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Table of Contents

 
 
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
     
(Mark One)
   
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the fiscal year ended: December 31, 2004
 
or
 
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                 to               
Commission File Number: 1-13105
ARCH COAL, INC.
(Exact name of registrant as specified in its charter)
     
Delaware   43-0921172
(State or other jurisdiction
  (IRS Employer
of incorporation or organization)
  Identification No.)
     
One City Place Drive, Suite 300, St. Louis, MO   63141
(Address of principal executive offices)
  (Zip Code)
(Registrant’s telephone number, including area code): (314) 994-2700
Securities registered pursuant to Section 12(b) of the Act:
     
Common Stock, $.01 par value
Preferred Share Purchase Rights
5% Perpetual Cumulative Convertible Preferred Stock
Title of Each Class
  New York Stock Exchange
New York Stock Exchange
None
Name of Each Exchange On Which Registered
Securities registered pursuant to Section 12(g) of the Act: None
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ     No o
     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes þ     No o
     At March 1, 2005, based on the closing price of the registrant’s common stock on the New York Stock Exchange on that date, the aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $2,376.8 million. In determining this amount, the registrant has assumed that all of its executive officers and directors, and persons known to it to be the beneficial owners of more than five percent of its common stock, are affiliates. Such assumption shall not be deemed conclusive for any other purpose.
     At March 1, 2005, there were 62,721,235 shares of the registrant’s common stock outstanding.
Documents incorporated by reference:
1.  Portions of the registrant’s definitive proxy statement, to be filed with the Securities and Exchange Commission no later than April 1, 2005, are incorporated by reference into Part III of this Form 10-K.
 
2.  Portions of the registrant’s Annual Report to Stockholders for the year ended December 31, 2004 are incorporated by reference into Parts I, II and IV of this Form 10-K.
 
 


TABLE OF CONTENTS
               
        Page
         
           
   BUSINESS     1  
     PROPERTIES     12  
     LEGAL PROCEEDINGS     14  
     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS     14  
           
     MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS     14  
     SELECTED FINANCIAL DATA     14  
     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     14  
     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     14  
     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     14  
     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     14  
     CONTROLS AND PROCEDURES     14  
     OTHER INFORMATION     14  
           
     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT     15  
     EXECUTIVE COMPENSATION     15  
     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT     15  
     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS     15  
     PRINCIPAL ACCOUNTANT FEES AND SERVICES     15  
           
     EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS     16  
 Amended and Restated Retention Agreement
 Form of Retention Agreement
 Modified Coal Lease
 Coal Lease
 Portions of the Company's Annual Report to Stockholders
 Subsidiaries
 Consent
 Power of Attorney
 Certification
 Certification
 Certification
 Certification


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PART I
ITEM 1.  BUSINESS
General
      Arch Coal, Inc. (“Arch Coal” or the “Company”) is one of the largest coal producers in the United States. The Company mines, processes and markets compliance and low-sulfur coal from mines located in both the eastern and western United States, enabling it to ship coal cost-effectively to most of the major domestic coal-fired electric generation facilities. As of December 31, 2004, the Company operated or controlled 27 mines and controlled approximately 3.7 billion tons of proven and probable coal reserves. Arch Coal sold 128.4 million tons of coal in 2004. The Company sells substantially all of its coal to producers of electric power, steel producers and industrial facilities.
      The Company owns a 99% membership interest in Arch Western Resources, LLC (“Arch Western”), a joint venture that was formed in connection with the Company’s acquisition of the United States coal operations of Atlantic Richfield Company on June 1, 1998. The principal operating units of Arch Western are Thunder Basin Coal Company, L.L.C., which operates the Black Thunder mine in the Southern Powder River Basin in Wyoming; Mountain Coal Company, L.L.C., which operates the West Elk mine in Colorado; Canyon Fuel Company, LLC (“Canyon Fuel”), which operates three mines in Utah; and Arch of Wyoming, LLC, which operated two mines in the Hanna Basin of Wyoming which are now in reclamation mode. Arch Western owns 100% of the membership interests of Thunder Basin Coal Company, L.L.C., Mountain Coal Company, L.L.C. and Arch of Wyoming, LLC. Arch Western owns a 65% membership interest in Canyon Fuel, with the remaining 35% membership interest owned by Arch Coal directly.
Business Environment
      United States Coal Markets. Production of coal in the United States has increased from 434 million tons in 1960 to about 1.1 billion tons in 2004. The following table sets forth demand trends for United States coal by consuming sector through 2025 as compiled, preliminary(p) or forecasted(f) by the United States Department of Energy/ Energy Information Agency.
                                                                           
                                    Annual
                                    Growth
                                    2003-
Consumption by Sector   2002   2003   2004(p)   2005(f)   2010(f)   2015(f)   2020(f)   2025(f)   2025(f)
                                     
    (tons in millions)
Electric Generation
    978       1,005       1,012       1,042       1,139       1,185       1,267       1,425       1.6 %
Industrial
    61       61       61       66       66       65       66       66       0.3 %
Steel Production
    24       24       24       24       20       18       15       13       (2.7 %)
Residential/ Commercial
    0       4       3       5       5       5       5       5       0.4 %
Export
    40       43       49       48       42       35       35       26       (2.3 %)
                                                       
 
Total
    1,102       1,137       1,149       1,185       1,272       1,308       1,388       1,535       1.5 %
                                                       
      Electricity Generation. Coal has consistently maintained a 49% to 53% market share over competing energy sources to generate electricity during the past ten years because of its relatively low cost and its availability throughout the United States. Coal is the lowest cost fossil-fuel used for base-load electric power generation — considerably less expensive than natural gas or oil. Coal-based generation is also competitive with nuclear power generation, especially on an all-in cost per megawatt-hour basis. Hydroelectric power is inexpensive but is limited by both geography and susceptibility to seasonal and climatic conditions. Non hydropower renewable power generation accounts for only 1.9% of all the electricity generated in the U.S. and is limited by resources and/or technology. Consequently, approximately 91% of the coal produced in the United States in 2004 was sold in the domestic market as a fuel to the electric generation segment. The remainder of the tons were sold in 2004 as steam coal for industrial and residential purposes, into the export market, and as metallurgical coal. In addition to the relative competitiveness of coal-fired generation plants, coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting coal production and power generation, technological developments and the location, availability and quality of competing sources of coal, as well as other fuels such as natural gas, oil and nuclear and alternative energy sources such as hydroelectric power.
      Long-term demand for electric power will depend upon a variety of economic, regulatory, technological and climatic factors beyond our control. Historically, domestic demand for electric power has increased as the United States economy

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has grown. Two important regulatory initiatives, one designed to increase competition among utilities and lower the cost of electricity for consumers, and another to improve air quality by reducing the level of sulfur emitted from coal-burning power generation plants, have had and are expected to continue to have significant effects on the electric utility industry and its coal suppliers.
      According to the Energy Information Administration, coal is expected to remain the primary fuel for electricity generation through 2025. The following table sets forth the source fuel for electricity generation from 2002 through 2025 as compiled, preliminary(p) or forecasted(f) by the Energy Information Administration.
                                                                           
                                    Annual
                                    Growth
                                    2003-
    2002   2003   2004(p)   2005(f)   2010(f)   2015(f)   2020(f)   2025(f)   2025
                                     
    (billion kilowatt hours)
Coal
    1,933       1,974       1,973       2,055       2,250       2,306       2,495       2,890       1.8%  
Petroleum
    95       119       122       121       127       135       143       148       0.9%  
Natural Gas
    691       650       721       698       922       1,171       1,375       1,403       4.4%  
Nuclear
    780       764       793       796       813       826       830       830       0.4%  
Hydro/ Renewable/other
    360       376       369       416       414       452       471       499       1.4%  
                                                       
 
Total
    3,858       3,883       3,977       4,086       4,526       4,890       5,314       5,770       1.9%  
                                                       
      Coal’s primary advantage is its relatively low cost compared to other fuels used to generate electricity. The following table sets forth the Energy Information Agency’s forecast of delivered fuel prices to electric utilities through 2025 as compiled, preliminary(p) or forecasted(f) by the Energy Information Administration. The table below is derived from the Energy Information Administration’s long-term forecast published in December 2004 and is presented in 2003 dollars.
                                                                         
                                    Annual
                                    Growth
                                    2003-
    2002   2003   2004(p)   2005(f)   2010(f)   2015(f)   2020(f)   2025(f)   2025(f)
                                     
    (dollars per million Btus)
Annual Energy Outlook
                                                                       
Petrol (Residual)
  $ 3.73     $ 4.74     $ 4.77     $ 5.38     $ 4.19     $ 4.44     $ 4.71     $ 5.00       0.2%  
Natural Gas
    3.56       5.37       5.82       5.92       4.27       4.81       5.20       5.44       0.0%  
Coal
    1.25       1.28       1.34       1.29       1.25       1.23       1.25       1.31       0.1%  

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     Coal Production. United States coal production was 1.1 billion tons in 2004. The following table, derived from data prepared by the Energy Information Administration, sets forth principal United States production statistics for the periods indicated as compiled or preliminary(p).
                                                           
    1980   1985   1990   1995   2000   2003   2004(p)
                             
Total Tons (in millions)
    830       884       1,029       1,033       1,074       1,072       1,111  
 
East
    566       554       627       544       508       469       486  
 
West
    264       330       402       489       566       603       625  
 
Underground
    329       349       424       396       374       353       367  
 
Surface
    501       555       605       637       700       719       744  
Percent of Total Tons
                                                       
 
East
    68 %     63 %     61 %     53 %     47 %     44 %     44 %
 
West
    32       37       39       47       53       56       56  
 
Underground
    40       39       41       38       35       33       33  
 
Surface
    60       61       59       62       65       67       67  
Number of Mines (from Platts)
                                                       
 
Underground
    1,875       1,695       1,422       977       707       537       534  
 
Surface
    1,997       1,660       1,285       1,127       746       737       761  
                                           
 
Total
    3,872       3,355       2,707       2,104       1,453       1,274       1,295  
                                           
Average Number of Mine Employees (from Platts)
                                                       
 
Underground
    150,328       107,357       63,960       44,254       36,825       31,948       32,407  
 
Surface
    74,610       61,924       43,402       31,777       24,640       26,218       26,774  
                                           
 
Total
    224,938       169,281       107,362       76,031       61,465       58,166       59,181  
                                           
Average Production per Mine
(tons in thousands)
                                                       
 
Underground
    177       203       297       402       531       613       687  
 
Surface
    249       325       472       568       935       974       979  
Sales and Marketing
      The Company sells coal both under long-term contracts, the terms of which are 12 months or greater, and on a current market or spot basis. When the Company’s coal sales contracts expire or are terminated, it is exposed to the risk of having to sell coal into the spot market, where demand is variable and prices are subject to greater volatility. Historically, the price of coal sold under long-term contracts has exceeded prevailing spot prices for coal. However, with more volatility experienced in the market in the past several years, new contracts have been priced at or below existing spot rates.
      The terms of the Company’s coal sales contracts result from bidding and extensive negotiations with customers. Consequently, the terms of these contracts typically vary significantly in many respects, including price adjustment features, provisions permitting renegotiation or modification of coal sale prices, coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, and force majeure, suspension, termination and assignment provisions.
      Provisions permitting renegotiation or modification of coal sale prices are present in many of the Company’s more recently negotiated long-term contracts and usually occur midway through a contract or every two to three years, depending upon the length of the contract. In some circumstances, customers have the option to terminate the contract if prices have increased by a specified percentage from the price at the commencement of the contract or if the parties cannot agree on a new price. The term of sales contracts has decreased 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.
      Arch Coal also participates in the “over the counter market” for a small portion of its production.

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Competition
      The coal industry is intensely competitive, primarily as a result of the existence of numerous producers in the coal producing regions in which the Company operates. The Company competes with several major coal producers in the Central Appalachian and Powder River Basin areas. It also competes with a number of smaller producers in those and its other market regions. Additionally, coal competes for share of the power generation market with other fuels such as natural gas and petroleum.
Operations
      As of December 31, 2004, the Company operated a total of 27 mines, all located in the United States. The Company uses several distinct extraction techniques: continuous mining, longwall mining, truck-and-shovel mining, truck-and-loader mining, highwall mining, excavator-and-loader mining and dragline mining. Coal is transported from the Company’s mining complexes to customers by means of railroad cars, river barges or trucks, or a combination of these means of transportation. As is customary in the industry, virtually all the Company’s coal sales are made F.O.B. mine or loadout, meaning that customers are responsible for the cost of transporting purchased coal to their facilities.
      The Company manages its production sources to supply coal within three of the major low sulfur coal producing basins in the United States — the Central Appalachia Basin, Powder River Basin and the Western Bituminous Basin. These geographically distinct areas are characterized by similar geology, coal transportation routes to consumers, regulatory environments and coal quality. These regional similarities have caused market and contract pricing environments to develop by coal basin and form the basis for the Company’s segmentation of its operations.
      Coal prices are influenced by a number of factors and vary dramatically by region. As a result of these regional characteristics, prices of coal within a given major coal producing basin tend to be relatively consistent. The two principal components of the price of coal within a region are the price of coal at the mine, which is influenced by market conditions (supply and demand) and by mine operating costs, coal quality, and transportation costs involved in moving coal from the mine to the point of use. In addition to supply and demand factors, the price of coal at the mine is influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Underground mining, which is the mining method the Company uses in the Western Bituminous and also a method the Company primarily uses at certain mines in Central Appalachia, is generally more expensive than surface mining, which is the mining method the Company uses in the Powder River Basin and also for certain of its Central Appalachian mines. This is the case because of the higher capital costs, including costs for modern mining equipment and construction of extensive ventilation systems and higher labor costs due to lower productivity that are associated with underground mining.
      In addition to the cost of mine operations, the price of coal is also a function of quality characteristics such as heat value, sulfur, ash and moisture content. Higher carbon and lower ash content generally result in higher prices. Coal from the Central Appalachian Basin generally has a sulfur content of 0.7% to 1.5% and a high heat content of between 12,000 and 14,000 Btus per pound. The coal from the Western Bituminous region typically has a lower sulfur content of 0.50% to 1% and a lower heat content of between 10,500 and 12,500 Btus per pound. Powder River Basin coal generally has the lowest relative sulfur content among the Company’s regions, with a sulfur content of between 0.15% and 1.20%, and the lowest relative heat content, which typically is between 7,500 and 10,000 Btus per pound.
      The Company’s management, including its Chief Executive Officer and Chief Operating Officer, reviews and makes resource allocations based on the goal of maximizing its profits within a coal basin in light of the comparative cost structures of its various operations. Because the Company’s customers purchase coal on a regional basis, contracts can generally be sourced from several different locations within a region. Once the Company has a contractual commitment to purchase an amount of coal at a certain price, the Company’s central marketing group assigns contract shipments to its various mines which can be used to source the coal in the appropriate region.
      The focus of the Company’s operating structure is on the reduction of controllable costs. Although revenues are reported at the mine level, the Company’s mine management is asked only to manage volume and revenue adjustments due to quality variances for contract shipments assigned to their mines. In 2004, the Company’s mine management was evaluated and compensated in part on the basis of operating costs per ton at the mine level, as well as on the basis of other non-financial measures such as safety and environmental results.
      Based on its management structure, the Company does not utilize mine-by-mine profit as a measure to make decisions. As a result of its management of revenues on a regional basis, the reported profit at any individual mine may not

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be meaningful and is not indicative of the future economic prospects of the mine. This is the case because an individual mine’s profit is based on the contract shipments that are assigned to it by the central marketing group and the pricing of those contracts, with assignments typically being made on the basis of the availability of coal and the cost of transporting the coal to the customer. Therefore, a mine that is assigned a lower-price contract will have a lower profit margin than a similar mine with similar costs that ships a nearly identical product on a higher-price contract.
      The following maps show the locations of the Company’s significant mining operations:
          Central Appalachia Operations
(AREAMAP

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          Powder River Basin and Western Bituminous Operations
(AREAMAP

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      The following table provides the location and a summary of information regarding the Company’s principal mining complexes and the total sales associated with these operations for the prior three years:
                                                 
                    Tons Sold
    Captive   Contract            
Mining Complex (Location)   Mine(s)(1)   Mine(1)   Mining Equipment(2)   Transportation   2002   2003   2004
                             
Central Appalachia
                                               
Mingo Logan (WV)
  U     U       LW, C     NS     5.8       5.5       5.1  
Coal-Mac (WV)(3)
  S(2)     U       L, E     Barge/NS/CSX     2.1       2.1       2.6  
Hobet 21 (WV)(4)
  S     U       D, L, S, C     CSX     5.3       5.2       4.6  
Arch of West Virginia (WV)(5)
  S     U       D, L, E     CSX     3.6       2.8       3.1  
Samples (WV)(6)
  S     U       D, L, S, HW     Barge/CSX     5.5       5.5       5.1  
Campbells Creek (WV)
      U(2)           Barge     1.1       1.0       1.2  
Lone Mountain (KY)
  U(3)           C     NS/CSX     2.6       2.7       2.9  
Cumberland River (VA, KY)
  S(2), U(2)     U, S       L, C     NS     1.6       1.5       1.6  
Western United States
                                               
Black Thunder (WY)(7)
  S           D, S     UP/BN     65.1       62.6       75.1  
Coal Creek (WY)(8)
                UP/BN                  
West Elk (CO)
  U           LW, C     UP     6.7       6.5       6.2  
Skyline (UT)(9)
  U           LW, C     UP     3.4       3.1       0.6  
SUFCO (UT)(9)
  U           LW, C     UP     7.2       7.5       7.8  
Dugout Canyon (UT)(9)
  U           LW, C     UP     2.0       2.5       3.8  
Arch of Wyoming (WY)(10)
                UP     0.6       0.5       0.2  
                                       
Totals
                            112.6       109.0       119.9  
                                       
 
                                 
S   =   Surface Mine   D   =   Dragline   UP   =   Union Pacific Railroad
U
  =   Underground Mine   L   =   Loader/Truck   CSX   =   CSX Transportation
            S   =   Shovel/Truck   BN   =   Burlington Northern Railroad
            E   =   Excavator/Truck   NS   =   Norfolk Southern Railroad
            LW   =   Longwall            
            C   =   Continuous Miner            
            HW   =   Highwall Miner            
  (1)  Amounts in parenthesis indicate the number of captive and contract mines at the mining complex or location at December 31, 2004. Captive mines are mines which the Company owns and operates on land owned or leased by it. Contract mines are mines which other operators mine for the Company under contracts on land owned or leased by the Company.
 
  (2)  Reported for captive operations only.
 
  (3)  Utilized a 23-cubic-yard loader.
 
  (4)  Utilizes an 83-cubic-yard dragline and a 51-cubic-yard shovel.
 
  (5)  Utilizes two 37-cubic-yard hydraulic excavators and two 23-cubic-yard loaders.
 
  (6)  Utilizes a 105-cubic-yard dragline, one 53-cubic-yard shovels and three 28-cubic-yard loaders.
 
  (7)  Utilizes 164-cubic-yard, 130-cubic-yard, 106-cubic-yard, 78-cubic-yard and 45-cubic-yard draglines and 85-cubic-yard, 73-cubic-yard, 68-cubic-yard, 55-cubic-yard and 53-cubic-yard shovels.
 
  (8)  The Company idled its mining operations at Coal Creek during the third quarter of 2000 because of unfavorable conditions existing in the market environment.
 
  (9)  Prior to July 31, 2004 the Company owned a 65% interest in Canyon Fuel and accounted for it as an equity investment and its financial statements and tons sold were not consolidated into the Company’s financial statements. Subsequent to July 31, 2004, the Company acquired the remaining 35% of Canyon Fuel and its financial statements and tons sold are consolidated into the Company’s financial statements. Amounts shown represent 100% of Canyon Fuel’s sales volume for all periods presented. The Skyline mine was idled in 2004.
(10)  This complex was put into reclamation mode in 2004.

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      Mingo Logan. The Mingo Logan mine is an underground operation located in Mingo County and Logan County, West Virginia on approximately 12,000 acres. Six continuous miners support a longwall. The mined coal is processed through a preparation plant at the mine. The loadout facility at Mingo Logan is serviced by Norfolk Southern Railroad.
      Coal-Mac. The Coal-Mac mine is located in Mingo County and Logan County, West Virginia on approximately 9,100 acres. The equipment at the mine consists of one hydraulic excavator, six wheel-loader spreads, 2 loadout facilities, and a preparation plant. Coal-Mac’s loadout facilities are serviced by Norfolk Southern Railroad and CSX Transportation.
      Hobet 21. The Hobet 21 mine is located in Boone County and Lincoln County, West Virginia on approximately 19,700 acres. Equipment at Hobet 21 includes a dragline, electric shovel and wheel-loader spread. The coal at Hobet 21 is processed at an on-site preparation plant and transported from Hobet 21’s loadout facility, which is serviced by CSX Transportation.
      Arch of West Virginia. The Arch of West Virginia mine is located primarily in Logan County, West Virginia on approximately 19,700 acres. Two hydraulic excavators and two loaders are present. The loadout facility at the mine is serviced by CSX Transportation.
      Samples. The Samples mine is located primarily in Kanawha County, West Virginia on approximately 10,850 acres. Equipment at Samples includes a dragline, a shovel and four loaders. Coal from Samples is transported by rail to a loadout facility approximately 1.4 miles from the mine. CSX Transportation services this loadout. Coal also is transported by barge from this loadout.
      Lone Mountain. The Lone Mountain mine is located in Harlan County, Kentucky and Lee County, Virginia on approximately 15,200 acres. Continuous miner units and bridge units are present at Lone Mountain. The loadout facility at Lone Mountain is serviced by Norfolk Southern Railroad and CSX Transportation.
      Cumberland River. The Cumberland River mine is located in Wise County, Virginia and Letcher County, Kentucky on approximately 12,200 acres. Mining techniques include both surface and underground mining utilizing endloaders with trucks and continuous miners. Cumberland River’s coal is processed at an on-site preparation plant and its loadout is serviced by Norfolk Southern Railroad.
      Black Thunder. The Black Thunder mine is located in Campbell County, Wyoming on approximately 24,150 acres. Mining the approximately 68-foot coal seam are five draglines and eleven shovels. There is no washing plant at Black Thunder. The coal is crushed through either the near pit crushing and conveying system or the primary system. Coal from these two crushing facilities is conveyed into one of two silos or a slot storage facility. Coal is shipped through three loadouts on trains operated by Burlington Northern and Union Pacific.
      Coal Creek. The Coal Creek mine is located in Campbell County, Wyoming on approximately 7,030 acres. Coal Creek has been idle since July 2000. The Coal Creek mine is located on a joint rail line operated by Burlington Northern and Union Pacific.
      West Elk. The West Elk mine is an underground operation located in Gunnison County, Colorado on approximately 11,900 acres. The coal is mined by three continuous miners in support of a longwall. The loadout facility at the mine is serviced by the Union Pacific Railroad.
      Skyline. Canyon Fuel’s Skyline mine is an underground longwall mine located in Carbon County and Emery County, Utah on approximately 9,650 acres. The loadout facility at Skyline is serviced by the Union Pacific Railroad. The Skyline mine was idled during 2004.
      SUFCO. Canyon Fuel’s SUFCO mine, an underground longwall mine, is located in Sevier County, Juab County and Emery County, Utah on approximately 26,700 acres. Two continuous miners support the longwall. All of the coal produced from the mine is crushed at a facility located at the mine and trucked either directly to customers or to a train loadout located approximately 80 miles from the mine. The Union Pacific Railroad serves this loadout.
      Dugout Canyon. Canyon Fuel’s Dugout Canyon mine is an underground longwall mine located in Carbon, County, Utah on approximately 7,800 acres. Two continuous miners support the longwall operation. The coal produced is crushed at the mine and trucked to a third party loadout served by the Union Pacific Railroad.

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Transportation
      Coal from the mines of the Company’s subsidiaries is transported by rail, truck and barge to domestic customers and to Atlantic coast terminals for shipment to domestic and international customers.
      The Company’s Arch Coal Terminal is located on a 60-acre site on the Big Sandy River approximately seven miles upstream from its confluence with the Ohio River. Arch Coal Terminal provides coal storage and transloading services.
      Company subsidiaries together own a 17.5% interest in Dominion Terminal Associates (“DTA”), which leases and operates a ground storage-to-vessel coal transloading facility (the “DTA Facility”) in Newport News, Virginia. The DTA Facility has a rated throughput capacity of 20 million tons of coal per year and ground storage capacity of approximately 1.7 million tons. The DTA Facility serves international customers, as well as domestic coal users located on the eastern seaboard of the United States.
Regulations Affecting Coal Mining
      The information contained in the “Contingencies — Reclamation” and “Certain Trends and Uncertainties — Environmental and Regulatory Factors” sections of “Management’s Discussion and Analysis” of the Company’s 2004 Annual Report to Stockholders is incorporated herein by reference.
Glossary of Selected Mining Terms
      Assigned Reserves. Recoverable coal reserves that have been designated for mining by a specific operation.
      Auger Mining. Auger mining employs a large auger, which functions much like a carpenter’s drill. The auger bores into a coal seam and discharges coal out of the spiral onto waiting conveyor belts. After augering is completed, the openings are reclaimed. This method of mining is usually employed to recover any additional coal left in deep overburden areas that cannot be reached economically by other types of surface mining.
      Btu — British Thermal Unit. A measure of the energy required to raise the temperature of one pound of water one degree Fahrenheit.
      Coal Seam. A bed or stratum of coal.
      Coal Washing. The process of removing impurities, such as ash and sulfur based compounds, from coal.
      Compliance Coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, which is equivalent to .72% sulfur per pound of 12,000 Btu coal. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the federal Clean Air Act.
      Continuous Miner. A machine used in underground mining to cut coal from the seam and load it into conveyors or into shuttle cars in a continuous operation.
      Continuous Mining. One of two major underground mining methods now used in the United States (also see “Longwall Mining”). This process utilizes a continuous miner. The continuous miner removes or “cuts” the coal from the seam. The loosened coal then falls on a conveyor for removal to a shuttle car or larger conveyor belt system.
      Dragline. A large machine used in the surface mining process to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket suspended from the end of a long boom. The bucket, which is suspended by cables, is able to scoop up great amounts of overburden as it is dragged across the excavation area.
      Dragline Mining. A method of mining where large capacity draglines remove overburden to expose the coal seams.
      Excavator-and-Loader Mining. A form of surface mining in which large excavators remove overburden from above the coal seam. The overburden is loaded into trucks and hauled to a valley fill or back-stacked on previously mined areas.
      Highwall Mining. Highwall mining employs a large machine with a continuous miner head. The head cuts into a coal seam and discharges coal out onto waiting conveyor belts. After highwall mining is completed, the openings are reclaimed. This method of mining is usually employed to recover any additional coal left in deep overburden areas that cannot be reached economically by other types of surface mining.

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      Longwall Mining. One of two major underground coal mining methods now used in the United States (see also “Continuous Mining”). This method employs a rotating drum, which is pulled mechanically back and forth across a face of coal that is usually several hundred feet long. The loosened coal falls onto a conveyor for removal from the mine. Longwall operations include a hydraulic roof support system that advances as mining proceeds, allowing the roof to fall in a controlled manner in areas already mined.
      Low-Sulfur Coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.
      Metallurgical Coal. The various grades of coal suitable for distillation into carbon in connection with the manufacture of steel. Also known as “met” coal.
      Preparation Plant. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.
      Probable Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart; therefore, the degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
      Proven Reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.
      Reclamation. The restoration of land and environmental values to a mining site after the coal is extracted. Reclamation operations are usually underway where the coal has already been taken from a mine, even as mining operations are taking place elsewhere at the site. The process commonly includes “recontouring” or shaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers.
      Recoverable Reserves. The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.
      Reserves. That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
      Spot Market. Sales of coal under an agreement for shipments over a period of less than one year.
      Steam Coal. Coal used in steam boilers to produce electricity.
      Surface Mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.
      Tons. References to a “ton” mean a “short” or net tonne, which is equal to 2,000 pounds.
      Truck-and-Loader Mining. A form of surface mining in which endloaders remove overburden from above the coal seam. The overburden is loaded into trucks and hauled to a valley fill or back-stacked on previously mined areas.
      Truck-and-Shovel Mining. An open-cast method of mining that uses large shovels to remove overburden, which is used to backfill pits after coal removal.
      Unassigned Reserves. Recoverable coal reserves that have not yet been designated for mining by a specific Company operation.
      Underground Mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.
Employees
      As of March 1, 2005, the Company employed a total of approximately 4,150 persons, approximately 530 of whom were represented by the UMWA under a collective bargaining agreement that expires in 2006 and approximately 190 of whom are represented by the Scotia Employees Association.

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EXECUTIVE OFFICERS
      The following is a list of the Company’s executive officers, their ages and their positions and offices held with the Company during the last five years.
      Bradley M. Allbritten, 47, is Vice President — Marketing of the Company and has served in such capacity since August 2002. From March 2000 to February 2003, Mr. Allbritten was the Company’s Vice President — Human Resources. Mr. Allbritten served as the Company’s Director of Human Resources from February 1999 through February 2000. From January 1995 to February 1999, Mr. Allbritten served as Human Resources Manager for Atlantic Richfield Company.
      C. Henry Besten, Jr., 56, is Senior Vice President — Strategic Development of the Company and has served in such capacity since December 2002. Mr. Besten is also President of the Company’s Arch Energy Resources, Inc. subsidiary and has served in that capacity since July 1997. From July 1997 to December 2002, Mr. Besten served as Vice President — Strategic Marketing of the Company. Mr. Besten also served as Acting Chief Financial Officer of the Company from December 1999 to November 2000.
      John W. Eaves, 47, is Executive Vice President and Chief Operating Officer of the Company and has served in such capacity since December 2002. From February 2000 to December 2002, Mr. Eaves served as Senior Vice President Marketing of the Company and from September 1995 to December 2002 as President of the Company’s Arch Coal Sales Company, Inc. subsidiary. Mr. Eaves also served as Vice President — Marketing of the Company from July 1997 through February 2000. Mr. Eaves serves on the board of directors of ADA-ES, Inc.
      Sheila B. Feldman, 50, is Vice President — Human Resources of the Company and has served in such capacity since February 2003. From 1997 to February 2003, Ms. Feldman was the Vice President — Human Resources and Public Affairs of Solutia Inc.
      Robert G. Jones, 48, is Vice President — Law, General Counsel and Secretary of the Company and has served in such capacity since March 2000. Mr. Jones served the Company as Assistant General Counsel from July 1997 through February 2000 and as Senior Counsel from August 1993 to July 1997.
      Steven F. Leer, 52, is President and Chief Executive Officer and a Director of the Company and has served in such capacity since 1992.
      Robert J. Messey, 59, is Senior Vice President and Chief Financial Officer of the Company and has served in such capacity since December 2000. Prior to joining Arch Coal, Mr. Messey served as vice president of financial services of Jacobs Engineering Group Inc. from January 1999 and, prior to that, served as senior vice president and chief financial officer of Sverdrup Corporation from 1992. Mr. Messey serves on the board of directors of Baldor Electric Company.
      David B. Peugh, 50, is Vice President — Business Development of the Company and has served in such capacity since 1993.

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ITEM 2. PROPERTIES
      The Company estimates that it owned or controlled, as of December 31, 2004, approximately 3.7 billion tons of proven and probable recoverable reserves. Recoverable reserves include only saleable coal and do not include coal which would remain unextracted, such as for support pillars, and processing losses, such as washery losses. Reserve estimates are prepared by the Company’s engineers and geologists and reviewed and updated periodically. Total recoverable reserve estimates and reserves dedicated to mines and complexes change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings and other factors. The following tables present the Company’s estimated assigned and unassigned recoverable coal reserves at December 31, 2004:
Total Assigned Reserves
(tonnage in millions)
                                                                                                         
    Total           Sulfur Content               Past Reserve
    Assigned           (lbs. Per million Btus)       Reserve Control   Mining Method   Estimates
    Recoverable               As Received            
    Reserves   Proven   Probable   <1.2   1.2-2.5   >2.5   Btu per lb.(1)   Leased   Owned   Surface   Underground   2002   2003
                                                     
Wyoming(2)
    1,840       1,791       49       1,782       58             8,804       1,840             1,840             1,089       1,025  
Central App
    409       322       87       116       274       19       12,832       386       23       157       252       388       441  
Illinois
                                                                               
Utah
    112       59       53       112                   11,652       110       2             112       125       116  
Colorado
    80       59       21       79       1             11,879       77       3             80       112       85  
                                                                               
Total
    2,441       2,231       211       2,089       333       19       9,715       2,413       28       1,997       444       1,714       1,667  
                                                                               
Total Unassigned Reserves
(tonnage in millions)
                                                                                         
    Total           Sulfur Content            
    Unassigned           (lbs. Per million Btus)       Reserve Control   Mining Method
    Recoverable               As Received        
    Reserves   Proven   Probable   <1.2   1.2-2.5   >2.5   Btu per lb.(1)   Leased   Owned   Surface   Underground
                                             
Wyoming
    487       313       174       438       49             9,483       392       95       313       174  
Central App
    418       271       147       120       243       55       12,778       321       97       87       331  
Illinois
    257       187       70                   257       11,325       36       221       12       245  
Utah
    37       17       20       29       8             11,229       37                   37  
Colorado
    58       46       12       57       1             11,529       58                   58  
                                                                   
Total
    1,257       834       423       644       301       312       11,100       844       413       412       845  
                                                                   
 
(1)  As received btu per lb. includes the weight of moisture in the coal on an as sold basis.
 
(2)  Includes approximately 700 million tons of coal reserves under the “Little Thunder” federal coal lease for which the Company was the successful bidder in September 2004. The coal lease for the Little Thunder reserves was issued effective March 1, 2005.
      As of December 31, 2004, approximately 90,000 acres out of the Company’s total of approximately 658,000 acres of coal land was leased from the federal government. These leases have terms expiring between 2005 and 2024, subject to readjustment or extension and to earlier termination for failure to meet diligent development requirements. The Company has entered into leases covering substantially all of its leased reserves which are not scheduled to expire prior to expiration of projected mining activities. Royalties are paid to lessors either as a fixed-price per-ton or as a percentage of the gross sales price of the mined coal. Under current mining plans, all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewals.
      The Company pays percentage-based royalties under the majority of its significant leases. The terms of most of these leases extend until the exhaustion of mineable and merchantable coal. The remaining leases have initial terms ranging from one to 40 years from the date of their execution, with most containing options to renew. In some cases, a lease bonus, or prepaid royalty, is required, payable either at the time of execution of the lease or in annual installments. In most cases, the prepaid royalty amount is applied to reduce future production royalties.

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      The Pine Creek, Black Bear, Campbells Creek, Samples, Ruffner and Holden 25/Ragland preparation plants and related loadout facilities are located on properties held under leases which expire at varying dates over the next thirty years with either optional 20-year extensions or with unlimited extensions, and the balance of the Company’s preparation plants and loadout facilities are located on property owned by the Company.
      All of the identified coal reserves held by the Company’s subsidiaries have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 74% consist of compliance coal while an additional 11% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Some of the Company’s low-sulfur coal can be marketed as compliance coal when blended with other compliance coal. Accordingly, most of the Company’s reserves are primarily suitable for the domestic steam coal markets. However, a portion of the low-sulfur and compliance coal reserves at the Mingo Logan operation, and coal reserves at the Cumberland River and Lone Mountain operations, when blended with coal from Mingo Logan, may also be used as metallurgical coal.
      Title to coal properties held by lessors or grantors to the Company and its subsidiaries and the boundaries of properties are normally verified at the time of leasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completely verified until such time as the Company’s independent operating subsidiaries prepare to mine such reserves. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine such reserves could be adversely affected.
      From time to time, lessors or sublessors of land leased by the Company’s subsidiaries have sought to terminate such leases on the basis that such subsidiaries have failed to comply with the financial terms of the leases or that the mining and related operations conducted by such subsidiaries are not authorized by the leases. Some of these allegations relate to leases upon which the Company conducts operations material to the Company’s consolidated financial position, results of operations and liquidity, but the Company does not believe any pending claims by such lessors or sublessors have merit or will result in the termination of any material lease or sublease.
      The Company leased 20,500 acres of property to other coal operators in 2004. The Company received royalty income of $4.0 million, $1.7 million, and $9.4 million in 2004, 2003 and 2002, respectively, from the mining of 2.9 million, 1.3 million tons and 6.9 million tons, respectively, on those properties. Reserves at properties leased by the Company to other coal operators are not included in the reserve figures set forth in this Annual Report.
      The Company must obtain permits from applicable state regulatory authorities before it begins to mine particular reserves. Applications for permits require extensive engineering and data analysis and presentation, and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and other impacts on the environment, the construction of overburden fills and water containment areas, and reclamation of the area after coal extraction. The Company is required to post bonds to secure performance under its permits. As is typical in the coal industry, the Company strives to obtain mining permits within a time frame that allows it to mine reserves as planned on an uninterrupted basis. The Company generally begins preparing applications for permits for areas that it intends to mine up to three years in advance of their expected issuance date. Regulatory authorities have considerable discretion in the timing of permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.
      The Company’s reported coal reserves are those that could be economically and legally extracted or produced at the time of their determination. In determining whether the Company’s reserves meet this standard, it takes into account, among other things, the Company’s potential inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. The Company has obtained, or the Company has a high probability of obtaining, all required permits or government approvals with respect to its reserves. Except as described elsewhere in this document with respect to permits to conduct mining operations involving valley fills, which has been taken into account in determining the Company’s reserves, the Company is not currently aware of matters which would significantly hinder its ability to obtain future mining permits or governmental approvals with respect to its reserves.
      The Company periodically engages third parties to review its reserve estimates. The most recent third party review of the Company’s reserve estimates was conducted by Weir International Mining Consultants in April 2003.
      The carrying cost of the Company’s coal reserves at December 31, 2004 was $1,322.2 million, consisting of $100.3 million of prepaid royalties and the $1,221.9 million net book value of coal lands and mineral rights.

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      The Company’s executive headquarters occupy approximately 78,000 square feet of leased space at One City Place Drive, in St. Louis, Missouri. See “Item 1. Business” for a further description of the Company’s subsidiaries’ mining complexes, mines, transportation facilities and other operations. The Company’s subsidiaries currently own or lease the equipment utilized in their mining operations.
ITEM 3. LEGAL PROCEEDINGS
      The information required by this Item is contained in the “Contingencies — Legal Contingencies” section of “Management’s Discussion and Analysis” contained in the Company’s 2004 Annual Report to Stockholders and is incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
      There were no matters submitted to a vote of security holders of the Company through the solicitation of proxies or otherwise during the fourth quarter of 2004.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
      The information required by this Item is contained in the Company’s 2004 Annual Report to Stockholders under the caption “Corporate Governance and Stockholder Information” and is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA
      The information required by this Item is contained in the Company’s 2004 Annual Report to Stockholders under the caption “Selected Financial Information”, and is incorporated herein by reference.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
      The information required by this Item is contained in the Company’s 2004 Annual Report to Stockholders under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, and is incorporated herein by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
      The information required by this Item is contained in the Company’s 2004 Annual Report to Stockholders under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, and is incorporated herein by reference.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
      Reference is made to Part IV, Item 14 of this Annual Report on Form 10-K for the information required by Item 8.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
      None.
ITEM 9A. CONTROLS AND PROCEDURES
      Reference is made to Part II, Item 8 of this Annual Report on Form 10-K for the information required by Item 9A.
ITEM 9B. OTHER INFORMATION
      None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
      There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the subcaptions “Nominees For a Three-Year Term That Will Expire in 2008”, “Directors Whose Terms Will Expire in 2007”, and “Directors Whose Terms Will Expire in 2006” which appear under the caption “Election of Directors” in the Company’s Proxy Statement to be distributed to Company stockholders in connection with the Company’s 2005 Annual Meeting (the “2005 Proxy Statement”). See also the list of the Company’s executive officers and related information under “Executive Officers” in Part I, Item 1 herein.
ITEM 11. EXECUTIVE COMPENSATION
      There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing in the “Summary Compensation Table”, the sections entitled “Stock Option Grants”, “Performance Unit Awards”, Performance — Contingent Phantom Stock Awards”, “Stock Option Exercises and Year-End Values”, and the Pension Plan section (including the table therein), the Employment Agreements section, and the Compensation of Directors section in the 2005 Proxy Statement. No portion of the Personnel and Compensation Committee Report on Executive Compensation for 2004 or the Arch Coal Performance Graph is incorporated herein in reliance on Regulation S-K, Item 402(a)(8).
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
      There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption “Ownership of Arch Coal Common Stock” in the 2005 Proxy Statement.
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
      None.
ITEM 14.  PRINCIPAL ACCOUNTANTS FEES AND SERVICES
      There is hereby incorporated by reference into this Annual Report on Form 10-K the information appearing under the caption “Audit Committee Report” in the 2005 Proxy Statement.

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PART IV
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
                   
          (a)(1)     The following consolidated financial statements of Arch Coal, Inc. and subsidiaries included in the Company’s 2004 Annual Report to Stockholders are incorporated by reference:
 
                  Consolidated Statements of Operations — Years Ended December 31, 2004, 2003 and 2002
 
                  Consolidated Balance Sheets — December 31, 2004 and 2003
 
                  Consolidated Statements of Stockholders’ Equity — Years Ended December 31, 2004, 2003 and 2002
 
                  Consolidated Statements of Cash Flows — Years Ended December 31, 2004, 2003 and 2002
 
                  Notes to Consolidated Financial Statements
 
          (a)(2)     The following consolidated financial statement schedule of Arch Coal, Inc. and subsidiaries is included in Item 14 at the page indicated:
 
                  II — Valuation and Qualifying Accounts at page   .
 
                All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted
 
          (a)(3)     Exhibits filed as part of this Report are as follows:
 
  3.1             Restated Certificate of Incorporation of Arch Coal, Inc. (incorporated herein by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2000)
 
  3.2             Restated and Amended Bylaws of Arch Coal, Inc. (incorporated herein by reference to the Company’s Annual Report on Form 10-K for the Year Ended December 31, 2000)
 
  4.1             Form of Rights Agreement, dated March 3, 2000 (incorporated herein by reference to Exhibit 1 to a current report on Form 8-A filed on March 9, 2000)
 
  4.2             Description of Indenture pursuant to Shelf Registration Statement (incorporated herein by reference to the Company’s Registration Statement on Form S-3 (Registration No. 333-58738) filed on April 11, 2001)
 
  4.3             Certificate of Designations Establishing the Designations, Powers, Preferences, Rights, Qualifications, Limitations and Restrictions of the Company’s 5% Perpetual Cumulative Convertible Preferred Stock (incorporated herein by reference to Exhibit 3 to current report on Form 8-A filed on March 5, 2003)
 
  4.4             Indenture, dated as of June 25, 2003, by and among Arch Western Finance, LLC, the Company, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., Thunder Basin Coal Company, L.L.C. and The Bank of New York, as trustee (incorporated herein by reference to Exhibit 4.1 to the Form S-4 of Arch Western Finance, LLC (Reg. No. 333-107569))
 
  4.5             Credit Agreement, dated as of December 22, 2004, by and among Arch Coal, Inc., the Banks party thereto, PNC Bank, National Association, as administrative agent, Citicorp USA, Inc., JPMorgan Chase Bank, N.A., and Wachovia Bank, National Association, as co-syndication agents, and Fleet National Bank, as documentation agent (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on December 28, 2004).
 
  10.1             Amended and Restated Retention Agreement between Arch Coal, Inc. and Steven F. Leer, dated October 1, 2004 (filed herewith)
 
  10.2             Form of Retention Agreement between Arch Coal, Inc. and each of its Executive Officers (other than its Chief Executive Officer) (filed herewith)

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  10.3             Deed of Lease and Agreement between Dingess-Rum Coal Company and Amherst Coal Company (predecessor to Ark Land Company), dated June 1, 1962, as supplemented January 1, 1968, June 1, 1973, July 1, 1974 and November 12, 1987; Lease Exchange Agreement dated July 2, 1979 amended as of January 1, 1984, January 7, 1993 and February 24, 1993; Partial Release dated as of May 6, 1988; Assignments dated March 15, 1990 and October 5, 1990 (incorporated herein by reference to Exhibit 10.8 of the Company’s Registration Statement on Form S-4 (Registration No. 333-28149) filed on May 30, 1997)
 
  10.4             Agreement of Lease by and between Shonk Land Company, Limited Partnership and Lawson Hamilton (predecessor to Ark Land Company), dated February 8, 1983, as amended October 7, 1987, March 9, 1989, April 1, 1992, October 31, 1992, December 5, 1992, February 16, 1993, August 4, 1994, October 1, 1995, July 31, 1996 and November 27, 1996 (incorporated herein by reference to Exhibit 10.9 of the Company’s Registration Statement on Form S-4 (Registration No. 333-28149) filed on May 30, 1997)
 
  10.5             Lease between Little Coal Land Company and Ashland Land & Development Co., a wholly-owned subsidiary of Ashland Coal, Inc. which was merged into Allegheny Land Company, a second tier subsidiary of the Company (incorporated herein by reference to Exhibit 10.11 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No.33-22425), as amended, filed by Ashland Coal, Inc., a subsidiary of the Company, on August 11, 1988)
 
  10.6             Agreement of Lease dated January 1, 1988, between Courtney Company and Allegheny Land Company (legal successor by merger with Allegheny Land Co. No. 2, the assignee of Primeacre Land Corporation under October 5, 1992, assignments), a second-tier subsidiary of the Company (incorporated herein by reference to Exhibit 10.3 to the Annual Report on Form 10-K for the Year Ended December 31, 1995, filed by Ashland Coal, Inc., a subsidiary of the Company)
 
  10.7             Lease between Dickinson Properties, Inc., the Southern Land Company, and F. B. Nutter, Jr. and F. B. Nutter, Sr., predecessors in interest to Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the Company that subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.14 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as Amended, filed by Ashland Coal, Inc., a subsidiary of the Company, on August 11, 1988)
 
  10.8             Lease Agreement between Fielden B. Nutter, Dorothy Nutter and Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the Company that Subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.22 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as amended, filed by Ashland Coal, Inc., a subsidiary of the Company, on August 11, 1988)
 
  10.9             Lease and Modification Agreement between Horse Creek Coal Land Company, Ashland and Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the Company that subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.24 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as amended, filed by Ashland Coal, Inc., a subsidiary of the Company, on August 11, 1988)
 
  10.10             Lease Agreement between C. C. Lewis Heirs Limited Partnership and Allegheny Land Company, a second-tier subsidiary of the Company (incorporated herein by reference to Exhibit 10.25 of a Post-Effective Amendment No 1 to a Registration Statement on Form S-1 (Registration No.33-22425), as amended, filed by Ashland Coal, Inc., a subsidiary of the Company, on August 11, 1988)
 
  10.11             Sublease between F. B. Nutter, Sr., et al., and Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the Company that subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.27 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as amended, filed by Ashland Coal, Inc., a subsidiary of the Company, on August 11, 1988)

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  10.12             Coal Lease Agreement dated as of March 31, 1992, among Hobet Mining, Inc. (successor by merger with Dal-Tex Coal Corporation) as lessee and UAC and Phoenix Coal Corporation, as lessors, and related Company Guarantee (incorporated herein by reference to a Current Report on Form 8-K dated April 6, 1992 filed by Ashland Coal, Inc., a subsidiary of the Company)
 
  10.13             Lease dated as of October 1, 1987, between Pocahontas Land Corporation and Mingo Logan Collieries Company whose name is now Mingo Logan Coal Company (incorporated herein by reference to Exhibit 10.3 to Amendment No. 1 to a Current Report on Form 8-K filed on February 14, 1990 by Ashland Coal, Inc., a subsidiary of the Company)
 
  10.14             Consent, Assignment of Lease and Guaranty dated January 24, 1990, among Pocahontas Land Corporation, Mingo Logan Coal Company, Mountain Gem Land, Inc. and Ashland Coal, Inc. (incorporated herein by reference to Exhibit 10.4 to Amendment No. 1 to a Current Report on Form 8-K filed on February 14, 1990 by Ashland Coal, Inc., a subsidiary of the Company)
 
  10.15             Federal Coal Lease dated as of June 24, 1993 between the United States Department of the Interior and Southern Utah Fuel Company (incorporated herein by reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.16             Federal Coal Lease between the United States Department of the Interior and Utah Fuel Company (incorporated herein by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.17             Federal Coal Lease dated as of July 19, 1997 between the United States Department of the Interior and Canyon Fuel Company, LLC (incorporated herein by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.18             Federal Coal Lease dated as of January 24, 1996 between the United States Department of the Interior and the Thunder Basin Coal Company (incorporated herein by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.19             Federal Coal Lease Readjustment dated as of November 1, 1967 between the United States Department of the Interior and the Thunder Basin Coal Company (incorporated herein by reference to Exhibit 10.21 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.20             Federal Coal Lease effective as of May 1, 1995 between the United States Department of the Interior and Mountain Coal Company (incorporated herein by reference to Exhibit 10.22 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.21             Federal Coal Lease dated as of January 1, 1999 between the Department of the Interior and Ark Land Company (incorporated herein by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.22             Federal Coal Lease dated as of October 1, 1999 between the United States Department of the Interior and Canyon Fuel Company, LLC (incorporated herein by reference to Exhibit 10 of the Company’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 1999)
 
  10.23             Federal Coal Lease effective as of March 1, 2005 by and between the United States of America and Ark Land LT, Inc. covering the tract of land known as “Little Thunder” in Campbell County, Wyoming (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on February 10, 2005)
 
  10.24             Modified Coal Lease (WYW71692) executed January 1, 2003 by and between the United States of America, through the Bureau of Land Management, as lessor, and Triton Coal Company, LLC, as lessee covering a tract of land known as “North Rochelle” in Campbell County, Wyoming (filed herewith).
 
  10.25             Coal Lease (WYW71692) executed January 1, 1998 by and between the United States of America, through the Bureau of Land Management, as lessor, and Triton Coal Company, LLC, as lessee covering a tract of land known as “North Roundup” in Campbell County, Wyoming (filed herewith).
 
  10.26             Form of Indemnity Agreement between Arch Coal, Inc. and Indemnitee (as defined therein) (incorporated herein by reference to Exhibit 10.15 of the Company’s Registration Statement on Form S-4 (Registration No. 333-28149) filed on May 30, 1997)

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  10.27             Arch Coal, Inc. Incentive Compensation Plan For Executive Officers (incorporated herein by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on February 28, 2005.
 
  10.28             Arch Coal, Inc. (formerly Arch Mineral Corporation) Deferred Compensation Plan (incorporated herein by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8 (Registration No. 333-68131) filed on December 1, 1998)
 
  10.29             Arch Coal, Inc. 1997 Stock Incentive Plan (as Amended and Restated on February 28, 2002) (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2002)
 
  10.30             Arch Mineral Corporation 1996 ERISA Forfeiture Plan (incorporated herein by reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-4 (Registration No. 333-28149) filed on May 30, 1997)
 
  10.31             Arch Coal, Inc. Outside Directors’ Deferred Compensation Plan effective January 1, 1999 (incorporated herein by reference to Exhibit 10.30 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  10.32             Second Amendment to the Arch Mineral Corporation Supplemental Retirement Plan effective January 1, 1998(incorporated herein by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K for the Year Ended December 31, 1998)
 
  13             Portions of the Company’s Annual Report to Stockholders for the year ended December 31, 2004 (filed herewith)
 
  21             Subsidiaries of the Company (filed herewith)
 
  23.1             Consent of Ernst & Young LLP (filed herewith)
 
  24             Power of Attorney (filed herewith)
 
  31.1             Rule 13a-14(a)/15d-14(a) Certification of Steven F. Leer (filed herewith)
 
  31.2             Rule 13a-14(a)/15d-14(a) Certification of Robert J. Messey (filed herewith)
 
  32.1             Section 1350 Certification of Steven F. Leer (filed herewith)
 
  32.2             Section 1350 Certification of Robert J. Messey (filed herewith)
 
Exhibits 10.27, 10.28, 10.29, 10.30 and 10.32 are executive compensation plans.
      Upon written or oral request to the Company’s Secretary, a copy of any of the above exhibits will be furnished at cost.

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SIGNATURES
      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  Arch Coal, Inc.
  (Registrant)
  By:  /s/ Steven F. Leer
 
 
  Steven F. Leer
  President and Chief Executive Officer
 
  Date: March 10, 2005
         
Signatures   Capacity
     
 
/s/ Steven F. Leer
 
Steven F. Leer
  President and Chief Executive Officer and Director
 
/s/ Robert J. Messey
 
Robert J. Messey
  Senior Vice President and Chief Financial Officer (Principal Financial Officer)
 
/s/ John W. Lorson
 
John W. Lorson
  Controller
 
*
 
James R. Boyd
  Director
 
*
 
Frank M. Burke
  Director
 
*
 
Patricia Fry Godley
  Director
 
*
 
Douglas H. Hunt
  Director
 
*
 
Thomas A. Lockhart
  Director
 
*
 
A. Michael Perry
  Director
 
*
 
Robert G. Potter
  Director
 
*
 
Theodore D. Sands
  Director
 
*By:   /s/ Robert G. Jones
 
Robert G. Jones
As Attorney-in-fact
   
ORIGINAL POWERS OF ATTORNEY AUTHORIZING STEVEN F. LEER AND ROBERT G. JONES, AND EACH OF THEM, TO SIGN THIS ANNUAL REPORT ON FORM 10-K AND ANY FURTHER AMENDMENTS THERETO ON BEHALF OF THE ABOVE-NAMED PERSONS HAVE BEEN WITH THE SECURITIES AND EXCHANGE COMMISSION AS EXHIBIT 24 TO THIS REPORT ON FORM 10-K.

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SCHEDULE II
ARCH COAL, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(in thousands)
                                               
        ADDITIONS            
        CHARGED            
    BALANCE AT   TO COSTS   CHARGED       BALANCE AT
    BEGINNING   AND   TO OTHER       END OF
    OF YEAR   EXPENSES   ACCOUNTS   DEDUCTIONS(1)   YEAR
                     
Year Ended December 31, 2004
                                       
 
Reserves deducted from Asset Accounts
                                       
   
Other Assets — Other Notes and Accounts Receivable
  $ 1,469     $ 570     $ 962 (2)   $     $ 3,001  
     
Current Assets — Supplies Inventory
    18,763       1,746       3,010 (2)     543       22,976  
   
Deferred Income Taxes
    161,113             2,157 (3)     265       163,005  
Year Ended December 31, 2003
                                       
 
Reserves deducted from Asset Accounts
                                       
   
Other Assets — Other Notes and Accounts Receivable
    3,894       1,315             3,740 (5)     1,469  
     
Current Assets — Supplies Inventory
    17,515       1,583             335       18,763  
   
Deferred Income Taxes
    145,603       3,543       11,967 (4)           161,113  
Year Ended December 31, 2002
                                       
 
Reserves deducted from Asset Accounts
                                       
   
Other Assets — Other Notes and Accounts Receivable
    544       3,409             59       3,894  
     
Current Assets — Supplies Inventory
    16,598       1,831             914       17,515  
   
Deferred Income Taxes
    119,723       25,880                   145,603  
 
(1)  Reserves utilized, unless otherwise indicated.
 
(2)  Balance at acquisition date of subsidiaries.
 
(3)  Amount represents the valuation allowance for tax benefits from the exercise of employee stock options. The benefit, net of valuation allowance, was recorded as paid-in capital.
 
(4)  Amount represents state net operating loss carryforwards identified in 2003 which were fully reserved.
 
(5)  Amount includes $1.6 million that was recognized as income upon collection of the related receivable.

21

EXHIBIT 10.1 October 1, 2004 Mr. Steven F. Leer [address] Dear Steve: In order to encourage you to remain in the employ of the Company, this Agreement sets forth those benefits which the Company will provide to you in the event your employment with the Company (1) is Terminated without Cause during the term of this Agreement, or (2) you resign for Good Reason following a Change in Control of the Company under the circumstances described below. SECTION A. DEFINITIONS 1. "Agreement" shall mean this letter agreement. 2. "Average Annual Bonus" shall be the highest of (i) the most recent annual bonus paid to you, (ii) if your date of termination occurs after the end of the calendar year but prior to the payment of annual bonuses with respect to the prior year, the amount calculated as payable as your annual bonus pursuant to the bonus targets approved by the Board of Directors of the Company for such year compared to the actual performance of the Company for such year; or (iii) the average annual bonus paid to you in the three full calendar years proceeding the Date of Termination. If you have not been employed by the Company, for three full calendar years prior to the Date of Termination, the average annual bonus for purposes of clause (iii) of this definition shall be a percentage of your highest annual salary in effect at any time during the term of this Agreement equal to the average percentage of annual base pay paid as an annual bonus by all executives of the Company at your Incentive Compensation level in the three calendar years proceeding the Date of Termination. 3. "Board" shall mean the Company's Board of Directors. 4. "Cause" shall occur hereunder only upon (A) the willful and continued failure by you substantially to perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to you by the Board which specifically identifies the manner in which the Board believes that you have not substantially performed your duties, (B) the willful engaging by you in gross misconduct materially and demonstrably injurious to the Company including, without limitation, a violation of the Company's Code of Business Conduct in effect from time to time, or (C) your conviction of or the entering of a plea of nolo contendere to the commission of a 1

felony. For purposes of this paragraph, no act, or failure to act, on your part shall be considered "willful" unless done, or omitted to be done, by you not in good faith and without reasonable belief that your action or omission was in the best interest of the Company. Notwithstanding the foregoing, you shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to you a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board at a meeting of the Board called and held for the purpose, among others (after at least 20 days prior notice to you and an opportunity for you, together with your counsel, to be heard before the Board), of finding that (i) in the good faith opinion of the Board you failed to perform your duties or engaged in misconduct as set forth above in subparagraph (A) or (B) of this paragraph, and, if applicable, that you did not correct such failure or cease such misconduct after being requested to do so by the Board, or (ii) as set forth in subparagraph (C) of this paragraph, you have been convicted of or have entered a plea of nolo contendere to the commission of a felony. 5. "Change in Control" shall be deemed to have occurred if (i) there shall be consummated (A) any consolidation, merger, or share exchange of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company in which the holders of the Company's Common Stock immediately prior to the merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the merger, or (B) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company, or (iii) at any time during a period of two (2) consecutive years, "Continuing Directors" shall cease for any reason to constitute at least a majority of the Board. For such purpose, "Continuing Directors" shall be directors who were in office at the beginning of such two year period and new directors whose election or nomination for election by the Company's shareholders was approved by a vote of at least two-thirds of the Continuing Directors then in office. 6. "COBRA" shall mean the Consolidated Omnibus Budget Reconciliation Act, as amended. 7. "Common Stock" shall mean the common stock, par value $0.01 per share, of the Company. 8. "Company" shall mean Arch Coal, Inc. and any successor to its business and/or assets which executes and delivers the agreement provided for in Section F, paragraph 1 hereof or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law. 9. "Competitive Activity" shall have the meaning as set forth in Section D, paragraph 4. 2

10. "Competitive Operation" shall have the meaning as set forth in Section D, paragraph 4. 11. "Confidential Information" shall mean information relating to the Company's, its divisions' and Subsidiaries' and their successors' business practices and business interests, including, but not limited to, customer and supplier lists, business forecasts, business and strategic plans, financial and sales information, information relating to products, process, equipment, operations, marketing programs, research, or product development, engineering records, computer systems and software, personnel records or legal records. 12. "Constructive Termination" shall mean your resignation of employment with the Company after the occurrence of any one of the following events: (i) a reduction in your base salary or Incentive Compensation level or participation in any of the benefit plans or compensation plans of the Company for which you are currently or become eligible during the term of this Agreement; (ii) a diminution of your position, duties, title, status or responsibilities during the term of this Agreement; (iii) a failure by the Company to, in good faith, review the appropriateness of your base salary and incentive compensation package on at least an annual basis; or (iv) any breach by the Company of any material provision of this Agreement. 13. "Date Of Termination" shall mean: (A) if this Agreement is terminated for Disability, thirty (30) days after the Notice of Termination is given by the Company to you (provided that you shall not have returned to the performance of your duties on a full-time basis during such thirty (30) day period), (B) if your employment is terminated for Good Reason by you, the date specified in the Notice of Termination, and (C) if your employment is Terminated for any other reason, the date on which a Notice of Termination is received or delivered by you unless a later date is specified. 14. "Disability" shall occur when: if, as a result of your incapacity due to physical or mental illness, you shall have been absent from your duties with the Company for six (6) consecutive months and shall not have returned to full-time performance of your duties within thirty (30) days after written notice is given to you by the Company. 15. "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended. 16. "Excise Tax" shall have the meaning as set forth in Section E. 17. "Good Reason" shall mean: (a) without your express written consent, the assignment to you after a Change in Control of the Company, of any duties inconsistent with, or a significant diminution of, your position, duties, responsibilities or status with the 3

Company immediately prior to a Change in Control of the Company, or a diminution in your titles as in effect immediately prior to a Change in Control of the Company or any removal of you from, or any failure to reelect you to, any of such positions; (b) a reduction by the Company in your base salary in effect immediately prior to a Change in Control of the Company or a failure by the Company to increase (within fifteen months of your last increase in base salary) your base salary after a Change in Control of the Company in an amount which is substantially similar, on a percentage basis, to the average percentage increase in base salary for all corporate officers of the Company during the preceding twelve (12) months; (c) the failure by the Company to continue in effect any thrift, stock ownership, pension, life insurance, health, dental and accident or disability plan in which you are participating or are eligible to participate at the time of a Change in Control of the Company (or plans providing you with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any Change in Control of the Company, or the taking of any action by the Company which would adversely affect your participation in or materially reduce your benefits under any of such plans or deprive you of any material fringe benefits enjoyed by you at the time of the Change in Control of the Company or the failure by the Company to provide you with the number of paid vacation days to which you are entitled in accordance with the vacation policies of the Company in effect at the time of a Change in Control of the Company, unless a comparable plan is substituted therefor; (d) the failure by the Company to continue in effect any incentive plan or arrangement (including without limitation, the Company's incentive compensation plan, annual bonus and contingent bonus arrangements and credits and the right to receive performance awards and similar incentive compensation benefits) in which you are participating at the time of a Change in Control of the Company (or to substitute and continue other plans or arrangements providing you with substantially similar benefits), or a reduction in your Incentive Compensation level in effect at the time of a Change in Control of the Company except as otherwise required by the terms of such plans as in effect at the time of any Change in Control of the Company; (e) the failure by the Company to continue in effect any plan or arrangement to receive securities of the Company (including, without limitation, any plan or arrangement to receive and exercise stock options, stock appreciation rights, restricted stock or grants thereof or to acquire stock or other securities of the Company) in which you are participating at the time of a Change in Control of the Company (or to substitute and continue plans or arrangements providing you with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any Change in Control of the Company, or 4

the taking of any action by the Company which would adversely affect your participation in or materially reduce your benefits under any such plan; (f) the relocation of the Company's principal executive offices to a location outside the St. Louis metropolitan area, or the Company's requiring you to be based anywhere other than at your current location or at the location of the Company's principal executive or divisional offices, except for required travel on the Company's business to an extent substantially consistent with your present business travel obligations, or, in the event you consent to any such relocation of the Company's principal executive or divisional offices, the failure by the Company to pay (or reimburse you for) all reasonable moving expenses incurred by you relating to a change of your principal residence in connection with such relocation and to indemnify you against any loss (defined as the difference between the actual sale price of such residence and the greater of (a) your aggregate investment in such residence, or (b) the fair market value of such residence as determined by a real estate appraiser reasonably satisfactory to both you and the Company) realized in the sale of your principal residence in connection with any such change of residence; (g) any breach by the Company of any material provision of this Agreement; or (h) any failure by the Company to obtain the assumption of this Agreement by any successor or assign of the Company. 18. "Gross-up Payment" shall have the meaning as set forth in Section E. 19. "Notice of Termination" shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of your employment under the provision so indicated. 20. "Payment" shall have the meaning as set forth in Section E. 21. "Person" shall have the meaning as set forth in Sections 13(d) and 14(d)(2) of the Exchange Act. 22. "Qualifying Termination" shall mean the termination of your employment after a Change in Control of the Company while this Agreement is in effect, unless such termination is (a) by reason of your death or Disability, (b) by the Company for Cause, or (c) by you other than for Good Reason. 23. "Salary Continuation Period" shall have the meaning set forth in Section C, paragraph 1. 5

24. "Significant Stockholder" shall mean any shareholder of the Company who, immediately prior to the Effective Date, owned more than 5% of the common stock of the company. 25. "Subsidiary" shall mean any corporation of which more than 20% of the outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether or not at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency) is at the time directly or indirectly owned by the Company, by the Company and one or more other Subsidiaries, or by one or more other Subsidiaries. 26. "Termination" shall mean the actual or Constructive Termination of your employment with the Company. SECTION B. TERM AND BENEFITS This Agreement shall be in effect for a period of one (1) year from the date you accept this Agreement and shall automatically renew for successive one (1) year periods unless terminated by either party by at least one (1) year advance written notice prior to the commencement of the next succeeding one (1) year period at which time the Agreement shall terminate at the end of the next succeeding one (1) year period. During the term of employment hereunder, you agree to devote your full business time and attention to the business and affairs of the Company and to use your best efforts, skills and abilities to promote its interests. In the event of your retirement, at your election or in accordance with the Company's generally applicable retirement policies, as in effect from time to time, this Agreement shall automatically terminate, without additional notice to you, as of the effective date of your retirement. Notwithstanding the first sentence of this paragraph and the first sentence of this Section B, if a Change in Control of the Company should occur while you are still an employee of the Company and while this Agreement is in effect, then this Agreement shall continue in effect from the date of such Change in Control of the Company for a period of two years. Prior to a Change in Control of the Company, your employment may be terminated by the Company for Cause at any time pursuant to a Notice of Termination. In such event, you shall not be entitled to the benefits provided hereunder. No benefits shall be payable hereunder unless your employment is terminated without Cause or there shall have been a Change in Control of the Company and your employment by the Company shall thereafter terminate in accordance with Section D hereof. SECTION C. TERMINATION PRIOR TO CHANGE IN CONTROL 1. Compensation Prior to a Change in Control. If you are Terminated by the Company without Cause during the term of this Agreement and prior to a Change in Control of the Company, you shall be entitled to receive: 6

(a) payment of the higher of; (1) your salary immediately prior to your Date of Termination, or (2) your highest salary during the prior three fiscal years preceding the fiscal year in which your Date of Termination occurs, for a period of two (2) years after your Date of Termination ("Salary Continuation Period"); (b) continuation of your and your eligible dependents' existing participation at regular employee rates, in effect from time to time, in all of the Company's medical, dental and group life plans and other programs in which you were participating immediately prior to your Date of Termination during the Salary Continuation Period, after which time you and your eligible dependents will be eligible for coverage under COBRA. In the event that your continued participation in any such plan or program is for whatever reason impossible, the Company shall arrange upon comparable terms to provide you with benefits substantially equivalent on an after tax basis to those which you and your eligible dependents are, or become, entitled to receive under such plans and programs; (c) if and when payments are made, payment in cash of any pro-rata portion (up through your Date Of Termination) of any amounts you would have received under the Company's performance unit/share plans, Annual Incentive Compensation Plan, and any other similar executive compensation plan in which you were a participant immediately prior to your Date of Termination; (d) provide for payment in cash an amount equal to your Average Annual Bonus; (e) continuation of your existing participation in the Company's thrift plan, cash balance pension plan, non-qualified supplemental pension plan, deferred compensation plan and financial counseling services plan during the Salary Continuation Period (payments made pursuant to paragraph 1(a) and 1(c) hereof shall be deemed includable compensation under these plans to the same extent as if you had remained an active employee of the company and the payments were made for base salary and annual bonus, respectively); (f) outplacement services substantially similar to those historically offered by the Company to displaced senior executives; for a period not to exceed the Salary Continuation Period; (g) pay to you an amount equal to the value of all unused, earned and accrued vacation as of your Date of Termination; and (h) provide for the immediate vesting of all stock options held by you, as of your Date of Termination, under any Company stock option plan and all such options shall be exercisable during the Salary Continuation Period and for 120 days thereafter. 7

However, in the event that your employment with the Company is Terminated during the term of this Agreement and prior to a Change in Control of the Company and such Termination is not a Termination without Cause (including, without limitation, termination by reason of your voluntary termination (other than Constructive Termination), retirement, death, or Disability), or if your employment is terminated for Cause during the term of this Agreement, you shall not be entitled to receive any benefits under this Agreement. 2. Release. In exchange for the benefits herein, you completely release the Company to the fullest extent permitted by law from all claims you may have against the Company on your Date of Termination except claims related to (a) claims for benefits to which you are entitled under this Agreement and (b) any applicable worker's compensation or unemployment compensation. 3. Payment of Benefits. Unless otherwise provided in this Agreement, in the applicable compensation or stock option plan or program, or unless you otherwise elect, all payments shall be made to you in a single lump sum within thirty (30) days after your Date of Termination. Notwithstanding the payment of benefits hereunder in a lump sum, the benefits stated herein to continue through the Salary Continuation Period shall continue through the period. These benefits are in addition to all accrued and vested benefits to which you are entitled to under any of the Company's plans and arrangements, including but not limited to, the accrued vested benefits to which you are eligible for and entitled to receive under any of the Company's qualified and non-qualified benefit or retirement plans, or any successor plans in effect on your Date of Termination hereunder. 4. No Duty to Mitigate. You shall not be required to mitigate the amount of any payment provided for in this Section by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Section be reduced by any compensation earned by you as the result of employment by another employer after your Date of Termination, or otherwise. Except as provided herein, the Company shall have no right to set off against any amount owing hereunder any claim which it may have against you. SECTION D. TERMINATION FOLLOWING CHANGE IN CONTROL 1. Qualifying Termination. If your termination is a Qualifying Termination, you shall be entitled to receive the payments and benefits provided in this Section. 2. Notice of Termination. Except as provided in Section F, paragraph 1, any termination of your employment following a Change in Control of the Company shall be communicated by written Notice of Termination to the other party hereto. No termination shall be effective without such Notice of Termination. 8

3. Compensation Upon Termination After a Change in Control. (a) If your termination is a Qualifying Termination, then the Company shall pay to you as severance pay (and without regard to the provisions of any benefit or incentive plan), in a lump sum cash payment on the fifth (5th) day following your Date of Termination, an amount equal to three (3) times the higher of; (1) your salary immediately prior to your Date of Termination, or (2) your highest salary during the prior three (3) fiscal years preceding the fiscal year in which your Date of Termination occurs or, if greater, the prior three (3) fiscal years preceding the fiscal year in which the Change in Control of the Company occurs. (b) If your termination is a Qualifying Termination, the Company shall, in addition to the payments required by the preceding paragraph: (i) provide for continuation of your and your eligible dependents' participation at regular employee rates, in effect from time to time, in all of the Company's medical, dental and group life plans and other programs in which you were participating immediately prior to your Date of Termination for a period of three years from your Date of Termination, after which time you and your eligible dependents will be eligible for coverage under COBRA. In the event that your continued participation in any such plan or program is for whatever reason impossible, the Company shall arrange upon comparable terms to provide you with benefits substantially equivalent on an after tax basis to those which you and your eligible dependents are, or become, entitled to receive under such plans and programs; (ii) provide for full payment in cash of any performance unit/share awards in existence on your Date of Termination less any amounts paid to you under the applicable performance unit/share plan upon a Change in Control of the Company pursuant to the provisions of such plan; plus any pro rata portion (up through your date of termination) of any amounts you would have received under the Company's Incentive Compensation Plan and any other similar executive compensation plan in which you were a participant immediately prior to your Date of Termination; (iii) provide for payment in cash of an amount equal to three times your Average Annual Bonus; (iv) provide those benefits or compensation under any compensation plan, arrangement or agreement not in existence as of the date hereof but which may be established by the Company prior to your Date of Termination at such time as payments are made thereunder to the same extent as if you had been a full-time employee on the date such payments would otherwise have been made or benefits vested; 9

(v) for three (3) years after your Date of Termination, provide and pay for outplacement services, by a firm reasonably acceptable to you, that have historically been offered to displaced employees generally by the Company under substantially the same terms and fee structure as is consistent with an employee in your then current position (or, if higher, your position immediately prior to the Change in Control of the Company); (vi) for three (3) years after your Date of Termination, provide and pay for financial planning services, by a firm reasonably acceptable to you, that have historically been offered to you under substantially the same terms and fee structure as is consistent with an employee in your then current position (or, if higher, your position immediately prior to the Change in Control of the Company); (vii) pay to you an amount equal to the value of all unused, earned and accrued vacation as of your Date of Termination pursuant to the Company's policies in effect immediately prior to the Change in Control of the Company; and (viii) provide for the immediate vesting of all stock options held by you, as of your Date of Termination, under any Company stock option plan and all such options shall be exercisable for the remaining terms of the options. (ix) payments made pursuant to paragraphs 3.(a) and 3.(b)(iii) hereof shall be deemed includable compensation under the Company's thrift plan, cash balance pension plan, non-qualified supplemental pension plan and deferred compensation plan as if you had remained an active employee of the Company and payments were made for base salary and annual bonus, respectively. 4. Release. In exchange for the benefits herein, you completely release the Company to the fullest extent permitted by law from all claims you may have against the Company on your Date of Termination except claims related to (a) claims for benefits to which you are entitled under this Agreement and (b) any applicable worker's compensation or unemployment compensation. 5. Payment of Benefits. Unless otherwise provided in this Agreement or in the applicable compensation or stock option plan or program, or unless you otherwise elect, all payments shall be made to you within thirty (30) days after your Date of Termination. These benefits are in addition to all accrued and vested benefits to which you are entitled to under any of the Company's plans and arrangements, including but not limited to, the accrued vested benefits to which you are eligible for and entitled to receive under any of the Company's qualified and non-qualified benefit or retirement plans, or any successor plans in effect on your Date of Termination hereunder. 10

6. No duty to Mitigate. You shall not be required to mitigate the amount of any payment provided for in this Section by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Section be reduced by any compensation earned by you as the result of employment by another employer after your Date of Termination, or otherwise. Except as provided herein, the Company shall have no right to set off against any amount owing hereunder any claim which it may have against you. 7. Competitive Activity. In consideration of the foregoing, you agree that if your employment is terminated during the term of this Agreement and after a Change in Control of the Company, then during a period ending six (6) months following your Date of Termination you shall not engage in any Competitive Activity; provided, you shall not be subject to the foregoing obligation if the Company breaches a material provision of this Agreement. If you choose to engage in any Competitive Activity during that period, the Company shall be entitled to recover any benefits paid to you under this Agreement. For purposes of this Agreement, "Competitive Activity" shall mean your participation, without the written consent of the General Counsel of the Company, in the management of any business operation of any enterprise if such operation (a "Competitive Operation") engages in substantial and direct competition with any business operation actively conducted by the Company or its divisions and Subsidiaries on your Date of Termination. For purposes of this paragraph, a business operation shall be considered a Competitive Operation if such business sells a competitive product or service which constitutes (i) 15% of that business's total sales or (ii) 15% of the total sales of any individual subsidiary or division of that business and, in either event, the Company's sales of a similar product or service constitutes (i) 15% of the total sales of the Company or (ii) 15% of the total sales of any individual Subsidiary or division of the Company. Competitive Activity shall not include (i) the mere ownership of securities in any enterprise, or (ii) participation in the management of any enterprise or any business operation thereof, other than in connection with a Competitive Operation of such enterprise. SECTION E. ADDITIONAL PAYMENTS BY THE COMPANY Notwithstanding anything to the contrary in this Agreement, in the event that any payment or distribution by the Company to or for your benefit, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (a "Payment"), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended, or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest or penalties, are hereinafter collectively referred to as the "Excise Tax"), the Company shall pay to you an additional payment (a "Gross-up Payment") in an amount such that after payment by you of all taxes (including any interest or penalties imposed with respect to such taxes), including any income, employment and Excise Tax imposed on any Gross-up Payment, you retain an amount of the Gross-up Payment equal to the Excise Tax imposed upon the Payments. You and the Company shall make an initial determination as to whether a 11

Gross-up Payment is required and the amount of any such Gross-up Payment. If you and the Company can not agree on whether a Gross-up Payment is required or the amount thereof, then an independent nationally recognized accounting firm, appointed by you, shall determine the amount of the Gross-up Payment. The Company shall pay all expenses which you may incur in determining the Gross-up Payment. You shall notify the Company in writing of any claim by the Internal Revenue Service which, if successful, would require the Company to make a Gross-up Payment (or a Gross-up Payment in excess of that, if any, initially determined by the Company and you) within ten days of the receipt of such claim. The Company shall notify you in writing at least ten days prior to the due date of any response required with respect to such claim if it plans to contest the claim. If the Company decides to contest such claim, you shall cooperate fully with the Company in such action; provided, however, the Company shall bear and pay directly or indirectly all costs and expenses (including additional interest and penalties) incurred in connection with such action and shall indemnify and hold you harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of the Company's action. If, as a result of the Company's action with respect to a claim, you receive a refund of any amount paid by the Company with respect to such claim, you shall promptly pay such refund to the Company. If the Company fails to timely notify you whether it will contest such claim or the Company determines not to contest such claim, then the Company shall immediately pay to you the portion of such claim, if any, which it has not previously paid to you. SECTION F. MISCELLANEOUS 1. Assumption of Agreement. The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation, share exchange or otherwise) to all or substantially all of the business and/or assets of the Company, by agreement in form and substance satisfactory to you, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Failure of the Company to obtain such agreement prior to the effectiveness of any such succession shall be a breach of a material provision of this Agreement and shall entitle you to compensation in the same amount and on the same terms as you would be entitled pursuant to Section D, except that for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed your Date of Termination without a Notice of Termination being given. 2. Confidentiality. All Confidential Information which you acquire or have acquired in connection with or as a result of the performance of services for the Company, whether under this Agreement or prior to the effective date of this Agreement, shall be kept secret and confidential by you unless (a) the Company otherwise consents, (b) the Company breaches any material provision of this Agreement, or (c) you are legally required to disclose such Confidential Information by a court of competent jurisdiction. This covenant of confidentiality shall extend beyond the term of this Agreement and shall survive the termination of this Agreement for any 12

reason. If you breach this covenant of confidentiality, the Company shall be entitled to recover from any benefits paid to you under this Agreement its damages resulting from such breach. 3. Employment. You agree to be bound by the terms and conditions of this Agreement and to remain in the employ of the Company during any period following any public announcement by any Person of any proposed transaction or transactions which, if effected, would result in a Change in Control of the Company until a Change in Control of the Company has taken place. However, nothing contained in this Agreement shall impair or interfere in any way with the right of the Company to terminate your employment for Cause prior to a Change in Control of the Company. 4. Arbitration. Any controversy or claim arising out of or relating to this Agreement, or the breach thereof, shall be settled exclusively by arbitration in accordance with the Center for Public Resources' Model ADR Procedures and Practices, and judgment upon the award rendered by the arbitrator(s) may be entered in any court having jurisdiction thereof. Notwithstanding the foregoing, the Company shall not be restricted from seeking equitable relief, including injunctive relief as set forth in paragraph 5 of this Section, in the appropriate forum. Any cost of arbitration will be paid by the Company. In the event of a dispute over the existence of Good Reason or Cause after a Change in Control of the Company, the Company shall continue to pay your salary, bonuses and plan benefits pending resolution of the dispute. If you prevail in the arbitration, the remaining amounts due to you under this Agreement are to be immediately paid to you. 5. Injunctive Relief. You acknowledge and agree that the remedy of the Company at law for any breach of the covenants and agreements contained in paragraph 2 of this Section and in Section D, paragraph 4 will be inadequate, and that the Company will be entitled to injunctive relief against any such breach or any threatened, imminent, probable or possible breach. You represent and agree that such injunctive relief shall not prohibit you from earning a livelihood acceptable to you. 6. Notice. For the purposes of this Agreement, notices and all other communications provided for in this Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the respective addresses set forth on the first page of this Agreement, provided that all notices to the Company shall be directed to the attention of the General Counsel of the Company, or to such other address as either party may have furnished to the other in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt. 7. Indemnification. The Company will indemnify you to the fullest extent permitted by the laws of the State of Missouri and the existing By-laws of the Company, in respect of all your services rendered to the Company and its divisions and Subsidiaries prior to your Date of Termination. You shall be entitled to the protection of any insurance policies the Company now or hereafter maintains generally for the benefit 13

of its directors, officers and employees (but only to the extent of the coverage afforded by the existing provisions of such policies) to protect against all costs, charges and expenses whatsoever incurred or sustained by you in connection with any action, suit or proceeding to which you may be made a party by reason of your being or having been a director, officer or employee of the Company or any of its divisions or Subsidiaries during your employment therewith. 8. Further Assurances. Each party hereto agrees to furnish and execute such additional forms and documents, and to take such further action, as shall be reasonably and customarily required in connection with the performance of this Agreement or the payment of benefits hereunder. 9. Miscellaneous. No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing signed by you and such officer(s) as may be specifically designated by the Board. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly in this Agreement. 10. Termination of other Agreements. Upon execution by both parties, this Agreement shall terminate and shall replace all prior employment and severance agreements between you and the Company and its divisions or Subsidiaries and the terms hereof shall govern as if executed on the initial date of such prior employment and severance agreements. 11. Severability. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect. 12. Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument. 13. Legal Fees And Expenses. Any other provision of this Agreement notwithstanding, the Company shall pay all legal fees and expenses which you may incur as a result of the Company's unsuccessful contesting of the validity, enforceability or your interpretation of, or determinations under, any part of this Agreement. 14. Governing Law. This Agreement shall be governed in all respects by the laws of the State of Missouri. 15. Agreement Binding on Successors. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and 14

assigns. This Agreement shall inure to the benefit of and be enforceable by your personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If you should die while any amounts would still be payable to you hereunder if you had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to your devisee, legatee, or other designee or, if there be no such designee, to your estate. 16. Headings. All Headings are inserted for convenience only and shall not affect any construction or interpretation of this Agreement. If this Agreement correctly sets forth our agreement on the subject matter hereof, please sign and return to the Company the enclosed copy of this Agreement which will then constitute our agreement on this matter. Sincerely, ARCH COAL, INC. By: ----------------------------------- ACCEPTED as of the day first above written - ------------------------------- Employee 15

EXHIBIT 10.2 October 1, 2004 [Employee name and Address] Dear : --------------------------- In order to encourage you to remain in the employ of the Company, this Agreement sets forth those benefits which the Company will provide to you in the event your employment with the Company (1) is Terminated without Cause during the term of this Agreement, or (2) you resign for Good Reason following a Change in Control of the Company under the circumstances described below. SECTION A. DEFINITIONS 1. "Agreement" shall mean this letter agreement. 2. "Average Annual Bonus" shall be the highest of (i) the most recent annual bonus paid to you, (ii) if your date of termination occurs after the end of the calendar year but prior to the payment of annual bonuses with respect to the prior year, the amount calculated as payable as your annual bonus pursuant to the bonus targets approved by the Board of Directors of the Company for such year compared to the actual performance of the Company for such year; or (iii) the average annual bonus paid to you in the three full calendar years proceeding the Date of Termination. If you have not been employed by the Company, for three full calendar years prior to the Date of Termination, the average annual bonus for purposes of clause (iii) of this definition shall be a percentage of your highest annual salary in effect at any time during the term of this Agreement equal to the average percentage of annual base pay paid as an annual bonus by all executives of the Company at your Incentive Compensation level in the three calendar years proceeding the Date of Termination. 3. "Board" shall mean the Company's Board of Directors. 4. "Cause" shall occur hereunder only upon (A) the willful and continued failure by you substantially to perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to you by the Board which specifically identifies the manner in which the Board believes that you have not substantially performed your duties, (B) the willful engaging by you in gross misconduct materially and demonstrably injurious to the Company including, without limitation, a violation of the Company's Code of Business Conduct in effect from time to time, or (C) your conviction of or the entering of a plea of nolo contendere to the commission of a felony. For purposes of this paragraph, no act, or failure to act, on your part shall be 1

considered "willful" unless done, or omitted to be done, by you not in good faith and without reasonable belief that your action or omission was in the best interest of the Company. Notwithstanding the foregoing, you shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to you a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board at a meeting of the Board called and held for the purpose, among others (after at least 20 days prior notice to you and an opportunity for you, together with your counsel, to be heard before the Board), of finding that (i) in the good faith opinion of the Board you failed to perform your duties or engaged in misconduct as set forth above in subparagraph (A) or (B) of this paragraph, and, if applicable, that you did not correct such failure or cease such misconduct after being requested to do so by the Board, or (ii) as set forth in subparagraph (C) of this paragraph, you have been convicted of or have entered a plea of nolo contendere to the commission of a felony. 5. "Change in Control" shall be deemed to have occurred if (i) there shall be consummated (A) any consolidation, merger, or share exchange of the Company in which the Company is not the continuing or surviving corporation or pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, other than a merger of the Company in which the holders of the Company's Common Stock immediately prior to the merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the merger, or (B) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company, or (ii) the shareholders of the Company shall approve any plan or proposal for the liquidation or dissolution of the Company, or (iii) at any time during a period of two (2) consecutive years, "Continuing Directors" shall cease for any reason to constitute at least a majority of the Board. For such purpose, "Continuing Directors" shall be directors who were in office at the beginning of such two year period and new directors whose election or nomination for election by the Company's shareholders was approved by a vote of at least two-thirds of the Continuing Directors then in office. 6. "COBRA" shall mean the Consolidated Omnibus Budget Reconciliation Act, as amended. 7. "Common Stock" shall mean the common stock, par value $0.01 per share, of the Company. 8. "Company" shall mean Arch Coal, Inc. and any successor to its business and/or assets which executes and delivers the agreement provided for in Section F, paragraph 1 hereof or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law. 9. "Competitive Activity" shall have the meaning as set forth in Section D, paragraph 4. 2

10. "Competitive Operation" shall have the meaning as set forth in Section D, paragraph 4. 11. "Confidential Information" shall mean information relating to the Company's, its divisions' and Subsidiaries' and their successors' business practices and business interests, including, but not limited to, customer and supplier lists, business forecasts, business and strategic plans, financial and sales information, information relating to products, process, equipment, operations, marketing programs, research, or product development, engineering records, computer systems and software, personnel records or legal records. 12. "Constructive Termination" shall mean your resignation of employment with the Company after the occurrence of any one of the following events: (i) a reduction in your base salary or Incentive Compensation level or participation in any of the benefit plans or compensation plans of the Company for which you are currently or become eligible during the term of this Agreement; (ii) a diminution of your position, duties, title, status or responsibilities during the term of this Agreement; (iii) a failure by the Company to, in good faith, review the appropriateness of your base salary and incentive compensation package on at least an annual basis; or (iv) any breach by the Company of any material provision of this Agreement. 13. "Date Of Termination" shall mean: (A) if this Agreement is terminated for Disability, thirty (30) days after the Notice of Termination is given by the Company to you (provided that you shall not have returned to the performance of your duties on a full-time basis during such thirty (30) day period), (B) if your employment is terminated for Good Reason by you, the date specified in the Notice of Termination, and (C) if your employment is Terminated for any other reason, the date on which a Notice of Termination is received or delivered by you unless a later date is specified. 14. "Disability" shall occur when: if, as a result of your incapacity due to physical or mental illness, you shall have been absent from your duties with the Company for six (6) consecutive months and shall not have returned to full-time performance of your duties within thirty (30) days after written notice is given to you by the Company. 15. "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended. 16. "Excise Tax" shall have the meaning as set forth in Section E. 17. "Good Reason" shall mean: (a) without your express written consent, the assignment to you after a Change in Control of the Company, of any duties inconsistent with, or a significant diminution of, your position, duties, responsibilities or status with the Company immediately prior to a Change in Control of the Company, or a 3

diminution in your title(s) as in effect immediately prior to a Change in Control of the Company or any removal of you from, or any failure to reelect you to, any of such positions; (b) a reduction by the Company in your base salary in effect immediately prior to a Change in Control of the Company or a failure by the Company to increase (within fifteen months of your last increase in base salary) your base salary after a Change in Control of the Company in an amount which is substantially similar, on a percentage basis, to the average percentage increase in base salary for all corporate officers of the Company during the preceding twelve (12) months; (c) the failure by the Company to continue in effect any thrift, stock ownership, pension, life insurance, health, dental and accident or disability plan in which you are participating or are eligible to participate at the time of a Change in Control of the Company (or plans providing you with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any Change in Control of the Company, or the taking of any action by the Company which would adversely affect your participation in or materially reduce your benefits under any of such plans or deprive you of any material fringe benefits enjoyed by you at the time of the Change in Control of the Company or the failure by the Company to provide you with the number of paid vacation days to which you are entitled in accordance with the vacation policies of the Company in effect at the time of a Change in Control of the Company, unless a comparable plan is substituted therefor; (d) the failure by the Company to continue in effect any incentive plan or arrangement (including without limitation, the Company's incentive compensation plan, annual bonus and contingent bonus arrangements and credits and the right to receive performance awards and similar incentive compensation benefits) in which you are participating at the time of a Change in Control of the Company (or to substitute and continue other plans or arrangements providing you with substantially similar benefits), or a reduction in your Incentive Compensation level in effect at the time of a Change in Control of the Company except as otherwise required by the terms of such plans as in effect at the time of any Change in Control of the Company; (e) the failure by the Company to continue in effect any plan or arrangement to receive securities of the Company (including, without limitation, any plan or arrangement to receive and exercise stock options, stock appreciation rights, restricted stock or grants thereof or to acquire stock or other securities of the Company) in which you are participating at the time of a Change in Control of the Company (or to substitute and continue plans or arrangements providing you with substantially similar benefits), except as otherwise required by the terms of such plans as in effect at the time of any Change in Control of the Company, or the taking of any action by the Company which would adversely affect your participation in or materially reduce your benefits under any such plan; 4

(f) the relocation of the Company's principal executive offices to a location outside the St. Louis metropolitan area, or the Company's requiring you to be based anywhere other than at your current location or at the location of the Company's principal executive or divisional offices, except for required travel on the Company's business to an extent substantially consistent with your present business travel obligations, or, in the event you consent to any such relocation of the Company's principal executive or divisional offices, the failure by the Company to pay (or reimburse you for) all reasonable moving expenses incurred by you relating to a change of your principal residence in connection with such relocation and to indemnify you against any loss (defined as the difference between the actual sale price of such residence and the greater of (a) your aggregate investment in such residence, or (b) the fair market value of such residence as determined by a real estate appraiser reasonably satisfactory to both you and the Company) realized in the sale of your principal residence in connection with any such change of residence; (g) any breach by the Company of any material provision of this Agreement; or (h) any failure by the Company to obtain the assumption of this Agreement by any successor or assign of the Company. 18. "Gross-up Payment" shall have the meaning as set forth in Section E. 19. "Notice of Termination" shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of your employment under the provision so indicated. 20. "Payment" shall have the meaning as set forth in Section E. 21. "Person" shall have the meaning as set forth in Sections 13(d) and 14(d)(2) of the Exchange Act. 22. "Qualifying Termination" shall mean the termination of your employment after a Change in Control of the Company while this Agreement is in effect, unless such termination is (a) by reason of your death or Disability, (b) by the Company for Cause, or (c) by you other than for Good Reason. 23. "Salary Continuation Period" shall have the meaning set forth in Section C, paragraph 1. 24. "Significant Stockholder" shall mean any shareholder of the Company who, immediately prior to the Effective Date, owned more than 5% of the common stock of the company. 5

25. "Subsidiary" shall mean any corporation of which more than 20% of the outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether or not at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency) is at the time directly or indirectly owned by the Company, by the Company and one or more other Subsidiaries, or by one or more other Subsidiaries. 26. "Termination" shall mean the actual or Constructive Termination of your employment with the Company. SECTION B. TERM AND BENEFITS This Agreement shall be in effect for a period of one (1) year from the date you accept this Agreement and shall automatically renew for successive one (1) year periods unless terminated by either party by at least one (1) year advance written notice prior to the commencement of the next succeeding one (1) year period at which time the Agreement shall terminate at the end of the next succeeding one (1) year period. During the term of employment hereunder, you agree to devote your full business time and attention to the business and affairs of the Company and to use your best efforts, skills and abilities to promote its interests. In the event of your retirement, at your election or in accordance with the Company's generally applicable retirement policies, as in effect from time to time, this Agreement shall automatically terminate, without additional notice to you, as of the effective date of your retirement. Notwithstanding the first sentence of this paragraph and the first sentence of this Section B, if a Change in Control of the Company should occur while you are still an employee of the Company and while this Agreement is in effect, then this Agreement shall continue in effect from the date of such Change in Control of the Company for a period of two years. Prior to a Change in Control of the Company, your employment may be terminated by the Company for Cause at any time pursuant to a Notice of Termination. In such event, you shall not be entitled to the benefits provided hereunder. No benefits shall be payable hereunder unless your employment is terminated without Cause or there shall have been a Change in Control of the Company and your employment by the Company shall thereafter terminate in accordance with Section D hereof. SECTION C. TERMINATION PRIOR TO CHANGE IN CONTROL 1. Compensation Prior to a Change in Control. If you are Terminated by the Company without Cause during the term of this Agreement and prior to a Change in Control of the Company, you shall be entitled to receive: (a) payment of the higher of; (1) your salary immediately prior to your Date of Termination, or (2) your highest salary during the prior three fiscal years 6

preceding the fiscal year in which your Date of Termination occurs, for a period of one (1) year after your Date of Termination ("Salary Continuation Period"); (b) continuation of your and your eligible dependents' existing participation at regular employee rates, in effect from time to time, in all of the Company's medical, dental and group life plans and other programs in which you were participating immediately prior to your Date of Termination during the Salary Continuation Period, after which time you and your eligible dependents will be eligible for coverage under COBRA. In the event that your continued participation in any such plan or program is for whatever reason impossible, the Company shall arrange upon comparable terms to provide you with benefits substantially equivalent on an after tax basis to those which you and your eligible dependents are, or become, entitled to receive under such plans and programs; (c) if and when payments are made, payment in cash of any pro-rata portion (up through your Date Of Termination) of any amounts you would have received under the Company's performance unit/share plans, Annual Incentive Compensation Plan, and any other similar executive compensation plan in which you were a participant immediately prior to your Date of Termination; (d) provide for payment in cash an amount equal to your Average Annual Bonus; (e) continuation of your existing participation in the Company's thrift plan, cash balance pension plan, non-qualified supplemental pension plan, deferred compensation plan and financial counseling services plan during the Salary Continuation Period (payments made pursuant to paragraph 1(a) and 1(c) hereof shall be deemed includable compensation under these plans to the same extent as if you had remained an active employee of the company and the payments were made for base salary and annual bonus, respectively); (f) outplacement services substantially similar to those historically offered by the Company to displaced senior executives; for a period not to exceed the Salary Continuation Period; (g) pay to you an amount equal to the value of all unused, earned and accrued vacation as of your Date of Termination; and (h) provide for the immediate vesting of all stock options held by you, as of your Date of Termination, under any Company stock option plan and all such options shall be exercisable during the Salary Continuation Period and for 120 days thereafter. However, in the event that your employment with the Company is Terminated during the term of this Agreement and prior to a Change in Control of the Company and such Termination is not a Termination without Cause (including, without limitation, termination 7

by reason of your voluntary termination (other than Constructive Termination), retirement, death, or Disability), or if your employment is terminated for Cause during the term of this Agreement, you shall not be entitled to receive any benefits under this Agreement. 2. Release. In exchange for the benefits herein, you completely release the Company to the fullest extent permitted by law from all claims you may have against the Company on your Date of Termination except claims related to (a) claims for benefits to which you are entitled under this Agreement and (b) any applicable worker's compensation or unemployment compensation. 3. Payment of Benefits. Unless otherwise provided in this Agreement, in the applicable compensation or stock option plan or program, or unless you otherwise elect, all payments shall be made to you in a single lump sum within thirty (30) days after your Date of Termination. Notwithstanding the payment of benefits hereunder in a lump sum, the benefits stated herein to continue through the Salary Continuation Period shall continue through the period. These benefits are in addition to all accrued and vested benefits to which you are entitled to under any of the Company's plans and arrangements, including but not limited to, the accrued vested benefits to which you are eligible for and entitled to receive under any of the Company's qualified and non-qualified benefit or retirement plans, or any successor plans in effect on your Date of Termination hereunder. 4. No Duty to Mitigate. You shall not be required to mitigate the amount of any payment provided for in this Section by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Section be reduced by any compensation earned by you as the result of employment by another employer after your Date of Termination, or otherwise. Except as provided herein, the Company shall have no right to set off against any amount owing hereunder any claim which it may have against you. SECTION D. TERMINATION FOLLOWING CHANGE IN CONTROL 1. Qualifying Termination. If your termination is a Qualifying Termination, you shall be entitled to receive the payments and benefits provided in this Section. 2. Notice of Termination. Except as provided in Section F, paragraph 1, any termination of your employment following a Change in Control of the Company shall be communicated by written Notice of Termination to the other party hereto. No termination shall be effective without such Notice of Termination. 3. Compensation Upon Termination After a Change in Control. (a) If your termination is a Qualifying Termination, then the Company shall pay to you as severance pay (and without regard to the provisions of any benefit or incentive plan), in a lump sum cash payment on the fifth (5th) day following 8

your Date of Termination, an amount equal to two (2) times the higher of; (1) your salary immediately prior to your Date of Termination, or (2) your highest salary during the prior three (3) fiscal years preceding the fiscal year in which your Date of Termination occurs or, if greater, the prior three (3) fiscal years preceding the fiscal year in which the Change in Control of the Company occurs. (b) If your termination is a Qualifying Termination, the Company shall, in addition to the payments required by the preceding paragraph: (i) provide for continuation of your and your eligible dependents' participation at regular employee rates, in effect from time to time, in all of the Company's medical, dental and group life plans and other programs in which you were participating immediately prior to your Date of Termination for a period of two years from your Date of Termination, after which time you and your eligible dependents will be eligible for coverage under COBRA. In the event that your continued participation in any such plan or program is for whatever reason impossible, the Company shall arrange upon comparable terms to provide you with benefits substantially equivalent on an after tax basis to those which you and your eligible dependents are, or become, entitled to receive under such plans and programs; (ii) provide for full payment in cash of any performance unit/share awards in existence on your Date of Termination less any amounts paid to you under the applicable performance unit/share plan upon a Change in Control of the Company pursuant to the provisions of such plan; plus any pro rata portion (up through your date of termination) of any amounts you would have received under the Company's Incentive Compensation Plan and any other similar executive compensation plan in which you were a participant immediately prior to your Date of Termination; (iii) provide for payment in cash of an amount equal to two times your Average Annual Bonus; (iv) provide those benefits or compensation under any compensation plan, arrangement or agreement not in existence as of the date hereof but which may be established by the Company prior to your Date of Termination at such time as payments are made thereunder to the same extent as if you had been a full-time employee on the date such payments would otherwise have been made or benefits vested; (v) for two (2) years after your Date of Termination, provide and pay for outplacement services, by a firm reasonably acceptable to you, that have historically been offered to displaced employees generally by the Company under substantially the same terms and fee structure as is 9

consistent with an employee in your then current position (or, if higher, your position immediately prior to the Change in Control of the Company); (vi) for two (2) years after your Date of Termination, provide and pay for financial planning services, by a firm reasonably acceptable to you, that have historically been offered to you under substantially the same terms and fee structure as is consistent with an employee in your then current position (or, if higher, your position immediately prior to the Change in Control of the Company); (vii) pay to you an amount equal to the value of all unused, earned and accrued vacation as of your Date of Termination pursuant to the Company's policies in effect immediately prior to the Change in Control of the Company; and (viii) provide for the immediate vesting of all stock options held by you, as of your Date of Termination, under any Company stock option plan and all such options shall be exercisable for the remaining terms of the options. (ix) payments made pursuant to paragraphs 3.(a) and 3.(b)(iii) hereof shall be deemed includable compensation under the Company's thrift plan, cash balance pension plan, non-qualified supplemental pension plan and deferred compensation plan as if you had remained an active employee of the Company and payments were made for base salary and annual bonus, respectively. 4. Release. In exchange for the benefits herein, you completely release the Company to the fullest extent permitted by law from all claims you may have against the Company on your Date of Termination except claims related to (a) claims for benefits to which you are entitled under this Agreement and (b) any applicable worker's compensation or unemployment compensation. 5. Payment of Benefits. Unless otherwise provided in this Agreement or in the applicable compensation or stock option plan or program, or unless you otherwise elect, all payments shall be made to you within thirty (30) days after your Date of Termination. These benefits are in addition to all accrued and vested benefits to which you are entitled to under any of the Company's plans and arrangements, including but not limited to, the accrued vested benefits to which you are eligible for and entitled to receive under any of the Company's qualified and non-qualified benefit or retirement plans, or any successor plans in effect on your Date of Termination hereunder. 6. No duty to Mitigate. You shall not be required to mitigate the amount of any payment provided for in this Section by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Section be reduced by any 10

compensation earned by you as the result of employment by another employer after your Date of Termination, or otherwise. Except as provided herein, the Company shall have no right to set off against any amount owing hereunder any claim which it may have against you. 7. Competitive Activity. In consideration of the foregoing, you agree that if your employment is terminated during the term of this Agreement and after a Change in Control of the Company, then during a period ending six (6) months following your Date of Termination you shall not engage in any Competitive Activity; provided, you shall not be subject to the foregoing obligation if the Company breaches a material provision of this Agreement. If you choose to engage in any Competitive Activity during that period, the Company shall be entitled to recover any benefits paid to you under this Agreement. For purposes of this Agreement, "Competitive Activity" shall mean your participation, without the written consent of the General Counsel of the Company, in the management of any business operation of any enterprise if such operation (a "Competitive Operation") engages in substantial and direct competition with any business operation actively conducted by the Company or its divisions and Subsidiaries on your Date of Termination. For purposes of this paragraph, a business operation shall be considered a Competitive Operation if such business sells a competitive product or service which constitutes (i) 15% of that business's total sales or (ii) 15% of the total sales of any individual subsidiary or division of that business and, in either event, the Company's sales of a similar product or service constitutes (i) 15% of the total sales of the Company or (ii) 15% of the total sales of any individual Subsidiary or division of the Company. Competitive Activity shall not include (i) the mere ownership of securities in any enterprise, or (ii) participation in the management of any enterprise or any business operation thereof, other than in connection with a Competitive Operation of such enterprise. SECTION E. ADDITIONAL PAYMENTS BY THE COMPANY Notwithstanding anything to the contrary in this Agreement, in the event that any payment or distribution by the Company to or for your benefit, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (a "Payment"), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended, or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest or penalties, are hereinafter collectively referred to as the "Excise Tax"), the Company shall pay to you an additional payment (a "Gross-up Payment") in an amount such that after payment by you of all taxes (including any interest or penalties imposed with respect to such taxes), including any income, employment and Excise Tax imposed on any Gross-up Payment, you retain an amount of the Gross-up Payment equal to the Excise Tax imposed upon the Payments. You and the Company shall make an initial determination as to whether a Gross-up Payment is required and the amount of any such Gross-up Payment. If you and the Company can not agree on whether a Gross-up Payment is required or the amount thereof, then an independent nationally recognized accounting firm, appointed by you, shall determine the amount of the Gross-up Payment. The Company shall pay 11

all expenses which you may incur in determining the Gross-up Payment. You shall notify the Company in writing of any claim by the Internal Revenue Service which, if successful, would require the Company to make a Gross-up Payment (or a Gross-up Payment in excess of that, if any, initially determined by the Company and you) within ten days of the receipt of such claim. The Company shall notify you in writing at least ten days prior to the due date of any response required with respect to such claim if it plans to contest the claim. If the Company decides to contest such claim, you shall cooperate fully with the Company in such action; provided, however, the Company shall bear and pay directly or indirectly all costs and expenses (including additional interest and penalties) incurred in connection with such action and shall indemnify and hold you harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of the Company's action. If, as a result of the Company's action with respect to a claim, you receive a refund of any amount paid by the Company with respect to such claim, you shall promptly pay such refund to the Company. If the Company fails to timely notify you whether it will contest such claim or the Company determines not to contest such claim, then the Company shall immediately pay to you the portion of such claim, if any, which it has not previously paid to you. SECTION F. MISCELLANEOUS 1. Assumption of Agreement. The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation, share exchange or otherwise) to all or substantially all of the business and/or assets of the Company, by agreement in form and substance satisfactory to you, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Failure of the Company to obtain such agreement prior to the effectiveness of any such succession shall be a breach of a material provision of this Agreement and shall entitle you to compensation in the same amount and on the same terms as you would be entitled pursuant to Section D, except that for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed your Date of Termination without a Notice of Termination being given. 2. Confidentiality. All Confidential Information which you acquire or have acquired in connection with or as a result of the performance of services for the Company, whether under this Agreement or prior to the effective date of this Agreement, shall be kept secret and confidential by you unless (a) the Company otherwise consents, (b) the Company breaches any material provision of this Agreement, or (c) you are legally required to disclose such Confidential Information by a court of competent jurisdiction. This covenant of confidentiality shall extend beyond the term of this Agreement and shall survive the termination of this Agreement for any reason. If you breach this covenant of confidentiality, the Company shall be entitled to recover from any benefits paid to you under this Agreement its damages resulting from such breach. 12

3. Employment. You agree to be bound by the terms and conditions of this Agreement and to remain in the employ of the Company during any period following any public announcement by any Person of any proposed transaction or transactions which, if effected, would result in a Change in Control of the Company until a Change in Control of the Company has taken place. However, nothing contained in this Agreement shall impair or interfere in any way with the right of the Company to terminate your employment for Cause prior to a Change in Control of the Company. 4. Arbitration. Any controversy or claim arising out of or relating to this Agreement, or the breach thereof, shall be settled exclusively by arbitration in accordance with the Center for Public Resources' Model ADR Procedures and Practices, and judgment upon the award rendered by the arbitrator(s) may be entered in any court having jurisdiction thereof. Notwithstanding the foregoing, the Company shall not be restricted from seeking equitable relief, including injunctive relief as set forth in paragraph 5 of this Section, in the appropriate forum. Any cost of arbitration will be paid by the Company. In the event of a dispute over the existence of Good Reason or Cause after a Change in Control of the Company, the Company shall continue to pay your salary, bonuses and plan benefits pending resolution of the dispute. If you prevail in the arbitration, the remaining amounts due to you under this Agreement are to be immediately paid to you. 5. Injunctive Relief. You acknowledge and agree that the remedy of the Company at law for any breach of the covenants and agreements contained in paragraph 2 of this Section and in Section D, paragraph 4 will be inadequate, and that the Company will be entitled to injunctive relief against any such breach or any threatened, imminent, probable or possible breach. You represent and agree that such injunctive relief shall not prohibit you from earning a livelihood acceptable to you. 6. Notice. For the purposes of this Agreement, notices and all other communications provided for in this Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the respective addresses set forth on the first page of this Agreement, provided that all notices to the Company shall be directed to the attention of the General Counsel of the Company, or to such other address as either party may have furnished to the other in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt. 7. Indemnification. The Company will indemnify you to the fullest extent permitted by the laws of the State of Missouri and the existing By-laws of the Company, in respect of all your services rendered to the Company and its divisions and Subsidiaries prior to your Date of Termination. You shall be entitled to the protection of any insurance policies the Company now or hereafter maintains generally for the benefit of its directors, officers and employees (but only to the extent of the coverage afforded by the existing provisions of such policies) to protect against all costs, charges and expenses whatsoever incurred or sustained by you in connection with any action, suit or proceeding to which you may be made a party by reason of your being or having been a 13

director, officer or employee of the Company or any of its divisions or Subsidiaries during your employment therewith. 8. Further Assurances. Each party hereto agrees to furnish and execute such additional forms and documents, and to take such further action, as shall be reasonably and customarily required in connection with the performance of this Agreement or the payment of benefits hereunder. 9. Miscellaneous. No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing signed by you and such officer(s) as may be specifically designated by the Board. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly in this Agreement. 10. Termination of other Agreements. Upon execution by both parties, this Agreement shall terminate and shall replace all prior employment and severance agreements between you and the Company and its divisions or Subsidiaries and the terms hereof shall govern as if executed on the initial date of such prior employment and severance agreements. 11. Severability. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect. 12. Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument. 13. Legal Fees And Expenses. Any other provision of this Agreement notwithstanding, the Company shall pay all legal fees and expenses which you may incur as a result of the Company's unsuccessful contesting of the validity, enforceability or your interpretation of, or determinations under, any part of this Agreement. 14. Governing Law. This Agreement shall be governed in all respects by the laws of the State of Missouri. 15. Agreement Binding on Successors. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. This Agreement shall inure to the benefit of and be enforceable by your personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If you should die while any amounts would still be payable to you hereunder if you had continued to live, all such amounts, unless 14

otherwise provided herein, shall be paid in accordance with the terms of this Agreement to your devisee, legatee, or other designee or, if there be no such designee, to your estate. 16. Headings. All Headings are inserted for convenience only and shall not affect any construction or interpretation of this Agreement. If this Agreement correctly sets forth our agreement on the subject matter hereof, please sign and return to the Company the enclosed copy of this Agreement which will then constitute our agreement on this matter. Sincerely, ARCH COAL, INC. By: ---------------------------------- ACCEPTED as of the day first above written - ---------------------------------- Employee 15

EXHIBIT 10.24 (STAMP) Serial Number ------------------------- WYW71692 Date of Lease ------------------------- December 1, 1966 UNITED STATES DEPARTMENT OF THE INTERIOR BUREAU OF LAND MANAGEMENT MODIFIED COAL LEASE PART I. THIS MODIFIED COAL LEASE is entered into on JAN 01, 2003, by and between the UNITED STATES OF AMERICA, hereinafter called the Lessor, through the Bureau of Land Management, and Triton Coal Company, LLC 510 Reno Road Gillette, Wyoming 82718 hereinafter called Lessee. This modified lease shall retain the effective date of December 1, 1966, of the original coal lease, and is effective for a period of 20 years therefrom, and for so long thereafter as coal is produced in commercial quantities from the leased lands, subject to readjustment of lease terms at the end of the 20th lease year, December 1, 1986, and each 10-year period thereafter. The next readjustment date for the lease, as modified, will be December 1, 2006. SEC. 1. This lease is issued pursuant and subject to the terms and provisions of the: [X] Mineral Lands Leasing Act of 1920, as amended, 41 Stat. 437, 30 U.S.C. 181-287, hereinafter referred to as the Act; [ ] Mineral Leasing Act for Acquired Lands of 1947, 61 Stat. 913, 30 U.S.C. 351-359; and to the regulations and formal orders of the Secretary of the Interior which are now or hereafter in force, when not inconsistent with the express and specific provisions herein. SEC. 2. Lessee, as the holder of Coal Lease WYW71692, issued effective December 1, 1966, was granted the exclusive right and privilege to drill for, mine, extract, remove or otherwise process and dispose of the coal deposits in, upon, or under the lands described below as being in Campbell County, Wyoming: T.42 N., R. 70 W.,6th P.M. ----------------------------- Sec. 2:Lots 17,18; Sec. 3:Lots 17-20; Sec. 9:Lots 9, 10, 15, 16; Sec. 10:Lots 1-16; Sec. 11:Lots 1-4, 8, 9; Sec. 14:Lots 1-8; Sec. 15:Lots 1-8. The Lessor in consideration of fair market value, rents and royalties to be paid, and the conditions and covenants to be observed as herein set forth, hereby grants and leases to Lessee the exclusive right and privilege to drill for, mine, extract, remove, or otherwise process and dispose of the coal deposits in, upon, or under the lands described below as being in Campbell County, Wyoming: T. 42 N., R. 70 W., 6th P.M. ---------------------------- Sec. 11:Lot 10 (SW 1/4). containing within the lease, as modified, 1,971.77 acres, more or less, together with the right to construct such works, buildings, plants, structures, equipment and appliances and the right to use such on-lease rights-of-way which may be necessary and convenient in the exercise of the rights and privileges granted, subject to the conditions herein provided.

WYW71692 PART II. TERMS AND CONDITIONS Page 2 of 5 pages SEC. 1. (a) RENTAL RATE - Lessee shall pay lessor rental annually and in advance for each acre or fraction thereof during the continuance of the lease at the rate of $3.00 for each lease year. (b) RENTAL CREDITS - Rental shall not be credited against either production or advance royalties for any year. SEC. 2. (a) PRODUCTION ROYALTIES - The royalty shall be 12 1/2 percent of the value of the coal produced by strip or augur methods and 8 percent of the value of coal produced by underground mining methods as set forth in the regulations. Royalties are due to Lessor the final day of the month succeeding the calendar month in which the royalty obligation accrues. (b) ADVANCE ROYALTIES - Upon request by the Lessee, the authorized officer may accept, for a total of not more than 10 years, the payment of advance royalties in lieu of continued operation, consistent with the regulations. The advance royalty shall be based on a percent of the value of a minimum number of tons determined in the manner established by the advance royalty regulations in effect at the time the Lessee requests approval to pay advance royalties in lieu of continued operation. SEC. 3. BONDS - Lessee shall maintain in the proper office a lease bond in the amount of $3,883,000. The authorized officer may require an increase in this amount when additional coverage is determined appropriate. SEC. 4. DILIGENCE - This lease is subject to the conditions of diligent development and continued operation, except that these conditions are excused when operations under the lease are interrupted by strikes, the elements, or casualties not attributable to the Lessee. The Lessor, in the public interest, may suspend the condition of continued operation upon payment of advance royalties in accordance with the regulations in existence at the time of the suspension. If not already submitted,the Lessee shall submit an amended operation and reclamation plan pursuant to Section 7 of the Act (30 U.S.C. 207(c) within 3 years of the date of modification or prior to approval to commence mining operations The Lessor reserves the power to assent to or order the suspension of the terms and conditions of this lease in accordance with, inter alia, Section 39 of the Mineral Leasing Act, 30 U.S.C. 209. SEC. 5. LOGICAL MINING UNIT (LMU) - Either upon approval by the Lessor of the Lessee's application or at the direction of the Lessor, this lease shall become an LMU or part of an LMU, subject to the provisions set forth in the regulations. The stipulations established in an LMU approval in effect at the time of LMU approval or modification will supersede the relevant inconsistent terms of this lease so long as the lease remains committed to the LMU. If the LMU of which this lease is a part is dissolved, the lease shall then be subject to the lease terms which would have been applied if the lease had not been included in an LMU. SEC. 6. DOCUMENTS, EVIDENCE AND INSPECTION - At such times and in such form as Lessor may prescribe, Lessee shall furnish detailed statements showing the amounts and quality of all products removed and sold from the lease, the proceeds therefrom, and the amount used for production purposes or unavoidably lost. Lessee shall keep open at all reasonable times for the inspection of any duly authorized office of Lessor, the leased premises and all surface and underground improvements, works, machinery, ore stockpiles, equipment, and all books, accounts, maps, and records relative to operations, surveys, or investigations on or under the leased lands. Lessee shall allow Lessor access to and copying of documents reasonably necessary to verify Lessee compliance with terms and conditions of the lease. While this lease remains in effect, information obtained under this section shall be closed to inspection by the public in accordance with the Freedom of Information Action (5 U.S.C. 552). SEC. 7. DAMAGES TO PROPERTY AND CONDUCT OF OPERATIONS - Lessee shall comply at its own expense with all reasonable orders of the Secretary, respecting diligent operations, prevention of waste, and protection of other resources. Lessee shall not conduct exploration operations, other than casual use, without an approved exploration plan. All exploration plans prior to the commencement of mining operations within an approved mining permit area shall be submitted to the authorized officer. Lessee shall carry on all operations in accordance with approved methods and practices as provided in the operating regulations, having due regard for the prevention of injury to life, health, or property, and prevention of waste, damage or degradation to any land, air, water, cultural, biological, visual, and other resources, including mineral deposits and formations of mineral deposits not leased hereunder, and to other land uses or users. Lessee shall take measures deemed necessary by Lessor to accomplish the intent of this lease term. Such measures may include, but not limited to, modification to proposed siting or design of facilities, timing of operations, and specifications of interim and final reclamation procedures. Lessor reserves to itself the right to lease, sell, or otherwise dispose of the surface or other mineral deposits in the lands and the right to continue existing uses and to authorize future uses upon or in the leased lands, including issuing leases for mineral deposits not covered hereunder and approving easements or rights-of-way. Lessor shall condition such uses to prevent unnecessary or unreasonable interference with rights of Lessee as may be consistent with concepts of multiple use and multiple mineral development. SEC. 8. PROTECTION OF DIVERSE INTERESTS, AND EQUAL OPPORTUNITY - Lessee shall: pay when due all taxes legally assessed and levied under the laws of the State or the United States; accord all employees complete freedom of purchase; pay all wages at least twice each month in lawful

WYW71692 Page 3 of 5 pages money of the United States; maintain a safe working environment in accordance with standard industry practices; restrict the workday to not more than 8 hours in any one day for underground workers, except in emergencies; and take measures necessary to protect the health and safety of the public. No person under the age of 16 years shall be employed in any mine below the surface. To the extent that laws of the State in which the lands are situated are more restrictive than the provisions in this paragraph, then the State laws apply. Lessee will comply with all provisions of Executive Order No. 11246 of September 24, 1965, as amended, and the rules, regulations, and relevant orders of the Secretary of Labor. Neither Lessee nor Lessee's subcontractors shall maintain segregated facilities. SEC. 9. (a) TRANSFERS (Check the appropriate space) X This lease may be transferred in whole or in part to any person, - --- association or corporation qualified to hold such lease interest. This lease may be transferred in whole or in part to another public - --- body, or to a person who will mine the coal on behalf of, and for the use of, the public body or to a person who for the limited purpose of creating a security interest in favor of a lender agrees to be obligated to mine the coal on behalf of the public body. This lease may only be transferred in whole on in part to another small - --- business qualified under 13 CFR 121. Transfers of record title, working or royalty interest must be approved in accordance with the regulations. (b) RELINQUISHMENTS - The Lessee may relinquish in writing at any time all rights under this lease or any portion thereof as provided in the regulations. Upon Lessor's acceptance of the relinquishment, Lessee shall be relieved of all future obligations under the lease or the relinquished portion thereof, whichever is applicable. SEC. 10. DELIVERY OF PREMISES, REMOVAL OF MACHINERY, EQUIPMENT, ETC. - At such time as all portions of this lease are returned to Lessor, Lessee shall deliver up to Lessor the land leased, underground timbering, and such other supports and structures necessary for the preservation of the mine workings on the leased premises or deposits and place all workings in condition for suspension or abandonment. Within 180 days thereof, Lessee shall remove from the premises all other structures, machinery, equipment, tools, and materials that it elects to or as required by the authorized officer. Any such structures, machinery, equipment, tools, and materials remaining on the leased lands beyond 180 days, or approved extension thereof, shall become the property of the Lessor, but Lessee shall either remove any or all such property or shall continue to be liable for the cost of removal and disposal in the amount actually incurred by the Lessor. If the surface is owned by third parties, Lessor shall waive the requirement for removal, provided the third parties do not object to such waiver. Lessee shall, prior to the termination of bond liability or at any other time when required and in accordance with all applicable laws and regulations, reclaim all lands the surface of which has been disturbed, dispose of all debris or solid waste, repair the offsite and onsite damage caused by Lessee's activity or activities incidental thereto, and reclaim access roads or trails. SEC. 11. PROCEEDINGS IN CASE OF DEFAULT - If Lessee fails to comply with applicable laws, existing regulations, or the terms, conditions and stipulations of this lease, and the noncompliance continues for 30 days after written notice thereof, this lease shall be subject to cancellation by the Lessor only by judicial proceedings. This provision shall not be construed to prevent the exercise by Lessor of any other legal and equitable remedy, including waiver of the default. Any such remedy or waiver shall not prevent later cancellation for the same default occurring at any other time. SEC. 12. HEIRS AND SUCCESSORS-IN-INTEREST - Each obligation of this lease shall extend to and be binding upon, and every benefit hereof shall inure to, the heirs, executors, administrators, successors, or assigns of the respective parties hereto. SEC. 13 INDEMNIFICATION - Lessee shall indemnify and hold harmless the United States from any and all claims arising out of the Lessee's activities and operations under this lease. SEC. 14. SPECIAL STATUTES - This lease is subject to the Federal Water Pollution Control Act (33 U.S.C. 1151 - 1175); the Clean Air Act (42 U.S.C. 1857 et seq.), and to all other applicable laws pertaining to exploration activities, mining operations and reclamation, including the Surface Mining Control and Reclamation Act of 1977 (30 U.S.C. 1201 et seq.) SEC. 15 SPECIAL STIPULATIONS - In addition to observing the general obligations and standards of performance set out in the current regulations, the Lessee shall comply with and be bound by the following special stipulations. These stipulations are also imposed upon the Lessee's agents and employees. The failure or refusal of any of these persons to comply with the stipulations shall be deemed a failure of the Lessee to comply with the terms of the lease. The Lessee shall require his agents, contractors and subcontractors involved in activities concerning this lease to include these stipulations in the contracts between and among them. These stipulations may be revised or amended, in writing, by the mutual consent of the Lessor and the Lessee at any time to adjust to changed conditions or to correct an oversight. (a) CULTURAL RESOURCES - (1) Before undertaking any activities that may disturb the surface of the leased lands, the Lessee shall conduct a cultural resource intensive field inventory in a manner specified by the authorized officer of the BLM or of the surface managing agency, if different, on portions of the mine plan area and adjacent areas, or exploration plan area, that may be adversely affected by lease-related activities and which were not previously inventoried at such a level of intensity. The inventory shall be conducted by a qualified professional cultural resource specialist (i.e., archeologist, historian, historical architect, as appropriate),

WYW71692 Page 4 of 5 pages approved by the authorized officer of the surface managing agency (BLM, if the surface is privately owned), and a report of the inventory and recommendations for protecting any cultural resources identified shall be submitted to the Assistant Director of the Western Support Center of the Office of Surface Mining, the authorized officer of the BLM, if activities are associated with coal exploration outside an approved mining permit area (hereinafter called Authorized Officer), and the Authorized Officer of the surface managing agency, if different. The Lessee shall undertake measures, in accordance with instructions from the Assistant Director, or Authorized Officer, to protect cultural resources on the leased lands. The Lessee shall not commence the surface disturbing activities until permission to proceed is given by the Assistant Director or authorized officer. (2) The Lessee shall protect all cultural resource properties within the lease area from lease-related activities until the cultural resource mitigation measures can be implemented as part of an approved mining and reclamation or exploration plan. (3) The cost of conducting the inventory, preparing reports, and carrying out mitigation measures shall be borne by the Lessee. (4) If cultural resources are discovered during operations under this lease, the Lessee shall immediately bring them to the attention of the Assistant Director or Authorized Officer, or the Authorized Officer of the surface managing agency, if the Assistant Director is not available. The Lessee shall not disturb such resources except as may be subsequently authorized by the Assistant Director or Authorized Officer. Within two (2) working days of notification, the Assistant Director or Authorized Officer will evaluate or have evaluated any cultural resources discovered and will determine if any action may be required to protect or preserve such discoveries. The cost of data recovery for cultural resources discovered during lease operations shall be borne by the surface managing agency unless otherwise specified by the Authorized Officer of the BLM or of the surface managing agency, if different. (5) All cultural resources shall remain under the jurisdiction of the United States until ownership is determined under applicable law. (b) PALEONTOLOGICAL RESOURCES - If paleontological resources, either large and conspicuous, and/or of significant scientific value are discovered during surface disturbing activities, the find will be reported to the Authorized Officer immediately. Surface disturbing activities will be suspended within 250 feet of said find. An evaluation of the paleontological discovery will be made by a BLM approved professional paleontologist within five (5) working days, weather permitting, to determine the appropriate action(s) to prevent the potential loss of any significant paleontological value. Operations within 250 feet of such discovery will not be resumed until written authorization to proceed is issued by the Authorized Officer. The Lessee will bear the cost of any required paleontological appraisals, surface collection of fossils, or salvage of any large conspicuous fossils of significant scientific interest discovered during the operations. (c) MULTIPLE MINERAL DEVELOPMENT - Operations will not be approved which, in the opinion of the Authorized Officer, would unreasonably interfere with the orderly development and/or production from a valid existing mineral lease issued prior to this one for the same lands. (d) OIL AND GAS/COAL RESOURCES - The BLM realizes that coal mining operations conducted on Federal coal leases issued within producing oil and gas fields may interfere with the economic recovery of oil and gas; just as Federal oil and gas leases issued in a Federal coal lease area may inhibit coal recovery, BLM retains the authority to alter and/or modify the resource recovery and protection plans for coal operations and/or oil and gas operations on those lands covered by Federal mineral leases so as to obtain maximum resource recovery. (e) RESOURCE RECOVERY AND PROTECTION - Notwithstanding the approval of a resource recovery and protection plan (R2P2) by the BLM, Lessor reserves the right to seek damages against the operator/lessee in the event (i) the operator/lessee fails to achieve maximum economic recovery (MER) (as defined at 43 CFR 3480.0-5(21)) of the recoverable coal reserves or (ii) the operator/lessee is determined to have caused a wasting of recoverable coal reserves. Damages shall be measured on the basis of the royalty that would have been payable on the wasted or unrecovered coal. The parties recognize that under an approved R2P2, conditions may require a modification by the operator/lessee of that plan. In the event a coal bed or portion thereof is not to be mined or is rendered unmineable by the operation, the operator/lessee shall submit appropriate justification to obtain approval by the authorized officer (AO) to leave such reserves unmined. Upon approval by the AO, such coalbeds or portions thereof shall not be subject to damages as described above. Further, nothing in this section shall prevent the operator/lessee from exercising its right to relinquish all or portion of the lease as authorized by statute and regulation. In the event the AO determines that the R2P2, as approved, will not attain MER as the result of changed conditions, the AO will give proper notice to the operator/lessee as required under applicable regulations. The AO will order a modification if necessary, identifying additional reserves to be mined in order to attain MER. Upon a final administrative or judicial ruling upholding such an ordered modification, any reserves left unmined (wasted) under that plan will be subject to damages as described in the first paragraph under this section. Subject to the right to appeal hereinafter set forth, payment of the value of the royalty on such unmined recoverable coal reserves shall become due and payable upon determination by the AO that the coal reserves have been rendered unmineable or at such time that the operator/lessee has demonstrated an unwillingness to extract the coal. The BLM may enforce this provision either by issuing a written decision requiring payment of the MMS demand for such

WYW71692 Page 5 of 5 pages royalties, or by issuing a notice of noncompliance. A decision or notice of noncompliance issued by the Lessor that payment is due under this stipulation is appealable as allowed by law. (f) PUBLIC LAND SURVEY PROTECTION - The Lessee will protect all survey monuments, witness corners, reference monuments, and bearing trees against destruction, obliteration, or damage during operations on the lease areas. If any monuments, corners or accessories are destroyed, obliterated, or damaged by this operation, the Lessee will hire an appropriate county surveyor or registered land surveyor to reestablish or restore the monuments, corners, or accessories at the same location, using surveying procedures in accordance with the "Manual of Surveying Instructions for the Survey of the Public Lands of the United States." The survey will be recorded in the appropriate county records, with a copy sent to the Authorized Officer. - -------------------------------------------------------------------------------- TRITON COAL COMPANY, LLC THE UNITED STATES OF AMERICA By /s/ ILLEGIBLE By /s/ ROBERT A. BARNETT --------------------------------- -------------------------------- (Signature of Lessee) (Signing Officer) VICE PRESIDENT State Director - ------------------------------------ ------------------------------------ (Title) (Title) JAN. 20, 2003 JAN 30 2003 - ------------------------------------ ------------------------------------- (Date) (Date) - -------------------------------------------------------------------------------- Title 18 U.S.C. Section 1001, makes it a crime for any person knowingly and willfully to make to any department or agency of the United States any false, fictitious or fraudulent statements or representations as to any matter within its jurisdiction.

EXHIBIT 10.25 Book 1463 of Photos, Page 581 3400-12 Serial Number (April 1986) UNITED STATES WYW 127221 DEPARTMENT OF THE INTERIOR North Rochelle Tract 727983 BUREAU OF LAND MANAGEMENT COAL LEASE (STAMP) 97 NOV -3 AM 9:00 RECEIVED CHEYENNE, WYOMING - -------------------------------------------------------------------------------- PART I: LEASE RIGHTS GRANTED This lease, entered into by and between the United States of America, hereinafter called the lessor, through the Bureau of Land Management, and (Name and Address) TRITON COAL COMPANY 50 JEROME LANE FAIRVIEW HEIGHTS, ILLINOIS 62208 hereinafter called lessee, is effective (date) January 1, 1998 for a period of 20 years and for so long thereafter as coal is produced in commercial quantities from the leased lands, subject to readjustment of lease terms at the end of the 20th lease year and each 10-year period thereafter. SEC. 1. This lease is issued pursuant and subject to the terms and provisions of the: X Mineral Lands Leasing Act of 1920, Act of February 25, 1920, as amended, - --- 41 Stat. 437, 30 U.S.C. 181-287, hereinafter referred to as the Act; Mineral Leasing Act for Acquired Lands, Act of August 7, 1947, 61 Stat. - --- 913, 30 U.S.C. 351-359; and to the regulations and formal orders of the Secretary of the Interior which are now or hereafter in force, when not inconsistent with the express and specific provisions herein. SEC. 2. Lessor, in consideration of any bonuses, rents, and royalties to be paid, and the conditions and covenants to be observed as herein set forth, hereby grants and leases to lessee the exclusive right and privilege to drill for, mine, extract, remove or otherwise process and dispose of the coal deposits in, upon, or under the following described lands in Campbell County, Wyoming: T.42 N., R. 70 W., 6th P.M., Wyoming Sec. 4: Lots 5-16, 19 and 20; Sec. 5: Lots 5-16; T.43 N., R. 70 W., 6th P.M., Wyoming Sec. 32: Lots 9-16; Sec. 33: Lots 11-14. containing 1481.93 acres, more or less, together with the right to construct such works, buildings, plants, structures, equipment and appliances and the right to use such on-lease rights-of-way which may be necessary and convenient in the exercise of the rights and privileges granted, subject to the conditions herein provided. PART II. TERMS AND CONDITIONS SEC. 1.(a) RENTAL RATE - Lessee shall pay lessor rental annually and in advance for each acre or fraction thereof during the continuance of the lease at the rate of $3.00 for each lease year. (b) RENTAL CREDITS - Rental shall not be credited against either production or advance royalties for any year. SEC. 2.(a) PRODUCTION ROYALTIES - The royalty shall be 12 1/2 percent for coal produced by strip or auger methods and 8 percent for coal produced by underground mining methods of the value of the coal as set forth in the regulations. Royalties are due to Lessor the final day of the month succeeding the calendar month in which the royalty obligation accrues. (b) ADVANCE ROYALTIES - Upon request by the Lessee, the authorized officer may accept, for a total of not more than 10 years, the payment of advance royalties in lieu of continued operation, consistent with the regulations. The advance royalty shall be based on a percent of the value of a minimum number of tons determined in the manner established by the advance royalty regulations in effect at the time the lessee requests approval to pay advance royalties in lieu of continued operation. SEC. 3. BONDS - Lessee shall maintain in the proper office a lease bond in the amount of $24,466,000. The authorized officer may require an increase in this amount when additional coverage is determined appropriate. SEC. 4. DILIGENCE - This lease is subject to the conditions of diligent development and continued operation, except that these conditions are excused when operations under the lease are interrupted by strikes, the elements, or casualties not attributable to the lessee. The lessor, in the public interest, may suspend the condition of continued operation upon payment of advance royalties in accordance with the regulations in existence at the time of the suspension. Lessee's failure to produce coal in commercial quantities at the end of 10 years shall terminate the lease. Lessee shall submit an amended operation and reclamation plan pursuant to Section 7 of the Act not later than 3 years after lease issuance. The lessor reserves the power to assent to or order the suspension of the terms and conditions of this lease in accordance with, inter alia, Section 39 of the Mineral Leasing Act, 30 U.S.C. 209. SEC. 5. LOGICAL MINING UNIT (LMU) - Either upon approval by the lessor of the lessee's application or at the direction of the lessor, this lease shall become an LMU or part of an LMU, subject to the provisions set forth in the regulations.

Book 1463 of Photos, Page 582 WYW127221 Page 2 of 4 The stipulations established in an LMU approval in effect at the time of LMU approval will supersede the relevant inconsistent terms of this lease so long as the lease remains committed to the LMU. If the LMU of which this lease is a part is dissolved, the lease shall then be subject to the lease terms which would have been applied if the lease had not been included in an LMU. SEC. 6. DOCUMENTS, EVIDENCE AND INSPECTION - At such times and in such form as lessor may prescribe, lessee shall furnish detailed statements showing the amounts and quality of all products removed and sold from the lease, the proceeds therefrom, and the amount used for production purposes or unavoidably lost. Lessee shall keep open at all reasonable times for the inspection of any duly authorized officer of the lessor, the leased premises and all surface and underground improvements, works, machinery, ore stockpits, equipment, and all books, accounts, maps, and records relative to operations, surveys, or investigations on or under the leased lands. Lessee shall allow lessor access to and copying of documents reasonably necessary to verify lessee compliance with terms and conditions of the lease. While this lease remains in effect, information obtained under this section shall be closed to inspection by the public in accordance with the Freedom of Information Act (5 U.S.C. 552). SEC. 7. DAMAGES TO PROPERTY AND CONDUCT OF OPERATIONS - Lessee shall comply at its own expense with all reasonable orders of the Secretary, respecting diligent operations, prevention of waste, and protection of other resources. Lessee shall not conduct exploration operations, other than casual use, without an approved exploration plan. All exploration plans prior to the commencement of mining operations within an approved mining permit area shall be submitted to the authorized officer. Lessee shall carry on all operations in accordance with approved methods and practices as provided in the operating regulations, having due regard for the prevention of injury to life, health, or property, and prevention of waste, damage, or degradation to any land, air, water, cultural, biological, visual, and other resources, including mineral deposits and formations of mineral deposit not leased hereunder, and to other land uses or users. Lessee shall take measures deemed necessary by lessor to accomplish the intent of this lease term. Such measures may include, but are not limited to modification to proposed siting or design of facilities, timing of operations, to itself the right to lease, sell or otherwise dispose of the surface or other mineral deposits in the lands and the right to continue existing uses and to authorized future uses upon or in the leased lands, including issuing leases for minerals deposits not covered hereunder, and approving easements or rights-of-way. Lessor shall condition such uses to prevent unnecessary or unreasonable interference with rights of lessee as may be consistent with concepts of multiple use and multiple mineral development. SEC. 8. PROTECTION OF DIVERSE INTEREST, AND EQUAL OPPORTUNITY - Lessee shall; pay when due all taxes legally assessed and levied under the laws of the State or the United States; accord all employees complete freedom of purchase; pay all wages at lease twice each month in lawful money of the United States; maintain a safe working environment in accordance with standard industry practices; restrict the workday to not more than 8 hours in any one day for underground workers except in emergencies; and take measure necessary to protect the health and safety of the public. No person under the age of 16 years shall be employed in any mine below the surface. To the extent that laws of the State in which the lands are situated are more restrictive than the provisions in the paragraph, then the State laws apply. Lessee will comply with all provisions of Executive Order No. 11246 of September 24, 1965, as amended, and the rules, regulations, and relevant orders of the Secretary of Labor. Neither lessee nor lessee's subcontractors shall maintain segregated facilities. SEC. 9.(a) TRANSFERS X This lease may be transferred in whole or in part to any person, - --- association or corporation qualified to hold such lease interest. This lease may be transferred in whole or in part to another public body, - --- or to a person who will mine the coal on behalf of, and for the use of, the public body or to a person who for the limited purpose of creating a security interest in favor of a lender agrees to be obligated to mine the coal on behalf of the public body. This lease may only be transferred in whole or in part to another small - --- business qualified under 13 CFR 121. Transfers of record title, working or royalty interest must be approved in accordance with the regulations. (b) RELINQUISHMENTS - The lessee may relinquish in writing at any time all rights under this lease or any portion thereof as provided in the regulations. Upon lessor's acceptance of the relinquishment, lessee shall be relieved of all future obligations under the lease or the relinquished portion thereof, whichever is applicable. SEC. 10. DELIVERY OF PREMISES, REMOVAL OF MACHINERY, EQUIPMENT, ETC. - At such times as all portions of this lease are returned to lessor, lessee shall deliver up to lessor the land leased, underground timbering, and such other supports and structures necessary for the preservation of the mine workings on the leased premises or deposits and place all workings in condition for suspension or abandonment. Within 180 days thereof, lessee shall remove from the premises all other structures, machinery, equipment, tools, and materials that it elects to or as required by the authorized officer. Any such structures, machinery, equipment, tools, and materials remaining on the leased lands beyond 180 days, or approved extension thereof, shall become the property of the lessor, but lessee shall either remove any or all such property or shall continue to be liable for the cost of removal and disposal in the amount actually incurred by the lessor. If the surface is owned by third parties, lessor shall waive the requirement for removal, provided the third parties do not object to such waiver. Lessee shall, prior to the termination of bond liability or at any other time when required and in accordance with all applicable laws and regulations, reclaim all lands the surface of which has been disturbed, dispose of all debris or solid waste, repair the offsite and onsite damage caused by lessee's activity or activities incidental thereto, and reclaim access roads or trails. SEC. 11. PROCEEDINGS IN CASE OF DEFAULT - If lessee fails to comply with applicable laws, existing regulations, or the terms, conditions and stipulations of this lease, and the noncompliance continues for 30 days after written notice thereof, this lease shall be subject to cancellation by the lessor only by judicial proceedings. This provision shall not be construed to prevent the exercise by lessor of any other legal and equitable remedy, including waiver of the default. Any such remedy or waiver shall not prevent later cancellation for the same default occurring at any other time. SEC. 12. HEIRS AND SUCCESSORS-IN-INTEREST - Each obligation of this lease shall extend to and be binding upon, and every benefit hereof shall insure to the heirs, executors, administrators, successors, or assigns of the respective parties hereto. SEC. 13. INDEMNIFICATION - Lessee shall indemnify and hold harmless the United States from any and all claims arising out of the lessee's activities and operations under this lease. SEC. 14. SPECIAL STATUTES - This lease is subject to the Clean Water Act (33 U.S.C. 1252 el.seq.), the Clean Air Act (42 U.S.C. 1857 el. seq.), and to all other applicable laws pertaining to exploration activities, mining operations and reclamation, including the Surface Mining Control and Reclamation Act of 1977 (30 U.S.C. 1201 el. seq.)

Book 1463 of Photos, Page 583 WYW127221 Page 3 of 4 SEC. 15. SPECIAL STIPULATIONS - In addition to observing the general obligations and standards of performance set out in the current regulations, the lessee shall comply with and be bound by the following stipulations. These stipulations are also imposed upon the lessee's agents and employees. The failure or refusal of any of these persons to comply with stipulations shall be deemed a failure of the lessee to comply with the terms of the lease. The lessee shall require his agents, contractors and subcontractors involved in activities concerning this lease to include these stipulations in the contracts between and among them. These stipulations may be revised or amended, in writing, by the mutual consent of the lessor and the lessee at any time to adjust to changed conditions or to correct an oversight. (a) CULTURAL RESOURCES - (1) Before undertaking any activities that may disturb the surface of the leased lands, the lessee shall conduct a cultural resource intensive field inventory in a manner specified by the authorized officer of the BLM or of the surface managing agency, if different, on portions of the mine plan area and adjacent areas, or exploration plan area, that may be adversely affected by lease-related activities and which were not previously inventoried at such a level of intensity. The inventory shall be conducted by a qualified professional cultural resource specialist (i.e., archeologist, historian, historical architect, as appropriate), approved by the authorized officer of the surface managing agency (BLM, if the surface is privately owned), and a report of the inventory and recommendations for protecting any cultural resources identified shall be submitted to the Assistant Director of the Western Support Center of the Office of Surface Mining, the authorized officer of the BLM, if activities are associated with coal exploration outside an approved mining permit area (hereinafter called Authorized Officer), and the Authorized Officer of the surface managing agency, if different. The lessee shall undertake measures, in accordance with instructions from the Assistant Director, or Authorized Officer, to protect cultural resources on the leased lands. The lessee shall not commence the surface disturbing activities until permission to proceed is given by the Assistant Director or authorized officer. (2) The lessee shall protect all cultural resource properties within the lease area from lease-related activities until the cultural resource mitigation measures can be implemented as part of an approved mining and reclamation or exploration plan. (3) The cost of conducting the inventory, preparing reports, and carrying out mitigation measures shall be borne by the lessee. (4) If cultural resources are discovered during operations under this lease, the lessee shall immediately bring them to the attention of the Assistant Director or Authorized Officer, or the Authorized Officer of the surface managing agency, if the Assistant Director is not available. The lessee shall not disturb such resources except as may be subsequently authorized by the Assistant Director or Authorized Officer. Within two (2) working days of notification, the Assistant Director or Authorized Officer will evaluate or have evaluated any cultural resources discovered and will determine if any action may be required to protect or preserve such discoveries. The cost of data recovery for cultural resources discovered during lease operations shall be borne by the surface managing agency unless otherwise specified by the Authorized Officer of the BLM or of the surface managing agency, if different. (5) All cultural resources shall remain under the jurisdiction of the United States until ownership is determined under applicable law. (b) PALEONTOLOGICAL RESOURCES - If paleontological resources, either large and conspicuous, and/or of significant scientific value are discovered during construction, the find will be reported to the Authorized Officer immediately. Construction will be suspended within 250 feet of said find. An evaluation of the paleontological discovery will be made by a BLM approved professional paleontologist within five (5) working days, weather permitting, to determine the appropriate action(s) to prevent the potential loss of any significant paleontological value. Operations within 250 feet of such discovery will not be resumed until written authorization to proceed is issued by the Authorized Officer. The lessee will bear the cost of any required paleontological appraisals, surface collection of fossils, or salvage of any large conspicuous fossils of significant scientific interest discovered during the operations. (c) MULTIPLE MINERAL DEVELOPMENT - Operations will not be approved which, in the opinion of the Authorized Officer, would unreasonably interfere with the orderly development and/or production from a valid existing mineral lease issued prior to this one for the same lands. (d) OIL AND GAS/COAL RESOURCES - The BLM realizes that coal mining operations conducted on Federal coal leases issued within producing oil and gas fields may interfere with the economic recovery of oil and gas; just as Federal oil and gas leases issued in a Federal coal lease area may inhibit coal recovery, BLM retains the authority to alter and/or modify the resource recovery and protection plans for coal operations and/or oil and gas operations on those lands covered by Federal mineral leases so as to obtain maximum resource recovery. (e) RESOURCE RECOVERY AND PROTECTION - Notwithstanding the approval of a resource recovery and protection plan (R2P2) by the BLM, lessor reserves the right to seek damages against the operator/lessee in the event (i) the operator/lessee fails to achieve maximum economic recovery (MER) (as defined at 43 CFR 3480.0-5(21)) of the recoverable coal reserves or (ii) the operator/lessee is determined to have caused a wasting of recoverable coal reserves. Damages shall be measured on the basis of the royalty that would have been payable on the wasted or unrecovered coal. The parties recognize that under an approved R2P2, conditions may require a modification by the operator/lessee of that plan. In the event a coalbed or portion thereof is not to be mined or is rendered unmineable by the operation, the operator/lessee shall submit appropriate justification to obtain approval by the authorized officer (AO) to leave such reserves unmined. Upon approval by the AO, such coalbeds or portions thereof shall not be subject to damages as described above. Further, nothing in this section shall prevent the operator/lessee from exercising its right to relinquish all or portion of the lease as authorized by statute and regulation. In the event the AO determines that the R2P2, as approved, will not attain MER as the result of changed conditions, the AO will give proper notice to the operator/lessee as required under applicable regulations. The AO will order a modification if necessary, identifying additional reserves to be mined in order to attain MER. Upon a final administrative or judicial ruling upholding such an ordered modification, any reserves left unmined (wasted) under that plan will be subject to damages as described in the first paragraph under this section. Subject to the right to appeal hereinafter set forth, payment of the value of the royalty on such unmined recoverable coal reserves shall become due and payable upon determination by the AO that the coal reserves have been rendered unmineable or at such time that the operator/lessee has demonstrated an unwillingness to extract the coal. The BLM may enforce this provision either by issuing a written decision requiring payment of the MMS demand for such royalties, or by issuing a notice of non-compliance. A decision or notice of non-compliance issued by the lessor that payment is due under this stipulation is appealable as allowed by law. (f) PUBLIC LAND SURVEY PROTECTION - The lessee will protect all survey monuments, witness corners, reference monuments, and bearing trees against destruction, obliteration, or damage during operations on the lease areas. If any monuments, corners or accessories are destroyed, obliterated, or damaged by this operation, the lessee will hire an appropriate county surveyor or registered land surveyor to reestablish or restore the monuments, corners, or accessories at the same location, using surveying procedures in accordance with the "Manual of Surveying Instructions for the Survey of the Public Lands of the United Sates." The survey will be recorded in the appropriate county records, with a copy sent to the Authorized Officer.

Book 1463 of Photos, Page 584 WYW127221 Page 4 of 4 R2-FS-2820-13 (42) NOTICE FOR LANDS OF THE NATIONAL FOREST SYSTEM UNDER JURISDICTION OF DEPARTMENT OF AGRICULTURE The permittee/lessee must comply with all the rules and regulations of the Secretary of Agriculture set forth at Title 36, Chapter II, of the Code of Federal Regulations governing the use and management of the National Forest System (NFS) when not inconsistent with the rights granted by the Secretary of the Interior in the permit. The Secretary of Agriculture's rules and regulations must be complied with for: (1) all use and occupancy of the NFS prior to approval of an exploration plan by the Secretary of the Interior, (2) uses of all existing improvements, such as forest development roads, within and outside the area permitted by the Secretary of the Interior, and (3) use and occupancy of the NFS not authorized by an exploration plan approved by the Secretary of the Interior. All matters related to this stipulation are to be addressed to: District Ranger 2250 East Richards Street Douglas, WY 82633 Telephone: 307-358-4690 who is the authorized representative of the Secretary of Agriculture. NOTICE CULTURAL AND PALEONTOLOGICAL RESOURCES - The Forest Service (FS) is responsible for assuring that the leased lands are examined to determine if cultural resources are present and to specify mitigation measures. Prior to undertaking any surface-disturbing activities on the lands covered by this lease, the lessee or operator, unless notified to the contrary by the FS, shall: 1. Contact the FS to determine if a site specific cultural resource inventory is required. If a survey is required, then: 2. Engage the services of a cultural resource specialist acceptable to the FS to conduct a cultural inventory of the area of proposed surface disturbance. The operator may elect to inventory an area larger than the area of proposed disturbance to cover possible site relocation which may result from environmental or other considerations. An acceptable inventory is to be submitted to the FS for review and approval at the time a surface disturbing plan of operation is submitted. R2-FS-2820-13 (92) 3. Implement mitigation measures required by the FS and BLM to preserve or avoid destruction of cultural resource values. Mitigation may include relocation of proposed facilities, testing, salvage, and recordation or other protective measures. All costs of the inventory and mitigation will be borne by the lessee or operator, and all data and materials salvaged will remain under the jurisdiction of the U.S. Government as appropriate. The lessee or operator shall immediately bring to the attention of the FS and BLM any cultural or paleontological resources or any other objects of scientific interest discovered as a result of surface operations under this lease, and shall leave such discoveries intact until directed to proceed by FS and BLM. FOREST SERVICE REGION 2 SENSITIVE SPECIES - The FS is responsible for assuring that the leased lands are examined prior to undertaking any surface disturbing activities to determine effects upon any plant or animal species listed as sensitive by the Regional Forester. The findings of this examination may result in some restrictions to the operator's plan or even disallow use and occupancy that would lead to the listing of a sensitive species under the Endangered Species Act of 1973. ENDANGERED OR THREATENED SPECIES - The FS is responsible for assuring that the leased land is examined prior to undertaking any surface-disturbing activities to determine effects upon any plant or animal species listed or proposed for listing as endangered or threatened, or their habitats. The findings of this examination may result in some restrictions to the operator's plans or even disallow use and occupancy that would be in violation of the Endangered Species Act of 1973, by detrimentally affecting endangered or threatened species or their habitats. The lessee/operator may, unless notified by the FS that the above examinations are not necessary, conduct the examinations on the leased lands at his discretion and cost. These examinations must be done by or under the supervision of a qualified resource specialist approved by the FS. Acceptable reports must be provided to the FS identifying the anticipated effects of a proposed action on endangered or threatened species or their habitats, and the anticipated effects and impacts to Forest Service Region 2 Sensitive species that may occur or have habitat in the area. - -------------------------------------------------------------------------------- The United States of America Triton Coal Company By - ------------------------------- ----------------------------------- Company or Lessee Name /s/ John [illegible] /s/ [illegible] - ------------------------------- ----------------------------------- (Signature of Lessee) (Signing Officer) President State Director - ------------------------------- ----------------------------------- (Title) (Title) 11/29/97 Dec. 18, 1997 - ------------------------------- ----------------------------------- (Date) (Date) ================================================================================ Title 18 U.S.C. Section 1001, makes it a crime for any person knowingly and willfully to make to any department or agency of the United States any false, fictitious or fraudulent statements or representations as to any matter within its jurisdiction. ================================================================================ This form does not constitute an information collection as defined by 44 U.S.C. 3502 and therefore does not require OMB approval. STATE OF WYOMING } Campbell County } ss. } Filed for record this 22nd day of January A.D., 1998 at 10:08 o'clock A.M. and recorded in Book 1463 of Photos on page 581-584 Fees $12.00. RECORDED By /s/ Susan Saunders ABSTRACTED Deputy /s/ Ameilia M. Snider - --------------------------- INDEXED -------------------------- County Clerk and Ex-Officio CHECKED Register of Deeds 727983

exv13
 

PART II — ANNUAL REPORT
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Forward-Looking Statements
      In this annual report, statements that are not reported financial results or other historical information are “forward-looking statements.” Forward-looking statements give current expectations or forecasts of future events and are not guarantees of future performance. They are based on our management’s expectations that involve a number of business risks and uncertainties, any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements.
      Forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts. They use words such as “anticipate,” “estimate,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. In particular, these include statements relating to:
  •  our expectation of continued growth in the demand for our coal by the domestic electric generation industry;
 
  •  our belief that legislation and regulations relating to the Clean Air Act and other proposed environmental initiatives and the relatively higher costs of competing fuels will increase demand for our compliance and low sulfur coal;
 
  •  our expectations regarding incentives to generators of electricity to minimize their fuel costs as a result of electric utility deregulation;
 
  •  our expectation that we will continue to have adequate liquidity from cash flow from operations;
 
  •  a variety of market, operational, geologic, permitting, labor and weather related factors;
 
  •  our expectations regarding any synergies to be derived from the Triton acquisition; and
 
  •  the other risks and uncertainties which are described below under “Contingencies” and “Certain Trends and Uncertainties,” including, but not limited to, the following:
  •  A reduction in consumption by the domestic electric generation industry may cause our profitability to decline.
 
  •  Extensive environmental laws and regulations could cause the volume of our sales to decline.
 
  •  The coal industry is highly regulated, which restricts our ability to conduct mining operations and may cause our profitability to decline.
 
  •  We may not be able to obtain or renew our surety bonds on acceptable terms.
 
  •  Unanticipated mining conditions may cause profitability to fluctuate.
 
  •  Intense competition and excess industry capacity in the coal producing regions has adversely affected our revenues and may continue to do so in the future.
 
  •  Deregulation of the electric utility industry may cause customers to be more price-sensitive, resulting in a potential decline in our profitability.
 
  •  Our profitability may be adversely affected by the status of our long-term coal supply contracts.
 
  •  Decreases in purchases of coal by our largest customers could adversely affect our revenues.
 
  •  Unavailability of coal reserves would cause our profitability to decline.

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  •  Disruption in, or increased costs of, transportation services could adversely affect our profitability.
 
  •  Numerous uncertainties exist in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower revenues, higher costs or decreased profitability.
 
  •  Title defects or loss of leasehold interests in our properties could result in unanticipated costs or an inability to mine these properties.
 
  •  Acquisitions that we have undertaken or may undertake involve a number of inherent risks, any of which could cause us not to realize the benefits anticipated to result.
 
  •  Some of our agreements limit our ability to manage our western operations exclusively.
 
  •  Our expenditures for postretirement medical and pension benefits have increased since 2002 and could further increase in the future.
 
  •  Our inability to comply with restrictions imposed by our credit facilities and other debt arrangements could result in a default under these agreements.
 
  •  Our estimated financial results may prove to be inaccurate.
      We cannot guarantee that any forward-looking statements will be realized, although we believe that we have been prudent in our plans and assumptions. Achievement of future results is subject to risks, uncertainties and assumptions that may prove to be inaccurate. Should known or unknown risks or uncertainties materialize, or should underlying assumptions prove to be inaccurate, actual results could vary materially from those anticipated, estimated or projected.
      We undertake no obligation to publicly update forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. You are advised, however, to consider any additional disclosures that we or Arch Coal may make on related subjects in future filings with the SEC. You should understand that it is not possible to predict or identify all factors that could cause our actual results to differ. Consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties.
Recent Development
      On March 3, 2005, shares of performance-contingent phantom stock granted in January 2004 to our executive officers vested and were paid out in a combination of cash and shares of our stock. The phantom stock grant vested when our average closing stock price exceeded $40 per share over 20 consecutive trading days. As a result of the payout, we will incur a charge of $9.9 million, or approximately $0.16 per share, during our quarter ending March 31, 2005.
Overview
      We are a producer and marketer of compliance and low-sulfur coal exclusively, which we supply to domestic electric utilities and independent power producers, as well as to steel producers and industrial facilities. We operate large, modern mines in each of the three major low-sulfur coal-producing basins in the United States. These mines are among the most productive in the regions in which they operate and are supported by an extensive, low-cost reserve base totaling 3.7 billion tons.
      We derive approximately 70% of our revenues from long-term supply contracts (defined as having terms of one year or greater). These supply agreements typically have terms of one to three years, although certain contracts have much longer durations. The remainder of our coal sales result from sales on the spot market.

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      The locations of our mining operations are as follows:
      Powder River Basin (“PRB”) — We operate one surface mine, Black Thunder (into which the operations of the North Rochelle mine were integrated during 2004), and we own one idle surface mine, Coal Creek, in the Powder River Basin of Wyoming. The PRB is the nation’s largest and fastest growing coal supply basin.
      Central Appalachia (“CAPP”) — We operate or control 22 mines in this coal basin (defined as southern West Virginia, eastern Kentucky and Virginia). Included in this total are 14 deep mines and 8 surface mines. We are in the process of developing a large longwall mine, Mountain Laurel, that is expected to ramp up to full production in 2007. CAPP is the principal source of low-sulfur coal in the eastern United States.
      Western Bituminous Region (“WBIT”) — We operate three mines in this region (defined as Colorado, Utah and southern Wyoming), including a longwall mine in Colorado and two longwall mines in Utah. In addition, we have announced plans to begin development work on another longwall mine at the currently idle Skyline mine complex in Utah. Coal from WBIT can be used as a substitute for high-Btu eastern coal, which is in short supply.
      Coal is the dominant fuel source for electric generation in the United States. Coal was the fuel source for 51% of the electricity generated in the United States in 2004. Furthermore, coal has significant advantages that should enable it to maintain or even increase market share over the course of the next two decades. First, coal is a low-cost fuel for electric generation, averaging less than one-third of the cost of natural gas or crude oil per megawatt hour of generation. In addition, there is significant excess capacity at existing coal-fired power plants, and this excess capacity represents a very low-cost source of electricity to the grid. At present, coal-fired power plants are operating at an average utilization rate of 71%. We believe that there is significant potential to increase those utilization rates and thus drive increased coal demand. In addition, power generators have announced plans to construct 65 gigawatts of new coal-fired generating capacity in future years, which would increase the installed base by roughly 20%.
      The principal driver for U.S. coal demand is growth in domestic power generation. Domestic power needs are expected to grow over the next several years as the economy grows and the U.S. economy becomes increasingly electrified. The U.S. Energy Information Administration projects that power demand will grow at a rate of 1.9% annually over the course of the next two decades.
      As energy demand grows, we believe that coal is well positioned to supply much of this demand. Competing fuels that have played a prominent role in meeting the nation’s power needs in recent years are starting to be confronted with obstacles that could impede their future growth.
      America’s fleet of nuclear power plants, which is the second leading source of electric generation in the U.S. with a roughly 20% share, is operating near its effective capacity. Nuclear output has remained relatively flat since 2001. It appears unlikely that any new nuclear capacity will be constructed in the next five to 10 years.
      Natural gas, the source of roughly 17% of U.S. electricity supply, is facing growing concerns about the ability to increase North American production sufficiently to keep pace with demand. While imports of liquefied natural gas (LNG) are expected to alleviate some of this supply pressure in the future; it will likely be several years before LNG will play a meaningful role in U.S. electric generation.
      That means that coal will continue to act as the dominant fuel source for electric generation in the years ahead. In addition, we believe that low-sulfur coal will benefit disproportionately from future coal demand growth. Utilities have sought to comply with the sulfur dioxide standards contained in Phase II of the Clean Air Act by shifting increasingly to low sulfur coals rather than building expensive scrubbing capacity. At present, less than 30% of eastern coal-based power

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generation is equipped with scrubbers. Until a significant amount of new scrubbing capacity is added, we believe that low-sulfur coal will have a very pronounced advantage in the marketplace.
      Our management has positioned the company to benefit from these trends by focusing on cost containment and growth in our core operating regions.
      In recent quarters, operating costs have risen due in part to higher costs associated with medical benefits, workers’ compensation, insurance, explosives, diesel fuel, steel, permitting and surety bonding. We are focused on offsetting future cost increases with cost savings and productivity improvements elsewhere. During 2005, we plan to capture operating synergies created by recent acquisitions; continue our efforts to extend best practices across all mines; implement process improvements; apply cutting-edge maintenance programs; and invest in advanced technologies where appropriate and prudent.
      During 2004, we committed — or made plans to commit — more than $1.2 billion in growth capital. Much of this capital will be invested in future periods as we make additional payments on reserve additions or continue mine development projects. We expect to fund most of our currently anticipated capital requirements through existing cash on the balance sheet and internally generated cash flow.
      We currently anticipate that much of our future growth will be organic in nature. As demand for coal grows, we will evaluate the expansion of our existing operations and the development of new mines on our existing reserve base.
Results of Operations
Acquisitions
      On August 20, 2004, we acquired (1) Vulcan Coal Holdings, L.L.C., which owned all of the common equity of Triton Coal Company, LLC (“Triton”), and (2) all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Immediately following the consummation of the transaction, we sold the smaller of Triton’s two mines, Buckskin, to Kiewit Mining Acquisition Company, at a net sales price of $73.1 million. After completion of these transactions, we integrated the operations of the larger of Triton’s two mines, North Rochelle, with our existing Black Thunder mine in the Powder River Basin.
      On July 31, 2004, we purchased the remaining 35% interest in Canyon Fuel Company, LLC (“Canyon Fuel”) not owned by us from ITOCHU Corporation for a purchase price of $112.2 million, including related costs and fees. Net of cash acquired, the fair value of the transaction totaled $97.4 million. As a result of the acquisition, we own substantially all of the ownership interests of Canyon Fuel and no longer account for our investment in Canyon Fuel on the equity method but consolidate Canyon Fuel in our financial statements subsequent to the July 31, 2004 purchase date.

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Items Affecting Comparability of Reported Results
      The comparison of our operating results for the years ending December 31, 2004, 2003 and 2002 are affected by the following significant items:
                         
    Year Ended December 31,
     
    2004   2003   2002
             
    (Amount in millions)
Operating Income
                       
Gain on sale of NRP units
  $ 91.3     $ 42.7     $  
Retroactive royalty rate reductions
    2.7             4.4  
Black lung excise tax refund
    2.1              
Severance costs — Skyline mine
    (2.1 )            
Gain from land sales
    6.7       3.8       0.8  
Long-term incentive compensation accrual
    (5.5 )     (16.2 )      
Severance tax recoveries
          2.5        
Reduction in workforce
          (2.6 )      
Gain on contract buyout
                5.6  
Workers’ compensation premium adjustment
                4.6  
                   
Net increase in operating income
  $ 95.2     $ 30.2     $ 15.4  
Other
                       
Expenses resulting from termination of hedge accounting for interest rate swaps
    (8.3 )     (4.3 )      
Expenses resulting from early debt extinguishment
    (0.7 )     (4.7 )      
Interest on federal income tax refund
    2.2              
Interest on black lung excise tax refund
    0.7              
Gain from mark-to-market adjustments on interest rate swaps that no longer qualify as hedges
          13.4        
                   
Net increase in pre-tax income
  $ 89.1     $ 34.6     $ 15.4  
                   
      Gain on Sale of NRP Units. During 2004, we sold our remaining limited partnership units of NRP resulting in proceeds of approximately $111.4 million and gains of $91.3 million. During 2003, we sold our general partner interest and subordinated units resulting in proceeds of $115.0 million and a gain of $42.7 million.
      Retroactive Royalty Rate Adjustments. During 2004 and 2002, we filed a royalty rate reduction request with the Bureau of Land Management (“BLM”) for our West Elk mine in Colorado. The BLM notified us that we would receive a royalty rate reduction for a specified number of tons representing retroactive portions for the respective years totaling $2.7 million and $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in both years. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments.
      Black Lung Excise Tax Refunds. During 2004, we were notified by the IRS that we would receive additional black lung excise tax refunds and interest related to black lung claims that were originally denied by the IRS in 2002. We recognized a gain of $2.8 million ($2.1 million refund and $0.7 million of interest) related to the claims. The $2.1 million refund was recorded as a component of cost of coal sales, while the $0.7 million of interest was recorded as interest income.
      Severance Costs — Skyline Mine. During 2004, Canyon Fuel, which was accounted for under the equity method through July 31, 2004, began the process of idling its Skyline Mine (the idling

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process was completed in May 2004), and incurred severance costs of $3.2 million for the year ended December 31, 2004. Our share of these costs totals $2.1 million and is reflected in income from equity investments.
      Gain from Land Sales. During the years ended December 31, 2004, 2003 and 2002, we recognized gains from land sales at our idle properties. These gains are reported as other operating income.
      Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps. On June 25, 2003, we repaid the term loans of our subsidiary, Arch Western, with the proceeds from the offering of senior notes. In connection with the repayment of the term loans, we recognized expenses related to the write-off of loan fees and other debt extinguishment costs. Additionally, we had designated certain interest rate swaps as hedges of the variable rate interest payments due under the Arch Western term loans. Pursuant to the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”), historical mark-to-market adjustments related to these swaps through June 25, 2003 were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the contractual terms of the swap agreements. For the years ending December 31, 2004 and 2003, we recognized expenses of $8.3 million and $4.3 million, respectively, related to the amortization of previously deferred mark-to-market adjustments and expenses of $0.7 million and $4.7 million, respectively, related to early debt extinguishment costs.
      Interest on federal income tax refunds. In connection with the settlement of tax audits for prior years, we recorded interest income in 2004 related to federal income tax refunds. This amount is reflected as interest income.
      Long-term Incentive Compensation Plan Expense. During 2004, we accrued $5.5 million under long-term incentive compensation plans. Awards under these plans included restricted stock unit grants that vest over three years and performance unit awards that are earned if the Company meets certain financial, safety and environmental targets during the three years ending December 31, 2006. During the fourth quarter of 2003, our Board of Directors approved awards under a four-year performance unit plan that began in 2000. Amounts accrued for the plan totaled $16.2 million in 2003.
      Severance Tax Recoveries. During 2003, we were notified by the State of Wyoming of a favorable ruling relating to our calculation of coal severance taxes. The ruling resulted in a refund of previously paid taxes and the reversal of previously accrued taxes payable. This amount was recorded as a component of cost of coal sales in the Consolidated Statement of Operations.
      Reduction in Workforce. During the year ending December 31, 2003, we instituted cost reduction efforts throughout our operations. These cost reduction efforts included the termination of approximately 100 employees at our corporate office and CAPP mining operations. Of the expense recognized, $1.6 million was recognized as a component of cost of coal sales, with the remainder recognized as a component of selling, general and administrative expenses.
      Mark-to-market adjustments on interest rate swaps that no longer qualify as hedges. We are a party to several interest rate swap agreements that were entered into in order to hedge the variable rate interest payments due under Arch Western’s term loans. Subsequent to the repayment of those term loans, the swaps no longer qualify for hedge accounting under FAS 133. As such, favorable changes in the market value of the swap agreements were recorded as a component of income and are included in other non-operating income in the Consolidated Statements of Operations. During the year ended December 31, 2003, we recognized income of $13.4 million related to the mark-to-market adjustments on these swap agreements.

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      Gain on Contract Buyout. During 2002, we settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain, which was recognized in other operating income in the Consolidated Statements of Operations.
      Workers’ Compensation Premium Adjustment. During 2002, we received a workers’ compensation premium adjustment refund from the State of West Virginia. During 1998, we entered into the West Virginia workers’ compensation plan at one of our subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers’ Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers’ Compensation refunded $4.6 million in premiums. The refund is reflected as a reduction in cost of coal sales.
Year Ended December 31, 2004, Compared to Year Ended December 31, 2003
      Summarized operating results for 2004 versus 2003 and additional discussion of the 2004 results are provided below.
Revenues
                                 
    Year Ended December 31,   Increase (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands, except per ton data)
Coal sales
  $ 1,907,168     $ 1,435,488     $ 471,680       32.9 %
Tons sold
    123,060       100,634       22,426       22.3 %
Coal sales realization per ton sold
  $ 15.50     $ 14.26     $ 1.24       8.7 %
Tons sold by operating segment
                                 
    Tons Sold   % of Total
         
    2004   2003   2004   2003
                 
    (Amounts in thousands)
Powder River Basin
    81,857       64,050       66.5 %     63.6 %
Central Appalachia
    30,008       29,667       24.4 %     29.5 %
Western Bituminous Region
    11,195       6,917       9.1 %     6.9 %
                         
Total operating regions
    123,060       100,634       100.0 %     100.0 %
      Coal sales. The increase in coal sales resulted from the combination of higher pricing, increased volumes and the acquisitions of Triton and the remaining 35% interest in Canyon Fuel during the third quarter of 2004.
      Volumes increased slightly in Central Appalachia (an increase of 1.2%), but increased more dramatically in the Powder River Basin (an increase of 27.8%) and at our Western Bituminous operations (an increase of 61.9%). Volumes in both the Powder River Basin and the Western Bituminous region benefited from the acquisitions that were completed in the third quarter of 2004.
      Per ton realizations increased due primarily to higher contract prices in all three regions. In the Powder River Basin, per ton realization increased 11.3%, including above-market pricing on certain contracts acquired in the Triton acquisition. The Central Appalachia region experienced the largest per ton realization increase (an increase of 21.3%), as both contract and spot market prices were higher than in 2003. Additionally, a higher percentage of our sales were metallurgical coal sales in 2004 as compared to 2003. The Western Bituminous region’s per ton realization increased 13.4%. In addition to higher contract pricing, per ton realizations in the Western Bituminous region were also affected by the acquisition of the remaining 35% interest in Canyon Fuel. Excluding the effects of the Canyon Fuel acquisition, per ton realizations for Western Bituminous would have increased 10.4% over the prior year.

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      On a consolidated basis, the increase in per ton realizations was partially offset by the change in mix of sales volumes among our operating regions. As reflected in the table above, Central Appalachia volumes (which have the highest average realization) decreased while volumes in the Powder River Basin and Western Bituminous Region increased from the prior year.
Costs and Expenses
                                 
    Year Ended December 31,   Increase (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands, except per ton data)
Cost of coal sales
  $ 1,638,284     $ 1,280,608     $ 357,676       27.9 %
Depreciation, depletion and amortization
    166,322       158,464       7,858       5.0 %
Selling, general and administrative expenses
    52,842       43,942       8,900       20.3 %
Long-term incentive compensation expense
    5,495       16,217       (10,722 )     (66.1 )%
Other expenses
    35,758       18,245       17,513       96.0 %
                         
    $ 1,898,701     $ 1,517,476     $ 381,225       25.1 %
                         
      Cost of coal sales. The increase in cost of coal sales is primarily due to the increase in coal sales revenues discussed above. Specific factors contributing to the increase are as follows:
  •  Production taxes and coal royalties (which are incurred as a percentage of coal sales realization) increased $71.8 million.
 
  •  Poor rail performance during 2004 resulted in missed shipments and disruptions in production.
 
  •  Our Central Appalachia operations incurred higher costs related to additional processing necessary to sell coal in metallurgical markets.
 
  •  The cost of purchased coal increased $105.9 million, reflecting a combination of increased purchase volumes and higher spot market prices that were prevalent during 2004. During 2004, we utilized purchased coal to fulfill steam coal sales commitments in order to direct more of our produced coal into the metallurgical markets.
 
  •  Costs for explosives and diesel fuel increased $9.5 million and $22.4 million, respectively.
 
  •  Costs for operating supplies increased $16.9 million due primarily to increased commodity and steel prices during the year.
 
  •  Repairs and maintenance costs increased $21.3 million due partially to the acquisitions made during the third quarter of 2004.
      During the first quarter of 2004, we reflected the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”), in accordance with the provisions of FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. Incorporation of the provisions of the Act resulted in a $68.0 million reduction of our postretirement medical benefit obligation. Postretirement medical expenses for fiscal year 2004 after incorporation of the provisions of the Act resulted in $18.2 million less expense than that previously anticipated (substantially all of which is recorded as a component of cost of coal sales). The benefit for the year ending December 31, 2004 was partially offset by increased costs resulting from changes to other actuarial assumptions that were incorporated at the beginning of the year.

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      Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the acquisitions made during the third quarter of 2004.
      Regional Analysis:
        Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2004   2003   $   %
                 
Powder River Basin
  $ 6.19     $ 5.45     $ 0.74       13.6 %
Central Appalachia
  $ 34.84     $ 30.87     $ 3.97       12.9 %
Western Bituminous Region
  $ 15.71     $ 15.41     $ 0.30       1.9 %
        Powder River Basin — On a per-ton basis, operating costs increased in the Powder River Basin primarily due to increased cost of purchased coal ($0.31 per ton), increased production taxes and coal royalties ($0.17 per ton) and to the higher explosives and diesel fuel costs discussed above. Additionally, average costs were higher due to the integration of the acquired North Rochelle mine into our Black Thunder mine.
 
        Central Appalachia — Operating cost per ton increased due to increased costs for coal purchases ($2.52 per ton), increased diesel fuel ($0.38 per ton) and production taxes and coal royalties ($0.49 per ton) as well as the increased preparation costs for metallurgical coal discussed above. Additionally, poor rail performance at our Central Appalachia operations resulted in disruptions in production. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs.
 
        Western Bituminous Region — Operating cost per ton increased primarily due to increased production taxes and coal royalties ($0.27 per ton).
      Selling, general and administrative expenses. Selling, general and administrative expenses increased due primarily to legal and professional fees, franchise taxes and higher expenses resulting from amounts expected to be earned under our annual incentive plans.
      Other expenses. The increase in other expenses is primarily a result of higher costs to terminate certain contractual obligations for the purchase of coal as compared to the prior year.
Other Operating Income
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands)
Income from equity investments
  $ 10,828     $ 34,390     $ (23,562 )     (68.5 )%
Gain on sale of units of NRP
    91,268       42,743       48,525       113.5 %
Other operating income
    67,483       45,226       22,257       49.2 %
                         
    $ 169,579     $ 122,359     $ 47,220       38.6 %
                         
      Income from equity investments. Income from equity investments for 2004 consists of $8.4 million from our investment in Canyon Fuel (prior to our July 31, 2004 acquisition of the 35% interest we did not own) and $2.4 million from our investment in NRP (prior to the sale of NRP units in March 2004). For 2003, income from equity investments consisted of $19.7 million of income from our

II-9


 

investment in Canyon Fuel and $14.7 million from our investment in NRP. The decline in income from our investment in Canyon Fuel results from the consolidation of Canyon Fuel into our financial statements subsequent to the July 31, 2004 purchase date, lower production and sales levels at Canyon Fuel prior to the acquisition and additional costs related to idling the Skyline Mine, including the severance costs noted above.
      Other operating income. The increase in other operating income is primarily due to the recognition in 2004 of $13.9 million of previously deferred gains from the 2003 and 2004 NRP unit sales. These deferred gains are being recognized over the terms of our leases with NRP. The increase is also due to gains recognized on land sales of $6.7 million in 2004 compared to $3.8 million in 2003.
Interest Expense, Net
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands)
Interest expense
  $ 62,634     $ 50,133     $ 12,501       24.9 %
Interest income
    (6,130 )     (2,636 )     (3,494 )     (132.5 )%
                         
    $ 56,504     $ 47,497     $ 9,007       19.0 %
                         
      Interest expense. The increase in interest expense results from a higher average interest rate in the first six months of 2004 as compared to the same period in 2003 as well as a higher amount of average borrowings from August through December 2004 as compared to the prior year. In 2004, the Company’s outstanding borrowings consisted primarily of fixed rate borrowings, while borrowings in the first half of 2003 were primarily variable rate borrowings. Short-term interest rates in 2003 were lower than the fixed rate borrowing that made up the majority of average debt balances in 2004.
      Interest Income. The increase in interest income is partly due to interest on the federal income tax refunds discussed above. The remaining increase results primarily from interest on short-term investments.
Other non-operating income and expense
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands)
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps
  $ 9,010     $ 8,955     $ 55       0.6 %
Other non-operating income
    (1,044 )     (13,211 )     12,167       92.1 %
                         
    $ 7,966     $ (4,256 )   $ 12,222       287.2 %
                         
      Amounts reported as non-operating consist of income or expense resulting from the Company’s financing activities other than interest. As described above, the Company’s results of operations for the years ended December 31, 2004 and 2003 include expenses of $8.3 million and $4.3 million, respectively, related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Additionally, we incurred expenses of $0.7 million and $4.7 million related to early debt extinguishment costs in 2004 and 2003, respectively.
      Other non-operating income in 2003 was primarily from mark-to-market adjustments on swaps as described above. During 2003, we terminated these positions or entered into offsetting positions.

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Income taxes
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands)
Income tax benefit
  $ 130     $ 23,210     $ (23,080 )     (99.4 )%
      Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The income tax benefit recorded in 2004 is due primarily to a $7.1 million benefit due to favorable tax settlements and a $9.7 million reduction in income tax reserves associated with the completion of the 1999 through 2002 federal income tax audits. The change is also the result of the tax benefit from percentage depletion offset by the tax impact from the sales of the NRP units throughout 2004.
      Deferred tax assets and liabilities are recorded at the maximum effective tax rate. Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. We have historically been subject to alternative minimum tax (AMT), and it is more likely than not that we will remain an AMT taxpayer in the foreseeable future. Valuation allowances are established against deferred tax assets so as to value the asset to an amount that is realizable, as further described in “Management’s Discussion and Analysis of Financial Condition — Critical Accounting Policies.”
Net income before cumulative effect of accounting change
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands)
Net income before cumulative effect of accounting change
  $ 113,706     $ 20,340     $ 93,366       459.0 %
      The increase in net income before cumulative effect of accounting change is primarily due to higher coal sales revenues and the gain recognized from the sales of NRP units during 2004 (net of related tax provision).
Year Ended December 31, 2003, Compared to Year Ended December 31, 2002
      Summarized operating results for 2003 versus 2002 and additional discussion of the 2003 results are provided below.
Revenues
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2003   2002   $   %
                 
    (Amounts in thousands, except per ton data)
Coal sales
  $ 1,435,488     $ 1,473,558     $ (38,070 )     (2.6 )%
Tons sold
    100,634       106,691       (6,057 )     (5.7 )%
Coal sales realization per ton sold
  $ 14.26     $ 13.81     $ 0.45       3.3 %

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Percentage of tons sold by operating segment
                                 
    Tons Sold   % of Total
         
    2003   2002   2003   2002
                 
    (Amounts in thousands)
Powder River Basin
    64,050       67,249       63.6 %     63.0 %
Central Appalachia
    29,667       32,054       29.5 %     30.1 %
Western Bituminous Region
    6,917       7,388       6.9 %     6.9 %
                         
Total operating regions
    100,634       106,691       100.0 %     100.0 %
      Coal sales. Coal sales revenues decreased in 2003 as compared to 2002 primarily as a result of a decline in sales volume in 2003. Volumes were depressed in large part because our utility customers reduced coal stockpile inventory levels throughout the year. Offsetting the volume decline was an increase in average realization, due primarily to higher pricing on contract shipments made in 2003 as compared to 2002. We experienced higher pricing in all of our operating basins, as average realizations increased 10.4% in the Powder River Basin, 2.6% in Central Appalachia and 2.8% in the Western Bituminous region.
      Our consolidated coal sales revenues are impacted by the mix of sales among our operating regions, as Central Appalachia coal has higher pricing on a per-ton basis than either of our other operating regions. The comparison of revenues for 2003 and 2002 is relatively unaffected by the mix of sales between our operating regions.
Costs and Expenses
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2003   2002   $   %
                 
    (Amounts in thousands, except per ton data)
Cost of coal sales
  $ 1,280,608     $ 1,262,516     $ 18,092       1.4 %
Depreciation, depletion and amortization
    158,464       174,752       (16,288 )     (9.3 )%
Selling, general and administrative expenses
    43,942       37,999       5,943       15.6 %
Long-term incentive compensation expense
    16,217             16,217       N/A  
Other expenses
    18,245       29,595       (11,350 )     (38.4 )%
                         
    $ 1,517,476     $ 1,504,862     $ 12,614       0.8 %
                         
      Cost of coal sales. Cost of coal sales increased despite a decrease in coal sales revenues and tonnage due primarily to increased costs related to our pension and postretirement medical plans of $34.0 million. This increase was a result of changes in the actuarial assumptions used to determine the liabilities and expenses related to the plans. Of the $34.0 million increase, $33.5 million related to our Central Appalachian operations. Additionally, cost of coal sales in 2003 was negatively impacted by the charges related to the reduction in force mentioned above and due to disruptions in production resulting from severe weather in the first quarter of 2003 at certain operations.
      Depreciation, depletion and amortization. The decrease is due partially to a decline in depletion in 2003 as compared to 2002 that relates to a decrease in overall sales volumes of 5.7%. The decrease also relates to a decline in the amortization of coal supply agreements in 2003 as compared to 2002. This was primarily a result of the renegotiation of a significant contract in 2003. In April 2003, we agreed to terms with a customer seeking to buy out of the remaining term of an above-market supply contract. The buyout resulted in the receipt of $52.5 million in cash and the write off of the contract value of approximately $37.5 million. Amortization related to this contract was

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$0.9 million in 2003 compared to $2.8 million in 2002. Additionally, two other contracts were fully amortized in 2003. Amortization on these contracts totaled $2.5 million in 2003 versus $5.4 million in 2002.
      Regional Analysis:
        Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2003   2002   $   %
                 
Powder River Basin
  $ 5.45     $ 5.31     $ 0.14       2.6 %
Central Appalachia
  $ 30.87     $ 28.26     $ 2.61       9.2 %
Western Bituminous Region
  $ 15.41     $ 14.53     $ 0.88       6.1 %
        Powder River Basin — On a per-ton basis, operating costs increased slightly primarily a result of higher costs for certain operating supplies, including explosives and diesel fuel.
 
        Central Appalachia — On a per-ton basis, operating costs increased 9.2% in 2003. As discussed above, Central Appalachia costs were negatively affected by the increased expense resulting from changes in actuarial assumptions on our pension and postretirement medical plans.
 
        Western Bituminous Region — On a per-ton basis, operating costs increased 6.1% in 2003. Volumes declined as a result of our utility customers reducing inventory stockpiles throughout the year. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs.
      Selling, general and administrative expenses. The increase in selling, general and administrative expenses is primarily due to an increase in compensation-related expenses and costs related to the reduction in force mentioned above. Our 2003 administrative expenses include approximately $2.7 million earned under our annual incentive plan. No amounts were earned under the annual incentive plan in 2002.
      Other expenses. The decrease in other expenses is primarily a result of lower costs to terminate certain contractual obligations for the purchase of coal as compared to the prior year.
Other Operating Income
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2003   2002   $   %
                 
    (Amounts in thousands)
Income from equity investments
  $ 34,390     $ 10,092     $ 24,298       240.8 %
Gain on sale of units of NRP
    42,743             42,743       N/A  
Other operating income
    45,226       50,489       (5,263 )     (10.4 )%
                         
    $ 122,359     $ 60,581     $ 61,778       102.0 %
                         
      Income from equity investments. Income from equity investments for 2003 is comprised of $19.7 million from our investment in Canyon Fuel and $14.7 million from our investment in NRP. For 2002, income from Canyon Fuel was $7.8 million and income from NRP was $2.3 million. The improved results from Canyon Fuel are due primarily to improved operating margins, as reduced operating costs more than offset slightly lower realizations. The increase in income from NRP is due to

II-13


 

the fact that 2003 includes a full year of income from NRP, while 2002 includes only that period from the formation of NRP in October 2002.
      Other operating income. The decline in other operating income is due primarily to lower outlease royalty income resulting from the contribution of reserves and the related leases to NRP. The royalty income we recorded in 2003 was $7.1 million lower than that reported in 2002. This decline was partially offset by the gains on the sale of land described above.
Interest Expense, Net
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2004   2003   $   %
                 
    (Amounts in thousands)
Interest expense
  $ 50,133     $ 51,922     $ (1,789 )     (3.4 )%
Interest income
    (2,636 )     (1,083 )     (1,553 )     (143.4 )%
                         
    $ 47,497     $ 50,839     $ (3,342 )     (6.6 )%
                         
      Interest expense. The decline in interest expense is the result of lower average outstanding borrowings, as average debt levels declined more than 10% in 2003 as compared to 2002. During 2003, we reduced our overall debt levels through a public offering of preferred stock. This decline in debt levels was partially offset by higher interest rates. In June of 2003, we replaced Arch Western’s variable-rate term loans with fixed rate senior notes. The fixed-rate on the senior notes is higher than the variable rates that we paid in 2002.
Other non-operating income and expense
      Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. As described above, our results of operations for 2003 include expenses of $4.7 million related to debt extinguishment costs and $4.3 million related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred.
      Additionally, we recognized income of $13.4 million from mark-to-market adjustments for interest rate swap agreements which no longer qualify for hedge accounting.
Benefit from income taxes
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2003   2002   $   %
                 
    (Amounts in thousands)
Benefit from income taxes
  $ 23,210     $ 19,000     $ 4,210       22.2 %
      Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The increase in the income tax benefit for 2003 is primarily due to the utilization of a capital loss which had previously been reserved. We were able to utilize the capital loss to offset a portion of the gain from the sale of units of NRP.
      Deferred tax assets and liabilities are recorded at the maximum effective tax rate. Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. We have historically been subject to alternative minimum tax (AMT), and it is more likely than not that we will remain an AMT taxpayer in the foreseeable future. Valuation allowances are established against deferred tax assets so as to value the asset to an amount that is realizable, as further described in “Management’s Discussion and Analysis of Financial Condition — Critical Accounting Policies.”

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Net income (loss) before cumulative effect of accounting change
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2003   2002   $   %
                 
    (Amounts in thousands)
Net income (loss) before cumulative effect of accounting change
  $ 20,340     $ (2,562 )   $ 22,902       N/A  
      The increase in net income before cumulative effect of accounting change is primarily due to the gain on the sale of units of NRP, offset by the long-term compensation plan expense, each of which is described above.
Cumulative effect of accounting change
      Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“FAS 143”). FAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of FAS 143 resulted in a cumulative effect loss as of January 1, 2003 of $3.7 million, net of tax.
Outlook
      Railroad Transportation Disruptions. During 2004, rail service disruptions resulted in missed shipments in all of our operating regions, including some of our highest margin coal in Central Appalachia. In addition, we were periodically forced to curtail production at the West Elk mine in Colorado and the Black Thunder mine in Wyoming due to high inventory levels stemming from insufficient rail service. Inventory levels increased approximately 89% from the prior year to 16.1 million tons as of December 31, 2004.
      The railroad disruptions, which initially resulted from inadequate staffing at the railroads, equipment shortages and an unexpected increase in overall rail shipments, improved somewhat during the third and fourth quarters, but suffered a setback following hurricane-related disruptions in the Southeast regions of the United States late in the third quarter. We anticipate continued challenges, with gradual improvement in rail service in the first half of 2005. We are working with our customers and the railroads in an effort to address these issues in a timely manner.
      Expenses Related to Interest Rate Swaps. We had designated certain interest rate swaps as hedges of the variable rate interest payments due under Arch Western’s term loans. Pursuant to the requirements of FAS 133, historical mark-to-market adjustments related to these swaps through June 25, 2003 of $27.0 million were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the original contractual terms of the swap agreements. As of December 31, 2004, the remaining deferred amounts will be recognized as expense in the following periods: $7.7 million in 2005; $4.8 million in 2006; and $1.9 million in 2007.
      Chief Objectives. We are focused on taking steps to increase shareholder returns by improving earnings, strengthening cash generation, and improving productivity at our large-scale mines, while building on our strategic position in each of the nation’s three principal low-sulfur coal basins. We believe that success in the coal industry is largely dependent on leadership in three crucial areas of performance — safety, environmental stewardship and return on investment — and we are pursuing such leadership aggressively. At the same time, we are sustaining our longstanding focus on being a low-cost producer in the regions where we operate. We are also seeking to enhance our position as a preferred supplier to U.S. power producers by acting as a reliable and highly ethical partner. We plan to focus on organic growth by continuing to develop our existing reserve base, which is large and

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highly strategic. We also plan to evaluate acquisitions that represent a good fit with our existing operations.
Disclosure and Internal Controls
      An evaluation was performed under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2004. Based on that evaluation, our management, including the CEO and CFO, concluded that the disclosure controls and procedures were effective as of such date. There were no changes in internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Liquidity and Capital Resources
      The following is a summary of cash provided by or used in each of the indicated types of activities during the past three years:
                           
    Year Ended December 31,
     
    2004   2003   2002
             
    (In thousands)
Cash provided by (used in):
                       
 
Operating activities
  $ 146,728     $ 162,361     $ 176,417  
 
Investing activities
    (595,294 )     6,832       (128,303 )
 
Financing activities
    517,192       75,791       (45,447 )
      Cash provided by operating activities declined in 2004 as compared to 2003 primarily as a result of increased investment in working capital. Trade accounts receivable represented the largest use of funds, increasing by more than $32.5 million (net of amounts acquired in business combinations) in 2004. This increase is due to higher sales levels during the period, as revenues have increased approximately 33% in 2004 as compared to 2003. Additionally, inventory increased by more than $12.0 million (net of amounts acquired in business combinations) in 2004. This increase is due primarily to the continued rail difficulties that resulted in missed shipments during the year. Cash provided by operating activities in 2003 declined as compared to 2002 due primarily to lower income levels (after adjusting for gains from the NRP unit sale in December 2003 and other asset sales).
      Cash used in investing activities in 2004 is represented largely by payments for acquisitions of $387.8 million, net of cash acquired, during the third quarter of 2004. We acquired the 35% of the Canyon Fuel investment not owned by us and the North Rochelle operations from Triton in July and August 2004, respectively. The Canyon Fuel acquisition was funded with a $22.0 million five-year note and approximately $90 million of cash on hand. The Triton acquisition was funded with borrowings under our existing revolving credit facility of $22.0 million, a term loan in the amount of $100.0 million, and with cash on hand. Capital expenditures and advance royalty payments were $292.6 million and $33.8 million, respectively. Capital expenditures include $122.2 million related to the first of five annual payments under the lease of coal mineral reserves at Little Thunder discussed below. The remaining capital expenditures related to other various plant and equipment purchases, primarily at our Powder River Basin and Central Appalachia mines. These cash outlays were offset partially by proceeds of $111.4 million from the sale of the NRP units. Cash provided by investing activities in 2003 reflects the receipt of $115.0 million from the sale of the subordinated units and general partner interest of NRP and the receipt of $52.5 million from the buyout of a coal supply contract with above-market pricing. These non-recurring cash inflows offset our capital expenditures and advance royalty payments, which totaled $165.0 million. Cash used in investing activities in 2002 is due primarily to capital expenditures and advance royalty payments, which totaled $164.4 million,

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offset partially by the impact of the sale of limited partnership units of NRP in 2002, which generated proceeds of $33.6 million.
      On September 22, 2004, the U.S. Bureau of Land Management (“BLM”) accepted our bid of $611.0 million for a 5,084-acre federal coal lease known as Little Thunder, which is adjacent to our Black Thunder mine in the Powder River Basin. According to the BLM, the lease contains approximately 719.0 million mineable tons of compliance coal. We paid the first of five annual payments at the time of the bid. The remaining four annual lease payments will be made in fiscal years 2006 through 2009.
      Cash provided by financing activities in 2004 consists primarily of proceeds from the issuance of senior notes of $261.9 million and proceeds from the issuance of common stock through a public offering of $230.5 million (as described more fully below). Additionally, financing activities in 2004 also include net borrowings under our revolving credit facility of $25.0 million, proceeds of $37.0 million from the issuance of common stock under our employee stock incentive plan and dividend payments of $24.0 million. Cash provided by financing activities in 2003 reflects the proceeds from the issuance of the Arch Western Finance senior notes (which were used to retire Arch Western’s existing debt) and the proceeds from the sale of preferred stock (see additional discussion below). Cash used in financing activities during 2002 primarily represents net payments under our revolver and lines of credit, payments of dividends, and reductions of capital lease obligations. In addition, during 2002, we entered into a sale and leaseback of equipment that resulted in proceeds of $9.2 million.
      On November 24, 2004, we filed a Universal Shelf Registration Statement on Form S-3 with the Securities and Exchange Commission. The Universal Shelf allows us to offer, from time to time, an aggregate of up to $1.0 billion in debt securities, preferred stock, depositary shares, purchase contracts, purchase units, common stock and related rights and warrants.
      On October 28, 2004, we completed a public offering of 7,187,500 shares of our common stock, including the underwriters’ full over-allotment option, at a price of $33.85 per share. We used the net proceeds of the offering, totaling $230.5 million after the underwriters’ discount and expenses, to repay borrowings under our revolving credit facility incurred to finance our acquisition of Triton Coal Company and the first annual payment for the Little Thunder federal coal lease. We intend to use the remaining proceeds for general corporate purposes, including the development of the Mountain Laurel longwall mine in Central Appalachia.
      On October 22, 2004, two subsidiaries of Arch Western, as co-obligors, issued $250 million of 63/4% senior notes due 2013 at a price of 104.75% of par, pursuant to Rule 144A under the Securities Act of 1933, as amended. The notes form a single series with Arch Western Finance’s existing 63/4% senior notes due 2013, except that the new notes are subject to certain transfer restrictions and are not fully fungible with the existing notes. We have an exchange offer underway for the notes; after completion of the exchange offer, the notes will be fully fungible with the previously issued notes. The net proceeds of the offering were used to repay and retire the outstanding indebtedness under Arch Western’s $100.0 million term loan maturing in 2007, to repay indebtedness under our revolving credit facility and for general corporate purposes.
      On June 25, 2003, Arch Western Finance, LLC, a subsidiary of Arch Western, completed the offering of $700 million of 63/4% senior notes due 2013. The proceeds of the offering were primarily used to repay Arch Western’s existing term loans. Interest on the senior notes is payable on January 1 and July 1 each year commencing January 1, 2004. The senior notes are guaranteed by Arch Western and certain of Arch Western’s subsidiaries and are secured by a security interest in promissory notes we issued to Arch Western evidencing cash loaned to us by Arch Western. The terms of the senior notes contain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets, and make investments.

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      On January 31, 2003, we completed a public offering of 2,875,000 shares of 5% Perpetual Cumulative Convertible Preferred Stock. The net proceeds from the offering of approximately $139.0 million were used to reduce indebtedness under our revolving credit facility and for working capital and general corporate purposes, including potential acquisitions.
      Excluding any significant mineral reserve acquisitions, we generally satisfy our working capital requirements and fund 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 working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next several years. Our ability to satisfy 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.
      Capital expenditures were $292.6 million, $132.4 million and $137.1 million for 2004, 2003 and 2002, respectively. Capital expenditures are made to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We anticipate that capital expenditures during 2005 will range from $340 to $360 million. This estimate includes capital expenditures related to development work at certain of our mining operations, including the Mountain Laurel complex in West Virginia and the North Lease mine in Utah formerly known as Skyline. Also, this estimate assumes no other acquisitions, significant expansions of our existing mining operations or additions to our reserve base. We anticipate that we will fund these capital expenditures with available cash, existing credit facilities and cash generated from operations.
      On December 22, 2004, we entered into a $700.0 million revolving credit facility that matures on December 22, 2009. The rate of interest on borrowings under the credit facility is a floating rate based on LIBOR. The credit facility is secured by substantially all of our assets as well as our ownership interests in substantially all of our subsidiaries, except our ownership interests in Arch Western and its subsidiaries. The credit facility replaced our existing $350.0 million revolving credit facility. At December 31, 2004, we had $69.0 million in letters of credit outstanding which, when combined with the $25.0 million of outstanding borrowings under the revolver, resulted in $606.0 million of unused borrowings under the revolver. At December 31, 2004, financial covenant requirements do not restrict the amount of unused capacity available to us for borrowing and letters of credit.
      Financial covenants contained in our revolving credit facility consist of a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. The leverage ratio requires that we not permit the ratio of total net debt (as defined in the facility) at the end of any calendar quarter to EBITDA (as defined in the facility) for the four quarters then ended to exceed a specified amount. The interest coverage ratio requires that we not permit the ratio of EBITDA (as defined) at the end of any calendar quarter to interest expense for the four quarters then ended to be less than a specified amount. The senior secured leverage ratio requires that we not permit the ratio of total net senior secured debt (as defined) at the end of any calendar quarter to EBITDA (as defined) for the four quarters then ended to exceed a specified amount. We were in compliance with all financial covenants at December 31, 2004.
      At December 31, 2004, debt amounted to $1,011.1 million, or 48% of capital employed, compared to $706.4 million, or 51% of capital employed, at December 31, 2003. Based on the level of consolidated indebtedness and prevailing interest rates at December 31, 2004, debt service obligations, which include the current maturities of debt and interest expense for 2005, are estimated to be $76.0 million.
      We periodically establish uncommitted lines of credit with banks. These agreements generally provide for short-term borrowings at market rates. At December 31, 2004, there were $20.0 million of such agreements in effect, of which none were outstanding.

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      We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2004, substantially all of our outstanding debt bore interest at fixed rates.
      Additionally, we are exposed to market risk associated with interest rates resulting from our interest rate swap positions. Prior to the June 25, 2003 Arch Western Finance senior notes offering and subsequent repayment of Arch Western’s term loans, we utilized interest rate swap agreements to convert the variable-rate interest payments due under the term loans and our revolving credit facility to fixed-rate payments.
      At December 31, 2004, our net interest rate swap position is as follows:
  •  Swaps with a notional value of $25.0 million which are designated as hedges of future interest payments to be made under our revolving credit facility. Under these swaps, we pay a fixed rate of 5.96% (before the credit spread over LIBOR) and receive a variable rate based upon 30-day LIBOR. The remaining term of the swap agreements at December 31, 2004 was 30 months.
 
  •  Swaps with a total notional value of $500.0 million consisting of offsetting positions of $250.0 million each. Because of the offsetting nature of these positions, we are not exposed to significant market interest rate risk related to these swaps. Under these swaps, we pay a weighted average fixed rate 5.72% on $250.0 million of notional value and receive a weighted average fixed rate of 2.71% on $250.0 million of notional value. The remaining terms of these swap agreements at December 31, 2004 ranged from 8 to 31 months.
      As of December 31, 2004, the fair value of our net interest rate swap position was a liability of $12.4 million. This liability is included in other noncurrent liabilities in the accompanying Consolidated Balance Sheets.
      We are also exposed to commodity price risk related to our purchase of diesel fuel. We enter into forward purchase contracts and heating oil swaps to reduce volatility in the price of diesel fuel for our operations. The swap agreements essentially fix the price paid for diesel fuel by requiring us to pay a fixed heating oil price and receive a floating heating oil price. The changes in the floating heating oil price highly correlate to changes in diesel fuel prices.
      The discussion below presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen. The major accounting policies for these instruments are described in Note 1 to the consolidated financial statements.
      At December 31, 2004, our debt portfolio consisted of substantially fixed rates. A change in interest rates on the fixed rate debt impacts the net financial instrument position but has no impact on interest incurred or cash flows. The sensitivity analysis related to our fixed rate debt assumes an instantaneous 100-basis point move in interest rates from their levels at December 31, 2004, with all other variables held constant. A 100-basis point increase in market interest rates would result in a $58.4 million decrease in the fair value of the Company’s fixed rate debt at December 31, 2004. At December 31, 2004, a $.05 per gallon increase in the price of heating oil would result in a $0.1 million increase in the fair value of the financial position of the heating oil swap agreements.
      As it relates to our interest rate swap positions, a change in interest rates impacts the net financial instrument position. A 100-basis point increase in market interest rates would result in a $0.6 million decrease in the fair value of our liability under the interest rate swap positions at December 31, 2004.

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Contractual Obligations
      The following is a summary of our significant contractual obligations as of December 31, 2004 (in thousands):
                                 
    Payments Due by Period
     
    2005   2006-2007   2008-2009   After 2009
                 
Long-term debt, including related interest
  $ 75,069     $ 136,317     $ 162,250     $ 1,174,438  
Operating leases
    25,282       44,767       35,786       29,066  
Royalty leases
    32,227       309,320       297,987       72,715  
Unconditional purchase obligations
    539,107       163,975       100,113        
Other long-term obligations
                      23,200  
                         
Total contractual cash obligations
  $ 671,685     $ 654,379     $ 596,136     $ 1,299,419  
                         
      Royalty leases represent non-cancelable royalty lease agreements as well as federal lease bonus payments due under the Little Thunder lease. Payments due under the Little Thunder lease total $611.0 million, to be paid in five equal annual installments of $122.2 million. The first installment was paid in September 2004 with the remaining four annual payments due in fiscal years 2006 through 2009. Unconditional purchase obligations represent amounts committed for purchases of materials and supplies, payments for services, purchased coal, and capital expenditures. Other long-term obligations represent our contractual amounts owed in conjunction with our ownership interest in Dominion Terminal Associates as described in Note 20 to the Consolidated Financial Statements.
      We currently do not anticipate making any contributions to our pension plan in 2005. We believe that our on-hand cash balance, cash generated from operations, and borrowing capacity under our revolving credit facility and other debt facilities will be sufficient to meet these obligations and our requirements for working capital and capital expenditures.
Contingencies
Reclamation
      The federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. We accrue for the costs of reclamation in accordance with the provisions of FAS 143, which was adopted as of January 1, 2003. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Other costs of reclamation common to surface and underground mining are related to reclaiming refuse and slurry ponds, eliminating sedimentation and drainage control structures, and dismantling or demolishing equipment or buildings used in mining operations. The establishment of the asset retirement obligation liability is based upon permit requirements and requires 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. Our management believes it is making adequate provisions for all expected reclamation and other associated costs.
Legal Contingencies
      Permit Litigation Matters. A group of local and national environmental organizations filed suit against the U.S. Army Corps of Engineers in the U.S. District Court in Huntington, West Virginia on October 23, 2003. In its complaint, Ohio River Valley Environmental Coalition, et al v. Bulen, et al, the plaintiffs allege that the Corps has violated its statutory duties arising under the Clean Water Act, the

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Administrative Procedure Act and the National Environmental Policy Act in issuing the Nationwide 21 (“NWP 21”) general permit. The plaintiffs allege that the procedural requirements of the three federal statutes identified in their complaint have been violated, and that the Corps may not utilize the mechanism of a nationwide permit to authorize valley fills. Among specific fills identified in the complaint as not meeting the requirements of the NWP 21 are valley fills associated with several of our operating subsidiaries, although none are party to this litigation. If the plaintiffs prevail in this litigation, it may delay our receipt of these permits.
      On July 8, 2004, the District court entered a final order enjoining the Corps from authorizing new valley fills using the mechanism of its nationwide permit. The Court also ordered the Corps to suspend current authorizations issued for fills that had not yet commenced construction on the date of the order. The district court modified its earlier decision on August 13 when it directed the Corps to suspend all permits for fills that had not commenced construction as of July 8, 2004.
      A total of three permits at two of our operating subsidiaries will be affected by the Court’s July 8 order. Because the Court found that it is the Corps’ procedure in issuing the permits, and not defects in the fills themselves, our affected subsidiaries will be able to re-apply for individual permits under section 404 of the Clean Water act to construct each fill. We currently do not believe that the individual permit process will have an impact on our mining operations.
      The Corps and several intervening trade associations, of which we are a member of three, filed an appeal with the U.S. Court of Appeals for the Fourth circuit in this matter on September 16, 2004.
      West Virginia Flooding Litigation. We and three of our subsidiaries have been named, among others, in 17 separate complaints filed in Wyoming, McDowell, Fayette, Upshur, Kanawha, Raleigh, Boone and Mercer Counties, West Virginia. These cases collectively include approximately 1,780 plaintiffs who are seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July of 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these cases, along with several additional flood damages cases not involving our subsidiaries, be handled pursuant to the Court’s Mass Litigation rules. As a result of this ruling, the cases have been transferred to the Circuit Court of Raleigh County in West Virginia to be handled by a panel consisting of three circuit court judges, which certified certain legal issues back to the West Virginia Supreme Court. The West Virginia Supreme Court has resolved these issues, and the panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts.
      While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition or results of operations.
      Ark Land Company v. Crown Industries. In response to a declaratory judgment action filed by Ark Land Company, a subsidiary of ours, in Mingo County, West Virginia against Crown Industries involving the interpretation of a severance deed under which Ark Land controls the coal and mining rights on property in Mingo County, West Virginia, Crown Industries filed a counterclaim against Ark Land and a third party complaint against us and two of our other subsidiaries seeking damages for trespass, nuisance and property damage arising out of the exercise of rights under the severance deed on the property by our subsidiaries. The defendant has alleged that our subsidiaries have insufficient rights to haul certain foreign coals across the property without payment of certain wheelage or other fees to the defendant. In addition, the defendant has alleged that we and our subsidiaries have violated West Virginia’s Standards for Management of Waste Oil and the West Virginia Surface Coal Mining and Reclamation Act by spilling and disposing of hydrocarbon and other wastes on and in the property and

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by failing to return the property to its approximate original contour. It also alleges that we or our contractor have improperly disposed of explosive components. This case is set for trial in May 2005.
      While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on it, we believe this matter will be resolved without a material adverse effect on our financial condition or results of operations.
      We are a party to numerous other 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. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.
Certain Trends and Uncertainties
Substantial Leverage — Covenants
      As of December 31, 2004, we had outstanding consolidated indebtedness of $1,011.1 million, representing approximately 48% of our capital employed. Despite making substantial progress in reducing debt, we continue to have significant debt service obligations, and the terms of our credit agreements limit our flexibility and result in a number of limitations on us. We also have significant lease and royalty obligations. Our ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of our indebtedness will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that we serve as well as 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 financings 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 and the terms of our credit agreements could have material consequences to our business, including, but not limited to: (i) making it more difficult to satisfy debt covenants and debt service, lease payment and other obligations; (ii) making it more difficult to pay quarterly dividends as we have in the past; (iii) increasing our vulnerability to general adverse economic and industry conditions; (iv) limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general corporate requirements; (v) reducing the availability of cash flows from operations to fund acquisitions, working capital, capital expenditures or other general corporate purposes; (vi) limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; or (vii) placing us at a competitive disadvantage when compared to competitors with less relative amounts of debt.
      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 covenants that create limitations on our ability to, among other things, borrow the full amount under our credit facilities, effect acquisitions or dispositions and incur additional debt, 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 adversely affect our ability to borrow under our credit facilities or result in an event of default under these agreements. In the event of a default, our 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.

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      Any downgrade in our credit ratings could adversely affect our ability to borrow and result in more restrictive borrowing terms, including increased borrowing costs, more restrictive covenants and the extension of less open credit. This in turn could affect our internal cost of capital estimates and therefore operational decisions.
Profitability
      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. We are exposed to commodity price risk related to our purchase of diesel fuel, explosives and steel. In addition, weather conditions, equipment replacement or repair, fires, variations in thickness of the layer, or seam, of coal, 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. Prolonged disruption of production at any of our principal mines, particularly our Black Thunder mine, would result in a decrease in our revenues and profitability, which could be material. Other factors affecting the production and sale of our coal that could result in decreases in our profitability include:
  •  continued high pricing environment for our raw materials, including, among other things, diesel fuel, explosives and steel;
 
  •  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;
 
  •  work stoppages or other labor difficulties;
 
  •  labor shortages
 
  •  mine worker vacation schedules and related maintenance activities; and
 
  •  changes in coal market and general economic conditions.
Environmental and Regulatory Factors
      The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:
  •  the discharge of materials into the environment;
 
  •  employee health and safety;
 
  •  mine permits and other licensing requirements;
 
  •  reclamation and restoration of mining properties after mining is completed;
 
  •  management of materials generated by mining operations;
 
  •  surface subsidence from underground mining;
 
  •  water pollution;
 
  •  legislatively mandated benefits for current and retired coal miners;
 
  •  air quality standards;
 
  •  protection of wetlands;
 
  •  endangered plant and wildlife protection;
 
  •  limitations on land use;

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  •  storage of petroleum products and substances that are regarded as hazardous under applicable laws; and
 
  •  management of electrical equipment containing polychlorinated biphenyls, or PCBs.
      In addition, the electric generating industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on our mining operations or our customers’ ability to use coal and may require us or our customers to significantly change operations or to incur substantial costs.
      While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.
      Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of our coal. These regulations can take a variety of forms, as explained below.
      The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standard for ozone. In particular, coal-fired power plants will be affected by state regulations designed to achieve attainment of the ambient air quality standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead.
      In July 1997, the EPA adopted more stringent ambient air quality standards for particulate matter and ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. In April 2004, the EPA issued final nonattainment designations for the eight-hour ozone standard, and, in December 2004, issued the final nonattainment standard for PM25. States will have to reuse their State Implementation Plans to require electric power generators to further reduce nitrogen oxide and particulate matter emissions, particularly in designated nonattainment areas. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and our development of new mines. This in turn may result in decreased production and a corresponding decrease in our revenues. Although the future scope of these ozone and particulate

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matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines.
      The EPA has also initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA’s regional haze program could affect the future market for coal.
      Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities for alleged violations of the Clean Air Act. The EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. We supply coal to some of the currently affected utilities, and it is possible that other of our customers will be sued. These lawsuits could require the utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely impact their demand for coal.
      New regulations concerning the routine maintenance provisions of the New Source Review program were published in October 2003. Fourteen states, the District of Columbia and a number of municipalities filed lawsuits challenging these regulations, and in December 2003 the Court stayed the effectiveness of these rules. Oral agreement was heard on this matter in January 2005. In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, EPA issued enforcement notices to several electric utility companies.
      In January 2004, the EPA proposed two new rules pursuant to the Clean Air Act that, once final, may require additional controls and impose more stringent requirements at coal-fired power generation facilities. First, EPA is seeking to lower nickel and mercury emissions at new and existing sources by requiring the use of Maximum Achievable Control Technology (“MACT”) or by implementing a nationwide “cap and trade” program. Second, EPA has proposed to require the submission of State Implementation Plans by 29 states and the District of Columbia to include control measures to reduce the emissions of sulfur dioxide and/or nitrogen oxides, pursuant to the eight-hour ozone and PM25 standards established pursuant to the Clean Air Act. The EPA has stated that it will issue new rules in 2005. Should either or both of these proposed rules become final, additional costs may be associated with operating coal-fired power generation facilities that may render coal a less attractive fuel source.
      Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants

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of greater than 25 megawatt capacity. Affected electric utilities can comply with these requirements by:
  •  burning lower sulfur coal, either exclusively or mixed with higher sulfur coal;
 
  •  installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal;
 
  •  reducing electricity generating levels; or
 
  •  purchasing or trading emissions credits.
      Specific emissions sources receive these credits, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows its holder to emit one ton of sulfur dioxide.
      In addition to emissions control requirements designed to control acid rain and to attain the national ambient air quality standards, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009. These controls are likely to require significant new improvements in controls by power plant owners. The most prominently targeted pollutant is mercury, which is already the subject of a proposed rule, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources.
      Other proposed initiatives may have an effect upon coal operations. One such proposal is the Bush Administration’s recently announced Clear Skies Initiative. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury from power plants. Other so-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of air pollutants. Were such initiatives enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.
      Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease.
      Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we are contractually obligated under the terms of our leases to comply with all laws, including SMCRA and equivalent state and local laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.
      SMCRA also requires us to submit a bond or otherwise financially secure the performance of our reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring

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on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines.
      We also lease some of our coal reserves to third party operators. Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the mine operator. Sanctions against the “owner” or “controller” are quite severe and can include civil penalties, reclamation fees and reclamation costs. We are not aware of any currently pending or asserted claims against us asserting that we “own” or “control” any of our lessees’ operations.
      Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel.
      West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the EPA’s approval of West Virginia’s antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. In August 2003, the Southern District of West Virginia vacated the EPA’s approval of West Virginia’s anti-degradation procedures, and remanded the matter to the EPA. On March 29, 2004, EPA Regions III sent a letter to the WVDEP that approved portions of the state’s anti-degradation program, denied approval of portions pending further study, and recommended removal of certain language on the state’s regulations. Depending upon the outcome of the DEP review, the issuance or re-issuance of Clean Water Act permits to us may be delayed or denied, and may increase the costs, time and difficulty associated with obtaining and complying Clean Water Act permits for surface mining operations.
      Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and

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similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights.
      Mining Permits and Approvals. Mining companies must obtain numerous permits that strictly regulate environmental and health and safety matters in connection with coal mining, some of which have significant bonding requirements. In connection with obtaining these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
      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. Accordingly, the permits we need for our mining operations 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.
      In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically we submit the necessary permit applications several months before we plan to begin mining a new area. In our experience, permits generally are approved several months after a completed application is submitted. In the past, we have generally obtained our mining permits without significant delay. However, we cannot be sure that we will not experience difficulty in obtaining mining permits in the future.
      Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the activities of mine operators, including us, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations. We cannot predict the possible effect of such regulatory changes.
      Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.
      Surety Bonds. Federal and state laws require us to obtain surety bonds to guarantee performance or payment of certain long-term obligations including mine closure and reclamation costs, federal and state workers’ compensation benefits, coal leases and other miscellaneous obligations. It has become increasingly difficult for us to secure new surety bonds or retain existing bonds without the posting of collateral. In addition, surety bond costs have increased and the market terms of such bonds have generally become more unfavorable. We may be unable to maintain our surety bonds or acquire new bonds in the future due to lack of availability, higher expense, unfavorable market terms, or an inability to post sufficient collateral. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse impact on us.
      Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of endangered species may have the

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effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.
      Other Environmental Laws Affecting Us. We are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe that we are in substantial compliance with all applicable environmental laws.
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, and some of our competitors may have greater financial resources. We compete with several major coal producers in the Central Appalachian and Powder River Basin areas. We also compete with a number of smaller producers in those and other market regions. Additionally, we are subject to the continuing risk of reduced profitability as a result of excess industry capacity.
Electric Industry Factors; Customer Creditworthiness
      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 dependent to a significant extent on summer and winter temperatures and the strength of the economy); government regulation; technological developments and the location, availability, quality and price of competing sources of coal; other fuels such as natural gas, oil and nuclear; and alternative energy sources such as hydroelectric power. Demand for 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 a decline in profitability.
      Electric utility deregulation is expected to provide incentives to generators of electricity to minimize their fuel costs and is believed to have caused electric generators to be more aggressive in negotiating prices with coal suppliers. Deregulation may have an adverse effect on our profitability to the extent it causes our customers to be more cost-sensitive.
      In addition, our ability to receive payment for coal sold and delivered depends on the creditworthiness of our customers. In general, the creditworthiness of our customers has deteriorated. If such trends continue, our acceptable customer base may be limited.
Terms of Long-Term Coal Supply Contracts
      During 2004, sales of coal under long-term contracts, which are contracts with a term greater than 12 months, accounted for 70% of our total revenues. The prices for coal shipped under these contracts may be below the current market price for similar type coal at any given time. For the year ended December 31, 2004, the weighted average price of coal sold under our long-term contracts was $15.15 per ton. As a consequence of the substantial volume of our sales which are subject to these long-term agreements, we have less coal available with which to capitalize on stronger coal

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prices if and when they arise. In addition, because long-term contracts may allow the customer to elect volume flexibility, our ability to realize the higher prices that may be available on the spot market may be restricted when customers elect to purchase higher volumes under such contracts. Our exposure to market-based pricing may also be increased should customers elect to purchase fewer tons. In addition, the increasingly short terms of sales contracts and the consequent absence of price adjustment provisions in such contracts make it more likely that we will not be able to recover inflation related increases in mining costs during the contract term.
Reserve Degradation and Depletion
      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 acquired 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. Exhaustion of reserves at particular mines can also have an adverse effect on operating results that is disproportionate to the percentage of overall production represented by such mines. Mingo Logan’s Mountaineer Mine is estimated to exhaust its longwall mineable reserves in the first quarter of 2007, although we expect to make up the lost production with our planned opening of our Mountain Laurel complex in Logan County, West Virginia which should ramp up to full production in mid-2007. The Mountaineer Mine generated $30.5 million and $26.1 million of our total operating income in the years ended 2004 and 2003, respectively.
Potential Fluctuations in Operating Results — Factors Routinely Affecting Results of Operations
      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 profitability. Weather conditions, equipment replacement or repair, fuel and supply prices, insurance costs, fires, variations in coal seam thickness, amounts of overburden rock and other natural materials, and other geological conditions have had, and can be expected in the future to have, a significant impact on operating results. A prolonged disruption of production at any of our principal mines, particularly the Mingo Logan operation in West Virginia or Black Thunder mine in Wyoming, would result in a decrease, which could be material, in our revenues and profitability.
      The geological characteristics of Central Appalachia coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, 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. In addition, as compared to mines in the Powder River Basin, permitting and licensing and other environmental and regulatory requirements are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and customers’ ability to use coal produced by, operators in Central Appalachia, including us.
      Other factors affecting the production and sale of our coal that could result in decreases in profitability include: (i) expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements; (ii) disruption or increases in the cost of transportation services; (iii) changes in laws or regulations, including permitting requirements; (iv) litigation; (v) work stoppages or other labor difficulties; (vi) mine worker vacation schedules and related maintenance activities; and (vii) changes in coal market and general economic conditions.

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Transportation
      The coal industry depends on rail, trucking and barge transportation to deliver shipments of coal to customers, and transportation costs are a significant component of the total cost of supplying coal. Disruption or insufficient availability of these transportation services could temporarily impair our ability to supply coal to customers and thus adversely affect our business and the results of our operations. In addition, increases in transportation costs associated with our coal, or increases in our transportation costs relative to transportation costs for coal produced by our competitors or of other fuels, could adversely effect our business and results of operations.
Reserves — Title; Leasehold Interests
      We base our reserve information on geological data assembled and analyzed by our staff, which includes various engineers and geologists, and periodically reviewed by outside firms. The reserve estimates are annually updated to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities of recoverable reserves, including many factors beyond 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 cause estimates to vary considerably from actual results.
      For these reasons, estimates of the economically recoverable quantities attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties, and revenues and expenditures with respect to our reserves, may vary from estimates, and such variances may be material. These estimates thus may not accurately reflect our actual reserves.
      Most of our mining operations are conducted on properties we lease. The loss of any lease could adversely affect our ability to develop the associated reserves. Because title to most of our leased properties and mineral rights is not usually verified until we have made 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 certain of our reserves may be adversely affected if defects in title or boundaries exist. In order to obtain leases or mining contracts to conduct mining operations on property where these defects exist, 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 on which mining operations are not commenced during the term of the lease.
Acquisitions
      We continually seek to expand our operations and coal reserves in the regions in which we operate through acquisitions of businesses and assets, including leases of coal reserves. Acquisition transactions involve inherent risks, such as:
  •  uncertainties in assessing the value, strengths, weaknesses, contingent and other liabilities and potential profitability of acquisition or other transaction candidates;
 
  •  the potential loss of key personnel of an acquired business;
 
  •  the ability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction;

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  •  problems that could arise from the integration of the acquired business;
 
  •  unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale; and
 
  •  unexpected development costs, such as those related to the development of the Little Thunder reserves, that adversely affect our profitability.
      Any one or more of these factors could cause us not to realize the benefits anticipated to result from the acquisition of businesses or assets.
Pension and Postretirement Benefits
      We estimate our future postretirement medical and pension benefit obligations based on various assumptions, including:
  •  actuarial estimates;
 
  •  assumed discount rates;
 
  •  estimates of mine lives;
 
  •  expected returns on pension plan assets; and
 
  •  changes in health care costs.
      Based on changes in our assumptions, our annual postretirement health and pension benefit costs have increased. If our assumptions relating to these benefits change in the future, our costs could further increase, which would reduce our profitability. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse effect on our financial results.
      On January 1, 1998, we replaced our existing pension plans with a new cash balance pension plan. The accrued benefits of active participants under the former plans were vested as of that date and the participant’s cash balance account was credited with the present value of the participant’s earned pension benefit, payable at normal retirement age. On February 12, 2004, the United States District Court for the Southern District of Illinois affirmed its earlier ruling that the cash balance formula used in IBM’s conversion to a cash balance plan violated the age discrimination provisions under ERISA. IBM has announced that it will appeal the decision to the Seventh Circuit Court of Appeals. The Illinois District Court’s decision conflicts with the decisions of two other district courts and with proposed regulations for cash balance plans issued by Treasury and the IRS in December 2002. In addition, on February 2, 2004, the Treasury Department proposed legislation that would clarify that cash balance plans do not violate the age discrimination rules that apply to pension plans as long as they treat older workers at least as well as younger workers. The retirement account formula used for our pension plan may not meet the standard ultimately set forth in the IBM Court’s decision. Consequently, the IBM decision may have an impact on our and other companies’ cash balance pension plans. The effect of the IBM decision on our cash balance plan or our financial position has not been determined at this time.
Certain Contractual Arrangements
      Our affiliate, Arch Western Resources, LLC, is the owner of our reserves and mining facilities in the Powder River Basin and Western Bituminous regions of the United States. The agreement under which Arch Western was formed provides that a subsidiary of ours, as the managing member of Arch Western, generally has exclusive power and authority to conduct, manage and control the business of Arch Western. However, consent of BP p.l.c., 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 such time, Arch Western has a debt

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rating less favorable than specified ratings with Moody’s Investors Service or Standard & Poor’s or fails to meet specified indebtedness and interest ratios.
      In connection with our June 1, 1998 acquisition of Atlantic Richfield Company’s (“ARCO”) coal operations, 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 certain actions taken prior to June 1, 2013, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western, or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. ARCO was acquired by BP p.l.c. in 2000. Depending on the time at which any such indemnification obligation were to arise, it could impact our profitability for the period in which it arises.
      Our Amended and Restated Certificate of Incorporation requires the affirmative vote of the holders of at least two-thirds of outstanding common stock voting thereon to approve a merger or consolidation and certain other fundamental actions involving or affecting control of us. Our Bylaws require the affirmative vote of at least two-thirds of the members of our Board of Directors in order to declare dividends and to authorize certain other actions.
Critical Accounting Policies
      Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Additionally, these estimates and judgments are discussed with our Audit Committee on a periodic basis. Actual results may differ from the estimates used under different assumptions or conditions. Note 1 to the Consolidated Financial Statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:
Asset Retirement Obligations
      Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of FAS 143. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon historical internal or third-party costs, depending on how the work is expected to be performed. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of FAS 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:
  •  Discount rate — FAS 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of FAS 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.

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  •  Third-party margin — FAS 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin is added to the estimated costs of these activities. This margin is estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than the estimates of our cost to perform the reclamation activities with internal resources. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.
      On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2004, we had recorded asset retirement obligation liabilities of $199.6 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2004, we estimate that the aggregate undiscounted cost of final mine closure is approximately $354.7 million.
Employee Benefit Plans
      We have non-contributory defined benefit pension plans covering certain of our salaried and non-union hourly employees. Benefits are generally based on the employee’s age and compensation. We fund the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes. For the years ended December 31, 2004 and 2003, we contributed $21.6 million and $18.9 million to the plan. We account for our defined benefit plans in accordance with FAS 87, Employer’s Accounting for Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis.
      The calculation of our net periodic benefit costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be “critical accounting estimates.” Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.
  •  The expected long-term rate of return on plan assets is an assumption reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan’s investment targets are 65% equity, 30% fixed income securities and 5% cash. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine pension expense was 8.5% and 9.0% for the years ended December 31, 2004 and 2003, respectively, which is less than the plan’s actual life-to-date returns. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into the future. The impact of lowering the expected long-term rate of return on plan assets from 8.5% to 8.0% for 2004 would have been an increase to expense of approximately $0.9 million.
 
  •  The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic pension cost. In estimating that rate, Statement No. 87 requires rates of return on high quality, fixed income investments. We utilize a bond portfolio model that includes

II-34


 

  bonds that are rated “AA” or higher with maturities that match the expected benefit payments under the plan. The discount rates used to determine pension expense for 2004 and 2003 were 6.5% and 7.0%, respectively. The impact of lowering the discount rate from the 6.5% utilized in 2004 to an assumed 6.0% would have resulted in an approximate $1.3 million increase in expense in 2004.
      The differences generated in changes in assumed discount rates and returns on plan assets are amortized into earnings over a five-year period.
      For the measurement of our year-end pension obligation for 2004 (and pension expense for 2005), we maintained our long-term rate of return assumption at 8.5% and changed our discount rate to 6.0%.
      We also currently provide certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for retirees who were members of the United Mine Workers of America is not contributory. Our current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid. We account for our other postretirement benefits in accordance with FAS 106, Employer’s Accounting for Postretirement Benefits Other Than Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis.
      Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. These assumptions include the discount rate and the future medical cost trend rate.
  •  The discount rate assumption reflects the rates available on high-quality fixed-income debt instruments at year-end and is calculated in the same manner as discussed above for the pension plan. The discount rate used to calculate the postretirement benefit expense for 2004 and 2003 was 6.5% and 7.0%, respectively. Had the discount rate been lowered from 6.5% to 6.0% in 2004, we would have incurred additional expense of $8.4 million.
 
  •  Future medical trend rate represents the rate at which medical costs are expected to increase over the life of the plan. The health care cost trend rate is determined based upon our historical changes in health care costs as well as external data regarding such costs. We have implemented many effective programs that have resulted in actual increases in medical costs to fall far below the double-digit increases experienced by most companies in recent years. The postretirement expense in 2004 was based on an assumed medical inflationary rate of 8.0%, trending down in half percent increments to 5%, which represents the ultimate inflationary rate for the remainder of the plan life. This assumption was based on our then current three-year historical average of per capita increases in health care costs. If we had utilized a medical trend rate of 9.0% in 2004, we would have incurred $4.0 million of additional expense.
      For the measurement of our year-end other postretirement obligation for 2004 (and other postretirement expense for 2005), we maintained our medical inflationary rate assumption at 8.0% (trending down to 5%) and changed our discount rate to 6.0%.
Income Taxes
      We record deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of assets and liabilities. A valuation allowance is recorded to reflect the amount of future tax benefits that management believes are not likely to be realized. In determining the appropriate valuation allowance, we take into account the level of expected future

II-35


 

taxable income and available tax planning strategies. If future taxable income was lower than expected or if expected tax planning strategies were not available as anticipated, we may record additional valuation allowance through income tax expense in the period such determination was made.

II-36


 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
      The Consolidated financial statements of Arch Coal, Inc. and subsidiaries and related notes thereto and report of independent registered public accounting firm follow.
INDEX TO FINANCIAL STATEMENTS OF ARCH COAL, INC. AND SUBSIDIARIES
     
Reports of Independent Registered Public Accounting Firm
  II-38
Management’s Report on Internal Control over Financial Reporting
  II-41
Report of Management
  II-42
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
  II-43
Consolidated Balance Sheets at December 31, 2004 and 2003
  II-44
Consolidated Statements of Stockholders’ Equity at December 31, 2004, 2003 and 2002
  II-45
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
  II-46
Notes to Consolidated Financial Statements
  II-47

II-37


 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To Board of Directors and Shareholders
of Arch Coal, Inc.
      We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Arch Coal, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Arch Coal Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
      In our opinion, management’s assessment that Arch Coal, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Arch Coal, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

II-38


 

      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Arch Coal, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004 of Arch Coal, Inc. and our report dated February 23, 2005 expressed an unqualified opinion thereon.
  -s- ERNST & YOUNG LLP
  Ernst & Young LLP
St. Louis, Missouri
February 23, 2005

II-39


 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To Board of Directors and Shareholders
of Arch Coal, Inc.
      We have audited the accompanying consolidated balance sheets of Arch Coal, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the financial statements referred to above (appearing on pages II-43 to II-84 of this annual report) present fairly, in all material respects, the consolidated financial position of Arch Coal, Inc. and subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Arch Coal, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2005 expressed an unqualified opinion thereon.
      As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003.
  -s- ERNST & YOUNG LLP
  Ernst & Young LLP
St. Louis, Missouri
February 23, 2005

II-40


 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
      Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting is effective as of December 31, 2004.
      Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

II-41


 

REPORT OF MANAGEMENT
      The management of Arch Coal, Inc. is responsible for the preparation of the consolidated financial statements and related financial information in this annual report. The financial statements are prepared in accordance with accounting principles generally accepted in the United States and necessarily include some amounts that are based on management’s informed estimates and judgments, with appropriate consideration given to materiality.
      The Company maintains a system of internal accounting controls designed to provide reasonable assurance that financial records are reliable for purposes of preparing financial statements and that assets are properly accounted for and safeguarded. The concept of reasonable assurance is based on the recognition that the cost of a system of internal accounting controls should not exceed the value of the benefits derived. The Company has a professional staff of internal auditors who monitor compliance with and assess the effectiveness of the system of internal accounting controls.
      The Audit Committee of the Board of Directors, composed of directors who are free from relationships that may impair their independence from Arch Coal, Inc., meets regularly with management, the internal auditors, and the independent auditors to discuss matters relating to financial reporting, internal accounting control, and the nature, extent and results of the audit effort. The independent auditors and internal auditors have full and free access to the Audit Committee, with and without management present.
     
 

-s- STEVEN F. LEER

Steven F. Leer
President and Chief Executive Officer
  -s- ROBERT J. MESSEY
Robert J. Messey
Senior Vice President and Chief Financial Officer

II-42


 

CONSOLIDATED STATEMENTS OF OPERATIONS
                           
    Year Ended December 31,
     
    2004   2003   2002
             
    (In thousands of dollars except per share
    data)
REVENUES
                       
 
Coal sales
  $ 1,907,168     $ 1,435,488     $ 1,473,558  
COSTS AND EXPENSES
                       
 
Cost of coal sales
    1,638,284       1,280,608       1,262,516  
 
Depreciation, depletion and amortization
    166,322       158,464       174,752  
 
Selling, general and administrative expenses
    52,842       43,942       37,999  
 
Long-term incentive compensation expense
    5,495       16,217        
 
Other expenses
    35,758       18,245       29,595  
                   
      1,898,701       1,517,476       1,504,862  
                   
OTHER OPERATING INCOME
                       
 
Income from equity investments
    10,828       34,390       10,092  
 
Gain on sale of units of Natural Resource Partners, LP
    91,268       42,743        
 
Other operating income
    67,483       45,226       50,489  
                   
      169,579       122,359       60,581  
                   
Income from operations
    178,046       40,371       29,277  
                   
Interest expense, net:
                       
 
Interest expense
    (62,634 )     (50,133 )     (51,922 )
 
Interest income
    6,130       2,636       1,083  
                   
      (56,504 )     (47,497 )     (50,839 )
                   
Other non-operating income (expense):
                       
 
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps
    (9,010 )     (8,955 )      
 
Other non-operating income
    1,044       13,211        
                   
      (7,966 )     4,256        
Income (loss) before income taxes and cumulative effect of accounting change
    113,576       (2,870 )     (21,562 )
Benefit from income taxes
    (130 )     (23,210 )     (19,000 )
                   
Income (loss) before cumulative effect of accounting change
    113,706       20,340       (2,562 )
Cumulative effect of accounting change, net of taxes
          (3,654 )      
                   
NET INCOME (LOSS)
  $ 113,706     $ 16,686     $ (2,562 )
Preferred stock dividends
    (7,187 )     (6,589 )      
                   
Net income (loss) available to common shareholders
  $ 106,519     $ 10,097     $ (2,562 )
                   
EARNINGS PER COMMON SHARE
                       
Basic earnings (loss) before cumulative effect of accounting change
    1.91       0.26       (0.05 )
Cumulative effect of accounting change
          (0.07 )      
                   
Basic earnings (loss) per common share
  $ 1.91     $ 0.19     $ (0.05 )
                   
Diluted earnings (loss) before cumulative effect of accounting change
    1.78       0.26       (0.05 )
Cumulative effect of accounting change
          (0.07 )      
                   
Diluted earnings (loss) per common share
  $ 1.78     $ 0.19     $ (0.05 )
                   
The accompanying notes are an integral part of the consolidated financial statements.

II-43


 

CONSOLIDATED BALANCE SHEETS
                     
    December 31,
     
    2004   2003
         
    (In thousands of dollars
    except share data)
ASSETS
Current assets
               
 
Cash and cash equivalents
  $ 323,167     $ 254,541  
 
Trade accounts receivable
    180,902       118,376  
 
Other receivables
    34,407       29,897  
 
Inventories
    119,893       69,907  
 
Prepaid royalties
    12,995       4,586  
 
Deferred income taxes
    33,933       19,700  
 
Other
    25,560       16,638  
             
   
Total current assets
    730,857       513,645  
             
Property, plant and equipment
               
 
Coal lands and mineral rights
    1,725,339       1,085,517  
 
Plant and equipment
    1,423,550       1,090,762  
 
Deferred mine development
    408,657       285,150  
             
      3,557,546       2,461,429  
Less accumulated depreciation, depletion and amortization
    (1,524,346 )     (1,146,294 )
             
   
Property, plant and equipment, net
    2,033,200       1,315,135  
             
Other assets
               
 
Prepaid royalties
    87,285       70,880  
 
Goodwill
    37,381        
 
Deferred income taxes
    241,226       246,024  
 
Equity investments
          172,045  
 
Other
    126,586       69,920  
             
   
Total other assets
    492,478       558,869  
             
   
Total assets
  $ 3,256,535     $ 2,387,649  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
               
 
Accounts payable
  $ 148,014     $ 89,975  
 
Accrued expenses
    217,216       180,314  
 
Current portion of debt
    9,824       6,349  
             
   
Total current liabilities
    375,054       276,638  
Long-term debt
    1,001,323       700,022  
Accrued postretirement benefits other than pension
    380,424       352,097  
Asset retirement obligations
    179,965       143,545  
Accrued workers’ compensation
    82,446       77,672  
Other noncurrent liabilities
    157,497       149,640  
             
   
Total liabilities
    2,176,709       1,699,614  
             
Stockholders’ equity
               
 
Preferred stock, $.01 par value, $50 liquidation preference, authorized 10,000,000 shares, issued 2,875,000 shares
    29       29  
 
Common stock, $.01 par value, authorized 100,000,000 shares, issued 62,500,458 and 53,561,979 shares
    631       536  
 
Paid-in capital
    1,280,513       988,476  
 
Retained deficit
    (166,273 )     (255,936 )
 
Unearned compensation
    (1,830 )      
 
Less treasury stock, at cost, 357,200 shares
    (5,047 )     (5,047 )
 
Accumulated other comprehensive loss
    (28,197 )     (40,023 )
             
   
Total stockholders’ equity
    1,079,826       688,035  
             
   
Total liabilities and stockholders’ equity
  $ 3,256,535     $ 2,387,649  
             
The accompanying notes are an integral part of the consolidated financial statements.

II-44


 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Three Years Ended December 31, 2004
                                                                     
                            Accumulated    
                Retained       Treasury   Other    
    Common   Preferred   Paid-In   Earnings   Unearned   Stock at   Comprehensive    
    Stock   Stock   Capital   (Deficit)   Compensation   Cost   Loss   Total
                                 
    (In thousands of dollars except share and per share data)
BALANCE AT JANUARY 1, 2002
  $ 527     $     $ 835,427     $ (239,336 )   $     $ (5,047 )   $ (20,829 )   $ 570,742  
 
Comprehensive income
                                                               
   
Net loss
                            (2,562 )                             (2,562 )
   
Minimum pension liability adjustment
                                                    (16,416 )     (16,416 )
   
Unrealized losses on derivatives
                                                    (5,192 )     (5,192 )
                                                 
 
Total comprehensive loss
                                                            (24,170 )
 
Dividends paid ($.23 per share)
                            (12,045 )                             (12,045 )
 
Issuance of 81,454 shares of common stock under the stock incentive plan, including income tax benefits
                    336                                       336  
                                                 
BALANCE AT DECEMBER 31, 2002
    527             835,763       (253,943 )           (5,047 )     (42,437 )     534,863  
 
Comprehensive income
                                                               
   
Net income
                            16,686                               16,686  
   
Minimum pension liability adjustment
                                                    3,403       3,403  
   
Unrealized losses on derivatives
                                                    (5,940 )     (5,940 )
   
Net amount reclassified to income
                                                    4,951       4,951  
                                                 
 
Total comprehensive income
                                                            19,100  
 
Dividends
                                                               
   
Common ($.23 per share)
                            (12,090 )                             (12,090 )
   
Preferred ($2.29 per share)
                            (6,589 )                             (6,589 )
 
Issuance of 2,875,000 shares of perpetual cumulative convertible preferred stock
            29       138,995                                       139,024  
 
Issuance of 770,609 shares of common stock under the stock incentive plan, including income tax benefits
    9               13,718                                       13,727  
                                                 
BALANCE AT DECEMBER 31, 2003
    536       29       988,476       (255,936 )           (5,047 )     (40,023 )     688,035  
 
Comprehensive income
                                                               
   
Net income
                            113,706                               113,706  
   
Minimum pension liability adjustment
                                                    1,221       1,221  
   
Mark-to-market for available-for-sale securities
                                                    2,081       2,081  
   
Net amount reclassified to income
                                                    8,524       8,524  
                                                 
 
Total comprehensive income
                                                            125,532  
 
Dividends
                                                               
   
Common ($.2975 per share)
                            (16,856 )                             (16,856 )
   
Preferred ($2.50 per share)
                            (7,187 )                             (7,187 )
 
Issuance of 7,187,500 shares of common stock pursuant to public offering
    72               230,455                                       230,527  
 
Issuance of 500,000 shares of common stock as contribution to pension plan
    5               15,435                                       15,440  
 
Issuance of 149,190 shares of common stock under the stock incentive plan — restricted stock units
    1               4,246               (4,247 )                      
 
Expense recognized on restricted stock units
                                    2,417                       2,417  
 
Issuance of 1,658,179 shares of common stock under the stock incentive plan — stock options, including income tax benefits
    17               41,901                                       41,918  
                                                 
BALANCE AT DECEMBER 31, 2004
  $ 631     $ 29     $ 1,280,513     $ (166,273 )   $ (1,830 )   $ (5,047 )   $ (28,197 )   $ 1,079,826  
                                                 
The accompanying notes are an integral part of the consolidated financial statements.

II-45


 

CONSOLIDATED STATEMENTS OF CASH FLOWS
                             
    Year Ended December 31,
     
    2004   2003   2002
             
    (In thousands of dollars)
OPERATING ACTIVITIES
                       
Net income (loss)
  $ 113,706     $ 16,686     $ (2,562 )
Adjustments to reconcile to cash provided by operating activities:
                       
 
Depreciation, depletion and amortization
    166,322       158,464       174,752  
 
Prepaid royalties expensed
    13,889       13,153       8,503  
 
Accretion on asset retirement obligations
    12,681       12,999        
 
Gain on sale of units of Natural Resource Partners, LP
    (91,268 )     (42,743 )      
 
Net gain on disposition of property, plant and equipment
    (6,668 )     (3,782 )     (751 )
 
Income from equity investments
    (10,828 )     (34,390 )     (10,092 )
 
Net distributions from equity investments
    17,678       49,686       17,121  
 
Cumulative effect of accounting change
          3,654        
 
Other non-operating (income) expense
    7,966       (4,256 )      
 
Changes in operating assets and liabilities (see Note 21)
    (67,406 )     (375 )     (4,634 )
 
Other
    (9,344 )     (6,735 )     (5,920 )
                   
   
Cash provided by operating activities
    146,728       162,361       176,417  
                   
INVESTING ACTIVITIES
                       
 
Payments for acquisitions, net of cash acquired
    (387,751 )            
 
Capital expenditures
    (292,605 )     (132,427 )     (137,089 )
 
Proceeds from sale of units of Natural Resource Partners, LP
    111,447       115,000       33,603  
 
Proceeds from coal supply agreements
          52,548        
 
Additions to prepaid royalties
    (33,813 )     (32,571 )     (27,339 )
 
Proceeds from disposition of property, plant and equipment
    7,428       4,282       2,522  
                   
   
Cash (used in) provided by investing activities
    (595,294 )     6,832       (128,303 )
                   
FINANCING ACTIVITIES
                       
 
Net borrowings (payments) on revolver and lines of credit
    25,000       (65,971 )     (26,513 )
 
Net payments on long-term debt
    (302 )     (675,000 )      
 
Proceeds from issuance of senior notes
    261,875       700,000        
 
Debt financing costs
    (12,806 )     (18,508 )     (8,228 )
 
Proceeds from sale and leaseback of equipment
                9,213  
 
Reductions of obligations under capital lease
                (8,210 )
 
Dividends paid
    (24,043 )     (17,481 )     (12,045 )
 
Proceeds from issuance of preferred stock
          139,024        
 
Proceeds from sale of common stock
    267,468       13,727       336  
                   
   
Cash provided by (used in) financing activities
    517,192       75,791       (45,447 )
                   
   
Increase in cash and cash equivalents
    68,626       244,984       2,667  
   
Cash and cash equivalents, beginning of year
    254,541       9,557       6,890  
                   
   
Cash and cash equivalents, end of year
  $ 323,167     $ 254,541     $ 9,557  
                   
SUPPLEMENTAL CASH FLOW INFORMATION:
                       
 
Cash paid during the year for interest
  $ 53,558     $ 30,014     $ 51,695  
 
Cash paid (received) during the year for income taxes
  $ 13,350     $ (6,407 )   $ (3,115 )
The accompanying notes are an integral part of the consolidated financial statements.

II-46


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands of Dollars Except Per Share Data)
1. Accounting Policies
Principles of Consolidation
      The consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries (“the Company”), which operate in the coal mining industry. The Company’s primary business is the production of steam and metallurgical coal from surface and deep mines throughout the United States, for sale to utility, industrial and export markets. The Company’s mines are primarily located in the Powder River Basin, Central Appalachia and Western Bituminous regions of the United States. All subsidiaries (except as noted below) are wholly owned. Intercompany transactions and accounts have been eliminated in consolidation.
      The Company’s Wyoming, Colorado and Utah coal operations are included in a joint venture named Arch Western Resources, LLC (“Arch Western”). Arch Western is 99% owned by the Company and 1% owned by BP Amoco. The Company also acts as the managing member of Arch Western.
      As of and for the period ending July 31, 2004, the membership interests in the Utah coal operations, Canyon Fuel Company, LLC (“Canyon Fuel”), were owned 65% by Arch Western and 35% by a subsidiary of ITOCHU Corporation. Through July 31, 2004, the Company’s 65% ownership of Canyon Fuel was accounted for on the equity method in the Consolidated Financial Statements as a result of certain super-majority voting rights in the joint venture agreement. Income from Canyon Fuel through July 31, 2004 is reflected in the Consolidated Statements of Operations as income from equity investments (see additional discussion in Note 5, “Equity Investments”). On July 31, 2004, the Company acquired the remaining 35% of Canyon Fuel. See Note 3, “Business Combinations” for further discussion.
      The Company’s 17.5% partnership interest in Dominion Terminal Associates is accounted for on the equity method in the consolidated balance sheets. Allocable costs of the partnership for coal loading and storage are included in other expenses in the consolidated statements of operations. (See additional discussion in “Commitments and Contingencies” in Note 20.)
Accounting Estimates
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Accounting Change
      On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“FAS 143”). FAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time the obligations are incurred. Upon initial recognition of a liability, the cost should also be capitalized as part of the carrying amount of the related long-lived asset and allocated to expense over the useful life of the asset. Previously, the Company accrued for the expected costs of these obligations over the estimated useful mining life of the property. See additional discussion in Note 11, “Asset Retirement Obligations.”

II-47


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
Cash and Cash Equivalents
      Cash and cash equivalents are stated at cost. Cash equivalents consist of highly liquid investments with an original maturity of three months or less when purchased.
Allowance for Uncollectible Receivables
      The Company maintains allowances to reflect the expected uncollectability of its trade accounts receivable and other receivables based on past collection history, the economic environment and specified risks identified in the receivables portfolio. Allowances recorded at December 31, 2004 and 2003 were $3.0 million and $1.5 million, respectively.
Inventories
      Inventories consist of the following:
                 
    December 31,
     
    2004   2003
         
Coal
  $ 76,009     $ 38,249  
Supplies, net of allowance
    43,884       31,658  
             
    $ 119,893     $ 69,907  
             
      Coal and supplies inventories are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs and operating overhead. The Company has recorded a valuation allowance for slow-moving and obsolete supplies inventories of $23.0 million and $18.8 million at December 31, 2004 and 2003, respectively.
Coal Acquisition Costs and Prepaid Royalties
      The costs to obtain coal lease rights are capitalized and amortized primarily by the units-of-production method over the estimated recoverable reserves. Amortization occurs either as the Company mines on the property or as others mine on the property through subleasing transactions.
      Rights to leased coal lands are often acquired through royalty payments. Where royalty payments represent prepayments recoupable against production, they are capitalized, and amounts expected to be recouped within one year are classified as a current asset. As mining occurs on these leases, the prepayment is charged to cost of coal sales.
Coal Supply Agreements
      Acquisition costs allocated to coal supply agreements (sales contracts) are capitalized and amortized on the basis of coal to be shipped over the term of the contract. Value is allocated to coal supply agreements based on discounted cash flows attributable to the difference between the above or below-market contract price and the then-prevailing market price. The net book value of the Company’s above-market coal supply agreements was $11.1 million and $6.4 million at December 31, 2004 and 2003, respectively. These amounts are recorded in other assets in the accompanying Consolidated Balance Sheets. The net book value of all below-market coal supply agreements was $29.2 million at December 31, 2004. This amount is recorded in other noncurrent liabilities in the accompanying Consolidated Balance Sheets. Amortization expense on all above-market coal supply agreements was $3.8 million, $16.6 million and $22.2 million in 2004, 2003 and 2002, respectively. Amortization income on all below-market coal supply agreements was $4.1 million in 2004. Based on expected shipments related to these contracts, the Company expects to record annual amortization

II-48


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
expense on the above-market coal supply agreements and annual amortization income on the below-market coal supply agreements in each of the next five years as reflected in the table below.
                 
    Above-market   Below-market
    contracts   contracts
         
2005
  $ 6,487     $ 15,183  
2006
    769       12,326  
2007
    361       1,342  
2008
    361       389  
2009
    361        
      During 2003, the Company agreed to terms with a large customer seeking to buy out of the remaining term of an above-market coal supply contract. The buy-out resulted in the receipt of $52.5 million in cash during the quarter. The Company wrote off the remaining contract value of $37.5 million and recorded a deferred gain of approximately $15 million related to this transaction. The deferred gain will be recognized ratably through 2012.
Exploration Costs
      Costs related to locating coal deposits and determining the economic mineability of such deposits are expensed as incurred.
Property, Plant and Equipment
Plant and Equipment
      Plant and equipment are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures which extend the useful lives of existing plant and equipment or increase the productivity of the asset are capitalized. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, which range from three to 30 years except for preparation plants and loadouts. Preparation plants and loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimum level of depreciation.
      Leased plant and equipment meeting certain criteria is capitalized and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed on the straight-line method over the term of the lease.
Deferred Mine Development
      Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited. Additionally, the asset retirement obligation asset has been recorded as a component of deferred mine development.
Coal Lands and Mineral Rights
      A significant portion of the Company’s coal reserves are controlled through leasing arrangements. Amounts paid to acquire such lease rights are capitalized and depleted over the life of those reserves that are proven and probable. Depletion of coal lease rights is computed using the units-of-production method and the rights are assumed to have no residual value. The leases are generally long-term in nature (original terms range from 10 to 50 years), and substantially all of the leases contain provisions that allow for automatic extension of the lease term as long as mining continues.

II-49


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
The net book value of the Company’s leased coal interests was $1,169.7 million and $693.3 million at December 31, 2004 and 2003, respectively. This increase is due to the addition of leased coal interests resulting from the North Rochelle and Canyon Fuel acquisitions and the Little Thunder leasing arrangement (See additional discussion in “Commitments and Contingencies” in Note 20).
Goodwill
      Goodwill represents the excess of purchase price and related costs over the value assigned to the net tangible and identifiable intangible assets of businesses acquired. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (“FAS 142”), goodwill is not amortized but is tested for impairment annually, or if certain circumstances indicate a possible impairment may exist. Impairment testing is performed at a reporting unit level. An impairment loss generally would be recognized when the carrying amount of the reporting unit exceeds the fair value of the reporting unit, with the fair value of the reporting unit determined using a discounted cash flow analysis.
Asset Impairment
      If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.
Revenue Recognition
      Coal sales revenues include sales to customers of coal produced at Company operations and coal purchased from other companies. The Company recognizes revenue from coal sales at the time title passes to the customer. Transportation costs that are billed by the Company and reimbursed to the transportation provider (pass through costs) are included in coal sales and cost of coal sales.
Other Operating Income
      Other operating income reflects income from sources other than coal sales, including administration and production fees from Canyon Fuel (these fees ceased as of the July 31, 2004 acquisition by the Company of the remaining 35% interest in Canyon Fuel), royalties earned from properties leased to third parties, and gains and losses from dispositions of long-term assets. These amounts are recognized as services are performed or otherwise earned.
Derivative Financial Instruments
      Derivative financial instruments are accounted for in accordance with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”). FAS 133 requires all derivative financial instruments to be reported on the balance sheet at fair value. Changes in fair value are recognized either in earnings or equity, depending on the nature of the underlying exposure being hedged and how effective the derivatives are at offsetting price movements in the underlying exposure.
      The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives for undertaking various hedge transactions. The Company evaluates the effectiveness of its hedging relationships both at the hedge inception and on an ongoing basis. Any ineffectiveness is recorded in the Consolidated Statements of Operations. Ineffectiveness for the years ended December 31, 2004 and 2003 was $0.2 million and $0.4 million, respectively.

II-50


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
      The Company has historically utilized interest-rate swap agreements to modify the interest characteristics of outstanding Company debt. The swap agreements essentially convert variable-rate debt to fixed-rate debt. These agreements require the exchange of amounts based on variable interest rates for amounts based on fixed interest rates over the life of the agreement. The Company accrues amounts to be paid or received under interest-rate swap agreements over the lives of the agreements. Such amounts are recognized as adjustments to interest expense over the lives of agreements, thereby adjusting the effective interest rate on the Company’s debt.
      At December 31, 2004, the Company’s net interest rate swap position is as follows:
  •  Swaps with a notional value of $25.0 million which are designated as hedges of future interest payments to be made under the Company’s revolving credit facility. Under these swap agreements, the Company pays a fixed rate of 5.96% (before the credit spread over LIBOR) and receives a weighted-average variable rate based upon 30-day LIBOR. At December 31, 2004, the remaining term of the swap agreements was 30 months.
 
  •  Swaps with a total notional value of $500.0 million consisting of offsetting positions of $250.0 million each. Because of the offsetting nature of these positions, the Company is not exposed to market interest rate risk related to these swaps. Under these swaps, the Company pays a weighted average fixed rate 5.72% on $250.0 million of notional value and receives a weighted average fixed rate of 2.71% on $250.0 million of notional value. The remaining terms of these swap agreements at December 31, 2004 ranged from 8 to 31 months.
      Changes in the market value of the interest-rate swaps that no longer qualify as hedges are recorded as income or expense in the period of the change. During 2003, the Company recorded gains of $13.4 million resulting from changes in the market value of interest-rate swaps. This amount is included as other non-operating income in the accompanying Consolidated Statements of Operations.
Income Taxes
      Deferred income taxes are based on temporary differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates for years during which taxes are expected to be paid or recovered.
Stock-Based Compensation
      These financial statements include the disclosure requirements of Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation (“FAS 123”), as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure (“FAS 148”). With respect to accounting for its stock options, as permitted under FAS 123, the Company has retained the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 (“APB 25”), Accounting for Stock Issued to Employees, and related Interpretations. Had compensation expense for stock option grants been determined based on the fair value at the grant dates consistent with the method of FAS 123, the Company’s net income (loss) and

II-51


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
earnings (loss) per common share would have been changed to the pro forma amounts as indicated in the following table:
                           
    Year Ended December 31
     
    2004   2003   2002
             
As reported
                       
 
Net income (loss) available to common shareholders
  $ 106,519     $ 10,097     $ (2,562 )
 
Basic earnings (loss) per share
    1.91       0.19       (0.05 )
 
Diluted earnings (loss) per share
    1.78       0.19       (0.05 )
Pro forma (unaudited)
                       
 
Net income (loss) available to common shareholders
  $ 101,054     $ 858     $ (11,168 )
 
Basic earnings (loss) per share
    1.81       0.02       (0.21 )
 
Diluted earnings (loss) per share
    1.70       0.02       (0.21 )
      On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (FAS 123R), which requires all public companies to measure compensation cost in the income statement for all share-based payments (including employee stock options) at fair value for interim or annual periods beginning after June 15, 2005. The Company intends to adopt FAS 123R on July 1, 2005 using the modified-prospective method and anticipates a pre-tax charge to income of approximately $3.5 million for the expensing of unvested stock options and price contingent stock awards for the period July 1, 2005 through December 31, 2005. FAS 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption.
Recent Accounting Pronouncements
      In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4” (FAS 151). This Statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Provisions of this statement are effective for fiscal years beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on its financial statements.
      In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions” (FAS 153). This Statement’s amendments are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, FAS 153 eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. Provisions of this statement are effective for fiscal periods beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on its financial statements.

II-52


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
Reclassifications
      Certain amounts in the prior years’ financial statements have been reclassified to conform with the classifications in the current year’s financial statements with no effect on previously reported net income or stockholders’ equity.
2. Changes in Estimates and Other Non-Recurring Revenues and Expenses
      During the year ending December 31, 2004, the Company assigned its rights and obligations on a parcel of land to a third party resulting in a gain of $5.8 million. The gain is reflected in other operating income.
      During 2004, the Company filed a royalty rate reduction request with the Bureau of Land Management (“BLM”) for its West Elk mine in Colorado. The BLM notified the Company that it would receive a royalty rate reduction for a specified number of tons representing a retroactive portion for the year totaling $2.7 million. The retroactive portion was recognized as a component of cost of coal sales in the Consolidated Statement of Operations.
      In connection with the settlement of tax audits for prior years, the Company recorded interest income of $2.2 million in 2004 related to federal income tax refunds. This amount is reflected as interest income.
      During the year ending December 31, 2004, the Company was notified by the IRS that it would receive additional black lung excise tax refunds and interest related to black lung claims that were originally denied by the IRS in 2002. The Company recognized a gain of $2.8 million ($2.1 million refund and $0.7 million of interest) related to the claims. The $2.1 million refund was recorded as a component of cost of coal sales, while the $0.7 million of interest was recorded as interest income.
      During the year ending December 31, 2004, Canyon Fuel, which was accounted for under the equity method through July 31, 2004, began the process of idling its Skyline Mine (the idling process was completed in May 2004), and incurred severance costs of $3.2 million for the year ended December 31, 2004. The Company’s share of these costs totals $2.1 million and is reflected in income from equity investments.
      During the year ending December 31, 2003, the Company instituted cost reduction efforts throughout its operations. These cost reduction efforts included the termination of approximately 100 employees at the Company’s corporate headquarters and its Central Appalachia mining operations and the recognition of expenses related to severance of $2.6 million. Of this amount, $1.6 million was reported as a component of cost of coal sales, with the remainder reported in selling, general and administrative expenses. Substantially all of the amounts noted were paid during 2003.
      During the year ended December 31, 2003, the Company was notified by the State of Wyoming of a favorable ruling relating to the Company’s calculation of coal severance taxes. The ruling resulted in a refund of previously paid taxes and the reversal of previously accrued taxes payable. The impact on the 2003 financial results was a gain of $2.5 million, which was reflected as a reduction of cost of coal sales.
      During the year ended December 31, 2003, the Company repaid its variable-rate term loans with the proceeds from the sale of fixed-rate notes. At that time, the Company determined that certain interest rate swaps that had been designated as hedges of the variable-rate interest payments were no longer effective hedges. Historical mark-to-market losses related to these swaps totaling $27.0 million had been previously deferred and are now being amortized as additional expense over the contractual terms of the swap agreements. The swap agreements’ contractual termination dates

II-53


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
range from September 2005 through October 2007. During 2004 and 2003, the Company recognized expenses of $8.3 million and $4.3 million, respectively, related to the amortization of these previously deferred mark-to-market adjustments. The Company recognized an additional $0.7 million and $4.7 million of expense in 2004 and 2003, respectively, that represented early debt extinguishment costs. These amounts are included in expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps in the accompanying Consolidated Statements of Operations.
      During the year ended December 31, 2002, the Company settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain of $5.6 million, which was recognized in other operating income in the Consolidated Statements of Operations.
      The Company recognized a pre-tax gain of $4.6 million during the year ended December 31, 2002 as a result of a workers’ compensation premium adjustment refund from the State of West Virginia. During 1998, the Company entered into the West Virginia workers’ compensation plan at one of its subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers’ Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers’ Compensation refunded $4.6 million in premiums, which was recognized as an adjustment to cost of coal sales in the Consolidated Statements of Operations.
      During 2002, the Company filed a royalty rate reduction request with the BLM for its West Elk mine in Colorado. The BLM notified the Company that it would receive a royalty rate reduction for a specified number of tons representing a retroactive portion for the year totaling $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in the Consolidated Statement of Operations. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments in the Consolidated Statement of Operations.
3. Business Combinations
Canyon Fuel 35% Acquisition
      On July 31, 2004, the Company purchased the 35% interest in Canyon Fuel that it did not own from ITOCHU Corporation. The purchase price, including related costs and fees, of $112.2 million was funded with cash of $90.2 million and a five-year, $22.0 million non-interest bearing note. Net of cash acquired, the fair value of the transaction totaled $97.4 million. As a result of the acquisition, the Company owns substantially all of the ownership interests of Canyon Fuel and will no longer account for its investment in Canyon Fuel on the equity method but will consolidate Canyon Fuel in its financial statements. As of December 31, 2003, Canyon Fuel controlled approximately 161.0 million tons of low-sulfur coal reserves in Utah and produced approximately 13.0 million tons of coal in 2003. The results of operations of the Canyon Fuel mines are included in the Company’s Western Bituminous segment.
      The preliminary purchase accounting allocation related to the acquisition has been recorded in the accompanying consolidated financial statements as of, and for the period subsequent to, July 31, 2004. The final valuation of the assets acquired and liabilities assumed is expected to be finalized once third-party appraisals are completed. The Company expects the completion of these appraisals during the first half of 2005.

II-54


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(In Thousands of Dollars Except Per Share Data)
      The following table summarizes the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition (dollars in thousands):
     <