U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Annual Energy Outlook 2014
Release Dates: April 7 - 30, 2014 | Next Early Release Date: December 2014 | See schedule
Electricity from Executive Summary
Although coal is expected to continue its important role in U.S. electricity generation, there are many uncertainties that could affect future outcomes. Chief among them are the relationship between coal and natural gas prices and the potential for policies aimed at reducing greenhouse gas (GHG) emissions. In 2012, natural gas prices were low enough for a few months for power companies to run natural gas-fired generation plants more economically than coal plants in many areas. During those months, coal and natural gas were nearly tied in providing the largest share of total electricity generation, something that had never happened before. In the Reference case, existing coal plants recapture some of the market they recently lost to natural gas plants because natural gas prices rise more rapidly than coal prices. However, the rise in coal-fired generation is not sufficient for coal to maintain its generation share, which falls to 35 percent by 2040 as the share of generation from natural gas rises to 30 percent.
In the alternative High Oil and Natural Gas Resource case, with much lower natural gas prices, natural gas supplants coal as the top source of electricity generation (Figure 3). In this case, coal accounts for only 27 percent of total generation in 2040, while natural gas accounts for 43 percent. However, while natural gas generation in the power sector surpasses coal generation in 2016 in this case, more coal energy than natural gas energy is used for power generation until 2035 because of the higher average thermal efficiency of the natural gas-fired generating units. Coal use for electric power generation falls to 14.7 quadrillion Btu in 2040 in the High Oil and Natural Gas Resource case (compared with 18.7 quadrillion Btu in the Reference case), while natural gas use rises to 15.1 quadrillion Btu in the same year (Figure 4). Natural gas use for electricity generation is 9.7 quadrillion Btu in 2040 in the Reference case.
Coal's generation share and the associated carbon dioxide (CO2) emissions could be further reduced if policies aimed at reducing GHG emissions were enacted (Figure 5). For example, in the GHG15 case, which assumes a fee on CO2 emissions that starts at $15 per metric ton in 2014 and increases by 5 percent per year through 2040, coal's share of total generation falls to 13 percent in 2040. Energy-related CO2 emissions also fall sharply in the GHG15 case, to levels that are 10 percent, 15 percent, and 24 percent lower than projected in the Reference case in 2020, 2030, and 2040, respectively. In 2040, energy-related CO2 emissions in the GHG15 case are 28 percent lower than the 2005 total. In the GHG15 case, coal use in the electric power sector falls to only 6.1 quadrillion Btu in 2040, a decline of about two-thirds from the 2011 level. While natural gas use in the electric power sector initially displaces coal use in this case, reaching more than 10 quadrillion Btu in 2016, it falls to 8.8 quadrillion Btu in 2040 as growth in renewable and nuclear generation offsets natural gas use later in the projection period.
Natural gas consumption grows in industrial and electric power sectors as domestic production also serves an expanding export market
Relatively low natural gas prices, maintained by growing shale gas production, spur increased use in the industrial and electric power sectors, particularly over the next decade. In the Reference case, natural gas use in the industrial sector increases by 16 percent, from 6.8 trillion cubic feet per year in 2011 to 7.8 trillion cubic feet per year in 2025. After 2025, the growth of natural gas consumption in the industrial sector slows, while total U.S. consumption continues to grow (Figure 7). This additional growth is mostly for use in the electric power sector. Although natural gas continues to capture a growing share of total electricity generation, natural gas consumption by power plants does not increase as sharply as generation because new plants are very efficient (needing less fuel per unit of power output). The natural gas share of generation rose from 16 percent of generation in 2000 to 24 percent in 2011 and increases to 27 percent in 2025 and 30 percent in 2040. Natural gas use in the residential and commercial sectors remains nearly constant, as increasing end-use demand is balanced by increasing end-use efficiency.
Natural gas consumption also grows in other markets in the Reference case, including heavy-duty freight transportation (trucking) and as a feedstock for GTL production of diesel and other fuels. Those uses account for 6 percent of total U.S. natural gas consumption in 2040, as compared with almost nothing in 2011.
Natural gas use in the electric power sector grows even more sharply in the High Oil and Natural Gas Resource case, as the natural gas share of electricity generation grows to 39 percent, reaching 14.8 trillion cubic feet in 2040, more than 55 percent greater than in the Reference case. Industrial sector natural gas consumption growth is also stronger in this case, with growth continuing after 2025 and reaching 13.0 trillion cubic feet in 2040 (compared to 10.5 trillion cubic feet in 2040 in the Reference case). Much of the industrial growth in the High Oil and Natural Gas Resource case is associated with natural gas use for GTL production and increased lease and plant use in natural gas production.
The share of U.S. electricity generation from renewable energy grows from 13 percent in 2011 to 16 percent in 2040 in the Reference case. Electricity generation from solar and, to a lesser extent, wind energy sources grows as their costs decline, making them more economical in the later years of the projection. However, the rate of growth in renewable electricity generation is sensitive to several factors, including natural gas prices and the possible implementation of policies to reduce GHG emissions. If future natural gas prices are lower than projected in the Reference case, as illustrated in the High Oil and Gas Resource case, the share of renewable generation would grow more slowly, to only 14 percent in 2040. Alternatively, if broad-based policies to reduce GHG emissions were enacted, renewable generation would be expected to grow more rapidly. In three cases that assume GHG emissions fees that range from $10 to $25 per metric ton in 2014 and rise by 5 percent per year through 2040 (GHG10, GHG15, and GHG25), the renewable share of total U.S. electricity generation in 2040 ranges from 23 percent to 31 percent (Figure 8).
The AEO2013 Reference case reflects a less optimistic outlook for advanced biofuels to capture a rapidly growing share of the liquid fuels market than earlier Annual Energy Outlooks. As a result, biomass use in the Reference case totals 5.9 quadrillion Btu in 2035 and 7.1 quadrillion Btu in 2040, up from 4.0 quadrillion Btu in 2011.
Electricity from Market Trends
Electricity use per household declines from 2011 to 2040 in the Reference case
Average electricity demand per household declines by 6 percent in the Reference case, from 12.3 megawatthours in 2011 to 11.5 megawatthours in 2040. As the number of households grows, however, total delivered electricity consumption in the residential sector increases by about 24 percent. Over the same period, residential use of natural gas falls by 12 percent, and use of petroleum and other liquids falls by 25 percent. Total energy demand for most electric end uses increases, even as it declines on a per-household basis. In 2040, space cooling and "other uses" consume 42 percent and 52 percent more electricity, respectively, than in 2011 and remain the largest residential uses of electricity. Electricity use for personal computers (PCs) and related equipment and for clothes washers declines.
The largest reduction in residential electricity use is for lighting (Figure 56). The Energy Independence and Security Act of 2007 (EISA2007) phases in standards that require a reduction of about 30 percent in energy use for general-service lamps between 2012 and 2014, with specific dates that vary by light level. On January 1, 2013, the requirements went into effect for 75-watt incandescent bulbs; the requirements for 100-watt incandescent bulbs went into effect a year earlier. The EISA2007 standards result in the replacement of incandescent bulbs with more efficient compact fluorescent lighting and light-emitting diode (LED) lamps.
Among electric end-use services in the residential sector, lighting demand declines at the fastest rate (1.8 percent per year) and "other uses" rise at the fastest rate (1.4 percent per year). The growth in other uses stems from the introduction of new electrical devices in households, with little coverage by efficiency standards. Electricity use for water heating also increases, but at a slower rate (0.7 percent per year) than the growth in number of households (1.0 percent per year).
Renewable energy fuels most additions to commercial distributed generation capacity
PV and wind account for 58.7 percent of commercial distributed generation capacity in 2040 in the AEO2013 Reference case. Exponential growth of PV capacity has occurred in both new and existing construction during recent years as a result of utility incentives, new financing options, and the 30-percent federal ITC that reverts to 10 percent in 2017. In the Reference case, commercial PV capacity increases by 6.5 percent annually from 2011 to 2040. In the No Sunset case, with ITCs for all distributed generation technologies extended through 2040, PV capacity increases by an average of 7.4 percent per year.
Small-scale wind capacity increases by 7.4 percent per year from 2011 to 2040 in the Reference case and by an even greater 12.6 percent per year from 2011 to 2040 in the No Sunset case (Figure 62). As with PV, additional federal and local incentives help to drive growth in commercial wind capacity. Wind capacity accounts for 10.7 percent of the 28.4 gigawatts of total distributed generation capacity in 2040 in the No Sunset case, and PV accounts for 55.2 percent.
Rising fuel prices offset the effects of the 10-percent ITC on nonrenewable technologies for distributed generation. In the Reference case, microturbine capacity using natural gas grows by 15.0 percent per year on average, from 83.3 megawatts in 2011 to 4.7 gigawatts in 2040; and the growth rate in the No Sunset case is only slightly higher, at 15.3 percent. The microturbine share of total DG capacity in 2040 is 18.0 percent in the No Sunset case, as compared with 21.6 percent in the Reference case, and fuel cell capacity grows at an annual rate of roughly 10.9 percent in the Reference case and 11.3 percent in the No Sunset case.
Reliance on natural gas, natural gas liquids, and renewables rises as industrial energy use grows
Much of the growth in industrial energy consumption in the AEO2013 Reference case is accounted for by natural gas use, which increases by 18 percent from 2011 and 2025 and by 6 percent from 2025 to 2040 (Figure 64). With domestic natural gas production increasing sharply in the projection, natural gas prices remain relatively low. The mix of industrial fuels changes relatively slowly, however, reflecting limited capability for fuel switching in most industries.
Consumption of renewable fuels in the industrial sector grows by 22 percent from 2011 to 2025 in the Reference case and by 37 percent from 2025 to 2040. The paper industry remains the predominant consumer of renewable energy (mostly biomass) in the industrial sector. Industrial consumption of natural gas liquids (NGL) increases by 21 percent from 2011 to 2025, followed by a 9-percent decline from 2025 to 2040. NGL are consumed predominantly as feedstocks in the bulk chemicals industry and for process heat in other industries. NGL use declines starting in 2025 as shipments of bulk chemicals begin to decline in the face of increased international competition. Industrial coal use drops by less than 1 percent from 2011 to 2040, and the use of petroleum and other liquid fuels increases by 6 percent.
Low natural gas prices and increased availability of biomass contribute to growth in the use of combined heat and power (CHP). A small decline in the purchased electricity share of industrial energy consumption (less than 1 percent from 2011 to 2040) reflects growth in CHP, as well as efficiency improvements resulting from rising standards for electric motors.
Heavy-duty vehicles dominate natural gas consumption in the transportation sector
Natural gas, as compressed natural gas (CNG) and liquefied natural gas (LNG), is the fastest-growing fuel in the transportation sector, with an average annual growth rate of 11.9 percent from 2011 to 2040 (Figure 74). HDVs—which include tractor trailers, vocational vehicles, buses, and heavy-duty pickups and vans with a gross vehicle weight rating (GVWR) of 10,001 pounds or more—lead the growth in natural gas demand throughout the projection period. Natural gas fuel consumption by HDVs increases from almost zero in 2011 to more than 1 quadrillion Btu in 2040, at an average annual growth rate of 14.6 percent.
Although HDVs fueled by natural gas have significant incremental costs in comparison with their diesel-powered counterparts, the increase in natural gas consumption for HDVs is spurred by low prices of natural gas compared with diesel fuel, as well as purchases of natural gas vehicles for relatively high-VMT applications, such as tractor trailers.
The total number of miles traveled annually by HDVs grows by 82 percent in the Reference case, from 240 billion miles in 2011 to 438 billion miles in 2040, for an average annual increase of 2.1 percent. HDVs, those with a GVWR greater than 26,000 pounds (primarily tractor trailers), account for about three-fourths of truck VMT and 91 percent of natural gas consumption by all HDVs in 2040. The rise in VMT is supported by rising economic output over the projection period and an increase in the number of trucks on the road, from 9.0 million in 2011 to 13.7 million in 2040.
Growth in electricity use slows but still increases by 28 percent from 2011 to 2040
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
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
Decisions to add capacity, and the choice of fuel for new capacity, depend on a number of factors . With growing electricity demand and the retirement of 103 gigawatts of existing capacity, 340 gigawatts of new generating capacity  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
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
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
Technology choices for new generating capacity are based largely on capital, operating, and transmission costs . 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 , 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
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
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
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
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.
Industrial and electric power sectors lead
U.S. growth in natural gas consumption
U.S. total natural gas consumption grows from 24.4 trillion cubic feet in 2011 to 29.5 trillion cubic feet in 2040 in the AEO2013 Reference case. Natural gas use increases in all the end-use sectors except residential (Figure 85), where consumption declines as a result of improvements in appliance efficiency and falling demand for space heating, attributable in part to population shifts to warmer regions of the country.
Despite falling early in the projection period from a spike in 2012, which resulted from very low natural gas prices relative to coal, consumption of natural gas for power generation increases by an average of 0.8 percent per year, with more natural gas used for electricity production as relatively low prices make natural gas more competitive with coal. Over the projection period, the natural gas share of total power generation grows, while the coal share declines.
Natural gas consumption in the industrial sector increases by an average of 0.5 percent per year from 2011 to 2040. This includes 0.7 trillion cubic feet of natural gas used in GTL, which is largely consumed in the transportation sector. Industrial output grows as the energy-intensive industries take advantage of relatively low natural gas prices, particularly through 2025. After 2025, growth in the sector slows in response to rising prices and increased international competition.
Although vehicle uses currently account for only a small part of total U.S. natural gas consumption, the projected percentage growth in natural gas demand by vehicles is the largest percentage growth in the projection. With incentives and low natural gas prices leading to increased demand for natural gas as a fuel for HDVs, particularly after 2025, consumption in vehicles increases from about 40 billion cubic feet in 2011 to just over 1 trillion cubic feet in 2040.
Pipeline exports increase as Canadian imports fall and exports to Mexico rise
With relatively low natural gas prices in the AEO2013 Reference case, the United States becomes a net exporter of natural gas in 2020, and net exports grow to 3.6 trillion cubic feet in 2040 (Figure 92). Most of the projected growth in U.S. exports consists of pipeline exports to Mexico, which increase steadily over the projection period, as increasing volumes of imported natural gas from the United States fill the growing gap between Mexico's production and consumption. Exports to Mexico increase from 0.5 trillion cubic feet in 2011 to 2.4 trillion cubic feet in 2040.
U.S. exports of domestically sourced LNG (excluding existing exports from the Kenai facility in Alaska, which fall to zero in 2013) begin in 2016 and rise to a level of 1.6 trillion cubic feet per year in 2027. One-half of the projected increase in U.S. exports of LNG originate in the Lower 48 states and the other half from Alaska. Continued low levels of LNG imports through the projection period position the United States as a net exporter of LNG by 2016. In general, future U.S. exports of LNG depend on a number of factors that are difficult to anticipate, including the speed and extent of price convergence in global natural gas markets, the extent to which natural gas competes with oil in domestic and international markets, and the pace of natural gas supply growth outside the United States.
Net natural gas imports from Canada decline sharply from 2016 to 2022, then stabilize somewhat before dropping off again in the final years of the projection, as continued growth in domestic production mitigates the need for imports. Even as overall consumption exceeds supply in the United States, some natural gas imports from Canada continue, based on regional supply and demand conditions.
Energy-related carbon dioxide emissions remain below their 2005 level through 2040
On average, energy-related CO2 emissions in the AEO2013 Reference case decline by 0.2 percent per year from 2005 to 2040, as compared with an average increase of 0.9 percent per year from 1980 to 2005. Reasons for the decline include: an expected slow and extended recovery from the recession of 2007-2009; growing use of renewable technologies and fuels; automobile efficiency improvements; slower growth in electricity demand; and more use of natural gas, which is less carbon-intensive than other fossil fuels. In the Reference case, energy-related CO2 emissions in 2020 are 9.1 percent below their 2005 level. Energy-related CO2 emissions total 5,691 million metric tons in 2040, or 308 million metric tons (5.1 percent) below their 2005 level (Figure 108).
Petroleum remains the largest source of U.S. energy-related CO2 emissions in the projection, but its share falls to 38 percent in 2040 from 44 percent in 2005. CO2 emissions from petroleum use, mainly in the transportation sector, are 448 million metric tons below their 2005 level in 2040.
Emissions from coal, the second-largest source of energy-related CO2 emissions, are 246 million metric tons below the 2005 level in 2040 in the Reference case, and their share of total energy-related CO2 emissions declines from 36 percent in 2005 to 34 percent in 2040. The natural gas share of total CO2 emissions increases from 20 percent in 2005 to 28 percent in 2040, as the use of natural gas to fuel electricity generation and industrial applications increases. Emissions levels are sensitive to assumptions about economic growth, fuel prices, technology costs, and policies that are explored in many of the alternative cases completed for AEO2013.
Power plant emissions of sulfur dioxide are reduced by further environmental controls
In the AEO2013 Reference case, sulfur dioxide (SO2) emissions from the U.S. electric power sector fall from 4.4 million short tons in 2011 to a range between 1.2 and 1.7 million short tons in the 2016-2040 projection period. The reduction occurs in response to the MATS . Although SO2 is not directly regulated by the MATS, the reductions are achieved as a result of acid gas limits that lead to the installation of FGD units or DSI systems, which also remove SO2. AEO2013 assumes that, in order to comply with MATS, coal-fired power plants must have one of the two technologies installed by 2016. Both technologies, which are used to reduce acid gas emissions regulated under MATS, also reduce SO2 emissions.
EIA assumes a 95-percent SO2 removal efficiency for FGD units and a 70-percent SO2 removal efficiency for DSI systems paired with baghouse fabric filters. AEO2013 also assumes that a baghouse fabric filter is required for all coal-fired plants in order to comply with the nonmercury metal emissions limits set forth by MATS [143, 144].
From 2011 to 2040, approximately 43 gigawatts of coal-fired capacity is retrofitted with FGD units in the Reference case, and another 50 gigawatts is retrofitted with DSI systems. In 2016, all operating coal-fired generation units larger than 25 megawatts are assumed to have either DSI or FGD systems installed. After a 73-percent decrease from 2011 to 2016, SO2 emissions increase slowly from 2016 to 2040 (Figure 109) as total electricity generation from coal-fired power plants increases. The increase is relatively small, however, because overall growth in generation from coal is slow, and the required installations of FGD and DSI equipment limit SO2 emissions from plants in operation.
Nitrogen oxides emissions show little change from 2011 to 2040 in the Reference case
Annual emissions of nitrogen oxides (NOX) from the electric power sector, which totaled 1.9 million short tons in 2011, range between 1.6 and 2.1 million short tons from 2011 to 2040 (Figure 110). Annual NOX emissions from electricity generation dropped by 47 percent from 2005 to 2011 as a result of the implementation of the Clean Air Interstate Rule (CAIR), which led to year-round operation of advanced pollution control equipment (that under the NOX budget program operated during the summer season only) and to additional installations of NOX pollution control equipment.
In the AEO2013 Reference case, annual NOX emissions in 2040 are 4 percent below the 2011 level, despite a 6-percent increase in annual electricity generation from coal-fired power plants over the period. The drop in emissions is primarily a result of CAIR, which established an annual cap-and-trade program for NOX emissions in 25 states and the District of Columbia. A slight rise in NOX emissions after 2020 corresponds to a projected recovery in coal-fired generation.
MATS does not have a direct effect on NOX emissions, because none of the potential technologies required to comply with MATS has a significant impact on NOX emissions. However, because MATS contributes to a reduction in coal-fired generation nationwide, it indirectly reduces NOX emissions from the power sector in states not affected by CAIR.
From 2011 to 2040, 15.4 gigawatts of coal-fired capacity is retrofitted with NOX controls in the AEO2013 Reference case. Coal-fired power plants can be retrofitted with three types of NOX control technologies: selective catalytic reduction (SCR), selective noncatalytic reduction (SNCR), or low-NOX burners, depending on the specific characteristics of the plant, including boiler configuration and the type of coal used. SCRs make up 90 percent of the NOX controls installed in the Reference case, SNCRs 5 percent, and low-NOX burners 5 percent.
Electricity from Issues in Focus
The AEO2013 Reference case is best described as a current laws and regulations case because it generally assumes that existing laws and regulations remain unchanged throughout the projection period, unless the legislation establishing them sets a sunset date or specifies how they will change. The Reference case often serves as a starting point for analysis of proposed changes in legislation or regulations. While the definition of the Reference case is relatively straightforward, there may be considerable interest in a variety of alternative cases that reflect updates or extensions of current laws and regulations. Areas of particular interest include:
- Laws or regulations that have a history of being extended beyond their legislated sunset dates. Examples include the various tax credits for renewable fuels and technologies, which have been extended with or without modifications several times since their initial implementation.
- Laws or regulations that call for periodic updating of initial specifications. Examples include appliance efficiency standards issued by the U.S. Department of Energy (DOE) and CAFE and greenhouse gas (GHG) emissions standards for vehicles issued by the National Highway Traffic Safety Administration (NHTSA) and the U.S. Environmental Protection Agency (EPA).
- Laws or regulations that allow or require the appropriate regulatory agency to issue new or revised regulations under certain conditions. Examples include the numerous provisions of the Clean Air Act that require EPA to issue or revise regulations if it finds that an environmental quality target is not being met.
Two alternative cases are discussed in this section to provide some insight into the sensitivity of results to scenarios in which existing tax credits or other policies do not sunset. No attempt is made to cover the full range of possible uncertainties in these areas, and readers should not view the cases discussed as EIA projections of how laws or regulations might or should be changed. The cases examined here look only at federal laws or regulations and do not examine state laws or regulations.
The two cases prepared—the No Sunset case and the Extended Policies case—incorporate all the assumptions from the AEO2013 Reference case, except as identified below. Changes from the Reference case assumptions include the following.
No Sunset case
Tax credits for renewable energy sources in the utility, industrial, and buildings sectors, or for energy-efficient equipment in the buildings sector, are assumed to be extended, including the following:
- The PTC of 2.2 cents per kilowatthour and the 30-percent investment tax credit (ITC) available for wind, geothermal, biomass, hydroelectric, and landfill gas resources, assumed in the Reference case to expire at the end of 2012 for wind and 2013 for the other eligible resources, are extended indefinitely. On January 1, 2013, Congress passed a one-year extension of the PTC for wind and modified the qualification rules for all eligible technologies; these changes are not included in the AEO2013 Reference case, which was completed in December 2012, but they are discussed in "Effects of energy provisions in the American Taxpayer Relief Act of 2012".
- For solar power investments, a 30-percent ITC that is scheduled to revert to a 10-percent credit in 2016 is, instead, assumed to be extended indefinitely at 30 percent.
- In the buildings sector, personal tax credits for the purchase of renewable equipment, including photovoltaics (PV), are assumed to be extended indefinitely, as opposed to ending in 2016 as prescribed by current law. The business ITCs for commercial-sector generation technologies and geothermal heat pumps are assumed to be extended indefinitely, as opposed to expiring in 2016; and the business ITC for solar systems is assumed to remain at 30 percent instead of reverting to 10 percent. On January 1, 2013, legislation was enacted to reinstate tax credits for energy-efficient homes and selected residential appliances. The tax credits that had expired on December 31, 2011, are now extended through December 31, 2013. This change is not included in the Reference case.
- In the industrial sector, the 10-percent ITC for combined heat and power (CHP) that ends in 2016 in the AEO2013 Reference case  is assumed to be preserved through 2040, the end of the projection period.
Extended Policies case
The Extended Policies case includes additional updates to federal equipment efficiency standards that were not considered in the Reference case or No Sunset case. Residential and commercial end-use technologies eligible for incentives in the No Sunset case are not subject to new standards. Other than those exceptions, the Extended Policies case adopts the same assumptions as the No Sunset case, plus the following:
- Federal equipment efficiency standards are assumed to be updated at periodic intervals, consistent with the provisions in existing law, at levels based on ENERGY STAR specifications or on the Federal Energy Management Program purchasing guidelines for federal agencies, as applicable. Standards are also introduced for products that currently are not subject to federal efficiency standards.
- Updated federal energy codes for residential and commercial buildings increase by 30 percent in 2020 compared to the 2006 International Energy Conservation Code in the residential sector and the American Society of Heating, Refrigerating and Air-Conditioning Engineers Building Energy Code 90.1-2004 in the commercial sector. Two subsequent rounds in 2023 and 2026 each add an assumed 5-percent incremental improvement to building energy codes. The equipment standards and building codes assumed for the Extended Policies case are meant to illustrate the potential effects of those policies on energy consumption for buildings. No cost-benefit analysis or evaluation of impacts on consumer welfare was completed in developing the assumptions. Likewise, no technical feasibility analysis was conducted, although standards were not allowed to exceed the "maximum technologically feasible" levels described in DOE's technical support documents.
- The AEO2013 Reference, No Sunset, and Extended Policies cases include both the attribute-based CAFE standards for light-duty vehicles (LDVs) in model year (MY) 2011 and the joint attribute-based CAFE and vehicle GHG emissions standards for MY 2012 to MY 2025. The Reference and No Sunset cases assume that the CAFE standards are then held constant at MY 2025 levels in subsequent model years, although the fuel economy of new LDVs continues to rise modestly over time. The Extended Policies case modifies the assumption in the Reference and No Sunset cases, assuming continued increases in CAFE standards after MY 2025. CAFE standards for new LDVs are assumed to increase by an annual average rate of 1.4 percent.
- In the industrial sector, the ITC for CHP is extended to cover all properties with CHP, no matter what the system size (instead of being limited to properties with systems smaller than 50 megawatts as in the Reference case ), which may include multiple units. Also, the ITC is modified to increase the eligible CHP unit cap to 25 megawatts from 15 megawatts. These extensions are consistent with previously proposed legislation.
The changes made to the Reference case assumptions in the No Sunset and Extended Policies cases generally lead to lower estimates for overall energy consumption, increased use of renewable fuels particularly for electricity generation and reduced energy-related carbon dioxide (CO2) emissions. Because the Extended Policies case includes most of the assumptions in the No Sunset case but adds others, the effects of the Extended Policies case tend to be greater than those in the No Sunset case—but not in all cases, as discussed below. Although these cases show lower energy prices, because the tax credits and end-use efficiency standards lead to lower energy demand and reduce the costs of renewable technologies, appliance purchase costs are also affected. In addition, the government receives lower tax revenues as consumers and businesses take advantage of the tax credits.
Total energy consumption in the No Sunset case is close to the level in the Reference case (Figure 13). Improvements in energy efficiency lead to reduced consumption in this case, but somewhat lower energy prices lead to relatively higher levels of consumption, partially offsetting the impact of improved efficiency. In 2040, total energy consumption in the Extended Policies case is 3.8 percent below the Reference case projection.
Buildings energy consumption
Renewable distributed generation (DG) technologies (PV systems and small wind turbines) provide much of the buildings-related energy savings in the No Sunset case. Extended tax credits in the No Sunset case spur increased adoption of renewable DG, leading to 61 billion kilowatthours of onsite electricity generation from DG systems in 2025, compared with 28 billion kilowatthours in the Reference case. Continued availability of the tax credits results in 137 billion kilowatthours of onsite electricity generation in 2040 in the No Sunset case—more than three times the amount of onsite electricity generated in 2040 in the Reference case. Similar adoption of renewable DG occurs in the Extended Policies case. With the additional efficiency gains from assumed future standards and more stringent building codes, delivered energy consumption for buildings is 3.9 percent (0.8 quadrillion British thermal units [Btu]) lower in 2025 and 8.0 percent (1.7 quadrillion Btu) lower in 2040 in the Extended Policies case than in the Reference case. The reduction in 2040 is more than seven times as large as the 1.1-percent (0.2 quadrillion Btu) reduction in the No Sunset case.
Electricity use shows the largest reduction in the two alternative cases compared to the Reference case. Building electricity consumption is 1.3 percent and 5.8 percent lower, respectively, in the No Sunset and Extended Policies cases in 2025 and 2.1 percent and 8.7 percent lower, respectively, in 2040 than in the Reference case, as onsite generation continues to increase and updated standards affect a greater share of the equipment stock in the Extended Policies case. Space heating and cooling are affected by the assumed standards and building codes, leading to significant savings in energy consumption for heating and cooling in the Extended Policies case. In 2040, delivered energy use for space heating in buildings is 9.6 percent lower, and energy use for space cooling is 20.3 percent lower, in the Extended Policies case than in the Reference case. In addition to improved standards and codes, extended tax credits for PV prompt increased adoption, offsetting some of the costs for purchased electricity for cooling. New standards for televisions and for personal computers and related equipment in the Extended Policies case lead to savings of 28.3 percent and 31.8 percent, respectively, in residential electricity use for this equipment in 2040 relative to the Reference case. Residential and commercial natural gas use declines from 8.1 quadrillion Btu in 2011 to 7.8 quadrillion Btu in 2025 and 7.2 quadrillion Btu in 2040 in the Extended Policies case, representing a 2.2-percent reduction in 2025 and a 8.5-percent reduction in 2040 relative to the Reference case.
Industrial energy consumption
The No Sunset case modifies the Reference case assumptions by extending the existing ITC for industrial CHP through 2040. The Extended Policies case starts from the No Sunset case and expands the credit to include industrial CHP systems of all sizes and raises the maximum credit that can be claimed from 15 megawatts of installed capacity to 25 megawatts. The changes result in 1.6 gigawatts of additional industrial CHP capacity in the No Sunset case compared with the Reference case in 2025 and 3.5 gigawatts of additional capacity in 2040. From 2025 through 2040, more CHP capacity is installed in the No Sunset case than in the Extended Policy case. CHP capacity is 0.3 gigawatts higher in the No Sunset Case than in the Extended Policies Case in 2025 and 1.2 gigawatts higher in 2040. Although the Extended Policies case includes a higher tax benefit for CHP than the No Sunset case, which by itself provides greater incentive to build CHP capacity, electricity prices are lower in the Extended Policies case than in the No Sunset case starting around 2020, and the difference increases over time. Lower electricity prices, all else equal, reduce the economic attractiveness of CHP. Also, the median size of industrial CHP units size is 10 megawatts , and many CHP systems are well within the 50-megawatt total system size, which means that relaxing the size constraint is not as strong an incentive for investment as is allowing the current tax credit for new CHP investments to continue after 2016.
Natural gas consumption averages 9.7 quadrillion Btu per year in the industrial sector from 2011 to 2040 in the No Sunset case—about 0.1 quadrillion Btu, or 0.9 percent, above the level in the Reference case. Over the course of the projection, the difference in natural gas consumption between the No Sunset case and the Reference case is small but increases steadily. In 2025, natural gas consumption in the No Sunset case is approximately 0.1 quadrillion Btu higher than in the Reference Case, and in 2040 it is 0.2 quadrillion Btu higher. Natural gas consumption in the Extended Policies case is virtually the same as in the No Sunset case through 2030. After 2030, refinery use of natural gas stabilizes in the Extended Policies case as continued increases in CAFE standards reduce demand for petroleum products.
Transportation energy consumption
The Extended Policies case differs from the Reference and No Sunset cases in assuming that the CAFE standards recently finalized by EPA and NHTSA for MY 2017 through 2025 (which call for a 4.1-percent annual average increase in fuel economy for new LDVs) are extended through 2040 with an assumed average annual increase of 1.4 percent. Sales of vehicles that do not rely solely on a gasoline internal combustion engines for both motive and accessory power (including those that use diesel, alternative fuels, or hybrid electric systems) play a substantial role in meeting the higher fuel economy standards after 2025, growing to almost 72 percent of new LDV sales in 2040, compared with about 49 percent in the Reference case.
LDV energy consumption declines in the Reference case from 16.1 quadrillion Btu (8.7 million barrels per day) in 2011 to 14.0 quadrillion Btu (7.7 million barrels per day) in 2025 as a result of the increase in CAFE standards. Extension of the increases in CAFE standards in the Extended Policies case further reduces LDV energy consumption to 11.9 quadrillion Btu (6.5 million barrels per day) in 2040, or about 8 percent lower than in the Reference case. Petroleum and other liquid fuels consumption in the transportation sector is virtually identical through 2025 in the Reference and Extended Policies cases but declines in the Extended Policies case from 13.3 million barrels per day in 2025 to 12.3 million barrels per day in 2040, as compared with 13.0 million barrels per day in 2040 in the Reference case (Figure 14).
Renewable electricity generation
The extension of tax credits for renewables through 2040 would, over the long run, lead to more rapid growth in renewable generation than in the Reference case. When the renewable tax credits are extended without extending energy efficiency standards, as assumed in the No Sunset case, there is a significant increase in renewable generation in 2040 compared to the Reference case (Figure 15). Extending both renewable tax credits and energy efficiency standards in the Extended Policies case results in more modest growth in renewable generation, because renewable generation is a significant source of new generation to meet load growth, and enhanced energy efficiency standards tend to reduce overall electricity consumption and the need for new generation resources.
The AEO2013 Reference case does not reflect the provisions of the American Taxpayer Relief Act of 2012 (P.L. 112-240) passed on January 1, 2013 , which extends the PTCs for renewable generation beyond what is included in the AEO2013 Reference case. While this legislation was completed too late for inclusion in the Reference case, EIA did complete an alternative case that examined key energy-related provisions of that legislation, the most important of which is the extension of the PTC for renewable generation. A brief summary of those results is presented in the box, "Effects of energy provisions in the American Taxpayer Relief Act of 2012."
Over the past 20 years, natural gas has been the go-to fuel for new electricity generation capacity. From 1990 to 2011, natural gas-fired plants accounted for 77 percent of all generating capacity additions, and many of the plants added were very efficient combined-cycle plants. However, with slow growth in electricity demand and spikes in natural gas prices between 2005 and 2008, much of the added capacity was used infrequently. Since 2009 natural gas prices have been relatively low, making efficient natural gas-fired combined-cycle plants increasingly competitive to operate in comparison with existing coal-fired plants, particularly in the Southeast and other regions where they have been used to meet demand formerly served by coal-fired plants. In 2012, as natural gas prices reached historic lows, there were many months when natural gas displacement of coal-fired generation was widespread nationally.
In the AEO2013 Reference case, the competition between coal and natural gas in electricity generation is expected to continue in the near term, particularly in certain regions. However, because natural gas prices are projected to increase more rapidly than coal prices, existing coal plants gradually recapture some of the market lost in recent years. Natural gas-fired plants continue to be the favored source for new generating capacity over much of the projection period because of their relatively low costs and high efficiencies. The natural gas share of total electricity generation increases in the Reference case from 24 percent in 2011 to 30 percent in 2040. Coal remains the largest source of electricity generation, but its share of total electricity generation, which was 51 percent in 2003, declines from 42 percent in 2011 to 35 percent in 2040.
At any point, short-term competition between existing coal- and gas-fired generators—i.e., the decisions determining which generators will be dispatched to generate electricity—depends largely on the relative operating costs for each type of generation, of which fuel costs are a major portion. A second aspect of competition occurs over the longer term, as developers choose which fuels and technologies to use for new capacity builds and whether or not to make mandated or optional upgrades to existing plants. The natural gas or coal share of total generation depends both on the available capacity of each fuel type (affected by the latter type of competition) and on how intensively the capacity is operated.
There is significant uncertainty about future coal and natural gas prices, as well as about future growth in electricity demand, which determines the need for new generating capacity. In AEO2013, alternative cases with higher and lower coal and natural gas prices and variations in the rate of electricity demand growth are used to examine the potential impacts of those uncertainties. The alternative cases illustrate the influence of fuel prices and demand on dispatch and capacity planning decisions.
Recent history of price-based competition
In recent years, natural gas has come into dispatch-level competition with coal as the cost of operating natural gas-fired generators has neared the cost of operating coal-fired generators. A number of factors led to the growing competition, including:
- A build-out of efficient combined-cycle capacity during the early 2000s, which in general was used infrequently until recently
- Expansion of the natural gas pipeline network, reducing uncertainty about the availability of natural gas
- Gains in natural gas production from domestic shale formations that have contributed to falling natural gas prices
- Rising coal prices.
Until mid-2008, coal-fired generators were cheaper to operate than natural gas-fired generators in most applications and regions. Competition between available natural gas combined-cycle generators (NGCC) and generators burning eastern (Appalachian) and imported coal began in southeastern electric markets in 2009. Rough parity between NGCC and more expensive coal-fired plants continued until late 2011, when increased natural gas production led to a decline in the fuel price and, in the spring of 2012, a dramatic increase in competition between natural gas and even less expensive types of coal. With natural gas-fired generation increasing steadily, the natural gas share of U.S. electric power sector electricity generation was almost equal to the coal share for the first time in April 2012.
The following discussion focuses on the electric power sector, excluding other generation sources in the residential, commercial, and industrial end-use sectors. The industrial sector in particular may also respond to changes in coal and natural gas fuel prices by varying their level of development, but industrial users typically do not have the option to choose between the fuels as in the power sector, and there are fewer opportunities for direct competition between coal and natural gas for electricity generation.
Outlook for fuel competition in power generation.
The difference between average annual prices per million Btu for natural gas and coal delivered to U.S. electric power plants narrowed substantially in 2012, so that the fuel costs of generating power from NGCC units and coal steam turbines per megawatthour were essentially equal on a national average basis (Figure 26), given that combined-cycle plants are much more efficient than coal-fired plants. When the ratio of natural gas prices to coal prices is approximately 1.5 or lower, a typical natural gas-fired combined-cycle plant has lower generating costs than a typical coal-fired plant. In the Reference case projection, natural gas plants begin to lose competitive advantage over time, as natural gas prices increase relative to coal prices. Because fuel prices vary by region, and because there is also considerable variation in efficiencies across the existing fleet of both coal-fired and combined-cycle plants, dispatch-level competition between coal and natural gas continues.
In the Reference case, coal-fired generation increases from 2012 levels and recaptures some of the power generation market lost to natural gas in recent years. The extent of that recovery varies significantly, however, depending on assumptions about the relative prices of the two fuels. The following alternative cases, which assume higher or lower availability or prices for natural gas and coal than in the Reference case are used to examine the likely effects of different market conditions:
- The Low Oil and Gas Resource case assumes that the EUR per shale gas, tight gas, or tight oil well is 50 percent lower than in the Reference Case. In 2040, delivered natural gas prices to the electric power sector are 26 percent higher than in the Reference case.
- The High Oil and Gas Resource case assumes that the EUR per shale gas, tight gas, or tight oil well is 100 percent higher than in the Reference case, and the maximum well spacing for shale gas, tight gas, and tight oil plays is assumed to be 40 acres. This case also assumes that the EUR for wells in the Alaska offshore and the Federal Gulf of Mexico is 50 percent higher than in the Reference case, that there is development of kerogen resources in the lower 48 states, and that the schedule for development of Alaskan resources is accelerated. In 2040, delivered natural gas prices are 39 percent lower than projected in the Reference case.
- The High Coal Cost case assumes lower mine productivity and higher costs for labor, mine equipment, and coal transportation, which ultimately result in higher coal prices for electric power plants. In 2040, the delivered coal price is 77 percent higher than in the Reference case.
- The Low Coal Cost case assumes higher mining productivity and lower costs for labor, mine equipment, and coal transportation, leading to lower coal prices for electric power plants. In 2040, the delivered coal price is 41 percent lower than in the Reference case.
Figure 27 compares the ratio of average per-megawatthour fuel costs for NGCC plants and coal steam turbines at the national level across the cases. It illustrates the relative competitiveness of dispatching coal-fired steam turbines versus NGCC plants, including the differences in efficiency (heat rates) of the two types of generators. The ratio of natural gas to coal would be about 1.5 without considering the difference in efficiency. Higher coal prices or lower natural gas prices move the ratio closer to the line of competitive parity, where NGCC plants have more opportunities to displace coal-fired generators. In contrast, when coal prices are much lower than in the Reference case, or natural gas prices are much higher, the ratio is higher, indicating less likelihood of dispatch-level competition between coal and natural gas. In both the High Oil and Gas Resource case and the High Coal Cost case, the average NGCC plant is close to parity with, or more economical than, the average coal-fired steam turbine.
Capacity by plant type
In all five cases, coal-fired generating capacity in 2025 (Figure 28) is below the 2011 total and remains lower through 2040 (Figure 29), as retirements outpace new additions of coal-fired capacity. Coal and natural gas prices are key factors in the decision to retire a power plant, along with environmental regulations and the demand for electricity. In the Low Oil and Gas Resource case and Low Coal Cost case, there are slightly fewer retirements than in the Reference case, as a higher fuel cost ratio for power generation is more favorable to coal-fired power plants. In the High Oil and Gas Resource case and High Coal Cost case, coal-fired plants are used less, and more coal-fired capacity is retired than in the Reference case. In the Reference case, 49 gigawatts of coal-fired capacity is retired from 2011 to 2040, compared with a range from 38 gigawatts to 73 gigawatts in the alternative cases. The interaction of fuel prices and environmental rules is a key factor in coal plant retirements. AEO2013 assumes that all coal-fired plants have flue gas desulfurization equipment (scrubbers) or dry sorbent injection systems installed by 2016 to comply with the Mercury and Air Toxics Standards. Higher coal prices, lower wholesale electricity prices (often tied to natural gas prices), and reduced use may make investment in such equipment uneconomical in some cases, resulting in plant retirements.
In all the cases examined, new additions of coal-fired capacity from 2012 to 2040 total less than 15 gigawatts. For new builds, natural gas and renewables generally are more competitive than coal, and concerns surrounding potential future GHG legislation also dampen interest in new coal-fired capacity . New capacity additions are not the most important factor in the competition between coal and natural gas for electricity generation. There is also significant dispatch-level competition in determining how intensively to operate existing coal-fired power plants versus new and existing natural gas-fired plants.
New natural gas-fired capacity, including combined-cycle units and combustion turbines, comprises the majority of new additions in the Reference case. The total capacity of all U.S. natural gas-fired power plants grows in each of the cases, but the levels vary depending on the relative fuel prices projected. Across the resource cases, NGCC capacity in 2025 ranges between 227 and 243 gigawatts, and in 2040 it ranges between 262 and 344 gigawatts, reflecting the impacts of fuel prices on the operating costs of new capacity.
New nuclear capacity and renewable capacity are affected primarily by changes in natural gas prices, with substantial growth in both technologies occurring in the Low Oil and Gas Resource case. Most of the increase occurs after 2025, when delivered natural gas prices in that case exceed $7 per million Btu, and the costs of the nuclear and renewable technologies have fallen from current levels. In this case, higher natural gas prices reduce the competitiveness of natural gas as a fuel for new capacity builds, leading to higher prices and lower demand for electricity. Total generating capacity is similar in the Reference case and the Low Oil and Gas Resource case, but the large amount of renewable capacity built in the Low Oil and Gas Resource case—particularly wind and solar—does not contribute as much generation as NGCC capacity toward meeting either electricity demand or reserve margin requirements.
Generation by fuel
In the Reference case, coal-fired generation increases by an average of 0.2 percent per year from 2011 through 2040. Even though less capacity is available in 2040 than in 2011, the average capacity utilization of coal-fired generators increases over time. In recent years, as natural gas prices have fallen and natural gas-fired generators have displaced coal in the dispatch order, the average capacity factor for coal-fired plants has declined substantially. The coal fleet maintained an average annual capacity factor above 70 percent from 2002 through 2008, but the capacity factor has declined since then, falling to about 57 percent in 2012. As natural gas prices increase in the AEO2013 Reference case, the utilization rate of coal-fired generators returns to previous historical levels and continues to rise, to an average of around 74 percent in 2025 and 78 percent in 2040. Across the alternative cases, coal-fired generation varies slightly in 2025 (Figure 30) and 2040 (Figure 31) as a result of differences in plant retirements and slight differences in utilization rates. The capacity factor for coal-fired power plants in 2040 ranges from 69 percent in the High Oil and Gas Resource case to 81 percent in the Low Oil and Gas Resource case.
Natural gas-fired generation varies more widely across the alternative cases, as a result of changes in the utilization of NGCC capacity, as well as the overall amount of combined-cycle capacity available. In recent years, the utilization rate for NGCC plants has increased, while the utilization rate for coal-fired steam turbines has declined. Capacity factors for the two technologies were about equal at approximately 57 percent in 2012. As natural gas prices rise in the Reference case, the average capacity factor for combined-cycle plants drops below 50 percent in the near term and remains between 48 percent and 54 percent over the remainder of projection period. In the High Oil and Gas Resource case, where combined-cycle generation is more competitive with existing coal-fired generation and the largest amount of new combined-cycle capacity is added, the average capacity factor for combined-cycle plants rises to 70 percent in the middle years of the projection period and remains about 63 percent through the remainder of the projection period. In the Low Oil and Gas Resource case, generation from combined-cycle plants is 37 percent lower in 2040 than in the Reference case, and the capacity factor for NGCC plants declines from around 45 percent in the mid term to 36 percent in 2040. Natural gas-fired generation in the Low Oil and Gas Resource case is replaced primarily with generation from new nuclear and renewable power plants. Similar fluctuations in natural gas-fired generation, but smaller in magnitude, are also seen across the coal cost cases.
The coal and natural gas shares of total electricity generation vary widely across the alternative cases. The coal share of total generation varies from 30 percent to 43 percent in 2025 and from 28 percent to 40 percent in 2040. The natural gas share varies from 22 percent to 36 percent in 2025 and from 18 percent to 42 percent in 2040. In the High Oil and Gas Resource case, natural gas becomes the dominant generation fuel after 2015, and its share of total generation is 42 percent in 2040 (Figure 32).
Competition in the southeastern United States
While examining the national-level results is useful, the competition between coal and natural gas is best examined in a region that has significant amounts of both coal-fired and natural gas-fired capacity, such as the southeastern United States. In the southeastern subregion of the SERC Reliability Corporation (EMM Region 14), the ratio of average fuel costs for NGCC plants to average fuel costs for coal-fired steam turbines in both the High Coal Cost case and the High Oil and Gas Resource case is below that in the Reference case (Figure 33). In this region, which has a particularly efficient fleet of NGCC plants, the fuel cost ratios in both the High Coal Cost case and the High Oil and Gas Resource case remain near or below competitive parity for the majority of the projection period, indicating continued strong competition in the region. While average coal steam turbine heat rates remain largely static over the projection period, the average NGCC heat rates in this region drop appreciably by 2040, and are among the lowest in the nation.
The delivered cost of coal in the region is somewhat higher than in many other regions. Central Appalachian and Illinois Basin coals must be transported by rail or barge to the Southeast, and coal from the Powder River Basin must travel great distances by rail. The region also uses some imported coal, typically along the Gulf Coast, which tends to be more expensive.
In the High Oil and Gas Resource case, retirements of coal-fired generators in this region total 8 gigawatts in 2016 (5 gigawatts higher than in the Reference case) and remain at that level through 2040. Lower fuel prices for new natural gas-fired capacity, along with requirements to install environmental control equipment on existing coal-fired capacity, leads to additional retirements of coal-fired plants. As a result, the coal share of total capacity in the region drops from 39 percent in 2011 to 23 percent in 2040 in the High Oil and Gas Resource case, and the NGCC share rises from 24 percent in 2011 to 40 percent in 2040, when it accounts for the largest share of total generating capacity.
The capacity factors of coal-fired and NGCC power plants also vary across the cases, resulting in a significant shift in the shares of generation by fuel. The natural gas share of total electric power generation in the SERC southeast subregion grows from 31 percent in 2011 to 36 percent in 2040 in the Reference case, as compared with 56 percent in 2040 in the High Oil and Gas Resource case. Conversely, the coal share drops from 47 percent in 2011 to 40 percent in 2040 in the Reference case, compared with 20 percent in 2040 in the High Oil and Gas Resource case.
Competition in the Midwest
In the western portion of the ReliabilityFirst Corporation (RFC) region (EMM Region 11), which covers Ohio, Indiana, and West Virginia as well as portions of neighboring states, the ratio of the average fuel cost for natural gas-fired combined-cycle plants to the average fuel cost for coal-fired steam turbines approaches parity in the High Coal Cost case and the High Oil and Gas Resource case (Figure 34). The RFC west subregion is more heavily dependent on coal, with coal-fired capacity accounting for 58 percent of the total in 2011. The coal share of total capacity falls to 48 percent in 2040 in the Reference case with the retirement of nearly 15 gigawatts of coal-fired capacity from 2011 to 2017. NGCC capacity, which represented only 7 percent of the region's total generating capacity in 2011, accounts for 11 percent of the total in 2040 in the Reference case.
In the High Coal Cost case, only a limited amount of shifting from coal to natural gas occurs in this region, which has a large amount of existing coal-fired capacity and access to multiple sources of coal, including western basins as well as the Illinois and Appalachian basins. Higher transportation rates in this case deter the use of Western coal in favor of more locally sourced Interior and Appalachian coal. The ability to switch coal sources to moderate fuel expenditures reduces the economic incentive to build new NGCC plants, even with coal prices that are higher than those in the Reference case. The NGCC share of the region's total capacity does increase in the High Oil and Gas Resource case relative to the Reference case, to 16 percent in 2040. In all the cases, however, coal-fired generating capacity makes up more than 42 percent of the total in 2040.
The different capacity factors of coal-fired steam turbines and NGCC capacity contribute to a shift in the generation fuel shares, but the lower levels of natural gas-fired capacity in the region limit the impacts relative to those seen in the Southeast. The natural gas share of total generation in the region grows from 6 percent in 2011 to 8 percent in 2040 in the Reference case, 10 percent in 2040 in the High Coal Cost case, and 18 percent in 2040 the High Oil and Gas Resource case. Coal's share of the region's electric power sector generation declines from 66 percent in 2011 to 64 percent in 2040 in the Reference case, and to 54 percent in both the High Coal Cost case and the High Oil and Gas Resource case. In the High Coal Cost case, much of the coal-fired generation is replaced with biomass co-firing rather than natural gas, because without the lower natural gas prices in the High Oil and Gas Resource case, it is more economical to use biomass in existing coal-fired units than to build and operate new natural gas-fired generators.
Other factors affecting competition
In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region, even in the AEO2013 alternative fuel price cases. New England is located far from coal sources, and a regional cap on GHG emissions is in place, which makes investment in new coal-fired capacity unlikely. In the southeastern United States, however, there is more balance between natural gas-fired and coal-fired generating resources.
Further limitations not discussed above include:
- Start-up and shutdown costs. In general, combined-cycle units are considered to be more flexible than steam turbines. They can ramp their output up and down more easily, and their start-up and shutdown procedures involve less time and expense. However, plants that are operated more flexibly (i.e., ramping up and down and cycling on and off) often have higher maintenance requirements and higher maintenance costs.
- Emission rates and allowance costs. Another component of operating costs not mentioned above is the cost of buying emissions allowances for plants covered by the Acid Rain Program and Clean Air Interstate Rule. In recent years, allowance prices have dropped to levels that make them essentially negligible, although for many years they were a significant component of operating costs.
- Transmission constraints on the electricity grid and other reliability requirements. Certain plants, often referred to as reliability must-run plants, are located in geographic areas where they are required to operate whenever they are available. In other cases, transmission limitations on the grid at any given time may determine maximum output levels for some plants.
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 . 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 , 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.
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 . 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 . 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 . 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 . EPACT2005 also provided a PTC of $18 per megawatt hour for electricity produced during the first 8 years of plant operation . 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 .
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  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 , 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 .
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 . 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 .
In March 2012, DOE announced its intention to provide $450 million in funding to assist in the initial development of SMR technology . 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 , 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.
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.
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.
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 . 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 . 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.
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 , 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.
Electricity from Legislation and Regulations
On August 21, 2012, the United States Court of Appeals for the District of Columbia Circuit announced its intent to vacate CSAPR, which it had stayed from going into effect earlier in 2012. CSAPR was to replace CAIR, which was in effect, by establishing emissions caps (levels) for sulfur dioxide (SO2) and nitrogen oxides (NOX) emissions from power plants in the eastern half of the United States. As a result of the court's action, the regulation of SO2 and NOX emissions will continue to be administered under CAIR pending the promulgation of a valid replacement. AEO2013 assumes that CAIR remains a binding regulation through 2040.
CAIR covers all fossil-fueled power plant units with nameplate capacity greater than 25 megawatts in 27 eastern states and the District of Columbia (Figure 11). Twenty-two states and the District of Columbia fall under the caps for both annual emissions of SO2 and NOX and ozone season NOX. Three states are controlled for only ozone season NOX , and two states are controlled for only annual SO2 and NOX emissions. The caps went into effect for NOX in 2009 and for SO2 in 2010. Both caps are scheduled to be tightened again in 2015. AEO2013 considered how the power sector would use the emissions allowance trading that EPA set up to lower compliance costs, including capturing the interplay of the SO2 program for acid rain under the Clean Air Act Amendments Title IV and the CAIR program that uses the same allowances.
Although CSAPR shared some basic similarities with CAIR, there are key differences between the two programs. Generally, CSAPR had greater limitations on trading to ensure that emissions reductions would occur in all states; lower emissions caps; and more rapid phasing in of tighter emissions caps. CSAPR also did not allow carryover of banked allowances from the Acid Rain SO2 and NOX Budget programs. Each program was aimed at substantial reductions of power sector SO2 and NOX emissions.
AEO2013 represents the limits on SO2 and NOX emissions trading as specified by CAIR. The National Energy Modeling System (NEMS) includes the representation of emissions for both the CAIR and non-CAIR regions. In NEMS, power plants in both regions are required to submit allowances to account for their emissions as if covered by the rule. NEMS allows for power plants in the CAIR regions to trade SO2 allowances with those plants in the non-CAIR region, but the SO2 allowances are valued differently for each region. NEMS also allows for the banking of SO2 and NOX allowances consistent with CAIR's provisions.
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 . 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  included five findings:
- Spent nuclear fuel can be disposed of safely in a mined geologic repository.
- A mined geologic repository will be available when needed for disposal of spent nuclear fuel.
- Until a mined geologic repository is available, spent nuclear fuel can be safely managed.
- Spent nuclear fuel can be safely stored at reactors for 30 years without significant environmental impacts.
- Storage will be made available for spent nuclear fuel onsite or offsite, if required.
The NRC issued an order in August 2012 that suspended actions related to issuance of operating licenses and license renewals . 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 .
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" . 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 . 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 . 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) . 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 .
To the extent possible, AEO2013 incorporates the impacts of state laws requiring the addition of renewable generation or capacity by utilities doing business in the states. Currently, 30 states and the District of Columbia have an enforceable renewable portfolio standard (RPS) or similar law (Table 3). Under such standards, each state determines its own levels of renewable generation, eligible technologies , and noncompliance penalties. AEO2013 includes the impacts of all RPS laws in effect at the end of 2012 (with the exception of Alaska and Hawaii, because NEMS provides electricity market projections for the contiguous lower 48 states only). However, the projections do not include policies with either voluntary goals or targets that can be substantially satisfied with nonrenewable resources. In addition, NEMS does not treat fuel-specific provisions—such as those for solar and offshore wind energy—as distinct targets. Where applicable, such distinct targets (sometimes referred to as "tiers," "set-asides," or "carve-outs") may be subsumed into the broader targets, or they may not be included in the modeling because they could be met with existing capacity and/or projected growth based on modeled economic and policy factors.
In the AEO2013 Reference case, states generally are projected to meet their ultimate RPS targets. The RPS compliance constraints in most regions are approximated, because NEMS is not a state-level model, and each state generally represents only a portion of one of the NEMS electricity regions. Compliance costs in each region are tracked, and the projection for total renewable generation is checked for consistency with any state-level cost-control provisions, such as caps on renewable credit prices, limits on state compliance funding, or impacts on consumer electricity prices. In general, EIA has confirmed the states' requirements through original documentation, although the Database of State Incentives for Renewables & Efficiency was also used to support those efforts .
No new RPS programs were enacted over the past year; however, some states with existing RPS programs made modifications in 2012, as discussed below. The aggregate RPS requirement for the various state programs, as modeled in AEO2013, is shown in Figure 12. In 2025 the targets account for about 10 percent of U.S. electricity sales. The requirement is derived from the legal targets and projected sales and does not account for any of the discretionary or nondiscretionary waivers or limits on compliance found in most state RPS programs.
At present, most states are meeting or exceeding their required levels of renewable generation based on qualified generation . A number of factors have helped to create an environment favorable for RPS compliance, including a surge of new RPS-qualified generation capacity timed to take advantage of federal incentives that either have expired or were scheduled to expire; significant reductions in the cost of renewable technologies like wind and solar; and generally reduced growth (or, in some cases, even contraction) of electricity sales. In addition to the availability of federal tax credits, which historically have gone through a cycle of expiration and renewal, renewable energy projects were given access to other options for federal support, including cash grants (also known as Section 1603 grants) and loan guarantees. The short-term availability of federal incentives has helped to make renewable capacity attractive to investors and helped utilities meet state requirements or potential future load growth in advance (that is, build ahead of time to take advantage of the federal incentives). The attractiveness of renewable projects to investors has also been supported by declining equipment costs for wind turbines and solar photovoltaic systems, as well as by improvements in the performance of those technologies. The declines in technology cost are, in themselves, the result of a complex set of interactions of policy, market, and engineering factors. Finally, most state RPS programs have targets that are tied to retail electricity sales; and with relatively slow growth in electricity sales in most parts of the country, the renewable generation that has entered service recently has gone further toward meeting the proportionally lower targets for absolute amounts of energy (that is, for kilowatthours of energy, as opposed to energy as a percent of sales).
EIA projects that, overall, RPS-qualified generation will continue to meet or exceed aggregate targets for state RPS programs through 2040, as shown in Figure 12. Through the next decade, the surplus qualifying generation will decline gradually, as little additional qualifying capacity is added, allowing the targets to catch up with supply. By the end of the projection horizon, however, the surplus widens substantially as renewable generation technologies become increasingly competitive with conventional generation sources. It should be noted that the aggregate targets and qualifying generation shown in Figure 12 may mask significant regional variation, with some regions producing excess qualifying generation and others producing just enough to meet the requirement or even needing to import generation from adjoining regions to meet state targets. Furthermore, just because there is, in aggregate, more qualifying generation than is needed to meet the targets, this does not necessarily imply that projected generation would be the same without state RPS policies. State RPS policies may encourage investment in places where it otherwise would not occur, or would not occur in the amounts projected, even as other parts of the country see substantial growth above state targets, or even in their absence. It does, however, suggest that state RPS programs will not be the sole reason for future growth in renewable generation.
Recent RPS modifications
A number of states modified their RPS programs in 2012, either through regulatory proceedings or through legislative action. These changes are reflected in Table 3. The changes affect some aspects of the laws and implementing regulations, but they do not have substantive effects on the representation of the RPS programs in AEO2013. Key changes include:
California Assembly Bill 2196, which establishes requirements for certain biomass-based generation resources, requires that biomass-derived gas be produced on site or sourced from a common carrier pipeline that operates within the state. It also sets additional requirements related to the in-service date of a common carrier source and the ability to claim certain environmental benefits from the use of such sources.
The state enacted a series of bills that accelerate the solar-specific compliance schedule (while leaving the aggregate RPS target unchanged) and expand the tier 1 requirement category to include thermal output from certain animal waste and ground-source heat pumps.
The Department of Energy Resources issued final rules regarding the use of certain biomass resources to meet the RPS standard. Biomass facilities must meet certain conditions with regard to conversion technology and feedstock sourcing to be eligible for use in meeting the standard.
Senate Bill 218 allows certain thermal resources, including heat derived from qualified solar, geothermal, and biomass sources, to meet renewable energy targets. It also allows electricity produced from the cofiring of biomass in certain existing coal plants to meet the requirements. The bill also adjusts the total renewable energy target upward by 1 percentage point, to 24.8 percent by 2025.
Senate Bill 1925 changed the compliance schedule for the solar component of the RPS. The revised law is implemented with a solar target of 3.47 percent of sales by 2021.
The legislature passed a set of laws that allow certain types of cogeneration facilities to qualify in meeting the RPS.
Electricity from Comparison with other projections
Table 11 compares summary results from the AEO2013 Reference case with projections from EVA, IHSGI, INFORUM, ICF, and the National Renewable Energy Laboratory (NREL). In 2025, total electricity sales range from a low of 4,095 billion kilowatthours (INFORUM) to a high of 4,712 billion kilowatthours (IHSGI) . The AEO2013 Reference case projects 4,140 billion kilowatthours of total electricity sales in 2025, EVA projects 4,311 billion kilowatthours in 2025, and NREL projects 4,487 billion kilowatthours in 2026. In comparison with the other projections, IHSGI shows higher sales across all sectors in 2025, with the exception of the commercial sector (1,709 billion kilowatthours), where the EVA projection of 1,824 billion kilowatthours is 115 billion kilowatthours higher. The higher total in the commercial sector counterbalances EVA's lower projection of 736 billion kilowatthours for the industrial sector, compared with 1,186 billion kilowatthours in the AEO2013 Reference case, 1,246 billion kilowatthours in the IHSGI projection, and 1,033 billion kilowatthours in the INFORUM projection.
Total electricity sales in 2035 in the IHSGI projection (5,316 billion kilowatthours) are higher than in the others: 4,406 billion kilowatthours in the INFORUM projection, 4,421 billion kilowatthours in the AEO2013 Reference case, 4,824 billion kilowatthours (in 2036) in the NREL projection, and 4,923 billion kilowatthours in the EVA projection. EVA projects the highest level of electricity sales in both the residential and commercial sectors in 2035 but a lower level of industrial sales in comparison with the other projections. Electricity sales in the industrial sector in the IHSGI projection are 1,332 billion kilowatthours in 2035, as compared with 1,142 billion kilowatthours in the AEO2013 Reference case, 978 billion kilowatthours in the INFORUM projection, and only 515 billion kilowatthours in the EVA projection. Total electricity sales in 2040 are again led by the IHSGI projection, with 5,602 billion kilowatthours, followed by 5,238 billion kilowatthours in the EVA projection, 4,608 billion kilowatthours in the AEO2013 Reference case, and 4,940 billion kilowatthours in the NREL projection.
IHSGI, INFORUM, and the AEO2013 Reference case provide projections for average electricity prices by sector for 2025 and 2035. NREL provides a U.S. average electricity price projection for 2026 and 2036, but not by sector. IHSGI, NREL, and the AEO2013 Reference case provide projections for average electricity prices in 2040. Average electricity prices in the AEO2013 Reference case are 9.5 cents per kilowatthour in 2025, 10.1 cents per kilowatthour in 2035, and 10.8 cents per kilowatthour in 2040. Average electricity prices in the INFORUM projection are 10.0 cents per kilowatthour in 2025 and 10.5 cents per kilowatthour in 2035 . IHSGI projects considerably higher average electricity prices than either the AEO2013 Reference case or INFORUM, at 11.2 cents per kilowatthour in 2025, 11.9 cents per kilowatthour in 2035, and 12.2 cents per kilowatthour in 2040. NREL projects overall average electricity prices of 10.4 cents per kilowatthour in 2026, 11.7 cents per kilowatthour in 2036, and 12.0 cents per kilowatthour in 2040 (the NREL prices were provided in 2009 dollars).
In all the projections, average electricity prices by sector follow patterns similar to changes in the weighted average electricity price across all sectors (including transportation services). The lowest prices by sector in 2025 are in the AEO2013 Reference case (11.6 cents per kilowatthour for the residential sector, 9.7 cents per kilowatthour for the commercial sector, and 6.5 cents per kilowatthour for the industrial sector). The highest average electricity prices by sector in 2025 are in the IHSGI projection (13.3 cents per kilowatthour for the residential sector, 11.6 cents per kilowatthour for the commercial sector, and 7.6 cents per kilowatthour for the industrial sector). The AEO2013 Reference case, IHSGI, and NREL reflect similar price patterns for 2035 (or 2036 for NREL) and 2040.
Total U.S. electricity generation plus imports in 2025 range from a low of 4,296 billion kilowatthours in the INFORUM projection to a high of 5,207 billion kilowatthours in the IHSGI projection. Within that range, the AEO2013 Reference case projects total generation of 4,612 billion kilowatthours. Coal continues to represent the largest share of generation in 2025 in the AEO2013 Reference case, which reports 1,727 billion kilowatthours from coal versus 1,252 billion kilowatthours from natural gas. By comparison, the natural gas share of total generation in the IHSGI projection in 2025 surpasses generation from coal by 126 billion kilowatthours, with 1,732 billion kilowatthours of generation from natural gas and 1,605 billion kilowatthours from coal. IHSGI projects 1,646 billion kilowatthours of electricity generation from both coal and natural gas in 2023, with the natural gas total exceeding that for coal in 2024 and beyond as a result of the assumed implementation of a carbon tax in the IHSGI projection. Conversely, coal continues to represent the largest share of generation in the AEO2013 Reference case in 2035—1,807 billion kilowatthours as compared with 1,519 billion kilowatthours from natural gas. The AEO2013 Reference case is based on current regulations and policies and does not assume a carbon tax. In 2035, the natural gas share of total generation in the IHSGI projection exceeds generation from coal by 808 billion kilowatthours. In the AEO2013 Reference case, coal continues to represent the largest share of generation in 2040 at 1,829 billion kilowatthours, compared with 1,582 billion kilowatthours from natural gas. In comparison, the natural gas share of total generation in 2040 in the IHSGI projection widens its lead over coal by 1,088 billion kilowatthours. In the EVA projection, coal is outpaced by natural gas as a share of total generation in 2040, with 2,330 billion kilowatthours from natural gas and 1,740 billion kilowatthours from coal .
Projections for electricity generation from U.S. nuclear power plants in 2025 range from a low of 794 billion kilowatthours (NREL, in 2026) to a high of 923 billion kilowatthours in the IHSGI projection. NREL projects a steady decline in nuclear generation, from 794 billion kilowatthours in 2025 to 510 billion kilowatthours in 2036 and 442 billion kilowatthours in 2040, due to significant plant retirements. For 2035, the AEO2013 Reference case projects a drop in nuclear generation from the 2025 level, to 875 billion kilowatthours, as a result of capacity retirements. In contrast, nuclear generation increases to 953 billion kilowatthours in 2035 in the IHSGI projection. The AEO2013 Reference case shows nuclear generation rebounding to 903 billion kilowatthours in 2040, as compared with 991 billion kilowatthours in the IHSGI projection.
Total generating capacity by fuel in 2025 (including combined heat and power [CHP]) is fairly similar across the projections, ranging from a low of 1,098 gigawatts in the AEO2013 Reference case to a high of 1,237 gigawatts in the IHSGI projection. IHSGI projects slightly more growth in total generating capacity due to what appears to be a much higher demand projection. Natural gas- and oil-fired capacity combined is projected to total 555 gigawatts in 2025 in the IHSGI projection, compared with 500 gigawatts in the AEO2013 Reference case and a maximum of 568 gigawatts in the EVA projection. In all the projections, the hydroelectric/other category includes generation from both hydroelectric and nonhydroelectric renewable resources. In all the projections, hydroelectric capacity remains essentially unchanged, with almost all growth attributable to nonhydroelectric renewable resources. Hydroelectric/other capacity is the highest in 2025 in the IHSGI outlook at 289 gigawatts, compared with 257 gigawatts in the NREL projection (for 2026), 234 gigawatts in the ICF projection, 210 gigawatts in the EVA projection, and 208 gigawatts in the AEO2013 Reference case.
Both the IHSGI and NREL projections reflect lower levels of coal-fired generating capacity in 2040, with 251 gigawatts projected by IHSGI and 224 gigawatts by NREL. In comparison, natural gas- and oil-fired capacity (again dominated by natural gas-fired generating capacity) and hydroelectric/other capacity (dominated by nonhydroeletric renewable capacity) are projected to increase from 2025 levels. IHSGI projects 722 gigawatts of natural gas- and oil-fired capacity and 396 gigawatts of hydroelectric/other capacity in 2040. NREL projects 691 gigawatts of natural gas- and oil-fired capacity and 322 gigawatts of hydroelectric/other capacity in 2040. The AEO2013 Reference case projects 632 gigawatts of natural gas- and oil-fired capacity and 270 gigawatts of hydroelectric/other capacity in 2040.
Cumulative capacity retirements from 2011 through 2025 range from 151 gigawatts in the EVA projection to 82 gigawatts in the AEO2013 Reference case. The majority of the retirements in the IHSGI, ICF, and AEO2013 Reference case projections from 2011 to 2025 are attributed to coal-fired capacity. In the EVA and ICF outlooks, 73 gigawatts of coal-fired capacity is retired from 2011 to 2025. Over the same period, 46 gigawatts of coal-fired capacity is retired in the IHSGI outlook and 49 gigawatts in the AEO2013 Reference case. The NREL projection assumes 33 gigawatts of coal-fired capacity retirements from 2011 to 2026. EVA projects 73 gigawatts of oil- and natural gas-fired capacity retirements between 2011 and 2025, as compared with the ICF, AEO2013 Reference case, and IHSGI projections, which range between 29 gigawatts and 36 gigawatts over the same period. NREL projects 69 gigawatts of oil- and natural gas-fired retirements through 2026. With the exception of EVA and ICF, all the capacity retirements greater than 1 gigawatt between 2011 and 2025 in the outlooks are attributed to coal, oil, and natural gas capacity. EVA and ICF both project 3 gigawatts of nuclear retirements by 2025, while EVA projects 2 gigawatts of hydroelectric/other capacity retirements for the same period.
Cumulative capacity retirements through 2035 range from a high of 161 gigawatts in the EVA projection to a low of 100 gigawatts in the AEO2013 Reference case. Coal-fired capacity represents a large portion of the cumulative retirements from 2011 to 2035, with ICF projecting 82 gigawatts, EVA 77 gigawatts, IHSGI 68 gigawatts, and the AEO2013 Reference case 49 gigawatts. The AEO2013 Reference case projects no retirements of coal-fired capacity from 2025 to 2035. Over the same period, EVA projects only 4 gigawatts, ICF 9 gigawatts, and IHSGI 22 gigawatts. Cumulative retirements of oil- and natural gas-fired capacity from 2011 to 2035 total 44 gigawatts in the AEO2013 Reference case and 74 gigawatts in the EVA projection. NREL projects cumulative totals of 70 gigawatts and 138 gigawatts of retirements for coal-fired capacity and for oil- and natural gas-fired capacity, respectively, from 2011 to 2036. EVA and the AEO2013 Reference case project cumulative nuclear capacity retirements of 9 gigawatts and 6 gigawatts, respectively, from 2011 to 2035, and IHSGI projects 21 gigawatts of cumulative nuclear retirements over the same period. NREL projects 35 gigawatts of cumulative nuclear retirements from 2011 to 2036.
Projections for natural gas consumption, production, imports, and prices differ significantly among the outlooks compared in Table 12. The variations result, in large part, from differences in underlying assumptions. For example, the AEO2013 Reference case assumes that current laws and regulations are unchanged through the projection period, whereas some of the other projections include assumptions about anticipated policy developments over the next 25 years. In particular, the AEO2013 Reference case does not incorporate any future changes in policy directed at carbon emissions or other environmental issues, whereas ExxonMobil and some of the other outlooks include explicit assumptions about policies aimed at reducing carbon emissions.
IHSGI and ICF project large increases in natural gas production and consumption over the projection period. IHSGI projects that, as production increases, prices will remain low and U.S. consumers, particularly in the electric power sector, will continue to benefit from an abundance of relatively inexpensive natural gas. In contrast, ICF projects that prices will rise at a more rapid rate than in the IHSGI projection. EVA projects growth in natural gas production, but at lower rates than IHSGI and ICF. Both EVA and ExxonMobil also project strong growth in natural gas consumption in the electric power sector through 2035. EVA differs from the others, however, by projecting strong growth in natural gas consumption despite a rise in natural gas prices to $8.00 per million Btu in 2035. Timing of the growth in consumption is somewhat different between the ExxonMobil projection and the other outlooks. ExxonMobil expects consumption to increase only through 2025, after which it remains relatively flat. The AEO2013 Reference case projects a smaller increase in natural gas consumption for electric power generation than in the other outlooks, with additional natural gas production allowing for a sharp increase in net exports, particularly as liquefied natural gas (LNG). The INFORUM projection shows a smaller rise in production and consumption of natural gas than in any of the other projections.
All the outlooks shown in Table 12 project increases in natural gas production from the 2011 production level of 23.0 trillion cubic feet. IHSGI projects the largest increase, to 36.1 trillion cubic feet in 2035—13.1 trillion cubic feet or 57 percent more than the 2011 levels—with most of the increase coming in the near term (9.3 trillion cubic feet from 2011 to 2025). An additional 1.5 trillion cubic feet of natural gas production is added from 2035 to 2040. In the ICF projection, natural gas production grows by 12.5 trillion cubic feet over the period from 2011, to 35.5 trillion cubic feet in 2035. More than one-half of the increase (6.5 trillion cubic feet) occurs before 2020. INFORUM projects the smallest increase in natural gas production, at only 4.9 trillion cubic feet from 2011 to the 2035 total of 27.9 trillion cubic feet.
The AEO2013 Reference case and EVA project more modest growth in natural gas production. In the AEO2013 Reference case and EVA projections, natural gas production grows to 31.4 trillion cubic feet in 2035, an increase of 8.4 trillion cubic feet from 2011 levels. The AEO2013 Reference case and EVA projections show slower growth in natural gas production from 2011 to 2025, at 5.6 trillion cubic feet and 6.9 trillion cubic feet, respectively. Although the AEO2013 Reference case shows the least aggressive near-term growth in natural gas production, it shows the strongest growth from 2025 to 2035 among the projections, with another increase of 1.8 trillion cubic feet from 2035 to 2040.
Differences among the projections for natural gas production generally coincide with differences in total natural gas consumption or net imports/exports. EVA projects positive growth in net imports throughout the projection period, driven by strong growth in natural gas consumption. Although the EVA projection shows significant growth in pipeline imports, it shows no growth in net LNG exports. In contrast, the IHSGI, ICF, and AEO2013 Reference case projections show net exports of natural gas starting on or before 2020. The AEO2013 Reference case projects the largest increase in net exports of natural gas, with net pipeline exports increasing alongside steady growth in net LNG exports. In the ICF projection, the United States becomes a net exporter of natural gas by 2020 but remains a net importer of pipeline through 2035. Combined net exports of natural gas grow to 0.7 trillion cubic feet in 2035 in the ICF projection, with all the growth accounted for by LNG exports, which increase by 1.5 trillion cubic feet from 2011 to 2035. IHSGI projects a U.S. shift from net importer to net exporter of natural gas after 2017, with net exports declining after 2024.
All the projections show total natural gas consumption growing throughout the projection periods, and most of them expect the largest increases in the electric power sector. IHSGI projects the greatest growth in natural gas consumption for electric power generation, driven by relatively low natural gas prices, followed by ExxonMobil and EVA, with somewhat higher projections for natural gas prices. The ICF projection shows less growth in natural gas consumption for electric power generation, despite lower natural gas prices, than in the EVA projection. In the AEO2013 Reference case and INFORUM projections, natural gas consumption for electric power generation is somewhat less than in the other outlooks. Some of that variation may be the result of differences in assumptions about potential fees on carbon emissions. For example, the ExxonMobil outlook assumes a tax on carbon emissions, whereas the AEO2013 Reference case does not.
Projections for natural gas consumption in the residential and commercial sectors are similar in the outlooks, with expected levels of natural gas use remaining relatively stable over time. The AEO2013 Reference case projects the lowest level of residential and commercial natural gas consumption, largely as a result of increases in equipment efficiencies, with projected consumption in those sectors falling by 0.1 trillion cubic feet from 2011 to 2040, to a level slightly below those projected by IHSGI and ICF. ExxonMobil projects a significant one-time decrease of 1.0 trillion cubic feet from 2020 to 2025.
The largest difference among the outlooks for natural gas consumption is in the industrial sector, where definitional differences can make accurate comparisons difficult. ExxonMobil and the AEO2013 Reference case both project increases in natural gas consumption in the industrial sector from 2011 to 2040 that are greater than 1.0 trillion cubic feet, with most of the growth in the AEO2013 Reference case occurring from 2015 to 2020. ICF projects the largest increase in industrial natural gas consumption, at 2.2 trillion cubic feet from 2011 to 2035, followed by EVA's projection of 1.8 trillion cubic feet over the same period. Although ExxonMobil projects a significant one-time decrease in industrial natural gas consumption—1.0 trillion cubic feet from 2025 to 2030—its projected level of industrial consumption in 2025, at 9.0 trillion cubic feet, is higher than in any of the other projections. Despite ExxonMobil's projected decrease in industrial natural gas consumption from 2025 to 2030, its projection for 2030 (8.0 trillion cubic feet) is second only to EVA's projection of 8.4 trillion cubic feet. IHSGI and INFORUM show modest increases in industrial natural gas consumption from their 2011 levels, to 6.9 trillion cubic feet in 2035 in both outlooks. Projected industrial natural gas consumption declines in the IHSGI projection after 2035, to 6.7 trillion cubic feet in 2040.
Only four of the outlooks included in Table 12 provide projections for Henry Hub natural gas spot prices. EVA shows the highest Henry Hub prices in 2035 and IHSGI the lowest. In the IHSGI projection, Henry Hub prices remain low through 2035, when they reach $4.98 per million Btu, compared with $3.98 per million Btu in 2011. Natural gas prices to the electric power sector rise from $4.87 per thousand cubic feet in 2011 to $5.47 per thousand cubic feet in 2035 in the IHSGI projection. The low Henry Hub prices in the IHSGI projection are supported by an abundant supply of relatively inexpensive natural gas, with only a small increase in net exports in comparison with the increase in the AEO2013 Reference case. EVA, in contrast, shows the Henry Hub price rising to a much higher level of $8.00 per million Btu in 2035, apparently as a result of stronger growth in natural gas consumption, particularly for electric power generation, and a lower level of natural gas exports. Indeed, the EVA outlook shows the U.S. remaining a net importer of natural gas through 2035.
Henry Hub natural gas prices in the ICF and AEO2013 Reference case projections for 2035—at $6.21 per million Btu and $6.32 per million Btu, respectively—fall within the price range bounded by IHSGI and EVA. In the AEO2013 Reference case, commercial, electric power, and industrial natural gas prices all rise by between $2 and $3 per thousand cubic feet from 2011 to 2035, while residential prices rise by $3.88 per thousand cubic feet over the same period. The residential sector is also the only sector for which the AEO2013 Reference case projects a decline in natural gas consumption to below 2011 levels in 2035. ICF projects a much smaller increase in delivered natural gas prices for the commercial, industrial, and electric power sectors, with prices rising to more than $2 per thousand cubic feet above 2011 levels by 2035 only in the electric power sector. With smaller price increases, ICF projects a much larger increase for natural gas consumption in the electric power and industrial sectors from 2011 to 2035 than in the AEO2013 Reference case.
The AEO2013 Reference case projects the highest levels of total coal production and prices in comparison with other coal outlooks available from EVA, ICF, IHSGI, INFORUM, the IEAâ€™s World Energy Outlook, and ExxonMobil. Total consumption in AEO2013 is also higher than in the other outlooks, except for INFORUM and ICF, whose consumption projections for 2035 are 2 percent and 5 percent higher, respectively, than projected in the AEO2013 Reference case (Table 14).
The detailed assumptions that underlie the various projections are not generally available, although there are some important known differences that contribute to the differences among the outlooks. For instance, EVA and ICF assume the implementation of new regulations for cooling water intake and coal combustion residuals; ExxonMobil, which has the lowest projection of coal consumption, assumes a carbon tax; and ICF also includes a carbon cap-and-trade program beginning in 2023. Because those policies are not current law, the AEO2013 Reference case excludes them, which contributes to the lower coal consumption projections in many of the other outlooks relative to AEO2013. Variation among the assumptions about growth in energy demand and other fuel prices, particularly for natural gas, also contribute to the differences.
Although the AEO2013 projections for total coal consumption are actually somewhat lower than the ICF and INFORUM projections, the other outlooks offer more pessimistic projections. ExxonMobil is the most pessimistic, with coal consumption 33 percent and 55 percent lower in 2025 and 2030, respectively, than in the AEO2013 Reference case. Coal consumption in 2025 is 17 percent (174 million tons) less in the EVA outlook than in the AEO2013 Reference case and 8 percent less in the IHSGI outlook. The INFORUM and ICF outlooks for total coal consumption in 2035 are between 21 million tons (2 percent) and 55 million tons (5 percent) higher, respectively, than in the AEO2013 Reference case.
The electricity sector is the predominant consumer of coal and the primary source of differences among the projections, due to their differing assumptions about regulations and the economics of coal versus other fuel choices over time. Although EVA shows a greater reduction in coal use for electricity generation in 2025 than does IHSGI, for 2035 the two projections are similar. After 2035, EVA shows a continued small increase in coal use for electricity generation, whereas it continues to fall in the IHSGI projection and in 2040 is 37 million tons less than projected by EVA. The ICF outlook for coal consumption in electricity generation is similar to the AEO2013 projection through 2025 but then declines gradually through 2035. IEA projects a level of coal use for electricity generation in 2035 that is most similar to the AEO2013 Reference case.
In all the projections, coal consumption in the end-use sectors is low in comparison with the electric power sector; however, there are several notable differences among the outlooks. Most notably, the ICF outlook shows increasing coal use in the other sectors that offsets declining consumption for electric power. ICF is the only projection that shows an increase in coal use in the industrial and buildings sectors. AEO2013 shows the next highest level of coal consumption in the industrial and buildings sectors, but it is still less than half of ICF's projection for industrial and buildings consumption in 2035. Both IHSGI and EVA show significant declines in coal use in those sectors over the projection period. In 2040, coal use in the buildings and industrial sectors in the IHSGI and EVA projections is equal to only 39 percent and 60 percent, respectively, of the coal use in those sectors in AEO2013. In addition, only AEO2013 and ICF project coal use for liquids production. Some of the gains in the two sectors are offset in the ICF outlook by lower consumption of coal at coke plants, which falls from 21 million tons in 2011 to 12 million tons in 2035. In the other outlooks, coal use at coke plants is similar to the levels in the AEO2013 Reference case, with modest declines through the end of their projections.
Differences among the projections for U.S. domestic coal production fall within a smaller range than the projections for coal consumption, depending in part on each outlook's projections for net exports. For example, coal production in the EVA and IHSGI projections is buoyed by relatively high export levels after 2011, with total coal production falling by 13 percent and 5 percent, respectively, from 2011 to 2035, compared with a 16-percent decline in total coal consumption in both projections. The ICF and INFORUM outlooks, which project 11-percent and 8-percent increases in total coal consumption through 2035, respectively, show changes in total coal production of 4 percent and no growth, respectively, as a result of significantly lower net export levels.
The projections for coal exports in the AEO2013 Reference case generally fall between the EVA and IHSGI projections. INFORUM's projection for coal exports is the lowest among the outlooks but similar to ICF's projection for 2035. The composition of EVA's exports also differs from that in AEO2013, in that EVA expects most exports to be thermal coal, whereas most exports in the early years of the AEO2013 Reference case are coking coal. In 2025, coking coal accounts for 57 percent of total coal exports in the AEO2013 Reference case, compared with 34 percent in the EVA projection. In 2040, however, the coking coal share of exports in the AEO2013 projection declines to 44 percent, compared with 32 percent in the EVA projection. In comparison, coking coal accounts for 74 percent of total coal exports in 2035 in the ICF projection.
In the EVA and IHSGI projections, coal imports remain low and relatively flat. AEO2013 also shows low levels of imports initially, but they grow to 36 million tons in 2040 from 5 million tons in 2025. For 2035, the ICF outlook implies 136 million tons of coal imports (calculated by subtracting production from the sum of consumption and exports), which is higher than all the others shown in the comparison table. Coal imports remain above 20 million tons in the INFORUM projections, and as in the ICF and AEO2013 projections, they increase over time, doubling in 2035 from the 2025 level.
Only AEO2013, ICF, and INFORUM provide projections of minemouth coal prices. In the ICF projections, minemouth prices in 2025 are 20 percent below those in 2011 (on a dollar-per-ton basis), and they decline only slightly through 2035. INFORUM projects coal minemouth prices that are very similar to the AEO2013 prices (on a dollar-per-million Btu basis).
The ICF outlook shows the lowest price for coal delivered to the electricity sector in both 2025 and 2035, with the real coal price lower than in 2011. INFORUM's prices for coal delivered to electricity generators (on a dollar-per-ton basis) are similar. IHSGI's delivered coal prices to electricity generators are significantly lower than those in the AEO2013 Reference case and remain close to the 2011 price over the entire projection period. As a result, the IHSGI delivered coal price to electricity generators is 9 percent lower in 2025 and 22 percent lower in 2040, on a dollar-per-ton basis, than projected in the AEO2013 Reference case.
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.
23. U.S. Court of Appeals for the District of Columbia Circuit, "State of New York v. Nuclear Regulatory Commission and United States of America" (Washington, DC: June 8, 2012), http://www.cadc.uscourts.gov/internet/opinions.nsf/57ACA94A8FFAD8AF85257A1700502AA4/$file/11-1045-1377720.pdf.
24. U.S. Nuclear Regulatory Commission, "CLI-12-16, Memorandum and Order" (Washington, DC: August 7, 2012), http://www.nrc.gov/reading-rm/doc-collections/commission/orders/2012/2012-16cli.pdf.
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/.
44. The eligible technology, and even the definition of the technology or fuel category, will vary by state. For example, one state's definition of renewables may include hydroelectric power generation, while another's definition may not. Table 3 provides more detail on how the technology or fuel category is defined by each state.
45. More information about the Database of State Incentives for Renewables & Efficiency can be found at http://www.dsireusa.org/incentives.
46. Database of State Incentives for Renewables & Efficiency, http://www.dsireusa.org/rpsdata/index.cfm.
65. United States Internal Revenue Code, Title 26, Subtitle A—Income Taxes, Â§48(a)(2)(A)(ii), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title26/pdf/USCODE-2011-title26-subtitleA-chap1-subchapA.pdf.
66. United States Internal Revenue Code, Title 26, Subtitle A—Income Taxes, Â§48(c)(3)(B)(iii), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title26/pdf/USCODE-2011-title26-subtitleA-chap1-subchapA.pdf.
67. Calculations based on U.S. Energy Information Administration, Form EIA-860, Schedule 3, 2011 data (Washington, DC: January 9, 2013), http://www.eia.gov/electricity/data/eia860/index.html.
68. U.S. Congress, "American Taxpayer Relief Act of 2012," P.L. 112-240, Sections 401 through 412, http://www.gpo.gov/fdsys/pkg/PLAW-112publ240/pdf/PLAW-112publ240.pdf.
69. Modeled provisions based on U.S. Congress, "American Taxpayer Relief Act of 2012," P.L. 112-240, Sections 401, 404, 405, 407, 408, 409, and 412, http://www.gpo.gov/fdsys/pkg/PLAW-112publ240/pdf/PLAW-112publ240.pdf.
82.EPA's Proposed Carbon Pollution Standard for New Power Plants would require that new fossil fuel-fired power plants meet an output-based standard of 1,000 pounds of carbon dioxide per megawatthour of electricity generated. That standard would effectively prohibit the construction of new coal-fired power plants without carbon capture and storage. Currently, the EPA is evaluating comments and expects to issue a final rule in 2013. Because the rule is not yet final, it is not assumed to take effect in any of the AEO2013 cases.
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.
98. U.S. Nuclear Regulatory Commission, Report to Congress: Advanced Reactor Licensing (Washington, DC: August 2012), http://pbadupws.nrc.gov/docs/ML1215/ML12153A014.pdf.
99. U.S. Department of Energy, "Economic Aspects of Small Modular Reactors" (Washington, DC: March 1, 2012), http://www.energy.gov/sites/prod/files/Economic%20Aspects%20of%20SMRs.pdf.
100. U.S Department of Energy, "Obama Administration Announces $450 Million to Design and Commercialize U.S. Small Modular Nuclear Reactors" (Washington, DC: March 22, 2012), http://energy.gov/ne/articles/obama-administration-announces-450-million-design-and-commercialize-us.
101. U.S Department of Energy, "Energy Department Announces New Investment in U.S. Small Modular Reactor Design and Commercialization" (Washington, DC: November 20, 2012), http://energy.gov/articles/energy-department-announces-new-investment-us-small-modular-reactor-design-and.
102. M.R. Blood, "Troubled Calif. nuke plant aims to restart reactor," USA Today (October 4, 2012), http://www.usatoday.com/story/news/nation/2012/10/04/troubled-calif-nuke-plant-aims-to-restart-reactor/1614255/.
103. E. Wolff, "Consumers may not get San Onofre outage bill," U-T San Diego (October 25, 2012), http://www.utsandiego.com/news/2012/oct/25/customers-could-save-360-million-dark-nuke-plant-p/.
104. P. Arévalo, "San Onofre to Cut 730 Jobs," San Juan Capistrano Patch (August 20, 2012), http://sanjuancapistrano.patch.com/articles/san-onofre-to-cut-730-jobs.
105. "Costly estimates for Crystal River repairs," World Nuclear News (October 2, 2012), http://www.world-nuclear-news.org/C-Costly_estimates_for_Crystal_River_repairs-0210124.html.
106. Reuters, "UPDATE 1-Duke Energy says Crystal River nuclear repair could exceed $3 bln" (October 1, 2012), http://www.reuters.com/article/2012/10/01/utilities-duke-crystalriver-idUSL1E8L1PQ520121001.
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.
142. U.S. Environmental Protection Agency, "Mercury and Air Toxics Standards," http://www.epa.gov/mats.
143. Recent analysis performed by the EPA indicates that upgraded electrostatic precipitators may also enable coal-fired power plants to meet the nonmercury metal emissions control requirement for MATS. This assumption was not included in AEO2013 but will be revisited in future AEOs.
144. U.S. Energy Information Administration, "Dry sorbent injection may serve as a key pollution control technology at power plants," Today in Energy (March 16, 2012), http://www.eia.gov/todayinenergy/detail.cfm?id=5430.
145. EIA summed the sector-level sales from the INFORUM and EVA projections to develop a total electricity sales value for comparison purposes.
146. EIA estimated a weighted-average electricity price for INFORUM based on the sector-level prices and sales.
147. For purposes of comparison, generation from natural gas, turbine, and oil/gas steam capacity from EVA was combined, resulting in a total of 2,330 billion kilowatthours of generation from natural gas for 2040, as shown in Table 25.
- Coal's share of electric power generation falls over the projection period
- Natural gas consumption grows in industrial and electric power sectors as domestic production also serves an expanding export market
- Renewable fuel use grows at a faster rate than fossil fuel use
- Electricity use per household declines from 2011 to 2040 in the Reference case
- Renewable energy fuels most additions to commercial distributed generation capacity
- Reliance on natural gas, natural gas liquids, and renewables rises as industrial energy use grows
- Growth in electric use slows but still increases by 28 percent from 2011 to 2040
- Coal-fired plants continue to be the largest source of U.S. electricity generation
- Most new capacity additions use natural gas and renewables
- Additions to power plant capacity slow after 2012 but accelerate beyond 2023
- Growth in generating capacity parallels rising demand for electricity
- Cost and regulatory uncertainties vary across options for new capacity
- Nuclear power plant capacity grows slowly through uprates and new builds
- Solar photovoltaics and wind dominate renewable capacity growth
- Solar, wind, and biomass lead growth in renewable generation, hydropower remains flat
- State renewable portfolio standards increase renewable electricity generation
- Industrial and electric power sectors lead U.S. growth in natural gas consumption
- Pipeline exports increases as Canadian imports fall and exports to Mexico rise
- Energy-related carbon dioxide emissions remain below their 2005 level through 2040
- Power plant emissions of sulfur dioxide are reduced by further environmental controls
- Nitrogen oxide emissions show little change from 2011 to 2040 in the Reference case
Issues in Focus
- No sunset and extended policies cases
- Competition between coal and natural gas in the electric power sector
- Nuclear power in AEO2013
Legislation and Regulation
- Recent rulings on the Cross-State Air Pollution Rule and the Clean Air Interstate Rule
- Nuclear waste disposal and the Waste Confidence Rule
- State renewable energy requirements and goals: Update through 2012
Comparison with other projections