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The Future of Illinois Basin Coal
1 994 and Beyond
Subhash B. Bhagwat
NOV 0 5 1987
UL STATE
Department of Energy and Natural Resources ILLINOIS STATE GEOLOGICAL SURVEY
ILLINOIS MINERAL NOTES 97
1987
Editor: Andrea Van Proyen Graphic Artist: John L. Moss
Bhagwat, Subhash B.
The future of Illinois Basin coal : 1 994 and beyond / Subhash B. Bhagwat. — Champaign, IL : Illinois State Geological Survey 1987.
26 p. ; 28 cm. — (Illinois Mineral Notes ; 97)
1 . Coal — Illinois Basin — Economic aspects. 2. Coal trade — Il- linois Basin. I. Title. II. Series.
Printed by authority of the State of Illinois/1987/1000
ILLINOIS STATE GEOLOGICAL SURVEY
3 3051 00005 9687
The Future of Illinois Basin Coal:
1 994 and Beyond
Subhash B. Bhagwat
LI&tfAK*
NOV 0 5 1987
III STAR fiEBUgfSJi ft
ILLINOIS STATE GEOLOGICAL SURVEY Morris W. Leighton, Chief Natural Resources Building 615 East Peabody Drive Champaign, Illinois 61820
ILLINOIS MINERAL NOTES 97 1987
Digitized by the Internet Archive
in 2012 with funding from
University of Illinois Urbana-Champaign
http://archive.org/details/futureofillinois97bhag
CONTENTS
ABSTRACT v
INTRODUCTION 1
THE CLEAN AIR ACT 1
THE LAST QUARTER-CENTURY OF U.S. COAL PRODUCTION 3
MARKETS FOR ILLINOIS BASIN COAL, 1975-1985 3
Utility Markets 3
State-by-state breakdown of utility market shares 5
Impact of western coals on Illinois Basin utility markets 8 Non-utility Markets 12 Cost Competitiveness 13 Conclusions from 1975-1985 Market Analysis 15
MARKETS FOR ILLINOIS BASIN COAL, 1994 AND BEYOND 16
Scenario 1 : Continued Application of Current Regulations 16 Scenario 2: Acid Rain Legislation Requiring Further S02 Reduction 20
REFERENCES 26
FIGURES
1 Trends in U.S. and Illinois Basin coal production, 1930-1986 4
2 Shipments of Illinois Basin coal to electric utilities, 1 975-1 985 5
3 Districts in the U.S. that produce bituminous and subbituminous coal and lignite 1 0
4 1985 railroad freight rates for coal 15
5 Forced outage rate of coal-fired steam units 23
6 Age and megawatt capability of coal-fired steam units 23
TABLES
1 Shipments of Illinois coal to utilities by state 6
2 Shipments of Indiana coal to utilities by state 6
3 Shipments of western Kentucky coal to utilities by state 7
4 Total 1 975 and 1 985 utility markets and shares held by Illinois Basin states 9
5 Western coals sold to utility markets of Illinois Basin coal, 1 975 and 1 985 1 1
6 Shipments of Illinois Basin coal to non-utility markets, 1 975 and 1 985 1 2
7 FOB mine price and labor productivity for major coal-producing states, 1984 14
8 Average delivered cost of coal supplied to electric utilities, 1985 14
9 Coal-burning electric utilities that started operation from 1 981 -1 985 in Illinois Basin market states 17
1 0 New coal-burning electric capacity expected to come on line by 1 994 in Illinois Basin market states 20
1 1 FGD capacities and sulfur contents of coal in utility plants planned in the Illinois Basin coal market states 20
1 2 Sulfur dioxide reduction targets as per proposed 1 986 acid rain bill 22
1 3 Btu/lb and percentage sulfur of Illinois Basin coal received by utilities, 1 975 25
1 4 Btu/lb and percentage sulfur of Illinois coal received by utilities, 1 984 25
1 5 Projected markets for Illinois Basin coal in 1 994 and 2000 if acid rain legislation enacted 26
ABSTRACT
Since the Clean Air Act was implemented in 1971, production of high-sulfur Illinois Basin coal has stagnated, while total U.S. coal production has continued to increase. Illinois Basin coal production figures for the years 1975 through 1985 show that low- sulfur western coals have successfully captured newly developing coal markets that traditionally would have been Illinois Basin coal markets, despite revisions in the Clean Air Act aimed at reducing the disadvantage of high-sulfur coals in the market- place. The continuing weak position of Illinois Basin coal is attributed to a lack of cost competitiveness. It is predicted that Illinois Basin coal production will continue to lag through 1994 and beyond if current clean air regulations are enforced and the price of Illinois Basin coal does not become competitive. If acid rain legislation is enacted, production of Illinois Basin coal will undoubtedly decrease, resulting in the loss of thousands of mining jobs.
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INTRODUCTION
By 1994, the most stringent clean air standards in U.S. history could go into effect. This legislation could further reduce the markets for Illinois Basin coal, already seriously eroded. The Illinois Basin, which covers a large part of Illinois and extends into southwestern Indiana and western Kentucky, has extensive reserves of bituminous coal; however, because of the coal s high sulfur content, production has been virtually stagnant since implementation of the Clean Air Act in 1970, even after later revisions to the act aimed at improving the market for high-sulfur coals. Total U.S. coal production has continued to increase in the same time period.
This paper analyzes the utility and non-utility markets for Illinois Basin coal for 1975 through 1985 and projects Illinois Basin coal production under two different scenarios: (1) continued enforcement of current legislation and (2) enactment of acid rain legislation. Background information is provided on the Clean Air Act and on U.S. coal production.
THE CLEAN AIR ACT
Although the Clean Air Act was passed in 1963, it was not until 1970 that the federal government empowered the U.S. Environmental Protection Agency (USEPA) to set uniform air quality standards. Under the act, the USEPA has set National Ambient Air Quality Standards (NAAQS) for ambient pollutant concentrations for seven of the most common and widespread pollutants: sulfur dioxide (S02), nitrogen oxides (NOx), particulate matter, lead, carbon dioxide, hydrocarbons, and ozone. The Clean Air Act limits the amount of S02 , NOx, and particulates that may be emitted by coal- fired boilers.
For enforcement purposes, the United States was divided into 274 air quality control regions. Each region has to meet the limits imposed by the NAAQS. Control regions within state boundaries where the ambient pollutant concentrations are below or meet the NAAQS are designated as attainment areas. Areas where the ambient pollutant concentrations are above the NAAQS are designated as nonattainment areas. In nonattainment areas, the states are required to devise a strategy to ensure that the minimum standards set by the USEPA are met and maintained. This strategy is incorporated into State Implementation Plans, or SIPs. New and modified pollution sources within nonattainment areas are required to meet the lowest achievable emission regardless of cost.
For plants built prior to 1971, S02 emissions are to be gradually lowered via the SIPs, with the ultimate goal of bringing their emissions down to meet the NAAQS. The time for achieving this objective was not fixed. However, the SIPs were subject to approval by the USEPA. In the early 1980s, the SIPs were revised,
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and although they still permit relatively high levels of S02 emis- sions from some plants, there is general consensus among the states that plants built prior to 1971 should not emit over 2.0 pounds per million British thermal units (106 Btu) of heat input.
The 1971 New Source Performance Standards (NSPS) issued by the USEPA required that utility coal -fired boilers of 73-megawatt (MW) output or greater, on which construction or modification had begun after August 17, 1971, could not emit more than 1.2 lbs S02/106 Btu. Plant operators were required to use "continuous emission monitoring" to measure the S02 emission levels in the flue gas outlets of coal-fired boilers. If the average emission level exceeded that specified by the NSPS for more than 3 hours, the plant could be cited for violation.
In 1977, the Clean Air Act was amended to require that states set limits on the existing pollution sources within nonattainment areas. It was specified that such sources must use "reasonably available pollution control technologies" (RACT). Both technological and economic feasibility are considered when applying RACT to existing sources. In attainment areas, new and modified pollution sources are regulated to "prevent significant deterioration" (PSD) of the clean air within the control region. These sources are required to use the "best available control technology" (BACT). BACT is an emission limitation based on the maximum degree of reduction that can be achieved when energy, environmental, and other costs are considered.
In 1979, the USEPA issued the Revised New Source Performance Standards (RNSPS). These standards are more stringent than the NSPS and apply to all coal-fired utility plants capable of producing more than 73 MW of generating capacity and on which construction or modification began after September 18, 1978.
The RNSPS retain the 1971 NSPS standard of 1.2 lbs S02/106 Btu of heat input as a ceiling for emissions, but additionally requires that S02 emissions from all new or modified (post-1978) boilers be reduced on a sliding scale of percentages that considers the different sulfur contents of U.S. coals. All coals burned must have at least 90 percent of the S02 removed from their emissions, unless 90-percent removal reduces emissions to less than 0.6 lbs/106 Btu. If emissions go below that level, reductions between 70 and 90 percent are permitted, depending on the sulfur content of the coal. Utilities are required to monitor S02 emissions continuously, both at the flue gas inlet and at the outlet of these new sources, to determine whether the required removal is attained on a 24-hour rolling average. The RNSPS regulations require the use of some form of flue-gas desulfurization (FGD) unit, or scrubber, for all new or modified utility boilers, since only scrubbers can reduce emissions by more than 70 percent. (1)
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THE LAST QUARTER-CENTURY OF U.S. COAL PRODUCTION
Since 1961, the U.S. coal -mining industry has grown an average of 3 3 percent per year, although there have been significant year- to-year fluctuations (fig. 1). Total U.S. coal production in- creased from about 410 million tons in 1961, to 660 million tons in 1975, to an estimated 900 million tons in 1986. Coal exports to other countries accounted for 8.5 percent of U.S. production in 1960, 7.6 percent in 1975, and is estimated at 10 percent for 1985.
Low-sulfur western coals have accounted for an increasing percent- age of total U.S. coal production the last 10 years, due to both increased demand for electricity in the western states and the implementation of clean air regulations throughout the U.S. In 1975, about 15.5 percent (100 million tons) of U.S. coal came from the western coal basin states. By 1985, western coal basin states accounted for 30.5 percent (270 million tons) of U.S. coal produc- tion. In the same 10-year period, coal production in the rest of the U.S. increased by only 13 percent (70 million tons).
None of this 13 percent increase in non-western coal production came from the Illinois Basin. From 1975 through 1985, coal pro- duction in the Illinois Basin stagnated at between 120 and 140 million tons (except for 1978 and 1981, which were strike years).
MARKETS FOR ILLINOIS BASIN COAL, 1975-1985
The most important market for Illinois Basin coal is electric utilities. From 1975 through 1985, about 89 percent of Illinois Basin coal was shipped to electric utilities. The remaining 11 percent of Illinois Basin coal is used by coke and gas plants and small industrial users that generate steam (see section "Non- utility Markets").
Utility Markets
Figure 2 shows total sales of Illinois Basin coal to utilities from 1975 through 1985, with estimates for sales for 1986. As one can see, there have been fluctuations in total sales to utilities during this period. Data on shipments for 1978, 1979, 1981, 1982, 1984, and 1985 were adjusted to account for the effect on sales of the mine worker strikes in 1978 and 1981 and the threat of a strike in 1984. Stocks are depleted in strike years and they must be replenished in the years following the strikes. It is, there- fore, appropriate to average the sales for these years. Adjusted sales figures are represented by a star in figure 2.
When shipments are averaged for these strike-affected years, sales of Illinois Basin coal to utilities show a declining trend from 1975 through 1983. From 1984 through 1986, sales appear to have recovered. However, it is inappropriate to conclude that the decline in sales has been reversed from just three years of data.
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900 -i
1938 1944 |- + 10.0%-| 2 6%
Rapid Great Fluctuations Growth
World War II General Decline in Production
1961
1986
+ 3.3%
Sustained Average Growth
United States
1938 1944 1954 f- + 7.91%H 4.75% -\—
Rapid Shrinkage Growth
World War II
+ 3.6%-
1972
1986
Sustained Average Growth
Stagnation
Year
Figure 1 Trends in U.S. and Illinois Basin coal production, 1930-1986 (data adapted from U.S. Dept. of Energy, Bituminous Coal and Lignite Distribution).
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130-
120-
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1975
|
I 76 |
I 77 |
I 78 |
I 79 |
1 1 80 81 Year |
I 82 |
I 83 |
1 84 |
1 85 |
86
Figure 2 Shipments of Illinois Basin coal to electric utilities, 1 975-1 985 (data adapted from Bitumin- ous Coal and Lignite Distribution 1 975, U.S. Dept. of the Interior, Bureau of Mines and Coal Distribution Jan-Dec 1985, DOE/EIA-0125(85/4Q). Sales figures that were averaged to reflect effect of strike years are represented by a "fc .
State-by-state breakdown of utility market shares. Tables 1, 2, and 3 show the dependence of Illinois, Indiana, and western Kentucky coal producers, respectively, on demand from utilities in states in their market areas. In 1985, the total market area for Illinois Basin coal extended into 17 states, compared with 14 states in 1975. The largest single market for any state remained within its own boundaries, although the percentage of coal con- sumed by utilities within the state declined from 45 to 31 for Illinois and from 80 to 72 for Indiana. In-state consumption of western Kentucky coal increased to 35 percent of total sales to utilities in 1985, as compared with about 31 percent in 1975.
Illinois' shipments to utilities in states immediately north and west of Illinois declined due to competition from low-sulfur western and eastern coals, but the decline was more than offset by increases in shipments to utilities in Missouri, Georgia, Florida, Tennessee, Alabama, and Indiana.
There are several reasons Illinois coal producers increased sales to these states:
• Illinois coal is easily transported to these states via the waterways and railroads. This keeps transportation costs for Illinois coal lower than for coals from western states, thus lowering delivered prices.
• The cost of mining coal in Illinois is lower than in the Appalachian Basin states. Georgia, Florida, Tennessee,
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Table 1. Shipments of Illinois coal to utilities by state
|
1975 |
1985 |
|||
|
(million tons) |
(percent) |
(mil lion tons) |
(percent) |
|
|
Alabama Florida Georgia 11 1 inois |
0.389 ** 0.987 22.006 |
0.8 ** 2.0 44.9 |
2.819 3.723 3.131 16.541 |
5.3 7.0 5.9 31.3 |
|
Indiana Iowa Kansas Kentucky |
3.081 2.290 1.982 |
6.3 4.7 4.0 |
7.653 1.959 0.481 0.117 |
14.5 3.7 0.9 0.2 |
|
Michigan Minnesota Mississippi Missouri |
0.334 1.399 0.924 10.496 |
0.7 2.9 1.9 21.4 |
0.027 0.242 0.149 13.419 |
0.5 0.3 25.4 |
|
Tennessee Wisconsin |
0.521 4.595 |
1.1 9.4 |
1.389 1.248 |
2.6 2.4 |
|
49.004 |
100.1* |
52.898 |
100.0 |
* Does not total 100% due to rounding. ** Included in Georgia.
Sources: Bituminous Coal and Lignite Distribution 1975, U.S. Dept. of the Interior, Bureau of Mines and Coal Distribution Jan-Dec 1985, DOE/EIA-0125(85/4Q) .
Table 2. Shipments of Indiana coal to utilities by state
|
1975 |
1985 |
|||
|
(million tons) |
(percent) |
(million tons) |
(percent) |
|
|
Alabama |
0.025 |
0.1 |
.. |
|
|
Georgia |
0.482 |
2.2 |
1.301 |
4.8 |
|
11 1 inois |
0.371 |
1.7 |
1.310 |
4.9 |
|
Indiana |
17.222 |
79.8 |
19.413 |
71.8 |
|
Iowa |
— |
0.378 |
1.4 |
|
|
Kentucky |
1.689 |
7.8 |
2.487 |
9.2 |
|
Michigan |
0.092 |
0.4 |
0.098 |
0.4 |
|
Minnesota |
-- |
-- |
0.148 |
0.6 |
|
Missouri |
0.390 |
1.8 |
__ |
|
|
Ohio |
0.045 |
0.2 |
0.028 |
0.1 |
|
Tennessee |
0.449 |
2.1 |
0.208 |
0.8 |
|
Wisconsin |
-.816 |
3.8 |
1.661 |
6.1 |
|
21.581 |
99.9* |
27.032 |
100.1* |
Does not total 100% due to rounding.
Sources: Bituminous Coal and Lignite Distribution 1975, U.S. Dept. of the Interior, Bureau of Mines and Coal Distribution Jan-Dec 1985, D0E/E I A-0125( 85/4Q) .
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Table 3. Shipments of western Kentucky coal to utilities by state
|
1975 |
1985 |
|||||
|
(million tons) |
(percent) |
(million tons) ( |
percent) |
|||
|
Al abama |
6.459 |
12.1 |
0.981 |
2.7 |
||
|
Arkansas |
— |
— |
0.014 |
-- |
||
|
Florida |
4.102 |
7.7 |
4.444 |
12.1 |
||
|
Georgia |
3.783 |
7.1 |
2.230 |
6.1 |
||
|
11 1 inois |
0.844 |
1.6 |
1.116 |
3.0 |
||
|
Indiana |
4.159 |
7.8 |
2.853 |
7.8 |
||
|
Iowa |
0.064 |
0.1 |
0.051 |
0.1 |
||
|
Kentucky |
16.587 |
31.0 |
12.929 |
35.2 |
||
|
Michigan |
1.058 |
2.0 |
0.101 |
0.3 |
||
|
Minnesota |
0.101 |
0.2 |
0.059 |
0.2 |
||
|
Mississippi |
0.467 |
0.9 |
0.188 |
0.5 |
||
|
Missouri |
0.372 |
0.7 |
0.006 |
-- |
||
|
Ohio |
1.896 |
3.5 |
1.605 |
4.4 |
||
|
Pennsylvania |
-- |
— |
0.056 |
0.2 |
||
|
Tennessee |
11.475 |
21.5 |
8.020 |
21.9 |
||
|
Wisconsin |
2.070 |
3.9 |
2.043 |
5.6 |
||
|
53.437 |
100.1* |
36.696 |
100.1* |
* Totals may not add to 100 percent due to individual rounding
Sources: Bituminous Coal and Lignite Distribution 1975, U.S. Dept. of the Interior, Bureau of Mines and Coal Distribution Jan-Dec 1985, D0E/EIA-0125(85/4Q) .
Alabama, and Indiana received the majority of their coal from the Appalachian Basin States.
• Some utilities in these states converted from oil and/or gas to coal. This conversion was partly a result of the 1978 Fuel Use Act and partly due to the 1979-80 oil price increases. It led to increased total coal demand and an increase in demand for Illinois Basin coal, which benefited Illinois coal.
• About half of U.S. FGD capacity (= 25,000 MW) is installed in the market states for Illinois Basin coal. An esti- mated 20 to 25 percent of this capacity is installed on plants built prior to 1971, while the remaining is on plants built in the 1975-1985 period. Illinois coal could take advantage of the demand stabilization resulting from FGD installations because of its relative cost advantage.
Indiana also increased its shipments to utilities by about 5.5 million tons from 1975 through 1985. However, Indiana coal has been more successfully marketed in its adjoining states, such as Illinois and Kentucky, and states in close proximity, such as Wisconsin, than in distant states such as Georgia. One of the reasons for the increase may be the decrease in average sulfur content of Indiana coal from 3.12 percent in 1975 to 2.54 percent
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in 1985; it may also have been the result of lower prices due to lower transportation costs and of marketing strategy.
In 1985, Illinois Basin coal shipments from western Kentucky to electric utilities totaled about 37 million tons, nearly 17 mil- lion tons less than in 1975. In this same time period, western Kentucky coal producers also became much more dependent on utili- ties in Florida, although their tonnage shipments to Florida did not increase significantly. In a smaller total 1985 market, western Kentucky coal producers lost sales in Alabama, Kentucky, Tennessee, and Mississippi to coal producers from Illinois and eastern Kentucky. The majority of those sales were lost in Alabama.
From 1975 to 1985, the total demand for coal by electric utilities in the 17-state Illinois Basin market area increased from about 306 to 373 million tons (table 4). Table 4 data indicate that Illinois has increased its market shares in southern states and lost shares in northern states. These states are the same to which shipments in absolute tons also increased or decreased (table 1). Illinois coal thus has taken advantage of opportuni- ties in the southern markets but lost a significant share of the northern markets. Similarly, Indiana has increased its shares of the utility coal markets in Illinois, Kentucky, and Wisconsin in absolute as well as relative terms. Western Kentucky, on the other hand, has lost market shares in nearly all the states in 1985 compared with 1975.
From 1975 through 1985, total coal shipments to utilities from the Illinois Basin declined from 124 million tons to 117 million tons (tables 1, 2, 3) and the market share of Illinois Basin coal in the 17-state market area declined from 41 percent in 1975 to 31 percent in 1985 (table 4). The data indicate a shift in strength within the Illinois Basin in favor of Illinois and Indiana coal at the expense of western Kentucky coal. From 1975 to 1985, Illinois' and Indiana's share of total shipments to utilities increased from 57 percent to 68 percent. The production curves in figure 2 confirm this shift.
Impact of western coals on Illinois Basin utility markets.
Increased demand for low-sulfur western coals has eaten into the utility markets for Illinois Basin coals. Western coals are those produced in districts 16-20, 22, and 23 as defined in the Bitumi- nous Coal Act of 1937 and its amendments (fig. 3). Of these seven districts, mines in district 18 (Arizona, California and most of New Mexico) and district 23 (Washington and Alaska) did not ship any coal to the Illinois Basin coal markets. Districts 18 and 23 have, therefore, been excluded from table 5, which shows shipments from western coal districts to states served by Illinois Basin coal. As table 5 indicates, in both 1975 and 1985, only coal
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ISGS
producers from districts 19 and 22 shipped significant amounts of coal to the Illinois Basin coal market states. These districts represent mainly Wyoming and Montana coals. In 1985, Colorado coals from district 16 also figure significantly in the statis- tics, while districts 17 and 20 disappear as exporters to the Illinois Basin market states.
In 1975, coal shipments from western states to utilities in the 14 states in the Illinois Basin market area totaled about 32 million tons. When, by 1985, the Illinois Basin market area had grown to 17 states, shipments of western coals to these states totaled 8? million tons. Western coals' share of total utility coal demand in the 17-state area increased from about 11 percent in 1975 to 22 percent in 1985. About 74 percent of the total increased coal demand by utilities in the Illinois Basin coal market area was met by western states.
As table 5 indicates, most western coals were exported to northern and midwestern states: Minnesota, Wisconsin, Michigan, Iowa,
Table 4. Total 1975 and 1985 utility markets and shares held by Illinois Basin states
Total Market Illinois Share Indiana Share W. Kentucky Share (million tons) (%) (%) (%)
Market State 1975 1985 1975 1985 1975 1985 1975 1985
|
Alabama |
19.246 |
21.525 |
2.0 |
13.1 |
0.1 |
— |
33.6 |
4.6 |
|
Arkansas |
__ |
11.861 |
-- |
-- |
-- |
-- |
-- |
0.1 |
|
Florida |
5.451 |
16.640 |
-- |
22.4 |
-- |
-- |
75.3 |
26.7 |
|
Georgia |
14.619 |
24.201 |
6.8 |
12.9 |
3.3 |
5.4 |
25.9 |
9.2 |
|
Illinois |
34.853 |
31.682 |
63.3 |
52.2 |
1.1 |
4.1 |
2.4 |
3.5 |
|
Indiana |
28.715 |
36.224 |
10.7 |
21.1 |
60.0 |
53.6 |
14.5 |
7.9 |
|
Iowa |
5.560 |
12.345 |
41.2 |
15.9 |
-- |
3.1 |
1.1 |
0.4 |
|
Kansas |
3.220 |
14.088 |
— |
3.4 |
-- |
■~ |
|
™ ~ |
|
Kentucky |
25.724 |
23.405 |
7.7 |
0.5 |
6.6 |
10.6 |
64.5 |
55.2 |
|
Michigan |
21.802 |
23.005 |
1.5 |
0.1 |
0.4 |
0.4 |
4.9 |
0.4 |
|
Minnesota |
8.782 |
11.397 |
15.9 |
2.1 |
-- |
1.3 |
1.2 |
0.5 |
|
Mississippi |
1.573 |
3.873 |
58.7 |
3.8 |
-- |
— |
29.7 |
4.9 |
|
Missouri |
17.741 |
22.065 |
59.2 |
60.8 |
2.2 |
-- |
2.1 |
-- |
|
Ohio |
46.412 |
47.861 |
-- |
-- |
0.1 |
-- |
4.1 |
3.4 |
|
Pennsylvania |
35.778 |
39.573 |
-- |
-- |
-- |
-- |
— |
0.1 |
|
Tennessee |
24.659 |
18.178 |
2.1 |
7.6 |
1.8 |
1.1 |
46.5 |
44.1 |
|
Wisconsin |
11.598 |
15.357 |
39.6 |
8.1 |
7.0 |
10.8 |
17.8 |
13.3 |
|
305.733 |
373.280 |
Sources: Bituminous Coal and Lignite Distribution 1975, U.S. Dept. of the Interior, Bureau of Mines and Coal Distribution Jan-Dec 1985, D0E/E IA-0125( 85/4Q) .
ISGS 9 IMN97
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ISGS
11
IMN97
Illinois, and Indiana. Western coal producers also captured the major new utility markets that developed when Arkansas and Kansas experienced economic growth and when utilities in those states switched to coal. Even in Missouri (a state in which Illinois Basin coal has been sold in increasing quantities in the last 10 years), western coal producers' share of the utility market in- creased from 5.6 percent in 1975 to 26 percent in 1985. Western coal producers' share of the Ohio market declined between 1975 and 1985, while their share of the Illinois market remained nearly unchanged.
Non-utility Markets
From 1975 through 1985, overall non-utility demand for Illinois Basin coal declined. Non-utility markets are divided into (1) coke and gas plants and (2) other industrial uses. Shipments of coal from Illinois to coke and gas plants declined and could not be completely offset by increases of shipments from Indiana or western Kentucky (table 6). The decline in demand for Illinois Basin coal used for coke-making was due to the economic conditions in the steel industry in the Chicago area. (The entire U.S. steel industry has lost markets to lower priced steel imported from Europe and Asia.)
The sales of Illinois Basin coal (about 12 million tons) for other industrial uses remained virtually unchanged in this time period. Decreased shipments from Illinois were offset by equivalent increases in shipments from Indiana and western Kentucky. Illinois coal was displaced by Indiana and western Kentucky coals in certain border areas, such as Vermilion and Massac counties, as well as areas in western Illinois where barge access may have reduced transportation costs.
Table 6. Shipments of Illinois Basin coal to non-utility markets (million tons), 1975 and 1985
By state of origin Total
Illinois Indiana Western Kentucky Illinois Basin
Kind of shipment 1975 1985 1975 1985 1975 1985 1975 1985
Coke and gas plants 4.27 2.01 — -- — — 4.29 2.01
Other industries 6.45 4.16 3.45 5.64 2.12 2.27 12.02 12.07
Total 10.72 6.17 3.45 5.64 2.12 2.27 16.29 14.08
Sources: Bituminous Coal and Lignite Distribution 1975, U.S. Dept. of the Interior, Bureau of Mines and Coal Distribution Jan-Dec 1985, D0E/EIA-0125(85/4Q) .
IMN97 12 ISGS
Cost Competitiveness
Western coal has successfully captured large portions of the growing U.S. coal demand, even though modifications in clean air legislation have made S02 pollution less of an issue. In 1984, Illinois Basin coal prices at the mine were on average lower than in the Appalachian states but higher than in the western states (table 7). Since average mine labor productivity in the western states also was much higher, the western states are likely to con- tinue to hold a price advantage over Illinois Basin coal at the mines.
On the basis of delivered price, Illinois Basin coals do not compare favorably with competitors in many states of the market area (table 8). Low-sulfur coals from eastern Kentucky and the western states, as well as imports from South Africa and Colombia, are delivered at competitive or lower prices than Illinois Basin coals. The price competition is intense everywhere except in Illinois and Indiana, and even there the situation could become even worse if attempts to decrease pollution are intensified as they would be under proposed acid rain legislation.
The delivered price of coal includes the transportation cost. In 1985 about 50 percent of Illinois Basin coal was transported by rail and 30 percent by barge. In comparison, most western coal coming into the Illinois Basin market area was carried by rail or by a combination of rail and barge. A comparison of 1985 rail freight rates as a function of distance is presented in figure 4. (Barge transportation costs are not available, but we know they are generally lower than rail costs.) The variations in rates are due to contract specifications such as the annual ton- nage, the contract duration, the car ownership, and the size of each shipment (i.e., single car, whole train, unit train). In many market areas the western coal producers, especially those from Wyoming and Montana, are able to absorb the high cost of transportation over long distance and compete successfully with the Illinois Basin coal because their mining costs are low and because transportation costs do not increase proportionately with transportation distance. As figure 4 indicates, the freight rate does not increase proportionally to the distance. The cost per ton per mile generally declines as the distance increases.
In order to be able to regain their market position, the producers of Illinois Basin coal must solve two major problems:
• Ways must be found to improve mine productivity and lower the cost of mining.
• Better methods of cleaning coal must be developed.
Because the margin of possible quality improvement from conventional coal cleaning is smaller for Illinois Basin coal than for coals from elsewhere in the country, we must find better ways to lower the sulfur content of the deliv-
ISGS 13 IMN97
Table 7. FOB mine price and labor productivity for major coal-producing states, 1984
|
Market state |
Mine Price |
Labo |
r Productivity |
|
($/ton) |
(ton |
/person/hour) |
|
|
Illinois |
24.98 |
2.22 |
|
|
Indiana |
25.32 |
2.93 |
|
|
West Kentucky |
26.81 |
2.61 |
|
|
West Virginia |
34.18 |
1.88 |
|
|
East Kentucky |
28.61 |
2.13 |
|
|
Pennsyl vania |
33.48 |
1.67 |
|
|
Virginia |
31.17 |
1.61 |
|
|
Ohio |
33.17 |
2.01 |
|
|
Wyoming |
11.89 |
13.77 |
|
|
Montana |
13.57 |
14.27 |
|
|
Colorado |
23.07 |
3.24 |
Source: Coal Production 1984, DOE/EIA-01 18( 84) p. 30 and p. 48
Table 8. Average delivered cost of coal supplied to electric utilities, 1985 (tf/10& Btu)
State of Destination
Alabama Arkansas Florida Georgia
II 1 inois Indiana Iowa Kansas
Kentucky Michigan Minnesota Mississippi
Missouri
Tennessee
Wisconsin
State of Origin
IL IN WKY EKY MT WY CO UT
151 — 136 157 —
158 215 -- 187 216 165 169 — 182
Imports
South
Africa Colombia
164 173
165 139 159 115 248
140 140 192
213 149 186
157 146
128 154
177 176
255
219
130 160
185
159 144
195 110
156 192
157
146
164
278 336
270 286
— 145
— 137
188
140 152
— 320 330
119
188
Source: Cost and Quality of Fuels for Electric Utility Plants 1985, D0E/EIA-0191(1985) , table 48, p. 69-72.
IMN97
14
ISGS
50-
O
0)
cP
DO D
a a
□ DD a^
DDrn ° £P °
a (man a
0°
(S> a
DD
~i 1 1 1 1 r
08 1 12
Distance (thousand miles)
-i 1 1 1 1 1 T
14 16 18 2
Figure 4 1985 railroad freight rates for coal (source: Coal Week, 1985).
ered coal. About 90 percent of Illinois Basin coal is currently cleaned before shipment, therefore, improvements in coal quality must come from better coal cleaning tech- nologies. Such improvements in technology have been slow in coming, however, partly because of the development costs involved and partly due to the incentives given to the development of post-combustion cleaning of flue gases by clean air regulations. In contrast, western coals do not need much cleaning because of their low sulfur contents. Currently, only about 5 percent of western coals and about 40 percent of the Appalachian region coal production are cleaned prior to shipment.
Conclusions from 1975-1985 Market Analysis
The fact that at least half of the western coal delivered into the Illinois market area in 1985 was burned by electric utilities in plants that did not exist or did not burn coal in 1975 is indica- tive of the serious problem facing Illinois Basin coal. Until now the main problem with Illinois Basin coal seemed to be its high sulfur content and, at least in the traditional market areas, the delivered cost of Illinois Basin coal was considered to be compet- itive. As a result, it was safe to assume that newly constructed
ISGS
15
IMN97
electric utilities with mandatory FGD equipment would elect to burn the lower cost Illinois Basin coal over the low-sulfur, higher priced western coals. Developments of the past 10 years and especially of the 1981-85 period indicate, however, that western coals have successfully captured newly developing coal markets as close to the Illinois Basin as Arkansas, thereby proving wrong the assumption that the RNSPS would significantly increase sales of Illinois Basin coal. A review of coal-burning electric utilities that started operation in the Illinois Basin market area from 1981 through 1985 (table 9) indicates that Illinois Basin coal represents only 32 percent of this 22,000 MW capacity, while low-sulfur coals from eastern and western states account for the remainder of this capacity. Despite favorable environmental conditions, a majority of the new plants opted for other than Illinois Basin coal. It cannot be assumed without reservations that in the future Illinois Basin coal will be in a strong position to capture newly developing demand in its market area.
MARKETS FOR ILLINOIS BASIN COAL, 1994 AND BEYOND
In the future, markets for Illinois Basin coal will continue to be affected by the same factors affecting markets from 1975 through 1985--environmental regulations and cost competitiveness—with the added burden of possibly even more stringent clean air legislation being enacted. Illinois Basin coal markets for 1994 and beyond are examined under two scenarios: (1) continued application of RNSPS and SIPs and (2) enactment of acid rain legislation requiring further S02 reductions.
Scenario 1: Continued Application of Current Regulations
Under the RNSPS, plants capable of producing 73 MW of electricity that have been built since September 1978 are required to reduce SO2 emissions potential by 70 to 90 percent and, thus, are virtually forced to have an FGD system installed. Plants built prior to 1971 are regulated under the SIPs and are not required to limit their emissions severely enough to require FGD installa- tions. Newer, larger plants will, therefore, be a primary area of expansion for Illinois Basin coal producers.
The USEPA has also released pollution standards for new indus- trial, commercial, and institutional steam generating units with greater than 29 MW capacity and less than 73 MW capacity (2). These standards require intermediate-size plants to achieve a 90 percent reduction in S02 emissions and to meet the limit of 1.2 lbs SO2/IO6 Btu heat input when using conventional FGD systems.
IMN97 16 ISGS
Table 9. Coal-burning electric utilities that started operation from 1981-1985 in Illinois Basin market states
State
Al abama
Company and Plant Name
Alabama Power James H. Miller
Installed Capacity
(MW)
706
Year Started
Origin of Coal
1985
Al abama
Sulfur
Content
(%)
0.57
Arkansas
Arkansas Power Independence
White Bluff
800 800 800
1982 1984 1981
Wyoming Wyoming Wyoming
0.22 0.22 0.45
Florida
Georgia
111 inois
Indiana
Iowa
Florida Power Crystal River
Gainesville (City of) Deerhaven
Lakeland (City of) CD. Mcintosh, Jr.
♦Seminole Electric Coop Semi nole
*Tampa Electric Co. Big Bend
Georgia Power Scherer
♦Central Illinois Power Co. Newton
*Hoosier Energy REC Inc. Merom 1,2
Indiana and Michigan El Co.
Rockport (project 2601) *Indianapol is Power & Light
Petersburgh 4 ♦Northern IN Public Serv.
R.M.Schahfer 17,18
♦Public Service Co. of IN Gibson 5
City of Ames 8
Iowa Southern Utility Co
Ottumwa 1 ♦City of Muscatine
Muscatine 9
740 1982 Kentucky 0.79
740 1984 Virginia 0.68
West Vi rginia 0.68
Imports 0.64
|
251 |
1981 |
Kentucky West Virg |
inia |
0.65 0.72 |
|
334 |
1982 |
Kentucky |
1.51 |
|
|
620 620 |
1983 1984 |
Kentucky 11 1 inois |
3.04 2.65 |
|
|
486 |
1984 |
11 1 inois Kentucky |
3.00 2.30 |
|
|
891 891 |
1981 1983 |
Kentucky Virginia |
0.68 0.70 |
|
|
617 |
1982 |
West Vi rg 11 1 inois Indiana |
inia |
0.67 2.60 0.60 |
|
490 490 |
1983 1982 |
11 1 inois Indiana |
3.00 3.20 |
|
|
L300 |
1984 |
Wyoming |
0.36 |
|
|
574 |
1985 |
Indiana |
2.20 |
|
|
848 |
82/85 |
11 1 inois Colorado Wyoming ( |
(42%) (33%) 25%) |
3.00 0.49 0.50 |
|
668 |
1982 |
11 1 inois Indiana |
2.40 2.40 |
|
|
71 |
1981 |
Iowa Wyoming |
1.24 0.42 |
|
|
726 |
1981 |
Wyoming |
0.38 |
|
|
160 |
1982 |
11 1 inois |
2.90 |
ISGS
17
IMN97
Table 9 continued
State
|
Company and |
Instal led |
Year |
Origin |
Sul fur |
|
Plant Name |
Capacity (MW) |
Started |
of Coal |
Content (%) |
|
Kansas City |
||||
|
Nearman Creek 1 |
262 |
1981 |
Wyoming |
0.33 |
|
Kansas Power & Light |
||||
|
Jeffrey Energy Center 3 |
720 |
1983 |
Wyoming |
0.34 |
|
Sunflower Electric Coop |
||||
|
Holobomb |
319 |
1983 |
Wyomi ng |
0.47 |
|
*Big River Electric Coop |
||||
|
D.B. Wilson 1 |
501 |
1984 |
Kentucky |
4.00 |
|
♦Kentucky Utilities |
||||
|
Ghent 3, 4 |
1,113 |
81/84 |
Indiana (50%) |
3.10 |
Kansas
Kentucky
Michigan
*Louiville Gas & Electric Mill Creek 4
Detroit Edison
Belle River ST1, ST2
*Grand Haven City 3
Marquette City Shiras 3
544
698
698
65
44
1982
1982
Kentucky (50%) 0.75
Kentucky
1984 Montana 1985
1983 Indiana Kentucky
Kentucky Montana
3.26
0.36
1.9 2.9
0.97 0.50
Michigan South Central Pwr.Agy. Litchfield 1
Mississippi Mississippi Power
Victor Daniel Jr. 2
Associated Electric Coop Thomas Hi 1 1 3
Missouri
Ohio
*Sikeston (City of) Sikeston 1
Dayton Power 8 Light Killen Station 2
|
55 |
1982 |
Ohio |
3.0 |
|
500 |
1981 |
Colorado |
0.5 |
|
Utah |
0.5 |
670 235 666
Wisconsin *Wisconsin Power A Light
Edgewater 5 380
1982 Missouri
1981
II 1 inois
4.2
2.5
1982 Kentucky 0.6 West Virginia 0.6
1984 Illinois (45%) 3.3 Wyoming (55%) 0.3
Total
♦Total burning Illinois Basin Coal
22,093 7,153
(32%)
Sources: Inventory of Power Plants in the United States, D0E/EIA-0095(85) , U.S. Department of Energy (Table 15, p. 34-229 for plant starting date, capacity and fuel type) and Cost and Quality of Fuels for Electric Utility Plants 1985, D0E/EIA-0191(85) , U.S. Department of Energy (Table 49, p. 73-114 for origin of coal and sulfur content).
IMN97
18
ISGS
Plants using an emerging S02 control technology are required to achieve a 50 percent reduction in emission potential and to meet the limit of 0.6 lbs S02/106 Btu heat input. The 90 percent reduction is similar to the RNSPS and therefore seems to favor the use of high-sulfur coal—provided it is priced lower than low- sulfur coal. The 50 percent reduction, applicable when an emerging SO2 technology is used, may favor the use of lower sulfur coals and thus not help future markets for Illinois Basin coals.
A 1985 survey by the National Coal Association indicated that by 1994 about 18,500 MW of new coal -burning, electric-generating capacity may be added in the Illinois Basin coal market area as shown in table 10. About 30 percent of this new generating capacity will be added in states where Illinois Basin's market share is already less than 4 percent, namely, Arkansas, Kansas, Michigan, Minnesota, Ohio, and Pennsylvania.
Of the future planned capacity in the Illinois Basin market area, information about planned installation of FGD-systems is available on a total of 8,312 MW. An estimated additional 2,000-MW FGD capacity is likely to be added, but neither the source of coal nor its sulfur contents have been declared (3). Table 11 gives the breakdown of planned scrubber capacities. (It should be noted that table 11 data are not comparable to table 10 data because no time span for planned FGD is given.) The states listed in table 11 are major consumers of Illinois Basin coal and, therefore, are a significant indicator of future FG0 deployment and of future prospects for Illinois Basin coal. (It is also significant to note that no FGD systems are planned in such Illinois Basin market states as Missouri and Tennessee.) Illinois Basin coal producers are thus assured of a 3,366-MW market in Indiana and western Kentucky and an estimated 50 to 75 percent of the Florida potential or 1,420 to 2,134 MW, for a maximum of 5,500 MW. Illinois Basin coal producers share of the Florida market has sharply declined in the past decade and competition from low- sulfur Appalachian and imported coal is rising in that state. Neither Ohio, with its locally available high-sulfur coals nor eastern Kentucky with its locally available low-sulfur coal are prospective markets for Illinois Basin coal. Arkansas utility plants use cheaper, western coals and are not a viable market for II linois Basin coal .
At current rates of capacity utilization a demand of 1,300 tons of coal per 1-MW capacity per year will be generated, adding about 7 million tons to the demand for Illinois Basin coal in 1994. Extrapolating the 1994 estimate for the year 2000, about 12 million tons per year of additional sales will be generated, compared to 1985. Assuming non-utility Illinois Basin coal demand remains at its current level of 14 million tons per
ISGS 19 IMN97
year, the total demand for Illinois Basin coal in 1994 is estimated to be 138 million tons (about 143 million tons in the year 2000). Given their current production proportions, Illinois, Indiana, and western Kentucky's shares of total basin demand for the years 1994 and 2000 will be:
II 1 inois
Indiana
Western Kentucky
TOTAL
1994
2000
(million tons per year)
62 36
40
65 37 41
138
143
These projections of future demand for Illinois Basin coal indicate that coal mining in the Illinois Basin will continue to stagnate until 1994 and beyond if current clean air regulations remain the only applicable sets of regulations and no progress is made with regard to Illinois Basin coal's price competitiveness.
Scenario 2: Acid Rain Legislation Requiring Further SO2 Reduction
Acid rain legislation introduced in 1986 would have required that S02 emissions be below 2.0 lbs/106 Btu by 1993 and below 1.2 lbs/106 Btu by 1997 (on a monthly state-by-state average basis).
Table 10. New coal-burning electric capacity expected to come on line by 1994 in Illinois Basin market states
|
State |
MW |
State |
MW |
|
Alabama |
1,998 |
Michigan |
655 |
|
Arkansas |
836 |
Minnesota |
851 |
|
Florida |
1,986 |
Mississippi |
— |
|
Georgia |
1,616 |
Missouri |
1,425 |
|
Illinois |
— |
Ohio |
1,300 |
|
Indiana |
2,409 |
Pennsylvania |
1,350 |
|
Iowa |
650 |
Tennessee |
— |
|
Kansas |
680 |
Wisconsin |
972 |
|
Kentucky |
1,745 |
Total new capacity: 18,473 MW
Source: Steam Electric Plant Factors 1985, National Coal Association, Washington, DC, table 16c.
Table 11. FGD capacities and sulfur contents of coal in utility plants planned in the Illinois Basin coal market states
State
Capacity (MW) Sulfur (%)
|
Ohio |
1,386 500 |
3.5 unknown |
|
|
Indiana |
1,950 |
3.5 |
|
|
Kentucky |
- West ■ East |
1,416 1,000 |
3.5 unknown |
|
Iowa |
720 |
0.4 |
|
|
Florida |
2,840 |
unknown |
|
|
Arkansas |
500 |
unknown |
|
|
Total |
10,312 |
Source: Steam Electric Plant Factors 1985, National Coal Association, Washington, DC, table 16c.
IMN97
20
ISGS
These reductions would have to come from utilities built prior to 1971, that is, those presently regulated by the SIPs. This acid rain bill permitted the SIPs to be flexible in terms of fuel mix and technology choice and suggested means of financing the cuts. The targeted S02 emission reductions are listed by state in table 12. In 1980 the total S02 emissions from utilities in the United States was about 17.3 million tons, of which 13.2 million tons (76%) came from the 17-state Illinois Basin coal market area. The 1986 bill would have required that by 1993 S02 pollution be low- ered nationwide to 5.7 million tons below 1980 levels. By 1997, S02 pollution would have to have been lowered to 10.0 million tons below 1980 levels. By 1993, about 5.2 million tons (90%) of the reduction would have to come from the Illinois Basin coal market area; by 1997 about 8.6 million tons (85%) of the reduc- tions would have been from the Illinois Basin coal market area. Since the newly built plants will be subject to the 1.2 lbs S02/106 Btu limit, all the reductions from the 1980 levels must come from already existing sources of pollution, about 75 percent of which may, on an average, have to be from the utilities.
Illinois Basin coal will suffer a potentially substantial loss of markets if acid rain legislation is passed because many utilities are expected to switch to fuels containing lower amounts of sulfur. How many utilities will switch fuels depends upon an individual plant's economic situation. The cost of retrofitting with and operation of FGD systems will have to be compared to the additional cost of burning low-sulfur fuels. An additional consideration is the age of the plant. In general, the older the plant the greater the chances that switching to a lower sulfur fuel may be more beneficial than retrofitting with FGD. Older plants also experience more outages for repairs (fig. 5). Refurbishing the older plants can reduce outages but if the cost of refurbishment exceeds 50 percent of the cost of building a new plant an older plant may be classified as a new plant and subject to RNSPS. The plant would then be required to install an FGD system. How old a plant needs to be before fuel switching is economical is a matter of research and no definite answer to the question can be offered at this time. In this report it has been assumed that utility plants 20 or more years old may be the prime candidates for fuel switching.
In 1985, about 30 percent of the U.S. electric-generating capacity was more than 20 years old (fig. 6). By 1995, this percentage is expected to increase to 60. Thus it is assumed that about 30 percent (35 million tons) of current Illinois Basin coal sales may be affected by 1994 and about 60 percent (70 million tons) by the year 2000. The ability of Illinois Basin states to increase their production of lower sulfur coals is expected to be limited.
ISGS 21 IMN97
Table 12. Sulfur dioxide reduction targets as per proposed 1986 acid rain bill
|
SO2 emissions baseline |
Reductions |
Reductions |
||||||
|
(103 |
tons/yr) |
(2 |
.0 lbs/MBt |
u) |
(1.2 |
lbs/MBU |
) |
|
|
1980 |
1980 |
103 |
% of % |
Of |
103 |
% of |
% of |
|
|
STATE |
Total |
Utility |
tons/yr |
Total Ut |
ility |
tons/yr |
Total |
Utility |
|
♦Alabama |
759 |
543 |
118 |
16 |
22 |
307 |
40 |
57 |
|
♦Arkansas |
900 |
88 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Alaska |
102 |
27 |
10 |
9 |
36 |
10 |
9 |
36 |
|
California |
446 |
78 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Colorado |
132 |
78 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Connecticut |
72 |
32 |
0 |
0 |
1 |
0 |
0 |
1 |
|
Delaware |
109 |
53 |
23 |
21 |
44 |
23 |
21 |
44 |
|
D. Columbia |
15 |
5 |
0 |
0 |
0 |
0 |
0 |
0 |
|
♦Florida |
1,095 |
726 |
1 |
0 |
0 |
299 |
27 |
41 |
|
♦Georgia |
840 |
737 |
279 |
33 |
38 |
480 |
57 |
65 |
|
Idaho |
47 |
0 |
0 |
0 |
0 |
0 |
0 |
0 |
|
♦Illinois |
1,471 |
1,126 |
375 |
26 |
33 |
709 |
48 |
63 |
|
♦Indiana |
2,008 |
1,540 |
880 |
44 |
57 |
1,173 |
58 |
76 |
|
♦Iowa |
329 |
231 |
42 |
13 |
18 |
126 |
38 |
55 |
|
♦Kansas |
223 |
150 |
23 |
10 |
15 |
23 |
10 |
15 |
|
♦Kentucky |
1,121 |
1,008 |
504 |
45 |
50 |
726 |
65 |
72 |
|
Louisiana |
304 |
25 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Maine |
95 |
16 |
0 |
0 |
0 |
1 |
1 |
6 |
|
Maryland |
338 |
223 |
32 |
9 |
14 |
117 |
35 |
52 |
|
Massachusetts |
344 |
276 |
57 |
16 |
21 |
120 |
35 |
44 |
|
♦Michigan |
907 |
565 |
3 |
0 |
0 |
251 |
28 |
44 |
|
♦Minnesota |
260 |
177 |
0 |
0 |
0 |
59 |
23 |
33 |
|
♦Mississippi |
285 |
129 |
0 |
0 |
0 |
30 |
10 |
23 |
|
♦Missouri |
1,301 |
1,141 |
684 |
53 |
60 |
887 |
68 |
78 |
|
Montana |
164 |
23 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Nebraska |
75 |
49 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Nevada |
243 |
40 |
0 |
0 |
0 |
0 |
0 |
0 |
|
New Hampshire |
93 |
81 |
31 |
33 |
38 |
52 |
56 |
65 |
|
New Jersey |
279 |
110 |
0 |
0 |
0 |
0 |
0 |
0 |
|
New Mexico |
269 |
85 |
19 |
7 |
22 |
19 |
7 |
22 |
|
New York |
944 |
480 |
5 |
1 |
1 |
137 |
15 |
29 |
|
North Carolina |
602 |
435 |
0 |
0 |
0 |
139 |
23 |
32 |
|
North Dakota |
107 |
83 |
0 |
0 |
0 |
14 |
13 |
17 |
|
♦Ohio |
2,647 |
2,172 |
1,143 |
43 |
53 |
1,600 |
60 |
74 |
|
Oklahoma |
121 |
38 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Oregon |
60 |
3 |
0 |
0 |
0 |
0 |
0 |
0 |
|
♦Pennsylvania |
2,022 |
1,466 |
411 |
20 |
28 |
880 |
44 |
60 |
|
Rhode Island |
15 |
5 |
0 |
0 |
0 |
0 |
0 |
0 |
|
South Carolina |
326 |
213 |
11 |
3 |
5 |
101 |
31 |
47 |
|
South Dakota |
39 |
29 |
0 |
0 |
0 |
12 |
29 |
40 |
|
♦Tennessee |
1,077 |
934 |
479 |
45 |
51 |
681 |
63 |
73 |
|
Texas |
1,277 |
303 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Utah |
72 |
23 |
0 |
0 |
0 |
0 |
0 |
0 |
|
Vermont |
7 |
1 |
0 |
0 |
0 |
0 |
1 |
17 |
|
Vi rginia |
361 |
164 |
4 |
1 |
3 |
45 |
12 |
27 |
|
Washington |
272 |
69 |
27 |
10 |
39 |
29 |
10 |
41 |
|
West Virginia |
1,088 |
944 |
315 |
29 |
33 |
594 |
55 |
63 |
|
♦Wisconsin |
637 |
486 |
229 |
36 |
47 |
343 |
54 |
71 |
|
Wyoming |
184 |
121 |
50 |
27 |
41 |
50 |
27 |
41 |
|
US Total** |
26,480 |
17,325 |
5,753 |
22 |
33 |
10,035.5 |
38 |
58 |
♦ Illinois Basin coal market area.
♦♦ Excluding Arizona and Hawaii.
Source: Coal Week, April 14, 1986, p. 7.
IMN97
22
ISGS
Unit age (years)
Figure 5 Forced outage rate of coal-fired steam units (source: Annual Outlook for U.S. Electric Power 1986, DOE/EIA-0474(86) p. 27).
|
100-i |
number of units by age group |
m |
egaw by a |
att ce ge g |
ipability roup 1 >40 years |
|
|
80- |
| |
30-39 years |
||||
|
Percent o o |
20-29 years |
|||||
|
jivixj: |
||||||
|
20- |
10-19 years |
|||||
|
<10 years |
||||||
|
r>- |
1985
1995
1985
1995
Figure 6 Age and megawatt capability of coal-fired steam units (source: Annual Outlook for U.S. Electric Power 1986, DOE/EIA-0474(86) p. 26).
ISGS
23
IMN97
Tables 13 and 14 contain data on Btu/lb and sulfur contents of coal delivered to electric utilities from the Illinois Basin states in 1975 and 1984, respectively. Although the sulfur content of Illinois Basin coal has been lowered, the improvement is marginal, which means the percentage of compliance-quality coal is low. By comparison, the sulfur content of coal delivered from West Virginia and Kentucky declined significantly from 1975 through 1984. In 1975, about 19 percent of Kentucky coal and about 25 percent of West Virginia coal shipped to utilities contained low enough sulfur to satisfy the 2.0 lbs/106 Btu emission limits prescribed by many SIPs and targeted by the acid rain proposals for 1993. In 1984, the percentage of these compliance coals had risen to 41 in Kentucky and 44 in West Virginia. Some of this qualitative improvement was due to better coal cleaning but most of it was due to the ability of these states to shift coal production to areas with compliance-quality coal deposits. Although some shift to medium-sulfur coal is apparent in Indiana, compliance-quality coal reserves in the Illinois Basin are scarce. Therefore, a major change in production of compliance-quality coal appears unlikely--unless significant new low-sulfur deposits are discovered in the near future. Thus the estimates of the percentage of Illinois Basin coal expected to be affected by the proposed acid rain legislation seem plausible.
A worst case scenario for sales of Illinois Basin coal is developed in table 15. This scenario does not account for technological changes that may occur in the future that would allow increased sales of high-sulfur coals. Also unaccounted for are productivity changes in mines and changes in transportation costs that could affect the competititve situation of Illinois Basin coal .
As table 15 indicates, if acid rain legislation is enacted the potential impact of decreased production of Illinois Basin coal on employment could be serious. About 25,000 persons were employed in the coal mines of the Illinois Basin in 1985. They produced about 131 million tons of coal. Increasing coal mining productivity is expected to reduce the number of persons employed in coal mining in the future, even without decreased production. Up to 5,400 jobs could be jeopardized by the year 1994 due to potential production losses. A total of 11,000 jobs could be jeopardized by the year 2000.
In a best-case scenario, all 24 million tons of new annual coal demand expected to be created in the Illinois Basin market area (as a result of the projected addition of 18,500 MW generating capacity by 1994) would indeed come from the Illinois Basin. For a best-case analysis, we would also have to assume that no market
IMN97 24 ISGS
Table 13. Btu/lb and percentage sulfur of Illinois Basin coal received by utilities, 1975
|
State of |
Origin |
|||||
|
State of Destination |
111 |
inois |
Indiana |
West Kent |
ucky |
|
|
Btu/lb |
S(%) |
Btu/lb |
S(%) |
Btu/lb |
sm |
|
|
Alabama |
11,735 |
3.1 |
10,500 |
4.7 |
11,271 |
3.8 |
|
Arkansas |
-- |
- |
-- |
- |
-- |
- |
|
Florida |
11,780 |
3.0 |
12,783 |
2.3 |
11,397 |
2.9 |
|
Georgia |
10,900 |
3.4 |
11,371 |
3.6 |
11,669 |
2.6 |
|
Illinois |
10,395 |
3.3 |
11,036 |
2.5 |
11,047 |
3.0 |
|
Indiana |
10,405 |
2.7 |
10,750 |
3.1 |
10,919 |
3.6 |
|
Iowa |
10,615 |
2.7 |
10,016 |
0.6 |
10,506 |
3.4 |
|
Kansas |
— |
- |
-- |
- |
-- |
- |
|
Kentucky |
10,464 |
2.8 |
10,831 |
3.3 |
10,555 |
4.0 |
|
Michigan |
11,897 |
2.5 |
11,204 |
3.6 |
11,878 |
3.3 |
|
Minnesota |
10,902 |
3.0 |
— |
- |
11,172 |
4.2 |
|
Mississippi |
11,682 |
2.8 |
-- |
- |
11,451 |
2.9 |
|
Missouri |
11,022 |
3.1 |
11,371 |
3.4 |
11,349 |
2.7 |
|
Ohio |
__ |
_ |
10,827 |
3.3 |
10,941 |
3.0 |
|
Pennsylvania |
— |
- |
— |
- |
— |
- |
|
Tennessee |
10,856 |
3.3 |
11,209 |
3.6 |
10,918 |
3.8 |
|
Wisconsin |
11,133 |
2.7 |
11,353 |
3.6 |
11,096 |
3.5 |
Source: Annual Summary of Cost and Quality of Steam-Electric Plant Fuels 1975. With supplements on the origin of coal, annual, May 1976. Staff report by the Bureau of Power, Federal Power Commission, Table IV, p. 43-49.
Table 14. Btu/lb and percentage sulfur of Illinois Basin coal received by utilities, 1984
|
State of |
origin |
|||||
|
State of Destination |
11 1 inois |
Indiana |
West Kent |
ucky |
||
|
Btu/lb |
S(%) |
Btu/lb |
S(%) |
Btu/lb |
S(%) |
|
|
Alabama |
11,885 |
1.6 |
10,786 |
3.3 |
11,448 |
3.2 |
|
Arkansas |
— |
- |
-- |
- |
-- |
- |
|
Florida |
11,743 |
2.8 |
-- |
- |
12,015 |
2.8 |
|
Georgia |
11,369 |
2.5 |
11,265 |
2.7 |
11,657 |
2.9 |
|
11 linois |
10,798 |
2.9 |
10,935 |
1.5 |
11,266 |
2.2 |
|
Indiana |
10,773 |
2.7 |
10,890 |
2.6 |
11,457 |
3.3 |
|
Iowa |
11,018 |
2.9 |
10,916 |
3.2 |
10,965 |
2.8 |
|
Kansas |
11,360 |
2.6 |
-- |
- |
-- |
- |
|
Kentucky |
-- |
- |
11,072 |
2.5 |
11,041 |
3.5 |
|
Michigan |
11,579 |
2.7 |
10,996 |
2.8 |
— |
- |
|
Minnesota |
12,342 |
1.9 |
11,497 |
1.8 |
11,900 |
1.1 |
|
Mississippi |
12,058 |
2.6 |
— |
- |
12,341 |
2.7 |
|
Missouri |
11,144 |
2.4 |
10,987 |
1.3 |
11,445 |
3.4 |
|
Ohio |
.. |
_ |
-- |
- |
11,383 |
3.0 |
|
Pennsylvania |
-- |
- |
-- |
- |
-- |
- |
|
Tennessee |
11,733 |
2.0 |
10,957 |
1.8 |
11,759 |
2.7 |
|
Wisconsin |
11,063 |
2.8 |
11,215 |
2.3 |
11,766 |
2.9 |
Source: Cost and Quality of Fuels for Electric Utility Plants 1( D0E/EIA-0191(84), Table 58, p. 67-71.
ISGS 25 IMN97
Table 15. Projected markets for Illinois Basin coal in 1994 and 2000 if acid rain legislation enacted (million tons)
|
Utility |
Ind |
jstrial |
Total |
||||
|
Year |
1985 sales |
New demand |
Losses due to acid rain laws |
Net util ity |
|||
|
1994 2000 |
117 117 |
+ 7 +12 |
-35 -70 |
89 59 |
+ 14 + 14 |
103 73 |
losses would be suffered if acid rain legislation is enacted. Given these two assumptions, a comparable proportional increase in demand to the year 2000 would add a market potential of 18 million tons. This would mean that by the year 1994, total coal sales in the Illinois Basin would be 155 million tons. By the year 2000, total tonnage would be 173.
REFERENCES
(1) Energy Information Administration, 1983, Impacts of the proposed clean air act amendments of 1982 on the coal and electric utility industries, D0E/EIA-0407.
(2) Federal Register, June 19, 1986, p. 22384-22419.
(3) Steam Electric Plant Factors 1985, National Coal Association, table 16c, p. 147-149.
IMN97 ?f> ISGS
Related Publications
Mineral economics publications related to this IMN that you might wish to order from the Illinois State Geological Survey are listed below. For your convenience an order form is provided on the next page.
Illinois Mineral series — $1.25 each
55 "The energy crisis and its potential impact on the Illinois clay products industry,"
byR.L Major, 1974.
60 "Factors responsible for variation in productivity of Illinois coal mines," by
Ramesh Malhotra, 1 975.
76 "Oil: 1 980 — an analysis of the current situation from an international, national
and Illinois perspective," by S. B. Bhagwat, 1 980.
81 "The future competitive position of coal from the Illinois Basin," by S. B.
Bhagwat and T. J. Collias, 1 981 .
84 "Cost of underground coal mining in Illinois," by S. B. Bhagwat and Philip
Robare,1982.
90 "The lime and limestone market for sulfur removal: potential for 1 992," by S. B.
Bhagwat, 1985.
95 "Illinois mineral industry in 1 984 and review of preliminary mineral production data for 1 985," by I. E. Samson and S. B. Bhagwat, 1 987. (Since 1 931 reports such as this have been published annually.)
96 "Directory of Illinois stone, sand and gravel producers, 1986-87," by I. E. Samson and J. M. Masters, 1987.
Reprint series — $1 .00 each
1986-G "Coal mine productivity — somethingstheaveragesdon'ttell,"byH. E. Risser.
1980-M "Market potential for lllilnois Basin coal— an update," by S. B. Bhagwat.
1983-A "Costofsurfaceminingcoalin Illinois," by S.B. Bhagwat.
1 985-A "Economic and regulatory framework for production of solid compliance fuels
from medium to high sulfur coal," by S. B. Bhagwan and L. A. Johnson.
1 986-M "Recovery of fine grained sand and kaolin from sand washing tailing ponds —
a feasibility study," by L. A. Khan, S. B. Bhagwat, J. W. Baxter, and D. J. Berggren.
1 986-S "Economic feasibility of recovering fines from waste streams of mineral
processing plants," by L. A. Khan, S. B. Bhagwat, and J. W. Baxter.
1986-U "The United States fluorspar industry in a cost/price crunch," by S. B. Bhagwat.
1 986-V "Domestic utilization of high sulfur coals: trends and prospects," by
S. B. Bhagwat.
1 987-B "Economics of secondary recovery of coal," by L. A. Khan, S. B. Bhagwat, and
J. W. Baxter.
Maps — $3.00
"Coal industry in Illinois," (scale 1 :500,000) by H. H. Damberger, S. B. Bhagwat, J. D. Treworgy, D. J. Berggren, M. H. Bargh, and I. E. Samson, 1984.
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