Table 1. Coal Demand Regions and Relevant Characteristics, 1988, 1993, and 1997 | ||||||||||||||||||
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Demand Region | Total Domestic Coal Receipts | Domestic Coal Received by Electric Utility Generators |
Electric Utility Coal-Fired Generating Net Summer Capability |
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Thousand Short Tons | Percent of U.S. Total | Thousand Short Tons | Percent of U.S. Total | Capability (Gigawatts) | Percent of U.S. Total | |||||||||||||
1988 | 1993 | 1997 | 1988 | 1993 | 1997 | 1988 | 1993 | 1997 | 1988 | 1993 | 1997 | 1988 | 1993 | 1997 | 1988 | 1993 | 1997 | |
New England | 6,696 | 4,141 | 6,414 | 0.8 | 0.5 | 0.6 | 6,325 | 4,555 | 5,324 | 0.9 | 0.6 | 0.6 | 2.7 | 2.6 | 2.7 | 0.9 | 0.9 | 0.9 |
Middle Atlantic | 70,253 | 64,421 | 76,487 | 8.2 | 7.3 | 7.7 | 51,532 | 46,511 | 53,687 | 7.1 | 6.1 | 6.1 | 23.0 | 23.0 | 22.9 | 7.8 | 7.6 | 7.6 |
East North Central | 193,389 | 196,343 | 237,757 | 22.6 | 22.2 | 23.9 | 155,300 | 165,684 | 202,401 | 21.4 | 21.7 | 23.1 | 74.5 | 77.0 | 75.4 | 25.3 | 25.6 | 24.9 |
West North Central | 112,365 | 116,337 | 131,862 | 13.2 | 13.2 | 13.3 | 99,540 | 101,896 | 120,150 | 13.7 | 13.3 | 13.7 | 34.5 | 34.9 | 35.3 | 11.7 | 11.6 | 11.7 |
South Atlantic | 141,606 | 141,701 | 166,234 | 16.6 | 16.0 | 16.7 | 120,058 | 118,366 | 146,847 | 16.5 | 15.5 | 16.8 | 62.9 | 64.6 | 67.4 | 21.4 | 21.5 | 22.2 |
East South Central | 85,737 | 97,057 | 108,478 | 10.0 | 11.0 | 10.9 | 73,868 | 86,610 | 102,352 | 10.2 | 11.3 | 11.7 | 35.9 | 36.6 | 36.2 | 12.2 | 12.2 | 11.9 |
West South Central | 126,542 | 139,664 | 143,816 | 14.8 | 15.8 | 14.5 | 117,144 | 130,848 | 135,759 | 16.1 | 17.1 | 15.5 | 30.4 | 31.4 | 31.8 | 10.3 | 10.4 | 10.5 |
Mountain | 104,271 | 109,200 | 113,046 | 12.2 | 12.4 | 11.4 | 97,184 | 103,137 | 103,539 | 13.4 | 13.5 | 11.8 | 28.4 | 28.8 | 29.3 | 9.7 | 9.6 | 9.7 |
Pacific | 8,661 | 10,791 | 9,596 | 1.0 | 1.2 | 1.0 | 5,856 | 6,917 | 5,657 | 0.8 | 0.9 | 0.6 | 1.8 | 2.0 | 2.0 | 0.6 | 0.7 | 0.7 |
U.S. Total | 853,930 | 883,934 | 995,181 | 100.0 | 100.0 | 100.0 | 726,806 | 764,524 | 875,717 | 100.0 | 100.0 | 100.0 | 294.2 | 300.9 | 302.9 | 100.0 | 100.0 | 100.0 |
Notes: U.S. total coal receipts include those for which destination is unknown. U.S. total coal-fired generating capacity in Pacific Region includes non-contiguous States. Totals may
not equal sum of components because of independent rounding. Domestic coal accounted for 92.3 percent of total distribution in 1997. Sources: Total Domestic Coal Receipts - 1988: Coal Distribution Report 1988, Table 8. Total Domestic Coal Receipts - 1993: Coal Industry Annual 1993, pp. 101-102. Total Domestic Coal Receipts - 1997: Coal Industry Annual 1997, Table 61, pp. 104-105. Coal Received By Electric Generators - 1988: Coal Distribution Report 1988, Table 8. Coal Received By Electric Generators - 1993: Coal Distribution Report 1993, (Internal), Table 8. Coal Received By Electric Generators - 1997: Coal Distribution Report 1997, (Internal), Table 8. Capacity 1997 - Inventory of Power Plants in the United States, as of January 1, 1998, Table 16. |
The growth in coal receipts by electric utility generators in 1988, 1993, and 1997 is primarily due to the increased utilization of the existing electric utility owned coal-fired generating units rather than construction of new coal-fired power plants. The national average utilization rate for electric utility coal-fired power plants increased from 59.8 percent in 1988, to 62.2 percent in 1993, and 67.4 percent in 1997.(2) This increased utilization is in response to growth in the demand for electricity, as well as changes in electricity generation from other sources. The South Atlantic Division, however, did have four new electric utility owned coal-fired units come online in 1996. Electric utilities experienced an average annual growth in retail sales of 2.2 percent between 1988 and 1997. (3) Coal-fired generation increased with this demand for electricity and maintained a national average share of total electric utility generation of 57 percent over this time period. The coal share of total electricity generation, including nonutility generation, was also constant at approximately 53 percent. (4) However, regional differences in the share of electricity produced by coal did occur between 1993 and 1997 due to changes in use of petroleum, nuclear power, and hydroelectric generation. Nuclear-powered generation declined significantly in 1997 from the previous year, because several nuclear units were shut down for all or part of 1997. In the East North Central Division, the nuclear generation was even lower in 1997 than it was in 1993, 36 billion kilowatt-hours less.(5) As a result, the coal share of total electric utility generation increased from 73 to 80 percent in that region and coal receipts by electric generators increased commensurately. In the East South Central Division, the opposite occurred. Nuclear generation increased by 36 billion kilowatthours between 1993 and 1997. Coal receipts by electric generators continued to increase, however, due to increases in demand for electricity, even as the coal share of total electric utility generation declined from 79 percent to 70 percent. In the Middle Atlantic Division, decreased oil-fired generation created more demand for coal in 1997. This increased utilization of existing coal-fired power plants occurred at the same time that utilities were required to comply with Phase I of the CAAA90. The emission allowances allocated to each plant for Phase I are based on an emission rate of 2.5 pounds of SO2 per million British thermal units(6) consumed and the historical average fuel consumption by the plant in 1985 through 1987. During 1985, utilization rates were much lower, approximately 56 percent(7) as compared to 67 percent in 1997. Since more coal was being consumed by the coal-fired power plants in 1997 than in 1985 through 1987, additional actions had to be taken to reduce emissions to the allowance levels. Most of the coal-fired power plants affected by Phase I are located in the following five regions--Middle Atlantic, East North Central, West North Central, South Atlantic, and East South Central. A few additional coal-fired units, that were substituted for the original units named in the legislation, are located in Massachusetts and Wyoming.(8)
In the five key Census Divisions mentioned above, the SO2 emissions from all coal-fired plants, not just those affected by Phase I, were lower in 1995 than they were in 1988 (Figure 2). Reductions in emissions were observed even before Phase I began in 1995, as some utilities started testing lower sulfur coals in their power plants. After 1995 the emissions from coal-fired power plants in the East North Central and the South Atlantic Divisions began to rise, however, as coal-fired generation increased to satisfy greater demand for electricity and to replace the reduced generation from nuclear plants. Although the SO2 emissions were higher, all utilities had the necessary emission allowances and were in compliance with the Phase I requirements. The reduction in SO2 emissions has occurred, in part, through a change in the type of coal contracted for and received by electric utilities. Nationwide, the sulfur content of the coal receipts, expressed as pounds of sulfur per million Btu, declined by 13 percent between 1988 and 1997 (Table 2). Most of that decline occurred by 1993 as utilities were beginning to test new or blended coals in their plant boilers. The decline was greatest in the East North Central and West North Central Divisions, where the average sulfur content fell by 22 and 47 percent, respectively, from 1988 to 1997. The sulfur content of coal received by electric utilities in the South Atlantic and East South Central Divisions also went down over those years. The sulfur content of coal receipts in the West South Central and Mountain regions did not decline, but it was already lower than the national average. In general, those regions were not affected by the Phase I requirements, except through a few
substitution units located in Wyoming. Coal-fired power plants in the Middle Atlantic region met the requirements of Phase I by installing flue gas desulfurization equipment on some of the coal-fired power plants and by obtaining additional allowances for most of the others. Although a few plants did shift to a lower sulfur coal, the average sulfur content of all coal receipts in the region did not decline from the 1988 levels.
The national average Btu per pound of coal received, i.e. the heat content of the coal, declined slightly over these years, less than 2 percent. However, this decline in the heat content of coal receipts accounts for approximately 10 percent of the increase in the tonnage of reported coal receipts. The largest decreases in heat content, of 4.8, 3.6, and 2.8
percent, occurred in three regions, East North Central, West North Central, and East South Central, respectively,
between 1988 and 1997. Since coal characteristics vary across the supply regions, these changes indicate that the sources
of coal supplied to the electric generators have changed. The supply and distribution patterns are described in the
following sections. Coal Supply By Region Regions Defined
The Nation's coal supply regions are illustrated in Figure 3 and their respective contributions to 1997 total supply are contained in Table 3. Compared with coal demand regions, which are based upon State boundaries and Census Divisions, definitions of the Nation's coal supply regions are somewhat more complex. They evolved from producing district boundaries defined in the Bituminous Coal Act of 1937 and, especially in the East, were based upon the location of mining districts and their associated river and rail transportation infrastructure.
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Regional Coal Characteristics
Despite its apparent simplicity, coal is a complex substance with myriad chemical characteristics that determine its suitability for use as a fuel and as a key ingredient in the manufacture of steel and other products. Among the most important distinguishing characteristics of coal are heat content, sulfur content, and ash content.
While a detailed examination of the Nation's coal characteristics by supply region is beyond the scope of this report, general observations about the characteristics of the Nation's coal supplies provide a useful framework for this analysis.
The Powder River Basin of Wyoming is the Nation's leading source of low-sulfur, low-Btu subbituminous coal. Coal from this region typically has a heating value in the range of 8,500 to 8,900 Btu per pound with a sulfur content of 0.3 to 0.5 pounds of sulfur per million Btu.
The Central Appalachian region, comprising roughly Virginia, the eastern portion of Kentucky, and the southern portion of West Virginia, is the Nation's primary source of bituminous coal that is relatively low in sulfur. Heat content is significantly higher than Wyoming coal. Heating values for Central Appalachian coal average approximately 12,500
Btu per pound, with a sulfur content averaging 0.85 pounds of sulfur per million Btu.
Similarly, coal from the Southern Appalachian Region, which includes Alabama and Tennessee, features an average heat content of about 12,500 Btu per pound, but a moderately higher sulfur content in the range of 0.8 to 1.2 pounds
of sulfur per million Btu.
By comparison, coal from Northern Appalachia (Maryland, Ohio, northern West Virginia, and the bituminous coal regions of Pennsylvania) and from the Illinois Basin (western Kentucky, Illinois and Indiana) has a relatively high sulfur
content, ranging from 1.4 to 3.5 pounds sulfur per million Btu, with heating values in the range of 11,000 to 13,000 Btu
per pound.
Coals being produced from the Rockies (including primarily Colorado and Utah) and from the Southwest region are similar in sulfur content to Wyoming coal but have a substantially higher range of heating values. Southwest region
subbituminous and bituminous coals range from 9,000 to 12,000 Btu per pound. Colorado and Utah bituminous coals
are typically in excess of 11,000 Btu per pound. The coal-producing regions of Texas, Louisiana, and North Dakota
are characterized by lignite, a brownish-black coal of low rank with a high moisture content. Heating values for
currently mined lignites average about 6,500 Btu per pound.(9)
Coal Distribution Shares By Supply Region
Unlike shares of total coal demand by region, the domestic coal distribution shares attributable to the various coal supply regions changed significantly between 1988 and 1997. As shown in Figure 4, the supply regions most affected by these changes have been Northern Appalachia, the Illinois Basin, and Powder River Basin.
Nationwide, the share of coal from Northern Appalachia declined from 16.5 in 1988 to 13.5 percent in 1993, before rising to 14.0 percent in 1997. Similarly, the share attributable to coal fields in the Illinois Basin declined from 15.2 percent in 1988 to 10.9 percent in 1997. Concurrently, the share of distributed coal originating in the Powder River Basin increased from 24.3 percent in 1988 to 32.0 percent in 1997. Overall, the following trends emerge from the information presented in Table 4.
Concurrently, the combined portion of coal supplied by the Powder River Basin and the Rockies soared from 18.8 percent in 1988 to 36 percent in 1997.
Between 1988 and 1997, the most pronounced shifts in mode occurred in the East South Central, Mountain, and East North Central demand regions. In the East South Central region, the rail share of total shipments increased from 40.2 percent in 1988 to 47.2 percent in 1997. This shift occurred mostly at the expense of truck shipments, which declined in share from 21.5 percent to 15.7 percent, reflecting the shift in coal sources from Central and Southern Appalachia and the Illinois Basin to the Powder River Basin and the Rockies. Similarly, the share of coal moving by rail to the East North Central region increased from 58 percent in 1988 to 63.4 percent in 1997, clearly reflecting the region's increased reliance upon coal from the Powder River Basin and the Rockies. In the Middle Atlantic Region, the shares of coal moved by rail and by truck gained sharply between 1988 and 1993, largely as a result of decreased shipments by conveyor in the region. By 1997, however, the share of coal moving to the region by rail returned to roughly the level observed in 1988 as shipments by barge, and to a lesser extent by truck, gained market share. In the Mountain region, the share of coal supplied by rail increased from 48.2 percent in 1988 to 56.6 percent in 1997 while the share supplied by other modes (primarily tramway) declined from 34.1 percent in 1988 to 25.5 percent in 1997. Most of this shift occurred between 1992 and 1993 and was attributable to a shift from tramway to rail for New Mexico coal supplied to power generators in New Mexico. 1. Independent power producers are defined in this report as nonutility wholesale producers of electricity that are not included in the industrial or commercial sectors. They have an industrial classification code of NAICS 22 and account for approximately 2 percent of the coal consumed by electric generators in 1997. 2. Energy Information Administration, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000), Tables 8.3 and 8.6. 3. Ibid., Table 8.9. 4. Ibid., Tables 8.2 and 8.3. 5. Energy Information Administration, Electric Power Annual 1993, DOE/EIA-0348(93) (Washington, DC, December 1994), Table 13. Energy Information Administration, Electric Power Annual 1997 Volume I, DOE/EIA-0348(97/1) (Washington, DC, July 1998), Table 10. 6. British thermal unit is a measure of the heat content of a quantity of coal or other fuel. It is the quantity of heat needed to raise the temperature of 1 pound of water by 1 F at or near 39.2 F. Also,2.5 pounds of SO2 emissions are equivalent to 1.25 pounds of sulfur. In the coal (assumingcomplete combustion). 7. Energy Information Administration, Inventory of Power Plants in the United States 1985, DOE/EIA-0095(85) (Washington, DC, August 1986), Table 1. Energy Information Administration, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000), Table 8.3. 8. Energy Information Administration, The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update, DOE/EIA-0582(97) (Washington, DC, March 1997), Table B1. 9. Sulfur and Btu values based on coal delivered to electric utilities. Energy Information Administration,Cost and Quality of Fuels for Electric Utility Plants 1998 Tables, DOE/EIA-0191 (Washington, DC, June 1999), Table 23. |