Filed Pursuant to Rule 424(b)(1) Registration No. 333-45198 PROSPECTUS 8,700,000 Shares Arch Coal, Inc. Common Stock --------------- We are selling 3,943,032 shares and an Arch Coal, Inc. stockholder is selling 4,756,968 shares. We are registering the selling stockholder's shares on its behalf. Our common stock trades on the New York Stock Exchange under the symbol "ACI". On February 15, 2001, the last sale price of the shares as reported on the New York Stock Exchange was $19.26 per share. Investing in our common stock involves risks that are described in the "Risk Factors" section beginning on page 6 of this prospectus. --------------- Per Share Total --------- ----- Public offering price............................. $19.00 $165,300,000 Underwriting discount............................. $.97 $8,439,000 Proceeds, before expenses, to Arch Coal........... $18.03 $71,092,867 Proceeds, before expenses, to the selling stockholder...................................... $18.03 $85,768,133 The underwriter may also purchase up to an additional 1,227,765 shares from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments. Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. The shares will be ready for delivery on or about February 22, 2001. --------------- Merrill Lynch & Co. --------------- The date of this prospectus is February 15, 2001.
TABLE OF CONTENTS Page ---- Prospectus Summary....................................................... 1 Risk Factors............................................................. 6 Forward-Looking Statements............................................... 13 Use of Proceeds.......................................................... 14 Price Range of Common Stock and Dividends................................ 14 Capitalization........................................................... 15 Selected Consolidated Financial and Operating Data....................... 16 Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................... 18 Business................................................................. 30 The Coal Industry........................................................ 39 Management............................................................... 46 Selling Stockholder...................................................... 49 Description of Capital Stock............................................. 50 United States Taxation of Non-U.S. Holders............................... 52 Underwriting............................................................. 56 Legal Matters............................................................ 59 Experts.................................................................. 59 Where You Can Find More Information...................................... 59 Glossary of Selected Mining Terms........................................ 61 --------------- You should rely only on the information contained or incorporated by reference in this prospectus and in the registration statement filed in connection with this offering and the exhibits to that registration statement. We have not, and the selling stockholder and the underwriter have not, authorized any other person to provide you with different information. We are not, and the selling stockholder and the underwriter are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. i
PROSPECTUS SUMMARY This summary may not contain all the information that may be important to you. You should read the entire prospectus, including the information set forth in "Risk Factors," and all the information incorporated by reference, before making an investment decision. Some of the terms used in this prospectus relating to the coal industry are defined in a glossary beginning on page 61 of this prospectus. Arch Coal We are one of the largest coal producers in the United States. We mine, process and market compliance and low-sulfur coal from mines located in both the eastern and western United States, enabling us to ship coal cost- effectively to most of the major domestic coal-fired electric generation facilities. Compliance coal and low-sulfur coal are coals which, when burned, emit 1.2 pounds or less and 1.6 pounds or less of sulfur dioxide per million Btus, respectively. 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. As of December 31, 1999, we controlled approximately 3.5 billion tons of measured and indicated recoverable coal reserves, approximately 2.0 billion tons of which were assigned reserves and approximately 1.5 billion tons of which were unassigned reserves. Assigned reserves are recoverable coal reserves that have been designated to be mined by a specific operation. As of September 30, 2000, we had 28 operating mines. We sold 111.2 million tons of coal in 1999 and 79.4 million tons of coal during the nine months ended September 30, 2000. We sell substantially all of our coal to producers of electric power. We have a substantial amount of debt relative to our equity capitalization. Our mining operations and coal reserves are inherently subject to changing conditions that can result in fluctuations in our profitability. We sell a significant amount of coal under long-term contracts, which are contracts with a term of greater than 12 months, at above current market prices, the expiration or renegotiation of which could adversely affect our profitability. While coal prices have recently strengthened in all regions, our recent results of operations reflected less favorable coal prices because nearly all of our production was previously committed and priced under earlier weak market conditions. Environmental and regulatory developments have forced us to close a large surface mine in West Virginia. In 1999, we wrote down the value of a portion of our assets in the eastern United States, restructured our operations, and recorded several substantial charges. We believe, however, that we are well-positioned to take advantage of several trends that are positively affecting the coal industry: . Demand for electricity continues to grow, and coal-fired electric generation facilities currently provide more than 50% of the electric power produced in the United States. . Coal continues to be the least expensive fuel commonly used in the generation of electricity. Utility deregulation trends are expected to result in increased price competition among generators of electricity, for which the importance of production costs should increase correspondingly. . Coal-fired electric generation plants operated at an average of 68% of their capacity in 1999. These plants are capable of meeting the demand for more electricity at a low incremental cost. . The federal Clean Air Act, which provides for phased-in restrictions on the amount of sulfur dioxide that electric generation and other facilities can emit, has caused demand for low-sulfur coal to increase in recent years. Approximately 90% of our reserve base consists of low-sulfur coal, and two-thirds is compliance quality. We currently produce only compliance and low-sulfur coals. . Demand for coal from the Southern Powder River Basin in Wyoming, which is low in sulfur content and relatively inexpensive to mine, has approximately doubled over the last decade. We control approximately 1.4 billion tons of recoverable coal reserves in the Powder River Basin. Our Black Thunder mine is one of the largest coal mines in the nation, producing at a rate of approximately 60 million tons annually. 1
We continue to focus on realizing the potential of our assets and maximizing stockholder value by making decisions based upon our five chief financial objectives: . aggressively paying down our debt, . further strengthening our cash generation, . improving our earnings, . increasing our productivity, and . reducing our costs. Our principal executive office is located at CityPlace One, Suite 300, St. Louis, Missouri 63141, and our telephone number is (314) 994-2700. 2
The Offering Common stock offered: By Arch Coal................................... 3,943,032 By Ashland Inc., the sole selling stockholder.. 4,756,968 ---------- Total...................................... 8,700,000 Shares outstanding after the offering............. 42,116,219 shares ---------- Use of Proceeds................................... We estimate that our net proceeds from this offering without exercise of the over-allotment option will be approximately $70.7 million. We intend to use the net proceeds of this offering to reduce our indebtedness. We will not receive any of the proceeds from the sale of shares by the selling stockholder. New York Stock Exchange Symbol.................... ACI Unless otherwise indicated, the information in this prospectus assumes no exercise by the underwriter of its over-allotment option. The number of shares outstanding immediately after the offering is based upon the number of shares outstanding as of December 31, 2000, and excludes 6,000,000 shares reserved for issuance under our existing stock incentive plans, including 1,594,340 shares issuable upon exercise of options outstanding as of that date at a weighted average exercise price of $19.11 per share. See "Risk Factors" and the other information included or incorporated by reference in this prospectus for a discussion of factors you should carefully consider before deciding to invest in our common stock. 3
Summary Consolidated Financial and Operating Data Nine Months Ended Year Ended December 31, September 30, -------------------------------- --------------------- 1997 1998 1999 1999 2000 ---------- ---------- ---------- ---------- ---------- (in thousands, except per share data) (unaudited) Consolidated Statement of Operations Data: Total revenues........ $1,066,875 $1,505,635 $1,567,382 $1,194,654 $1,057,243 Income (loss) from operations........... 41,882 87,847 (327,026) 47,325 38,715 Net income (loss)..... 30,281 30,013 (346,280) 2,072 (22,350) Basic and diluted earnings (loss) per common share......... $ 1.00 $ 0.76 $ (9.02) $ 0.05 $ (0.59) Consolidated Operating and Other Data: Tons sold............. 40,525 81,098 111,177 82,728 79,384 Tons produced......... 36,698 75,817 109,524 80,896 76,112 Adjusted EBITDA....... $ 224,646 $ 313,500 $ 325,949 $ 255,130 $ 220,480 Net cash provided from operating activities........... $ 190,263 $ 188,023 $ 279,963 $ 195,964 $ 127,257 As of September 30, 2000 ------------------------ (in thousands) (unaudited) Consolidated Balance Sheet Data: Total assets........................................... $2,260,480 Working capital........................................ (93,798) Long-term debt......................................... 1,066,216 Other long-term obligations............................ 619,389 Accumulated deficit.................................... (242,400) Stockholders' equity................................... 212,361 Adjusted EBITDA is income from operations before the effect of changes in accounting principles and extraordinary items; merger-related costs, unusual items, asset impairment and restructuring charges; net interest expense; income taxes; and depreciation, depletion and amortization of Arch Coal and its subsidiaries and its ownership percentage in its equity investments. Adjusted EBITDA should not be considered in isolation nor as an alternative to net income, operating income, cash flows from operations or as a measure of a company's profitability, liquidity or performance under U.S. generally accepted accounting principles. Information for 1997 reflects our merger with Ashland Coal, Inc. on July 1, 1997 and also reflects a $39.1 million charge in connection with the Ashland Coal merger comprised of termination benefits, relocation costs and costs associated with duplicate facilities. Information for 1998 reflects the acquisition of Atlantic Richfield Company's domestic coal operations on June 1, 1998. We refinanced our debt in connection with this acquisition, and 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. Income from operations for 1998 reflects pre- tax gains of $41.5 million from the disposition of assets, including $18.5 million on the sale of assets and idle properties in eastern Kentucky and $7.5 million on the sale of our idle Big Sandy Terminal. The loss from operations for 1999 reflects one-time pre-tax charges of $364.6 million related principally to the write-down of assets at our Dal-Tex, Hobet 21 and Coal-Mac operations and the write-down of other coal reserves in Central Appalachia, and a $23.1 million pre-tax charge related to the restructuring of our administrative workforce and the closure of mines in Illinois, Kentucky and West Virginia. We changed our 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. 4
Recent Developments On January 24, 2001, we reported our preliminary and unaudited financial and operating results for the three months and year ended December 31, 2000, a summary of which follows: Three Months Ended Year Ended December 31, 2000 December 31, 2000 ------------------- ------------------- (in thousands, except per share data) (unaudited) Consolidated Statement of Operations Data: Total revenues................ $347,378 $ 1,404,621 Income from operations........ 35,269 73,984 Net income (loss)............. 9,614 (12,736) Basic and diluted earnings (loss) per common share...... 0.25 (0.33) Consolidated Operating and Other Data: Tons sold..................... 26,135 105,519 Tons produced................. 23,947 100,060 Adjusted EBITDA............... $ 94,695 $ 315,175 Net cash provided from operating activities......... $ 8,515 $ 135,772 As of December 31, 2000 ----------------- (in thousands) (unaudited) Consolidated Balance Sheet Data: Total assets................................................ $2,232,614 Working capital............................................. (37,556) Long-term debt.............................................. 1,090,666 Other long-term obligations................................. 606,628 Accumulated deficit......................................... (234,980) Stockholders' equity........................................ 219,874 Adjusted EBITDA is income from operations before the effect of changes in accounting principles and extraordinary items; merger-related costs, unusual items, asset impairment and restructuring charges; net interest expense; income taxes; and depreciation, depletion and amortization of Arch Coal and its subsidiaries and its ownership percentage in its equity investments. Adjusted EBITDA should not be considered in isolation nor as an alternative to net income, operating income, cash flows from operations or as a measure of a company's profitability, liquidity or performance under U.S. generally accepted accounting principles. 5
RISK FACTORS Investing in our common stock will provide you with an equity ownership interest in Arch Coal. As one of our stockholders, your investment will be subject to risks, including risks inherent in our business. The value of your investment could decline and could result in a loss. You should carefully consider the following factors as well as other information contained and incorporated by reference in this prospectus before deciding to invest in our common stock. We have a substantial amount of debt relative to our equity capitalization, which limits our flexibility and imposes restrictions on us, and a downturn in economic or industry conditions may materially affect our ability to meet our future debt service and liquidity needs. As of September 30, 2000, we had outstanding consolidated indebtedness of $1.152 billion, representing approximately 84% of our capital employed. As a result, we will have significant debt service obligations, and the terms of our credit agreements limit our flexibility and impose a number of restrictions upon us. We also have significant lease and royalty obligations. Debt service consists of payments of interest and principal. We are required to make aggregate principal payments on our indebtedness of $33.6 million in 2001, $60.5 million in 2002, $1.1 billion in 2003, $0.6 million in each of 2004 and 2005 and $2.9 million, in the aggregate, thereafter. Our ability to satisfy our debt service and lease and royalty obligations, and our ability to effect any refinancing of our indebtedness, will depend upon our future operating performance, which will be affected by prevailing economic conditions in the markets that we serve and financial, business and other factors, many of which are beyond our control. We may be unable to generate sufficient cash flow from operations and future borrowings or other financing may be unavailable in an amount sufficient to enable us to fund our debt service, lease and royalty payment obligations or our other liquidity needs. Our relative amount of debt could have material consequences to our business, including, but not limited to: . making it more difficult for us to satisfy our debt covenants and debt service, lease payment and other obligations; . making it more difficult for us to pay quarterly dividends as we have in the past; . increasing our vulnerability to general adverse economic and industry conditions; . limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general corporate requirements; . reducing the availability of cash flow from operations to fund acquisitions, working capital, capital expenditures or other general corporate purposes; . limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; and . placing us at a competitive disadvantage when compared to competitors with less relative amounts of debt. A significant portion of our debt bears interest at variable rates that are linked to short-term interest rates. If interest rates rise, our costs relative to those obligations would also rise. We have recently experienced operating and net losses, which may continue or reoccur in the future. We incurred an operating loss of approximately $327.0 million and a net loss of approximately $346.3 million for the year ended December 31, 1999, and a preliminary and unaudited net loss of approximately $12.7 million for the year ended December 31, 2000. The losses in 1999 were primarily attributable to a write-down of the carrying value of some of our operating assets and coal reserves. This adjustment was partially due 6
to adverse legal and regulatory rulings related to surface mining techniques, as well as persistent negative pricing for Central Appalachian coal production. The losses were also partially attributable to a restructuring of our workforce and the closure of several mines. The loss in 2000 was primarily attributable to the temporary idling of our West Elk mine in Colorado following the detection of combustion gases in a portion of the mine. Because the coal mining industry is subject to significant regulatory oversight, and due to the continuing possibility of negative pricing or other industry trends beyond our control, we may suffer losses in the future if legal and regulatory rulings, mine idlings and closures, negative pricing trends or other factors continue to affect our ability to mine and sell coal profitably. We may be unable to comply with restrictions imposed by our credit facilities and other debt agreements, which could result in a default under these agreements, enabling lenders to declare amounts borrowed due and payable or otherwise result in unanticipated costs. The agreements governing our outstanding debt impose a number of restrictions on us. For example, the terms of our credit facilities and leases contain financial and other restrictive covenants that limit our ability to, among other things, complete acquisitions or dispositions and borrow additional funds, and require us to, among other things, maintain various financial ratios and comply with various other financial covenants. Our ability to comply with these restrictions may be affected by events beyond our control and, as a result, we may be unable to comply with these restrictions. A failure to comply with these restrictions could constitute a default under our debt agreements, and any default could lead to defaults under our other debt agreements. In the event of a default, the lenders could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts, or we might be forced to seek an amendment to our debt agreements which could make the terms of these agreements more onerous for us. For example, as of December 31, 1999, we were not in compliance with some covenants contained in our bank credit facilities as a result of a write-down of impaired assets and other restructuring costs. The credit facilities were amended in January 2000, as a result of which we made a one-time payment of $1.8 million, agreed to an interest rate increase of 0.375% on our term loan and revolving credit facility and pledged assets to collateralize our term loan and revolving credit facility, including the stock of some of our subsidiaries and some real property holdings, accounts receivable and inventory. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Credit Facilities" for a more detailed discussion of this amendment to our credit facilities. An adverse decision in pending litigation could result in the permanent closure of all or a portion of our mining operations in West Virginia, which would cause our profitability to materially decline and could cause our stock price to decline. A federal district court injunction that prohibits the West Virginia Division of Environmental Protection from issuing permits for our Dal-Tex mine to use valley fill mining techniques resulted in the shutdown of this mine in July 1999. A subsequent order prohibits the construction or expansion of valley fills in West Virginia. Valley fill, or mountaintop, mining techniques used in Central Appalachia involve the creation of large, engineered works into which excess earth and rock extracted during surface mining are placed. The plaintiffs in the litigation alleged, among other things, that the issuance of mining permits without the preparation of an environmental impact statement, or EIS, that would evaluate the environmental effects of mountaintop mining and the construction of valley fills violated environmental laws. We have appealed the order specific to our Dal-Tex operations, and we, the West Virginia Division of Environmental Protection and others have appealed the broader order concerning valley fills. Because it is not financially viable for coal producers to operate some mining properties without valley fills, if the appeals court agrees with the district court, we and other coal producers in West Virginia may be forced to close all or a portion of our mining operations in West Virginia, to the extent those operations are dependent on the use of valley fills. If we permanently close these operations in West Virginia, our profitability will decline because we will record various charges in connection with the closures. We will also experience a loss of revenues from these 7
operations. For the year ended December 31, 1998, we received approximately $100.8 million in revenues from our Dal-Tex mining operations, which constituted 6.7% of our total 1998 revenues. If the district court decision is overturned, then a settlement agreement entered into between the parties will require the preparation of an EIS prior to the issuance of permits for the construction of valley fills. The preparation of these statements is time- consuming and is sometimes the subject of litigation. As a result, even if the district court decision is overturned, we do not expect to reopen our Dal-Tex mining operation before mid-2001, at the earliest, subject to then-existing market conditions. See "Business--Legal Proceedings--Dal-Tex Litigation" for a more detailed description of the Dal-Tex litigation. New environmental regulations governing coal-fired electric generating plants could reduce the demand for coal as a fuel source and affect the volume of our sales. Several new environmental regulations require a reduction in nitrogen oxide emissions generated by coal-fired electric generating plants. Substantially all of our revenues from sales of coal in the year ended December 31, 1999 were from sales to generators operating these types of plants. Enforcement actions against a number of these generators, which include some of our customers, and proposed legislation ultimately may require additional reductions in nitrogen oxide emissions. The Environmental Protection Agency is also considering regulations that would require reductions in mercury emissions from coal-fired electric generating plants. To comply with these regulations and enforcement actions, these generators may choose to switch to other fuels that generate less of these emissions, such as natural gas or oil. In addition, coal has become less attractive as a fuel source to generators considering constructing new electric generating facilities. These developments could cause a material decrease in the volume of our sales. See "The Coal Industry--Clean Air Act" for a more detailed discussion of these regulations. Because our industry is highly regulated, our ability to conduct mining operations is restricted and our profitability may decline. Government authorities regulate the coal mining industry on matters as diverse as employee health and safety, air quality standards, water pollution, groundwater quality and availability, plant and wildlife protection, the reclamation and restoration of mining properties, the discharge of materials into the environment and surface subsidence from underground mining. In addition, federal legislation mandates benefits for various retired coal miners represented by the United Mine Workers of America. These regulations and legislation have had, and will continue to have, a significant effect on our costs of production and competitive position. Future regulations, legislation or orders may also cause our sales or profitability to decline by hindering our ability to continue our mining operations or by increasing our costs. Mining companies must obtain numerous permits that strictly regulate environmental and health and safety matters in connection with coal mining. Regulatory authorities exercise considerable discretion in the timing of permit issuance. Also, private individuals and the public at large possess rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. As described above, we shut down our Dal-Tex mining operation in West Virginia in July 1999 as a result of legal action preventing the issuance of permits necessary for those operations. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that may be changed or interpreted in a manner which restricts our ability to conduct our mining operations or to do so profitably. Our profitability may be adversely impacted by unanticipated mine operating conditions and other factors that are not within our control, which could cause our quarterly or annual results to decrease and our stock price to decline. Our 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 our profitability. Weather conditions, equipment replacement or repair, fires, variations in thickness of the layer, 8
or seam, of coal, amounts of rock and other natural materials and other geological conditions, have had, and can be expected in the future to have, a significant impact on our operating results. For example, we were forced to temporarily idle our West Elk mine in Colorado for more than five months during 2000 following the detection of combustion gases in a portion of the mine. This mine accounted for 7.0% of our total 1999 revenues. As a result of the temporary closure of this mine, we incurred between $4 million and $6 million per month in after-tax losses while the mine was idled. Additional fire-related costs will be incurred in 2001. To date, we have received and recognized an aggregate of $31 million of pre-tax partial insurance payments that cover a portion of the losses incurred at West Elk during 2000. Any additional insurance recovery will depend on resolution of our claim with the insurance carrier, the timing of which is uncertain. In addition, a prolonged disruption of production at any of our principal mines, particularly our Mingo Logan operation in West Virginia, would result in a decrease, which could be material, in our revenues and profitability. Other factors affecting the production and sale of our coal that could result in decreases in our profitability include: . expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements; . disruption or increases in the cost of transportation services; . changes in laws or regulations, including permitting requirements; . litigation; . the timing and amount of insurance recoveries; . work stoppages or other labor difficulties; . mine worker vacation schedules and related maintenance activities; and . changes in coal market and general economic conditions. Any adverse impact on our operating results could cause our stock price to decline substantially, particularly if the results are below research analyst or investor expectations. Intense competition and excess industry capacity in the coal producing regions in which we operate has adversely affected our revenues and profitability and may continue to do so in the future. The coal industry is intensely competitive, primarily as a result of the existence of numerous producers in the coal producing regions in which we operate, and a number of our competitors have greater financial resources than we do. We compete with approximately six major coal producers in each of the Central Appalachian and Powder River Basin areas. We also compete with a number of smaller producers in those and our other market regions. We are subject to the risk of reduced profitability as a result of excess industry capacity, which has occurred in the past, and which results in reduced prices for our coal. The demand for and pricing of our coal is greatly influenced by consumption patterns of the domestic electric generation industry, and any reduction in the demand for our coal by this industry may cause our profitability to decline. Demand for coal and the prices that we will be able to obtain for our 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 our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of coal, alternative fuels such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power. Demand for our low-sulfur coal and the prices that we 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 our coal by the domestic electric generation industry may cause our profitability to decline. 9
Deregulation of the electric utility industry may cause our customers to be more price-sensitive in purchasing coal, which could cause our profitability to decline. 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. To the extent utility deregulation causes our customers to be more cost sensitive, deregulation may have a negative affect on our profitability. Our profitability may be adversely affected by the renegotiation, termination or expiration of favorable long-term coal supply contracts. We sell a substantial portion of our coal under long-term coal supply agreements, which are contracts with a term greater than 12 months. As a consequence, we may experience fluctuations in operating results due to the expiration or termination of, or sales price redeterminations or suspensions of deliveries under, these coal supply agreements. In 1999, sales of coal under long-term contracts accounted for approximately 76% of our total revenues. Some of these contracts include pricing which is above, and, in some cases, materially above, current market prices. We currently supply coal under long- term coal supply contracts with one customer which have price renegotiation or modification provisions that take effect in mid-2001. The prices for coal shipped under these contracts are materially above the current market price for similar type coal. For the year ended December 31, 1999, and the nine months ended September 30, 2000, approximately $16.8 million and $15.1 million, respectively, of our operating income related to these contracts. We expect income from operations to be reduced by approximately one-half of the operating income attributable to these contracts in 2001, and by the full amount of this operating income in 2002. These amounts are predicated on current market pricing and will change with market conditions. Some price adjustment provisions permit a periodic decrease in the contract price to reflect decreases in production costs, including those related to technological improvements, changes in specified price indices or items such as taxes or royalties. Price renegotiation or modification provisions may provide for downward adjustments in the contract price based on market factors. We have also renegotiated some contracts to change the contract term or accommodate adverse market conditions such as decreasing coal spot market prices. New nitrous oxide emission limits could also result in price adjustments, or could force electric generators to terminate or modify long-term contracts. Other short- and long-term contracts define base or optional tonnage requirements by reference to the customer's requirements, which may change as a result of factors beyond our, and in some instances, the customer's control, including utility deregulation. If the parties to any long-term contracts with us were to modify, suspend or terminate those contracts, our profitability would decline to the extent that we are unable to find alternative customers at a similar or higher level of profitability. Because our profitability is substantially dependent on the availability of an adequate supply of coal reserves that can be mined at competitive costs, the unavailability of these types of reserves would cause our profitability to decline. Our profitability depends substantially on our 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. We have in the past, and will in the future, acquire coal reserves for our mine portfolio from third parties. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. Disruption in or increased costs of transportation services could adversely affect our profitability. 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. Disruptions of these transportation services could temporarily impair our ability to supply coal to our customers. In 10
addition, increases in transportation costs, or changes in costs relative to transportation costs for coal produced by our competitors, could adversely affect our profitability. We face numerous uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability. The coal reserve information included or incorporated in this prospectus has not been audited by an independent expert. We base our reserve information on geological data assembled and analyzed by our staff, which includes various engineers and geologists. 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 our control. 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 vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities attributable to any particular group of properties, classifications of 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 our reserves, may vary from estimates, and these variances may be material. These estimates thus may not accurately reflect our actual reserves. Defects in title or the loss of any leasehold interests in our properties could limit our ability to mine these properties or result in significant unanticipated costs. We conduct a significant part of our mining operations on properties that we lease. The loss of any lease could adversely affect our ability to mine the associated reserves. Because title to most of our leased properties and mineral rights is not thoroughly verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property, our right to mine some of our reserves has in the past, and may again in the future, be adversely affected if defects in title or boundaries exist. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we have had to, and may in the future have to, incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. Agreements entered into in connection with the acquisition of our reserves and mining facilities in the western United States contain limitations on our ability to manage these operations exclusively and could subject us to significant indemnification obligations. Our affiliate, Arch Western Resources, LLC, is the owner of our reserves and mining facilities in the western United States. The agreement under which Arch Western was formed provides that one of our subsidiaries, 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 ARCO, 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, at that time, Arch Western has a debt rating less favorable than Ba3 from Moody's Investors Service or BB- from Standard & Poor's or fails to meet specified indebtedness and interest ratios. 11
In connection with the Arch Western acquisition, we entered into an agreement under which we agreed to indemnify ARCO against specified tax liabilities in the event that these liabilities arise as a result of actions taken prior to June 1, 2013, including the sale or other disposition of specified properties of Arch Western, the repurchase of some equity interests in Arch Western by Arch Western or the reduction under some circumstances of indebtedness incurred by Arch Western in connection with the Arch Western acquisition. Depending on the time at which any indemnification obligation were to arise, it could impact our profitability for the period in which it arises. The membership interests in Canyon Fuel Company, LLC, 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 which governs the management and operations of Canyon Fuel provides for a management board to manage the business and affairs of Canyon Fuel. Some major business decisions concerning Canyon Fuel require the vote of 70% of the membership interests and therefore limit our ability to make these decisions. These decisions include admission of additional members, approval of annual business plans, the making of capital expenditures, sales of coal below specified prices, agreements between Canyon Fuel and any member, 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, entering into leases, and the selection and removal of officers. The Canyon Fuel agreement also contains restrictions on the transfer of our membership interest in Canyon Fuel. Our stockholder rights plan and amended charter documents may make it harder for others to obtain control of us even though some stockholders might consider such a development favorable, which may adversely affect our stock price. In March 2000, we adopted a stockholder rights plan which, together with provisions of our amended and restated certificate of incorporation and our by- laws, may delay, inhibit or prevent someone from gaining control of us through a tender offer, business combination, proxy contest or some other method even if some of our stockholders might believe a change in control is desirable. See "Description of Capital Stock" for a description of our rights plan and these charter and by-law provisions. 12
FORWARD-LOOKING STATEMENTS This prospectus includes and incorporates by reference forward-looking statements within the "safe harbor" provision of the Private Securities Litigation Reform Act of 1995. These statements may generally be identified by the use of words such as "estimate," "expect," "anticipate," "believe," "intend," "plan," "continue," "may," "will," "should," or "shall." We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those projected in these statements, some of which are described under "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The forward-looking statements contained and incorporated by reference in this prospectus are based on expectations or assumptions, some or all of which may be incorrect. These expectations and assumptions include the following: . our expectation of continued growth in the demand for electricity; . our belief that legislation and regulations relating to the Clean Air Act will increase demand for our coal; . our expectation of improving market conditions for the price of our coal; . our expectation that we will continue to have adequate liquidity from our cash flow from operations, together with available borrowings under our credit facilities, to finance our working capital needs and meet our debt reduction goals; and . our expections as to changes in mining rates and costs for a variety of operational, geological, permitting, labor and weather-related reasons, including equipment availability. 13
USE OF PROCEEDS We estimate that the net proceeds to us from this offering will be approximately $70.7 million, or approximately $92.9 million if the underwriter exercises its over-allotment option in full to purchase 1,227,765 additional shares, based on the public offering price of $19.00 per share, and after deducting the underwriting discount and estimated offering expenses payable by us. We currently intend to use one-half of the net proceeds of this offering to reduce indebtedness under our revolving credit facility and the remainder to reduce indebtedness under our amortizing term loan. As of December 31, 2000, outstanding indebtedness under our revolving credit facility and amortizing term loan was $332.1 million and $135.0 million, respectively. The indebtedness to be reduced bears interest at variable rates based on a PNC Bank base rate or LIBOR. The interest rates in effect as of December 31, 2000 were 8.03% and 8.29% on outstanding indebtedness under the revolving credit facility and amortizing term loan, respectively. The indebtedness under both the revolving credit facility and amortizing term loan matures on May 31, 2003. We will not receive any proceeds from the sale of shares offered by the selling stockholder under this prospectus. PRICE RANGE OF COMMON STOCK AND DIVIDENDS Our common stock is listed on the New York Stock Exchange. The following table sets forth for the periods indicated the range of high and low sales prices per share of our common stock as reported on the New York Stock Exchange and the cash dividends declared on the common stock for the periods indicated. Common Stock Price ------------- High Low Dividends ------ ------ --------- Year Ended December 31, 1999: First Quarter......................................... $16.88 $ 9.75 $.1150 Second Quarter........................................ 14.81 10.94 .1150 Third Quarter......................................... 15.56 11.38 .1150 Fourth Quarter........................................ 13.00 8.56 .1150 Year Ended December 31, 2000: First Quarter......................................... $11.38 $ 6.50 $.0575 Second Quarter........................................ 9.00 4.75 .0575 Third Quarter......................................... 11.25 6.94 .0575 Fourth Quarter........................................ 14.94 9.38 .0575 Year Ending December 31, 2001: First Quarter (through February 15, 2001)............. $21.88 $12.88 On February 15, 2001, the last sale price of our common stock as reported on the New York Stock Exchange was $19.26 per share. On December 31, 2000, there were approximately 12,211 holders of record of our common stock. The future declaration and payment of dividends and the amount of dividends will depend upon our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by credit agreements or senior securities and other factors deemed relevant by our board of directors. In 2000, we reduced the amount of our dividend payments by 50%. Our board of directors has considered and may again consider further reducing the amount of dividends we pay. 14
CAPITALIZATION The following table sets forth our capitalization as of September 30, 2000 and as adjusted to give effect to the sale of 3,943,032 shares of common stock at the public offering price of $19.00 per share and the application of the net proceeds as described in "Use of Proceeds." As of September 30, 2000 ---------------------------- (in thousands) (unaudited) Actual As Adjusted ------------ -------------- Total debt........................................ $1,152,216 $ 1,081,473 ============ ============ Stockholders' equity: Preferred stock, $.01 par value, 10,000,000 shares authorized, no shares issued and outstanding, actual and as adjusted............. -- -- Common stock, $.01 par value, 100,000,000 shares authorized, 38,164,482 issued and outstanding, actual; 42,107,514 shares issued and outstanding, as adjusted........................ 397 436 Paid-in capital.................................. 473,335 544,039 Accumulated deficit.............................. (242,400) (242,400) Treasury stock, at cost.......................... (18,971) (18,971) ------------ ------------ Total stockholders' equity..................... $ 212,361 $ 283,104 ============ ============ Total capitalization.............................. $1,364,577 $ 1,364,577 ============ ============ 15
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 1997, 1998 and 1999 are derived from our audited consolidated financial statements incorporated by reference in this prospectus. The selected consolidated financial data for, and as of the end of, the nine months ended September 30, 1999 and 2000 are derived from our unaudited consolidated financial statements incorporated by reference in this prospectus, and in the opinion of management, include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes incorporated by reference in this prospectus. Nine Months Ended Year Ended December 31, September 30, --------------------------------- ---------------------- 1997 1998 1999 1999 2000 ---------- ---------- ---------- ---------- ---------- (in thousands except per share data) Statement of Operations Data: (unaudited) Coal sales, equity income and other revenues............... $1,066,875 $1,505,635 $1,567,382 $1,194,654 $1,057,243 Costs and expenses: Cost of coal sales..... 916,802 1,313,400 1,426,105 1,071,187 946,617 Selling, general and administrative expenses.............. 28,885 44,767 46,357 33,188 29,611 Amortization of coal supply agreements..... 18,063 34,551 36,532 28,894 30,790 Merger-related expenses.............. 39,132 -- -- -- -- Write-down of impaired assets................ -- -- 364,579 -- -- Other expenses......... 22,111 25,070 20,835 14,060 11,510 ---------- ---------- ---------- ---------- ---------- Income (loss) from operations............. 41,882 87,847 (327,026) 47,325 38,715 Interest expense, net... 17,101 61,446 88,767 67,466 68,165 Benefit from income taxes.................. 5,500 5,100 65,700 18,400 7,100 ---------- ---------- ---------- ---------- ---------- Income (loss) before extraordinary loss and cumulative effect of accounting change...... 30,281 31,501 (350,093) (1,741) (22,350) Extraordinary loss...... -- (1,488) -- -- -- Cumulative effect of accounting change...... -- -- 3,813 3,813 -- ---------- ---------- ---------- ---------- ---------- Net income (loss)....... $ 30,281 $ 30,013 $ (346,280) $ 2,072 $ (22,350) ========== ========== ========== ========== ========== Balance Sheet Data (at period end): Total assets............ $1,656,324 $2,918,220 $2,332,374 $2,748,274 $2,260,480 Working capital......... 40,904 20,176 (54,968) 16,856 (93,798) Long-term debt, less current maturities..... 248,425 1,309,087 1,094,993 1,181,209 1,066,216 Other long-term obligations............ 594,127 657,759 655,166 658,985 619,389 Retained earnings (Accumulated deficit).. 138,676 150,423 (213,466) 139,277 (242,400) Stockholders' equity.... 611,498 618,216 241,295 594,270 212,361 Common Stock Data: Basic and diluted earnings (loss) per common share before extraordinary loss and cumulative effect of accounting change...... 1.00 0.79 (9.12) (0.05) (0.59) Basic and diluted earnings (loss) per common share........... 1.00 0.76 (9.02) 0.05 (0.59) Dividends per share..... 0.445 0.46 0.46 0.3450 0.1725 Shares outstanding at period end............. 39,658 39,372 38,164 38,463 38,164 Cash Flow Data: Cash provided by operating activities... $ 190,263 $ 188,023 $ 279,963 $ 195,964 $ 127,257 Depreciation, depletion and amortization....... 143,632 204,307 235,658 179,942 153,286 Purchases of property, plant and equipment.... 77,309 141,737 98,715 76,078 103,121 Dividend payments....... 13,630 18,266 17,609 13,218 6,584 Adjusted EBITDA......... 224,646 313,500 325,949 255,130 220,480 Operating Data: Tons sold............... 40,525 81,098 111,177 82,728 79,384 Tons produced........... 36,698 75,817 109,524 80,896 76,112 Tons purchased from third parties.......... 2,906 4,997 3,781 3,257 3,875 16
Adjusted EBITDA is income from operations before the effect of changes in accounting principles and extraordinary items; merger-related costs, unusual items, asset impairment and restructuring charges; net interest expense; income taxes; and depreciation, depletion and amortization of Arch Coal and its subsidiaries and its ownership percentage in its equity investments. Adjusted EBITDA should not be considered in isolation nor as an alternative to net income, operating income, cash flows from operations or as a measure of a company's profitability, liquidity or performance under U.S. generally accepted accounting principles. Information for 1997 reflects our merger with Ashland Coal, Inc. on July 1, 1997 and also reflects a $39.1 million charge in connection with the Ashland Coal merger comprised of termination benefits, relocation costs and costs associated with duplicate facilities. Information for 1998 reflects the acquisition of Atlantic Richfield Company's domestic coal operations on June 1, 1998. We refinanced our debt in connection with this acquisition, and 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. Income from operations for 1998 reflects pre- tax gains of $41.5 million from the disposition of assets, including $18.5 million on the sale of assets and idle properties in eastern Kentucky and $7.5 million on the sale of our idle Big Sandy Terminal. The loss from operations for 1999 reflects one-time pre-tax charges of $364.6 million related principally to the write-down of assets at our Dal-Tex, Hobet 21 and Coal-Mac operations and the write-down of other coal reserves in Central Appalachia, and a $23.1 million pre-tax charge related to the restructuring of our administrative workforce and the closure of mines in Illinois, Kentucky and West Virginia. We changed our 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. 17
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview We were originally organized as Arch Mineral Corporation in 1969. On July 1, 1997, Ashland Coal, Inc. then a majority-owned subsidiary of Ashland Inc., merged with a subsidiary of our company. A total of 18,660,054 shares of our common stock were issued in the merger, resulting in a total purchase price, including the fair value of stock options and transaction-related fees, of approximately $464.8 million. In connection with the merger, we changed our name to Arch Coal, Inc. Immediately prior to the merger, Ashland beneficially owned common stock representing approximately 57% of the voting power of Ashland Coal and approximately 51% of our voting stock. Immediately after the merger, Ashland owned approximately 54% of our outstanding common stock, which ownership increased to 58% as of June 1999, when Ashland announced an interest in exploring strategic alternatives for its interest in our company. Ashland retained its stake in our company until its March 2000 distribution of approximately 17.4 million shares of our common stock to Ashland's stockholders after which Ashland owned approximately 12.4% of our outstanding common stock. On June 1, 1998, we acquired the United States coal operations of Atlantic Richfield Company for an aggregate of approximately $1.14 billion in cash and combined these operations with our western operations in a new joint venture named Arch Western Resources, LLC. We own 99% of this joint venture and ARCO owns the remaining 1% interest. The principal operating units of Arch Western are Thunder Basin Coal Company, L.L.C., owned 100% by Arch Western, which operates a coal mine in the Southern Powder River Basin in Wyoming; Mountain Coal Company, L.L.C., owned 100% by Arch Western, which operates a coal mine in Colorado; Canyon Fuel Company, LLC, 65% owned by Arch Western and 35% owned by ITOCHU Coal International Inc., a subsidiary of ITOCHU Corporation, which operates three coal mines in Utah; and Arch of Wyoming, LLC, owned 100% by Arch Western, which operates two coal mines in the Hanna Basin of Wyoming. Excluding our Canyon Fuel joint venture, the results of which we account for under the equity method of accounting, we sold approximately 111.2 million tons of coal in 1999, 107.1 million tons of which we produced and the balance of which we purchased for resale through contractual arrangements. We sold approximately 82% of this tonnage under long-term contracts, which are contracts of greater than one year, and the balance on the spot market. We derived approximately 76% of 1999 total revenues from sales of coal under long- term contracts. Our sales of steam coal, which is coal used in steam boilers to produce electricity, in 1999 totaled 108.7 million tons, or approximately 98% of 1999 coal sales, while sales of metallurgical coal, which is coal suitable for distillation into carbon in connection with the production of steel, in 1999 totaled 2.5 million tons, or approximately 2% of 1999 coal sales. In 1999, sales of coal in the export market totaled approximately 3.5 million tons. Sales of steam coal accounted for approximately 59% of these export sales, while the balance of export sales consisted of sales of metallurgical coal. Our 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 result in fluctuations in our profitability. Weather conditions, equipment replacement or repair, 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 our operating results. For example, we were forced to temporarily idle our West Elk mine in Colorado for more than five months during 2000 following the detection of combustion gases in a portion of the mine. The temporary closure of this mine adversely affected our operating results in 2000. A prolonged disruption of production at any of our principal mines, particularly our Mingo Logan operation in West Virginia, would have a material adverse effect on us. Other factors affecting the production and sale of our coal that can result in fluctuations in our profitability include the following: . expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements; . disruption or increases in the cost of transportation services; 18
. changes in laws or regulations, including permitting requirements; . litigation; . work stoppages or other labor difficulties; and . changes in coal market and general economic conditions. Outlook West Elk Mine. On July 12, 2000, we resumed production at our West Elk underground mine in Gunnison County, Colorado, and, after experiencing geological conditions unrelated to the fire that have hindered production, the mine returned to normal levels of production during the fourth quarter of 2000. West Elk had been idle since January 28, 2000, following the detection of combustion-related gases in a portion of the mine. We incurred between $4 million and $6 million per month in after-tax losses while the mine was idled. Additional fire-related costs were incurred at the West Elk mine following the resumption of mining activities and will continue to be incurred in 2001 as we reclaim drilling sites and roads and eventually dismantle pumping equipment. To date, we have received and recognized aggregate pre-tax partial insurance payments of $31 million that cover a portion of the losses incurred at West Elk during 2000. We expect to receive additional insurance payments under our property and business interruption policy. Any additional recovery, however, will depend on resolution of our claim with the insurance carrier, the timing of which is uncertain. West Virginia Operations. On October 20, 1999, the U.S. District Court for the Southern District of West Virginia permanently enjoined the West Virginia Division of Environmental Protection (DEP) from issuing any permits that authorize the construction of valley fills as part of coal mining operations. The West Virginia DEP complied with the injunction by issuing an order banning the issuance of permits for the construction of nearly all new valley fills and the expansion of nearly all existing valley fills. On October 29, 1999, the district court granted a stay of its injunction, pending the outcome of an appeal of the court's decision filed by the West Virginia DEP with the U.S. Court of Appeals for the Fourth Circuit. The West Virginia DEP rescinded its order in response to the stay granted by the court. We cannot predict the outcome of the West Virginia DEP's appeal to the Fourth Circuit. If, however, the district court's ruling is not overturned or if a legislative or other solution is not achieved, we and other coal producers in West Virginia may be forced to close all or a portion of our mining operations in West Virginia, to the extent those operations are dependent on the use of valley fills. The injunction discussed above was entered as part of the litigation that caused a delay in obtaining mining permits for our Dal-Tex operation described under "Business--Legal Proceedings--Dal-Tex Litigation". In 1999, we recorded charges for severance and closure costs aggregating $13.8 million with respect to the idling of this operation. As a result of the delay, we idled our Dal-Tex mining operation on July 23, 1999. If all necessary permits are obtained, which is not expected to occur until mid-2001 at the earliest, and the permanent injunction is withdrawn by the Fourth Circuit, then we may determine to reopen the mine subject to then-existing market conditions. Previously, we had disclosed that longwall mineable reserves at Mingo Logan were likely to be exhausted during 2002. As a result of improvements to the mine plan, we now believe that we can extend longwall mining at that operation for an additional 12 months, which will be well into 2003. Longwall mining is a mining technique in which a rotating drum is pulled mechanically across the face of coal and a hydraulic system supports the roof of the mine while it advances through the coal. Coal Markets. Recent developments, including rising natural gas prices, declining coal inventory levels and the recent energy crisis in California, have translated into improved market conditions for coal. As of January 2001, the 19
price of natural gas has more than doubled since December 1999. No domestic nuclear plants are currently in the permitting stage while in September 2000, Wisconsin Electric Power Company announced plans to construct two new coal- fired units with a combined generating capacity of 1,200 megawatts, and in January 2001, UniSource Energy Corp. and Bechtel Power Corp. each announced plans to build 380 megawatt coal-fired units in northern Arizona, and LS Power LLC, an independent power producer, announced plans to build a 1,000 to 1,600 megawatt coal-fired plant in Arkansas, which it anticipates will burn coal from the Powder River Basin. Hydroelectric power conditions are weaker than normal due to dry conditions. Also, since late July, quoted and spot prices for coal produced in the regions in which we operate have risen. However, because most of our production was already committed and priced for 2000, our results for the year reflected the earlier market weakness. We continue to take steps to match our production levels to market needs. We have ceased production at our Coal Creek surface mine in Campbell County, Wyoming. We also plan to maintain a production level of approximately 60 million tons from our Black Thunder mine near Gillette, Wyoming. Low-Sulfur Coal Producer. We continue to believe that we are well-positioned to capitalize on the continuing growth in demand for low-sulfur coal to produce electricity. With Phase II of the Clean Air Act in effect, compliance coal has captured a growing share of United States coal demand and commands a higher price than high-sulfur coals in the marketplace. Compliance coal is coal that meets the requirements of Phase II of the Clean Air Act without the use of expensive scrubbing technology. All of our western coal production and approximately half of our eastern production is compliance quality. Chief Financial Objectives. We continue to focus on realizing the potential of our assets and maximizing stockholder value by making decisions based upon our five chief financial objectives: (1) further strengthening our cash generation, (2) improving our earnings, (3) increasing our productivity, (4) aggressively paying down our debt, and (5) reducing our costs. We are aggressively pursuing cost savings which, together with improved productivity, are designed to enable us to achieve our other financial objectives. In addition to the corporate-wide restructuring in late 1999 that we believe will result in a substantial reduction in operating costs for the current and future years, we recently initiated a cost reduction effort targeting key cost drivers at each of our captive mines. We may issue additional equity securities to further pursue our objective of aggressively paying down our debt. We are also exploring Internet- based solutions that could reduce costs, especially in the procurement area. We repaid $28.8 million of debt during the first nine months of the year and made the second of five annual payments of $31.6 million for the Thundercloud federal reserve lease, despite lower cash generation and increased expenditures related to the idling of the West Elk mine, and a net payment of $31.6 million to purchase assets out of an operating lease. We anticipate continuing to make substantial progress toward reducing debt in the future. Recent Operating Results We recently announced our preliminary and unaudited financial and operating results for our fourth quarter and year ended December 31, 2000. Our revenue for the quarter ended December 31, 2000 was $347.4 million, as compared to revenue of $372.7 million in the same period of 1999. Net income for the fourth quarter of 2000, was $9.6 million, as compared to a net loss of $348.4 million in the same quarter of 1999. Coal sales were 26.1 million tons in the fourth quarter of 2000, as compared to 28.4 million tons in the same period of 1999. Fourth quarter 2000 results benefited from a third partial insurance recovery of $7.0 million (pre-tax) related to the January 2000 fire at our West Elk mine in Colorado, a $13.0 million pre-tax gain associated with the settlement of certain workers' compensation liabilities, and a $9.8 million pre-tax gain 20
resulting from previously unrecognized post-retirement benefit changes which occurred in prior years. Partially offsetting that benefit were the adverse roof conditions at West Elk and higher diesel fuel prices, which together had a negative impact of $14.0 million for the quarter. Results of Operations Our results of operations for the years ended 1997, 1998 and 1999 and for the first nine months of 1999 and 2000 are discussed below. Our results of operations for 1997, 1998 and 1999 are not directly comparable because of our July 1, 1997 merger with Ashland Coal and our June 1, 1998 acquisition of ARCO's United States coal operations. Results of operations do not include the activity of Ashland Coal or ARCO's United States coal operations prior to the effective dates of those transactions. Nine Months Ended September 30, 2000 Compared to Nine Months Ended September 30, 1999. Net Income (Loss). We incurred a net loss of $22.4 million for the nine months ended September 30, 2000 compared to net income of $2.1 million for the nine months ended September 30, 1999. Results for the nine months ended September 30, 2000 were adversely impacted by the temporary idling of our West Elk mine in Gunnison County, Colorado. The mine was idled from January 28, 2000 to July 12, 2000, following the detection of combustion gases in a portion of the mine. During the nine months ended September 30, 2000, the mine contributed coal sales of $23.1 million and an operating loss of $38.6 million, excluding insurance recoveries, compared to $80.1 million of coal sales and $7.6 million of operating income during the nine months ended September 30, 1999. Offsetting a portion of the loss at the West Elk mine were pre-tax partial insurance payments aggregating $24.0 million received during the nine months ended September 30, 2000 as part of our coverage under our property and business interruption insurance policy. Also, as a result of recent permit revisions at our idle mine properties in Illinois, we reviewed and reduced our reclamation liability at those locations by $7.8 million during the current period. In addition, the Internal Revenue Service issued a notice in 2000 outlining the procedures for obtaining tax refunds on federal excise taxes paid by the industry on export sales tonnage. The notice is a result of a 1998 federal district court decision that found these taxes to be unconstitutional. We recorded $12.7 million of pre-tax income related to these excise tax recoveries during the nine months ended September 30, 2000. Revenues. Total revenues for the nine months ended September 30, 2000 were $1.057 billion, a decrease of 11.5% from revenues of $1.195 billion for the nine months ended September 30, 1999. Factors contributing to the decrease included reduced sales at our West Elk mine as a result of the temporary idling of that mine, as described above. Also, we closed our Dal-Tex, Wylo and Arch of Illinois operations and two surface mines in Kentucky during the second half of 1999. In addition, production and sales at our Mingo Logan operation decreased 12% and 10%, respectively, in the current period compared to the same period in the prior year. Partially offsetting sales at our closed eastern operations were increased sales at other eastern operations. We idled the Dal-Tex operation on July 23, 1999 due to a delay in obtaining new mining permits which resulted from legal action in the U.S. District Court for the Southern District of West Virginia, as described under "Business--Legal Proceedings--Dal-Tex Litigation". The Wylo operation ceased production in December 1999 due to the depletion of its recoverable reserves. The Arch of Illinois underground operation, which had remained operative after the closing of the Arch of Illinois surface operations in 1998, was closed in December 1999 due to a lack of demand for the mine's high-sulfur coal. Demand for high-sulfur coal has declined rapidly as a result of the stringent Clean Air Act requirements that are driving a shift to low-sulfur coal. Two small surface mines in Kentucky were closed because their cost structures were not competitive in the then-existing market environment. The resulting decrease in production and sales from our eastern operations was partially offset by increased production and sales at our Black Thunder mine in Wyoming. As a result, on a per-ton-sold basis, our average selling price of $12.72 during the first nine months of 2000 reflected a decrease of $1.23 from the same period in the prior year primarily as a result of the continuing increase in 21
coal sales from our western operations. Western coal, especially Powder River Basin coal, has a significantly lower average sales price than that of eastern coal, but is also significantly less costly to mine. Income from Operations. Excluding the decrease in income from operations resulting from the temporary idling of the West Elk mine, the partial insurance payments, the reclamation liability adjustment at Arch of Illinois and the excise tax recoveries, income from operations decreased $7.0 million for the nine months ended September 30, 2000 when compared to the same period in the prior year. The decrease was attributable to low sales relating to difficult market conditions in United States coal markets during the period along with increased fuel costs of over $1.0 million per month compared to the same period in 1999, resulting from higher diesel fuel and oil prices. Income from operations also declined at our Mingo Logan longwall operation where, despite the contribution of $30.0 million to our income from operations, results were below the $40.9 million of income from operations for the nine months ended September 30, 1999. The decrease was primarily caused by depressed coal prices, generally less favorable mining conditions and increased mine development expenses associated with the start-up of operations in the Alma seam in preparation for moving longwall equipment into the newly developed seam in early 2001. Partially offsetting the decrease in income from operations was improved performance at several of our other mines caused in part by our continued focus on reducing costs and improving productivity and reduced costs during the nine months ended September 30, 2000 resulting from the closure of the Dal-Tex operation in July 1999. The Dal-Tex complex incurred production shortfalls, deterioration of mining conditions and resulting lower operating income prior to its closing on July 23, 1999. As a result of the closing, we recorded a charge of $6.5 million through the third quarter of 1999, consisting principally of severance costs, obligations for non-cancelable lease payments and a change in the reclamation liability. Other factors that affected period to period comparisons were several sales of surplus land which resulted in a gain of $8.4 million during the current period. During the nine months ended September 30, 1999, we sold a dragline at the Arch of Illinois operation, resulting in a gain of $2.5 million, and also had settlements with two suppliers that added $4.5 million to the prior period results. Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $3.6 million from the nine months ended September 30, 1999. The decrease was attributable to cost savings resulting from the restructuring of our administrative workforce that occurred during the fourth quarter of 1999, partially offset by higher legal and consulting expenses incurred during the second quarter of 2000. Adjusted EBITDA. Adjusted EBITDA was $220.5 million for the nine months ended September 30, 2000 compared to $255.1 million for the nine months ended September 30, 1999. The decrease in adjusted EBITDA was primarily attributable to the continued negative impact of the temporary idling of our West Elk mine, excluding insurance recoveries, and lower operating profit at the Mingo Logan operation. This was partially offset by improved performance at our Black Thunder mine and the impact of the partial insurance payments due to the idling of the West Elk mine. Year Ended December 31, 1999 Compared to Year Ended December 31, 1998. Net Income (Loss). We incurred a net loss in 1999 of $346.3 million compared to net income of $30.0 million in 1998. Results for 1999 included operating results of the Arch Western operations for the entire year, whereas results for 1998 only included results of the Arch Western operations from June 1, 1998, including a 65% share of Canyon Fuel income, net of purchase accounting adjustments. The decrease in 1999 was primarily the result of several one-time charges. During the fourth quarter of 1999, we determined that significant changes were necessary in the manner and extent to which a portion of our Central Appalachia coal assets would be deployed. The changes were necessitated by the adverse legal and regulatory rulings related to surface mining techniques as well as continued negative pricing trends related to Central Appalachian coal production. In accordance with applicable accounting pronouncements, we evaluated the recoverability of our active mining operations and our coal reserves for which no future mining plans exist. This evaluation indicated that the future undiscounted cash flows of three mining operations, Dal-Tex, Hobet 21 22
and Coal-Mac, and coal reserves with no future mining plans were below their carrying value. Accordingly, during the fourth quarter of 1999, we adjusted the operating assets and coal reserves to their estimated fair value of approximately $99.7 million, resulting in a non-cash impairment charge of $364.6 million, including $50.6 million relating to operating assets and $314.0 million relating to coal reserves. The estimated fair value of the three mining operations was based on anticipated future cash flows discounted at a rate commensurate with the risk involved. The cash flow assumptions used in this determination are consistent with our future plans for those operations and consider the impact of inflation on coal prices and operating costs which are expected to offset each other. The value of the coal reserves with no future mining plans was based upon the fair value of these properties to be derived from subleased operations. We do not expect the impairment charge to have a material impact on our operating results subsequent to 1999. During 1999, we also recorded pre-tax charges totaling $23.1 million related to the restructuring of our administrative workforce, the closure of our Dal-Tex mine in West Virginia, and the closure of several mines at our Coal-Mac complex in Kentucky and the remaining underground mine at our Arch of Illinois complex. Of the $23.1 million charge, $20.3 million was recorded in cost of coal sales, $2.3 million was recorded in selling, general and administrative expenses and $0.5 million was recorded in other expenses in our consolidated statements of operations. During 1999, we also recorded a $112.3 million valuation allowance for a portion of our deferred tax assets that we believe, more likely than not, will not be realized. Prior to the year ended December 31, 1999, our internal forecast of book and taxable income provided sufficient anticipated future taxable income to recognize deferred tax assets in full. However, a combination of factors arising during 1999 resulted in a determination that, as of December 31, 1999, a valuation allowance of $112.3 million was appropriate, including: (a) the significant increase in the amount of our gross tax assets attributable to temporary differences arising from the 1999 impairment charge and (b) unfavorable adjustments to forecasted future income attributable to (i) the effect of the Dal-Tex litigation on future mountain top mining activities in West Virginia and (ii) persistent negative trends in prices for our compliance coal. Effective January 1, 1999, we changed our method of depreciation on preparation plants and loadouts from a straight-line basis to a units-of- production basis, which is based upon units produced, subject to a minimum level of depreciation. These assets are usage-based and their economic lives are typically based and measured on coal processed by the assets. We believe the units-of-production method is preferable to the method previously used because the new method recognizes that depreciation of this equipment is related substantially to physical wear due to usage as well as the passage of time. This method recovers production costs over the lives of the preparation plants and loadouts with coal sales revenue and results in a better matching of the cost of the physical assets to the periods in which the assets are consumed. The cumulative effect of applying the new depreciation method for years prior to 1999 was an increase to income of $3.8 million. Revenues. Total revenues of $1.567 billion for 1999 were 4.1% higher than revenues for 1998, primarily as a result of including a full year of operating results from the Arch Western operations in 1999, which accounted for approximately $406.7 million of our revenues in 1999 compared to only seven months of operating results from the Arch Western operations in 1998, which accounted for approximately $228.5 million of our revenues in 1998. Revenues were also favorably impacted by increased production and sales at our Samples mine. The increase was partially offset by reduced production and sales at our Dal-Tex and Wylo operations, both located in Central Appalachia, and our Arch of Illinois surface mining operation. The Wylo operations and Arch of Illinois surface operations ceased production in December 1999 and June 1998, respectively, due to the depletion of their recoverable coal reserves. We idled the Dal-Tex operation on July 23, 1999 due to a delay in obtaining new mining permits which resulted from legal action in the U.S. District Court for the Southern District of West Virginia. On a per-ton-sold basis, our average selling price of $13.58 during 1999 reflected a decrease of $4.03 from 1998, primarily because of the inclusion of the Arch Western 23
operations for all of 1999 compared to only seven months during 1998. Western coal, especially Powder River Basin coal, has a significantly lower average sales price than that of eastern coal, but is also significantly less costly to mine. Income from Operations. Excluding the one-time charges discussed above, income from operations decreased $27.2 million despite the inclusion of the Arch Western operations for the entire year compared to only seven months in 1998. Net gains on the disposition of assets were $7.5 million in 1999 compared to $41.5 million in 1998. The gain in 1998 included a pre-tax gain of $18.5 million on the sale of assets and idle properties in eastern Kentucky and a pre-tax gain of $7.5 million on the sale of our idle Big Sandy Terminal. The operating results in 1999 also included pre-tax gains of $5.0 million related to settlements with various suppliers. Operating results in 1999 were negatively affected by production shortfalls, generally less favorable mining conditions and lower operating income from our idled Dal-Tex mine complex. Operating results were also negatively affected in 1999 at Mingo Logan, where, despite a contribution of $46.6 million of operating income, results were significantly below the $77.8 million contributed to income from operations in 1998. The decrease was primarily caused by depressed coal prices, generally less favorable mining conditions and increased mine development expenses associated with the start-up of mining in the Alma seam during 1999. The Mountaineer Mine contributed 12% and 15% of our coal sales revenues in 1999 and 1998, respectively. During the first half of 1999, we continued to experience production shortfalls and operating challenges at our Black Thunder mine in Wyoming due to geological, water drainage and equipment sequencing problems. The negative impacts discussed above were partially offset by lower operating losses in 1999 at the Arch of Kentucky operation compared to 1998. The Arch of Kentucky operation was shut down in January 1998. Results during 1998 were impacted by the costs associated with the shut down of that operation. Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $1.6 million primarily due to the inclusion of the Arch Western operations for the entire year compared to only seven months in 1998, the restructuring charge discussed above and additional legal and other expenses related to surface-mining issues in West Virginia. Amortization. Sales contract amortization increased $2.0 million primarily from the inclusion of a full year of the Arch Western operations compared to seven months in 1998. Interest Expense. Interest expense increased $27.9 million due to the increase in debt associated with the June 1998 Arch Western acquisition. Income Taxes. The income tax benefit recorded in 1999 resulted from the pre-tax loss, offset by the valuation allowance recorded against our deferred tax assets. We believe that taxable income will be generated by us in future periods that is consistent with historical income levels and will, more likely than not, permit the realization of the net deferred tax assets remaining at December 31, 1999. We expect to recognize part of the benefit of our deferred tax asset at the alternative minimum tax rate of approximately 24%. Our effective tax rate is sensitive to changes in annual profitability and percentage depletion. Adjusted EBITDA. Adjusted EBITDA was $325.9 million for 1999 compared to $313.5 million for 1998. The increase in adjusted EBITDA is primarily attributable to an inclusion of an entire year of Arch Western operations in our financial results compared to only seven months in 1998. Year Ended December 31, 1998 Compared to Year Ended December 31, 1997. Net Income. Net income for 1998 was $30.0 million compared to $30.3 million for 1997. The 1998 results included a full year of operating results from the former Ashland Coal operations, whereas 1997 included only six months of results from those operations. In addition, 1998 included results of the Arch Western operations from June 1, 1998, including a 65% share of Canyon Fuel income, net of purchase accounting adjustments. 24
Revenues. Total revenues of $1.506 billion for 1998 increased 41% from 1997 as a result of the inclusion of a full year of results from the former Ashland Coal operations in 1998 and seven months of operating results from the Arch Western operations, including income from our equity investment in Canyon Fuel. On a per-ton-sold basis, however, our average selling price decreased by $7.93, primarily because of the inclusion of the Arch Western operations. Western coal, especially Powder River Basin coal, has a significantly lower average sales price than that of eastern coal, but is also significantly less costly to mine. Selling prices in 1998 were also affected by adverse market conditions in the western United States and export markets, as well as by reduced seasonal demand caused by unusually warm winter weather. Income from Operations. Net income for 1998 approximated that for 1997 despite the Arch Western acquisition and the inclusion of a full year of results in 1998 from the former Ashland Coal operations. Operating results were favorably impacted in 1998 by increased production from our Mingo Logan longwall operation. This positive result was offset, in part, by production shortfalls, deterioration of mining conditions and resulting lower net income contributions from our Dal-Tex and Hobet mining complexes in Central Appalachia and the June 1998 closure of our large surface operation in Illinois as a result of reserve depletion. In particular, as a result of the continued delay in receiving new mining permits because of the Dal-Tex litigation, the Dal-Tex operation was forced to operate in less favorable mining areas with higher overburden ratios and lower productivity, resulting in higher production costs. Our 1998 results were also significantly impacted by operating difficulties at the Arch Western operations. We experienced production shortfalls and operating challenges at our Black Thunder mine in Wyoming due to geological, water drainage and equipment sequencing problems and substantial transportation delays at our West Elk mine in Colorado. In addition, Canyon Fuel experienced difficult geological conditions at its Skyline Mine. Other items adversely affecting 1998 results, as compared to 1997 results, included the expiration of an above-market-price long-term coal supply contract with Georgia Power in December 1997, reduced shipments under another above-market-price long-term coal supply contract in 1998, the completion in 1997 of a $10.8 million annual accretion of a 1993 unrecognized net gain related to pneumoconiosis, or black lung, liabilities, and a net increase in reclamation costs of $4.9 million in 1998 compared to a benefit in 1997 of $4.4 million resulting from an adjustment of our reclamation liability. Operating results in 1998 included gains from the disposition of assets of $41.5 million compared to $4.8 million in 1997. The gain in 1998 included pre-tax gains of $18.5 million on the sale of assets and idle properties in eastern Kentucky and $7.5 million on the sale of our idle Big Sandy Terminal. Results for 1997 were also affected by a one-time charge of $23.8 million, net of a tax benefit of $15.3 million, related to the Ashland Coal merger. Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $15.9 million primarily due to the effects of the Ashland Coal merger and the Arch Western acquisition. Amortization. As a result of the amortization of the carrying value of the sales contracts acquired in the Ashland Coal merger and the Arch Western acquisition, amortization of coal supply agreements increased $16.5 million. Interest Expense. Interest expense increased $44.4 million due to the increase in debt as a result of the Arch Western acquisition. Extraordinary Item. During 1998, we incurred an extraordinary charge of $1.5 million, net of a tax benefit of $0.9 million, related to the early extinguishment of debt in connection with the refinancing of our debt in connection with the Arch Western acquisition. Adjusted EBITDA. Adjusted EBITDA was $313.5 million for 1998 compared to $224.6 million for 1997. The increase in adjusted EBITDA is primarily attributable to the Ashland Coal merger and the Arch Western acquisition. 25
Liquidity And Capital Resources We have generally satisfied our working capital requirements and funded our capital expenditures and debt-service obligations with cash generated from operations. We believe that cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next several years. Our ability to satisfy our debt service obligations, to fund planned capital expenditures, to make acquisitions and to pay dividends will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control. Cash Flows. The following is a summary of cash provided by or used in each of the indicated types of activities for the periods presented. Nine Months Ended Year Ended December 31, September 30, --------------------------------- -------------------- 1997 1998 1999 1999 2000 --------- ----------- --------- --------- --------- (dollars in thousands) Cash provided by (used in): (unaudited) Operating activities... $ 190,263 $ 188,023 $ 279,963 $ 195,964 $ 127,257 Investing activities... (80,009) (1,271,371) (84,358) (65,342) (106,978) Financing activities... (114,793) 1,101,585 (219,736) (153,896) (22,009) Cash provided by operating activities decreased in the nine months ended September 30, 2000 compared to the same period in 1999 due to a decrease in cash provided from equity investments, and reduced cash from sales, increased costs resulting from the temporary idling of the West Elk mine and increased fuel costs. These were partially offset by increased receivable collections and an increase in accounts payable and accrued expenses in the nine months ended September 30, 2000 when compared to the prior year's period. The decrease in cash provided from equity investments results primarily from the amendment in the prior year of a coal supply agreement with the Intermountain Power Agency, which was a significant portion of the $72.8 million cash distribution from Canyon Fuel to us during the nine months ended September 30, 1999. Cash provided by operating activities increased substantially during 1999 compared to 1998 primarily as a result of a full year of operations from our Arch Western mines in 1999 compared to only seven months of operations in 1998. The slight decrease in cash provided by operating activities from 1997 to 1998 was principally due to increased interest expense as a result of increased borrowings associated with the Arch Western acquisition and tax payments related to adjustments to income taxes payable in prior years. The decrease was partially offset by increased operating activity resulting from the Arch Western acquisition. Cash used in investing activities increased in the nine months ended September 30, 2000 compared to the same period in 1999 primarily as a result of making the second of five annual $31.6 million payments under the Thundercloud federal lease which is related to the Black Thunder mine in Wyoming. The first payment was made at the time of the acquisition of the lease in 1998. Subsequent annual payments were made in January 2000 and 2001. The remaining payments are due in January 2002 and 2003. In addition, during the nine months ended September 30, 2000, we purchased all remaining assets under a 1998 sale and leaseback arrangement for $45.0 million. Comparisons between 2000 and 1999 are also affected by the amendment of a coal supply agreement during 1999. The amendment changed the contract terms from above-market to market-based pricing. As a result of the amendment, we received proceeds of $14.1 million from the customer (net of royalty and tax obligations) during the first quarter of 1999. The decrease in cash used in investing activities in 1999 compared to 1998 resulted primarily from the payment of $1.1 billion in cash in connection with the Arch Western acquisition completed in 1998. The Arch Western acquisition was also the reason for the significant increase in cash used for investing activities in 1998 compared to 1997. 26
Our expenditures for property, plant and equipment were $103.1 million for the nine months ended September 30, 2000, and $98.7 million, $141.7 million and $77.3 million for 1999, 1998 and 1997, respectively. We make capital expenditures to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We anticipate that these capital expenditures will be funded by available cash and existing credit facilities. Cash provided by financing activities for the nine months ended September 30, 2000 reflects reduced debt payments in the current period compared to the same period in the prior year. In addition, during the second quarter of 2000, we entered into a sale and leaseback arrangement with respect to certain equipment which resulted in net proceeds of $13.4 million. Dividend payments decreased $6.6 million in the nine months ended September 30, 2000 as compared to the same period in the prior year, resulting from a decrease in shares outstanding, and a reduction in the quarterly dividend from 11.5 cents per share to 5.75 cents per share. The dividend reduction is attributable to our goal to aggressively reduce debt. Cash used in financing activities during 1999 principally reflects debt reduction of $189.1 million. We were able to reduce debt from greater cash flows generated from operations. Cash provided by financing activities in 1998 reflects an increase in borrowings of $1.1 billion associated with the Arch Western acquisition. Credit Facilities. In connection with the Arch Western acquisition, we entered into two new five-year credit facilities: a $675 million non-amortizing term loan, or the Arch Western credit facility, and a $900 million credit facility, or the Arch Coal credit facility, including a $300 million fully amortizing term loan and a $600 million revolving credit facility. Borrowings under the Arch Coal credit facility were used to finance the acquisition of ARCO's Colorado and Utah coal operations, to pay related fees and expenses, to refinance existing corporate debt and for general corporate purposes. Borrowings under the Arch Western credit facility were used to fund a portion of a $700 million cash distribution by Arch Western to ARCO, which occurred simultaneously with ARCO's contribution of its Wyoming coal operations and other assets to Arch Western. The $675 million term loan is secured by Arch Western's membership interests in its subsidiaries. We have not guaranteed the Arch Western credit facility. At September 30, 2000, there was $231.0 million available to borrow under our revolving credit facility. We are exposed to market risk associated with interest rates. At September 30, 2000, our debt included $1.147 billion of floating-rate debt, for which the rate of interest is, at our option, the PNC Bank base rate or a rate based on LIBOR and current market rates for bank lines of credit. To manage this exposure, we enter into interest-rate swap agreements to modify the interest-rate characteristics of outstanding debt. At September 30, 2000, we had interest-rate swap agreements having a total notional value of $755.0 million. These swap agreements are used to convert variable-rate debt to fixed- rate debt. Under these swap agreements, we pay a weighted average fixed rate of 5.75% (before the credit spread over LIBOR) and receive a weighted average variable rate based upon 30-day and 90-day LIBOR. At September 30, 2000, the remaining term of the swap and collar agreements ranged from 23 to 57 months. We accrue 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 our debt. The fair value of the swap agreements are not recognized in the financial statements. 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. All instruments are entered into for other than trading purposes. Financial covenants contained in our credit facilities consist of a maximum leverage ratio, a minimum fixed charge coverage ratio and a minimum net worth test. The leverage ratio requires that we do not permit the ratio of our total indebtedness at the end of any calendar quarter to adjusted EBITDA for the 12 months then ended to exceed a specified amount. The fixed charge coverage ratio requires us to maintain the ratio of our adjusted EBITDA plus lease expense to our interest expense plus lease expense for the 12 months then ended 27
above a specified amount. The net worth test requires that we do not permit our net worth to be less than a specified amount plus 50% of cumulative net income. At December 31, 1999, as a result of the effect of the write-down of impaired assets and other restructuring costs, we did not comply with the net worth test. At that date, we were required to have a net worth of at least $508.4 million. After giving effect to the write-down of impaired assets and other restructuring costs, our net worth was $241.3 million at that date. We received an amendment to the credit facilities on January 21, 2000 which reset the net worth requirement to $163.0 million at December 31, 1999. These amendments resulted in, among other things, a one-time payment of $1.8 million and an increase in the interest rate of 0.375% associated with our term loan and the revolving credit facility. In addition, the amendments required us to pledge assets to collateralize the term loan and the revolving credit facility, including the stock of some of our subsidiaries, some real property interests, accounts receivable and inventory. We were in compliance with these financial covenants at December 31, 2000. At September 30, 2000, our debt amounted to $1.152 billion, or 84% of capital employed, compared to $1.181 billion, or 83% of capital employed, at December 31, 1999. Based on our current level of consolidated indebtedness and prevailing interest rates, our debt service obligations, including optional payments associated with the revolving credit facility, for the 12 months ending September 30, 2001 will be approximately $180 million. We periodically establish uncommitted lines of credit with banks. These agreements generally provide for short-term borrowings at market rates. At September 30, 2000, there were $20.0 million of these agreements in effect, none of which were outstanding. Lease and Royalty Obligations. We lease equipment, land and various other properties under non- cancelable long-term leases expiring at various dates. Minimum payments due during the 12 months ending September 30, 2001, under agreements in effect at September 30, 2000, will be approximately $84 million. Contingencies Reclamation. 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. Reclamation is the restoration of land and environmental conditions of a mining site after the coal is removed. We accrue for the costs of final mine closure and 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 water and waste rock or coal sediment mixtures, eliminating sedimentation and drainage control structures and dismantling or demolishing equipment or buildings used in mining operations. We also accrue 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 other ongoing reclamation liabilities are based upon permit requirements and require various estimates and assumptions, principally associated with costs and productivities. We review our entire environmental liability periodically and make necessary adjustments, including permit changes and revisions to costs and productivities to reflect current experience. These adjustments are recorded to cost of coal sales. Adjustments included a decrease in the liability of $9.2 million in the nine months ended September 30, 2000. The adjustments occurred principally as a result of recent permit revisions at our idle mine properties in Illinois. Adjustments recorded in the nine months ended September 30, 1999 resulted in a $0.7 million charge to expense. We believe that we are making adequate provisions for all expected reclamation and other associated costs. 28
Legal Contingencies. We are a party to numerous claims and lawsuits with respect to various matters. We provide for costs related to contingencies, including environmental matters, when a loss is probable and the amount is reasonably determinable. We estimate that our probable aggregate loss as a result of claims as of September 30, 2000 is $4.0 million, which amount is included in other noncurrent liabilities on our balance sheet. This amount does not include losses that may be incurred as a result of the temporary or permanent shutdown of the Dal-Tex operations. For a discussion of this litigation, see "Business--Legal Proceedings--Dal-Tex Litigation". We estimate that our reasonably possible aggregate losses from all material litigation that is currently pending could be as much as $0.5 million on a pre-tax basis in excess of the probable loss previously recognized. After conferring with counsel, we believe that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity. For a more complete discussion of litigation to which we are a party, see "Business--Legal Proceedings." 29
BUSINESS We are one of the largest coal producers in the United States. We mine, process and market compliance and low-sulfur coal from mines located in both the eastern and western United States, enabling us to ship coal cost- effectively to most of the major domestic coal-fired electric generation facilities. As of December 31, 1999, we controlled approximately 3.5 billion tons of measured and indicated recoverable coal reserves, approximately 2.0 billion tons of which were assigned reserves and approximately 1.5 billion tons of which were unassigned reserves. On September 30, 2000, we had 28 operating surface, underground and other mines. We sold 111.2 million tons of coal in 1999 and 79.4 million tons of coal during the nine months ended September 30, 2000. Substantially all of our coal is sold as steam coal to producers of electric power. Operations As of September 30, 2000, we operated a total of 28 mines, all located in the United States. Coal is transported from our mining complexes to customers by railroad cars, river barges and trucks. As is customary in the industry, virtually all of our 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 tables set forth the location of and a summary of information regarding our principal mining complexes and the recoverable coal reserves associated with these operations. Captive Contract Mining Mining Complex (Location) Mines* Mines* Equipment(1) Transportation - -------------------------- ------- -------- ------------ -------------- Central Appalachia Mingo Logan (WV)................... U U(4), S L, LW, C NS Coal-Mac (KY)(5)................... S S L CSX Dal-Tex (WV)(6).................... -- -- D, L, S CSX Hobet 21 (WV)...................... S, U U D, L, S(7) CSX Arch of West Virginia (WV)......... S, U -- D, L, S(8) CSX Samples (WV)....................... S -- D, L, S(9) Barge, CSX Campbells Creek (WV)............... -- U(2) -- Barge Lone Mountain (KY)................. U(2) -- C NS Pardee (VA)........................ S, U U L,C NS Western United States Black Thunder (WY)................. S -- D, S(10) UP, BN Coal Creek (WY)(11)................ -- -- -- UP, BN West Elk (CO)(12).................. U -- LW, C UP Skyline (UT)(13)................... U -- LW, C UP SUFCO (UT)(13)..................... U -- LW, C UP Dugout Canyon (UT)(13)............. U -- C(14) UP Arch of Wyoming (WY)............... S(2) -- D, S(15) UP Midwestern United States Arch of Illinois (IL)(16).......... -- -- C UP, IC S = Surface Mine D = Dragline UP = Union Pacific Railroad U = Underground Mine L = Loader/Truck IC = Illinois Central Railroad S = Shovel/Truck BN = Burlington Northern Railroad LW = Longwall NS = Norfolk Southern Railroad C = Continuous Miner CSX = CSX Railroad 30
Tons Total Tons Produced in Produced in Cost(4)/ Assigned --------------------- the Nine Book Value Recoverable 1997(2) 1998(3) 1999 Months Ended As of Reserves Proven Probable ------- ------- ----- September 30, 2000 December 31, 1999 ----------- ------- -------- Mining Complex (Location) (in millions) (in millions) ($ in millions) (tonnage in millions) -------------------------- --------------------- ------------------ ----------------- ---------------------------- Central Appalachia Mingo Logan (WV)........ 4.7 11.0 12.2 8.1 $133/67 22.4 11.0 11.4 Coal-Mac (KY)(5)........ 0.8 1.5 1.0 -- 14/4 5.9 3.2 2.7 Dal-Tex (WV)(6)......... 2.5 4.6 2.3 -- 10/3 84.2 69.8 14.4 Hobet 21 (WV)........... 2.0 4.1 5.1 4.2 45/31 88.9 84.6 4.3 Arch of West Virginia (WV)................... 4.9 5.5 4.7 2.7 120/25 19.6 19.6 -- Samples (WV)............ 4.4 4.9 5.9 4.8 115/48 27.5 27.5 -- Campbells Creek (WV).... 0.8 0.9 1.2 1.0 3/1 11.6 11.6 -- Lone Mountain (KY)...... 2.0 2.4 2.3 1.7 85/36 60.6 55.1 5.5 Pardee (VA)............. 2.5 1.4 1.7 1.3 34/11 9.3 5.6 3.7 Arch of Kentucky (KY)... 3.9 -- -- -- -- Western United States Black Thunder (WY)...... -- 24.7 50.9 44.7 226/203 1,052.5 1,028.2 24.3 Coal Creek (WY)(11)..... -- 4.4 11.4 4.2 41/37 238.6 238.6 -- West Elk (CO)(12)....... -- 3.9 7.3 1.8 96/71 141.3 118.0 23.3 Skyline (UT)(13)........ -- 2.4 3.8 2.2 N/A 79.6 79.6 -- SUFCO (UT)(13).......... -- 3.7 5.8 4.3 N/A 117.9 50.5 67.4 Dugout Canyon (UT)(13).. -- 0.2 0.8 0.4 N/A 34.1 28.3 5.8 Arch of Wyoming (WY).... 2.2 1.3 1.0 0.6 58/4 0.4 0.4 -- Midwestern United States Arch of Illinois (IL)(16)............... 4.9 3.5 2.4 -- 107/3 20.0 20.0 -- ---- ---- ----- ---- ------- ------- ----- Total................. 35.6 80.4 119.8 82.0 2,014.4 1,851.6 162.8 - -------- * Amounts in parenthesis indicate the number of captive and contract mines at the mining complex or location. Captive mines are mines which we own and operate on land owned or leased by us. Contract mines are mines which other operators mine for us under contracts on land owned or leased by us. (1) Reported for captive operations only. (2) Represents six months production for the mines acquired in the Ashland Coal transaction, including Mingo Logan, Hobet 21, Dal-Tex and Coal-Mac. (3) Represents seven months production for the mines acquired in the Arch Western transaction, including Black Thunder, Coal Creek, West Elk, Skyline, SUFCO and Dugout Canyon. Skyline, SUFCO and Dugout Canyon are mines operated by Canyon Fuel; production represents 100% for these facilities. (4) Reflects the cost of plant and equipment, including purchase accounting adjustments. (5) We idled the two captive mining operations at our Coal-Mac (KY) complex on January 3, 2000 because of the small surface mines' high cost structure compared to our larger mines. (6) We idled our mining operations at the Dal-Tex complex on July 23, 1999 due to a delay in obtaining mining permits resulting from legal action in the U.S. District Court for the Southern District of West Virginia. See "Legal Proceedings--Dal-Tex Litigation" for further discussion regarding this legal action. (7) 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. (8) Utilizes a 49-cubic-yard dragline, a 43-cubic-yard shovel, a 22-cubic-yard shovel and a 28-cubic-yard loader at the Ruffner Mine. (9) Utilizes a 118-cubic-yard dragline, two 53-cubic-yard shovels, a 22-cubic- yard hydraulic excavator, three 28-cubic-yard loaders, and one 23 cubic yard loader. (10) Utilizes 170-cubic-yard, 130-cubic-yard, 90-cubic-yard and 45-cubic-yard draglines and 82-cubic-yard, 60-cubic-yard and 53-cubic-yard shovels. (11) We idled our mining operations at Coal Creek during the third quarter of 2000 because its cost structure was not competitive in the current market environment. (12) We temporarily idled our mining operations at West Elk from January 28, 2000 to July 12, 2000 following the detection of higher than normal levels of carbon monoxide in a portion of the mine. 31
(13) Mines are operated by Canyon Fuel. Canyon Fuel is an equity investment and its financial statements are not consolidated into our financial statements. (14) Currently under development, full production projected to begin with the addition of a longwall when market conditions warrant. (15) Utilizes 76-cubic-yard and 64-cubic-yard draglines at Medicine Bow and a 32-cubic-yard dragline at Seminoe II. (16) We idled our remaining operations at the Arch of Illinois mining complex and sealed the underground mine in December 1999 due to a lack of demand for the mine's high-sulfur coal. The mining complex was the last of our mining operations in the Midwestern United States. Coal Reserves We estimate that we owned or controlled, as of December 31, 1999, approximately 3.5 billion tons of measured and indicated recoverable reserves, approximately 2.0 billion tons of which were assigned reserves and approximately 1.5 billion tons of which were unassigned reserves. Assigned reserves are recoverable coal reserves that have been designated to be mined by a specific operation. Unassigned reserves are recoverable reserves that have not yet been designated for mining by a specific operation. 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 our 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 table presents our estimated recoverable coal reserves at December 31, 1999: Total Recoverable Reserves (tonnage in millions) Sulfur Content (lbs. per million Reserve Total Btus) Control Mining Method Recoverable ------------------ ------------ ------------------- Reserves Proven Probable -1.2 1.2-2.5 +2.5 Owned Leased Underground Surface ----------- ------ -------- ----- ------- ---- ----- ------ ----------- ------- Wyoming................. 1,455 1,431 24 1,455 -- -- 150 1,305 134 1,321 Central Appalachia...... 1,332 914 418 568 708 56 513 819 604 728 Illinois................ 299 218 81 -- 9 290 249 50 270 29 Utah*................... 233 159 74 233 -- -- 8 225 233 -- Colorado................ 141 118 23 141 -- -- 3 138 141 -- ----- ----- --- ----- --- --- --- ----- ----- ----- Total................. 3,460 2,840 620 2,397 717 346 923 2,537 1,382 2,078 ===== ===== === ===== === === === ===== ===== ===== Assigned Recoverable Reserves (tonnage in millions) Sulfur Content Total (lbs. per million Reserve Assigned Btus) Control Mining Method Recoverable ------------------ ------------ ------------------- Reserves Proven Probable -1.2 1.2-2.5 +2.5 Owned Leased Underground Surface ----------- ------ -------- ----- ------- ---- ----- ------ ----------- ------- Wyoming................. 1,291 1,267 24 1,291 -- -- -- 1,291 -- 1,291 Central Appalachia...... 330 288 42 177 148 5 103 227 146 184 Illinois................ 20 20 -- -- -- 20 20 -- 20 -- Utah*................... 232 159 73 232 -- -- 7 225 232 -- Colorado................ 141 118 23 141 -- -- 2 139 141 -- ----- ----- --- ----- --- --- --- ----- --- ----- Total................. 2,014 1,852 162 1,841 148 25 132 1,882 539 1,475 ===== ===== === ===== === === === ===== === ===== - -------- * Represents 100% of the reserves held by Canyon Fuel, in which we have a 65% interest. 32
Unassigned Recoverable Reserves (tonnage in millions) Sulfur Content Total (lbs. per million Reserve Unassigned Btus) Control Mining Method Recoverable ----------------- ------------ ------------------- Reserves Proven Probable -1.2 1.2-2.5 +2.5 Owned Leased Underground Surface ----------- ------ -------- ---- ------- ---- ----- ------ ----------- ------- Wyoming................. 163 163 -- 163 -- -- 150 13 134 29 Central Appalachia...... 1,002 626 376 392 560 50 410 592 458 544 Illinois................ 279 198 81 -- 9 270 229 50 250 29 Utah*................... 1 1 -- 1 -- -- 1 -- 1 -- Colorado................ -- -- -- -- -- -- -- -- -- -- ----- --- --- --- --- --- --- --- --- --- Total................. 1,445 988 457 556 569 320 790 655 843 602 ===== === === === === === === === === === - -------- * Represents 100% of the reserves held by Canyon Fuel, in which we have a 65% interest. Over 98% of our recoverable reserves consists of steam coal, which is coal used in steam boilers to make electricity. Less than 2% of our 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 our operations. Approximately 92,201 acres of our 664,000 acres of coal land as of December 31, 1999, which includes 100% of the acreage held by Canyon Fuel, are leased from the federal government under leases with terms expiring between 2001 and 2019, subject to readjustment or extension and to earlier termination for failure to meet diligent development requirements. We have entered into leases covering substantially all of our leased reserves which are not scheduled to expire prior to expiration of projected mining activities. We also control, through ownership or long-term leases, approximately 5,880 acres of land which are used either for our coal processing facilities or are being held for possible future development. Royalties are paid to lessors either as a fixed price per ton or as a percentage of the gross sales price of the mined coal. We pay percentage-based royalties under the majority of our 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. We must obtain permits from applicable state regulatory authorities before we begin to mine 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. We are required to post bonds to secure our performance under our permits. We generally begin preparing applications for permits for areas that we intend 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. We idled our Dal-Tex operation in West Virginia in June 1999 due to a delay in obtaining mining permits for mines involving the use of valley fill mining techniques as a result of litigation. See "Legal Proceedings--Dal-Tex Litigation." Our reported coal reserves are those that could be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, our 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 for litigation described under "Legal Proceedings" with respect to permits to conduct mining operations involving valley fills (which remains unresolved but has been taken into account in determining our reserves), we are not currently aware of matters which would significantly hinder our ability to obtain future mining permits with respect to our reserves. 33
Sales and Marketing We sell coal both under long-term contracts, the terms of which are greater than 12 months, and on a current market, or spot, basis. When our coal sales contracts expire or are terminated, we are 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 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 our 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 our 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. A factor that may impact our sale of coal in the future is the development of coal commodity trading. The New York Mercantile Exchange initiated electricity commodity trading a few years ago and has developed standards for a coal contract. The Exchange has announced that it intends to initiate coal contract trading based on a Huntington, West Virginia barge loading hub. However, the Exchange has not yet initiated trading. The development of standards to determine pricing has been difficult because of the non-homogeneous character of coal and diversity in mining locations, conditions and operations. Nonetheless, in anticipation of commodity trading, some brokerage and marketing firms have entered the coal markets and devised transactions that mimic commodity activity. Today, limited, but growing, over- the-counter trading is being conducted on both firm-forward transactions as well as put, call and other options. The trend to more commodity-type transactions could mark a significant change in how coal is sold. We are unable to predict whether this trend will have a material effect on us and whether any such effect would be positive or negative on our 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 we operate. We compete with approximately six major coal producers in each of the Central Appalachian and Powder River Basin areas. We also compete with a number of smaller producers in those and our other market regions. Excess industry capacity, which has occurred in the past, tends to result in reduced prices for our coal. 34
The most important factors on which we compete are coal price at the mine, coal quality and characteristics, transportation costs from the mine to the customer and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our 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 our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of coal, alternative fuels such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power. Demand for our low- sulfur coal and the prices that we 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. Environmental Regulations Federal, state and local governmental authorities regulate the coal mining industry on matters as diverse as air quality standards, water pollution, groundwater quality and availability, plant and wildlife protection, the reclamation and restoration of mining properties, the discharge of materials into the environment and surface subsidence from underground mining. These regulations and legislation have had and will continue to have a significant effect on our costs of production and competitive position. New legislation, regulations or orders may be adopted or become effective which may adversely affect our mining operations, our cost structure or the ability of our customers to use coal. For example, new legislation, regulations or orders may require us to incur increased costs or to significantly change our operations. New legislation, regulations or orders may also cause coal to become a less attractive fuel source, resulting in a reduction in coal's share of the market for fuels used to generate electricity. Depending upon the nature and scope of the legislation, regulations or orders, any legislation, regulation or order could significantly increase our costs to mine coal. For examples of environmental regulations which would affect our customers see "The Coal Industry--Clean Air Act". Permitting. Mining companies must obtain numerous permits that impose strict regulations on various environmental and health and safety matters in connection with coal mining. For example, regulations are imposed on the emission of air and water borne pollutants, the manner and sequencing of coal extraction and reclamation, the storage, use and disposal of waste and other substances, some of which may be hazardous, and the construction of fills and impoundments, which are wastewater containment areas. Regulatory authorities have considerable discretion in the timing of permit issuance and both private individuals and the public at large possess rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. For example, we idled our Dal-Tex operation in West Virginia on July 23, 1999 due to a delay in obtaining mining permits which resulted from legal action in the U.S. District Court for the Southern District of West Virginia. See "Legal Proceedings--Dal-Tex Litigation" for a discussion of this legal action. Environmental Legislation. The federal Surface Mining Control and Reclamation Act of 1977 was enacted to regulate surface mining of coal and the surface effects of underground mining. All states in which we operate have similar laws and regulations enacted under SMCRA which regulate surface and deep mining that impose, among other requirements, reclamation and environmental requirements and standards. The federal Clean Water Act affects coal mining operations in two principal ways. First, the United States Army Corps of Engineers issues permits under Section 404 of the Clean Water Act whenever a mine operator proposes to build a fill or impoundment in waters of the United States. In addition, the EPA must approve the issuance by a state agency of permits that allow the discharge of pollutants into water bodies under 35
Section 402 of the Clean Water Act. These permits encompass storm water discharges from a mine facility. Regular monitoring and compliance with reporting requirements and performance standards are preconditions for the issuance and renewal of these permits. All states in which we operate also have laws restricting discharge of pollutants into the waters of those states. The federal Resource Conservation and Recovery Act and implementing federal regulations exclude from the definition of hazardous waste all coal extraction, beneficiation and processing wastes. Additionally, other coal mining wastes which are subject to a SMCRA permit are exempt from RCRA permits and standards. Each of the states in which we are currently engaged in mining similarly exempt coal mining waste from their respective state hazardous waste laws and regulations. The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act, affects coal mining operations by subjecting them to liability for the remediation of releases of hazardous substances, other than waste excluded from federal and state regulation, as noted above, that may endanger public health or welfare or the environment. The federal Clean Air Act imposes numerous requirements on various categories of emission sources, and West Virginia state air regulations impose permitting obligations and performance standards on coal preparation plants and coal handling facilities. The use of explosives in surface mining causes nitrogen oxides, or "NOx", to be emitted into the air. The emissions of NOx from the use of explosives at surface mines in the Powder River Basin is gaining increased scrutiny from regulatory agencies and the public. We have taken steps to monitor the level of NOx emitted during blasting activities at our surface mines in the Powder River Basin and are continuing efforts to find a method of reducing these NOx emissions. Any increase in the regulation of NOx emissions from blasting activities could have an adverse effect on our Powder River Basin surface mines. Depending upon the nature and scope of any such regulations, the effect on the mines could be material. On December 11, 1997, United States government representatives at the climate change negotiations in Kyoto, Japan, agreed to reduce the emissions of greenhouse gas in the United States, including carbon dioxide and other gas emissions that are believed to be trapping heat in the atmosphere and warming the earth's climate. The adoption of the requirements of the Kyoto protocol by the United States is subject to conditions which may not occur, and are also subject to the protocol's ratification by the United States Senate. The United States Senate has indicated that it will not ratify an agreement unless specified conditions, not currently provided for in the Kyoto protocol, are met. At present, it is not possible to predict whether the Kyoto protocol will attain the force of law in the United States or what its impact would be on us. Further developments in connection with the Kyoto protocol could increase our costs to mine coal. Employees As of September 30, 2000, we employed a total of 3,361 persons, 558 of whom were represented by the UMWA under a collective bargaining agreement that expires in 2002 and 143 of whom are represented by the Scotia Employees Association under a collective bargaining agreement that expires in 2003. Legal Proceedings Dal-Tex Litigation. On July 16, 1998, ten individuals and The West Virginia Highlands Conservancy filed suit in the U.S. District Court for the Southern District of West Virginia against the director of the West Virginia DEP and officials of the U.S. Army Corps of Engineers alleging violations of SMCRA, the Clean Water Act and the National Environmental Policy Act. Specifically, plaintiffs made the following allegations in the suit: . the Corps violated NEPA by approving mining permits without the preparation of an EIS under NEPA that would evaluate the environmental effects of mountaintop mining and the construction of valley fills; 36
. the Corps violated the Clean Water Act by issuing generic Section 404 dredge and fill permits rather than site-specific individual permits; . the West Virginia DEP has failed to require the restoration of mined lands to approximate original contour and that it has not enforced approved post-mining land uses following reclamation; and . the West Virginia DEP lacked authority to issue permits for the construction of valley fills. Nine of our permits were identified in the complaint as violating the legal standards that the plaintiffs requested the court to interpret. In addition, pending permit applications for our Dal-Tex mining operations, which are operated by our subsidiary, Hobet Mining, Inc., were specifically identified as permits that should be enjoined from issuance. These permit applications, known as the Spruce Fork permits, include a SMCRA mining permit application requesting authorization from the West Virginia DEP to commence surface mining operations and a Section 404 permit application requesting authorization from the Corps to construct a valley fill. We intervened in the lawsuit in support of the Corps and the West Virginia DEP on August 6, 1998. Settlement Agreement. A settlement between the plaintiffs and the Corps, which was reached on December 23, 1998, resolved the Clean Water Act and NEPA claims against the Corps, except those relating to the Spruce Fork permits. The settlement agreement requires the Corps, in cooperation with other agencies, to prepare a programmatic EIS on the effects of valley fills on streams and the environment. This EIS was scheduled to be completed by January 2001. This date, however, was not met and there has been no indication from the Corps as to when the EIS will be completed. Until it is completed, an individual Clean Water Act Section 404 dredge and fill permit must be obtained prior to the construction of any valley fill greater than 250 acres. Our Hobet Mining subsidiary later agreed to apply for an individual Section 404 permit for the Dal-Tex valley fill, which will require the preparation of an EIS to evaluate the effects of the valley fill on the environment. Preliminary Injunction. Subsequent to the settlement agreement, the West Virginia DEP approved the Spruce Fork SMCRA permit. Plaintiffs sought a preliminary injunction staying the Spruce Fork permit and enjoining us from future operations on the permit until a full trial on the merits could be held. The district court issued the preliminary injunction on March 3, 1999. As a result, we idled the Dal-Tex mine on July 23, 1999. Consent Decree. On July 26, 1999, the plaintiffs and the West Virginia DEP submitted a proposed consent decree which would resolve the remaining issues in the case, except those relating to the West Virginia DEP's authority to issue permits for the construction of valley fills. Under the proposed consent decree, the West Virginia DEP agreed in principle to amend its regulations and procedures to correct alleged deficiencies. In addition, the parties agreed in principle on a new definition of approximate original contour as it applies to mountaintop mining, as well as to regulatory changes involving post-mining land uses. Our Hobet Mining subsidiary agreed as part of the consent decree to revise portions of its Spruce Fork permit applications to conform to the new definition of approximate original contour to be adopted by the West Virginia DEP. After inviting public comment on the proposed consent decree, the court entered the consent decree in a final order on February 17, 2000, and the West Virginia legislature approved the West Virginia DEP's proposed statutory and regulatory changes to implement the consent decree on April 3, 2000. Permanent Injunction. On October 20, 1999, the district court addressed the remaining counts in the plaintiffs' complaint by issuing a permanent injunction against the West Virginia DEP enjoining the issuance of any new permits that authorize the construction of valley fills as part of mining operations. The West Virginia DEP complied with the injunction by issuing an order banning the issuance of permits for nearly all new valley fills and the expansion of existing valley fills. The West Virginia DEP also filed an appeal of the district court's decision with the U.S. Court of Appeals for the Fourth Circuit. On October 29, 1999, the district court granted a stay of its decision, pending the outcome of the appeal. The West Virginia DEP rescinded its administrative order on November 1, 1999 in response to the district court's action. 37
The U.S. Court of Appeals for the 4th Circuit heard oral arguments in this case on December 7, 2000 and is expected to render an opinion in the first half of 2001. We cannot predict the outcome of the West Virginia DEP's appeal. If the district court's decision is upheld, we, and other coal producers, may be forced to close all or a portion of our mining operations in West Virginia, to the extent those operations are dependent on the use of valley fills. If we are successful on appeal, then we could be required to complete the EIS for the Section 404 dredge and fill permit and comply with the conditions imposed on the Spruce Fork permit as a result of the consent decree, each of which could delay the issuance of the Spruce Fork permit and, consequently, the reopening of the mine until mid-2001 at the earliest. If all necessary permits are issued, we may determine to reopen the mine subject to then-existing market conditions. Cumulative Hydrologic Impact Assessment Litigation. On January 20, 2000, two environmental organizations, the Ohio Valley Environmental Coalition and the Hominy Creek Watershed Association, filed suit against the West Virginia DEP in the U.S. District Court in Huntington, West Virginia. In addition to allegations that the West Virginia DEP violated state law and provisions of the Clean Water Act, the plaintiffs allege that the West Virginia DEP's issuance of permits for surface and underground coal mining has violated non-discretionary duties mandated by SMCRA. Specifically, the plaintiffs allege that the West Virginia DEP has failed to require coal operators seeking permits to conduct water monitoring to verify stream flows and ascertain water quality, to always include specified water quality information in their permit applications and to analyze the probable hydrologic consequences of their operations. The plaintiffs also allege that the West Virginia DEP has failed to analyze the cumulative hydrologic impact of mining operations on specific watersheds. The plaintiffs seek an injunction to prohibit the West Virginia DEP from issuing any new permits which fail to comply with all of the elements identified in their complaint. The complaint identifies, and seeks to enjoin, three pending permits that are sought by our Mingo Logan subsidiary to continue existing surface mining operations at the Phoenix reserve. On January 15, 2001, the West Virginia DEP notified the plaintiffs that we have completed all steps necessary to obtain the permits. A hearing was held on February 14, 2001 on the plaintiffs' motion for a preliminary injunction seeking to enjoin the DEP's decision to issue the permits. If the permits are not issued, it is possible that those operations will have to be suspended in early 2001. We cannot predict whether this litigation will result in a suspension of the affected surface mining operations. If, however, the operations are suspended, our ability to mine surface coal at Mingo Logan could be adversely affected and, depending upon the length of suspension, the effect could be material. Lone Mountain Litigation. On October 24, 1996, the rock strata overlaying an abandoned underground mine adjacent to the coal-refuse impoundment used by the Lone Mountain preparation plant failed, resulting in the discharge of approximately 6.3 million gallons of water mixed with fine coal refuse into a tributary of the Powell River in Lee County, Virginia. The U.S. Department of the Interior has notified us that it intends to file a civil action under the Clean Water Act and the Comprehensive Environmental Response, Compensation and Liability Act to recover the natural resource damages suffered as a result of the discharge. The Interior Department alleges that fresh water mussels listed on the federal endangered species list that reside in the Powell River were affected as a consequence of the discharge. We and the Interior Department have reached an agreement in principle to settle this matter, which would require us to make a payment of $2.5 million. The settlement is subject to us and the Interior Department entering into a definitive agreement. The Interior Department initiated the final administrative steps to complete settlement of this claim, and, following a period of public comment, we expect to make the settlement payment in February 2001. Our consolidated balance sheet as of September 30, 2000 reflects a reserve for the full amount of this settlement. 38
THE COAL INDUSTRY United States Coal Markets Production of coal in the United States has increased from 434 million tons in 1960 to over 1 billion tons in 1999. The following table sets forth demand trends for United States coal by consuming sector through 2020 as compiled, estimated(e) or forecasted(f) by the United States Department of Energy/Energy Information Agency. Annual Growth 1998- Consumption by Sector 1997 1998 1999e 2005f 2010f 2015f 2020f 2020f - --------------------- ----- ----- ----- ----- ----- ----- ----- ------ (tons in millions) Electric Generation........... 922 939 940 1,070 1,092 1,129 1,177 1.0% Industrial.................... 71 69 66 73 73 74 75 0.4% Steel Production.............. 30 28 28 26 23 21 20 (1.6%) Residential/Commercial........ 6 6 5 7 7 7 7 0.4% Export........................ 84 78 58 62 64 57 58 (1.4%) ----- ----- ----- ----- ----- ----- ----- Total....................... 1,113 1,120 1,097 1,238 1,259 1,288 1,337 0.9% ===== ===== ===== ===== ===== ===== ===== Electricity Generation Coal has consistently maintained a 50% 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. On an average, all-in cost per megawatt-hour basis, coal-fired generation is substantially less expensive than electricity generated utilizing natural gas, oil or nuclear power. Hydroelectric power is inexpensive but is limited geographically, and there are few suitable sites for new hydroelectric power dams. Consequently, approximately 86% of the coal produced in the United States in 1999 was sold in the domestic market as a fuel to the electric generation segment. The remainder of the tons were sold in 1999 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 alternative 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. 39
According to the Energy Information Agency, coal is expected to remain the primary fuel for electricity generation through 2020. The following table sets forth the source fuel for electricity generation from 1990 through 2020 as compiled, estimated(e) or forecasted(f) by the Energy Information Agency. 1990 1995 1999e 2000f 2005f 2010f 2015f 2020f ----- ----- ----- ----- ----- ----- ----- ----- (billion kilowatt hours) Coal............................ 1,590 1,710 1,882 1,931 2,127 2,172 2,251 2,347 Petroleum....................... 124 75 119 90 68 54 47 44 Natural Gas..................... 378 499 556 601 717 1,001 1,297 1,476 Nuclear......................... 577 673 728 688 674 627 511 427 Hydro/Renewable/other........... 356 401 407 402 425 443 451 462 ----- ----- ----- ----- ----- ----- ----- ----- Total......................... 3,025 3,358 3,691 3,712 4,011 4,297 4,557 4,756 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 2020. The table contains two data-sets. The top data-set is derived from the Energy Information Agency's Long-Term forecast published in December 1999 and is presented in 1998 dollars. The lower data-set is derived from the Energy Information Agency's Short-Term outlook published in August 2000. The expected prices for petroleum fuel-oil and natural gas for 2001 are considerably above the forecasted prices published less than a year ago, which highlights the pricing volatility of petroleum and natural gas compared to coal. 1997 1998 1999e 2000f 2001f 2005f 2010f 2015f 2020f ------------------- ----- ----- ----- ----- ----- ----- (dollars per million Btus) Annual Energy Outlook (December 1999) Petrol (Residual).......... $ 2.92 $2.17 $2.55 $3.21 $3.04 $3.11 $3.13 $3.19 $3.30 Natural Gas................ 2.73 2.34 2.48 2.59 2.59 2.79 3.08 3.21 3.33 Coal....................... 1.28 1.25 1.26 1.24 1.19 1.11 1.07 1.03 0.98 Short-Term Energy Outlook (August 2000) Petrol (Residual).......... $2.39 $4.09 $3.39 Natural Gas................ 2.57 3.70 3.66 Coal....................... 1.22 1.21 1.22 Coal Production United States coal production was over one billion tons in 1999. The following table, derived from data prepared by the Energy Information Agency, sets forth principal United States production statistics for the periods indicated. 40
1980 1985 1990 1995 1998 1999 ------- ------- ------ ------ ------ ------ Total Tons (in millions).... 820 884 1,026 1,033 1,118 1,093 Percent of Total Tons East...................... 69% 63% 61% 53% 51% 48% West...................... 31 37 39 47 49 52 Underground............... 40 40 41 38 37 36 Surface................... 60 60 59 62 63 64 Number of Mines Underground............... 1,875 1,695 1,422 977 827 753 Surface................... 1,997 1,660 1,285 1,127 899 870 ------- ------- ------ ------ ------ ------ Total..................... 3,872 3,355 2,707 2,104 1,726 1,623 Average Number of Mine Employees Underground............... 150,328 107,357 84,154 57,879 49,391 43,325 Surface................... 74,610 61,924 47,152 32,373 37,866 34,352 Average Production per Mine (tons in thousands) Underground............... 175 207 298 406 505 516 Surface................... 246 321 469 565 779 810 Coal Producing Regions Coal is mined from coalfields throughout the United States, with the major production centers located in Central Appalachia, the Southern Powder River Basin, western bituminous coalfields, Northern Appalachia and the Illinois Basin. [Map of major U.S. coal producing regions appears here] 41
Central Appalachia. The Central Appalachia region includes coalfields in eastern Kentucky, southwestern Virginia and central and southern West Virginia. Production in Central Appalachia was 262 million tons in 1999 compared with 278 million tons in 1998. A variety of mining techniques are used in this region as seams are found on mountaintops and below valley floors. The coal from Central Appalachia has an average heat content of 12,500 Btus per pound and generally has low sulfur content. Southern Powder River Basin. The Southern Powder River Basin is located in northeastern Wyoming. Production in the Southern Powder River Basin in 1999 was 317 million tons compared with 297 million tons in 1998. Coal quality in this region averages 8,600 Btus per pound and 0.3% sulfur. Western Bituminous Coal Regions. The western bituminous coal regions include the Hanna and Carbon Basins in Wyoming, the Uinta Basin in northwestern Colorado and Utah, the San Juan Basin in New Mexico and Colorado and the Raton Basin in southern Colorado. Production in the western bituminous coal region in 1999 was 114 million tons, compared with 113 million tons in 1998. These regions produce high quality, low-sulfur steam coal for selected markets in the region, for export through West Coast ports and for shipments to some Midwestern power plants for which the Powder River Basin's subbituminous coals are not suitable. Coal from the western bituminous coal region has a heat content ranging from 9,000 to 11,500 Btus per pound and generally has low sulfur content. Northern Appalachia. Medium- and high-sulfur coal is found in the Northern Appalachia coalfields of western Pennsylvania, southeastern Ohio and northern West Virginia. Production in Northern Appalachia was approximately 141 million tons in 1999 compared with 157 million tons in 1998. The coal from Northern Appalachia has a heat content ranging from 12,500 to 13,000 Btus per pound. Illinois Basin. The Illinois Basin is located under most of Illinois, western Indiana and western Kentucky. Production in the basin was 104 million tons in 1999 and 111 millions tons in 1998. The Illinois Basin is a declining production center due to the region's relatively high-sulfur coal and competition from lower-sulfur western coal. The coal from the Illinois Basin has a heat content ranging from 10,000 to 12,000 Btus per pound and generally has medium to high sulfur content. Coal Characteristics In general, coal of all geological composition is characterized by end use as either steam coal or metallurgical coal. Heat value and sulfur content, the most important variables in the profitable marketing and transportation of coal, determine the best end use of a particular type of coal. We mine, process, market and transport bituminous and subbituminous coal, characteristics of which are described below. Heat Value. The heat value of coal is commonly measured in British thermal units, or "Btus". A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal found in the Eastern and Midwestern regions of the United States tends to have a heat content ranging from 10,000 42
to 13,400 Btus per pound. Most coal found in the western United States ranges from 8,000 to 10,000 Btus per pound. Bituminous coal is a "soft" black coal with a heat content that ranges from 10,500 to 14,000 Btus per pound. This coal is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah, and is the type most commonly used for electric power generation in the United States. Bituminous coal is used for utility and industrial steam purposes, and includes metallurgical coal, a feed stock for coke, which is used in steel production. We produce an insignificant amount of metallurgical coal. Subbituminous coal is a black coal with a heat content that ranges from 7,800 to 9,500 Btus per pound. Most subbituminous reserves are located in Montana, Wyoming, New Mexico, Washington and Alaska. Subbituminous coal is used almost exclusively by electric utilities and some industrial consumers. Sulfur Content. Sulfur content can vary from seam to seam and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Demand for low-sulfur coal has increased, and is expected to continue to increase, as generators of electricity strive to reduce sulfur dioxide emissions to meet requirements of the Clean Air Act. Subbituminous coal typically has a lower sulfur content than bituminous coal, but some bituminous coal in southern West Virginia, eastern Kentucky, Colorado and Utah also has low sulfur content. Higher-sulfur coal can be burned in plants equipped with sulfur-reduction technology, as a scrubbing process reduces sulfur dioxide emissions by 50% to 90%. Plants without scrubbers can burn high-sulfur coal by purchasing emission allowances on the open market, which allow the user to emit a ton of sulfur dioxide. Some older coal-fired plants have been retrofitted with scrubbers. Any new coal-fired generation plant built in the United States will use clean coal- burning technology. Coal Mining Techniques Coal mining operations commonly use four distinct techniques to extract coal from the ground. The most appropriate technique is determined by coal seam characteristics such as location, logistics and recoverable reserve base. Drill hole data are used initially to define the size, depth and quality of the coal reserve area before committing to a specific extraction technique. All coal mining techniques rely heavily on technology; consequently, technological improvements have resulted in increased productivity. A coal mine's yield is defined as the ratio of clean output tonnage to raw material tonnage. The four most common mining techniques are continuous mining, longwall mining, truck and shovel mining and dragline mining. We utilize both continuous and longwall mining techniques in our underground mining operations and either truck and shovel or dragline techniques in our surface mining operations, depending on the characteristics of the mine. Continuous Mining. Continuous mining is one of two underground mining methods used in the United States. Main airways and transportation entries are evacuated and remote-controlled continuous miners extract coal from so-called rooms, leaving pillars to support the roof, by removing coal from the seam. Shuttle cars are used to transport coal to the conveyor belt for transport to the surface. This method is often used to mine smaller coal blocks or thin seams, and seam recovery is typically approximately 50%. Productivity for continuous mining averages 25 to 50 tons per manshift. Longwall Mining. Longwall mining is one of two underground mining methods used in the United States. A rotating drum is pulled mechanically across the face of coal and a hydraulic system supports the roof of the mine while 43
it advances through the coal. Chain belts then move the loosened coal to a standard underground mine conveyor system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal which are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive, but is effective only for large blocks of medium to thick coal seams. High capital costs associated with longwall mining demand a large, contiguous reserve base. Seam recovery using longwall mining is typically 70% and productivity averages 48 to 80 tons per manshift. Truck and Shovel Mining. Truck and shovel mining is an open-cast method which uses large, electric-powered shovels to remove earth and rock covering a coal seam, or overburden, which is used to refill pits after the coal is removed. Shovels load coal in haul trucks for transportation to the preparation plant or rail loadout. Seam recovery using the truck and shovel method is typically 90%. Productivity depends on equipment, geological composition and mining ratios and varies between 250 to 400 tons per manshift in the Powder River Basin and 30 to 80 tons per manshift in Eastern regions of the United States. Dragline Mining. Dragline mining is an open-cast method which uses large capacity electric-powered draglines, which are large buckets suspended from the end of a long boom, to remove overburden to expose the coal seams. Shovels load coal in haul trucks for transportation to the preparation plant and then to the rail loadout. Truck capacity can range from 80 to 300 tons per load. Seam recovery using the dragline method is typically 90% or more and productivity levels are similar to those for truck and shovel mining. Once the raw coal is mined, it is often crushed, sized and washed in preparation plants where the product consistency and heat content are improved. This process involves crushing the coal to the required size, removing impurities and, where necessary, blending with other coal to match customer specification. Coal Costs Coal costs vary dramatically and are affected by a number of factors. Two general characteristics are particularly important. First, coal costs vary widely depending upon the region in which the coal is produced. Second, utility purchases of coal, in which both mine-mouth coal costs and transportation costs are considered, strongly influence other coal costs. Other factors that influence coal costs are geological characteristics such as seam thickness, overburden ratios and depth of underground reserves, transportation costs, regional coal production capacity relative to demand and coal quality characteristics such as heat value, ash, moisture and sulfur content, royalty payments and severance taxes. Powder River Basin coal is relatively inexpensive to mine because the seams are thick and typically close to the surface. As a result, open-cast mining methods are used. The large capital costs associated with dragline mining and truck and shovel mining are amortized over millions of tons of coal produced. Powder River Basin mines are highly productive and labor is a much smaller component of the cost structure. Eastern coal is more expensive to mine than western coal because it has a high percentage of underground coal and its surface coal tends to have thinner coal seams. Clean Air Act A major regulatory development affecting the coal industry is Title IV of the Clean Air Act Amendments, enacted in 1990. The amendments have had, and will continue to have, a significant effect on the domestic coal industry. In general, Phase I, which became effective in 1995, regulates the level of emissions of sulfur dioxide from power plants and targets the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, extended the restrictions of the amendments to all power plants of greater than 75 megawatt capacity. The amendments do not define allowable emission levels on a per plant basis, but instead allocate emission allowances to the affected plants and allow the emission allowances to be traded so that market participants can fashion more efficient and flexible compliance strategies. The emission allowance allocations for Phase I units 44
were based on 2.5 pounds of sulfur dioxide per million Btus and Phase II allocations are based on 1.2 pounds of sulfur dioxide per million Btus. These and other restrictions on sulfur dioxide emissions have increased the demand for low-sulfur coal and decreased the demand for high-sulfur coal. Several other developments under the Clean Air Act may affect our customers' demand for coal as a fuel source. For example, in July 1997, the Environmental Protection Agency proposed that 22 eastern states, including states in which many of our customers are located, make substantial reductions in NOx emissions. The EPA expects the states to achieve these reductions by requiring power plants to reduce their nitrous oxide emissions to a level of 0.15 pounds of nitrous oxide per million Btus of energy consumed. Many of the states sued the EPA in the U.S. Court of Appeals for the District of Columbia Circuit to challenge the new standard. In June 2000, the court upheld the standard, but did not determine the timeframe within which the standard must be implemented. To achieve these reductions, power plants may be required to install reasonably available control technology and additional control measures. The installation of these measures would make it more costly to operate coal-fired utility power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. The EPA is also proposing to implement stricter ozone standards by 2003. The U.S. Court of Appeals for the District of Columbia Circuit has, however, enjoined the EPA from implementing the new ozone standards on constitutional and other legal grounds. The U.S. Supreme Court has agreed to review the lower court's decision. It is impossible to predict the outcome of this legal action. If the EPA is successful on appeal, then the implementation of the standards could require some of our customers to reduce NOx emissions, which is a precursor to ozone formation, or even prevent the construction of new facilities that contribute to the non-attainment of the new ozone standard. The U.S. Department of Justice, on behalf of the EPA, has filed a lawsuit against seven investor-owned utilities and brought an administrative action against one government-owned utility for alleged violations of the Clean Air Act. The EPA claims that over 30 of these utilities' power stations have failed to obtain permits required under the Clean Air Act for major improvements which have extended the useful service of the stations or increased their generating capacity. We supply coal to seven of the eight utilities. It is impossible to predict the outcome of this legal action. Any outcome that adversely affects our customers or makes coal a less attractive fuel source could, however, adversely affect our coal sales, revenues and profitability. Health and Safety Matters The Federal Mine Safety and Health Act of 1977 imposes health and safety standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, and the equipment used in mining operations. The Black Lung Benefits Reform Act of 1977 generally requires each coal mine operator to secure payment of federal and state black lung benefits to its employees through insurance, bonds, or contributions to a state-controlled fund. This Act also provides for the payment from a trust fund of benefits and medical expenses to employees for whom no benefits have been obtainable from their employer. This trust is financed by a tax on coal sales. The Coal Industry Retiree Health Benefit Act of 1992 addressed two under- funded trust funds which were created to provide medical benefits for certain UMWA retirees. The Benefit Act provides for the funding of medical and death benefits for certain retired members of the UMWA through premiums to be paid by assigned operators (former employers), transfers of monies in 1993 and 1994 from an overfunded pension trust established for the benefit of retired UMWA members, and transfers from the Abandoned Mine Lands Fund, which is funded by a federal tax on coal production, that commenced in 1995. 45
MANAGEMENT Set forth below is information regarding each of our executive officers and directors. All ages are presented as of January 1, 2001. Name Age Position - ---- --- -------- Steven F. Leer.......... 48 President and Chief Executive Officer and Director Bradley M. Allbritten... 43 Vice President--Human Resources C. Henry Besten, Jr..... 52 Vice President--Strategic Marketing John W. Eaves........... 42 Senior Vice President--Marketing Robert G. Jones......... 44 Vice President--Law & General Counsel Robert J. Messey........ 54 Senior Vice President and Chief Financial Officer Terry L. O'Connor....... 55 Vice President--External Affairs David B. Peugh.......... 46 Vice President--Business Development Robert W. Shanks........ 47 Vice President--Operations Kenneth G. Woodring..... 50 Executive Vice President--Mining Operations James R. Boyd........... 54 Chairman of the Board and Director Philip W. Block......... 53 Director Frank M. Burke, Jr...... 60 Director Ignacio Dominguez Urquijo................ 55 Director Thomas L. Feazell....... 63 Director Robert L. Hintz......... 70 Director Douglas H. Hunt......... 47 Director James L. Parker......... 63 Director A. Michael Perry........ 64 Director Theodore D. Sands....... 55 Director Steven F. Leer has been our President and Chief Executive Officer and a director of our company since 1992. He is also a Director of the Center for Energy and Economic Development, Vice-Chairman of the National Coal Council, and Chairman of the National Mining Association. Bradley M. Allbritten has been our Vice President--Human Resources since March 2000. Mr. Allbritten served as our 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. has been our Vice President--Strategic Marketing and President of our Arch Energy Resources, Inc. subsidiary since July 1997. Mr. Besten also served as our acting Chief Financial Officer from December 1999 through November 2000. Mr. Besten served as Senior Vice President--Marketing for Ashland Coal from 1990 until the Ashland Coal merger in July 1997. John W. Eaves has been our Senior Vice President--Marketing since March 2000. He served as Vice President--Marketing from July 1997 through February 2000. Mr. Eaves has served as President of our Arch Coal Sales Company, Inc. subsidiary since September 1995. Robert G. Jones has been our Vice President--Law & General Counsel since March 2000. Mr. Jones served as our Assistant General Counsel from July 1997 through February 2000 and as Senior Counsel from August 1993 to July 1997. Robert J. Messey has been our Senior Vice President and Chief Financial Officer since December 1, 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 46
financial officer of Sverdrup Corporation from 1992. Mr. Messey was employed with Ernst & Young from June 1967 to December 31, 1992, most recently as an audit partner. Mr. Messey serves on the board of directors of Baldor Electric Company. Terry L. O'Connor has been our Vice President--External Affairs since June 1998. From 1989 to May 1998, he served as Vice President--External Affairs of Atlantic Richfield Company. David B. Peugh has been our Vice President--Business Development since 1993. Robert W. Shanks has been our Vice President--Operations since July 1997. Since April 1999 he has also served as President of Arch Western Resources, LLC. Mr. Shanks was President of Apogee Coal Company, a subsidiary of our company, from July 1995 to July 1997. Kenneth G. Woodring has been our Executive Vice President--Mining Operations since July 1997. Mr. Woodring served as Senior Vice President-- Operations of Ashland Coal from 1989 through July 1997. James R. Boyd, our Chairman of the Board, has been a director of our company since 1990. He has served as Senior Vice President and Group Operating Officer of Ashland Inc., a multi-industry company with operations in chemicals, motor oil and car care products and highway construction, since 1989. Philip W. Block has been a director of our company since 1999 and, since 1992, has been Administrative Vice President of Human Resources of Ashland. Frank M. Burke, Jr. has been a director of our company since September 2000. He has served as Chairman, Chief Executive Officer and Managing General Partner of Burke, Mayborn Company, Ltd., a private investment and consulting company, since 1984. Mr. Burke is also a director of Kaneb Services, Inc., Kaneb Pipe Line Partners, L.P., and Avidyn, Inc. (formerly Medical Control, Inc.). Ignacio Dominguez Urquijo has been a director of our company since 1998 and, since June 1998, has been Chief Executive Officer and Administrator of Carboex, S.A., a fuel trading firm belonging to Endesa Group, the leading Spanish utility company, and Senior Vice President of Endesa Group. Mr. Dominguez was the General Manager of SE.PI, a Spanish government holding group, from July 1996 to June 1998 and served as Director and General Manager for Processing Industries of TENEO, a Spanish government holding group, and its predecessor, I.N.I., from 1992 to July 1996. Thomas L. Feazell has been a director of our company since 1997 and was a director of Ashland Coal from 1981 to 1997. He served as Senior Vice President, General Counsel and Secretary of Ashland from 1992 until his retirement in March 1999. He is a director of National City Bank of Ashland, Kentucky. Robert L. Hintz has been a director of our company since 1997 and, since 1989, has been Chairman of the Board of R. L. Hintz & Associates, a management consulting firm. Mr. Hintz was a director of Ashland Coal from 1993 to 1997. He is a director of Chesapeake Corporation. Douglas H. Hunt has been a director of our company since 1995 and, since May 1995, has served as Director of Acquisitions of Petro-Hunt, L.L.C., a private oil and gas exploration and production company. James L. Parker has been a director of our company since 1995. He served as President of Hunt Petroleum Corporation, a private oil and gas exploration and production company, from 1990 until his retirement in February 2001. Mr. Parker has served as President and director of Hunt Coal Corporation, a subsidiary of Hunt Petroleum Corporation since 1994. 47
A. Michael Perry has been a director of our company since 1998. He has served as Chairman of Bank One, West Virginia, N.A. since 1993 and as its Chief Executive Officer since 1983. Mr. Perry is also a director of Champion Industries, Inc. Theodore D. Sands has been a director of our company since 1999 and, since February 1999, has served as President of HAAS Capital, LLC, a private consulting and investment company. Mr. Sands is also a director of Mosiac Group Inc., Protein Sciences Corporation and Terra Nitrogen Corporation. Mr. Sands served as Managing Director, Investment Banking for the Global Metals/Mining Group of Merrill Lynch & Co. from 1982 until February 1999. 48
SELLING STOCKHOLDER The selling stockholder is Ashland Inc. Ashland is a multi-industry company with operations in chemicals, motor oil and car care products and highway construction. Ashland also owns 38% of Marathon Ashland Petroleum LLC, a petroleum refiner and marketer. As of September 30, 2000, Ashland beneficially owned 4,756,968 shares, or approximately 12.4%, of our outstanding common stock and, after completion of the offering will own no shares of our common stock. Messrs. Philip W. Block, James R. Boyd and Thomas L. Feazell, directors of our company, are current or former executive officers of Ashland. Messrs. Block and Boyd, as current officers of Ashland, may be deemed to be beneficial owners of the shares of our common stock owned by Ashland, although they disclaim any beneficial ownership. Ashland acquired 50% of the shares of Arch Mineral Corporation, our predecessor company, upon its formation in July 1969. In late 1969, in 1973 and in 1977, Ashland acquired additional shares of Arch Mineral common stock, during which time its ownership interest in Arch Mineral fluctuated between approximately 45% and 50%. On July 1, 1997, one of our subsidiaries merged with Ashland Coal. Immediately prior to the merger, Ashland acquired an additional 1% interest in Arch Mineral common stock, so that, immediately prior to the merger, it beneficially owned common stock representing approximately 57% of the voting power of Ashland Coal and approximately 51% of our voting stock. Immediately after the merger, Ashland owned approximately 54% of our outstanding common stock. On June 22, 1999, Ashland announced an interest in exploring strategic alternatives for its then 58% interest in our company. On March 16, 2000, Ashland's board of directors declared a taxable distribution to its stockholders of approximately 17.4 million of its 22.1 million shares of our common stock. On that date, Ashland also announced that it planned to dispose of its remaining approximately 4.7 million shares of our common stock within one year of the distribution, subject to market conditions. Ashland distributed 17.4 million shares of our common stock to its stockholders of record as of March 24, 2000. Ashland is party to a registration rights agreement with us under which this offering is being registered under the Securities Act of 1933. In addition, Ashland may, prior to the sale of shares of our common stock contemplated by this prospectus, sell some of those shares under Rule 144 under the Securities Act. In the ordinary course of business, we receive services and purchase fuel, oil and other products on a competitive basis from affiliates of Ashland, which totaled $2.8 million for the nine months ended September 30, 2000, $4.8 million in 1999, $7.2 million in 1998, and $4.7 million in 1997. We believe that charges between us and Ashland for services and purchases have been transacted on terms equivalent to those prevailing among unaffiliated parties. 49
DESCRIPTION OF CAPITAL STOCK Our certificate of incorporation provides for authorized capital consisting of 100,000,000 shares of common stock, par value $.01 per share, and 10,000,000 shares of preferred stock, par value $.01 per share. Based on shares of Arch common stock outstanding at December 31, 2000, upon completion of the offering, there will be 42,116,219 shares of Arch common stock issued and outstanding. Common Stock Each share of common stock entitles its holder of record to one vote on all matters to be voted on by our stockholders. Subject to the rights of holders of preferred stock, holders of common stock are entitled to share on a pro rata basis in any distribution to stockholders in the event of our liquidation, dissolution or winding up. No holder of common stock has any preemptive right to subscribe for any stock or other security of ours. Preferred Stock Our board of directors, without further action by our stockholders, may from time to time authorize the issuance of shares of preferred stock in one or more series and, within some limitations, fix the powers, preferences and rights and the qualifications, limitations or restrictions thereof and the number of shares constituting any series or designations of such series. We have established, but not issued, a series of junior participating preferred stock in connection with our stockholder rights plan, which is discussed below. Satisfaction of any dividend preferences of outstanding preferred stock would reduce the amount of funds available for the payment of dividends on common stock. Holders of preferred stock would normally be entitled to receive a preference payment in the event of our liquidation, dissolution or winding up before any payment is made to the holders of common stock. In addition, in specified circumstances, the issuance of our preferred stock may render more difficult or tend to discourage our change in control. Although we do not currently have plans to issue shares of preferred stock, our board of directors, without stockholder approval, may issue preferred stock with voting and conversion rights which could adversely affect the rights of holders of shares of common stock. Rights Plan In March 2000 we adopted a stockholder rights plan under which preferred share purchase rights are held by holders of our common stock. The rights are exercisable only if a person or group acquires 20% or more of our common stock 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 our 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 our common stock or voting stock of the acquiring person at a discount. At its option, the board of directors may allow some or all holders (except for the acquiring person) to exchange their rights for our common stock. The rights will expire on March 20, 2010, subject to our earlier redemption or exchange as described in the plan. Certain Provisions of Our Governing Documents Charter Provision Regarding Issuance of Preferred Stock. Our certificate provides that preferred stock may be issued by the board of directors, provided that the holders of preferred stock will not be entitled to more than the lesser of one vote per $100 of liquidation value or one vote per share, when voting as a class with the holders of shares of other capital stock. Holders of preferred stock will not be entitled to vote on any matter separately as a class, except to the extent required by 50
law or as specified with respect to (a) any amendment or alteration of our charter that would adversely affect the powers, preferences or special rights of the preferred stock or (b) our failure to pay dividends on any series of preferred stock for any six quarterly dividend payment periods, whether or not consecutive. Charter Provisions Affecting Control and Other Transactions. Our certificate requires the affirmative vote of not less than two-thirds of the outstanding shares of common stock voting thereon before we may adopt an agreement or plan of merger or consolidation, authorize the sale, lease or exchange of all or substantially all of our property and assets, authorize our dissolution or the distribution of all or substantially all of our assets to our stockholders or amend certain provisions of our charter, including the authorization of capital stock, the supermajority provisions and the election not to be governed by Section 203 of the Delaware General Corporation Law. Our bylaws permit the amendment or repeal of our bylaws upon the affirmative vote of not less than two-thirds of our board of directors. Charter Provisions Regarding the Number of Directors. Our certificate provides that the number of directors may be established or changed by the affirmative vote of not less than two-thirds of the members of the board of directors but in no event shall the number be less than three. Classification of Board of Directors. Our certificate provides that our board of directors consists of three classes of directors. At each annual meeting of our stockholders, only the election of directors of the class whose term is expiring is voted upon, and upon election each director serves a three-year term. 51
UNITED STATES TAXATION OF NON-U.S. HOLDERS General This section summarizes the material U.S. tax consequences to a holder of common stock that is a "Non-U.S. Holder" (as defined below). However, the discussion is limited in the following ways: . The discussion only relates to you if you hold your common stock as a capital asset (that is, for investment purposes), and if you do not have a special tax status. . The discussion does not relate to tax consequences that depend upon your particular tax situation in addition to your ownership of common stock. We suggest that you consult your tax advisor about the consequences of holding common stock in your particular situation. . The discussion is based on current law. Changes in the law may change the tax treatment of common stock. . The discussion does not relate to state, local or foreign law. . We have not requested a ruling from the Internal Revenue Service on the tax consequences of owning common stock. As a result, the IRS could disagree with portions of this discussion. If you are considering buying common stock, we suggest that you consult your tax advisor about the tax consequences of holding common stock in your particular situation. For the purposes of this discussion, a "Non-U.S. Holder" is: . an individual that is a nonresident alien; . a corporation--or entity taxable as a corporation for U.S. federal income tax purposes--created under non-U.S. law; or . an estate or trust that is not taxable in the United States on its worldwide income. If a partnership holds common stock, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner of a partnership holding common stock, we suggest that you consult your tax advisor. Withholding Taxes in General Unless an exception applies, all dividends paid to a Non-U.S. Holder will be subject to U.S. withholding tax at a rate of 30%. These taxes will be withheld either by the paying agent or by the bank, broker, or other intermediary through which you hold your common stock. In general, the entire dividend we pay is subject to withholding tax. However, special rules apply if we pay a dividend that is greater than our current or accumulated "earnings and profits" as calculated for U.S. federal income tax purposes. In that case, we (or the intermediary) either: . may elect to withhold only on the portion of the dividend that is out of our earnings and profits. In this case, the remainder of the dividend would not be subject to withholding tax; or . may withhold on the entire dividend. In that case, you would be entitled to obtain a refund from the IRS for the withholding tax on the portion of the dividend that exceeds our earnings and profits. 52
Exceptions to 30% Withholding Taxes You may be entitled to a reduced rate of withholding taxes--or exemption from withholding taxes--if you are eligible for a tax treaty between the United States and your country of residence. The particular withholding tax rate that would apply to you depends on your tax status and on the particular tax treaty. However, the rate under most treaties is 15% for a typical portfolio investor. To be eligible for preferential tax treatment under a tax treaty, you generally must meet each of the following requirements: . You must be the beneficial owner of our common stock. That is, you are not holding our common stock on behalf of someone else; . You must be a resident of the tax treaty jurisdiction and you satisfy all the other requirements in the treaty; . You must comply with the documentation requirements discussed below; and . If you are treated as a partnership or other pass-through entity either for U.S. federal income tax purposes or under the tax laws of the treaty jurisdiction, you must satisfy additional requirements. In order to comply with the documentation requirements to claim tax treaty benefits, you must satisfy one of the following conditions. These conditions have been significantly changed for dividends paid on or after January 1, 2001. . You complete Form W-8BEN and provide it to the intermediary. The Form W-8BEN must contain your name and address, and you must fill out Part II of the form to state your claim for treaty benefits. As long as our common stock remains actively traded, you are not required to obtain a Taxpayer Identification Number to claim treaty benefits. . You hold your common stock directly through a "qualified intermediary." In this case, you need not file Form W-8BEN if the qualified intermediary has in its files, or obtains from you, certain information concerning your eligibility for treaty benefits. A qualified intermediary is an intermediary that (1) is either a U.S. or non-U.S. entity, (2) is acting out of a non-U.S. branch or office and (3) has signed an agreement with the IRS providing that it will administer all or part of the U.S. tax withholding rules under specified procedures. . In some limited circumstances, you may be permitted to provide documentary evidence in lieu of Form W-8BEN even if you hold your common stock through an intermediary that is not a qualified intermediary. Alternatively, even if the dividends paid to you are not exempt from U.S. tax under a tax treaty, dividends paid to you will be exempt from U.S. withholding tax if the dividend income is effectively connected with the conduct of your trade or business in the United States. To claim this exemption, you must generally complete Form W-8ECI. Even if you meet one of the above requirements, you will not be entitled to the reduction in--or exemption from--withholding tax on dividends paid to you under any of the following circumstances: . The withholding agent or an intermediary knows or has reason to know that you are not entitled to the reduction in rate or the exemption from withholding tax. Specific rules apply for this test. . The IRS notifies the withholding agent that information that you or an intermediary provided concerning your status is false. . An intermediary through which you hold the common stock fails to comply with the necessary procedures. In particular, an intermediary is generally required to forward a copy of your Form W-8BEN (or other documentary information concerning your status) to the withholding agent for the common stock. However, if you hold your common stock through a qualified intermediary-- 53
or if there is a qualified intermediary in the chain of title between yourself and the withholding agent for the common stock--the qualified intermediary will not generally forward this information to the withholding agent. The amount of dividends paid to you, and the amount withheld from the dividends, will generally be reported to the IRS and to you on Form 1042-S. However, this reporting does not apply to you if you hold your common stock directly through a qualified intermediary and the applicable procedures are complied with. The rules regarding withholding are complex and vary depending on your individual situation. They are also subject to change, and certain transition rules apply for calendar year 2001. In addition, special rules apply to certain types of non-U.S. holders of common stock, including partnerships, trusts, and other entities treated as pass-through entities for U.S. federal income tax purposes. We suggest that you consult with your tax advisor regarding the specific methods for satisfying these requirements. Sale of Common Stock If you sell all or any portion of your common stock, you will not be subject to federal income tax on any gain unless one of the following applies: . The gain is connected with a trade or business that you conduct in the United States. . You are an individual and are present in the United States for at least 183 days during the year in which you dispose of the common stock, and certain other conditions are satisfied. . We are or have been a "United States real property holding corporation" for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of the disposition or the period during which you hold your common stock. We have not analyzed whether or not we are a real property holding corporation for U.S. federal income tax purposes, but given the nature of our industry, it is reasonably likely that we would qualify as one. Even if we are a United States real property holding corporation, a non-U.S. holder still will not be subject to U.S. tax if our common stock were considered to be "regularly traded on an established securities market" and you did not own, actually or constructively, at any time during the shorter of the periods described above, more than five percent of our common stock. U.S. Trade or Business If you hold your common stock in connection with a trade or business that you are conducting in the United States.: . Any dividends on the common stock, and any gain from disposing of the common stock, generally will be subject to income tax at the usual U.S. rates applicable to U.S. persons. . If you are a corporation, you may be subject to the "branch profits tax" on your earnings that are connected with your U.S. trade or business, including earnings from the common stock. This tax is 30%, but may be reduced or eliminated by an applicable income tax treaty. Estate Taxes If you are an individual, your common stock will be subject to U.S. estate tax when you die unless you are entitled to the benefits of an estate tax treaty. 54
Information Reporting and Backup Withholding Under the U.S. information reporting rules, when a shareholder receives dividends or proceeds of the sale of stock, the appropriate intermediary must report to the IRS and to the shareholder the amount of the dividends or sale proceeds. Some shareholders, including all corporations, are exempt from these rules. In addition, a nonexempt shareholder is required to provide the intermediary with certain identifying information. If this information is not supplied, or if the intermediary knows or has reason to know that it is not true, dividends or sale proceeds are subject to "backup withholding" at a rate of 31%. Backup withholding is not an additional tax, and the shareholder may use the tax as a credit against the tax it otherwise owes. These rules apply to Non-U.S. Holders of common stock as follows: . Dividends paid to you will be exempt from the usual information reporting rules if you are eligible for a reduced withholding rate under a tax treaty as discussed above. However, as described above, dividends paid to you may be reported to the IRS on Form 1042-S. . If you are not eligible for a tax treaty and do not provide information to the intermediary identifying yourself as a Non-U.S. Holder, in some cases you may be subject to backup withholding at the rate of 31% instead of regular dividend withholding at the rate of 30%. If necessary, you may provide the intermediary with Form W-8BEN, without claiming treaty benefits, in order to claim the 30% rate. Sale proceeds you receive on a sale of your common stock through a broker may be subject to information reporting and/or backup withholding if you are not eligible for an exemption. In particular, information reporting and backup withholding may apply if you use the U.S. office of a broker, and information reporting (but not backup withholding) may apply if you use the foreign office of a broker that has certain connections to the U.S. In general, you may file Form W-8BEN, without claiming treaty benefits, to claim an exemption from information reporting and backup withholding. We suggest that you consult your tax advisor concerning information reporting and backup withholding on a sale. 55
UNDERWRITING We and the selling stockholder intend to offer the shares of our common stock through the underwriter. Merrill Lynch, Pierce, Fenner & Smith Incorporated is the sole underwriter. Subject to the terms and conditions in the purchase agreement among us, the selling stockholder and the underwriter, we and the selling stockholder have agreed to sell to the underwriter, and the underwriter has agreed to purchase from us and the selling stockholder, a total of 8,700,000 shares. The underwriter has agreed to purchase all of the shares sold under the purchase agreement if any of the shares are purchased. We and the selling stockholder have agreed to indemnify the underwriter against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriter may be required to make in respect of those liabilities. The underwriter is offering the shares, subject to prior sale, when, as and if issued to and accepted by it, subject to approval of legal matters by its counsel, including the validity of the shares, and other conditions contained in the purchase agreement, such as the receipt by the underwriter of officer's certificates and legal opinions. The underwriter reserves the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part. Commissions and Discounts The underwriter has advised us and the selling stockholder that it proposes initially to offer the shares to the public at the initial public offering price on the cover page of this prospectus and to dealers at that price less a concession not in excess of $.57 per share. The underwriter may allow, and the dealers may reallow, a discount not in excess of $.10 per share to other dealers. After the initial public offering, the public offering price, concession and discount may be changed. The following table shows the public offering price, underwriting discount and proceeds before expenses to us and the selling stockholder. The information assumes either no exercise or full exercise by the underwriter of its over-allotment option. Per Share Without Option With Option --------- -------------- ----------- Public offering price.............. $19.00 $165,300,000 $188,627,535 Underwriting discount.............. $.97 $8,439,000 $9,629,932 Proceeds, before expenses, to Arch Coal.............................. $18.03 $71,092,867 $93,229,470 Proceeds, before expenses, to Ashland Inc., the sole selling stockholder....................... $18.03 $85,768,133 $85,768,133 The expenses of the offering, not including the underwriting discount, are estimated at $350,000, and will be paid by us. Over-allotment Option We have granted an option to the underwriter to purchase up to 1,227,765 additional shares at the public offering price less the underwriting discount. The underwriter may exercise this option for 30 days from the date of this prospectus solely to cover any over-allotments. No Sales of Similar Securities We, our directors, certain of our officers, the selling stockholder and some other significant stockholders have agreed, with exceptions, not to sell or transfer any common stock for 90 days after the date of this prospectus without first obtaining the written consent of Merrill Lynch. Specifically, we and these other parties have agreed not to directly or indirectly 56
. offer, pledge, sell or contract to sell any common stock, . sell any option or contract to purchase any common stock, . purchase any option or contract to sell any common stock, . grant any option, right or warrant for the sale of any common stock, . lend or otherwise dispose of or transfer any common stock, . request or demand that we file a registration statement related to the common stock, or . enter into any swap or other agreement that transfers, in whole or in part, the economic consequence of ownership of any common stock whether any such swap or transaction is to be settled by delivery of shares or other securities, in cash or otherwise. This lockup provision applies to common stock and to securities convertible into or exchangeable or exercisable for or repayable with common stock. It also applies to common stock owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition. Merrill Lynch, in its sole discretion, may release any of the securities subject to lockup agreements at any time prior to the expiration of the lockup period without notice. Merrill Lynch has no present intent or arrangement to release any of the securities subject to these lockup agreements. We are not restricted by this lockup provision from the sale or distribution of our common stock in connection with certain business combination transactions, stock-based compensation plans and our dividend reinvestment plan. New York Stock Exchange Listing The shares are listed on the New York Stock Exchange under the symbol "ACI". Price Stabilization, Short Positions Until the distribution of the shares is completed, Securities and Exchange Commission rules may limit the underwriter from bidding for and purchasing our common stock. However, the underwriter may engage in transactions that stabilize the price of the common stock, such as bids or purchases to peg, fix or maintain that price. In connection with the offering, the underwriter may make short sales of the common stock. Short sales involve the sale by the underwriter at the time of the offering of a greater number of shares than it is required to purchase in the offering. Covered short sales are sales made in an amount not greater than the over-allotment option. The underwriter may close out any covered short position by either exercising its over-allotment option or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriter will consider, among other things, the price of shares available for purchase in the open market as compared to the public offering price at which it may purchase the shares through the over-allotment option. Naked short sales are sales in excess of the over-allotment option. The underwriter must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriter is concerned that there may be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering. Purchases of the common stock to stabilize its price or to reduce a short position may cause the price of the common stock to be higher than it might be in the absence of such purchases. Neither we nor the underwriter makes any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we nor the underwriter makes any representation that the underwriter will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice. 57
The underwriter will be facilitating Internet distribution for this offering to some of its Internet subscription customers. The underwriter intends to allocate a limited number of shares for sale to its online brokerage customers. An electronic prospectus is available on the Internet web site maintained by Merrill Lynch. Other than the prospectus in electronic format, the information on the Merrill Lynch web site is not part of this prospectus. 58
LEGAL MATTERS The validity of the shares of common stock offered will be passed upon by Robert G. Jones, our Vice President--Law and General Counsel. Certain legal matters with respect to the offering will be passed upon for us by Kirkpatrick & Lockhart LLP, Pittsburgh, Pennsylvania. The underwriter has been represented by Cravath, Swaine & Moore, New York, New York. Cravath, Swaine & Moore regularly provides legal services to Ashland. EXPERTS Ernst & Young LLP, independent auditors, have audited our financial statements and schedule included or incorporated by reference in our Annual Report on Form 10-K for the years ended December 31, 1997 and 1998 and Form 10- K, as amended, for the year ended December 31, 1999, and the financial statements of Canyon Fuel Company, LLC for the years ended December 31, 1998 and 1999 included in our Annual Report on Form 10-K, as amended, for the year ended December 31, 1999, all as set forth in their reports, which are incorporated by reference in this prospectus and elsewhere in the registration statement. These financial statements and schedule are incorporated by reference in reliance on the reports of Ernst & Young LLP given on their authority as experts in accounting and auditing. WHERE YOU CAN FIND MORE INFORMATION We are subject to the reporting requirements of the Securities Exchange Act of 1934 and, in accordance with that Act, file annual and quarterly reports, proxy statements and other information with the Securities and Exchange Commission. These reports, proxy statements and other information may be inspected and copies of these materials may be obtained upon payment of fees at the Public Reference Room maintained by the Securities and Exchange Commission at 450 Fifth Street, N.W., Washington, D.C. 20549, as well as the regional offices of the Securities and Exchange Commission located at 500 West Madison Street, Chicago, Illinois, and Seven World Trade Center, New York, New York. You may obtain information on the operation of the Public Reference Room by calling the Commission at 1-800-SEC-0330. In addition, we are required to file electronic versions of these materials with the Securities and Exchange Commission through the Securities and Exchange Commission's Electronic and Data Gathering, Analysis and Retrieval system. The Securities and Exchange Commission maintains a World Wide Web site at http://www.sec.gov that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. Our common stock is listed on the New York Stock Exchange, and reports and other information concerning us may be inspected at the New York Stock Exchange, Inc. at 20 Broad Street, New York, New York 10005. We have filed with the Securities and Exchange Commission a registration statement on Form S-3 under the Securities Act of 1933 with respect to the common stock offered in this prospectus. This prospectus does not contain all of the information set forth in the registration statement and the exhibits to that registration statement. The Securities and Exchange Commission allows us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring to those documents. All documents and reports subsequently filed by us under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of the registration statement and prior to effectiveness of the registration statement and after the date of this prospectus and prior to the termination of the offering made by this prospectus are incorporated by reference. Any statement contained in this prospectus or in a document incorporated or deemed to be incorporated by reference in this prospectus shall be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any subsequently filed document which is incorporated by reference in this prospectus modifies or supersedes that statement. A statement so modified or superseded will not be deemed, except as so modified or superseded, to be a part of this prospectus. 59
Copies of the registration statement, including all exhibits to it, may be obtained from the Securities and Exchange Commission's principal office in Washington, D.C. upon the payment of the fees prescribed by the Securities and Exchange Commission, or may be examined without charge at the offices of the Securities and Exchange Commission described above. Copies of these materials may also be obtained from the EDGAR database. The following documents filed by us with the Securities and Exchange Commission under the Exchange Act are incorporated by reference in this prospectus: 1. Our Annual Report on Form 10-K for the fiscal year ended December 31, 1999, as amended; 2. Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2000, June 30, 2000 and September 30, 2000, each as amended; 3. Our Current Report on Form 8-K dated March 9, 2000; 4. The description of the common stock contained in our Registration Statement on Form 8-B dated June 17, 1997, as the same may be amended; and 5. The description of the preferred stock purchase rights contained in our Registration Statement on Form 8-A dated March 9, 2000, as the same may be amended. We will provide to each person to whom a copy of this prospectus is delivered, upon the written or oral request of such person, without charge, a copy of any or all of the documents that are incorporated in this prospectus by reference. Requests should be directed to External Affairs, Arch Coal, Inc., CityPlace One, Suite 300, St. Louis, Missouri 63141. Our telephone number is (314) 994-2700. 60
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 openings 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. 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. Longwall Mining. One of two major underground coal mining methods currently in use. 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. Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction. Overburden Ratio. A measurement indicating the volume of earth and rock, in cubic yards, that must be removed to expose one ton of marketable 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. 61
Probable (Indicated) Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation. Proven (Measured) 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 reshaping 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. Scrubber. Any of several forms of chemical/physical devices which operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, which must then be removed for disposal. 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 ton, which is equal to 2,000 pounds. Unassigned Reserves. Recoverable coal reserves that have not yet been designated for mining by a specific 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. Unit Train. A long train of between 90 and 150 hopper cars, carrying coal between a single mine and a destination. A typical unit train can carry at least 10,000 tons of coal in a single shipment. 62
- -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 8,700,000 Shares Arch Coal, Inc. Common Stock --------------- PROSPECTUS --------------- Merrill Lynch & Co. February 15, 2001 - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------