,M1,S %.&: 
 
 Twill, " 
 
 c ^ 
 
 Dynamics of the 
 
 U.S. Coal Markets 1995 to 2010 
 
 How They Will Affect Illinois 
 
 Subhash B. Bhagwat 
 
 Illinois Minerals 116 
 
 Department of Natural Resources 
 ILLINOIS STATE GEOLOGICAL SURVEY 
 
Dynamics of the 
 
 U.S. Coal Markets 1995 to 2010 
 
 How They Will Affect Illinois 
 
 Subhash B. Bhagwat 
 
 Illinois Minerals 116 
 
 ILLINOIS STATE GEOLOGICAL SURVEY 
 
 William W. Shilts, Chief 
 
 Natural Resources Building 
 
 615 East Peabody Drive 
 
 Champaign, IL 61820-6964 t> ^ 
 
 (217)333-4747 ^» <<jr 
 
 4? 
 
Digitized by the Internet Archive 
 
 in 2012 with funding from 
 
 University of Illinois Urbana-Champaign 
 
 http://archive.org/details/dynamicsofuscoal116bhag 
 
FOREWORD 
 
 from the Chief 
 
 Coal has been a major resource for Illinois since early in the 19th century. The Illinois State 
 Geological Survey was created in 1905 in large measure to support the development of Illinois 
 mineral industries, especially the coal industry. The state still contains large, potentially valu- 
 able coal deposits, but the Illinois coal industry has fallen on hard times in recent years. 
 
 In this report, mineral economist Dr. Subhash Bhagwat takes us through the reasons, such as 
 air pollution reduction measures, for the precipitous decline in Illinois coal production from 60 
 million tons in 1990 to less than 50 million tons in 1995. This decline has shut down two dozen 
 mines and reduced mining employment from more than 10,000 in 1990 to less than 6,000 in 
 1995. 
 
 Dr. Bhagwat forecasts supply and demand for Illinois coal, as well as the continuing and future 
 effects of government policies such as the Federal Clean Air Act and the deregulation of elec- 
 tricity generation. The clean air legislation, which attacks the problem of acid rain by limiting the 
 levels of sulfur dioxide when coal is burned, has had an enormous impact on Illinois coal pro- 
 duction. The added expense of removing sulfur in Illinois coal to comply with the Clean Air Act 
 has helped make the use of Illinois coal uneconomical when compared with low-sulfur coal from 
 western states. 
 
 Deregulation of the electric utility industry will also add a new element of competition to the mar- 
 ket when consumers will be able to shop for the lowest priced electricity. To compete for cus- 
 tomers, utilities will have to find the lowest cost generation in terms of fuel, pollution and 
 clean-up, and capital costs. 
 
 Already uncompetitive with low-sulfur western coals, Illinois coal will increasingly compete with 
 cleaner sources of energy such as natural gas. This report's value is in laying out the various 
 potential shapes of the economic playing field on which Illinois coal must compete. 
 
 Although the short-term prognosis for Illinois coal is not good, Dr. Bhagwat gives us a clear view 
 of the problems facing the Illinois coal industry and the kind of research we need to do now to 
 address these problems in the future. We need to know the potential impact of all the factors af- 
 fecting Illinois coal before formulating public policy. 
 
 ^OL^u/.^Uf 
 
 William W. Shilts, Chief 
 Illinois State Geological Survey 
 
Editorial Board 
 
 Jonathan H. Goodwin, Chair 
 Michael L. Barnhardt Donald G. Mikulic 
 
 Heinz H. Damberger William R. Roy 
 
 Anne L Erdmann C. Pius Weibel 
 
 David R. Larson 
 
 ILLINOIS 
 
 NATURAL 
 
 RESOURCES 
 
 Printed by Authority of the State of Illinois/1997/600 
 © Printed with soybean ink on recycled paper 
 
CONTENTS 
 
 ABSTRACT 1 
 
 INTRODUCTION 1 
 
 DEMAND-SIDE DYMANICS 2 
 
 Electric Utilities Demand 2 
 
 Electric Demand Forecasts 2 
 
 Coal demand for electric generation 
 
 Coking Coal and Industrial Demand 3 
 
 REGULATORY DYNAMICS 3 
 
 Clean Air Act 4 
 
 Sulfur dioxide emissions limits 
 
 Percent reduction clause 
 
 Pollution credits 
 
 Future compliance strategies 
 
 Nitrogen oxide emissions 
 
 Other emissions 
 Trade Regulations and Utility Deregulation 6 
 
 Consequences of deregulation 
 
 SUPPLY-SIDE DYNAMICS 7 
 
 Coal Supplies 7 
 
 Other Supply Factors 7 
 
 Nuclear energy 
 
 Natural gas electric generation 
 
 Coal-based generation 
 
 Pollution credits 
 
 ISGS PROJECTIONS OF ELECTRIC DEMAND 1 
 
 FUTURE OF ILLINOIS COAL 10 
 
 WHAT CAN BE DONE? 12 
 
 REFERENCES 13 
 
 FIGURES 
 
 1 Annual growth rates in U.S. electric utility generation 3 
 
 2 Coal reserves by sulfur content and region 7 
 
 TABLES 
 
 1 Annual growth in U.S. electric utililty generation (by fuel) 8 
 
 2 Coal prices at mine and productivity 9 
 
 3 ISGS Industrial Minerals and Resource Economics Section's projection of 
 
 U.S. demand for electricity by fuel (billion kWh) 1 
 
 4 Operable and planned capacity additions 1993-2003 1 1 
 
 5 Utility coal sales and prices 1995 12 
 
ABSTRACT 
 
 Illinois coal sales declined from 60 million tons in 1990 to less than 50 million tons in 1995, and 
 the Industrial Minerals and Resource Economics Section of the Illinois State Geological Survey 
 projects them to decline to the range of 26 to 40 million tons by 2010. Public policies, particularly 
 the Clean Air Act (CAA) and its amendments, have dramatically altered coal markets and will 
 continue to do so. These policies will continue to set the market terms under which the Illinois 
 coal industry competes. 
 
 The 1970 CAA amendment's limit on S0 2 emissions of 1.2 Ib/mmBtu on coal-fired power plants 
 sparked the beginning of a major expansion of the low-sulfur coal mining industry in Wyoming 
 and Montana. Sales of high-sulfur coal produced east of the Mississippi River began to stag- 
 nate as low-sulfur western coal became available at low cost. Largely because low-sulfur coal 
 remained highly cost-effective, attempts in 1977 to improve the competitive position of high- 
 sulfur coal by requiring that both high- and low-sulfer coal have their emission potential reduced 
 by 90% failed. 
 
 The 1990 CAA amendments introduced "pollution credit" trading to promote emission reductions 
 nationally at the lowest cost to the economy. They also extended the emission limits to all previ- 
 ously exempt plants and mandated a nationwide S0 2 emissions reduction of 10 million tons 
 through 2000. Finally, they banned any increase in national emission levels beyond the level 
 mandated for the year 2000. Introducing new competitive elements by which utilities can more 
 economically and efficiently meet regulatory standards, these amendments favor the use of the 
 cleanest fuels and the shifting of electricity generation to the lowest-cost power plants nationwide. 
 The winners will likely be the environment, the economy, and the producers of low-sulfur, low- 
 cost fuels. The immediate cost will be borne by regions that produce high-sulfur coal, such as 
 the Illinois Basin. 
 
 Dynamic supply and demand changes in the U.S. coal market, market competition between coal, 
 natural gas and nuclear energy, and changes in the electric utility regulatory environment will 
 bring about major changes in the years through 2010. Continued availability of low-cost western 
 coal, adequate amounts of natural gas, and the continuation of emissions credits are likely to 
 adversely affect Illinois coal sales. 
 
 The key to long-term sustainability for the Illinois coal industry is to concentrate research and 
 policy efforts on improving the cost competitiveness of coal produced in the state. 
 
 INTRODUCTION 
 
 Public policies, particularly the Clean Air Act (CAA) and its amendments, have dramatically altered 
 coal markets, and will continue to do so. To assess how coal markets will affect Illinois coal pro- 
 duction in the next 15 years, this report analyzes the changes in coal markets since the beginning 
 of the CAA regulations in the late 1960s, the changes that will ensue from expected future de- 
 regulation of the electric generation industry, and projected changes in coal supply and demand. 
 
 Before the 1970 CAA amendment that limited sulfur emissions from newly constructed coal- 
 burning power plants, the coal industry in Wyoming and Montana produced less than 5 million 
 tons of coal per year. The amendment provided the necessary incentive to develop these low- 
 sulfur resources and the coal industry in the western United States rose and expanded to the 
 point that it now produces about 350 million tons a year. Low-sulfur coal from the western states 
 captured most of the 1970's growth in coal demand, which due to a slowing growth rate in elec- 
 tricity demand, was not as strong as in previous decades. Because of the clean air regulations, 
 coal production east of the Mississippi River captured little of this growth in demand. The effect 
 was more severe in states that produce high-sulfur coal, particularly Illinois, Indiana, Ohio, and 
 western Kentucky. 
 
 The CAA was amended in 1977 in an attempt to help the coal industry in states producing high- 
 sulfur coal. These amendments said that regardless of a certain coal's sulfur content, the sulfur 
 emission from burning that coal had to be reduced by up to 90 percent of what the emission 
 would be if no abatement procedures were used. This restriction applied only to plants built after 
 the amendments took effect. This amendment, commonly referred to as the "percent reduction 
 clause," in effect required all new power plants to install flue gas clean-up equipment, called 
 scrubbers, whether the plant burned high-sulfur coal or not. The intent was that the advantage 
 
from purchasing low-cost, low-sulfur western coal in lieu of installing scrubbers would be negated 
 by mandating investments for scrubbers for all new power plants. 
 
 This strategy failed to significantly boost sales of high-sulfur coal. Fewer than expected coal-fired 
 power plants were built because of the continued decline in the electricity demand growth rate 
 and because utilities maximized nuclear generation in an attempt to recover the nuclear plants' 
 high capital costs. A perhaps more important reason for the strategy's failure is the fact that the 
 price of low-sulfur coal continued to be significantly lower than the price of high-sulfur coal. 
 
 In 1990, the CAA was again amended to introduce efficiencies of competition to sulfur emission 
 reduction activities. The amendment revokes the percent reduction clause but requires that the 
 national sulfur emission reduction targets for the years 1995 and 2000 are met. The amendment 
 also revokes the "grandfathering" of older power plants on sulfur emission limits and forces them 
 to reduce pollution to meet the targets. Individual power plants now have flexible targets. They 
 can either reduce actual emissions, or purchase allowances, sometimes called pollution credits, 
 from other power plants that have reduced emissions to levels lower than required by law. This 
 provision promotes competition not only between low- and high-sulfur coals, but also between 
 coal and natural gas. 
 
 Further changes in the regulatory environment are expected in the 1995 to 2010 period. Elec- 
 tricity wholesalers have already been freed by the 1992 federal Energy Policy Act to purchase 
 electricity anywhere, instead of only from their regulated monopoly utility. Retail customers will 
 soon be free to purchase power on the open market. This market deregulation will intensify com- 
 petition to produce power at the lowest cost. Electricity will be much more price sensitive as users 
 shop for the best deal. This will naturally affect the demand for coals and other fuel. 
 
 DEMAND-SIDE DYNAMICS 
 
 Total coal demand is comprised of the demand for coking coal, demand for industrial use and 
 export, and, by far the largest element, demand for coal for electric generation. Coal demand in 
 the U.S. increased from 523 million tons in 1970 to 941 million tons in 1995. Increased domestic 
 consumption of electricity created most of this rise in demand. 
 
 The comparative cost of fuels is the other factor beside electricity demand that determines coal 
 demand. The choice between using coal, natural gas, oil or nuclear generation depends primarily 
 upon the total cost of electricity generation, including fuel price, the cost of fuel transportation, 
 investment in generation and pollution prevention equipment, and the decommissioning cost of 
 nuclear power plants. This aspect is discussed below in the Supply-Side Dynamics section. 
 
 Electric Utilities Demand 
 
 The portion of U.S. coal production used in electricity generation increased from 66% to 81% 
 between 1970 and 1995. Electric utilities accounted for 61 percent of domestic consumption in 
 1970, 81 percent in 1980 and 88 percent in 1995. 
 
 According to the U.S. Department of Energy, coal-fired power plants generated 46 percent of all 
 electricity in 1970, 51 percent in 1980, and 55 percent in 1995 (USDOE, Aug. 1996). Nuclear 
 electricity's share of total consumption rapidly increased from 1.4 percent in 1970 to 11 percent in 
 1980, and to 22.5 percent in 1995. The oil and natural gas price shocks in 1974 and 1979-81 re- 
 sulted in significant conservation and fuel switching by individuals, businesses, and electric utili- 
 ties. By 1995, the share of oil and natural gas in electricity generation had fallen to 2% and 10.3% 
 respectively, well below their 1970 levels of 11% and 24%. 
 
 Growth in U.S. electric demand averaged about 2.7% per year between 1970 and 1995. How- 
 ever, there were differences in annual growth rates during periods of stronger and weaker eco- 
 nomic cycles: a yearly average of 6.7% between 1970 and 1973, 3.2% in 1973-1979, about 3% in 
 1984-1989, but only 1.8% in 1979-1984 and 1.2% in 1989-1995 period. The trend in the growth 
 rates of utility generation has been downward, from about 3.1% in 1971 to 1.6% in 1995 (fig.1). 
 
 Electric Demand Forecasts 
 
 In 1991 , the U.S. Department of Energy and four other institutions forecasted U.S. electricity 
 demand to grow at 1.4 to 2.4% per year from 1990 through 2010 (USDOE, March 1991). 
 Changed conditions in the interim, however, indicate that electricity demand may grow at lower 
 
-4.0 
 
 1970 
 
 1975 
 
 1980 
 
 1985 
 
 1990 
 
 1995 
 
 Figure 1 Annual growth rates in U.S. electric utility genera- 
 tion (USDOE, Aug. 1996). 
 
 rates. The 1993 Annual Energy Outlook 
 revised the forecast to the range of 1 .3 
 to 1 .8% annual growth for these years 
 (USDOE, Jan. 1993). The 1996 DOE 
 forecast projects total electricity demand 
 to rise an average 1 .26% per year be- 
 tween 1995 and 2010 (USDOE, Jan. 
 1996). Generation by electric utilities is 
 projected to rise at a 1% per year rate, 
 and non-utility generation and cogener- 
 ation at 3% per year. 
 
 Growth rates for electrical generation in 
 the non-utility and cogeneration sectors 
 fluctuated strongly over the period; 7% 
 of total electricity generation in 1970 but 
 only 3% in 1 980. Then it increased to 
 9% in 1990 and exceeded 14% in 1995. 
 
 Coal Demand for Electric Generation 
 
 The 1994 data on heat consumption indicate that 1 ton of coal is required to generate about 2 
 billion kWh of electricity. Based on this ratio, U.S. demand in 2010 for coal for electricity genera- 
 tion by utilities and independent power producers together will be about 1025 million tons. 
 
 An important aspect to the above forecast is the overall conversion efficiency of coal-burning 
 power plants. Each percentage point increase in thermal efficiency of power plants can reduce 
 coal demand by 2.5%. Although the average thermal efficiency in the U.S. is unlikely to change 
 drastically because of the very small capacity additions expected in the next 15 years, a small 
 change of 1 percentage point can reduce demand forecast by as much as 30 million tons. Such a 
 change is conceivable as load factors for efficient, low-cost plants are increased and less efficient 
 older plants are retired or their usage reduced. 
 
 Coking Coal and Industrial Demand 
 
 Coke for ore smelting is made from coal. In 1970, coking plants in the U.S. and overseas con- 
 sumed about 153 million tons of U.S. coal production. Over the past 25 years, total domestic and 
 foreign consumption of U.S. coal for coke-making is down by more than 40% to about 90 million 
 tons in 1995. Although foreign consumption increased over this time, U.S. consumption fell 70%. 
 About 9% of U.S. coal production in 1995 was sold for coke-making. 
 
 Domestic consumption by industrial users other than electric utilities and coke plants, and exports 
 of non-coking coal, have together declined from about 121 million tons in 1970 to about 101 mil- 
 lion tons in 1995, or about 10.5% of total U.S. coal production. 
 
 Coal demand for coke making, industrial uses and exports, which totaled about 190 million tons 
 in 1995, may add another 200 million tons to increase the total U.S. coal demand in 2010 to about 
 1 ,225 million tons. The total demand growth rate for coal is thus expected to average about 
 1.15% per year. 
 
 REGULATORY DYNAMICS 
 
 Besides traditional demand dynamics, federal regulations and market interventions are critical in 
 determining the overall demand for coal, and demand for Illinois coal in particular. 
 
 The two primary sets of regulations affecting coal markets, especially the electricity generating 
 sector of the coal market, are the Clean Air Act amendments of 1990 and electric utility regula- 
 tions concerning the production, distribution and trade in electric power. Another intervention is 
 the large indirect subsidy provided to the nuclear electric generating industry. The potential for 
 future regulation of "greenhouse gases" may also already be playing a role in fuel choice deci- 
 sions by utilities. 
 
The Clean Air Act 
 
 The Clean Air Act was passed in 1963, its first regulations became effective in the late 1960s, 
 and it was amended in 1970, 1977, and 1990. 
 
 Sulfer Dioxide Emission Limits The 1970 amendments limited SO2 emissions from all new 
 electric power plants to 1 .2 lbs per million Btu of energy consumed. Older plants were to be regu- 
 lated according to schedules to be developed under individual State Implementation Plans. The 
 1970 amendments provided a strong incentive to mine low-sulfur coal deposits in the western 
 states and sparked the modern, fast-growing coal mining industry there. Its low sulfur content 
 and falling price soon allowed western coal to take market shares away from the higher-sulfur 
 midwestern coals. 
 
 Percent Reduction Clause The intense political activity that followed this development led to 
 the 1977 amendments. These retained the maximum limit on sulfur emissions, but introduced a 
 new clause intended to help coals from eastern states regain competitiveness. The "percent 
 reduction requirement" generally required SO2 emissions to be 90% lower than what they would 
 be without scrubbing, regardless of the sulfur content of the coal. Maximum permissible emission 
 levels remained at 1 .2 lbs SO2 per million Btu. Some plants were allowed a 70% reduction in 
 potential emission if this reduced emissions to less than 0.6 lbs SO2 per million Btu. 
 
 In effect, the percent reduction requirement imposed stricter total emission limits on lower-sulfur 
 coals than on higher-sulfur coals, and created a bias in favor of midwestern coals. This attempt 
 to correct the 1970 amendment's bias toward low-sulfur western coals ultimately failed because 
 of economic reasons. 
 
 Pollution Credits The 1990 amendments were the result of congressional desire to create 
 incentives to develop technologies that would result in even lower emissions than prescribed by 
 law. Congress also wished to lessen the regulatory interference the earlier amendments introduced 
 and rely more on free market mechanisms, while at the same time achieving the objective of 
 cleaner air. 
 
 The 1990 amendments eliminated the percent reduction requirement, but mandated a reduction 
 in nation-wide S0 2 emissions of 5 million tons by January 1995 (Phase I) and another 5 million 
 tons by January 2000 (Phase II). The 1990 amendments also capped future S0 2 emissions at 
 the 2000 level. . 
 
 Congress intended these amendments to provide flexibility in complying with the objectives of the 
 law. The mechanism to do this is the "pollution credit," which allows plants that reduce emissions 
 below the legal limits to achieve an economic benefit — a credit — that they can sell to plants that 
 are over the limit. The overall national goal of emission reduction is unchanged, and an economic 
 incentive has been added by giving exchangeable value to initiatives that reduce emissions. 
 
 The 1990 amendments make emission reduction an economic decision without compromising on 
 the level of overall reduction. In addition, regulations regarding the ambient air quality anywhere 
 in the U.S. were not changed, guaranteeing that regional air quality does not deteriorate. How- 
 ever, future changes in ambient air quality regulations are currently being contemplated. 
 
 A sign that the 1990 amendments are having the intended effect is the declining market price per 
 unit of pollution credit traded (1 Unit = 1 ton of S0 2 per year). 1990 predictions for the price of a 
 •unit of pollution credit were as high as $1,500, a price that reflected the avoidance of retro-fitting 
 old plants with new pollution control devices and increased waste disposal. As of March 1996, 
 pollution credits were traded at about $65 to $70 per unit (Coal Week, April 1, 1996). The falling 
 price indicates an excess of supply of pollution credits over demand, i.e., significant overcom- 
 pliance on the part of the utilities. (See box on page 5.) 
 
 Future Compliance Strategies In the short-term, most power plants will gain compliance by 
 simply switching to low-sulfur western coal. Pollution can be reduced to levels well below the 
 limits set for 1995, and even below the limits for the year 2000, simply by fuel-switching, which 
 avoids additional investment in scrubbers. Because the delivered price of low-sulfur western coal 
 is comparable with the local price of high-sulfur coal in most states, demand for western coal is 
 expected to rise through the year 2000. Depending upon the degree of over-compliance achieved 
 through fuel switching, this demand may continue to rise through 2010. A large majority of 
 
Why Pollution Credits Cost So Little 
 
 If a power plant targeted for Phase I clean-up were to burn Illinois Coal (3% sulfur, 
 1 1 ,500 Btu/lb), the plant would emit 5.22 lbs of S0 2 , or 2.72 lbs over the permitted 
 level of 2.5 lbs per million Btu of energy consumption. This plant would have to buy 
 2.72 lbs of emission allowances from another plant, install a scrubber, or switch to 
 lower sulfur fuels such as western coal or natural gas. As the table below shows, 
 the shift to low-sulfur coal for air quality compliance involves little or no additional 
 expense. 
 
 In Phase I of the 1990 Clean Air Act Amendments, a major shift to western low- 
 sulfer coal occured because of the cost advantage. This has significantly contrib- 
 uted to the large number of pollution credits generated due to overcompliance. 
 
 Many plants have reduced 
 Delivered price of coal to utilities in three regions. emissions to levels well below 
 
 the 2.5 lb limit. The EPA re- 
 ports that 2.3 million units 
 (each unit equals a ton of S0 2 ) 
 were available for purchase at 
 the end of 1995. Many plants 
 have already reduced emis- 
 sions to levels below the 
 stricter standards for the year 
 2000 (1.2 lbs S02), and have 
 thus eliminated any need to 
 purchase pollution credits. 
 
 The surplus of credits led to a 
 drastic fall in price, from about 
 $130 per unit in April 1995 to 
 $65 a year later. 
 
 Because some utilities will be 
 unable to reduce emissions 
 by coal switching for technical, 
 economic or logistical reasons, 
 a market for pollution credits 
 will continue to exist. How- 
 ever, it is likely that the prices 
 will remain low due to over- 
 supply. 
 
 
 Low-sulfur 
 coal 
 
 High-sulfur 
 coal 
 
 South Atlantic 1 
 
 
 
 1 995 price/mm Btu 
 
 $1.54 
 
 $1.48 
 
 1996 price/mm Btu 
 
 $1.51 
 
 $1.56 
 
 West North Central 2 
 
 
 
 1 995 price/mm Btu 
 
 $0.96 
 
 $1.83 
 
 1 996 price/mm Btu 
 
 $0.92 
 
 $1.22 
 
 East North Central 3 
 
 
 
 1995 price/mm Btu 
 
 $1.40 4 
 
 $1.22 
 
 1996 price/mm Btu 
 
 $1.44 4 
 
 $1.28 
 
 1 DE, DC, FL, GA, NC, SC, VA, WV 
 
 2 IA, KS, MN, IA, NE, ND, SD 
 3 IL, IN, Ml, OH, Wl 
 
 4 This is more expensive than average because one 
 Illinois utility paid exceptionally high prices for some 
 western coal it was obligated to buy under an older 
 contract agreement. 
 
 This low cost reflects the disincentive for plants to invest in equipment that would 
 allow more Illinois coal to be burned, and it reflects the attractiveness of switching 
 to western coal as an alternative to scrubbers for meeting emission standards. 
 
 affected plants have indicated that they will follow this strategy in Phase I of the 1990 amendments 
 (USDOE, 1994). 
 
 Some plants will include natural gas in the fuel mix as a strategy to meet the Phase I emission 
 limit. This fuel choice will allow some plants to also comply with the Phase II emission limits. The 
 excess emission allowances will be carried over past the year 2000 until new coal-fired facilities 
 use them up. Because only a finite number of credits will be available, sulfur-free fuels such as 
 natural gas will be preferred by users who must comply with the S0 2 emission "cap". Available 
 technologies like Flue Gas Desulfurization (FGD) and Fluidized Bed Combustion (FBC), and 
 emerging ones like Integrated Gasification Combined Cycle (IGCC) would permit coal-burning 
 with little or no S0 2 emission. Decisions to use them, however, will depend on their total generat- 
 ing cost versus the total cost of sulfur-free fuels. 
 
Nitrogen Oxide Emissions Emissions of nitrogen oxides (NO x ) are also regulated under the 
 Clean Air Act. Some NO x rules apply only to plants that are affected by CAA SO2 regulations. 
 Each affected unit must hold NO x emissions below 0.45 or 0.5 lbs per million Btu, depending 
 upon the boiler type. For fossil-fuel-fired units located in ozone non-attainment areas (defined 
 within the law), the NO x emission limit is either 0.2 lbs per million Btu or a 55-65% reduction below 
 the 1990 emission level in the warmest five months of the year. States must determine what con- 
 trol technology is reasonably available to achieve this goal. If the compliance strategy of reducing 
 NO x emissions includes burning natural gas, it will affect coal use. 
 
 Other Emissions The 1990 amendments also propose to control emissions of Hazardous Air 
 Pollutants (HAPs), but the EPA has not yet studied the issue sufficiently to develop regulations. 
 When such regulations are established, they may affect coal use. Depending upon the coal used, 
 up to 16 HAPs are known to be released by combustion. These include arsenic, benzene, beryl- 
 lium, cadmium, chlorine, chromium, dioxins/furans, formaldehyde, lead, manganese, mercury, 
 nickel, polycyclic aromatic hydrocarbons, radionuclides, selenium, and toluene. According to the 
 utility industry, their concentrations are not a health risk to humans (EPRI, 1994). Any restric- 
 tions on HAPs would result in at least some additional fuel switching to natural gas, which would 
 reduce the use of coal in electricity generation. Regulations are also being considered to reduce 
 permissible dust emissions from 10 micron sized particles to 2.5 micron sized particles. Such a 
 regulation may negatively affect the use of all coals. 
 
 Trade Regulations and Utility Deregulation 
 
 Currently, most investor-owned electric utilities are "regulated monopolies." Within a monopoly 
 utility's geographic area, customers can only purchase electricity from that utility and it must sup- 
 ply all customers in its service area. A state commission determines the utility's rate of return on 
 investment, and must approve all expenses the company charges to consumers. 
 
 Electric utilities are now being deregulated under the 1992 National Comprehensive Energy Pol- 
 icy Act. Wholly-owned "independent" power-producing companies that are not subject to the 
 same constraints as utilities are now permitted. These independents are free to produce and sell 
 electricity to anyone anywhere. Utilities are also now permitted to merge and take advantage of 
 synergies in competing for distant and/or major markets. Utility mergers are on the rise, and 
 some have taken place between companies in different states. Wholesalers who buy electricity 
 for resale are now free to purchase it anywhere, and utilities are required to provide transmission 
 for a fair market charge. Retail customers, however, are still required to purchase electricity from 
 the utilities until state laws are amended. Other aspects of the deregulation climate are the inter- 
 national electricity and gas transactions already taking place between the United States, Canada 
 and Mexico. These may intensify in the future due to the North American Free Trade Agreement 
 (NAFTA). 
 
 Consequences of Deregulation 
 
 The deregulation efforts will likely intensify price competition among producers of electricity and 
 force cost-cutting measures in the industry. Some of the expected and potential consequences of 
 the increased competition are: 
 
 • Old low-efficiency and high-cost generating units will be retired earlier than planned. 
 
 • Lower-cost units that remain in production will be able to further reduce cost per kWh by 
 increasing the capacity utilization (load factor). 
 
 • Investor-owned-utilities may no longer be required to purchase excess electricity generated by 
 independent small producers. 
 
 • National or regional electricity distribution networks may emerge as independent service firms. 
 
 • Intracity distribution networks may be available for purchase by the cities or private enterprise. 
 
 • While producers of electricity may be freed from regulations, distribution networks might con- 
 tinue as some form of "regulated monopolies." 
 
• Gas-fired combined-cycle electricity generation may assume a greater role in production and 
 help lower costs. The natural gas industry is already deregulated, allowing utilities to shop for 
 the least-cost gas deals nation-wide, and from neighboring countries under NAFTA. 
 
 • Due to intense price competition in electricity markets, utilities with unamortized investments in 
 nuclear power plants may face economic hardships from these potentially difficult to recover 
 investments. 
 
 • Because they are too small to be economically competitive, rural electric power supply compa- 
 nies are already facing loan servicing problems. In addition, several of them have partial owner- 
 ship interests in nuclear power plants. Federal assistance worth billions of dollars has been 
 granted to several cooperatives. At least $1 1 billion of loans are currently in default, requiring 
 remedial action (Wall Street Journal, Oct. 3, 1996). The magnitude of public assistance 
 required in this area could determine the speed of deregulation in the electric power business. 
 But there is no doubt that deregulation will put competitive pressures on high-cost power suppli- 
 ers in the decade ahead. 
 
 SUPPLY-SIDE DYNAMICS 
 
 Coal Supplies 
 
 Coal availability in the United States is not a geological problem. According to DOE, recoverable 
 coal reserves in the U.S. total about 265 billion tons. About 61 billion tons of the U.S. recoverable 
 coal reserves are in the Interior Region and about 80% of that is in the Illinois Basin, which 
 
 includes parts of Illinois, Indiana and west- 
 ern Kentucky. Thus, nearly 49 billion tons of 
 recoverable coal reserves, or 1 8.5% of the 
 national total, are in the Illinois Basin (US- 
 DOE, 1995). 
 
 160 
 
 140- 
 
 « 12( H 
 
 c 
 
 •2 100 
 
 t: 
 o 
 
 -C 
 
 w 
 
 c 
 o 
 
 m 
 
 80 
 
 60 
 40 
 
 20- 
 
 
 
 
 
 
 High sulfur 
 Medium sulfur 
 Low sulfur 
 
 
 
 - 
 
 
 
 
 - 
 
 ] 
 
 
 
 
 
 However, this quantity is limited by the qual- 
 ity of recoverable coal reserves, especially 
 their sulfur content. The low-sulfur (<1 .2 lbs 
 S0 2 per million Btu) recoverable reserves in 
 the U.S. are about 100 billion tons, very little 
 of which is in the Interior Region. Little or no 
 Illinois Basin coal can comply with the maxi- 
 mum allowable S0 2 limit through the year 
 2000 without additional cleaning or other 
 forms of emission controls (fig. 2). About 
 87% of the nation's low-sulfur coal reserves 
 are in the western states, while 61% of 
 high-sulfur (>3.36 lbs S0 2 per million Btu) 
 recoverable coal reserves are in the Interior 
 Region, mostly in the Illinois Basin. The 
 1990 Clean Air Act amendments have re- 
 sulted in a drastic reduction in demand for high-sulfur coal. The demand for medium-sulfur (>1 .2 
 and <3.36 lbs S0 2 per million Btu) coal is likely to be secure for the years through 2000 but may 
 not remain so after that. 
 
 Appalachian 
 
 Interior 
 Regions 
 
 Western 
 
 Figure 2 Coal reserves by sulfur content and region 
 (USDOE, Feb. 1995). 
 
 Other Supply Factors 
 
 Fuel cost is the main determinant of electricity generating plants' operating cost. Operating and 
 capital costs, including capital costs for emission control equipment and waste disposal, as well 
 as building and shut down costs, comprise total generating cost. Fuel choice is thus determined 
 not only by its price but also by the cost of equipment needed to burn it cleanly and to safely dis- 
 pose of waste. For instance, high-sulfur coal cannot be burned cleanly without expensive invest- 
 ment in emission control devices, but low-sulfur coals can be. 
 
 Illinois Coal is in competition with other fuel supplies for generating electricity, and when its total 
 cost (production, consumption, disposal, etc.) is compared to the costs of other fuels, the lowest 
 total cost fuel will be used. 
 
To understand Illinois coals' current and near term disadvantage in comparison to other fuels, the 
 cost structures of these fuels and the comparative costs of various pollution abatement strategies 
 within the current and future regulatory environment must be understood. 
 
 Nuclear Energy Pollution control and waste disposal costs of fossil fuels have been included 
 in the price of coal-generated electricity, but the nuclear industry's costs of development and 
 waste disposal have been and remain highly subsidized by taxpayer dollars. It also appears that 
 insufficient money is being set aside to pay for the decommissioning of nuclear plants, which may 
 be higher than the cost of building them (Heinze Fry, 1991). These unrealized or transferred 
 costs allowed nuclear energy to capture a larger share of the growth in electric generation than 
 coal (table 1). From 1989 to 1995, nuclear 
 
 electricity generation grew at 4.1 % annu- Table 1 Annual growth in U.S. electric utility generation 
 ally, compared with 1 % for coal-based (by fuel). 
 
 Coal Nuclear Natural gas 
 
 generation. 
 
 Because nuclear power plants are highly 
 
 capital-intensive, their economic operation 1970-1973 6.4% 55.7% -3.0% 
 requires maximum use as base load gen- 
 erating capacity. Their low operating cost 1973-1979 4.0 20.5 -0.6 
 due to low fuel costs is also an incentive -myology 4 5 51 _ 2 
 to maximize their use. 
 ~ , o , 1984-1989 3.0 10.1 -2.2 
 
 Capacity utilization in U.S. nuclear power 
 
 plants has increased from near 50% in 1989-1995 1.0 4.1 2.4 
 
 1973 to about 78% in 1995 (USDOE, Aug. 
 
 1996). Some growth in nuclear capacity Source: USDOE, Aug. 1996 
 
 utilization may still be possible, but the 
 
 maximum sustainable load factor may 
 
 have been reached. A new nuclear plant — the 1 170 MW Watts Bar 1 — became operational in 
 
 May 1996, but no other new plants are scheduled to begin production in the coming ten years 
 
 because none is under construction or in the licensing stage. 
 
 Nuclear plants' low operating costs, and the large portion of initial capital investment that remains 
 to be recovered for many plants, will act to keep these plants in service. Retiring them would 
 leave utilities with stranded costs that would have to be recovered either through higher electric 
 rates or taxpayer subsidies. Nonetheless, the DOE forecast assumes some nuclear plant retire- 
 ments for cost reasons. Smaller, older nuclear plants will be among those to be retired. However, 
 the 1 170 MW generating capacity of the newly operational Watts Bar 1 will more than make up 
 for retirements. Although DOE forecasts nuclear electricity generation to decline by 2010, a small 
 increase at an annual rate of 0.5% may be a more appropriate assumption. 
 
 Natural Gas Electric Generation. Gas-based generation increased at 2.4% per year during 
 1989 to 1995, after a sustained 16 year decline. Comparative total costs for coal and natural gas 
 in both the utilities and the independent sectors is likely to favor gas, unless gas prices rise to the 
 point where coal becomes a better choice despite its additional sulfur removal and waste disposal 
 costs. Incremental growth in demand for electricity in the future might promote the construction of 
 gas-fired combined cycle plants with 60% thermal efficiency compared with coal-fired plants with 
 40% efficiency. Gas-fired plants take only 1 to 3 years to build and cost at least 40% less than 
 coal-fired plants (EPRI, Sept. 1987). Unlike in the 1980s, gas is no longer perceived as a com- 
 modity in short supply. DOE estimates proven U.S. gas reserves to be about 165 trillion cubic feet 
 (Tcf), the equivalent of ten years of supply at the current rate of production. An additional 1 ,200 
 Tcf can be found and produced at current prices and with currently available technology (US- 
 DOE, 1994). Its ease of use, its ready availability and clean-burning characteristics, and the ab- 
 sence of waste disposal costs and the low initial capital requirements associated with it, make 
 natural gas an attractive fuel for future electricity generation despite its higher price. Planned ca- 
 pacity additions by electric utilities indicate that of the 32,000 MW to be added between 1 993 and 
 the year 2000, about 60% will be gas-based and only 20% coal-based {USDOE, 1992). 
 
 Coal-Based Generation According to the 1996 DOE annual energy outlook, the growth in 
 coal-based electricity generation between 1995 and 2010 will come from an increase in capacity 
 utilization from 62% to about 75%. No net addition to coal-based generating capacity is expected 
 in this period, because added capacity will only replace retired capacity. 
 
Recent projections of U.S. coal production in 2010 range from DOE's 1,182 million tons to 1,348 
 million tons by WEFA, formerly the Wharton Econometric Forecasting Associates Group (USDOE, 
 Jan. 1996). 
 
 Coal mined in the western states enjoys a price advantage over midwestern coal primarily 
 because mining costs in those states are extremely low (table 2), and because average nationwide 
 rail transportation rates declined 17% between 1986 and 1993 as a result of the transportation 
 
 industry deregulation in the late 1970s (Philo, Keefe, etal., 1995). The competition between rail- 
 road companies and the creation of large companies through mergers and acquisitions contrib- 
 uted to increased efficiency and lower cost. Coal represents a major revenue source for railroad 
 
 companies and transportation 
 
 Table 2 Coal prices at mine and productivity. costs are a major cost factor for 
 
 coal-fired electric utilities (Vaninetti 
 and Valentine, 1996). 
 
 In 1995, the price of Wyoming coal 
 at the mine was $6.58 per ton 
 compared with $23.05 for Illinois 
 coal. Although the average Btu 
 value of Wyoming coal is lower 
 than the Illinois average, the Wyo- 
 ming coal shipped to Illinois and 
 other eastern states is generally 
 above average in Btu value. The 
 difference in Btu value, therefore, 
 is not large enough to make up for 
 the basic price difference between 
 Illinois and Wyoming coals. 
 
 Average 
 
 Productivity 
 
 Change/yr 
 
 mine price 
 
 in 1995 
 
 1986-1995 
 
 ($/t) 
 
 (t/person/hr) 
 
 (%) 
 
 Illinois 
 Indiana 
 Kentucky 
 East 
 West 
 Colorado 
 Montana 
 Wyoming 
 
 23.05 
 21.71 
 
 26.00 
 
 20.75 
 
 19.26 
 
 9.62 
 
 6.58 
 
 3.87 
 4.68 
 
 3.47 
 
 3.97 
 
 6.14 
 
 21.06 
 
 30.06 
 
 5.6 
 3.7 
 
 4.6 
 3.4 
 5.3 
 2.0 
 
 7.5 
 
 Source: USDOE, Oct. 1996 The |Qwer CQSt Qf mjnjng jp WyQ . 
 
 ming and Montana is due to thicker 
 coal deposits buried under thinner layers of overburden than in Illinois. Large-scale surface min- 
 ing is possible there with productivity five to eight times higher than in Illinois coal mines (table 2). 
 Productivity in llllinois coal mines has grown at an average rate of 5.6% annually from 1986 to 
 1995. At this rate, mine productivity approximately doubles every 13 years. However, productivity 
 in Wyoming mines rose 7.5% per year in this period, a rate that more than doubles productivity 
 every 10 years. Thus, the cost advantage for Wyoming coal has been further enhanced. 
 
 Pollution Credits In addition to its lower price, Wyoming coal also has a lower sulfur content 
 that helps keep emissions to levels low enough to meet the final limits set for the year 2000 by 
 the 1990 CAA amendments. Utilities that switched to Wyoming coal since 1990 have been able to 
 meet or exceed the cleanliness standards for both Phase I and Phase II of the CAA amendments. 
 And they have done this with lower fuel costs and without the added expenses for flue gas clean- 
 up that would be needed for Illinois coal. The use of Wyoming coal also makes the purchase of 
 emission allowances unnecessary. 
 
 Emission allowances were traded for $70 per ton of S0 2 in April 1 996. Purchasing of allowances 
 to account for an emission reduction from 2.5 lbs to 1 .2 lbs of S0 2 per million Btu would cost only 
 about 5 cents. However, low-sulfur compliance coal is already cheaper than high-sulfur coal, 
 leaving no economic incentive to purchase any emission allowances in conjunction with the pur- 
 chase of Illinois coal. 
 
 The federal EPA reports a 2.3 million unit (1 Unit = 1 ton S0 2 ) over-compliance at the end of 
 Phase I. During Phase II, the national S0 2 emissions are to be lowered by 5 million units from 
 the Phase I target. With a 2.3 million unit over-compliance in Phase I, almost half of the reduc- 
 tions targeted in Phase II have already been achieved. It is conceivable that the economic ad- 
 vantages of switching to lower sulfur coal in Phase II will favor such a switch and carry a similar 
 or higher level of over-compliance into the next century. An increase in the use low-sulfur coal 
 through the year 2000 is also likely due to the provision in the 1990 CAA amendments that there 
 be no nationwide increase in S0 2 emissions after the year 2000. Any addition to the generating 
 capacity after 2000 that has the potential to emit S0 2 into the atmosphere must be offset by an 
 
1995 3405 1714 497 673 521 
 
 2005 3878 1938 702 714 525 1.2 
 
 equal reduction of emission from existing sources or by way of purchasing emission allowances 
 created by the 1990 CAA amendments. Given the economic advantages of burning low-sulfur 
 western coal over high-sulfur coal, utilities would continue to have an incentive to prefer low-sulfur 
 coals and minimize credit purchases for plants to be built after the year 2000. This would result in 
 a further decline in the sales of high-sulfur coals such as the Illinois coal. 
 
 ISGS PROJECTIONS OF ELECTRIC DEMAND 
 
 The projections of U.S. demand for electricity in table 3 are based on average growth rates of 
 1 .2% for coal, 3.5% for gas and 0.5% for nuclear electricity, with no growth in the other sources. 
 The overall rate of growth in electricity is 1 .3% per year. 
 
 For the 1995-2010 period, the USDOE projects coal-based generation by electric utilities to 
 grow 1.26 percent per year. Coal-based non-utility generation is projected to grow an average 
 of 2 percent per year. Gas-based utility generation is projected to rise 2.4 percent per year and 
 Gas-based non-utility generation by 3.9 percent annually. The DOE also projects nuclear gen- 
 eration to decline slightly (USDOE, Jan. 1996). 
 
 ♦u„ r,\J,*r;~ , ,t;nt., ir ,jL»n, ™, ,ih Table 3 ISGS Industrial Minerals and Resource Economics See- 
 
 the electric utility industry col d tiorVs jection of us . demand for electricity by fuel (billion kWh). 
 
 change this scenario. Currently, 
 
 utilities are required to purchase . . _ , ^ , Chanae 
 
 excess electricity produced by in- Year Total Coal Gas Nuclear Other (%/y 9 
 
 dependent power producers (IPP). 
 Because the price is set at the utili- 
 ties' marginal production costs, it 2000 3653 1832 593 703 525 1.2 
 guarantees a market at the highest 
 possible price for IPP-generated 
 excess electricity. A deregulated 2010 4130 2050 830 725 525 1.3 
 electricity industry will abolish this 
 provision and force the IPPs to 
 
 compete with the utilities in the open market. Some of the IPPs may receive taxpayer support 
 during the transition period, but in the long run, growth rates in the independent sector will likely 
 be smaller than in the utilities sector. 
 
 An important footnote to the above forecast is the overall conversion efficiency of coal-burning 
 power plants. Each percentage point increase in thermal efficiency of power plants can reduce 
 coal demand by 2.5 percent. Although the average thermal efficiency in the U.S. is unlikely to 
 change drastically because of the very small capacity additions expected in the next 15 years, a 
 small change of 1 percentage point can reduce demand forecast by as much as 30 million tons. 
 Such a change is conceivable as load factors for efficient, low cost plants are increased and less 
 efficient older plants are retired or their usage reduced. 
 
 FUTURE OF ILLINOIS COAL 
 
 The Illinois coal mining industry has been particularly hard hit by the dynamics of the coal market. 
 Caught between environmental imperatives and economic constraints, coal production in Illinois 
 began to decline after the passage of the 1990 Clean Air Act amendments. For about 25 years, 
 Illinois coal production averaged about 60 million tons per year, but it began to fall after electric 
 utilities recognized the economic as well as environmental advantages of burning low-sulfur coal 
 produced primarily in the western United States. In 1995, Illinois produced only 49.5 million tons 
 of coal. 
 
 An Illinois Coal Development Board (ICDB) report lists eight mine closures in 1994 and 1995 and 
 seven expected mine closures in 1996 (Keefe, Morey, and Heabert, Oct. 1996). Twelve other 
 coal mines in Illinois closed in the 1991 - 1993 period (Philo, Keefe, et al., 1995). The reasons 
 listed for the mine closures indicate an inability to compete in the market due to exhaustion of 
 marketable quality coal reserves or the high cost of mining. Coal mining employment in the 19 
 coal-producing counties declined from 10,129 in 1990 to 5,663 in 1995. Unemployment rates in 
 many coal-producing counties in southern Illinois exceeded 10% in 1994 compared with the state 
 average of 5.7%. 
 
 10 
 
The ICDB report also indicates that long-term sales contracts are declining rapidly (Keefe, Morey, 
 and Heabert, 1996). Modern capital-intensive mines need stable long-term sales commitments. 
 The market situation since 1990 has led to a decline in demand for high-sulfur coal and falling 
 spot market prices. In 1995, almost 80% of Illinois coal production was under long-term con- 
 tracts. 
 
 In 1996, that proportion fell to 67%. Only 42% of the current production is under contract for the 
 year 2000 and about 20% for 2010. Spot market sales, which accounted for 33% of 1995 sales, 
 would have to rise to 80% in 2010 if total coal sales were to remain at the 1995 level. The decline 
 in sales from 53 million tons in 1994 to 49.5 million in 1995 indicates that the tonnage of contract 
 losses has not been made up by tonnage increase in spot sales. Declining total sales, together 
 with falling long-term utility contractual commitments, indicate difficulties ahead for Illinois coal, 
 more than 90% of which is sold to electric utilities. 
 
 The ICDB report projects Illinois coal sales to utilities to decline to 33.3 million tons in the year 
 2000 (Keefe, Morey, and Heabert, 1996). Resource Data International (RDI) projects sales of Illi- 
 nois coal to electric utilities in year 2000 
 
 Table 4 Operable and planned capacity additions 
 1993-2003. 
 
 
 Operable (MW) 
 
 Planned (MW) 
 
 State 
 
 Total 
 
 Coal 
 
 Total 
 
 Coal 
 
 Illinois 
 
 36,909 
 
 17,220 
 
 881 
 
 
 
 Indiana 
 
 23,235 
 
 21,623 
 
 1,538 
 
 
 
 Missouri 
 
 16,842 
 
 11,663 
 
 1,913 
 
 542 
 
 Florida 
 
 31,109 
 
 10,850 
 
 3,627 
 
 719 
 
 Tennessee 
 
 18,227 
 
 10,020 
 
 2,540 
 
 
 
 Georgia 
 
 23,149 
 
 14,549 
 
 4,894 
 
 
 
 Total 
 
 149,471 
 
 85,925 
 
 15,393 
 
 1,261 
 
 Source: Keefe, Morey, and Heabert, 1996 
 
 at 29 million tons. If current sales of 8.5 
 million tons to non-utility consumers and 
 to other countries remain unchanged, 
 total sales of Illinois coal in 2000 could 
 be 37.5 to 42 million tons according to 
 ICDB and RDI forecasts. 
 
 According to DOE, the total operable 
 generating capacity in 1993 in the six 
 largest consumer states of Illinois coal — 
 Illinois, Indiana, Missouri, Florida, Ten- 
 nessee and Georgia — was 149,471 
 MW, of which 85,925 MW or 57.5% was 
 coal-fired (table 4). About 15,393 MW 
 of new capacity is planned to be added 
 through the year 2003, but only 8.2% of 
 it (1 ,261 MW) is to be coal-fired. This 
 equals a total capacity growth of about 
 0.8% per year and a growth rate of 
 0.15% per year in coal-fired capacity in 
 the six most important coal markets for Illinois. The new coal-fired capacity in the six states would 
 require two to three million tons of coal annually. Whether this would enhance demand for Illinois 
 coal will depend upon price and supply factors. The 1995 average delivered prices of coal in the 
 six states are compared in table 5. 
 
 In Indiana and Missouri, low-sulfur coal from Wyoming is delivered at significantly lower prices 
 than Illinois coal. Wyoming coal prices are 25 to 48 cents per million Btu lower than Illinois coal. 
 In Tennessee, Georgia and Florida, coal from Illinois is closely matched in price with other coals 
 used there. However, increasing sales of Wyoming coal and decreasing sales of Illinois coal in 
 Georgia indicate that market competitiveness of Wyoming coal is expanding further into the 
 southeastern states. Only in Illinois does locally mined coal appear to cost less than coal from 
 Wyoming and Montana. Even here, however, long-term contracts signed by one utility many 
 years earlier are the reason for the higher average price of Wyoming coal. In 1 994, a utility that 
 paid up to $3 per million Btu for Wyoming coal on contract was able to purchase large quantities 
 of Wyoming coal on the spot market for $1 .30 per million Btu, which was slightly lower than the 
 price paid for Illinois coal. 
 
 While Illinois coal production has declined since 1990 at an average annual rate of 4.3%, sales to 
 electric utilities have declined by 5.4% annually. RDI's projection for sales of Illinois coal to utili- 
 ties of 29 million tons in the year 2000 reflects an acceleration of this decline through the rest of 
 this century. 
 
 Because the quantity of emission reduction to be achieved in Phase II is similar to that in Phase I, 
 it would not be surprising if Illinois coal sales continue to decline 4.3% annually, the rate at which 
 
 
 ** 
 
 
 
 •s 
 
 $> 
 
 & 
 
 V 
 
 11 
 
Table 5 Utility coal sales and prices 1995. 
 
 Source state 1 000 tons 
 
 Cents/ 
 million Btu 
 
 Consumec 
 
 I in ILLINOIS 
 
 
 Illinois 
 
 1 1 ,879 
 
 135 
 
 Wyoming 
 
 14,081 
 
 183 
 
 Montana 
 
 2,685 
 
 250 
 
 Colorado 
 
 1,526 
 
 136 
 
 Consumec 
 
 I in INDIANA 
 
 
 Indiana 
 
 16,297 
 
 119 
 
 Wyoming 
 
 18,060 
 
 115 
 
 Illinois 10,661 
 
 Consumed in MISSOURI 
 
 140 
 
 they have declined since 1990. This would put Illinois 
 coal production at about 40 million tons in 2000, of 
 which sales to utilities would total about 30 to 32 mil- 
 lion tons. 
 
 The decline in utility sales of Illinois coal in 1995 over 
 1994 was only about 2 million tons, compared to a 12 
 million ton drop from 1992 to 1994. This reflects the 
 fact that most coal switching for compliance reasons 
 was completed in 1 994 to meet the January 1 , 1 995, 
 deadline for Phase I of the CAA amendment. The 
 compliance deadline for Phase II is January 1, 2000. 
 About two thirds of all Phase II affected utilities will 
 likely switch to low-sulfur coal for compliance. As a 
 result of this strategy, the next major decline in Illinois 
 coal sales can be expected before January 2000. 
 
 The conditions for Illinois coal in the first decade of the 
 next century remain unchanged: slow growth in elec- 
 tricity demand, an even slower growth in coal-based 
 electricity generation, and a higher price in comparison 
 with the low-sulfur western coal. Illinois mines that can 
 compete with the price of western coal have the best 
 prospects for continued production into the next dec- 
 ade. Under favorable cost conditions, the coal produc- 
 tion in Illinois could continue at the 40 million ton level 
 through the year 2010. If, however, mining costs in 
 Illinois continue to be uncompetitive, coal production 
 could continue to fall at the rate observed since 1990 
 and reach a low of 26 million tons in 2010. Coal pro- 
 duction in the first eight months of 1997 is running at 
 an annual rate of about 42 billion tons, which indicates 
 that production in the year 2010 may be lower than 
 predicted. Other factors such as the price and avail- 
 ability of natural gas and whether substantial nuclear 
 capacity will be retired will also have an influence on 
 Illinois coal production in 2010. 
 
 WHAT CAN BE DONE? 
 
 The root causes of the recent decline in Illinois coal 
 production have been economic, albeit triggered by 
 the CAA amendments in 1990. A new dimension has 
 been added to the market dynamics in the form of the 
 prospects of deregulation in the electricity market. The 
 capital-intensive coal mining industry, with a direct 
 influence of geologic factors, requires time to respond 
 to market changes that are taking place at a fast rate. 
 It is, therefore, imperative that impending market 
 changes are studied and anticipated at least a decade 
 or more ahead of time and appropriate changes made 
 in research, economic and environmental policies. The Illinois State Geological Survey has been 
 involved in some of the anticipatory research to assist the coal industry in Illinois. 
 
 • Geologic research at the ISGS has identified geologic settings under which lower-sulfur coal 
 deposits occur. Application of these geologic models by geologists at the ISGS and in industry 
 has permitted the delineation of lower-sulfur coal deposits over the past 20 years and permitted 
 a significant shift of production toward these lower-sulfur reserves. 
 
 • The ISGS analysis of coal markets identified coal mining costs as the cornerstone of competi- 
 tiveness and provided mining cost estimates for Illinois coal mines. Research and development 
 
 Illinois 
 
 4,168 
 
 135 
 
 Wyoming 
 
 25,566 
 
 88 
 
 Consumec 
 
 I in FLORIDA 
 
 
 Kentucky 
 
 12,508 
 
 176 
 
 Illinois 
 
 5,961 
 
 179 
 
 West Virginia 
 
 1,518 
 
 175 
 
 Imported 
 
 2,581 
 
 180 
 
 Colorado 
 
 811 
 
 184 
 
 Consumec 
 
 I in TENNESSEE 
 
 Kentucky 
 
 16,179 
 
 116 
 
 Illinois 
 
 3,949 
 
 110 
 
 Utah 
 
 1,134 
 
 118 
 
 Tennessee 
 
 1,078 
 
 122 
 
 Consumed 
 
 in GEORGIA 
 
 
 Kentucky 
 
 15,202 
 
 165 
 
 Wyoming 
 
 6,762 
 
 152 
 
 West Virginia 
 
 3,772 
 
 197 
 
 Illinois 
 
 604 
 
 154 
 
 Virginia 
 
 1,987 
 
 164 
 
 Source: U.S. DOE, July 1996 
 
 12 
 
policies based on the recognition that cost-competitiveness determines the future of the coal 
 industry have a better chance of success than those that don't. 
 
 • Mine subsidence research at the ISGS and other institutions in Illinois has provided knowledge 
 vital for the successful application of high-extraction mining techniques, such as the longwall 
 technique, essential for efficient, low-cost mining of coal. 
 
 • Engineering research at the ISGS has contributed to the knowledge of coal and flue gas clean- 
 ing, the use of Illinois coal in clean coal technologies, such as the Integrated Gasification Com- 
 bined Cycle (IGCC) technology, and to the development of new uses of coal, such as in the 
 production of activated carbon. 
 
 Coal mines that have survived the competition are primarily high-productivity, low-cost mines. 
 Future market changes are expected to be even more profound than in the recent past, requiring 
 stronger efforts to enhance the economic competitiveness of Illinois coal mines. Research and 
 development to lower the cost of mining, cleaning and transporting coal must be intensified. The 
 goal must be to produce electricity from Illinois coal at a lower cost than from other fuels. 
 
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 13 
 
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 14