- -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------- FORM 10-K
TABLE OF CONTENTS
PART I ITEM 1. BUSINESS GENERAL Arch Coal, Inc. ("Arch Coal" or the "Company") is one of the largest coal producers in the United States. The Company mines, processes and markets compliance and low-sulfur coal from mines located in both the eastern and western United States, enabling it to ship coal cost-effectively to most of the major domestic coal-fired electric generation facilities. As of December 31, 2002, the Company had 25 operating mines and controlled approximately 2.9 billion tons of proven and probable coal reserves. Arch Coal sold 106.7 million tons of coal in 2002. The Company sells substantially all of its coal to producers of electric power. 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 principal operating units of Arch Western are Thunder Basin Coal Company, L.L.C., which operates the Black Thunder mine 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. BUSINESS ENVIRONMENT United States Coal Markets. Production of coal in the United States has increased from 434 million tons in 1960 to about 1.1 billion tons in 2002. The following table sets forth demand trends for United States coal by consuming sector through 2025 as compiled, preliminary(p) or forecasted(f) by the United States Department of Energy/Energy Information Agency.
impacting coal production and power generation, technological developments and the location, availability and quality of competing sources of coal, as well as other fuels such as natural gas, oil and nuclear and alternative energy sources such as hydroelectric power. Long-term demand for electric power will depend upon a variety of economic, regulatory, technological and climatic factors beyond our control. Historically, domestic demand for electric power has increased as the United States economy has grown. Two important regulatory initiatives, one designed to increase competition among utilities and lower the cost of electricity for consumers, and another to improve air quality by reducing the level of sulfur emitted from coal-burning power generation plants, have had and are expected to continue to have significant effects on the electric utility industry and its coal suppliers. According to the Energy Information Agency, coal is expected to remain the primary fuel for electricity generation through 2025. The following table sets forth the source fuel for electricity generation from 1990 through 2025 as compiled, preliminary(p), annualized(a) or forecasted(f) by the Energy Information Agency.
Coal Production. United States coal production was 1.1 billion tons in 2002. The following table, derived from data prepared by the Energy Information Agency, sets forth principal United States production statistics for the periods indicated.
There are some contract terms that differ between a standard "eastern United States" contract and a standard "western United States" contract. In the eastern United States, many customers require that the coal be sampled and weighed at the destination. In the western United States, virtually all samples are taken at the source. More eastern United States coal is purchased on the spot market. The eastern United States market has more recently been a shorter-term market because of the larger number of smaller mining operations in that region. Western United States contracts sometimes stipulate that some production taxes and coal royalties be reimbursed in full by the buyer rather than as a pricing component within the contract. These items comprise a significant portion of western United States coal pricing. A factor that may impact the Company's sale of coal in the future is the development of coal commodity trading. The New York Mercantile Exchange has initiated both electricity commodity trading and coal contract trading. The coal contract trading is based on a Huntington, West Virginia barge loading hub. In addition, some brokerage and marketing firms have entered the coal markets and devised transactions that mimic commodity activity. Today, limited over-the-counter trading is being conducted on both firm-forward transactions as well as put, call and other options. A trend to more commodity-type transactions could mark a significant change in how coal is sold. The Company is unable to predict whether this trend will have a material effect on its sales and whether any such effect would be positive or negative on its operating results. COMPETITION The coal industry is intensely competitive, primarily as a result of the existence of numerous producers in the coal producing regions in which the Company operates. The Company competes with several major coal producers in the Central Appalachian and Powder River Basin areas. It also competes with a number of smaller producers in those and its other market regions. 4
OPERATIONS As of December 31, 2002, the Company operated a total of 25 mines, 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. As is customary in the industry, virtually all the Company's coal sales are made F.O.B. mine or loadout, meaning that customers are responsible for the cost of transporting purchased coal to their facilities. 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, 2002:
(9) Mines are operated by Canyon Fuel. Canyon Fuel is an equity investment and its financial statements and tons produced are not consolidated into the Company's financial statements and tons produced. Amounts represent 100% of Canyon Fuel's production and assigned reserves of which the Company has a 65% interest. (10) Utilizes 76-cubic-yard dragline at Medicine Bow and a 32-cubic-yard dragline at Seminoe II. (11) Reflects the cost of plant, equipment and development at the mine as of December 31, 2002. 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. 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. REGULATIONS AFFECTING COAL MINING The information contained in the "Contingencies -- Reclamation" and "Certain Trends and Uncertainties -- Environmental and Regulatory Factors" sections of "Management's Discussion and Analysis" of the Company's 2002 Annual Report to Stockholders is incorporated herein by reference. GLOSSARY OF SELECTED MINING TERMS Assigned Reserves. Recoverable coal reserves that have been designated for mining by a specific operation. Auger Mining. Auger mining employs a large auger, which functions much like a carpenter's drill. The auger bores into a coal seam and discharges coal out of the spiral onto waiting conveyor belts. After augering is completed, the openings are reclaimed. This method of mining is usually employed to recover any additional coal left in deep overburden areas that cannot be reached economically by other types of surface mining. Btu -- British Thermal Unit. A measure of the energy required to raise the temperature of one pound of water one degree Fahrenheit. Coal Seam. A bed or stratum of coal. Coal Washing. The process of removing impurities, such as ash and sulfur based compounds, from coal. Compliance Coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the federal Clean Air Act. Continuous Mining. One of two major underground mining methods now used in the United States (also see "Longwall Mining"). This process utilizes a machine -- a "continuous miner" -- that mechanizes the entire coal extraction process. The continuous miner removes or "cuts" the coal from the seam. The loosened coal then falls on a conveyor for removal to a shuttle car or larger conveyor belt system. Dragline. A large machine used in the surface mining process to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket suspended from the end of a long boom. The bucket, which is suspended by cables, is able to scoop up great amounts of overburden as it is dragged across the excavation area. 6
Longwall Mining. One of two major underground coal mining methods now used in the United States (see also "Continuous Mining"). This method employs a rotating drum, which is pulled mechanically back and forth across a face of coal that is usually several hundred feet long. The loosened coal falls onto a conveyor for removal from the mine. Longwall operations include a hydraulic roof support system that advances as mining proceeds, allowing the roof to fall in a controlled manner in areas already mined. Low-Sulfur Coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus. Metallurgical Coal. The various grades of coal suitable for distillation into carbon in connection with the manufacture of steel. Also known as "met" coal. Preparation Plant. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal's sulfur content. Probable Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart; therefore, the degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation. Proven Reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established. Reclamation. The restoration of land and environmental values to a mining site after the coal is extracted. Reclamation operations are usually underway where the coal has already been taken from a mine, even as mining operations are taking place elsewhere at the site. The process commonly includes "recontouring" or shaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Recoverable Reserves. The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law. Spot Market. Sales of coal under an agreement for shipments over a period of one year or less. Steam Coal. Coal used in steam boilers to produce electricity. Surface Mine. A mine in which the coal lies near the surface and can be extracted by removing overburden. Tons. References to a "ton" mean a "short" or net tonne, which is equal to 2,000 pounds. Unassigned Reserves. Recoverable coal reserves that have not yet been designated for mining by a specific Company operation. Underground Mine. Also known as a "deep" mine. Usually located several hundred feet below the earth's surface, an underground mine's coal is removed mechanically and transferred by shuttle car or conveyor to the surface. EMPLOYEES As of March 1, 2003, the Company employed a total of approximately 3750 persons, approximately 600 of whom were represented by the UMWA under a collective bargaining agreement that expires in 2006 and approximately 160 of whom are represented by the Scotia Employees Association under a collective bargaining agreement that expires in 2003. 7
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, 45, is Vice President -- Marketing of the Company and has served in such capacity since August 2002. From March 2000 to February 2003, Mr. Allbritten was the Company's Vice President -- Human Resources. Mr. Allbritten served as the Company's Director of Human Resources from February 1999 through February 2000. C. Henry Besten, Jr., 54, is Senior Vice President -- Strategic Development of the Company and has served in such capacity since December 2002. Mr. Besten is also President of the Company's Arch Energy Resources, Inc. subsidiary and has served in that capacity since July 1997. From July 1997 to December 2002, Mr. Besten served as Vice President -- Strategic Marketing of the Company. Mr. Besten also served as Acting Chief Financial Officer of the Company from January 2000 to December 2000. John W. Eaves, 45, is Executive Vice President and Chief Operating Officer of the Company and has served in such capacity since December 2002. From February 2000 to December 2002, Mr. Eaves served as Senior Vice President -- Marketing of the Company and from September 1995 to December 2002 as President of the Company's Arch Coal Sales Company, Inc. subsidiary. Mr. Eaves also served as Vice President -- Marketing of the Company from July 1997 through February 2000. Sheila B. Feldman, 48, is Vice President -- Human Resources of the Company and has served in such capacity since February 2003. Robert G. Jones, 46, is Vice President -- Law, General Counsel and Secretary of the Company and has served in such capacity since March 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, 50, is President and Chief Executive Officer and a Director of the Company and has served in such capacity since 1992. Robert J. Messey, 57, is Senior Vice President and Chief Financial Officer of the Company and has served in such capacity since December 2000. David B. Peugh, 48, is Vice President -- Business Development of the Company and has served in such capacity since 1993. Robert W. Shanks, 49, is Vice President -- Operations of the Company and has served in such capacity since July 1997. Since June 1998 he has also served as President of Arch Western Resources. During the past five years, Mr. Shanks has also served as President of the Company's Apogee Coal Company subsidiary. Kenneth G. Woodring, 53, is Executive Vice President -- Mining Operations of the Company and has served in such capacity since July 1997. ITEM 2. PROPERTIES The Company estimates that it owned or controlled, as of December 31, 2002, approximately 2.9 billion tons of proven and probable recoverable reserves. Recoverable reserves include only saleable coal and do not include coal which would remain unextracted, such as for support pillars, and processing losses, such as washery losses. Reserve estimates are prepared by the Company's engineers and geologists and reviewed and updated periodically. Total recoverable reserve estimates and reserves dedicated to mines and complexes change from time to time to reflect mining activities, analysis of new engineering and geological data, changes 8
in reserve holdings and other factors. The following table presents the Company's estimated recoverable coal reserves at December 31, 2002 (tonnage in millions):
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 Company must obtain permits from applicable state regulatory authorities before it begins to mine particular reserves. Applications for permits require extensive engineering and data analysis and presentation, and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and other impacts on the environment, the construction of overburden fills and water containment areas, and reclamation of the area after coal extraction. The Company is required to post bonds to secure performance under its permits. As is typical in the coal industry, the Company strives to obtain mining permits within a time frame that allows it to mine reserves as planned on an uninterrupted basis. The Company generally begins preparing applications for permits for areas that it intends to mine up to three years in advance of their expected issuance date. Regulatory authorities have considerable discretion in the timing of permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. The Company's reported coal reserves are those that could be economically and legally extracted or produced at the time of their determination. In determining whether the Company's reserves meet this standard, it takes into account, among other things, the Company's potential inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. Except as described elsewhere in this document with respect to permits to conduct mining operations involving valley fills, which has been taken into account in determining the Company's reserves, the Company is not currently aware of matters which would significantly hinder its ability to obtain future mining permits with respect to its reserves. The carrying cost of the Company's coal reserves at December 31, 2002 (which does not include the Company's 65% share of Canyon Fuel) was $816.9 million, consisting of $56.0 million of prepaid royalties and the $760.9 million net book value of coal lands and mineral rights. The Company's executive headquarters occupy approximately 78,000 square feet of leased space at One CityPlace Drive, in St. Louis, Missouri. See "Item 1. Business" 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 utilized in their mining operations. ITEM 3. LEGAL PROCEEDINGS The information required by this Item is contained in the "Contingencies -- Legal Contingencies" section of "Management's Discussion and Analysis" contained in the Company's 2002 Annual Report to Stockholders and is incorporated herein by reference. 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 2002. 10
PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The information required by this Item is contained in the Company's 2002 Annual Report to Stockholders under the caption "Stockholder Information" and is incorporated herein by reference. ITEM 6. SELECTED FINANCIAL DATA The information required by this Item is contained in the Company's 2002 Annual Report to Stockholders under the caption "Selected Financial Information", and is incorporated herein by reference. 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 2002 Annual Report to Stockholders under the caption "Management's Discussion and Analysis", and is incorporated herein by reference. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this Item is contained in the Company's 2002 Annual Report to Stockholders under the caption "Management's Discussion and Analysis", and is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Reference is made to Part IV, Item 14 of this Annual Report on Form 10-K for the information required by Item 8. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III 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 subcaptions "Nominees For a Three-Year Term That Will Expire in 2006", "Directors Whose Terms Will Expire in 2005", and "Directors Whose Terms Will Expire in 2004" which appear under the caption "Election of Directors" in the Company's Proxy Statement to be distributed to Company stockholders in connection with the Company's 2003 Annual Meeting (the "2003 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. 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 sections entitled "Stock Option Grants", "Stock Option Exercises and Year-End Values", and the Pension Plan section (including the table therein), the Employment Agreements section, and the Compensation of Directors section in the 2003 Proxy Statement. No portion of the Personnel and Compensation Committee Report on Executive Compensation for 2002 or the Arch Coal Performance Graph is incorporated herein in reliance on Regulation S-K, Item 402(a)(8). 11
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 "Ownership of Arch Coal Common Stock" in the 2003 Proxy Statement. 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 "Related Party Transactions" in the 2003 Proxy Statement. ITEM 14. CONTROLS AND PROCEDURES There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption "Disclosure Controls and Procedures" in the Company's 2002 Annual Report to Stockholders. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
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) By: /s/ STEVEN F. LEER ------------------------------------ Steven F. Leer President and Chief Executive Officer Date: March 13, 2003
CERTIFICATIONS I, Steven F. Leer, certify that: 1. I have reviewed this annual report on Form 10-K of Arch Coal, Inc; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report are our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ STEVEN F. LEER -------------------------------------- Steven F. Leer President and Chief Executive Officer Date: March 13, 2003 18
I, Robert J. Messey, certify that: 1. I have reviewed this annual report on Form 10-K of Arch Coal, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c. presented in this annual report are our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors: a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. By: /s/ ROBERT J. MESSEY ------------------------------------ Robert J. Messey Senior Vice President and Chief Financial Officer Date: March 13, 2003 19
SCHEDULE II ARCH COAL, INC. AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS (IN THOUSANDS)
PART II -- ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS FORWARD-LOOKING STATEMENTS Statements in this annual report which are not statements of historical fact are forward-looking statements within the "safe harbor" provision of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on the information available to, and the expectations and assumptions deemed reasonable by, the Company at the time the statements are made. Because these forward-looking statements are subject to various risks and uncertainties, actual results may differ materially from those projected in the statements. These expectations, assumptions and uncertainties include: the Company's expectation of growth in the demand for electricity; belief that legislation and regulations relating to the Clean Air Act and the relatively higher costs of competing fuels will increase demand for its compliance and low-sulfur coal; expectation of improved market conditions for the price of coal; expectation that the Company will continue to have adequate liquidity from its cash flow from operations, together with available borrowings under its credit facilities, to finance the Company's working capital needs; a variety of operational, geologic, permitting, labor and weather related factors; and the other risks and uncertainties which are described below under "Contingencies" and "Certain Trends and Uncertainties." RESULTS OF OPERATIONS 2002 COMPARED TO 2001 Net Income (Loss). The Company incurred a net loss of $2.6 million for the year ended December 31, 2002 compared to net income of $7.2 million for the year ended December 31, 2001. Results for 2002 were adversely impacted by the state of oversupply in the coal market that resulted from an extremely mild winter in late 2001 and early 2002 and a period of industrial economic weakness that dampened electricity demand. As a result, the Company reduced its rates of production from planned levels at its mining operations during 2002. The Company produced 99.6 million tons in 2002, a decrease of 4.9 million tons as compared to 2001 production. Additionally, the current year results were negatively impacted by production difficulties and increased costs at the Company's Samples surface operation in West Virginia during the first half of 2002 resulting from the transition into a new permit area and away from a sandstone intrusion first encountered during the second quarter of 2001. Results for the year ended December 31, 2002 were positively impacted by the following other items: (1) A $5.6 million pre-tax gain resulting from the settlement of certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. (2) A $4.6 million pre-tax gain as a result of a workers' compensation premium adjustment refund from the State of West Virginia. (3) A $4.4 million pre-tax gain resulting from retroactive reductions in royalty rates at certain of the Company's mines. These items were partially offset by a pre-tax charge of $1.1 million for an increase in the Company's litigation reserve resulting from several litigation settlements. Results for 2001 were positively impacted by strong margins on the limited tonnage open to market-based pricing during the early part of 2001 and by reduced interest expense associated with lower debt levels. The results for 2001 were negatively impacted by production difficulties and increased costs at the Company's West Elk mine in Gunnison County, Colorado caused by high methane levels and at the Samples surface operation in West Virginia caused by a sandstone intrusion into the principal coal seam. Results for the year ended December 31, 2001 were positively impacted by the following other items: (1) A $9.4 million pre-tax insurance settlement as part of the Company's coverage under its property and business interruption policy. The insurance settlement represented the final settlement for losses incurred for the 2000 West Elk mine idling described below. (2) A $7.4 million pre-tax gain from a state tax credit covering prior periods. (3) A $4.6 million pre-tax gain as a result of progress in processing claims associated II-1
with the recovery of certain previously paid excise taxes on export sales. The gain stemmed from an IRS notice during the second quarter of 2000 outlining the procedures for obtaining tax refunds on black lung excise taxes paid by the industry on export sales. The notice was the result of a 1998 federal district court decision that found such taxes to be unconstitutional. Of the $4.6 million recognized, $3.1 million represented the interest component of the claim and was recorded as interest income. (4) An increase of pre-tax income of $7.5 million primarily from a reduction in the amount of expected reclamation work at the Company's idle Illinois properties resulting from permit revisions. (5) A $13.5 million pre-tax gain primarily on the sale of land. These items were partially offset by a pre-tax charge of $4.1 million for stock-based compensation benefits that may be realized in future periods and by a pre-tax charge of $5.6 million for an increase in the Company's litigation reserve resulting from several litigation settlements. Revenues. Total revenues for the year ended December 31, 2002 were $1,534.1 million, an increase of 3.1% from 2001 revenues. The increase was primarily attributable to increased coal sales revenue resulting from higher pricing on coal shipped during 2002 as compared to 2001. Average coal sales realizations on a per ton basis were $13.81 for the year ended December 31, 2002 compared to $12.82 per ton for the year ended December 31, 2001. Partially offsetting the impact of higher prices was a decrease in the number of tons sold, from 109.5 million tons in the year ended December 31, 2001 to 106.7 million for the year ended December 31, 2002. Income from Equity Investments. For the year ended December 31, 2002, income from equity investments totaled $10.1 million, a decrease of $16.2 million, or 61.6% from levels in 2001. In 2002, income from equity investments was comprised of $7.8 million from the Company's investment in Canyon Fuel Company, LLC and $2.3 million from the Company's investment in Natural Resource Partners, LP (NRP). Income from equity investment in 2001 was comprised solely of income from the Company's investment in Canyon Fuel. The decrease in investment income from Canyon Fuel resulted from decreased operating earnings at Canyon Fuel due to the expiration of a favorable sales contract at the end of 2001 and a weak market environment for Utah coal throughout 2002. Additionally, in 2001, Canyon Fuel recognized recoveries of previously paid property taxes. The Company's share of these recoveries was $2.6 million, which is reflected as income from equity investments in the Consolidated Statements of Operations. Income from the Company's equity investment in NRP represents the Company's share of NRP's earnings for the period from October 17, 2002 (the date of the formation of NRP) through November 30, 2002. Financial information for NRP through December 31, 2002 was not available at the time that the Company released its financial results. As such, the Company will account for income from its investment in NRP on a one-month lag. Other Revenues. Other revenues for the year ended December 31, 2002 decreased $8.6 million as compared to the year ended December 31, 2001. The decrease was primarily attributable to significant asset sales in 2001 which did not recur in 2002. These asset sales resulted in a pre-tax gain of $13.5 million in 2001, compared to $0.8 million in 2002. Additionally, royalty income in 2002 from coal reserves leased to third parties declined by approximately $2.9 million, due primarily to the fact that certain of the leased reserves were contributed to NRP as described above. These items were partially offset by income from the settlement of coal contracts described above. II-2
Income from Operations. The following table presents income from operations excluding the unusual items discussed above.
Interest Income. The decrease in interest income of $3.2 million in 2002 is the result of the recognition of the interest component of the black lung excise tax recovery during the year ended December 31, 2001 described previously. Income Taxes. The Company's effective tax rate is sensitive to changes in annual profitability and percentage depletion. The income tax benefit recorded in 2002 is primarily the result of favorable tax settlements and the impact of percentage depletion. During 2002, the Company received notice from the IRS of proposed adjustments for previous tax years. These adjustments resulted in an increase in the tax benefit of $10.5 million. The benefit resulting from the percentage depletion increased in 2002 as compared to 2001 as a result of the impact of higher coal prices and increased profitability at certain of the Company's mines. Adjusted EBITDA. Adjusted EBITDA was $228.9 million for the year ended December 31, 2002 compared to $282.3 million for the prior year. The decrease in Adjusted EBITDA was primarily attributable to the decrease in income from operations resulting from the reduced production levels discussed above. Adjusted EBITDA is defined as income from operations before the effect of net interest expense; income taxes; the Company's depreciation, depletion and amortization; and the Company's equity interest in the depreciation, depletion and amortization of Canyon Fuel. Adjusted EBITDA is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded to calculate Adjusted EBITDA are significant in understanding and assessing the Company's financial condition. Therefore, Adjusted EBITDA should not be considered in isolation nor as an alternative to net income, income from operations, or cash flows from operations or as a measure of the Company's profitability, liquidity or performance under generally accepted accounting principles. The Company believes that Adjusted EBITDA presents a useful measure of the ability to service and incur debt based on ongoing operations. Furthermore, analogous measures are used by industry analysts to evaluate operating performance. Investors should be aware that the Company's presentation of Adjusted EBITDA may not be comparable to similarly titled measures used by other companies. The table below shows how the Company calculates Adjusted EBITDA.
export sales. The notice was the result of a 1998 federal district court decision that found such taxes to be unconstitutional. Of the $4.6 million recognized, $3.1 million represents the interest component of the claim and was recorded as interest income. (4) An increase of pre-tax income of $7.5 million primarily from a reduction in the amount of expected reclamation work at the Company's idle Illinois properties resulting from permit revisions. (5) A $13.5 million pre-tax gain primarily on the sale of land. These items were partially offset by a pre-tax charge of $4.1 million for stock-based compensation benefits that may be realized in future periods and by a pre-tax charge of $5.6 million for an increase in the litigation reserve resulting from several litigation settlements. Results for the year ended December 31, 2000 were adversely impacted by operating losses incurred at the West Elk mine offset to some extent by partial pre-tax insurance settlements of $31.0 million received throughout 2000 under the Company's business interruption policy. The mine was idled from January 28, 2000 to July 12, 2000 following the detection of combustion gases in a portion of the mine. These combustion gases were unrelated to the high methane levels experienced at the mine in 2001. Results for the year ended December 31, 2000 were positively impacted by the following other items: (1) Pre-tax gains of $21.8 million resulting from the settlement of certain workers' compensation liabilities with the State of West Virginia. This was partially offset by adjustments to other workers' compensation liabilities resulting from changes in estimates that caused increases to the liability of $13.5 million. The net workers' compensation adjustment was a pre-tax gain of $8.3 million. (2) A pre-tax gain of $7.8 million resulting from a reduction in the Company's reclamation liability due to permit revisions at its idle mine properties in Illinois. (3) A $12.1 million pre-tax gain primarily on the sale of land. (4) A pre-tax gain of $12.7 million related to excise tax recoveries on export shipments in connection with the IRS notice described above. (5) A $9.8 million pre-tax curtailment gain resulting from previously unrecognized postretirement benefit changes that occurred from plan amendments in previous years. The West Elk mine's coal sales for the year ended December 31, 2001 of $77.0 million were $35.5 million greater than its sales of $41.5 million in 2000, although the mine experienced significant production difficulties during both periods as described above. This compares to $110.3 million of coal sales during the year ended December 31, 1999, a period of uninterrupted production. Excluding the impact of the related insurance recoveries, operating losses for the mine for 2001 and 2000 were $11.3 million and $43.4 million, respectively, compared to operating income of $13.1 million during 1999. At the Samples surface operation, a sandstone intrusion caused the coal seam to thin which resulted in lower production and higher associated costs. During the year ended December 31, 2001, the Samples surface operation experienced an operating loss of $19.2 million compared to operating income of $4.3 million during the same period of 2000. Revenues. Total revenues for the year ended December 31, 2001 were $1,488.7 million, an increase of $84.1 million from the same period in 2000. This increase was the result of several factors including the increase in sales at West Elk when compared to the same period in 2000, improved pricing on the limited tonnage that was open to market-based pricing during 2001, and increased pass-through transportation revenues. Income from Equity Investment. During the year ended December 31, 2001, Canyon Fuel, recognized recoveries of previously paid property taxes. The Company's share of these recoveries is $2.6 million, which is reflected as income from equity investment in the Consolidated Statements of Operations. In addition, Canyon Fuel experienced improved performance at its three underground mines in Utah. II-5
Income from Operations. The following table presents income from operations, excluding the unusual items discussed above.
losses incurred at the Samples surface operation resulting from the sandstone intrusion during 2001. The table below shows how the Company calculates Adjusted EBITDA.
litigation, the ruling may adversely impact both the Company's ability to sustain its current mining operations and its ability to open new mines. For further discussion of this case, see Certain Trends and Uncertainties -- Environmental and Regulatory Factors -- Clean Water Act beginning on page II-16. The Company idled its Dal-Tex operation on July 23, 1999 as a result of an adverse ruling in prior litigation on the issue of valley fills. This ruling was later reversed on appeal; however, as of the date of the 2002 injunction described above, the Company had not yet completed the process necessary to obtain the Section 404 permits for the mine. Once the Company obtains the necessary permits, it intends to reopen the mine subject to then-existing market conditions. Low-Sulfur Coal Producer. The Company continues to believe that it is well-positioned to capitalize on the continuing growth in demand for low-sulfur coal to produce electricity. Substantially all of the Company's current coal production and approximately 90% of its reserves are low in sulfur. In fact, approximately 68% of the Company's coal reserves are compliance quality, which means that the reserves meet Phase II standards of the Clean Air Act without application of expensive scrubbing technology. With Phase II now in effect, compliance coal has captured a growing share of United States coal demand and commands a higher price in the marketplace than high-sulfur coal. Chief Objectives. The Company continues to focus on taking steps to increase shareholder returns by improving earnings, strengthening cash generation, improving productivity and reducing costs at its large-scale mines, while building on its leading position in its target coal-producing basins, the Powder River Basin and the Central Appalachian Basin. DISCLOSURE CONTROLS AND PROCEDURES An evaluation was performed under the supervision and with the participation of the Company's management, including the CEO and CFO, of the effectiveness of the design and operation of the Company's disclosure controls and procedures as of December 31, 2002. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that the Company's disclosure controls and procedures were effective as of such date. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to December 31, 2002. LIQUIDITY AND CAPITAL RESOURCES The following is a summary of cash provided by or used in each of the indicated types of activities during the past three years:
higher capital expenditures and reduced proceeds from property dispositions. Cash used in investing activities during 2001 increased compared to 2000 due primarily to higher capital expenditures in 2001 and proceeds from the termination of coal supply agreements in 2000. Cash used in financing activities during 2002 primarily represents net payments under the Company's revolver and lines of credit, payments of dividends, and reductions of capital lease obligations. In addition, during 2002, the Company entered into a sale and leaseback of equipment that resulted in proceeds of $9.2 million. Cash used in financing activities during 2001 reflects the cash generated by the February 2001 and May 2001 issuances of common stock (described below) resulting in proceeds of $372.2 million, the pay-down of $376.9 million of debt and the repurchase of the Company's common stock at a cost of $5.0 million. On February 22, 2001, the Company completed a public offering of 9,927,765 shares of common stock, including the remaining 4,756,968 shares held by its then largest stockholder, Ashland Inc., and 5,170,797 primary and treasury shares issued directly by the Company. Proceeds realized from the transaction, which totaled $92.9 million net of the underwriters' discount and expenses, were used to pay down debt. On April 12, 2001, the Company filed a Universal Shelf Registration Statement on Form S-3 with the Securities and Exchange Commission. The Universal Shelf allows the Company to offer, from time to time, an aggregate of up to $750 million in debt securities, preferred stock, depositary shares, common stock and related rights and warrants. On May 8, 2001, the Company utilized the shelf registration and completed a public offering of 8,500,000 primary shares of common stock. On May 16, 2001, the underwriters involved in the offering purchased an additional 424,200 shares pursuant to an over-allotment option granted by the Company in connection with the May 8, 2001 offering. The proceeds realized from these transactions after the underwriting discount and expenses were $279.3 million. The proceeds were used to retire the Company's term loan with the remainder used to reduce the borrowings under the Company's revolving credit facility. On January 31, 2003, the Company again utilized its Universal Shelf and completed a public offering of 2,875,000 shares of 5% Perpetual Cumulative Convertible Preferred Stock. The net proceeds realized by the Company from the offering of $139.1 million are being used to reduce indebtedness under the Company's revolving credit facility, and for working capital and general corporate purposes. Subsequent to the January 2003 offering, the Company can still issue an additional $311.8 million in debt and equity securities under the Universal Shelf. On September 14, 2001, the Company's Board of Directors approved a stock repurchase plan, under which the Company may repurchase up to 6.0 million of its shares of common stock from time to time. Through December 31, 2001, the Company repurchased 357,200 shares of its common stock for $5.0 million pursuant to the plan at an average purchase price of $14.13 per share. The repurchased shares are being held in the Company's treasury. Future repurchases under the plan will be made at management's discretion and will depend on market conditions and other factors. The Company generally satisfies its working capital requirements and funds its capital expenditures and debt-service obligations with cash generated from operations. The Company believes that cash generated from operations and its borrowing capacity will be sufficient to meet its working capital requirements and anticipated capital expenditures for at least the next several years. The Company's ability to fund planned capital expenditures, to make acquisitions and to pay dividends will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal industry, and by financial, business and other factors, some of which are beyond the Company's control. Expenditures for property, plant and equipment were $137.1 million, $123.4 million and $115.1 million for 2002, 2001 and 2000, respectively. Capital expenditures are made to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. II-9
On April 18, 2002, the Company and its subsidiary, Arch Western Resources, LLC ("Arch Western") completed a refinancing of their existing credit facilities. The new credit facilities include five-and six-year non-amortizing term loans totaling $675.0 million at Arch Western and a five-year revolving credit facility totaling $350.0 million for the Company. The five-year non-amortizing term loan at Arch Western is for $150.0 million while the six-year non-amortizing term loan is for $525.0 million. The rate of interest on borrowings under both of the credit facilities is a floating rate based on LIBOR. The Company's credit facility is secured by its ownership interests in substantially all of its subsidiaries, except its ownership interests in Arch Western and its subsidiaries. The Arch Western credit facility is secured by substantially all of its subsidiaries, but is not guaranteed by the Company. Financial covenants contained in the Company's new credit facilities consist of a maximum leverage ratio, a minimum fixed charge ratio and a minimum net worth test. The leverage ratio requires that the Company not permit the ratio of total indebtedness at the end of any calendar quarter to adjusted EBITDA for the four quarters then ended to exceed a specified amount. The fixed charge coverage ratio requires that the Company not permit the ratio of the Company's adjusted EBITDA plus lease expense to interest expense for the four quarters then ended to be less than a specified amount. The net worth test requires that the Company not permit its net worth to be less than a specified amount plus 50% of cumulative net income. The Company was in compliance with all financial covenants at December 31, 2002. At December 31, 2002, the Company had $42.6 million in letters of credit outstanding which, when combined with outstanding borrowings under the revolver, resulted in $242.4 million of unused capacity under the revolving credit facility. Sufficient unused capacity is currently available to fund all operating needs. Financial covenant requirements may restrict the amount of unused capacity available to the Company for borrowings and letters of credit. At December 31, 2002, debt amounted to $747.3 million, or 58% of capital employed, compared to $773.9 million, or 58% of capital employed, at December 31, 2001. Based on the level of consolidated indebtedness and prevailing interest rates at December 31, 2002, debt service obligations, which include the current maturities of debt and interest expense for 2003, are estimated to be $67.3 million. The Company periodically establishes uncommitted lines of credit with banks. These agreements generally provide for short-term borrowings at market rates. At December 31, 2002, there were $20.0 million of such agreements in effect, of which none were outstanding. The Company is exposed to market risk associated with interest rates. At December 31, 2002, after taking into consideration interest rate swap agreements, debt included $740.0 million of floating-rate debt for which the rate of interest is, at the Company's option, the PNC Bank base rate or a rate based on LIBOR. To manage this exposure, the Company enters into interest-rate swap agreements to modify the interest-rate characteristics of outstanding Company debt. At December 31, 2002, the Company had interest-rate swap agreements having a total notional value of $525.0 million, including $250.0 million for which the fixed rate becomes effective as of October 2003. These swap agreements are used to convert variable-rate debt to fixed-rate debt. Under these swap agreements, the Company pays a weighted average fixed rate of 5.74% (before the credit spread over LIBOR) and receives a weighted average variable rate based upon 30-day and 90-day LIBOR. The Company accrues amounts to be paid or received under interest-rate swap agreements over the lives of the agreements. These amounts are recognized as adjustments to interest expense over the lives of agreements, thereby adjusting the effective interest rate on the Company's debt. Gains and losses on terminations of interest-rate swap agreements are deferred on the balance sheet (in other long-term liabilities) and amortized as an adjustment to interest expense over the remaining term of the terminated swap agreement. The remaining terms of the swap agreements at December 31, 2002, ranged from 32 to 57 months. All instruments are entered into for other than trading purposes. The Company is also exposed to commodity price risk related to its purchase of diesel fuel. The Company enters into forward purchase contracts and heating oil swaps to substantially eliminate volatility in the price of diesel fuel for its operations. The swap agreements essentially fix the price paid for diesel fuel by requiring the Company to pay a fixed heating oil price and receive a floating heating oil price. The II-10
changes in the floating heating oil price highly correlate to changes in diesel fuel prices. Gains and losses on terminations of heating oil swap agreements are deferred on the balance sheet (in other long-term liabilities) and amortized as an adjustment to diesel fuel cost over the original term of the terminated heating oil swap agreement as if it were still in place. The discussion below presents the sensitivity of the market value of the Company's financial instruments to selected changes in market rates and prices. The range of changes reflects the Company's view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen. The major accounting policies for these instruments are described in Note 1 to the consolidated financial statements. Changes in interest rates have different impacts on the fixed-rate and variable-rate portions of the Company's debt portfolio. A change in interest rates on the fixed portion of the debt portfolio impacts the net financial instrument position but has no impact on interest incurred or cash flows. A change in interest rates on the variable portion of the debt portfolio impacts the interest incurred and cash flows but does not impact the net financial instrument position. The sensitivity analysis related to the fixed portion of the Company's debt portfolio assumes an instantaneous 100-basis-point move in interest rates from their levels at December 31, 2002, with all other variables held constant. A 100-basis-point decrease in market interest rates would result in an $18.3 million increase in the fair value of the fixed portion of the debt at December 31, 2002. Based on the variable-rate debt included in the Company's debt portfolio as of December 31, 2002, after considering the effect of the swap agreements, a 100-basis-point increase in interest rates would result in an annualized additional $4.0 million of interest expense incurred based on December 31, 2002 debt levels. At December 31, 2002, a $.05 per gallon decrease in the price of heating oil would result in a $0.2 million decrease in the fair value of the financial position of the heating oil swap agreements. CONTRACTUAL OBLIGATIONS The following is a summary of the Company's significant contractual obligations as of December 31, 2002 (in thousands):
CONTINGENCIES RECLAMATION The federal Surface Mining Control and Reclamation Act of 1977 ("SMCRA") and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. The Company accrues for the costs of final mine closure reclamation over the estimated useful mining life of the property. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Other costs of final mine closure common to surface and underground mining are related to reclaiming refuse and slurry ponds, eliminating sedimentation and drainage control structures, and dismantling or demolishing equipment or buildings used in mining operations. The Company also accrues for significant reclamation that is completed during the mining process prior to final mine closure. The establishment of the final mine closure reclamation liability and the other ongoing reclamation liabilities are based upon permit requirements and require various estimates and assumptions, principally associated with costs and productivities. The Company reviews its entire environmental liability periodically and makes necessary adjustments, including permit changes and revisions to costs and productivities to reflect current experience. The Company's management believes it is making adequate provisions for all expected reclamation and other associated costs. LEGAL CONTINGENCIES The Company is a party to numerous claims and lawsuits with respect to various matters, including those discussed below. The Company provides for costs related to contingencies, including environmental matters, when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on the consolidated financial condition, results of operations or liquidity of the Company. CERTAIN TRENDS AND UNCERTAINTIES SUBSTANTIAL LEVERAGE -- VARIABLE INTEREST RATE -- COVENANTS As of December 31, 2002, the Company had outstanding consolidated indebtedness of $747.3 million, representing approximately 58% of the Company's capital employed. Despite making substantial progress in reducing debt, the Company continues to have significant debt service obligations, and the terms of its credit agreements limit its flexibility and result in a number of limitations on the Company. The Company also has significant lease and royalty obligations. The Company's ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of its indebtedness will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that the Company serves as well as financial, business and other factors, many of which are beyond the Company's control. The Company may be unable to generate sufficient cash flow from operations and future borrowings, or other financings may be unavailable in an amount sufficient to enable it to fund its debt service, lease and royalty payment obligations or its other liquidity needs. The Company's relative amount of debt and the terms of its credit agreements could have material consequences to its business, including, but not limited to: (i) making it more difficult to satisfy debt covenants and debt service, lease payment and other obligations; (ii) making it more difficult to pay quarterly dividends as the Company has in the past; (iii) increasing the Company's vulnerability to general adverse economic and industry conditions; (iv) limiting the Company's ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general corporate requirements; (v) reducing the availability of cash flows from operations to fund acquisitions, working capital, capital expenditures or other general corporate purposes; (vi) limiting the Company's flexibility in planning for, or reacting to, changes in the Company's business and the industry in which the Company competes; or II-12
(vii) placing the Company at a competitive disadvantage when compared to competitors with less relative amounts of debt. After taking into consideration the Company's interest rate swaps which convert the Company's variable rate debt to fixed, approximately 63% of the Company's indebtedness at December 31, 2002 bears interest at variable rates that are linked to short-term interest rates. If interest rates rise, the Company's costs relative to those obligations would also rise. Terms of the Company's credit facilities and leases contain financial and other covenants that create limitations on the Company's ability to, among other things, effect acquisitions or dispositions and borrow additional funds, and require the Company to, among other things, maintain various financial ratios and comply with various other financial covenants. Failure by the Company to comply with such covenants could result in an event of default under these agreements which, if not cured or waived, would enable the Company's lenders to declare amounts borrowed due and payable, or otherwise result in unanticipated costs. LOSSES The Company reported a net loss of $2.6 million for the year ended December 31, 2002. The losses in 2002 were primarily attributable to the Company's decision to scale back production during the year in response to a weak market environment and increased costs at certain Company operations. The decision to scale back production came after the Company had prepared most of the operations to maximize production in order to capitalize on higher market prices for coal the Company had previously projected for 2002. Therefore, certain costs incurred to maximize production did not result in higher revenues but did increase the cost of coal sales. Because the coal mining industry is subject to significant regulatory oversight and affected by the possibility of adverse pricing trends or other industry trends beyond the Company's control, the Company may suffer losses in the future if legal and regulatory rulings, mine idlings and closures, adverse pricing trends or other factors affect the Company's ability to mine and sell coal profitably. ENVIRONMENTAL AND REGULATORY FACTORS The coal mining industry is subject to regulation by federal, state and local authorities on matters such as: - the discharge of materials into the environment; - employee health and safety; - mine permits and other licensing requirements; - reclamation and restoration of mining properties after mining is completed; - management of materials generated by mining operations; - surface subsidence from underground mining; - water pollution; - legislatively mandated benefits for current and retired coal miners; - air quality standards; - protection of wetlands; - endangered plant and wildlife protection; - limitations on land use; II-13
- storage of petroleum products and substances that are regarded as hazardous under applicable laws; and - management of electrical equipment containing polychlorinated biphenyls, or PCBs. In addition, the electric generating industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for the Company's coal. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on the Company's mining operations or its customers' ability to use coal and may require the Company or its customers to change operations significantly or incur substantial costs. While it is not possible to quantify the expenditures incurred by the Company to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. The Company posts performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers. Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of the Company's coal. These regulations can take a variety of forms, as explained below. The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standard for ozone. In particular, coal-fired power plants will be affected by state regulations designed to achieve attainment of the ambient air quality standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead. In July 1997, the EPA adopted more stringent ambient air quality standards for particulate matter and ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA's position, although it remanded the EPA's ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA's adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and the development of new mines by the Company. This in turn may result in decreased production by the Company and a corresponding decrease in the Company's revenues. Although the future scope of these ozone and particulate matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines. Furthermore, in October 1998, the EPA finalized a rule that will require 19 states in the Eastern United States that have ambient air quality problems to make substantial reductions in nitrogen oxide emissions by the year 2004. To achieve these reductions, many power plants would be required to install additional control measures. The installation of these measures would make it more costly to operate coal-fired power II-14
plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel. Along with these regulations addressing ambient air quality, the EPA has initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA's regional haze program could affect the future market for coal. Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned electric utility for alleged violations of the Clean Air Act. The EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. The Company supplies coal to some of the currently affected utilities, and it is possible that other of the Company's customers will be sued. These lawsuits could require the utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely impact their demand for coal. Other Clean Air Act programs are also applicable to power plants that use the Company's coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants of greater than 25 megawatt capacity. Affected electric utilities can comply with these requirements by: - burning lower sulfur coal, either exclusively or mixed with higher sulfur coal; - installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal; - reducing electricity generating levels; or - purchasing or trading emissions credits. Specific emissions sources receive these credits, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows its holder to emit one ton of sulfur dioxide. In addition to emissions control requirements designed to control acid rain and to attain the national ambient air quality standards, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009. These controls are likely to require significant new improvements in controls by power plant owners. The most prominently targeted pollutant is mercury, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources. Other proposed initiatives may have an effect upon coal operations. One such proposal is the Bush Administration's recently announced Clear Skies Initiative. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury from power plants. Other so-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement II-15
towards increased regulation of a number of air pollutants. Were such initiatives enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements. Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease. Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, the Company is contractually obligated under the terms of its leases to comply with all laws, including SMCRA and equivalent state and local laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan. SMCRA also requires the Company to submit a bond or otherwise financially secure the performance of its reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines. The Company also leases some of its coal reserves to third party operators. Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed, according to the regulations, to have "owned" or "controlled" the mine operator. Sanctions against the "owner" or "controller" are quite severe and can include civil penalties, reclamation fees and reclamation costs. The Company is not aware of any currently pending or asserted claims against it asserting that it "owns" or "controls" any of its lessees' operations. On March 29, 2002, the U.S. District Court for the District of Columbia issued a ruling that could restrict underground mining activities conducted in the vicinity of public roads, within a variety of federally protected lands, within national forests and within a certain proximity of occupied dwellings. The lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to challenge regulations issued by the Department of Interior providing, among other things, that subsidence and underground activities that may lead to subsidence are not surface mining activities within the meaning of SMCRA. SMCRA generally contains restrictions and certain prohibitions on the locations where surface mining activities can be conducted. The District Court entered summary judgment upon the plaintiff's claims that the Secretary of the Interior's determination violated SMCRA. By order dated April 9, 2002, the court remanded the regulations to the Secretary of the Interior for reconsideration. The significance of this decision for the coal mining industry remains unclear because this ruling is subject to appellate review. The Department of Interior and the National Mining Association, a trade group that intervened in this action, sought a stay of the order pending appeal to the U.S. Court of Appeals for the District of Columbia Circuit and the stay was granted. If the District Court's decision is not overturned, or if some legislative solution is not enacted, this ruling could have a material adverse effect on all coal mine operations that utilize underground mining techniques, including those of the Company. While it still may II-16
be possible to obtain permits for underground mining operations in these areas, the time and expense of that permitting process are likely to increase significantly. Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel. Clean Water Act. Section 301 of the Clean Water Act prohibits the discharge of a pollutant from a point source into navigable waters except in accordance with a permit issued under either Section 402 or Section 404 of the Clean Water Act. Navigable waters are broadly defined to include streams, even those that are not navigable in fact, and may include wetlands. All mining operations in Appalachia generate excess material, which must be placed in fills in adjacent valleys and hollows. Likewise, coal refuse disposal areas and coal processing slurry impoundments are located in valleys and hollows. Almost all of these areas contain intermittent or perennial streams, which are considered navigable waters. An operator must secure a Clean Water Act permit before filling such streams. For approximately the past 25 years, operators have secured Section 404 fill permits to authorize the filling of navigable waters with material from various forms of coal mining. Operators have also obtained permits under Section 404 for the construction of slurry impoundments although the use of these impoundments, including discharges from them, requires permits under Section 402. Section 402 discharge permits are generally not suitable for authorizing the construction of fills in navigable waters. On May 8, 2002, the United States District Court for the Southern District of West Virginia issued an order in Kentuckians for the Commonwealth v. Rivenburgh enjoining the Huntington, West Virginia office of the U.S. Army Corps of Engineers from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of overburden from mountaintop mining operations solely for the purpose of waste disposal. These valleys typically contain streams that, under the Clean Water Act, are considered navigable waters of the United States. The court held that the filling of these waters solely for waste disposal is a violation of the Clean Water Act. The effect of this injunction would have been to make mountaintop mining uneconomical in those areas subject to the injunction. The court's injunction also prohibited the issuance of permits authorizing fill activities associated with types of mining activities other than mountaintop mining where the primary purpose or use of those fill activities is the disposal of waste. Such activities might include those associated with slurry impoundments and coal refuse disposal areas. On January 29, 2003, the Court of Appeals for the Fourth Circuit overturned the Kentuckians decision as being overly broad and also ruled that the valley fills in question are not illegal; that the EPA and the U.S. Army Corps of Engineers have exercised their oversight responsibilities in a reasonable and consistent manner; and that the agencies' interpretation of the regulation under which valley fills historically have been permitted is a reasonable construction of the Clean Water Act. West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the EPA's approval of West Virginia's antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. The plaintiffs in this lawsuit, Ohio Valley Environmental II-17
Coalition v. Whitman, challenge provisions in West Virginia's antidegradation implementation policy that exempt current holders of National Pollutant Discharge Elimination System (NPDES) permits and Section 404 permits, among other parties, from the antidegradation review process. The Company is exempt from antidegradation review under these provisions. Revoking this exemption and subjecting the Company to the antidegradation review process could delay the issuance or reissuance of Clean Water Act permits to the Company or cause these permits to be denied. If the plaintiffs are successful and if the Company discharges into waters that have been designated as high-quality by the state, the costs, time and difficulty associated with obtaining and complying with Clean Water Act permits for surface mining of its operations could increase. Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines that the Company currently owns or has previously owned or operated, and sites to which the Company sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, the Company may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where it owns surface rights. Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, the Company may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits. In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including the Company, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically the Company submits the necessary permit applications several months before it plans to begin mining a new area. In the Company's experience, permits generally are approved several months after a completed application is submitted. In the past, the Company has generally obtained its mining permits without significant delay. However, the Company cannot be sure that it will not experience difficulty in obtaining mining permits in the future. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the activities of mine operators, including the Company, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations. The Company cannot predict the possible effect of such regulatory changes. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Surety Bonds. Federal and state laws require the Company to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers' compensation costs, coal leases and other miscellaneous obligations. Many of these bonds are renewable II-18
on a yearly basis. It has become increasingly difficult for the Company to secure new surety bonds or renew such bonds without the posting of collateral. In addition, surety bond costs have increased while the market terms of such bonds have generally become more unfavorable. West Virginia Cumulative Hydrologic Impact Analysis Litigation. Two environmental groups sued the West Virginia Department of Environmental Protection in January 2000 in federal court, alleging various violations of the Clean Water Act and SMCRA. The lawsuit was amended in September 2001 to name Gale Norton, Secretary of the Interior, as a defendant. The U.S. Office of Surface Mining is a division within the Department of Interior. The lawsuit, Ohio River Valley Environmental Coalition, Inc. v. Castle, specifically alleges that the West Virginia Department of Environmental Protection has violated its non-discretionary duty to require all surface and underground mining permit applications to include certain stream flow and water quality data and an analysis of the probable hydrologic consequences of the proposed mine, and that the West Virginia Department of Environmental Protection failed to conduct SMCRA-required cumulative hydrologic impacts analysis prior to issuing mining permits. The lawsuit also alleges that the Office of Surface Mining has a non-discretionary duty to apply the federal SMCRA law in West Virginia due to the deficiencies in the state program. In March 2001, the district court denied the plaintiff's motion for a preliminary injunction on its claims against the West Virginia Department of Environmental Protection. In September 2001, the district court denied a motion to dismiss for lack of jurisdiction filed by defendant Michael Callaghan, Secretary of the West Virginia Department of Environmental Protection. Callaghan filed an interlocutory appeal of this decision in October 2001. The Fourth Circuit Court of Appeals is awaiting briefing under an extended schedule in this case. If the plaintiffs are eventually successful in this lawsuit, the West Virginia Department of Environmental Protection will have to modify its procedures and requirements for the content and review of mining permit applications, or the federal government will be ordered to assume control over mining permits in West Virginia. Any of these changes are likely to increase the cost of preparing applications and the time required for their review, and may entail additional operating expenditures and, possibly, restrictions on operating. West Virginia SMCRA Bond Lawsuit. In November 2000, the West Virginia Highlands Conservancy filed a lawsuit in federal district court against the U.S. Department of Interior, the U.S. Office of Surface Mining and the West Virginia Department of Environmental Protection. The lawsuit, West Virginia Highlands Conservancy v. Norton, which seeks declaratory and injunctive relief, generally challenges the adequacy of the two-tier West Virginia alternative bond reclamation program. The first tier requires mine operators to post a bond of up to $5,000 per acre mined. The second tier creates a special reclamation fund which is funded by an assessment on mine operators of three cents per ton of coal mined. The West Virginia Highlands Conservancy claims that, individually and collectively, the alternative bond reclamation program has inadequate funds to cover the state's cost of conducting mining site reclamation for those sites where the mine operator has defaulted, or might default, on its reclamation obligations. Based upon the alleged inadequacy of the alternative bonding program, the lawsuit claims that the Department of the Interior and the Office of Surface Mining violated their obligations under SMCRA by either (1) not asserting federal control over the West Virginia SMCRA bonding program or (2) not revoking federal approval of the West Virginia SMCRA program and assuming control under SMCRA. The lawsuit also alleges that the West Virginia Department of Environmental Protection (1) failed to ensure that the state bonding program met certain minimum requirements and (2) improperly issued SMCRA permits without requiring mine operators to post sufficient reclamation bonds. In May 2001, the district court dismissed all claims against the West Virginia Department of Environmental Protection based upon the principle of sovereign immunity. The Office of Surface Mining, in June 2001, initiated formal administrative action against the West Virginia Department of Environmental Protection regarding the alleged deficiencies in the state bonding program. The current deficit will be eliminated through special reclamation taxes on clean coal production totaling fourteen cents per ton, of which seven cents is an additional temporary tax that will terminate in 39 months. The Office of Surface Mining has projected that these taxes will eliminate the deficit. These taxes and whatever other requirements may be adopted in the future by the advisory council will likely result in increases in the funds that mine operators are required to post in order to obtain permits and could II-19
result in further additional costs or fees related to the operation of a coal mine or the sale of coal. Any changes to the state reclamation bonding program could also complicate and protract the process of applying for and obtaining necessary permits. On June 25, 2002, the West Virginia Highlands Conservancy filed an amended complaint challenging the Office of Surface Mining's approval of the amendments to the West Virginia alternative bonding program. The district court entered a final order on January 9, 2003 denying the plaintiffs' motion for summary judgment on the issues raised in its complaint. The court also granted with four minor exceptions the motion for summary judgment filed by the Office of Surface Mining in support of its May 29 rule. Unless appealed and stayed, the Department for Environmental Protection will continue to administer its bonding program to address the deficiencies noted by OSM in its May 29, 2002 rule. Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of endangered species may have the effect of prohibiting or delaying the Company from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. A number of species indigenous to the Company's properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, the Company does not believe there are any species protected under the Endangered Species Act that would materially and adversely affect its ability to mine coal from its properties in accordance with current mining plans. Other Environmental Laws Affecting the Company. The Company is required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. The Company believes that it is in substantial compliance with all applicable environmental laws. COMPETITION -- EXCESS INDUSTRY CAPACITY The coal industry is intensely competitive, primarily as a result of the existence of numerous producers in the coal-producing regions in which the Company operates, and some of the Company's competitors may have greater financial resources. The Company competes with several major coal producers in the Central Appalachian and Powder River Basin areas. The Company also competes with a number of smaller producers in those and other market regions. The Company is also subject to the risk of reduced profitability as a result of excess industry capacity, which results in reduced coal prices. ELECTRIC INDUSTRY FACTORS; CUSTOMER CREDITWORTHINESS Demand for coal and the prices that the Company will be able to obtain for its coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for approximately 90% of domestic coal consumption in recent years. These coal consumption patterns are influenced by factors beyond the Company's control, including the demand for electricity (which is dependent to a significant extent on summer and winter temperatures); government regulation; technological developments and the location, availability, quality and price of competing sources of coal; other fuels such as natural gas, oil and nuclear; and alternative energy sources such as hydroelectric power. 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 in order to meet federal Clean Air Act requirements. Any reduction in the demand for the Company's coal by the domestic electric generation industry may cause a decline in profitability. Electric utility deregulation is expected to provide incentives to generators of electricity to minimize their fuel costs and is believed to have caused electric generators to be more aggressive in negotiating prices with coal suppliers. Deregulation may have a negative effect on the Company's profitability to the extent it causes the Company's customers to be more cost-sensitive. II-20
In addition, the Company's ability to receive payment for coal sold and delivered depends on the creditworthiness of its customers. In general, the creditworthiness of the Company's customers has deteriorated. If such trends continue, the Company's acceptable customer base may be limited. RELIANCE ON AND TERMS OF LONG-TERM COAL SUPPLY CONTRACTS During 2002, sales of coal under long-term contracts, which are contracts with a term greater than 12 months, accounted for 84% of the Company's total revenues. The prices for coal shipped under these contracts may be below the current market price for similar type coal at any given time. As a consequence of the substantial volume of its sales which are subject to these long-term agreements, the Company has less coal available with which to capitalize on stronger coal prices if and when they arise. In addition, because long-term contracts typically allow the customer to elect volume flexibility, the Company's ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to purchase higher volumes under such contracts, or the Company's exposure to market-based pricing may be increased should customers elect to purchase fewer tons. The increasingly short terms of sales contracts and the consequent absence of price adjustment provisions in such contracts also make it more likely that inflation related increases in mining costs during the contract term will not be recovered by the Company. RESERVE DEGRADATION AND DEPLETION The Company's profitability depends substantially on its ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. The Company has in the past acquired and will in the future acquire, coal reserves for its mine portfolio from third parties. The Company may not be able to accurately assess the geological characteristics of any reserves that it acquires, which may adversely affect the profitability and financial condition of the Company. 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 such mines. Mingo Logan's Mountaineer Mine is estimated to exhaust its longwall mineable reserves in 2006. The Mountaineer Mine generated $33.7 million and $36.7 million of the Company's total operating income in the year ended 2002 and 2001, respectively. POTENTIAL FLUCTUATIONS IN OPERATING RESULTS -- FACTORS ROUTINELY AFFECTING RESULTS OF OPERATIONS The Company's mining operations are inherently subject to changing conditions that can affect levels of production and production costs at particular mines for varying lengths of time and can result in decreases in profitability. Weather conditions, equipment replacement or repair, fuel prices, fires, variations in coal seam thickness, amounts of overburden rock and other natural materials, and other geological conditions have had, and can be expected in the future to have, a significant impact on operating results. A prolonged disruption of production at any of the Company's principal mines, particularly its Mingo Logan operation in West Virginia or Black Thunder mine in Wyoming, would result in a decrease, which could be material, in the Company's revenues and profitability. Other factors affecting the production and sale of the Company's coal that could result in decreases in its profitability include: (i) expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements; (ii) disruption or increases in the cost of transportation services; (iii) changes in laws or regulations, including permitting requirements; (iv) litigation; (v) work stoppages or other labor difficulties; (vi) mine worker vacation schedules and related maintenance activities; and (vii) changes in coal market and general economic conditions. TRANSPORTATION The coal industry depends on rail, trucking and barge transportation to deliver shipments of coal to customers, and transportation costs are a significant component of the total cost of supplying coal. Disruption of these transportation services could temporarily impair the Company's ability to supply coal to its customers. Increases in transportation costs, or changes in such costs relative to transportation costs for II-21
coal produced by its competitors or for other fuels, could have an adverse effect on the Company's business and results of operations. RESERVES -- TITLE The Company bases its reserve information on geological data assembled and analyzed by its staff which includes various engineers and geologists, and outside firms. The reserve estimates are annually updated to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities of recoverable reserves, including many factors beyond the control of the Company. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, such as geological and mining conditions which may not be fully identified by available exploration data or may differ from experience in current operations, historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies, and assumptions concerning coal prices, operating costs, severance and excise taxes, development costs, and reclamation costs, all of which may cause estimates to vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties, and revenues and expenditures with respect to the Company's reserves, may vary from estimates, and such variances may be material. These estimates thus may not accurately reflect the Company's actual reserves. The Company continually seeks to expand its operations and coal reserves in the regions in which it operates through acquisitions of businesses and assets. Acquisition transactions involve various inherent risks, such as assessing the value, strengths, weaknesses, contingent and other liabilities, and potential profitability of acquisition or other transaction candidates; the potential loss of key personnel of an acquired business; the ability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction; and unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction. Any one or more of these factors could impair the Company's ability to realize the benefits anticipated to result from the acquisition of businesses or assets. A significant part of the Company's mining operations are conducted on properties leased by the Company. The loss of any lease could adversely affect the Company's ability to develop the associated reserves. Because title to most of the Company's leased properties and mineral rights is not usually verified until a commitment is made by the Company to develop a property, which may not occur until after the Company has obtained necessary permits and completed exploration of the property, the Company's right to mine certain of its reserves may be adversely affected if defects in title or boundaries exist. In order to obtain leases or mining contracts to conduct mining operations on property where these defects exist, the Company has had to, and may in the future have to, incur unanticipated costs. In addition, the Company may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves or maintain its leasehold interests in properties on which mining operations are not commenced during the term of the lease. CERTAIN CONTRACTUAL ARRANGEMENTS The Company's affiliate, Arch Western Resources, LLC, is the owner of Company reserves and mining facilities in the western United States. The agreement under which Arch Western was formed provides that a subsidiary of the Company, as the managing member of Arch Western, generally has exclusive power and authority to conduct, manage and control the business of Arch Western. However, consent of BP Amoco, the other member of Arch Western, would generally be required in the event that Arch Western proposes to make a distribution, incur indebtedness, sell properties or merge or consolidate with any other entity if, II-22
at such time, Arch Western has a debt rating less favorable than specified ratings with Moody's Investors Service or Standard & Poor's or fails to meet specified indebtedness and interest ratios. In connection with the Company's June 1, 1998 acquisition of Atlantic Richfield Company's ("ARCO") coal operations, the Company entered into an agreement under which it agreed to indemnify ARCO against specified tax liabilities in the event that these liabilities arise as a result of certain actions taken prior to June 1, 2013, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western, or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. ARCO was acquired by BP Amoco in 2000. Depending on the time at which any such indemnification obligation were to arise, it could impact the Company's profitability for the period in which it arises. The membership interests in Canyon Fuel, which operates three coal mines in Utah, are owned 65% by Arch Western and 35% by a subsidiary of ITOCHU Corporation of Japan. The agreement that governs the management and operations of Canyon Fuel provides for a management board to manage its business and affairs. Some major business decisions concerning Canyon Fuel require the vote of 70% of the membership interests and therefore limit the Company's ability to make these decisions. These decisions include admission of additional members; approval of annual business plans; the making of significant capital expenditures; sales of coal below specified prices; agreements between Canyon Fuel and any member; the institution or settlement of litigation; a material change in the nature of Canyon Fuel's business or a material acquisition; the sale or other disposition, including by merger, of assets other than in the ordinary course of business; incurrence of indebtedness; the entering into of leases; and the selection and removal of officers. The Canyon Fuel agreement also contains various restrictions on the transfer of membership interests in Canyon Fuel. The Company's Amended and Restated Certificate of Incorporation requires the affirmative vote of the holders of at least two-thirds of outstanding common stock voting thereon to approve a merger or consolidation and certain other fundamental actions involving or affecting control of the Company. The Company's Bylaws require the affirmative vote of at least two-thirds of the members of the Board of Directors of the Company in order to declare dividends and to authorize certain other actions. CRITICAL ACCOUNTING POLICIES The Company's financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Additionally, these estimates and judgments are discussed with the Company's audit committee on a periodic basis. Actual results may differ from the estimates used under different assumptions or conditions. Note 1 to the Consolidated Financial Statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity: ACCRUED RECLAMATION AND MINE CLOSURE COSTS The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. The Company accrues for the cost of final mine closure reclamation over the estimated useful mining life of the property. The Company determines the total amount to be accrued on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on engineering data. Cost estimates are based upon historical internal or third-party costs, depending on how the work is II-23
expected to be performed. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. On at least an annual basis, the Company reviews its entire reclamation liability and makes necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2002 and 2001, the Company had recorded reclamation and mine closure liabilities of $137.7 million and $129.4 million, respectively. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2002, we estimate that the aggregate cost of final mine closure is approximately $292.2 million. Effective January 1, 2003, the Company adopted FAS 143, Accounting for Asset Retirement Obligations, which significantly changes the way in which the Company accounts for its reclamation and mine closure liabilities. The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. See further discussion regarding the impact of adoption of FAS 143 in Note 1 to the Consolidated Financial Statements. EMPLOYEE BENEFIT PLANS The Company has non-contributory defined benefit pension plans covering certain of its salaried and non-union hourly employees. Benefits are generally based on the employee's years of service and compensation. The Company funds the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes. The Company accounts for its defined benefit plans in accordance with FAS 87, Employer's Accounting for Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis. The Company also currently provides certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for retirees who were members of the United Mine Workers of America ("UMWA") is not contributory. The Company's current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid. The Company accounts for its other postretirement benefits in accordance with FAS 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis. Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the pension and postretirement benefit plans. These assumptions include the discount rate, future cost trend rates and future rates of return for pension plan assets. Each of these assumptions is discussed further below: - The discount rate assumption reflects the rates available on high-quality fixed-income debt instruments at year end. - Future cost trend rates include the rate of compensation increase for the pension obligation and the health care cost trend rate for other postretirement benefit obligations. The rate of compensation increase is determined based upon the Company's long-term plans for such increases. The health care cost trend rate is determined based upon the Company's own historical trends for health care costs as well as external data regarding such costs. - Assumptions regarding future rates of return for pension plan assets are based on long-term historical actual return information for the mix of investments that comprise plan assets, and future estimates of long-term investment returns. II-24
Due to changes in these and other assumptions, the Company expects that expenses in 2003 related to its pension and postretirement plans will increase by approximately $32 million as compared to expenses incurred in 2002. INCOME TAXES The Company records deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of assets and liabilities. A valuation allowance is recorded to reflect the expected future tax benefits to be realized. In determining the appropriate valuation allowance, the Company takes into account the level of expected future taxable income and available tax planning strategies. If future taxable income was lower than expected or if expected tax planning strategies were not available as anticipated, the Company may record additional valuation allowance through income tax expense in the period such determination was made. II-25
REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors Arch Coal, Inc. We have audited the accompanying consolidated balance sheets of Arch Coal, Inc. and subsidiaries as of December 31, 2002 and 2001 and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above (appearing on pages II-28 to II-59 of this annual report) present fairly, in all material respects, the consolidated financial position of Arch Coal, Inc. and subsidiaries at December 31, 2002 and 2001, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for derivatives and hedging activities effective January 1, 2001. /s/ ERNST & YOUNG LLP ERNST & YOUNG LLP St. Louis, Missouri January 22, 2003 II-26
REPORT OF MANAGEMENT The management of Arch Coal, Inc. is responsible for the preparation of the consolidated financial statements and related financial information in this annual report. The financial statements are prepared in accordance with accounting principles generally accepted in the United States and necessarily include some amounts that are based on management's informed estimates and judgments, with appropriate consideration given to materiality. The Company maintains a system of internal accounting controls designed to provide reasonable assurance that financial records are reliable for purposes of preparing financial statements and that assets are properly accounted for and safeguarded. The concept of reasonable assurance is based on the recognition that the cost of a system of internal accounting controls should not exceed the value of the benefits derived. The Company has a professional staff of internal auditors who monitor compliance with and assess the effectiveness of the system of internal accounting controls. The Audit Committee of the Board of Directors, composed of directors who are free from relationships that may impair their independence from Arch Coal, Inc., meets regularly with management, the internal auditors, and the independent auditors to discuss matters relating to financial reporting, internal accounting control, and the nature, extent and results of the audit effort. The independent auditors and internal auditors have full and free access to the Audit Committee, with and without management present.
CONSOLIDATED STATEMENTS OF OPERATIONS
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY THREE YEARS ENDED DECEMBER 31, 2002
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (IN THOUSANDS OF DOLLARS EXCEPT PER SHARE DATA) 1. ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries ("the Company"), which operate in the coal mining industry. The Company operates one reportable segment: the production of steam and metallurgical coal from surface and deep mines throughout the United States, for sale to utility, industrial and export markets. The Company's mines are primarily located in the Central Appalachian and western regions of the United States. All subsidiaries (except as noted below) are wholly owned. Significant intercompany transactions and accounts have been eliminated in consolidation. The Company's Wyoming, Colorado and Utah coal operations are included in a joint venture named Arch Western Resources, LLC ("Arch Western"). Arch Western is 99% owned by the Company and 1% owned by BP Amoco. The Company also acts as the managing member of Arch Western. The membership interests in Canyon Fuel Company, LLC ("Canyon Fuel") are owned 65% by the Company and 35% by a subsidiary of ITOCHU Corporation, a Japanese corporation. The agreement which governs the management and operations of Canyon Fuel provides for a Management Board to manage its business and affairs. Generally, the Management Board acts by affirmative vote of the representatives of the members holding more than 50% of the membership interests. However, significant participation rights require either the unanimous approval of the members or the approval of representatives of members holding more than 70% of the membership interests. Those matters which are considered significant participation rights include the following: - approval of the annual business plan; - approval of significant capital expenditures; - approval of significant coal sales contracts; - approval of the institution of, or the settlement of litigation; - approval of incurrence of indebtedness; - approval of significant mineral reserve leases; - selection and removal of the CEO, CFO, or General Counsel; - approval of any material change in the business of Canyon Fuel; - approval of any disposition whether by sale, exchange, merger, consolidation, license or otherwise, and whether directly or indirectly, of all or any portion of the assets of Canyon Fuel other than in the ordinary course of business; and - approval of request that a member provide additional services to Canyon Fuel. The Canyon Fuel agreement also contains various restrictions on the transfer of membership interests in Canyon Fuel. As a result of these super-majority voting rights, the Company's 65% ownership of Canyon Fuel is accounted for on the equity method in the consolidated financial statements. Income from Canyon Fuel is reflected in the Consolidated Statements of Operations as income from equity investments. (See additional discussion in "Investment in Canyon Fuel" in Note 4.) The Company owns 34% of the limited partnership units of Natural Resource Partners, LP (NRP) and 42.25% of the general partner interest. The Company's investment in NRP is accounted for on the equity method in the consolidated financial statements. (See additional discussion in "Investment in Natural Resource Partners" in Note 5.) II-32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company's 17.5% partnership interest in Dominion Terminal Associates is accounted for on the equity method in the consolidated balance sheets. Allocable costs of the partnership for coal loading and storage are included in other expenses in the consolidated statements of operations. ACCOUNTING ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. CASH AND CASH EQUIVALENTS Cash and cash equivalents are stated at cost. Cash equivalents consist of highly liquid investments with an original maturity of three months or less when purchased. ALLOWANCE FOR UNCOLLECTIBLE RECEIVABLES The Company maintains allowances to reflect the expected uncollectability of its trade accounts receivable and other receivables based on past collection history, the economic environment and specified risks identified in the receivables portfolio. Allowances recorded at December 31, 2002 and 2001 were $3.9 million and $0.5 million, respectively. INVENTORIES Inventories consist of the following:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) based on discounted cash flows attributable to the difference between the above-market contract price and the then-prevailing market price. Accumulated amortization for sales contracts was $191.0 million and $198.6 million at December 31, 2002 and 2001, respectively. EXPLORATION COSTS Costs related to locating coal deposits and determining the economic mineability of such deposits are expensed as incurred. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures which extend the useful lives of existing plant and equipment or increase the productivity of the asset are capitalized. Costs of purchasing rights to coal reserves and developing new mines, or significantly expanding the capacity of existing mines, are capitalized. These costs are amortized using the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited. During 2002, all mineral reserves of the Company that are capitalized are being amortized on the units-of-production method through Company operations or through sublease transactions (for which the Company receives royalty revenue) except for a block of 197 million tons located adjacent to its Hobet 21 operations. The current value associated with this property is $178.7 million, which the Company plans to recover via mining operations in the future. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, which range from three to 30 years except for preparation plants and loadouts. Preparation plants and loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimum level of depreciation. Leased property meeting certain criteria is capitalized and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed on the straight-line method over the term of the lease. ASSET IMPAIRMENT If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value. REVENUE RECOGNITION Coal sales revenues include sales to customers of coal produced at Company operations and coal purchased from other companies. The Company recognizes revenue from coal sales at the time title passes to the customer. Transportation costs that are billed by the Company and reimbursed to the transportation provider are included in coal sales and cost of coal sales. Revenues from sources other than coal sales, including gains and losses from dispositions of long-term assets, are included in other revenues and are recognized as services are performed or otherwise earned. DERIVATIVE FINANCIAL INSTRUMENTS The Company utilizes derivative financial instruments in the management of its interest rate and diesel fuel exposures. The Company does not use derivative financial instruments for trading or speculative purposes. The Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133"), on January 1, 2001. FAS 133 requires all derivative financial instruments to be reported on the balance sheet at fair value. Changes in fair value are recognized either in earnings or equity, depending on the nature of the underlying exposure being hedged II-34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) and how effective the derivatives are at offsetting price movements in the underlying exposure. All of the Company's existing derivative positions, which consist of interest rate swaps and heating oil swaps, qualified for cash flow hedge accounting under FAS 133 and are deemed to be effective for the variable- rate debt and diesel fuel purchases being hedged. Prior to the adoption of FAS 133, the fair values of the swap agreements were not recognized in the financial statements. Gains and losses on terminations of swap agreements that qualify as cash flow hedges are deferred on the balance sheets (in other long-term liabilities) and amortized as an adjustment to expense over the remaining original term of the terminated swap agreement. The Company evaluates all derivative instruments each quarter to determine that they are highly effective. Any ineffectiveness is recorded in the Consolidated Statements of Operations. Ineffectiveness for the year ended December 31, 2002 was $0.8 million and was recorded as a reduction of other expenses in the Consolidated Statements of Operations. The Company enters into interest-rate swap agreements to modify the interest characteristics of outstanding Company debt. The swap agreements essentially convert variable-rate debt to fixed-rate debt. These agreements require the exchange of amounts based on variable interest rates for amounts based on fixed interest rates over the life of the agreement. The Company accrues amounts to be paid or received under interest-rate swap agreements over the lives of the agreements. Such amounts are recognized as adjustments to interest expense over the lives of agreements, thereby adjusting the effective interest rate on the Company's debt. The Company enters into heating oil swaps to eliminate volatility in the price to purchase diesel fuel for its operations. The swap agreements essentially fix the price paid for diesel fuel by requiring the Company to pay a fixed heating oil price and receive a floating heating oil price. The changes in the floating heating oil price highly correlate to changes in diesel fuel costs. The Company recorded the fair value of the derivative financial instruments on the balance sheet as an "other non-current liability" and recorded the unrealized loss, net of tax, in "accumulated other comprehensive loss." The adoption of FAS 133 had no impact on the Company's results of operations or cash flows. INCOME TAXES Deferred income taxes are based on temporary differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates for years during which taxes are expected to be paid or recovered. STOCK-BASED COMPENSATION These financial statements include the disclosure requirements of Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation ("FAS 123"), as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation -- Transition and Disclosure ("FAS 148"). With respect to accounting for its stock options, as permitted under FAS 123, the Company has retained the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 ("APB 25"), Accounting for Stock Issued to Employees, and related Interpretations. Had compensation expense for stock option grants been determined based on the fair value at the grant dates II-35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) consistent with the method of FAS 123, the Company's net income (loss) and earnings (loss) per common share would have been changed to the pro forma amounts as indicated in the following table:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) tons mined at its Skyline mine. The rate reduction applies to certain tons mined from September 1, 2001 through September 1, 2006. The Company's portion of the retroactive refund was $1.1 million, and is reflected in 2002 as income from equity investments in the Consolidated Statements of Operations. The Company's operating results for the year ended December 31, 2001, reflect a $9.4 million insurance settlement as part of the Company's coverage under its property and business interruption policy. The insurance settlement represents the final settlement for losses incurred at the West Elk mine in Gunnison County, Colorado, which was idled from January 28, 2000 to July 12, 2000 following the detection of combustion-related gases. The results for the year ended December 31, 2000, reflect $31.0 million in partial insurance settlements associated with this event. During the year ended December 31, 2001, the Company reduced its reclamation liability resulting in a pre-tax gain of $7.5 million, of which $5.6 million was the result of permit revisions and the ultimate sale of the surface rights at its idle mine properties in Illinois, and $1.9 million was a result of estimate changes. Also, as a result of permit revisions at the idle mine properties in Illinois during the year ended December 31, 2000, the Company reduced its reclamation liability, resulting in a pre-tax gain of $7.8 million. During the year ended December 31, 2001, as a result of progress in processing claims associated with the recovery of certain previously paid excise taxes on export sales, the Company recognized a pre-tax gain of $4.6 million. Of the $4.6 million recognized, $3.1 million represents the interest component of the claim and was recorded as interest income. The gain stems from an IRS notice during the second quarter of 2000 outlining the procedures for obtaining tax refunds on black lung excise taxes paid by the industry on export sales. The notice was the result of a 1998 federal district court decision that found such taxes to be unconstitutional. The Company recorded $12.7 million of pre-tax income related to these excise tax recoveries during the year ended December 31, 2000. During the year ended December 31, 2001, the Company received a state tax credit covering prior periods that resulted in a pre-tax gain of $7.4 million. As a result of several litigation settlements, the Company increased its litigation reserve during 2001, resulting in a pre-tax decrease in income of $5.6 million. The Company also increased its stock-based benefit program accruals for awards that met minimum performance levels to qualify for a payout. This resulted in a decrease in pre-tax income of $4.1 million during the year ended December 31, 2001. During 2001, Canyon Fuel, the Company's equity method investment, recognized recoveries of previously paid property taxes. The Company's share of these recoveries was $2.6 million and is reflected in income from equity investment on the Consolidated Statements of Operations for the year ending December 31, 2001. The Company recognized a $13.5 million pre-tax gain in 2001 and a $12.1 million pre-tax gain in 2000 primarily as a result of selling land. In 2000, as a result of adjustments to employee postretirement medical benefits, the Company recognized $9.8 million of pre-tax curtailment gains resulting from previously unrecognized postretirement benefit changes which occurred from plan amendments in previous years. The Company also settled certain workers' compensation liabilities during 2000 with the state of West Virginia, resulting in pre-tax gains of $21.8 million. This was partially offset in 2000 by adjustments to other workers' compensation liabilities resulting from changes in estimates which caused increases to the liability of $13.5 million. II-37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 3. OTHER COMPREHENSIVE INCOME Other comprehensive income items under FAS 130, Reporting Comprehensive Income, are transactions recorded in stockholders' equity during the year, excluding net income and transactions with stockholders. Following are the items included in other comprehensive income (loss) and the related tax effects:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED BALANCE SHEET INFORMATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As of December 31, 2002, the unit price for NRP's common limited partnership units was $20.70. Based on this market price, the market value of the Company's investment is approximately $159.2 million. Income from the Company's equity investment in NRP represents the Company's share of NRP's earnings for the period from October 17, 2002 (the formation of NRP) through November 30, 2002. Financial information for NRP through December 31, 2002 was not available at the time that the Company released its financial results. As such, the Company will account for income from its investment in NRP on a one-month lag. Summarized financial information for NRP as of December 31, 2002 and for the period from October 17, 2002 through December 31, 2002 is as follows (in thousands):
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 7. INCOME TAXES Significant components of the provision (benefit) for income taxes are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Significant components of the Company's deferred tax assets and liabilities that result from carryforwards and temporary differences between the financial statement basis and tax basis of assets and liabilities are summarized as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. DEBT AND FINANCING ARRANGEMENTS Debt consists of the following:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) having a total notional value of $525.0 million, including $250.0 million for which the fixed rate becomes effective as of October 2003. These swap agreements are used to convert variable-rate debt to fixed-rate debt. Under these swap agreements, the Company pays a weighted-average fixed rate of 5.74% (before the credit spread over LIBOR) and is receiving a weighted-average variable rate based upon 30-day and 90-day LIBOR. At December 31, 2002, the remaining terms of the swap agreements ranged from 32 to 57 months. 9. FAIR VALUES OF FINANCIAL INSTRUMENTS The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments: Cash and cash equivalents: The carrying amounts approximate fair value. Debt: The carrying amounts of the Company's borrowings under its revolving credit agreement, lines of credit, variable-rate term loans and other long-term debt approximate their fair value. Interest rate swaps: The fair values of interest rate swaps are based on quoted prices, which reflect the present value of the difference between estimated future amounts to be paid and received. At December 31, 2002 and 2001 the fair value of these swaps are liabilities of $37.4 million and $24.6 million, respectively. Heating oil swaps: The fair values of heating oil swaps are based on quoted prices. The fair value of these swaps are an asset of $0.3 million at December 31, 2002 and a liability of $2.7 million at December 31, 2001. 10. ACCRUED WORKERS' COMPENSATION The Company is liable under the federal Mine Safety and Health Act of 1977, as amended, to provide for pneumoconiosis (black lung) benefits to eligible employees, former employees, and dependents with respect to claims filed by such persons on or after July 1, 1973. The Company is also liable under various states' statutes for black lung benefits. The Company currently provides for federal and state claims principally through a self-insurance program. Charges are being made to operations as determined by independent actuaries, at the present value of the actuarially computed present and future liabilities for such benefits over the employees' applicable years of service. In addition, the Company is liable for workers' compensation benefits for traumatic injuries which are accrued as injuries are incurred. Workers' compensation costs (credits) include the following components:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In 2000, the Company settled several of its mining operations' self-insured workers' compensation and black lung liabilities with the State of West Virginia resulting in pre-tax gains of $21.8 million. This was partially offset in 2000 by adjustments to other workers' compensation liabilities resulting from changes in estimates which caused increases to the liability of $13.5 million. The net workers' compensation adjustment was a pre-tax gain of $8.3 million. Summarized below is information about the amounts recognized in the consolidated balance sheets for workers' compensation benefits:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 12. EMPLOYEE BENEFIT PLANS DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS The Company has non-contributory defined benefit pension plans covering certain of its salaried and non-union hourly employees. Benefits are generally based on the employee's years of service and compensation. The Company funds the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes. The Company also currently provides certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for retirees who were members of the United Mine Workers of America ("UMWA") is not contributory. The Company's current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid. Summaries of the changes in the benefit obligations, plan assets (primarily listed stocks and debt securities) and funded status of the plans are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table details the components of pension and other postretirement benefit costs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 13. CAPITAL STOCK On February 22, 2001, the Company completed a public offering of 9,927,765 shares of common stock, including the remaining 4,756,968 shares held by its then largest stockholder, and 5,170,797 primary and treasury shares issued directly by the Company. The proceeds realized by the Company from the transaction of $92.9 million after the underwriters' discount and expenses, were used to pay down debt. On April 12, 2001, the Company filed a Universal Shelf Registration Statement on Form S-3 with the Securities and Exchange Commission. The Universal Shelf allows the Company to offer, from time to time, an aggregate of up to $750 million in debt securities, preferred stock, depositary shares, common stock and related rights and warrants. On May 8, 2001, the Company utilized its Universal Shelf and completed a public offering of 8,500,000 primary shares of common stock. On May 16, 2001, the underwriters involved in the offering purchased an additional 424,200 shares pursuant to an over-allotment option granted by the Company in connection with the May 8, 2001 offering. The proceeds realized from these transactions after the underwriting discount and expenses were $279.3 million. These proceeds were used to pay down debt. On January 31, 2003, the Company utilized its Universal Shelf and completed a public offering of 2,875,000 shares of 5% Perpetual Cumulative Convertible Preferred Stock. The net proceeds realized by the Company from the offering of $139.1 million are being used to reduce indebtedness under the Company's revolving credit facility, and for working capital and general corporate purposes. Dividends on the preferred stock will be cumulative and will be payable quarterly at the annual rate of 5% of the liquidation preference. Each share of the preferred stock will be initially convertible, under certain conditions, into 2.3985 shares of the Company's common stock. The preferred stock is redeemable, at the Company's option, on or after January 31, 2008 if certain conditions are met. The holders of the preferred stock are not entitled to voting rights on matters submitted to the Company's common shareholders. However, if the Company fails to pay the equivalent of six quarterly dividends, the holders of the preferred stock will be entitled to elect two directors to the Company's board of directors. Subsequent to the January 2003 offering, the Company can still issue an additional $311.8 million in debt and equity securities under the Universal Shelf. On September 14, 2001, the Company's Board of Directors approved a stock repurchase plan, under which the Company may repurchase up to 6.0 million of its shares of common stock from time to time. Through December 31, 2002, the Company repurchased 357,200 shares of its common stock for $5.0 million pursuant to the plan at an average price of $14.13 per share. The repurchased shares are being held in the Company's treasury, which the Company accounts for using the average cost method. Future repurchases under the plan will be made at management's discretion and will depend on market conditions and other factors. As of December 31, 2000, the Company had acquired 1,726,900 shares under a prior repurchase program at an average price of $12.29 per share. All of the December 31, 2000 treasury shares were reissued in connection with the February 22, 2001 public offering discussed above. 14. STOCKHOLDER RIGHTS PLAN On March 3, 2000, the Board of Directors adopted a stockholder rights plan under which preferred share purchase rights were distributed as a dividend to the Company's stockholders of record on March 20, 2000. The rights are exercisable only if a person or group acquires 20% or more of the Company's Common Stock (an "Acquiring Person") or announces a tender or exchange offer the consummation of which would result in ownership by a person or group of 20% or more of the Company's Common Stock. Each right entitles the holder to buy one one-hundredth of a share of a series of junior participating preferred stock at an exercise price of $42, or in certain circumstances allows the holder (except for the Acquiring Person) to purchase the Company's Common Stock or voting stock of the Acquiring Person at a II-49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) discount. At its option, the Board of Directors may allow some or all holders (except for the Acquiring Person) to exchange their rights for Company Common Stock. The rights will expire on March 20, 2010, subject to earlier redemption or exchange by the Company as described in the plan. 15. STOCK INCENTIVE PLAN AND OTHER INCENTIVE PLANS Under the Company's 1997 Stock Incentive Plan (the "Company Incentive Plan"), 9,000,000 shares of the Company's common stock were reserved for awards to officers and other selected key management employees of the Company. The Company Incentive Plan provides the Board of Directors with the flexibility to grant stock options, stock appreciation rights (SARs), restricted stock awards, restricted stock units, performance stock or units, merit awards, phantom stock awards and rights to acquire stock through purchase under a stock purchase program ("Awards"). Awards the Board of Directors elects to pay out in cash do not count against the 9,000,000 shares authorized in the Company Incentive Plan. As of December 31, 2002, stock options, performance units and restricted stock awards were the only types of awards granted. Each is discussed more fully below. STOCK OPTIONS Stock options are generally subject to vesting provisions of at least one year from the date of grant and are granted at a price equal to 100% of the fair market value of the stock on the date of grant. Information regarding stock options under the Company Incentive Plan is as follows for the years ended December 31, 2002, 2001 and 2000:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the remaining 0.4 million options vest ratably over three years. The stock options granted in 2000 vest ratably over three years.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company is committed under long-term contracts to supply coal that meets certain quality requirements at specified prices. These prices are generally adjusted based on indices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer. The Company and its operating subsidiaries sold approximately 106.7 million tons of coal in 2002. Approximately 84% of this tonnage and revenue was sold under long-term contracts (contracts having a term of greater than one year). Prices for coal sold under long-term contracts ranged from $3.56 to $61.43 per ton. Long-term contracts ranged in remaining life from one to 15 years. Some of these contracts include pricing which is above, and, in some cases, materially above, current market prices. Sales (including spot sales) to major customers were as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 19. RELATED PARTY TRANSACTIONS As described in Note 1, the Company has a 65% ownership interest in Canyon Fuel which is accounted for on the equity method. The Company receives administration and production fees from Canyon Fuel for managing the Canyon Fuel operations. The fee arrangement is calculated annually and is approved by the Canyon Fuel Management Board. The production fee is calculated on a per-ton basis while the administration fee represents the costs incurred by the Company's employees related to Canyon Fuel administrative matters. The fees recognized as other income by the Company and as expense by Canyon Fuel were $9.5 million, $8.1 million and $7.4 million for the years ended December 31, 2002, 2001 and 2000, respectively. Amounts receivable from Canyon Fuel were $6.3 million and $2.7 million as of December 31, 2002 and 2001, respectively. Such amounts are classified as other receivables in the Consolidated Balance Sheets. As described in Note 1, the Company has a 34% ownership interest in NRP. The Company leases certain coal reserves from NRP and pays royalties to NRP for the right to mine those reserves. Terms of the leases require the Company to prepay royalties with those payments recoupable against production. Amounts recognized as cost of coal sales for royalties paid to NRP during the year ended December 31, 2002 were $2.1 million. Amounts paid to NRP and included in the accompanying balance sheet as prepaid royalties as of December 31, 2002 were $1.8 million. 20. COMMITMENTS AND CONTINGENCIES The Company leases equipment, land and various other properties under noncancelable long-term leases, expiring at various dates. Rental expense related to these operating leases amounted to $19.0 million in 2002, $22.5 million in 2001 and $22.7 million in 2000. The Company has also entered into various non-cancelable royalty lease agreements and federal lease bonus payments under which future minimum payments are due. On October 1, 1998, the Company was the successful bidder in a federal auction of certain mining rights in the 3,546 acre Thundercloud tract in the Powder River Basin of Wyoming. The Company's lease bonus bid amounted to $158 million for the tract, of which $31.6 million was paid on October 1, 1998 and $31.6 million was paid in the month of January in each of the years 2000, 2001, and 2002, respectively. The remaining lease bonus payment is reflected below as a component of "Royalties". The tract contains approximately 412 million tons of demonstrated coal reserves and is contiguous with the Company's Black Thunder mine. Geological surveys performed by outside consultants indicate that there are sufficient reserves relative to these properties to permit recovery of the Company's investment. Minimum payments due in future years under these agreements in effect at December 31, 2002 are as follows (in thousands):
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of pending claims given existing legal accruals, will not have a material adverse effect on the consolidated financial condition, results of operations or liquidity of the Company. The Company holds a 17.5% general partnership interest in Dominion Terminal Associates ("DTA"), which operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia. DTA leases the facility from Peninsula Ports Authority of Virginia ("PPAV") for amounts sufficient to meet debt-service requirements. Financing is provided through $132.8 million of tax-exempt bonds issued by PPAV (of which the Company is responsible for 17.5%, or $23.2 million) which mature July 1, 2016. Under the terms of a throughput and handling agreement with DTA, each partner is charged its share of cash operating and debt-service costs in exchange for the right to use its share of the facility's loading capacity and is required to make periodic cash advances to DTA to fund such costs. On a cumulative basis, costs exceeded cash advances by $12.2 million at December 31, 2002 (such amount is included in other noncurrent liabilities). Future payments for fixed operating costs and debt service are estimated to approximate $2.3 million annually through 2015 and $26.0 million in 2016. In connection with the Company's acquisition of the coal operations of Atlantic Richfield Company ("ARCO") and the simultaneous combination of the acquired ARCO operations and the Company's Wyoming operations into the Arch Western joint venture, the Company agreed to indemnify another member of Arch Western against certain tax liabilities in the event that such liabilities arise as a result of certain actions taken prior to June 1, 2013, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. Depending on the time at which any such indemnification obligation was to arise, it could have a material adverse effect on the business, results of operations and financial condition of the Company. 21. CASH FLOW The changes in operating assets and liabilities as shown in the consolidated statements of cash flows are comprised of the following:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 22. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Quarterly financial data for 2002 and 2001 is summarized below:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) recorded $4.6 million of pre-tax income resulting from additional favorable developments associated with these tax refunds. Of this amount, $3.1 million represented the interest portion of the claim and was recorded as interest income (and therefore did not impact income from operations) (7) During the fourth quarter of 2001, the Company recognized a $7.4 million pre-tax gain from a state tax credit covering prior periods. (8) During the fourth quarter of 2001, the Company increased its litigation reserves reducing pre-tax income by $5.6 million resulting from several litigation settlements. (9) The sum of the quarterly earnings (loss) per common share amounts may not equal earnings (loss) per common share for the full year because per share amounts are computed independently for each quarter and for the year based on the weighted average number of common shares outstanding during each period. II-56
SELECTED FINANCIAL INFORMATION
- --------------- (1) During the year ended December 31, 2002, the Company settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain of $5.6 million which was recognized in other revenues in the Consolidated Statement of Operations. (2) The Company recognized a pre-tax gain of $4.6 million during the year ended December 31, 2002 as a result of a workers' compensation premium adjustment refund from the State of West Virginia. During 1998, the Company entered into the West Virginia workers' compensation plan at one of its subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers' Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers' Compensation refunded $4.6 million in premiums which was recognized as an adjustment to cost of coal sales in the Consolidated Statement of Operations. (3) During the year ended December 31, 2002, the Company was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its West Elk location. The rate reduction applies to a specified number of tons beginning October 1, 2001 and ending no later than October 1, 2005. The retroactive portion of the refund totaled $3.3 million and has been recognized in 2002 as a reduction of cost of coal sales in the Consolidated Statements of Operations. Additionally, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined from September 1, 2001 through September 1, 2006. The Company's portion of the retroactive refund was $1.1 million, and is reflected in 2002 as income from equity investments in the Consolidated Statements of Operations. (4) At the West Elk underground mine in Gunnison County, Colorado, following the detection of combustion-related gases in a portion of the mine, the Company idled its operation on January 28, 2000. On July 12, 2000, after controlling the combustion-related gases, the Company resumed production at the West Elk mine and started to ramp up to normal levels of production. The Company recognized partial pre-tax insurance settlements of $31.0 million during 2000 and a final pre-tax insurance settlement related to the event of $9.4 million during 2001. (5) The IRS issued a notice outlining the procedures for obtaining tax refunds on certain excise taxes paid by the industry on export sales tonnage. The notice was the result of a 1998 federal court decision that found such taxes to be unconstitutional. The Company recorded $12.7 million of pre-tax income related to these excise tax recoveries during 2000. During 2001 the Company recorded an additional $4.6 million of pre-tax income resulting from additional favorable developments associated with these tax refunds. (6) The Company recognized a $7.4 million pre-tax gain during 2001 from a state tax credit covering prior periods. (7) As a result of adjustments to employee postretirement medical benefits, the Company recognized $9.8 million of pre-tax curtailment gains resulting from previously unrecognized postretirement benefit changes which occurred in prior years. (8) The Company settled certain workers' compensation liabilities with the state of West Virginia partially offset by adjusting other workers' compensation liabilities resulting in a net pre-tax gain of $8.3 million. (9) The Company changed its depreciation method on preparation plants and loadouts during the first quarter of 1999 and recorded a cumulative effect of applying the new method for years prior to 1999 which resulted in a decrease to net loss in 1999 of $3.8 million net-of-tax. (10) The loss from operations for 1999 reflects one-time pre-tax charges of $387.7 million related principally to the write-down of assets at its Dal-Tex, Hobet 21 and Coal-Mac operations and the write-down of certain other coal reserves in central Appalachia. Included in this charge was a $23.1 million pre-tax charge related to the restructuring of the Company's administrative work force and the closure of mines in Illinois, Kentucky and West Virginia. (11) Information for 1998 reflects the acquisition of Atlantic Richfield Company's domestic coal operations on June 1, 1998. As a result of the refinancing of Company debt resulting from the acquisition, the II-58
Company incurred an extraordinary charge of $1.5 million (net-of-tax benefit) related to the early extinguishment of debt which existed prior to the acquisition. (12) Income from operations for 1998 reflects pre-tax gains of $41.8 million from the disposition of assets including $18.5 million and $7.5 million on the sale or certain assets and property in eastern Kentucky and the sale of the Company's idle Big Sandy Terminal, respectively. (13) Adjusted EBITDA is defined as income (loss) from operations before the effect of net interest expense; income taxes; our depreciation, depletion and amortization; our equity interest in the depreciation, depletion and amortization of Canyon Fuel Company; write-down of impaired assets and restructuring charges (Note 10 above); and changes in accounting principles and extraordinary items (Notes 9 and 11 above). Adjusted EBITDA is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded to calculate Adjusted EBITDA are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDA should not be considered in isolation from nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. We believe that Adjusted EBITDA presents a useful measure of our ability to service and incur debt based on ongoing operations. Furthermore, analogous measures are used by industry analysts to evaluate operating performance. Investors should be aware that our presentation of Adjusted EBITDA may not be comparable to similarly titled measures used by other companies. The table below shows how we calculate Adjusted EBITDA.
STOCKHOLDER INFORMATION COMMON STOCK Arch Coal's common stock is listed and traded on the New York Stock Exchange and also has unlisted trading privileges on the Chicago Stock Exchange. The ticker symbol is ACI.
EXHIBIT 21 SUBSIDIARIES OF ARCH COAL, INC. The following is a complete list of the direct and indirect subsidiaries of Arch Coal, Inc., a Delaware corporation: JURISDICTION OF NAME INCORPORATION/FORMATION ---- ----------------------- Allegheny Land Company Delaware Apogee Coal Company Delaware Arch Coal Sales Company, Inc. Delaware Arch Coal Terminal, Inc. Delaware Arch Energy Resources, Inc. Delaware (1) Arch of Wyoming, LLC Delaware Arch Reclamation Services, Inc. Delaware (1) Arch Uinta, LLC Delaware Arch Western Acquisition Corporation Delaware (2) Arch Western Resources, LLC Delaware Ark Land Company Delaware Ashland Terminal, Inc. Delaware (1) AU Sub, LLC Delaware (3) Canyon Fuel Company, LLC Delaware (4) Catenary Coal Company Delaware Catenary Coal Holdings, Inc. Delaware Coal-Mac, Inc. Kentucky (4) Cumberland River Coal Company Delaware Energy Development Co. Iowa (5) Hobet Mining, Inc. West Virginia (5) Julian Tipple, Inc. Delaware (4) Lone Mountain Processing, Inc. Delaware Mingo Logan Coal Company Delaware (1) Mountain Coal Company, L.L.C. Delaware Mountain Gem Land, Inc. West Virginia Mountain Mining, Inc. Delaware Mountaineer Land Company Delaware P. C. Holding, Inc. Delaware Paint Creek Terminals, Inc. Delaware (1) State Leases LLC Delaware (1) Thunder Basin Coal Company, L.L.C. Delaware (6) Western Energy Resources, Inc. Delaware (1) Owned by Arch Western Resources, LLC. (2) Arch Western Acquisition Corporation owns a 99% membership interest in Arch Western Resources, LLC. (3) Arch Western Resources, LLC owns a 65% membership interest in Canyon Fuel Company, LLC. (4) Owned by Catenary Coal Holdings, Inc. (5) Owned by Mountain Mining, Inc. (6) Owned by Ark Land Company.
EXHIBIT 23.1 Independent Auditors' Consent We consent to the incorporation by reference in this Annual Report (Form 10-K) of Arch Coal, Inc. of our report dated January 22, 2003, included in the 2002 Annual Report to Stockholders of Arch Coal, Inc. Our audits also included the financial statement schedule of Arch Coal. Inc. listed in Item 15(a). This schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. We also consent to the incorporation by reference in (1) the Registration Statement (Form S-3 No. 333-58738) of Arch Coal, Inc. and in the related Prospectus, (2) the Registration Statement (Form S-8 No. 333-30565) pertaining to the Arch Coal, Inc. 1997 Stock Incentive Plan and in the related Prospectus, (3) the Registration Statement (Form S-8 No. 333-32777) pertaining to the Arch Coal, Inc. Employee Thrift Plan and in the related Prospectus, and (4) the Registration Statement (Form S-8 No. 333-68131) pertaining to the Arch Coal, Inc. Deferred Compensation Plan and in the related Prospectus of our reports dated January 22, 2003, with respect to the financial statements of Canyon Fuel Company, LLC and the consolidated financial statements of Arch Coal, Inc. and subsidiaries and of our opinion with respect to the financial statement schedule of Arch Coal. Inc. listed in Item 15(a) included or incorporated by reference in the Arch Coal, Inc. Annual Report (Form 10-K) for the year ended December 31, 2002. /s/ Ernst & Young LLP St. Louis, Missouri March 12, 2003
EXHIBIT 24 POWER OF ATTORNEY KNOW ALL PERSONS BY THESE PRESENTS: That each of the undersigned directors and the undersigned Director/Officer of ARCH COAL, INC., a Delaware corporation ("Arch Coal"), hereby constitutes and appoints Steven F. Leer, and Robert G. Jones, and each of them, his true and lawful attorneys-in-fact and agent, with full power to act without the other, to sign Arch Coal's Annual Report on Form 10-K for the year ended December 31, 2002, to be filed with the Securities and Exchange Commission under the provisions of the Securities Exchange Act of 1934, as amended; to file such Annual Report and the exhibits thereto and any and all other documents in connection therewith, including without limitation amendments thereto, with the Securities and Exchange Commission; and to do and perform any and all other acts and things requisite and necessary to be done in connection with the foregoing as fully as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. DATED: February 20, 2003 /s/ STEVEN F. LEER - ------------------------ President, Chief Executive Officer and Director Steven F. Leer /s/ JAMES R. BOYD - ----------------------- Chairman of the Board and Director James R. Boyd /s/ FRANK M. BURKE - ----------------------- Director Frank M. Burke /s/ DOUGLAS H. HUNT - ----------------------- Director Douglas H. Hunt /s/ JAMES L. PARKER - ----------------------- Director James L. Parker /s/ A. MICHAEL PERRY - ----------------------- Director A. Michael Perry /s/ ROBERT G. POTTER - ----------------------- Director Robert G. Potter /s/ THEODORE D. SANDS - ----------------------- Director Theodore D. Sands
EXHIBIT 99 FINANCIAL STATEMENTS Canyon Fuel Company, LLC Years Ended December 31, 2002, 2001 and 2000
Canyon Fuel Company, LLC Financial Statements Years Ended December 31, 2002, 2001 and 2000 CONTENTS
Report of Independent Auditors The Members of Canyon Fuel Company, LLC We have audited the accompanying balance sheets of Canyon Fuel Company, LLC (a Delaware limited liability company) (the Company) as of December 31, 2002 and 2001, and the related statements of operations, members' equity and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Canyon Fuel Company, LLC at December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States. /s/ ERNST & YOUNG LLP St. Louis, Missouri January 22, 2003 1
Canyon Fuel Company, LLC Statements of Operations (In Thousands)
Canyon Fuel Company, LLC Balance Sheets (In Thousands)
Canyon Fuel Company, LLC Statements of Members' Equity (In Thousands) Years Ended December 31, 2002, 2001 and 2000
Canyon Fuel Company, LLC Statements of Cash Flows (In Thousands)
Canyon Fuel Company, LLC Notes to Financial Statements December 31, 2002 1. THE COMPANY Canyon Fuel Company, LLC (the Company) is a joint venture between Arch Western Resources, LLC (Arch Western) (65% ownership) and ITOCHU Coal International Inc. (ITOCHU) (35% ownership). The owners of the Company are referred to herein as the "Members." The Company owns an approximate 9% interest in Los Angeles Export Terminal, Inc. (LAXT). The Company operates one reportable segment: the production of steam coal from deep mines in Utah for sale primarily to utility companies in the United States. Net profits and losses and distributions of the Company's earnings are allocated to the Members based on their respective ownership percentage. 2. ACCOUNTING POLICIES ACCOUNTING ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. CASH AND CASH EQUIVALENTS Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with an original maturity of three months or less when purchased. 6
2. ACCOUNTING POLICIES (CONTINUED) INVENTORIES Inventories consist of the following:
2. ACCOUNTING POLICIES (CONTINUED) COAL SUPPLY AGREEMENTS Acquisition costs related to coal supply agreements are capitalized and amortized on the basis of coal to be shipped over the term of the contract. Value is allocated to coal supply agreements based on discounted cash flows attributable to the difference between the above-market contract price and the then-prevailing market price. Accumulated amortization for sales contracts was $25.2 million and $91.9 million at December 31, 2002 and 2001, respectively. In 2002, the Company wrote off $70.8 million of sales contract assets and accumulated amortization related to an expired contract that was fully amortized. EXPLORATION COSTS Costs related to locating coal deposits and determining the economic minability of such deposits are expensed as incurred. PROPERTY, PLANT AND EQUIPMENT Additions to property, plant and equipment are recorded at cost. Maintenance and repair costs are expensed as incurred. Mine development costs are capitalized and amortized on the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited. Proceeds from the sale of coal mined as a by-product of development activities are not included in coal sales but are accounted for as a reduction of the amount capitalized. Depletion of mineral properties is computed on the units-of-production method over the estimated recoverable coal reserves of the property being mined. At December 31, 2002, all mineral reserves of the Company that are capitalized are being amortized on the units-of-production method through Company operations. Depreciation and amortization of other property, plant and equipment are computed by the straight-line method over the expected lives of the assets, which range from 3 to 19 years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. Upon disposal of depreciated assets, residual cost less salvage value is included in the determination of current income. 8
2. ACCOUNTING POLICIES (CONTINUED) ASSET IMPAIRMENT If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value. As described in Note 3, the Company wrote off the value of its investment in LAXT during 2001. RECLAMATION AND MINE CLOSING COSTS The Company charges current reclamation costs to expense as incurred. Final reclamation costs, including dismantling and restoration, are estimated based upon current federal and state regulatory requirements and are accrued during operations using the units-of-production method on the basis of estimated costs as of the balance sheet date. The effect of changes in estimated costs and production is recognized on a prospective basis. The Company is not aware of any events of noncompliance with environmental laws and regulations. The exact nature of environmental issues and costs, if any, which the Company may encounter in the future cannot be predicted, primarily because of the changing character of environmental requirements that may be enacted by governmental agencies. As discussed in Note 10, in 2003, the Company will begin accounting for its final mine closure reclamation liabilities in accordance with FAS 143, Accounting for Asset Retirement Obligations. ACCRUED WORKERS' COMPENSATION COSTS The Company is liable under the federal Mine Safety and Health Act of 1977, as amended, to provide for pneumoconiosis (black lung) benefits to eligible employees, former employees and dependents with respect to claims filed by such persons on or after July 1, 1973. The Company is also liable under state statutes for black lung benefits. The Company currently provides for federal and state claims principally through a self-insurance program. Charges are being made to operations as determined by independent actuaries, at the present value of the actuarially computed present and future liabilities for such benefits over the employees' applicable years of service. In addition, the Company is liable for traumatic injuries which are accrued as injuries are incurred. 9
2. ACCOUNTING POLICIES (CONTINUED) REVENUE RECOGNITION Coal sales revenues include sales to customers of coal produced at Company operations (except for coal that is produced as the by-product of development activities) and coal purchased from other companies. The Company recognizes revenue from coal sales at the time title passes to the customer. Transportation costs that are billed by the Company and reimbursed to the transportation provider are included in coal sales and cost of coal sales. Revenues from sources other than coal sales, including gains and losses from dispositions of long-term assets, are included in other revenues and are recognized as performed or otherwise earned. INCOME TAXES The financial statements do not include a provision for income taxes, as the Company is treated as a partnership for income tax purposes and does not incur federal or state income taxes. Instead, its earnings and losses are included in the Members' separate income tax returns. COMPREHENSIVE INCOME The Company reports comprehensive income in its statements of members' equity. Comprehensive income represents changes in Members' equity from non-owner sources. For the years ended December 31, 2002 and 2001, minimum pension liability adjustments were the only item of other comprehensive income.
2. ACCOUNTING POLICIES (CONTINUED) DERIVATIVE INSTRUMENTS Statement of Financial Accounting Standards (FAS) 133, Accounting for Derivative Instruments and Hedging Activity, was effective on January 1, 2001. FAS 133 requires all derivative financial instruments to be reported on the balance sheet at fair value. Changes in fair value are recognized either in earnings or equity, depending on the nature of the underlying exposure being hedged and how effective the derivative is at offsetting price movements in the underlying exposure. As required, the Company adopted FAS 133 on January 1, 2001. The Company did not have any financial instruments which qualified as derivatives under FAS 133, and therefore, there was no impact to the Company as a result of the adoption of FAS 133. 3. NON-RECURRING INCOME AND EXPENSES During 2002, the Company was notified by the Bureau of Land Management that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined from September 1, 2001 through September 1, 2006. The retroactive portion of the refund totaled $1.7 million and has been recognized in 2002 as a reduction in cost of coal sales in the statement of operations. The Company owns an approximate 9% interest in LAXT which the Company has included in property, plant and equipment. LAXT began operations in 1997 and has experienced operating losses and negative cash flows since its inception, principally due to weak demand for U.S. coal exports to the Pacific Rim countries. During 2001, due to continuing weakness in the export coal market, LAXT's financial condition was not going to allow it to make its Minimum Annual Guarantee Rental Payment owed to the Port of Los Angeles, and several significant owners of LAXT indicated an unwillingness to provide additional funding to LAXT. The Company believed these events represented indicators of impairment under the provisions of FAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. Based on this, the Company determined that assets with a carrying value of $10.1 million did not have any future value to the Company and therefore were written off. In addition, the Company had a $2.3 million note receivable from LAXT which it no longer expected to realize and wrote off during 2001. 11
3. NON-RECURRING INCOME AND EXPENSES (CONTINUED) During 2001, the Company received notification that contested property tax valuations from 1998 and 1999 were settled in the Company's favor. The Company recognized $4.5 million of income in 2001, which is the amount refunded by the state of Utah to the Company. In addition, the Internal Revenue Service issued a notice during 2000 outlining the procedures for obtaining tax refunds on certain excise taxes paid by the industry on export sales tonnage. The notice is a result of a 1998 Federal District Court decision that found such taxes to be unconstitutional. As a result of processing these claims during 2001, the Company recorded $2.2 million of income related to these excise tax recoveries. 4. ACCRUED EXPENSES Accrued expenses included in current liabilities consist of the following:
5. EMPLOYEE BENEFIT PLANS DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS Essentially all of the Company's employees are covered by a defined benefit pension plan sponsored by the Company. The benefits are based on years of service and the employee's compensation, primarily during the last five years of service. The funding policy for the pension plan is to make annual contributions as required by applicable regulations. The Company also provides certain postretirement medical and life insurance benefits to substantially all employees who retire with the Company. The Company has the right to modify the plans at any time. The Company's current policy is to fund the cost of postretirement medical and life insurance benefits as they are paid. 13
5. EMPLOYEE BENEFIT PLANS (CONTINUED) Summaries of the changes in the benefit obligation and plan assets (primarily listed stocks and debt securities) and of the funded status of the plans follow:
5. EMPLOYEE BENEFIT PLANS (CONTINUED) Demographic and assumption changes under the defined benefit pension plan resulted in a $350,000 gain in 2002 and a $1,270,000 loss in 2001. The decrease in the funded status of pension benefits in the year 2002 resulted from decreased earnings on plan assets during the year. FAS 87, Employers' Accounting for Pensions, contains a minimum liability provision that requires, in some situations, that an employer recognize an "additional minimum liability" in the balance sheet without a corresponding charge to earnings. To the extent an additional minimum liability is required, a corresponding reduction in equity may also be recognized. Demographic and assumption changes in other postretirement benefits resulted in the $575,000 loss in 2002 and $635,000 gain in 2001.
5. EMPLOYEE BENEFIT PLANS (CONTINUED) The health care cost trend rate assumption has a significant effect on the amounts reported. However, as the employer contribution cap was reached, the impact of health care cost trend rate changes is not material. OTHER PLANS The Company sponsors a 401(k) savings plan which was established to assist eligible employees in providing for their future retirement needs. The savings plan matches a certain percentage of employee contributions. The Company's contribution to the savings plan was $1.6 million in 2002 and $1.4 million in 2001. 6. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS The Company places its cash equivalents in investment-grade short-term investments and limits the amount of credit exposure to any one commercial issuer. The Company markets its coal principally to electric utilities in the United States. Generally, credit is extended based on an evaluation of the customer's financial condition, and collateral is not generally required. Credit losses are provided for in the financial statements and historically have been minimal. The Company is committed under long-term contracts to supply coal that meets certain quality requirements at specified prices. These prices are generally adjusted based on indices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer. Intermountain Power Agency accounted for approximately 29%, 36% and 44% of coal sales in 2002, 2001 and 2000, respectively. This same customer accounted for 20% and 31% of accounts receivable at December 31, 2002 and 2001, respectively. Sierra Pacific accounted for approximately 24%, 20% and 17% of coal sales in 2002, 2001 and 2000, respectively. Pacificorp accounted for approximately 15% and 8% of coal sales in 2002 and 2001, respectively. Approximately 7%, 13% and 14% of coal sales in 2002, 2001 and 2000, respectively, were export sales to Japanese customers. 16
7. RELATED PARTY TRANSACTIONS As described in Note 1, 65% of the Company is owned by Arch Western. Arch Western acts as the Company's managing Member. The Company pays administration and production fees to Arch Western for managing the Company's operations. In addition, the Company pays certain additional management fees to ITOCHU, its 35% owner. These fees to Members were $10.3 million, $8.9 million and $8.0 million in 2002, 2001 and 2000, respectively. The Company has a payable balance to its Members of $6.4 million and $2.8 million at December 31, 2002 and 2001, respectively. 8. COMMITMENTS AND CONTINGENCIES In October 2002, the Company entered into a long-term operating lease for longwall equipment to be used at its Dugout mine. The lease contains options that would allow the Company to purchase the longwall at amounts approximating fair market value. Assuming the Company does not exercise these options, the lease will terminate on October 1, 2009. Rental expense was $1.5 million in 2002, and $0.6 million in 2001 and 2000, respectively. The Company has entered into various noncancelable royalty lease agreements and federal lease bonus payments under which future minimum payments are due. In May 2001, the Company was the successful bidder in a state auction of certain mining rights in the 2,560-acre Dugout tract in Carbon County, Utah. The Company's lease bid amounted to $1.0 million for the tract, of which $100 thousand was paid in each of the years 2002 and 2001, respectively. The Company will make payments of $100 thousand in each of the years 2003 and 2004 and $120 thousand in each of the years 2005 through 2009. The tract contains approximately 6 million tons of demonstrated coal reserves and is contiguous to the Company's Dugout mine. In May 1999, the Company was the successful bidder in a federal auction of certain mining rights in the 7,172-acre Pines tract in Sevier and Emory Counties in Utah. The Company's lease bonus bid amounted to $16.9 million for the tract, of which $3.4 million was paid on May 24, 1999 and an additional $3.4 million was paid in each of the years 2002, 2001 and 2000, respectively. The tract contains approximately 48 million tons of demonstrated coal reserves and is contiguous with the Company's Sufco mine. Geological surveys indicate that there are sufficient reserves relative to these properties to permit recovery of the Company's investment. Minimum payments due in future years under lease agreements (including the Dugout and Pines tract leases) are $6.8 million in 2003, $3.4 million in 2004, $3.0 million in 2005, $2.9 million in 2006, $3.1 million in 2007 and $9.2 million thereafter. 17
8. COMMITMENTS AND CONTINGENCIES (CONTINUED) The Company was in litigation with Skyline Partners, lessors of the coal reserves which comprise the Company's Skyline mine. The coal leases required the Company to make annual advance minimum royalty payments which are fully recoupable against a production royalty that is to be paid by the Company on each ton of coal mined and sold from the leaseholds. In 1997, the Company filed suit against Skyline Partners in Utah State Court alleging that the Company was not required to make the final minimum advance royalty payment. On February 24, 2000, the Company and Skyline Partners reached an agreement to settle the litigation. The settlement includes a $7.2 million recoupable payment by the Company to Skyline Partners which was recorded as a prepaid royalty in 2000 and a grant of an overriding royalty interest to Skyline Partners covering land adjacent to the Skyline mine reserves. The Company is also the subject of or party to a number of other pending or threatened legal actions. On the basis of management's best assessment of the likely outcome of these actions, expenses or judgments arising from any of these suits are not expected to have a material adverse effect on the Company's operations, financial position or cash flows. 9. CASH FLOW The changes in operating assets and liabilities as shown in the statements of cash flows are comprised of the following:
10. ACCOUNTING DEVELOPMENT Effective January 1, 2003, the Company adopted FAS 143. FAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of the new rules will result in a cumulative effect of adoption that will decrease net income and members' equity by approximately $1 million to $4 million. 19
EXHIBIT 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Arch Coal, Inc. (the "Company") on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, Steven F. Leer, Chief Executive Officer of the Company, certify as, pursuant to 18 U.S.C. sec. 1350, as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ STEVEN F. LEER -------------------------------------- Steven F. Leer Chief Executive Officer March 13, 2003
EXHIBIT 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Arch Coal, Inc. (the "Company") on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, Robert J. Messey, Chief Financial Officer of the Company, certify as, pursuant to 18 U.S.C. sec. 1350, as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ ROBERT J. MESSEY -------------------------------------- Robert J. Messey Chief Financial Officer March 13, 2003