‹ Analysis & Projections

Annual Energy Outlook 2014

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

Market Trends — Coal

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

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