Nuclear Power: Outlook for New U.S. Reactors

Congressional research reportMar 9, 2007

Ask Donna

What actually matters in this document.

Text

Nuclear Power:

Outlook for New U.S. Reactors

name redacted

Specialist in Energy and Environmental Policy

name redacted

Specialist in Energy Policy

March 9, 2007

Congressional Research Service

7-....

www.crs.gov

RL33442

CRS Report for Congress

Prepared for Members and Committees 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 89.8% of their total capacity

in 2006, 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, new reactors are

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.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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 ..............................................................................................9

Loan Guarantees ........................................................................................................... 10

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

Figures

Figure 1. Net Nuclear Generation vs. Capacity, 1973-2004..........................................................4

Figure 2. Relationship Between Combined Licenses, Early Site Permits, and Standard

Design Certifications................................................................................................................6

Figure 3. Natural Gas Prices Delivered to Electric Utilities........................................................ 15

Tables

Table 1. Announced Nuclear Plant License Applications..............................................................1

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 CO2 Permit Price Estimates for Greenhouse Gas Initiatives ............................. 18

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 ............................. 19

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

Contacts

Author Contact Information ...................................................................................................... 21

Congressional Research Service

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 eventually 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, a dozen more utilities

and other companies have announced plans to apply for reactor licenses (as shown in Table 1),

for a total of 34 new nuclear units. Several other companies have announced that they are

considering filing applications as well.

Table 1. Announced Nuclear Plant License Applications

Announced

Applicant

Site

Planned

Application

Date

Reactor Type

Units

Amarillo Power

Not specified

2007

GE ABWR

Constellation

Energy (Unistar)

Calvert Cliffs (MD)

4Q 2007

Areva EPR

Nine Mile Point (NY)

1st half 2008

Areva EPR

Not specified

4Q 2008

Areva EPR

Dominion

North Anna (VA)

November

2007

GE ESBWR

DTE Energy

Fermi (MI)

4Q 2008

Not specified

Duke Power

Cherokee (SC)

2007-2008

West. AP1000

Entergy

River Bend (LA)

May 2008

GE ESBWR

Exelon

Texas

November

2008

Not specified

FPL

Not specified

2009

Not specified

South Texas Project

2007

GE ABWR

Grand Gulf (MS)

November

2007

GE ESBWR

Bellefonte (AL)

October

2007

West. AP1000

Harris (NC)

October

2007

West. AP1000

Levy County (FL)

July 2008

West. AP1000

SCE&G

Summer (SC)

3Q 2007

West. AP1000

Southern

Vogtle (GA)

March 2008

West. AP1000

NRG Energy

NuStart

Progress Energy

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

Announced

Applicant

TXU

Site

Planned

Application

Date

Reactor Type

Units

Comanche Peak (TX)

4Q 2008

Not specified

Texas

4Q 2008

Not specified

Texas

4Q 2008

Not specified

Total Units

Sources: NRC, Nucleonics Week, Nuclear News, Nuclear Energy Institute, company news releases.

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.1

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 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.

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. That is the capacity of about four

to six reactors, although the credits could be spread among a larger number of new reactors under

current rules. If the tax credit results in new reactor construction, the next question will be

whether nuclear construction would continue without further credits. Greenhouse gas legislation

could also be an important factor in nuclear power economics; analysis shows that some

Energy Policy Act of 1992, Title XXVIII, P.L. 102-486.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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 2000.2 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 mid-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

823 billion kilowatt-hours of nuclear electricity generated in the United States during 20063 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. 4

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%.5 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 89.8% of

their total capacity in 2006, after averaging around 75% in the mid-1990s and around 65% in the

mid-1980s.6 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 capacity—about the

capacity of two large reactors.7 The uprates largely offset the closure of five poorly performing

reactors, totaling 3,700 megawatts of capacity, in 1997 and 1998.8 Further uprate requests are

pending.

Seaborg, Glenn T., The Plutonium Economy of the Future, October 5, 1970, p. 7.

“World Nuclear Generation Sets Record in 2006,” Nucleonics Week, February 15, 2007, p. 1.

International Energy Agency, Monthly Electricity Survey, January 2006.

Energy Information Administration, International Energy Annual 2003, Table 2.7; Nucleonics Week, op. cit.

Nucleonics Week, op. cit.; Nuclear Engineering International, November 2005, p. 37.

Nuclear Regulatory Commission, Power Uprates for Nuclear Plants, Fact Sheet, July 2004.

Nuclear News, “World List of Nuclear Power Plants,” March 2005, p. 59.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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 nucleargenerated 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).9 By 2005, the average operating cost was 1.7

cents/kwh.10

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. 11 By the late 1990s, there was real doubt about whether any

reactors would make it to 40 years. Since 2000, however, 48 commercial reactors have received

20-year license extensions from NRC, giving them up to 60 years of operation. License

extensions for seven more reactors are currently under review, and many others are anticipated,

according to NRC.12 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.

Uranium Information Centre, The Economics of Nuclear Power, Briefing Paper 8, January 2006, p. 3.

Nucleonics Week, “U.S. Utility Operating Costs, 2005,” September 14, 2006, p. 7.

Nuclear News, op. cit.

See http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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.13 Twenty-five reactors are currently under construction outside the United States.14

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 NRCissued 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.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

Nuclear News, “Word List of Nuclear Power Plants,” March 2006, p. 37.

World Nuclear Association, World Nuclear Power Reactors 2005-06 and Uranium Requirements, September 21,

2006. Excludes three reactors undergoing reconstruction in the United States and Canada.

10 CFR Part 50.

54 Federal Register 15372, April 18, 1989.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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.

Figure 2. Relationship Between Combined Licenses, Early Site Permits, and

Standard Design Certifications

Source: NRC.

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

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.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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.

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. 18 NRC

established the Office of New Reactors in 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 57 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

Weil, Jenny, “Safety of Existing Fleet to Remain the Top Priority at NRC, Klein Says,” Inside NRC, September 4,

2006, p. 1.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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 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. 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.

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 approved the Illinois permit March 8, 2007, and anticipates final action on the

others later this year.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.

For more information on nuclear plant security, see CRS Report RS21131, Nuclear Power Plants: Vulnerability to

Terrorist Attack, by (name redacted) and (name redacted).

See http://www.nrc.gov/reactors/new-licensing/esp.html.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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

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,”

Internal Revenue Bulletin, No. 2006-18, May 1, 2006, p. 855.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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, 2006.22 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 preoperational 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.”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. Even for regulated utilities, “loan

71 Federal Register 46306, August 11, 2006.

Ibid., p. 46329.

Telephone conversation with Marvin Shaw, DOE Office of General Counsel, May 16, 2006.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

guarantees are critically important to new nuclear plant financing,” the Nuclear Energy Institute

contended in September 2006 testimony. 25

DOE issued its initial solicitation for loan guarantees under EPACT on August 8, 2006.26 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).27 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.28 Therefore, if

a project has significant non-debt financing, the loan guarantees could cover considerably less

than 80% of 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.”29

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

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.

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.

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.”

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.

Testimony of Skip Bowman, op. cit.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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 2015.30 The real capital

charge rate is from the Environmental Protection Agency’s Integrated Planning Model (IPM).31

Calculations were done by CRS and are in constant 2004 dollars.

Table 2. Projected 2015 Costs and Assumptions

(2004$)

Assumption

Coal Plant

Advanced Coal

Plant

Advanced

Natural Gas

GCC

Advanced

Nuclear Power

Plant

Capital costs

$1,217/kw

$1,386/kw

$555/kw

$1,913/kw

Construction

schedule

4 years

3 years

6 years

Fixed O&M costs

$25.07/kw-year

$35.21/kw-year

$10.65/kw-year

$61.82/kw-year

Variable O&M costs

0.418 cents/kwh

0.265 cents/kwh

0.182 cents/kwh

0.045 cents/kwh

Fuel costs

$1.40/million

Btu

$1.40/million Btu

$5.08/million Btu

$0.66/million Btu

Heat rate

8,661 Btu/kwh

7,477 Btu/kwh

6,403 Btu/kwh

10,400 Btu/kwh

Capacity factor

90%

Real capital charge

rate

13.4%

Date project initiated

2015

Sources: DOE/EIA, Assumptions to the Annual Energy Outlook 2006 (March 2006); EPA, Standalone Documentation

for EPA Base Case 2004 (September 2005).

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

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.

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.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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.

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’ estimate of $1,528 per kw (2004).32 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$)

Cents per kwh

Pulverized

Coal Plant

Advanced

Coal Plant

4.5

4.6

Advanced

Natural Gas GCC

Advanced

Nuclear Power

Plant

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.

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.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

Table 4. Projected 2015 Annualized Costs, Including Subsidized Nuclear Power

(2004$)

Cents

per kwh

Pulverized

Coal Plant

Advanced

Coal Plant

Advanced

Natural Gas

GCC

Advanced

Nuclear Power

Plant

Advanced Nuclear

Power Plant with

Production Credit

4.5

4.6

5.6

4.2-4.7a

Source: CRS calculations based on Table 2 assumptions.

Range reflects uncertainty with future inflation and construction times and dates, which affect the real value

of the production credit.

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.

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, and 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.33

See Environmental Protection Agency, Analyzing Electric Power Generation under the CAAA, Office of Air and

Radiation (March 1998), p. A2-12.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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.

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 $6.65/mcf or million Btu (MMBtu) in 2004$. 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.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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

approximately $6.65 per MMBtu (2004$).

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 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.”34 The industry

also has been attempting to promote nuclear power as one solution to rising greenhouse gas

emissions.35 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. 36

Despite strong Bush Administration opposition to mandatory greenhouse gas reduction programs,

a number of congressional proposals to advance programs designed to reduce greenhouse gases

were introduced in the 109th Congress,37 and similar efforts have continued in the 110th Congress.

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.38 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.

Interdisciplinary MIT Study, The Future of Nuclear Power, Massachusetts Institute of Technology, 2003, p. 79.

See the Nuclear Energy Institute (NEI) website at http://www.nei.org/index.asp?catnum=1&catid=11.

Patrick Moore, “Going Nuclear,” Washington Post, April 16, 2006, p. B1.

See CRS Report RS22076, Climate Change: Summary and Analysis of the Climate Stewardship Act (S. 342, S. 1151,

and H.R. 759), by (name redacted) and (name redacted), and CRS Report RL32755, Air Quality: Multi-Pollutant

Legislation in the 109th Congress, by (name redacted) and (name redacted).

Ben Evans and Catherine Hunter, “Senate Rejects Global Warming Amendment,” CQ Today, June 22, 2005.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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 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 4354 vote.

Four proposals introduced in the 109th Congress had analyses conducted by EPA and others that

estimated their costs. For the 110th Congress, five bills have been introduced, but none have

accompanying cost analyses. 39 However, several of the bills analyzed during the 109th Congress

have been reintroduced in the 110th Congress, although with some modifications. These include S.

317, which has the CO2 control provisions of S. 2724 of the 109th Congress, S. 280 and H.R. 620,

which are modified versions of S. 1151 of the 109th Congress, and continuing efforts to draft

legislation based on recommendations by the National Commission on Energy Policy (NCEP).

The bills of the 109th Congress included 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 CO2 cap

would be set in two 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

For a comparison of bills introduced in the 110th Congress, see CRS Report RL33846, Greenhouse Gas Reduction:

Cap-and-Trade Bills in the 110th Congress, by (name redacted), (name redacted), and (name redacted).

For more on S. 2724, see CRS Report RL32755, Air Quality: Multi-Pollutant Legislation in the 109th Congress, by

(name redacted) and (name redacted).

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 (name redacted) and (name redacted).

For a discussion of safety valves, see CRS Report RS21067, Global Climate Change: Controlling CO2 Emissions—

Cost-Limiting Safety Valves, by (name redacted).

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

•

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 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 CO2 cap would require affected entities to reduce

their emissions to 1990 levels by 2010.

Table 6 indicates projected trade permit prices for the four proposals. 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 CO2 Permit Price Estimates for Greenhouse Gas Initiatives

(in 2004$/metric ton of CO2)

Year

S. 2724a

NCEP

Recommendations

S. 1151

S. 150

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.

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 about even with its coal-fired

competition. The fourth, S. 150, would provide the greatest advantage to nuclear power. It is also

A House version of the bill, H.R. 759, has been introduced by Representatives Gilchrest and Olver.

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 (name redacted) and (name redacted).

For more on S. 150, see CRS Report RL32755, Air Quality: Multi-Pollutant Legislation in the 109th Congress, by

(name redacted) and (name redacted).

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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$)

Pulverized

Coal Plant

Advanced Coal

Plant

Advanced

Natural Gas

GCC

Advanced

Nuclear

Power

Plant

2015

2020

2015

2020

2015

2020

S. 2724a

4.6

4.7

4.8

4.6

4.7

5.6

NCEP

Recommendations

4.9

5.1

5.0

5.1

4.8

4.9

5.6

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.

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.

Table 8. Effect of Permit Prices/Carbon Tax on Electricity Production Costs

Permit Price or

Carbon Tax

(2004$/metric ton

of CO2)

Natural Gas

(cents/kwh)

Conventional Coal

(cents/kwh)

Advanced Coal

(cents/kwh)

4.8

4.9

5.0

$10

4.9

5.3

$15

5.1

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.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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 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

U.S. Department of Energy, “DOE Announces Yucca Mountain License Application Schedule,” news release, July

19, 2006.

Data compiled by CRS. For table and details, see CRS Report RL32163, Radioactive Waste Streams: Waste

Classification for Disposal, by (name redacted).

See the Department of Energy website at http://www.gnep.energy.gov.

NRC, Waste Confidence Decision Review, 55 Federal Register 38472, September 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.

“Nuclear Fuel Management and Disposal Act,” transmitted to House Speaker Nancy Pelosi and Vice President

Richard Cheney March 6, 2007, by Energy Secretary Samuel Bodman.

Congressional Research Service

Nuclear Power: Outlook for New U.S. Reactors

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.

Author Contact Information

(name redacted)

Specialist in Energy and Environmental Policy

[redacted]@crs.loc.gov, 7-....

(name redacted)

Specialist in Energy Policy

[redacted]@crs.loc.gov, 7-....

Lovell, David L., Wisconsin Legislative Council Staff, State Statutes Limiting the Construction of Nuclear Power

Plants, October 5, 2006.

Wiese, Steven M., State Regulation of Nuclear Power, CRS Report prepared for the House Committee on Interior

and Insular Affairs, December 14, 1992, p. 18.

Congressional Research Service

EveryCRSReport.com

The Congressional Research Service (CRS) is a federal legislative branch agency, housed inside the

Library of Congress, charged with providing the United States Congress non-partisan advice on

issues that may come before Congress.

EveryCRSReport.com republishes CRS reports that are available to all Congressional staff. The

reports are not classified, and Members of Congress routinely make individual reports available to

the public.

Prior to our republication, we redacted names, phone numbers and email addresses of analysts

who produced the reports. We also added this page to the report. We have not intentionally made

any other changes to any report published on EveryCRSReport.com.

CRS reports, as a work of the United States government, are not subject to copyright protection in

the United States. Any CRS report may be reproduced and distributed in its entirety without

permission from CRS. However, as a CRS report may include copyrighted images or material from a

third party, you may need to obtain permission of the copyright holder if you wish to copy or

otherwise use copyrighted material.

Information in a CRS report should not be relied upon for purposes other than public

understanding of information that has been provided by CRS to members of Congress in

connection with CRS' institutional role.

EveryCRSReport.com is not a government website and is not affiliated with CRS. We do not claim

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.