‹ Analysis & Projections

Annual Energy Outlook 2014

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

Market Trends — Electricity

Growth in electricity use slows but still increases by 28 percent from 2011 to 2040


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The growth of electricity demand (including retail sales and direct use) has slowed in each decade since the 1950s, from a 9.8-percent annual rate of growth from 1949 to 1959 to only 0.7 percent per year in the first decade of the 21st century. In the AEO2013 Reference case, electricity demand growth remains relatively slow, as increasing demand for electricity services is offset by efficiency gains from new appliance standards and investments in energy-efficient equipment (Figure 75). Total electricity demand grows by 28 percent in the projection (0.9 percent per year), from 3,839 billion kilowatthours in 2011 to 4,930 billion kilowatthours in 2040.

Retail electricity sales grow by 24 percent (0.7 percent per year) in the Reference case, from 3,725 billion kilowatthours in 2011 to 4,608 billion kilowatthours in 2040. Residential electricity sales also grow by 24 percent, to 1,767 billion kilowatthours in 2040, spurred by population growth and continued population shifts to warmer regions with greater cooling requirements. Led by demand in the service industries, sales of electricity to the commercial sector increase by 27 percent, to 1,677 billion kilowatthours in 2040. Sales to the industrial sector grow by 17 percent, to 1,145 billion kilowatthours in 2040. Electricity sales to the transportation sector, although relatively small, triple from 6 billion kilowatthours in 2011 to 19 billion kilowatthours in 2040 with increasing sales of electric plug-in LDVs.

Electricity demand can vary with different assumptions about economic growth, electricity prices, and advances in energy-efficient technologies. In the High Economic Growth case, demand grows by 42 percent from 2011 to 2040, compared with 18 percent in the Low Economic Growth case and only 7 percent in the Best Available Technology case. Average electricity prices (in 2011 dollars) increase by 5 percent from 2011 to 2040 in the Low Economic Growth case and 13 percent in the High Economic Growth case, to 10.4 and 11.2 cents per kilowatthour, respectively, in 2040.

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.

Growth in generating capacity parallels rising demand for electricity


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Over the long term, growth in electricity generating capacity parallels the growth in end-use demand for electricity. Unexpected shifts in demand or dramatic changes affecting capacity investment decisions can, however, cause imbalances that may take years to be worked out.

Figure 79 shows indexes summarizing relative changes in total generating capacity and electricity demand. During the 1950s and 1960s, the capacity and demand indexes tracked closely. The energy crises of the 1970s and 1980s, together with other factors, slowed electricity demand growth, and capacity growth outpaced demand for more than 10 years thereafter, as planned units continued to come on line. Demand and capacity did not align again until the mid-1990s. Then, in the late 1990s, uncertainty about deregulation of the electricity industry caused a downturn in capacity expansion, and another period of imbalance followed, with growth in electricity demand exceeding capacity growth.

In 2000, a boom in construction of new natural gas-fired plants began, bringing capacity back into balance with demand and creating excess capacity. Construction of new wind capacity that sometimes needs backup capacity because of intermittency also began to grow after 2000. More recently, the 2007-2009 economic recession caused a significant drop in electricity demand, which has yet to recover. Slow near-term growth in electricity demand in the AEO2013 Reference case creates excess generating capacity. Capacity currently under construction is completed, but a limited amount of additional capacity is built before 2025, while older capacity is retired. By 2025, capacity growth and demand growth are in balance again, and they grow at similar rates through 2035. In the later years, total capacity grows at a rate slightly higher than demand, due in part to an increasing share of intermittent renewable capacity that does not contribute to meeting demand in the same proportion as dispatchable capacity.

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.

Solar photovoltaics and wind dominate renewable capacity growth


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Renewable generating capacity accounts for nearly one-fifth of total generating capacity in 2040 in the AEO2013 Reference case. Nearly all renewable capacity additions over the period consist of nonhydropower capacity, which grows by more than 150 percent from 2011 to 2040 (Figure 82).

Solar generation capacity leads renewable capacity growth, increasing by more than 1,000 percent, or 46 gigawatts, from 2011 to 2040. Wind capacity follows closely, accounting for an additional 42 gigawatts of new renewable capacity by 2040. Nonetheless, wind continues to be the leading source of nonhydropower renewable capacity in 2040, given its relatively high initial capacity in 2011, after a decade of exponential growth resulting from the availability of production tax credits and other incentives. Although geothermal and dedicated biomass generation capacity do not increase on the same scale as wind and solar (contributing an additional 5 gigawatts and 7 gigawatts, respectively, over the projection period), biomass capacity nearly doubles and geothermal capacity more than triples over the same period.

Renewable capacity additions are supported by state RPS, the federal renewable fuels standard, and federal tax credits. Near-term growth is strong as developers build capacity to qualify for tax credits that expire at the end of 2012, 2013, and 2016. After 2016, capacity growth through 2030 is minimal, given relatively slower growth in electricity demand, low natural gas prices, and the stagnation or expiration of the state and federal policies that support renewable capacity additions. As the need for new generation capacity increases, however, and as renewables become increasingly cost-competitive in selected regions, growth in nonhydropower renewable generation capacity rebounds during the final decade of the Reference case projection from 2030 to 2040.

Solar, wind, and biomass lead growth in renewable generation, hydropower remains flat


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In the AEO2013 Reference case, renewable generation increases from 524 billion kilowatthours in 2011 to 858 billion kilowatthours in 2040, growing by an average of 1.7 percent per year (Figure 83). Wind, solar, and biomass account for most of the growth. The increase in wind-powered generation from 2011 to 2040, at 134 billion kilowatthours, or 2.6 percent per year, represents the largest absolute increase in renewable generation. Generation from solar energy grows by 92 billion kilowatthours over the same period, representing the highest annual average growth at 9.8 percent per year. Biomass increases by 95 billion kilowatthours over the projection period, for an average annual increase of 4.5 percent.

Hydropower production drops in 2012, from 325 billion kilowatthours in 2011, as existing plants are assumed to continue operating at their long-term average production levels. Even with little growth in capacity, hydropower remains the leading source of renewable generation throughout the projection. Although total wind capacity exceeds hydropower capacity in 2040, wind generators typically operate at much lower capacity factors, and their total generation is lower. Biomass is the third-largest source of renewable generation throughout the projection, with rapid growth particularly in the first decade of the period, reaching 102 billion kilowatthours in 2021 from 37 billion kilowatthours in 2011. The strong growth is a result primarily of increased penetration of co-firing technology in the electric power sector, encouraged by state-level policies and increasing cost-competitiveness with coal in parts of the Southeast.

State renewable portfolio standards increase renewable electricity generation


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Regional growth in nonhydroelectric renewable electricity generation is based largely on three factors: availability of renewable energy resources, cost competitiveness with fossil fuel technologies, and the existence of state RPS programs that require the use of renewable generation. After a period of robust RPS enactments in several states, the past few years have been relatively quiet in terms of state program expansions.

In the AEO2013 Reference case, the highest level of nonhydroelectric renewable generation in 2040, at 104 billion kilowatthours, occurs in the WECC California (CAMX) region (Figure 84), whose area approximates the California state boundaries. (For a map of the electricity regions and a definition of the acronyms, see Appendix F.) The three largest sources of nonhydro-electric renewable generation in 2040 in that region are geothermal, solar, and wind energy. The region encompassing the Pacific Northwest has the most renewable generation in the United States when hydroelectric is included, which is the source of most of the region's renewable electricity generation.

State RPS programs heavily influence the growth of solar capacity in the eastern states. A prime example is the Reliability First Corporation/East (RFCE) region, where 7.5 billion kilowatthours of electricity is generated from solar resources in 2040, mostly from end-use capacity. The RFCE region is not known for a strong solar resource base, and the projected installations are in response to the federal tax credits, state incentives, and solar energy requirements embedded in state RPS programs. The CAMX region has the highest total for solar generation in 2040 at 36 billion kilowatthours, including 10 billion kilowatthours of generation from end-use solar capacity.

Endnotes for Market Trends: Electricity

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.

Reference Case Tables
Table 2. Energy Consumption by Sector and Source - United States XLS
Table 2.1. Energy Consumption by Sector and Source - New England XLS
Table 2.2. Energy Consumption by Sector and Source - Middle Atlantic XLS
Table 2.3. Energy Consumption by Sector and Source - East North Central XLS
Table 2.4. Energy Consumption by Sector and Source - West North Central XLS
Table 2.5. Energy Consumption by Sector and Source - South Atlantic XLS
Table 2.6. Energy Consumption by Sector and Source - East South Central XLS
Table 2.7. Energy Consumption by Sector and Source - West South Central XLS
Table 2.8. Energy Consumption by Sector and Source - Mountain XLS
Table 2.9. Energy Consumption by Sector and Source - Pacific XLS
Table 9. Electricity Generating Capacity XLS
Table 10. Electricity Trade XLS
Table 16. Renewable Energy Generating Capacity and Generation XLS
Table 17. Renewable Energy Consumption by Sector and Source XLS
Table 18. Energy-Related Carbon Dioxide Emissions by Sector and Source - United States XLS
Table 18.1. Energy-Related Carbon Dioxide Emissions by Sector and Source - New England XLS
Table 18.2. Energy-Related Carbon Dioxide Emissions by Sector and Source - Middle Atlantic XLS
Table 18.3. Energy-Related Carbon Dioxide Emissions by Sector and Source - East North Central XLS
Table 18.4. Energy-Related Carbon Dioxide Emissions by Sector and Source - West North Central XLS
Table 18.5. Energy-Related Carbon Dioxide Emissions by Sector and Source - South Atlantic XLS
Table 18.6. Energy-Related Carbon Dioxide Emissions by Sector and Source - East South Central XLS
Table 18.7. Energy-Related Carbon Dioxide Emissions by Sector and Source - West South Central XLS
Table 18.8. Energy-Related Carbon Dioxide Emissions by Sector and Source - Mountain XLS
Table 18.9. Energy-Related Carbon Dioxide Emissions by Sector and Source - Pacific XLS
Table 55. Electric Power Projections for EMM Region - United States XLS
Table 55.1. Electric Power Projections for EMM Region - Texas Regional Entity XLS
Table 55.1. Electric Power Projections for EMM Region - Reliability First Corporation / Michigan XLS
Table 55.11. Electric Power Projections for EMM Region - Reliability First Corporation / West XLS
Table 55.12. Electric Power Projections for EMM Region - SERC Reliability Corporation / Delta XLS
Table 55.13. Electric Power Projections for EMM Region - SERC Reliability Corporation / Gateway XLS
Table 55.14. Electric Power Projections for EMM Region - SERC Reliability Corporation / Southeastern XLS
Table 55.15. Electric Power Projections for EMM Region - SERC Reliability Corporation / Central XLS
Table 55.16. Electric Power Projections for EMM Region - SERC Reliability Corporation / Virginia-Carolina XLS
Table 55.17. Electric Power Projections for EMM Region - Southwest Power Pool / North XLS
Table 55.18. Electric Power Projections for EMM Region - Southwest Power Pool / South XLS
Table 55.19. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / Southwest XLS
Table 55.2. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / California XLS
Table 55.2. Electric Power Projections for EMM Region - Florida Reliability Coordinating Council XLS
Table 55.21. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / Northwest Power Pool Area XLS
Table 55.22. Electric Power Projections for EMM Region - Western Electricity Coordinating Council / Rockies XLS
Table 55.3. Electric Power Projections for EMM Region - Midwest Reliability Council / East XLS
Table 55.4. Electric Power Projections for EMM Region - Midwest Reliability Council / West XLS
Table 55.5. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / Northeast XLS
Table 55.6. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / NYC-Westchester XLS
Table 55.7. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / Long Island XLS
Table 55.8. Electric Power Projections for EMM Region - Northeast Power Coordinating Council / Upstate New York XLS
Table 55.9. Electric Power Projections for EMM Region - Reliability First Corporation / East XLS
Table 56. Electricity Generation by Electricity Market Module Region and Source XLS
Table 57. Electricity Generation Capacity by Electricity Market Module Region and Source XLS
Table 58. Renewable Energy Generation by Fuel - United States XLS
Table 58.1. Renewable Energy Generation by Fuel - Texas Regional Entity XLS
Table 58.1. Renewable Energy Generation by Fuel - Reliability First Corporation / Michigan XLS
Table 58.11. Renewable Energy Generation by Fuel - Reliability First Corporation / West XLS
Table 58.12. Renewable Energy Generation by Fuel - SERC Reliability Corporation / Delta XLS
Table 58.13. Renewable Energy Generation by Fuel - SERC Reliability Corporation / Gateway XLS
Table 58.14. Renewable Energy Generation by Fuel - SERC Reliability Corporation / Southeastern XLS
Table 58.15. Renewable Energy Generation by Fuel - SERC Reliability Corporation / Central XLS
Table 58.16. Renewable Energy Generation by Fuel - SERC Reliability Corporation / Virginia-Carolina XLS
Table 58.17. Renewable Energy Generation by Fuel - Southwest Power Pool / North XLS
Table 58.18. Renewable Energy Generation by Fuel - Southwest Power Pool / South XLS
Table 58.19. Renewable Energy Generation by Fuel - Western Electricity Coordinating Council / Southwest XLS
Table 58.2. Renewable Energy Generation by Fuel - Western Electricity Coordinating Council / California XLS
Table 58.2. Renewable Energy Generation by Fuel - Florida Reliability Coordinating Council XLS
Table 58.21. Renewable Energy Generation by Fuel - Western Electricity Coordinating Council / Northwest Power Pool Area XLS
Table 58.22. Renewable Energy Generation by Fuel - Western Electricity Coordinating Council / Rockies XLS
Table 58.3. Renewable Energy Generation by Fuel - Midwest Reliability Council / East XLS
Table 58.4. Renewable Energy Generation by Fuel - Midwest Reliability Council / West XLS
Table 58.5. Renewable Energy Generation by Fuel - Northeast Power Coordinating Council / Northeast XLS
Table 58.6. Renewable Energy Generation by Fuel - Northeast Power Coordinating Council / NYC-Westchester XLS
Table 58.7. Renewable Energy Generation by Fuel - Northeast Power Coordinating Council / Long Island XLS
Table 58.8. Renewable Energy Generation by Fuel - Northeast Power Coordinating Council / Upstate New York XLS
Table 58.9. Renewable Energy Generation by Fuel - Reliability First Corporation / East XLS