‹ Analysis & Projections

Annual Energy Outlook 2011

Release Date: April 26, 2011   |  Next Early Release Date: January 23, 2012  |   Report Number: DOE/EIA-0383(2011)


Early declines in coal production are more than offset by growth after 2014

U.S. coal production declined by 2.3 quadrillion Btu in 2009. In the AEO2011 Reference case, production does not return to its 2008 level until after 2025. Between 2008 and 2014 a potential recovery in coal production is kept in check by continued low natural gas prices and increased generation from renewables and nuclear capacity. After 2014, coal production grows at an average annual rate of 1.1 percent through 2035, with increases in coal use for electricity generation and for the production of synthetic liquids.

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Western coal production increases through 2035 (Figure 101) but at a much slower rate than in the past, as demand grows slowly. Low-cost supplies of coal from the West satisfy much of the additional fuel needs at coal-fired power plants east of the Mississippi River and supply most of the coal needed at new CTL and CBTL plants.

Coal production in the Interior region, which has trended slightly downward since the early 1990s, rebounds somewhat in the Reference case, increasing from 2.9 quadrillion Btu in 2009 to 3.5 quadrillion Btu in 2035. Most of the additional production from this region originates from mines tapping into the substantial reserves of mid- and high-sulfur 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 supply regions. Increasing production in the northern part of the basin, however, does help to moderate the overall production decline in Appalachia.

Long-term outlook for coal production varies considerably across cases

U.S. coal production varies across the AEO2011 cases, reflecting different assumptions about the costs of producing and transporting coal, the outlook for economic growth, and the outlook for world oil prices (Figure 102). In addition, although they are not shown in the figure, alternative assumptions about restrictions on GHG emissions could have even larger impacts on coal production over the projection period.

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Assumptions about economic growth primarily affect the projections for overall electricity demand, which in turn determine the need for coal-fired generation. In contrast, assumptions about the costs of producing and transporting coal primarily affect the choice of technologies for electricity generation, with coal capturing a larger share of the U.S. electricity market in the Low Coal Cost case and a smaller share in the High Coal Cost case. In the High Oil Price case, higher oil prices stimulate the demand for coal-based synthetic liquids, leading to a substantial expansion of coal use at CTL and CBTL plants. Production of coal-based synthetic liquids totals 1.6 million barrels per day in 2035 in the High Oil Price case, nearly three times the amount in the Reference case.

Coal production in the Reference case increases by 21 percent from 2009 to 2035, whereas the alternative cases show changes ranging from a decrease of 4 percent to an increase of 41 percent. In the earlier years of the projection, from 2009 to 2020, variations in coal production across the cases are smaller, ranging from a decline of 4 percent to an increase of 8 percent, primarily reflecting the smaller changes in overall energy demand over the shorter time frame.


Growth in average minemouth price slows compared to recent history

In the Reference case, the average real minemouth price for U.S. coal remains nearly unchanged, declining from $1.67 per million Btu in 2009 to $1.65 in 2020, and then rising to $1.73 in 2035—an increase of 0.2 percent per year over the entire projection period. In contrast, there were sizable increases in coal prices from 2000 to 2009, averaging 6.0 percent per year, and declines from 1990 to 2000 that averaged 4.2 percent per year. The moderation of coal prices in the Reference case results from a variety of factors, including a shift in production from Appalachia to the Interior and Western regions, which have lower costs of production, and a relatively flat outlook for coal mining productivity, which acts to keep mine production costs close to current levels.

In the Western and Interior coal supply regions, slight declines in mining productivity, combined with increased production, result in higher real minemouth prices in the AEO2011 Reference case, with prices increasing at average annual rates of 1.1 percent in the Western region and 0.5 percent in the Interior region from 2009 to 2035 (Figure 103).

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In the Appalachian region, the average real minemouth coal price increases by 0.2 percent per year from 2009 to 2035. The price outlook for Appalachian coal primarily reflects continuing but slower declines in coal mining productivity. Recent increases in the average price of Appalachian coal, from $1.27 per million Btu in 2000 to $2.56 per million Btu in 2009, in part as a result of significant declines in mining productivity over the decade, have substantially reduced the competitiveness of Appalachian coal with coal from other producing regions.

Substantial changes in coal prices would have moderate effects on demand

Alternative assumptions for coal mining and transportation costs affect delivered coal prices and demand. Two Coal Cost cases developed for AEO2011 examine the impacts on U.S. coal markets of alternative assumptions about mining productivity, labor costs, mine equipment costs, and coal transportation rates (Figure 104). Although alternative assumptions about economic growth and world oil prices lead to some variations in the price paths for coal, the differences from the Reference case are relatively small in those cases.

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In the High Coal Cost case, the average delivered coal price is $4.08 per million Btu (2009 dollars) in 2035–65 percent higher than in the Reference case, where the average price is $2.47 per million Btu in 2035. Because the higher coal prices result in switching from coal to natural gas and renewables in the electricity sector, U.S. coal consumption in 2035 is 16 percent (3.8 quadrillion Btu) lower in the High Coal Cost case than in the Reference case. In the Low Coal Cost case, delivered coal prices in 2035 average $1.53 per million Btu–38 percent lower than in the Reference case–and total coal consumption is 4 percent (0.9 quadrillion Btu) higher than in the Reference case.

Because the Economic Growth and Oil Price cases use the Reference case assumptions for coal mining and rail transportation costs, they show smaller variations in average delivered coal prices than do the two coal cost cases. Differences in coal price projections in the Economic Growth and Oil Price cases result mainly from higher and lower levels of demand for coal. In the Oil Price cases, higher and lower fuel costs for both coal producers and railroads also contribute to the slight variations in coal prices.

Concerns about GHG legislation affect the long-term outlook for coal

In the Reference case, the cost of capital for investments in GHG-intensive technologies—including conventional coal-fired power plants, CTL plants, CBTL plants, and integrated coal gasification and combined cycle plants without CCS—is increased by 3 percentage points to reflect the behavior of utilities, other energy companies, and regulators concerning the possible enactment of GHG legislation which could mandate that owners purchase allowances, invest in CCS, or invest in other projects to offset their emissions in the future. A No GHG Concern case, in which the additional 3 percentage points for GHG-intensive technologies is removed, is used to evaluate the impact on energy investments.

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In the No GHG Concern case, coal use for both electricity generation in the electric power sector and as part of production of coal-based synthetic liquids is 3.5 quadrillion Btu higher than in the Reference case (Figure 105), and 48 gigawatts (including 28 gigawatts at coal-based synthetic liquids plants) of new coal-fired generating capacity is added after 2009, as compared with 26 gigawatts in the Reference case (including about 12 gigawatts currently under construction). Of the 22 gigawatts of additional coal-fired capacity builds in the No GHG Concern case, 16 gigawatts, or 73 percent, are at coal-based synthetic liquids plants and 6 gigawatts are in the electric power sector. As a result, additions of both natural gas and renewable generating capacity are lower in the No GHG Concern case than in the Reference case. The production of coal-based synthetic liquids rises to 1.3 million barrels per day (2.7 quadrillion Btu) in 2035 in the No GHG Concern case, compared with 0.5 million barrels per day (1.1 quadrillion Btu) in the Reference case. Total CO2 emissions increase to 6,476 million metric tons in 2035 in the No GHG Concern case, about 3 percent higher than in the Reference case and 19 percent higher than in 2009.