‹ Analysis & Projections

Annual Energy Outlook 2014

Release Dates: April 7 - 30, 2014   |  Next Early Release Date: December 2014   |  See schedule

Nuclear from Market Trends

Renewables and natural gas lead rise in primary energy consumption

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The aggregate fossil fuel share of total energy use falls from 82 percent in 2011 to 78 percent in 2040 in the Reference case, while renewable use grows rapidly (Figure 54). The renewable share of total energy use (including biofuels) grows from 9 percent in 2011 to 13 percent in 2040 in response to the federal renewable fuels standard; availability of federal tax credits for renewable electricity generation and capacity during the early years of the projection; and state renewable portfolio standard (RPS) programs.

Natural gas consumption grows by about 0.6 percent per year from 2011 to 2040, led by the increased use of natural gas in electricity generation and, at least through 2020, the industrial sector. Growing production from tight shale keeps natural gas prices below their 2005-2008 levels through 2036. In the AEO2013 Reference case, the amount of liquid fuels made from natural gas (360 trillion Btu) is about three times the amount made from coal.

Increased vehicle fuel economy offsets growth in transportation activity, resulting in a decline in the petroleum and other liquids share of fuel use even as consumption of liquid biofuels increases. Biofuels, including biodiesel blended into diesel, E85, and ethanol blended into motor gasoline (up to 15 percent), account for 6 percent of all petroleum and other liquids consumption by energy content in 2040.

Coal consumption increases at an average rate of 0.1 percent per year from 2011 to 2040, remaining below 2011 levels until 2030. By the end of 2015, a total of 6.1 gigawatts of coal-fired power plant capacity currently under construction comes on line, and another 1.5 gigawatts is added after 2016 in the Reference case, including 0.9 gigawatts with carbon sequestration capability. Additional coal is consumed in the CTL process and to produce heat and power (including electricity generation at CTL plants).

Coal-fired plants continue to be the largest source of U.S. electricity generation

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Coal-fired power plants continue to be the largest source of electricity generation in the AEO2013 Reference case (Figure 76), but their market share declines significantly. From 42 percent in 2011, coal's share of total U.S. generation declines to 38 percent in 2025 and 35 percent in 2040. Approximately 15 percent of the coal-fired capacity active in 2011 is expected to be retired by 2040 in the Reference case, while only 4 percent of new generating capacity added is coal-fired. Existing coal-fired units that have undergone environmental equipment retrofits continue to operate throughout the projection.

Generation from natural gas increases by an average of 1.6 percent per year from 2011 to 2040, and its share of total generation grows from 24 percent in 2011 to 27 percent in 2025 and 30 percent in 2040. The relatively low cost of natural gas makes the dispatching of existing natural gas plants more competitive with coal plants and, in combination with relatively low capital costs, makes plants fueled by natural gas an alternative choice for new generation capacity.

Generation from renewable sources grows by 1.7 percent per year on average in the Reference case, and the share of total generation rises from 13 percent in 2011 to 16 percent in 2040. The nonhydropower share of total renewable generation increases from 38 percent in 2011 to 65 percent in 2040.

Generation from U.S. nuclear power plants increases by 0.5 percent per year on average from 2011 to 2040, with most of the growth between 2011 and 2025, but the share of total U.S. electricity generation declines from 19 percent in 2011 to 17 percent in 2040, as the growth in nuclear generation is outpaced by growth in generation using natural gas and renewables.

Most new capacity additions use natural gas and renewables

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Decisions to add capacity, and the choice of fuel for new capacity, depend on a number of factors [132]. With growing electricity demand and the retirement of 103 gigawatts of existing capacity, 340 gigawatts of new generating capacity [133] is added in the AEO2013 Reference case from 2012 to 2040 (Figure 77).

Natural gas-fired plants account for 63 percent of capacity additions from 2012 to 2040 in the Reference case, compared with 31 percent for renewables, 3 percent for coal, and 3 percent for nuclear. Escalating construction costs have the largest impact on capital-intensive technologies, which include nuclear, coal, and renewables. However, federal tax incentives, state energy programs, and rising prices for fossil fuels increase the competitiveness of renewable and nuclear capacity. Current federal and state environmental regulations also affect the use of fossil fuels, particularly coal. Uncertainty about future limits on GHG emissions and other possible environmental programs also reduces the competitiveness of coal-fired plants (reflected in the AEO2013 Reference case by adding 3 percentage points to the cost of capital for new coal-fired capacity).

Uncertainty about electricity demand growth and fuel prices also affects capacity planning. Total capacity additions from 2012 to 2040 range from 252 gigawatts in the Low Economic Growth case to 498 gigawatts in the High Economic Growth case. In the Low Oil and Gas Resource case, natural gas prices are higher than in the Reference case, and new natural gas-fired capacity added from 2012 to 2040 totals 152 gigawatts, or 42 percent of total additions. In the High Oil and Gas Resource case, delivered natural gas prices are lower than in the Reference case, and 311 gigawatts of new natural gas-fired capacity is added from 2012 to 2040, accounting for 82 percent of total new capacity

Additions to power plant capacity slow after 2012 but accelerate beyond 2023

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Typically, investments in electricity generation capacity have gone through boom-and-bust cycles. Periods of slower growth have been followed by strong growth in response to changing expectations for future electricity demand and fuel prices, as well as changes in the industry, such as restructuring (Figure 78). A construction boom in the early 2000s saw capacity additions averaging 35 gigawatts a year from 2000 to 2005. Since then, average annual builds have dropped to 18 gigawatts per year from 2006 to 2011.

In the AEO2013 Reference case, capacity additions from 2012 to 2040 total 340 gigawatts, including new plants built not only in the power sector but also by end-use generators. Annual additions in 2012 and 2013 remain relatively high, averaging 22 gigawatts per year. Of those early builds, 51 percent are renewable plants built to take advantage of federal tax incentives and to meet state renewable standards.

Annual builds drop significantly after 2013 and remain below 9 gigawatts per year until 2023. During that period, existing capacity is adequate to meet growth in demand in most regions, given the earlier construction boom and relatively slow growth in electricity demand after the economic recession. Between 2025 and 2040, average annual builds increase to 14 gigawatts per year, as excess capacity is depleted and the rate of total capacity growth is more consistent with electricity demand growth. About 68 percent of the capacity additions from 2025 to 2040 are natural gas-fired, given the higher construction costs for other capacity types and uncertainty about the prospects for future limits on GHG emissions.

Costs and regulatory uncertainties vary across options for new capacity

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Technology choices for new generating capacity are based largely on capital, operating, and transmission costs [134]. Coal, nuclear, and wind plants are capital-intensive (Figure 80), whereas operating (fuel) expenditures make up most of the costs for natural gas plants. Capital costs depend on such factors as equipment costs, interest rates, and cost recovery periods, which vary with technology. Fuel costs vary with operating efficiency, fuel price, and transportation costs.

In addition to considerations of levelized costs [135], some technologies and fuels receive subsidies, such as production or ITCs. Also, new plants must satisfy local and federal emissions standards and must be compatible with the utility's load profile.

Regulatory uncertainty also affects capacity planning. New coal plants may require carbon control and sequestration equipment, resulting in higher material, labor, and operating costs. Alternatively, coal plants without carbon controls could incur higher costs for siting and permitting. Because nuclear and renewable power plants (including wind plants) do not emit GHGs, their costs are not directly affected by regulatory uncertainty in this area.

Capital costs can decline over time as developers gain technology experience, with the largest rate of decline observed in new technologies. In the AEO2013 Reference case, the capital costs of new technologies are adjusted upward initially to compensate for the optimism inherent in early estimates of project costs, then decline as project developers gain experience. The decline continues at a progressively slower rate as more units are built. Operating efficiencies also are assumed to improve over time, resulting in reduced variable costs unless increases in fuel costs exceed the savings from efficiency gains.

Nuclear power plant capacity grows slowly through uprates and new builds

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In the AEO2013 Reference case, nuclear power capacity increases from 101.1 gigawatts in 2011 to a high of 114.1 gigawatts in 2025, before declining to 108.5 gigawatts in 2036 (Figure 81), largely as a result of plant retirements. New additions in the later years of the projection bring nuclear capacity back up to 113.1 gigawatts in 2040. The capacity increase through 2025 includes 8.0 gigawatts of expansion at existing plants and 5.5 gigawatts of new capacity, which includes completion of a conventional reactor at the Watts Bar site. Four advanced reactors, reported as under construction, also are assumed to be brought online by 2020 and to be eligible for federal financial incentives. High construction costs for nuclear plants, especially relative to natural gas-fired plants, make additional options for new nuclear capacity uneconomical until the later years of the projection, when an additional 5.5 gigawatts is added. Nuclear capacity additions vary with assumptions about overall demand for electricity. Across the Economic Growth cases, net additions of nuclear capacity from 2012 to 2040 range from 5.5 gigawatts in the Low Economic Growth case to 36.1 gigawatts in the High Economic Growth case.

One nuclear unit, Oyster Creek, is expected to be retired at the end of 2019, as announced by Exelon in December 2010. An additional 6.5 gigawatts of nuclear capacity is assumed to be retired by 2036 in the Reference case. All other existing nuclear units continue to operate through 2040 in the Reference case, which assumes that they will apply for and receive operating license renewals, including in some cases a second 20-year extension after 60 years of operation (for more discussion, see "Issues in focus"). With costs for natural gas-fired generation rising in the Reference case and uncertainty about future regulation of GHG emissions, the economics of keeping existing nuclear power plants in operation are favorable.

Nuclear from Legislation and Regulations

3. Nuclear waste disposal and the Waste Confidence Rule

Waste confidence is defined by the U.S. Nuclear Regulatory Commission (NRC) as a finding that spent nuclear fuel can be safely stored for decades beyond the licensed operating life of a reactor without significant environmental effects [19]. It enables the NRC to license reactors or renew their licenses without examining the effects of extended waste storage for each individual site pending ultimate disposal.

NRC's Waste Confidence Rule issued in August 1984 [20] included five findings:

  1. Spent nuclear fuel can be disposed of safely in a mined geologic repository.
  2. A mined geologic repository will be available when needed for disposal of spent nuclear fuel.
  3. Until a mined geologic repository is available, spent nuclear fuel can be safely managed.
  4. Spent nuclear fuel can be safely stored at reactors for 30 years without significant environmental impacts.
  5. Storage will be made available for spent nuclear fuel onsite or offsite, if required.

The Waste Confidence Rule was updated in 1990 [21], reviewed in 1999, and updated again in 2010 [22].

In December 2010, with the termination of the repository program at Yucca Mountain, the Waste Confidence Rule was amended to state that spent nuclear fuel could be stored safely at reactor sites for 60 years following reactor shutdown. In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit struck down the NRC's 2010 amendment of the Waste Confidence Rule, stating that the NRC should have analyzed the environmental consequences of never building a permanent waste repository, and that the discussion of potential leaks or fires at spent fuel pools was inadequate [23].

The NRC issued an order in August 2012 that suspended actions related to issuance of operating licenses and license renewals [24]. Currently, the NRC is analyzing the potential impacts on licensing reviews and developing a proposed path forward to meet the court's requirements. Until the NRC revises the Waste Confidence Rule, it will not issue reactor operating licenses or operating license renewals. Licensing reviews and proceedings will continue, but Atomic Safety and Licensing Board hearings will be suspended pending further NRC guidance. NRC expects to issue a revised Waste Confidence Rule within 2 years [25].

Reactors with license renewal applications under review by the NRC may continue to operate, even if their existing licenses expire, until the NRC can resolve the waste confidence issue and promulgate a revised rule. The regulation states: "If the licensee of a nuclear power plant licensed under 10 CFR 50.21(b) or 50.22 files a sufficient application for renewal of either an operating license or a combined license at least 5 years before the expiration of the existing license, the existing license will not be deemed to have expired until the application has been finally determined" [26]. There are currently 15 reactors with license renewal applications in various stages of review by the NRC that are subject to the August 2012 order that suspends licensing decisions.

For those reactors that have not submitted applications for license renewal, the first license expiration date would occur in 2020. Because it is anticipated by the NRC that the issues with the Waste Confidence Rule will be resolved within 2 years, well before 2020, the continued operation of those reactors should not be affected. The AEO2013 Reference case assumes plants that have not submitted applications for license renewal will be unaffected.

Currently, utilities have the option to license reactors under either of two NRC rules. The NRC's Domestic Licensing of Production and Utilization Facilities rule defines a two-step process for obtaining an operating license [27]. First, a construction permit is issued, and then an operating license is issued. There are two U.S. reactors with current construction permits: Bellefonte Unit 1 and Watts Bar Unit 2. Both plants are owned by the Tennessee Valley Authority (TVA), which has announced that construction of Bellefonte Unit 1 will not proceed until fuel loading at Watts Bar Unit 2 is completed [28]. Neither reactor will be able to receive an operating license until the waste confidence issue is resolved, but construction may continue. TVA has not provided a projected date for commencement of operations at Bellefonte Unit 1, but it is unlikely that resolution of the issues associated with the Waste Confidence Rule will affect the operational date of Bellefonte Unit 1. Watts Bar Unit 2 was originally scheduled to go online in 2012, but delays in construction make it unlikely that it will be ready to begin operation before the issues with the Waste Confidence Rule can be resolved. AEO2013 assumes that Watts Bar Unit 2 will come online in December 2015.

The NRC's "Licenses, Certifications, and Approvals for Nuclear Power Plants" rule defines a one-step process, whereby the construction permit and operating license are issued as a combined license (COL) [29]. Once an application for a COL is submitted, the utility may engage in certain pre-construction activities. To date, two plants, each with two reactors, have received COLs in 2012. Vogtle Units 3 and 4 and Summer Units 2 and 3 will both be unaffected by the issues with the Waste Confidence Rule. Once construction and all inspections are complete, the Vogtle and Summer plants may commence operations. For utilities that have submitted applications but have not received COLs, issuance of those licenses may be delayed. For COL applications currently under active review, it is possible that two—Levy County Units 1 and 2 and William States Lee III Units 1 and 2—may be delayed, based on their review status and the NRC's schedule for application reviews. The online dates for the units should be unaffected if issues with the Waste Confidence Rule are resolved within the next 2 years.

Based on EIA's analysis of the Waste Confidence Rule and ongoing proceedings, the AEO2013 Reference case assumes that the issuance of new operating licenses will not be affected. AEO2013 also assumes that the Waste Confidence Rule will not affect power uprates, because uprates do not increase the amount of spent nuclear fuel requiring storage, as confirmed in a public policy statement issued by the NRC [30].

Nuclear from Issues in Focus

5. Nuclear power in AEO2013

In 2011, approximately 19 percent of the nation's electricity was generated by 104 operating commercial nuclearreactors, totaling 101 gigawatts of capacity. In the AEO2013 Reference case, annual generation from nuclear power grows by 14.3 percent from the 2011 total to 903 gigawatthours in 2040. However, the nuclear share of the overall generation mix declines to 17 percent as growth in nuclear generation is outpaced by the increases in generation from natural gas and renewables. The Reference case projects the addition of 19 gigawatts of nuclear capacity from 2011 to 2040, in comparison with the addition of 215 gigawatts of natural gas capacity and 104 gigawatts of renewable capacity.

Nuclear capacity is added both through power uprates at existing nuclear power plants and through new builds. Uprates at existing plants account for 8.0 gigawatts of nuclear capacity additions in the Reference case and new construction adds 11.0 gigawatts of capacity over the projection period. About 5.5 gigawatts of new capacity results from Watts Bar Unit 2, Summer Units 2 and 3, and Vogtle Units 3 and 4, all of which are projected to be online by 2020. The AEO2013 Reference case includes the retirement of 0.6 gigawatts at Oyster Creek in 2019, as well as retirements of an additional 6.5 gigawatts of capacity toward the end of the projection. AEO2013 also includes several alternative cases that examine the impacts of different assumptions about the long-term operation of existing nuclear power plants, new builds, deployment of new technologies, and the impacts on electricity markets of different assumptions about future nuclear capacity.


Power uprates increase the licensed capacity of existing nuclear power plants and enable those plants to generate more electricity [83]. The U.S. Nuclear Regulatory Commission (NRC) must approve all uprate projects before they are undertaken and verify that the reactors will still be able to operate safely at the proposed higher levels of output. Power uprates can increase plant capacity by up to 20 percent of the original licensed capacity, depending on the magnitude and type of uprate project. Capital expenditures may be small (e.g., installing a more accurate sensor) or significant (e.g., replacing key plant components, such as turbines).

EIA relied on both reported data and estimates to define the uprates included in AEO2013. Reported data comes from the Form EIA-860 [84], which requires all nuclear power plant owners to report plans to build new plants or make modifications (such as an uprate) to existing plants within the next 10 years. In 2011, nuclear power plants reported plans to complete a total of 1.5 gigawatts of uprate projects over the next 10 years.

In addition to the reported uprates, EIA included an additional 6.5 gigawatts of uprates over the projection period. The inclusion of potential uprate capacity is based on interactions with EIA stakeholders who have significant experience in implementing power plant uprates.

New Builds

Building a new nuclear power plant is a complex operation that can take more than a decade to complete. Projects generally require specialized high-wage workers, expensive materials and components, and engineering construction expertise, which can be provided by only a select group of firms worldwide. In the current economic environment of low natural gas prices and flat demand for electricity, the overall market conditions for new nuclear plants are challenging.

Nuclear power plants are among the most expensive options for new electric generating capacity [85]. The AEO2013 Reference case assumes that the overnight capital costs (the cost before interest) associated with building a nuclear power plant in 2012 were $5,429 (2011 dollars) per kilowatt, which translates to almost $12 billion for a dual-unit 2,200-megawatt power plant. The estimate does not include such additional costs as financing, interest carried forward, and peripheral infrastructure updates [86]. Despite its cost, deployment of new nuclear capacity supports the long-term resource plans of many utilities by allowing fuel diversification and by providing a hedge against potential future GHG regulations or higher natural gas prices.

Incentive programs encourage the construction of new reactors in the United States. At the federal level, the Energy Policy Act of 2005 (EPACT2005) established a Loan Guarantee Program for new nuclear plants that are completed and operational by 2020 [87]. A total of $18.5 billion is available, of which $8.3 billion has been conditionally committed to the construction of Southern Company's Vogtle Units 3 and 4 [88]. EPACT2005 also provided a PTC of $18 per megawatt hour for electricity produced during the first 8 years of plant operation [89]. To be eligible for this credit, new nuclear plants must be operational by 2021, and the credit is limited to the first 6 gigawatts of new nuclear capacity. In addition to federal incentives, several states provide a favorable regulatory environment for new nuclear plants by allowing plant owners to recover their investments through retail electricity rates.

In addition to reported plans to build new nuclear power plants, another 5.5 gigawatts of unplanned capacity is built in the later years of the Reference case projection. Higher natural gas prices, growth in electricity demand, and the need to displace retired nuclear and coal-fired capacity all play a role in the growth at the end of the projection period in the Reference case.


NRC has the authority to issue initial operating licenses for commercial nuclear power plants for a period of 40 years. Decisions to apply for operating license renewals are made entirely by nuclear power plant owners, and typically they are based on economics and the ability to meet NRC requirements.

In April 2012, Oyster Creek Unit 1 became the first commercial nuclear reactor to have operated for 40 years, followed by Nine Mile Point Unit 1 in August, R. E. Ginna in September, and Dresden Unit 2 in December 2012. Two additional plants, H.B. Robinson Unit 2 and Point Beach Unit 1, will complete 40 years of operation in 2013. As of December 2012, the NRC had granted license renewals to 72 of the 104 operating U.S. reactors, allowing them to operate for a total of 60 years. Currently, the NRC is reviewing license renewal applications for 13 reactors, and 15 more applications for license renewals are expected between 2013 and 2019.

NRC regulations do not limit the number of license renewals a nuclear power plant may be granted. The nuclear power industry is preparing applications for license renewals that would allow continued operation beyond 60 years. The first such application, for permission to operate a commercial reactor for a total of 80 years is tentatively scheduled to be submitted in 2015. Aging plants may face a variety of issues that could lead to a decision not to apply for a second license renewal, including both economic and regulatory issues—such as increased operation and maintenance (O&M) costs and capital expenditures to meet NRC requirements. Industry research is focused on identifying challenges that aging facilities might encounter and formulating potential approaches to meet those challenges [90, 91]. Typical challenges involve degradation of structural materials, maintaining safety margins, and assessing the structural integrity of concrete [92].

The outcome of pending research and market developments will be important to future decisions regarding life extensions beyond 60 years. The AEO2013 Reference case assumes that the operating lives of most of the existing U.S. nuclear power plants will be extended at least through 2040. The only planned retirement included in the Reference case is the announced early retirement of the Oyster Creek nuclear power station in 2019, as reported on Form EIA-860. The Reference case also assumes an additional 7.1 gigawatts of nuclear power capacity retirements by 2040, representing about 7 percent of the current fleet. These generic retirements reflect uncertainty related to issues associated with long-term operations and age management.

In March 2012, the NRC issued three orders [93] that require nuclear power plants to implement requirements related to lessons learned from the accident at Japan's Fukushima Daiichi nuclear power plant in March 2011. Compliance assessments are underway currently at U.S. nuclear power plants. The requirements of the orders must be implemented by December 2016 and will remain in place until they are superseded by rulemaking. Given the evolving nature of NRC's regulatory response to the accident at Fukushima Daiichi, the Reference case does not include any retirements that could result from new NRC requirements that may involve plant modifications to meet such requirements.

Small Modular Reactors

Small Modular Reactor (SMR) technology differs from traditional, large-scale light-water reactor technology in both reactor size and plant scalability. SMRs are typically smaller than 300 megawatts and can be built in modular arrangements. Traditional reactors are generally 1,000 megawatts or larger. The initial estimates for scalable SMRs range from 45 to 225 megawatts. SMRs are small enough to be fabricated in factories and can be shipped to sites via barge, rail, or truck. Those factors may reduce both capital costs and construction times. Smaller SMRs offer utilities the flexibility to scale nuclear power production as demand changes.

The actual construction of a large nuclear power plant can take up to a decade. During construction, the plant owner may incur significant interest costs and risk further cost increases because of delays and cost overruns. SMRs have the potential to mitigate some of the risks, based on their projected construction period of 3 years. Moody's credit rating agency has described large nuclear power plants as bet-the-farm endeavors for most companies, given the size of the investment and length of time needed to build a nuclear power facility [94], as highlighted by comparisons of the costs of building nuclear power plants with the overall sizes of the companies building them. AEO2013 assumes that the overnight cost of a 2,200-megawatt nuclear power plant is approximately $12 billion, which is a significant share of the market capitalization of some of the nation's largest electric power companies. For example, the largest publicly traded company that owns nuclear power plants in the United States has a market capitalization of about $50 billion [95].

Although SMRs may offer several potential advantages, there are key issues that remain to be resolved. SMRs are not yet licensed by the NRC. While there are many similarities between SMRs and traditional large reactors, there are several key differences identified by the NRC that will need to be reviewed before a design certification is issued. Until the situation is clarified, there will be substantial uncertainty about the final costs of SMRs. In addition, the NRC must develop a regulatory infrastructure to support licensing review of the SMR designs. The NRC has identified several potential policy and technical issues associated with SMR licensing [96]. In August 2012, the NRC provided a report to Congress that addressed the licensing of reactors, including SMRs [97, 98].

Ultimately, the path to commercialization for SMRs is to develop the infrastructure to manufacture the modules in factories and then ship the completed units to plant sites. Performing a majority of the construction in factories could standardize the assembly process and result in cost savings, as has occurred with U.S. Navy shipbuilding, where construction cost savings have been achieved by centralizing much of the production in a controlled factory setting [99].

In March 2012, DOE announced its intention to provide $450 million in funding to assist in the initial development of SMR technology [100]. Through cost-sharing agreements with private industry, DOE solicited proposals for promising SMR projects that have the potential to be licensed by the NRC and achieve commercial operation by 2022. In November 2012, DOE announced the selection of Babcock & Wilcox [101], in partnership with the Tennessee Valley Authority (TVA) and Bechtel International, to share the costs of preparing a license application for up to four SMRs at TVA's Clinch River site in Oak Ridge, Tennessee.

Alternative nuclear cases

In the AEO2013 Low Nuclear case, uprates currently under review by, or expected to be submitted to, the NRC are not included unless they have been reported to EIA. No nuclear power plants are assumed to receive second license renewals in the Low Nuclear case; all plants are assumed to retire after roughly 60 years of operation, except for those specifically discussed below. Other than the 5.5 gigawatts of new capacity already planned, no new nuclear power plants are assumed to be built.

In addition to the retirement of Oyster Creek in 2019, the Low Nuclear case includes the retirement of Kewaunee in 2013. Nuclear power plants that are in long-term shutdown also are assumed to be retired, including San Onofre Nuclear Generating Station (SONGS) Unit 3 and Crystal River Unit 3. Both plants have been in extended shutdown for more than a year, and there is substantial uncertainty about the cost and feasibility of operating the facilities in the future. Southern California Edison is assessing the long-term viability of SONGS Unit 3 and has indicated that it will not be operating for some time, in light of ongoing steam generator issues [102, 103, 104]. Crystal River Unit 3 has been offline since September 2009, as a result of cracks in the containment structure. As of October 2012, replacement power costs and the repairs to Unit 3 were initially estimated to be between $1.3 and $3.5 billion. However, repairs could eventually include replacement of the entire containment structure. Further repairs to Crystal River Unit 3 are being evaluated [105, 106]. In the Reference and High Nuclear cases, SONGS Unit 3 and Crystal River Unit 3 are assumed to return to service when maintenance and repairs have been completed.

The High Nuclear case assumes that all existing nuclear power plants receive their second license renewals and operate through 2040. Uprates in the High Nuclear case are consistent with those in the Reference case (8.0 gigawatts added by 2025). In addition to plants already under construction, the High Nuclear case assumes that nuclear power plants with active license applications at the NRC are constructed, provided that they have a tentatively scheduled Atomic Safety and Licensing Board hearing and will deploy a certified Nuclear Steam Supply System design. This assumption results in the planned addition of 13.3 gigawatts of new nuclear capacity, which is 7.8 gigawatts above what is assumed in the Reference case.

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In the High Nuclear case, planned capacity additions are more than double those in the Reference case, but unplanned additions do not change noticeably. The additional planned capacity reduces the need for new unplanned capacity. The importance of natural gas prices for nuclear power plant construction is highlighted in the results of the Low Oil and Gas Resource case, where the average price of natural gas delivered to the electric power sector in 2040 is 26 percent higher than in the Reference case. The higher natural gas prices make nuclear power a more competitive source for new generating capacity, resulting in the addition of 26 gigawatts of unplanned nuclear power capacity from 2011 to 2040. In the High Oil and Gas Resource case, where the average price of natural gas delivered to the electric power sector in 2040 is 39 percent lower than in the Reference case, no unplanned nuclear capacity is built. Similarly, no unplanned nuclear capacity is added in the Low Nuclear case (Figure 35).

The Small Modular Reactor case assumes that SMRs will be the nuclear technology choice available after 2025, rather than traditional gigawatt-scale nuclear power plants. There is uncertainty surrounding SMR design certification and supply chain and infrastructure development, which makes it difficult to develop capital cost assumptions for SMRs. The Small Modular Reactor case assumes that SMRs have the same overnight capital costs per kilowatt as a traditional 1,100-megawatt unit, consistent with cost assumptions in the Reference case. This assumption was made for the purpose of assessing the impact on the amount of new nuclear capacity of a shorter construction period for SMRs than for traditional nuclear power plants.

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In the High Nuclear case, nuclear generation in 2040 is 12 percent higher than in the Reference case, and the nuclear share of total generation is 19 percent, compared with 17 percent in the Reference case. The increase in nuclear generation offsets a decline in generation from natural gas (Figure 36) and renewable fuels, which are 5 percent and 2 percent lower in 2040, respectively, than in the Reference case. Coal-fired generation in the High Nuclear case is virtually the same as in the Reference case.

In the Low Nuclear case, generation from nuclear power in 2040 is 44 percent lower than in the Reference case, due to the loss of 45.4 gigawatts of nuclear capacity that is retired after 60 years of operation. As a result, the nuclear share of total generation falls to 10 percent in 2040. The loss of generation is made up primarily by increased generation from natural gas, which is 17 percent higher in the Low Nuclear case than in the Reference case in 2040. Generation from coal and generation from renewables in 2040 both are 2 percent higher than projected in the Reference case.

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CO2 emissions from the electric power sector are affected by the share of nuclear power in the generation mix. Unlike coal- and natural gas-fired plants, nuclear power plants do not emit CO2. Consequently, CO2 emissions from the electric power sector in 2040 are 5 percent lower in the Reference case than in the Low Nuclear case, as a result of switching from nuclear generation to mostly natural gas and some coal [107]. In the High Nuclear case, CO2 emissions from the power sector are 1 percent lower than projected in the Reference case, because the High Nuclear case results in slightly more generation from nuclear units than from fossil-fueled units (Figure 37).

Real average electricity prices in 2040 are 1 percent lower in the High Nuclear case than in the Reference case, as slightly less natural gas capacity is dispatched, reducing natural gas prices, which lowers the marginal price of electricity. In the Low Nuclear case, average electricity prices in 2040 are 5 percent higher than in the Reference case as a result of the retirement of a significant amount of nuclear capacity, which has relatively low operating costs, and its replacement with natural gas capacity, which has higher fuel costs that are passed through to consumers in retail electricity prices.

The impacts of nuclear plant retirements on retail electricity prices in the Low Nuclear case are more apparent in regions with relatively large amounts of nuclear capacity. For example, electricity prices in the Low Nuclear case are 9 percent higher in 2040 than in the Reference case for the SERC (Southeast) region, 8 percent higher for the MRO (Midwest) region, and 6 percent higher in the Northeast, Mid-Atlantic, and Ohio River Valley regions [108]. Even in regions where no nuclear capacity is retired, there are small increases in electricity prices compared to the Reference case, because higher demand for natural gas in regions where nuclear plants are retired increases the price of natural gas in all regions.

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In the Small Modular Reactor case, shorter construction periods result in lower interest costs, which help to reduce the overall cost of nuclear construction projects. Figure 38 compares the resulting levelized costs for traditional large reactors and for SMRs in the Reference case. For SMRs, there is a savings of approximately $6 per megawatthour in the capital portion of the levelized cost. However, estimates of the fixed O&M costs for SMRs, derived from a University of Chicago study [109], are 40 percent higher than those assumed in AEO2013 for a new large-scale plant on a dollar per megawatt basis. The higher O&M cost could offset, in part, the capital cost benefit of a shorter construction period. Therefore, the SMR case shows only a 1.4-percent reduction in overall levelized cost relative to the Reference case. The small difference results in about 2.3 gigawatts more new nuclear power capacity in the Small Modular Reactor case than projected in the Reference case. The sensitivity to small changes in cost is notable, given the high degree of uncertainty associated with SMR costs based on the maturity of the technology.


19. U.S. Nuclear Regulatory Commission, "Temporary storage of spent nuclear fuel after cessation of reactor operation—generic determination of no significant environmental impact," (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part051/part051-0023.html.
20. U.S. Nuclear Regulatory Commission, "Waste Confidence Decision," Federal Register, Vol. 49, No. 171 (Washington, DC: August 31, 1984), http://pbadupws.nrc.gov/docs/ML1233/ML12335A680.pdf.
21. U.S. Nuclear Regulatory Commission, "Waste Confidence Decision Review," Federal Register, Vol. 55, No. 181 (Washington, DC: September 18, 1990), http://pbadupws.nrc.gov/docs/ML1209/ML120960684.pdf.
22. U.S. Nuclear Regulatory Commission, "Waste Confidence Decision Update," Federal Register, Vol. 75, No. 246 (Washington, DC: December 23, 2010), pp. 81037-81076, https://www.federalregister.gov/articles/2010/12/23/2010-31637/waste-confidence-decision-update.
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25. U.S. Nuclear Regulatory Commission, "NRC Directs Staff to Conduct Two-Year Environmental Study and Revision to Waste Confidence Rule" (Washington, DC: September 6, 2012), http://www.nrc.gov/reading-rm/doc-collections/news/2012/12-098.pdf.
26. U.S. Nuclear Regulatory Commission, "Effect of timely renewal application" (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part002/part002-0109.html.
27. U.S. Nuclear Regulatory Commission, "Domestic Licensing of Production and Utilization Facilities" (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part050/.
28. Tennessee Valley Authority, "TVA's Bellefonte Resets Work Priorities" (Hollywood, AL: March 15, 2012), http://www.tva.gov/news/releases/janmar12/bln.htm.
29. U.S. Nuclear Regulatory Commission, "Licenses, Certifications, and Approvals for Domestic Nuclear Power Plants" (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part052/.
30. U.S. Nuclear Regulatory Commission, "Deciphering the Waste Confidence Order" (Washington, DC: August 9, 2012), http://public-blog.nrc-gateway.gov/2012/08/09/deciphering-the-waste-confidence-order/.
83. U.S. Energy Information Administration, "Uprates can increase U.S. nuclear capacity substantially without building new reactors," Today in Energy (Washington DC: July 17, 2012), http://www.eia.gov/todayinenergy/detail.cfm?id=7130.
84. U.S. Energy Information Administration, "Form EIA-860 detailed data" (Washington, DC: September 24, 2012, for Final 2011 data; revised January 9, 2013), http://www.eia.gov/electricity/data/eia860/index.html.
85. U.S. Energy Information Administration, "Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013," in AEO2013 Early Release Overview, DOE/EIA-0383ER(2013) (Washington, DC: January 28, 2013), http://www.eia.gov/forecasts/aeo/er/electricity_generation.cfm.
86. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2013, DOE/EIA-0554(2013) (Washington, DC: April 2013), http://www.eia.gov/forecasts/aeo/assumptions/.
87. U.S. Government Printing Office, "Energy Policy Act of 2005, Public Law 109-58, Title XVII—Incentives for Innovative Technologies" (Washington, DC: August 8, 2005), http://www.gpo.gov/fdsys/pkg/PLAW-109publ58/html/PLAW-109publ58.htm.
88. U.S. Department of Energy, Loan Programs Office, "Loan Guarantee Program: Georgia Power Company" (Washington, DC: June 4, 2012), http://www.lpo.energy.gov/?projects=georgia-power-company.
89. U.S. Government Printing Office, "Energy Policy Act of 2005, Public Law 109-58, Title XVII—Incentives for Innovative Technologies, Sections 638, 988, and 1306" (Washington, DC: August 2005), http://www.gpo.gov/fdsys/pkg/PLAW-109publ58/html/PLAW-109publ58.htm.
90. Electric Power Research Institute, "2012 Research Portfolio: Long Term Operations (QA)" (Palo Alto, CA: 2012) http://mydocs.epri.com/docs/Portfolio/PDF/2012_41-10-01.pdf.
91. Electric Power Research Institute, "2013 Research Portfolio: Materials Degradation/Aging" (Palo Alto, CA: 2013), http://portfolio.epri.com/Research.aspx?sId=NUC&rId=211.
92. L.J. Bond and D.L. Brenchley, Proceedings of the Inaugural Meeting of the International Forum for Reactor Aging Management (IFRAM), PNNL-20719 (Colorado Springs, CO: September, 2011), http://ifram.pnnl.gov/reports/PNNL-20719_Proceedings_IFRAMKick-OffMtg-091911.pdf.
93. U.S. Nuclear Regulatory Commission, "Orders to Implement Japan Lessons-Learned" (Washington, DC: March 12, 2012), http://www.nrc.gov/reactors/operating/ops-experience/japan/byorders/.
94. R. Lum, "Moody's: Building new nuclear a 'bet the farm' endeavor for most companies," SNL Energy (July 10, 2009), https://www.snl.com/interactivex/article.aspx?id=9764943&KPLT=6 (subscription site).
95. Duke Energy, "Duke Energy Fast Facts" (Charlotte, NC: July 9, 2012), http://www.duke-energy.com/pdfs/de-factsheet.pdf.
96. U.S. Nuclear Regulatory Commission, "Policy Issues Associated with Licensing Advanced Reactor Designs" (Washington, DC: March 29, 2012), http://www.nrc.gov/reactors/advanced/policy-issues.html.
97. U.S. Nuclear Regulatory Commission, "Potential Policy, Licensing, and Key Technical Issues for Small Modular Nuclear Reactor Designs" (Washington, DC: March 28, 2010), http://pbadupws.nrc.gov/docs/ML0932/ML093290268.pdf.
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107. Coal has a CO2 emissions factor approximately double that of natural gas. CO2 uncontrolled emissions factors for the electric power sector can be found in EIA's "Electric Power Annual," Table A.3, http://www.eia.gov/electricity/annual/html/epa_a_03.html.
108. The SERC Region in NEMS is represented by an aggregate of EMM Regions 12, 13, 14, 15, and 16. The MRO Region is represented by EMM Regions 3 and 4. The Northeast is represented by EMM regions 5, 6, 7, and 8. The Mid-Atlantic and Ohio Valley are represented by EMM Regions 9, 10, and 11.
109. R. Rosner and S. Goldberg, "Small Modular Reactors—Key to Future Nuclear Power Generation in the U.S.," University of Chicago Energy Policy Institute at Chicago (November 2011), http://epic.sites.uchicago.edu/sites/epic.uchicago.edu/files/uploads/EPICSMRWhitePaperFinalcopy.pdf.
132. The factors that influence decisionmaking on capacity additions include electricity demand growth, the need to replace inefficient plants, the costs and operating efficiencies of different generation options, fuel prices, state RPS programs, and the availability of federal tax credits for some technologies.
133.Unless otherwise noted, the term capacity in the discussion of electricity generation indicates utility, nonutility, and CHP capacity.
134.Costs are for the electric power sector only.
135. The levelized costs reflect the average of regional costs. For detailed discussion of levelized costs, see U.S. Energy Information Administration, "Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013," http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.