‹ Analysis & Projections

Annual Energy Outlook 2014

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

Coal from Executive Summary

Coal's share of electric power generation falls over the projection period


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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.


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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.


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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.

Coal from Market Trends

Production of liquid fuels from biomass, coal, and natural gas increases

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In 2011, world production of liquid fuels from biomass, coal, and natural gas totaled 2.1 million barrels per day, or about 2 percent of the energy supplied by all liquid fuels. In the AEO2013 Reference case, production from the three sources grows to 5.7 million barrels per day in 2040 (Figure 51), or about 4 percent of the energy supplied by all liquid fuels.

In the Low Oil Price case, production of liquid fuels from these sources grows to 6.7 million barrels per day in 2040, as technology development is faster than projected in the Reference case, making the liquids easier to produce at lower cost, and demand for ethanol for use in existing blend ratios is higher. In the High Oil Price case, production grows to 9.1 million barrels per day in 2040, as higher prices stimulate greater investment in advanced liquid fuels technologies.

Across the three oil price cases, the largest contributions to production of advanced liquid fuels come from U.S. and Brazilian biofuels. In the Reference case, biofuel production totals 4.0 million barrels per day in 2040, and production of gas-to-liquids (GTL) and coal-to-liquids (CTL) fuels accounts for 1.7 million barrels per day of additional production in 2040. Biofuels production in 2040 totals 5.5 million barrels per day in the Low Oil Price case and 5.9 million barrels per day in the High Oil Price case. The projections for CTL and GTL production are more sensitive to world oil prices, varying from 1.2 million barrels per day in the Low Oil Price case to 3.3 million barrels per day in the High Oil Price case in 2040. In the Reference case, the U.S. share of world GTL production in 2040 is 36 percent, as recent developments in domestic shale gas supply have contributed to optimism about the long-term outlook for U.S. GTL plants.

Renewables and natural gas lead rise in primary energy consumption

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

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

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

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

Reliance on natural gas, natural gas liquids, and renewables rises as industrial energy use grows


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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.

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


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

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

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

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

Most new capacity additions use natural gas and renewables


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

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

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

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


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

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

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

Costs and regulatory uncertainties vary across options for new capacity


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

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

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

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

Early declines in coal production are followed by growth after 2016


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U.S. coal production largely follows the trend of domestic coal consumption, but increasingly it is influenced by coal exports. In the near term, the combination of relatively low natural gas prices and high coal prices, the lack of a strong recovery in electricity demand, and increasing generation of electricity from renewables suppress domestic coal consumption. In addition, new requirements to control emissions of mercury and acid gases result in the retirement of some coal-fired generating capacity, contributing to a near-term decline in coal demand. After 2016, coal production in the Reference case increases by an average of 0.6 percent per year through 2040 (Figure 104), as a result of growing coal exports and increasing use of coal in the electricity sector as electricity demand grows and natural gas prices rise.

On a regional basis, the Interior and Western regions show similar growth in production, while Appalachian output declines. Following some early setbacks, Western coal production increases steadily through 2035 before leveling off. Coal from the West satisfies much of the additional need for fuel at coal-fired power plants, and it is also boosted by increasing exports and production of synthetic liquids. Coal production in the Interior region, which has trended downward slightly since the early 1990s, reaches new highs in the AEO2013 Reference case. Additional production from the region originates mostly from mines tapping into the substantial reserves of bituminous coal in Illinois, Indiana, and western Kentucky. Appalachian coal production declines substantially from current levels, as coal produced from the extensively mined, higher-cost reserves of Central Appalachia is supplanted by lower-cost coal from other regions. An expected increase in production from the northern part of the Appalachian basin moderates the overall decline.

Outlook for U.S. coal production is affected by fuel price uncertainties


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U.S. coal production varies across the AEO2013 cases, reflecting the effects of different assumptions about the costs of producing and transporting coal, the outlook for natural gas prices, and possible controls on GHG emissions (Figure 105). In general, assumptions that reduce the competitiveness of coal versus natural gas result in less coal production: in the High Coal Cost case as a result of significantly higher estimated costs to mine and transport coal, and in the High Oil and Gas Resource case as a result of lower natural gas production costs than in the Reference case. Similarly, actions to reduce GHG emissions can reduce the competiveness of coal, because its high carbon content can translate into a price penalty, in the form of GHG fees, relative to other fuels. Conversely, lower coal prices in the Low Coal Cost case and higher natural gas prices in the Low Oil and Gas Resource case improve the competitiveness of coal and lead to higher levels of coal production.

Of the cases shown in Figure 105, the most substantial decline in U.S. coal production occurs in the GHG15 case, where an economy-wide CO2 emissions price that rises to $53 per metric ton in 2040 leads to a 50-percent drop in coal production from the Reference case level in 2040. Across the remaining cases, variations range from 15 percent lower to 6 percent higher than production in the Reference case in 2020; and by 2040, as the gap in coal prices widens over time, the range of differences increases to 24 percent below and 16 percent above the Reference case in the High Coal Cost and Low Coal Cost cases, respectively. In two additional GHG cases developed for AEO2013 (not shown in Figure 105), economy-wide CO2 allowance fees are assumed to increase to $36 per metric ton in the GHG10 case and $89 per metric ton in the GHG25 case in 2040, resulting in total coal production in 2040 that is 25 percent lower and 72 percent lower, respectively, than in the Reference case.

Expected declines in mining productivity lead to further increases in average minemouth prices


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In the AEO2013 Reference case, the average real minemouth price for U.S. coal increases by 1.4 percent per year, from $2.04 per million Btu in 2011 to $3.08 in 2040, continuing the upward trend in coal prices that began in 2000 (Figure 106). A key factor underlying the higher coal prices in the projection is an expectation that coal mining productivity will continue to decline, but at slower rates than during the 2000s.

In the Appalachian region, the average minemouth coal price increases by 1.5 percent per year from 2011 to 2040. In addition to continued declines in coal mining productivity, the higher price outlook for the Appalachian region reflects a shift to higher-value coking coal, resulting from the combination of growing exports of coking coal and declining shipments of steam/thermal coal to domestic markets. Recent increases in the average price of Appalachian coal, from $1.31 per million Btu in 2000 to $3.33 per million Btu in 2011, in part as a result of significant declines in mining productivity over the past decade, have substantially reduced the competitiveness of Appalachian coal with coal from other regions.

In the Western and Interior coal supply regions, declines in mining productivity, combined with increasing production, lead to increases in the real minemouth price of coal, averaging 2.3 percent per year for the Western region and 1.2 percent per year for the Interior region from 2011 to 2040.

In two alternative coal cost cases developed for AEO2013, the average U.S. minemouth coal price in 2040 is as low as $1.70 per million Btu in the Low Coal Cost case (45 percent below the Reference case) and as high as $6.20 per million Btu in the High Coal Cost case (101 percent higher than in the Reference case). Results for the two cases, which are based on different assumptions about mining productivity, labor costs, mine equipment costs, and coal transportation rates, are provided in Appendix D.

Concerns about future GHG policies affect builds of new coal-fired generating capacity


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In the AEO2013 Reference case, the cost of capital for investments in GHG-intensive technologies is increased by 3 percentage points, primarily to reflect the behavior of electricity generators who must evaluate long-term investments across a range of generating technologies in an environment where future restrictions of GHG emissions are likely. The higher cost of capital is used to estimate the costs for new coal-fired power plants without carbon capture and storage (CCS) and for capital investment projects at existing coal-fired power plants (excluding CCS). The No GHG Concern case illustrates the potential impact on energy investments when the cost of capital is not increased for GHG-intensive technologies.

In the No GHG Concern case, a lower cost of capital leads to the addition of 26 gigawatts of new coal-fired capacity from 2012 to 2040, up from 9 gigawatts in the Reference case (Figure 107). Nearly all projected builds in the Reference case are plants already under construction. As a result, additions of natural gas, nuclear, and renewable generating capacity all are slightly lower in the No GHG Concern case than in the Reference case.

In addition to affecting builds of new generating capacity, removing the premium for the cost of capital also influences capital investment projects at existing coal-fired power plants. In the No GHG Concern case, the lower cost of capital results in some additional retrofits of flue gas desulfurization (FGD) equipment relative to the Reference case, and fewer retrofits of dry sorbent injection (DSI) systems, which are a less capital-intensive option than FGD for controlling emissions of acid gases. To comply with the requirements specified in the Mercury and Air Toxics Standards (MATS), the AEO2013 projections assume that coal-fired power plants must be equipped with either FGD equipment or DSI systems with full fabric filters

Coal from Issues in Focus

4. Competition between coal and natural gas in the electric power sector

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.

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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.

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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

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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.

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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 [82]. 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

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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.

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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.

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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).

Regional impacts

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.

figure data

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.

figure data

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.

Energy-related carbon dioxide emissions remain below their 2005 level through 2040


figure data

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.

Coal from Comparison with other projections

7. Coal

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 IEA’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.

Endnotes

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.
134.Costs are for the electric power sector only.
135. The levelized costs reflect the average of regional costs. For detailed discussion of levelized costs, see U.S. Energy Information Administration, "Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013," http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.

Reference Case Tables
Table 1. Total Energy Supply, Disposition, and Price Summary XLS
Table 15. Coal Supply, Disposition, and Prices XLS
Table 18. Energy-Related Carbon Dioxide Emissions by Sector and Source - United States XLS
Table 18.1. Energy-Related Carbon Dioxide Emissions by Sector and Source - New England XLS
Table 18.2. Energy-Related Carbon Dioxide Emissions by Sector and Source - Middle Atlantic XLS
Table 18.3. Energy-Related Carbon Dioxide Emissions by Sector and Source - East North Central XLS
Table 18.4. Energy-Related Carbon Dioxide Emissions by Sector and Source - West North Central XLS
Table 18.5. Energy-Related Carbon Dioxide Emissions by Sector and Source - South Atlantic XLS
Table 18.6. Energy-Related Carbon Dioxide Emissions by Sector and Source - East South Central XLS
Table 18.7. Energy-Related Carbon Dioxide Emissions by Sector and Source - West South Central XLS
Table 18.8. Energy-Related Carbon Dioxide Emissions by Sector and Source - Mountain XLS
Table 18.9. Energy-Related Carbon Dioxide Emissions by Sector and Source - Pacific XLS
Table 67. Coal Production and Minemouth Prices by Region XLS
Table 68. Coal Production by Region and Type XLS
Table 69. Coal Minemouth Prices by Region and Type XLS
Table 70. World Steam Coal Flows By Importing Regions and Exporting Countries XLS
Table 71. World Metallurgical Coal Flows By Importing Regions and Exporting Countries XLS
Table 72. World Total Coal Flows By Importing Regions and Exporting Countries XLS