Report Contents [Report#:DOE/EIA-0383(2001)]
Summary
of the AEO2001
Cases/
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Market Trends - Coal
Emissions Caps Lead to More Use of Low-Sulfur Coal From Western Mines Figure 113. Coal production by region, 1970-2020 (million short tons) Continued improvements in mine productivity (which have averaged 6.7 percent per year since 1979) are projected to cause falling real minemouth prices throughout the forecast. Higher electricity demand and lower prices, in turn, are projected to yield increasing coal demand, but the demand is subject to an overall sulfur emissions cap from CAAA90, which encourages progressively greater reliance on the lowest sulfur coals (from Wyoming, Montana, Colorado, and Utah). The use of western coals can result in up to 85 percent lower sulfur dioxide emissions than the use of many types of higher sulfur eastern coal. As coal demand grows in the forecast, however, new coal-fired generating capacity is required to use the best available control technology: scrubbers or advanced coal technologies that can reduce sulfur emissions by 90 percent or more. Thus, even as the demand for low-sulfur coal is projected to grow, there are still expected to be market opportunities for low-cost higher sulfur coal throughout the forecast. From 1999 to 2020, high- and medium-sulfur coal production is projected to decline from 616 to 592 million tons (0.2 percent per year), and low-sulfur coal production is projected to rise from 490 to 740 million tons (2.0 percent per year). As a result of the competition between low-sulfur coal and post-combustion sulfur removal, western coal production is expected to continue its historical growth, reaching 819 million tons in 2020 (Figure 113), but its annual growth rate is projected to fall from the 9.3 percent achieved between 1970 and 1999 to 1.8 percent in the forecast period. Minemouth Coal Prices Continue To Fall in the Projections Figure 114. Average minemouth price of coal by region, 1990-2020 (1999 dollars per short ton) Minemouth coal prices declined by $5.80 per ton (in 1999 dollars) between 1970 and 1999, and they are projected to decline by 1.4 percent per year, or $4.28 per ton, between 1999 and 2020 (Figure 114). The price of coal delivered to electricity generators, which declined by approximately 95 cents per ton between 1970 and 1999, is projected to fall to $19.45 per ton in 2020—a 1.1-percent annual decline. The mines of the Northern Great Plains, with thick seams and low overburden ratios, have had higher labor productivity than other coalfields, and their advantage is expected to be maintained throughout the forecast. Average U.S. labor productivity (Figure 115) is projected to follow the trend for eastern mines most closely, because eastern mining is more labor-intensive than western mining. Figure 115. Coal mining labor productivity by region, 1990-2020 (short tons per miner per hour) Labor Cost Contribution to Total Coal Prices Continues To Decline Figure 116. Labor cost component of minemouth coal prices, 1970-2020 (billion 1999 dollars) Gains in coal mine labor productivity result from technology improvements, economies of scale, and better mine design. At the national level, however, average labor productivity is also expected to be influenced by changing regional production shares. Competition from very low sulfur, low-cost western and imported coals is projected to limit the growth of eastern low-sulfur coal mining. The boiler performance of western low-sulfur coal has been successfully tested in all U.S. Census divisions except New England and the Mid-Atlantic, and its use in eastern markets is projected to increase. Eastern coalfields contain extensive reserves of higher sulfur coal in moderately thick seams suited to longwall mining. Continued penetration of technologies for extracting and hauling large volumes of coal in both surface and underground mining suggests that further reductions in mining cost are likely. Improvements in labor productivity have been, and are expected to remain, the key to lower coal mining costs. As labor productivity improved between 1970 and 1999, the average number of miners working daily fell by 2.2 percent per year. With improvements expected to continue through 2020, a further decline of 1.2 percent per year in the number of miners is projected. The share of wages (excluding irregular bonuses, welfare benefits, and payroll taxes paid by employers) in minemouth coal prices [92], which fell from 31 percent to 17 percent between 1970 and 1999, is projected to decline to 15 percent by 2020 (Figure 116). High Labor Cost Assumption Leads to Lower Production in the East Alternative assumptions about future regional mining costs affect the projections for market shares of eastern and western mines and the national average minemouth price of coal. In two alternative mining cost cases, projected minemouth prices, delivered prices, and the resulting regional coal production levels vary with changes in projected mining costs. Productivity is assumed to increase by 2.2 percent per year through 2020 in the reference case, while wage rates and equipment costs are constant in 1999 dollars. The national minemouth coal price is projected to decline by 1.4 percent per year to $12.70 per ton in 2020 (Figure 117). In the low mining cost case, productivity is assumed to increase by 3.7 percent per year, and real wages and equipment costs are assumed to decline by 0.5 percent per year [93]. As a result, the average minemouth price is projected to fall by 2.1 percent per year to $10.84 per ton in 2020 (14.6 percent less than projected in the reference case). Eastern coal production is projected to be 4 million tons higher in the low mining cost case than in the reference case in 2020, reflecting the higher labor intensity of mining in eastern coalfields. In the high mining cost case, productivity is assumed to increase by only 0.6 percent per year, and real wages and equipment costs are assumed to increase by 0.5 percent per year. Consequently, the average minemouth price of coal is projected to fall by 0.5 percent per year to $15.18 per ton in 2020 (19.5 percent higher than in the reference case). Eastern production in 2020 is projected to be 13 million tons lower in the high mining cost case than in the reference case. Transportation Costs Are a Key Factor for Coal Markets Figure 118. Projected change in coal transportation costs in three cases, 1999-2020 (percent) The competition between coal and other fuels, and among coalfields, is influenced by coal transportation costs. Changes in fuel costs affect transportation costs (Figure 118), but transportation fuel efficiency also grows with other productivity improvements in the forecast. As a result, in the reference case, average coal transportation rates are projected to decline by 1.1 percent per year between 1999 and 2020. Historically, the most rapid declines in coal transportation costs have occurred on routes originating in coalfields that have had the greatest declines in real minemouth prices. Railroads are likely to reinvest profits from increasing coal traffic to reduce transportation costs and, thus, expand the market for such coal. Therefore, coalfields that are most successful at improving productivity and lowering minemouth prices are likely to obtain the lowest transportation rates and, consequently, the largest markets at competitive delivered prices. Assuming that mines in the Powder River Basin will complete needed expansions of their train-loading capacities, western coal is expected to be able to meet the increase in demand expected with the advent of Phase 2 of CAAA90, which became effective on January 1, 2000. The transition will require more low-sulfur coal than was projected in AEO2000, because scrubber retrofits are expected to be made at a slower pace in AEO2001. Any coal transportation problems associated with the increased shift to low-sulfur coal are expected to be temporary. Higher Economic Growth Would Favor Coal for Electricity Generation A strong correlation between economic growth and electricity use accounts for the variation in coal demand projections across the economic growth cases (Figure 119), with domestic coal consumption in 2020 projected to range from 1,245 to 1,426 million tons in the low and high economic growth cases, respectively. Of the difference, coal use for electricity generation is projected to make up 173 million tons. The difference in total projected coal production between the two economic growth cases is 182 million tons, of which 148 million tons (81 percent) is projected to be western production. Although western coal must travel up to 2,000 miles to reach some of its markets, it is expected to remain competitively priced in all regions except the Northeast when its transportation costs are added to its low minemouth price and low sulfur allowance cost. Changes in world oil prices affect the costs of energy (both diesel fuel and electricity) for coal mining. In the low and high oil price cases, the average prices of coal delivered to electricity generators are projected to be 0.8 percent lower and 0.2 percent higher, respectively, in 2020 than projected in the reference case. The low world oil price case projects 79 million tons less coal use in 2020 than the high world oil price case. Low oil prices encourage electricity generation from oil, whereas high oil prices encourage coal consumption. The higher projection for coal consumption in the high oil price case is attributable to the electricity generation sector, which is projected to account for virtually all of the increase. Coal Consumption for Electricity Continues To Rise in the Forecast Figure 120. Electricity and other coal consumption, 1970-2020 (million short tons) Domestic coal demand is projected to increase by 262 million tons in the reference case forecast, from 1,035 million tons in 1999 to 1,297 million tons in 2020 (Figure 120), because of projected growth in coal use for electricity generation. Coal demand in other domestic end-use sectors is projected to decline. Coal consumption for electricity generation (excluding cogeneration) is projected to increase from 923 million tons in 1999 to 1,186 million tons in 2020 as the utilization of existing coal-fired generation capacity increases and, in later years, new capacity is added. The average utilization rate is projected to increase from 68 percent in 1999 to 83 percent in 2020. Because coal consumption (in tons) per kilowatthour generated is higher for subbituminous and lignite than for bituminous coals, the shift to western coal is projected to increase the tonnage per kilowatthour of generation in the midwestern and southeastern regions. In the East, generators are expected to shift to lower sulfur Appalachian bituminous coals that contain more energy (Btu) per ton. Although coal is projected to maintain its fuel cost advantage over both oil and natural gas, gas-fired generation is expected to be the most economical choice for construction of new power generation units in most situations, when capital, operating, and fuel costs are considered. Between 2005 and 2020, rising natural gas costs and nuclear retirements are projected to cause increasing demand for coal-fired baseload capacity. Industrial Steam Coal Use Rises, But Demand for Coking Coal Declines In the non-electricity sectors, a projected increase of 7 million tons in industrial steam coal consumption between 1999 and 2020 (0.5-percent annual growth) is expected to be offset by a decrease of 9 million tons in coking coal consumption (Figure 121). Increasing consumption of industrial steam coal is projected to result primarily from greater use of existing coal-fired boilers in energy-intensive industries. The projected decline in domestic consumption of coking coal results from the expected displacement of raw steel production from integrated steel mills (which use coal coke for energy and as a material input) by increased production from minimills (which use electric arc furnaces that require no coal coke) and by increased imports of semi-finished steels. The amount of coke required per ton of pig iron produced is also declining, as process efficiency improves and injection of pulverized steam coal is used increasingly in blast furnaces. Domestic consumption of coking coal is projected to fall by 1.9 percent per year through 2020, but domestic production of coking coal is expected to be stabilized, in part, by sustained levels of export demand. Although total energy consumption in the combined residential and commercial sectors is projected to grow by 1.3 percent per year, most of the growth is expected to be captured by electricity and natural gas. Coal consumption in the residential and commercial sectors is projected to remain constant, accounting for less than 1 percent of total U.S. coal demand in the forecast. U.S. Coal Exports to Europe and Asia Are Projected To Remain Stable Figure 122. Projected U.S. coal exports by destination, 2010 and 2020 (million short tons) U.S. coal exports declined sharply between 1998 and 1999, from 78 million tons to 58 million tons, but are projected to remain relatively stable over the forecast horizon, settling at 56 million tons by 2020 (Figure 122). Australian and South African coal export prices dropped substantially in 1999, displacing U.S. coal exports to Europe and Asia. Price cuts by Australia, the world’s leading coal exporter, were attributed to both strong productivity growth and a favorable exchange rate against the U.S. dollar. The U.S. share of total world coal trade is projected to decline from 11 percent in 1999 to 8 percent by 2020 as international competition intensifies and demand for coal imports in Europe and the Americas grows more slowly or declines. From 1999 to 2020, U.S. steam coal exports are projected to decline slightly, from 26 million tons to 22 million tons, despite substantial projected growth in world steam coal trade. Steam coal exports from Australia, South Africa, China, and Indonesia are expected to increase in response to growing import demand in Asian countries, and increasing exports from South Africa are expected to displace some U.S. exports to Europe. U.S. coking coal exports are projected to increase slightly, from 32 million tons in 1999 to 34 million tons in 2020. A small increase in the world trade in coking coal is expected, primarily in Asia. Australia is expected to capture an increasing share of the international market for coking coal because of its proximity to Asian importers and its ample reserves of coking coal. Low-Sulfur Coal Continues To Gain Share in the Generation Market Figure 123. Projected coal production by sulfur content, 2010 and 2020 (million short tons) Phase 1 of CAAA90 required 261 coal-fired generating units to reduce sulfur dioxide emissions to about 2.5 pounds per million Btu of fuel. Phase 2, which took effect on January 1, 2000, tightens the annual emissions limits imposed on these large, higher emitting plants and also sets restrictions on smaller, cleaner plants fired with coal, oil, and gas. The program affects existing utility units serving generators over 25 megawatts capacity and all new utility units [94]. With relatively modest capital investments many generators can blend very low sulfur subbituminous and bituminous coal in Phase 1 affected boilers. Such fuel switching often generates sulfur dioxide allowances beyond those needed for Phase 1 compliance, and the excess allowances generated during Phase 1 were banked for use in Phase 2 or sold to other generators. (The proceeds of such sales can be seen as further reducing fuel costs for the seller.) In the forecast, fuel switching for regulatory compliance and for cost savings is projected to reduce the composite sulfur content of all coal produced (Figure 123). The main sources of low-sulfur coal are the Central Appalachian, Powder River Basin, and Rocky Mountain regions, as well as coal imports. Coal users may incur additional costs in the future if environmental problems associated with nitrogen oxides, particulate emissions, and possibly carbon dioxide emissions from coal combustion are monetized and added to the costs of coal combustion. |
