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

 

(Exact name of registrant as specified in its charter)

 

 

 

Registrant’s telephone number, including area code: (314) 994-2700

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

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):

 

 

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

 

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:

 

 

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.

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.

 

 

 

 

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

 

 

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.

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

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)

 

 

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

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

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.

The following diagram illustrates a typical dragline surface mining operation:

 

 

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.

The following diagram illustrates a typical underground mining operation using longwall mining techniques:

 

 

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:

 

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:

 

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:

 

 

 

 

 

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.

 

 

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.

 

 

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.

 

 

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

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.

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:

 

 

 

 

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.

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

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:

 

 

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.

 

 

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.

 

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:

 

 

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

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.

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.

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:

 

 

We submitted our most recent chief executive officer certification to the New York Stock Exchange on May 23, 2007.

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.

 

 

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

 

 

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:

 

 

Declines in the prices we receive for our coal could adversely affect our profitability and the value of our coal reserves.

 

 

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:

 

 

 

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.

 

 

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.

 

 

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.

 

 

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

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.

 

 

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.

 

 

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.

 

 

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.

 

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:

 

 

 

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.

 

 

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.

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.

 

 

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:

 

 

 

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.

 

 

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

could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

 

 

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 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, including those related to the matters listed below, have significant effects on the coal mining industry:

 

 

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.

 

 

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.

 

 

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

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.

 

 

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 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.

 

 

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

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.

 

 

None.

 

 

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 Unassigned Reserves

 

(Tons in millions)

 

 

 

 

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

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.

 

 

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,

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.

 

 

There were no matters submitted to a vote of security holders through the solicitation of proxies or otherwise during the fourth quarter of 2007.

 

 

 

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.

 

 

 

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 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

 

 

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.

 

 

 

 

 

 

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.

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

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:

 

 

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

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:

 

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:

 

 

These increases in other operating income are partially offset by:

 

 

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:

 

 

 

 

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.

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:

 

 

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:

 

 

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

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:

 

 

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:

 

 

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.

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:

 

 

These increases in other operating income are partially offset by:

 

 

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: