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, 2003, the Company had 25 operating mines and controlled approximately 2.8 billion tons of proven and probable coal reserves. Arch Coal sold 100.6 million tons of coal in 2003. 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 2003. 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.
Electricity Generation. Coal has consistently maintained a 49% to 53% market share over competing energy sources to generate electricity during the past ten years because of its relatively low cost and its availability throughout the United States. Coal is the lowest cost fossil-fuel used for base-load electric power generation - considerably less expensive than natural gas or oil. Coal-fired generation is also competitive with nuclear power generation, especially on an all-in cost per megawatt-hour basis. Hydroelectric power is inexpensive but is limited by both geography and susceptibility to seasonal and climatic conditions. Non hydropower renewable power generation accounts for only 1.9% of all the electricity generated in the U.S. and is limited by resources and/or technology. Consequently, approximately 87.6% of the coal produced in the United States in 2003 was sold in the domestic market as a fuel to the electric generation segment. The remainder of the tons were sold in 2003 as steam coal for industrial and residential purposes, into the export market, and as metallurgical coal. In addition to the relative competitiveness of coal-fired generation plants, coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting coal production and power generation, technological developments and the location, availability and quality of competing sources of coal, as well as 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 2001 through 2025 as compiled, preliminary(p) or forecasted(f) by the Energy Information Agency.
Coal’s primary advantage is its relatively low cost compared to other fuels used to generate electricity. The following table sets forth the Energy Information Agency’s forecast of delivered fuel prices to electric utilities through 2025 as compiled, preliminary(p) or forecasted(f) by the Energy Information Agency. The table below is derived from the Energy Information Agency’s long-term forecast published in December 2003 and is presented in 2002 dollars.
Coal Production. United States coal production was 1.1 billion tons in 2003. The following table, derived from data prepared by the Energy Information Agency, sets forth principal United States production statistics for the periods indicated as compiled or preliminary(p).
Sales and Marketing
The Company sells coal both under long-term contracts, the terms of which are greater than 12 months, and on a current market or spot basis. When the Company’s coal sales contracts expire or are terminated, it is exposed to the risk of having to sell coal into the spot market, where demand is variable and prices are subject to greater volatility. Historically, the price of coal sold under long-term contracts has exceeded prevailing spot prices for coal. However, in the past several years new contracts have been priced at or near existing spot rates.
The terms of the Company’s coal sales contracts result from bidding and extensive negotiations with customers. Consequently, the terms of these contracts typically vary significantly in many respects, including price adjustment features, provisions permitting renegotiation or modification of coal sale prices, coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, and force majeure, suspension, termination and assignment provisions.
Provisions permitting renegotiation or modification of coal sale prices are present in many of the Company’s more recently negotiated long-term contracts and usually occur midway through a contract or every two to three years, depending upon the length of the contract. In some circumstances, customers have the option to terminate the contract if prices have increased by a specified percentage from the price at the commencement of the contract or if the parties cannot agree on a new price. The term of sales contracts has decreased significantly over the last two decades as competition in the coal industry has increased and, more recently, as electricity generators have prepared themselves for federal Clean Air Act requirements and the impending deregulation of their industry.
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.
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.
Operations
As of December 31, 2003, the Company operated a total of 30 mines, all located in the United States. The Company uses four distinct extraction techniques: continuous mining, longwall mining, truck-and-shovel mining and dragline mining. 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 maps show the locations of the Company’s significant mining operations:
Eastern Operations
Western Operations
The following table provides the location and a summary of information regarding the Company’s principal mining complexes and the total sales associated with these operations for the prior three years:
S
=
Surface Mine
D
=
Dragline
UP
=
Union Pacific Railroad
U
=
Underground Mine
L
=
Loader/ Truck
CSX
=
CSX Transportation
S
=
Shovel/ Truck
BN
=
Burlington Northern Railroad
LW
=
Longwall
NS
=
Norfolk Southern Railroad
C
=
Continuous Miner
HW
=
Highwall Miner
(1)
Amounts in parenthesis indicate the number of captive and contract mines at the mining complex or location. Captive mines are mines which the Company owns and operates on land owned or leased by it. Contract mines are mines which other operators mine for the Company under contracts on land owned or leased by the Company.
(2)
Reported for captive operations only.
(3)
The Company idled its mining operations at the Dal-Tex complex on July 23, 1999 due to a delay in obtaining mining permits resulting from legal action in the U.S. District Court for the Southern District of West Virginia.
(4)
Utilizes an 83-cubic-yard dragline and a 51-cubic-yard shovel. A dragline is a large machine used in the surface mining process to remove layers of earth and rock covering coal.
(5)
Utilizes a 53-cubic-yard dragline, a 43-cubic-yard shovel, a 22-cubic-yard shovel and a 28-cubic-yard loader at the Ruffner mine.
(6)
Utilizes a 105-cubic-yard dragline, two 53-cubic-yard shovels and three 28-cubic-yard loaders.
(7)
Utilizes 164-cubic-yard, 130-cubic-yard, 78-cubic-yard and 45-cubic-yard draglines and 53-cubic-yard, 60-cubic-yard and 82-cubic-yard shovels.
(8)
The Company idled its mining operations at Coal Creek during the third quarter of 2000 because of unfavorable conditions existing in the market environment.
(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. The Skyline mine is scheduled to be idled by June 30, 2004.
(10)
Utilizes 76-cubic-yard dragline at Medicine Bow and a 32-cubic-yard dragline at Seminoe II. These mines will be put into reclamation mode in 2004.
Mingo Logan. The Mingo Logan mine is an underground operation located in Mingo County and Logan County, West Virginia on approximately 11,900 acres. Six continuous miners support a longwall. The mined coal is processed through a preparation plant at the mine. The loadout facility at Mingo Logan is serviced by Norfolk Southern Railroad.
Coal-Mac. The Coal-Mac mine is located in Mingo County and Logan County, West Virginia on approximately 4,600 acres. The equipment at the mine consists of six wheel-loader spreads, 2 loadout facilities, and a preparation plant. Coal-Mac’s loadout facilities are serviced by Norfolk Southern Railroad and CSX Transportation. Coal also is transported by barge from Coal-Mac.
Hobet 21. The Hobet 21 mine is located in Boone County and Lincoln County, West Virginia on approximately 13,000 acres. Equipment at Hobet 21 includes a dragline, electric shovel, wheel-loader spread and two continuous miner units. The coal at Hobet 21 is processed at an on-site preparation plant and transported from Hobet 21’s loadout facility, which is serviced by CSX Transportation.
Arch of West Virginia. The Arch of West Virginia mine is located primarily in Logan County, West Virginia on approximately 9,900 acres. A dragline, two shovels and a loader are present. The loadout facility at the mine is serviced by CSX Transportation.
Samples. The Samples mine is located primarily in Kanawha County, West Virginia on approximately 8,100 acres. Equipment at Samples includes a dragline, two shovels and three loaders. Coal from Samples is transported by rail to a loadout facility approximately 1.4 miles from the mine. CSX Transportation services this loadout. Coal also is transported by barge from this loadout.
Lone Mountain. The Lone Mountain mine is located in Harlan County, Kentucky and Lee County, Virginia on approximately 14,500 acres. Continuous miner units and continuous hauler units are present at Lone Mountain. The loadout facility at Lone Mountain is serviced by Norfolk Southern Railroad and CSX Transportation.
Black Thunder. The Black Thunder mine is located in Campbell County, Wyoming on approximately 14,711 acres. Mining the approximately 68-foot coal seam are four draglines and seven shovels. There is no washing plant at Black Thunder. The coal is crushed through either the near pit crushing and conveying system or the primary system. Coal from these two crushing facilities is conveyed into one of two silos or a slot storage facility. Coal is shipped through two loadouts on trains operated by Burlington Northern and Union Pacific.
Coal Creek. The Coal Creek mine is located in Campbell County, Wyoming on approximately 6,720 acres. Coal Creek has been idle since July 2000. The equipment at the mine consists of one shovel, ten trucks and a loadout facility. The Coal Creek mine is located on a joint rail line operated by Burlington Northern and Union Pacific.
West Elk. The West Elk mine is an underground operation located in Gunnison County, Colorado on approximately 14,700 acres. The coal is mined by two continuous miners in support of a longwall. The loadout facility at the mine is serviced by the Union Pacific Railroad.
Skyline. Canyon Fuel’s Skyline mine is an underground longwall mine located in Carbon County and Emery County, Utah on approximately 11,300 acres. Three continuous miners support a longwall. The coal produced from the mine is crushed and loaded into trains at the mine. The loadout facility at Skyline is serviced by the Union Pacific Railroad. The Skyline mine is scheduled to be idled by June 30, 2004 because current market prices do not support expansion into an additional reserve base at the mine.
SUFCO. Canyon Fuel’s SUFCO mine, an underground longwall mine, is located in Sevier County, Juab County and Emery County, Utah on approximately 23,900 acres. Two continuous miners support the longwall. All of the coal produced from the mine is crushed at a facility located at the mine and trucked either directly to customers or to a train loadout located approximately 80 miles from the mine. The Union Pacific Railroad serves this loadout.
Dugout Canyon. Canyon Fuel’s Dugout Canyon mine is an underground longwall mine located in Carbon, County, Utah on approximately 13,700 acres. Two continuous miners support the longwall operation. The coal produced is crushed at the mine and trucked to a third party loadout served by the Union Pacific Railroad.
Transportation
Coal from the mines of the Company’s subsidiaries is transported by rail, truck and barge to domestic customers and to Atlantic 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 2003 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, which is equivalent to .72% sulfur per pound of 12,000 Btu coal. 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 Miner. A machine used in underground mining to cut coal from the seam and load it into conveyors or into shuttle cars in a continuous operation.
Continuous Mining. One of two major underground mining methods now used in the United States (also see “Longwall Mining”). This process utilizes a continuous miner. 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.
Dragline Mining. A method of mining where large capacity draglines remove overburden to expose the coal seams.
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.
Reserves. That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
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.
Truck-and-Shovel Mining. An open-cast method of mining that uses large shovels to remove overburden, which is used to backfill pits after coal removal.
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, 2004, the Company employed a total of approximately 3650 persons, approximately 550 of whom were represented by the UMWA under a collective bargaining agreement that expires in 2006 and approximately 125 of whom are represented by the Scotia Employees Association.
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, 46, 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. From January 1995 to February 1999, Mr. Allbritten served as Human Resources Manager for Atlantic Richfield Company.
C. Henry Besten, Jr., 55, 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 December 1999 to November 2000.
John W. Eaves, 46, 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. Mr. Eaves serves on the board of directors of ADA-ES, Inc.
Sheila B. Feldman, 49, is Vice President - Human Resources of the Company and has served in such capacity since February 2003. From 1997 to February 2003, Ms. Feldman was the Vice President - Human Resources and Public Affairs of Solutia Inc.
Robert G. Jones, 47, 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, 51, is President and Chief Executive Officer and a Director of the Company and has served in such capacity since 1992.
Robert J. Messey, 58, is Senior Vice President and Chief Financial Officer of the Company and has served in such capacity since December 2000. Prior to joining Arch Coal, Mr. Messey served as vice president of financial services of Jacobs Engineering Group Inc. from January 1999 and, prior to that, served as senior vice president and chief financial officer of Sverdrup Corporation from 1992. Mr. Messey serves on the board of directors of Baldor Electric Company.
David B. Peugh, 49, is Vice President - Business Development of the Company and has served in such capacity since 1993. Mr. Peugh is a Director of Natural Resource Partners, L.P.
Kenneth G. Woodring, 54, is Executive Vice President - Mining Operations of the Company and has served in such capacity since July 1997.
ITEM 2.
ITEM 2. PROPERTIES
The Company estimates that it owned or controlled, as of December 31, 2003, approximately [2.8] 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 in reserve holdings and other factors. The following tables present the Company’s estimated assigned and unassigned recoverable coal reserves at December 31, 2003:
Total Assigned Reserves
(tonnage in millions)
Total Unassigned Reserves
(tonnage in millions)
(1)
As received Btu per lb. includes the weight of moisture in the coal on an as sold basis.
(2)
Represents 100% of the reserves held by Canyon Fuel, in which the Company has a 65% interest.
Over 98% of the Company’s recoverable reserves consists of steam coal, which is coal used in steam boilers to make electricity. Less than 2% of the Company’s recoverable reserves consists of metallurgical coal, which is a grade of coal used in the production of steel. Metallurgical coal represents an immaterial amount of the Company’s operations.
As of December 31, 2003, approximately 86,688 acres (which includes 100% of the acreage held by Canyon Fuel) out of the Company’s total of approximately 627,482 acres of coal land was leased from the federal government. These leases have terms expiring between 2004 and 2024, subject to readjustment or extension and to earlier termination for failure to meet diligent development requirements. The Company has entered into leases covering substantially all of its leased reserves which are not scheduled to expire prior to expiration of projected mining activities. Royalties are paid to lessors either as a fixed-price per-ton or as a percentage of the gross sales price of the mined coal. Under current mining plans, all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewals.
The Company pays percentage-based royalties under the majority of its significant leases. The terms of most of these leases extend until the exhaustion of mineable and merchantable coal. The remaining leases have initial terms ranging from one to 40 years from the date of their execution, with most containing options to renew. In some cases, a lease bonus,
or prepaid royalty, is required, payable either at the time of execution of the lease or in annual installments. In most cases, the prepaid royalty amount is applied to reduce future production royalties.
The Pine Creek, Black Bear, Campbells Creek, Samples, Ruffner and Holden 25/Ragland preparation plants and related loadout facilities are located on properties held under leases which expire at varying dates over the next thirty years with either optional 20-year extensions or with unlimited extensions, and the balance of the Company’s preparation plants and loadout facilities are located on property owned by the Company.
All of the identified coal reserves held by the Company’s subsidiaries have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 68% consist of compliance coal while an additional 21% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Some of the Company’s low-sulfur coal can be marketed as compliance coal when blended with other compliance coal. Accordingly, most of the Company’s reserves are primarily suitable for the domestic steam coal markets. However, a substantial portion of the low-sulfur and compliance coal reserves at the Mingo Logan operations may also be used as a high-volatile, low-sulfur, metallurgical coal.
Title to coal properties held by lessors or grantors to the Company and its subsidiaries and the boundaries of properties are normally verified at the time of leasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completely verified until such time as the Company’s independent operating subsidiaries prepare to mine such reserves. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine such reserves could be adversely affected.
From time to time, lessors or sublessors of land leased by the Company’s subsidiaries have sought to terminate such leases on the basis that such subsidiaries have failed to comply with the financial terms of the leases or that the mining and related operations conducted by such subsidiaries are not authorized by the leases. Some of these allegations relate to leases upon which the Company conducts operations material to the Company’s consolidated financial position, results of operations and liquidity, but the Company does not believe any pending claims by such lessors or sublessors have merit or will result in the termination of any material lease or sublease.
The Company leased 17,969 acres of property to other coal operators in 2003. The Company received royalty income of $11.4 million, $9.4 million and $1.7 million in 2001, 2002 and 2003, respectively, from the mining of 6.5 million tons, 6.9 million tons and 1.3 million tons, respectively, on those properties. Reserves at properties leased by the Company to other coal operators are not included in the reserve figures set forth in this Annual Report.
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. The Company has obtained, or the Company has a high probability of obtaining, all required permits or government approvals with respect to its reserves. 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 or governmental approvals with respect to its reserves.
The Company periodically engages third parties to review its reserve estimates. The most recent third party review of the Company’s reserve estimates was conducted by Weir International Mining Consultants in April 2003.
The carrying cost of the Company’s coal reserves at December 31, 2003 (which does not include the Company’s 65% share of Canyon Fuel) was $820.2 million, consisting of $75.5 million of prepaid royalties and the $744.7 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 City Place 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.
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 2003 Annual Report to Stockholders and is incorporated herein by reference.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders of the Company through the solicitation of proxies or otherwise during the fourth quarter of 2003.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required by this Item is contained in the Company’s 2003 Annual Report to Stockholders under the caption “Stockholder Information” and is incorporated herein by reference.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this Item is contained in the Company’s 2003 Annual Report to Stockholders under the caption “Selected Financial Information”, and is incorporated herein by reference.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required by this Item is contained in the Company’s 2003 Annual Report to Stockholders under the caption “Management’s Discussion and Analysis”, and is incorporated herein by reference.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this Item is contained in the Company’s 2003 Annual Report to Stockholders under the caption “Management’s Discussion and Analysis”, and is incorporated herein by reference.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Part IV, Item 14 of this Annual Report on Form 10-K for the information required by Item 8.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
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 2003 Annual Report to Stockholders.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the subcaptions “Nominees For a Three-Year Term That Will Expire in 2007”, “Directors Whose Terms Will Expire in 2006”, and “Directors Whose Terms Will Expire in 2005” 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 2004 Annual Meeting (the “2004 Proxy Statement”). See also the list of the Company’s executive officers and related information under “Executive Officers” in Part I, Item 1 herein.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing in the “Summary Compensation Table”, the 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 2004 Proxy Statement. No portion of the Personnel and Compensation Committee Report on Executive Compensation for 2003 or the Arch Coal Performance Graph is incorporated herein in reliance on Regulation S-K, Item 402(a)(8).
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption “Ownership of Arch Coal Common Stock” in the 2004 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption “Related Party Transactions” in the 2004 Proxy Statement.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANTS FEES AND SERVICES
There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption “Audit Committee Report” in the 2004 Proxy Statement.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
*
Exhibits 10.24, 10.25, 10.26, 10.27 and 10.29 are executive compensation plans.
**
Upon written or oral request to the Company’s Secretary, a copy of any of the above exhibits will be furnished at cost.
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 5, 2004
ORIGINAL POWERS OF ATTORNEY AUTHORIZING STEVEN F. LEER AND ROBERT G. JONES, AND EACH OF THEM, TO SIGN THIS ANNUAL REPORT ON FORM 10-K AND AMENDMENTS THERETO ON BEHALF OF THE ABOVE-NAMED PERSONS HAVE BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION AS EXHIBIT 24 TO THIS REPORT.
SCHEDULE II
ARCH COAL, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
(1)
Reserves utilized, unless otherwise indicated.
(2)
Amount represents state net operating loss carryforwards identified in 2003 which were fully reserved.
(3)
Amount includes $1.6 million that was recognized as income upon collection of the related receivable.