Summary and Introduction

By the end of the next decade, demand for electricity in the United States is expected to increase by about 20 percent, according to the Energy Information Administration (EIA). That projected increase—coupled with concerns about the effects of greenhouse-gas emissions on the environment—has encouraged policymakers to reassess the role that nuclear power might play both in expanding the capacity to generate electricity and in limiting the amount of greenhouse gases produced by the combustion of fossil fuels. Because nuclear power uses an abundant fuel source to generate electricity without emitting such gases, prospects that new nuclear power plants will be planned and financed in the next decade are greater than at any time since the 1970s, when cost overruns and concerns about public safety halted investment in such facilities.

This reappraisal of nuclear power is motivated in large part by the expectation that market-based approaches to limit greenhouse-gas emissions could be put in place in the near future. Several options currently being considered by the Congress—including "cap-and-trade" programs—would impose a price on emissions of carbon dioxide, the most common greenhouse gas.¹ If implemented, such limits would encourage the use of nuclear technology by increasing the cost of generating electricity with conventional fossil-fuel technologies. The prospect that such legislation will be enacted is probably already reducing investment in conventional coal-fired power plants.

Current energy policy, especially as established and expanded under the Energy Policy Act of 2005 (EPAct), provides incentives for building additional capacity to generate electricity using innovative fossil-fuel technologies and an advanced generation of nuclear reactor designs that are intended to decrease costs and improve safety.² Among the provisions of EPAct that specifically apply to newly built nuclear power plants are funding for research and development; investment incentives, such as loan guarantees and insurance against regulatory delays; and production incentives, including a tax credit. Since the enactment of EPAct, about a dozen utilities have announced their intention to license about 30 nuclear plants.

This study assesses the commercial viability of advanced nuclear technology as a means of meeting future demand for electricity by comparing the costs of producing electricity from different sources under varying circumstances. The Congressional Budget Office (CBO) estimated the cost of producing electricity using a new generation of nuclear reactors and other base-load technologies under a variety of assumptions about prospective carbon dioxide charges, EPAct incentives, and future market conditions.³ This study compares the cost of advanced nuclear technology with that of other major sources of base-load capacity that are available throughout the country—including both conventional and innovative fossil-fuel technologies. Because the study focuses only on technologies that can be used as base-load capacity in most parts of the country, it does not address renewable energy technologies that are intermittent (such as wind and solar power) or technologies that use resources readily available only in certain areas (such as geothermal or hydroelectric power).

In the long run, carbon dioxide charges would increase the competitiveness of nuclear technology and could make it the least expensive source of new base-load capacity. More immediately, EPAct incentives by themselves could make advanced nuclear reactors a competitive technology for limited additions to base-load capacity. However, under some plausible assumptions that differ from those CBO adopted for its reference scenario—in particular, those that project higher future construction costs for nuclear plants or lower natural gas prices—nuclear technology would be a relatively expensive source of capacity, regardless of EPAct incentives. CBO’s analysis yields the following conclusions:

Electricity is produced using a variety of technologies powered by different sources of fuel, but the sources that predominate are coal, natural gas, and uranium. Coal-burning technologies emit the most carbon dioxide per unit of electricity; natural gas technologies emit carbon dioxide at about half that rate; and nuclear power, a "zero emissions technology," emits no carbon dioxide at all.⁴ (See Box 1-1 for details on power plant technologies.)

An advanced generation of nuclear reactors is one of several options currently under consideration for providing additional base-load capacity to produce electricity. Utilities will weigh the cost of new nuclear power plants against that of both conventional and innovative fossil-fuel alternatives. Among the conventional alternatives are pulverized coal technology and combined-cycle turbines that rely on natural gas. Among the innovative alternatives are technologies that capture and store most of the carbon dioxide emitted when coal and natural gas are burned. Utilities use several other technologies to generate electricity, but they are not widespread and are not likely to be commercially viable base-load alternatives in most areas.

Nuclear Power Plants
Advanced, or third-generation, nuclear reactors were developed by enhancing the designs of existing nuclear power plants, which use first- and second-generation reactors developed before the 1980s, before major advances in digital control systems. Interest in those older designs disappeared in the 1970s for a variety of reasons, including construction cost overruns, poor operational performance, and concerns about the safety of the nuclear technology. Beginning in the 1990s, industry and government participated in a variety of cost-sharing programs to develop the third generation of nuclear reactors, which are designed to be safer to operate and less expensive to build and maintain.¹

Fossil-Fuel Power Plants
Coal and natural gas can be burned to create electricity through several different technologies. Pulverized coal power plants, which burn solid coal ignited by injected air, are by far the most common option for generating base-load electricity. Combined-cycle technology, which harnesses residual steam heat from the combustion cycle, has become, over the past 20 years, the most efficient method of generating electricity from natural gas. However, those conventional coal and natural gas technologies emit carbon dioxide and are therefore susceptible to the pricing of such emissions, so innovative technologies with "carbon capture and storage" (CCS) may become the most commercially viable option for using those fossil fuels.

Although CCS technologies have not yet been deployed commercially at power plants, many observers expect them to be available over the upcoming decade. Those technologies would capture carbon dioxide emitted by power plants fueled by either coal or natural gas and store it underground in geologic formations, such as deep saline formations, oil and gas fields, and coal beds that cannot be mined economically. For coal power plants with CCS, the coal would first be gasified and then the resulting gas ignited. Such integrated-gasification combined-cycle (IGCC) technology, which is already in use at a few power plants that do not capture carbon dioxide, allows for capturing it before combustion, when it is more concentrated. Natural gas power plants with CCS use the same combined-cycle process as conventional natural gas plants but filter the carbon dioxide from the natural gas before combustion.

Technologies Not Included in the Congressional Budget Office’s Analysis
Oil and renewable energy technologies are not expected to compete with nuclear technology as a source of new base-load capacity nationwide. Because of high fuel costs, oil-fired generators are commercially competitive only in a few areas that have limited access to coal and natural gas, most notably, Hawaii. Intermittent technologies such as wind and solar power, which cannot operate much of the day, are not a source of base-load capacity. Other renewable technologies, like geothermal and hydroelectric power, can provide a more consistent flow of electricity but use resources that are mostly available in the West. Biomass technology can generate base-load electricity in certain parts of the country but is typically limited to small applications because fuel costs become prohibitive at large facilities.

1. The incentives provided by the Energy Policy Act of 2005 that are addressed in this study promote the research, design, and deployment of third-generation reactors. Additional incentives under that law promote the research and development of designs for a fourth generation, but those technologies are not expected to be deployable until around 2030.

2. In its analysis, the Congressional Budget Office also estimated the cost of electricity from new IGCC plants without CCS. Those results are not presented because they are roughly similar to the results for pulverized coal power plants.

3. For a more detailed discussion of technologies to capture and store carbon dioxide, see Congressional Budget Office, The Potential for Carbon Sequestration in the United States (September 2007), pp. 8–17.

Historically, most base-load capacity has been provided using coal or nuclear technologies because, once the plants have been built, low fuel costs make them relatively cheap to operate continuously. Even though natural gas prices have increased significantly in recent years, natural gas remains the dominant source of peak capacity because power plants using that fuel are less expensive to build than coal-fired plants or nuclear reactors and easier to start up and shut down.

From 1994 to 2006, a period when the total amount of electricity generated rose by 25 percent, utilities appear to have increased base-load generation primarily by stepping up production at existing coal and nuclear plants, while using natural gas technology to expand overall capacity. During that time, the amount of electricity generated by nuclear and coal power plants expanded by about 20 percent as those facilities operated at closer to maximum capacity. (See Figure 1-1.) However, coal and nuclear capacity remained roughly constant because utilities increasingly chose to construct new natural gas power plants. By 2006, natural gas capacity had doubled, accounting for 75 percent more electricity generation than in 1994. Because of the extensive investment in natural gas capacity, the amount of excess capacity—which is used to meet surges in demand or to compensate for shutdowns at power plants—remained roughly the same.⁵

Source: Congressional Budget Office based on data from the Energy Information Administration.

Note: Electricity-generating capacity is measured in megawatts; the electrical power generated by that capacity is measured in megawatt hours. During a full hour of operation, 1 megawatt of capacity produces 1 megawatt hour of electricity, which can power roughly 800 average households.

a. Natural gas capacity represents about 85 percent of total gas capacity, with the remainder using petroleum-based or other gases.

Investors may have preferred new natural gas power plants as a source of additional base-load and peak capacity because "combined-cycle" technology became an affordable and efficient technique for generating electricity.⁶ As recently as 2000, EIA forecast that combined-cycle natural gas technology would be the least expensive means of generating base-load electricity until at least 2020. The expansion of natural gas capacity since 1994, rather than nuclear or coal capacity, could indicate that investors had similar expectations. However, EIA now projects that some of the recent increase in the price of natural gas will persist. (Figure 1-2 charts actual and projected natural gas prices.) If that assessment proves to be the case, natural gas capacity could be a relatively expensive source of base-load power.

Source: Congressional Budget Office based on data from the Energy Information Administration (EIA).

Prices are expressed in real (inflation-adjusted) dollars using the gross domestic product price index; they represent average prices received by natural gas producers (in the lower 48 states) and, therefore, do not include the cost of delivering natural gas from the wellhead to the power plant. EIA provides the average price of natural gas delivered to power plants for the years from 1997 to 2006. On average, those prices exceed the reported prices by $0.70 per million Btu.

Over the past few years, most likely in response to both the prospect of carbon dioxide charges and the incentives offered in EPAct, several utilities have begun planning new nuclear projects, which may signal the end of a 30-year hiatus in financing the construction of nuclear power plants. As of 2007, over a dozen utilities had announced their intention to file construction and operating licenses (COLs), which are obtained through the Nuclear Regulatory Commission (NRC), for roughly 30 nuclear plants.⁷ Those plants would provide about 40,000 megawatts of new capacity.⁸ For perspective, the roughly 100,000 megawatts of existing nuclear capacity currently provides about 20 percent of all electrical power in the United States.

Although the announcements reflect renewed interest in building new nuclear power plants, they do not indicate how much capacity utilities will ultimately build. Completing the revised design and licensing process is expected to cost about $100 million per plant, less than 5 percent of the anticipated cost for constructing a nuclear plant. Filing a COL application by the end of 2008 may be necessary for those projects to remain eligible for a share of the $7.5 billion (in nominal dollars) in production tax credits, but filing does not obligate an applicant to build the proposed plant.

New base-load capacity requires years to plan and build—roughly a decade in the case of nuclear technology. Because power plants can operate for many years (numerous power stations built in the first half of the previous century are still in use), new capacity is expected to replace existing capacity slowly in the absence of a cost advantage.

Utilities typically invest in new electricity-generating capacity to meet increases in demand or to replace facilities that have become too expensive to operate. When planning new power plants, both traditional regulated utilities (whose return on investment is largely determined by public utility commissions) and merchant generators (whose return is dictated by market outcomes) consider which technology generates electricity at the lowest cost. The cost of electricity from new capacity depends on the cost of building a plant, the cost of financing that construction, and the recurring cost of operating the plant (including the cost of fuel).

For the purposes of CBO’s analysis, conventional coal plants are assumed to use pulverized coal technology, which produces energy by burning a crushed form of solid coal, and conventional natural gas plants are assumed to convert gas into electricity using combined-cycle turbines. The advanced nuclear technology considered in the analysis is confined to reactor designs that would be available in the next decade. At the same time, development continues on innovative fossil-fuel technologies that are designed to capture and store almost all of the carbon dioxide emitted while generating electricity. Over the next decade, investors will also consider those carbon capture-and-storage, or CCS, technologies as an alternative for new generation capacity.⁹

To compare the cost of alternatives for new generating capacity, CBO developed a reference scenario to serve as a benchmark against which the effects of both existing and prospective policy initiatives and future market conditions could be measured. Specifically, the reference scenario excludes the possible effects of carbon dioxide charges and EPAct incentives. On the basis of the assumptions underlying that scenario, CBO estimated the levelized costs of five technological alternatives. Levelized cost, a construct frequently used in analyzing investment in electricity generation, is the minimum price of electricity at which a technology generates enough revenue to pay all of the utilities’ costs, including a sufficient return to investors.¹⁰ Federal, state, and local policies can change the costs incurred by utilities by providing incentives, which shift costs or financial risk to the public, or by levying taxes on the utilities, which increases their costs.

Among federal laws and programs that influence investors’ decisions about which technology to choose for new electricity-generating capacity are standard corporate tax laws, programs that support specific technologies by altering tax laws or providing other incentives, and taxes on specific goods whose production or consumption affects others. Carbon dioxide charges in particular could significantly increase the utilities’ costs of generating electricity, which could reduce the amount of investment in new capacity if customers reduced their usage in reaction to higher prices. This analysis, however, focuses on how potential carbon dioxide charges and the provisions of EPAct would change the relative cost of alternatives for generating electricity and does not address the total quantity of base-load capacity that might be built once investors accounted for future demand. However, there is general agreement that demand will continue to grow with the population; accordingly, investing in additional capacity will be commercially viable unless the costs of supplying electricity rise significantly.

Measuring the utilities’ costs across a range of potential carbon dioxide charges indicates which technologies might be competitive, given certain assumptions about future legislative action and market outcomes. In general, the higher the costs to utilities of emitting carbon dioxide, the more competitive nuclear power would be because it is the only zero-emissions base-load technology.

In the absence of both emission charges and EPAct incentives, conventional fossil-fuel technology would dominate nuclear technology. But, even without EPAct incentives, if lawmakers enacted legislation that resulted in a carbon dioxide charge of about $45 per metric ton, nuclear generation would most likely become a more attractive investment for new capacity than conventional fossil-fuel generation (see the left panel of Figure 1-3). If the cost of emitting carbon dioxide was between $20 and $45 per metric ton, nuclear generation as an option for new capacity would probably be preferred over coal but not natural gas.

Notes: Electricity-generating capacity is measured in megawatts; the electrical power generated by that capacity is measured in megawatt hours. During a full hour of operation, 1 megawatt of capacity produces 1 megawatt hour of electricity, which can power roughly 800 average households.

Advanced nuclear technology refers to third-generation reactors. Conventional coal power plants are assumed to use pulverized coal technology, which produces energy by burning a crushed form of solid coal. Conventional natural gas power plants are assumed to convert gas into electricity using combined-cycle turbines.

These comparisons exclude the impacts of incentives provided under the Energy Policy Act of 2005.

Most of CBO’s analysis focuses on technology choices for new power plants, but electricity from new capacity would still compete in the same market as that from existing capacity and could eventually begin to displace that capacity if the price of emitting carbon dioxide was sufficiently high. For instance, because utilities have already incurred construction costs for existing facilities, existing coal-fired power plants could be a less expensive source of electricity than new power plants under the range of carbon dioxide charges considered (see the right panel of Figure 1-3). If building new nuclear power plants proved to be less expensive than building new coal-fired plants but more expensive than using existing coal capacity, additions to nuclear capacity would be limited to meeting increases in electricity usage. Despite the high carbon intensity of conventional coal technology, 0 continuing to operate existing coal-fired plants would remain a relatively inexpensive source of electricity until carbon dioxide charges reached about $45 per metric ton.

During the next several years, the incentives put in place or extended by EPAct could significantly improve the relative cost of at least the first few nuclear plants built. (See Table 1-1 for an overview of EPAct incentives.) In contrast to carbon dioxide charges, which make nuclear alternatives attractive by increasing the cost of fossil-fuel alternatives, subsidies for new nuclear projects directly reduce the cost of nuclear plants in comparison to fossil-fuel options.

Notes: CCS=carbon capture and storage; DOE=Department of Energy; EPAct=Energy Policy Act of 2005; FOAK=first-of-a-kind costs; MW=megawatt; MWh=megawatt hour.

Electricity-generating capacity is measured in MW; the electrical power generated by that capacity is measured in MWh. During a full hour of operation, 1 MW of capacity produces 1 MWh of electricity, which can power roughly 800 average households.

Advanced nuclear technology refers to third-generation reactors; nuclear technology not designated "advanced" may use first- and second-generation reactors. Innovative coal and natural gas technologies are assumed to capture and store most carbon dioxide emissions.

g. The production tax credit for advanced nuclear technology is not adjusted for inflation; consequently, the maximum value of the credit is likely to decrease substantially by the time advanced nuclear power plants begin operating. In addition, if more than 6,000 MW of capacity qualified, the credit would then be divided proportionally among all qualified capacity. For example, if 12,000 MW of capacity qualified, then the owners of each plant would receive a maximum credit of $9/MWh. The per-MWh value of the credit would also be reduced if the nuclear power plant operated at 80 percent above capacity.

The largest incentives available under EPAct are a production tax credit and a loan guarantee program. The tax credit provides up to $18 in tax relief per megawatt hour of electricity produced at qualifying power plants during the first eight years of operation. (For comparison, the average wholesale price of electricity in 2005 was about $50 per megawatt, on average.)¹¹ The loan guarantee program provides a federal guarantee on debt that covers as much as 80 percent of construction costs. (Debt for building capacity has been financed at roughly 1 percentage point to 5 percentage points above the Treasury-bill rate.)¹² The loan guarantee program also applies to utilities employing innovative fossil-fuel or renewable technologies.

Without the incentives offered to investors who chose nuclear and other innovative generating technologies, conventional coal technology would be the least expensive means of generating electricity (see Figure 1-4). Generating electricity with nuclear technology would be roughly 35 percent more expensive than using conventional coal technology and 30 percent more expensive than using natural gas capacity. Accordingly, investment in nuclear capacity would be unlikely in the absence of carbon dioxide charges and EPAct incentives.

CBO’s reference scenario excludes both the effects of prospective carbon dioxide constraints and the impact of EPAct incentives.

Electricity-generating capacity is measured in megawatts; the electrical power generated by that capacity is measured in megawatt hours. During a full hour of operation, 1 megawatt of capacity produces 1 megawatt hour of electricity, which can power roughly 800 average households.

The estimate of the effect of EPAct incentives assumes that advanced nuclear technology receives the maximum production tax credits and loan guarantees. The production tax credits are shared among 6,000 megawatt or less of advanced nuclear capacity, and loan guarantees cover 80 percent of construction costs.

Nuclear power would be a competitive technology for a few new power plants, however, if those plants received the maximum benefits that could be provided under EPAct. Most of the reductions in the cost for those plants would come from the production tax credit and loan guarantees. Other incentives—such as preferential tax treatment for decommissioning funds and limited liability protection—would have a relatively small effect on the cost of nuclear capacity.13 Incentives covering first-of-a-kind (FOAK) costs could be crucial for attracting financing for the first nuclear plants of each advanced reactor design, although those incentives might not directly affect the cost of subsequent plants. The investment tax credit and loan guarantees for innovative coal plants with CCS and loan guarantees for innovative natural gas power plants with CCS reduce the utilities’ costs for those technologies but not by enough to make them less expensive than nuclear power plants that qualify for EPAct incentives or conventional fossil-fuel power plants.

The cost of new nuclear capacity would probably be higher if utilities attempted to build a large number of power plants over the next decade. For instance, building all of the 30 proposed nuclear plants over the next 10 to 15 years—roughly the period of availability for the production tax credit—could significantly increase construction costs for nuclear power plants by increasing demand for scarce components that are necessary to build reactors (for example, specialized steel forgings).

A large wave of additions could also lead to higher costs by reducing the value of the production tax credits or by exhausting coverage under the loan guarantee program. EPAct limits production tax credits for nuclear power plants to a total of $7.5 billion, which means that each eligible plant’s allotment of credits would decrease if more than 6,000 megawatts of capacity (roughly the capacity of five plants) qualified for the credit.¹⁴ CBO’s analysis incorporates the assumption that no more than 6,000 megawatts of capacity would qualify. Thus, the comparison of costs is intended to indicate only whether nuclear technology would be a commercially viable choice for up to a few nuclear power plants. For gauging the long-run competitiveness of nuclear generation, potential carbon dioxide charges are more likely to influence the development of new nuclear capacity than EPAct incentives.

The commercial viability of nuclear capacity depends both on generators’ perceptions of future market conditions at the point they consider committing to the construction of a plant—which might not occur for a few years—and the return that investors would require if confronted with carbon dioxide charges. An array of factors—recent volatility in natural gas prices and construction costs, nuclear power’s history of construction cost overruns, and uncertainty about future policy on carbon dioxide emissions—suggests that a wide range of costs are plausible for each of the base-load technologies. Those ranges in costs for new power plants demonstrate that each technology faces considerable uncertainty.

The assumptions used in the reference scenario are intended to represent investors’ perceptions, but even if those base-case assumptions accurately portray the current outlook, unanticipated events may alter those perceptions before investors make binding commitments to nuclear capacity. CBO compared levelized costs under several plausible future scenarios for fuel, construction, and financing costs to identify which technology utilities would probably choose for new capacity under a broad range of circumstances.

Cost of Fuel. In the reference scenario, CBO assumed that natural gas prices in the future would be similar to average prices observed since 2000. However, if natural gas prices fell to levels seen in the 1990s and carbon dioxide emissions remained unconstrained, conventional natural gas technology would be the cheapest source of base-load capacity, even if nuclear technology benefited from EPAct incentives. Conversely, if natural gas prices continued to rise, as they have since the 1990s, natural gas technology would be unlikely to be a competitive alternative for base-load electricity generation. (Table 1-2 shows the cost of generating electricity using each technology under the reference scenario and under alternative market conditions that involve substantial deviations from the base-case assumptions about costs for fuel and construction.)

Although uranium prices have fluctuated widely over the past few years, fuel costs have historically accounted for a small share of the cost of nuclear capacity. EIA projects that the price of nuclear fuel will increase by about 40 percent over the next decade—a trend that CBO incorporates in its base-case assumptions—but if nuclear fuel prices stay at the relatively low 2006 level, the overall cost of nuclear technology would decrease by only 3 percent. (Table 1-2 shows that the cost of nuclear technology is largely insensitive to changes in fuel prices.) Utilities investing in new nuclear power plants would incur most of the cost of that technology during construction.

		Variations in Future Market Conditions				Variations in
		Fuel Costs		Construction Costs		Future Carbon Dioxide Policy
	Reference Scenario	High (+100%)	Low (-50%)	High (+100%)	Low (-50%)	Emissions Capped at 2008 Level	Emissions Capped at About 85% Below 2008 Level by 2050


Advanced Nuclear	72	80	68	121	48	72	72

Conventional Coal	55	70	47	83	40	80	128

Conventional Natural Gas	57	97	36	69	51	67	86

Alternative market and policy conditions are overlaid on the reference scenario, which excludes both the effects of prospective carbon dioxide constraints and the impact of incentives provided under the Energy Policy Act of 2005.

Cost of Construction. Historically, construction costs for nuclear facilities have been roughly double initial estimates. NRC’s revised licensing process for nuclear power plants is expected to reduce midconstruction modifications, which were blamed for many cost overruns in the past. Moreover, vendors argue that advanced reactors will have lower construction costs because they have fewer parts than older reactors. As a result, CBO’s base-case assumption for construction costs is about 25 percent lower than the historical average—a figure that reflects recent experience in the construction of advanced reactors in Japan. If those factors turned out not to reduce construction costs in the United States, nuclear capacity would probably be an unattractive investment even with EPAct incentives, unless substantial carbon dioxide charges were imposed.

Cost of Financing. The cost of financing construction is substantial for all technologies but particularly so for capital-intense technologies. In CBO’s base-case assumptions, the cost incurred to finance commercially viable projects did not depend on which technology was used for a given project. That assumption would be justified if volatility in natural gas prices and the prospect of constraints on carbon dioxide emissions created cost uncertainties for conventional fossil-fuel technologies that were similar in magnitude to the uncertainties facing investment in nuclear technology.¹⁵

Utilities that invest in coal capacity face substantial cost uncertainties because of the prospect of future carbon dioxide constraints and the unknown stringency of such constraints. (The last two columns of Table 1-2 show the cost for new power plants by technology associated with two proposed carbon dioxide constraints.) A policy that constrained carbon dioxide emissions to 2008 levels is projected to increase the cost of electricity from conventional coal-fired plants by roughly one-half and a more stringent constraint would more than double the cost.¹⁶ The projected cost of electricity from conventional natural gas capacity is about half as sensitive to such constraints. Because nuclear plants do not emit carbon dioxide, their levelized costs would be unaffected by the stringency of carbon charges.

A cap-and-trade program would require utilities or other entities to hold permits, or allowances, to emit carbon dioxide. Because the permits would be tradable, a utility could buy them if it exceeded the emission cap or sell them if it emitted less than the cap allowed. The price at which those allowances traded would be the price of emitting carbon dioxide.

The Energy Policy Act (Public Law 109-58) was signed into law on August 8, 2005. The Energy Independence and Security Act (P.L. 110-140), which was enacted in December 2007, did not provide additional incentives for nuclear technology or alter the EPAct incentives analyzed in this study.

This study considers only stack emissions of carbon dioxide—emissions resulting directly from the operation of the power plant. All technologies cause additional emissions from the construction and decommissioning of a power plant, as well as from the production of fuel.

The electrical power industry’s ability to continue to meet demand is conventionally measured by comparing peak usage—the amount of capacity used when electricity demand is greatest—to the amount of capacity available during the periods of peak usage. Both peak usage and the amount of capacity available to meet it increased by roughly 30 percent between 1994 and 2006, indicating the amount of excess capacity has, for the most part, stayed stable. (Peak usage data are available from EIA at www.eia.doe.gov/cneaf/electricity/epa/epat3p2.html under the label "net internal demand.") However, the infrastructure for transmitting electricity between certain areas of the country is limited; accordingly, excess capacity in one region may not be available to all other regions.

Combined-cycle gas turbines generate electricity in two sequential processes, first using the energy produced by burning natural gas and then harnessing residual steam heat. The single-cycle process is generally considered an inefficient method of generating base-load power because it produces less electricity from a given amount of fuel.

See Energy Information Administration, U.S. Household Electricity Report (July 2005). Electricity-generating capacity is measured in megawatts; the electrical power generated by that capacity is measured in megawatt hours. During a full hour of operation, 1 megawatt of capacity generates 1 megawatt hour of electricity, which can power roughly 800 average households.

The levelized cost estimates calculated in this study do not include the cost of distributing electricity so the relevant price against which costs are compared is the wholesale price of electricity. Nor do the calculations include any impediments, incentives, or rate regulation provided by state or local governments. Several states have official or de facto prohibitions against the construction of additional nuclear power plants or additional conventional coal-fired power plants. Other states and localities encourage additional nuclear capacity through tax incentives or regulations that allow higher returns.

CBO based carbon dioxide charges under the two hypothetical cap-and-trade policies on allowance prices in Sergey Paltsev and others, Assessment of U.S. Cap-and-Trade Proposals, Working Paper No. 13176 (Cambridge, Mass.: National Bureau of Economic Research, June 2007).

Program	Technology	Incentives	Federal Cost

Research and Development

Nuclear Power 2010	Advanced nuclear	DOE covers one-half of FOAK costs for licensing and design	$281 million (nominal dollars through 2007)

FutureGen	Innovative coal	DOE shares the cost of developing new facilities	$97 million (nominal dollars through 2007)

Investment

Loan Guarantee	Eligible technologies (including advanced nuclear and innovative coal)	Provides low-cost debt financing on up to 80 percent of construction costs (the Treasury reimburses the lender in cases of default)	The utility pays the Treasury for administrative and subsidy costs, but tax revenues diminish under debt financing^a,b

Delay Insurance^c	Advanced nuclear	Applies to the first six nuclear plants covered by DOE. Compensates for certain delays in operation, providing up to $500 million apiece for the first two plants and $250 million each for the next four	Utility pays subsidy cost^a

Investment Tax Credit	Innovative coal^d	Provides tax credits for up to 20 percent of a project’s construction costs	Less than the dollar value of the credits^e


Production

Production Tax Credit	Advanced nuclear	Up to $18/MWh over the first eight years of operation for new nuclear plants^{f, g}	A reduction in tax revenues up to the value of the credits issued^h

Limited Liabilityⁱ	Nuclear	Applies to plants built through 2025. The nuclear industry would not be responsible for damage exceeding $10.6 billion from a nuclear accident^j	Probably small in terms of expected costs (see Box 3-1 in Chapter 3)

Tax Treatment of Decommissioning Funds	Nuclear	Extends to plants owned by merchant generators. Funds taxed at a reduced rate (20 percent)^k	A reduction in tax revenues