IMN97
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CUi^^J
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.
ISGS
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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,
ISGS 1 ,MN97
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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ISGS
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.
ISGS 3 IMN97
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).
IMN97
ISGS
130-
120-
C
o
c 110-
o
100-
90
• ^*
• •
• •
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,
ISGS
IMN97
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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ISGS
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
ISGS 7 IMN97
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
IMN97
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.
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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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