333,822 EL59X ilenh'HI i ,T89,v THE DEMAND FOR ENERGY IN THE ILLINOIS COAL MARKET Illinois Department of Energy and Natural Resources James R. Thompson, Governor State of Illinois Karen A.Witter, Director Illinois Department of Energy and Natural Resources UNIVERSITY OF ILLINOIS ^y AT URL CHAMPAIGN 3KSTACKS CENTRAL CIRCULATION BOOKSTACKS The person charging this material is re- sponsible for its renewal or its return to the library from which it was borrowed on or before the Latest Date stamped below. You may be charged a minimum fee of $75.00 for each lost book. Theft, mutilation, and underlining of books are reasons for disciplinary action and may result in dismissal from the University. TO RENEW CALL TELEPHONE CENTER, 333-8400 UNIVERSITY OF ILLINOIS LIBRARY AT URBANA-CHAMPAIGN OCT 28 1996 OCT 2 8 1996 When renewing by phone, write new due date below previous due date. L162 Digitized by the Internet Archive in 2013 http://archive.org/details/demandforenergyiOOelli Printed: May 198S THE DEMAND FOR ENERGY IN THE ILLINOIS COAL MARKET Prepared by: M. Fred Ellis Pawnee, Illinois DEPOSITORY for: Illinois Department of Energy and Natural Resources 325 West Adams Street Springfield, Illinois 62704-1892 AUG 2 8 1989 UNIVERSITY OF ILLINOIS AT URBANA-CHAMPAIGN James R. Thompson, Governor State of Illinois Karen Witter, Director Illinois Department of Energy and Natural Resources Springfield, Illinois NOTE This report has been reviewed by the Illinois Department of Energy and and Natural Resources (ENR) and approved for publication. Statements made by the author may or may not represent the views of the Department. Additional copies of this report are available through ENR Clearinghouse at 800/252-8955 (within Illinois) or 217/785-2800 (outside Illinois). Printed by the Authority of the State of Illinois. Date Printed: May 1989 Quantity Printed: 200 Referenced Printing Order: Illinois Department of Energy and Natural Resources Office of Research and Planning Office of Coal Development and Marketing 325 W. Adams, Room 300 Springfield, Illinois 62704-1892 217/785-2800 TABLE OF CONTENTS Page INTRODUCTION 1 CHAPTER ONE: PRODUCTION AND CONSUMPTION OF ILLINOIS COAL 5 CHAPTER TWO: ALABAMA 15 Tennessee Valley Authority- Alabama 21 CHAPTER THREE: FLORIDA 27 Gulf Power Company 33 Seminole Electric Cooperative Incorporated 39 Tampa Electric Company 43 CHAPTER FOUR: GEORGIA 49 Georgia Power Company . . 55 CHAPTER FIVE: ILLINOIS 67 Central Illinois Light Company 73 Central Illinois Public Service Company 79 Commonwealth Edison Company 87 Electric Energy Incorporated 97 Illinois Power Company 101 Southern Illinois Power Cooperative 109 Springfield City Water, Light and Power Department 113 CHAPTER SIX: INDIANA 117 Hoosier Energy Rural Electric Cooperative 123 Northern Indiana Public Service Company 127 Public Service Company of Indiana 133 CHAPTER SEVEN: IOWA 141 Eastern Iowa Light and Power Cooperative 145 Interstate Power Company 149 Iowa Electric Light and Power Company 155 Iowa-Illinois Gas and Electric Company 161 Iowa Southern Utilities Company 167 Muscatine Power and Water Department 173 CHAPTER EIGHT: KANSAS 177 Kansas City Board of Public Utilities 181 CHAPTER NINE: KENTUCKY 185 Tennessee Valley Authority-Kentucky 189 CHAPTER TEN: MINNESOTA 193 Rochester Department of Public Utilities 199 CHAPTER ELEVEN: MISSISSIPPI 203 Mississippi Power Company 207 CHAPTER TWELVE: MISSOURI 213 Associated Electric Cooperative Incorporated 219 Central Electric Power Cooperative 223 Kansas City Power and Light Company 227 Sikeston Board of Municipal Utilities 233 Union Electric Company 237 Utilicorp United Incorporated 243 CHAPTER THIRTEEN: TENNESSEE 247 Tennessee Valley Authority-Tennessee 251 CHAPTER FOURTEEN: WISCONSIN 261 Dairyland Power Cooperative 265 Madison Gas and Electric Company 271 Wisconsin Electric Power Company 275 CHAPTER FIFTEEN: SUMMARY 281 BIBLIOGRAPHY 309 INTRODUCTION Illinois is the fifth largest coal producing state in the nation, with about 62 million tons, representing seven percent of the nation's total. Kentucky is the largest state producer, followed by Wyoming, West Virginia and Pennsylvania. Illinois' coal production is dominated by a few large coal operators who account for most of the output. Peabody Coal Company continues to be the largest Illinois and U.S. coal producer. Of the remaining top ten Illinois coal producers, many are also large national coal producers. Illinois coal mines are large in size and realize economies of scale. This implies that as Illinois coal mines increase their production, their average cost of production decreases. On average, Illinois' 20 largest underground mines produce over 1.7 million tons per year and the seven largest surface mines average 2.4 million tons per year. As for sales, many of these mines have less than three buyers for their coal, while some mines are dedicated to only one buyer. In the event that coal contracts are not renewed or cancelled, many coal producers may have to "close their mines. Most acid rain studies do not take into account the loss of a major coal buyer and its impact on the economies of scale realized at these large mine sites. In many cases, a fifty percent reduction in sales could mean the closing of a mine because of the increased production costs and the inability to recover this cost in its coal price. Historically, utilities have utilized high sulfur coal because of its heating value, delivered price and localized availability. In return for a guaranteed quantity and quality of coal from coal producers, utilities were willing to sign long-term contracts. Generally, this time period was for the useful life of the coal -fired generating station since a boiler was designed to burn a certain quality of coal and any variation in coal quality could reduce its economic and operational performance. Since the early 1970's, utilities have been required to meet more strict air quality standards. These standards forced utilities to either install expensive environmental control technologies to remove a portion of the pollutant, or burn a coal that had a lower sulfur content. The availability of these "compliance" coals is primarily limited to the central Appalachian area; Wyoming; Montana; Colorado; and Utah. Most utilities chose to use a compliance coal to meet these stricter environmental standards. However, with the U.S. Environmental Protection Agency's Revised New Source Performance Standard of 1979, utilities have to install control technologies no matter the sulfur content of the coal. Today, the market for Illinois coal is comprised of a 13 state region shown in Map 1-1. However, the top eight states purchase 99 percent of the total. These states include Illinois, Missouri, Indiana, Georgia, Florida, Tennessee, Iowa and Wisconsin. The states of Mississippi, Kansas, Alabama, Minnesota and Kentucky purchase the remainder. Over the last three years, utiltiy sales have remained about the same at 56 million tons per year. Of the 33 electric utilities that use Illinois coal, the top ten consume approximately 80 percent of the total. Seven of these utilities are located outside of Illinois. The largest users of Illinois coal are Union Electric Company with 17 percent of total receipts; followed by Illinois Power Company with 12 percent; Public Service Company of Indiana at 11 percent; Georgia Power Company with ten percent; and Central Illinois Public Service Company at seven percent. Clearly, two of the major marketing problems facing Illinois coal producers that must be addressed in the future are the sulfur content and the mine price of coal. Both problems have crippled the marketability of Illinois coal in many parts of the United States. Fortunately, even with the uncertainty surrounding federal acid rain legislation and with many states tightening their air pollution standards, Illinois utility sales have held their own. However, these problems, unless alleviated, will jeopardize future sales. To overcome the sulfur problem, greater research and development of technologies that burn coal economically and in an environmentally safe manner have been undertaken. Improvements in mechanical coal cleaning techniques and chemical coal cleaning offer alternatives for pre-combustion technologies. A wider selection of combustion and post combustion technologies such as atmospheric and pressurized fluidized bed combustion; limestone furnace sorbent injection; coal gasification-combined cycle; clean fuel reburning; low NOx burners; and selective catalytic reduction offer other alternatives. Finally, improvements in flue gas desulfurization systems will provide the utility industry with alternatives in meeting the U.S. Environmental Protection Agency's Revised New Source Performance Standard and mandated air emission reductions at the state level. The second problem, the mine price of coal, has also been confronted. Since the utility industry is concerned with the delivered price of coal, any price reduction at the mine site should affect the delivered price. Today, the coal industry is very competitive, primarily because of the over-supply of coal and weak demand for coal. Illinois coal producers find more and more coals competing in what has been considered the Illinois coal market. Many of the coal producers are selling a low sulfur coal at a very competitive price. To compete, Illinois coal producers have reduced the mine price through increased mine efficiency. This increase is the result of reduced employment and more efficient use of capital equipment. Other problems impacting coal sales are the weak demand for electricity in the Illinois coal market. Many utilities are seeing minimal growth in their service territory, which translates into less demand for coal by present and future coal -fired capability. Also, the increase in nuclear generation has impacted the use of present coal -fired generation. As more and more nuclear stations come on line, there will be continued reductions in the demand for Illinois coal. As an example, Commonwealth Edison Company has reduced its Illinois coal consumption at its only station that uses Illinois coal by 43 percent. THE DEMAND FOR ENERGY IN THE ILLINOIS COAL MARKET is a study of the electric utility market for coal mined in Illinois for 1986. This analysis is a companion guide to the 1984 study of Illinois coal producers, titled, "An Historical Perspective on Illinois Coal Resources and Production, 1960-1984." This report analyzes the 33 electric utilities with generating stations greater than 50 megawatts in capacity, that purchased Illinois coal in 1986. Only electric utilities are analyzed since they consume nearly 90 percent of Illinois' annual coal production, or about 57 million tons. The remainder of sales are primarily to the industrial sector. The report contains information on each of the 13 states where these utilities are located and provides Illinois coal sales data since 1981. It lists the competing fuels that are used in these states. Data on nuclear fuel purchases and consumption are not available, but the study does include information on nuclear capability, both present and future. Utility data covering a general description of the company, generating statistics and coal data are also included. The study does analyze the future of the Illinois coal market and provides the reader with a database on current and future baseload generating capability. What the study shows is the current coal market and how the market will continue to shrink as the present coal -fired capability is retired. As the future demand for Illinois coal decreases, new coal -fired capability will not displace current capability because of the minimal increase in electrical demand and the displacement of some capability with nuclear power. The study is divided into an introduction and 15 chapters. Chapter One discusses the Illinois coal industry and contains general information on the supply and demand for Illinois coal. The chapter includes a discussion of Illinois coal production for 1986, mine value and employment. Chapter One includes data on the ten largest Illinois coal producers and their percent of production. The Illinois coal market is discussed and a map of the market is presented. Coal consuming states and utilities, quantity and quality of Illinois coal and delivered prices are also shown. The chapter concludes with a discussion of the quantity of Illinois coal burned, by boiler type and age of facility. Chapters Two through Fourteen detail the thirteen states with generating stations that use coal mined in Illinois. Each chapter discusses the demand for coal, petroleum and natural gas, including quantity, BTU value and delivered price. Each chapter includes data on generating capability, by fuel type; future baseload capability (including in-service date); net generation by fuel type; coal suppliers, and quantity and quality and price of coal; and Illinois coal receipts since 1981. Included with each state narrative is a map showing the locations of the coal -fired stations. Following the state perspective is an analysis of the electric utilities in that state using Illinois coal. This section discusses the utility's service territory; electric sales; coal -fired capability; net generation; coal receipts, by quantity and quality and delivered price since 1983; coal -fired generation statistics; major coal suppliers to include contract expiration dates, if available; and mode of transportation. A table at the end of each section supplements the information provided in the narrative. Chapter Fifteen contains the major findings of the report. Included in this chapter is an overall analysis, including graphs of the more important considerations of the study. Chapter Fifteen summarizes the current market for Illinois coal and discusses the potential for future market demand and risks to the Illinois coal market. CHAPTER ONE PRODUCTION AND CONSUMPTION OF ILLINOIS COAL ILLINOIS COAL PRODUCTION Illinois coal producers mined approximately 63 million tons of coal in 1986, an increase of about three million tons over 1985. The majority of the coal had a sulfur content greater than 2.5 percent, while only six percent of the coal was classified as a low sulfur coal. The coal production had a mine value of approximately $1.9 billion. Mine employment was about 13,500. Compared to the previous year, the mine value of the coal was nearly the same, while mine employment decreased by almost 1,300. The primary reasons why the revenue stayed the same were reduced prices brought on by a surplus of coal, renegotiated coal contracts and an increase in spot market coal purchases. The reduced mine employment resulted from a more competitive coal market and improvements in production efficiency. From 1985, the average production per mine employee per man-day increased by about ten percent. Nearly 65 percent of the production was taken from 31 underground mines and the remainder from 20 surface mines. The largest underground mine was Monterey Coal Company's Mine No. 2 with 3.3 million tons. The largest surface mine was Arch of Illinois' Captain Mine with 6.3 million tons. Overall, underground mines had an average production of 1.3 million tons and the surface mines averaged 1.1 million tons. The 51 mines were operated by 22 coal companies, of which the top ten producers mined 58 million tons, or 92 percent of the total. Peabody Coal Company continues to be the largest Illinois coal producer with 16 percent of production. Due to recent expansion in operations, Consolidation Coal Company and Arch Mineral Corporation are a close second and third with about 16 percent and 14 percent, respectively. Consolidation purchased Inland Steel Coal Company's two operating mines in southern Illinois, while Arch Mineral purchased Amax Coal Company's Leahy Mine in southern Illinois and opened the Horse Creek Mine near Pinckneyville. Table 1-1 lists the top ten Illinois coal producers, their coal production and percent of total Illinois coal production. This list has remained about the same in recent years. New additions to the list are Kerr-McGee Coal Corporation and White County Coal Corporation. TABLE 1-1. ILLINOIS COAL PRODUCERS, COAL PRODUCTION AND PERCENT OF ILLINOIS COAL PRODUCTION. TONS % OF COMPANY (000} TOTAL PEABODY COAL 10,175 16.1 CONSOLIDATION COAL 9,986 15.8 ARCH MINERAL 8,639 13.6 OLD BEN COAL 8,033 12.7 MONTEREY COAL 5,321 8.4 FREEMAN UNITED COAL 5,124 8.1 AMAX COAL 4,473 7.1 ZEIGLER COAL 2,992 4.7 KERR-MCGEE COAL 1,980 3.2 WHITE COUNTY COAL 1,463 2.4 ALL OTHERS 5.047 7.9 TOTAL 63.233 100.0 ILLINOIS COAL MARKET The Illinois utility coal market is comprised of 13 states, located in the midwestern and southeastern United States. Outside of Illinois, Missouri utilities continue to be the largest consumers of Illinois coal with 23 percent of the total, followed by Indiana and Georgia. Utilities from the top five states purchased about 50 million tons, or 87 percent of utility sales. In recent years, approximately 90 percent of sales have been to the electric utility industry. Map 1-1 shows the Illinois utility coal market by state and quantity purchased in millions of tons. Table 1-2 lists the 13 states where Illinois coal is consumed. The table contains information for electric utility sales only. Shown in the table are: the tons of coal purchased by electric utilities in each state; the percent of total electric sales; the average BTU content per pound of coal; percent sulfur, by weight; delivered price per ton; and cost in dollars per million BTU. Examination of the BTU content and sulfur content reveals that the better quality Illinois coal is exported. On a cost per million BTU basis, the delivered price of Illinois coal was the lowest to Tennessee at $1.23 per million BTU, while the most expensive was to Florida at $2.12 per million BTU. The average cost per million BTU dropped by three cents from $1.66 in 1985 to $1.63 in 1986. Utility coal sales also increased by five percent from the previous year. MAP 1-1 ILLINOIS UTILITY COAL MARKET TABLE 1-2. ILLINOIS COAL SALES BY STATE AND QUANTITY AND QUALITY OF COAL. TONS % OF % STATE (OOO) TOTAL BTU/LB SULFUR */TON S/MMBTU ILLINOIS 17,063 30 10,879 2.89 34.18 1.57 MISSOURI 12,854 23 11,139 2.37 35.46 1.59 INDIANA 10,214 18 10,751 2.68 35.89 1.67 GEORGIA 5,609 10 11,424 2.47 35.89 1.65 FLORIDA 3,935 7 11,616 2.76 49.33 2.12 TENNESSEE 2,915 5 11,749 1.89 28.77 1.23 IOWA 1,971 3 11,257 2.72 35.21 1.56 WISCONSIN 1,491 3 11,587 1.82 40.68 1.76 MISSISSIPPI 336 — 12.199 2.50 42.64 1.75 KANSAS 284 -- 11,471 2.48 37.84 1.65 ALABAMA 149 -- 12,062 .95 32.80 1.36 MINNESOTA 113 — 12,250 1.62 51.64 2.11 KENTUCKY 65 -- 11.949 .90 34.70 1.45 TOTAL/AVERAGE 56.999 100 11.113 2.59 36.19 1.63 The electric utility sales shown in Table 1-2 represent approximately 90 percent of Illinois' coal production. The balance of sales, about six million tons, were to the industrial coal market. The industrial customers are primarily located in Illinois, Indiana and Missouri. Illinois coal is sold to 62 generating stations operated by 33 utilities. Coal sales to three utilities—Indiana and Michigan Electric Company, Kentucky Utilities Company and Wisconsin Power and Light Company were discontinued after 1985, while new sales were added at two utilities—Kansas City Power and Light Company and Madison Gas and Electric Company. Overall, there was a net increase in sales of two million tons. In-state sales totalled 17 million tons or 30 percent of utility sales, while out-of-state sales were 40 million tons. In-state coal sales are to 16 generating stations with about ten thousand megawatts of capability.* These stations are owned by seven companies. * In this report, an electric utility generating station's ability to produce electricity is shown as "megawatts of summer capability" rather than "nameplate capacity." Capability as defined by the U.S. Department of Energy is "the maximum load that a generating unit, generating station, or other electrical apparatus can carry under specified conditions for a given period of time without exceeding approved limits of temperature and stress." A major factor in determining capability is the ambient air temperature. Nameplate rating, on the other hand, is the full load continuous rating as determined by the manufacturer. 8 Out-of-state sales are to 46 generating stations, with a total capability of approximately 37 thousand megawatts. These stations are operated by 26 utilities. The 47 thousand megawatts of electric capability where Illinois coal is utilized represents 16 percent of the nation's coal -fired capability. Table 1-3 lists the top ten utilities that burn Illinois coal; the number of generating stations that consume Illinois coal; quantity purchased; and the percent of Illinois coal sales to utilities. For example, Union Electric Company received 9.6 million tons, representing 17 percent of Illinois' utility coal sales. In total, these ten utilities purchased more than 44 million tons, or nearly 80 percent of total utility sales. The seven out-of-state utilities listed in Table 1-3 purchased 55 percent of the total, and are identified by an asterisk. TABLE 1-3. 1986 ILLINOIS COAL PURCHASES BY UTILITY, QUANTITY AND PERCENT OF TOTAL UTILITY PURCHASES. NO. OF TONS % OF UTILITY PLANTS fOOO) TOTAL * UNION ELECTRIC 4 9,616 17 ILLINOIS POWER 4 6,847 12 * PUBLIC SERVICE OF IND. 2 6,444 11 * GEORGIA POWER 3 5,609 10 CENTRAL IL. PUBLIC SERV 4 3,778 7 * TENNESSEE VALLEY AUTH. 6 3,128 5 * N. INDIANA PUBLIC SERV. 3 2,768 5 COMMONWEALTH EDISON 1 2,732 5 * ASSOCIATED ELEC. COOP 1 2,101 4 * SEMINOLE ELECTRIC COOP 1 1.435 3 TOTAL 29 44.458 79 * Out-of-state utilities. Table 1-4 lists the Illinois coal sales for the period 1981 through 1986. The table shows the quantity and quality of the coal; delivered price in dollars per ton and dollars per million BTU; and the percent of Illinois coal production. The demand remained fairly stable except for 1981 when there was a major strike between the United Mine Workers of America and the Bituminous Coal Operators Association. The table points out a modest decrease in sulfur content and a minimal increase in BTU content over the years. The delivered prices, except for 1981, have remained nearly constant at $1.60 per million BTU. TABLE 1-4. ILLINOIS COAL SALES TO ELECTRIC UTILITIES, BY QUANTITY AND QUALITY, DELIVERED PRICE AND PERCENT OF PRODUCTION, 1981- •1986. YEAR 1981 1982 1983 1984 1985 1986 THOUSAND TONS 43,877 51,619 50,557 57,601 54,196 56,999 PERCENT SULFUR 2.70 2.70 2.70 2.70 2.60 2.59 BTU/LB 10,958 10,959 11,000 11,027 11,075 11,113 $/TON 31.98 34.35 35.30 36.05 36.80 36.19 $/MMBTU 1.46 1.57 1.60 1.63 1.66 1.63 % OF PRODUCTION 85 84 87 88 90 90 CYCLONE BOILERS The type of boiler using Illinois coal is very important in this study. The two types shown seperately in Table 1-5 and Table 1-6 are the cyclone boiler and the pulverized coal boiler. Cyclone boilers use coal with a mesh size of between 1/4 inch and 0, while pulverized coal boilers utilize coal that is of the consistency of talcum powder. The cyclone boiler was designed to utilize low ash fusion coal which is characteristic of Illinois Basin coals. The coal is burned in a cylindrical, refractory lined chamber at a very high temperature. Because of the high temperature, the ash melts and is drained as a liquid and quenched. However, the high temperature produces a nitrogen oxide (NOx) emission rate of 1.4 to 1.8 pounds per million BTU of input, which is considerably higher than pulverized coal boilers. Since 1950, approximately 150 cyclone boilers have been built, with minimal construction after 1975. In the event that acid rain legislation becomes law, cyclone boilers will have difficulty meeting stricter standards for NOx emissions. This is important to Illinois coal producers, since about 44 percent of in-state capability consists of cyclone boilers and 30 percent of the capability in the Illinois export market is cyclone boilers. NOx control technologies for cyclone boilers are limited and much more expensive than control technologies for pulverized coal boilers. Table 1-5 provides the megawatts of capability and quantity of Illinois coal purchased for cyclone boilers. The table shows the megawatts of capability and boiler age as of 1995, with and without flue gas desulfurization (FGD), and the associated quantity of Illinois coal. In 1995, it is projected there will be 8,031 megawatts of capability without FGD that will be over 21 years old. This capability consumes about 14 million tons of Illinois coal annually. The table shows the minimal amount of cyclone capability with FGD. Most cyclone units were not required to meet any sulfur dioxide (S02) emission standards when constructed. However, as S02 standards become more strict, utilities with cyclone boilers will have to decide whether to use a low sulfur compliance coal or install FGD and burn high sulfur coal. As a general rule, utilities in the past have used a compliance coal rather than install FGD. 10 TABLE 1-5. CYCLONE BOILER CAPABILITY IN MEGAWATTS AND AGE, AND ILLINOIS COAL SALES. AGE OF PLANT AS OF 1995 (IN YEARS) 10-15 16-20 21-25 26-30 OVER 30 MW W/OUT FGD: - 1,011 2,859 3,297 1,875 ILLINOIS COAL SALES (000 TONS): - 1,403 6,124 6,605 1,387 MW WITH FGD: - 170 ILLINOIS COAL SALES (OOP TONS): zz 461 PULVERIZED COAL BOILERS Pulverized coal -fired boilers, such as the tangentially-fired boiler, consists of a vertical, rectangular box mounted in each corner of the furnace. These chambers are segmented where the coal and air are mixed in alternate corners to create a swirling motion. This configuration causes more residence time and turbulence for a more thorough burn of the coal. Because of the larger combustion area, temperatures are kept lower and thereby inhibit the production of NOx emissions to approximately 0.7 to 0.9 pound per million BTU of input. Other pulverized coal units (wall-fired) use a number of coal burners in the furnace wall. There are usually four burners in a row, with two, four or six rows. As the units become larger, additional burners can be mounted in the opposite wall (opposed wall -fired). Front wall -fired or opposed-wall fired boilers also emit about 0.7 to 0.9 pound of NOx per million BTU of input. Table 1-6 contains information for pulverized coal boilers. For example, 14,700 megawatts of capability without FGD will be over 25 years old in 1995. This capability consumes about 12.5 million tons of Illinois coal annually. As with cyclone boilers, the more strict air quality standards have resulted in the switch to a compliance coal rather than installation of FGD at the older stations. 11 TABLE 1-6. PULVERIZED COAL BOILER CAPABILITY IN MEGAWATTS AND AGE, AND ILLINOIS COAL SALES. AGE OF PLANT AS OF 1995 (IN YEARS) 10-15 16-20 21-25 26-30 OVER 30 MW W/OUT FGD: ~ 8,652 8,039 1,822 12,821 ILLINOIS COAL SALES (000 TONS): - 13,050 8,147 1,452 11,021 MW WITH FGD: 4,285 1,106 -- - 1,000 ILLINOIS COAL SALES (OOP TONS): 5.137 2.139 zz 83 AGE OF CAPABILITY Both of the previous tables show the huge amount of capability that will be over 20 >ears old by 1995. Many acid rain proposals call for a control program by the mid-to late-1990's. Should this be implemented, many plants because of their age, along with the cost of an FGD system may not be retrofitted with FGD and continue to burn high sulfur coal, but will switch to a low sulfur compliance coal. As stated earlier, Illinois coal is supplied to 62 stations, totalling about 47 thousand megawatts of capability. As of 1995, the capability without FGD totals 40.4 thousand megawatts. Broken down by age, 24 percent of this capability will be 16 to 20 years old; 27 percent will be 21 to 25 years old; 13 percent will be 26 to 30 years old; and 36 percent will be over 30 years old. These 40 thousand megawatts of capability consume approximately 86 percent of Illinois coal sales, annually. This data points out that any change in S02 and NOx emission standards could have a dramatic impact on the future of the Illinois coal market. 12 CHAPTER OUTLINE The following chapters discuss the states where Illinois coal is used. Included in each chapter is a discussion of the fossil -fuel demand; the various types of generation capability; plans for future baseload generating capability; and the quantity and quality of coal used. Following the state perspective is a discussion of the utilities where Illinois coal is burned. The utility section covers the business activity of each utility; coal -fired generation capability and net generation; coal demand; Illinois coal receipts since 1981; and a discussion of the coal-fired generating stations. At the end of each narrative is a table which provides additional data on the generating stations and systemwide operations. 13 CHAPTER TWO ALABAMA Alabama electric utilities purchased approximately 22 million tons of coal; 219 thousand barrels of petroleum; and 0.7 billion cubic feet of natural gas in 1986. For these categories, coal represented three percent of U.S. utility fossil -fuel receipts, while petroleum and natural gas purchases were only negligible. (No national data is available on uranium receipts for nuclear generation.) Alabama utilities purchased about three percent of the nation's total fuel for electric generation. Table 2-1 lists the quantity of each fossil -fuel; the BTU content and percent of total; and the cost per unit; and cost per million BTU. Almost all of the BTU inputs for electrical generation were derived from coal. TABLE 2-1. ALABAMA FOSSIL-FUEL SOURCES FOR ELECTRIC GENERATION. FUEL QUANTITY (0001 BTU (BILLION) % OF TOTAL $/UNIT $/MMBTU COAL PETROLEUM NATURAL GAS 22.181 tons 219 bis. 687 mmcf. 534.784 1.275 755 99.7 .2 .1 46. 20, 2, ,51 .27 .69 1.91 3.49 2.47 TOTAL 536.814 100.0 Alabama has one investor-owned utility; 36 municipal systems; 23 rural electric cooperatives; one wholesale system; and one federal system. The major suppliers of electricity are Alabama Power Company and the Tennessee Valley Authority. Alabama electric utilities have 18,818 megawatts of capability. This capability consists of 10,519 megawatts from coal, 4,856 megawatts from nuclear power and 2,940 megawatts from hydro power, with the remainder from natural gas and petroleum. Coal and nuclear represent 82 percent of Alabama's total capability. Alabama's total capability represents three percent of the U.S. total. Of the 44 states that have coal -fired generating capability, Alabama ranks twelfth. Table 2-2 shows the generating capability by fuel type; number of units; percent of Alabama's total capability; and percent of U.S. total 15 capability. The U.S. total is shown as the percent of Alabama's fuel type to the U.S. total for the same fuel type. For example, the 15,375 megawatts of coal and nuclear capability represent ten percent of the U.S total for these two categories. TABLE 2-2. ALABAMA SUMMER CAPABILITY. TOTAL COAL NUCLEAR TYPE OF CAPABILITY NATURAL PETROLEUM GAS WATER MEGAWATTS 18,818 10,519 4,856 NO. OF UNITS 147 41 5 % OF AL TOTAL 100 56 26 % OF U.S. TOTAL 3 4 6 101 4 400 8 2 2,940 89 16 3 Alabama utilities expect to add two coal units and two nuclear units in the future. The Tennessee Valley Authority will be adding the nuclear units and Alabama Power Company will be adding the coal -fired units. The coal-fired units will require about 3.3 million tons of coal annually. Table 2-3 contains information on these future additions.* TABLE 2-3. FUTURE BASELOAD CAPABILITY IN ALABAMA. UTILITY ALABAMA POWER TYA TOTAL STATION AND UNIT CAPABILITY UfiO FUEL ON LINE Miller 3 653 Coal 1989 Miller 4 653 Coal 1991 Bellefonte 1 1,223 Uranium 1994 Bellefonte 2 1.223 Uranium 1996 3.752 * Additions to future generating capacity are as of December 31, 1986. It is important to note that "on-line" dates are the most recent dates reported to the U.S. Department of Energy and are estimated. They can vary from one reporting period to the next. One thousand megawatts of nuclear capability displaces the use of about three million tons of coal annually. 16 Net generation by Alabama electric utilities totals nearly 69 thousand gigawatthours. (A gigawatthour is equal to one billion kilowatthours. ) For Alabama, coal supplies 75 percent of net generation, nuclear 17 percent and water eight percent. Nationally, Alabama accounts for three percent of net generation and ranks 14th among the states in total generation. Table 2-4 provides additional data for each category of generation. TABLE 2-4. ALABAMA NET GENERATION. TYPE OF CAPABILITY TOTAL COAL NUCLEAR PETROLEUM NATURAL GAS WATER GIGAWATTHOURS % OF AL TOTAL % OF U.S. TOTAL 68,575 100 3 51,693 75 4 11,561 17 3 34 59 5,527 8 2 In 1986, Alabama utilities purchased approximately 22 million tons of coal. Coal receipts were from eight coal producing states, with Illinois supplying less than one percent of the total. The sulfur content ranges from 0.9 percent to 3.9 percent with an overall average of 1.5 percent. The low sulfur coal is provided by coal producers from southern Tennessee, Illinois and West Virginia. The BTU content varies from 11,583 to 12,500 per pound of coal, with a weighted average of 12,175. On a BTU basis, Indiana coal has the lowest delivered price,** while Alabama coal is the most expensive. The Illinois coal averages $1.36 per million BTU. Table 2-5 lists the states or regions supplying coal to Alabama and their respective quantity and quality. ** Delivered price is a function of the mine price, transportation cost and related expenses of transporting the coal from the mine site to the generating station. As a general rule, the greater the distance, the greater the transportation expense and delivered price. Other factors affecting the delivered price are the type of mine (surface or underground), quality of the coal, quantity of coal and spot or contract price, to name a few. 17 TABLE 2-5. ALABAMA COAL SUPPLIERS. TONS % OF % STATE/REGION (OOO) TOTAL BTU/LB SULFUR 1/TON J/MMBTU ALABAMA 15,192 69 12,305 1.29 50.65 2.06 OHIO 2,626 12 11,685 2.34 47.81 2.05 E. KENTUCKY 1,987 9 12,038 1.47 32.23 1.34 W. KENTUCKY 1,264 6 11,708 3.49 26.65 1.14 S. TENNESSEE 672 3 12,434 .85 35.27 1.42 N. TENNESSEE 157 1 12,193 1.55 36.47 1.50 ILLINOIS 149 1 12,062 .95 32.80 1.36 W. VIRGINIA 112 - 12,180 .89 33.94 1.39 VIRGINIA 21 - 12,500 1.09 35.58 1.42 INDIANA 3 • 11.583 3.89 25.03 1.08 TOTAL/AVERAGE 22.183 100 12.175 1.54 46.51 1.91 The Tennessee Valley Authority purchased the 149 thousand tons of Illinois coal for its Widows Creek and Colbert stations. This figure represents less than one percent of Alabama's coal purchases and is a reduction of about 0.3 million tons from the previous year. Illinois coal sales, quality of the coal and the delivered price to Alabama electric utilities for the period 1984 through 1986 are shown in Table 2-6. As can be seen in the table, the TVA is purchasing a quality coal at a moderate price. Alabama utilities did not purchase Illinois coal for the period 1981 through 1983. TABLE 2-6. ALABAMA'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICE 1984-1986. YEAR 1984 1985 1986 THOUSAND TONS 74 400 149 PERCENT SULFUR 1.60 .90 .95 BTU/LB 11,885 12,127 12,062 $/T0N 34.00 36.52 32.80 1/MMBTU 1.43 1.51 1.36 The following section discusses the Tennessee Valley Authority system and its coal -fired generating capability in Alabama. Map 2-1 shows the location of the Tennessee Valley Authority's coal -fired generating stations throughout the Tennessee Valley. 18 MAP 2-1 COAL F I RED GENERATING STATIONS Colbert • * Widows Creek TENESSEE VALLEY AUTHORITY • ILLINOIS COAL 19 TENNESSEE VALLEY AUTHORITY - ALABAMA The Tennessee Valley Authority (TVA) is a corporate agency of the United States Government established by Congress in 1933. Its primary function was to develop the Tennessee River Basin and other resources in the Tennessee Valley. It is the largest electric power system in the United States, extending into seven states. The seven states are Alabama, Georgia, Kentucky, Mississippi, North Carolina, Tennessee and Virginia. The TVA provides electrical service to 160 municipalities and cooperatives, 47 industries and ten federal agencies. The TVA employs approximately 33 thousand and is headquartered in Knoxville, Tennessee. TVA's electrical generation encompasses the states of Alabama, Kentucky and Tennessee. The TVA system is comprised of about 29 thousand megawatts of capability, representing four percent of the U.S. total. Coal accounts for about 16,000 megawatts; nuclear 5,500 megawatts; and 3,500 megawatts of hydro, with the remainder from natural gas and petroleum capability. For the coal-fired capability, 19 percent is located in Alabama, 23 percent is located in Kentucky and 58 percent in Tennessee. Currently, the nuclear units are out of service and will be back on-line in the next few years. The TVA has electrical connections with: Georgia Power Company; Alabama Power Company; Mississippi Power and Light Company; Arkansas Power and Light Company; Eastern Kentucky Power Cooperative; Kentucky Utilities Company; Appalachian Power Company; Carolina Power and Light Company; Louisville Gas and Electric Company; Big River Rural Electric Cooperative; Central Illinois Public Service Company; Illinois Power Company; and Union Electric Company. TVA's total generation is 91 billion kilowatthours, with coal producing 83 billion kilowatthours and hydro generation accounting for most of the remainder. The TVA is the largest consumer of coal in the United States, with receipts of 36.6 million tons for its eleven stations. The coal is valued at $1.2 billion. To keep its coal costs competitive, the TVA purchases the coal from a large number of coal producers. In Alabama, the TVA has two coal -fired stations with capability of 3,038 megawatts, representing ten percent of TVA's total capability and 19 percent of its coal -fired capability. These two stations represent 16 percent of Alabama's total capability and 29 percent of Alabama's coal capability. The stations use a small quantity of Illinois coal. Table 2-7 lists TVA's Illinois coal purchases and delivered prices at the two Alabama stations for the period 1984 through 1986. The table shows a reduced consumption of Illinois coal from 1985 due primarily to the availability of less expensive coal. 21 TABLE 2-7. TVA'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES IN ALABAMA 1984-1986. YEAR 1984 1985 1986 THOUSAND TONS 74 400 149 PERCENT SULFUR 1.60 .90 .95 BTU/LB 11,885 12,127 12,062 $/TON 34.00 36.52 32.80 1/MMBTU 1.43 1.51 1.36 TVA's Alabama coal-fired stations have net generation of 13.3 billion kilowatthours, representing 14 percent of the TVA's total generation and 19 percent of Alabama's net generation. The following paragraphs discuss the two stations. The Colbert Station is located in northwestern Alabama at Pride. The station has five older pulverized coal units with capability of 1,276 megawatts. This capability accounts for 42 percent of TVA's Alabama capability and eight percent of TVA's systemwide coal -fired capability. The station's 7.6 billion kilowatthours of net generation represents 68 percent of its capability. The average cost per net kilowatthour of generation is two cents, ranking tenth in efficiency.* Included in this average cost is the fuel expense which accounts for 88 percent of the total . The station purchased 3.5 million tons of coal and burned 3.3 million tons in 1986. The coal averages 2.3 percent sulfur and 11,632 BTU. The S02 emission rate, which is a function of sulfur and BTU content, is 3.8 pounds per million BTU of heat input. Based on 1983 nationwide data, Colbert ranks 33rd in total tons of S02 emissions. Unit 5 is rated as * Efficiency is measured by the total power production expense. Included in this cost are the operation expense, maintenance expense and fuel expense. This cost is shown as "cents per kilowatthour of net generation." As a general rule, the lower the power production expense, the more often the station is used because of its economic efficiency. On average, 80 percent of the total power production expense is the fuel cost. This expense is shown in Table 2-8 under "COST CENTS/KWH." 22 easy to retrofit with FGD, while Units 1 through 4 are rated very difficult to retrofit ** because of age, cost and space limitations. The major coal supplier is R and F Coal Company from Ohio with 74 percent of the total. Addington Brothers Mining, Incorporated of Kentucky supplies most of the remainder. Only a small quantity of Illinois coal is used at the station. The Illinois coal supplier is Old Ben Coal Company by spot market, with delivery by rail and barge. The Widows Creek Station is located in northeastern Alabama near Stevenson. The station has eight pulverized coal units with a total capability of 1,762 megawatts. The capability represents 58 percent of TVA's Alabama capability and 11 percent of TVA's total capability. The station's 5.7 billion kilowatthours of net generation represents 37 percent of the station's capability. The average cost per kilowatthour is 2.1 cents, with fuel at 1.6 cents. Widows Creek is the least efficient coal -fired station operated by TVA, ranking eleventh. Widows Creek purchased 2.7 million tons of coal and consumed 2.5 million tons in 1986. The coal averages 12,161 BTU and 2.1 percent sulfur. The S02 emission rate is about 1.8 pounds per million BTU. Nationally, the station ranks 75th in total S02 emissions. ** The rank in tons of S02 emissions and the consideration of FGD retrofit were taken from Evaluation of S02 Emissions And The FGD Retrofit Feasibility At The 200 Top Emitting Generating Stations prepared by Energy Ventures Analysis, Incorporated for the U.S. Environmental Protection Agency. Data includes the ranking of the 200 largest S02 emitting facilities, and the cost and engineering considerations for FGD retrofit. S02 emissions were based on 1983 data. FGD retrofit categories are: easy; modest; difficult; and very difficult. The "easy" rank means that the capital cost is from 1.0 to 1.3 times more expensive than an FGD system at a new 500 megawatt plant; "modest" costs from 1.3 to 1.6 times more; "difficult" costs from 1.6 to 1.9; and "very difficult" is greater than 1.9 times the capital cost of a new FGD system. Ranking of the facilities for FGD retrofit was determined by the size of the boiler; site congestion; stack adjustments; boiler modifications; demolition; duct length requirements; gas flow adjustments; soil conditions and underground modifications. The study points out, "that it should be useful in determining the relative degree of difficulty of retrofitting FGD systems on these powerplants." Other options available to the utility industry are life extension projects to up-grade a coal -fired station and a number of clean coal technology options to meet air quality standards. These options are not discussed in this study. 23 Sixteen Kentucky coal producers supply 74 percent of Widows Creek's coal needs. The Illinois coal is supplied by Consolidation Coal Company by spot market, and represents about five percent of the station's total coal demand. The Illinois coal is transported by rail and barge. Widows Creek's Units 7 and 8 are retrofitted with limestone FGD systems. The Unit 7 scrubber was brought on-line in 1981 and the Unit 8 scrubber started in 1977. Both FGD systems are rated at 80 percent S02 removal. The capital cost for Unit 8 was $158 per kilowatt, with an operation and maintenance expense of seven mills per kilowatthour. (A mill is equal to one tenth of a cent). No figures are available for the Unit 7 system. Table 2-8 details the two TVA coal -fired generating stations in Alabama. The table includes information on the performance for 1986. Included in the table are data on the generating station and information on the coal suppliers, quantity and quality of coal, delivered prices and S02 emissions. 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CM «-• O *■* 00 00 in *• UJ •• >• •• t/> z ^ < o n* UJ 3Z •■" —I CO o t— • • i— I < Qi " < >- CO Z 3 z c2 (— — > O ■— ' u. o u. _J I -J Z —I i < —i <: — < —i »— < h- — J t- < O O O -J o o HOHmHO 38 SEMINOLE ELECTRIC COOPERATIVE, INCORPORATED Seminole Electric Cooperative is a rural electric cooperative involved in the generation, purchase and wholesale of electricity in central Florida. The Co-op's customers consist of 11 district cooperatives. Seminole's home office is located in Tampa, Florida. Electric sales are about seven billion kilowatthours, with a value of nearly $350 million. Of these sales, almost all of the total are produced by Seminole, while the balance is purchased from various investor-owned and municipally-owned utilities. This ranks Seminole fifth in statewide util ity sales. Seminole has one coal -fired generating station and owns about two percent of Florida Power Corporation's Crystal River nuclear station. The coal -fired station has a capability of 1,210 megawatts, while the nuclear portion is about 13 megawatts. The coal -fired capability represents 15 percent of Florida's coal -fired capability. Seminole has yearly generation of approximately seven billion kilowatthours. Statewide, this figure accounts for six percent of total generation. Seminole purchased about three million tons of coal in 1986. Of this total, one Illinois coal producer supplies 1.4 million tons, or 47 percent of the total, and represents 35 percent of Florida's Illinois coal purchases. Since 1984, Seminole has increased its Illinois coal receipts by about 400 percent, while the delivered price has fallen by $.08 per million BTU. Table 3-9 shows the Illinois coal purchases, quality of coal and delivered prices to Seminole since 1984. TABLE 3-9. SEMINOLE'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1984-1986. YEAR 1984 1985 1986 THOUSAND TONS 339 692 1,435 PERCENT SULFUR 2.81 2.61 2.51 BTU/LB 11,449 11,704 11,669 $/T0N 51.78 56.52 50.87 S/MMBTU 2.26 2.42 2.18 39 The Seminole Station is located in northeastern Florida at Palatka. The station consists of two new pulverized coal units with capability of 1,210 megawatts. Units 1 and 2 are each rated at 605 megawatts. Seminole's generation of 6.8 billion kilowatthours represents 64 percent of the station's capability and accounts for 99 percent of the Co-op's total generation. The production expense per kilowatthour of generation is not available, but the fuel expense is 2.1 cents per kilowatthour. Almost three million tons of coal is purchased and used each year. The coal averages 12,076 BTU per pound of coal and 2.7 percent sulfur. White County Coal Corporation supplies the Illinois coal under long-term contract through 2010. The Illinois coal is received by barge. Webster County Coal Corporation is the major Kentucky coal supplier for most of the remainder. Webster's contract runs through 2010. Both of Seminole's units utilize a limestone FGD system rated at 1,210 megawatts. The capital cost and operation and maintenance expenses are not available. The FGD system has a removal rate of 86 percent. The S02 emission rate for the station is about 0.6 pound per million BTU of input. Table 3-10 provides additional information on the Seminole Station, as well as, data on the Seminole system. Refer to Map 3-1 for the location of the Seminole Station. 40 CO o co >-i co 2 a. o z o o o r-t O •— ' • H- roo<<0 1-1 ►- CO ui ae~ co cn ca o cs < uj z 2 o z Z UJ uj a to UJ a o ■ UJ «-^ 1 o ■ _i x: i o ■ «C =0 Z 1 • 1 o on o i to ■ O Z »— 1 o ■ ©w 1 en ■ O I CM ■ si «3- ■ * i r- ■ ^ i CM ■ 3 1 •» H h- 1 o ■ 00 1 V* ■ x j ^g | 1- ^ 1 1 CO ^ » < H O CO 1 | O 1— 1 2C I UJ 1 O 1 3 j • H ^ 1 < > ^ 1 n «* 1 z ■ 1 >- • 1 i a. a. 3 h- 1 ^ 1— 1 C* m I 1 o o O 1 UJ _J — > 1 1 * * H Z •■* 2 1 i m cn o a Z 00 Z 1 1 o o «■* a 3 < ^ 1 i to to cm a CO Q. 1 m U < •— « a O UJ 1 i co ^ Z 1 1 00 CO Z » 1 i en at O — 1 1 i i-« •-* H- 1 ^4 1 i ~* ca Z 1 3 l i * * 1 UJ 3C i _j O 1 1 © 1-4 1 1 z _i a »- 1 1 M i < a < 1 I X! i h- a t- 1 1 UJ i o a CO 1 1 CO i H- a CM O CO < CO O X CO o CO < CO "O —1 CD ^v Ol a a. h- T— 00 3 er 0) >• co 1— z 0) •-• o u 1- H- <0 lo CM 3 O oo V) t- H * < a. o 3 o co ^ to en en O CO CO ^f ^h cn • © CM «-« l»* CM CO «*■ • • O CO IO «T ^h cn co cn —i o m o • • CM CO CO to to <■ • m ^h CM O O • • in r-* co »-* ^ co to >- — ^ o o « ^ cn to o a a — « H- >- Z Z ^ ^ < < O O 3 3 1— H- ^2 3J5 < < o o C9 CS o o >— 1 ►— 1 UJ UJ o O — I — I Z Z O O —1 — 1 •k •» 1— 1 ►— 1 co o cm m co co CM «-l IO CO cm cm en ^- cn co HrHMlH to to I- M UJ • • >-4 < >CQI ►- < O I— i Q. CC — I o *•* o a. 00 < O — I a. uj < < QC O O i-i o u. -J I —I < — I < t- < h- o o o CO UJ to cc •• " * z _l I— LU efel O UJ Q Z UJ CO Lul CC i-^ o >-^ o u. Z -J ■ •-■ < -I — I o o ■-* H- O 41 TAMPA ELECTRIC COMPANY Tampa Electric Company is a public utility engaged in the generation, transmission and sale of electricity on the west coast of Florida. The service territory covers approximately 1,900 square miles and includes the cities of Tampa, Winter Haven, Plant City and Dade City, with a total population of more than 850 thousand. The company supplies electricity to about 400 thousand customers. Tampa Electric Company is an operating subsidiary of TEC0 Energy, Incorporated, a holding company. Both employ approximately 3,400. Tampa Electric Company and TEC0 Energy, Incorporated are headquartered in Tampa, Florida. Electric sales of approximately 13 billion kilowatthours are valued at $.9 billion. Based on total kilowatthours sold, Tampa Electric ranks as the third largest Florida electric utility and 54th largest investor-owned utility, nationally. The company has two coal -fired generating stations and one oil-fired station. The two coal -fired stations have 2,663 megawatts of capability and represent 30 percent of Florida's coal -fired capability and eight percent of Florida's total capability. Tampa Electric has 1,137 miles of above ground lines and 1,578 miles of underground lines. Tampa has electrical interconnections with Florida Power Corporation, Florida Power and Light Company and the City of Lakeland. The company has generation of about 13 billion kilowatthours. Almost all of this total (99%) is from coal -fired generation with the balance from the oil-fired station. This generation represents 12 percent of Florida's total generation. Tampa Electric purchased 5.6 million tons of coal in 1986. Illinois coal producers supply 1.2 million tons, or 21 percent of Tampa's coal demand. Overall, the Illinois coal represents seven percent of Florida's total coal purchases. Since 1985, Tampa Electric has reduced its Illinois coal receipts by 28 percent. Table 3-11 shows Tampa Electric's Illinois coal purchases, quality of coal and delivered prices since 1983. 43 TABLE 3-11. TAMPA ELECTRIC COMPANY'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS 22 460 1,694 1,217 PERCENT SULFUR 3.00 2.94 2.97 2.98 BTU/LB 11,705 11,276 11,034 11,118 $/TON 31.00 31.98 42.87 42.97 VMMBTU 1-32 M2 1.94 1.93 The Big Bend Station is located in west central Florida at Tampa. The station consists of four pulverized coal units with capability of 1,559 megawatts. This capability represents 52 percent of Tampa's total capability. Big Bend's generation of 8.2 billion kilowatthours represents 60 percent of its capability and 61 percent of Tampa's total generation. The production expense averages 2.6 cents per kilowatthour, with fuel at 2.2 cents. Big Bend is Tampa's most efficient station. The company purchased 5.2 million tons of coal and used 3.6 million tons of coal in 1986. The coal averages 12,032 BTU per pound of coal and 2.3 percent sulfur. The station consumes 1.2 million tons of Illinois coal annually, representing 23 percent of the station's coal receipts. The Illinois coal is supplied by Amax Coal Company and Consolidation Coal Company by spot market, and Zeigler Coal Company through contract. The Illinois coal is received by barge. The major Kentucky coal suppliers are Gatliff Coal Company, Peabody Coal Company and Pyramid Mining Incorporated, all by contract. Big Bend unit 4 must meet the U.S. Environmental Protection Agency's New Source Performance Standard. To meet the S02 standard, the station utilizes a limestone FGD system rated at 419 megawatts. The FGD system came on-line in 1984 and is designed to remove about 90 percent of the S02 emissions. The capital cost and operation and maintenance expenses are not available. Overall, the station has an S02 emission rate of 2.8 pounds per million BTU of input. Nationally, Big Bend ranks 27th in tons of S02 emissions. Units 1 through 3 are rated as modest for retrofitting with an FGD system because of age, size and space availability. The Gannon Station is located in Tampa just north of the Big Bend station. The station has three pulverized coal units and three cyclone units, with capability of 1,104 megawatts. This figure accounts for 36 percent of Tampa's total capability. The three cyclone units represent 35 percent of the station's capability. Gannon's generation of five billion kilowatthours represents 52 percent of its capability and accounts for 37 percent of the company's total generation. Gannon has a production expense of 3.2 cents per kilowatthour with fuel at 2.5 cents. 44 The 2.2 million tons of coal burned averages 13,013 BTU per pound of coal and 1.1 percent sulfur. Most of the coal is transferred from the Big Bend station. The Kentucky coal is supplied by Gatliff Coal Company under contract. The S02 emission rate is 1.6 pounds per million BTU of input. Nationally, Gannon is ranked 121st in tons of S02 emissions. No information is available concerning the FGD retrofit cost and consideration. Table 3-12 details Tampa's coal-fired generating stations and company data for 1986. 45 —I Z WO O Z o wo o O Z >- WO o wo wo Q. WO o o CM O i— • *-* H- I CJ < wo CO i-« t— 00 cc wo en I- ^ WO "^ o wo I >■ Cw « X < _J w t- I- * 2 o LU O Z O LU w O £ < LU h- Cfl 1-4 Cv z >• WO O. < LU Z l — 1 O -J < WO < < < < o o o o o o o o o o o o o o o o • • • • cm cm wo en r*» wo en cm CO CO CO ^ © CO W3 ^ r^ r-» r«* co en en en en * ts o o o en wo co 00 en oo co wo CM o CM O wo o WO en tn wo o CM o WO < (SOX wo < wo Q C9 CD © 3 O WO NHlflOUS CM WO O 00 ^h CO (M en oo ^h o ^^ *—* •— ■ ^* rx> f-4 •-• en en wo en wn en o oo r*. ^- CM ^ ^ WO ^- CM O WO 00 WO WO wo cm en cm co o en i-i r»«. wo wo en oo wo o co en ^h en co cm wo wo wo • ••••• CM CM CM O O CM ^h co ^ wo «»■ en ^h o cm oo cm o ^h w* CM CM CO CO en wo co wo >- WO 1 H- Z 1 i co ^ ^ ^ wo en «-• O 1 t- ►- 1 1 NIONCAIO^ is : i rt-n^coN CM WO CM 3 O 1 1 * * CTO l 1 ^H CO CO CM • 00 oo CM CM CM CO o CM en • o oo wo WO >- < < i-i o z o o z ac z < © z •-< •-• — — h- < o > _i q z — j ee —i z lu :*s — • — — *: o > 3 < o 46 a LU --> < => Z O oo O O Z >— O w u oo \ O 00 O I— < H-f Q. i—i fr« < _l w H- I- M 2 o LU o z o UJ w >— Q. z >- UJ OO < O -J o CM CO < OO <<<<<< o o o © o o o o o u o o >- 3- O >■ O O o o o o o o • ••••• n oo o CO n oo o o m r-. ^h ^ ^H ^« ^H *■* CM CO NCOOniAN lAlAiOiflidlO (7i en en en en en ^h cm co ^ un z wo < wo >- O0 t- z « o < o 3 O ©*© —J Q. < Q- O 3 O O0 CO cn CM • CM CM CO • cn CO l-H o CO <—< o co I— I cn • o in o O0 O0 eg ec O O o o _J -J OO OO MM H- H- WO O0 M tt H- H- Z Z < < © © Z Z 2 3 H- H- © © < < — — . CO C3 O O — 1 — J LU LU O O -J — J « • CQ qo CM ID on ~* *T CNI O IO «0 CM • • • • » ■ CO CO H- W0 — i LU —4 W0 >oox t- < o — o. ec -i < => MOO. CO < Q —I Q. LU < LU l OO LU W0 < o Q. O LU © < o O LU Q Z LU 00 LU CC O U. < — J < •-• < — I © © © h- O h- — I © © ■-* h- O 47 CHAPTER FOUR GEORGIA Georgia electric utilities purchased approximately 27 million tons of coal; 0.5 million barrels of petroleum; and six billion cubic feet of natural gas in 1986. For these fossil -fuel categories, coal represented four percent of U.S. utility coal purchases, while petroleum and natural gas were only negligible. On a BTU basis, Georgia utilities purchased four percent of the nation's total fuel for electrical generation. Table 4-1 lists the fossil -fuel sources for Georgia electric utilities during 1986. TABLE 4-1. GEORGIA FOSSIL-FUEL SOURCES FOR ELECTRIC GENERATION. FUEL QUANTITY (000} BTU (BILLION) % OF TOTAL $/UNIT S/MMBTU COAL PETROLEUM NATURAL GAS 27,329 tons 539 bis. 5.787 mmcf. 663,863 3,285 5.926 98.6 .5 .9 43.95 14.12 2.05 1.81 2.32 2.00 TOTAL 673.073 100.0 Georgia has two investor-owned utilities; 51 municipal systems; 43 rural electric cooperatives; one state system; two U.S. government installations; and one county system. The major suppliers of electricity are Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, Southeastern Power Administration and Savanna Electric and Power Company. These five utilities account for most of Georgia's electrical generation, with nearly 80 percent of the total generation by Georgia Power Company. Georgia's electric utilities have 17,678 megawatts of capability. This capability consists of 12,095 megawatts of coal; 1,524 megawatts of nuclear; 1,507 megawatts of petroleum; 2,485 megawatts of hydro; and 67 megawatts of natural gas. Georgia's total capability accounts for three percent of the U.S. total. Of the 44 states that have coal-fired generation, Georgia ranks ninth. As shown in Table 4-2, coal accounts for 68 percent of Georgia's total capability, while the 1,524 megawatts of nuclear represents two percent of the nation's total. 49 TABLE 4-2. GEORGIA SUMMER CAPABILITY. TYPE OF CAPABILITY TOTAL COAL NUCLEAR PETROLEUM NATURAL GAS WATER MEGAWATTS 17,678 12,095 1,524 1,507 NO. OF UNITS 194 38 2 38 % OF GA TOTAL 100 68 9 9 % OF U.S. TOTAL 3 4 2 2 67 5 2,485 111 14 3 Georgia Power Company will bring one new coal -fired unit and two nuclear units on-line in the future. The coal -fired unit is owned by Georgia Power Company, while the two nuclear units are jointly owned by Georgia Power Company (51%), Oglethorp Power Corporation (30%), Municipal Electric Authority (17%) and the City of Dalton (2%). Table 4-3 details these generating units. TABLE 4-3. FUTURE BASELOAD CAPABILITY IN GEORGIA. STATION CAPABILITY UTILITY AND UNIT QUO FUEL ON LINE GEORGIA POWER COMPANY Scherer 4 Vogtle 1 Vogtle 2 755 1,198 1.198 Coal Uranium Uranium 1989 1987 1988 TOTAL 3.151 Net generation by Georgia electric utilities totals 75 thousand gigawatthours, a decrease of seven percent from 1985. Coal generates 87 percent of the total, while nuclear represents most of the remainder. On a national basis, Georgia accounts for three percent of generation and ranks 13th in total generation. Table 4-4 details each category. TABLE 4-4. GEORGIA NET GENERATION, TOTAL COAL TYPE OF CAPABILITY NATURAL NUCLEAR PETROLEUM GAS WATER GIGAWATTHOURS 74,909 64,883 7,238 % OF GA TOTAL 100 87 10 % OF U.S. TOTAL 3 5 2 270 421 2,097 3 1 50 Georgia utilities purchased approximately 27 million tons of coal in 1986. This coal is supplied by seven coal producing states. The sulfur content varies from 0.7 percent to 2.9 percent, with a weighted average of 1.8 percent. The BTU content varies from 11,424 to 12,974 per pound of coal, with an average of 12,146. On a BTU basis, Illinois coal has the lowest delivered price at $1.65 per million BTU, while West Virginia coal is the most expensive at $2.96 per million BTU. Table 4-5 lists the coal supplying states, or regions and their respective quantities and qualities of coal sold to Georgia. TABLE 4-5. GEORGIA COAL SUPPLIERS. TONS % OF % STATE/REGION (000) TOTAL BTU/LB SULFUR $/T0N $/MMBTU E. KENTUCKY 11,149 41 12,362 1.46 43.04 1.74 ILLINOIS 5,609 21 11,424 2.47 37.59 1.65 VIRGINIA 3,508 13 12,974 1.12 48.64 1.87 H. KENTUCKY 2,383 9 11,804 2.91 42.74 1.81 TENNESSEE 1,530 5 12,552 1.26 47.47 1.89 INDIANA 1,328 5 11,440 2.50 38.15 1.67 W. VIRGINIA 994 3 12,243 .65 72.57 2.96 ALABAMA 827 3 11.861 2.22 51.20 2.16 TOTAL/AVERAGE 27.328 100 12.146 1.78 43.95 1.81 Illinois coal suppliers sold about six million tons of coal to Georgia Power Company in 1986, representing 21 percent of Georgia's total utility coal receipts. Since 1981, Illinois coal sales have increased by one million tons, while the delivered price has stayed about the same. Illinois coal sales, quality of coal and delivered prices to Georgia, for the period 1981 through 1986 are shown in Table 4-6. TABLE 4-6. GEORGIA'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1981-1986. YEAR 1981 1982 1983 1984 1985 1986 THOUSAND TONS 4,507 5,083 5,028 5,472 5,247 5,609 PERCENT SULFUR 2.60 2.70 2.60 2.50 2.60 2.47 BTU/LB 11,279 11,380 11,314 11,369 11,317 11,424 $/T0N 36.46 40.13 41.46 39.63 37.31 37.59 $/MMBTU 1.62 1.76 1.83 1.74 1.65 1.65 51 Map 4-1 shows the locations of Georgia Power Company's coal -fired stations. A discussion of Georgia Power Company and its coal -fired generating stations follows. 52 MAP 4-1 COAL FIRED GENERATING STATIONS GEORGIA • ILLINOIS COAL 53 GEORGIA POWER COMPANY Georgia Power Company is involved in the generation, purchase and distribution of electricity to more than 600 communities in Georgia. The company also wholesales electricity to 46 municipalities and one county electric system, and provides steam for heating purposes to the business district of Atlanta. Georgia Power's service territory covers about 57 thousand square miles, with a population of 5.1 million and 1.4 million customers. The economic base consists of manufacturing and service industries. The company employs about 14,500. Georgia Power is an operating subsidiary of The Southern Company and is headquartered in Atlanta, Georgia. Electric sales of 65 billion kilowatthours are valued at $3.4 billion. These sales represent 52 percent of The Southern Company's total kilowatthour sales. Total kilowatthours sold ranks Georgia Power as the largest Georgia electric utility. Georgia Power owns or partially owns nine coal -fired generating stations, located throughout northern and southwestern Georgia. Not detailed in this section, but shown in Table 4-8, is the Scherer Station which Georgia Power owns 8.4 percent, or 70 megawatts of capability. The coal -fired capability totals 8,593 megawatts, or 70 percent of Georgia Power's total capability. The company has one operating nuclear station with 1,524 megawatts of capability, representing 12 percent of Georgia Power's total capability. The coal -fired capability further represents 71 percent of the state's coal -fired capability and 49 percent of Georgia's total capability. Georgia Power has 45,642 miles of above ground lines and 9,005 miles of underground lines. The company has electrical interconnections with Southern Electric Generating Company, Alabama Power Company, Gulf Power Company, Florida Power Corporation, Florida Power and Light Company, Savannah Electric and Power Company, Duke Power Company, Tennessee Valley Authority, South Carolina Electric and Gas Company, City of Tallahasee and South Carolina Public Service Authority. The company has electric generation of approximately 58 billion kilowatthours. Of this generation, coal accounts for 53 billion kilowatthours or 91 percent, while nuclear generation represents most of the remainder. Statewide, this generation represents 78 percent of total generation. Georgia Power Company purchased 26.5 million tons of coal in 1986. It is the third largest consumer of coal in the United States. Illinois coal producers supply 5.6 million tons, or 21 percent of this total. Georgia 55 Power is the fourth largest consumer of Illinois coal. Of these sales, the Wansley station receives 57 percent of the total. Since 1983, Georgia Power has increased its demand for Illinois coal by 12 percent, while the delivered price has decreased by ten percent. Table 4-7 lists Georgia Power's Illinois coal purchases, quality of coal and delivered prices for the past four years. TABLE 4-7 . GEORGIA POWER'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS 5,028 5,472 5,247 5,609 PERCENT SULFUR 2.60 2.50 2.58 2.47 BTU/LB 11,314 11,369 11,302 11,424 $/T0N 41.46 39.63 37.29 37.59 i/MMBTU 1.83 1.74 1.65 1.65 The following paragraphs discuss Georgia Power Company's eight coal -fired stations. Table 4-8 provides statistics on these stations and company data. Refer to Map 4-1 for the locations of these stations. The Arkwright Station is located in central Georgia at Macon. The station consists cf four older pulverized coal units with capability of 172 megawatts, representing one percent of the company's total capability. It is the smallest coal-fired station owned by Georgia Power. Arkwright's generation of 0.5 billion kilowatthours is 36 percent of the station's capability and one percent of Georgia Power's total electric generation. The production expense for this station is not available, however, the fuel expense averages 2.5 cents per kilowatthour. Arkwright consumed 0.3 million tons of coal in 1986. This coal averages 12,651 BTU per pound of coal and two percent sulfur. The S02 emission rate is three pounds per million BTU of input. No information is available on the FGD retrofit cost and consideration. States supplying coal to this station are Tennessee with 97 percent of the total and Kentucky with the balance. The Tennessee coal is supplied by Royal Fuel Corporation by contract. The Bowen Station is located in northwestern Georgia at Taylorsville. It consists of four pulverized coal units with capability of 3,075 megawatts. Bowen is the largest station in Georgia Power's system, accounting for 25 percent of the company's capability. It is also one of the largest coal -fired stations in the United States. The station's generation of 21.2 billion kilowatthours accounts for 79 percent of its capability and 36 percent of Georgia Power's total generation. It is Georgia Power's 56 most efficient coal-fired station for which data is available. The average production expense per kilowatthour is two cents, with fuel at 1.7 cents. The 8.3 million tons of coal purchased and consumed averages 12,199 BTU per pound of coal and 1.8 percent sulfur. The station's S02 emission rate is 2.8 pounds per million BTU of input. Nationally, it ranks tenth in tons of S02 emissions. The station is rated easy for FGD retrofit because of age, size and availability of space. Kentucky supplies 100 percent of the coal. The major coal suppliers are Cimarron Coal Corporation, Randall Fuel Company and Straight Creek Mining Company, all by contract. • The Hammond Station is located in northwestern Georgia at Coosa. The station has four pulverized coal units with capability of 805 megawatts, representing seven percent of Georgia Power's total capability. Unit four is the newest and largest with 484 megawatts. The station's generation of five billion kilowatthours represents 71 percent of its capability and accounts for nine percent of the company's total generation. Hammond ranks fifth in economic efficiency. The production expense averages 2.1 cents per kilowatthour. The fuel averages 1.7 cents per kilowatthour. The station purchased and consumed about 2.1 million tons of coal in 1986. The coal averages 12,558 BTU per pound of coal and 1.7 percent sulfur. The S02 emission rate is 2.8 pounds per million BTU of input. Hammond ranks 101st in tons of S02 emissions. Unit 4 is rated as modest for FGD retrofit, while Units 1 through 3 are rated as difficult. The three coal supplying states are Kentucky with (47%), Virginia (44%) and Tennessee (9%). The major Kentucky coal supplier is Greenwood Land and Mining Company by contract. Delta Coal Corporation supplies the Virginia coal under contract. The Harllee Branch Station is located in central Georgia at Milledgeville. It consists of four pulverized coal units with capability of 1,518 megawatts, or 12 percent of Georgia Power's total capability. The station's generation of 9.8 billion kilowatthours accounts for 74 percent of its capability and 17 percent of Georgia Power's total generation. It is the third most efficient station. The average production expense per kilowatthour is 2.3 cents, with fuel at 1.8 cents. The 3.9 million tons of coal used in 1986 averages 12,523 BTU per pound of coal and 1.3 percent sulfur. S02 emissions are about two pounds per million BTU of input. The station ranks 99th nationally in total S02 emissions. The FGD cost and availability are not available. Kentucky coal producers supply 51 percent of its coal needs, with the remainder from Virginia (25%) and Tennessee (24%). The major Kentucky supplier is Randall Fuel Company by contract. The Virginia coal is supplied by General Coal Company under contract, while the Tennessee coal is furnished by Consolidation Coal Company by contract. 57 The McDonough Station is located in northwestern Georgia near Smyrna. The station has two pulverized coal units with capability of 507 megawatts, accounting for four percent of Georgia Power's total capability. The station's generation of 3.2 billion kilowatthours represents 71 percent of capability and accounts for five percent of the company's total generation. McDonough ranks fourth in economic efficiency. The production expense averages 2.1 cents per kilowatthour, with fuel at 1.9 cents. The 1.3 million tons of coal purchased and burned averages 11,790 BTU and 2.4 percent sulfur. S02 emissions are four pounds per million BTU of input. Nationally, McDonough ranks 140th in tons of S02 emissions. Retrofitting with FGD is rated difficult because of space limitations. Illinois coal producers supply 34 percent of its coal needs, with the remainder from Kentucky. Illinois coal suppliers are Arch of Illinois under contract through June 1994 and Old Ben Coal Company under contract through June 1990. The Illinois coal is received by railroad. The major Kentucky coal suppliers are Cimarron Coal Corporation and Peabody Coal Company, both by contract. The Mitchell Station is located in southwestern Georgia at Albany. Mitchell has three older pulverized coal units with capability of 204 megawatts, representing two percent of Georgia Power's total capability. The station's generation of 1.1 billion kilowatthours represents 60 percent of its capability and accounts for two percent of the company's total generation. Mitchell's production expense is not available, but the fuel expense averages two cents per kilowatthour. The 0.4 million tons of coal burned averages 12,754 BTU per pound of coal and 1.3 percent sulfur. The S02 emission rate is 2.1 pounds per million BTU of input. No data is available concerning the S02 rank or the FGD cost consideration. All of the coal is supplied by Kentucky. Information on the coal supplier is not available. The Wansley Station is a jointly owned facility located in west central Georgia at Roopville. It consists of two pulverized coal units with capability of 1,730 megawatts. The station's generation of 11.1 billion kilowatthours accounts for 73 percent of its capability and 20 percent of Georgia Power's total generation. Wansley is operated by Georgia Power Company. Georgia Power Company owns 54 percent, with the balance owned by Oglethorpe Power Corporation with 30 percent, Municipal Electric Authority at 15 percent and the City of Dalton with less than two percent. The station is the third most efficient station. The average production expense per kilowatthour is two cents, with fuel at 1.8 cents. The 4.7 million tons of coal purchased and used averages 11,441 BTU per pound of coal and 2.5 percent sulfur. S02 emissions are 4.2 pounds per million BTU of input. Wansley ranks 13th in tons of S02 emissions, nationally. FGD cost considerations are not available. Illinois coal producers supply 71 percent of the coal needs, with the remaining 29 58 percent from Indiana and Virginia. The Illinois coal is supplied by Arch of Illinois under contract through mid 1994 and Old Ben Coal Company by contract through mid 1990. The Illinois coal is transported by rail. The major Indiana coal supplier is Old Ben Coal Company under contract, while the Virginia coal is supplied by Delta Coals Incorporated by contract. The Yates Station is located in west central Georgia at Newnan. It consists of seven pulverized coal units with capability of 1,250 megawatts, representing ten percent of Georgia Power's total capability. The station's generation of 6.3 billion kilowatthours accounts for 58 percent of its capability and 11 percent of Georgia Power's total generation. It is the least efficient Georgia Power station. The average production expense per kilowatthour is 2.6 cents, with fuel at 2.1 cents. The 2.9 million tons of coal consumed averages 11,671 BTU per pound of coal and 2.3 percent sulfur. The station's S02 emission rate is 3.9 pounds per million BTU of input. Nationally, Yates ranks 43rd in total tons of S02 emissions. No information is available on the FGD retrofit cost and consideration. Illinois is one of five states supplying coal to the station, supplying 63 percent of the coal receipts. The Illinois coal suppliers are Arch of Illinois under contract through June 1994 and Old Ben Coal Company under contract through June 1990. The coal is transported by rail. Other major coal suppliers are Arch of .Alabama by contract and Pyro Mining Company of Kentucky through" contract. 59 — i z co o z o co o O Z h- o «— • o I- ^ CO ^s. O CO CO O CO i— « I— < co Ou CO o o coo« UJ H- 00 uj 2 co en —jo *-• 03 0.(3 O UJ UJ z ca uj C9 < «J w o « CO O X 2 O UJ o Z O UJ w <0 z >> 3 »— CO I— CO < < < < o o o o o o o o o o o o PABILI (HW) 1 • • • • i * *r * «* o UJ 1 Z 1 Z «-* 1 O -J 1 1 f-i CM CO 00 1 <* ^ «*■ *■ i en en en en I fH f^ I-* 1-* 1— 1 1 — CM CO ^" o o o 00 CNJ CM en CM co CO CO CO m 00 CO m < »- o CM 00 o z CO Z o co < CO >■ CO i- z •-* o < o 3D O o*o —J Q. < a. 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CO CD CO CO en ^ UJ O UJ o o CM OS o z co z < o »»^ co o x u. z^— UJ o o CM en 00 o CO < CO o CO en en CM co en CM 00 CO CO CO CO m 0) >- CO I— z « o < o 3 O 0*0 en oo co O —I CW < Q- O 3 CO CO 76 ** =3 Z o co o <-> Z t— o >-* o CO to o I— <_> z I >■ < »-*? a. — • ^S < _J w h- 1- ^ UJ O z o C9 zcos < UJ O -J 00 < »— CO < < < o o o o o o o o o Q- Q. a. o o © • • • I** CM ^H ^H CO CO ^H CM CO o oo csj (OION en en en ft CM CO to o < o o o CO o CO CO en oo en CO . csj CO CO CM CO CO O co CM m CO CO o o < o CM 00 O Z to z o to < to >- to I— z «-• o < o 3 O oo _l O. < ew O =D o to 6.308 1.012 co ■ CO ■ CM ■ •— • ■ 2.321 1.747 to I 00 ■ r-. ■ n •— • M 48.94 46.46 to ■ to ■ to ■ *r ■ 8.35 5.48 f*. ■ CO ■ 3.41 0.69 •— < i en ■ H O 1 10,542 13,295 r> ■ O I CO ■ •— < ■ 101.0 1,155.0 O 1 to ■ CO ■ CM ■ ILLINOIS KENTUCKY -J 1 < ■ h- ■ O ■ H- ■ to to ec ec o o o o CO CO —1 — 1 h- h- z z *: ^ < < o o 2 2 »- H- Z Z < < o o auooww IlllilOO J J Z Z O O -J — I CO to CO 00 00 CO co o to en i— i t-H •— • en o o — i —t - CO H- < ■-4 o_ -I < l-H O CO < Q O. UJ < or O "-> u. -J I < -I I- «s o o I- o to UJ .. to to < UJ x to o - ^ Z >- 1 1 o o 3 H- 1 >■ h- l ec •— i UJ -J*-s 1 1 o o O 1 2£ ^ 3c 1 * * % z eo £ i 1 tO o to ■ 3 <*-' 1 1 CM tO f-. ■ to a. i 1 CO to 00 ■ < i u UJ 1 1 in CM ^g l to r-* Z ►-" 1 i en o» O -J 1 1 I— 1 •— « 1- 1 •— « 1 2 1 3 ! 1 •-» CM z 1 x O 1 1 UJ ►"H | 1 UJ —J 1 H- 1 1 u. 1 < ■ < 1 1 u. I h- ■ 1- 1 1 o I O 1 to 1 1 o I h- ■ CM O to to to at • ■ to t- z ■-■ o < o 3 O CO 00 O to en to © -j a. - ft. — • ** <-lw o « o z UJ o z o UJ w (9 UJ UJ Cw >• CO o o I m UJ < co <* i i at ■ 1 CM ■ i m ■ i «* ■ i co ■ •— « ■ i o ■ i at ■ i o a 1 lH ■ CO 1 1 *t ■ • 1 CM 1 CM ■ 1 CO ■ i CM ■ 00 1 1 00 1 m g i en ■ CM ■ COAL COAL ■ o o a a. a. 75.0 102.0 O 1 «— • ■ 1951 1958 ■ CO * ■ ■■■■■■■I GRAND- TOWER _j i < ■ h- ■ O I H- ■ JXV) < => z O oo o O Z H- © w O CM CD o z co Z < to o — i a ^-< -h >- co I- z •-• o z"- < o =5 O o-o _l o_ < a. o =3 O CO o o CO CM • CM CO 00 en CM CO • CM in CM m o o CO CO I— o CO "*s* O CO a. m x < jw o «-« zio UJ o z o UJ w C9 UJ a. >■ art CO CO z UJ < co ■ ■— ' H 00 U O u • II 00 H 00 ■ ^" H CO N CM H m M m H o > <— ■ ■ CM M CO H II ^* ■ co u CO H CM 1 00 H CO ■ at ■ at ■ * M CO ■ CM ■ O ■ • H ^H M COAL COAL ■ ■ ■ o o 75.0 75.0 O 1 o ■ in ■ •— * ■ 1953 1954 ■ CO ^ HUTSON- VILLE —J ■ < ■ 1— ■ O ■ h- ■ II II 3 N II h- ■ * I CM CO I CO II O Z II «3- II CO Z I ^ II *:• • CO II —I II 00 II —I II ^ II S H h- il CO II I ^-» II >• CO II t- Z n «o II H- H- M Z ■ < O U SON o-o il +-* II a I I ■ ■ CC M UJ II 1-4 II -J ■ _j a. u < Q. li O 3 II O CO u co co CM o CM co < 5« co ii ii ii ii ii ii ii ii ii ii ii ii ii ii ii ii ii CO II CM II II II II II n at u CO II ii ii ii ii ii ii ii ii ii ii ii ii l ii ii ii ii ii ii en CM •-• ii I ■ ■ co ii • ■ CO u CO II >* ii ■ ■ ii I il I I I I o <_> Z I— o O CL •-• a« UJ o z o UJ — ■ ' til UJ 3 I- UJ •-h a. z >- to < UJ UJ I to < < < < o o o o o o o o o o o o • • • (O IP 00 00 00 o <3- »a- to en en en ^H CM CO to o o UJ ec UJ to o» en to 00 (O o CM - z«-* © X h- h- S uj «r zolo uj o z o CO UJ z >■ c* — Z 00 z = <«— ' g I IO O -J ■ -* «-i < 00 1 GO II 10 H O ■ m M ^ ■ l . ■ o ■ ^h a r^ ■ H CM 1 O ■ to ■ m ■ O 1 co ■ CO ■ 00 1 * a CO ■ (O ■ en ■ m | CM 1 COAL COAL ■ o o a a. a. 550.0 560.0 O 1 o ■ •— • 1 <-* ■ •— < I 1977 1982 ■ t-i CM ■ * ■ Z ■ o sp ■ Ul < ■ o ■ H- ■ CM 00 o z co z < aox o oo < CO o Ctf ^ CO ►- z »i o < o 3 O < a. © 3 O co 4.455 1.000 O 1 © ■ •■4 I O 1 en i 1.975 1.901 CO ■ «* ■ cn ■ •— < ■ 46.16 43.74 o » m ■ t i 10.84 6.42 O 1 en i 00 • 2.67 0.59 11,688 11,502 «o 1 O I vo ■ *-« ■ 870.9 682.2 CO 1 m i ur> ■ ILLINOIS INDIANA < ■ i— ■ o ■ h- ■ WO WO < < CS C9 f. 00 en ^h r-» co co co etf ce O O z z < < o o -J —J •X. "X. "*. -a o o h- h- z z o o O O ** >—' O O — J -J LO O —I —I CO 00 00 00 CM I*". (71 S NN cm cm ^- co en en CO >■ •• CO gg ^ CO oaz3 h a. ce ■-■ z -J O — 1 h- Ul i-i o a. < 00 o 5° -< O O O — i O O hUh« 1- o 86 COMMONWEALTH EDISON COMPANY Commonwealth Edison Company (COMED) is an investor-owned electric utility operating in northern Illinois. The company is engaged in the production, purchase, transmission, distribution and sale of electricity to about three million customers. COMED supplies electricity to 393 communities in northern Illinois. The company's service territory covers approximately 11,525 square miles with a population of eight million. Most of the electric sales are derived from Chicago and the surrounding area. Commonwealth Edison employs 18,400 statewide, with the main office in Chicago, Illinois. COMED's electric sales are 65 billion kilowatthours, valued at $5.4 billion. Based on electric sales, COMED is the largest Illinois electric utility with 60 percent. Nationwide, the company ranks fourth. COMED has eight coal -fired stations totalling 6,940 megawatts of capability and five nuclear stations with 7,995 megawatts of capability. The coal -fired capability represents 37 percent of COMED' s total capability and 46 percent of Illinois' coal-fired capability. COMED's nuclear capability accounts for 44 percent of the company's capability and ten percent of the U.S. nuclear capability. On a national basis, COMED ranks fifth in utility coal receipts and first in nuclear generation. COMED has 62 thousand miles of above ground lines and 577 miles of underground cable. The company has electrical interconnections with Central Illinois Light Company, Central Illinois Public Service Company, Illinois Power Company, Indiana and Michigan Electric Company, Iowa Illinois Gas and Electric Company, Interstate Power Company, Northern Indiana Public Service Company, Wisconsin Electric Power Company and Wisconsin Power and Light Company. Commonwealth Edison has net generation of 69 billion kilowatthours. Coal generation totals 24 billion kilowatthours or 35 percent of COMED's total generation. Nuclear generation of 43 billion kilowatthours accounts for most of the remainder. Statewide, COMED accounts for 64 percent of the total electrical generation. COMED purchased 16 million tons of coal in 1986. Of this total, one Illinois coal producer, Peabody Coal Company supplies about 2.7 million tons, or 17 percent of the company's total coal demand. All of COMED's stations, except for the Kincaid Station, are using a western low sulfur coal. Statewide, COMED's Illinois coal purchase represents eight percent of all coal purchases and 16 percent of Illinois coal receipts. Table 5-11 shows COMED's Illinois coal purchases, quality of coal and delivered prices for the period 1983 through 1986. As shown in the table, the 87 demand for Illinois coal has steadily declined as additional nuclear capability comes on-line. Also, the delivered price has decreased by 16 percent from 1985. TABLE 5-11. COMMONWEALTH EDISON'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR ■ 1983 1984 1985 1986 THOUSAND TONS 3,234 3,005 2,517 2,732 PERCENT SULFUR 3.43 3.35 3.30 3.36 BTU/LB 10,211 10,300 10,283 10,268 $/TON 30.84 34.68 35.68 30.13 J/MMBTU 1.51 1.68 1.71 1.47 The following section discusses Commonwealth Edison's seven coal -fired stations in Illinois and the one station located in northern Indiana. Table 5-12 at the end of this narrative provides additional data on the generating stations and systemwide data. The Crawford Station consists of two pulverized coal units located in northeastern Illinois at Chicago. The 532 megawatts of capability accounts for three percent of COMED's total capability. Crawford has a 29 percent capability factor with generation of 1.4 billion kilowatthours. This figure is two percent of COMED's total generation. The station ranks seventh in economic efficiency, primarily because of the high cost of the Wyoming and Montana coals. Crawford's fuel expense is 4.4 cents per kilowatthour. The station purchased and consumed about 0.8 million tons of coal. The compliance coal is used to meet the S02 emissions standards established for the Chicago area. The coal averages 9,576 BTU per pound of coal and 0.5 percent sulfur. Crawford has a 0.9 pound of S02 per million BTU emission rate. The coal is supplied by Big Horn Coal Company and Black Butte Coal Company, under contract. The Fisk Station , located near the Crawford station in Chicago, consists of one pulverized coal unit. The station's capability is rated at 316 megawatts and represents two percent of the company's capability. Fisk's generation of 0.6 billion kilowatthours is 20 percent of its capability and less than one percent of COMED's total generation. Fisk is COMED's least efficient coal -fired station, with a production expense of 6.5 cents per kilowatthour. The station purchased and used about 0.4 million tons of Montana and Wyoming coal. The BTU and sulfur content are 9,575 and 0.5 percent, 88 respectively. The S02 emission rate is about 0.9 pound per million BTU. The coal is supplied through Black Butte Coal Company of Wyoming and Decker Coal Company of Montana, both by contract. The Jollet Station , located in northeastern Illinois at Joliet, consists of one cyclone unit and two pulverized coal units. The capability is 1,309 megawatts and accounts for six percent of COMED's total capability. Joliet's generation of 4.5 billion kilowatthours represents 39 percent of its capability and seven percent of COMED's total generation. The cost per kilowatthour is 4.7 cents, ranking sixth in overall efficiency. The fuel expense accounts for 77 percent of this total. The 2.5 million tons of coal consumed at the Joliet station averages 9,520 BTU per pound of coal and 0.5 percent sulfur. The S02 rate is less than one pound per million BTU of input. The Wyoming coal is supplied by Black Butte Coal Company and the Montana coal is supplied by Decker Coal Company, both by contract. The Klncaid Station , located in south central Illinois near Kincaid, consists of two cyclone units with a combined capability of 1,108 megawatts. The station accounts for six percent of COMED's total capability. Kincaid's generation is five billion kilowatthours, representing 51 percent of the station's capability and seven percent of COMED's total generation. The production cost per kilowatthour is 2.4 cents. Kincaid is COMED's most efficient fossil -fuel station. The fuel expense is 1.9 cents per kilowatthour. Kincaid is Commonwealth Edison's only station that utilizes a large quantity of Illinois coal. The station uses about 2.7 million tons of coal annually. The coal averages 10,268 BTU per pound of coal and 3.4 percent sulfur. S02 emissions are 6.4 pounds per million BTU of input. Nationwide, Kincaid ranks 14th in tons of S02 emissions. The station is rated modest for FGD retrofit because of its age, cost and availability of space. The mine-mouth coal is supplied by Peabody Coal Company and delivered by conveyor belt. The contract is scheduled to expire at the end of 1992. The Powerton Station is located in north central Illinois, near Pekin. The station consists of two relatively new cyclone units, rated at 1,400 megawatts of capability. The station represents seven percent of the company's total capability. The 5.2 billion kilowatthours of generation accounts for 42 percent of its capability and eight percent of COMED's total generation. The production expense is 3.8 cents per kilowatthour, with fuel at 3.2 cents. Powerton is the second most efficient fossil -fuel station. Powerton purchased four million tons of coal and consumed 3.1 million tons. The coal averages 9,409 BTU and 0.5 percent sulfur. S02 emissions are a little less than one pound per million BTU of input. The Montana 89 coal is supplied by Decker Coal Company, while the Wyoming coal is produced by Big Horn Coal Company and Black Butte Coal Company. All three companies are under contract. The State Line Station is located in northwestern Indiana at Hammond. The station consists of one cyclone unit and one pulverized coal unit. The 490 megawatts of capability represents three percent of the company's total capability. The two billion kllowatthours of generation accounts for 48 percent of its capability and three percent of COMED's total generation. The production expense is 3.8 cents per kilowatthour, ranking third in economic efficiency. State Line purchased 1.4 million tons of coal and consumed 1.1 million tons. The coal averages 9,481 BTU per pound of coal and 0.4 percent sulfur. S02 emissions are 0.9 pound per million BTU of input. The Montana coal is supplied by Decker Coal Company, under contract. Refer to Map 6-1 for the location of this station. The Waukegan Station is located in Waukegan, at the northeastern tip of Illinois. The one cyclone unit and two pulverized coal units are rated at 725 megawatts of capability, or four percent of COMED's total capability. The station produces four percent of COMED's generation with 2.3 billion kilowatthours. This figure also represents 36 percent of the station's capability. The 4.5 cents per kilowatthour ranks fourth 1n economic efficiency. The 1.3 million tons of coal purchased and consumed averages 9,502 BTU per pound of coal and 0.5 percent sulfur. The S02 emission rate is slightly less than one pound per million BTU of input. The Montana coal is supplied by Decker Coal Company, while the Wyoming coal is produced by Big Horn Coal Company and Black Butte Coal Company, all three under contract. The Will County Station is located in northeastern Illinois, near Lockport. The station consists of two cyclone and two pulverized coal units. Its capability 1s 1,060 megawatts, representing six percent of COMED's total capability. Will County's generation of 3.2 billion kilowatthours represents 35 percent of the station's capability and five percent of the company's total generation. Will County ranks fifth in economic efficiency at 4.5 cents per kilowatthour. Will County purchased 2.2 million tons of coal and consumed 1.8 million tons. The coal averages 9,532 BTU per pound of coal and 0.5 percent sulfur. S02 emissions are 0.9 pound per million BTU of input. The Montana coal is supplied by Decker Coal Company, while the Wyoming coal is produced by Big Horn Coal Company and Black Butte Coal Company, all by contract. The small quantity of Illinois coal is supplied by Peabody Coal Company, by contract, and transported by rail carrier. 90 Jllrt o z O CO o O Z H- O '«-' O CO \ o co o t- co o CO >- co o O CO z o NOm I l-i < m o h- 10 UJ 00 00 lu en JZOH a. m x < — i w o x i- »- s 2 o LU O Z O LU w C9 2 Z C9 O o o LU a: i— i u. i Z CO = < co a. < o < co r*» ■ CO ■ ■a- ■ en i en ■ f-» ■ co ■ CO ■ 00 ■ m | o ■ — • ■ co ■ *r ■ co ■ CD H — • ■ CM ■ CM ■ CO ■ CO ■ CO ■ m | CM ■ CO ■ CO ■ ^ i COAL COAL i a. a. 213.0 319.0 O 1 CM ■ CO I CO ■ 1958 1961 ■ r*» oo is ■ o ■ u_ si ■ o — 1 I < 1 H- ■ O 1 I- ■ CM 00 o z CO z co en o co < CO CO CO CO en en O — I I —> r^ >• co t— z •-• © < o => o ao o co o co en m en CM en oo < a. o 3 O CO o o >- 91 — 1 z co < => z o to o o z I— o ««— o oa O co i >■ Si o Ul o z o LU w (0 I- UJ m a. z >■ 3 -«^ < o UJ UJ I S3 O h- o « ^—' z CM •— i I W z o UJ •-■ CO < < I- h- to ■ en u <£> U * H * M en u CO H ■ to H» Z •-« o =3 O oo - CO en co co • co CO CO CO o m CO en o o < O h- * CO "^v O cO O c- I >■ < _J *~ h- t- S 2 O Ul o z o Ul w C9 UJ _J Z« to < co < < < o o o o o o >- o o o a> a. o o o • • • cm en co 0»0>H cm >* m en in co in co co en en en co h« co o •"3 en in CM m CM co co oo co o 00 en co en en o CO en o co u II 3 II II t- II 00 CO CO II CNJ 00 II co co CO II o z II co en en II CO z II • • • II "V. 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II M ii o II Ul >—> 1 i _j i | 3 M _l 1 M 1 1 Ul _ I II _l ii 2 II _i 1— 1 i < i i _i a. i 1 t- 3» < 1 ►- 1 1 ;3 < II _l a. n — i II 00 < 1 i > i I < a. i H- 1 < 1 1 2 h- ■ «C o- ii —J II ■X 1- 1 i < i I © ZS I 1 Ul • O 1 t- 1 1 UJ O II O =1 n _l II H- tO 1 1 SC 1 i o to 1 1 * 3 »- 1 to 1 1 X I h- II o to ii 1—4 II 105 z © in O I I-. ■ Ul -— . 1 CM ■ JZt^ 1 CO ■ O Z 1 •> ■ O "•«». 1 ^ | CM ■ W i 1 ^ < >-^ 1 a=«^ i cn ■ < -J w i r^ ■ o *-« 1 as z— « ! 00 1 O Z 1 00 1 «-* 2 1 •— < ■ ZtfO 1 00 I « 1 Ul O 1 CM 1 Z O 1 « 1 Ulw 1 <-* 1 ca -j i 1 _* _l UJ 1 1 < < ^3 1 1 o o U. 1 1 o o H- Ul I •-4 a. i 1 o o Z >- I i a. a. 3 f- 1 art 1 o o O 1 Ul _J *~s 1 1 • • 1 Z ^* 3 1 I *r r«* »-< ■ ZfiZ 1 I f* o 1 00 ■ 3 < w i i «— « r-t | t/> O. 1 < u Ul 1 I m 1 1 > 1 1- > CM O >- CO H- Z ■■*© < o 3 O cro O 3 o 4.518 2.666 cn ■ CM ■ •-< H * 1 1.258 1.140 CO I CO 1 CM 1 «— « > 27.24 24.01 m ■ m ■ g «o ■ CM ■ 11.66 12.01 * 1 r>» ■ >— « ■ 2.51 1.44 00 1 CM ■ H CM ■ 10,833 10,533 00 1 z o o o a: »- o — ' o O CO a. •-! x < -j w 00 O X m 2 h- »-* Qj o z o uj — , «0 teas OO o- o h- o «— ' 3g ^3 co 1—1 1 z O UJ >— < _J h- CO < < t- h- CO oo a en ■ o ■ — n «* ■ co ■ m ■ co a o ■ CM 1 CO ■ CM ■ 00 1 LO II »"4 II ■— « a «3- ■ I-" • a CO ■ o ■ m H 00 ■ CO ■ r*. ■ m | »— • 1 COAL COAL 1 o o 1 Q. 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Ql *3 cr 0) - OO u I— Z II CM 1— 1 O H • I— I— ■ o Z M «-< < O » r«. 3 o a 00 ■ QC H II U (/) II N w I — II O II -J ■ Z I _i a. 11 1— 1 u II •— i M 115 UJ *—» JZtf) O Z O t/> o O Z h- O *-^ CJ I— i* CO "^ O CO I >■ Ck t=« *? o « t- h- M £ o UJ o z o UJ ^ o Z 00 =» < a. < o o o CJ I co o ■ •-• I- < CO o ■ O I O H ** N 00 ■ r*» i O 1 O 1 CM I m | O 1 ^ i CO ■ CO ■ 1 < > oo i r»» ■ co 1 CO 1 m | CM 1 CM I COAL COAL ■ o o 39.8 39.7 to 1 en ■ 1961 1965 1 UJ ■ Q 1 ■ <— 1 ■ CO I 1 UJ 1 ■ ^ 1 u < 1 -J —i a < ■ H- ■ O ■ CM O CO z CO < CO Ul O — I ■ ^ ~* ^ CO H- Z •-• o < o s o < Q. O 3 O CO o> m en in CM cn • CM CO cn cn CO • CM CO CO m o CO o CO CO ec aL ^3 ^3 o o z z h- h- H- H- < < o o co co _i _l t- H- ■—1 M H- H- ^ *£ < < CO CO ^B 3 Z Z ^2 Z — « »>h O CO CD 00 00 • . m m ^- co r*«. p*. co co CO ^ 00 00 . . H- CO i-i UJ -J CO >- 00 z »- < o n* o_ at — i < => i— • o fl- ea < o — i o_ UJ < o o o o »- O H- CO UJ CO < ce •• <. => z c2 O. O UJ '- , z —J I— UJ O UJ Q z uj co uj cc i— i O "— ' o u_ Z -J i -JI-< —I o o — . h- (J 116 CHAPTER SIX INDIANA Indiana electric utilities purchased approximately 37 million tons of coal; 0.3 million barrels of petroleum and 0.9 billion cubic feet of natural gas in 1986. Coal represented five percent of U.S. utility coal purchases, while petroleum and natural gas were only negligible. Indiana utilities purchased four percent of the nation's total energy. Table 6-1 lists the fossil-fuel receipts for Indiana electric utilities. TABLE 6-1. INDIANA FOSSIL-FUEL SOURCES FOR ELECTRIC GENERATION. FUEL QUANTITY (000) BTU (BILLION) % OF TOTAL $/UNIT J/MMBTU COAL PETROLEUM NATURAL GAS 36,890 tons 335 bis. 891 mmcf. 787,903 1,935 896 99.7 .2 .1 33.70 22.48 4.56 1.58 3.89 4.54 TOTAL 790.734 100.0 Indiana has five investor-owned utilities, 72 municipal systems, 44 rural electric cooperatives and one state system, electricity are Indiana and Michigan Electric Company of Indiana, Northern Indiana Public Energy Rural Electric Cooperative Incorporated, Electric Company, and Wabash Valley Power utilities account for nearly 90 percent generation. The major suppliers of Company, Public Service Service Company, Hoosier Southern Indiana Gas and Association. These six of Indiana's electrical Indiana electric utilities have 19,276 megawatts of capability. This capability consists of 18,330 megawatts of coal -fired; 662 megawatts of petroleum- fired; 210 megawatts of natural gas-fired; and 74 megawatts of hydro. Indiana's total capability represents three percent of the U.S. total. Of the 44 states that have coal-fired generation, Indiana ranks second in coal -fired capability, behind Ohio. 117 Table 6-2 provides a breakdown of the various fuel types by capability, number of units, percent of Indiana's total capability and percent of U.S. total capability. The U.S. total is shown as the percent of Indiana's fuel type to the U.S. total for the same fuel type. For example, the 18,330 megawatts of Indiana coal capability represents 95 percent of Indiana's total capability and six percent of the total U.S. coal -fired capability. TABLE 6-2. INDIANA SUMMER CAPABILITY. TOTAL COAL TYPE OF CAPABILITY NATURAL PETROLEUM GAS MEGAWATTS 19,276 18,330 662 NO. OF UNITS 153 83 40 X OF IN TOTAL 100 95 3 % OF U.S. TOTAL 3 6 1 210 10 1 WATER 74 20 Indiana will add one new coal -fired unit in the near term. The unit is owned by Indiana and Michigan Electric Company, which is a subsidiary of American Electric Power Company. Table 6-3 details the Rockport station. TABLE 6-3. FUTURE BASELOAD CAPABILITY IN INDIANA. STATION CAPABILITY UTILITY AND UNIT fMVO FUEL INDIANA AND MICHIGAN ELEC. Rockoort 2 1.191 ON LINE Coal 1988 Net generation by Indiana electric utilities totals 77 thousand gigawatthours, a decrease of two percent from 1985. Almost all of this generation is derived from coal. On a national basis, Indiana accounts for three percent of total generation and ranks tenth in statewide generation. Indiana utilities produce six percent of the nation's total generation. Table 6-4 details Indiana's generation by fuel type. 118 TABLE 6-4. INDIANA NET GENERATION. TOTAL COAL TYPE OF CAPABILITY NATURAL PETROLEUM GAS WATER GIGAWATTHOURS 77,342 76,446 % OF IN TOTAL 100 99 % OF U.S. TOTAL 3 6 295 96 506 1 Indiana utilities purchased 37 million tons of coal in 1986. This coal is supplied by eight coal producing states. Indiana coal producers supply about 50 percent of the total. The sulfur content varies from 0.3 percent to 3.5 percent, with an overall average of 2.4 percent. The BTU content varies from 8,252 to 12,630, with a weighted average of 10,679. On a BTU cost basis, Ohio coal has the lowest delivered price at $1.16 per million BTU, while Colorado coal is the most expensive at $2.91 per million BTU. All of the low sulfur coal receipts are from the western United States. Table 6-5 lists the various coal supplying states, or regions and their respective quantities and qualities of coal sold to Indiana utilities. TABLE 6-5. INDIANA COAL SUPPLIERS. TONS % OF % STATE/REGION (0001 TOTAL BTU/LB SULFUR $/T0N $/MMBTU INDIANA 17,639 48 11,048 2.80 29.66 1.34 ILLINOIS 10,214 28 10,751 2.68 35.89 1.67 WYOMING 4,069 11 8,252 .33 35.33 2.14 W. KENTUCKY 2,330 6 11,657 3.45 28.20 1.21 MONTANA 1,384 4 9,481 .43 53.93 2.84 E. KENTUCKY 616 2 12,593 1.07 53.61 2.13 COLORADO 325 1 11,461 .49 66.76 2.91 W. VIRGINIA 282 -- 12,630 1.52 49.29 1.95 OHIO 31 -- 11.419 3.30 26.46 1.16 TOTAL/AVERAGE 36.890 100 10.679 2.39 33.70 1.58 Illinois coal suppliers sell about ten million tons of coal to three Indiana utilities. This coal represents 28 percent of Indiana's total utility coal receipts. Public Service Company of Indiana is the largest user with 6.4 million tons. Northern Indiana Public Service receives about three million tons and Hoosier Energy Rural Electric Cooperative purchases one million tons. However, the Hoosier coal contract expires in 1987. Illinois coal sales, quality of coal and delivered prices to 119 Indiana, for the period 1981 through 1986 are shown in Table 6-6. Since 1981, Indiana utilities have increased their Illinois coal receipts by five million tons. TABLE 6-6. INDIANA S ILLINOIS COAL PURCHASES AND DELIVERED PRICES 1986-1981. YEAR 1981 1982 1983 1984 1985 1986 THOUSAND TONS 5,102 7,152 6,967 9,958 8,952 10,214 PERCENT SULFUR 2.60 2.50 2.50 2.70 2.60 2.68 BTU/LB 10,629 10,621 10,723 10,773 10,757 10,751 $/T0N 32.04 33.83 33.54 34.80 35.39 35.89 J/MMBTU 1.51 1.59 1.56 1.62 1.65 1.67 A discussion of the three Indiana utilities that purchase Illinois coal follows. Map 6-1 shows the location of the Indiana coal -fired generating stations discussed in this chapter. For a discussion of the State Line station, see Commonwealth Edison Company in Chapter 5, Illinois. 120 MAP 6-1 COAL FIRED GENERATING STATIONS INDIANA * y i c h i gon City I *Boi I #y Ui t che I I State Line *Schahf er ' Cayooo ■ Nobel sv i I I e • ILLINOIS COAL 121 HOOSIER ENERGY RURAL ELECTRIC COOPERATIVE Hoosier Energy Rural Electric Cooperative Incorporated is located at Bloomington, Indiana. The Co-op is involved in the generation and sale of electricity in. 47 southern Indiana counties. Hoosier sells electricity to 19 member cooperatives. Electric sales are about five billion kilowatthours, with a value of $200 million. Hoosier ranks fifth in statewide utility sales. The Co-op employs 455. Hoosier has two coal -fired generating stations, located in southwestern Indiana. These stations have a total capability of 1,154 megawatts, representing six percent of Indiana's coal -fired capability. The cooperative generates about five billion kilowatthours, annually. Statewide, this accounts for six percent of total generation. The Co-op has electrical interconnections with Public Service Company of Indiana, Southern Indiana Gas and Electric Company, Indianapolis Power and Light Company and Big Rivers Rural Electric Cooperative. Information concerning the miles of power lines is not available. Hoosier purchased 2.4 million tons of coal in 1986. One Illinois coal operator supplies one million tons, or 42 percent of its coal demand. Hoosier's Illinois coal receipts represent three percent of total coal purchases and ten percent of Illinois coal purchases by Indiana utilities. Table 6-7 details Hoosier's Illinois coal purchases since 1983. As shown in the table, Hoosier has increased its Illinois coal receipts from 0.4 million tons to one million tons since 1983. However, the contract for Illinois coal is terminated in 1987. TABLE 6-7. HOOSIER'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS PERCENT SULFUR BTU/LB S/TON S/MMBTU 393 561 967 1,002 2.91 2.91 3.04 3.19 11,117 11,033 10,761 10,584 39.37 41.36 43.64 43.08 1.77 1.87 2.03 2.04 123 The Merom Station is located in southwestern Indiana at Sullivan. The station consists of two new pulverized coal boilers with capability of 920 megawatts. The station represents 80 percent of Hoosier's total capability. Merom' s generation of 3.5 billion kilowatthours represents 56 percent of the station's capability and 73 percent of Hoosier's total generation. No figure is available concerning the cost per kilowatthour of generation. The station purchased and used approximately 1.8 million tons of Illinois and Indiana coal in 1986. The coal averages 10,827 BTU per pound of coal and 3.4 percent sulfur. Freeman United Coal Mining Company supplies the Illinois coal under contract, with transportation by rail. The contract terminates in 1987. Amax Coal Company and Solar Sources, Incorporated are the major Indiana coal suppliers, by spot market. Merom utilizes two limestone FGD systems rated at 460 megawatts, each. These systems remove up to 90 percent of the S02 emissions, with an emission rate of 1.2 pounds per million BTU of input. No figures are available concerning the capital cost and operating expense of the FGD system. The Ratts Station is located in southwestern Indiana at Petersburg, on the White River. The station consists of two pulverized coal units with a capability of 234 megawatts. Units 1 and 2 are each rated at 117 megawatts. The station represents 20 percent of Hoosier's total capability. Ratts' generation of 1.2 billion kilowatthours represents 60 percent of the station's capability and 26 percent of Hoosier's total generation. No figure is available on the cost per kilowatthour of generation. Ratts' received and consumed approximately 0.6 million tons of Indiana coal in 1986. The Indiana coal reserves are owned by Hoosier and operated by an independent coal producer. The coal averages 11,098 BTU per pound of coal and 2.7 percent sulfur. S02 emissions are 4.8 pounds per million BTU of input. The station ranks 94th in total tons of S02 emissions. Ratts' is rated as modest to be retrofitted with FGD because of age and availability of space. 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Z *— ' UJ o CO 1 < 1 X 1 1 CO CO CO 1 CO CO Ok 1 • • • IOION 1 •-* • o u. CO 1 1 Cn CO CO 1 ^ CM CO 1 • • • 4-» ** i o co o *5 Ctt « U to 00 >- CO I— z i-i o < o 3 O 0*0 (A 3 O 3 O CO * co en ao i»* en • • • O CO O co ^- oo cn co co • • • CM ^-i CM CO O CM r-» o co • • • CO O O CO ^ CO co o en *r cn cm • • • .—i o <— < CO •-« CM • • • CO CM CM CM «* O CO CO CM O CO Q «— CJ o *-> z — I —i o O -I >- o •-■ 2 o CO o en CM CM CM GO 00 • CO CM o co CM CO o CO cn co CO < O co co o o < < o o CO CO -J -J h- h- z z :*: ^ • 9. «C • • CO CO CO CM CO 00 H- CO ■-* UJ -J CO • c 1—1 < >CDZ h- < O •-• CL Q£ -J — o 132 PUBLIC SERVICE COMPANY OF INDIANA Public Service Company of Indiana (PSIND), headquartered in Plainfield, Indiana, is engaged in the production, transmission, distribution and sale of electricity to more than 700 cities, towns and unincorporated communities in northcentral , central and southern Indiana. The company's service area includes 69 of the 92 Indiana counties. PSIND serves about 0.6 million electric customers. It also wholesales electricity to 43 municipalities and 16 rural electric cooperatives. The economic base of its service area consists of agriculture and diversified industry. PSIND employs about 3,000. Electric sales are approximately 18 billion kilowatthours, with a value of one billion dollars. Total kilowatthours sold ranks PSIND as the largest Indiana electric utility and the 35th largest, nationally. PSIND has six coal -fired generating stations, located throughout central and southern Indiana. The capability of these stations total 5,249 megawatts, or 95 percent of PSIND' s available capability. The remainder consists of oil and hydro units. The coal -fired capability further represents 27 percent of the state's total capability. Public Service Company of Indiana has 23,511 miles of above ground lines and 2,203 miles of underground lines. The company has electrical interconnections with Indianapolis Power and Light, Kentucky Utilities Company, Northern Indiana Public Service Company, Louisville Gas and Electric Company, Cincinnati Gas and Electric Company, Indiana and Michigan Electric Company, Southern Indiana Gas and Electric Company, Central Illinois Public Service Company, East Kentucky Rural Electric Cooperative and the Indiana Association of Rural Electric Cooperatives. PSIND has generation of about 25 billion kilowatthours, with coal accounting for 98 percent of the total. Statewide, this represents 32 percent of total generation. Public Service Company of Indiana purchased 11.2 million tons of coal in 1986. PSIND is the 12th largest user of coal in the United States. Illinois coal producers supply 6.4 million tons, or 57 percent of its total coal demand. The Gibson station uses 97 percent of the Illinois coal. PSIND is the third largest consumer of Illinois coal. Since 1983, the company has increased its demand for Illinois coal by 40 percent, while the delivered price has only increased by ten percent. Table 6-11 shows PSIND's Illinois coal purchases since 1983. 133 TABLE 6-11. PSIND'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS 4,610 6,027 5,748 6,444 PERCENT SULFUR 2.31 2.42 2.32 2.40 BTU/LB 10,674 10,645 10,630 10,640 $/TON 30.10 30.62 31.36 32.72 S/MMBTU 1.41 1.44 1.48 1.54 The following paragraphs discuss the six coal -fired stations operated by PSIND. Table 6-12 at the end of this narrative provides additional data on these stations. Refer to Map 6-1 for the locations of these stations. The Cayuga Station is located in west central Indiana at Cayuga, near the Vermilion River. The station consists of two pulverized coal units with capability of 985 megawatts, which represents 18 percent of the company's total capability. It is the second largest coal -fired station owned by PSIND. Cayuga's generation of 5.3 billion kilowatthours represents 62 percent of the station's capability and 22 percent of PSIND's total generation. It is PSIND' most efficient station with a production expense of 1.6 cents per kilowatthour, with the fuel expense at 1.4 cents. Cayuga purchased and consumed about 2.6 million tons of Indiana coal in 1986. The coal averages 10,414 BTU per pound of coal and 2.4 percent sulfur. S02 emissions are 4.5 pounds per million BTU of input. Nationally, it ranks 38th in tons of S02 emissions. Installation of an F6D system is rated modest because of the age of the station and availability of space. The Indiana coal is supplied by Peabody Coal Company under contract through 1993. The Edwardsoort Station is located in southwestern Indiana at Edwardsport. It consists of two relatively old pulverized coal units with capability of 120 megawatts. Edwardsport is the second smallest station in PSIND's system, with two percent of capability. The station's generation of 46 million kilowatthours represents four percent of its capability. No figures are available on the cost per kilowatthour of generation. The 36,000 tons of Indiana coal used averages 10,939 BTU per pound of coal and 2.5 percent sulfur. Edwardsport's S02 emission rate is 4.5 pounds per million BTU of input. No information is available on the FGD cost factor. J and R Coal Company supplies the Indiana coal under contract. The Gallagher Station is located in southeastern Indiana at New Albany. The station has four older pulverized coal units with capability of 560 megawatts, representing ten percent of PSIND's total capability. The 134 station's generation of 1.4 billion kilowatthours represents 29 percent of its capability and eight percent of the company's total generation. Gallagher is the third most efficient PSIND station. The production expense averages 2.4 cents per kilowatthour, with the fuel expense at 1.4 cents. The 0.7 million tons of coal purchased and consumed averages 11,410 BTU per pound of coal and 3.1 percent sulfur. The emission rate for S02 is 5.3 pounds per million BTU of input. Nationally, the station ranks 85th in tons of S02 emissions. The station is rated difficult to retrofit with FGD because of the age of the station and limited space. The three coal supplying states are Indiana, Kentucky and Illinois. The Illinois coal is supplied by Amax Coal Company under contract (August 1993) and Tek Bar Industries by spot market. The coal is transported by rail and barge. The Indiana coal is purchased from Amax Coal Company by contract through August 1993, while the Kentucky coal is received from Kentucky Pyro Mining Company by spot market. The Gibson Station is located in southwestern Indiana near Princeton. It consists of five newer pulverized coal units with capability of 3,140 megawatts. Gibson is the largest PSIND station and one of the largest stations in the nation. Unit 5 is jointly owned with Small Municipal and Cooperative Incorporated. The station's generation of 16 billion kilowatthours accounts for 58 percent of its capability and 65 percent of PSIND's total generation. It is PSIND's second most efficient plant. The production expense per kilowatthour is 1.8 cents, with the fuel expense at 1.6 cents. The 7.4 million tons of coal used averages 10,727 BTU per pound of coal and 2.4 percent sulfur. Illinois coal producers supply 89 percent of the station's coal needs, with the balance from Indiana. The Illinois coal is supplied by Amax Coal Company and Monterey Coal Company, under contract. Both contracts will expire at the end of 2002. The coal is transported by rail. The Indiana coal is supplied by Old Ben Coal Company by contract through September 1990. Gibson's unit 5 is equipped with a limestone FG0 system. The system was started in 1982 and is capable of removing 86 percent of the S02 emissions. No capital cost, or operation and maintenance expenses are available. The station's overall S02 emission rate is 3.8 pounds per million BTU of input, with Unit 5 at 1.2 pounds. Nationally, Gibson ranks fourth in tons of S02 emissions. Units 1 through 4 are rated as easy to retrofit with FGD because of the age of the station, unit size and availability of space. The Noblesville Station is located in central Indiana at Noblesville. The station has two older pulverized coal units with capability of 90 megawatts. The station's generation of 5.5 million kilowatthours represents one percent of its capability and accounts for only a negligible percent of the company's total generation. No cost figures are 135 available on the station. The 6,000 tons of coal burned averages 10,940 BTU per pound of coal and 4.1 percent sulfur. S02 emissions are 7.3 pounds per million BTU of input. The Indiana coal is purchased from the Whole Nine Yards Coal Company, by spot market. The Wabash River Station is located in west central Indiana at Terre Haute. Wabash River has six older pulverized coal units with capability of 753 megawatts, representing 14 percent of PSIND's total capability. The station's generation of 1.3 billion kilowatthours represents 20 percent of its capability and five percent of the company's generation. Wabash River's production expense is 2.6 cents per icilowatthour, with the fuel expense at 1.8 cents. Of the PSIND stations with cost figures, Wabash River is the least efficient. The 0.7 million tons of Indiana coal purchased and consumed in 1986 averages 10,937 BTU per pound of coal and 2.1 percent sulfur. S02 emissions are 3.8 pounds per million BTU of input. Nationally, the station ranks 78th in tons of S02 emissions. Retrofitting with an FGD system is rated difficult because of age, size and limited space. The major Indiana coal suppliers are Peabody Coal Company and Amax Coal Company, both by contract. 136 <: r> z o on o <_> Z I— u o M < H- z < < h- l-N «/> a z o ~3i u. O - o i— i z >— • i CO -iu en CO C3 «-• z UJ o o I >- Q. nn X < -I w O X I- r- * 2 O LU O z o UJ >-^ C3 z SO z < UJ Z •— « O -J < O 1 O I O ■ co ■ ^- ■ CO ■ CM 1 00 ■ ■ ■ m | ■ •— • ■ 00 1 10 ■ »-« ■ en ■ LO ■ »-* ■ CM I to ■ CO ■ O ■ CM ■ • 1 00 I CM I CO ■ IA 1 COAL COAL ■ 00 M Q. Q. 500.0 485.0 O 1 • | 1 m 1 1 00 ■ en 1 1970 1972 I r-« CM ■ < ■ >- ■ < ■ O -J ■ < ■ 1 h- ■ 1 O ■ 1 H- ■ CM O CO CO < o CO en CM CO CO • CM •— 1 CM • CM >- c/> t- z ~ o 3 O CO _l Q. < Q. O =♦ 00 CM CM < 137 o o CVJ co I o O 11 UJ *~*. 1 O H — J Z «fl i O M 1 Z H °£ ! UJ 1 O 1 x j H < ■ ^ 1 i "*«*» 1 z ■ w> 1 1 >- < H- ^ 1 Q. f-i X 1 * 1 «C -1 w | O »-> 1 CD z--» ! 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CM CM CM CM to 10 o o < k- o I- *: to ^%. o to cj H- < k-^» Q. — i ** o z s o UJ o z o UJ «— ' C9 to a. < O — I < r- to < < o o o o o o o o • • to co o o to to Ok Ok ^h CM I to CO —I o ■-» o o o to CM CO o z to z 00 I N II o II O) II CM II u ro- il II 1—1 •I to o Ok < k- o to < to 03 >- to t— z •-• o < o =0 O OO UI O 3 o to II II II II II II II to II O II II CO II II • II 1-H II II II I I II to II to II • II 00 II CM H II ■ II I II o ii r»» II U CM S3 II ~* II II II II u II Ok II no ii II • II II o- II II II II II u II o ii «r II Ok II -II II o II -* II I N II II Ok II • u ** II II a II a II n ■ II < II z ii <: II -+ II Q II Z U i-i 139 JZV) < => z o - Q. « *< <_l w CO OS* zao UJ o z o UJ w CO Ul o o CM I— I CO < CO <<<<<< o o o o o o O O O o o o m o CO co CM CO CO o CM CO CM CO 00 «*■ CO CO m O CM CO o z CO Z o CO < CO >- CO »- z < o 3 O o-o -J a. < Q- O 3 O CO 00 en co CO CO CM o CO CM CO CO i— i CM CO en co oo oo z < 1—1 a CO CO O O < < o o —1 -J CO CO CO CO ■-* —> h- t- z z ** tt ►- 1- o o < < t- I- z z 2 2 O O < < O O i-i ■"• OOOOJJ UJ LU CM UO _! _) £ 3E * •> •—* ■- • O CO CO CO «f cr> in ^f CO CM « « • • WlflH CM CM >- CO I- < -J z o to o tr» vi (/> o o CO o o o o CO o o o 144 EASTERN IOWA LIGHT AND POWER COOPERATIVE Eastern Iowa Light and Power Cooperative provides electrical service to about 19,000 customers in eastern Iowa. Its annual sales are approximately 0.3 billion kilowatthours, with a value of $21 million. The cooperative is headquartered in Wilton, Iowa. The co-op owns one coal -fired generating station with 65 megawatts of capability. The station is operated by Central Iowa Power Cooperative. This capability represents one percent of Iowa's coal -fired capability. The co-op's generation of 0.3 billion kilowatthours represents one percent of Iowa's total generation. Eastern Iowa Light and Power Cooperative purchased 124,000 tons of coal in 1986. Illinois coal producers supply 100 thousand tons, or 81 percent of the station's total coal demand. The Illinois coal receipts represent one percent of Iowa's total utility coal demand and five percent of the state's Illinois coal receipts. Table 7-6 details the co-op's Illinois coal purchases for the past four years. As seen in the table, the co-op's Illinois coal receipts have increased by about 35 percent, while the delivered price has fallen by 23 percent. TABLE 7-6. EASTERN IOWA CO-OP'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS PERCENT SULFUR BTU/LB $/T0N S/MMBTU Below is a description of the co-op's one coal -fired station. Table 7-7 provides additional data on the station. For the location of the station refer to Map 7-1. The Fair Station has two pulverized coal units with capability of 65 megawatts. The station's generation of 0.3 billion kilowatthours represents 46 percent of its capability. This generation represents one percent of Iowa's total generation. Production costs are not available, but the fuel expense averages 1.4 cents per kilowatthour. 145 68 96 75 97 2.96 2.88 2.74 2.59 11,119 11,477 11,675 11,554 35.34 28.95 30.07 28.09 1.59 1.26 1.29 1.22 The station used 138 thousand tons of Illinois, Indiana and Kentucky coal in 1986. The coal averages 11,464 BTU per pound of coal and 2.6 percent sulfur. The S02 emission rate is 4.5 pounds per million BTU of input. Because the station is small, no information is available concerning the cost and consideration of FGD retrofit. The Illinois coal is supplied through contract by Reiss Coal Company and Zeigler Coal Company by spot market. The coal is received by rail and barge. The Indiana coal is supplied by Solar Source Incorporated by spot market, while the Kentucky coal is received from Peyton Mining Company. The Fair Station is located in Montpelier. 146 _i r tn oz o co o o z H- o *-^ u I— ^ O CO o h- CO o LU *N > »- ** CO 1— 1—1 2 < LU I— Q. 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O 3 O CO 5.223 4.542 1.636 1.046 36.45 22.82 9.32 9.40 2.96 2.54 11,052 10,906 128.6 2.9 ILLINOIS INDIANA ■ H r»» h O H CM H • H m h I N I I H I II I ■ co ii co co co co CO CO en in en CM m u oo > «»■ ■ O H * H ~* II ^ II n u u LO II • II i— I CO 152 Q 1 O 1 o H H Ul--^ 1 1 O 1 Ul —. 1 o ■ _l Z oo I 1 O 1 -J Z OO 1 o ■ 2 3 Z I 1 O li < = • ■ o oo O I 1 m 1 O 00 O I •-H ■ o Z I— t O «—' 1 o 1 Ol 1 I «o 1 o Z 1— I Ow 1 u en ■ a ■ ■ ■ 3- | = j "^ j 1 * 1 2Z 1 to M ^ 1 i co i ^ 1 CO a i en i ^. 1 «o a 3 1 i •* i 3 1 • a t- l 1 •—> 1 H- 1 o a CO 1 1 •— « 1 CO 1 r— < a a Z 1 Z 1 a a II II 3 j 2 1 a 3 II II 1- ^ 1 1 CO 1 1 *- 1 1 CO o en i H- ^ 1 m a 1— II CM LO CO II wo *^ 1 I ^ 1 CM a CM CO II cn co m II o • 1 * 1 1 O Z 1 1 CO ^ 1 i»» i O OO 1 • a O 2 II CM CO t—* II O H- 1 1 CO 1 1 WO Z 1 1 • • • | O H- 1 CM a tO 2 II • • • II ^ 1 1 CM CM CM 1 a -^ M in «* m II UJ 1 1 CO 1 Ul 1 a CO II II O 1 -J 1 O 1 a a a _l H II II II II II *y 1 i w i *» 1 l»* a II II ^ 1 i •—* i ^ 1 r*. a II II \ 1 1 CM 1 ^^ 1 f^ a II II V*- 1 3 | +*■ 1 a a 3 II II II II 1 >■ i H- 1 i in en (O 1 1 >- a t- II r^ «-• o II < >-"^. i 1 CO 1 1 m lO 5 1 1 h* 1 Z 1 i to r»» m 1 1 O- « i< 1 en a ^^* II 10 o in II < -J •—< 1 I t-^ 1 Z 1 i * * • 1 1 < -J <— - 1 ^ , a z II • • • II o CO O Z 1 1 CM 1 1 . 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I < _i o. II M »-H i < II CO < 1 1 X 1 i < a. i i a z i H- 1 < 1 o. I t- z O o o o o o U1N00O • • • • *ono HHfOU) CM OOCANN en en en en «-• cm co ^ , M CO o o o m en CO CO CO en co CM CO co CO CM CO CO CM O CO O CM O CO o co < CO >- co t- z i-i o <: o 3 O ao _i a. -^ < <: o o — i — i ts C3 en co _j _j UJ LU •k * M* ►— Z Z a c :r :r en cm co oo co co co co r-« CO m • . oo oo f^ CM CM \— CO i—. UJ _i co .. >-^ < >or c- < O ■— a. a: 1-4 O O. CQ <: a — i a.uj< o CO UJ co a: •• ■< 3Z£ ex. O UJ •-• z -J h- LU O UJ Q Z UJ CO UJ Of w O ■— u. o u. —J i —1 Z —I I <: —i <: ~ <: —i »—<»--!»—< O O O — I O O »- O H- •— I— O 154 IOWA ELECTRIC LIGHT AND POWER COMPANY Iowa Electric Light and Power Company, headquartered in Cedar Rapids, Iowa, is a public utility engaged in the production, purchase, transmission, distribution and sale of electricity, and the sale of* natural gas in 55 Iowa counties. The company has 0.2 million customers in 392 communities and an extensive rural area. The population is about 0.8 million. Other electrical sales are to 28 municipalities and one private utility. It also sells steam/hot water service to about 300 customers in Cedar Rapids. The economic base of its service territory consists of agriculture and diversified industry. The company employs 1,500. Electric sales are approximately 4.3 billion kilowatthours, with a value of $284 million. Total kilowatthours sold ranks Iowa Electric as the second largest Iowa electric utility and the 85th largest, nationally. Iowa Electric has three coal -fired generating stations located in east central Iowa. The company also owns 15 percent of Iowa Southern Utilities Company's Ottumwa coal -fired station (101 megawatts), and 70 percent of the Duane Arnold Energy Center (350 megawatts of nuclear capability) which it operates. Iowa Electric's total capability is 880 megawatts, with the coal -fired capability representing 53 percent of the total. Most of the remainder is nuclear. The coal -fired capability represents eight percent of Iowa's coal -fired capability and six percent of the state's total capability. Iowa Electric has 3,096 miles of above ground lines and 1,635 miles of underground cable. The company has electrical interconnections with Iowa-Illinois Gas and Electric Company, Iowa Public Service Company, Iowa Power and Light Company, Corn Belt Power Cooperative and Iowa Southern Utilities Company. Iowa Electric has generation of 4.3 billion kilowatthours. Of this, coal accounts for 1.3 billion kilowatthours, or 30 percent of the total, with most of the balance from nuclear. Iowa Electric's generation represents 18 percent of Iowa's total generation. Iowa Electric purchased 704 thousand tons of coal in 1986. Of this total, Illinois supplies 491 thousand tons, or 70 percent. The Prairie Creek station receives 81 percent of the Illinois coal. The company's Illinois coal receipts represent four percent of Iowa's utility coal purchases and six percent of all utility coal purchases in Iowa. Table 7-10 lists Iowa Electric's Illinois coal purchases for the last two years. No Illinois coal sales were made prior to 1985. Since 1985, the company has decreased its Illinois coal receipts by 25 percent even though the delivered price has stayed the same. 155 TASLE 7-10. IOWA ELECTRICS ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1985 AND 1986. YEAR 1985 1986 THOUSAND TONS 656 491 PERCENT SULFUR 2.35 3.02 BTU/LB 11,520 11,719 $/TON 32.15 33.02 S/MMBTU 1.40 1.41 The following paragraphs discuss Iowa Electric's three coal -fired stations. For a discussion of the Ottumwa station, see the section on Iowa Southern Utilities Company. Table 7-11 details the coal -fired generating stations and provides systemwide data. The Prairie Creek Station is located in east central Iowa at Cedar Rapids. The station consists of four pulverized coal units with capability of 228 megawatts. Units 1 through 3 are operated by Iowa Electric but owned by Central Iowa Power Copperative. Unit 4 represents 15 percent of the company's total capability. Prairie Creek's generation of 0.7 billion kilowatthours represents 35 percent of the station's capability and 16 percent of Iowa Electric's total generation. The production expense is not available, but the fuel expense averages 1.6 cents per kilowatthour. Prairie Creek used a total of 334 thousand tons of Illinois and Missouri coal in 1986. The coal averages 11,697 BTU per pound of coal and 2.2 percent sulfur. S02 emissions are 3.7 pounds per million BTU of input. No data is available concerning the cost and consideration for FGD retrofit. Old Ben Coal Company supplies the Illinois coal under contract. The coal is received by rail. The Missouri coal is supplied by Missouri Mining Company by contract. The Sixth Street Station is located in east central Iowa at Cedar Rapids. It consists of six older pulverized coal units with capability of 85 megawatts. Sixth Street is the smallest station in Iowa Electric's system. The station's generation of 71 million kilowatthours accounts for ten percent of its capability and a minimal amount of Iowa Electric's total generation. The cost per kilowatthour of generation is 6.6 cents, with the fuel expense at four cents. The 69,000 tons of Illinois coal used in 1986 averages 11,724 BTU per pound of coal and 2.2 percent sulfur. Emissions of S02 are 3.7 pounds per million BTU of input. The Illinois coal is supplied by Old Ben Coal Company under contract and received by railroad. 156 The Sutherland Station is located in east central Iowa at Marshall town. The station has two pulverized coal units and one cyclone unit, with capability of 144 megawatts. The capability represents 16 percent of the company's total capability. The station's generation of 0.5 billion kilowatthours represents 39 percent of its capability and 12 percent of the company's total generation. The production expense is not available, but the fuel expense averages 1.6 cents per kilowatthour. The 269,000 tons of Illinois, Iowa and Missouri coal burned in 1986 averages 11,438 BTU per pound of coal and 2.3 percent sulfur. S02 emissions are 4.3 pounds per million BTU of input. Nationally, the station is ranked 176th in total tons of S02 emissions. Sutherland is rated difficult for FGD retrofit because of age, size and limited space. The Illinois coal is supplied by Midland Coal Company and Old Ben Coal Company, both by contract. The coal is received by rail. 157 — J x co o z o WO o O Z I— O •w u 3 CO ^ O CO CJ I— CO o M h- >■ CO z »- • < H- a. < Z h- O CO o o cc z UJ < 2 O CO a- Z o Q « HZh -«<< I h- r»» *— co co X 00 uao9< _! ■— < Z ■— t 00 -J « < h- •"^S 0£ UJ >- Z O UJ UJ o < _l w O Z 2 o UJ o z o UJ w (0 UJ Ul < a* 2 •"* O U. —* i o o UJ — J *—. Z 00 z co a. o UJ z *^ O -J CO < < < < o o o o o o o o o o o o a. Ok a. ol o o o o .... cm cm en m CM CM ^ CO O ^ 00 r*. in m en co en en oi en »-* CM co * * * * cc ^ 2 o o o CO CO CO CO m co co ao oo CM CM < © CM CO o z CO Z > 10 s. 41 a. o o o o - CO h- Z •-• o < o 3 O o*o O CO ■ •-■ 3.660 4.016 h en •— • i ■ o r«* i i«n i H • * 1 33.02 30.63 ■ ^ m i ■ 00 CO 1 H • • | ISO i 2.20 2.30 11,721 11,168 400.0 18.0 ILLINOIS MISSOURI II M * H CO II (O H CO o CO CO CM CM H I N II H CM H en h • H CM II CO H I N r»» ii en ii co u • H t-H II ^H II ii u H O II • II oo n •-* u * H II ■ ■ II ■ II ■ y I N ii ii u H II I 158 < =3 Z O oo O O Z I— O w O ►- * co *>^ o CO o I >- a. « ^ < — l w I- H- tt 2 O LU O z o LU w CO LU CO O —I < co <<<<<< o o o o o o o o o o o o o o o o o o a. a. o. o. o. a. o o o o o o CAPABI! 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QC —I «t 3 NN O O- CO < a — i a.u< < — I -IH< —I O O 160 IOWA -ILLINOIS GAS AND ELECTRIC COMPANY Iowa-Illinois Gas and Electric Company (IIG&E) is a combination utility involved in the production, purchase, transmission, distribution and sale of electricity, and sale of natural gas. It sells electricity in five districts in east central Iowa and one district in northwestern Illinois, with a population of more than 600 thousand. The economic base of its service territory consists of agriculture and industry. IIG&E serves about 190 thousand electric customers. The company employs approximately 1,500. IIG&E is headquartered in Davenport, Iowa. Electric sales are about four billion kilowatthours, with a value of $275 million. Total kilowatthours sold ranks IIG&E as the third largest Iowa electric utility and the 86th largest U.S. electric utility. IIG&E has two coal -fired generating stations located in eastcentral Iowa, and partially owns four coal -fired generating stations and one nuclear station. The four partially owned coal-fired stations include: 29 percent (149 megawatts) of Iowa Public Service Company's Neal Station Unit 3; 19 percent (125 megawatts) of Iowa Southern Utilities Company's Ottumwa Station; 32 percent (227 megawatts) of Iowa Power and Light Company's Council Bluffs Station; and 43 percent (280 megawatts) of IIG&E' s Louisa Station. The Louisa Station is operated by IIG&E. The company owns 25 percent (385 megawatts) of Commonwealth Edison Company's Quad Cities Station, which is nuclear. IIG&E's capability totals 1,339 megawatts. Of this capability, coal -fired totals 954 megawatts, or 71 percent of the total. Most of the remainder is nuclear. The coal -fired capability represents 16 percent of Iowa's coal -fired capability and 12 percent of the state's total capability. The company has 14,300 miles of above ground lines and 1,100 miles of underground cable. The company has electrical interconnections with Iowa Public Service Company, Iowa Electric Light and Power Company, Commonwealth Edison Company, Corn Belt Power Cooperative, Central Iowa Power Cooperative, Illinois Power Company, Union Electric Company, Iowa Power and Light Company, Interstate Power Company, Iowa Southern Utilities Company and Muscatine Power and Water. IIG&E has generation of 6.2 billion kilowatthours. Of this, coal accounts for nearly four billion kilowatthours, or 63 percent of the total, with the balance from nuclear generation. IIG&E's in-state generation represents 16 percent of Iowa's total generation. The company purchased approximately 0.6 million tons of coal in 1986. Of this total, Illinois supplies about 0.3 million tons, or 43 percent of the total. The Illinois coal is used at the Riverside station. The remaining 161 coal needs are supplied by Wyoming coal producers. IIG&E's Illinois coal purchases represent three percent of Iowa's total utility coal receipts and 15 percent of Iowa's Illinois coal purchases. Since 1983, IIG&E has increased its Illinois coal receipts by a minimal amount even though the delivered price has fallen by 34 percent. Table 7-12 shows IIG&E's Illinois coal purchases for the past four years. TABLE 7-12. IIG&E'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS 239 106 132 259 PERCENT SULFUR 2.76 2.76 2.39 2.41 BTU/LB 10,559 10,516 10,618 10,985 $/T0N 36.51 38.06 26.43 26.31 i/MMBTU LZ3 L81 L£5 1.15 The following paragraphs discuss IIG&E's two coal -fired stations. For a discussion of the Ottumwa station, see the section on Iowa Southern Utilities Company. The Louisa Station is located in southeastern Iowa at Fruitland. The station consists of one new pulverized coal unit with capability of 650 megawatts. The station is jointly owned by IIG&E (43%) 280 megawatts; Iowa Power and Light Company (31%) 198 megawatts; Iowa Public Service Company (15%) 91 megawatts; Central Iowa Power Cooperative (5%) 30 megawatts; and Interstate Power Company (4%) 26 megawatts. The station is operated by IIG&E. The portion owned by IIG&E represents 21 percent of the company's total capability. It is the largest coal -fired station operated by IIG&E. Louisa's generation of 2.8 billion kilowatthours represents 49 percent of the station's capability, while the 1.2 billion kilowatthours owned by IIG&E represents 19 percent of the company's total generation. The production expense averages 2.2 cents per kilowatthour, with the fuel expense at 1.9 cents. Louisa is the most efficient of the two coal -fired stations. Louisa consumed 1.8 million tons of Wyoming coal in 1986. The coal averages 8,331 BTU per pound of coal, with 0.4 percent sulfur. S02 emissions are 0.9 pound per million BTU of input. Because of its in-service date, Louisa must meet the U.S. Environmental Protection Agency's New Source Performance Standard. The Wyoming coal is supplied by Cordero Mining Company by contract through May 2003 and, Mobil Oil Mining and Coal Division by contract. 162 The Riverside Station is located in souteastern Iowa at Bettendorf. It consist of two pulverized coal units with capability of 173 megawatts. Riverside is the smallest station in IIG&E's system, with 13 percent of IIG&E's total capability. The station's generation of 0.4 billion kilowatthours accounts for 27 percent of its capability and six percent of IIG&E's total generation. The cost per kilowatthour of generation is 3.6 cents, while the fuel cost averages 2.3 cents. The coal used in 1986 averages 10,963 BTU per pound of coal and 2.4 percent sulfur. The station has an S02 emission rate of 4.3 pounds per million BTU of input. No information is available concerning the likelihood of FGD retrofit. The 259,000 tons of Illinois coal is supplied by Midland Coal Company under contract and Old Ben Coal Company by contract and spot market. The coal is received by rail. The Indiana coal is supplied by Amax Coal Company, Peabody Coal Company and Vigo Coal Company, all by contract. Table 7-13 provides additional data on the two coal -fired stations and systemwide data. Refer to Map 7-1 for the locations of these stations. 163 to o >= to z •— « < t— o. < Z I— O «0 o to CO UJ »— ■■* < i o »- r-» z to , | 1 00 1 ■ < 1-*-. 1 Q. 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O 3 o co CO f— 1 o CO o CM at at o» CM co en co co CM CO CO • CO I— I o CM CD O co co ec ec o o < < 2 2 o o _J _l (rt(/)HH CO CO z z ^ ^ H- >- © © H- I— I— \r- Z Z < < O O 2 2 O O •-« i-h < — i SX^CAOBCO 1—1 1—1 O ^ CO O* C7» 00 N • • • cn en cm ihih •— i a. -I < < Q O. UJ < ce < —i H- < o o co UJ •• CO CO < UJ z CO o < cc o o. a. < o -J o < O CO o _J z < « I 1 O —I z2 O UJ i— < z H- UJ UJ Cd CD i-i U. —I i < -J H- < o o t— o 171 MUSCATINE POWER AND WATER DEPARTMENT Muscatine Power and Water Department is a municipally-owned electric utility located in east central Iowa. Muscatine's service territory consists of the City of Muscatine with a population of 24,000. The department supplies electrical service to 10,000 customers. Electric sales are approximately one billion kilowatthours, with a value of nearly $50 million. Muscatine purchased 0.5 million tons of Illinois coal in 1986. The department's Illinois coal receipts represent four percent of Iowa's total coal demand and 25 percent of Illinois coal receipts in Iowa. Table 7-16 details the department's Illinois coal purchases for the past four years. Since 1983, Muscatine's Illinois coal purchases have stayed relatively the same at 0.5 million tons, while the delivered price has increased by six percent. TABLE 7-16. MUSCATINE'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS PERCENT SULFUR BTU/LB S/T0N S/MMBTU Muscatine Power and Water Department has one coal -fired generating station located in Muscatine. The following paragraphs discuss this station. The Muscatine Station consists of two pulverized coal units and one cyclone unit with total capability of 259 megawatts. Muscatine's generation of one billion kilowatthours represents 45 percent of its capability. Information is not available on the cost per kilowatthour of generation, but the fuel expense averages two cents per kilowatthour. The station consumed 478 thousand tons of Illinois coal in 1986. The cpal averages 11,280 BTU per pound of coal and 3.1 percent sulfur. The S02 emission rate is 2.9 pounds per million BTU of input. The coal is supplied by Freeman United Coal Mining Company by spot market and received by rail . 173 487 170 488 484 3.23 3.01 2.93 3.12 11,567 11,124 11,383 11,280 41.63 45.75 43.10 43.10 1.80 2.06 1.89 1.91 Muscatine's Unit 9 must meet the U.S. Environmental Protection Agency's New Source Performance Standard. It utilizes a limestone FGD system rated at 150 megawatts. The FGD system came on-line in 1983 and is designed to remove up to 90 percent of S02. Its emission rate is 1.2 pounds of S02 per million BTU of input. The station's overall S02 emission rate is 2.9 pounds per million BTU of input. Table 7-17 provides additional data on Muscatine's electric operations. 174 CO o co z < H- h- ec co < a. o UJ z Q < a£ Z UJ o h- i-i r«* < t— •^ S < • H- r-* Q CO i£> Z 00 ui < © cn — I Z i-h OOIm < Ul |- "§2 Q. Ul Jg Ul Ul Z C9 M 1— Q < Ul O OS CO »-» 5 U. 3E 1 — 1 < O o Q o H U □ -— . 1 o M — i ac CO 1 o M < =3 z 1 ■ N O CO O 1 CO 1 O Z 1— 1 r«- 1 o ■*— ' 1 ^- » o N H H H M N ~g 1 . 1 z M II ^ 1 N II 3 II II II II 1 >- II »- II o II < H- ^■s | U CO H r-l M Q. t-4 X 1 cn II z II cn II < —1 ^- U 3T II • H o •-■ II *>>. H t— i II CO II II u •♦>*• II II II II II II z '""• 1 o H II II o X 1 ^* II H M ^g 1 co ^£ II o II H-»- * •> O II t—t II zS CM »- 11 • H O 1 <-* N CO U Ul O 1 o •CO- H ^> II Z O 1 m H II UJ *— ** 1 ~-l U M cs X M M II H <-* B N U ■ — 1 1 1 —I — 1 —I CO II CM M Ul 1 1 < < < < II • II 23 1 1 o o o II CO II U. 1 1 o o o X M H H H H M II H H H H- UJ 1 H CM N M Q. 1 1 o >■ o CO H w* II 3C >■ 1 i a- o a. It • II 3 H- 1 ** II U II U CO H H II II >■ M H h- • n II CC m 1 (MiH^ *• O 00 ii o II Ul _J *~~* 1 1 • • • • © -J u CO M z ** ^B 1 i m en cn en U. ^ M CM H Z CO JE 1 I cm r»« u> cn 3 N •» N 3 < ^-* 1 i ■— i CM JE >- H .— i M co a. ■P 00 II ^-i II < •r- U M o X *»«N II H >- «/ H II "O h- 2j 14 CO N UJ 1 i cn cn cm 4) 1— t o M • II Z I i en co co a. »- H- N ^» N ^E »-* 1 i en en en a. 2J U 00 II o -J 1 | HHH 3 cr < o Z3 O o-c H II M ^ > M M U 1- 1 a> >■■* H U >— < 1 i sajen II M 3C I V» II II = * 1 Ul cn ce U II H H CO II H II II Z 1 1 M 4-> UJ H t—4 H O 1 1 h- •^ »— < N o U M | 1 < _i c _i U ^2 H h- 1 1 o < 3 —J CL N 1— 1 * < 1 1 CO »- < Q- II —J U 1- 1 I XD o O "^ U _J H CO 1 1 Z H- * o CO M •— 1 H CO CO o o o o CO CO i«i ^ H- t— CO CO »- I— Z Z Z Z < < o © o © 2 3 t— t— •-• •-■ - •• co z »- co < © MUZ —1 — 1 CO o H- .. i— i < CC Zcl >OJI3 I— < o a- o uj ■— i a. qc •-" z -J <. => — 1 1— LU —> o a. < < © CO o on Z I- o "*-* o I- ^ CO »*s, O CO co o co co CO o ** CO —J z CO O 3 •-< OOQ.H • < CO U. h- co o co co lu en JQGh co S z < - h- tt 2 o Lkl O z o ca LU O -J < k- CO < < < o o o o o o o o >■ o. o. o o o o SUNI CAPAB (Ml i rv is in 1 CO CO lO LU 1 Z ** 1 i co r*» cm 1 IOIAIO 1 O) Ot Ol ^- co 1— z i-« o < o 3 O o-o en CO o < o. O 3 O CO 183 < O o z o o to to ■ — O O I— I >■ a. «-b *s < _i w ui < z o2 o LU O z o CO LU I- UJ z co => «* to & - to 1 1— z •-H | 1 i-i o 00 1 H-h- en i •— < i < o 1 =0 o i ao < a. o 3 O WO CM •O o CM CM o CM CM en CM to i— i 00 to en CO o >- I- * tO >s. O to a. m »« < -I w o z 2 o LU O Z O LU■ o o o CO LO to r*» en en ^h CM o OS < o o o to CM o en oo CM en en o CM ao CM CM < © CM 0O o z to z o to < to CO o o o o < a. O 3 o to 00 CM CM I ■ I II II CO u 00 H 03 H • II II ■ I It I en a ^ n • N 00 N CO II a a a a a cm a f*. a • a en a a a a a a oo a ^- a • a cm a a to to < < 2 2 < < C9 CO <0 CM r»* en oo LO to oo ce oc O O < < 2 2 O O -J -J Z Z 5* M o o t- I— z z o o o O « — O O — i — J <0 _J _J •> « I— » ►-* 00 CO CD OS CO 00 CM CM O O ■-i CM CM co 00 o CM to o i— i O 00 < Q Q. LU < ce o «-■ to LU • • to tO < LU Z oo CJ < C£ Z 3 O cw Q£ 3 —I O. < o —J o < O oo o •-■ o z2 O LU < CO OS LU O Z LU LU OS CO •-• < —I H- < o o O —I < — I O O 184 CHAPTER NINE KENTUCKY Kentucky electric utilities purchased approximately 28 million tons of coal; 0.2 million barrels of petroleum; and 0.4 million cubic feet of natural gas in 1986. Coal represented four percent of U.S. utility coal purchases, while petroleum and natural gas were only negligible. These figures further represented four percent of the total U.S. BTU purchases by electric utilities. Table 9-1 lists the fossil -fuel categories for Kentucky electric utilities during 1986. TABLE 9-1. KENTUCKY FOSSIL-FUEL SOURCES FOR ELECTRIC GENERATION. FUEL QUANTITY (000) BTU (BILLION) % OF TOTAL $/UNIT S/MMBTU COAL PETROLEUM NATURAL GAS 28,148 tons 241 bis. 414 mmcf. 648,706 1,404 424 99.7 .2 .1 30.84 20.42 3.03 1.34 3.50 2.97 TOTAL 650.534 100.0 Kentucky has six investor-owned utilities, 29 municipal systems, 28 rural electric cooperatives and one U.S. Government system. The major suppliers of electricity are the Tennessee Valley Authority, Louisville Gas and Electric Company, Kentucky Utilities Company, Big Rivers Electric Cooperative, East Kentucky Power Cooperative and Kentucky Power Company. These utilities generation. account for about 90 percent of Kentucky's total Kentucky electric utilities have 15,110 megawatts of capability, representing two percent of the U.S. total capability. This capability consists of 13,919 megawatts of coal -fired; 782 megawatts of water; 223 megawatts of natural gas-fired; and 186 megawatts of petroleum- fired. Of the 44 states that have coal -fired capability, Kentucky ranks seventh. Table 9-2 breaksdown the various fuel types by capability, number of units, percent of Kentucky's total capability and percent of U.S. total capability. For example, the 13,919 megawatts of Kentucky coal capability represents five percent of the total U.S. coal capability. 185 9-2. KENTUCKY SUMMER CAPABILITY. TOTAL COAL PETROLEUM TYPE OF CAPABILITY NATURAL GAS WATER MEGAWATTS 15,110 13,919 186 NO. OF UNITS HI 59 15 % OF KY TOTAL 100 92 1 % OF U.S. TOTAL 2 5 « 223 7 2 782 30 5 1 Two new coal -fired stations are under construction in companies and stations statistics are shown in Table 9-3. Kentucky. The TABLE 9-3. FUTURE BASELOAD CAPABILITY IN KENTUCKY. UTILITY STATION AND UNIT CAPABILITY (MW) FUEL ON LINE E. KY. POWER* COOP. LOUISVILLE GAS & ELEC. Smith 1 Trimble County 1 602 526 Coal Coal 1992 1991 TOTAL 1.128 Net generation by Kentucky electric utilities totals 67 thousand gigawatthours, an increase of six percent from 1985. This figure ranks Kentucky as the 15th largest producing state in the nation. Coal produces 96 percent of the total generation. On a national basis, Kentucky accounts for three percent of total generation, while coal generates five percent of the U.S. total coal -fired generation. Table 9-4 details each of the categories of generation. TABLE 9-4. KENTUCKY NET GENERATION. TOTAL COAL TYPE OF CAPABILITY NATURAL PETROLEUM GAS WATER GIGAWATTHOURS 66,915 64,012 % OF KY TOTAL 100 96 % OF U.S. TOTAL 3 5 127 43 2,734 4 1 186 In 1986, Kentucky utilities purchased approximately 28 million tons of coal. This coal is supplied by seven coal producing states. The sulfur content varies from 0.7 percent to 3.5 percent, with a weighted average of 2.5 percent. The BTU content varies from 11,075 to 12,304 per pound of coal, with an average of 11,523. On a BTU cost basis, Tennessee coal has the lowest delivered price at $1.01 per million BTU, while Pennsylvania coal is the most expensive at $1.62 per million BTU. Table 9-5 lists the various coal supplying states, or regions, and their respective quantities and qualities of coal sold to Kentucky. TABLE 9-5. KENTUCKY COAL SUPPLIERS. TONS % OF % STATE/REGION (000) TOTAL BTU/LB SULFUR $/T0N J/MMBTU W. KENTUCKY 14,173 50 11,075 3.52 27.37 1.24 E. KENTUCKY 8,089 29 12,135 1.29 35.83 1.48 W. VIRGINIA 2,680 10 12,630 .68 36.80 1.46 INDIANA 2,556 9 11,135 2.62 29.22 1.31 OHIO 546 2 11,187 2.23 26.93 1.20 ILLINOIS 65 — 11,949 .93 34.70 1.45 TENNESSEE 29 -- 12,304 1.81 24.80 1.01 PENNSYLVANIA 11 -- 11.225 2.60 36.45 1.62 TOTAL/AVERAGE 28.149 100 11.523 2.49 30.84 1.34 Illinois coal suppliers sold about 65,000 tons of coal to the Tennessee Valley Authority's Shawnee Station located in Kentucky. The Illinois coal represents less than one percent of Kentucky's total utility coal receipts. The major coal supplying state is Kentucky with 79 percent of the total. Illinois coal sales, quality of coal and delivered prices to Kentucky for 1985 and 1986 are shown in Table 9-6. As seen in the table, the Tennessee Valley Authority is buying a quality Illinois coal with less than one percent sulfur and about 12,000 BTU per pound of coal. The TVA did not purchase any Illinois coal in 1983 and 1984. TABLE 9-6. and 1986. KENTUCKY'S ILLINOIS COAL PURCHASES AND DELIVERED PRICES 1985 YEAR 1985 1986 THOUSAND TONS 184 65 PERCENT SULFUR 1.50 .90 BTU/LB 11,904 11,949 $/T0N 33.44 34.70 J/MMBTU 1.40 1.45 187 A discussion of the Tennessee Valley Authority and its two coal -fired stations located in Kentucky follows. See Map 2-1, Alabama, for the locations of these generating stations. 188 TENNESSEE VALLEY AUTHORITY - KENTUCKY The Tennessee Valley Authority has 3,949 megawatts of capability located in Kentucky. This capability consists of two coal -fired stations with capability of 3,774 megawatts (96% of TVA's Kentucky capability) and five hydro units rated at 175 megawatts. This capability represents 14 percent of the TVA's total capability. Statewide, the TVA capability represents about 26 percent of Kentucky's coal -fired and total capability. TVA's Kentucky generation is approximately 19 billion kilowatthours, representing 28 percent of Kentucky's total generation. For TVA's Kentucky generation, coal accounts for almost all of the total. The TVA purchased approximately eight million tons of coal in 1986 for its two stations in Kentucky. Of this total, 65,000 tons were from Illinois, representing only a minimal amount of its total demand. Table 9-7 details TVA's Illinois coal purchases for its Kentucky generating stations for the last two years. The TVA facilities in Kentucky purchased no Illinois coal for 1983 and 1984. TABLE 9-7. TVA'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1985 AND 1986. YEAR 1985 1986 THOUSAND TONS 107 65 PERCENT SULFUR .90 .90 BTU/LB 12,069 11,949 $/T0N 34.76 34.70 1/MMBTU 1.44 1.45 The following paragraphs discuss the TVA's two coal -fired stations located in Kentucky. Table 9-8, at the end of the narrative, provides additional data on these stations. Refer to Map 2-1, Alabama, for the locations of these two stations. The Paradise Station is located in southwestern Kentucky at Drakesboro. The plant has three cyclone units with capability of 2,264 megawatts. The station accounts for 57 percent of TVA's Kentucky capability. The station's 12.6 billion kilowatthours of generation represents 64 percent 189 of its capability and 68 percent of TVA's Kentucky generation. The average cost of generation is 1.7 cents per kilowatthour. The fuel expense averages 1.4 cents per kilowatthour. Of TVA's coal -fired stations, Paradise is the most efficient. The 5.4 million tons of Kentucky and Ohio coal consumed in 1986 averages 4.1 percent sulfur and 10,998 BTU per pound of coal. The major Kentucky coal suppliers are Peabody Coal Company by contract; Green River Coal Company by contract; and Brown Badget Incorporated by contract. Paradise's Units 1 and 2 are equipped with limestone FGD systems that remove about 85 percent of the S02 emissions. The two retrofitted scrubbers came on-line in 1983. No capital cost or operating expense are available. Overall, the station has an S02 emission rate of 4.4 pounds per million BTU of input. Paradise is ranked number two nationally in total tons of S02 emissions. Paradise's Unit 3 is rated easy for FGD retrofit because of age, size and availability of space. The Shawnee Station is located in northwestern Kentucky at Paducah. The station consists of ten older pulverized coal units rated at 1,510 megawatts of capability. The station represents 38 percent of TVA's Kentucky capability. The station's generation of 5.9 billion kilowatthours represents 44 percent of the station's capability and 31 percent of TVA's Kentucky generation. The average cost per kilowatthour of generation is two cents. The fuel expense averages 1.7 cents per kilowatthour. Shawnee is TVA's second most efficient coal -fired station. The 2.5 million tons of coal consumed in 1986 averages 12,349 BTU per pound of coal and one percent sulfur. S02 emissions are 1.6 pounds per million BTU of input. Nationally, Shawnee ranks 36th in total tons of S02 emissions. Information concerning the cost and likelihood of FGD retrofit are not available. The coal is supplied by Illinois, Kentucky and West Virginia coal operators. The Illinois coal is supplied by Inland Steel Coal Company, by spot market. The major West Virginia coal suppliers are Ashland Coal Company and Island Creek Coal Company. The major Kentucky coal supplier is Tennessee Consolidated Coal Company. 190 _J Z CO < 3 Z O WO O O Z »- O w o I- ^ CO ^ o to tO o to >- « *: I- o < 3 t— »- tO z LU Q S^ Z I < >• h- tO *■* z OS O COOw 1 = •- cn h-< LU < CO 00 _i cn CQ ^ O — • LU LU Z LU LU to LU O I >■ a. i-i x «c -i w o »-• oa o z oS O LU O Z O LU w C9 LU >■ < tO < < < o o o o o o >■ >• >■ o o o o o o SUNN CAPABII (NW i in m * 1 CM CM «-• 1*0(00 1 • 1 >-H LU 1 Z *"* O -J I 1 CO CO Cn 1 1 1 ^H CM CO 1 * « CO o o o CO o o * o CM CM CO CO cn «*■ cn * CO * CM co CM CM < t- O CM CO © z CO Z < o > (SOX o z to < to 0) 3 cr *v i. CM ■o c to ■ to I— z l-> O io 3 O o-o < o. O 3 o to O CO CM O • • f*. oo to CO ii i u «3- H 00 00 ^ t0 CM O T-4 00 o CO ^ CM CM cm cn O 00 • • m lo o CM oo to cn »-» cn r»» © o to o • * *i to o to o m m o I— O *C O 00 to o H U II 00 H «*■ u • H CO II CM CM o to o *3- oo cn cn to m o to 191 — I z CO O z O CO o O Z t— O «— ' o 3 I- ^ CO • — o CO O H- UJ O i ^ < -J w O i-i O X £ o UJ o z o UJ w O z >■ 3 < CO Q. UJ O -J o o 00 I en co <<<<<<<<<< oooooooooo oooooooooo oooooooooo oooooooooo in to ifl io u) to in in in m <»)f)«nfo***ininio in u) to m mm ifl u) in in en en en en en en en en en en m N <«) « u> o co co co o en • • • — < o oo OlON en r«* co • • • o ^ o o>rs* ^- m r^ en en in m m • i-l ^h CM r«. oo oo • • • «» CO CM IONiH en oo u H CM M * H CO H • II ^ || I I I I I ■ U I | in h wo M «* H • H ~* H I I ■ I I r» m ^H u • u co ■ co ■ ■ I I H ■ r^ u CO H • u en u a I ii ■ I o n • ii ^* u u en co CM CO in oo CM co >- «-* — > ^ C3 o o ce l-H H 192 CHAPTER TEN MINNESOTA Minnesota electric utilities purchased approximately nine million tons of coal; 18 thousand barrels of petroleum; and one billion cubic feet of natural gas in 1986. Coal represented one percent of U.S. utility coal purchases, while petroleum and natural gas were only negligible. On a BTU basis, Minnesota utilities purchased one percent of the U.S. total. Table 10-1 lists the fossil -fuel sources for electric generation by Minnesota electric utilities. TABLE 10-1. MINNESOTA FOSSIL-FUEL SOURCES FOR ELECTRIC GENERATION. FUEL QUANTITY (000) BTU (BILLIONS % OF TOTAL $/UNIT S/MMBTU COAL PETROLEUM NATURAL GAS 9,324 tons - 18 bis. 1.309 mmcf. 162,703 104 1.307 99.1 .1 .8 23.74 16.12 2.95 1.36 2.60 2.95 TOTAL 164.114 100.0 Minnesota has three investor-owned utilities, 125 municipal systems, 51 rural electric cooperatives and four state systems. The major suppliers of electricity are Minnesota Power and Light Company, Northern States Power Company and Otter Trail Power Company. These three utilities account for most of Minnesota's electrical generation. Minnesota electric utilities representing one percent of the 4,360 megawatts of coal -fired; megawatts of petroleum- fired; 138 megawatts of hydro. Of the Minnesota ranks 23rd. have 7,859 megawatts of capability, U.S. total. This capability consists of 1,550 megawatts of nuclear-fired; 1,116 695 megawatts of natural gas-fired; and 44 states that have coal -fired generation, Table 10-2 provides a break down of the various fuel types by capability, number of units, percent of total capability and percent of U.S. total capability. The U.S. total is shown as the percent of Minnesota's fuel type to the U.S. total. For example, the 4,360 megawatts of coal capability represents two percent of the U.S. coal capability. 193 TABLE 10-2. MINNESOTA SUMMER CAPABILITY. TYPE OF CAPABILITY TOTAL COAL NUCLEAR NATURAL PETROLEUM GAS WATER MEGAWATTS 7,859 NO. OF UNITS 370 % OF MN TOTAL 100 % OF U.S. TOTAL 1 4,360 1,550 1,116 695 138 53 3 195 56 63 55 20 14 9 2 2 2 1 1 -- Northern States Power Company will add two new coal -fired stations in near term. These stations are listed in Table 10-3. the TABLE 10-3. FUTURE BASELOAD CAPABILITY IN MINNESOTA. UTILITY STATION AND UNIT CAPABILITY fMW) FUEL ON LINE NORTHERN STATES POWER Riverside 7 Sherburne 3* 130 739 Coal Coal 1987 1987 TOTAL 869 Jointly owned. Net generation by Minnesota electric utilities totals 28,000 gigawatthours, a decrease of eight percent from 1985. This generation ranks Minnesota 32nd in nationwide electrical generation. Coal supplies 58 percent of the total, while nuclear generates 39 percent. On a national basis, Minnesota accounts for one percent of total generation. Table 10-4 details the types of generation. TABLE 10-4. MINNESOTA NET GENERATION. TYPE OF CAPABILITY TOTAL COAL NUCLEAR PETROLEUM NATURAL GAS WATER GIGAWATTHOURS % OF MN TOTAL % OF U.S. TOTAL 28,401 100 1 16,267 58 1 11,052 39 3 22 124 936 3 194 In 1986, Minnesota purchased approximately nine million tons of coal. This coal is supplied by six coal producing states. The sulfur content varies from 0.3 percent to 1.6 percent, with a weighted average of 0.6 percent. The BTU content varies from 6,893 to 12,250 per pound of coal, with an average of 8,725. On a BTU cost basis, Wyoming coal has the lowest delivered price at $1.28 per million BTU, while Illinois coal is the most expensive at $2.11 per million BTU. Table 10-5 lists the various coal supplying states and their respective quantities and qualities of coal sold to Minnesota utilities. TABLE 10-5, MINNESOTA COAL SUPPLIERS. TONS % OF % STATE/REGION (000) TOTAL BTU/LB SULFUR $/T0N S/MMBTU MONTANA 6,138 66 8,638 .73 23.56 1.36 WYOMING 2,642 28 8,748 .30 22.30 1.28 N. DAKOTA 228 2 6,893 .82 24.22 1.76 INDIANA 140 2 10,937 1.40 30.11 1.38 ILLINOIS 113 1 12,250 1.62 51.64 2.11 W. KENTUCKY 63 1 11.649 1.29 35.68 1.53 TOTAL/AVERAGE 9.324 100 8.725 .63 23.74 1.36 One Illinois coal supplier sold about 0.1 million tons of coal to the Rochester Department of Public Utilities in 1986. The Illinois coal sale represents about one percent of Minnesota's total utility coal receipts. The major coal supplying states were Montana and Wyoming with 94 percent of the total. Illinois coal sales, quality of coal and delivered prices to Minnesota, for the period 1981 through 1986 are shown in Table 10-6. Since 1982, Illinois coal sales to Minnesota have decreased by about 500 percent. TABLE 10-6. MINNESOTA'S ILLINOIS COAL PURCHASES AND DELIVERED price: 1986-1981. YEAR 1981 1982 1983 1984 1985 1986 THOUSAND TONS 509 577 312 100 175 113 PERCENT SULFUR 2.70 2.70 2.80 1.90 1.50 1.62 BTU/LB 11,594 11,560 11,506 12,342 12,196 12,250 $/T0N 38.42 41.75 45.04 50.79 52.06 51.64 VMMBTU 1.66 1.81 1.96 2.06 2.13 2.11 195 A discussion of the Rochester Department of Public Utilities follows. Map 10-1 shows the location of the Silver Lake coal -fired generating station. Also included in the map is Interstate Power Company's Fox Lake coal -fired generating station, which is discussed in Chapter Seven. 196 MAP 10-1 COAL FIRED GENERATING STATIONS Fox Lake MINNESOTA • ILLINOIS COAL 197 ROCHESTER DEPARTMENT OF PUBLIC UTILITIES The Rochester Department of Public Utilities is a municipally-owned electric utility located in southeastern Minnesota. Rochester's service territory consists of the City of Rochester, with a population of 60,000. The department supplies electricity to approximately 29,000 customers. Electric sales are nearly 0.7 billion kilowatthours, valued at $42 million. The utility has one coal -fired generating station located in Rochester. The department also has one gas turbine generator and one hydro unit. The total capability is rated at 136 megawatts. Of this total, the coal -fired capability represents 78 percent. Statewide, Rochester's capability accounts for two percent of total capability. Rochester's electrical generation is about 0.3 billion kilowatthours. Almost all of this generation is from coal. Statewide, this figure accounts for one percent of the total . The utility purchased 113,000 tons of coal in 1986. All of the coal is supplied by one Illinois coal producer. This figure also represents all of the Illinois coal demand in Minnesota and one percent of the state's total coal receipts. Table 10-7 lists Rochester's Illinois coal purchases for the past four years. TABLE 10-7. ROCHESTER'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS PERCENT SULFUR BTU/LB S/TON S/MMBTU 142 2.15 12,400 50.52 2.04 100 1.90 12.342 50.79 2.06 175 1.50 12,196 52.06 2.13 113 1.62 12,250 51.64 2.11 The following paragraphs discuss Rochester's one coal -fired generating station. Refer to Map 10-1 for the location of this station. The Silver Lake 106 megawatts, capability and Station has four pulverized coal units with capability of This figure represents all of the departments 's coal -fired 78 percent of its total capability. Silver Lake's 199 generation of 0.3 billion kilowatthours represents 33 percent of the station's capability. The average cost per kilowatthour of generation is 3.6 cents, with the fuel expense at 2.8 cents. The station consumed 146,000 tons of Illinois coal in 1986. The coal averages 12,250 BTU per pound of coal and 1.6 percent sulfur. Silver Lake's S02 emission rate is 2.4 pounds per million BTU of input. No information is available concerning the cost and likelihood of FGD retrofit. The Illinois coal is supplied by Sahara Coal Company under contract. The coal is received by railroad carrier. 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CO CO (OUIrt en co to CO to 00 OOtH to en i-i • • • cm r»» ^ , ^ ^ to to •■* < O 3 O ZO X f-i to < _J oo _i _j i— i :*: CO 00 to CO CO o CM CO CM CO CM 10 CO CO * en to 00 < o to to as oc O O < < o o _1 —I to to •— « ■— « b. k. co to M! ** I— I- z z < < o o z z 3 3 t- I— O O < < M M (9UOO JJ UUJOO J J Z Z to to n* i-i cm r^ en cm en o cm • • ■ m m CM 00 NNN i-« to >■ •• to 3g »- to < o mUJZ N^ JVIO »— •• "— i < OS >caz3 x£ H- < o a. o uu -* Q. CC >— « z -J < =D -J 1— UJ — O (X < 00 O 5* — i o >— < CO i-i U. O u. — J i — 1 z _l 1 < — 1< I-i < -1 >- < »- -1 1— < O O O -J o o HOh« h- o 232 SIKESTON BOARD OF MUNICIPAL UTILITIES The Sikeston Board of Municipal Utilities is a municipally-owned utility involved in the generation and sale of electricity and water in Sikeston, Missouri. Sikeston's service territory has a population of about 18,000. Electric sales are about 0.2 billion kilowatthours, valued at ten million dollars. The Sikeston Board has one coal -fired generating station, located in Sikeston. The station's capability of 212 megawatts represents 96 percent of the utility's capability and one percent of Missouri's total capability. The utility's generation of 0.9 billion kilowatthours, represents two percent of Missouri's total generation. The Board purchased 0.3 million tons of coal in 1986. Illinois supplies 250,000 tons, or 83 percent of the total. Sikeston's Illinois coal purchase represents one percent of Missouri's utility coal receipts and two percent of Illinois coal receipts. Table 12-13 lists Sikeston's Illinois coal purchases for the past four years. As shown, the Sikeston Board has reduced its Illinois coal demand by 64 percent, while the delivered price has fallen by 27 percent. TABLE 12-13. SIKESTON'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS 667 659 277 242 PERCENT SULFUR 2.60 2.61 2.53 2.48 BTU/LB 11,368 11,367 11,176 11,211 $/T0N 41.51 43.88 43.14 29.79 1/MMBTU 1.83 1.93 1.93 1.33 The following paragraphs discuss the Sikeston's one Table 12-14 provides additional data on the station, location of the facility. coal -fired station. Map 12-1 shows the The Sikeston Station has one relatively new pulverized coal unit with capability of 212 megawatts. It is the only coal -fired station that the utility owns. Generation of 0.9 billion kilowatthours represents 46 percent of the station's capability. The cost per kilowatthour is not 233 available. The fuel expense averages 1.4 cents per kilowatthour of generation. The station consumed 0.4 million tons of Illinois and Kentucky coal in 1986. The coal averages 11,198 BTU per pound of coal and 2.6 percent sulfur. The Illinois coal is supplied by Old Ben Coal Company, Kenellis Energy Incorporated and Midwest Mining Company, all by contract. The coal is received by railroad. The Kentucky coal is supplied by Pyro Mining Company by contract. The station is equipped with a limestone FGD system to meet the U.S. Environmental Protection Agency's New Source Performance Standard. No figures are available on the capital cost of the system or its operating expense. The system is rated to remove up to 80 percent of the S02 emissions. The S02 emissions are 1.2 pounds per million BTU of input. 234 _J Z CO < 3 Z O CO O O Z I— o *-^ o CO 'v. 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CM O O * * •-h cm cn en • • CftONNNCVJ >- 00 00 < Q a. lu < as < -I o o »— CJ JO LU •• to to < LU Z tO O < ec Z 3 o a. 0£ 3 —I a. -" I— -J O —I zo? O LU ►— i z I— LU ga LU Q Z LU LU q; C3 i-i < -J I— < O O 245 CHAPTER THIRTEEN TENNESSEE Tennessee electric utilities purchased approximately 23 million tons of coal and 0.1 million barrels of petroleum in 1986. For these categories, coal represented three percent of U.S. utility coal purchases while petroleum was only negligible. On a BTU basis, Tennessee utilities purchased three percent of the nation's fuel for electric generation. Table 13-1 lists the primary fuel sources used by Tennessee electric utilities. As seen in the table, almost all of the fossil -fuel receipts is coal . TABLE 13-1. TENNESSEE FOSSIL-FUEL SOURCES FOR ELECTRIC GENERATION. FUEL QUANTITY (000) BTU (BILLION) % OF TOTAL S/UNIT $/MMBTU COAL PETROLEUM 22,535 tons 137 bis. 536,687 795 99.9 .1 33.79 19.57 1.42 3.37 TOTAL 537.482 100.0 Tennessee has one investor-owned utility, 63 municipal systems, 20 rural electric cooperatives and two U.S. Government systems. The major suppliers of electricity are the Tennessee Valley Authority and the U.S Army Corps of Engineers. These two federal systems account for most of Tennessee's utility generation, with over 90 percent of the total from the Tennessee Valley Authority. Tennessee's electric utilities have 17,003 megawatts of capability, accounting for three percent of the U.S. total. This capability consists of 9,289 megawatts of coal -fired; 3,750 megawatts of hydro; 2,296 megawatts of nuclear-fired; 1,152 megawatts of petroleum-fired; and 516 megawatts of natural gas-fired. Coal -fired capability accounts for 55 percent of the total. Of the 44 states that have coal -fired generation, Tennessee ranks 13th. Table 13-2 shows the breakdown of Tennessee's total capability. 247 TABLE 13-2. TENNESSEE SUMMER CAPABILITY. TYPE OF CAPABILITY TOTAL COAL NUCLEAR NATURAL PETROLEUM GAS WATER MEGAWATTS 17,003 NO. OF UNITS 164 % OF TN TOTAL 100 % OF U.S. TOTAL 3 9,289 2,296 1,152 516 3,750 37 2 20 20 85 55 14 7 3 21 3 3 1 -- 4 The Tennessee Valley Authority has plans of adding two nuclear units in the future. Table 13-3 details these generating station. TABLE 13-3. FUTURE BASELOAD CAPABILITY IN TENNESSEE. UTILITY STATION AND UNIT CAPABILITY (MW) FUEL ON LINE TENNESSEE VALLEY AUTHORITY Watts Bar 1 Watts Bar 2 1,152 1.152 Uranium Uranium 1990 1991 TOTAL 2.304 Net generation by Tennessee electric utilities totals 56 thousand gigawatthours, a reduction of 15 percent from 1985. Broken down by energy source, coal supplies 91 percent of the total, with the remainder from hydro. The Tennessee Valley Authority's two nuclear units are still out of service. On a national basis, Tennessee ranks 17th in electrical generation and accounts for two percent of total generation. Table 13-4 details each category. TABLE 13-4. TENNESSEE NET GENERATION. TYPE OF CAPABILITY TOTAL COAL NUCLEAR PETROLEUM WATER GIGAWATTHOURS % OF TN TOTAL % OF U.S. TOTAL 56,455 100 2 51,108 91 4 «■ « 126 5,326 9 2 248 In 1986, Tennessee utilities purchased approximately 23 million tons of coal. This coal is supplied by six coal producing states. The sulfur content varies from 1.1 percent to 2.7 percent, with a weighted average of two percent. The BTU content varies from 11,706 to 12,855 per pound of coal, with an average of 11,908. On a BTU cost basis, Illinois coal has the lowest delivered price at $1.23 per million BTU, while eastern Kentucky coal is the most expensive at $1.61 per million BTU. Table 13-5 lists the various coal supplying states and their respective quantities and qualities of coal sold in Tennessee. Kentucky coal producers supply 72 percent of Tennessee's total coal receipts. TABLE 13-5. TENNESSEE COAL SUPPLIERS. TONS % OF % STATE/REGION (000) TOTAL BTU/LB SULFUR S/TON S/MMBTU M. KENTUCKY 10,463 46 11,864 2.72 33.25 1.40 E. KENTUCKY 5,941 26 11,706 1.11 37.78 1.61 ILLINOIS 2,915 13 11,749 1.89 28.77 1.23 TENNESSEE 1,811 8 12,453 1.41 31.23 1.25 VIRGINIA 1,004 5 12,855 1.19 34.83 1.36 W. VIRGINIA 330 1 12,490 2.47 34.10 1.39 INDIANA 71 -_ 11.758 1.38 35.20 1.50 TOTAL/AVERAGE 22.535 100 11.908 2.01 33.79 1.42 coal suppliers sold about three million tons of coal to the i Valley Authority in 1986, representing 13 percent of Tennessee's ;ility coal receipts. Illinois coal sales are to three of TVA's Illinois Tennessee total utility coal receipts. Illinois coal sales are to three of iVA's generating stations located in Tennessee. Illinois coal sales for the period 1981 through 1986 are shown in Table 13-6. As seen in the the TVA has increased its demand for Illinois coal dramatically 1981, while the delivered price has fallen by 25 percent. table, since TABLE 13-6. TENNESSEE'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1981- -1986. YEAR 1981 1982 1983 1984 1985 1986 THOUSAND TONS 247 12 36 947 1,425 2,915 PERCENT SULFUR 2.20 2.00 2.00 2.00 1.90 1.89 BTU/LB 11,720 11,600 11,430 11,733 11,557 11,749 $/T0N 38.58 34.43 29.76 34.22 29.48 28.77 i/MMBTU 1.65 1.48 1.31 1.46 1.28 1.23 249 A discussion of the TVA generating stations follows. See the Alabama section, Chapter 2, for a discussion of the Tennessee Valley Authority and Map 2-1 for the locations of these coal -fired generating stations. 250 TENNESSEE VALLEY AUTHORITY -TENNESSEE The TVA has 16,313 megawatts of capability located in Tennessee. This capability consists of seven coal -fired stations with capability of 9,289 megawatts; 17 hydro stations rated at 3,060 megawatts; one nuclear station with 2,296 megawatts; and three natural gas/petroleum-fired stations with 1,668 megawatts. Overall, this capability represents 96 percent of Tennessee's total capability. TVA's Tennessee capability accounts for 58 percent of TVA's entire system. TVA's Tennessee production is approximately 51 billion kilowatthours, representing 90 percent of Tennessee's total generation. Of TVA's total generation, the Tennessee production accounts for 56 percent of the total. TVA has no nuclear generation because the station is out of service for the near term. The TVA purchased approximately 22.5 million tons of coal for its Tennessee facilities. Of this total, 2.9 million tons are from Illinois, representing 13 percent. Most of the Illinois coal is used at the Johnsonville Station. The Illinois coal averages 11,749 BTU per pound of coal and 1.9 percent sulfur. A majority of the Illinois coal is purchased on the spot market, primarily because of no nuclear generation at the present time. Table 13-7 shows the TVA's Illinois coal purchases for its stations located in Tennessee. As seen in the table, the TVA has increased its demand for Illinois coal by about 2.9 million tons since 1983. For this same period, the delivered price has decreased by three percent. TABLE 13-7. TVA'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS 36 947 1,350 2,915 PERCENT SULFUR 2.01 2.03 1.82 1.89 BTU/LB 11,430 11,733 11,536 11,749 $/T0N 29.77 34.22 29.60 28.77 S/MMBTU 1.30 1.46 1.28 1.23 Following is a description of TVA's seven coal -fired stations located in Tennessee. Table 13-8, at the end of the narrative, provides additional data on these stations. Refer to Map 2-1, Alabama, for the locations of these stations. 251 The Allen Station is located in southwestern Tennessee at Memphis. The plant has three cyclone units with capability of 873 megawatts. The capability accounts for five percent of TVA's Tennessee capability. The station's 3.6 billion kilowatthours of generation represents 47 percent of its capability and seven percent of TVA's Tennessee generation. The average cost of generation is 1.8 cents per kilowatthour, with the fuel expense at 1.4 cents. Of the TVA's 11 coal-fired stations, Allen ranks sixth in economic efficiency. The 1.4 million tons of Illinois and Kentucky coal purchased and consumed in 1986 averages 2.3 percent sulfur and 12,048 BTU per pound of coal. Allen's S02 emission rate is 3.7 pounds per million BTU of input. Nationally, Allen ranks 68th in total tons of S02 emissions. The station is rated difficult for FGD retrofit because of space constraints. The Illinois coal is supplied by Old Ben Coal Company, by spot market and Tek-Bar Industries Inc., under contract. The coal is received by rail and barge. The Kentucky coal is supplied by Brown Badgett Incorporated by contract, Hago Corporation by contract, Middle Kentucky Construction by contract and Pyro Mining Company through contract. The Bull Run Station is located in east central Tennessee at Clinton. The station consists of one pulverized coal unit rated at 900 megawatts of capability. The station represents six percent of TVA's Tennessee capability. The station's generation of 5.3 billion kilowatthours represents 67 percent of its capability. This figure also represents ten percent of TVA's Tennessee generation. The average cost per kilowatthour was two cents. Of this total, the fuel expense averages 1.8 cents. Bull Run ranks seventh in economic efficiency. The 2.1 million tons of Kentucky coal consumed averages 11,410 BTU per pound of coal and 0.9 percent sulfur. S02 emissions are 1.5 pounds per million BTU of input. The station is ranked 116th in total tons of S02 emissions, nationally. No information is available concerning the cost consideration for FGD retrofit. The coal is supplied by Falcon Coal Company by contract. The Cumberland Station is located in north central Tennessee at Cumberland City. The station consists of two pulverized coal units with capability of 2,538 megawatts. It is the largest TVA plant in Tennessee. The capability accounts for 16 percent of TVA's Tennessee capability. The station's 15.2 billion kilowatthours of generation represents 69 percent of its capability and 30 percent of TVA's Tennessee generation. The average cost of generation is 1.6 cents per kilowatthour, with the fuel expense at 1.4 cents. Cumberland is the TVA's second most efficient coal -fired station. The 6.5 million tons of coal consumed averages 2.8 percent sulfur and 11,656 BTU per pound of coal. The station has an S02 emission rate of 4.7 pounds per million BTU of input. Nationally, Cumberland is third in total tons of S02 emissions. The station is rated easy for FGD retrofit 252 because of age, size and availability of space. A small percentage of Illinois coal is used at the station, with a majority of the coal from Kentucky. The Illinois coal is supplied by Old Ben Coal Company, by spot market and Tek-Bar Industries, Inc., under contract. The coal is received by rail and barge. The major Kentucky coal suppliers are Peabody Coal Company and Island Creek Coal Company, both by contract. The Gallatin Station is located in north central Tennessee at Gallatin. The station has four older pulverized coal units with capability of 1,080 megawatts. The capability accounts for seven percent of TVA's Tennessee capability. The station's 6.1 billion kilowatthours of generation represents 64 percent of its capability and 12 percent of TVA's Tennessee generation. The average cost of generation is 1.7 cents per kilowatthour, with the fuel expense at 1.4 cents. Gallatin ranks fourth in economic efficiency. The 2.3 million tons of coal consumed in 1986 averages 2.7 percent sulfur and 12,397 BTU per pound of coal. S02 emissions are 4.3 pounds per million BTU of input. Nationally, it is ranked 28th in total tons of S02 emissions. Gallatin is rated difficult for FGD retrofit because of age and limited space. Most of the coal is supplied by Kentucky coal producers with a small amount from Tennessee. The major Kentucky coal suppliers are Island Creek Coal Company and Pyro Mining Company, both through contract. The Johnsonville Station is located in northwestern Tennessee at Johnsonville. The plant has ten older pulverized coal units with a capability of 1,294 megawatts. The capability accounts for eight percent of TVA's Tennessee capability. The station's 6.2 billion kilowatthours of generation represents 55 percent of its capability and 12 percent of TVA's Tennessee generation. The average cost of generation is 1.7 cents per kilowatthour. The fuel expense averages 1.4 cents per kilowatthour. The station ranks fifth in economic efficiency. The 2.9 million tons of coal consumed averages 1.8 percent sulfur and 11,696 BTU per pound of coal. S02 emissions are three pounds per million BTU of input. Nationally, the station is ranked 31st in total tons of S02 emissions. It is rated very difficult for FGD retrofit because of age and limited space. Illinois supplies 77 percent of its coal needs, with the balance from Indiana and Kentucky. The Illinois coal is supplied by Old Ben Coal Company and Consolidation Coal Company, by spot market. The coal is received by railroad. The major Kentucky coal supplier is Addington Brothers Mining Company by contract, while the major Indiana supplier is Yancy Minerals Incorporated by contract. The Kingston Station is located in east central Tennessee at Gallatin. The plant consists of nine older pulverized coal units with capability of 1,580 megawatts. It is the second largest TVA station in Tennessee. The capability accounts for ten percent of TVA's Tennessee capability. The 253 station's 9.7 billion kilowatthours of generation represents 70 percent of its capability and 19 percent of TVA's Tennessee generation. The average cost of generation is 1.7 cents per kilowatthour. The fuel expense averages 1.5 cents per kilowatthour. Kingston is TVA's third most efficient station. The four million tons of coal burned averages 1.2 percent sulfur and 11,097 BTU per pound of coal. Kingston's S02 emission rate is 1.9 pounds per million BTU of input. The station is ranked 55th in tons of S02 emissions, nationally. No information is available concerning the cost of FGD retrofit. Kentucky supplies 63 percent of the coal, with the remainder from Tennessee. The major Kentucky coal suppliers are Diversified Energy Incorporated and Falcon Coal Company, both by contract. The major Tennessee coal supplier is B&W Coal Company by contract. The Sevier Station is located in northeastern Tennessee at Rogerville. The plant has four older pulverized coal units with capability of 800 megawatts. Each unit is rated at 200 megawatts. The capability accounts for five percent of TVA's Tennessee capability. The station's five billion kilowatthours of generation represents 71 percent of its capability and ten percent of TVA's Tennessee generation. The average cost of generation is 1.6 cents per kilowatthour, with the fuel expense at 1.3 cents. Sevier is the TVA's most efficient plant. The 1.9 million tons of coal used averages 1.4 percent sulfur and 12,542 BTU per pound of coal. S02 emissions are 2.2 pounds per million BTU of input. Nationally, Sevier is ranked 59th in total tons of S02 emissions. The station is rated very difficult for FGD retrofit because of age and limited space. Virginia coal operators supply 50 percent of the coal. The remainder is from Kentucky, Tennessee and West Virginia. The station has a large number of coal suppliers. 254 _i r on < =3 Z OHO O Z H- O *-" O CO ^n» O CO CO o I— I »- CO UJ >— i LU h- CO < CO I— LU CO >• CO I- z COmO i 0£ ~ moh H- h- CO uj s co en -l< -« CO cs <>- z UJ UJ UJ 19 CO CO o a. •— i *e < _l w o z 2 o UJ o z o UJ w C9 OS i-i UJ _J 3 < w co ew < O -J CO < < < o o o o o o >■ >■ ^ c_> o o o o o en en en CM CM CM co co co en en o* •-• CM co o o o CO o o en co co en oo i— • en co en co o • CO r«. 00 < o CM 00 O Z CO Z o CO < CO 00 -J 00 >- CO H- Z •-« o =3 O _J Q. < a. 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Over 99 percent of the fossil -fuel demand is from coal . TABLE 14-1. WISCONSIN FOSSIL-FUEL SOURCES FOR ELECTRIC GENERATION. FUEL QUANTITY (000) BTU (BILLION) % OF TOTAL $/UNIT VMMBTU COAL PETROLEUM NATURAL GAS 16,815 tons 163 bis. 1.203 mmcf. 324,921 944 1.207 99.3 .3 .4 31.37 20.86 3.76 1.62 3.60 3.75 TOTAL 327.072 100.0 Wisconsin has 13 investor-owned utilities, 83 municipal systems, 30 rural electric cooperatives and three state systems. The major suppliers of electricity are Wisconsin Electric Power Company, Wisconsin Power and Light Company, Wisconsin Public Service Company, Dairyland Power Cooperative and Madison Gas and Electric Company. These utilities account for over 95 percent of Wisconsin's electrical generation. Wisconsin electric utilities have 10,939 megawatts of capability, representing two percent of the nation's total. This capability consists of 7,450 megawatts of coal -fired; 1,547 megawatts of nuclear-fired; 1,143 megawatts of petroleum-fired; 299 megawatts of natural gas-fired; 415 megawatts of water; and 86 megawatts of other. Coal capability accounts for 68 percent of the total. Of the 44 states that have coal -fired generation, Wisconsin ranks 15th. Wisconsin utilities have no plans of adding coal -fired capability in the near term. Table 14-2 breaks down Wisconsin's summer capability by fuel type. 261 TABLE 14-2. WISCONSIN SUMMER CAPABILITY. TYPE OF CAPABILITY TOTAL NATURAL COAL NUCLEAR PETROLEUM GAS WATER OTHEI 7,450 1,547 1,143 299 415 86 61 4 110 21 208 7 68 14 10 3 4 1 3 2 1 .- -- 2 MEGAWATTS 10,939 NO. OF UNITS 411 % OF WI TOTAL 100 % OF U.S. TOTAL 2 Net generation by Wisconsin electric utilities totals 43 thousand gigawatthours, an increase of four percent from 1985. Broken down by energy source, coal supplies 68 percent of the total and nuclear 26 percent. On a national basis, Wisconsin ranks 22nd in electrical generation and accounts for two percent of the total generation. For the U.S. total, Wisconsin coal generation accounts for two percent, while nuclear was three percent. Table 14-3 details each category of generation. TABLE 14-3. WISCONSIN NET GENERATION. TYPE OF CAPABILITY TOTAL COAL NUCLEAR PETROLEUM NATURAL GAS WATER OTHER GIGAWATTHOURS 42,785 % OF WI TOTAL 100 % OF U.S. TOTAL 2 29,100 68 2 11,199 26 3 109 105 2,161 5 1 112 1 Wisconsin electric utilities purchased approximately 17 million tons of coal in 1986. This coal is supplied by ten coal producing states. The sulfur content varies from 0.3 percent to 2.7 percent, with a weighted average of 0.9 percent. The BTU content varies from 8,489 to 13,144 per pound of coal , with an average of 9,662. On a BTU cost basis, western Kentucky and Virginia coals have the lowest delivered price at $1.49 per million BTU, while Ohio coal is the most expensive at $2.09 per million BTU. Table 14-4 lists the various coal supplying states and their respective quantities and qualities of coal sold to Wisconsin utilities. 262 TABLE 14-4. WISCO NSIN COAL TONS SUPPLIEI % OF IS. % STATE/REGION (OOO) TOTAL BTU/LB SULFUR J/TON S/MMBTU WYOMING 9,167 55 8,489 .32 26.35 1.55 MONTANA 2,073 12 8,669 .77 28.83 1.66 INDIANA 1,763 10 11,270 1.94 38.75 1.72 ILLINOIS 1,491 9 11,587 1.82 40.68 1.76 PENNSYLVANIA 1,377 8 12,990 1.57 44.20 1.71 M. KENTUCKY 699 4 12,179 2.69 36.33 1.49 WEST VIRGINIA 96 1 12,587 1.06 42.27 1.70 E. KENTUCKY 92 1 13,144 .92 48.82 1.86 VIRGINIA 37 -- 12,856 1.63 38.17 1.49 NEW MEXICO 20 -- 12,734 .42 50.10 1.97 OHIO 1 _- 12.800 2.60 53.48 2.09 TOTAL/AVERAGE 16.816 100 9.662 .90 31.37 1.62 Illinois coal suppliers sold about 1.5 million tons of coal to three Wisconsin utilities in 1986. The Illinois coal sales represent about nine percent of Wisconsin's total utility coal receipts. The reduction in Illinois coal receipts, in recent years, is a result of Wisconsin tightening its S02 emission standard. The major coal supplying states are Wyoming and Montana with 67 percent of the total. Illinois coal sales include Wisconsin Electric Power Company, Dairyland Power Cooperative and Madison Gas and Electric Company. Illinois coal sales for the period 1981 through 1986 are shown in Table 14-5. Since 1981, Illinois coal sales have fallen by 45 percent. TABLE 14-5. WISCONSIN'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1981 -1986. YEAR 1981 1982 1983 1984 1985 1986 THOUSAND TONS 2,717 3,295 3,409 2,994 1,478 1,491 PERCENT SULFUR 2.80 2.60 2.80 2.80 2.40 1.82 BTU/LB 11,046 11,137 11,193 11,063 11,513 11,587 $/TON 33.99 36.78 36.55 37.64 40.84 40.68 */MMBTU 1.54 1.65 1.63 1.70 1.77 1.76 A discussion of the three Wisconsin utilities that purchased Illinois coal in 1986 follows. Map 14-1 shows the locations of the generating stations. 263 MAP 14-1 COAL FIRED GENERATING STATIONS WISCONSIN • ILLINOIS COAL 264 DAIRYLAND POWER COOPERATIVE Dairyland Power Cooperative Incorporated (DPC) headquartered in LaCrosse, Wisconsin, is an electric cooperative involved in the generation and wholesale of electricity to 29 rural electric distribution cooperatives, with more than 174,000 customers. Electric sales are approximately four billion kilowatthours, with a value of $159 million. The service territory includes 62 counties and covers 45,000 square miles in five states. The five states are Wisconsin, Minnesota, Iowa, Illinois and Michigan. DPC employs about 700. DPC has four coal -fired generating stations, located in central and southern Wisconsin. These stations have capability of 785 megawatts, representing 91 percent of DPC's total capability. The coal -fired capability represents seven percent of Wisconsin's total capability. DPC has one nuclear unit rated at 51 megawatts. DPC has electrical generation of nearly three billion kilowatthours. Coal generates about 90 percent of the total. The three billion kilowatthours reprsent seven percent of Wisconsin's total generation. The co-op has 3,267 miles of transmission lines. DPC has electrical interconnections with Northern States Power Company, Interstate Power Company, Wisconsin Power and Light Company and Northwestern Wisconsin Electric Company. DPC purchased 2.2 million tons of coal in 1986. The coal is supplied by Illinois, Montana and Wyoming coal producers, with Illinois supplying 14 percent of the total. DPC's Illinois coal demand represents two percent of Wisconsin's utility coal receipts and accounts for 21 percent of Illinois coal purchases in Wisconsin. Table 14-6 lists DPC's Illinois coal purchases, quality of coal and delivered prices since 1983. DPC has decreased its Illinois coal receipts by 55 percent, while the delivered price has fallen by four percent. TABLE 14-6. DPC'S ILLINOIS COAL PURCHASES, QUALITY OF COAL AND DELIVERED PRICES 1983-1986. YEAR 1983 1984 1985 1986 THOUSAND TONS 713 757 360 320 PERCENT SULFUR 3.22 3.06 2.99 2.82 BTU/LB 10,792 10,740 10,835 10,890 $/T0N 34.40 34.77 35.15 33.35 1/MMBTU 1.59 1.62 1.62 1.53 265 The following paragraphs discuss the four coal -fired generating stations. Table 14-7, at the end of this narrative, supplies additional information on these stations and systemwide data. Map 14-1 shows the locations of these stations. The Alma Station is located in Buffalo County at Alma. It consists of five older pulverized coal units with capability of 186 megawatts. The station represents 21 percent of DPC's total capability. Alma's generation of 0.5 billion kilowatthours represents 30 percent of its capability and accounts for 17 percent of DPC's total generation. The average cost per kilowatthour of generation is 2.4 cents. Of this total, the fuel expense averages two cents. Alma is DPC's second most efficient station. The station burned 0.2 million tons of Illinois, Pennsylvania, West Virginia and Montana coal in 1986. The coal averages 10,989 BTU per pound of coal and 1.4 percent sulfur. S02 emissions are 2.4 pounds per million BTU of input. Nationally, Alma is ranked 160th in total tons of S02 emissions. No information is available concerning the cost of FGD retrofit. The Illinois coal is supplied by Consolidation Coal Company and Peabody Coal Company, both by contract. The coal is received by barge and rail. The Wyoming coal is supplied by Amax Coal Company by contract through 1997. Westmoreland Resources Company supplies the Montana coal by contract through 1993. The Pennsylvania coal is supplied by U.S. Steel Mining Company by contract. The Genoa Station is located in southern Wisconsin at New Genoa. It consists of one pulverized coal unit with capability of 353 megawatts, representing 20 percent of DPC's total capability. DPC owns 50 percent of the station. The 1.5 billion kilowatthours of generation represents 50 percent of its capability and 25 percent of DPC's total generation. The cost per kilowatthour of generation is 1.9 cents, with the fuel expense at 1.6 cents. Genoa is DPC's most efficient station. The station burned 0.7 million tons of coal in 1986. The coal averages 10,889 BTU per pound of coal and 1.7 percent sulfur. The S02 emission rate is 3.1 pounds per million BTU of input. Genoa ranks 105th nationally in total tons of S02 emissions. The station is rated very difficult for FGD retrofit because of limited space. Illinois coal producers supply about 30 percent of the coal. The Illinois coal is supplied by Peabody Coal Company under contract and Consolidation Coal Company by contract through 1989. The coal is received by rail and barge. The Pennsylvania coal is supplied by U.S. Steel Mining Company by contract, while the Montana coal is supplied by Westmoreland Resources Company by contract through 1993. The Madgett Station is located in central Wisconsin at Alma. The station is adjacent to the Alma station. It consists of one relatively new pulverized coal unit with capability of 371 megawatts. The station 266 represents 43 percent of DPC's total capability. Madgett's generation of 1.4 billion kilowatthours represents 43 percent of its capability and 47 percent of DPC's total generation. The cost per kilowatthour of generation is 2.6 cents, with the fuel expense at 2.3 cents. The station ranks third in economic efficiency. Madgett uses a compliance coal to meet the U.S. Environmental Protection Agency's New Source Performance Standard. The station burned one million tons of Wyoming coal in 1986. The coal averages 8,377 BTU per pound of coal and 0.3 percent sulfur. S02 emissions are 0.8 pound per million BTU of input. The Stoneman Station is located at the southern edge of Wisconsin at Cassville. It consists of two older pulverized coal units with capability of 53 megawatts. Stoneman is DPC's smallest coal -fired station and represents six percent of DPC's total capability. Stoneman's generation of 51 million kilowatthours represents 11 percent of its capability and a small amount of DPC's total generation. The cost per kilowatthour of generation is 2.9 cents, while the fuel expense averages 2.4 cents. It is the least efficient of the four coal -fired stations. The station burned 30,000 tons of Illinois and Pennsylvania coal in 1986. The coal averages 12,369 BTU per pound of coal and two percent sulfur. The S02 emission rate is 3.2 pounds per million BTU of input. No information is available concerning the cost consideration for FGD retrofit. Peabody Coal Company supplies the Illinois coal under contract. The coal is received by rail. The Pennsylvania coal is supplied by Consolidation Coal Company and U.S. Steel Mining Company, both by contract. 267 — J Z CO <5 z o o O Z I— o I- * to ^ O WO O I— co o CO Ul CO I* Ul (/) Ok z P»» o o • o •-< ^ CJ ^ i-o < lO 0£ I— 00 Ul Ul co cn _1 2 -* CBOO 52 -J UJ >- z Ct UJ I >- Q_ « *« <_l w ►- h- S Ul o z o Ul w Ul a. >- co < ui z *■* O -J < CO o o o o o o o o o o o o o o o q. cw a. o. a, • • • • • o cn o oo co CM «-l CM ^ !•«» cn en on on on ^h cm o ^ in < < o o o 00 CM CM CO CM CM O CO o cn IT) cn cn oo < O II 3 1 II H- 1 onso> co II CM 00 1 1 NN^CvJ cn II O Z 1 i co cn cm cn CO II CO Z 1 | • • • • • II ^* 1 IIOHNH CM II 00 1 II —1 1 II II II II II II II 3 1 II t— 1 KOiflotoa CO II 0O 1 1 CM CO ^ CO «* II jj | i cn co co cn co II 3E 1 1 • • • • • II ">«o 1 ! *-> t-4 t— « •— I i— 1 II ^ 1 II II II II II 2 1 i cn cm co on cn II O 1 i co r** co co cn II ^i i • • • • i co cn cm o • cn II II V* 1 i i lOCO^O co II 1 • • • • • II X i IWOHH i— i II II II II II II u 00 1 MONO cn — 1 1 1 O CM CM CO 00 II ^>. 1 i o oo cn oo cn II 3 1 | ■ m m m •h II H- 1 1 — > 00 - CO 1 u H- Z 1 1 -* CO CO CO CO II •-i O 1 1 • • • • • II I— »— 1 i « II Ul 1 1 «■ or II — 1 1 1 Z < CO M —J II _i a. i |N(-Z> < II < O. 1 1 -J z z »— II O 3 1 1 _ J O Ul • o II O CO 1 1 i-* Z 0k 2 1— M 268 UJ --o JZIA < 3 Z O co O <-> z t— o ^-» o I- ^ CO O CO o y- i >■ - 3 h- LU -J ^-o CO < o o ho i o o o co o o en Cn in oo o CO en * CO CO co < o o CO • CM WO CO en en CO < „ o < i— u UJ II _l Z CO » c (0 >• CO H- Z •-« o < o 3 O o-o o o LU < Q. 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II Z II • II O CO II 2 II 269 LU *-*. ■ Q= i-i X <_l w CO o z i- \~ ^ ££© uj o z o C0 _l to < UJ o o to O 1 o ■ o ■ m gf O 1 en ■ «o ■ to 1 m | *t ■ O 1 CM 1 n < 1 1 •—• I r^ ■ to 1 10 1 « 1 O 1 10 1 COAL COAL woo 17.5 35.2 I** 1 CM I 10 I 1951 1953 1 ^(M si H UJ ■ O ■ h- M CO -J 1 < 1 H- ■ O N CM CO © Z tO Z o co < to >■ to I- Z i-i o 3 O o-o —i a. < a. o =D o to 1 «* ^H CO 1 ■ oo co IO ■ icon i «— < I I • • 1 1 1 10 CM CO 1 ■ UJ CO o • ■ oo ^ •—t ■ ■ IO to to ■ 1 • . i i r-» .-* •—> I ■ CO 10 CO 1 ■ en en CO I I • 1 ■ CO ~+ en ■ ■ CO * CO 1 ■ o in >* i ■ r». en en i M * *•■ | ■ o «o r*» ■ ■ 1-4 1 ■ CO 10 O 1 ■ CM to o ■ H . . 1 ■ CO »-« CM ■ ■ 10 10 en ■ ■ o to to ■ a r»» o> CO ■ M • • * : H ■ O CM CM ■ 1 HH <—* ■ ■ ^ 10 CM 1 I • % ■ r^ — en ■ » CM CM 1 J < 1 *■* : 5 ■ ui > » <-« -j ■ © >■ ■ Z CO _j a 1 *■* z < ■ ■ -J z I- ■ ■ — J UJ o a ■ i-* o. h- ■ to to ac ec o o < < o o _> _J CO CO t— t— i CO to z z ^ ^ t- h- O O H- I— ►- H- Z Z < < o o Z 3 O O ^* — * < < O O _i -J w w(Mf -J-l UJ Ul » - <— i >— i Z Z CM O 00 CO CO CM lOlflCMCOON 40 00 * • • oo r*» CM CO CM CD ■ «— i <— * I ^H h- to —t Ul _1 to >• oo z H- < O i-i Q. 00 -JO I— i O CU oo < o — i O.Ui< — i O i— i o u. Z -J i ■-"<-! -IH< — I O O who 270 MADISON GAS AND ELECTRIC COMPANY Madison Gas and Electric Company is an investor-owned utility involved in the generation, purchase and distribution of electricity, and the sale of natural gas. Madison sells electricity to 105,000 customers in a 250 square mile area of southern Wisconsin, with most of the total in the Madison area. The company employs 725. Madison Gas and Electric Company is headquartered in Madison, Wisconsin. Electric sales are nearly two billion kilowatthours, valued at $125 million. Total kilowatthours sold ranks Madison as the fifth largest Wisconsin electric utility. Nationally, Madison is ranked 98th. Madison owns one coal-fired generating station, located in Madison, Wisconsin. Madison also owns 22 percent (216 megawatts) of Wisconsin Power and Light Company's Columbia coal -fired station and 18 percent of Wisconsin Public Service Corporation's Kewaunee nuclear station (95 megawatts). Madison's total capability is 598 megawatts. The coal -fired capability totals 317 megawatts, or 53 percent of Madison's capability. Madison's coal -fired capability represents three percent of the state's total capability. Madison has 1,400 miles of above ground power lines and 509 miles of underground lines. The company has electrical interconnections with Wisconsin Power and Light Company and Wisconsin Public Service Corporation. Madison has electrical generation of approximately 1.8 billion kilowatthours. Coal accounts for 61 percent of the total generation. Statewide, Madison's generation represents four percent of total generation. Madison purchased 36,000 tons of coal in 1986. Of this total, 3,000 tons of Illinois coal were purchased from one coal producer. For Wisconsin, Madison's Illinois coal purchase represents a small portion of the utility's total coal demand. Table 14-8 lists the Illinois coal purchase, quality of coal and delivered price for 1986. For the period of this study, Madison only purchased Illinois coal in 1986. 271 TABLE 14-8. MADISON'S ILLINOIS COAL PURCHASE, QUALITY OF COAL AND DELIVERED PRICE 1986. YEAR 1986 THOUSAND TONS 3 PERCENT SULFUR 1.41 BTU/LB 11,211 S/TON 39.58 $/MMBTU 1.77 The following paragraphs describe Madison's one coal -fired station, while Table 14-9 provides additional data. Refer to Map 14-1 for the location of this station. The Blount Street Station is located in Madison. The station consists of two older pulverized coal units with capability of 101 megawatts. The station represents 17 percent of Madison's total capability. The station's generation of 63 million kilowatthours represents seven percent of its capability and four percent of Madison's total generation. The production expense for the station is not available, but the fuel expense averages three cents per kilowatthour. Blount Street consumed 47,000 tons of Illinois and Indiana coal in 1986. The coal averages 11,211 BTU per pound of coal and 1.4 oercent sulfur. S02 emissions are 2.5 pounds per million BTU of input. The Illinois coal is supplied through Zeigler Coal Company, by spot market. The coal is received by rail. The Indiana coal is supplied by Little Sandy Coal Company and Bicknell Minerals Incorporated, both by spot market. 272 wo o WO I— I >• h- 52 Q. WO o o o z < o •-- 1 z en eg o * o t— rtUJ<(0 — 1 H- 00 ui uj wo en — i —* eaoo -< *■> H- 2 2 eg ui 32 Z UJ O (9 WO < o o Q O ■ UJ ^-» 1 o ■ _j z §Q » o ■ < 3 Z 1 m | o WO O 1 f» ■ O Z H- 1 *■ ■ O <~ ' 1 O 1 i i en ■ ^ 1 i— i i "^. 1 CO ■ 3 1 m I h- 1 to ■ co i •— • ■ z j 2 1 (- *: i i CO ^x 1 < ■ O WO 1 | O H- 1 21 ■ UJ 1 O 1 s ! 1 ^ 1 < ■ ^. 1 1 V* 1 Z 1 1 >■ - 1 1 O. 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LU «C OS CJ •"« I- < o o W0 LU •• ••W0 Z W0 < O LU Z « W0 O H- < QC .. <- z =3 z ed o o. o LU Q- < < CJ —I O UJ Q — i O •— " o u. — I Z —I i < l-M < _l H- -1 »— < O —I O O H- «-i H- O 280 CHAPTER FIFTEEN SUMMARY The Illinois utility coal market is comprised of a 13 state region located in the midwestern and southeastern United States. In this region, 33 electric utilities used Illinois coal at 62 generating stations in 1986. This study provides detailed information on the demand for energy in this area, including the states supplying coal to each utility and generating station. The report further provides comparative data on coal sales since 1981. The summary brings together much of this data in narrative and tabular form. It reviews relevant coal production data and briefly describes the existing market for Illinois coal. Finally, it analyzes certain key characteristics of the coal market and other factors which may influence the future market for Illinois coal. ILLINOIS COAL PRODUCTION Illinois is the fifth largest coal producing state in the nation, with about seven percent of the nation's total coal production. Illinois coal producers mined approximately 63 million tons of coal in 1986, an increase of about three million tons over 1985. The 51 mines in Illinois are operated by 22 coal companies, of which the top ten producers mine 58 million tons, or 92 percent of the total. The majority of the coal has a sulfur content greater than 2.5 percent, while only six percent of the coal is classified as a low sulfur coal. The Illinois coal production has a mine value of approximately $1.9 billion. Mine employment is about 13,500. Compared to the previous year, the mine value of the coal is nearly the same, while mine employment decreased by nearly 1,300. The primary reasons why revenue stayed the same are reduced coal prices brought on by a surplus of coal, renegotiated coal contracts and a small increase in spot market coal purchases. The reduced mine employment results from a more competitive coal market and improvements in production efficiency. From 1985, the average production per mine employee per man-day increased by about ten percent. About 65 percent of the coal production is taken from 31 underground mines and the remainder from 20 surface mines. The largest underground mine is Monterey Coal Company's Mine No. 2 with 3.3 million tons, while the 281 largest surface mine is Arch of Illinois' Captain Mine with 6.3 million tons. Overall, underground mines produce an average of 1.3 million tons and the surface mines average 1.1 million tons. The 27 largest mines in Illinois account for 81 percent of the total production. Peabody Coal Company continues to be the largest Illinois coal producer accounting for 16 percent of production. Due to recent expansions in operations, Consolidation Coal Company and Arch Mineral Corporation are a close second and third, with about 16 percent and 14 percent, respectively. Consolidation purchased Inland Steel Coal Company's two operating mines in southern Illinois, while Arch Mineral purchased Amax Coal Company's Leahy Mine in southern Illinois and opened the Horse Creek Mine near Pinckneyville. Many of the larger Illinois coal producers are major national producers. Table 15-1 lists the major Illinois coal producers, quantity of production and percent of Illinois coal production. The category of "All Others" consists of the remaining 12 companies and account for nearly eight percent of the total production. TABLE 15-1. ILLINOIS COAL PRODUCERS, COAL PRODUCTION AND PERCENT OF ILLINOIS COAL PRODUCTION. TONS % OF COMPANY (000) TOTAL PEABODY COAL 10,175 16.1 CONSOLIDATION COAL 9,986 15.8 ARCH MINERAL 8,639 13.6 OLD BEN COAL 8,033 12.7 MONTEREY COAL 5,321 8.4 FREEMAN UNITED COAL 5,124 8.1 AMAX COAL 4,473 7.1 ZEIGLER COAL 2,992 4.7 KERR-MCGEE COAL 1,980 3.2 WHITE COUNTY COAL 1,463 2.4 ALL OTHERS 5.047 7.9 TOTAL 63.233 100.0 282 EXISTING MARKET FOR ILLINOIS COAL The following paragraphs describe the Illinois utility coal market. Discussed is the geographic area of the market, the quantity and quality of the Illinois coal and the delivered prices in dollars per ton and per million BTU. The characteristics of the market, including its stability and value to the Illinois economy are also discussed. The Illinois utility coal market is comprised of 13 states, located in the midwestern and southeastern United States. Illinois utilities receive 30 percent of the total utility sales. Outside of Illinois, Missouri utilities continue to be the largest consumers of Illinois coal with 23 percent of the total, followed by Indiana and Georgia. Utilities from the top five states purchased about 50 million tons, or 88 percent of utility sales, while the top eight states purchased 99 percent of the total. Illinois coal that is higher in BTU content and lower in sulfur content is sold in the out-of-state market. In recent years, approximately 90 percent of sales have been to the electric utility industry. Map 15-1 shows the Illinois utility coal market by state and quantity purchased in millions of tons. * The delivered price of Illinois coal to Tennessee is the lowest at $1.23 per million BTU, while the most expensive is to Florida at $2.12 per million BTU. The average cost per million BTU dropped by three cents from $1.66 in 1985 to $1.63 in 1986. Utility coal sales also increased by five percent from the previous year. Table 15-2 lists the states where Illinois coal is consumed. Shown in the table is the quantity of coal purchased, the coal quality and delivered prices. There are 19 states and three foreign countries that supplied 265.2 million tons of coal to the thirteen state region in 1986. The top five coal supplying states are: Kentucky with 74.6 million tons; 111 inois--57.0 million tons; Wyoming--48.6 million tons; Indiana--25.3 million tons; and Alabama--16.4 million tons. These five states account for 84 percent of the total coal supply to this region. Rounding out the top ten coal supplying states are; Montana with 12.6 million tons; West Virginia--6.0 million tons; Virginia--5.4 million tons; Missouri--4.4 million tons; and Tennessee--4.3 million tons. Of the total supply, western coal producers account for 24 percent of the total, while the out-of-country suppliers (Canada, Colombia and South Africa) represent less than, one percent. The balance of Illinois coal sales, approximately six million tons, are to the industrial sector. The industrial customers are primarily located in Illinois, Indiana and Missouri. 283 MAP 15-1 LLINOIS UTILITY COAL MARKET 284 TABLE 15-2. ILLINOIS COAL SALES BY STATE AND QUANTITY AND QUALITY OF COAL. TONS % OF % STATE (OOO) TOTAL BTU/LB SULFUR J/TON S/MMBTU ILLINOIS 17,063 30 10,879 2.89 34.18 1.57 MISSOURI 12,854 23 11,139 2.37 35.46 1.59 INDIANA 10,214 18 10,751 2.68 35.89 1.67 GEORGIA 5,609 10 11,424 2.47 35.89 1.65 FLORIDA 3,935 7 11,616 2.76 49.33 2.12 TENNESSEE 2,915 5 11,749 1.89 28.77 1.23 IOWA 1,971 3 11,257 2.72 35.21 1.56 WISCONSIN 1,491 3 11,587 1.82 40.68 1.76 MISSISSIPPI 336 -- 12.199 2.50 42.64 1.75 KANSAS 284 -- 11,471 2.48 37.84 1.65 ALABAMA 149 -- 12,062 .95 32.80 1.36 MINNESOTA 113 -- 12,250 1.62 51.64 2.11 KENTUCKY 65 -- 11.949 .90 34.70 1.45 TOTAL/AVERAGE 56.999 100 11.113 2.59 36.19 1.63 Of special interest is the stability in the Illinois coal market since 1981. For the period of this study, the 13 state market purchased almost 100 percent of the utility sales. Since 1983, the utilities discussed in this study received 98 percent of the total. Some utilities have left the market, but in total, the utilities that make up the 1986 Illinois coal market are the same as in previous years. Since 1981, Illinois coal producers sold 314.8 million tons of coal to the utility industry, representing about 87 percent of total Illinois coal production. Graph 15-1 compares the Illinois coal production to utility sales since 1981. The demand for Illinois coal has remained fairly stable, except for 1981 when there was a major strike between the United Mine Workers of America and the Bituminous Coal Operators Association. Utility sales have remained in the range of 51 to 57 million tons, annually. Table 15-3 shows a modest decrease in sulfur content and a minimal increase in BTU content over the years. The delivered prices, except for 1981, have remained nearly constant at $1.60 per million BTU. 285 in en CO >■« P o & Q O H O CO CO I CO 03 23 o I— ( H U P Q O « Oh O H en w < >< P CO^OCDC^CO^OCOC^CO^OCDCV2CO^O snoi Nornm 286 TABLE 15-3. ILLINOIS COAL SALES TO ELECTRIC UTILITIES, BY QUANTITY AND QUALITY, DELIVERED PRICE AND PERCENT OF PRODUCTION, 1981-1986. YEAR 1981 1982 1983 1984 1985 1986 THOUSAND TONS 43,877 51,619 50,557 57,601 54,196 56,999 PERCENT SULFUR 2.70 2.70 2.70 2.70 2.60 2.59 BTU/LB 10,958 10,959 11,000 11,027 11,075 11,113 $/TON 31.98 34.35 35.30 36.05 36.80 36.19 $/MMBTU 1.46 1.57 1.60 1.63 1.66 1.63 % OF PRODUCTION 85 84 87 88 90 90 Of the 33 electric utilities that purchase Illinois coal, the top ten consume approximately 80 percent of the total. The largest users of Illinois coal are: Union Electric Company with 17 percent of total receipts; Illinois Power Company with 12 percent; Public Service Company of Indiana at 11 percent; Georgia Power Company at ten percent; and Central Illinois Public Service Company with seven percent. Of the top ten users, seven are located outside of Illinois. In total, these ten utilities purchased more than 44 million tons, or nearly 80 percent of Illinois utility coal sales. The seven out-of-state utilities listed in Table 15-4 purchased 55 percent of the total, and are identified by an asterisk. TABLE 15-4. ILLINOIS COAL PURCHASES BY UTILITY, QUANTITY AND PERCENT OF TOTAL UTILITY PURCHASES. UTILITY NO. OF PLANTS TONS (000) % OF TOTAL UNION ELECTRIC COMPANY 4 ILLINOIS POWER COMPANY 4 PUBLIC SERVICE OF INDIANA 2 GEORGIA POWER COMPANY 3 CENTRAL IL. PUBLIC SERVICE 4 TENNESSEE VALLEY AUTHORITY 6 N. INDIANA PUBLIC SERVICE 3 COMMONWEALTH EDISON COMPANY 1 ASSOCIATED ELECTRIC COOP 1 SEMINOLE ELECTRIC COOP 1 9,616 6,847 6,444 5,609 3,778 3,128 2,768 2,732 2,101 1.435 17 12 11 10 7 5 5 5 4 3 TOTAL 29 44.458 79 * Out-of-state utilities. 287 The top ten coal -fired generating stations purchased almost 33 million tons or 57 percent of the Illinois coal sales in 1986. The top ten stations are listed in Table 15-5. The Baldwin, Kincaid and Coffeen stations are located in Illinois. TABLE 15-5. TOP TEN ILLINOIS COAL CONSUMING STATIONS. UTILITY STATION MILLION TONS PUBL SERVICE OF INDIANA UNION ELECTRIC COMPANY ILLINOIS POWER COMPANY GEORGIA POWER COMPANY COMMONWEALTH EDISON COMPANY UNION ELECTRIC COMPANY TENN VALLEY AUTHORITY ASSOCIATED ELECTRIC COOP CENTRAL IL PUBL SERVICE GEORGIA POWER COMPANY GIBSON LA BAD IE BALDWIN WANSLEY KINCAID RUSH ISLAND JOHNSONVILLE NEW MADRID COFFEEN YATES 6.2 5.0 4.6 3.2 2.7 2.5 2.4 2.1 2.0 1*1 TOTAL 32.6 Of the 62 stations where Illinois coal is utilized,** in-state coal sales (30% of total sales) are to 16 generating stations with about ten thousand megawatts of capability. These stations are owned by seven companies. Out-of-state sales are to 46 generating stations, with a total capability of approximately 37 thousand megawatts. These stations are operated by 26 utilities. The 47 thousand megawatts of electric capability where Illinois coal is utilized represents 16 percent of the nation's coal -fired capability. As previously outlined, the utility coal market is very important to the Illinois coal industry. The utility industry consumes approximately 90 percent of Illinois' annual coal production. These sales result in employment of nearly 11,000 mine employees with an annual payroll of $362 million and total economic benefits of $1.2 billion. These figures are based on an average annual salary of $33,000 per mine employee (direct benefits) and an economic multiplier of 2.25. The multiplier takes into account jobs created to provide support service to a mine and additional income resulting from the spending of direct benefits. ** Table 15- all the name of station, 7, located at the end of the summary, contains a listing of stations using Illinois coal. Included in the table is the the utility, in alphabetical order, name of generating quantity of Illinois coal used and percent of II inois coal to the total quantity of coal used at each facility. 288 FACTORS AFFECTING THE FUTURE MARKET FOR ILLINOIS COAL The future of the Illinois utility coal market will be influenced by a number of factors which are known today. Some of these events will clearly have a negative impact on the market, while some events could influence the market in a positive manner. Other factors are significant only in the context of acid rain legislation. These factors include: -- future coal -fired capability in the market region; -- future nuclear capability in the market region; -- the duration and quantity of Illinois coal contracts; -- the size of the spot market; -- the boiler type and age distribution of stations using Illinois coal ; -- the S02 and NOx emission rates at stations using Illinois coal; -- the ease or difficulty of retrofitting stations with emission control technologies; and -- the amount of capability already retrofitted with FGD. These considerations are discussed below and illustrated in tables located at the end of the narrative. Their relevance to the future of the Illinois coal market is briefly analyzed. Future Illinois coal sales will be very dependent on new coal -fired generating capability. Some coal -fired capability has been moved backwards on the utility industry's planning horizon. This is primarily the result of small increases in electrical demand and the additions to nuclear capability. (Approximately 11,000 megawatts of nuclear capability will be on-line over the next ten years). Table 15-6 lists the future coal -fired capability in the Illinois coal market. The table lists the name of the utility, the name of the station and unit(s), the megawatts of capability and projected in-service date. The future capability totals 6,930 megawatts with a potential market for coal of about 20 million tons, annually. No information is available concerning the burning of Illinois coal at these 11 facilities. However, only two of the utilities listed are presently using Illinois coal for electrical generation. These two utilities will need about four million tons of coal for these two stations when they come on-line. Historically, utilities have utilized high sulfur coal because of its heating value, delivered price and localized availability. In return for a guaranteed quantity and quality of coal from coal producers, utilities were willing to sign long-term contracts. Generally, the length of the contracts was the useful life of the generating station since a boiler was designed to burn a certain quality of coal and any variation in coal quality could reduce its economic and operational performance. For Illinois coal sales, approximately 93 percent of sales are by contract, with the remainder by spot market. Of importance is the time frame when many of these contracts will expire. Approximately 50 percent of the 289 contract sales will terminate during a possible acid rain compliance period (1994-2002). Further, there are no guarantees that coal contracts will continue in the event of acid rain reductions. Unless best available control technologies are specified in a contract, a utility may be able to terminate a contract because of federal legislation. Graph 15-2 illustrates the quantity of Illinois coal by type of sale. Included in the pie chart is the percentage of sales by contract and spot market. The quantity of Illinois coal is shown as: contracts with no expiration dates; contracts with expiration dates through 1989; contracts with expiration dates of 1990 through 1993; contracts with expiration dates of 1994 through 1997; contracts with expiration dates of 1998 through 2002; contracts with expiration dates of 2003 through 2007; and contracts with expiration dates later than 2007. As an example, 13 percent of the contract sales will terminate during 1990-1993. Also included is the quantity of Illinois coal sold by spot market. Spot market sales total four million tons, or seven percent of the total utility sales. Since 1981, spot market sales have stayed about the same. Based on contract sales as of 1986, a minimum of 58 percent of the contract sales (33 million tons) will be in effect after 1993. Prior to 1993, a minimum of 29 percent of the contract sales (17 million tons) will have expired. A minimum quantity is used since no termination dates are available for six percent of the contract sales. Of the 62 stations using Illinois coal, 39 stations are using Illinois coal to meet at least 60 percent of their total coal demand. This will be of concern since many of these stations will be affected by acid rain legislation, if enacted. Of the 39 stations, 32 have no control technologies for reducing S02 emissions. Further, 25 of these stations are listed in the top 200 S02 emitting stations. Table 15-7 lists the stations using Illinois coal. Shown in the table is the name of the utility, the name of the generating station, the quantity of Illinois coal receipts and the percent of Illinois coal receipts to the total quantity of coal used at each facility. Overall, 59 percent of the coal used at the 62 stations comes from Illinois. Table 15-8 further lists the 40 generating stations using Illinois coal, by S02 rank. The 40 stations are derived from the top 200 list prepared by Energy Ventures Analysis Incorporated. The ranking is based on estimated S02 emissions as of 1980. Most acid rain proposals use 1980 as the base year for determining S02 emissions. In the event of S02 reductions, many of these stations will be forced to reduce their emissions by either installing F6D systems or using a low sulfur compliance coal. The table includes the name of the utility and generating station, its S02 rank and the quantity of Illinois coal used at the facility. The 40 stations consume approximately 50 million tons annually, or 87 percent of Illinois utility coal sales. Because of the large volume of Illinois coal going to many of the stations discussed above, Illinois coal mines are large in size and realize economies of scale. This implies that as Illinois coal mines increase their production, their average cost of production decreases. On average, Illinois' 20 largest underground mines produce over 1.7 million tons per year and the seven largest surface mines average 2.4 million tons per 290 CV2 I X O in w CO H w PS <3 H O CU CD o H U O O o o CO w < CO CD O I ro O O CN O o CN a: LU > O W UJ < o Q_ if) a o o q o q oo 291 year. As for sales, many of these mines have less than three buyers for their coal, while some mines are dedicated to only one buyer. In the event that coal contracts are not renewed or cancelled, many coal producers may have to close their mines. Most acid rain studies do not take into account the loss of a major coal buyer and its impact on the economies of scale realized at these large mine sites. In many cases, a fifty percent reduction in sales could mean the closing of a mine because of the increased production costs and the inability to recover this cost in its coal price. Illinois coal is burned in two types of utility boilers to generate steam for electrical generation. This is important in the event of acid rain reductions. Cyclone boilers produce a nitrogen oxide (NOx) emission rate of 1.4 to 1.8 pounds per million BTU of input, which is double the 0.7 to 0.9 emitted by pulverized coal boilers. Cyclone boilers will have difficulty meeting stricter standards for NOx emissions. NOx control technologies for cyclone boilers are limited and much more expensive than control technologies for pulverized coal boilers. Table 15-9 provides a listing of the 12 stations which have cyclone boilers using Illinois coal. The table includes the name of the utility, name of the station and unit(s), megawatts of capability and quantity of Illinois coal consumed. Cyclone boilers consume almost 16 million tons of Illinois coal, while pulverized coal boilers consume 41 million tons annually. Tables 15-10 and 15-11 provide the megawatts of capability and quantity of Illinois coal purchased by each boiler type. The tables show the megawatts of capability and boiler age as of 1995, with and without flue gas desulfurization (FGD) and the associated quantity of Illinois coal. This is important in the event of sulfur dioxide (S02) emission reductions. Many acid rain proposals call for a control program by the mid-to late-1990's. Should this be implemented, many plants because of their age, along with the cost of an FGD system may not retrofit with FGD and burn high sulfur coal, but switch to a low sulfur compliance coal, unless best available technology is mandated as an S02 control strategy. In 1995, it is projected there will be 30,713 megawatts of capability without FGD that will be over 21 years old. This capability consumes about 35 million tons of Illinois coal annually. In the event of federal legislation to reduce S02 emissions, a number of stations (units) may be candidates for FGD retrofit. Included in this study is 34 stations that use Illinois coal and the cost consideration of FGD retrofit. Broken down by cost consideration, 8.3 million tons of Illinois coal are used at facilities rated easy; 15.2 million tons are rated modest; 11 million tons are rated difficult; and 5.5 million tons are rated very difficult. Approximately 25 percent of the Illinois coal market could be lost because of the unlikelihood of FGD retrofit at some stations. The consideration for FGD retrofit includes: the age of the boiler, the size of the boiler, site congestion, stack adjustments, boiler modifications, demolition, duct length requirements, gas flow adjustments, soil conditions and underground modifications, to name a few. Table 15-12 includes the name of the utility, the name of the station and unit number(s), cost consideration of FGD retrofit and quantity of Illinois 292 coal receipts. These stations burn nearly 40 million tons of Illinois coal annually. The total quantity of Illinois coal by FGD cost consideration is shown at the bottom of Table 15-12 and listed as Table 15-12A. Approximately 14 percent of the Illinois utility coal sales are to generating stations that currently meet federal/state S02 emission standards. Sales to these stations are "somewhat protected" in the event of acid rain reductions. However, there is no guarantee that Illinois coal will always be used at these facilities. As an example, the coal contract with Hoosier Energy's Merom Station was terminated in 1987. Twelve stations equipped with FGD systems are presently using about eight million tons of Illinois coal annually. Table 15-13 provides a listing of the generating stations equipped with FGD systems and using Illinois coal. In conclusion, the Illinois coal market will be impacted by a number of factors in the future. In meeting these concerns, the Illinois coal industry is becoming more price competitive through increased mine efficiency. However, many factors are beyond the control of the coal producer and include the growth in electrical demand, nuclear generation, transportation cost of the coal and federal and state laws. This study has been an attempt to provide the reader with an understanding of the Illinois coal market. The final table in this study, Table 15-14, provides a detailed database on the 62 generating stations that use Illinois coal. The table includes the name of the utility; the name of the station; its location by state; the number of units in the station; the in-service dates for the oldest and newest units; the megawatts of capability; the percent of cyclone capability to the total capability of the station, if applicable; the megawatts of capability with an FGD system, if applicable; and the quantity of Illinois coal used at the facility. This table encompasses much of the data analyzed above and should be useful in obtaining an overall picture of the Illinois coal market. 293 WSJSA* "" URECOftL ,,m» THE 1U1H01S COAL MARKET. .FIRED CAPABILITY W w -.«»nti 1TY ON 101UEL ALABAMA POWER ASSOCIATED ELECTRIC COOP E. KENTUCKY POWER COOP EMPIRE DIST ELECTRIC COMP GEORGIA POWER COMPANY INDIANA AND MICHIGAN ELEC JACKSONVILLE ELECTRIC AUTH LOUISVILLE GAS I ELEC NORTHERN STATES POWER ORLANDO UTIL COMMISSION. STATION _ANDJ3N1I ^«£ m J* Miller 3 Miller 4 Vlatson 1 Smith 1 584 602 1997 1992 755 1,191 Riverton 1 Scherer 4 Rockport 2 St. Johns River 2 629 Trimble County 1 m. 7 130 Riverside / 739 Sherburne 3 72 PLANNED 1989 1988 1988 1991 1987 1987 294 TABL E 15-7. GENERATING STATIONS USING ILLINOIS COAL, QUANTITY OF ILLINOIS COAL AND PERCENT OF ILLINOIS COAL TO TOTAL COAL DEMAND AT THE FACILITY. ILLINOIS COAL % OF IL. COAL TO UTILITY AND STATION (OOP TONS) TOTAL RECEIPTS Associated Electric Cooperative New Madrid 2,101 100 Central Electric Power Cooperative Chamois 63 100 Central Illinois Light Company Duck Creek 897 100 Edwards 101 8 Central Illinois Public Service Coffeen 1,967 100 Grand Tower 340 100 Meredosia 600 100 Newton 871 56 Commonwealth Edison Company Kincaid 2,730 100 Will County 2 Dairyland Power Cooperative Alma 23 Genoa 290 30 Stoneman 8 28 Eastern Iowa Light and Power Cooperative Fair 97 78 Electric Energy Incorporated Joppa 1,183 51 Georgia Power Company Atkinson-McDonough 471 34 Wansley 3,231 71 Yates 1,907 63 Gulf Power Company Crist 1,282 76 Hoosier Energy Rural Electric Cooperative Merom > 1,002 56 295 TABLE 15-7 (CONTINUED) UTILITY AND STATION ILLINOIS COAL (000 TONS) % OF IL. COAL TO TOTAL RECEIPTS Illinois Power Company Baldwin Hennepin Vermillion Wood River 4,587 1,010 493 757 100 100 78 100 Interstate Power Company Dubuque Kapp Lansing 129 434 58 98 86 8 Iowa Electric Light and Power Prairie Creek Sixth Street Sutherland 400 67 24 96 100 11 Iowa- Illinois Gas and Electric Company Riverside 259 85 Iowa Southern Utilities Company Burlington 20 7 Kansas City Board of Public Utilities Kaw Quindaro 79 205 100 100 Kansas City Power and Light Company Montrose 43 5 Madison Gas and Electric Company Blount 3 8 Mississippi Power Company Watson 336 17 Muscatine Power and Water Department Muscatine 484 100 Northern Indiana Public Service Bailly Michigan City Schahfer 677 749 1,342 82 82 72 Public Service Company of Indiana Gallagher Gibson 213 6,231 27 89 296 TABLE 15-7 (CONTINUED) UTILITY AND STATION ILLINOIS COAL (000 TONS) % OF IL TOTAL . COAL TO RECEIPTS Rochester Department of Public Utilities Silver Lake 113 100 Seminole Electric Cooperative Seminole 1,435 49 Sikeston Board of Municipal Utilities Slices ton 242 80 Southern Illinois Power Cooperative Marion 737 100 Springfield City Water, Light and Power Dal 1 man Lakeside 710 77 100 100 Tampa Electric Company Big Bend Tennessee Valley Authority TOTAL 1,217 Allen 434 Col bert 3 Cumberland 98 Johnsonville 2,383 Shawnee 65 Widows Creek 146 Union Electric Company Labadie 4,948 Meramec 473 Rush Island 2,549 Sioux 1,646 Utilicorp United, Incorporated Sibley 790 Wisconsin Electric Power Company Oak Creek 1.167 57.000 23 29 1 77 2 5 100 89 100 98 100 66 59 Rounded 297 TABLE 15-8. TOP S02 EMITTING STATIONS THAT USE ILLINOIS COAL, BY UTILITY, STATION AND NATIONAL RANK. UTILITY S02 IL. COAL STATION RANK (000 TONS! Cumberland 3 98 Gibson 4 6,231 Labadie 6 4,948 Baldwin 7 4,587 Wans ley 13 3,231 Kincaid 14 2,730 Madrid 15 2,101 Montrose 23 43 Coffeen 24 1,967 Big Bend 27 1,217 Johnsonville 31 2,383 Col bert 33 3 Oak Creek 35 1,167 Shawnee 36 65 Sioux 40 1,646 Yates 43 1,907 Joppa 45 1,183 Michigan City 63 749 Crist 65 1,282 Allen 68 434 Widows Creek 75 146 Watson 77 336 Rush Island 79 2,549 Gallagher 85 213 Bailly 98 677 Meredosia 103 600 Genoa 105 290 Sibley 118 790 Hennepin 122 1,010 McOonough 140 471 Kapp 150 434 Vermilion 155 493 Alma 160 23 Dal 1 man 161 710 Meramec 164 473 Schahfer 169 1,342 Quindaro 174 205 Sutherl and 176 24 Marion 180 737 Grand Tower 188 340 Tennesee Valley Authority Public Service Company of Indiana Union Electric Company Illinois Power Company Georgia Power Company Commonwealth Edison Company Associated Electric Cooperative Kansas City Power and Light Central Illinois Public Service Tampa Electric Company Tennessee Valley Authority Tennessee Valley Authority Wisconsin Electric Power Tennessee Valley Authority Union Electric Company Georgia Power Company Electric Energy Incorporated Northern Indiana Public Service Gulf Power Company Tennessee Valley Authority Tennessee Valley Authority Mississippi Power Company Union Electric Company Public Service Company of Indiana Northern Indiana Public Service Central Illinois Public Service Dairyland Power Cooperative Utilicorp United Incorporated Illinois Power Company Georgia Power Company Interstate Power Company Illinois Power Company Dairyland Power Cooperative Springfield City Light k Power Union Electric Company Northern Indiana Public Service Kansas City Board of Publ. Util. Iowa Electric Light and Power Southern Illinois Power Coop Central Illinois Public Service TOTAL 49.835 298 TABLE 15-9. CYCLONE-FIRED BOILERS BURNING ILLINOIS COAL. UTILITY STATION UNITfSl MEGA- WATTS IL. COAL (OOP TONS) Associated Electric Coop Central Electric Power Coop Central Illinois Public Service Commonwealth Edison Company Commonwealth Edison Company Illinois Power Company Iowa Electric Light and Power Kansas City Board of Publ Util Kansas City Board of Publ Util Muscatine Power and Water Southern Illinois Power Coop Northern Indiana Public Service Northern Indiana Public Service Northern Indiana Public Service Springfield Water, Light and Pow Springfield Water, Light and Pow Tennessee Valley Authority Union Elect ire Company Utilicorp United Incorporated Madrid 1-2 1,160 2,101 Chamois 2 49 47 Coffeen 1-2 875 1,967 Kincaid 1-2 1,108 2,730 Will County 1-2 299 2 Baldwin 1-2 1,174 3,073 Sutherland 3 80 13 Kaw 3 55 34 Quindaro 1 73 66 Muscatine 8 79 148 Marion 1-4 272 737 Bailly 7-8 480 677 Mich City 2-3-12 589 749 Schahfer 14 431 352 Dall man 1-2 174 339 Lakeside 6-7 80 77 Allen 1-3 873 434 Sioux 1-2 900 1,646 Sibley 1-3 461 790 TOTAL 9,212 15.982 299 TABLE 15-10. CYCLONE BOILER CAPABILITY IN MEGAWATTS AND AGE, AND ILLINOIS COAL SALES. AGE OF PLANT AS OF 1995 (IN YEARS) 10-15 16-20 21-25 26-30 OVER 30 MW W/OUT FGD: -- 1,011 2,859 3,297 1,875 ILLINOIS COAL SALES (000 TONS): -- 1,403 6,124 6,605 1,387 MW WITH FGD: — 170 ILLINOIS COAL SALES (OOP TONS): zz 461 TABLE 15-11. PULVERIZED COAL BOILER CAPABILITY IN MEGAWATTS AND AGE, AND ILLINOIS COAL SALES. AGE OF PLANT AS OF 1995 (IN YEARS) 10-15 16-20 21-25 26-30 OVER 30 MW W/OUT FGD: — 8,652 8,039 1,822 12,821 ILLINOIS COAL SALES (000 TONS): « 13,050 8,147 1,452 11,021 MW WITH FGD: 4,285 1,106 -- — 1,000 ILLINOIS COAL SALES (OOP TONS): 5.137 2.139 — 83_ 300 TABLE 15-12. STATIONS USING ILLINOIS COAL AND COST CONSIDERATIONS FOR FGD RETROFIT. UTILITY STATION/UNITfS) COST CONSIDERATION IL COAL (000 TONS) Associated Electric Coop Madrid 1-2 Modest 2,101 Central 11 Publ Svce Central 11 Publ Svce Central 11 Publ Svce Coffeen 1-2 Grand Tower 3-4 Meredosia 1-3 Easy Very Difficult Very Difficult 1,967 340 600 Commonwealth Edison Kincaid 1-2 Modest 2,730 Dairyland Power Coop Genoa 3 Very Difficult 290 Electric Energy Inc Joppa 1-6 Modest 1,183 Georgia Power Company Georgia Power Company Georgia Power Company McDonough 1-2 Yates 1-5 Yates 6-7 Difficult Difficult Easy 471 847 1,060 Gulf Power Company Gulf Power Company Crist 4-5 Crist 6-7 Very Difficult Modest 223 1,059 Illinois Power Company Illinois Power Company Illinois Power Company Baldwin 1-3 Hennepin 1-2 Vermilion 1-2 Modest Difficult Difficult 4,587 1,010 493 Interstate Power Company Kapp 1-2 Difficult 434 Iowa Electric Light and Pow Sutherland 1-3 Difficult 24 Kan City Brd of Publ Util Quindaro 1-2 Difficult 205 Kansas City Power and Light Montrose 1-3 Very Difficult 43 Mississippi Power Mississippi Power Watson 4 Watson 5 Difficult Easy 116 220 Northern Ind Publ Service Northern Ind Publ Service Bailly 7-8 Michigan City 12 Difficult Difficult 677 596 Public Svce of Indiana Public Svce of Indiana Gallagher 1-4 Gibson 1-4 Difficult Easy 213 5,000 Southern 11 Power Coop Marion 1-3 Very Difficult 276 Springfield Light and Power Dallman 1-2 Difficult 339 Tampa Electric Company Big Bend 1-3 Modest 882 301 TABLE 15-12 (CONTINUED) UTILITY STATION/UNITfSl COST CONSIDERATION IL COAL (000 TONS) Tennessee Valley Authority Tennessee Valley Authority Tennessee Valley Authority Tennessee Valley Authority Allen 1-3 Colbert 5 Cumberland 1-2 Johnsonville 1-10 Difficult Easy Easy Very Difficult 434 3 98 2,383 Union Electric Company Union Electric Company Union Electric Company Union Electric Company Union Electric Company Labadie 1-4 Meramec 1-2 Meramec 3 Meramec 4 Sioux 1-2 Difficult Very Difficult Difficult Modest Modest 4,948 138 152 183 1,646 Utilicorp United Inc Sibley 1-3 Modest 790 Wisconsin Electric Power Oak Creek 1-8 Very Difficult 1.167 TOTAL 39.928 TABLE 15-12A. QUANTITY OF ILLINOIS COAL BY F6D COST CONSIDERATION. COST CONSIDERATION: EASY MODEST DIFFICULT IL COAL (000 TONS): 8.348 15.161 10.959 VERY DIFFICULT 5.460 The cost consideration of FGD retrofit was taken from Evaluation of S02 Emissions And The FGD Retrofit Feasibility At The 200 Top Emitting Generating Stations prepared by Energy Ventures Analysis Incorporated for the U.S. Environmental Protection Agency. FGD retrofit categories are: easy; modest; difficult; and very difficult. The "easy" rank means that the capital cost is from 1.0 to 1.3 times more expensive than an FGD system at a new 500 megawatt plant; "modest" costs from 1.3 to 1.6 times more; "difficult" costs from 1.6 to 1.9; and "very difficult" is greater than 1.9 times the capital cost of a new FGD system. The study states, "that it should be useful in determining the relative degree of difficulty of retrofitting FGD systems on these powerplants." 302 TABLE 15-13. STATIONS THAT ARE EQUIPPED WITH AN FGD SYSTEM AND USING ILLINOIS COAL. UTILITY STATION UNITfSl MEGA- WATTS IL. COAL (OOP TONS) Central Illinois Light Company Central Illinois Public Service Hoosler Energy Rur Electric Coop Muscatine Power and Water Northern Indiana Public Service Public Service Co of Indiana Seminole Electric Si Ices ton Board of Southern Illinois Springfield Water Tampa Electric Company Tennessee Valley Authority Coop Publ Util Power Coop Light & Power Duck Creek 1 366 897 Newton 1 550 871 Merom 1 & 2 920 1,002 Muscatine 9 155 289 Schahfer 17-18 739 604 Gibson 5 620 1,230 Seminole 1-2 1,210 1,435 Sikeston 1 212 242 Marion 4 170 461 Dallman 3 190 371 Big Bend 4 429 335 Widows Creek 7-8 1.000 83 TOTAL 6.561 7.820 303 ^— V ■ —J to 1 ot o O O •-• o o cn o co ^ON CO •— 1 < z ■ • « • • • • • • • • • • • • • o o > o co px. »-• px. © o o O CNJ COWN to CO o 1— a o to Cn O (OtfON CO CNJ CO en CO H f-H CO ** cn CO to CO px. 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UJ M >—t 1— CV o -o o u r— cV E T3 CV c cv ■M t— E o VI O- E c c IffM » f- S- t- o «4- E VI UJ CO VI E cv VI c 2 UJ T E X O VI O CV *^- o> «r* CO h- H- 3 => 2 307 7200-S33 PB-37 C BT BIBLIOGRAPHY Associated Electric Cooperative, Incorporated. "Annual Report for 1986." Springfield, Missouri. Central Electric Power Cooperative, Incorporated. "Annual Report for 1986." Jefferson City, Missouri. Central Illinois Light Company. "Annual Report for 1986." Form 21. Peoria, Illinois. Central Illinois Public Service Company. "Annual Report 1986." Form 21. Springfield, Illinois. Commonwealth Edison Company. "Annual Report 1986." Form 21. Chicago, Illinois. Dairyland Power Cooperative. "1986 Annual Report." Lacrosse, Wisconsin. Electric Energy Incorporated. "Annual Report for 1986." Form 21. Joppa, Illinois. Eastern Iowa Light and Power Cooperative. "Current News." Volume 33, Number 4. August 28, 1987. Electric Light and Power . "The Top 100 electric utilities' 1986 operating performances." 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