Results and Implications of the Analysis

Under the provisions of the Energy Policy Act of 2005, it is probable that at least a few nuclear power plants will be built over the next decade, most likely in markets where electricity usage and the corresponding demand for additional base-load capacity are expected to grow significantly. Ultimately, however, the longer-term competitiveness of nuclear technology as a source of electricity is likely to depend on policymakers’ decisions regarding carbon dioxide constraints. If such constraints are implemented, nuclear power will probably enjoy a cost advantage over conventional fossil-fuel alternatives as a source of electricity-generating capacity. Today, even the anticipation that carbon dioxide emissions will be priced is a factor being weighed in investors’ decisions about new base-load capacity. Those conclusions are tentative, though, because the electricity industry faces numerous uncertainties. If expectations related to future market conditions—especially those pertaining to construction costs or fuel prices—shift before investors commit to the construction of new base-load capacity, the prospects for new nuclear capacity could change dramatically.

In the Congressional Budget Office’s reference scenario, the estimated levelized costs of new capacity based on conventional coal or conventional natural gas technology are roughly equivalent. By comparison, the levelized costs of the other options under consideration are much higher. Specifically, the levelized costs for building and operating a new nuclear power plant are estimated to be about 30 percent more than the cost of either a conventional coal or natural gas plant. The costs for innovative coal and natural gas plants that capture and store carbon dioxide are even greater, exceeding those of the lowest-cost conventional fossil-fuel options by 50 percent. Accordingly, in the absence of carbon dioxide constraints and without the incentives of EPAct, utilities would probably continue to build power plants relying on conventional fossil-fuel technologies to meet increases in base-load electricity demand.

Differences in construction and fuel costs explain the differences between the levelized costs of conventional fossil-fuel technologies and nuclear technology. In the reference scenario, the cost of building a new coal plant is about two-thirds the cost of building a nuclear plant, and the cost of building a natural gas plant is even less (about a third of that required to build a nuclear plant). The levelized costs for conventional coal and natural gas technologies converge because the higher cost of building a coal plant is offset by the higher cost of using natural gas as a fuel. The highest-cost alternatives considered in the reference scenario, innovative fossil-fuel plants that capture and store carbon dioxide, are encumbered by the fact that they are more costly to build and fuel than their conventional counterparts. In the reference scenario, the levelized cost of a nuclear plant is about 15 percent below that of an innovative coal-fired facility with CCS (the least expensive of the two innovative fossil-fuel technologies).

CBO’s results echo those of other studies. Researchers at the Energy Information Administration and Massachusetts Institute of Technology found that, in the absence of carbon dioxide charges and EPAct incentives, new nuclear technology would have a higher levelized cost than conventional fossil-fuel technologies. Some disagreement exists about the size of the gap, however (see Figure 3-1).¹ The researchers at MIT predicted a larger cost gap because they concluded that an investment in new nuclear capacity would be riskier than an investment in conventional fossil-fuel technologies; consequently, they projected higher financing costs for nuclear technology.

Notes: EIA = Energy Information Administration; MIT = Massachusetts Institute of Technology.

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.

CBO’s estimates of levelized costs presented here are based on a reference scenario that excludes both the effects of prospective carbon dioxide constraints and the impact of incentives provided by the Energy Policy Act of 2005. EIA’s levelized costs are based on its reference case, which includes the assumption that power plants will be built in 2015. MIT’s levelized costs derive from its base case, which assumes a 40-year capital recovery period and an 85 percent capacity factor. MIT’s results were converted to 2006 dollars using the gross domestic product price index and do not include the cost of delivering electricity.

Neither the assumptions underlying that study nor CBO’s base-case assumptions explicitly included the additional costs that utilities would have to pay if not for the limited liability protection offered under the Price-Anderson Nuclear Industries Indemnity Act, a policy long in effect (and extended by EPAct) that is implicitly captured in the reference scenario’s assumptions. Supplementary analysis that expands on the reference scenario by exploring the likelihood that a catastrophic nuclear accident might occur suggests that removing that insurance subsidy would probably increase the levelized cost of nuclear generation by no more than 1 percent (see Box 3-1).

Among its various provisions, the Energy Policy Act of 2005 extended the Price-Anderson Nuclear Industries Indemnity Act, which limits the industry’s liability for accidents at nuclear power plants. In practice, Price-Anderson subsidizes utilities by reducing their cost of carrying liability insurance. Instead of purchasing full coverage, operators of nuclear power plants are required to obtain coverage only up to the liability limit, which is currently set at about $10 billion per accident.¹ The value of the subsidy is the difference between the premium for full coverage and the premium for $10 billion in coverage. On the basis of data obtained from two studies—one conducted by the Nuclear Regulatory Commission (NRC) and the other by the Department of Energy (DOE)—the Congressional Budget Office (CBO) estimates that the subsidy probably amounts to less than 1 percent of the levelized cost for new nuclear capacity.²

To assess the health hazards that existing nuclear power plants could pose, analysts at the NRC estimated the probability of radioactive releases occurring at several nuclear facilities, including the Surry power station in Virginia, and the consequence of such an event.³ Damage to property and possible injury or loss of life caused by a hypothetical accident at that facility could be pertinent to assessing the liability of proposed nuclear plants because several of them would be located in areas of the Southeast with roughly similar population densities. For the Surry power station, the NRC study provides assessments of both internally initiated accidents (which could be caused by malfunctioning equipment or human error) and externally initiated accidents (which could result from a fire or earthquake). According to the study, an internally initiated accident at such a facility that on average caused more than 10 deaths would occur, at most, once every million years. A fire-related accident causing more than 1,000 deaths on average would occur, at most, once every million years. CBO’s analysis adopted those probabilities and results for the sake of determining liability from fatalities. To that, CBO added estimates of injuries and property damage to provide a more complete estimate of liability.

CBO based its assessment of liability from injuries and property damage on the DOE report, which modeled a radioactive release at the Limerick facility near Philadelphia. That scenario includes, in addition to the number of fatalities, estimates of injury and property damage, from which CBO inferred potential liability resulting from an accident at the Surry plant.

On the basis of the probability of fatal accidents estimated in the NRC report and the estimates of damage from such accidents in the DOE report, it appears that catastrophic accidents are possible but likely to be rare; CBO estimates that an accident causing about $500 billion in damages will occur an average of 3 out of every 100 million years.⁴ Because such potential damages are spread over a long period, the long-run average of damages per year (the expected cost) would be only about $600,000. That figure does not include the cost of nonfatal accidents, which might already be covered by the $10 billion in damages for which the nuclear power industry is held liable under the Price-Anderson Act. If so, the projected annual subsidy is about $600,000 per reactor as well.

Insurance premiums represent a small portion of the levelized cost for a nuclear power plant. Even if the analysis based on the Surry facility understates the expected cost of fatal nuclear accidents by a factor of 10, paying a fair premium would not lead to large changes in the levelized cost. In CBO’s reference scenario, increasing the insurance premium by $6 million per year increases the levelized costs by 1 percent.

1. That $10 billion in coverage has two layers: The owner of a nuclear plant is required to purchase primary insurance covering liability up to $300 million. In the event of an accident, liability for damages assessed at between $300 million and $10 billion would then be shared among the owners of all U.S. nuclear plants, who would pay a "retroactive premium."

2. See Nuclear Regulatory Commission, Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants, NUREG-1150 (December 1990); and Department of Energy, Technical Guidance for Siting Criteria Development, SAND-81-1549 (December 1982). CBO’s estimate was derived to evaluate the sensitivity of levelized costs (or the minimum price of electricity at which a technology generates enough revenue to be economically viable) to limits on liability but should not be interpreted as a precise estimate of the expected cost of liability.

3. A description and evaluation of the NRC’s probabilistic risk assessment models is provided in Nuclear Power Joint Fact-Finding (Keystone Center, June 2007).

4. Each fatality is assumed to lead to $5,000,000 in liability, and each injury is assumed to cause $2,500,000 in liability.

Putting in place a cap-and-trade system that limited the amount of carbon dioxide power plants could emit or levying a tax on such emissions would encourage the construction of new nuclear capacity by increasing the cost of generating electricity with competing fossil-fuel technologies. Carbon dioxide constraints would have no direct effect on the levelized cost of nuclear plants and would have only a small effect on innovative fossil-fuel plants with CCS technology (which are assumed to capture 90 percent of carbon dioxide emissions). In general, under the assumptions incorporated in CBO’s analysis, nuclear technology would become a more competitive source of new base-load capacity as the cost of emitting carbon dioxide increased. Eventually, if carbon dioxide charges became high enough, it would be economical for utilities to construct new nuclear or new conventional natural gas plants to replace conventional coal plants that were still operational. Regardless of the magnitude of the charges that might be imposed, however, it is unlikely that nuclear plants could be built quickly enough at any point in the near future to replace existing coal power plants, which currently account for half of the electricity generated in the United States.

Adding a carbon dioxide charge of about $45 per metric ton to the levelized cost estimates in the reference scenario would make nuclear power the least expensive source of additional base-load capacity (see the left panel of Figure 3-2). Up to that threshold, at all but the lowest level of charges, conventional natural gas technology would probably be the least costly option. Because coal is more carbon-intense than natural gas, the cost advantage of new capacity based on natural gas technology would grow in relation to coal technology as carbon dioxide charges increased; but the advantage that natural gas technology enjoyed over nuclear technology would shrink and eventually disappear as emission charges reached about $45 per metric ton. Thereafter, the levelized cost advantage of nuclear technology over conventional gas technology would grow. Although carbon dioxide charges would not change the cost of nuclear power plants at all, they would increase the cost of innovative fossil-fuel alternatives; as a result, the cost advantage that nuclear technology held over those technologies would increase with carbon dioxide charges but at a slower rate than that observed with conventional fossil-fuel technologies.

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.

Variations in the base-case assumptions about the costs for construction, fuel, or financing could increase the levelized cost of meeting base-load demand with nuclear technology relative to that for alternative technologies. For example, if the construction costs of all generation technologies doubled, carbon dioxide charges would have to be set at $150 per metric ton for nuclear technology to be preferred over conventional natural gas technology. (The concluding section of this chapter provides a more comprehensive assessment of the sensitivity of various technologies to variations in the base-case assumptions.)

When carbon dioxide charges are added to the levelized costs estimated in the reference scenario, they fall most heavily on coal technologies. The effect is so significant that, at a carbon dioxide charge of about $45 per metric ton of emissions, this analysis suggests that utilities could build and operate new nuclear or conventional natural gas plants at a lower levelized cost than continuing to operate existing coal plants. But whether such a switch would occur would depend on other factors as well—including the markets for the components and labor necessary to build new reactors and the market for natural gas.

Even if carbon dioxide charges over $45 per metric ton were implemented, it would take decades for sufficient nuclear capacity to be put in place before most utilities could consider substituting new nuclear capacity for existing coal plants. Replacing the 300,000 megawatts of existing coal capacity would require hundreds of new nuclear plants. The capacity of the industry that builds nuclear plants and its suppliers of components is currently constrained and unlikely to expand rapidly enough for even tens of plants to be built in the next decade. For example, the Brattle Group (a consulting firm) has pointed out that the skilled labor necessary to erect power plants is in short supply and could be slow to expand if a surge in the demand for nuclear plants occurred.² Also, the supply of steel forgings necessary to build a reactor’s containment vessel—a structure that prevents radiation from leaking into the atmosphere—is limited.³

Although the trend toward natural gas technology that was evident in the 1990s could always recur, it is not likely that natural gas technology would completely replace coal technology as a source of electrical power. The primary reason is that increased demand for natural gas would exert upward pressure on the price of that fuel, perhaps pushing costs above the levels included in the reference scenario. To illustrate, at the highest prices for natural gas considered in CBO’s analysis of market and policy uncertainties, utilities would be extremely unlikely to prefer natural gas to either existing coal plants or new nuclear plants.

The maximum allocation of benefits currently available under EPAct would most likely lead to the planning and construction of at least a few new nuclear plants in the next decade, even in the absence of carbon dioxide charges. (Table 1-1 provides a complete list of incentives created or extended by EPAct.) If just a few nuclear plants qualified for the incentives, the most substantial one—the production tax credit—would lead to sizable reductions in those plants’ corporate income tax liability during the first several years of operation. Nuclear projects eligible for federal loan guarantees, which cover up to 80 percent of construction costs, would benefit from reductions in financing costs. The preferential tax treatment of decommissioning funds—funds that utilities are required to set aside to cover the cost of safely shutting down and securing a nuclear plant at the end of its useful life—would provide far less financial incentive because the discounted present value of the cost of decommissioning is small. (Although the decommissioning of a 1,350-megawatt plant costs nearly $500 million, by CBO’s estimate, the present value of that cost would be much smaller because that sum would be spent 40 years after the power plant was constructed. In the absence of the preferential income tax rate, decommissioning costs would still account for less than 1 percent of the levelized cost of generating electricity with new nuclear capacity.)

The value of other EPAct incentives—including cost-sharing for the licensing and design of advanced reactors, which is offered by the Nuclear Power 2010 program, and the protection afforded by delay insurance, which insures investors in new nuclear plants for the financial risk caused by litigation or licensing delays, is not reflected in CBO’s analysis of EPAct incentives because those subsidies directly reduce the cost of only the first plants built of any new type. Those first-of-a-kind costs are not projected to have large effects on the levelized cost estimates. (The value of both the Nuclear Power 2010 program and delay insurance is discussed further in Box 3-2.)

The Energy Policy Act of 2005 (EPAct) includes provisions authorizing the Nuclear Power 2010 program and Standby Support, a program offering insurance against regulatory delays. Both are intended to encourage investment in advanced nuclear technology by covering a share of "first-of-a-kind" (FOAK) costs. Specifically, the Nuclear Power 2010 program shares the cost of licensing and designing new nuclear power plants, and the delay insurance helps mitigate risks that are particular to the first plants to test the Nuclear Regulatory Commission’s revised licensing process.

Through fiscal year 2007, the Nuclear Power 2010 program contributed roughly $280 million to funds spent by three industry consortia that were attempting to design and obtain certification for the first power plants using advanced nuclear technology.¹ Such design and licensing costs for each new plant are estimated to be $300 million to $500 million. However, because utilities that decided to build subsequent plants using the same design would benefit from the knowledge and experience gained during the construction of the first few plants, their costs would be less, roughly $100 million.² The costs for subsequent plants are the basis of the design and licensing costs used in CBO’s reference scenario, where they account for 5 percent of a nuclear power plant’s levelized cost.

If the additional $200 million to $400 million in first-of-a-kind design and licensing costs was added to a single plant in CBO’s reference scenario, the levelized cost of that initial nuclear plant would increase by roughly 15 percent. But the first utilities to build plants might be able to share some FOAK costs by forming consortia, even in the absence of the federal program. Accordingly, in the absence of federal support for design and licensing costs, levelized costs for the first plants might increase by only a fraction of the 15 percent.

Even if utilities pay the Department of Energy’s (DOE’s) estimated subsidy costs for the delay insurance, the program would reduce utilities’ cost of generating electricity by the transferring financial risk from private investors to taxpayers. However, according to an assessment by DOE, the amount of financial risk transferred is small in comparison to that of the department’s program providing guarantees for construction loans.³ For the delay insurance, DOE estimates a hypothetical subsidy cost of $14 million for a reactor with a capacity of 1,090 megawatts. Under the terms of the insurance, the Treasury would reimburse a utility for up to $500 million in costs in the event of a covered delay.⁴ For the loan guarantee program, the maximum reimbursement is roughly 10 times as much.

1. Each consortium is developing a standard nuclear power plant blueprint based on a different third-generation reactor design. One of the three reactor designs, the advanced boiling water reactor, received final approval before the Nuclear Power 2010 program was initiated, but the program supports the design and licensing of a power plant’s components surrounding such a reactor.

2. See Louis Long and others, A Roadmap to Deploy New Nuclear Power Plants in the United States by 2010 (prepared for the Department of Energy, October 2001).

3. See Department of Energy, "Standby Support for Certain Nuclear Plant Delays; Final Rule," Federal Register, vol. 71, no. 155 (August 2006), p. 46324.

4. The $500 million in coverage is available only to the first two reactors. The next four reactors are eligible for reduced coverage. DOE estimates that the subsidy cost for the reduced coverage is roughly half of the $14 million subsidy cost for the first two reactors.

When the levelized costs estimated under the reference scenario are changed to account for the benefits provided by EPAct, nuclear technology emerges as a competitive source for a limited amount of new capacity, with costs roughly comparable to those of additional capacity based on conventional fossil-fuel technologies. Accounting for the EPAct incentives also reduces the levelized cost of both innovative fossil-fuel options. The levelized cost of innovative natural gas plants falls by about 5 percent, and that of innovative coal plants decreases by 20 percent. However, those technologies are still more costly than conventional fossil-fuel alternatives or nuclear technology. (See Figure 3-3 for an illustration of the cost of each technology under the full provision of EPAct incentives.) After those first few new nuclear plants qualified for EPAct incentives, the cost of new nuclear capacity would exceed the cost of new conventional coal capacity.

Notes: CBO’s reference scenario excludes both the effects of prospective carbon dioxide constraints and the impact of incentives provided by the Energy Policy Act of 2005 (EPAct). The estimate of the effect of EPAct incentives assumes the maximum production tax credits, loan guarantees, and investment tax credits. The production tax credits are shared among 6,000 megawatts or less of advanced nuclear capacity. Advanced nuclear and innovative fossil fuel technologies receive loan guarantees covering 80 percent of construction costs. Innovative coal technology receives investment tax credits for 20 percent of construction costs.

Production tax credits provided under EPAct reduce by almost 15 percent the levelized cost of nuclear technology estimated in the reference scenario, making them the incentive with the greatest potential value to investors. The effect of the production tax credits on levelized costs would be smaller if more than 6,000 megawatts of qualified nuclear capacity (equivalent to the output of three to five plants) was constructed; but construction of more capacity would indicate that nuclear technology did not require the full allotment of credits to be commercially viable.

Because the credits would not be used until after a plant began operating—in other words, once electricity had been sold and the utility had incurred sufficient tax liability—the reduction in the levelized cost of generating electricity for qualifying nuclear plants would necessarily be less than the nominal value of the credits awarded to each project. Thus, even though credits of $18 per megawatt hour of generated electricity are equal to about one-quarter of the levelized cost estimated in the reference scenario, after discounting, the credits would reduce the cost of nuclear capacity by only about 15 percent if they were used within three years of being awarded.

The maximum coverage available under the loan guarantee program—a guarantee on debt covering 80 percent of a plant’s construction costs, which implies that investors’ equity would cover the remaining 20 percent—would most likely reduce the levelized cost of new nuclear capacity by about 10 percent. But not all prospective nuclear plants would necessarily receive a guarantee of debt covering 80 percent of construction costs because the criteria for qualifying are restrictive. The Department of Energy has indicated that it will deny a utility’s application for a loan guarantee if the project is not deemed to be both innovative (essentially, in the case of nuclear technology, a plant design that has not been built in the United States) and commercially viable, and that no more than three plants based on each advanced reactor design can be considered innovative. The 30 plants currently being proposed use five reactor designs, so at most, 15 of those plants would qualify as innovative. In addition, just because a plant is considered both innovative and commercially viable does not mean it will receive the maximum guarantee of 80 percent. Under the base-case assumptions, covering 80 percent of construction costs would require guaranteeing debt with a face value of $4.5 billion to $7.5 billion for each plant (depending on the size of the reactor). Providing the maximum coverage to three plants based on each of the five reactor designs would result in roughly $100 billion in loan guarantees, a commitment that has not been proposed, let alone funded. (The President’s budget proposed a limit of $18.5 billion [in nominal dollars] on the cumulative amount of loan guarantees for new nuclear plants over the 2008–2011 period.)⁴ The loan guarantee program could encourage investors to choose relatively risky projects over more certain alternatives because they would be responsible for only about 20 percent of a project’s costs but would receive 100 percent of the returns that exceeded costs.⁵

Because some states and localities regulate the rates that consumers pay for electricity or offer incentives for specific technologies, the levelized cost of nuclear technology in certain areas of the country could be lower than the estimates in this analysis. Other states have policies that deter investment in new nuclear or coal capacity altogether, which renders the levelized cost of the prohibited technology moot.

States and localities encourage investment in new nuclear capacity through a variety of policies. Over half of the currently proposed new nuclear plants are sited in southeastern states, where most electricity-generation capacity is owned by utilities that charge regulated rates. To the extent that rate regulation guarantees that customers will reimburse utilities for the cost of building a new plant, financial risk is transferred from investors to customers, which leads to larger reductions in the cost of capital-intense technologies such as nuclear. In several of those states, additional incentives that could further reduce the cost of nuclear power are under consideration. Those provisions include allowing higher rates of return for nuclear power than for other technologies, allowing utilities to recover some construction costs before plants begin operations, and tax incentives. State incentives for new nuclear power plants are not limited to states with traditional regulation in place. For instance, Texas, a state that allows markets a large role in setting electricity prices, has expanded a tax incentive initially designed to encourage investment in renewable energy technologies to apply to new nuclear capacity. Last, California and a number of eastern states are considering legislation that would limit carbon dioxide emissions, which could increase the competitiveness of nuclear and innovative fossil-fuel technologies. As of 2007, however, the only states in that group that had proposed sites for new nuclear power plants were Maryland, Pennsylvania, and New York.

At least 11 states have prohibitions against the construction of new nuclear facilities until certain provisions governing the long-term disposal of spent nuclear fuel are put in place.⁶ Minnesota completely bans the construction of new nuclear power plants.

The commercial viability of new nuclear capacity depends on investors’ perceptions of future market conditions and carbon dioxide constraints when investment decisions are finalized. Licensing and regulatory approval for building new nuclear plants in the United States are expected to take about three years, so the construction of the first new nuclear plants would be unlikely to start until 2010 at the earliest. At that point, the commercial viability of a new plant would depend on anticipated market conditions and policy outcomes over the operating life of the plant, which may exceed 40 years. A combination of factors—recent volatility in construction costs and natural gas prices, nuclear power’s history of construction cost overruns, and uncertainty about future policy on carbon dioxide emissions—indicates that a wide range of costs are plausible for each of the technologies considered. Those ranges demonstrate that the future competitiveness of each technology and thus the conclusions presented in this analysis are quite uncertain.

If the base-case assumptions incorporated in CBO’s reference scenario did not hold—for instance, if construction costs for new nuclear power plants proved to be as high as the average cost of nuclear plants built in the 1970s and 1980s or if natural gas prices fell back to the average levels seen in the 1990s—new nuclear capacity would be an unattractive investment, regardless of the incentives provided by EPAct. Specifically, CBO compared the levelized cost of electricity from new capacity assuming that the overnight construction costs for nuclear technology would be 25 percent higher or that the fuel costs for natural gas capacity would be 50 percent lower than in the base case. Nuclear technology benefiting from EPAct incentives was about 15 percent more expensive than conventional fossil-fuel capacity in the first case and about 50 percent more expensive than conventional natural gas capacity in the second case. However, such variations in construction or fuel costs would be less likely to deter investment in new nuclear capacity if investors anticipated future charges for emitting carbon dioxide. New nuclear capacity could even compete at lower carbon dioxide charges if the price of natural gas continued to rise or if the construction cost reductions predicted by reactor designers were accurate (and thus below the costs assumed in the reference scenario).

Construction Costs. To examine the effect of uncertainties related to overnight construction costs, CBO calculated the levelized cost of each of the technological alternatives using values for construction costs that were 50 percent less than and 100 percent more than the assumptions in the reference scenario (see Figure 3-4). In the reference scenario, CBO assumed an overnight construction cost for new nuclear capacity of about $2.4 million per megawatt, so in the "lower" and "higher" cases, CBO used a cost of about $1.2 million and $4.8 million, respectively. Taking into consideration the history of very large construction cost overruns that have plagued the nuclear power industry in the past, the high end of the range encompasses costs well above those included in the reference scenario. Utilities would be unlikely to invest in new nuclear plants if construction costs for nuclear plants were twice those assumed in the reference scenario, as the levelized cost of a nuclear plant would be well over $100 per megawatt hour.

CBO’s reference scenario excludes both the effects of prospective carbon dioxide constraints and the impact of incentives provided by the Energy Policy Act of 2005.

CBO calculated levelized costs for the reference scenario using estimates of overnight construction costs from the Energy Information Administration (EIA). In the case of "Lower Construction Costs," CBO halved EIA’s estimates and recalculated levelized costs on that basis. In the case of "Higher Construction Costs," CBO doubled EIA’s estimates and recalculated the costs.

However, the construction costs for new capacity using the other technologies are subject to uncertainty as well. Adjusted for general inflation, construction costs for new power plants increased by 15 percent between 1994 to 2006, with most of that increase occurring over the past three years.⁷ If that trend continued, the overnight costs assumed in the reference scenario for all of the technologies would be too low. If the construction costs of each technology increased by a similar percentage, the impact on the levelized cost of the technologies with the highest overnight costs in the reference scenario—nuclear and innovative coal—would be the greatest. Conventional natural gas technology would become less expensive by comparison because construction costs account for a smaller percentage of that technology’s levelized cost. Conversely, reductions in construction costs would have a disproportionately large effect in reducing the relative cost of those technologies that had high construction costs in the reference scenario.

Fuel Costs. The price of the primary fuels used by each of the base-load technology options has increased in recent years. Contracted uranium prices (the prices that operators of nuclear plants pay for most of their fuel) increased by 40 percent between 2004 and 2006. Spot prices for uranium (the prices at which a relatively small amount of uranium trades on commodity exchanges) have climbed steeply and then fallen over the past year. Natural gas prices have increased dramatically (see Figure 2-1), and even spot prices for coal have recently increased to levels that are well above long-run averages. To capture the effects of uncertainty surrounding fuel prices, CBO estimated the levelized cost of each of the five technology options on the basis of fuel prices set at levels 50 percent less than and 100 percent more than those assumed in the reference scenario. (The results are displayed in Figure 3-5.)

CBO’s reference scenario excludes both the effects of prospective carbon dioxide constraints and the impact of incentives provided by the Energy Policy Act of 2005.

CBO estimated levelized costs for the reference scenario using estimates of fuel costs from the Energy Information Administration (EIA). In the case of "Lower Fuel Costs," CBO halved EIA’s estimates and recalculated levelized costs on that basis. In the case of "Higher Fuel Costs," CBO doubled EIA’s estimates and recalculated the costs.

The analysis shows that assumptions about fuel prices have particularly large effects on the estimated levelized cost of natural gas technologies. For conventional natural gas, doubling the cost of fuel used in the reference scenario increases the levelized cost of that technology by over 70 percent. For innovative natural gas plants, the corresponding increase in levelized cost is just over 60 percent. By contrast, nuclear power has the lowest fuel cost of the technologies considered under the base-case assumptions. Doubling that cost would increase the levelized cost of new nuclear capacity by about 15 percent above that assumed in the reference scenario.

Financing Costs. A levelized cost analysis accounts for risk by assuming that investors will require a higher rate of return for riskier projects. The effect of uncertainty on the return that investors will require to finance new base-load capacity can be shown for all of the options by calculating the levelized cost of each option at a lower rate of return (8-3/4 percent) and at a higher return (12-1/2 percent) and comparing those results with the rate of return (10 percent) used in the reference scenario. (The results of that analysis are presented in Figure 3-6.)

CBO’s reference scenario excludes both the effects of prospective carbon dioxide constraints and the impact of incentives provided by the Energy Policy Act of 2005.

CBO estimated levelized costs for the reference scenario using a financing rate of about 10 percent. For the category "Lower Rate of Return," CBO recalculated levelized costs using a financing rate of about 8-3/4 percent. For the category "Higher Rate of Return," CBO recalculated those costs using a rate of about 12-1/2 percent. In each case, financing rates were derived from CBO’s assumptions for debt and equity financing (which are discussed in detail in the Web supplement to this paper) and rounded to the nearest quarter of a percentage point.

The changes in levelized costs follow the same pattern as that produced under higher construction costs. The levelized costs for nuclear and innovative fossil-fuel technologies increase by more than those for the conventional fossil-fuel options, which require smaller up-front investments. But some observers rate the level of risk attached to nuclear technology as somewhat higher than that of the other alternatives, independent of the technology’s relatively high construction costs. The prospect that investors would require a higher rate of return relative to that of other options to compensate for a risk unique to nuclear power (for instance, an accident at an existing nuclear plant could significantly delay the construction of new plants, as was the case after the Three Mile Island accident) can be assessed by comparing the levelized cost of nuclear technology at the highest rate of return with the levelized cost of the other options calculated for the reference scenario. For example, the levelized cost of nuclear technology calculated at a 12-1/2 percent real rate of return is 65 percent higher than the levelized cost of conventional coal with a 10 percent real rate of return. With the same comparison applied to nuclear technology the least expensive innovative fossil-fuel technology—coal with CCS—the levelized cost of nuclear technology exceeds that of innovative coal technology by about 5 percent. Such comparisons suggest that if financial markets required a substantially higher rate of return for new nuclear technology than for other base-load technologies, investment in new nuclear plants would not be commercially viable.

It is less likely that the cost of building and fueling conventional coal plants will vary toward the extremes of the ranges included in this analysis than it would for the other generation options considered. Construction costs for coal plants have been less volatile than for nuclear plants, and the abundance of U.S. coal supplies has historically led to relatively stable prices for coal. Still, investors in new coal capacity face substantial uncertainty because of the prospect that carbon dioxide constraints will be implemented and the variability in the prospective stringency of such constraints. Although the implications of such stringency can be observed by adding specific carbon dioxide charges to the levelized costs estimated for the reference scenario, the effect is more clearly demonstrated by comparing the levelized cost of the technology alternatives at specific levels of carbon emissions that might be targeted by policymakers. CBO compared the levelized cost of the different base-load technologies under the reference scenario with the levelized cost at two different levels of stringency, one holding future emissions at their 2008 level and the other reducing future emissions even more, to about 85 percent below their 2008 level by 2050.⁸ Under the less stringent cap, the costs for electricity from newly built conventional coal and natural gas capacity would increase by about 70 percent and 20 percent, respectively. Under the more stringent cap, those costs would increase by about 165 percent and 65 percent, respectively. (Figure 3-7 shows the levelized cost under the hypothetical cap-and-trade programs.)

CBO’s reference scenario excludes both the effects of prospective carbon dioxide constraints and the impact of incentives provided by the Energy Policy Act of 2005.

In the reference scenario, carbon dioxide emissions are not constrained, so they are not priced. In the second case, the number of allowances issued each year for emitting carbon dioxide would correspond to a cap at roughly the level of emissions in 2008. In the third case, the number of such allowances would correspond to a cap about 85 percent below that level by 2050. The allowance prices resulting from those hypothetical constraints are listed in the Web supplement to this paper.

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. Both innovative coal and innovative natural gas technologies are assumed to capture and store most carbon dioxide emissions.

Levelized costs for CCS technologies are not reflected in Figure 3-1 because those estimates were not available in all of the reports. In particular, the MIT study group did not analyze CCS technologies in The Future of Nuclear Power (2003). That study group estimated the cost of coal-fired power plants with CCS technology in a later report, The Future of Coal (2007), but changes in the methodology obscure whether the levelized cost for CCS technology in that report can be compared with the levelized cost of nuclear power in the earlier analysis. EIA found that the cost of generating electricity from coal-fired power plants with CCS would exceed the cost of power generated by nuclear power plants by about 15 percent.