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Report
#:DOE/EIA-0383(2003) Released January 9, 2003 (Next Release: January 2004) Projection
and Year by Year Tables Previous
Annual Energy Outlooks |
Annual Energy Outlook 2003 with Projections to 2025 Market Trends - Coal Coal Production and Prices | Coal Mining Labor Productivity | Coal Transportation Costs | Coal Consumption | Coal Exports Emissions Caps Lead to More Use of Low-Sulfur Coal From Western Mines Continued improvements in mine productivity (which have averaged 6.2 percent per year since 1980) 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, 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 higher sulfur coal throughout the forecast. From 2001 to 2025, high- and medium-sulfur coal production is projected to increase from 598 to 607 million tons (0.1 percent per year), and low-sulfur coal production is projected to rise from 540 to 833 million tons (1.8 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 887 million tons in 2025 (Figure 101), but its annual growth rate is projected to fall from the 8.7 percent achieved between 1970 and 2001 to 1.7 percent in the forecast period. Rate of Decline in Minemouth Coal Price Is Expected To Slow Minemouth coal prices declined by $6.27 per ton (in 2001 dollars) between 1970 and 2001, and they are projected to decline by 0.8 percent per year, or $3.23 per ton, between 2001 and 2025 (Figure 102). The price of coal delivered to electricity generators, which declined by $2.17 per ton between 1970 and 2001, is projected to fall to $22.17 per ton in 2025—a 0.5-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 103) is projected to follow the trend for eastern mines most closely, because eastern mining is more labor-intensive than western mining. Coal Mining Labor Productivity Labor Costs as Share of Minemouth Coal Revenues Continue to Decline 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 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 by many electricity generators, 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 2001, the average number of miners working daily fell by 2.0 percent per year. With production increases and productivity improvements expected to continue through 2025, a further decline of 0.5 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 [47], which fell from 31 percent to 16 percent between 1970 and 2001, is projected to decline to 13 percent by 2025 (Figure 104). Lower Mining Cost Assumptions Lead to Higher 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 1.6 percent per year through 2025 in the reference case, while wage rates and equipment costs are constant in 2001 dollars. The national minemouth coal price is projected to decline by 0.8 percent per year to $14.36 per ton in 2025 (Figure 105). In the low mining cost case, productivity is assumed to increase by 3.1 percent per year, and real wages and equipment costs are assumed to decline by 0.5 percent per year [48]. As a result, the average minemouth price is projected to fall by 1.6 percent per year to $11.96 per ton in 2025 (17 percent less than projected in the reference case). Eastern coal production is projected to be 46 million tons higher in the low mining cost case than in the reference case in 2025, reflecting the higher labor intensity of mining in eastern coalfields. In the high mining cost case, productivity is assumed to increase by 0.1 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 0.1 percent per year to $17.24 per ton in 2025 (20 percent higher than in the reference case). Eastern production in 2025 is projected to be 60 million tons lower in the high mining cost case than in the reference case. Transportation Costs Are a Key Factor for Coal Markets Changes in transportation costs affect the competition between coal and other fuels and among coalfields. In 1997, transportation costs averaged 41 percent of the delivered price of contract coal shipments to electric utilities [49]. With the expectation of nationally declining minemouth prices, along with increases in average shipping distances as western coal expands market share, the average percentage is expected to rise. Increases in fuel costs affect transportation costs (Figure 106), but they are also influenced by improvements in transportation fuel efficiency. Overall, in the reference case, average coal transportation costs are projected to decline by 1.2 percent per year between 2001 and 2025. 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 and increases in production. For instance, in the Powder River Basin supply region, the average transportation rate per ton for contract shipments to electric utilities decreased by 35 percent between 1988 and 1997, while shipped tonnage increased by 74 percent [50]. For coal from the Powder River Basin, where transportation can make up 60 percent or more of delivered cost, lower transportation costs could further increase its market share. Also, with Phase 2 of CAAA90, which became effective on January 1, 2000, mines in the Powder River Basin will require expansion of their train-loading capacities to meet the increase in demand for low-sulfur coal. 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 107), with domestic coal consumption in 2025 projected to range from 1,381 to 1,524 million tons in the low and high economic growth cases, respectively. Of the difference, coal use for electricity generation is projected to make up 133 million tons. The difference in total projected coal production between the two economic growth cases is 144 million tons, of which 54 million tons (37 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 be competitively priced in all regions except the Northeast. The world oil price cases show relatively small changes in coal use for electricity generation. The low price case projects only 8 million tons less coal use for electricity generation in 2025 than is projected in the high price case. Low oil prices encourage electricity generation from existing oil-fired units, reducing generation from other fuels, but because oil-fired generation represents a very small proportion of total generation, its impact on coal consumption is minor, even in the high world oil price case. Although changes in oil prices are expected to have little effect on coal-fired generation, high oil prices could stimulate the coal-to-liquids market. In the high world oil price case, 19 million tons of coal is projected to be converted to roughly 35 million barrels of fuel liquids in 2025. Coal Consumption for Electricity Continues To Rise in the Forecast Domestic coal demand is projected to increase by 394 million tons in the reference case forecast, from 1,050 million tons in 2001 to 1,444 million tons in 2025 (Figure 108), because of projected growth in coal use for electricity generation. Total coal demand in other domestic end-use sectors is projected to remain relatively constant. Coal consumption for electricity generation is projected to increase from 957 million tons in 2001 to 1,350 million tons in 2025 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 69 percent in 2001 to 83 percent in 2025. 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 Midwest and Southeast 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 2025, rising natural gas costs, increasing demand for electricity, and retirements of existing fossil-fired steam capacity are projected to result in increasing demand for coal-fired baseload capacity. Industrial Steam Coal Use Rises, But Demand for Coking Coal Declines For applications other than electricity generation, a projected increase of 8 million tons in industrial steam coal consumption between 2001 and 2025 (0.5 percent annual growth) is expected to be offset by a decrease of 8 million tons in coking coal consumption (Figure 109). 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 1.5 percent per year through 2025. 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 the Americas Are Projected To Decline U.S. coal exports declined sharply between 1998 and 2001, from 78 million tons to 49 million tons, and are projected to continue to decline over the forecast horizon, reaching 26 million tons by 2025 (Figure 110). The most recent decline in U.S. coal exports occurred against the backdrop of a world coal market that saw an increase in trade from 546 million tons in 1998 to 650 million tons in 2001. While China and Indonesia satisfied much of the growth in international steam coal demand, low-cost supplies of coking coal from Australia supplanted substantial amounts of U.S. coking coal in the world market. The U.S. share of total world coal trade is projected to decline from 7 percent in 2001 to 3 percent by 2025 as international competition intensifies and demand for coal imports in Europe and the Americas grows more slowly or declines. From 2001 to 2025, U.S. steam coal exports are projected to decline from 23 million tons to 10 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. Increasing exports from South America (Colombia and Venezuela) are expected to lead to a gradual increase in that region’s share of the market for steam coal both in Europe and in the Americas. U.S. coking coal exports are projected to decline from 25 million tons in 2001 to 16 million tons in 2025. A small increase in the world trade in coking coal is expected, primarily in Asia. Low-Sulfur Coal Continues To Gain Share in the Generation Market 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, tightened 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 [51]. During Phase 1, many generators switched either partly or entirely from higher sulfur bituminous coals to low-sulfur subbituminous coal, incurring relatively modest capital investments. Such fuel switching often generated 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. 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 111). The main sources of low-sulfur coal are the Central Appalachian, Powder River Basin, and Rocky Mountain regions, and coal imported from Colombia. Coal users are likely to incur additional costs in the future as additional or new restrictions on emissions of nitrogen oxides, particulates, mercury, or carbon dioxide are adopted. An example of a proposal to further reduce emissions from U.S. power plants is the Bush Administration’s Clear Skies Initiative. Relative to current law and regulations, the Administration’s proposal specifies further restrictions on emissions of nitrogen oxides and sulfur dioxide and would introduce a national cap on mercury emissions. |