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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
 
 
 
 
Form 10-K
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2007
 
Commission file number: 1-13105
 
(ARCH COAL LOGO)
(Exact name of registrant as specified in its charter)
 
     
Delaware   43-0921172
 
(State or other jurisdiction
  (I.R.S. Employer
of incorporation or organization)
  Identification Number)
 
     
One CityPlace Drive, Ste. 300, St. Louis, Missouri   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:
 
         
Title of Each Class   Name of Each Exchange on Which Registered
Common Stock, $.01 par value
    New York Stock Exchange
Chicago Stock Exchange
 
Preferred Share Purchase Rights
    New York Stock Exchange  
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ  No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o  No þ
 
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. o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No þ
 
The aggregate market value of the voting stock held by non-affiliates of the registrant (excluding outstanding shares beneficially owned by directors, officers and treasury shares) as of June 29, 2007 was approximately $5.0 billion.
 
On February 25, 2008, 143,954,798 shares of the company’s common stock, par value $0.01 per share, were outstanding.
 
Portions of the company’s definitive proxy statement for the annual stockholders’ meeting to be held on April 24, 2008 are incorporated by reference into Part III of this Form 10-K.
 


 

 
TABLE OF CONTENTS
 
             
        Page
 
           
  BUSINESS.     1  
  RISK FACTORS.     23  
  UNRESOLVED STAFF COMMENTS.     31  
  PROPERTIES.     31  
  LEGAL PROCEEDINGS.     33  
  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.     34  
           
  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.     34  
  SELECTED FINANCIAL DATA.     36  
  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.     37  
  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.     55  
  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.     56  
  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.     56  
  CONTROLS AND PROCEDURES.     56  
  OTHER INFORMATION.     56  
           
  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.     56  
  EXECUTIVE COMPENSATION.     56  
  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.     56  
  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.     57  
  PRINCIPAL ACCOUNTING FEES AND SERVICES.     57  
           
  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES     57  
 Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
 Subsidiaries
 Consent of Ernst & Young LLP
 Power of Attorney
 Certification
 Certification
 Certification
 Certification


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Cautionary Statements Regarding Forward-Looking Information
 
This document contains “forward-looking statements” — that is, statements related to future, not past, events. In this context, forward-looking statements often address our expected future business and financial performance, and often contain words such as “anticipates,” “believes,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “predicts,” “projects,” “seeks,” “should,” “will” or other comparable words and phrases. Forward-looking statements by their nature address matters that are, to different degrees, uncertain. We believe that the factors that could cause our actual results to differ materially include the factors that we describe under the heading “Risk Factors” beginning on page 23. Those risks and uncertainties include but are not limited to the following:
 
  •  market demand for coal and electricity;
 
  •  geologic conditions, weather and other inherent risks of coal mining that are beyond our control;
 
  •  availability and price of mining and other industrial supplies;
 
  •  availability of skilled employees and other workforce factors;
 
  •  disruptions in the quantities of coal produced by our contract mine operators;
 
  •  our ability to acquire or develop coal reserves in an economically feasible manner;
 
  •  defects in title or the loss of a leasehold interest;
 
  •  railroad, barge, truck and other transportation performance and costs;
 
  •  our ability to successfully integrate the operations that we acquire;
 
  •  our ability to secure new coal supply arrangements or to renew existing coal supply arrangements;
 
  •  our relationships with, and other conditions affecting, our customers;
 
  •  our ability to service our outstanding indebtedness;
 
  •  our ability to comply with the restrictions imposed by our credit facility and other financing arrangements;
 
  •  the availability and cost of surety bonds;
 
  •  failure by Magnum Coal Company, which we refer to as Magnum, to satisfy certain below-market contracts that we guarantee;
 
  •  terrorist attacks, military action or war;
 
  •  environmental laws, including those directly affecting our coal mining operations and those affecting our customers’ coal usage;
 
  •  our ability to obtain and renew mining permits;
 
  •  future legislation and changes in regulations, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particular matter or greenhouse gases;
 
  •  the accuracy of our estimates of reclamation and other mine closure obligations;
 
  •  the existence of hazardous substances or other environmental contamination on property owned or used by us; and
 
  •  the availability of future permits authorizing the disposition of certain mining waste.
 
These factors should not be construed as exhaustive and should be read in conjunction with the other cautionary statements included in this document. These risks and uncertainties may cause our actual future results to be materially different than those expressed in our forward-looking statements. We do not undertake to update our forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law.


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Glossary of Selected Mining Terms
 
Certain terms that we use in this document are specific to the coal mining industry and may be technical in nature. The following is a list of selected mining terms and the definitions we attribute to them.
 
Assigned reserves Recoverable reserves designated for mining by a specific operation.
 
Btu A measure of the energy required to raise the temperature of one pound of water one degree of Fahrenheit.
 
Compliance coal Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, requiring no blending or other sulfur dioxide reduction technologies in order to comply with the requirements of the Clean Air Act.
 
Continuous miner A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.
 
Dragline A large machine used in surface mining to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket, suspended by cables from the end of a long boom, which is able to scoop up large amounts of overburden as it is dragged across the excavation area and redeposit the overburden in another area.
 
Longwall mining One of two major underground coal mining methods, generally employing two rotating drums pulled mechanically back and forth across a long face of coal.
 
Low-sulfur coal Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.
 
Preparation plant A facility used for crushing, sizing and washing coal to remove impurities and to prepare it for use by a particular customer.
 
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 or are otherwise less adequately spaced.
 
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. 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.


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Reserves That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
 
Room-and-pillar mining One of two major underground coal mining methods, utilizing continuous miners creating a network of “rooms” within a coal seam, leaving behind “pillars” of coal used to support the roof of a mine.
 
Unassigned reserves Recoverable reserves that have not yet been designated for mining by a specific operation.


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PART I
 
ITEM 1.   BUSINESS.
 
Introduction
 
We are one of the largest coal producers in the United States. At December 31, 2007, we operated 18 active mines located in each of the major low-sulfur coal-producing regions of the United States. Federal and state environmental regulations affect the demand for certain types of coal by limiting the amount of sulfur dioxide that may be emitted as a result of combustion. Due to these regulations, we believe demand for low-sulfur coal exceeds demand for other types of coal. Consequently, we focus on mining, processing and marketing coal with low sulfur content. At December 31, 2007, we estimate that our proven and probable coal reserves had an average heat value of approximately 10,000 Btus and an average sulfur content of approximately 0.71%. As such, we estimate that approximately 75.4% of our proven and probable coal reserves consists of compliance coal.
 
We sell substantially all of our coal to power plants, steel mills and industrial facilities. For the year ended December 31, 2007, we sold approximately 135.0 million tons of coal, including approximately 8.6 million tons of coal we purchased from third parties, fueling approximately 6% of all electricity generated in the United States. The locations of our mines enable us to ship coal to most of the major coal-fueled power plants in the United States. The following chart shows the breakdown of our coal production by region for 2007, expressed as a percentage of the total tons we produced:
 
2007 Coal Production, by Region
% of Total Tons
 
(GRAPH)
 
In 2007, we sold approximately 73.6% of our coal under contracts with a term of more than one year. At December 31, 2007, the average volume-weighted remaining term of our long-term contracts was approximately 3.8 years, with remaining terms ranging from one to ten years. At December 31, 2007, we had a sales backlog, including a backlog subject to price reopener or extension provisions, of approximately 377.5 million tons.
 
We believe that rapid economic expansion in developing nations, particularly China and India, has increased global demand for coal. We expect coal exports from the United States to increase in response to growing global coal demand, particularly as some of the traditional coal export nations experience mine, port, rail and labor challenges. We estimate that higher domestic demand for coal and higher U.S. coal exports will positively influence domestic coal demand. Additionally, we expect decreased production, particularly in the Central Appalachian region of the United States, to adversely impact domestic coal supply in the coming years. We anticipate continuing demand growth and weaker coal supplies to exert upward pressure on coal pricing in the future. As a result, we have not yet priced a portion of the coal we plan to produce over the next several years in order to take advantage of expected price increases. At December 31, 2007, our expected unpriced production approximated 15 million to 25 million tons in 2008, 85 million to 95 million tons in 2009 and 95 million to 105 million tons in 2010.


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Our History
 
We were organized in Delaware in 1969 as Arch Mineral Corporation. In July 1997, we merged with Ashland Coal, Inc., a subsidiary of Ashland Inc. formed in 1975. As a result of the merger, we became one of the largest producers of low-sulfur coal in the eastern United States.
 
In June 1998, we expanded into the western United States when we acquired the coal assets of Atlantic Richfield Company. This acquisition included the Black Thunder and Coal Creek mines in the Powder River Basin of Wyoming, the West Elk mine in Colorado and a 65% interest in Canyon Fuel Company, which operates three mines in Utah. In October 1998, we were the successful bidder for the Thundercloud reserve, a 412-million-ton federal reserve tract adjacent to the Black Thunder mine.
 
In July 2004, we acquired the remaining 35% interest in Canyon Fuel Company. In August 2004, we acquired Triton Coal Company’s North Rochelle mine adjacent to our Black Thunder operation. In September 2004, we were the successful bidder for the Little Thunder reserve, a 719-million-ton federal reserve tract adjacent to the Black Thunder mine.
 
In December 2005, we sold the stock of Hobet Mining, Inc., Apogee Coal Company and Catenary Coal Company and their four associated mining complexes (Hobet 21, Arch of West Virginia, Samples and Campbells Creek) and approximately 455.0 million tons of coal reserves in Central Appalachia to Magnum.
 
The Coal Industry
 
Global Coal Supply and Demand.  Because of its availability, stability and affordability, coal is a major contributor to the global energy supply, providing approximately 40% of the world’s electricity, according to the World Coal Institute, which we refer to as the WCI. Coal is also used in producing approximately 64% of the world’s steel supply, according to the WCI. Coal reserves can be found in almost every country in the world, and approximately 50 countries are currently mining coal.
 
Coal is traded worldwide and can be transported to demand centers by ship and by rail. Worldwide coal production approximated 5.9 billion tons in 2006 and 5.4 billion tons in 2005, according to the WCI. China produces more coal than any other country in the world. Historically, Australia has been the world’s largest coal exporter, exporting more than 200 million tons in each of the last three years, according to the WCI. China, Indonesia and South Africa have also historically been significant exporters in the global coal markets, however, growing demand in China has resulted in declining coal exports and increasing coal imports. These trends have caused China to become a less significant seaborne coal supply source. In 2007, coal supply from other regions was similarly affected because of mine disruptions, train derailments and port congestion.
 
Growing demand for coal for power generation in many Asian countries has begun to strain global coal supplies. Seaborne coal trade increased 4.6% to approximately 806.9 million metric tons in 2007, according to SSY Consultancy & Research, Ltd. Seaborne trade into Asia increased approximately 9.1%, while European trade decreased approximately 4.3%. Demand in China is expected to grow rapidly, as the demand for electricity and the need for steel used in construction and automobile production increase.
 
U.S. Coal Consumption.  In the United States, coal is used primarily by power plants to generate electricity, by steel companies to produce coke for use in blast furnaces and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Coal consumption in the United States has increased from 398.1 million tons in 1960 to approximately 1.2 billion tons in 2007, based on information provided by the Energy Information Administration, which we refer to as the EIA.
 
Throughout the United States, coal has long been favored as a fuel to produce electricity because of its cost advantage and its availability. Since 1970, the use of coal to generate electricity in the United States has nearly tripled in response to growing electricity demand. According to the EIA, coal accounted for approximately 50% of U.S. electricity generation in 2007 and is projected to account for approximately 55% in 2030. By comparison, generation from natural gas is expected to peak at approximately 21% in 2018 before slowly


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declining. The following chart shows U.S. electricity generation by fuel source from 1980 through 2007 and the projected generation through 2030:
 
Electricity Generation by Fuel, 1980-2030
(in billion kilowatthours)
 
(GRAPH)
 
Source: EIA
 
According to the National Mining Association, which we refer to as the NMA, coal is the lowest-cost fossil fuel used in producing electricity. We estimate that the cost of generating electricity from coal is less than one-third of the cost of generating electricity from other fuels. According to the EIA, the average delivered cost of coal to electric power generators during the first ten months of 2007 was $1.77 /mm Btus, which was $6.39 /mm Btus less expensive than residual fuel oil and $5.28 /mm Btus less expensive than natural gas.
 
The EIA projects that power plants will increase their demand for coal as demand for electricity increases. The EIA estimates that electricity demand will increase by at least 40% by 2030, despite continuing efforts throughout the United States to become more energy efficient. Coal consumption has generally grown at the pace of electricity growth because coal-fueled electricity generation is used in most cases to meet baseload requirements. We estimate that coal consumption for power generation increased approximately 1.7% in 2007 as a result of average economic growth and more favorable weather than in 2006. Historically, demand for electricity has generally grown in proportion to U.S. economic growth, as measured by gross domestic product. In 2007, real gross domestic product increased 2.2%, according to the U.S. Department of Commerce.
 
Demand for coal is broadly influenced by weather. Weather patterns requiring greater use of air-conditioning or heating translate into greater demand for coal-based electricity generation. According to the EIA, coal stockpiles at power plants represented an approximate 53-day supply at the end of 2007, compared to coal stockpiles representing an approximate 50-day supply at the end of 2006. We believe that some domestic power plants seek to protect against future supply disruptions by maintaining higher stockpile levels.
 
We believe that demand growth from new coal-fueled power plants represents an important element to the long-term outlook for coal. We estimate that roughly 25 gigawatts of new domestic coal-fueled electricity generation capacity is currently under construction or in advanced permitting stages, equating to more than 85 million tons of new incremental annual coal demand, based on information obtained from the National Energy Technology Laboratory, which we refer to as the NETL, and our internal estimates. We expect all or a significant majority of these plants to be built over the next five years. The NETL also estimates that, at


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December 31, 2007, approximately 17 gigawatts of generating capacity was under construction or in advanced stages of development in the United States.
 
Coal is expected to remain the fuel of choice for domestic power generation through at least 2030, according to the EIA. Through that time, we expect new technologies intended to lower emissions of mercury, sulfur dioxide, nitrogen oxide and particulate matter will be introduced into the power generation industry. We believe these technological advancements will help coal retain its role as a key fuel for electric power generation well into the future.
 
The other major market for coal is the steel industry. Coal is essential for iron and steel production. According to the WCI, approximately 64% of all steel is produced from iron made in blast furnaces that use coal. The steel industry uses metallurgical coal, which is distinguishable from other types of coal because of its high carbon content, low expansion pressure, low sulfur content and various other chemical attributes. As such, the price offered by steel makers for metallurgical coal is generally higher than the price offered by power plants and industrial users for steam coal. Rapid economic expansion in China, India and other parts of southeast Asia has significantly increased the demand for steel in recent years.
 
Prices for oil and natural gas in the United States have reached record levels because of increasing demand and tensions regarding international supply. Historically high oil and gas prices and global energy security concerns have increased government and private sector interest in converting coal into liquid fuel, a process known as liquefaction. Liquid fuel produced from coal can be refined further to produce transportation fuels, such as low-sulfur diesel fuel, gasoline and other oil products, such as plastics and solvents. Several coal-to-liquids projects are in the process of development, including a coal-to-liquids facility proposed by a coal-conversion company in which we own an equity interest. We also expect advances in technologies designed to convert coal into electricity through coal gasification processes and to capture and sequester carbon dioxide emissions from electricity generation and other sources. These technologies have garnered greater attention in recent years due to developing concerns about the impact of carbon dioxide on the global climate. We believe the advancement of coal-conversion and other technologies represents a positive development for the long-term demand for coal.
 
U.S. Coal Production.  The United States produces approximately one-fifth of the world’s coal production and is the second largest coal producer in the world, exceeded only by China. Coal in the United States represents approximately 94% of the domestic fossil energy reserves with over 250 billion tons of recoverable coal, according to the U.S. Geological Survey. The U.S. Department of Energy estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for more than 200 years. Coal production in the United States has increased from 434 million tons in 1960 to approximately 1.2 billion tons in 2007 based on information provided by EIA.
 
Western region—The western region includes, among other areas, the Powder River Basin and the Western Bituminous region. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. Coal from this region has a very low sulfur content and a low heat value. The price of Powder River Basin coal is generally less than that of coal produced in other regions because Powder River Basin coal exists in greater abundance, is easier to mine and thus has a lower cost of production. In addition, Powder River Basin coal is generally lower in heat value, which requires some electric power generation facilities to blend it with higher Btu coal or retrofit some existing coal plants to accommodate lower Btu coal. The Western Bituminous region includes western Colorado, eastern Utah and southern Wyoming. Coal from this region typically has a low sulfur content and varies in heat value. According to the EIA, coal produced in the western United States increased from 408.3 million tons in 1994 to 618.3 million tons in 2007 as regulations limiting sulfur dioxide emissions have increased demand for low-sulfur coal over this period.
 
Appalachian region—The Appalachian region is divided into the north, central and southern Appalachian regions. Central Appalachia includes eastern Kentucky, Virginia and southern West Virginia. Coal mined from this region generally has a high heat value and low sulfur content. Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a high heat value and a high sulfur content. According to the EIA, coal produced in the Appalachian region decreased from 445.4 million


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tons in 1994 to 379.6 million tons in 2007, primarily as a result of the depletion of economically attractive reserves, permitting issues and increasing costs of production.
 
Interior region—The Illinois basin includes Illinois, Indiana and western Kentucky and is the major coal production center in the interior region of the United States. Coal from the Illinois basin varies in heat value and has high sulfur content. Despite its high sulfur content, coal from the Illinois basin can generally be used by some electric power generation facilities that have installed pollution control devices, such as scrubbers, to reduce emissions. We anticipate that Illinois basin coal will play an increasingly vital role in the U.S. energy markets in future periods. Other coal-producing states in the interior region include Arkansas, Kansas, Louisiana, Mississippi, Missouri, North Dakota, Oklahoma and Texas. According to the EIA, coal produced in the interior region decreased from 179.9 million tons in 1994 to 150.2 million tons in 2007.
 
U.S. Coal Exports and Imports.  Coal exports decreased from 71.4 million tons in 1994 to 58.6 million tons in 2007. As discussed above, as global consumption for coal has increased in recent years, countries such as China, Indonesia, South Africa and Russia have decided to retain a greater percentage of their coal production for domestic consumption. This development, together with port congestion in Australia, historically the largest coal exporter in the world, and a weak U.S. dollar, has caused U.S. coal to become more attractive in global markets. We expect this trend to continue as global coal consumption continues to increase.
 
Historically, coal imported from abroad has represented a negligible share of total U.S. coal consumption. According to the EIA, coal imports increased from 8.9 million tons in 1994 to 36.3 million tons in 2007. Coal is imported into the United States primarily from Colombia, Indonesia and Venezuela. Imported coal generally serves coastal states along the Gulf of Mexico, such as Alabama and Florida, and states along the eastern seaboard. We expect coal imports into the United States to decrease due to increasing demand in Europe.
 
Coal Mining Methods
 
The geological characteristics of our coal reserves largely determine the coal mining method we employ. We use two primary methods of mining coal: surface mining and underground mining.
 
Surface Mining.  We use surface mining when coal is found close to the surface. We have included the identity and location of our surface mining operations in the table on page 9. In 2007, approximately 80% of the coal that we produced came from surface mining operations.
 
Surface mining involves removing overburden (earth and rock covering the coal) with heavy earth-moving equipment, such as draglines, power shovels, excavators and loaders. Once exposed, we drill, fracture and systematically remove the coal using haul trucks or conveyors to transport the coal to a preparation plant or to a loadout facility. We reclaim disturbed areas as part of our normal mining activities. After final coal removal, we use draglines, power shovels, excavators or loaders to backfill the remaining pits with the overburden removed at the beginning of the process. Once we have replaced the overburden and topsoil, we reestablish vegetation and make other improvements that have local community and environmental benefits.


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The following diagram illustrates a typical dragline surface mining operation:
 
(Mining Operation Picture)
 
Underground Mining.  We use underground mining methods when coal is located deep beneath the surface. We have included the identity and location of our underground mining operations in the table on page 9. In 2007, approximately 20% of the coal that we produced came from underground mining operations.
 
Our underground mines are typically operated using one or both of two different techniques: longwall mining and room-and-pillar mining.
 
Longwall mining involves using mechanical shearers to extract coal from long rectangular blocks of medium to thick seams. Ultimate seam recovery using longwall mining techniques can exceed 75%. In longwall mining, we use continuous miners to develop access to these long rectangular coal blocks. Hydraulically powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face of the coal seam, cutting the coal from the face. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion. In 2007, approximately 17% of the coal that we produced came from underground mining operations generally using longwall mining techniques.


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The following diagram illustrates a typical underground mining operation using longwall mining techniques:
 
(LONGWALL MINING PICTURE)
 
Room-and-pillar mining is effective for small blocks of thin coal seams. In room-and-pillar mining, we cut a network of rooms into the coal seam, leaving a series of pillars of coal to support the roof of the mine. We use continuous miners to cut the coal and shuttle cars to transport the coal to a conveyor belt for further transportation to the surface. The pillars generated as part of this mining method can constitute up to 40% of the total coal in a seam. Higher seam recovery rates can be achieved if retreat mining is used. In retreat mining, coal is mined from the pillars as workers retreat. As retreat mining occurs, the roof is allowed to collapse in a controlled fashion. Once we finish mining in an area, we generally abandon that area and seal it from the rest of the mine. In 2007, approximately 3% of the coal that we produced came from underground mining operations generally using room-and-pillar mining techniques.
 
The following diagram illustrates our typical underground mining operation using room-and-pillar mining techniques:
 
(ROOM AND PILLAR MINING PICTURE)


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Coal Preparation.  Coal extracted from the ground, particularly at our underground mining operations, contains impurities, such as rock, shale and clay, and occurs in a wide range of particle sizes. Each of our mining operations in the Central Appalachia region uses a coal preparation plant located near the mine or connected to the mine by a conveyor. These coal preparation plants allow us to treat the coal we extract from those mines to ensure a consistent quality and to enhance its suitability for particular end-users. In 2007, our preparation plants processed approximately 83% of the raw coal we produced in the Central Appalachia region. For more information about our preparation plants, you should see the section entitled “Our Mining Operations” below.
 
The treatments we employ depend on the properties of the extracted coal and its intended use. To remove impurities, we crush raw coal and classify it into various sizes. For the largest size fractions, we use dense media vessel separation techniques in which we float coal in a tank containing a liquid of specific gravity. Since coal is lighter than its impurities, it floats, and we can separate it from rock and shale. We treat intermediate sized particles with dense medium cyclones, in which a liquid is spun at high speeds to separate coal from rock. Fine coal is treated in spirals, in which the differences in density between coal and rock allow them, when suspended in water, to be separated. Ultra fine coal is recovered in column flotation cells utilizing the differences in surface chemistry between coal and rock. By injecting stable air bubbles through a suspension of ultra fine coal and rock, the coal particles adhere to the bubbles and rise to the surface of the column where they are removed. To minimize the moisture content in coal, we may process certain coal through a centrifuge. A centrifuge spins coal very quickly, causing water accompanying the coal to separate.
 
Our Mining Operations
 
At December 31, 2007, we operated 18 active mines at 11 mining complexes located in the United States. We have three reportable business segments, which are based on the low-sulfur coal producing regions in the United States in which we operate — the Powder River Basin, the Western Bituminous region and the Central Appalachia region. These geographically distinct areas are characterized by 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 region and form the basis for the segmentation of our operations.
 
The following map shows the locations of our mining operations:
 
(MAP)


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The following table provides a summary of information regarding our mining complexes at December 31, 2007, the total sales associated with these complexes for the years ended December 31, 2005, 2006 and 2007 and the total reserves associated with these complexes at December 31, 2007. The amount disclosed below for the total cost of property, plant and equipment of each mining complex does not include the costs of the coal reserves that we have assigned to an individual complex:
 
                                                         
                                      Total Cost
       
                                      of Property,
       
                                      Plant and
       
                                      Equipment
       
    Captive
  Contract
  Mining
      Tons Sold(2)     at December 31,
    Assigned
 
Mining Complex
  Mines(1)   Mines(1)   Equipment   Railroad   2005     2006     2007     2007     Reserves  
                    (Million tons)     ($ in millions)     (Million tons)  
 
Powder River Basin:
                                                       
Black Thunder
  S     D, S   UP/BN     87.6       92.5       86.2     $ 598.8       1,314.6  
Coal Creek(3)
  S     D, S   UP/BN           3.1       10.2       143.0       214.4  
Western Bituminous:
                                                       
Arch of Wyoming(4)
        UP                       24.5       19.6  
Dugout Canyon
  U     LW, C   UP     4.9       4.2       4.0       122.0       29.0  
Skyline(3)
  U     LW, C   UP           1.5       2.4       154.2       22.8  
Sufco
  U     LW, C   UP     7.5       7.4       6.7       229.0       51.3  
West Elk
  U     LW, C   UP     5.9       5.0       6.2       253.8       78.8  
Central Appalachia:
                                                       
Coal-Mac
  S   U   L, E   NS/CSX     3.2       3.7       3.9       141.1       30.9  
Cumberland River
  S(2), U(3)   U   L, C, HW   NS     2.3       2.6       2.4       122.6       21.0  
Lone Mountain
  U(3)     C   NS/CSX     2.6       2.5       2.4       167.1       34.7  
Mountain Laurel
  U     LW, C   CSX                 1.0       399.1       83.0  
                                                         
Totals
                    114.0       122.5       125.4     $ 2,355.2       1,900.1  
                                                         
 
 
         
S = Surface mine
  D = Dragline   UP = Union Pacific Railroad
U = Underground mine
  L = Loader/truck   CSX = CSX Transportation
    S = Shovel/truck   BN = Burlington Northern Santa Fe Railway
    E = Excavator/truck   NS = Norfolk Southern Railroad
    LW = Longwall    
    C = Continuous miner    
    HW = Highwall miner    
 
(1) Amounts in parentheses indicate the number of captive and contract mines at the mining complex at December 31, 2007. Captive mines are mines that we own and operate on land owned or leased by us. Contract mines are mines that other operators mine for us under contracts on land owned or leased by us.
 
(2) Tons sold include tons of coal we purchased from third parties and processed through our loadout facilities. Coal purchased from third parties and processed through our loadout facilities approximated 0.2 million tons in 2007, 1.7 million tons in 2006 and 2.2 million tons in 2005. We have not included tons of coal we purchased from third parties that were not processed through our loadout facilities in the amounts shown in the table above. Tons of coal sold that we purchased from third parties but did not process through our loadout facilities approximated 8.4 million tons in 2007, 8.5 million tons in 2006 and 8.8 million tons in 2005.
 
In December 2005, we sold 100% of the stock of Hobet Mining, Inc., Apogee Coal Company and Catenary Coal Company, which include the Hobet 21, Arch of West Virginia, Samples and Campbells Creek mining complexes and associated reserves, to Magnum. In June 2007, we sold the Mingo Logan-Ben Creek mining complex and associated reserves to Alpha Natural Resources. We have not included any information in the table above related to those complexes. Those complexes sold 1.2 million tons in 2007, 4.0 million tons in 2006 and 17.4 million tons in 2005.
 
(3) In 2006, we resumed mining at our Coal Creek and Skyline complexes. We had idled the Coal Creek complex in 2000 and the Skyline complex in 2004.
 
(4) The inactive surface mines at the Arch of Wyoming complex are in the final process of reclamation and bond release.


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Powder River Basin.  Our operations in the Powder River Basin are located in Wyoming and include two surface mining complexes. During 2007, these complexes sold approximately 96.4 million tons of compliance coal. We control approximately 1.8 billion tons of proven and probable coal reserves in the Powder River Basin.
 
Black Thunder Black Thunder is a surface mining complex located on approximately 24,300 acres in Campbell County, Wyoming. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of six active pit areas, one owned loadout facility and one leased loadout facility. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. Each of the loadout facilities can load a 15,000-ton train in less than three hours.
 
Coal Creek Coal Creek is a surface mining complex located on approximately 7,400 acres in Campbell County, Wyoming. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of two active pit areas and a loadout facility. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. The loadout facility can load a 15,000-ton train in less than three hours.
 
Western Bituminous.  Our operations in the Western Bituminous region are located in southern Wyoming, Colorado and Utah and include four underground mining complexes and one surface mining complex that includes four inactive surface mines. During 2007, the mining complexes in the Western Bituminous region sold approximately 19.3 million tons of compliance coal. We control approximately 459.9 million tons of proven and probable coal reserves in the Western Bituminous region.
 
Arch of Wyoming Arch of Wyoming is a surface mining complex located in Carbon County, Wyoming. The complex currently consists of four inactive surface mines located on approximately 29,900 acres that are in the final process of reclamation and bond release. In 2006, we began preliminary development of a new mining area located on approximately 30,100 acres. We control a significant portion of the coal reserves associated with this complex through federal, state and private leases. During 2007, we produced a minimal amount of coal attributable to the development of the new mining area.
 
Dugout Canyon Dugout Canyon mine is an underground mining complex located on approximately 18,200 acres in Carbon County, Utah. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of a longwall, two continuous miner sections and a truck loadout facility. We ship all of the coal to our customers via the Union Pacific railroad or by highway trucks. We wash a portion of the coal we produce at a 400-ton-per-hour preparation plant. The loadout facility can load approximately 20,000 tons of coal per day into highway trucks. Coal shipped by rail is loaded through a third-party facility capable of loading an 11,000-ton train in less than three hours.
 
Skyline Skyline is an underground mining complex located on approximately 12,400 acres in Carbon and Emery Counties, Utah. We control a significant portion of the coal reserves through federal leases and smaller portions through county and private leases. The complex


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currently consists of a longwall, a continuous miner section and a loadout facility. We ship all of the coal raw to our customers via the Union Pacific railroad or by highway trucks. We do not process the coal mined at this complex. The loadout facility can load a 12,000-ton train in less than four hours.
 
Sufco Sufco is an underground mining complex located on approximately 25,200 acres in Sevier County, Utah. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of a longwall, three continuous miner sections and a loadout facility located approximately 80 miles from the mine. We ship all of the coal raw to our customers via the Union Pacific railroad or by highway trucks. We do not process the coal mined at this complex. The loadout facility can load an 11,000-ton train in less than three hours.
 
West Elk West Elk is an underground mining complex located on approximately 17,900 acres in Gunnison County, Colorado. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of a longwall, three continuous miner sections and a loadout facility. We ship all of the coal raw to our customers via the Union Pacific railroad. We do not process the coal mined at this complex. The loadout facility can load an 11,000-ton train in less than three hours.
 
Central Appalachia.  Our operations in the Central Appalachia region are located in southern West Virginia, eastern Kentucky and southwestern Virginia and include four mining complexes comprised of nine underground mines and three surface mines. During 2007, these operations sold approximately 9.7 million tons of low-sulfur coal. Metallurgical coal accounted for 1.7 million tons of total coal sales from these operations in 2007. We control approximately 338.0 million tons of proven and probable coal reserves in Central Appalachia.
 
Coal-Mac Coal-Mac is a surface and underground mining complex located on approximately 46,800 acres in Logan and Mingo Counties, West Virginia. We control a significant portion of the coal reserves through private leases. The complex currently consists of two surface mines (one captive and one contract), one contract underground mine, a preparation plant and two loadout facilities, which we refer to as Holden 22 and Ragland. We ship coal trucked to the Ragland loadout facility directly to our customers via the Norfolk Southern railroad. The Ragland loadout facility can load a 15,000-ton train in less than four hours. We ship coal trucked to the Holden 22 loadout facility directly to our customers via the CSX railroad. We wash a portion of the coal transported to the Holden 22 loadout facility at an adjacent 600-ton-per-hour preparation plant. The Holden 22 loadout facility can load a 12,000-ton train in less than four hours.
 
Cumberland River Cumberland River is an underground and surface mining complex located on approximately 16,700 acres in Wise County, Virginia and Letcher County, Kentucky. We control a significant portion of the coal reserves through private leases. The complex currently consists of four underground mines (three captive, one contract) operating a total of five continuous miner sections, two captive surface operations, two highwall miners (one captive, one contract), a preparation plant and a loadout facility. We ship approximately one-third of the coal raw to our customers via the Norfolk Southern railroad. We


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process the remaining two-thirds of the coal through a 500-ton-per-hour preparation plant before shipping it to our customers via the Norfolk Southern railroad. The loadout facility can load a 12,500-ton train in less than four hours.
 
Lone Mountain Lone Mountain complex is an underground mining complex located on approximately 21,400 acres in Harlan County, Kentucky and Lee County, Virginia. We control a significant portion of the coal reserves through private leases. The complex currently consists of three underground mines operating a total of seven continuous miner sections. We convey coal mined in Kentucky to Virginia before we process it through a 1,200-ton-per-hour preparation plant. We then ship the coal to our customers via the Norfolk Southern or CSX railroad. The loadout facility can load a 12,500-ton unit train in less than four hours.
 
Mountain Laurel Mountain Laurel is an underground mining complex located on approximately 30,000 acres in Logan County, West Virginia. In 2007, we began preliminary development of a new surface mining area adjacent to our underground mine. We control a significant portion of the coal reserves through private leases. The complex currently consists of a longwall, four continuous miner sections, a preparation plant and a loadout facility. We process all of the coal through a 2,100-ton-per-hour preparation plant before shipping the coal to our customers via the CSX railroad. The loadout facility can load a 15,000-ton train in less than four hours.
 
We also incorporate by reference the information about the operating results of each of our segments for the years ended December 31, 2007, 2006 and 2005 contained in Note 22 — Segment Information to our consolidated financial statements beginning on page F-1.
 
Transportation
 
We ship our coal to customers by means of railroad, barges or trucks, or a combination of these means of transportation. We also ship our coal to Atlantic coast terminals or terminals along the Gulf of Mexico for transportation to domestic and international customers. As is customary in the industry, once the coal is loaded onto the rail car, barge, truck or vessel, our customers are typically responsible for the freight costs to the ultimate destination. Transportation costs borne by the customer vary greatly based on each customer’s proximity to the mine and our proximity to the loadout facilities.
 
Our Arch Coal Terminal is located in Catlettsburg, Kentucky on a 111-acre site on the Big Sandy River above its confluence with the Ohio River. The terminal provides coal and other bulk material storage and can load and offload river barges and trucks at the facility. The terminal can provide up to 500,000 tons of storage and can process up to six million tons of coal annually for shipment on the inland waterways.
 
In addition, we own a 17.5% interest in Dominion Terminal Associates, which leases and operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia. The 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 facility serves international customers, as well as domestic coal users located along the Atlantic coast of the United States.
 
Sales, Marketing and Customers
 
Coal prices are influenced by a number of factors and vary dramatically by region. As a result of these regional characteristics, prices of coal by product type within a given major coal producing region tend to be relatively consistent with each other. The price of coal within a region is influenced by market conditions, mine


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operating costs, coal quality, transportation costs involved in moving coal from the mine to the point of use and the costs of alternative fuels. 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. Within a particular geographic region, underground mining, which is the mining method we use in the Western Bituminous region and for certain of our Central Appalachia mines, is generally more expensive than surface mining, which is the mining method we use in the Powder River Basin and for certain of our Central Appalachia mines. This is the case because of the higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs due to lower productivity 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, and higher sulfur and higher ash content generally result in lower prices.
 
Management, including our chief executive officer and chief operating officer, reviews and makes resource allocations based on the goal of maximizing our profits in light of the comparative cost structures of our various operations. Because most of our customers purchase coal on a regional basis, coal can generally be sourced from several different locations within a region. Once we have a contractual commitment to sell coal at a certain price, we assign contract shipments to one or more mining complexes within a region capable of sourcing that coal.
 
Long-Term Coal Supply Arrangements
 
We sell coal both under long-term contracts, the terms of which are more than one year, and on a current market or spot basis with terms of one year or less. In 2007, we sold approximately 73.6% of our coal under long-term supply arrangements. At December 31, 2007, the average volume-weighted remaining term of our long-term contracts was approximately 3.8 years, with remaining terms ranging from one to ten years.
 
We expect to sell a significant portion of our coal under long-term supply arrangements. We selectively renew or enter into new long-term supply arrangements when we can do so at prices that we believe are favorable. When our coal sales contracts expire or are terminated, we are exposed to the risk of having to sell coal into the spot market, where demand is variable and prices are subject to greater volatility.
 
Provisions permitting renegotiation or modification of coal sale prices are present in some of our more recently negotiated long-term contracts and usually occur midway through a contract or every two to three years, depending upon the length of the contract. In some circumstances, either we have or our customer has the option to terminate the contract if the parties cannot agree on a new price.
 
We participate in the “over-the-counter market” for a small portion of our sales.
 
Competition
 
The coal industry is intensely competitive. The most important factors on which we compete are coal quality, transportation costs from the mine to the customer and the reliability of supply. Our principal domestic competitors include Alpha Natural Resources, Inc., CONSOL Energy Inc., Foundation Coal Holdings, Inc., Magnum Coal Company, Massey Energy Company, Patriot Coal Corporation, Peabody Energy Corp. and Rio Tinto Energy — North America. Some of these coal producers are larger than we are and have greater financial resources and larger reserve bases than we do. We also compete directly with a number of smaller producers in each of the geographic regions in which we operate. As the price of domestic coal increases, we also compete with companies that produce coal from one or more foreign countries, such as Colombia, Indonesia and Venezuela.
 
Additionally, coal competes with other fuels, such as nuclear energy, natural gas, hydropower and petroleum, for steam and electrical power generation. Costs and other factors relating to these alternative fuels, such as safety and environmental considerations, affect the overall demand for coal as a fuel.


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Geographic Data
 
We market our coal principally to power plants, steel mills and industrial facilities located in the United States. Coal sales to foreign customers approximated $196.7 million for 2007, $162.5 million for 2006 and $166.0 million for 2005.
 
Safety and Environmental Regulations
 
Our operations, like operations of other coal companies, are subject to regulation, primarily by federal and state authorities, on matters such as: air quality standards; reclamation and restoration activities involving our mining properties; mine permits and other licensing requirements; water pollution; employee health and safety; the discharge of materials into the environment; management of materials generated by mining operations; storage of petroleum products; protection of wetlands and endangered plant and wildlife protection. Many of these regulations require registration, permitting, compliance, monitoring and self-reporting and may impose civil and criminal penalties for non-compliance.
 
Additionally, the electric generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal over time. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, causing coal to become a less attractive fuel source and reducing the percentage of electricity generated from coal. Future legislation or regulation or more stringent enforcement of existing laws may have a significant impact on our mining operations or our customers’ ability to use coal.
 
While it is not possible to accurately 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. Federal and state mining laws and regulations 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. Compliance with these laws has substantially increased the cost of coal mining for domestic coal producers.
 
The following is a summary of the various federal and state environmental and similar regulations that have a material impact on our business:
 
Clean Air Act.  The federal Clean Air Act and similar state and local laws that regulate air emissions affect coal mining directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and/or emissions control requirements relating to particulate matter which may include controlling fugitive dust. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions of fine particulate matter measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fueled power plants and industrial boilers, which are the largest end-users of our coal. Continued tightening of the already stringent regulation of emissions and regulation of additional emissions such as carbon dioxide or other greenhouse gases from coal-fueled power plants and industrial boilers could eventually reduce the demand for coal.
 
Clean Air Act requirements that may directly or indirectly affect our operations include the following:
 
  •  Acid Rain.  Title IV of the Clean Air Act imposes a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fueled power plants with a capacity of more than 25-megawatts. Generally, the affected power plants have sought to comply with these requirements by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emissions allowances. Although we cannot accurately predict the future effect of this Clean Air Act provision on our operations, we believe that implementation of Phase II has resulted in, and will continue to result in, an upward pressure on the price of lower sulfur coals as coal-fueled power plants continue to comply with the more stringent restrictions of Title IV.
 
  •  Fine Particulate Matter.  The Clean Air Act requires the U.S. Environmental Protection Agency, which we refer to as EPA, to set national ambient air quality standards, which we refer to as NAAQS, for


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  certain pollutants associated with the combustion of coal, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. Areas that are not in compliance with these standards, referred to as non-attainment areas, must take steps to reduce emissions levels. For example, NAAQS currently exist for particulate matter measuring 10 micrometers in diameter or smaller (PM10) and for fine particulate matter measuring 2.5 micrometers in diameter or smaller (PM2.5). The EPA designated all or part of 225 counties in 20 states as well as the District of Columbia as non-attainment areas with respect to the PM2.5 NAAQS. Those designations have been challenged. Individual states must identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Under the Clean Air Act, individual states have up to twelve years from the date of designation to secure emissions reductions from sources contributing to the problem. Future regulation and enforcement of the new PM2.5 standard will affect many power plants, especially coal-fueled power plants, and all plants in non-attainment areas.
 
  •  Ozone.  Significant additional emission control expenditures will be required at coal-fueled power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a byproduct of coal combustion, are classified as an ozone precursor. As a result, emissions control requirements for new and expanded coal-fueled power plants and industrial boilers will continue to become more demanding in the years ahead. For example, in 2004, the EPA designated counties in 32 states as non-attainment areas under the new standard. These states had until June 2007 to develop plans, referred to as state implementation plans, or SIPs, for pollution control measures that allow them to comply with the standards. The EPA described the action that states must take to reduce ground-level ozone in a final rule promulgated in November 2005. The rule is subject to judicial challenge, however, making its impact difficult to assess. In July 2007, the EPA proposed to make the current standard more stringent. If the EPA’s current rules are upheld and the EPA finalizes a more stringent ozone NAAQS, additional emission control expenditures will likely be required at coal-fueled power plants.
 
  •  NOx SIP Call.  The NOx SIP Call program was established by the EPA in October 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said that they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrous oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. Phase II reductions were required by May 2007. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures will make it more costly to operate coal-fueled power plants, thereby making coal a less attractive fuel.
 
  •  Clean Air Interstate Rule.  The EPA finalized the Clean Air Interstate Rule, which we refer to as CAIR, in March 2005. CAIR calls for power plants in 29 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrous oxide. The rule requires states to regulate power plants under a cap and trade program similar to the system now in effect for acid deposition control and to that proposed by the Clean Skies Initiative. When fully implemented, the rule is expected to reduce regional sulfur dioxide emissions by over 70% and nitrogen oxides emissions by over 60% from 2003 levels. The stringency of the cap may require some coal-fueled power plants to install additional pollution control equipment, such as wet scrubbers, which could decrease the demand for low-sulfur coal at these plants and thereby potentially reduce market prices for low-sulfur coal. Emissions are permanently capped and cannot increase. The rule is also subject to judicial challenge, which makes its impact difficult to assess.
 
  •  Mercury.  In February 2008, the United States Court of Appeals for the District of Columbia Circuit vacated the EPA’s Clean Air Mercury Rule, which we refer to as CAMR, and remanded it to the EPA for reconsideration. The EPA is reviewing the court decision and evaluating its impacts. Before the court decision, some states had either adopted CAMR or adopted state-specific rules to regulate mercury emissions from power plants that are more stringent than CAMR. CAMR, as promulgated, would have permanently capped and reduced mercury emissions from coal-fueled power plants by establishing mercury emissions limits from new and existing coal-fueled power plants and creating a market-based cap-and-trade program that was expected to reduce nationwide emissions of mercury in two phases.


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  Under CAMR, coal-fueled power plants would have had until 2010 to cut mercury emission levels to 38 tons a year from 48 tons and until 2018 to bring that level down to 15 tons, a 69% reduction. Regardless of how the EPA responds on reconsideration or how states implement their state-specific mercury rules, rules imposing stricter limitations on mercury emissions from power plants will likely be promulgated and implemented. Any such rules may adversely affect the demand for coal.
 
  •  Carbon Dioxide.  In February 2003, a number of states notified the EPA that they planned to sue the agency to force it to set new source performance standards for electric utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In April 2007, the U.S. Supreme Court rendered its decision in Massachusetts v. EPA, finding that the EPA has authority under the Clean Air Act to regulate carbon dioxide emissions from automobiles and can decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endanger public health or the environment. The EPA’s final regulations in response to the decision are not expected until December 2008. In other actions, following the Massachusetts v. EPA decision, the U.S. Court of Appeals for the District of Columbia Circuit remanded to the EPA new source performance standards for utility and industrial boilers promulgated in 2006 for further proceedings in light of the Massachusetts v. EPA decision. In June 2006, the U.S. Court of Appeals for the Second Circuit heard oral argument in a public nuisance action filed by eight states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) and New York City to curb carbon dioxide emissions from power plants. The parties have filed post-argument briefs on the impact of the Massachusetts v. EPA decision, and a decision is currently pending. If as a result of these actions the EPA were to set emission limits for carbon dioxide from electric utilities, the amount of coal our customers purchase from us could decrease.
 
  •  Regional Haze.  The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks, particularly those located in the southwest and southeast United States. This program may result in additional emissions restrictions from new coal-fueled power plants whose operation may impair visibility at and around federally protected areas. This program may also require certain existing coal-fueled power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.
 
Surface Mining Control and Reclamation Act.  The Surface Mining Control and Reclamation Act, which we refer to as SMCRA, establishes mining, environmental protection, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, which we refer to as OSM, or from the applicable state agency if the state agency has obtained primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory program that is no less stringent than the federal mining regulatory program under SMCRA.
 
SMCRA permit provisions include a complex set of requirements which include, among other things, coal prospecting; mine plan development; topsoil or growth medium removal and replacement; selective handling of overburden materials; mine pit backfilling and grading; disposal of excess spoil; protection of the hydrologic balance; subsidence control for underground mines; surface runoff and drainage control; establishment of suitable post mining land uses; and revegetation.
 
The mining permit application preparation process is initiated by collecting baseline data to adequately characterize the pre-mining environmental conditions of the permit area. This work is typically conducted by third-party consultants with specialized expertise and includes surveys and/or assessments of the following: cultural and historical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential for threatened, endangered or other special status species; surface and ground water hydrology; climatology; riverine and riparian habitat; and wetlands. The geologic data is used to define and characterize the rock structures that will be encountered during the mining process. The geologic data and information derived from the other surveys and/or assessments are used to develop the mining and reclamation plans presented in the permit application.


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The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with Office of Surface Mining’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.
 
Once a permit application is prepared and submitted to the regulatory agency, it goes through an administrative completeness review and a thorough technical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, a public notice or advertisement of the proposed permit is required to be given, which begins a notice period that is followed by a public comment period before a permit can be issued. It is not uncommon for a SMCRA mine permit application to take over a year to prepare, depending on the size and complexity of the mine, and anywhere from six months to two years or even longer for the permit to be issued. The variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of litigation related to the specific permit or another related company’s permit.
 
In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, requires a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines and $0.135 per ton of coal produced from underground mines. In 2007, we recorded $38.0 million of expense related to these reclamation fees.
 
Mining Permits and Approvals.  Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to prepare and present data to federal, state or local authorities data pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization, permitting and implementation 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 or modification can be delayed, refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
 
In order to obtain mining permits and approvals from state regulatory authorities, mine operators 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 or even years before we plan to begin mining a new area. Some of our required permits are becoming increasingly more difficult and expensive to obtain, and the application review processes are taking longer to complete and becoming increasingly subject to challenge.
 
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.  Mine operators are often required by federal and/or state laws to assure, usually through the use of surety bonds, payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. Although surety bonds are usually noncancelable during their term, many of these bonds are renewable on an annual basis. The costs of these bonds have fluctuated in recent years while the market terms of surety bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at


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times by a decrease in the number of companies willing to issue surety bonds. In order to address some of these uncertainties, we use self-bonding to secure performance of certain obligations in Wyoming. As of December 31, 2007, we have self-bonded an aggregate of $306.4 million and have posted an aggregate of $263.0 million in surety bonds and $0.5 million in cash bonds for reclamation purposes. In addition, we had approximately $134.0 million of surety bonds and letters of credit outstanding at December 31, 2007 to secure workers’ compensation, coal lease and other obligations.
 
Clean Water Act.  The Clean Water Act of 1972 and comparable state laws that regulate waters of the United States can affect our mining operations directly and indirectly. One of the direct impacts on coal mining and processing operations is the Clean Water Act permitting requirements relating to the discharge of pollutants into waters of the United States. Indirect impacts of the Clean Water Act include discharge limits placed on coal-fueled power plant ash handling facilities’ discharges. Continued litigation of Clean Water Act issues could eventually reduce the demand for coal.
 
Clean Water Act requirements that may directly or indirectly affect our operations include the following:
 
  •  Wastewater Discharge.  Section 402 of the Clean Water Act creates a process for establishing effluent limitations for discharges to streams that are protective of water quality standards through the National Pollutant Discharge Elimination System, which we refer to as the NPDES, or an equally stringent program delegated to a state regulatory agency. Regular monitoring, reporting and compliance with performance standards are preconditions for the issuance and renewal of NPDES permits that govern the discharge into waters of the United States. The imposition of future restrictions on the discharge of certain pollutants into waters of the United States could affect the permitting process, increase the costs and difficulty of obtaining and complying with NPDES permits and could adversely affect our coal production.
 
Under the Clean Water Act, states must conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state’s anti-degradation regulations would prohibit the diminution of water quality in these streams. In general, waters discharged from coal mines to high quality streams may be required to meet new “high quality” standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits, and could adversely affect our coal production.
 
  •  Dredge and Fill Permits Act.  Many mining activities, such as the development of refuse impoundments, fresh water impoundments, refuse fills, valley fills, and other similar structures, may result in impacts to waters of the United States, including wetlands, streams and, in certain instances, man-made conveyances that have a hydrologic connection to such streams or wetlands. Prior to conducting such mining activities, coal companies are required to obtain a Section 404 permit, referred to as a dredge or fill permit, from the Army Corps of Engineers, which we refer to as the Corps. The Corps is authorized to issue two types of Section 404 permits: a general permit, referred to as a nationwide permit, for surface mining activities and an individual permit. The Corps may issue nationwide permits for any category of activities involving the discharge of dredge or fill material if the Corps determines that such activities are similar in nature and will cause only minimal adverse environmental effects individually or cumulatively. Generally, the Corps has used nationwide permits to authorize impacts to waters of the United States from mining activities because the process is a more streamlined permitting approach and consumes less Corps resources.
 
The use of the nationwide permit to authorize stream impacts from mining activities was successfully challenged in October 2003 in federal court in southern West Virginia, but was later overturned at the court of appeals. During the appeal period only, the Corps was enjoined (only in the southern district of West Virginia) from using the nationwide permit to authorize dredge and fill activities for mining impacts. As a precaution to mitigate the uncertainty surrounding the use of the nationwide permit in these areas, we converted certain ongoing permits, pending applications, and planned applications from nationwide permits to individual permits. This precautionary step was taken to minimize the potential for future production interruptions.


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You should see Item 3 — Legal Proceedings beginning on page 33 for more information about certain litigation pertaining to our permits.
 
Mine Health and Safety Laws.  Stringent safety and health standards have been imposed by federal legislation since Congress adopted the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed comprehensive safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, all of the states in which we operate also have programs for mine safety and health regulation and enforcement. In reaction to several mine accidents in recent years, federal and state legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. For example, in 2006, Congress enacted the Mine Improvement and New Emergency Response Act of 2006, which we refer to as the MINER Act. The MINER Act imposes additional obligations on coal operators including, among other things, the following:
 
  •  development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel;
 
  •  establishment of additional requirements for mine rescue teams;
 
  •  notification of federal authorities in the event of certain events;
 
  •  increased penalties for violations of the applicable federal laws and regulations; and
 
  •  requirement that standards be implemented regarding the manner in which closed areas of underground mines are sealed.
 
Various states, including West Virginia, have also enacted new laws to address many of the same subjects. The full financial impact of the new regulations is not yet known. However, the cost of implementation of the new safety and health regulations at the federal and state level may be substantial. In addition to the cost of implementation, there are increased penalties for violations which may also be substantial. Expanded enforcement could result in a proliferation of litigation regarding citations and orders issued as a result of the regulations.
 
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for coal mined in underground operations and up to $0.55 per ton for coal mined in surface operations. These amounts may not exceed 4.4% of the gross sales price. This excise tax does not apply to coal shipped outside the United States. In 2007, we recorded $65.0 million of expense related to this excise tax.
 
Comprehensive Environmental Response, Compensation and Liability Act.  The Comprehensive Environmental Response, Compensation and Liability Act, which we refer to as 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 trigger 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 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.
 
Resource Conservation and Recovery Act.  The Resource Conservation and Recovery Act, which we refer to as RCRA, may affect coal mining operations by establishing requirements for the proper management, handling, transportation and disposal of hazardous wastes. Currently, certain coal mine wastes, such as overburden and coal


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cleaning wastes, are exempted from hazardous waste management. Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion products generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion products do not warrant regulation as hazardous waste under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion products disposed in surface impoundments and landfills and used as mine-fill. The Office of Surface Mining and EPA have recently proposed regulations regarding the management of coal combustion products. The EPA also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. Most state hazardous waste laws also exempt coal combustion products, and instead treat it as either a solid waste or a special waste. Any costs associated with handling or disposal of hazardous wastes would increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of ash can lead to material liability.
 
Climate Change.  One by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change, which establishes a binding set of emission targets for greenhouse gases. With Russia’s accedence, the Kyoto Protocol became binding on all those countries that had ratified it in February 2005. To date, the United States has refused to ratify the Kyoto Protocol. Although the targets vary from country to country, if the United States were to ratify the Kyoto Protocol our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels from 2008 to 2012. Canada, which accounted for approximately 3.4% of our sales volume in 2007, ratified the Kyoto Protocol in 2002. Under the Kyoto Protocol, Canada will be required to cut greenhouse gas emissions to 6% below 1990 levels in 2008 to 2012, either in direct reductions in emissions or by obtaining credits through market mechanisms. This requirement could result in reduced demand for our coal by Canadian power plants.
 
Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, federal or state adoption of a greenhouse gas regulatory scheme, or otherwise. In 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. In December 2005, seven northeastern states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) signed the Regional Greenhouse Gas Initiative agreement, which we refer to as RGGI, calling for a 10% reduction of carbon dioxide emissions by 2019, with compliance to begin January 1, 2009. Maryland signed onto RGGI in July 2006. The RGGI final model rule was issued in August 2006, and the participating states are developing their state rules.
 
Climate change developments are also taking place in western states. In September 2006, California adopted greenhouse gas legislation that prohibits long-term baseload generators from having a greenhouse gas emissions rate greater than that of combined cycle natural gas generator and that allows for long-term deals with generators that sequester carbon emissions. In January 2007, the California Public Utility Commission adopted interim greenhouse gas standards requiring all new long-term power contracts to serve baseload capacity in California to have emissions no higher than a combined-cycle gas turbine plant. In February 2007, the governors of Arizona, California, New Mexico, Oregon and Washington launched the Western Climate Initiative in an effort to develop a regional strategy for addressing climate change. The goal of the Western Climate Initiative is to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region. In the spring of 2007, the governor of Utah and the premiers of British Columbia and Manitoba joined the initiative, and other states and provinces participate as observers.


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In January 2007, eight midwestern states (Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, Ohio and Wisconsin) agreed to support a voluntary registry for greenhouse gases. In November 2007, the governors of Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Ohio, South Dakota and Wisconsin and the premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. These and other state climate change rules will likely require additional controls on coal-fueled power plants and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon fuel. There can be no assurance at this time that a carbon dioxide cap and trade program, a carbon tax or other regulatory regime, if implemented by the states in which our customers operate, will not affect the future market for coal in those regions. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal.
 
Endangered Species.  The Endangered Species Act and other related federal and state statutes protect species threatened or endangered with possible extinction. Protection of threatened, endangered and other special status species may have the 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 or other related laws or regulations. 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. We have been able to continue our operations within the existing spatial, temporal and other restrictions associated with special status species. Should more stringent protective measures be applied to threatened, endangered or other special status species or to their critical habitat, then we could experience increased operating costs or difficulty in obtaining future mining permits. The federal government is currently considering whether to add polar bears to the list of endangered species. If the polar bear is listed as an endangered species, then that action could result in regulation of carbon dioxide emissions to address global warming. Limits on emissions of carbon dioxide could result in coal becoming a less attractive fuel source and could reduce the amount of coal our customers purchase from us.
 
Other Environmental Laws.  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 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.
 
Employees
 
At February 25, 2008, we employed a total of approximately 4,030 persons, approximately 220 of whom are represented by the Scotia Employees Association. We believe that our relations with all employees are good.


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Executive Officers
 
The following is a list of our executive officers, their ages as of February 25, 2008 and their positions and offices during the last five years:
 
             
Name
  Age    
Position
 
C. Henry Besten, Jr.
    59     Mr. Besten has served as our Senior Vice President-Strategic Development since 2002.
John W. Eaves
    50     Mr. Eaves has served as our President and Chief Operating Officer since April 2006. Mr. Eaves has also been a director since February 2006. From 2002 to April 2006, Mr. Eaves served as our Executive Vice President and Chief Operating Officer. Mr. Eaves also serves on the board of directors of ADA-ES, Inc.
Sheila B. Feldman
    53     Ms. Feldman has served as our Vice President-Human Resources since February 2003. From 1997 to February 2003, Ms. Feldman was the Vice President-Human Resources and Public Affairs of Solutia Inc. On December 17, 2003, Solutia Inc. and its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York.
Robert G. Jones
    51     Mr. Jones has served as our Vice President-Law, General Counsel and Secretary since 2000.
Paul A. Lang
    47     Mr. Lang has served as our Senior Vice President-Operations since December 2006. Mr. Lang served as President of Western Operations from July 2005 through December 2006 and President and General Manager of Thunder Basin Coal Company, L.L.C. from November 1998 through July 2005.
Steven F. Leer
    55     Mr. Leer has served as our Chairman and Chief Executive Officer since April 2006. Mr. Leer served as our President and Chief Executive Officer from 1992 to April 2006. Mr. Leer also serves on the board of directors of the Norfolk Southern Corporation, USG Corp., the Western Business Roundtable and the University of the Pacific and is chairman of the Coal Industry Advisory Board. Mr. Leer is a past chairman and continues to serve on the board of directors of the Center for Energy and Economic Development, the National Coal Council and the National Mining Association.
Robert J. Messey
    62     Mr. Messey has served as our Senior Vice President and Chief Financial Officer since 2000. Mr. Messey also serves on the board of directors of Baldor Electric Company and Stereotaxis, Inc.
David B. Peugh
    53     Mr. Peugh has served as our Vice President-Business Development since 1995
Deck S. Slone
    44     Mr. Slone has served as our Vice President-Investor Relations and Public Affairs since 2001.
David N. Warnecke
    52     Mr. Warnecke has served as our Vice President-Marketing and Trading since August 2005. From June 2005 until March 2007, Mr. Warnecke served as President of our Arch Coal Sales Company, Inc. subsidiary, and from April 2004 until June 2005, Mr. Warnecke served as Executive Vice President of Arch Coal Sales Company, Inc. Prior to June 2004, Mr. Warnecke was Senior Vice President-Sales, Trading and Transportation of Arch Coal Sales Company, Inc.
 
We submitted our most recent chief executive officer certification to the New York Stock Exchange on May 23, 2007.


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Available Information
 
We file annual, quarterly and current reports, and amendments to those reports, proxy statements and other information with the Securities and Exchange Commission. You may access and read our filings without charge through the SEC’s website, at sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
 
We also make the documents listed above available through our website, archcoal.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (314) 994-2700 or by mail at Arch Coal, Inc., One CityPlace Drive, Suite 300, St. Louis, Missouri, Attention: Vice President-Investor Relations and Public Affairs. The information on our website is not part of this Annual Report on Form 10-K.
 
ITEM 1A.   RISK FACTORS.
 
Our business involves certain risks and uncertainties. In addition to the risks and uncertainties described below, we may face other risks and uncertainties, some of which may be unknown to us and some of which we may deem immaterial. If one or more of these risks or uncertainties occur, our business, financial condition or results of operations may be materially and adversely affected.
 
Risks Related to Our Business
 
   A substantial or extended decline in coal prices could negatively affect our profitability and the value of our coal reserves.
 
Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. In turn, the prices we receive for our coal depend upon factors beyond our control, including the following:
 
  •  the supply of and demand for domestic and foreign coal;
 
  •  the demand for electricity and steel;
 
  •  domestic and foreign governmental regulations and taxes, including those establishing air emission standards for coal-fueled power plants;
 
  •  regulatory, administrative and judicial decisions, including those affecting future mining permits;
 
  •  the proximity, capacity and cost of transportation facilities;
 
  •  the availability and price of alternative fuels, such as natural gas, and alternative energy sources, such as hydroelectric, wind and solar power;
 
  •  technological developments, including those intended to convert coal to liquid or gas and those aimed at capturing and sequestering carbon; and
 
  •  the effects of worldwide energy conservation measures.
 
Declines in the prices we receive for our coal could adversely affect our profitability and the value of our coal reserves.
 
   Certain conditions and events beyond our control could negatively impact our coal mining operations, our production or our operating costs.
 
We mine coal at underground and surface mining operations. Certain factors beyond our control, including those listed below, could disrupt our coal mining operations, reduce our production or increase our operating costs:
 
  •  delays and difficulties in acquiring, maintaining or renewing necessary permits or mining or surface rights;


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  •  changes or variations in geological conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
 
  •  mining and processing equipment failures and unexpected maintenance problems;
 
  •  interruptions due to transportation delays;
 
  •  adverse weather and natural disasters, such as heavy rains or snow and flooding;
 
  •  shortage of qualified labor;
 
  •  unexpected or accidental surface subsidence from underground mining;
 
  •  accidental mine water discharges, fires, explosions or similar mining accidents; and
 
  •  regulatory issues involving the plugging of and mining through oil and gas wells that penetrate the coal seams we mine.
 
If any of these conditions or events occurs, particularly at our Black Thunder mining complex, our coal mining operations may be disrupted, we could experience a delay or halt of production or our operating costs could increase significantly. In addition, if our insurance coverage is limited or excludes certain of these conditions or events, then we may not be able to recover any of the losses we may incur as a result of such conditions or events, some of which may be substantial.
 
   Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel and rubber tires, or the inability to obtain a sufficient quantity of those supplies, could negatively affect our operating costs or disrupt or delay our production.
 
Our coal mining operations use significant amounts of steel, diesel fuel, rubber tires and other mining and industrial supplies. The costs of roof bolts we use in our underground mining operations depend on the price of scrap steel. We also use significant amounts of diesel fuel and tires for the trucks and other heavy machinery we use, particularly at our Black Thunder mining complex. A worldwide increase in mining, construction and military activities has caused a shortage of the large rubber tires we use in our mining operations. While we have taken initiatives aimed at extending the useful lives of our rubber tires, including increased driver training, improved road maintenance and reduced driving speeds, we may be unable to obtain a sufficient quantity of rubber tires in the future or at prices which are favorable to us. If the prices of mining and other industrial supplies, particularly steel-based supplies, diesel fuel and rubber tires, increase, our operating costs could be negatively affected. In addition, if we are unable to procure these supplies, our coal mining operations may be disrupted or we could experience a delay or halt in our production.
 
   Our labor costs could increase if the shortage of skilled coal mining workers continues.
 
Efficient coal mining using modern techniques and equipment requires skilled workers with experience and proficiency in multiple mining tasks. The resurgence in coal mining activity in recent years has caused a significant tightening of the labor supply. In addition, employee turnover rates in the coal industry have increased during this period as coal producers compete for skilled personnel. Because of the shortage of trained coal miners in recent years, we have operated certain facilities without full staff and have hired novice miners, who are required to be accompanied by experienced workers as a safety precaution. These measures have negatively affected our productivity and our operating costs. If the shortage of experienced labor continues or worsens, our production may be negatively affected or our operating costs could increase.
 
   Disruptions in the quantities of coal produced by our contract mine operators or purchased from other third parties could temporarily impair our ability to fill customer orders or increase our operating costs.
 
We use independent contractors to mine coal at certain of our mining complexes, including select operations at our Coal-Mac and Cumberland River mining complexes. In addition, we purchase coal from third parties that we sell to our customers. Operational difficulties at contractor-operated mines or mines operated by third parties from whom we purchase coal, changes in demand for contract miners from other coal producers


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and other factors beyond our control could affect the availability, pricing, and quality of coal produced for or purchased by us. Disruptions in the quantities of coal produced for or purchased by us could impair our ability to fill our customer orders or require us to purchase coal from other sources in order to satisfy those orders. If we are unable to fill a customer order or if we are required to purchase coal from other sources in order to satisfy a customer order, we could lose existing customers and our operating costs could increase.
 
   Our inability to acquire additional coal reserves or our inability to develop coal reserves in an economically feasible manner may adversely affect our business.
 
As we mine, we deplete our coal reserves. As a result, our ability to produce coal in the future depends, in part, on our ability to acquire additional coal reserves. We may not be able to obtain replacement reserves when we require them. If available, replacement reserves may not be available at favorable prices, or we may not be capable of mining those reserves at costs that are comparable with our existing coal reserves. Our ability to obtain coal reserves in the future could also be limited by restrictions under our existing or future debt agreements and competition from other coal producers. If we are unable to acquire coal reserves to replace the coal reserves we mine, our future production may decrease significantly and our operating results may be negatively affected.
 
In addition to the availability of additional coal reserves, our future performance depends on the accuracy with which we estimate the quantity and quality of the coal included within those reserves. We base our estimates of reserve information on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. The quantity and quality of the coal we are ultimately able to recover within our coal reserves may differ materially from our estimates. Inaccuracies in our estimates could result in revenue that is lower than we expect or operating costs that are higher than we expect.
 
   A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.
 
We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
 
   The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.
 
We depend upon barge, ship, rail, truck and belt transportation systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to supply coal to our customers. As we do not have long-term contracts with transportation providers to ensure consistent and reliable service, decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. If we experience disruptions in our transportation services or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.


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   We may be unable to realize the benefits we expect to occur as a result of acquisitions that we undertake.
 
We continually seek to expand our operations and coal reserves through acquisitions of other businesses and assets, including leasehold interests. Certain risks, including those listed below, could cause us not to realize the benefits we expect to occur as a result of those acquisitions:
 
  •  uncertainties in assessing the value, risks, profitability and liabilities (including environmental liabilities) associated with certain businesses or assets;
 
  •  the potential loss of key customers, management and employees of an acquired business;
 
  •  the possibility that operating and financial synergies expected to result from an acquisition do not develop;
 
  •  problems arising from the integration of an acquired business; and
 
  •  unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the rationale for a particular acquisition.
 
   Our profitability depends upon the long-term coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing long-term coal supply agreements or to enter into new agreements in the future.
 
We sell a portion of our coal under long-term coal supply agreements, which we define as contracts with terms greater than one year. Under these arrangements, we fix the prices of coal shipped during the initial year and may adjust the prices in later years. As a result, at any given time the market prices for similar-quality coal may exceed the prices for coal shipped under these arrangements. Changes in the coal industry may cause some of our customers not to renew, extend or enter into new long-term coal supply agreements with us or to enter into agreements to purchase fewer tons of coal than in the past or on different terms or prices. In addition, uncertainty caused by federal and state regulations, including the Clean Air Act, could deter our customers from entering into long-term coal supply agreements.
 
Because we sell a portion of our coal production under long-term coal supply agreements, our ability to capitalize on more favorable market prices may be limited. Conversely, at any given time we are subject to fluctuations in market prices for the quantities of coal that we have produced but which we have not committed to sell. As described above under “A substantial or extended decline in coal prices could negatively affect our profitability and the value of our coal reserves,” the market prices for coal may be volatile and may depend upon factors beyond our control. Our profitability may be adversely affected if we are unable to sell uncommitted production at favorable prices or at all. For more information about our long-term coal supply agreements, you should see “Long-Term Coal Supply Arrangements” beginning on page 13.
 
   The loss of, or significant reduction in, purchases by our largest customers could adversely affect our profitability.
 
For the year ended December 31, 2007, we derived approximately 25.3% of our total coal revenues from sales to our three largest customers, Tennessee Valley Authority, Ameren Corporation and Intermountain Power Agency, and approximately 49.5% of our total coal revenues from sales to our ten largest customers. At December 31, 2007, we had coal supply agreements with those ten customers that expire at various times from 2008 to 2017. We expect to renew, extend or enter into new long-term coal supply agreements with those and other customers. However, we may be unsuccessful in obtaining long-term coal supply agreements with those customers, and those customers may discontinue purchasing coal from us. If any of those customers, particularly any of our three largest customers, was to significantly reduce the quantities of coal it purchases from us, or if we are unable to sell coal to those customers on terms as favorable to us as the terms under our current long-term coal supply agreements, our profitability could suffer significantly. We have limited protection during adverse economic conditions and may face economic penalties if we are unable to satisfy certain quality specifications under our long-term coal supply agreements.


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Our long-term coal supply agreements typically contain force majeure provisions allowing the parties to temporarily suspend performance during specified events beyond their control. Most of our long-term coal supply agreements also contain provisions requiring us to deliver coal that satisfies certain quality specifications, such as heat value, sulfur content, ash content, hardness and ash fusion temperature. These provisions in our long-term coal supply agreements could result in negative economic consequences to us, including price adjustments, purchasing replacement coal in a higher-priced open market, the rejection of deliveries or, in the extreme, contract termination. Our profitability may be negatively affected if we are unable to seek protection during adverse economic conditions or if we incur financial or other economic penalties as a result of these provisions of our long-term supply agreements.
 
   The amount of indebtedness we have incurred could significantly affect our business.
 
At December 31, 2007, we had consolidated indebtedness of approximately $1.3 billion. We also have significant lease and royalty obligations. Our ability to satisfy our debt, lease and royalty obligations, and our ability to refinance our indebtedness, will depend upon our future operating performance. Our ability to satisfy our financial obligations may be adversely affected if we incur additional indebtedness in the future. In addition, the amount of indebtedness we have incurred could significantly affect:
 
  •  our ability to satisfy debt covenants and debt service, lease payment and other obligations;
 
  •  our ability to generate cash flow from operations or to obtain additional financing;
 
  •  our credit ratings;
 
  •  our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; and
 
  •  our competitiveness when compared to competitors with less debt.
 
   We may be unable to comply with restrictions imposed by our credit facilities and other financing arrangements.
 
The agreements governing our outstanding debt and our accounts receivable securitization program impose a number of restrictions on us. For example, the terms of our credit facilities, leases and other financing arrangements contain financial and other covenants that create limitations on our ability to borrow the full amount under our credit facilities, effect acquisitions or dispositions and incur additional debt and require us to 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 and the counterparties to our other financing arrangements 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 financing arrangements which could make the terms of these arrangements more onerous for us. For more information about some of the restrictions contained in our credit facilities, leases and other financial arrangements, you should see “Liquidity and Capital Resources” beginning on page 46.
 
   Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.
 
Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. We generally reprice these bonds annually, however, they are not cancellable by the surety. Surety bond issuers and holders may increase premiums on the bonds or impose other less favorable terms upon those renewals. The ability of surety bond issuers and holders to demand additional collateral or other less favorable terms has increased as the number of companies willing to issue these bonds has decreased over time. Our failure to maintain, or our inability to acquire, surety bonds required by federal and state law


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could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.
 
   Our profitability may be adversely affected if we must satisfy certain below-market contracts with coal we purchase on the open market or with coal we produce at our remaining operations.
 
We have agreed to guarantee Magnum’s obligations to supply coal under certain coal sales contracts that we sold to Magnum. In addition, we have agreed to purchase coal from Magnum in order to satisfy our obligations under certain other contracts that have not yet been transferred to Magnum, the longest of which extends to the year 2017. If Magnum cannot supply the coal required under these coal sales contracts, we would be required to purchase coal on the open market or supply coal from our existing operations in order to satisfy our obligations under these contracts. At December 31, 2007, if we had purchased the 20.4 million tons of coal required under these contracts over their duration at market prices then in effect, we would have incurred a loss of approximately $363.1 million.
 
   Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may adversely affect our business.
 
Terrorist attacks and threats, escalation of military activity or acts of war have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. As a result, we could experience delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal or extended collections from our customers.
 
Risks Related to Environmental and Other Regulations
 
   Governmental regulations impose significant costs on us and our customers, and future regulations could increase those costs or limit our ability to produce and sell coal.
 
Governmental regulations, including those related to the matters listed below, have significant effects on the coal mining industry:
 
  •  employee health and safety;
 
  •  mine permitting and licensing requirements;
 
  •  reclamation and restoration of mining properties after mining is completed;
 
  •  air quality standards;
 
  •  water pollution;
 
  •  the discharge of materials into the environment;
 
  •  management of materials generated by mining operations;
 
  •  surface subsidence from underground mining;
 
  •  statutorily mandated benefits for current and retired coal miners;
 
  •  protection of wetlands;
 
  •  endangered plant and wildlife protection;
 
  •  limitations on land use;
 
  •  storage and disposal of petroleum products and substances that are regarded as hazardous under applicable laws; and
 
  •  management of electrical equipment containing PCBs.


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The costs, liabilities and requirements associated with these regulations may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our mining operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. Our profitability may be negatively affected if we incur significant costs and liabilities as a result of these regulations.
 
The possibility exists that new legislation and/or regulations and orders may be adopted that may adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax our business or our customers, may also require us or our customers to change operations significantly or incur increased costs. These regulations, if enacted in the future, could have a material adverse effect on our business, financial condition and results of operations.
 
You should see “Safety and Environmental Regulations” beginning on page 14 for more information about the various governmental regulations affecting us.
 
   Our failure to obtain and renew permits necessary for our mining operations could negatively affect our business.
 
Mining companies must obtain numerous permits that regulate environmental and health and safety matters in connection with coal mining, including permits issued by various federal and state agencies and regulatory bodies. We believe that we have obtained the necessary permits to mine our developed reserves at our mining complexes. However, as we commence mining our undeveloped reserves, we will need to apply for and obtain the required permits. The permitting rules are complex and change frequently, making our ability to comply with the applicable requirements more difficult or even impossible. In addition, private individuals and the public at large have certain 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. The permits may also 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. An inability to conduct our mining operations pursuant to applicable permits would reduce our production, cash flow and profitability.
 
   The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization. As a result, coal users may switch to other fuels, which could affect the volume of our sales and the price of our products.
 
Coal contains impurities, including but not limited to sulfur, mercury, chlorine, carbon and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fueled power plants could increase the costs of using coal thereby reducing demand for coal as a fuel source and the volume and price of our coal sales. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of power plants in the future.
 
Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of costly emission control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from power plants, coal users may need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low-sulfur coal or switch to other fuels. Reductions in mercury emissions required by certain states will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. Recent and new proposals calling for reductions in emissions of carbon dioxide and other greenhouse gases could significantly increase the cost of operating existing coal-fueled power


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plants and could inhibit construction of new coal-fueled power plants. Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our operations and financial results could be adversely impacted.
 
   If the assumptions underlying our estimates of reclamation and mine closure obligations are inaccurate, our costs could be greater than anticipated.
 
SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which we refer to as Statement No. 143, requires us to record these obligations as liabilities at fair value. In estimating fair value, we considered the estimated current costs of reclamation and mine closure and applied inflation rates and a third-party profit, as required by Statement No. 143. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. If actual costs differ from our estimates, our profitability could be negatively affected.
 
   Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
 
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.
 
We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
 
Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.
 
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
 
   Judicial rulings that restrict how we may dispose of mining wastes could significantly increase our operating costs, discourage customers from purchasing our coal and materially harm our financial condition and operating results.
 
To dispose of mining overburden generated by our surface mining operations, we often need to obtain permits to construct and operate valley fills and surface impoundments. Some of these permits are Clean Water Act § 404 permits issued by the Army Corps of Engineers. Two of our operating subsidiaries were identified in an existing lawsuit, which challenged the issuance of such permits and asked that the Corps be ordered to


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rescind them. Our operating subsidiaries are seeking to intervene in the suit to protect their interests in being allowed to operate under the issued permits and have asked that the claims against them be dismissed. We cannot predict the final outcome of this lawsuit. If mining methods at issue are limited or prohibited, it could significantly increase our operational costs, make it more difficult to economically recover a significant portion of our reserves and lead to a material adverse effect on our financial condition and results of operation. We may not be able to increase the price we charge for coal to cover higher production costs without reducing customer demand for our coal. You should see Item 3 — Legal Proceedings beginning on page 33 for more information about the litigation described above.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS.
 
None.
 
ITEM 2.   PROPERTIES.
 
At December 31, 2007, we owned or controlled primarily through long-term leases approximately 99,700 acres of coal land in West Virginia, 100,300 acres of coal land in Wyoming, 98,700 acres of coal land in Illinois, 61,100 acres of coal land in Utah, 47,300 acres of coal land in Kentucky, 21,800 acres of coal land in New Mexico and 18,500 acres of coal land in Colorado. In addition, we also owned or controlled through long-term leases smaller parcels of property in Alabama, Indiana, Montana and Texas. We lease approximately 114,200 acres of our coal land from the federal government and approximately 28,000 acres of our coal land from various state governments. These governmental leases are subject to readjustment and/or extension and to earlier termination for failure to meet diligent development requirements. Certain of our preparation plants or loadout facilities are located on properties held under leases which expire at varying dates over the next 30 years. Most of the leases contain options to renew. Our remaining preparation plants and loadout facilities are located on property owned by us or for which we have a special use permit.
 
Our executive headquarters occupy approximately 92,900 square feet of leased space at One CityPlace Drive, in St. Louis, Missouri. Our subsidiaries currently own or lease the equipment utilized in their mining operations. You should see “Business” beginning on page 1 for more information about our mining operations, mining complexes and transportation facilities.
 
Our Reserves
 
We estimate that we owned or controlled approximately 2.9 billion tons of proven and probable recoverable reserves at December 31, 2007. Recoverable reserves include only saleable coal and do not include coal which would remain unextracted, such as for support pillars, and processing losses, such as washery losses. Reserve estimates are prepared by our engineers and geologists and reviewed and updated periodically. Total recoverable reserve estimates and reserves dedicated to mines and complexes change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings and other factors.
 
The following tables present our estimated assigned and unassigned recoverable coal reserves at December 31, 2007:
 
Total Assigned Reserves
 
(Tons in millions)
 
                                                                                                         
    Total
                                                                         
    Assigned
                Sulfur Content
          Reserve Control     Mining Method     Past Reserve Estimates  
    Recoverable
                (lbs. per million Btus)     As Received
                      Under-
             
    Reserves     Proven     Probable     <1.2     1.2-2.5     >2.5     Btus per lb.(1)     Leased     Owned     Surface     ground     2005     2006  
 
Wyoming
    1,549       1,508       41       1,504       45             8,856       1,534       15       1,549             1,748       1,655  
Utah
    103       60       43       91       12             11,399       102       1             103       108       110  
Colorado
    79       60       19       79                   11,695       78       1             79       74       67  
Central App
    169       160       9       59       109       1       12,816       162       7       74       95       243       216  
Illinois
                                                                      13        
                                                                                                         
Total
    1,900       1,788       112       1,733       166       1       9,465       1,876       24       1,623       277       2,186       2,048  
                                                                                                         
 
 
(1) As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.


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Total Unassigned Reserves
 
(Tons in millions)
 
                                                                                         
    Total
                                                             
    Unassigned
                Sulfur Content
                               
    Recoverable
                (lbs. per million Btus)     As Received
    Reserve Control     Mining Method  
    Reserves     Proven     Probable     <1.2     1.2-2.5     >2.5     Btus per lb.(1)     Leased     Owned     Surface     Underground  
 
Wyoming
    398       301       97       351       47             9,653       307       91       224       174  
Utah
    35       16       19       31       4             10,842       34       1             35  
Colorado
    49       39       10       47       2             11,597       48       1             49  
Central App
    169       121       48       46       100       23       12,779       137       32       41       128  
Illinois
    376       270       106                   376       11,605       58       318       2       374  
                                                                                         
Total
    1,027       747       280       475       153       399       11,016       584       443       267       760  
                                                                                         
 
 
(1) As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.
 
At December 31, 2007, approximately 16% of our coal reserves were held in fee, with the balance controlled by leases, most of which do not expire until the exhaustion of mineable and merchantable coal. Under current mining plans, substantially all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewals. Royalties are paid to lessors either as a fixed price per ton or as a percentage of the gross sales price of the mined coal. The majority of the significant leases are on a percentage royalty basis. In some cases, a payment 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.
 
Federal and state legislation controlling air pollution affects the demand for certain types of coal by limiting the amount of sulfur dioxide which may be emitted as a result of fuel combustion and encourages a greater demand for low-sulfur coal. All of our identified coal reserves have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 75.4% consist of compliance coal, or coal which emits 1.2 pounds or less of sulfur dioxide per million Btus upon combustion, while an additional 6.6% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Most of our reserves are suitable for the domestic steam coal markets. A substantial portion of the low-sulfur and compliance coal reserves at the Cumberland River, Lone Mountain and Mountain Laurel mining complexes may also be used as metallurgical coal.
 
The carrying cost of our coal reserves at December 31, 2007 was $1.2 billion, consisting of $127.2 million of prepaid royalties and a net book value of coal lands and mineral rights of $1.1 billion.
 
Title to coal properties held by lessors or grantors to us and our 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 our 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 our 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 we conduct operations material to our consolidated financial position, results of operations and liquidity, but we do not believe any pending claims by such lessors or sublessors have merit or will result in the termination of any material lease or sublease.
 
We leased approximately 24,900 acres of property to other coal operators in 2007. We received royalty income of $5.6 million in 2007 from the mining of approximately 2.1 million tons, $5.0 million in 2006 from the mining of approximately 2.4 million tons and $7.1 million in 2005 from the mining of approximately 3.0 million tons on those properties. We have included reserves at properties leased by us to other coal operators in the reserve figures set forth in this report.
 
Our reported coal reserves are those that could be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other


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things, our potential inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. We have obtained, or we have a high probability of obtaining, all required permits or government approvals with respect to our 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 our reserves, we are not currently aware of matters which would significantly hinder our ability to obtain future mining permits or governmental approvals with respect to our reserves.
 
We periodically engage third parties to review our reserve estimates. The most recent third-party review of our reserve estimates was conducted by Weir International Mining Consultants in February 2008.
 
ITEM 3.   LEGAL PROCEEDINGS.
 
We are involved in various claims and legal actions arising in the ordinary course of business, including employee injury claims. 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.
 
Permit Litigation Matters
 
Two of our operating subsidiaries have been identified in an existing lawsuit as having been granted Clean Water Act § 404 permits by the Corps allegedly in violation of the Clean Water Act and the National Environmental Policy Act. Surface mines at our Mingo Logan and Coal-Mac mining complexes have been identified in the suit for having received permits from the Corps. The lawsuit, brought by the Ohio Valley Environmental Coalition in the U.S. District Court for the Southern District of West Virginia, had originally been filed against the Corps for permits it had issued to coal operations owned by subsidiaries of a company unrelated to us or our operating subsidiaries. The existing suit claims that the Corps had issued permits to the coal operations belonging to the unrelated company that do not comply with the National Environmental Policy Act and violate the Clean Water Act. Plaintiffs were later allowed to amend their complaint to add challenges to permits issued to our Coal-Mac, Inc. and Mingo Logan Coal Company subsidiaries, but those claims have not advanced. Rather, the court proceeded first on the earlier challenge to four permits of companies unrelated to us.
 
The court proceeded to rule on the challenges to those four permits in orders of March 23 and June 13, 2007. In the first of those orders, the court rescinded the four permits, finding that the Corps had inadequately assessed the likely impact of valley fills on headwater streams and had relied on inadequate or unproven mitigation to offset those impacts. That ruling could require the Corps to prepare environmental impact statements on those permits, which would slow the permit process. The ruling could, as a practical matter, affect our Coal-Mac and other future permits, but the Corps has already done an environmental impact statement on the Mingo Logan permit. In the second order, the court entered a declaratory judgment that discharges of sediment from the valley fills into sediment control ponds constructed in-stream to control that sediment must themselves be permitted and meet the limits imposed on discharges from these ponds. Unless reversed, that ruling will likely complicate the ability to construct sediment ponds in steep-sloped areas where in-stream locations are frequently the only practicable ones. Both of the district court rulings are on appeal to the Fourth Circuit Court of Appeals, and a decision is expected from that court in 2008.
 
While the court was considering the challenge to the four permits unrelated to our operating subsidiaries, the plaintiffs were permitted to add challenges to our Coal-Mac, Inc. and Mingo Logan Coal Company subsidiaries. Plaintiffs sought preliminary inunctions as to both operations, but later reached agreements with our operating subsidiaries that have allowed mining to progress in limited areas while the district court’s rulings are on appeal.
 
West Virginia Flooding Litigation
 
Over 3,000 plantiffs have sued us and more than 180 other defendants in Wyoming, McDowell, Fayette, Kanawha, Raleigh, Boone and Mercer Counties, West Virginia for property damage and personal injuries arising out of flooding that occurred in southern West Virginia on or about July 8, 2001. The plaintiffs have sued coal,


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timber, oil and gas, 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 other flood damage cases not involving us, will 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. Trials, by watershed, have begun and are proceeding in phases. On May 2, 2006, following the Mullins/Oceana phase I trial, in which we were not involved, the jury returned a verdict against the two non-settling defendants. However, the court set aside that verdict and granted judgment in favor of the defendants. The plaintiffs in that trial group have appealed that decision, and we, along with other defendants, have filed an amicus brief in that appeal. We were previously named in cases involving the Coal River watershed; however, on January 18, 2007, the court dismissed the plaintiffs’ claims involving that watershed for failure to state a claim. This ruling has also been appealed. We are also named in the remaining Upper Guyandotte watershed trial group. A trial date has not yet been set for that group.
 
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
 
There were no matters submitted to a vote of security holders through the solicitation of proxies or otherwise during the fourth quarter of 2007.
 
PART II
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
 
Market for Registrant’s Common Equity and Related Stockholder Matters
 
Our common stock is listed and traded on the New York Stock Exchange under the symbol “ACI”. On February 25, 2008, our common stock closed at $54.90 on the New York Stock Exchange. On that date, there were approximately 8,200 holders of record of our common stock.
 
Holders of our common stock are entitled to receive dividends when they are declared by our board of directors. When dividends are declared on common stock, they are usually paid in mid-March, June, September and December. We paid dividends on our common stock totaling $38.7 million, or $0.27 per share, in 2007 and $31.4 million, or $0.22 per share, in 2006. There is no assurance as to the amount or payment of dividends in the future because they are dependent on our future earnings, capital requirements and financial condition. You should see “Liquidity and Capital Resources” beginning on page 46 for more information about restrictions on our ability to declare dividends.
 
The following table sets forth for each period indicated the dividends paid per common share, the high and low sale prices of our common stock and the closing price of our common stock on the last trading day for each of the quarterly periods indicated. The information in the following table has been adjusted to reflect a two-for-one stock split of our common stock in the form of a 100% stock dividend paid on May 15, 2006.
 
                                 
    2007  
    March 31     June 30     September 30     December 31  
 
Dividends per common share
  $ 0.06     $ 0.07     $ 0.07     $ 0.07  
High
    33.79       42.59       37.00       45.22  
Low
    27.18       30.33       27.76       32.99  
Close
    30.69       34.80       33.74       44.93  
 


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    2006  
    March 31     June 30     September 30     December 31  
 
Dividends per common share
  $ 0.04     $ 0.06     $ 0.06     $ 0.06  
High
    44.15       56.45       44.13       37.03  
Low
    34.30       37.10       25.88       25.85  
Close
    37.97       42.37       28.91       30.03  
 
Stock Price Performance Graph
 
The following performance graph compares the cumulative total return to stockholders on our common stock with the cumulative total return on two indices: a peer group, consisting of CONSOL Energy, Inc., Foundation Coal Holdings, Inc., Massey Energy Company and Peabody Energy Corp., and the Standard & Poor’s (S&P) 400 (Midcap) Index. The graph assumes that:
 
  •  you invested $100 in Arch Coal common stock and in each index at the closing price on December 31, 2002;
 
  •  all dividends were reinvested;
 
  •  annual reweighting of the peer groups; and
 
  •  you continued to hold your investment through December 31, 2007.
 
You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance. The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our common stock.
 
5-Year Total Stockholder Return
Arch Coal, Inc. v. S&P 400 (Midcap) Index and Industry Peer Group
 
 
                                                 
    Year Ended December 31  
    2002     2003     2004     2005     2006     2007  
 
Arch Coal, Inc. 
  $ 100     $ 146     $ 168     $ 377     $ 287     $ 432  
S&P 400 (Midcap)
    100       136       158       178       196       212  
Industry Peer Group
    100       163       286       482       447       806  

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Issuer Purchases of Equity Securities
 
In September 2006, our board of directors authorized a share repurchase program for the purchase of up to 14,000,000 shares of our common stock. There is no expiration date on the current authorization, and we have not made any decisions to suspend or cancel purchases under the program. As of December 31, 2007, we have purchased 1,562,400 shares of our common stock under this program. We did not purchase any shares of our common stock under this program during the quarter ended December 31, 2007. Based on the closing price of our common stock as reported on the New York Stock Exchange on February 25, 2008, there is approximately $682.8 million of our common stock that may yet be purchased under this program.
 
ITEM 6.   SELECTED FINANCIAL DATA.
 
                                         
    Year Ended December 31  
    2007
    2006
    2005
    2004
    2003
 
    (1)     (2) (3)     (2) (3) (4) (5)     (4) (6) (7)     (4) (7) (8)  
    (Amounts in thousands, except per share data)  
 
Statement of Operations Data:
                                       
Coal sales revenue
  $ 2,413,644     $ 2,500,431     $ 2,508,773     $ 1,907,168     $ 1,435,488  
Income from operations
    229,617       336,667       77,857       178,046       40,371  
                                         
Income before cumulative effect of accounting change
    174,929       260,931       38,123       113,706       20,340  
Cumulative effect of accounting change
                            (3,654 )
                                         
Net income
    174,929       260,931       38,123       113,706       16,686  
Preferred stock dividends
    (219 )     (378 )     (15,579 )     (7,187 )     (6,589 )
                                         
Net income available to common stockholders
  $ 174,710     $ 260,553     $ 22,544     $ 106,519     $ 10,097  
                                         
Basic earnings per common share before cumulative effect of accounting change
  $ 1.23     $ 1.83     $ 0.18     $ 0.95     $ 0.13  
Diluted earnings per common share before cumulative effect of accounting change
    1.21       1.80       0.17       0.89       0.13  
Basic earnings per common share
    1.23       1.83       0.18       0.95       0.10  
Diluted earnings per common share
    1.21       1.80       0.17       0.89       0.10  
Balance Sheet Data:
                                       
Total assets
  $ 3,594,599     $ 3,320,814     $ 3,051,440     $ 3,256,535     $ 2,387,649  
Working capital
    (35,370 )     46,471       216,376       355,803       237,007  
Long-term debt, less current maturities
    1,085,579       1,122,595       971,755       1,001,323       700,022  
Other long-term obligations
    420,819       391,819       382,256       800,332       722,954  
Stockholders’ equity
    1,531,686       1,365,594       1,184,241       1,079,826       688,035  
Common Stock Data:
                                       
Dividends per share
  $ 0.2700     $ 0.2200     $ 0.1600     $ 0.1488     $ 0.1152  
Shares outstanding at year-end
    143,158       142,179       142,741       125,716       106,410  
Cash Flow Data:
                                       
Cash provided by operating activities
  $ 330,810     $ 308,102     $ 254,607     $ 148,728     $ 162,361  
Depreciation, depletion and amortization
    242,062       208,354       212,301       166,322       158,464  
Capital expenditures
    488,363       623,187       357,142       292,605       132,427  
Dividend payments
    38,945       31,815       27,639       24,043       17,481  
Operating Data:
                                       
Tons sold
    135,010       134,976       140,202       123,060       100,634  
Tons produced
    126,624       126,015       129,685       115,861       93,966  
Tons purchased from third parties
    8,495       10,092       11,226       12,572       6,602  
 
 
(1) On June 29, 2007, we sold select assets and related liabilities associated with our Mingo Logan-Ben Creek mining complex in West Virginia for $43.5 million. We recognized a net gain of $8.9 million in 2007 resulting from the sale.
 
(2) On October 27, 2005, we conducted a precautionary evacuation of our West Elk mine after we detected elevated readings of combustion-related gases in an area of the mine where we had completed mining activities but had not yet removed final longwall equipment. We estimate that the idling resulted in $30.0 million of lost profits during the first quarter of 2006, in


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addition to the effect of the idling and fire-fighting costs incurred during the fourth quarter of 2005 of $33.3 million. We recognized insurance recoveries related to the event of $41.9 million during the year ended December 31, 2006. We have reflected these insurance recoveries as a reduction of our cost of coal sales for the year ended December 31, 2006.
 
(3) On December 31, 2005, we sold all of the stock of three subsidiaries and their associated mining operations and coal reserves in Central Appalachia to Magnum. As a result of the transaction, we recognized a gain during 2005 of $7.5 million which we recorded as a component of other operating income. In addition, we recognized expenses of $8.7 million during 2006 related to the finalization of working capital adjustments to the purchase price, adjustments to estimated volumes associated with sales contracts acquired by Magnum and expense related to settlement accounting for pension plan withdrawals.
 
(4) On May 15, 2006, we completed a two-for-one stock split of our common stock in the form of a 100% stock dividend. All share and per share amounts reflect the split.
 
(5) On December 30, 2005, we completed a reserve swap with Peabody Energy Corp. and sold to Peabody a rail spur, rail loadout and an idle office complex located in the Powder River Basin, for a purchase price of $84.6 million. As a result of the transaction, we recognized a gain of $46.5 million which we recorded as a component of other operating income.
 
(6) During 2004, we acquired the North Rochelle mine in the Powder River Basin. We also purchased the remaining 35% interest in Canyon Fuel that we did not already own and began consolidating Canyon Fuel in our financial statements as of July 31, 2004.
 
(7) During 2004 and 2003, we sold our investment in Natural Resource Partners in four separate transactions occurring in December 2003 and March, June and October 2004. We recognized a gain of $42.7 million in the fourth quarter of 2003 and an aggregate gain of $91.3 million during 2004.
 
(8) On January 1, 2003, we adopted Statement No. 143 resulting in a cumulative effect of accounting change of $3.7 million (net of tax).
 
ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
 
Overview
 
We are one of the largest coal producers in the United States. For the year ended December 31, 2007, we sold approximately 135.0 million tons of coal, including approximately 8.6 million tons of coal we purchased from third parties, fueling approximately 6% of all electricity generated in the United States. Since federal and state environmental regulations limit the amount of sulfur dioxide that power plants may emit, we believe demand for low sulfur coal exceeds demand for other types of coal. As a result, we focus on mining, processing and marketing bituminous and sub-bituminous coal with low sulfur content for sale to domestic power plants, steel mills and industrial facilities.
 
In 2007, we estimate that U.S. coal consumption rose by approximately 2% to 1.2 billion tons, according to estimates provided by the EIA. Conversely, according to the EIA, domestic coal production declined by approximately 1.5% in 2007. In 2008, we expect continued growth in electricity demand, although at lower levels than in 2007 given the forecast for slower U.S. economic growth. In addition, we expect strengthening global demand for coal to increase U.S. coal exports, particularly as traditional coal export countries, such as Australia, China and South Africa, experience mine, port, rail and labor challenges. We estimate that higher domestic coal demand and higher coal exports, together with decreased production particularly in the Central Appalachia region of the United States, will adversely affect the availability of domestic coal in the coming years and result in upward pressure on domestic coal prices. As such, we have not yet priced a portion of the coal we plan to produce over the next several years in order to take advantage of expected price increases. At December 31, 2007, our expected unpriced production approximated 15 million to 25 million tons in 2008, 85 million to 95 million tons in 2009 and 95 million to 105 million tons in 2010.
 
The locations of our mines enable us to ship coal to most of the major coal-fired power plants in the United States. Our three reportable business segments are based on the low-sulfur coal producing regions in the United States in which we operate — the Powder River Basin, the Western Bituminous region and the Central Appalachia region. These geographically distinct areas are characterized by 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 region and form the basis for the segmentation of our operations.


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The Powder River Basin is located in northeastern Wyoming and southeastern Montana. The coal we mine from surface operations in this region has a very low sulfur content and a low heat value compared to the other regions in which we operate. The price of Powder River Basin coal is generally less than that of coal produced in other regions because Powder River Basin coal exists in greater abundance, is easier to mine and thus has a lower cost of production. Because Powder River Basin coal is generally lower in heat value, some power plants must blend it with higher Btu coal or retrofit existing coal plants to accommodate Powder River Basin coal. The Western Bituminous region includes western Colorado, eastern Utah and southwestern Wyoming. Coal we mine from underground mines in this region typically has a low sulfur content and varies in heat value. Central Appalachia includes eastern Kentucky, Virginia and southern West Virginia. Coal we mine from both surface and underground mines in this region generally has a high heat value and low sulfur content. In addition, a portion of the coal we produce in the Central Appalachia region consists of metallurgical coal. We are typically able to sell metallurgical coal to customers in the steel industry at prices that exceed the price we are able to sell steam coal to power plants and industrial facilities because metallurgical coal has high heat content, low expansion pressure, low sulfur content and various other chemical attributes.
 
In 2007, we continued the efforts we had begun in prior periods aimed at positioning our operations for increasing global and domestic coal demand. During the first half of 2007, we installed a replacement longwall at our Sufco mining complex in Utah. In addition, we began construction of a new loadout facility at our Black Thunder mining complex in Wyoming. This facility, which we have strategically located in relation to the direction of our mining activities, will replace the facility that we currently lease from a third party under an agreement set to expire within the next year. In 2007, we also continued development of a new reserve area at our West Elk mining complex in Colorado and commenced production at our Mountain Laurel mining complex in Central Appalachia. Coal produced at our lower-cost Mountain Laurel mining complex will replace the coal we have historically produced at the higher-cost Mingo Logan-Ben Creek mining complex that we sold to a subsidiary of Alpha Natural Resources at the end of the first half of 2007. We also expect that the opening of the Mountain Laurel complex will enable us to take advantage of increasing global metallurgical coal demand.
 
Items Affecting Comparability of Reported Results
 
The comparability of our operating results for the years ended December 31, 2007, 2006 and 2005 is affected by the following significant items:
 
Sale of Mingo Logan-Ben Creek mining complex — On June 29, 2007, we sold selected assets and related liabilities associated with our Mingo Logan-Ben Creek mining complex in West Virginia to a subsidiary of Alpha Natural Resources, Inc. for $43.5 million. During the year ended December 31, 2007, our Ben Creek operations contributed coal sales of 1.2 million tons, revenues of $75.1 million and income from operations of $9.1 million. During the year ended December 31, 2006, our Ben Creek operations contributed coal sales of 4.0 million tons, revenues of $243.8 million and income from operations of $19.5 million. During the year ended December 31, 2005, our Ben Creek operations contributed coal sales of 4.7 million tons, revenues of $261.5 million, and income from operations of $15.2 million. We recognized a net gain of $8.9 million in the year ended December 31, 2007 resulting from this transaction, net of accrued losses of $12.5 million on firm commitments to purchase coal through 2008 to supply below-market sales contracts that can no longer be sourced from our operations and $4.9 million of employee-related payments. We recorded the gain as a component of other operating income, net.
 
Sale of select Central Appalachia operations — On December 31, 2005, we sold the stock of three subsidiaries and their four associated mining operations and coal reserves in Central Appalachia to Magnum. The three subsidiaries were Hobet Mining, Inc., Apogee Coal Company and Catenary Coal Company, which included the Hobet 21, Arch of West Virginia, Samples and Campbells Creek mining complexes. For the year ended December 31, 2005, these complexes sold 12.7 million tons of coal, had revenues of $509.8 million and incurred a loss from operations of $8.3 million. We recognized a net gain of $7.5 million in the fourth quarter of 2005 in conjunction with this transaction. The gain we recorded included accrued losses of $65.4 million on firm commitments to purchase coal in 2006 to supply below-market sales contracts, which could no longer be sourced from our operations as a result of the transaction. In addition, we recognized expenses of $8.7 million


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during 2006 related to the finalization of working capital adjustments to the purchase price, adjustments to estimated volumes associated with sales contracts acquired by Magnum and settlement accounting for pension plan withdrawals. In accordance with the terms of the transaction, we paid $50.2 million to Magnum in 2006 to purchase coal and to offset certain ongoing operating expenses of Magnum.
 
Peabody reserve swap and asset sale — On December 30, 2005, we completed a reserve swap with Peabody Energy Corp. and sold to Peabody a rail spur, rail loadout and an idle office complex located in the Powder River Basin for a purchase price of $84.6 million. In the reserve swap, we exchanged 60.0 million tons of coal reserves for a similar block of 60.0 million tons of coal reserves in order to facilitate more efficient mine plans for both companies. In conjunction with the transactions, we will continue to lease the rail spur and loadout and office facilities through September 2008 while we mine adjacent reserves. We recognized a gain of $46.5 million on the transaction, after the deferral of $7.0 million of the gain, equal to the present value of the lease payments. We are recognizing the deferred gain over the term of the lease.
 
West Elk combustion event — A combustion-related event at our West Elk mine in Colorado in October 2005 caused the idling of the mine into the first quarter of 2006. We estimate that the idling resulted in $30.0 million in lost profits during the first quarter of 2006, in addition to the effect of the idling and fire-fighting costs incurred during the fourth quarter of 2005 of $33.3 million. We recognized insurance recoveries related to the event of $41.9 million during the year ended December 31, 2006. We have reflected these insurance recoveries as a reduction of our cost of coal sales for the year ended December 31, 2006.
 
Accounting for pit inventory — On January 1, 2006, we adopted the provisions of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry. This issue applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the issue, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. Prior to 2006, we recorded stripping costs associated with the tons of coal uncovered and not yet extracted (pit inventory) at our surface mining operations as coal inventory. The cumulative effect of adoption was to reduce inventory by $40.7 million and deferred development cost by $2.0 million with a corresponding decrease to retained earnings, net of tax, of $26.1 million. This accounting change creates volatility in our results of operations, as cost increases or decreases related to fluctuations in pit inventory can only be attributed to tons extracted from the pit.
 
Results of Operations
 
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
Summary.  Our results during 2007 when compared to 2006 were affected primarily by changes in our regional sales mix; weaker market conditions; higher depreciation, depletion and amortization, higher cash costs in the Powder River Basin; the net effect of the insurance proceeds we recorded in 2006 related to the West Elk idling and the effect of the idling in the first quarter of 2006; and an increase in interest expense. In response to the soft market conditions, we reduced production volume targets in all operating segments in 2007.
 
Revenues.  The following table summarizes information about coal sales during the year ended December 31, 2007 and compares those results to the comparable information for the year ended December 31, 2006:
 
                                 
    Year Ended December 31     Increase (Decrease)  
    2007     2006     Amount     %  
    (Amounts in thousands, except per ton data)  
 
Coal sales
  $ 2,413,644     $ 2,500,431     $ (86,787 )     (3.5 )%
Tons sold
    135,010       134,976       34        
Coal sales realization per ton sold
  $ 17.88     $ 18.53     $ (0.65 )     (3.5 )%
 
Coal sales.  Coal sales decreased from 2006 to 2007 primarily due to changes in our segment mix, despite flat overall sales volume. An increase in Powder River Basin sales volumes and a decrease in Central Appalachia sales volumes resulted in a lower average sales price because Powder River Basin coal has a lower average sales


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price per ton than Central Appalachia coal. We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results” on page 41.
 
Expenses, costs and other.  The following table summarizes expenses, costs and other operating income, net for the year ended December 31, 2007 and compares those results to the comparable information for the year ended December 31, 2006:
                                 
          Increase (Decrease)
 
    Year Ended December 31     in Net Income  
    2007     2006     $     %  
          (Dollars in thousands)        
 
Cost of coal sales
  $ 1,888,285     $ 1,909,822     $ 21,537       1.1 %
Depreciation, depletion and amortization
    242,062       208,354       (33,708 )     (16.2 )
Selling, general and administrative expenses
    84,446       75,388       (9,058 )     (12.0 )
Other operating income, net
    (30,766 )     (29,800 )     966       3.2  
                                 
Total
  $ 2,184,027     $ 2,163,764     $ (20,263 )     (0.9 )%
                                 
 
Cost of coal sales.  Cost of coal sales decreased from 2006 to 2007 primarily due to the effect of the change in our segment mix, as the Powder River Basin’s production costs per ton are lower than costs for our other regions. We also purchased fewer tons to satisfy contracts we retained after the sale to Magnum. This decrease was partially offset by higher unit costs in the Powder River Basin, primarily reflecting higher commodity and supplies costs, and higher unit costs in the Western Bituminous region. Higher unit costs in the Western Bituminous region were primarily due to the impact of insurance proceeds we recognized in 2006 related to the West Elk combustion-related event, which more than offset the impact of the idling in the first quarter of 2006. We have provided more information about our operating segments under the heading “Operating segment results” on page 41.
 
Depreciation, depletion and amortization.  The increase in depreciation, depletion and amortization expense from 2006 to 2007 is due primarily to the costs of ongoing capital improvement and mine development projects that we capitalized in 2006 and 2007 and a decrease in the amortization of deferred gains on acquired sales contracts. We have provided additional information concerning our capital spending in the section entitled “Liquidity and Capital Resources” beginning on page 46.
 
Selling, general and administrative expenses.  The increase in selling, general and administrative expenses from 2006 to 2007 is primarily due to an increase in the expense associated with our deferred compensation plans, which results from changes in the value of our common stock, as well as other employee compensation costs.
 
Other operating income, net.  The increase in other operating income, net in 2007 compared to 2006 is due primarily to the following:
 
  •  an $8.9 million gain on the 2007 sale of the Ben Creek complex discussed previously;
 
  •  a $6.0 million gain on the sale of non-core reserves in the Powder River Basin and a $2.4 million gain on the sale of non-core reserves in Central Appalachia, both in 2007;
 
  •  unrealized gains of $5.0 million in 2007 on coal derivatives entered into for trading purposes; and
 
  •  expenses of $8.7 million during 2006 related to the Magnum transaction.
 
These increases in other operating income are partially offset by:
 
  •  a decrease of $15.2 million related to realized and unrealized gains in 2006 associated with sulfur dioxide emission allowance put options and swaps;
 
  •  a gain of $10.3 million in 2006 on the acquisition of our interest in Knight Hawk Holdings, LLC, representing the difference between the fair value of coal reserves we surrendered for the interest and their carrying value; and
 
  •  a decrease of $3.3 million in the amount of income from equity investments.


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Operating segment results.  The following table shows results by operating segment for the year ended December 31, 2007 and compares those amounts to the comparable information for the year ended December 31, 2006:
 
                                 
    Year Ended December 31     Increase (Decrease)  
    2007     2006     Amount     %  
    (Amounts in thousands, except per ton data)  
 
Powder River Basin
                               
Tons sold
    99,145       96,246       2,899       3.0 %
Coal sales realization per ton sold(1)
  $ 10.59     $ 10.82     $ (0.23 )     (2.1 )%
Operating margin per ton sold(2)
  $ 1.23     $ 2.15     $ (0.92 )     (42.8 )%
Western Bituminous
                               
Tons sold
    19,362       18,122       1,240       6.8 %
Coal sales realization per ton sold(1)
  $ 24.73     $ 22.42     $ 2.31       10.3 %
Operating margin per ton sold(2)
  $ 5.11     $ 6.86     $ (1.75 )     (25.5 )%
Central Appalachia
                               
Tons sold
    16,503       20,608       (4,105 )     (19.9 )%
Coal sales realization per ton sold(1)
  $ 47.87     $ 46.90     $ 0.97       2.1 %
Operating margin per ton sold(2)
  $ 3.89     $ 2.95     $ 0.94       31.9 %
 
 
(1) Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the year ended December 31, 2007, transportation costs per ton billed to customers were $0.03 for the Powder River Basin, $3.17 for the Western Bituminous region and $1.82 for Central Appalachia. Transportation costs per ton billed to customers for the year ended December 31, 2006 were $0.02 for the Powder River Basin, $2.91 for the Western Bituminous region and $1.54 for Central Appalachia.
 
(2) Operating margin per ton is calculated as the result of coal sales revenues less cost of coal sales and depreciation, depletion and amortization divided by tons sold.
 
Powder River Basin — Sales volume in the Powder River Basin increased slightly in 2007 over 2006 levels due to increased shipments from the Coal Creek mine, which was restarted during 2006, and higher volumes of brokerage activity. These volumes were partially offset by a decrease at the Black Thunder mining complex due to planned volume reductions in response to the weaker market conditions in 2007, as well as weather-related shipment challenges and an unplanned belt outage that occurred in the first quarter of 2007. Decreases in sales prices during 2007 when compared with 2006 primarily reflect the higher volumes from the Coal Creek mining complex, which has a lower price due to its lower heat content, and lower sulfur dioxide emission allowance adjustments. On a per-ton basis, operating margins in 2007 decreased from 2006 due in part to the decrease in per-ton coal sales prices and an increase in per-ton costs. The increase in per-ton costs resulted primarily from higher diesel fuel prices and higher labor, tire and leasing costs.
 
Western Bituminous — In the Western Bituminous region, sales volume increased during 2007 when compared with 2006, reflecting a full year of production at the West Elk and Skyline mining complexes. The West Elk mining complex was idle during the first quarter of 2006 after the combustion-related event in the fourth quarter of 2005, and the Skyline longwall commenced mining in a new reserve area in the second quarter of 2006. These increases were partially offset by the lower volumes from planned volume reductions in response to the weaker market conditions in 2007. Higher sales prices during 2007 represent higher base pricing resulting from the roll-off of lower-priced legacy contracts. Operating margins per ton for 2007 decreased from 2006 primarily due to the impact of insurance proceeds we recognized in 2006 related to the West Elk combustion-related event and higher depreciation, depletion and amortization costs resulting from the impact of the installation of a new longwall at the Sufco mining complex. These factors offset the impact of the improved per-ton coal sales prices. The $41.9 million of insurance proceeds we recognized in 2006 offset the estimated $30.0 million adverse effect of the idling in the first quarter of 2006.


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Central Appalachia — Our sales volumes in Central Appalachia decreased during 2007 when compared with 2006 primarily due to higher volumes of coal shipped during 2006 associated with sales contracts we retained after the sale of certain Central Appalachia operations in 2005 to Magnum and the sale of the Ben Creek operations at the end of the second quarter of 2007. The commencement of production at the Mountain Laurel complex at the beginning of the fourth quarter of 2007 partially offset these effects. The higher realized prices in 2007 reflect the decrease in the volumes sold under the lower-priced contracts we retained after the sale to Magnum. Operating margins per ton for 2007 increased from 2006 due to the lower volumes sold under the contracts retained after the Magnum sale and the commencement of production at the low-cost Mountain Laurel complex. The tons sold under the retained contracts are purchased from Magnum at an amount equal to the contracted sales price, which diluted our per-ton margins in 2006. Difficult geologic conditions in certain locations, particularly at our Mingo Logan-Ben Creek complex, and higher depreciation, depletion and amortization costs partially offset the positive impact on operating margin.
 
Net interest expense.  The following table summarizes our net interest expense for the year ended December 31, 2007 and compares that information to the comparable information for the year ended December 31, 2006:
 
                                 
          Decrease
 
    Year Ended December 31     in Net Income  
    2007     2006     $     %  
          (Amounts in thousands)        
 
Interest expense
  $ (74,865 )   $ (64,364 )   $ (10,501 )     (16.3 )%
Interest income
    2,600       3,725       (1,125 )     (30.2 )
                                 
Total
  $ (72,265 )   $ (60,639 )   $ (11,626 )     (19.2 )%
                                 
 
The increase in interest expense during 2007 compared to the year-ago period resulted primarily from an increase in outstanding borrowings under our various lines of credit, which was partially offset by an increase in capitalized interest. We capitalized $18.0 million of interest during the year ended December 31, 2007 and $14.8 million during the year ended December 31, 2006. For more information on our ongoing capital improvement and development projects, you should see “Liquidity and Capital Resources” beginning on page 46.
 
Other non-operating expense.  The following table summarizes our other non-operating expense for the year ended December 31, 2007 and compares that information to the comparable information for the year ended December 31, 2006:
 
                                 
          Increase
 
    Year Ended December 31     in Net Income  
    2007     2006     $     %  
    (Amounts in thousands)  
 
Other non-operating expense:
                               
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps
  $ (1,919 )   $ (4,836 )   $ 2,917       60.3 %
Other non-operating expense
    (354 )     (2,611 )     2,257       86.4  
                                 
Total
  $ (2,273 )   $ (7,447 )   $ 5,174       69.5 %
                                 
 
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 include expenses related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. All deferred amounts have now been recognized. Other non-operating income includes mark-to-market adjustments related to certain swap activity that does not qualify for hedge accounting. No swaps were outstanding at December 31, 2007.
 
Income taxes.  Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion deductions. The income tax benefit of $19.9 million in 2007 compared with our income tax provision of $7.7 million in 2006 results from lower pre-tax income in 2007 and the benefit of a reduction


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in our valuation allowance against deferred tax assets of $38.7 million compared with higher pre-tax income in 2006 offset by a valuation allowance reduction of $49.1 million.
 
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
 
Summary.  Our results for 2006 reflect higher margins driven primarily by increased price realizations and the disposition of certain Central Appalachia operations at the end of 2005. We achieved those results despite continued rail challenges in the western United States and weaker market conditions at the end of 2006. In 2005, we experienced significant disruptions in our rail service from major repair and maintenance work in the Powder River Basin. During 2006, we experienced some shipment disruptions due to ongoing repairs and maintenance on the rail lines, although not of the magnitude experienced in 2005. Our results for 2006 also reflected production at our Coal Creek surface mining complex in Wyoming, which restarted production in 2006, and our Skyline longwall mining complex in Utah, which commenced mining in a new reserve area in 2006.
 
Revenues.  The following table summarizes information about coal sales during the year ended December 31, 2006 and compares those results to the comparable information for the year ended December 31, 2005:
 
                                 
    Year Ended December 31     Increase (Decrease)  
    2006     2005     Amount     %  
    (Amounts in thousands, except per ton data)  
 
Coal sales
  $ 2,500,431     $ 2,508,773     $ (8,342 )     (0.3 )%
Tons sold
    134,976       140,202       (5,226 )     (3.7 )
Coal sales realization per ton sold
  $ 18.53     $ 17.89     $ 0.64       3.6 %
 
Coal sales remained relatively flat during 2006 when compared to 2005. Higher contract prices in all three of our segments partially offset lower volumes resulting primarily from the sale of certain Central Appalachia operations in the fourth quarter of 2005. A higher percentage of Powder River Basin sales, which have a lower average sales price per ton than our other regions, caused the average overall sales price to increase only slightly. We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results” on page 45.
 
Expenses, costs and other.  The following table summarizes expenses, costs and other operating income and expenses, net for the year ended December 31, 2006 and compares those results to the comparable information for the year ended December 31, 2005:
 
                                 
          Increase (Decrease)
 
    Year Ended December 31     in Net Income  
    2006     2005     $     %  
          (Amounts in thousands)        
 
Cost of coal sales
  $ 1,909,822     $ 2,174,007     $ 264,185       12.2 %
Depreciation, depletion and amortization
    208,354       212,301       3,947       1.9  
Selling, general and administrative expenses
    75,388       91,568       16,180       17.7  
Gain on sale of Powder River Basin assets
          (46,547 )     (46,547 )     (100.0 )
Gain on sale of Central Appalachia operations
          (7,528 )     (7,528 )     (100.0 )
Other operating (income) expense, net
    (29,800 )     7,115       36,915       518.8  
                                 
Total
  $ 2,163,764     $ 2,430,916     $ 267,152       11.0 %
                                 
 
Cost of coal sales.  Our cost of coal sales decreased from 2005 to 2006 primarily due to the sale of certain Central Appalachia operations described above. This decrease was partially offset by increased sales volume, particularly in the Powder River Basin, and higher costs, primarily production taxes and coal royalties, which we pay as a percentage of coal sales. We have provided more information about our operating segments under the heading “Operating segment results” on page 45.


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Depreciation, depletion and amortization.  The decrease in depreciation, depletion and amortization from 2005 to 2006 is due primarily to the sale of certain Central Appalachia operations described above. Capital improvements associated with development projects largely offset the decrease resulting from the sale of certain Central Appalachia operations in 2005. We have provided additional information concerning our capital spending during 2006 in the section entitled “Liquidity and Capital Resources” beginning on page 46.
 
Selling, general and administrative expenses.  Selling, general and administrative expenses decreased in 2006 compared to 2005 due primarily to a decrease of $6.7 million related to deferred compensation, a decrease of $8.3 million related to incentive compensation awards, and the establishment of a charitable foundation in 2005 of $5.0 million.
 
Gain on sale.  You should see “Items Affecting Comparability of Reported Results” beginning on page 38 for more information about the gains on the sale of our Powder River Basin assets and Central Appalachia operations.
 
Other operating (income) expense, net.  The increase in net income in 2006 compared to 2005 from changes in other operating (income) expense is due primarily to the following:
 
  •  a decrease of $31.1 million between years in the amount of realized and unrealized losses associated with sulfur dioxide emission allowance put options and swaps;
 
  •  a decrease of $13.9 million in the net expense related to bookouts between periods (the netting of coal sales and purchase contracts with the same counterparty);
 
  •  a gain of $10.3 million in 2006 on the acquisition of our interest in Knight Hawk Holdings, LLC, representing the difference between the fair value of coal reserves we surrendered for the interest and their carrying value;
 
  •  an increase of $6.2 million in the amount of income from equity investments; and
 
  •  a $16.0 million expense in 2005 related to settlement of certain disputes with a landowner.
 
These increases in other operating income are partially offset by:
 
  •  a decrease of $28.8 million in gains from sales of property, plant and equipment;
 
  •  expenses of $8.7 million during 2006 related to the Magnum transaction; and
 
  •  a decrease of $4.9 million in the amount of deferred gain associated with the sale of our interest in Natural Resource Partners, L.P., which we recognize over the terms of our leases with Natural Resource Partners L.P., some of which were transferred to Magnum.


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Operating segment results.  The following table shows results by operating segment for the year ended December 31, 2006 and compares those amounts to the comparable information for the year ended December 31, 2005:
 
                                 
    Year Ended December 31     Increase (Decrease)  
    2006     2005     Amount     %  
    (Amounts in thousands, except per ton data)  
 
Powder River Basin
                               
Tons sold
    96,246       91,471       4,775       5.2 %
Coal sales realization per ton sold(1)
  $ 10.82     $ 8.20     $ 2.62       32.0 %
Operating margin per ton sold(2)
  $ 2.15     $ 0.95     $ 1.20       126.3 %
Western Bituminous
                               
Tons sold
    18,122       18,199       (77 )     (0.4 )%
Coal sales realization per ton sold(1)
  $ 22.42     $ 19.01     $ 3.41       17.9 %
Operating margin per ton sold(2)
  $ 6.86     $ 3.27     $ 3.59       109.8 %
Central Appalachia
                               
Tons sold
    20,608       30,532       (9,924 )     (32.5 )%
Coal sales realization per ton sold(1)
  $ 46.90     $ 42.73     $ 4.17       9.8 %
Operating margin per ton sold(2)
  $ 2.95     $ (0.59 )   $ 3.54       600.0 %
 
 
(1) Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the year ended December 31, 2006, transportation costs per ton billed to customers were $0.02 for the Powder River Basin, $2.91 for the Western Bituminous region and $1.54 for Central Appalachia. Transportation costs per ton billed to customers for the year ended December 31, 2005 were $0.08 for the Powder River Basin, $3.10 for the Western Bituminous region and $1.48 for Central Appalachia.
 
(2) Operating margin per ton is calculated as the result of coal sales revenues less cost of coal sales and depreciation, depletion and amortization divided by tons sold.
 
Powder River Basin — Sales volume increased in the Powder River Basin as a result of the restart of the Coal Creek mining complex in the second quarter of 2006 and rail service that improved during 2006 when compared to 2005. The increase in coal sales prices in 2006 in the Powder River Basin resulted from higher contract pricing when compared to 2005, due primarily to the expiration of lower-priced legacy contracts. On a per-ton basis, operating margins in 2006 increased significantly from 2005 primarily due to the increase in per-ton coal sales realizations, partially offset by increased production taxes and coal royalties that we pay as a percentage of coal sales realizations, higher repair and maintenance activity and higher diesel, tire and explosives costs during 2006 compared to 2005.
 
Western Bituminous — In the Western Bituminous region, the effect of an extended longwall move at the Dugout Canyon mining complex offset a portion of the 1.5 million tons sold from our Skyline mining complex, which commenced production in a new reserve area in the second quarter of 2006. The increase in coal sales prices in the Western Bituminous region in 2006 resulted from higher contract pricing when compared to 2005, due primarily to the expiration of lower-priced legacy contracts. Operating margins per ton in 2006 increased from 2005 primarily due to higher per ton sales prices and insurance recoveries related to the West Elk thermal event of $41.9 million, partially offset by higher costs resulting from the idling of the West Elk complex in the first quarter of 2006, an extended longwall move at our Dugout Canyon mining complex, higher coal royalties and production taxes, which we pay as a percentage of sales, and higher repair and supplies costs.
 
Central Appalachia — Our sales volumes in Central Appalachia decreased as a result of the sale of operations to Magnum described previously. The increase in our coal sales prices in Central Appalachia in 2006 resulted from higher contract pricing when compared to 2005, due primarily to the expiration of lower-priced legacy contracts. The sale to Magnum of certain operations with lower-priced legacy contracts also helped to improve


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our average coal sales price per ton. Operating margins per ton in 2006 increased significantly from 2005 primarily as a result of the sale to Magnum, due to operating losses at these operations in 2005.
 
Net interest expense.  The following table summarizes our net interest expense for the year ended December 31, 2006 and compares that information to the comparable information for the year ended December 31, 2005:
 
                                 
          Increase (Decrease)
 
    Year Ended December 31     in Net Income  
    2006     2005     $     %  
    (Amounts in thousands)  
 
Interest expense
  $ (64,364 )   $ (72,409 )   $ 8,045       11.1 %
Interest income
    3,725       9,289       (5,564 )     (59.9 )
                                 
Total
  $ (60,639 )   $ (63,120 )   $ 2,481       3.9 %
                                 
 
The decrease in interest expense during 2006 compared to 2005 resulted primarily from an increase in the amount of interest capitalized in connection with certain major long-term development projects described in more detail in the section entitled “Liquidity and Capital Resources” beginning on page 46. We capitalized $14.8 million of interest during 2006 and $4.2 million during 2005. The decrease in interest income is due to a decrease in short-term investments, which we liquidated, in part, to fund our capital improvement and development projects.
 
Other non-operating expense.  The following table summarizes our other non-operating expense for the year ended December 31, 2006 and compares that information to the comparable information for the year ended December 31, 2005:
 
                                 
          Increase
 
    Year Ended December 31     in Net Income  
    2006     2005     $     %  
    (Amounts in thousands)  
 
Other non-operating expense:
                               
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps
  $ (4,836 )   $ (7,740 )   $ 2,904       37.5 %
Other non-operating expense
    (2,611 )     (3,524 )     913       25.9  
                                 
Total
  $ (7,447 )   $ (11,264 )   $ 3,817       33.9 %
                                 
 
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 include expenses related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Other non-operating income includes mark-to-market adjustments related to certain swap activity that does not qualify for hedge accounting.
 
Income taxes.  Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion deductions. The income tax provision of $7.7 million in 2006 compared with the income tax benefit of $34.7 million in 2005 is primarily the result of increases in pre-tax income in 2006, offset by a $49.1 million decrease in our valuation allowance against deferred tax assets in 2006, compared to a $6.1 million decrease in our valuation allowance in 2005.
 
Liquidity and Capital Resources
 
Our primary sources of cash include sales of our coal production to customers, borrowings under our credit facilities, sales of assets, and debt and equity offerings related to significant transactions. 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 or borrowings under our credit facilities, accounts receivable securitization or commercial paper programs. We believe that cash generated from operations,


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borrowing under our credit facilities and sales of assets 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, to repurchase our common shares 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.
 
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  
    2007     2006     2005  
    (Amounts in thousands)  
 
Cash provided by (used in):
                       
Operating activities
  $ 330,810     $ 308,102     $ 254,607  
Investing activities
    (424,995 )     (688,005 )     (291,543 )
Financing activities
    96,742       121,925       (25,730 )
 
Cash provided by operating activities increased $22.7 million in 2007 compared to 2006, despite a decrease in earnings, primarily as a result of transactions in 2006 related to our sale of certain Central Appalachia operations to Magnum on December 31, 2005. We made payments of $50.2 million in 2006 related to that transaction, involving the purchase of coal and certain operating expenses pursuant to the purchase agreement. In addition, we purchased coal in 2006 to satisfy below-market contracts that we could not source from our remaining operations.
 
Cash provided by operating activities increased $53.5 million in 2006 compared to 2005 primarily as a result of an increase in net income, which was offset by an increased investment in working capital and the effect of certain transactions with Magnum discussed above.
 
Cash used in investing activities in 2007 was $263.0 million less than in 2006, primarily due to a $134.8 million decrease in capital expenditures, an increase of $69.5 million in proceeds from asset sales, and a decrease of $36.4 in payments to acquire equity interests in other companies that are accounted for on the equity method. We make capital expenditures to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We may also acquire coal reserves opportunistically. During 2006 and 2007, we made the second and third of five annual payments of $122.2 million on the Little Thunder federal coal lease. In addition, during 2007, we acquired additional property and reserves of approximately $97.4 million. Of the remaining capital spending in 2007, major projects included the completion of development at the Mountain Laurel complex in Central Appalachia, ongoing development of a new reserve area at the West Elk mining complex in Colorado, payments for the replacement longwall now in service at our Sufco mining complex in Utah and costs to construct the Black Thunder mining complex’s new loadout. The Mountain Laurel longwall commenced production on October 1, 2007. In the prior year, in addition to spending on the Mountain Laurel development, we also had spending related to the restart of the Coal Creek mining complex and the commencement of mining in a new reserve area at our Skyline mining complex.
 
Cash inflows from investing activities in 2007 included a recovery of $18.3 million from the lease of equipment in the Powder River Basin. We had previously made deposits to purchase the equipment, primarily in the fourth quarter of 2006. Our proceeds from asset sales in 2007 included $43.5 million related to the sale of the Ben Creek complex and $26.0 million from the sale of non-core reserves in the Powder River Basin and Central Appalachia.
 
Cash used in investing activities in 2006 was $396.5 million higher than in 2005, due to increased capital expenditures and the purchase of equity-method investments, as well as a decrease of $116.3 million in proceeds from dispositions of property, plant and equipment. In 2006, we made the second of five annual payments of $122.2 million on the Powder River Basin’s Little Thunder federal coal lease, which will continue through 2009. Costs related to the development of the Mountain Laurel complex in West Virginia, higher spending at our


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Powder River Basin operations related to the restart of the Coal Creek mining complex and progress payments related to the purchase of a replacement longwall at our Sufco mining complex resulted in an increase in capital expenditures in 2006 compared to 2005. We also spent $40.0 million during 2006 to acquire equity interests in other companies that will be accounted for on the equity method.
 
We anticipate that capital expenditures during 2008 will range from approximately $445 million to $505 million, including reserve additions of approximately $135 million to $165 million. Reserve additions in 2008 will include the fourth of five payments of $122.2 million for the Little Thunder coal lease. The 2008 estimate also includes capital expenditures related to development work at certain of our mining operations, including the development of a new seam, with a new longwall, at the West Elk mining complex and continuing work on the new loadout at Black Thunder. We anticipate that we will fund these capital expenditures with available cash, cash generated from operations and existing credit facilities.
 
Cash provided by financing activities decreased $25.2 million in 2007 compared to 2006. The decrease results primarily from a decrease in borrowings on the revolving credit facility and other lines of credit, including those under the accounts receivable securitization and commercial paper programs, offset by a decrease in shares we repurchased during 2007 when compared with 2006. We had available borrowing capacity of approximately $640.0 million under our lines of credit at December 31, 2007. We spent $43.9 million during 2006 under a share repurchase program authorized by the board of directors in September 2006. The program, which replaces a program adopted in 2001, provides for the purchase of up to 14.0 million shares of common stock. We increased our dividend rate in April 2006 and 2007 and as a result, dividends paid increased $7.1 million.
 
Cash provided by financing activities in 2006 was $121.9 million compared to a use of cash of $25.7 million in 2005. The increase results primarily from borrowings on the revolving credit facility and other credit facilities, including those under the accounts receivable securitization program discussed below, of $192.3 million, compared to net payments of $25.0 million during 2005. The increase in borrowings was to fund our higher capital expenditures, including the Little Thunder federal coal lease noted above. Financing activities in 2006 also included cash received of $7.0 million from the issuance of common stock under our employee stock incentive plans, a decrease of $24.9 million from 2005. We also spent $43.9 million during 2006 under the share repurchase program.
 
At December 31, 2007, debt amounted to $1,303.2 million, or 46% of capital employed, compared to $1,173.8 million, or 46% of capital employed, at December 31, 2006. Based on the level of consolidated indebtedness and prevailing interest rates at December 31, 2007, debt service obligations for 2008, which include the maturities of principal and interest payments, are estimated to be $284.4 million.
 
On August 15, 2007, we entered into a commercial paper placement program to provide short-term financing at rates that are generally lower than the rates available under our revolving credit facility. Under the program, as amended, we may sell up to $75.0 million in interest-bearing or discounted short-term unsecured debt obligations with maturities of no more than 270 days. The commercial paper placement program is supported by an unsecured $75.0 million revolving credit facility with a maturity date of June 7, 2008. As of December 31, 2007, we had $75.0 million outstanding under the agreement with a weighted-average interest rate of 5.08% and maturity dates ranging from two to 81 days.
 
Our revolving credit facility allows for up to $800.0 million of borrowings and matures June 23, 2011. We had borrowings outstanding under the revolving credit facility of approximately $160.0 million December 31, 2007 and $103.0 million at December 31, 2006. Borrowings under the credit facility bear interest at a floating rate based on LIBOR determined by reference to our leverage ratio, as calculated in accordance with the credit agreement, as amended. The weighted average interest rate of borrowings outstanding at December 31, 2007 was 6.30%.
 
Our revolving 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 Resources, LLC and its subsidiaries. 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


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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, 2007.
 
We have a receivable securitization program of $150.0 million. Under the terms of the program, eligible trade receivables consist of trade receivables generated by our operating subsidiaries. Outstanding borrowings under the program were approximately $90.8 million at December 31, 2007 and $89.2 million at December 31, 2006. Although the participants in the program bear the risk of non-payment of purchased receivables, we have agreed to indemnify the participants with respect to various matters. The participants under the program will be entitled to receive payments reflecting a specified discount on amounts funded under the program, including drawings under letters of credit, calculated on the basis of the base rate or commercial paper rate, as applicable. We will pay facility fees, program fees and letter of credit fees (based on amounts of outstanding letters of credit) at rates that vary with our leverage ratio. The average cost of borrowing under the securitization program was approximately 5.79% at December 31, 2007. Under the program, we are subject to certain affirmative, negative and financial covenants customary for financings of this type, including restrictions related to, among other things, liens, payments, merger or consolidation and amendments to the agreements underlying the receivables pool. The administrator may terminate the program upon the occurrence of certain events that are customary for facilities of this type (with customary grace periods, if applicable), including, among other things, breaches of covenants, inaccuracies of representations and warranties, bankruptcy and insolvency events, changes in the rate of default or delinquency of the receivables above specified levels, a change of control and material judgments. A termination event would permit the administrator to terminate the program and enforce any and all rights, subject to cure provisions, where applicable. Additionally, the program contains cross-default provisions, which would allow the administrator to terminate the program in the event of non-payment of other material indebtedness when due and any other event which results in the acceleration of the maturity of material indebtedness.
 
We filed a shelf registration statement on Form S-3 with the SEC on March 14, 2006 that allows us to offer and sell from time to time an unlimited amount of unsecured debt securities consisting of notes, debentures, and other debt securities, common stock, preferred stock, warrants, and/or units. Related proceeds could be used for general corporate purposes, including repayment of other debt, capital expenditures, possible acquisitions and any other purposes that may be stated in any prospectus supplement.
 
Ratio of Earnings to Fixed Charges
 
The following table sets forth our ratios of earnings to combined fixed charges and preference dividends for the periods indicated:
 
                                         
    Year Ended December 31  
    2007     2006     2005     2004     2003  
 
Ratio of earnings to combined fixed charges and preference dividends(1)
    2.40 x     3.93 x     N/A       2.57 x     1.14x  
 
 
(1) Earnings consist of income (loss) from continuing operations before income taxes and are adjusted to include only distributed income from affiliates accounted for on the equity method and fixed charges (excluding capitalized interest). Fixed charges consist of interest incurred on indebtedness, the portion of operating lease rentals deemed representative of the interest factor and the amortization of debt expense. Combined fixed charges and preference dividends exceeded earnings by $13.1 million for the year ended December 31, 2005.


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Contractual Obligations
 
The following is a summary of our significant contractual obligations as of December 31, 2007:
 
                                         
    Payments Due by Period  
    2008     2009-2010     2011-2012     After 2012     Total  
    (Amounts in thousands)  
 
Long-term debt, including related interest
  $ 284,355     $ 132,750     $ 251,966     $ 982,063     $ 1,651,134  
Operating leases
    30,612       57,472       41,838       43,981       173,903  
Coal lease rights
    145,802       179,083       36,052       18,833       379,770  
Coal purchase obligations
    313,712       200,313       102,566       296,887       913,478  
Unconditional purchase obligations
    236,978       10,376                   247,354  
                                         
Total contractual obligations
  $ 1,011,459     $ 579,994     $ 432,422     $ 1,341,764     $ 3,365,639  
                                         
 
Interest on long-term debt was calculated using rates in effect at December 31, 2007 for the remaining term of outstanding borrowings.
 
Coal lease rights represent non-cancelable royalty lease agreements, as well as federal lease bonus payments due. In particular, remaining payments due under the Little Thunder lease in Wyoming will be paid in two equal annual installments of $122.2 million in 2008 and 2009.
 
Our coal purchase obligations include purchase obligations in the over-the-counter market, as well as unconditional purchase obligations with coal suppliers. Additionally, they include coal purchase obligations incurred with the sale of certain Central Appalachia operations in 2005 and the sale of the Mingo Logan-Ben Creek complex in 2007 to supply ongoing customer sales commitments.
 
Unconditional purchase obligations include open purchase orders, which have not been recognized as a liability. The commitments in the table above relate to commitments for the purchase of materials and supplies, payments for services and capital expenditures.
 
The table above excludes our asset retirement obligations. Our consolidated balance sheet reflects a liability of $224.5 million for the fair value of asset retirement obligations that arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The determination of the fair value of asset retirement obligations involves a number of estimates, as discussed in the section entitled “Critical Accounting Policies” beginning on page 52, including the timing of payments to satisfy asset retirement obligations. The timing of payments to satisfy asset retirement obligations is based on numerous factors, including mine closure dates. You should see the notes to our consolidated financial statements for more information about our asset retirement obligations.
 
The table above also excludes certain other obligations reflected in our consolidated balance sheet, including estimated funding for pension and postretirement benefit obligations, for which the timing of payments may vary based on changes in the fair value of plan assets (for pension obligations) and actuarial assumptions and payments under our self-insured workers’ compensation program. You should see the section entitled “Critical Accounting Policies” beginning on page 52 for more information about these assumptions. We expect to make contributions of $2.5 million to our pension plans in 2008. You should see the notes to our consolidated financial statements for more information about the amounts we have recorded for workers’ compensation and pension and postretirement benefit obligations.
 
Off-Balance Sheet Arrangements
 
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in


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our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
 
We use a combination of surety bonds, corporate guarantees (e.g., self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, coal lease obligations and other obligations as follows as of December 31, 2007:
 
                                         
                Workers’
             
    Reclamation
    Lease
    Compensation
             
    Obligations     Obligations     Obligations     Other     Total  
    (Amounts in thousands)  
 
Self bonding
  $ 306,385     $     $     $     $ 306,385  
Surety bonds
    262,995       45,239       14,600       15,507       338,341  
Letters of credit
                46,352       12,261       58,613  
 
We have agreed to continue to provide surety bonds and letters of credit for the reclamation and retiree healthcare obligations of the properties we sold to Magnum in order to facilitate an orderly transition. Magnum is required to reimburse us for costs related to the surety bonds and letters of credit until it can replace these items. If the surety bonds and letters of credit related to the reclamation obligations are not replaced by Magnum within a specified period of time, then Magnum must post a letter of credit in our favor in the amount of the obligations. At December 31, 2007, we had $92.0 million of surety bonds related to properties sold to Magnum, which are included in the table.
 
Magnum also acquired certain coal supply contracts with customers who have not consented to the assignment of the contract to Magnum. We have committed to purchase coal from Magnum to sell to those customers at the same price we are charging the customers for the sale. In addition, certain contracts have been assigned to Magnum, but we have guaranteed Magnum’s performance under the contracts. The longest of the coal supply contracts extends to the year 2017. If Magnum is unable to supply the coal for these coal sales contracts then we would be required to purchase coal on the open market or supply contracts from our existing operations. At market prices effective at December 31, 2007, the cost of purchasing 15.4 million tons of coal to supply the contracts that have not been assigned over their duration would exceed the sales price under the contracts by approximately $265.7 million, and the cost of purchasing 5.0 million tons of coal to supply the assigned and guaranteed contracts over their duration would exceed the sales price under the contracts by approximately $97.4 million. We have also guaranteed Magnum’s performance under certain operating leases, the longest of which extends through 2011. If we were required to perform under our guarantees of the operating lease agreements, we would be required to make $10.3 million of lease payments. We do not believe that it is probable that we would have to purchase replacement coal or fulfill our obligations under the lease guarantees and therefore, no liability has been recorded for these potential losses as of December 31, 2007. However, if we would have to perform under these guarantees, it could potentially have a material adverse effect on our business, results of operations and financial condition.
 
In connection with the acquisition of the coal operations of Atlantic Richfield Company, which we refer to as ARCO, and the simultaneous combination of the acquired ARCO operations and our Wyoming operations into the Arch Western joint venture, we agreed to indemnify the other member of Arch Western against certain tax liabilities in the event that such liabilities arise prior to June 1, 2013 as a result of certain actions taken, 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. If we were to become liable, the maximum amount of potential future tax payments was $61.0 million at December 31, 2007, of which none is recorded as a liability in our financial statements. Since the indemnification is dependent upon the initiation of activities within our control and we do not intend to initiate such activities, it is remote that we will become liable for any obligation related to this indemnification. However, if such indemnification obligation were to arise, it could potentially have a material adverse effect on our business, results of operations and financial condition.
 
In addition, tax reporting applied to this transaction by the other member of Arch Western was audited by the Internal Revenue Service, which we refer to as the IRS. We do not believe that we are bound by the outcome


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of this audit. We have begun negotiations with the IRS as to adjustments, if any, of Arch Western’s tax reporting. The outcome of these negotiations when settled could result in adjustments to the basis of the partnership assets, and it is possible we may be required to adjust our deferred income taxes associated with our investment in Arch Western. The outcome of the negotiations is uncertain, however, any change that impacts us related to an IRS negotiation may result in a non-cash decrease in deferred income tax assets that could fall within a range of zero to $25.0 million.
 
Critical Accounting Policies
 
We prepare our financial statements 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 our 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. We have provided a description of all significant accounting policies in the notes to our consolidated financial statements. 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 SMCRA 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. Our asset retirement obligations are initially recorded at fair value, or the amount at which the obligations could be settled in a current transaction between willing parties. This involves determining the present value of estimated future cash flows on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage and reclamation costs and assumptions regarding productivity. We estimate disturbed acreage based on approved mining plans and related engineering data. Since we plan to use internal resources to perform the majority of our reclamation activities, our estimate of reclamation costs involves estimating third-party profit margins, which we base on our historical experience with contractors that perform certain types of reclamation activities. We base productivity assumptions on historical experience with the equipment that we expect to utilize in the reclamation activities. In order to determine fair value, we must also discount our estimates of cash flows to their present value. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
 
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the actual cost of reclamation and the fair value will be recorded as a gain or loss when the obligation is settled. We expect our actual cost to reclaim our properties will be less than the expected cash flows used to determine the asset retirement obligation. At December 31, 2007, we had recorded asset retirement obligation liabilities of $224.5 million, including amounts classified as a current liability. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2007, we estimate that the aggregate undiscounted cost of final mine closure is approximately $538.0 million.
 
Stock-Based Compensation
 
As of January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, which we refer to as Statement No. 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. We adopted Statement No. 123R using the modified-prospective method. Under this method, compensation cost for share-based payments to employees is based on their grant-date fair value from the


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beginning of the fiscal period in which the recognition provisions are first applied. Measurement and recognition of compensation cost for awards that were granted prior to, but not vested as of, the date Statement No. 123R was adopted are based on the same estimate of the grant-date fair value and the same recognition method used previously under Statement No. 123. We use the Black-Scholes option pricing model for options and a lattice model at the grant date for the portion of share-based payments with performance and market conditions that is paid out in stock to determine the fair value.
 
Derivative Financial Instruments
 
We use derivative financial instruments to manage exposures to commodity prices and interest rates. We also enter into over-the-counter coal positions for trading purposes. All derivative financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or other comprehensive income if they qualify for cash flow hedge accounting. Amounts in other comprehensive income are reclassified to earnings when the hedged transaction affects earnings. Any ineffective portion of a cash flow hedge’s change in fair value is recognized immediately in earnings. The amount of ineffectiveness recognized in other operating (income) expense, net relating to our heating oil derivatives was a gain of $1.4 million for the year ended December 31, 2007. Ineffectiveness was insignificant for the year ended December 31, 2006.
 
We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking various hedge transactions. We evaluate the effectiveness of our hedging relationships both at the hedge inception and on an ongoing basis.
 
Employee Benefit Plans
 
We have non-contributory defined benefit pension plans covering certain of our salaried and 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. We contributed $2.7 million in cash to the plans during the year ended December 31, 2007 and $19.3 million in cash and stock to the plans during the year ended December 31, 2006. We account for our defined benefit plans in accordance with Statement of Financial Accounting Standards No. 87, Employer’s Accounting for Pensions, as amended by Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, which we refer to as Statement No. 87 and Statement No. 158. Statement No. 158 requires that the actuarially-determined funded status of the plans be recorded in the balance sheet.
 
In June 2006, the disposition of certain Central Appalachia operations in 2005 resulted in withdrawals that constituted a settlement of our pension benefit obligation for which we recognized expense of $3.2 million.
 
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% for 2007 and 8.25% for 2006. These long-term rate of return assumptions are less than the plan’s actual life-to-date returns. Any difference between the actual experience and the assumed experience is recorded in other comprehensive income and amortized into earnings in the future. The impact of lowering the expected long-term rate of


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  return on plan assets 0.5% for 2007 would have been an increase in expense of approximately $1.0 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 debt instruments. We utilize a bond portfolio model that includes bonds that are rated “AA” or higher with maturities that match the expected benefit payments under the plan. The discount rate used to determine pension expense was 5.9% for 2007 and 5.8% for the first six months of 2006 and 6.4% for the last six months of 2006, as a result of a remeasurement of the plan obligation related to the settlement event discussed above. The impact of lowering the discount rate 0.5% for 2007 would have been an increase in expense of approximately $2.4 million.
 
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 2007 (and pension expense for 2008), we changed our discount rate to 6.5%.
 
We also currently provide certain postretirement medical and 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 benefit 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 insurance benefits as they are paid. We account for our other postretirement benefits in accordance with Statement of Financial Accounting Standards No. 106, Employer’s Accounting for Postretirement Benefits Other Than Pensions, as amended by Statement No. 158. Statement No. 158 requires that the actuarially-determined funded status of the plans be recorded in the balance sheet.
 
In 2005, the disposition of the Central Appalachia operations to Magnum constituted a settlement of our postretirement benefit obligation for which we recognized a loss of $59.2 million.
 
Actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. 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 was 5.9% for 2007 and 5.8% for 2006. Had the discount rate been lowered by 0.5% in 2007, we would have incurred additional expense of $0.6 million.
 
For the measurement of our year-end other postretirement obligation for 2007 and postretirement expense for 2008, we changed our discount rate to 6.5%. During 2007, the postretirement benefit plans were amended to improve benefits to participants. As a result of the amendment, annual retiree contribution increases have been limited so as not to exceed 25% of the previous year’s total contribution. Prior to the amendment, all medical cost increases were passed on to the retirees and had no impact on the plan.
 
Income Taxes
 
We provide for deferred income taxes for temporary differences arising from differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance may be 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 expected future taxable income and available tax planning strategies. If future taxable income is lower than expected or if expected tax planning


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strategies are not available as anticipated, we may record additional valuation allowance through income tax expense in the period such determination is made.
 
As of January 1, 2007, we adopted Interpretation No. 48, Accounting for Uncertainty in Income Taxes, which we refer to as FIN 48. FIN 48 prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Upon adoption of FIN 48, we increased our liability for unrecognized tax benefits by $1.0 million, including interest and penalties of $0.2 million, which was recorded as a reduction of the beginning balance of retained earnings.
 
Accounting Standards Issued and Not Yet Adopted
 
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, which we refer to as Statement No. 157. Statement No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Statement No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Statement No. 157 is effective prospectively for fiscal years beginning after November 15, 2007, and interim periods within that fiscal year. We do not expect the impact of adoption will be material.
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
 
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.
 
We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, and to a limited extent, through the use of derivative instruments. At December 31, 2007, our expected unpriced production approximated 15 million to 25 million tons in 2008, 85 million to 95 million tons in 2009 and 95 million to 105 million tons in 2010.
 
We are exposed to commodity price risk in our trading of coal, which represents the potential loss that could be caused by an adverse change in the market value of coal. Our coal trading portfolio included forward and option contracts at December 31, 2007. We had no positions entered into for trading purposes as of December 31, 2006. With respect to our coal trading positions, a $0.50 decrease in Powder River Basin coal prices and a $2 decrease in Central Appalachia coal prices would cause a $2.9 million decrease in the fair value of these positions. The timing of the estimated future realization of the value of our trading portfolio is 30% in 2008, 68% in 2009 and 2% in 2010.
 
We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. We use approximately 45 million gallons of diesel fuel annually in our operations. We enter into forward physical purchase contracts and heating oil swaps and options to reduce volatility in the price of diesel fuel for our operations, and in doing so had protected approximately 23% of our forecasted purchases for 2008 at December 31, 2007. At December 31, 2006, we had protected approximately 68% of our forecasted purchases for 2007. 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 call options protect against increases in diesel fuel by granting us the right to participate in increases in heating oil prices. The changes in the floating heating oil price highly correlate to changes in diesel fuel prices. Accordingly, the derivatives qualify for hedge accounting and the changes in the fair value of the derivatives are recorded through other comprehensive income. At December 31, 2007, a $0.25 per gallon decrease in the price of heating oil would result in a $2.2 million increase in our expense in 2008 resulting from heating oil derivatives, which would be offset by a decrease in the cost of our physical diesel purchases.
 
We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2007, $977.4 million of our outstanding debt had fixed interest rates, primarily our 6.75% Senior Notes, and $325.8 million of outstanding borrowings had interest rates that fluctuated based on changes in the respective market rates. A one percentage point increase in the interest rates related to these borrowings would


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result in an annualized increase in interest expense of $3.3 million, based on borrowing levels at December 31, 2007.
 
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
The consolidated financial statements and consolidated financial statement schedule of Arch Coal, Inc. and subsidiaries are included in this Annual Report on Form 10-K beginning on page F-1.
 
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
 
None.
 
ITEM 9A. CONTROLS AND PROCEDURES.
 
We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2007. Based on that evaluation, our management, including our chief executive officer and chief financial officer, 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, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
We incorporate by reference the report of independent registered public accounting firm and management’s report on internal control over financial reporting included on pages F-2 and F-4, respectively, of this Annual Report on Form 10-K.
 
ITEM 9B.  OTHER INFORMATION.
 
None.
 
PART III
 
ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
 
We incorporate by reference the information under the headings “Code of Conduct,” “Director Biographies” and “Board Meetings and Committees” appearing in the section entitled “Corporate Governance Practices” and the information appearing in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our proxy statement to be distributed to stockholders in connection with the 2008 annual meeting.
 
ITEM 11.  EXECUTIVE COMPENSATION.
 
We incorporate by reference the information under the headings “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan-Based Awards for the Year Ended December 31, 2007,” “Outstanding Equity Awards at December 31, 2007,” “Option Exercises and Stock Vested for the Year Ended December 31, 2007,” “Pension Benefits,” “Nonqualified Deferred Compensation,” “Potential Payments Upon Termination of Employment or Change-in-Control” and “Director Compensation for the Year Ended December 31, 2007” appearing in the section entitled “Executive and Director Compensation” in our proxy statement to be distributed to stockholders in connection with the 2008 annual meeting.
 
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
 
We incorporate by reference the information appearing under the sections entitled “Security Ownership of Directors and Executive Officers” and “Security Ownership of Certain Beneficial Owners” in our proxy statement to be distributed to stockholders in connection with the 2008 annual meeting.


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Securities Authorized for Issuance Under Equity Compensation Plans
 
The Arch Coal, Inc. 1997 Stock Incentive Plan, which has been approved by our stockholders, is the sole plan under which we are authorized to issue shares of our common stock to employees. The following table shows the number of shares of common stock to be issued upon exercise of options outstanding at December 31, 2007, the weighted average exercise price of those options, and the number of shares of common stock remaining available for future issuance at December 31, 2007, excluding shares to be issued upon exercise of outstanding options. No warrants or rights had been issued under the plan as of December 31, 2007.
 
                         
                Number of
 
                Securities Remaining
 
    Number of
          Available for
 
    Securities to
          Future Issuance
 
    be Issued
    Weighted-Average Exercise
    Under Equity
 
    Upon Exercise
    Price of
    Compensation Plans
 
    of Outstanding
    Outstanding Options,
    (Excluding Securities
 
    Options, Warrants
    Warrants
    to be Issued
 
Plan Category
  and Rights     and Rights     Upon Exercise)  
 
Equity compensation plans approved by security holders
    2,849,963     $ 18.19       3,943,297  
Equity compensation plans not approved by security holders
                 
                         
Total
    2,849,963     $ 18.19       3,943,297  
                         
 
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
 
We incorporate by reference the information under the headings “Overview” and “Director Independence” appearing in the section entitled “Corporate Governance Practices” in our proxy statement to be distributed to stockholders in connection with the 2008 annual meeting.
 
ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES.
 
We incorporate by reference the information in the section entitled “Ratification of the Appointment of Independent Public Accounting Firm” in our proxy statement to be distributed to stockholders in connection with the 2008 annual meeting.
 
PART IV
 
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
The consolidated financial statements and consolidated financial statement schedule of Arch Coal, Inc. and subsidiaries are included in this Annual Report on Form 10-K beginning on page F-1.
 
You should see the exhibit index for a list of exhibits included in this Annual Report on Form 10-K.


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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
The consolidated financial statements of Arch Coal, Inc. and subsidiaries and reports of independent registered public accounting firm follow.
 
Index to Consolidated Financial Statements
 
         
    F-2  
    F-4  
    F-5  
    F-6  
    F-7  
    F-8  
    F-9  
Financial Statement Schedule
    F-39  


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Table of Contents

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Stockholders of Arch Coal, Inc.
 
We have audited Arch Coal, Inc’s internal control over financial reporting as of December 31, 2007, 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 included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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, Arch Coal, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 of Arch Coal, Inc. and our report dated February 28, 2008, expressed an unqualified opinion thereon.
 
Ernst <DATA,ampersand> Young LLP
 
St. Louis, Missouri
February 28, 2008


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Stockholders of Arch Coal, Inc.
 
We have audited the accompanying consolidated balance sheets of Arch Coal, Inc. (the Company) as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
 
We conducted our audits 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 the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arch Coal, Inc. at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
 
As discussed in Note 1 to the consolidated financial statements, the Company changed its methods of accounting for share-based payments and for stripping costs effective January 1, 2006. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for pension and other postretirement benefits effective December 31, 2006. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for uncertainty in income taxes effective January 1, 2007.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Arch Coal, Inc.’s internal control over financial reporting as of December 31, 2007, 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 28, 2008, expressed an unqualified opinion thereon.
 
 
-s- Ernst <DATA,ampersand> Young
    LLP
St. Louis, Missouri
February 28, 2008


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REPORT OF MANAGEMENT
 
The management of Arch Coal, Inc. (the “Company”) 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, comprised of independent directors, 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.
 
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 
The management of Arch Coal, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Securities Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company’s management, including its principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of its 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 its evaluation, management concluded that the Company’s internal control over financial reporting is effective as of December 31, 2007.
 
The Company’s independent registered public accounting firm, Ernst & Young LLP, has issued an audit report on the Company’s internal control over financial reporting.
 
     
-s- Steven F. Leer
Steven F. Leer
Chairman and Chief
Executive Officer
  -s- Robert J. Messey
Robert J. Messey
Senior Vice President and Chief
Financial Officer


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CONSOLIDATED STATEMENTS OF INCOME
 
                         
    Year Ended December 31  
    2007     2006     2005  
    (In thousands, except per share data)  
 
REVENUES
                       
Coal sales
  $ 2,413,644     $ 2,500,431     $ 2,508,773  
COSTS, EXPENSES AND OTHER
                       
Cost of coal sales
    1,888,285       1,909,822       2,174,007  
Depreciation, depletion and amortization
    242,062       208,354       212,301  
Selling, general and administrative expenses
    84,446       75,388       91,568  
Other operating (income) expense:
                       
Gain on sale of Powder River Basin assets
                (46,547 )
Gain on sale of Central Appalachian operations
                (7,528 )
Other operating (income) expense, net
    (30,766 )     (29,800 )     7,115  
                         
      2,184,027       2,163,764       2,430,916  
                         
Income from operations
    229,617       336,667       77,857  
Interest expense, net:
                       
Interest expense
    (74,865 )     (64,364 )     (72,409 )
Interest income
    2,600       3,725       9,289  
                         
      (72,265 )     (60,639 )     (63,120 )
Other non-operating expense:
                       
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps
    (1,919 )     (4,836 )     (7,740 )
Other non-operating expense
    (354 )     (2,611 )     (3,524 )
                         
      (2,273 )     (7,447 )     (11,264 )
                         
Income before income taxes
    155,079       268,581       3,473  
Provision for (benefit from) income taxes
    (19,850 )     7,650       (34,650 )
                         
NET INCOME
    174,929       260,931       38,123  
Preferred stock dividends
    (219 )     (378 )     (15,579 )
                         
Net income available to common stockholders
  $ 174,710     $ 260,553     $ 22,544  
                         
EARNINGS PER COMMON SHARE
                       
Basic earnings per common share
  $ 1.23     $ 1.83     $ 0.18  
                         
Diluted earnings per common share
  $ 1.21     $ 1.80     $ 0.17  
                         
Basic weighted average shares outstanding
    142,518       142,770       127,304  
                         
Diluted weighted average shares outstanding
    144,019       144,812       129,940  
                         
Dividends declared per common share
  $ 0.27     $ 0.22     $ 0.16  
                         
 
The accompanying notes are an integral part of the consolidated financial statements.


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CONSOLIDATED BALANCE SHEETS
 
                 
    December 31  
    2007     2006  
    (In thousands, except per share data)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 5,080     $ 2,523  
Trade accounts receivable
    229,965       212,185  
Other receivables
    19,724       48,588  
Inventories
    177,785       129,826  
Prepaid royalties
    22,055       6,743  
Deferred income taxes
    18,789       51,802  
Other
    47,747       35,610  
                 
Total current assets
    521,145       487,277  
Property, plant and equipment:
               
Coal lands and mineral rights
    1,690,176       1,587,303  
Plant and equipment
    1,729,501       1,626,984  
Deferred mine development
    672,496       550,385  
                 
      4,092,173       3,764,672  
Less accumulated depreciation, depletion and amortization
    (1,628,535 )     (1,521,604 )
                 
Property, plant and equipment, net
    2,463,638       2,243,068  
Other assets:
               
Prepaid royalties
    105,106       112,667  
Goodwill
    40,032       40,032  
Deferred income taxes
    296,559       263,759  
Equity investments
    82,950       80,213  
Other
    85,169       93,798  
                 
Total other assets
    609,816       590,469  
                 
Total assets
  $ 3,594,599     $ 3,320,814  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 150,026     $ 198,875  
Accrued expenses
    188,875       190,746  
Current maturities of debt and short-term borrowings
    217,614       51,185  
                 
Total current liabilities
    556,515       440,806  
                 
Long-term debt
    1,085,579       1,122,595  
Accrued postretirement benefits other than pension
    59,181       49,817  
Asset retirement obligations
    219,991       205,530  
Accrued workers’ compensation
    41,071       43,655  
Other noncurrent liabilities
    100,576       92,817  
                 
Total liabilities
    2,062,913       1,955,220  
Stockholders’ equity:
               
Preferred stock, $0.01 par value, 10,000 shares authorized; issued and outstanding shares 85 and 144, at December 31, 2007 and 2006, respectively; $50 liquidation preference
    1       2  
Common stock, $0.01 par value, authorized 260,000 shares, issued 143,158 and 142,179 shares, respectively
    1,436       1,426  
Paid-in capital
    1,358,695       1,345,188  
Retained earnings
    173,186       38,147  
Accumulated other comprehensive loss
    (1,632 )     (19,169 )
                 
Total stockholders’ equity
    1,531,686       1,365,594  
                 
Total liabilities and stockholders’ equity
  $ 3,594,599     $ 3,320,814  
                 
 
The accompanying notes are an integral part of the consolidated financial statements.


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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Three Years Ended December 31, 2007
 
                                                                 
                                        Accumulated
       
                      Retained
          Treasury
    Other
       
    Preferred
    Common
    Paid-In
    Earnings
    Unearned
    Stock at
    Comprehensive
       
    Stock     Stock     Capital     (Deficit)     Compensation     Cost     Loss     Total  
    (In thousands, except per share data)  
 
BALANCE AT January 1, 2005
  $ 29     $ 631     $ 1,280,513     $ (166,273 )   $ (1,830 )   $ (5,047 )   $ (28,197 )   $ 1,079,826  
Comprehensive income:
                                                               
Net income
                            38,123                               38,123  
Minimum pension liability adjustment
                                                    (2,751 )     (2,751 )
Unrealized gains on available-for-sale securities
                                                    8,498       8,498  
Unrealized gains on derivatives
                                                    22,646       22,646  
Net amount reclassified to income
                                                    (8,828 )     (8,828 )
                                                                 
Total comprehensive income
                                                            57,688  
Dividends:
                                                               
Common ($0.16 per share)
                            (20,452 )                             (20,452 )
Preferred ($2.50 per share)
                            (6,053 )                             (6,053 )
Preferred stock conversion
    (27 )     66       9,487       (9,526 )                              
Issuance of 546 shares of treasury stock as contribution to pension plan
            3       12,872                       3,857               16,732  
Issuance of 3,038 shares of common stock under the stock incentive plan — stock options, including income tax benefits
            15       43,564                                       43,579  
Employee stock-based compensation expense
                    140               12,781                       12,921  
Issuance of 680 shares of common stock under the stock incentive plans
            4       20,894               (20,898 )                      
                                                                 
BALANCE AT DECEMBER 31, 2005
    2       719       1,367,470       (164,181 )     (9,947 )     (1,190 )     (8,632 )     1,184,241  
Comprehensive income:
                                                               
Net income
                            260,931                               260,931  
Minimum pension liability adjustment
                                                    14,941       14,941  
Unrealized losses on available-for- sale securities
                                                    (8,834 )     (8,834 )
Unrealized losses on derivatives
                                                    (14,384 )     (14,384 )
Net amount reclassified to income
                                                    9,689       9,689  
                                                                 
Total comprehensive income
                                                            262,343  
Dividends:
                                                               
Common ($0.22 per share)
                            (31,448 )                             (31,448 )
Preferred ($2.50 per share)
                            (378 )                             (378 )
Contribution of 168 shares of treasury stock and 182 shares of common stock to pension plan
            3       15,407                       1,190               16,600  
Issuance of 127 shares of common stock under the stock incentive plan — restricted stock and restricted stock units
                                                         
Issuance of 30 shares of common stock upon conversion of preferred stock
                                                       
Effect of two for one stock split
            716               (716 )                              
Issuance of 661 shares of common stock under the stock incentive plan — stock options
            4       7,039                                       7,043  
Employee stock-based compensation expense
                    9,080                                       9,080  
Purchase of 1,562 shares of common stock under stock repurchase program
                                            (43,877 )             (43,877 )
Retirement of treasury stock
            (16 )     (43,861 )                     43,877                
Effect of adoption of EITF 04-6
                            (26,061 )                             (26,061 )
Effect of adoption of Statement No. 158
                                                    (11,949 )     (11,949 )
Effect of adoption of Statement No. 123R
                    (9,947 )             9,947                        
                                                                 
BALANCE AT DECEMBER 31, 2006
    2       1,426       1,345,188       38,147                   (19,169 )     1,365,594  
Comprehensive income:
                                                               
Net income
                            174,929                               174,929  
Pension, postretirement and other post-employment benefits
                                                    11,070       11,070  
Net amount reclassified to income
                                                    2,490       2,490  
Unrealized losses on available-for- sale securities
                                                    (2,815 )     (2,815 )
Unrealized gains on derivatives
                                                    1,584       1,584  
Net amount reclassified to income
                                                    5,208       5,208  
                                                                 
Total comprehensive income
                                                            192,466  
Dividends:
                                                               
Common ($0.27 per share)
                            (38,696 )                             (38,696 )
Preferred ($2.50 per share)
                            (219 )                             (219 )
Issuance of 186 shares of common stock under the stock incentive plan — restricted stock and restricted stock units
            2       (2 )                                      
Issuance of 283 shares of common stock upon conversion of preferred stock
    (1 )     3       (2 )                                      
Issuance of 510 shares of common stock under the stock incentive plan — stock options including income tax benefits
            5       7,734                                       7,739  
Employee stock-based compensation expense
                    5,777                                       5,777  
Effect of adoption of FIN 48
                            (975 )                             (975 )
                                                                 
BALANCE AT DECEMBER 31, 2007
  $ 1     $ 1,436     $ 1,358,695     $ 173,186     $     $     $ (1,632 )   $ 1,531,686  
                                                                 
 
The accompanying notes are an integral part of the consolidated financial statements.


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CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31  
    2007     2006     2005  
    (In thousands)  
 
OPERATING ACTIVITIES
                       
Net income
  $ 174,929     $ 260,931     $ 38,123  
Adjustments to reconcile net income to cash provided by operating activities:
                       
Depreciation, depletion and amortization
    242,062       208,354       212,301  
Prepaid royalties expensed
    11,962       9,045       14,252  
Net (gain) loss on dispositions of property, plant and equipment
    (17,769 )     649       (82,168 )
Gain on investment in Knight Hawk Holdings, LLC
          (10,309 )      
Employee stock-based compensation
    5,777       9,080       12,937  
Other non-operating expense
    2,273       7,447       11,264  
Changes in operating assets and liabilities:
                       
Receivables
    10,254       (49,265 )     (48,432 )
Inventories
    (55,471 )     (39,783 )     (38,368 )
Accounts payable and accrued expenses
    (59,634 )     (115,123 )     108,536  
Income taxes
    (31,825 )     20,505       (33,513 )
Accrued postretirement benefits other than pension
    3,733       8,662       28,660  
Asset retirement obligations
    21,609       10,967       6,498  
Accrued workers’ compensation
    971       (2,898 )     (9,705 )
Other
                14,701  
Other
    21,939       (10,160 )     19,521  
                         
Cash provided by operating activities
    330,810       308,102       254,607  
INVESTING ACTIVITIES
                       
Capital expenditures
    (488,363 )     (623,187 )     (357,142 )
Proceeds from dispositions of property, plant and equipment
    70,296       777       117,048  
Additions to prepaid royalties
    (19,713 )     (20,062 )     (28,164 )
Purchases of investments/advances to affiliates
    (5,540 )     (45,533 )     (23,285 )
Reimbursement of deposit on equipment
    18,325              
                         
Cash used in investing activities
    (424,995 )     (688,005 )     (291,543 )
FINANCING ACTIVITIES
                       
Net proceeds from commercial paper and net borrowings on lines of credit
    133,476       192,300       (25,000 )
Net proceeds from (payments on) other debt
    (2,696 )     442       (2,376 )
Debt financing costs
    (202 )     (2,171 )     (2,662 )
Dividends paid
    (38,945 )     (31,815 )     (27,639 )
Purchases of treasury stock
          (43,876 )      
Issuance of common stock under incentive plans
    5,109       7,045       31,947  
                         
Cash provided by (used in) financing activities
    96,742       121,925       (25,730 )
                         
Increase (decrease) in cash and cash equivalents
    2,557       (257,978 )     (62,666 )
Cash and cash equivalents, beginning of year
    2,523       260,501       323,167  
                         
Cash and cash equivalents, end of year
  $ 5,080     $ 2,523     $ 260,501  
                         
SUPPLEMENTAL CASH FLOW INFORMATION:
                       
Cash paid during the year for interest
  $ 69,866     $ 59,116     $ 69,839  
Cash received during the year for income taxes
  $ (2,145 )   $ (8,921 )   $ (5,518 )
 
The accompanying notes are an integral part of the consolidated financial statements.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.   Accounting Policies
 
Basis of Presentation
 
The consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries and controlled entities (the “Company”). The Company’s primary business is the production of steam and metallurgical coal from surface and underground mines located throughout the United States, for sale to utility, industrial and export markets. The Company’s mines are located in southern West Virginia, eastern Kentucky, Virginia, Wyoming, Colorado and Utah. All subsidiaries (except as noted below) are wholly-owned. Intercompany transactions and accounts have been eliminated in consolidation.
 
The Company owns a 99% membership interest in a joint venture named Arch Western Resources, LLC (“Arch Western”) which operates coal mines in Wyoming, Colorado and Utah. The Company also acts as the managing member of Arch Western.
 
On June 29, 2007, the Company sold select assets and related liabilities associated with its Mingo Logan-Ben Creek mining complex in West Virginia. See further discussion in Note 2, “Property Transactions.”
 
On December 31, 2005, the Company entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Magnum Coal Company (“Magnum”). Pursuant to the Purchase Agreement, the Company sold the stock of three of its subsidiaries and their Central Appalachian mining operations. See further discussion in Note 2, “Property Transactions.”
 
Accounting Pronouncements Adopted
 
On January 1, 2007, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). FIN 48 prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under FIN 48, a company can recognize the benefit of an income tax position only if it is more likely than not (greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position.
 
Upon adoption of FIN 48, the Company increased its liability for unrecognized tax benefits by $1.0 million, including interest and penalties of $0.2 million, which was recorded as a reduction of the beginning balance of retained earnings. Total unrecognized tax benefits were $3.2 million at the adoption date, all of which would affect the effective tax rate if recognized. The Company will continue to recognize interest and penalties related to income tax matters in income tax expense.
 
Accounting Estimates
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Cash and Cash Equivalents
 
Cash and cash equivalents are stated at cost. Cash equivalents consist of highly-liquid investments with an original maturity of three months or less when purchased.
 
Allowance for Uncollectible Receivables
 
The Company’s allowance for uncollectible receivables reflects the amounts of its trade accounts receivable and other receivables that are not expected to be collected, based on past collection history, the economic


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
environment and specified risks identified in the receivables portfolio. Receivables are considered past due if the full payment is not received by the contractual due date. The allowance deducted from the balance of receivables was $0.2 million and $3.2 million at December 31, 2007 and 2006, respectively.
 
Inventories
 
Coal and supplies inventories are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs, transportation costs prior to title transfer to customers and operating overhead. Prior to the adoption of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry (“EITF 04-6”), the Company had classified stripping costs associated with the tons of coal uncovered and not yet extracted (pit inventory) at its surface mining operations as coal inventory. As a result of the adoption of EITF 04-6 on January 1, 2006, stripping costs incurred during the production phase of the mine are considered variable production costs and are included in the cost of inventory extracted during the period the stripping costs are incurred. The effect of adopting EITF 04-6 was a reduction of $40.7 million and $2.0 million of inventory and deferred development costs, respectively, with a corresponding decrease to retained earnings, net of tax, of $26.1 million.
 
Investments
 
Investments and ownership interests are accounted for under the equity method of accounting if the Company has the ability to exercise significant influence, but not control, over the entity. The Company reflects its share of the entity’s income in other (income) expense, net in its Consolidated Statements of Income. Marketable equity securities held by the Company that do not qualify for equity method accounting are classified as available-for-sale and are recorded at their fair value on the balance sheet with a corresponding entry to other comprehensive income and deferred taxes.
 
Prepaid Royalties
 
Rights to leased coal lands are often acquired through royalty payments. Where royalty payments represent prepayments recoupable against future production, they are recorded as a prepaid asset, with amounts expected to be recouped within one year classified as current. 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 over the tons of coal shipped during the term of the contract. Value is allocated to coal supply agreements based on discounted cash flows attributable to the difference between the contract price and the prevailing market price at the date of acquisition. The net book value of the Company’s above-market coal supply agreements was $3.5 million and $3.8 million at December 31, 2007 and 2006, respectively. These amounts are recorded in other current assets and other assets in the accompanying Consolidated Balance Sheets. The net book value of the below-market coal supply agreements was $1.3 million and $3.2 million at December 31, 2007 and 2006, respectively. These amounts are recorded in accrued expenses and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. Amortization expense on all above-market coal supply agreements was $0.3 million, $1.0 million and $8.0 million in 2007, 2006 and 2005, respectively. Amortization income on all below-market coal supply agreements was $1.9 million, $11.8 million and $16.0 million in 2007, 2006 and 2005, respectively.
 
Exploration Costs
 
Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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. During the years ended December 31, 2007, 2006 and 2005, interest costs of $18.0 million, $14.8 million and $4.2 million, respectively, were capitalized. Expenditures that extend the useful lives of existing plant and equipment or increase the productivity of the asset are capitalized. The cost of maintenance and repairs that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, which generally 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.
 
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. Costs may include construction permits and licenses; mine design; construction of access roads, shafts, slopes and main entries; and removing overburden to access reserves in a new pit. Additionally, deferred mine development includes the costs associated with asset retirement obligations.
 
Coal Lands and Mineral Rights
 
Amounts paid to acquire the Company’s coal reserves are capitalized and depleted over the life of proven and probable reserves. A significant portion of the Company’s coal reserves are controlled through leasing arrangements. The cost of coal lease rights are depleted 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. The net book value of the Company’s leased coal interests was $1.0 billion and $954.2 million at December 31, 2007 and 2006, respectively.
 
The Company has entered into various non-cancelable royalty lease agreements and federal lease bonus payments under which future minimum payments are due. On September 22, 2004, the Company was the successful bidder in a federal auction of certain mining rights in the 5,084-acre Little Thunder tract in the Powder River Basin of Wyoming. The Company’s lease bonus bid amounted to $611.0 million for the tract payable in five equal installments. The Company paid the second and third installments of $122.2 million in 2006 and 2007, with the two remaining annual payments to be paid in 2008 and 2009. These payments are capitalized as the cost of the underlying mineral reserves.
 
Impairment
 
If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates that the carrying amount of the asset will not be recoverable through projected undiscounted cash flows related to the asset over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset to its fair value.
 
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 Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“Statement No. 142”), goodwill is not amortized but is tested for impairment annually, or when 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
Deferred Financing Costs
 
The Company capitalizes costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the interest method. Deferred financing costs were $20.2 million and $24.8 million at December 31, 2007 and 2006, respectively. These amounts are recorded in other assets in the accompanying Consolidated Balance Sheets. Amounts classified as current were $4.7 million and $4.6 million at December 31, 2007 and 2006, respectively. These amounts are recorded in other current assets in the accompanying Consolidated Balance Sheets.
 
Revenue Recognition
 
Coal sales revenues include sales to customers of coal produced at Company operations and coal purchased from third parties. The Company recognizes revenue from coal sales at the time risk of loss passes to the customer at contracted amounts. Transportation costs are included in cost of coal sales and amounts billed by the Company to its customers for transportation are included in coal sales.
 
Other Operating (Income) Expense, net
 
Other operating (income) expense, net in the accompanying Consolidated Statements of Income reflects income and expense from sources other than coal sales, including royalties earned from properties leased to third parties; income from equity investments; gains and losses from dispositions of long-term assets; and gains and losses on derivatives that do not qualify for hedge accounting.
 
Asset Retirement Obligations
 
The Company’s legal obligations associated with the retirement of long-lived assets are recognized at fair value at the time the obligations are incurred. Obligations are incurred at the time development of a mine commences for underground and surface mines or construction begins for support facilities, refuse areas and slurry ponds. The obligation’s fair value is determined using discounted cash flow techniques and is accreted over time to its expected settlement value. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying amount of the related long-lived asset. Amortization of the related asset is recorded on a units-of-production basis over the mine’s estimated recoverable reserves. See additional discussion in Note 11, “Asset Retirement Obligations.”
 
Derivative Financial Instruments
 
The Company generally has used derivative financial instruments to manage exposures to commodity prices and interest rates. Additionally, the Company may hold certain coal derivative financial instruments for trading purposes.
 
All derivative financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if the derivatives are not eligible for hedge accounting or in other comprehensive income if they qualify for cash flow hedge accounting. Amounts in other comprehensive income are reclassified to earnings when the hedged transaction affects earnings. The Company formally documents the relationships between hedging instruments and the respective 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 ineffective portion of a cash flow hedge’s change in fair value is recognized immediately in earnings. The amount of ineffectiveness recognized in other operating (income) expense, net in the accompanying


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Consolidated Statements of Income relating to our heating oil derivatives was a gain of $1.4 million for the year ended December 31, 2007. The amount of ineffectiveness relating to interest rate swaps recognized in other non-operating expense in the accompanying Consolidated Statements of Income was a loss of $1.0 million for the year ended December 31, 2005. Ineffectiveness was insignificant for the year ended December 31, 2006.
 
Income Taxes
 
Deferred income taxes are provided for temporary differences arising from differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not that a deferred tax asset will not be realized. In determining the appropriate valuation allowance, the Company considers projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and its overall deferred tax position.
 
Benefit Plans
 
The Company has non-contributory defined benefit pension plans covering certain of its salaried and hourly employees. Benefits are generally based on the employee’s age and compensation. The Company also currently provides certain postretirement medical and life insurance coverage for eligible employees. Costs of providing benefits are determined on an actuarial basis and accrued over the employee’s period of active service.
 
On December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“Statement No. 158”). Statement No. 158 requires that an employer recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) and other postemployment benefits determined on an actuarial basis as an asset or liability in its balance sheet and to recognize changes in the funded status though comprehensive income when they occur. Statement No. 158 also requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet. See Notes 12 and 13 for additional disclosures relating to these obligations.
 
The Company has an obligation under the Coal Industry Retiree Health Benefit Act of 1992 (“Benefit Act”), which provides for the funding of medical and death benefits for certain retired members of the United Mine Workers of America (“UMWA”) through premiums paid by assigned operators (former employers), transfers in 1993 and 1994 from an overfunded pension trust established for the benefit of retired UMWA members, and transfers from the Abandoned Mine Lands Fund (funded by a federal tax on coal production) commencing in 1995. The Company treats its obligation under the Benefit Act as a participation in a multi-employer plan and records expense as premiums are paid.
 
Stock-Based Compensation
 
As of January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (“Statement No. 123R”), which requires all public companies to measure compensation cost in the statement of income for all share-based payments (including employee stock options) at fair value. Prior to the adoption of Statement No. 123R, the Company accounted for its stock options under the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”) and related interpretations, as permitted by Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure (“Statement No. 123”). The Company adopted Statement No. 123R using the modified-prospective method. Under this method, compensation cost for share-based payments to employees is based on their grant-date fair value from the adoption date forward. Measurement and recognition of compensation cost for awards that were granted prior to, but not vested as of, the date Statement No. 123R was adopted are based on the same estimate of the grant-date fair value and the same recognition method used previously under Statement No. 123. The effects of


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Table of Contents

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
adoption on retained earnings, net income and the Consolidated Statement of Cash Flows for the year ended December 31, 2006 were insignificant. See further discussion in Note 16, “Stock Based Compensation and Other Incentive Plans.”
 
Accounting Standards Issued and Not Yet Adopted
 
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“Statement No. 157”). Statement No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements under other accounting pronouncements that require or permit fair value measurements. Statement No. 157 is effective prospectively for fiscal years beginning after November 15, 2007, and interim periods within that fiscal year. The FASB deferred the effective date of Statement No. 157 for one year for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The Company does not expect adoption of Statement No. 157 to have a material impact on the Company’s financial position or results of operations.
 
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Liabilities — Including an amendment of FASB Statement No. 115 (“Statement No. 159”). Statement No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Statement No. 159 is effective prospectively for fiscal years beginning after November 15, 2007. The Company does not expect adoption of Statement No. 159 to have a material impact on the Company’s financial position or results of operations.
 
2.   Property Transactions
 
On September 28, 2007, the Company purchased coal reserves and surface rights in Illinois for $38.9 million. This property is adjacent to other properties owned by the Company and includes approximately 157 million tons of recoverable coal reserves. Of the total recoverable tons, approximately 134 million tons are owned, with the remainder controlled under long-term leases.
 
On June 29, 2007, the Company sold select assets and related liabilities associated with its Mingo Logan-Ben Creek mining complex in West Virginia for $43.5 million. For the years ended December 31, 2007, 2006 and 2005, the Company’s Mingo Logan-Ben Creek operations contributed coal sales of 1.2 million, 4.0 million and 4.7 million tons, revenues of $75.1 million, $243.8 million and $261.5 million and income from operations of $9.1 million, $19.5 million and $15.2 million, respectively.
 
The Company recognized a net gain of $8.9 million in the year ended December 31, 2007 resulting from the sale of the Mingo Logan-Ben Creek complex. That amount has been reflected in other operating (income) expense, net in the accompanying Consolidated Statements of Income. This gain is net of accrued losses of $12.5 million on firm commitments to purchase coal through 2008 to supply below-market sales contracts that can no longer be sourced from the Company’s operations and $4.9 million of employee-related payments, which were paid prior to December 31, 2007.
 
On December 31, 2005, the Company sold the stock of three subsidiaries and their four associated mining operations and coal reserves in Central Appalachia to Magnum. The three subsidiaries were Hobet Mining, Inc., Apogee Coal Company and Catenary Coal Company, which included the Hobet 21, Arch of West Virginia, Samples and Campbells Creek mining operations. Included in the sale were a total of 455.0 million tons of reserves. For the year ended December 31, 2005, collectively, these subsidiaries sold 12.7 million tons of coal, had revenues of $509.8 million and incurred losses from operations of $8.3 million. As a result of the sale, Magnum acquired all of the assets and liabilities of the subsidiaries including various employee liabilities of idle union properties whose former employees were signatory to a UMWA contract.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The net book value of the subsidiaries sold was a net liability of $123.1 million, consisting of the following (in thousands):
 
         
Assets
       
Current assets
  $ 87,300  
Property, plant, equipment
    309,100  
Other assets
    3,800  
         
Total assets
    400,200  
Liabilities
       
Current liabilities
    77,700  
Accrued postretirement benefits other than pension
    367,800  
Accrued workers’ compensation
    15,400  
Reclamation and mine closure
    31,200  
Other noncurrent liabilities
    31,200  
         
Total liabilities
    523,300  
         
Net liabilities
  $ 123,100  
         
 
The Company recognized a $7.5 million net gain in the fourth quarter of 2005 in conjunction with this transaction. The gain recorded by the Company included accrued losses of $65.4 million on firm commitments to purchase coal in 2006 to supply below-market sales contracts, which could no longer be sourced from the Company’s operations as a result of the transaction. As the Company shipped coal to satisfy the below-market contracts, the liability was relieved against cost of coal sales. In addition, the Company recognized expenses of $8.7 million during 2006 related to the finalization of working capital adjustments to the purchase price, adjustments to estimated volumes associated with sales contracts acquired by Magnum and expense related to settlement accounting for pension plan withdrawals. See further discussion of the settlement in Note 13, “Employee Benefit Plans.”
 
In accordance with the terms of the transaction, the Company paid $50.2 million to Magnum in 2006 to purchase coal and to offset certain ongoing operating expenses of Magnum. As of December 31, 2007 and 2006, the Company had a current receivable due from Magnum of $1.1 million and $8.5 million, respectively, included in other receivables on the accompanying Consolidated Balance Sheets.
 
In accordance with the Purchase Agreement, the Company agreed to various guarantees which are described in Note 20, “Guarantees.”
 
On December 30, 2005, the Company completed a reserve swap with Peabody Energy Corp. (“Peabody”) and sold to Peabody a rail spur, rail loadout and an idle office complex located in the Powder River Basin for a purchase price of $84.6 million. In the reserve swap, the Company exchanged 60.0 million tons of its coal reserves for a similar block of 60.0 million tons of coal reserves held by Peabody in order to facilitate more efficient mine plans for both companies. Due to the similarity of the exchanged reserves, the reserves received were recorded at the net book value of the reserves transferred. In conjunction with the transactions, the Company will continue to lease the rail spur and loadout and office facilities through September 2008 while it mines adjacent reserves. The Company recognized a gain of $46.5 million on the transaction, after the deferral of $7.0 million of the gain, equal to the present value of the lease payments. The deferred gain will be recognized over the term of the lease. See further discussion in Note 19, “Leases.”
 
During the years ended December 31, 2007, 2006 and 2005, gains (losses) on other dispositions of property, plant and equipment were $8.9 million, $(0.6) million and $28.2 million, respectively. Included in the gain for 2007 was a gain of $8.4 million on the sales of non-strategic reserves in the Powder River Basin and Central Appalachia. Included in the gain for 2005 was a gain of $9.0 million on the sale of surface land rights at


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
the Company’s Central Appalachian operations in West Virginia, a gain of $6.3 million on the assignment of the Company’s rights and obligations on several parcels of land and a gain of $7.3 million on the sale of a dragline.
 
3.   Accumulated Other Comprehensive Income
 
Other comprehensive income items under Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income, are transactions recorded in stockholders’ equity during the year, excluding net income and transactions with stockholders. Following are the items included in accumulated other comprehensive income (loss):
 
                                         
                Pension,
             
                Postretirement
             
          Minimum
    and Other
          Accumulated
 
          Pension
    Post-
          Other
 
    Financial
    Liability
    Employment