about whether any reactors would make it to 40
years. Since 2000, however, 44 commercial reactors have received 20-year license
extensions from NRC, giving them up to 60 years of operation. License extensions
for 10 more reactors are currently under review, and many others are anticipated,
according to NRC.13 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.
Although no new U.S. nuclear power plant has opened in the past 10 years,
commercial reactor construction has continued elsewhere in the world, particularly
in Asia. Since the most recent U.S. reactor began operating in 1996, 37 have started
up in other countries, an average of about four per year.14 Twenty-five reactors are
currently under construction outside the United States.15
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.
11 Nucleonics Week, “U.S. Utility Operating Costs, 2005,” September 14, 2006, p. 7.
12 Nuclear News, op. cit.
13 See [http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html]
14 Nuclear News, “Word List of Nuclear Power Plants,” March 2006, p. 37.
15 World Nuclear Association, World Nuclear Power Reactors 2005-06 and Uranium
(continued...)
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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
for sale.16 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:17
! 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.18
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,
15 (...continued)
Requirements, September 21, 2006. Excludes three reactors undergoing reconstruction in
the United States and Canada.
16 10 CFR Part 50.
17 54 Federal Register 15372, Apr. 18, 1989.
18 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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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, environmental impact 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 have to address emergency planning issues, such as evacuation routes.
The utility may use the 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.
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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. This additional information 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.
The licensing process is currently estimated by NRC to take about three and a
half years, although NRC Chairman Dale Klein has called for that schedule to be
shortened.19 NRC announced in July that it would establish an Office of New
Reactors in January 2007 to handle the potential influx of new reactor license
applications.
After the license is issued, the utility must decide whether to begin building 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.
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 longer 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,
19 Weil, Jenny, “Safety of Existing Fleet to Remain the Top Priority at NRC, Klein Says,”
Inside NRC, September 4, 2006, p. 1.
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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 completed 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.20
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.
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 2007.21
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
20 For more information on nuclear plant security, see CRS Report RS21131, Nuclear Power
Plants: Vulnerability to Terrorist Attack, by Mark Holt and Anthony Andrews.
21 See [http://www.nrc.gov/reactors/new-licensing/esp.html].
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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.22
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.
22 Internal Revenue Bulletin, No. 2006-18, May 1, 2006, p. 855.
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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 issued the final rule for the Standby Support program on August 11,
2006.23 Criteria established by the rule for receiving coverage under the program
include the issuance of a COL, a detailed construction schedule, documentation that
construction has started, and a detailed schedule for completing the inspections, tests,
analyses, and acceptance criteria required for reactor operation to begin. The first
two reactors to meet all the criteria would receive the $500 million coverage.
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. Standby Support
coverage is not provided for delays caused by “failure of the sponsor to take any
action required by law, regulation, or ordinance.”24 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.25
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.
23 71 Federal Register 46306, August 11, 2006.
24 Ibid., p. 46329.
25 Telephone conversation with Marvin Shaw, DOE Office of General Counsel, May 16,
2006.
CRS-12
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. Even for
regulated utilities, “loan guarantees are critically important to new nuclear plant
financing,” the Nuclear Energy Institute contended in September 2006 testimony.26
DOE issued its initial solicitation for loan guarantees under EPACT on August
8, 2006.27 The total amount of the loan guarantees in the initial solicitation is limited
to $2 billion and does not include nuclear technology. Along with the initial
solicitation, DOE issued guidelines for considering those initial proposals and said
it was working on final regulations to govern future loan guarantee solicitations. The
deadline for applications under the initial solicitation was originally November 6,
2006, but was subsequently delayed to December 31, 2006.
EPACT requires that before a loan guarantee is granted, the estimated subsidy
cost (including estimated default losses) must be covered by a specific appropriation
or by an up-front payment from the borrower. DOE’s initial solicitation says that,
because appropriations for the program are not anticipated, each borrower will have
to pay the estimated subsidy cost. According to the solicitation, the subsidy cost will
be calculated for each loan and must be approved by the Office of Management and
Budget (OMB).28 OMB will undoubtedly want to ensure that the payments are high
enough to cover all the anticipated default and other subsidy costs incurred by the
DOE loan guarantee program. The size of the payments required by OMB could
strongly affect the value of the loan guarantees to borrowers.
Also important to potential borrowers is the percentage of project costs that can
be covered by the DOE loan guarantees. Although EPACT Section 1702(c) allows
DOE to provide loan guarantees for up to 80% of a project’s estimated cost, DOE’s
guidelines for the initial solicitation “expresses a preference” that the loan guarantees
cover not more than 80% of a project’s debt.29 Therefore, if a project has significant
non-debt financing, the loan guarantees could cover considerably less than 80% of
26 Testimony of Skip Bowman, President and Chief Executive Officer, Nuclear Energy
Institute, to the Energy and Water Development Subcommittee of the House Appropriations
Committee, September 13, 2006.
27 U.S. Department of Energy, Loan Guarantee Program Office, Federal Loan Guarantees
for Projects that Employ Innovative Technologies in Support of the Advanced Energy
Initiative, Solicitation Number DE-PS01-06LG00001, August 8, 2006.
28 EPACT refers to the cost definition in the Federal Credit Reform Act of 1990, which
defines the subsidy cost as “the estimated long-term cost to the government of a direct loan
or a loan guarantee, calculated on net present value basis, excluding administrative costs.”
29 U.S. Department of Energy, Loan Guarantees for Projects that Employ Innovative
Technologies; Guidelines for Proposals Submitted in Response to the First Solicitation,
effective August 8, 2006.
CRS-13
the total cost. The Nuclear Energy Institute contended that “the procedures outlined
in the guidelines are so restrictive and so conditional that they would not support
financing of a nuclear power plant.”30
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 evaluate the potential competitive
position of nuclear power, CRS constructed an illustrative example involving four
hypothetical powerplants: a conventional pulverized coal-fired 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.
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 are from the Energy
Information Administration (EIA) and reflect costs and technical performance
anticipated by EIA for projects initiated in 2015.31 The real capital charge rate is
from the Environmental Protection Agency’s Integrated Planning Model (IPM).32
Calculations were done by CRS and are in constant 2004 dollars.
For nuclear fuel and coal costs, the assumptions reflect the price trends projected
by EIA during the construction period. For coal, EIA projects stable prices in real
terms from 2015 through 2023. For uranium, EIA projects stable prices in real terms
between 2015 and 2030. Because natural gas prices have historically been more
volatile than coal prices, CRS has performed a sensitivity analysis on natural-gas
generating costs using a range of potential future natural gas prices. This sensitivity
analysis, along with a general discussion of natural gas and coal prices, is presented
after the base case results, which assume stable (in real terms) projected 2015 prices.
30 Testimony of Skip Bowman, op. cit.
31 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.
32 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].
CRS-14
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).
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
initiated 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’
CRS-15
estimate of $1,528 per kw (2004).33 Under base case conditions, it seems unlikely
that a new nuclear power plant would be constructed in the United States, barring a
sustained, long-term increase in natural gas prices and the creation of a substantial,
mandatory greenhouse gas reduction program that would increase coal-fired and
natural gas-fired generating costs.
Table 3. Projected 2015 Annualized Costs
(2004$)
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.
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.
33 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].
CRS-16
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 prices and the regulatory environment for both
nuclear power and future fossil fuel-fired generation.
Sensitivity Analysis
Volatile Natural Gas Prices. Relatively high 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.
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].
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
CRS-17
shorter time frame to recover a power plant investment reflects the uncertainty
existing in the electricity market.34
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 the current relatively high prices may
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.
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 is 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 power plants would be a questionable venture economically, unless their
capital costs could be reduced substantially. If the latter, nuclear power construction
could become attractive in the future if prices persist at above about $6.65 per
MMBtu (2004$).
However, it should be noted that volatile natural gas prices do not have any
direct effect on generating costs at coal-fired facilities. In contrast to natural gas
prices, coal prices generally have been on a slow, steady decline for 30 years. The
34 See Environmental Protection Agency, Analyzing Electric Power Generation under the
CAAA, Office of Air and Radiation (March 1998), p. A2-12.
CRS-18
increasing share of coal being supplied by large, low-cost surface mining 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.”35 The industry also has been attempting to promote nuclear
power as one solution to rising greenhouse gas emissions.36 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.37
Despite strong Bush 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.38
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.39 The proposals would
have placed a cap on U.S. greenhouse gas emissions based on a 2001 baseline. The
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,
35 Interdisciplinary MIT Study, The Future of Nuclear Power, Massachusetts Institute of
Technology, 2003, p. 79.
36 See the Nuclear Energy Institute (NEI) website at [http://www.nei.org/index.asp?catnum=
1&catid=11].
37 Patrick Moore, “Going Nuclear,” Washington Post, April 16, 2006, p. B1.
38 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.
39 Ben Evans and Catherine Hunter, “Senate Rejects Global Warming Amendment,” CQ
Today, June 22, 2005.
CRS-19
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 the nation’s 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.
Proposals under discussion in the 109th Congress include the following:
! S. 2724 (Senator Carper).40 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 megawatts (mw). The CO cap would be set in two
2
phases, with 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).41 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.42
! S. 1151 (Senators McCain and Lieberman).43 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
40 For more on S. 2724, see CRS Report RL32755, Air Quality: Multi-Pollutant Legislation
in the 109th Congress, by Larry Parker and John Blodgett.
41 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.
42 For a discussion of safety valves, see CRS Report RS21067, Global Climate Change:
Controlling CO Emissions — Cost-Limiting Safety Valves, by Larry Parker.
2
43 A House version of the bill, H.R. 759, has been introduced by Representatives Gilchrest
and Olver.
CRS-20
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.44
! S. 150 (Senator Jeffords).45 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
2
for Greenhouse 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
$33.1
Sources: For S. 843 and S. 150: EPA, Office of Air And Radiation, Multi-Pollutant
Analysis: Comparison Briefing (October 2005); for NCEP Recommendations: The National
Commission on Energy Policy, Ending the Energy Stalemate: A Bipartisan Strategy to Meet
America’s Energy Challenges (December 2004); for S. 1151: Sergey Palsev, et al.,
Emissions Trading to Reduce Greenhouse Gas Emissions in the United States: The McCain
Lieberman Proposal [S. 139], Report No. 97 (June 2003). Estimates converted into 2004$
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.
44 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.
45 For more on S. 150, see CRS Report RL32755, Air Quality: Multi-Pollutant Legislation
in the 109th Congress, by Larry Parker and John Blodgett.
CRS-21
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 about even with its coal-fired competition. 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).
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.
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.
CRS-22
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 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. However, 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. DOE currently hopes to
begin receiving waste at Yucca Mountain by 2017.46
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.47 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
46 U.S. Department of Energy, “DOE Announces Yucca Mountain License Application
Schedule,” news release, July 19, 2006.
47 Data compiled by CRS. For table and details, see CRS Report RL32163, Radioactive
Waste Streams: An Overview of Waste Classification for Disposal, byAnthony Andrews.
CRS-23
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
strontium that would need to be placed in Yucca Mountain, thereby expanding its
disposal capacity.48
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.”49
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.50
Six states — California, Connecticut, Kentucky, New Jersey, West Virginia, and
Wisconsin — have specific laws that link approval for new nuclear power plants to
adequate waste disposal capacity. Kansas forbids cost recovery for “excess” nuclear
power capacity if no “technology or means for disposal of high-level nuclear waste”
is available.51 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.52 No nuclear plants have been ordered since
the various state restrictions were enacted, so their ability to meet the Supreme
Court’s criteria has 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.
48 See the Department of Energy website at [http://www.gnep.energy.gov].
49 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.
50 S. 2589, introduced by Senator Domenici by request.
51 Lovell, David L., Wisconsin Legislative Council Staff, State Statutes Limiting the
Construction of Nuclear Power Plants, October 5, 2006.
52 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.