ITEM 1. BUSINESS
General
Arch Coal, Inc. ("Arch Coal" or the "Company") is the second largest coal producer in the United States. The Company mines, processes and markets compliance and low-sulfur coal from 31 surface, underground and auger mines located in coal fields in the western United States and in the central Appalachian region. Compliance and low-sulfur coal are types of coal that, when burned, emit 1.2 pounds and 1.6 pounds or less of sulfur dioxide per million Btu, respectively. As of December 31, 1999, the Company controlled approximately 3.5 billion tons of measured and indicated coal reserves, of which approximately 1.8 billion tons were located in coal fields in the western United States and 1.3 billion tons were located in coal fields in central Appalachia. The remaining reserves were located in midwestern coal fields. In December 1999, the Company closed its last mining operation in the midwest due to a lack of demand for the mine's high-sulfur coal.
The Company owns a 99% membership interest in Arch Western Resources, LLC ("Arch Western"), a joint venture that was formed in connection with the Company's acquisition of the United States coal operations of Atlantic Richfield Company on June 1, 1998 (the "Arch Western transaction"). The principal operating units of Arch Western are Thunder Basin Coal Company, L.L.C., which operates the Black Thunder and Coal Creek mines in the Southern Powder River Basin in Wyoming; Mountain Coal Company, L.L.C., which operates the West Elk mine in Colorado; Canyon Fuel Company, LLC ("Canyon Fuel"), which operates three mines in Utah; and Arch of Wyoming, LLC, which operates two mines in the Hanna Basin of Wyoming. Arch Western owns 100% of the membership interests of Thunder Basin Coal Company, L.L.C., Mountain Coal Company, L.L.C. and Arch of Wyoming, LLC. Arch Western owns a 65% membership interest in Canyon Fuel, with the remaining 35% membership interest owned by ITOCHU Coal International Inc., a subsidiary of ITOCHU Corporation of Japan.
The Company and its operating subsidiaries (other than Canyon Fuel, the results of operations of which are accounted for using the equity method) sold approximately 111.2 million tons of coal in 1999, 107.1 million tons of which were produced by the Company and the balance of which was purchased for resale. Approximately 82% of this tonnage was sold under long-term contracts (contracts having a term greater than one year) and the balance was sold on the spot market (contracts having a term of one year or less). Approximately 76% of 1999 total revenues were derived from sales of coal under long-term contracts. Sales of steam coal in 1999 totaled 108.7 million tons, or approximately 98% of the Company's 1999 coal sales, while sales of metallurgical coal in 1999 totaled 2.5 million tons, or approximately 2% of the Company's 1999 coal sales. In 1999, sales of coal in the export market totaled approximately 3.5 million tons. Sales of steam coal accounted for approximately 59% of these export sales, while the balance of export sales consisted of sales of metallurgical coal.
Recent Developments
West Elk Operations. The Company temporarily idled its West Elk underground mine in Gunnison County, Colorado, on January 28, 2000 following the detection of higher-than-normal levels of carbon monoxide in a portion of the mine. Higher-than-normal readings of carbon monoxide indicate that combustion is present somewhere within the affected portion of the mine. The Company has sealed the affected portion of the mine while it further isolates the affected area and determines the cause of and solutions to the problem. West Elk produced approximately 7.3 million tons of coal in 1999, employs approximately 300 people and generated approximately $13.1 million of the Company's total operating income in 1999. The Company does not believe the mine's closure will have a material long-term effect on the Company's financial condition, but it could have a material adverse effect on the Company's results of operations until the mine is reopened and fully operating.
Ashland Inc. Proposal. Ashland Inc. ("Ashland"), which owns approximately 58% of the outstanding common stock of the Company, announced on March 16, 2000 that its Board of Directors has declared a taxable distribution to Ashland's stockholders of approximately 17.4 million of its 22.1 million shares of the Company's common stock. The shares will be distributed on or around March 27, 2000 to Ashland's stockholders of record as of March 24, 2000. Ashland also confirmed that it plans to dispose of its remaining 4.7 million shares of the Company's common stock in a tax efficient manner after the distribution, subject to then-existing market conditions. There will be no impact on the operations of the Company as a result of the distribution by Ashland. Ashland first announced its interest in exploring strategic alternatives for its investment in the Company on June 22, 1999.
West Virginia Operations. Recent regulatory developments in West Virginia have adversely affected the Company's ability to economically exploit its mining properties. On October 20, 1999, the U.S. District Court for the Southern District of West Virginia permanently enjoined the West Virginia Division of Environmental Protection (the "West Virginia DEP") from issuing any new permits that authorize the construction of valley fills as part of coal mining operations. The West Virginia DEP complied with the injunction by issuing an order banning the issuance of nearly all new permits involving valley fills and prohibiting the further advancement of nearly all existing fills. On October 29, 1999, the district court granted a stay of its injunction, pending the outcome of an appeal of the court's decision filed by the West Virginia DEP with the U.S. Court of Appeals for the Fourth Circuit. The West Virginia DEP rescinded its order in response to the stay granted by the court. It is impossible to predict the outcome of the West Virginia DEP's appeal to the Fourth Circuit. If, however, the district court's ruling is not overturned or if a legislative or other solution is not achieved, then the ability of the Company and other coal producers to mine coal in West Virginia would be seriously compromised.
Business Environment
Demand for Coal. Coal is the fuel used to generate 51% of all electricity produced in the United States. Coal has consistently maintained a 51-53% market share over competing energy sources during the past 10 years because of its relatively low cost and its availability throughout the United States. On an average, all-in cost per megawatt-hour basis, coal-fired generation is substantially less expensive than electricity generated utilizing natural gas, oil or nuclear power. Hydroelectric power is inexpensive but is limited geographically, and there are few suitable sites for new hydroelectric power dams. Consequently, nearly 85% of the approximate 1.1 billion tons of coal produced in the United States in 1999 was sold in the domestic market as a fuel to generate electricity. The remaining tons were sold into the export market (6%), were sold as metallurgical coal (2%), or were sold as steam coal for other industrial/residential purposes (7%). In addition to the relative competitiveness of coal-fired generation plants, coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting coal production and power generation, technological developments and the location, availability, and quality of competing sources of coal, as well as alternative fuels (natural gas, oil and nuclear) and alternative energy sources (hydroelectric).
Long-term demand for electric power will depend on a variety of economic, regulatory, technological and climatic factors beyond the Company's control. Historically, domestic demand for electric power has generally increased as the U.S. economy has grown. Two important regulatory initiatives, one designed to increase competition among utilities and lower the cost of electricity for consumers (see "Electricity Utility Deregulation," below), and another to improve air quality by reducing the level of sulfur emitted from coal-burning power generation plants (see "Clean Air Act Amendments," below) have had and are expected to continue to have significant effects on the electric utility industry and its coal suppliers.
Electric Utility Deregulation. Electric utility deregulation is expected to continue to cause utilities to focus on minimizing their fuel costs, be more aggressive in negotiating prices with coal suppliers and be more willing to switch to alternative fuels. To the extent utility deregulation affects the Company's customers, the Company believes some aspects of deregulation may adversely affect the Company's business and operating results while other aspects of deregulation may have a positive effect. Deregulation should result in increased utilization of low cost coal-fired generating plants, but at the same time should increase pricing pressure on coal producers since fuel costs account for a high percentage of the cost of operating a generating plant.
Clean Air Act Amendments. A major regulatory change affecting the coal industry is Title IV of the Clean Air Act Amendments (the "Amendments") enacted in 1990. The Amendments have had, and will continue to have, a significant effect on the domestic coal industry. In general, Phase I of the Amendments, which became effective in 1995, regulates the level of emissions of sulfur dioxide from power plants and targets the highest sulfur dioxide emitters. Phase II, which became effective on January 1, 2000, extends the restrictions of the Amendments to all power plants of greater than a 75 megawatt capacity. The Amendments do not define allowable emission levels on a per plant basis, but instead allocate emission allowances to the affected plants and allow the emission allowances to be traded so that market participants can fashion more efficient and flexible compliance strategies. The emission allowance allocations for Phase I units were based on 2.5 pounds of sulfur dioxide per million Btus and Phase II allocations are based on 1.2 pounds of sulfur dioxide per million Btus.
Industry Competition, Market Prices and the Cost of Production. Even assuming that Clean Air Act Phase II requirements and electric utility deregulation will strengthen demand for low-sulfur coal, the Company still faces substantial competition from other coal producers in an overall market characterized by excess supply. The coal industry has historically been prone to oversupply situations as there have been few barriers to entry. At the same time, profit margins from remaining above-market contracts, coupled with high exit costs in the form of environmental and employee-related liabilities, have encouraged the perpetuation of marginal operations.
The price at which the Company's production can be sold is dependent upon a variety of factors, many of which are beyond the Company's control. The Company sells coal under long-term contracts and on the spot market. See the "Sales and Marketing" section below. Generally, the relative competitiveness of coal vis-a-vis other fuels or other coals is evaluated on a delivered cost per heating value unit basis. In addition to competition from other fuels, coal quality, the marginal cost of producing coal in various regions of the country and transportation costs are major determinants of the price for which the Company's production can be sold. Coal production costs vary widely depending upon the region in which the coal is produced. Factors that directly influence production cost include geological characteristics (including seam thickness), overburden ratios, depth of underground reserves and transportation costs. Western coal is relatively inexpensive to mine because the seams are thick and typically close to the surface. As a result, open-cast mining methods are used. The large capital costs associated with dragline mining and truck and shovel mining are amortized over a relatively large amount of coal produced. Western mines are also highly productive and labor is a much smaller component of the cost structure. Eastern coal is more expensive to mine than western coal because there is a high percentage of underground coal in the east and eastern surface coal tends to have thinner coal seams. Additionally, underground mining has higher labor (including reserves for future costs associated with labor benefits and health care) and capital (including modern mining equipment and construction of extensive ventilation systems) costs than those of surface mining. In recent years, increased development of large surface mining operations, particularly in the western United States, and more efficient mining equipment and techniques, have contributed to the excess coal production capacity in the United States. Competition resulting from excess capacity encourages producers to reduce prices and to pass productivity gains through to customers. The lower production cost in the western mines is offset somewhat by the higher quality of many eastern coals and higher transportation cost from these western mines to many coal-fired power plants in the country.
Demand for the Company's low-sulfur coal and the prices that the Company will be able to obtain for it will also be affected by the price and availability of high-sulfur coal, which can be marketed in tandem with emissions allowances. Intraregional and interregional competition is keen as producers seek to position themselves as the low-cost producer and supplier of high-demand product to the electricity generating industry.
Transportation of Coal. Transportation costs are another fundamental factor affecting coal industry competition, particularly interregional competition. Nearly 65% of coal deliveries to utilities are made by rail. Coordination of the many eastern loadouts, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, coal transportation rates from the
Powder River Basin into central Appalachian markets limited the use of Powder River Basin coal in those markets. More recently, however, lower rail rates from the Powder River Basin to markets served by eastern producers have created major competitive challenges for eastern producers.
Barge transportation is the lowest-cost method of transporting coal long distances in the eastern United States, and the large numbers of eastern producers with river access keep coal prices competitive. The Company believes that many utilities with plants located on the Ohio River system are well positioned for deregulation as competition for river shipments should remain high for central Appalachian coal. With close proximity to competitively- priced central Appalachian coal and the ability to receive western coals, the Company believes utilities with plants located on the Ohio River system will become price setters in a deregulated environment. The ability of these utilities to blend western and eastern coal will also create a new, dynamic fuel procurement environment that could place western and eastern coals in even greater competition and limit rail price premiums. River transport is an important transportation option not available to Powder River Basin producers between Wyoming and midwestern river terminals.
Most coal mines are served by a single rail company, but many of the Powder River Basin mines are served by two competing rail carriers. Rail competition in this producing region is important, since rail costs constitute up to 75% of the delivered cost of Powder River Basin coal in remote markets.
Although undergoing significant consolidation, the coal industry in the United States remains highly fragmented. There can be no assurance that the Company's costs will permit it to compete effectively with other producers seeking to provide coal to a customer. To prosper in the business environment described above, a coal producer must be able to maintain low production costs, offer a variety of products and have access to multiple transportation systems.
Sales and Marketing
The Company sells coal under long-term contracts (contracts having a term of greater than 12 months) as well as on a current market, or spot basis. When the Company's coal sales contracts expire, the Company is exposed to the risk of having to sell coal into the spot market, where demand is variable and prices are therefore subject to greater volatility. Historically, the price of coal sold pursuant to contracts exceeded then-prevailing spot prices for coal. However, due to deregulation and other factors discussed previously, in the past several years new contracts have been priced at or near existing spot rates.
The terms of coal sales contracts result from bidding and extensive negotiations with customers. Consequently, the terms of such contracts vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, and force majeure, termination and assignment provisions.
Frequently, base prices are set at the beginning of the term of a contract and are then adjusted at intervals for changes due to inflation or deflation and, in many cases, changes in costs such as taxes, reclamation fees, black lung excise taxes and royalties. The inflation or deflation adjustments are measured by public indices, the most common of which is the implicit price deflator for the gross domestic product as published by the United States Department of Commerce. The base price is also often adjusted to a market price which is either negotiated or determined in a predetermined manner when there is a price reopener.
Price reopeners are present in many of the more recently executed long-term contracts and usually occur midway through the term of a contract. Reopeners typically allow the contract price to be renegotiated in order to be in line with the then-prevailing market price. In some circumstances, customers have the option to terminate
the contract if the parties do not agree on a new price. The length of sales contracts has decreased significantly over the last few years as electricity generators have prepared for federal Clean Air Act requirements and the impending deregulation of their industry.
Quality and volumes for coal are stipulated in coal sales contracts, although customers normally have the option to vary volume to some limited extent. Variations in the quality and volumes of coal may lead to adjustments in the contract price. Coal sales contracts typically stipulate procedures for quality control, sampling and weighing.
Contract provisions in some cases specify how coal will be supplied in the event of a force majeure, including such events as strikes, adverse mining conditions, serious transportation problems or, in certain instances, changes in laws. More recent contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the customer. Coal sales contracts typically contain termination clauses if either party fails to comply with the terms and conditions of the contract.
In certain contracts, the Company has a right of substitution, allowing it to provide coal from different mines as long as it is of a certain specified quality and will be sold at the same delivered cost.
There are certain contracting terms that differ between a standard "eastern U.S." contract and a standard "western U.S." contract. In the eastern United States, many customers require that the coal be sampled, analyzed and weighed at the destination, whereas in the western United States most of that activity is conducted at the source. More eastern United States coal is purchased on the spot market. The eastern United States market has traditionally been a more short-term market because of the larger number of smaller mining operations in that region. Western U.S. contracts may stipulate that certain production taxes and coal royalties be reimbursed in full by the buyer rather than being a pricing component within the contract. These items are a significant portion of western U.S. coal pricing.
Another factor that may impact the sale of coal in the future is the development of coal commodity trading. The New York Mercantile Exchange initiated electricity commodity trading a few years ago and has been developing standards for coal contracts. The Exchange has announced its intention to initiate coal contract trading based on a Huntington, West Virginia barge loading hub. However, to date, the Exchange has not initiated such trading. The development of standards to determine pricing has been difficult because of the non-homogeneous character of coal and diversity in mining locations, conditions and operations. Nonetheless, in anticipation of commodity trading, some brokerage and marketing firms have entered the coal markets and devised transactions that mimic commodity activity. Today, over- the-counter trading is being conducted to a limited extent on both firm forward transactions as well as put, call and other options. The trend to more commodity type transactions could mark a significant change in how coal is sold. It is too early to determine whether this trend will have a material effect on the Company and its operating results.
Reliance on Major Customers
The Company's total sales to American Electric Power Company, Inc. ("AEP") and Southern Company and their respective affiliates accounted for approximately 10.0% and 10.5%, respectively, of the Company's total revenues in 1999. AEP and Southern Company and/or their affiliates each currently has multiple long-term contracts with the Company. If the Company experienced an unanticipated and immediate loss of all of the contracts with either of these customers, the loss could have a material adverse effect on the Company's business and results of operations.
Operations
As of December 31, 1999, the Company operated a total of 33 mining complexes, all located in the United States. Coal is transported from the Company's mining complexes to customers by means of railroad cars, river barges or trucks, or a combination of these means of transportation. The following table provides the location and a summary of information regarding the Company's principal mining complexes and the coal reserves associated with these operations as of December 31, 1999:
- --------
S = Surface Mine D = Dragline UP = Union Pacific U = Underground Mine L = Loader/Truck Railroad S = Shovel/Truck IC = Illinois Central LW = Longwall Railroad C = Continuous Miner BN = Burlington Northern Railroad NS = Norfolk Southern Railroad * Multiple captive and contract mines are included in parentheses. (/1/Reported)for captive operations only. (/2/Reflects)purchase accounting adjustments. (/3/The)Company idled the two captive mining operations at its Coal-Mac (KY) complex on January 3, 2000 because of the small surface mines' high cost structure compared to the Company's larger mines. (/4/The)Company idled its mining operations at the Dal-Tex complex on July 23, 1999 due to a delay in obtaining mining permits resulting from legal action in the U.S. District Court for the Southern District of West Virginia. See "Part I, Item 3. Legal Proceedings--Dal-Tex Litigation" for further discussion regarding this legal action. (/5/Utilizes)an 83-cubic-yard dragline and a 51-cubic-yard shovel. (/6/Utilizes)a 49-cubic-yard dragline, a 43-cubic-yard shovel, a 22-cubic-yard shovel and a 28-cubic-yard loader at the Ruffner Mine. (/7/Utilizes)a 110-cubic-yard dragline, two 53-cubic-yard shovels, a 22-cubic- yard hydraulic excavator and two 28-cubic-yard loaders.
(/8/Utilizes)170-cubic-yard, 130-cubic-yard, 90-cubic-yard and 45-cubic-yard draglines and 53-cubic-yard, 60-cubic-yard and 82-cubic-yard shovels. (/9/The)Company temporarily idled its mining operations at West Elk on January 28, 2000 following the detection of higher-than-normal levels of carbon monoxide in a portion of the mine. See "Part 1, Item 1. Business--Recent Developments" for further information regarding this matter. (/10/Canyon)Fuel is an equity investment and its financial statements are not consolidated into the Company's financial statements. (/11/Currently)under development; full production projected to begin with the addition of a longwall in the 3rd quarter of 2001. (/12/Utilizes)76-cubic-yard and 64-cubic-yard draglines at Medicine Bow and a 32-cubic-yard dragline at Seminoe II. (/13/The)Company idled its remaining operations at the Arch of Illinois mining complex and sealed the underground mine in December 1999 due to a lack of demand for the mine's high-sulfur coal. The mining complex was the last of the Company's mining operations in the midwestern United States.
All mining complexes described above have unit train load-out facilities except Campbell's Creek. Preparation plants are located at the following complexes: Mingo Logan, Hobet 21, Arch of West Virginia, Samples, Campbell's Creek, Pardee, and Lone Mountain, as well as the idled Dal-Tex complex. The mining complexes, mines and related facilities described above are accessible by public road, and power to the complexes, mines and facilities is supplied by public utility companies doing business in the area of such operations. The plant and equipment at each of the mining complexes are suitable for the mining operations undertaken at each complex.
All of the coal reserves at the mining complexes described above are either compliance or low-sulfur coal, with the exception of the coal reserves at the idled Arch of Illinois mining complex.
Although the Company believes it has a strong reserve base relative to its competition, the Company's profitability depends substantially on having access to coal reserves that have the geologic characteristics that enable them to be mined at competitive costs. There can be no assurance that replacement reserves, particularly in central Appalachia, will be available when required or, if available, that such replacement reserves can be mined at costs comparable to those characteristic of the depleting mines. Exhaustion of reserves at particular mines can also have an adverse effect on operating results that is disproportionate to the percentage of overall production represented by the tonnage produced at such mines.
The Company may experience significant fluctuations in operating results in the future, both on an annual and quarterly basis, as a result of one or more factors beyond its control, including expiration or termination of, or sales price redeterminations or suspensions of deliveries under, long-term contracts; disruption of transportation services; changes in mine operating conditions; changes in laws or regulations, including permitting requirements; unexpected results in litigation; work stoppages or other labor difficulties; competitive and overall coal market conditions; and general economic conditions. The Company's mining operations are subject to conditions or events beyond the Company's control that can affect the cost of mining at particular mines for varying lengths of time and could have an adverse effect on results of operations. These factors include weather conditions; fires and explosions; equipment replacement and repair requirements; variations in coal seam thickness; amount of overburden, rock and other natural materials; and other surface or subsurface conditions. Such production factors frequently result in significant fluctuations in operating results.
Third quarter results of operations are frequently adversely affected by lower production and resultant higher costs due to scheduled vacation periods at the Company's union mines. In addition, costs are typically somewhat higher during vacation periods because of maintenance activity carried on during those periods. These adverse effects may make the third quarter not comparable to the other quarters and not indicative of results to be expected for the full year.
Transportation
Coal from the mines of the Company's subsidiaries is transported by rail, truck and barge to domestic customers and to Atlantic or Pacific coast terminals for shipment to domestic and international customers.
The Company's Arch Coal Terminal is located on a 60-acre site on the Big Sandy River approximately seven miles upstream from its confluence with the Ohio River. Arch Coal Terminal provides coal storage and transloading services.
The Company's Paint Creek Terminal is located on leased property on the Kanawha River at Crown Hill, West Virginia. The facility transloads coal trucked from the Campbells Creek and Samples mines for shipment by barge to the Company's customers.
Company subsidiaries together own a 17.5% interest in Dominion Terminal Associates ("DTA"), which leases and operates a ground storage-to-vessel coal transloading facility (the "DTA Facility") in Newport News, Virginia. The DTA Facility has a rated throughput capacity of 20 million tons of coal per year and ground storage capacity of approximately 1.7 million tons. The DTA Facility serves international customers, as well as domestic coal users located on the eastern seaboard of the United States.
As of December 31, 1999, Arch Western owned a 5.3% equity interest and Canyon Fuel owned a 9.0% equity interest in the Los Angeles Export Terminal ("LAXT"), which owns and operates a dry bulk terminal operation within the Port of Los Angeles. LAXT is served by the Union Pacific railroad. Current annual rated capacity at the terminal is 10 million tons. The City of Los Angeles owns the land upon which the facility has been constructed. LAXT has entered into a 35 year lease with the City which provides compensation for its contribution of cash and land to the venture. The total cost of the facility was approximately $144 million.
Regulations Affecting Coal Mining
Federal, state and local governmental authorities regulate the coal mining industry on matters as diverse as employee health and safety, air quality standards, water pollution, groundwater quality and availability, plant and wildlife protection, the reclamation and restoration of mining properties, the discharge of materials into the environment and surface subsidence from underground mining. These regulations have had and will continue to have a significant effect on the Company and the coal mining industry.
Permits and Environmental Matters. Mining companies must obtain numerous permits that impose strict regulations on various environmental and health and safety matters in connection with coal mining. For example, regulations are imposed on the emission of air and water borne pollutants, the manner and sequencing of coal extractions and reclamation, the storage, use and disposal of waste and other substances, some of which may be hazardous, and the construction of fills and impoundments. Regulatory authorities have considerable discretion in the timing of permit issuance and both private individuals and the public at large possess rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. The Company idled its Dal-Tex operation in West Virginia on July 23, 1999, due to a delay in obtaining mining permits which resulted from legal action in the U.S. District Court for the Southern District of West Virginia. See "Part 1. Item 3. Legal Proceedings--Dal-Tex Litigation" for a discussion of the legal action.
Certain Environmental Legislation. The federal Surface Mining Control and Reclamation Act of 1977 ("SMCRA") was enacted to regulate certain surface mining of coal and the surface effects of underground mining. All states in which the Company's subsidiaries operate have similar laws and regulations enacted pursuant to SMCRA which regulate surface and deep mining and that impose, among other requirements, reclamation and environmental requirements and standards.
The federal Clean Water Act affects coal mining operations in two principal ways. First, the U.S. Army Corps of Engineers (the "Corps") issues permits under Section 404 of the Clean Water Act whenever a mine operator proposes to build a fill or impoundment in waters of the United States. In addition, the Environmental Protection Agency (the "EPA") must approve the issuance by a state agency of National Pollutant Discharge Elimination System ("NPDES") permits under Section 402 of the Clean Water Act. These permits encompass storm water discharges from a mine facility. Regular monitoring and compliance with reporting requirements and performance standards are preconditions for the issuance and renewal of NPDES permits governing the discharge of pollutants into waters. All states in which the Company's subsidiaries operate also have laws restricting discharge of pollutants into the waters of those states.
The federal Resource Conservation and Recovery Act ("RCRA") and the federal regulations thereunder exclude from the definition of hazardous waste all coal extraction, beneficiation and processing wastes. Additionally, other coal mining wastes which are subject to a SMCRA permit are exempt from RCRA permits and standards. Each of the states in which the Company's subsidiaries are currently engaged in mining similarly exempt coal mining waste from their respective state hazardous waste laws and regulations. The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act, affects coal mining operations by subjecting them to liability for the remediation of releases of hazardous substances (other than waste excluded from federal and state regulation, as noted above) that may endanger public health or welfare or the environment.
The federal Clean Air Act, as amended in 1990, imposes numerous requirements on various categories of emission sources, and West Virginia state air regulations impose permitting obligations and performance standards on certain coal preparation plants and coal handling facilities, such as crushers and screens.
Certain Health and Safety Legislation. The federal Mine Safety and Health Act of 1977 imposes health and safety standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, and the equipment used in mining operations. The Black Lung Benefits Reform Act of 1977 generally requires each coal mine operator to secure payment of federal and state black lung benefits to its employees through insurance, bonds or contributions to a state-controlled fund. The Black Lung Benefits Reform Act of 1977 also provides for the payment from a trust fund of benefits and medical expenses to employees for whom no benefits have been obtainable from their employer. This trust is financed by a tax on coal sales.
The Coal Industry Retiree Health Benefit Act of 1992 ("Benefit Act") addressed two under-funded trust funds which were created to provide medical benefits for certain United Mine Workers Association ("UMWA") retirees. The Benefit Act provides for the funding of medical and death benefits for certain retired members of the UMWA through premiums to be paid by assigned operators (former employers), transfers of monies in 1993 and 1994 from an overfunded pension trust established for the benefit of retired UMWA members, and transfers that commenced in 1995 from the Abandoned Mine Lands Fund (funded by a federal tax on coal production).
Compliance with Regulatory Requirements and Existing Environmental Liability. The Company's operating subsidiaries endeavor to conduct their operations in compliance with all applicable federal, state, and local laws and regulations. However, because of the extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry. From time to time the Company and its subsidiaries are party to civil and administrative proceedings as a result of alleged failures to comply with mandatory federal or state health and safety regulations. See "Part 1. Item 3. Legal Proceedings."
Employees
As of January 31, 2000, the Company and its subsidiaries (including Canyon Fuel) employed a total of 3,764 persons (including 19 part-time employees), 623 of whom were represented by the UMWA under a collective bargaining agreement that expires in 2002.
EXECUTIVE OFFICERS
The following is a list of the Company's executive officers, their ages and their positions and offices held with the Company during the last five years.
Bradley M. Allbritten, 42, is Vice President--Human Resources of the Company and has served in such capacity since March 1, 2000. Mr. Allbritten served as the Company's Director of Human Resources from February 1999 through February 2000.
C. Henry Besten, Jr., 51, is Vice President--Strategic Marketing of the Company and President of the Company's Arch Energy Resources, Inc. subsidiary and has served in such capacities since July 1997. Mr. Besten is also serving as Chief Financial Officer of the Company, on an interim basis, until the Company names a permanent Chief Financial Officer. During the past five years, Mr. Besten has also served as Senior Vice President--Marketing for Ashland Coal, Inc., ("Ashland Coal"), which merged with a subsidiary of the Company in July 1997.
John W. Eaves, 42, is Senior Vice President--Marketing of the Company and President of the Company's Arch Coal Sales Company, Inc. and has served in such capacities from March 1, 2000 and September 1995, respectively. Mr. Eaves served as Vice President--Marketing of the Company from July 1997 through February 2000.
Robert G. Jones, 43, is Vice President--Law & General Counsel of the Company and has served in such capacity since March 1, 2000. Mr. Jones served the Company as Assistant General Counsel from July 1997 through February 2000 and as Senior Counsel from August 1993 to July 1997.
Steven F. Leer, 47, is President and Chief Executive Officer of the Company and has served in such capacity since 1992.
Terry L. O'Connor, 54, is Vice President--External Affairs of the Company and has served in such capacity since June 1998.
David B. Peugh, 45, is Vice President--Business Development of the Company and has served in such capacity since 1993.
Robert W. Shanks, 46, is Vice President--Operations of the Company and has served in such capacity since July 1997. During the past five years, Mr. Shanks has also served as President of the Company's Apogee Coal Company subsidiary.
Kenneth G. Woodring, 50, is Executive Vice President--Mining Operations of the Company and has served in such capacity since July 1997. During the past five years, Mr. Woodring has also served as Senior Vice President--Operations of Ashland Coal.
ITEM 2.
ITEM 2. PROPERTIES
Arch Coal and its operating subsidiaries (other than Canyon Fuel, the results of operations of which are accounted for using the equity method) sold 111.2 million tons of coal in the twelve months ended December 31, 1999, as compared to 81.1 and 40.5 million tons sold in the twelve months ended December 31, 1998 and 1997, respectively. The growth in tons sold is due to the Ashland Coal, Inc. merger which was effective July 1, 1997 and the Arch Western transaction which was effective June 1, 1998. Of the total tonnage sold in the twelve months ended December 31, 1999, approximately 82% was sold under long-term contracts, as compared to 76% and 72% for the twelve months ended December 31, 1998 and 1997, respectively, with the balance being sold on the spot market. In the twelve months ended December 31, 1999, Arch Coal and its operating subsidiaries (excluding Canyon Fuel) sold 3.5 million tons of coal in the export market, compared to 3.7 and 1.9 million tons in the twelve months ended December 31, 1998 and 1997, respectively.
The Company estimates that as of December 31, 1999 it owned or controlled measured (proven) and indicated (probable) coal reserves of approximately 3.5 billion tons, as set forth in the following table. Reserve estimates are prepared by the Company's engineers and geologists and are reviewed and updated periodically. Total reserve estimates will change from time to time reflecting mining activities, analysis of new engineering and geological data, changes in reserve holdings and other factors. Anticipated losses from extraction and, where applicable, washing of the coal have been eliminated from the estimate. The Company believes that a majority of these reserves are comprised of low-sulfur coal, and a substantial portion of such low-sulfur coal is so-called "compliance coal." Compliance coal emits 1.2 pounds or less of sulfur dioxide per million Btu upon combustion without the aid of sulfur reduction technology, and is referred to as such because combustion of such coal results in sulfur emissions within the parameters required by the Clean Air Act.
Recoverable Coal:
- -------- * Represents 100% of the reserves held by Canyon Fuel
The Company's coal properties are either owned outright or controlled by lease. As of December 31, 1999, the Company's subsidiaries owned, or controlled primarily through long-term leases, approximately 106,000, 57,000 and 15,000 acres of coal lands in Wyoming, Utah and Colorado, respectively; 273,000, 101,000 and 10,000 acres of coal lands in West Virginia, Eastern Kentucky, and Virginia, respectively; and 102,000 acres of coal lands in the Illinois Basin.
Approximately 92,201 acres of the Company's 664,000 acres of coal land (which totals include 100% of the acreage held by Canyon Fuel) are leased from the federal government with terms expiring between 1999 and 2018, subject to readjustment and/or extension and to earlier termination for failure to meet diligent development requirements. Additionally, private term leases covering principal reserves under the Company's current mining plans are not scheduled to expire prior to expiration of projected mining activities. The Company's subsidiaries also control through ownership or long-term leases approximately 5,880 acres of land which are used either for its coal processing facilities or are being held for possible future development. Royalties are paid to lessors either as a fixed price per ton or as a percentage of the gross sales price of the mined coal. The majority of the significant leases are on a percentage royalty basis. The terms of most of these leases extend until the exhaustion of mineable and merchantable coal. The remaining leases have primary terms ranging from one to 40 years from the date of their execution, with most containing options to renew. In certain cases, a lease bonus (prepaid royalty) is required, payable either at the time of execution of the lease or in annual installments following such execution. In most cases, the prepaid royalty amount is applied to reduce future production royalties. Mining plans are not necessarily indicative of the life of the mine. The extent to which reserves will eventually be mined depends upon a variety of factors, including future economic conditions and governmental actions affecting both the mining and marketability of coal.
The Pine Creek, Black Bear, Campbells Creek, Samples, Ruffner and Holden 25/Ragland preparation plants and related loadout facilities are located on properties held under leases which expire at varying dates over the next thirty years with either optional 20-year extensions or with unlimited extensions, and the balance of the Company's preparation plants and loadout facilities are located on property owned by the Company.
All of the identified coal reserves held by the Company's subsidiaries have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 69% consist of compliance coal while an additional 21% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Some of the Company's low-sulfur coal can be marketed as compliance coal when blended with other compliance coal. Accordingly, most of the Company's reserves are primarily suitable for the domestic steam coal markets. However, a substantial portion of the low-sulfur and compliance coal reserves at the Mingo Logan operations may also be used as a high-volatile, low-sulfur, metallurgical coal.
Title to coal properties held by lessors or grantors to the Company and its subsidiaries and the boundaries of properties are normally verified at the time of leasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completely verified until such time as the Company's independent operating subsidiaries prepare to mine such reserves. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine such reserves could be adversely affected.
From time to time, lessors or sublessors of land leased by the Company's subsidiaries have sought to terminate such leases on the basis that such subsidiaries have failed to comply with the financial terms of the leases or that the mining and related operations conducted by such subsidiaries are not authorized by the leases. Some of these allegations relate to leases upon which the Company conducts operations material to the Company's consolidated financial position, results of operations and liquidity, but the Company does not believe any pending claims by such lessors or sublessors have merit or will result in the termination of any material lease or sublease.
The carrying cost of the Company's coal reserves at December 31, 1999 (which does not include the Company's 65% share of Canyon Fuel) was $916.6 million, consisting of $1.3 million of prepaid royalties included in current assets and $915.3 million net book value of coal lands and mineral rights.
The Company's executive headquarters occupy approximately 50,000 square feet of leased space at CityPlace One, St. Louis, Missouri. See "Item 1. Business" incorporated by reference herein for a further description of the Company's subsidiaries' mining complexes, mines, transportation facilities and other operations. The Company's subsidiaries currently own or lease the equipment that is utilized in their mining operations.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Dal-Tex Litigation. On July 16, 1998, ten individuals and The West Virginia Highlands Conservancy filed suit in U.S. District Court for the Southern District of West Virginia against the director of the West Virginia DEP and officials of the Corps alleging violations of SMCRA and the Clean Water Act. The plaintiffs alleged that the West Virginia DEP and the Corps have violated their duties under SMCRA and the Clean Water Act by authorizing the construction of "valley fills" under certain surface coal mining permits. These fills are the large, engineered works into which the excess earth and rock extracted above and between the seams of coal that are removed during surface mining are placed. The plaintiffs also alleged that the West Virginia DEP has failed to require (i) that lands mined are restored to "approximate original contour" and (ii) that approved post-mining land uses are enforced following reclamation.
Four indirect, wholly owned subsidiaries of the Company hold nine permits that were identified in the complaint as violating the legal standards that the plaintiffs requested the district court interpret. In addition, a pending permit application for the Company's Dal-Tex operation (known as the "Spruce Fork Permit") was specifically identified as a permit the issuance of which should be enjoined. Three subsidiaries of the Company intervened in the lawsuit in support of the Corps and the West Virginia DEP on August 6, 1998.
A partial settlement between the plaintiffs and the Corps was reached on December 23, 1998. Pursuant to that settlement, all claims were dismissed against the Corps for its alleged failure to execute its duties under the Clean Water Act. The settlement agreement reached between the Corps and the plaintiffs requires the preparation of a programmatic environmental impact statement (an "EIS") under the National Environmental Policy Act of 1969 ("NEPA") to evaluate the environmental effects of mountaintop mining. This EIS is scheduled to be completed by January 2001. Until it is completed, any proposed fill greater than 250 acres in size must secure an individual Clean Water Act Section 404 "dredge and fill" permit, instead of a general permit like the one the Corps indicated it would issue for the Dal-Tex operation under its nationwide authorization program. The Spruce Fork Permit was not included in the settlement, and the claims against the Corps with respect to that permit were not dismissed.
On March 3, 1999, the district court issued a preliminary injunction which prohibited the Corps from issuing a general Clean Water Act Section 404 dredge and fill permit for the Dal-Tex operation and enjoined the Company from future operations on the permit until a full trial on the merits could be held. As a result of the entry of the preliminary injunction, the Company idled the Dal- Tex mine on July 23, 1999.
On July 26, 1999, the plaintiffs and the West Virginia DEP tendered to the district court a proposed consent decree which would resolve most of the remaining issues in the case. Pursuant to the proposed consent decree, the West Virginia DEP agreed in principal to amend its regulations and procedures to correct alleged deficiencies. In addition, the parties agreed in principal on a new definition of approximate original contour as it applies to mountaintop mining, as well as to certain regulatory changes involving post- mining land uses. After inviting public comment of the proposed consent decree, the court entered the consent decree in a final order on February 17, 2000.
The Company's Hobet Mining subsidiary agreed as part of the consent decree to revise portions of its Spruce Fork Permit application to conform to the new definition of approximate original contour to be adopted by the West Virginia DEP. Hobet Mining also agreed to seek an individual Clean Water Act Section 404 dredge and fill permit from the Corps as part of its future mining operation. Before issuing that permit, the Corps must first complete an EIS to comply with the provisions of NEPA. The completion of this EIS and issuance of all permits are not expected until mid-2001 at the earliest.
The plaintiffs' allegation that the West Virginia DEP violated its duties under the Clean Water Act by authorizing the construction of valley fills under certain coal mining permits was not resolved by the consent decree. On October 20, 1999, the district court entered a permanent injunction against the West Virginia DEP prohibiting the issuance of any new permits that authorize the construction of valley fills as part of mining operations. The court concluded that the excess earth and rock that is placed in a valley fill during mining is not fill material, but rather is waste, which may not be placed in intermittent and perennial streams because the disposal of such material cannot meet applicable water quality standards.
The West Virginia DEP immediately complied with the district court's injunction by issuing an administrative order banning the expansion of nearly all existing valley fills as well as prohibiting the issuance of nearly all new permits for valley fills. The West Virginia DEP also filed an appeal of the district court's decision with the U.S. Court of Appeals for the Fourth Circuit. On October 29, 1999, the district court granted a stay of its decision, pending the outcome of the appeal. The West Virginia DEP rescinded its administrative order on November 1, 1999 in response to the district court's action.
It is impossible to predict the outcome of the West Virginia DEP's appeal. If, however, the district court's decision is upheld, the Company and other coal producers may be forced to close all or a portion of their mining operations in West Virginia because of the prohibition on constructing valley fills for their existing and future mines. Regardless of the outcome of the appeal, the Company determined that significant changes were necessary in the manner and extent in which certain central Appalachia coal assets would be deployed.
Cumulative Hydrologic Impact Assessment ("CHIA") Litigation. On January 20, 2000, two environmental organizations, the Ohio Valley Environmental Coalition and the Hominy Creek Watershed Association, filed suit against the West Virginia DEP in U.S. District Court in Huntington, West Virginia. In addition to allegations that the West Virginia DEP violated state law and provisions of the Clean Water Act, the plaintiffs allege that the West Virginia DEP's issuance of permits for surface and underground coal mining has violated certain non-discretionary duties mandated by SMCRA. Specifically, the plaintiffs allege that the West Virginia DEP has failed to require coal operators seeking permits (i) to conduct water monitoring to verify stream flows and ascertain water quality, (ii) to always include certain water quality information in their permit applications and (iii) to analyze the probable hydrologic consequences of their operations. The plaintiffs also allege that the West Virginia DEP has failed to analyze the cumulative hydrologic impacts of mining operations on specific watersheds.
The plaintiffs seek an injunction to prohibit the West Virginia DEP from issuing any new permits which fail to comply with all of the elements identified in their complaint. The complaint identifies, and seeks to enjoin, three pending permits that are sought by the Company's Mingo Logan subsidiary to continue existing surface mining operations at the Phoenix reserve. If the permits are not issued, it is possible that those operations will have to be suspended by the subsidiary early in 2001. On February 17, 2000, the West Virginia DEP filed a motion to dismiss all claims in the lawsuit. Depending upon the disposition of the motion, the Mingo Logan subsidiary may choose to intervene in the matter.
It is impossible to predict whether this litigation will result in a suspension of the affected surface mining operations. If, however, the operations are suspended, the Company's financial condition and results of operations could be adversely affected and, depending upon the length of the suspension, the effect could be material.
Lone Mountain Litigation. On October 24, 1996, the rock strata overlaying an abandoned underground mine adjacent to the coal-refuse impoundment used by the Lone Mountain preparation plant failed, resulting in the discharge of approximately 6.3 million gallons of water and fine coal slurry into a tributary of the Powell River in Lee County, Virginia.
The U.S. Department of the Interior has notified the Company that it intends to file a civil action under the Clean Water Act and the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") to recover the natural resource damages suffered as a result of the discharge. The Interior Department alleges that fresh water mussels listed on the federal Endangered Species List that reside in the Powell River were affected as a consequence of the discharge. The Company and the Interior Department have reached an agreement in principal to settle this matter, which would require a payment of $2.5 million by the Company. The settlement is subject to the Company and the Interior Department entering into a definitive agreement. The Company's consolidated balance sheet as of December 31, 1999 reflects a reserve for the full amount of this settlement.
Skyline Partners Litigation. In February 2000, Canyon Fuel and Skyline Partners entered into a definitive settlement agreement to settle the litigation between them. The settlement included a $7.2 million payment by Canyon Fuel to Skyline Partners representing disputed amounts of advance minimum royalties, interest, reimbursement of legal fees, a grant of an overriding royalty interest to Skyline Partners covering land adjacent to the Skyline Mine reserves and a reduction in the total amount of advance minimum royalties available for recoupment by Canyon Fuel.
Other Litigation. On October 31, 1997, the EPA notified a Company subsidiary that it was a potentially responsible party in the investigation and remediation of two hazardous waste sites located in Kansas City, Kansas, and Kansas City, Missouri. The Company's involvement arises from the subsidiary's sale, in the mid-1980s, of fluids containing small quantities of polychlorinated biphenyls ("PCBs") to a company authorized to engage in the processing and disposal of these wastes. Some of these waste materials were sent to one of the sites for final disposal. The Company responded to the information request submitted by the EPA on December 1, 1997. Any liability which might be asserted by the EPA against the Company is not believed to be material because of the de minimis quantity and concentration of PCBs linked to the Company. Moreover, the party with which the subsidiary contracted to dispose of the waste material has agreed to indemnify the Company for any costs associated with this action.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders of the Company through the solicitation of proxies or otherwise during the fourth quarter of 1999.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required by this Item is contained in the Company's 1999 Annual Report to Stockholders under the caption "Stockholder Information" and is incorporated herein by reference.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this Item is contained in the Company's 1999 Annual Report to Stockholders under the caption "Selected Financial Information" and is incorporated herein by reference.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required by this Item is contained in the Company's 1999 Annual Report to Stockholders under the caption "Management's Discussion and Analysis," and is incorporated herein by reference.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this Item is contained in the Company's 1999 Annual Report to Stockholders under the caption "Management's Discussion and Analysis," and is incorporated herein by reference.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Part IV, Item 14 of this Annual Report for the information required by Item 8.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the subcaption "Nominees for Director" which appears under the caption "Election of Directors" in the Company's Proxy Statement to be distributed to Company stockholders in connection with the Company's 2000 Annual Meeting (the "2000 Proxy Statement"). See also the list of the Company's executive officers and related information under "Executive Officers" in Part I, Item 1. herein.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing in the "Summary Compensation Table", the "Option Grants in Last Fiscal Year" table, the "Aggregated Option Exercise in Last Fiscal Year and Fiscal Year-End Option Values" table, the Pension Plan section (including the table therein), the Employment and Retention Agreements section, the Compensation of Directors section, and the Compensation Committee Interlocks and Insider Participation section in the Company's 2000 Proxy Statement. No portion of the Personnel and Compensation Committee Report on Executive Compensation for 1999 or the Arch Coal Performance Graph is incorporated herein in reliance on Regulation S-K, Item 402(a)(8).
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption "Security Ownership of Certain Beneficial Owners and Management" in the Company's 2000 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption "Certain Relationships and Related Transactions" in the Company's 2000 Proxy Statement.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) The following consolidated financial statements of Arch Coal, Inc. and subsidiaries included in the Company's 1999 Annual Report to Stockholders are incorporated by reference:
Consolidated Statements of Operations--Years Ended December 31, 1999, 1998 and 1997
Consolidated Balance Sheets--December 31, 1999 and 1998
Consolidated Statements of Stockholders' Equity--Years Ended December 31, 1999, 1998 and 1997
Consolidated Statements of Cash Flows--Years Ended December 31, 1999, 1998 and 1997
Notes to Consolidated Financial Statements
The following financial statements of Canyon Fuel Company, LLC are incorporated by reference to Exhibit 99 to this Annual Report on Form 10-K:
Statements of Income--Years Ended December 31, 1999 and 1998 and the period from December 20, 1996 (inception) through December 31, 1997
Balance Sheets--December 31, 1999 and 1998
Statements of Members' Equity--Years Ended December 31, 1999 and 1998 and the period from December 20, 1996 (inception) through December 31, 1997
Statements of Cash Flows--Years Ended December 31, 1999 and 1998 and the period from December 20, 1996 (inception) through December 31, 1997
Notes to Financial Statements
(a)(2) The following consolidated financial statement schedule of Arch Coal, Inc. and subsidiaries is included in Item 14 at the page indicated:
II--Valuation and Qualifying Accounts at page 25.
All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.
(a)(3) Exhibits filed as part of this Report are as follows:
- --------
*Exhibits 10.27, 10.28, 10.29, 10.30 and 10.32 are executive compensation plans. **Upon written or oral request to the Company's Secretary, a copy of any of the above exhibits will be furnished at cost.
(b) Reports on Form 8-K
A report on Form 8-K dated October 7, 1999 (confirming (i) the Company's receipt of a proposal from Ashland Inc. that contemplates a tax-free spin- off of Ashland's interest in the Company and (ii) that a Special Committee of the Company's Board of Directors is in discussions with Ashland concerning such proposal) was filed by the Company in the quarter ended December 31, 1999.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Arch Coal, Inc. (Registrant)
/s/ John W. Lorson By: _________________________________ John W. Lorson Controller (Chief Accounting Officer)
Date: March 16, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 16, 2000.
Robert G. Jones *By: ________________________________ Robert G. Jones As Attorney-in-fact
ORIGINAL POWERS OF ATTORNEY AUTHORIZING STEVEN F. LEER AND ROBERT G. JONES, AND EACH OF THEM, TO SIGN THIS ANNUAL REPORT ON FORM 10-K AND AMENDMENTS THERETO ON BEHALF OF THE ABOVE-NAMED PERSONS HAVE BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION AS EXHIBIT 24 TO THIS REPORT.
SCHEDULE II
ARCH COAL, INC. AND SUBSIDIARIES
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
- -------- (/1/Reserves)utilized, unless otherwise indicated. (/2/Balances)acquired in the Arch Western transaction and Ashland Coal merger.