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Continued Growth Is Projected for Coal Production from Western Mines Figure 107. Coal production by region, 1970-2020 (million short tons)

Coal Production and Prices

Further Declines Are Seen for U.S. Minemouth Coal Prices

Figure 108. Average minemouth price of coal by region, 1990-2020 (1997 dollars per ton) 40- History Projections

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Eastern

U.S. average

Western

Continued improvements in mine productivity (averaging 6.2 percent a year since 1977) are projected to cause falling real mine prices throughout the forecast. Higher electricity demand and lower prices, in turn, yield increasing coal demand, but the demand is subject to a fixed sulfur emissions cap from CAAA90, which mandates 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 less sulfur emissions than the use of many types of higher sulfur eastern coal. As coal demand grows, 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 grows, there will still be a market for low-cost higher-sulfur coal throughout the forecast.

From 1997 to 2020, high- and medium-sulfur coal production rises from 654 to 662 million tons (0.1 percent a year), and low-sulfur coal production rises from 445 to 696 million tons (2.0 percent a year). As a result of the competition between low-sulfur coal and post-combustion sulfur removal, western coal production continues its historic growth, reaching 772 million tons in 2020 (Figure 107), but its annual growth rate falls from the 9.4 percent achieved between 1970 and 1997 to 1.8 percent in the forecast period.

1990 1995 95 20 2000 2005 2010 2015 2020 Minemouth coal prices declined by $4.97 per ton in 1997 dollars between 1970 and 1997, and they are projected to decline by 1.5 percent a year, or $5.40 per ton, between 1997 and 2020 (Figure 108). The price of coal delivered to electricity generators, which was essentially unchanged between 1970 and 1997, falls to $18.77 per ton in 2020-a 1.4-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 maintained throughout the forecast. Average U.S. labor productivity (Figure 109) follows the trend for eastern mines most closely, because eastern mining is more labor-intensive than western mining.

Figure 109. Coal mining labor productivity by
region, 1990-2020 (short tons per miner per hour)
40 History
Projections

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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 will also 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 lowsulfur coal mining. Western low-sulfur coal has been successfully tested in all U.S. Census divisions except New England and the Mid-Atlantic, and its penetration of eastern markets is projected to increase.

Eastern coalfields contain extensive reserves of higher sulfur coal in moderately thick seams suited to longwall mining. Maturing technologies for extracting and hauling high coal volumes in both surface and underground mining suggest 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 1997, the number of miners fell by 2.1 percent a year. With improvements continuing through 2020, a further decline of 1.3 percent a year in the number of miners is projected. The share of wages in minemouth coal prices [70], which fell from 31 percent to 17 percent between 1970 and 1997, is projected to decline to 15 percent by 2020 (Figure 110).

Alternative assumptions about future regional mining costs affect the market shares of eastern and western mines and the national average minemouth price of coal. In two alternative mining cost cases, demand for coal by electricity generators was allowed to respond to relative fuel prices, but coal demand from other sectors was held constant. Minemouth prices, delivered prices, and resultant regional coal production levels varied with changes in mining costs.

In the reference case projections, productivity increases by 2.3 percent a year through 2020, while wage rates are constant in 1997 dollars. The national minemouth coal price declines by 1.5 percent a year to $12.74 per ton in 2020 (Figure 111). In the low mining cost case, productivity increases by 3.8 percent a year, and real wages decline by 0.5 percent a year [71]. The average minemouth price falls by 2.4 percent a year to $10.42 per ton in 2020 (18.2 percent less than in the reference case). Eastern coal production is 17 million tons higher in the low 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 increases by only 1.2 percent a year, and real wages increase by 0.5 percent a year. The average minemouth price of coal falls by 0.8 percent a year to $14.94 per ton in 2020 (17.3 percent higher than in the reference case). Eastern production in 2020 is 52 million tons lower in the high labor cost case than in the reference case.

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The competition between coal and other fuels, and among coalfields, is influenced by coal transportation costs. Changes in fuel costs affect transportation rates (Figure 112), but fuel efficiency also grows with other productivity improvements in the forecast. As a result, in the reference case, average coal transportation rates decline by 1.1 percent a year between 1997 and 2020. The most rapid declines have occurred on routes that originate in coalfields with 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.

Expansion of the national market for Powder River Basin coal slowed during 1996 and 1997 as a result of rail service problems after the Union PacificSouthern Pacific railroad merger. Many Gulf Coast and Midwest consumers had problems maintaining coal stocks as the frequency and predictability of unit-train coal deliveries deteriorated. Improvements in the first two quarters of 1998 suggest that service efficiency is returning to pre-merger levels. Activities resulting from other mergers, such as the current integration of Conrail within Norfolk Southern and CSX, may cause similar short-term problems, but AEO99 projects that rail rates for coal will continue their historic decline in real terms.

A strong correlation between economic growth and electricity use accounts for the variation in coal demand across the economic growth cases (Figure 113), with domestic coal consumption ranging from 1,195 to 1,363 million tons. Of the difference, coal use for electricity generation makes up 144 million tons. The difference in total coal production between the two economic growth cases is 166 million tons, of which 94 million tons (57 percent) is projected to be western production. Despite the fact that western coal must travel up to 2,000 miles to reach some of its markets, when its transportation costs are added to its low mine price and low sulfur allowance cost, it remains competitively priced in all regions except the Northeast.

Changes in world oil prices affect the costs of energy (both diesel fuel and electricity) for coal mining. In the high and low oil price cases, average minemouth coal prices are 0.2 percent higher and 0.6 percent lower, respectively, in 2020 than in the reference case. The low world oil price case projects 33 million tons less coal use in 2020 than in the high world oil price case as low oil prices encourage electricity generation from oil, while high oil prices encourage greater coal consumption. About 55 percent of the difference in production levels is western coal needed to meet the sulfur emissions cap. The higher coal consumption in the high oil price case is shared between the electricity generation and industrial steam coal sectors, with electricity taking 28 million tons (85 percent) of the difference and the industrial sector gaining the rest.

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Domestic coal demand rises by 245 million tons in the forecast, from 1,030 million tons in 1997 to 1,275 million tons in 2020 (Figure 114), because of growth in coal use for electricity generation. Coal demand in other domestic end-use sectors increases by 3 million tons, as reduced coking coal consumption is offset by coal demand for industrial cogeneration. Coal consumption for electricity generation (excluding industrial cogeneration) rises from 924 million tons in 1997 to 1,166 million tons in 2020, due to increased utilization of existing generation capacity and, in later years, additions of new capacity. The average utilization rate for coal-fired power plants increases from 67 to 79 percent between 1997 and 2020. Coal consumption (in tons) per kilowatthour of generation is higher for subbituminous and lignite coals than for bituminous coal. Thus, the shift to western coal increases the tonnage per kilowatthour of generation in midwestern and southeastern regions. In the East, generators shift from higher to lower sulfur Appalachian bituminous coals that contain more energy (Btu) per short ton. Although coal maintains its fuel cost advantage over both oil and natural gas, gas-fired generation is the most economical choice for construction of new power generation units through 2010 when capital, operating, and fuel costs are considered. Between 2010 and 2020, rising natural gas costs and nuclear retirements are projected to cause increasing demand for coal-fired baseload capacity.

In the non-electricity sectors, an increase of 12 million tons in industrial steam coal consumption between 1997 and 2020 (0.7-percent annual growth) is offset by a decrease of 9 million tons in coking coal consumption (Figure 115). Increasing consumption of industrial steam coal results primarily from increased use of coal in the chemical and foodprocessing industries and from increased use of coal for cogeneration (the production of both electricity and usable heat for industrial processes).

The projected decline in domestic consumption of coking coal results from the 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 1.7 percent a year through 2020. Domestic production of coking coal is stabilized, in part, by sustained levels of export demand.

While total energy consumption in the residential and commercial sectors grows by 0.8 percent a year, most of the growth is captured by electricity and natural gas. Coal consumption in these sectors remains constant, accounting for less than 1 percent of total U.S. coal demand.

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U.S. coal exports rise slowly in the forecast, from 84 million tons in 1997 to 93 million in 2020 (Figure 116), primarily as a result of higher demand for steam coal imports in Asia. Exports of metallurgical coal in 2020 are slightly lower than the 1997 level. Worldwide trade in metallurgical coal declines slightly, reflecting generally slow growth in steel production and improved process efficiency, but the U.S. market share remains essentially unchanged.

U.S. steam coal exports to Europe increase from 13 million tons in 1997 to 20 million in 2020 (1.9percent annual growth). Europe's steam coal imports rise from 119 million tons in 1997 to 135 million tons in 2020 (0.5 percent a year), reflecting reduced subsidies for domestic coal production, as well as some new generating capacity. The AEO99 forecast for European imports is lower than some that have been provided by the governments of the importing nations themselves, where environmental considerations, including emerging carbon emissions issues, limit fuel choices.

U.S. coal exports to Asia increase by 1.6 percent a year, from 14 million tons in 1997 to 20 million in 2020, as metallurgical exports fall by 1.5 percent and steam coal exports rise by 3.8 percent annually. Coal imports to Asia from all sources rise by 1.6 percent a year, from 274 million tons in 1997 to 394 million in 2020, as Pacific Rim nations without indigenous fossil fuel resources base electricity generation on imported coal. Most of the growth in Asian imports is projected to be supplied by Australia, South Africa, China, and Indonesia.

Phase 1 of CAAA90 required 261 coal-fired generators to reduce sulfur dioxide emissions to about 2.5 pounds per million Btu of fuel. Phase 2, which begins in 2000, tightens the annual emissions limits imposed on these large, higher-emitting plants and also sets restrictions on smaller, cleaner plants fired by coal, oil, and gas. The program affects existing utility units serving generators over 25 megawatts capacity and all new utility units [72].

Relatively modest capital investments have allowed many generators to 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. Excess allowances are 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). Fuel switching for regulatory compli ance and cost savings is projected to reduce the composite sulfur content of all coal produced (Figure 117). National sulfur emissions from coal-fired generators have already declined by approximately 24 percent between 1990 and 1995 [73].

Coal users may incur additional costs in the future if environmental problems associated with nitrogen oxides, particulate emissions, and possibly CO2 emissions from coal combustion are monetized and added to the costs of coal combustion. The most probable method would be a regulatory market mechanism like that established under CAAA90 to price sulfur emissions.

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