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 minemouth average 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.

Coal Consumption

Electricity Generation Sets the Trend for U.S. Coal Consumption

Figure 114. Electricity and other coal consumption, 1970-2020 (million short tons per year)

Industrial Coal Use

Is Projected To Increase

Figure 115. Non-electricity coal consumption by sector, 1997, 2000, and 2020 (million short tons)

1,500

History

Projections

Total Electricity

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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Petroleum products are the leading source of carbon emissions from energy use. In 2020, petroleum is projected to contribute 823 million metric tons of carbon to the total 1,975 million tons, a 42-percent share (Figure 120). About 81 percent (665 million metric tons) of the petroleum emissions result from transportation use, which could be lower with less travel or more rapid development and adoption of higher efficiency or alternative-fuel vehicles.

Coal is the second leading source of carbon emissions, projected to produce 676 million metric tons in 2020, or 34 percent of the total. The share declines from 36 percent in 1997 because coal consumption increases at a slower rate through 2020 than consumption of petroleum and natural gas, the sources of virtually all other energy-related carbon emissions. Most of the increases in coal emissions result from electricity generation. A slight increase in emissions from industrial steam coal use is partially offset by a decline in emissions from coking coal.

Electricity use is a major cause of carbon emissions. Although electricity produces no emissions at the point of use, its generation currently accounts for 36 percent of total carbon emissions, and that share is expected to increase to 38 percent in 2020. Coal, which accounts for about 52 percent of electricity generation in 2020 (excluding cogeneration), produces 81 percent of electricity-related carbon emissions (Figure 121). In 2020, natural gas accounts for 30 percent of electricity generation but only 18 percent of electricity-related carbon emissions.

Between 1997 and 2020, 50 gigawatts of nuclear capacity are expected to be retired, resulting in a 43percent decline in nuclear generation. To compensate for the loss of nuclear capacity and meet rising demand, 345 gigawatts of new fossil-fueled capacity (excluding cogeneration) will be needed. Increased generation from fossil fuels will raise electricity. related carbon emissions by 213 million metric tons, or 40 percent, from 1997 levels. Generation from renewable technologies increases by 53 billion kilowatthours, or 12 percent, between 1997 and 2020 but is insufficient to offset the projected increase in generation from fossil fuels.

In 2020, natural gas use is projected to produce 475 million metric tons of carbon emissions, a 24percent share. Of the fossil fuels, natural gas consumption and emissions increase most rapidly through 2020, at average annual rates of 1.7 percent; however, natural gas produces only half the carbon emissions of coal per unit of input. Average emissions from petroleum use are between those for coal and natural gas. The use of renewable fuels and nuclear generation, which emit little or no carbon, mitigates the growth of emissions.

The projections include announced activities under the Climate Challenge program, such as fuel switching, repowering, life extension, and demand-side management, but they do not include offset activities, such as reforestation. Additional use of lower carbon fuels, reduced electricity demand growth, or improved technologies all could contribute to lower emissions than are projected here.

1990 1995 2000 2005 2010 2015 2020 CAAA90 called for annual emissions of sulfur dioxide (SO2) by electricity generators to be reduced to approximately 12 million short tons in 1996, 9.48 million tons between 2000 and 2009, and 8.95 million tons a year thereafter. More than 95 percent of the SO2 produced by generators results from coal combustion, with the rest from residual oil.

In Phase 1, 261 generating units at 110 plants were issued tradable emissions allowances permitting SO2 emissions to reach a fixed amount per yeargenerally less than the plant's historical emissions. Allowances may also be banked for use in future years. Switching to lower sulfur, subbituminous coal was the option chosen by more than half of the generators. In Phase 2, beginning in 2000, emissions constraints on Phase 1 plants will be tightened, and limits will be set for the remaining 2,500 boilers at 1,000 plants. With allowance banking, emissions are expected to decline from 11.9 million tons in 1995 to 11.4 million in 2000 (Figure 122). Since allowance prices are projected to increase after 2000, it is expected that 26.4 gigawatts of capacityabout 88 300-megawatt plants-will be retrofitted with scrubbers to meet the Phase 2 goal (Table 11).

86

2000 2005 2010 2015 2020

13.6 13.6 25.8 26.4 26.4

90 240 293 182 130

Nitrogen oxide (NO) emissions in the United States will fall significantly over the next 5 years as new legislation takes effect (Figure 123). First will be the second phase of the NOx reduction program from CAAA90, which calls for NOx reductions at electric power plants in two phases-the first in 1995 and the second in 2000. It is expected that the second phase of CAAA90 will result in NO, reductions of 1.5 million tons between 1999 and 2000.

A second piece of legislation, the ozone transport rule (OTR), will take effect in 2003. After studying the ozone transport problem, the U.S. Environmental Protection Agency (EPA) issued the OTR in September 1997. The OTR sets caps on NO, emissions in each of 22 midwestern and eastern States during the 5-month summer season (May through September). The EPA wants to establish a cap and trade program with tradable emission permits. Holders of the permits would be free to use them themselves or sell them to someone whose NOx emission reduction options are more costly.

The OTR is expected lead to a total NO, emissions reduction of 0.7 million tons between 2002 and 2003 as control technologies are installed on utility boilers. By 2020, 10 gigawatts of capacity is expected to be retrofitted with advanced combustion controls, selective noncatalytic reduction units (SNCR) are expected to be added to 96 gigawatts, and selective catalytic reduction units (SCR) are expected to be added to 111 gigawatts. The annualized cost is estimated to be $2 billion, relative to about $200 billion in annual consumer expenditures for electricity.