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Annual Energy Outlook 2014

Release Date: May 7, 2014   |  Next Early Release Date: December 2014   |  See schedule  |  full report

Market Trends: Coal

Coal production growth limited by competitive fuel prices and little new coal-fired capacity

Coal production in 2012 was more than 7% below the 2011 total (Figure MT-60), mostly as a result of gas-on-coal competition. In the AEO2014 Reference case, coal production recovers briefly as natural gas prices rise before dropping to 2012 levels in 2016, as the need for electricity generators to comply with Mercury and Air Toxic Standards (MATS) leads to a wave of coal-fired capacity retirements. From 2016 to 2030, coal production increases gradually as growing electricity demand and rising natural gas prices spur the use of coal for power generation. After 2030, when existing coal units reach maximum utilization rates and virtually no new capacity is built, coal production stabilizes. Coal exports, which totaled 3.2 quadrillion Btu in 2012, remain at that level through 2020 and then increase to 3.8 quadrillion Btu in 2040. Overall, U.S. coal production grows by an average of 0.3%/year in the Reference case, from 20.6 quadrillion Btu in 2012 to 22.6 quadrillion Btu in 2040.


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On a regional basis, strong production growth in the Interior region contrasts with generally stagnant production in Appalachia and the West. Interior coal production reaches new highs as scrubbers installed at existing coal-fired generating units allow them to burn the region’s higher-sulfur coals with lower delivered costs. Western production grew steadily for decades but fell by 14% from 2008 to 2012 as a result of the recession and competition from natural gas. Western production increases slightly in the Reference case, tempered by slow growth in coal use for electricity generation and by competition from coal producers in the Interior region. Appalachian coal production declines by 14% from 2012 to 2016, as coal produced from the extensively mined, higher-cost reserves of Central Appalachia is supplanted by lower-cost coal from other regions.

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

U.S. coal production varies across the AEO2014 cases, reflecting different assumptions about coal production and transportation costs, natural gas prices, and actions to limit greenhouse gas (GHG) emissions (Figure MT-61). In general, assumptions that reduce the competitiveness of coal versus natural gas lead to lower coal production. For example, relative to the Reference case, coal production is lower in both the High Coal Cost case (higher costs for coal mining and transportation) and the High Oil and Gas Resource case (lower costs for natural gas production). Similarly, actions to cut GHG emissions would also reduce the competiveness of coal because of its high carbon content. 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.


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Of the cases shown in Figure MT-61, the GHG10 case shows the largest decline in U.S. coal production, with an economy-wide CO2 emissions price that rises to $34 per metric ton of CO2 (2012 dollars) in 2040, leading to 32% lower coal production in 2040 compared with the Reference case. Production in the High Coal Cost and Low Coal Cost cases is 7% lower and 4% higher, respectively, than in the Reference case in 2020, evolving to 25% lower and 11% higher in 2040 as the gap between coal and natural gas prices widens. In addition to the GHG10 case, two more GHG scenarios were developed for AEO2014 (not shown in Figure MT-61)—the GHG25 case, with an economywide CO2 allowance fee that increases to $85 per metric ton in 2040; and the GHG10 and Low Gas Prices case, with lower natural gas prices than in the Reference case. In the GHG25 case and the GHG10 and Low Gas Prices case, total coal production in 2040 is 73% and 53% lower, respectively, than in the Reference case.

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

In the AEO2014 Reference case, the average real minemouth price for U.S. coal increases by 1.4%/year, from $1.98/MMBtu in 2012 to $2.96/MMBtu in 2040, continuing the upward trend that began in 2000 (Figure MT-62). A key factor underlying the higher coal prices is an expected decline in coal mining productivity in most areas, but at slower rates than those seen between 2000 and 2011. The minemouth price fell slightly in 2012, primarily as a result of a 19% decline in the price of coking coal [15]. Steam coal prices also declined in 2012, but by less than 1%. In the High and Low Coal Cost cases developed for AEO2014, different assumptions about mining productivity lead to minemouth coal prices in 2040 that are 87% higher and 45% lower, respectively, than in the Reference case.


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In the Appalachia region, the average minemouth coal price increases by 1.6%/year from 2012 to 2040, because of a decline in mine productivity. The higher price outlook in the region also reflects a larger share of total production for higher-value coking coal, resulting from a decline in shipments of steam coal to domestic markets. Recent increases in the average price of Appalachia coal, from $1.33/MMBtu in 2000 to $3.16/MMBtu in 2012, have reduced the ability of Appalachia coal to compete with coal from other regions.

In the Western region, the coal price grows by 2.1%/year from 2012 to 2040. An increase in stripping ratios at mines in Wyoming's Powder River Basin, which contributed to a 32% decrease in the basin’s coal mining productivity from 2000 to 2012, continues to push mining costs higher. In the Interior region, with a more optimistic outlook for mine productivity, minemouth prices rise by 1.0%/year from 2012 to 2040. Increased output from large, highly productive longwall mines
in the region supports expected improvements in productivity.

Endnotes

  1. Minemouth coal price estimates for coking coal (or premium metallurgical) and steam coal in 2012 dollars/short ton are provided in the AEO2014 Reference case "Supplemental Tables for Regional Detail," Table 140. These prices are converted to units of 2012 dollars/million Btu by using the production and price data from AEO2014 Supplemental Data Tables 139 and 140, the heat content data for total coal production from Supplemental Data Table 146, and an estimated heat content of 26.3 million Btu/short ton for U.S. coking coal production. For regional detail, see the AEO2014 Reference case "Supplemental Tables for Regional Detail," http://www.eia.gov/forecasts/aeo/tables_ref.cfm.

Reference Case Tables
Table 1. Total Energy Supply, Disposition, and Price Summary XLS
Table 2. Energy Consumption by Sector and Source - United States XLS
Table 3. Energy Prices by Sector and Source - United States XLS
Table 4. Residential Sector Key Indicators and Consumption XLS
Table 5. Commercial Sector Key Indicators and Consumption XLS
Table 6. Industrial Sector Key Indicators and Consumption XLS
Table 7. Transportation Sector Key Indicators and Delivered Energy Consumption XLS
Table 8. Electricity Supply, Disposition, Prices, and Emissions XLS
Table 9. Electricity Generating Capacity XLS
Table 10. Electricity Trade XLS
Table 11. Petroleum and Other Liquids Supply and Disposition XLS
Table 12. Petroleum and Other Liquids Prices XLS
Table 13. Natural Gas Supply, Disposition, and Prices XLS
Table 14. Oil and Gas Supply XLS
Table 15. Coal Supply, Disposition, and Prices XLS
Table 16. Renewable Energy Generating Capacity and Generation XLS
Table 17. Renewable Energy Consumption by Sector and Source XLS
Table 18. Energy-Related Carbon Dioxide Emissions by Sector and Source - United States XLS
Table 19. Energy-Related Carbon Dioxide Emissions by End Use XLS
Table 20. Macroeconomic Indicators XLS
Table 21. International Petroleum and Other Liquids Supply, Disposition, and Prices XLS