Arch Coal 10-K 2007
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
Commission file number: 1-13105
(Exact name of registrant as specified in its charter)
Registrants 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 registrants 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 or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer þ Accelerated Filer o Non-Accelerated Filer o
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 30, 2006 was approximately $4.4 billion.
On February 26, 2007, approximately 142,374,800 shares of the companys common stock, par value $0.01 per share, were outstanding.
Portions of the companys definitive proxy statement for the annual stockholders meeting to be held on April 26, 2007 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 expects, anticipates, intends, plans, believes, seeks, or will. Forward-looking statements by their nature address matters that are, to different degrees, uncertain. For us, particular uncertainties arise from changes in the demand for our coal by the domestic electric generation industry; from legislation and regulations relating to the Clean Air Act and other environmental initiatives; from operational, geological, permit, labor and weather-related factors; from fluctuations in the amount of cash we generate from operations; from future integration of acquired businesses; and from numerous other matters of national, regional and global scale, including those of a political, economic, business, competitive or regulatory nature. These 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. For a description of some of the risks and uncertainties that may affect our future results, you should see Risk Factors beginning on page 26.
Glossary of Selected Mining Terms
Certain terms that we use in this Annual Report on Form 10-K 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 when we use them throughout this document.
We are one of the largest coal producers in the United States. At December 31, 2006, we operated 21 active mines located in each of the three major low sulfur coal-producing regions of the United States. Federal and state regulations controlling air pollution affect the demand for certain types of coal by limiting the amount of sulfur dioxide which may be emitted as a result of fuel combustion. As a result of these regulations, we believe demand for low sulfur coal exceeds demand for other types of coal and often earns a premium in the marketplace. Consequently, we focus on mining, processing and marketing bituminous and sub-bituminous coal with low sulfur content. At December 31, 2006, we estimate that our proven and probable coal reserves had an average heat value of approximately 9,924 Btus and an average sulfur content of approximately 0.60%. Because of these characteristics, we estimate that approximately 79.8% of our proven and probable coal reserves consists of compliance coal.
We sell substantially all of our coal to producers of electric power, steel producers and industrial facilities. For the year ended December 31, 2006, we sold approximately 135.0 million tons of coal, including approximately 10.0 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-fired electric generation facilities in the United States. The following table shows the breakdown of our coal production by region for 2006 and 2005, expressed as a percentage of the total tons produced:
In 2006, we sold approximately 78.5% of our coal under long-term supply arrangements with a term of more than one year. At December 31, 2006, the average volume-weighted remaining term of our long-term contracts was approximately 4.6 years, with remaining terms ranging from one to 11 years. At December 31, 2006, we had a sales backlog, including a backlog subject to price reopener or extension provisions, of approximately 460.9 million tons.
Despite a slight decline in United States demand for coal in 2006, we expect global and domestic demand for coal to grow over time. Based on industry estimates of future production, we expect demand growth 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, 2006, we had expected production available for repricing of approximately 11 million to 16 million tons in 2007, 75 million to 85 million tons in 2008 and 110 million to 120 million tons in 2009.
We were organized in Delaware in 1969 as Arch Mineral Corporation. In July 1997, we merged with Ashland Coal, Inc., a subsidiary of Ashland Oil 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 longwall mine in Colorado and a 65% interest in Canyon Fuel Company, which operates three longwall mines in Utah.
In October 1998, we added to our Powder River Basin reserves when 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 again expanded our position in the Powder River Basin with the acquisition of Triton Coal Companys 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.
At the end of 2005, we sold the stock of Hobet Mining, Apogee Coal Company and Catenary Coal Company and their four associated mining operations (Hobet 21, Arch of West Virginia, Samples and Campbells Creek) and approximately 455.0 million tons of coal reserves in Central Appalachia to Magnum Coal Company, which we refer to as Magnum.
The Coal Industry
Overview. Coal is a combustible, sedimentary, organic rock formed from vegetation that has been consolidated between other rock strata and altered by the combined effects of pressure and heat over millions of years. The degree of change undergone by coal as it matures from peat to anthracite significantly affects its physical and chemical properties. Initially, peat is converted into lignite, a relatively soft material that can range in color from dark black to various shades of brown. The continuing effects of temperature and pressure causes lignite to transform into sub-bituminous coal. Lignite and sub-bituminous coal are typically softer, friable materials characterized by high moisture levels and low carbon content. Because of their carbon content, lignite and sub-bituminous coal generally produce less energy than bituminous, or hard, coal, formed by continuing chemical and physical changes. Under the right conditions, continuing organic maturity can result in anthracite, a hard black rock with a high carbon and energy content and a low level of moisture. According to the World Coal Institute, which we refer to as the WCI, sub-bituminous and bituminous coal comprise approximately 82% of the global coal reserves.
Because of its chemical composition, coal is a major contributor to the global energy supply, providing more than 39% of the worlds electricity, according to the WCI. The United States produces approximately one-fifth of the worlds coal and is the second largest coal producer in the world, exceeded only by China. Coal in the United States represents approximately 95% of the domestic fossil energy reserves with over 250 billion tons of recoverable coal, according to the United States Geological Survey.
Coal is primarily used to fuel electric power generation in the United States. Based on data from the Energy Information Administration, which we refer to as the EIA, coal-based power plants generated
approximately 50% of the electricity produced in the United States in 2006. Coal also represents the lowest cost fossil fuel used for electric power generation. According to the EIA, the average delivered cost of coal to electric power generators during the fourth quarter of 2006 was $1.67/mm Btu, which was $5.67/mm Btu less expensive than residual fuel oil and $5.12/mm Btu less expensive than natural gas.
Compared to other fuels used for electric power generation, coal is domestically available and reliable. Prices for oil and natural gas in the United States have reached record levels in recent years because of tensions regarding international supply and the impact of hurricane interruptions in the Gulf of Mexico in 2005. Historically high oil and natural gas prices have resulted in renewed interest, not only in adding new coal-based electric power generation, but also in refining coal into transportation fuels, such as low-sulfur diesel. According to data from Platts, more than 90 gigawatts of new coal-based generation is now planned in the United States. Additionally, government and private sector interest in coal-gasification and coal-to-liquids technologies has increased.
We expect coal to continue to grow as a domestic fuel as capital is deployed for mine development and expansion and for increased railroad capacity. During 2006, the two existing rail transportation providers in the Powder River Basin in Wyoming expanded their rail capacity, and a potential third rail transportation provider is advancing with plans to construct additional access to this region. We believe this development further demonstrates the commitment to coal as a future source of fuel for 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 sulfur dioxide, nitrous oxides, mercury, and particulates will be introduced into the power generation industry. We also expect advances in technologies designed to capture and sequester carbon dioxide emissions. These technologies have garnered greater attention in recent years due to the perceived impact of carbon dioxide on the global climate. We believe these technological advancements will help coal retain its role as a key fuel for electric power generation well into the future.
U.S. Coal Consumption. Coal produced in the United States is used primarily by electric generation facilities 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 1.1 billion tons in 2006, based on information provided by EIA.
According to the EIA, United States coal consumption by sector for 2006 and 2005 is as follows (tons in millions):
Coal has long been favored as an electricity generating fuel because of its cost advantage and its availability throughout the United States. According to the EIA, coal accounted for approximately 50% of U.S. electricity generation in 2006 and is projected to account for approximately 57% in 2030, while generation from natural gas is expected to peak in 2020. The largest cost component in electricity generation at natural gas- and coal-fired power plants is fuel. According to the National Mining Association, which we refer to as the NMA, coal is the lowest-cost fossil fuel used for electric power generation, averaging less than one-third of the price of both petroleum and natural gas. According to the EIA, for a new coal-fired power plant built today, fuel costs would represent about one-half of total operating costs, whereas the share for a new natural gas-fired power plant would be almost 90%. Other factors that influence an electric generation facilitys choice of generation method may include facility cost, fuel transportation infrastructure and environmental restrictions.
Planned new domestic coal-fueled electric generation capacity announcements exceeded 90 gigawatts at December 31, 2006, equating to as much as 300 million tons of additional coal demand annually. We estimate that, at December 31, 2006, approximately 15 gigawatts of generating capacity was under construction or in advanced stages of development with completion expected by 2010, an amount that could translate into as much as 60 million tons of incremental coal demand during that time period. We believe that demand growth from new coal-fueled electric generation facilities represents an important element to the long-term outlook for coal.
According to the EIA, the breakdown of United States electricity generation by fuel source in 2006 is as follows:
The EIA projects that generators of electricity will increase their demand for coal as demand for electricity increases. The EIA expects coal use for electricity generation to increase by 1.5% per year on average from 2005 to 2030. Coal consumption has generally grown at the pace of electricity growth because coal-fired generation is used in most cases to meet base load requirements. We estimate that coal consumption for power generation declined 0.9% in 2006 as a result of an overall reduction in electricity generation demand. Demand for electricity has historically grown in proportion to the United States economic growth by gross domestic product. In 2006, however, gross domestic product rose by approximately 3.4% according to the U.S. Department of Commerce. According to our estimates, this anomaly of a growing economy and declining coal consumption has occurred only four times since the early 1950s.
Demand for coal is broadly influenced by weather as evidenced by the decline in coal consumption in 2006 in response to very mild weather patterns throughout much of the United States. Weather patterns requiring greater use of heating or air-conditioning translate into greater demand for coal generation. As a result of the mild weather during 2006, coal stockpiles at electric generation facilities totaled 136.0 million tons near the end of 2006, according to the EIA, representing an approximate 47-day supply. In comparison, coal stockpiles totaled 101.1 million tons, or an approximate 35-day supply at December 31, 2005, according to the EIA. We believe that some electric generation facilities may decide to maintain higher coal supplies in order to alleviate the impact of critically low stockpiles such as those experienced at the end of 2005. Coal consumption patterns are also influenced by governmental regulation impacting coal production and power generation; technological developments; and the location, availability and quality of competing sources of energy, including natural gas, oil and nuclear energy, and alternative energy sources, such as hydroelectric power.
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. Because of these characteristics, the price offered by steel makers for metallurgical coal is generally higher than the price offered by electric generation facilities for steam coal.
Historically high oil and gas prices and global energy security concerns have increased interest in converting coal into a liquid fuel, a process known as liquefaction. Liquid fuel produced from coal can be refined further to produce transportation fuels and other oil products, such as plastics and solvents. Public and governmental interest in these and other coal-conversion technologies has increased, particularly with the introduction of several legislative initiatives in early 2007. Several projects have begun, including a coal-to-liquids facility proposed by DKRW Advanced Fuels LLC, a company in which we acquired a 25% equity interest during 2006. 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. In 2006, total coal production in the United States as estimated by the U.S. Department of Energy was 1.1 billion tons. Production of coal in the United States has increased from 434 million tons in 1960 to approximately 1.1 billion tons in 2006 based on information provided by EIA. According to the EIA, the breakdown of United States coal production by producing region for 2006 and 2005 is as follows (tons in millions):
Western region. The western region includes 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. However, 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 existing coal plants to accommodate lower Btu coal. The Western Bituminous region includes western Colorado and eastern Utah. 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 612.9 million tons in 2006.
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 395.2 million tons in 2006, 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. During 2006, we acquired a 331/3% interest in Knight Hawk Holdings, LLC, a coal producer in the Illinois basin. We anticipate that Illinois basin coal will play an increasingly vital role in the United States 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 151.4 million tons in 2006.
International Coal Production. Coal is imported into the United States, primarily from Columbia 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 believe that significant new capital expenditures for transportation infrastructure would have to be incurred by inland coal consumers in the United States if they desired to import significant quantities of foreign coal because most domestic waterways and water transportation facilities are built for export rather than import of coal. To date, the cost of transporting coal from the coast to interior electric generation facilities via rail has generally proven to be expensive. However, coal imports have demonstrated recent strength due to their competitive pricing, particularly when compared to Appalachian coal. According to the EIA, coal imports increased from 8.9 million tons in 1994 to 36.1 million tons in 2006.
Coal Mining Methods
The geological characteristics of coal reserves largely determine the coal mining method employed. There are 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 12. In 2006, approximately 74% of our coal production 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 unit train loadout facility. After we have removed the coal, 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 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 12. In 2006, approximately 18% of our coal production 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 the full extraction of coal from a section of a coal seam using mechanical shearers. Longwall mining is effective for long rectangular blocks of medium to thick coal seams. Ultimate seam recovery using longwall mining techniques can reach 70%. In longwall mining, we use continuous miners described below to develop access to long rectangular coal seams. Hydraulically-powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face of the coal seam, loosening the coal. 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 2006, approximately 15% of our coal production 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 mining equipment to cut the coal from the mining face 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, we mine as much coal as possible from the pillars as our workers retreat. We then allow the roof to collapse in a controlled fashion. Once we have completed retreat mining to the mouth of a panel, we generally abandon the mined panel and seal it from the rest of the mine. In 2006, approximately 3% of our coal production 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:
The remaining 8% of our coal production in 2006 included coal we purchased from third parties at prevailing market rates or pursuant to other contractual arrangements.
Coal Preparation. Coal extracted from the ground, particularly at our underground mining operations, contains impurities, such as rock and dirt, and comes in a variety of different-sized fragments. 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 2006, our preparation plants treated approximately 60% of the coal we produced in the Central Appalachia region. For more information about our preparation plants, you should see the section entitled Our Mining Operations beginning on page 11.
The treatments we employ depend on the properties of the extracted coal and its intended use. To remove impurities, we crush raw coal and separate it into various sizes. For larger pieces of coal, we use dense media 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 other sediment. We treat smaller pieces of coal using a number of different methods, including centrifuge and froth flotation devices. A centrifuge spins material very quickly, causing solids and liquids to separate. In a froth flotation system, a froth is produced by blowing air into a water bath containing chemical reagents. This process creates bubbles, which attract to the coal but not other sediment.
Our Mining Operations
At December 31, 2006, we operated 21 active mines at 12 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 the location of and a summary of information regarding our mining complexes at December 31, 2006, the total sales associated with these complexes for the years ended December 31, 2004, 2005 and 2006 and the total reserves associated with these complexes at December 31, 2006. The amounts disclosed below for the total cost of property, plant and equipment of each mining complex do not include the costs of the coal reserves that we have assigned to any individual complex:
Powder River Basin. Our operations in the Powder River Basin are located in Wyoming and include two surface mines. During 2006, these mining complexes sold approximately 95.6 million tons of compliance coal to customers in the United States. 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 mines and four inactive surface mines. All of the surface mines are in reclamation mode. During 2006, the mining complexes in the Western Bituminous region sold approximately 18.1 million tons of compliance coal to customers in the United States. We
control approximately 464.0 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 Virginia and included eleven underground mines and four surface mines at December 31, 2006. During 2006, these operations sold approximately 12.8 million tons of compliance and metallurgical coal to customers in the United States and abroad. Metallurgical coal accounted for 2.0 million tons of total coal sales from these operations in 2006. We control approximately 402.0 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, 2006, 2005 and 2004 contained in Note 25 Segment Information to our consolidated financial statements beginning on page F-1.
We ship our coal to customers by means of railroad cars, river barges or trucks, or a combination of these means of transportation. We also ship our coal to Atlantic coast terminals for shipment to domestic and international customers. As is customary in the industry, once the coal is loaded onto the barge or rail car, our customers are typically responsible for the freight costs to the ultimate destination. Transportation costs borne by the customer vary greatly based on each customers 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 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. In addition to providing storage and transloading services, the terminal provides maintenance and other services.
In addition, our subsidiaries together 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 on the eastern seaboard 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 also a method we use at certain mines in Central Appalachia, is generally more expensive than surface mining, which is the mining method we use in the Powder River Basin and also 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, our centralized marketing group assigns contract shipments to our various mines which can be used to source the coal in the appropriate region.
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 2006, we sold approximately 78.5% of our coal under long-term supply arrangements. At December 31, 2006, the average volume-weighted remaining term of our long-term contracts was approximately 4.6 years, with remaining terms ranging from one to 11 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.
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., International Coal Group, Inc., James River Coal Company, Massey Energy Company, Magnum Coal Company, Peabody Energy Corp. and Rio Tinto Energy North America. Some of these coal producers are larger than us 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 may also begin to compete with companies that produce coal from one or more foreign countries, such as Columbia 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, such as safety and environmental considerations, relating to these alternative fuels affect the overall demand for coal as a fuel.
We market our coal principally to electric generation facilities in the United States. Coal sales to foreign customers approximated $162.5 million for 2006, $166.0 million for 2005 and $134.0 million for 2004.
Our operations, like operations of other coal companies, are subject to regulation, primarily by federal and state authorities, on matters such as the discharge of materials into the environment; employee health and safety; mine permits and other licensing requirements; reclamation and restoration activities involving our mining properties; management of materials generated by mining operations; surface subsidence from underground mining; water pollution; air quality standards; protection of wetlands; endangered plant and wildlife protection; limitations on land use; storage of petroleum products; and substances that are regarded as hazardous under applicable laws including electrical equipment containing polychlorinated biphenyls, which we refer to as PCBs.
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. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on our mining operations or our customers ability to use coal and may require us or our customers to significantly change operations or to incur substantial costs.
While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. 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 all 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 operations:
Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of our coal. These regulations can take a variety of forms, as explained below.
The Clean Air Act imposes obligations on the United States Environmental Protection Agency, which we refer to as EPA, and on the states to implement regulatory programs that will lead to the attainment and maintenance of national ambient air quality standards, which we refer to as NAAQS. EPA has promulgated a number of NAAQS for air pollutants that are associated with the combustion of coal, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these standards. As these standards become more stringent in the years ahead, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding.
In July 1997, EPA adopted more stringent standards for ozone and particulate matter, which we refer to as PM. EPA adopted what is commonly referred to as the 8-hour ozone standard, established for the first time annual and daily standards for fine PM, or particles that are 2.5 micrometers in diameter (PM2.5), and revised the NAAQS for coarse PM, or particles that are less than 10 micrometers in diameter (PM10). EPAs Phase I and Phase II 8-hour ozone implementation rules were challenged, and in December 2006, the D.C. Circuit Court of Appeals vacated and remanded EPAs Phase I 8-hour ozone implementation rule. Litigation challenging certain EPA designations for PM2.5 non-attainment areas is currently being held in abeyance pending reconsideration by EPA. States having designated non-attainment areas for the 1997 standards are required to submit their state implementation plans for achieving attainment of the 8-hour ozone standards by April 2007 and the PM2.5 standards by April 2008 and are likely to require electric power generators to reduce further sulfur dioxide, nitrogen oxide and particulate matter emissions. The attainment deadlines for 8-hour ozone non-attainment areas range from 2007 to 2012 and for PM2.5 non-attainment areas range from 2010 to 2015.
In September 2006, EPA promulgated final, new PM NAAQS. EPA strengthened the daily PM2.5 standards but retained the annual PM2.5 standards and daily PM10 standards and revoked the annual PM10 standards. The 2006 PM NAAQS are the subject of challenge in the D.C. Circuit Court of Appeals. States having non-attainment areas for the 2006 PM2.5 NAAQS are required to submit their state implementation plans for the 2006 PM2.5 NAAQS by April 2013, and the attainment dates range from 2015 to 2020. With respect to ozone, EPA is currently obligated under a consent decree to sign proposed and final rulemakings concerning any new or revised ozone NAAQS in May 2007 and February 2008, respectively.
In October 1998, EPA finalized a rule that requires 19 states in the eastern United States that have ambient air quality programs to make substantial reductions in nitrogen oxide emissions. Under the rule,
which is commonly known as NOx SIP Call, Phase I states were required to reduce nitrogen oxide emissions by 2004, and Phase II states are required to reduce nitrogen oxide emissions by 2007. Except for five states (Indiana, Illinois, Kentucky, Michigan and Virginia) that failed to submit their Phase II NOx SIP Call rules, all affected states have adopted and submitted to EPA NOx SIP Call rules. For the five states that did not submit Phase II NOx SIP Call rules, EPA is expected to promulgate a federal implementation plan in February 2008. As a result of any federal and state implementation plans, many electric power generation facilities and large industrial plants have been or will be required to install additional emission control measures.
EPA has also initiated a regional haze program designed to protect and improve visibility at and around National Parks, National Wilderness Areas and International Parks, particularly those located in the southwest and southeast United States. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. In June 2005, EPA finalized amendments to the regional haze rules or Clean Air Visibility Rule, which we refer to as CAVR, that will require certain existing coal-fired power plants to install Best Available Retrofit Technology, which we refer to as BART, to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, and particulate matter. In October 2006, EPA published a final emissions trading rule as an alternative to BART. As a result, individual facilities may not have to install emission controls provided the target emissions reductions are met. In December 2006, the D.C. Circuit Court of Appeals upheld EPAs CAVR, rejecting arguments that EPAs CAVR improperly allows the states covered by EPAs Clean Air Interstate Rule trading program to forgo source-specific emissions control requirements to reduce haze. Regional haze state implementation plans are due in 2008.
New regulations concerning the routine maintenance provisions of the New Source Review program were published in October 2003. These regulations were challenged, and in March 2006, the D.C. Circuit Court of Appeals vacated EPAs rule as contrary to §111(a) (4) of the Clean Air Act. EPA and a utility trade association petitioned the United States Supreme Court for a writ of certiorari in November 2006. In addition, in October 2005, the EPA published a proposed rule requiring an hourly emissions test for power plants for determining an emissions increase under the New Source Review program. In September 2006, EPA proposed changes to the New Source Review program concerning de-bottlenecking, aggregation, and project netting.
In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, EPA issued enforcement notices to several electric utility companies. Additionally, the U.S. Department of Justice, on behalf of EPA, filed lawsuits against several investor-owned electric utilities for alleged violations of the Clean Air Act. EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. Some of these lawsuits have been settled, with the owners agreeing to install additional pollution control devices on their coal-fired power plants, and other cases are still pending.
In March 2004, North Carolina submitted to EPA a petition under §126 of the Clean Air Act regarding interstate transport of pollution. In its petition, North Carolina alleges that power plants in 12 southeastern and midwestern states contribute significantly to non-attainment in, and interfere with
maintenance by, North Carolina with respect to the PM2.5 NAAQS. In addition, North Carolina alleges that power plants in five states contribute significantly to non-attainment in, and interfere with maintenance by, North Carolina with respect to the 8-hour ozone NAAQS. In March 2006, EPA promulgated a final rule denying North Carolinas §126 petition. Following EPAs denial of North Carolinas §126 petition, North Carolina and environmental groups petitioned for review. Depending upon the outcome of the litigation, EPAs response to North Carolinas §126 petition could adversely impact the coal needs of power plants in the affected states. With respect to the international transport of pollution, Canadian cities petitioned EPA in November 2006, under §115 of the Clean Air Act, to require emissions reductions from 150 coal-fired power plants in seven midwestern states. If EPA grants the petition, then the affected plants could be required to reduce emissions.
In March 2005, EPA issued three new rules that will impact coal-fired power plants. The three new rules are (i) the Clean Air Interstate Rule, which we refer to as CAIR, aimed at capping emissions of sulfur dioxide and nitrogen oxides in the eastern United States; (ii) the mercury de-listing rule, which de-lists power plants as a source of mercury and other toxic air pollutants and rescinds a finding made in 2000 that it was appropriate and necessary to regulate power plants under Section 112(c) of the Clean Air Act; and (iii) the Clean Air Mercury Rule, which we refer to as CAMR, aimed at capping and reducing mercury emissions from coal-fired power plants. Both CAIR and CAMR provide power plant operators a market-based system in which plants that exceed federal requirements can sell emission allowances to plant operators who need more time to comply with the stricter rules. CAIR requires reductions of sulfur dioxide and/or nitrogen oxide emissions across 28 eastern states and the District of Columbia and, when fully implemented in 2015, CAIR will reduce sulfur dioxide emissions in these states by over 70% and nitrogen oxide emissions by over 60% from 2003 levels. Under CAMR, mercury emissions from coal-fired power plants will not be regulated as a Hazardous Air Pollutant, which would require installation of Maximum Available Control Technology, which we refer to as MACT. Instead, using the cap-and-trade system, these plants will have until 2010 to cut mercury emission levels to 38 tons a year from 48 tons and until 2018 to bring that level down to 15 tons, a 69% reduction. All three rules are the subject of ongoing litigation.
CAIR and CAMR state implementation plans were due November 2006. More than 21 states missed the deadline for CAMR state implementation plans. For these states, EPA is expected to promulgate a CAMR federal implementation plan in 2007. More than 23 states have adopted or are in the process of adopting state-specific rules that are more stringent than CAMR.
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 has subsequently signed on as a full participant in RGGI. The RGGI final model rule was issued in August 2006, and the participating states are developing their state rules. New York, for example, issued draft rules in December 2006 proposing to auction, as opposed to allocate, 100% of its allowances under RGGI. Climate change developments are also taking place in California. In September 2006, California adopted greenhouse gas legislation requiring that long-term base-load generators must not have greenhouse gas emissions rates greater than that of combined cycle natural gas generators. Rules implementing the new greenhouse gas legislation for investor-owned utilities are expected in February
2007. A trading partnership between RGGI states and California has been announced. These and other state climate change rules will likely require additional controls on coal-based electric power generation facilities and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon fuel. In addition, there are a number of climate change lawsuits alleging nuisance and other theories of liability against various defendants pending in the lower courts. In November 2006, the United States Supreme Court heard oral argument in Massachusetts v. EPA on whether EPA has improperly failed to list carbon dioxide as a criteria pollutant. If this litigation results in a court order directing EPA to promulgate a new NAAQS for carbon dioxide, then the market demand for coal could decline.
Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Title IV imposes a two-phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants of greater than 25-megawatt capacity. Affected electric power generation facilities can comply with these requirements by: (i) burning lower sulfur coal, either exclusively or mixed with higher sulfur coal, (ii) installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal, (iii) reducing electricity generating levels or (iv) purchasing or trading emissions allowances. Specific emissions sources receive these allowances, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each allowance permits its holder to emit one ton of sulfur dioxide.
Other proposed initiatives may have an effect upon coal operations. Several so-called mutli-pollutant bills, which would regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement toward increased regulation of emissions, including carbon dioxide and mercury.
Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease. The states in which we operate also have mine safety and health laws. In January 2006, the West Virginia legislature amended its mine safety and health laws to require mine operators to notify emergency response coordinators promptly after serious accidents and provide miners with wireless tracking and communications devices and self-contained self-rescue breathing equipment. Federal legislation was enacted in June 2006 that imposes new requirements for emergency response plans, notification procedures in the event of accidents, and increased civil penalties for violations of the law.
Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act, which we refer to as SMCRA, establishes operational, reclamation and closure standards for all aspects of surface
mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we are contractually obligated under the terms of our leases to comply with all laws, including SMCRA and equivalent state and local laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.
SMCRA also requires us to submit a bond or otherwise financially secure the performance of our reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines. These amounts will decline to $0.315 and $0.135, respectively, beginning October 2007.
We also lease some of our coal reserves to third-party operators. Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed, according to the regulations, to have owned or controlled the mine operator. Sanctions against the owner or controller are quite severe and can include civil penalties, reclamation fees and reclamation costs. We are not aware of any claims against us asserting that we own or control any of our lessees operations.
Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions, and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act.
Clean Water Act. The federal Clean Water Act prohibits the discharge of pollutants into waters of the United States without a permit and defines each of these terms broadly. The statute affects our mining operations in two distinct ways. First, for any discharge of rock or soil into a topographic feature that might constitute a stream, the U.S. Army Corps of Engineers will require a permit specified under §404 of the Clean Water Act for the placement of such fill material into the stream. The Corps implementation of this program and issuance of this permit has been highly litigated in West Virginia since 1998.
Second, EPA, or states which have been delegated the duty, require a permit specified under §402 of the Clean Water Act for any discharge of water from any site that has been disturbed by the act of mining.
The §402 permit imposes limitations on the composition of the effluent that flows from the site, and requires that water quality standards specified for the receiving stream also be achieved. This requires our mining operations to always observe certain management practices, such as routing all surface water flows through sedimentation structures, before the discharge enters public waters. Depending upon the precise water quality standards that must be achieved, additional treatment of the discharge may also be required.
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 implicate the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights.
Mining Permits and Approvals. Mining companies must obtain numerous permits that strictly regulate environmental and health and safety matters in connection with coal mining, some of which have significant bonding requirements. In connection with obtaining these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
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 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. You should see the section entitled Contingencies beginning on page 63 for more information about certain litigation pertaining to our permits.
Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of endangered 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. 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. The Bush Administration has also proposed to add polar bears to the list of endangered species. If that proposal should be finalized, then that action could result in regulation of carbon dioxide emissions to address global warming.
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 Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe that we are in substantial compliance with all applicable environmental laws.
At February 26, 2007, we employed a total of approximately 4,050 persons, approximately 220 of whom are represented by the Scotia Employees Association. We believe that our relations with all employees are good.
The following is a list of our executive officers, their ages as of February 26, 2007 and their positions and offices during the last five years:
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 SECs website, at sec.gov. You may also read and copy any document we file at the SECs 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 results of operations and the value of our coal reserves are substantially dependent upon the prices we receive for our coal. The prices we receive for our coal depend upon factors beyond our control, including the coal consumption patterns of the United States electric generation industry. According to the EIA, the United States electric generation industry accounts for approximately 92% of domestic coal consumption. Certain factors beyond our control, including those listed below, influence the amount of coal consumed for United States electric power generation:
Demand for our low sulfur coal and the prices we obtain for it will also be affected by the price and availability of high sulfur coal. In some instances, United States electric power generators can use high sulfur coal together with emissions allowances in order to satisfy federal and state air emission standards. In addition, restrictions imposed by federal and state air emission standards may cause some electric power generators to shift from coal to natural gas-fired power plants. A decrease in coal consumption by United States electric power generators could reduce the prices we receive for our coal. Significant decreases in the prices we receive for our coal could have a material adverse effect on our profitability and the value of our coal reserves.
We conduct coal mining operations in underground mines and at surface mines. 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 occur, particularly at our Black Thunder mine, 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 and rubber tires. 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 mine. 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 steel, diesel fuel and rubber tires increase, our operating costs could be negatively affected. In addition, if we are unable to procure rubber tires, our coal mining operations may be disrupted or we could experience a delay or halt of 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, Cumberland River and Mingo Logan mining complexes. Operational difficulties at contractor-operated mines, 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 us by contractors. Disruptions in the quantities of coal produced for us by our contract mine operators 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. Certain assumptions and other factors beyond our control, including those listed below, could affect the accuracy of our estimates:
We control substantial undeveloped reserves and have not identified the equipment or workforce that will be employed to mine these reserves. Permits have been obtained for some of these undeveloped reserves. We expect to obtain the required remaining permits by the time we commence mining these reserves, but we may be unable to do so at all or within the necessary time period. Some of the required
permits have become increasingly more difficult and expensive to obtain and the application review processes are taking longer to complete and have been subject to more frequent challenges.
Because of these uncertainties, 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 contain minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
We depend upon barge, 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 substantial portion of our coal under long-term coal supply agreements, which we define as contracts with a term 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 substantial 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 Our profitability and the value of our coal reserves depend upon coal demand by United States electric power generators and other factors beyond our control, 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 17.
For the year ended December 31, 2006, we derived approximately 25.3% of our total coal revenues from sales to our three largest customers, Tennessee Valley Authority, American Electric Power Company, Inc. and TUCO, Inc., and approximately 52.7% of our total coal revenues from sales to our ten largest customers. At December 31, 2006, we had coal supply agreements with those ten customers that expire at various times from 2007 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, 2006, we had consolidated indebtedness of approximately $1.2 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. We may be unable to generate sufficient cash flow from operations and future borrowings or other financing may be unavailable in an amount sufficient to enable us to satisfy our financial obligations or our other liquidity needs. 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 have significant consequences to our business, including those listed below:
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.
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. Several factors, including those listed below, could cause us to be unable to maintain or to acquire surety bonds in the future:
We have agreed to guarantee Magnums obligations to supply coal under certain coal sales contracts that we sold to Magnum, the longest of which extends to the year 2017. In order for the transfer of these coal sales contracts to become effective, the customers must approve the assignments of the contracts to Magnum. At December 31, 2006, one customer had not yet approved these assignments. Until this customer consents, we have agreed to purchase the coal required to satisfy these obligations from Magnum at the same price we charge the customer under the contracts. 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. If we had purchased all of the coal required under these contracts at market prices in effect on December 31, 2006, we would have incurred a loss of approximately $97.1 million related to these contracts.
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
Federal and state authorities regulate certain areas, including those listed below, that significantly affect 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. You should see Environmental Matters beginning on page 18 for more information about the federal and state regulations affecting us.
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 the coal industry, may also require us or our customers to change operations significantly or incur increased costs. Such regulations, if enacted in the future, could have a material adverse effect on our business, financial condition and results of operations.
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.
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 the section entitled Contingencies beginning on page 63 for more information about the litigation described above.
At December 31, 2006, we owned or controlled primarily through long-term leases approximately 156,000 acres of coal land in West Virginia, 101,000 acres of coal land in Wyoming, 72,000 acres of coal land in Illinois, 62,000 acres of coal land in Utah, 49,000 acres of coal land in Kentucky, 22,000 acres of coal land in New Mexico and 17,000 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 115,000 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 have terms expiring between 2007 and 2010 and are subject to readjustment and/or extension and to earlier termination for failure to meeting diligent development requirements. Our Pardee, Levan, Sufco, Cardinal, Holden 22, Mingo Logan, Ragland, Medicine Bow and Seminoe II 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 93,000 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 Item 1. Business beginning on page 1 for more information about our mining operations, mining complexes and transportation facilities.
We estimate that we owned or controlled approximately 2.9 billion tons of proven and probable recoverable reserves at December 31, 2006. 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 by state our estimated assigned and unassigned recoverable coal reserves at December 31, 2006:
Total Assigned Reserves
(Tons in millions)
Total Unassigned Reserves
(Tons in millions)
At December 31, 2006, approximately 13.0% 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. Other leases have primary terms expiring in various years ranging from 2007 to 2020, and most contain options to renew for stated periods. 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 79.8% consist of compliance coal, or coal which emits 1.2 pounds or less of sulfur dioxide per million Btu upon combustion, while an additional 7.2% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Some of our low-sulfur coal can be marketed as compliance coal when blended with other compliance coal. Accordingly, most of our reserves are primarily suitable for the domestic steam coal markets. However, a substantial portion of the low-sulfur and compliance coal reserves at the Mingo Logan, Cumberland River and Lone Mountain operations may also be used as a high-volatile, low-sulfur, metallurgical coal.
The carrying cost of our coal reserves at December 31, 2006 was $1.1 billion, consisting of $119.4 million of prepaid royalties and the $988.3 million net book value of coal lands and mineral rights.
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 58,000 acres of property to other coal operators in 2006. We received royalty income of $5.0 million in 2006 from the mining of approximately 2.4 million tons, $7.1 million in 2005 from the mining of approximately 3.0 million tons and $4.0 million in 2004 from the mining of approximately 2.9 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.
We must obtain permits from applicable state regulatory authorities before we begin to mine particular reserves. Applications for permits require extensive engineering and data analysis and presentation, and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and other impacts on the environment, the construction of overburden fills and water containment areas, and reclamation of the area after coal extraction. We are required to post bonds to secure performance under our permits. As is typical in the coal industry, we strive to obtain mining permits within a time frame that allows us to mine reserves as planned on an uninterrupted basis. We generally begin preparing applications for permits for areas that we intend to mine up to three years in advance of their expected issuance date. Regulatory authorities have considerable discretion in the timing of permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.
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 2007.
You should see Contingencies beginning on page 63 for more information about our pending litigation.
There were no matters submitted to a vote of security holders through the solicitation of proxies or otherwise during the fourth quarter of 2006.
Market for Registrants 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 26, 2007, our common stock closed at $31.01 on the New York Stock Exchange. On that date, there were approximately 8,760 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 $31.4 million, or $0.22 per share, in 2006 and $20.7 million, or $0.16 per share, in 2005. 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.
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 three indices: a peer group, the peer group used in our definitive proxy statement for our 2006 Annual Meeting of Stockholders and the Standard & Poors (S&P) 400 (Midcap) Index. The graph assumes that:
For 2006, our peer group, which we refer to for purposes of the table below as the New Industry Peer Group, consists of CONSOL Energy, Inc., Foundation Coal Holdings, Inc., Massey Energy Company and Peabody Energy Corp. For purposes of preparing the performance graph included in our definitive proxy statement for our 2006 Annual Meeting of Stockholders, our peer group, which we refer to for purposes of the table below as the Old Industry Peer Group, consisted of CONSOL Energy, Inc., Freeport McMoran Copper&Gold, Massey Energy Company, Newmont Mining Corp., Peabody Energy Corp. and Southern Copper Corp. We have updated our peer group to include those companies that we believe are most representative of our industry.
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 stock.
5-Year Total Stockholder Return
Arch Coal, Inc. v. S&P 400 (Midcap) Index and Industry Peer Groups
Issuer Purchases of Equity Securities
The following table summarizes information about shares of our common stock that we purchased during the fourth quarter of 2006.
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.
Our results for 2006 reflect higher margins driven primarily by increased price realization 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 weak near-term market conditions. 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 mine in Wyoming, which restarted production in 2006, and Skyline longwall mine in Utah, which commenced mining in a new reserve area in 2006.
Across all three of our segments, we have committed to sell a large percentage of our coal under sales contracts that we signed in periods when market prices of coal were lower than current market prices. Beginning in 2006 and continuing over the course of the next several years, many of these commitments will expire, and we expect to reprice future coal production at more favorable prices. Abnormal weather patterns, better than expected performance by competing fuels, increased coal production and an increase in utilities coal stockpiles during 2006 resulted in lower consumption by electric power generation facilities. Nevertheless, we believe domestic and global demand growth for coal along with supply pressures, particularly in the Appalachia basin, will cause coal prices to increase. In addition, we expect demand growth from new domestic coal-fueled capacity will also influence future coal consumption and coal prices. At December 31, 2006, we had expected production available for repricing of approximately 11 million to 16 million tons in 2007, 75 million to 85 million tons in 2008 and 110 million to 120 million tons in 2009.
We expect public interest in domestic energy security to accelerate the adoption of coal conversion and other clean-coal technologies. We anticipate that growing legislative support for reducing the geopolitical risks associated with United States oil supplies will cause alternative fuel sources, including liquid fuels generated from coal, to become more significant. We believe that advancement of these technologies represents a positive development for the long-term outlook for coal demand.
Items Affecting Comparability of Reported Results
The comparison of our operating results for the years ended December 31, 2006, 2005 and 2004 is affected by the following significant items:
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 Coal Company. The three subsidiaries were Hobet Mining, Apogee Coal Company and Catenary Coal Company, which included the Hobet 21, Arch of West Virginia, Samples and Campbells Creek mining operations. For the year ended December 31, 2005, these subsidiaries sold 12.7 million tons of coal, had revenues of $509.8 million and incurred a loss from operations of $8.3 million, and for the year ended December 31, 2004, these subsidiaries sold 14.0 million tons of coal, had revenues of $475.1 million and incurred a loss from operations of $3.8 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. In addition, we were required under the agreement to manage working capital for the operations sold to Magnum for a period of time after the transaction. As of December 31, 2006, we had a current receivable due from Magnum of $8.5 million.
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 with Peabody 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 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. The deferred gain will be recognized over the term of the lease.
West Elk combustion event The 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. We do not expect to recover any significant additional amounts as a result of this event.
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. Historically, 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. Due to decreases in pit inventory, net income was $10.6 million higher during the year ended December 31, 2006 than it would have been under our previous methodology of accounting for pit inventory.
Sales of interests in Natural Resource Partners L.P. During 2004, we sold our remaining limited partnership units of Natural Resource Partners L.P., resulting in proceeds of approximately $111.4 million and a gain of $91.3 million.
Acquisition of Triton Coal Company, LLC On August 20, 2004, we acquired (1) Vulcan Coal Holdings, L.L.C., which owned all of the common equity of Triton Coal Company, LLC, and (2) all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Following the consummation of the transaction, we completed an agreement to sell Tritons Buckskin mine to Kiewit Mining Acquisition Company. The net sales price for this second transaction was $73.1 million. The total purchase price, including related costs and fees, was funded with cash on hand, including the proceeds from the Buckskin sale, $22.0 million in borrowings under our existing revolving credit facility and a $100.0 million term loan at our Arch Western Resources subsidiary. We integrated the North Rochelle mine into our existing Black Thunder mine in the Powder River Basin.
Acquisition of remaining interests of Canyon Fuel On July 31, 2004, we purchased the remaining 35% interest in Canyon Fuel that we did not previously own from ITOCHU Corporation. Since the acquisition, we own all of the ownership interests of Canyon Fuel and consolidate Canyon Fuel in our financial statements. The results of operations of the Canyon Fuel mines are included in our Western Bituminous segment.
Results of Operations
The following discussion summarizes our operating results for the year ended December 31, 2006 and compares those results to our operating results for the year ended December 31, 2005.
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 prices per ton by operating segment below.
The following table shows the number of tons sold by operating segment during the year ended December 31, 2006 and compares those amounts to the comparable information for the year ended December 31, 2005:
Sales volume increased in the Powder River Basin as a result of the restart of the Coal Creek mine in the second quarter of 2006 and rail service that improved during 2006 when compared to 2005. In the Western Bituminous region, the effect of an extended longwall move at the Dugout Canyon mine offset a portion of the 1.5 million tons sold from our Skyline mine, which commenced production in a new reserve
area in the second quarter of 2006. Our volumes in Central Appalachia decreased as a result of the sale of operations to Magnum described previously.
The following table shows the coal sales price per ton by operating segment during the year ended December 31, 2006 and compares those amounts to the comparable information for the year ended December 31, 2005. Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the year ended December 31, 2006, transportation costs per ton billed to customers were $0.02 for the Powder River Basin, $2.91 for the Western Bituminous region and $1.49 for Central Appalachia. Transportation costs per ton billed to customers for the year ended December 31, 2005 were $0.08 for the Powder River Basin, $3.10 for the Western Bituminous region and $1.48 for Central Appalachia.
The increase in our coal sales prices in 2006 resulted from higher contract pricing within all of our segments when compared to 2005, due primarily to the expiration of lower-priced legacy contracts. As discussed previously, we continue to replace sales contracts that we signed in periods when market prices of coal were lower than current market prices. In Central Appalachia, the divestiture described previously of certain operations with lower-priced legacy contracts also helped to improve our average coal sales price per ton.
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 margins by segment below.
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 Central Appalachia operations. We have provided additional information concerning our capital spending during 2006 in the section entitled Liquidity and Capital Resources beginning on page 56.
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 46 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 margins. Our operating margins (reflected below on a per-ton basis) include all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs discussed in Revenues above) and all depreciation, depletion and amortization attributable to mining operations.
Powder River Basin On a per-ton basis, operating margins in 2006 increased significantly from 2005 primarily due to the increase in per-ton coal sales realizations discussed previously. The effect of the higher realizations were partially offset by increased production taxes and coal royalties, which we pay as a percentage of coal sales realizations, higher repair and maintenance activity and higher diesel, tire and explosives costs during 2006 compared to 2005.
Western Bituminous Operating margins per ton in 2006 increased from 2005 primarily due to higher per ton sales prices and insurance recoveries related to the West Elk thermal event of $41.9 million, partially offset by higher costs resulting from an extended longwall move at our Dugout Canyon mine, higher coal royalties and production taxes, which we pay as a percentage of sales, and higher repair and supplies costs.
Central Appalachia Operating margins per ton in 2006 increased significantly from 2005 primarily as a result of the sale of certain operations at the end of 2005, discussed previously, which operated at a loss in 2005, and higher coal sales realizations.
Net interest expense. The following table summarizes our net interest expense for the year ended December 31, 2006 and compares that information to the comparable information for the year ended December 31, 2005:
The decrease in interest expense during 2006 compared to 2005 resulted primarily from an increase in the amounts of interest capitalized in connection with certain major long-term development projects described in more detail in the section entitled Liquidity and Capital Resources beginning on page 56. We capitalized $14.8 million of interest during 2006 and $4.2 million during 2005. The decrease in interest income is due to a decrease in short-term investments, which we liquidated, in part, to fund our capital improvement and development projects. For more information on our ongoing capital improvement and development projects, you should see the section entitled Liquidity and Capital Resources beginning on page 56.
Other non-operating expense. The following table summarizes our other non-operating expense for the year ended December 31, 2006 and compares that information to the comparable information for the year ended December 31, 2005:
Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. As described above, our results of operations include expenses related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Other non-operating income includes mark-to-market adjustments related to certain swap activity that does not qualify for hedge accounting.
Income taxes. Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion deductions. The income tax provision of $7.7 million in 2006 compared with the income tax benefit of $34.7 million in 2005 is primarily the result of increases in pre-tax income in 2006, offset by a $49.1 million decrease in our valuation allowance against deferred tax assets in 2006, compared to a $6.1 million decrease in our valuation allowance in 2005.
The following discussion summarizes our operating results for the year ended December 31, 2005 and compares those results to our operating results for the year ended December 31, 2004.
Revenues. The following table summarizes information about coal sales during the year ended December 31, 2005 and compares those results to the comparable information for the year ended December 31, 2004:
Coal sales. The increase in our coal sales resulted from a combination of increased volumes, higher pricing, and the acquisitions of Triton in the Powder River Basin on August 20, 2004 and the remaining 35% interest in Canyon Fuel in the Western Bituminous region on July 31, 2004. Our per ton realizations increased due primarily to higher contract prices in all three segments. On a consolidated basis, the increase in per ton realization was partially offset by the change in mix of sales volumes among our
operating regions. As reflected in the table below, Central Appalachia volumes (which have the highest average realization) were relatively flat in 2005, while volumes from lower realization regions (the Powder River Basin and Western Bituminous region) increased from 2004.
The following table shows the number of tons sold by operating segment during the year ended December 31, 2005 and compares those amounts to the comparable information for the year ended December 31, 2004:
In 2005, all of our operating segments benefited from an overall increase in demand, while volumes in the Powder River Basin and the Western Bituminous region also benefited from the acquisitions described above compared to 2004.
The following table shows the coal sales price per ton by operating segment during the year ended December 31, 2005 and compares those amounts to the comparable information for the year ended December 31, 2004. Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. As other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. Transportation costs per ton billed to customers for the year ended December 31, 2005 were $0.08 for the Powder River Basin, $3.10 for the Western Bituminous region and $1.48 for Central Appalachia. For the year ended December 31, 2004, transportation costs per ton billed to customers were $0.05 for the Powder River Basin, $2.12 for the Western Bituminous region and $1.46 for Central Appalachia.
In the Powder River Basin, our coal sales prices increased due to higher base pricing and above-market pricing on certain contracts acquired with our Triton acquisition, as well as higher sulfur dioxide quality premiums resulting from an increase in sulfur dioxide emission allowance prices. Our coal sales prices in Central Appalachia increased in 2005, as both contract and spot market prices were higher than in 2004. Additionally, we received higher sales prices on our metallurgical coal sales in 2005 compared to 2004. The Western Bituminous regions coal sales prices increased due to higher contract pricing.
Expenses, costs and other. The following table summarizes expenses, costs and other operating income and expenses, net for the year ended December 31, 2005 and compares those results to the comparable information for the year ended December 31, 2004:
Cost of coal sales. The increase in cost of coal sales is primarily due to the acquisitions of Triton in the Powder River Basin and the remaining 35% interest in Canyon Fuel in the Western Bituminous region, along with an increase in sales-sensitive taxes and royalties and higher diesel fuel, explosives and utilities costs.
Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the acquisitions during the third quarter of 2004 and to higher capital expenditures during 2005.
Selling, general and administrative expenses. Selling, general and administrative expenses increased during 2005 due primarily to $14.9 million of expense we recognized for performance-contingent phantom stock awards to certain employees. In addition, when comparing 2005 to 2004, costs increased as a result of higher contract services, including legal and professional fees ($5.2 million), employee severance expense ($1.3 million), the establishment of a charitable foundation during the fourth quarter of 2005 ($5.0 million) and executive deferred compensation expense ($4.6 million).
Other operating (income) expense, net. Gains on sales of assets other than those noted above were $28.2 million in 2005, compared to $6.7 million in 2004. This increase was partially offset by the elimination of administrative fees from Canyon Fuel subsequent to our acquisition of the remaining 35% interest during the third quarter of 2004 which resulted in $4.8 million of income in 2004, reduced bookout income, related to the netting of coal sales and purchase contracts with the same counterparty, of $9.4 million compared to the prior year and a $6.5 million decrease in 2005 compared to 2004 of previously-deferred gains from our sales of limited partnership units in Natural Resource Partners L.P. in 2003 and 2004. These deferred gains are being recognized over the terms of our leases with Natural Resource Partners L.P. These increases in other operating income, net were offset by a $16.0 million settlement with a landowner, as well as an expense of $19.7 million recognized to reflect the change in fair
value of sulfur dioxide emission allowance swaps and put options and coal swaps which are derivatives but do not qualify for hedge accounting treatment.
Operating margins. Our operating margins (reflected below on a per-ton basis) include all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs discussed in Revenues above) and all depreciation, depletion and amortization attributable to mining operations.
Powder River Basin On a per-ton basis, higher coal sales prices in the Powder River Basin were partially offset by higher operating costs, primarily due to higher production taxes and coal royalties, diesel fuel costs, depreciation, depletion and amortization costs and higher repairs and maintenance costs. Additionally, average costs were higher due to the integration of the North Rochelle mine into our Black Thunder mine in the third quarter of 2004. These costs would have been largely offset by increased productivity had rail service not adversely impacted volumes during the year.
Western Bituminous On a per-ton basis, higher coal sales prices were partially offset by the effect of the West Elk thermal event discussed under Items Affecting Comparability of Reported Results on page 46.
Central Appalachia On a per-ton basis, higher coal sales prices were partially offset by increased costs for coal purchases, increased labor costs, production taxes and coal royalties, costs for operating supplies and diesel fuel, as well as the increased preparation costs for metallurgical coal discussed above. Additionally, during 2005 our Mingo Logan mine moved into less favorable geological conditions than during 2004, resulting in higher per-ton costs.
Net interest expense. The following table summarizes our net interest expense for the year ended December 31, 2005 and compares that information to the comparable information for the year ended December 31, 2004:
The increase in interest expense results from a higher amount of average borrowings in 2005 as compared to the same period in 2004. In addition, we recognized $1.4 million of interest expense associated with state tax assessments. The increase in interest income resulted primarily from interest on short-term investments.
Other non-operating expense. The following table summarizes our other non-operating expense for the year ended December 31, 2005 and compares that information to the comparable information for the year ended December 31, 2004:
Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. As described above, our results of operations include expenses related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Other non-operating income includes mark-to-market adjustments related to certain swap activity that does not qualify for hedge accounting.
Income taxes. Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The increase in the income tax benefit of $34.7 million in 2005 as compared to $0.1 million in 2004 is primarily the result of the taxable income from non-mining sources from the sale of the Natural Resource Partners L.P. limited partnership units in the first quarter of 2004. The benefit for 2005 is the result of our taxable income and the effect of percentage depletion on our results.
Liquidity and Capital Resources
Our primary sources of cash include sales of our coal production to customers, borrowings under our credit facilities, sales of assets and debt and equity offerings related to significant transactions. Excluding any significant mineral reserve acquisitions, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations or borrowings under our credit facilities or accounts receivable securitization program. Our ability to satisfy debt service obligations, to fund planned capital expenditures, to make acquisitions and to pay dividends will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.
The following is a summary of cash provided by or used in each of the indicated types of activities during the past three years:
Cash provided by operating activities increased $53.5 million in 2006 compared to 2005 primarily as a result of an increase in net income which was offset by an increased investment in working capital and payments resulting from our sale of certain Central Appalachia operations on December 31, 2005. Specifically, we made payments to Magnum of $50.2 million in 2006 pursuant to the purchase agreement related to that transaction. The payment related to the purchase of coal and certain operating expenses. In addition, at December 31, 2005, we accrued losses of $65.4 million related to commitments to purchase coal in 2006 to satisfy below-market contracts that we could not source from our remaining operations.
Cash provided by operating activities increased during 2005 compared to 2004 primarily as a result of improved performance at our operations in addition to a decreased investment in working capital. While trade accounts receivable and inventory represented the largest use of funds, increasing by $86.8 million in 2005 compared to an increase of $44.0 million in 2004, those increases were offset by an increase in accounts payable and accrued expenses of more than $108.5 million in 2005 compared to a decrease of $6.8 million in 2004. In addition, we received $14.7 million during the second quarter of 2005 related to payment of receivables for settled audit years from the Internal Revenue Service.
Cash used in investing activities in 2006 was $396.5 million higher than in 2005, due to increased capital expenditures and the purchase of equity-method investments, as well as a decrease of $116.3 million in proceeds from dispositions of property, plant and equipment. In 2006, we made the second of five annual payments of $122.2 million on the Powder River Basins Little Thunder federal coal lease, which will continue through 2009. Costs related to the development of the Mountain Laurel complex in West Virginia, higher spending at our Powder River Basin operations related to the restart of the Coal Creek mine and costs related to the purchase of a replacement longwall at the Canyon Fuel operations in the Western Bituminous region resulted in an increase in capital expenditures in 2006 compared to the prior year period. We also spent $40.0 million during 2006 to acquire equity interests in other companies that will be accounted for on the equity method.
We make capital expenditures to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We anticipate that capital expenditures during 2007 will be between approximately $240 million and $280 million, excluding reserve additions. This estimate includes capital expenditures related to development work at certain of our mining operations, including the Mountain Laurel complex in West Virginia, work on a new loadout at Black Thunder, and the final expenditures for a new longwall at the SUFCO mine. This estimate assumes no other acquisitions, significant expansions of our existing mining operations or additions to our reserve base. In addition to these expenditures, we will make another $122.2 million installment for the Little
Thunder coal lease. We anticipate that we will fund these capital expenditures with available cash, existing credit facilities and cash generated from operations.
Cash used in investing activities in 2005 was $305.8 million lower than in 2004, due to acquisitions in July 2004 of the 35% of the Canyon Fuel membership interest not previously owned by us and the North Rochelle operations from Triton in August 2004, offset by partially higher capital expenditures and payments to affiliates and to purchase equity investments of $23.3 million in 2005. Offsetting uses of cash were proceeds from the sales of land and equipment of $117.0 million, including $84.6 million related to the sale of the Powder River Basin assets, compared to $7.4 million in 2004. In 2004, proceeds of $111.4 million were received from the sale of limited partnership units in Natural Resource Partners L.P.
Capital expenditures of $357.1 million in 2005 increased $64.5 million, fueled by increases in capital spending at the Central Appalachia operations of approximately $150.1 million, offset by a decrease in payments made on the Little Thunder lease. The increase in Central Appalachia operations includes the development and construction of the Mountain Laurel mining complex, where expenditures of $88.3 million in 2005 represented an increase of approximately $83.0 million over 2004. We financed the Canyon Fuel acquisition with a $22.0 million five-year note and approximately $90.0 million of cash on hand. We financed the Triton acquisition with borrowings under the revolving credit facility of $22.0 million, a term loan in the amount of $100.0 million and with cash on hand.
Cash provided by financing activities in 2006 was $121.9 million compared to a use of cash of $25.7 million in 2005. The increase results primarily from borrowings on the revolving credit facility and other credit facilities, including those under the accounts receivable securitization program discussed below, of $192.3 million, compared to net payments of $25.0 million during 2005. The increase in borrowings was to fund our higher capital expenditures, including the Little Thunder federal coal lease noted above. We also had $58.3 million of letters of credit outstanding under the securitization program at December 31, 2006. The average cost of borrowing under the securitization program was approximately 5.36% at December 31, 2006. We had available borrowing capacity of $695.5 million under our credit facilities at December 31, 2006. Financing activities in 2006 also included cash received of $7.0 million from the issuance of common stock under our employee stock incentive plans, a decrease of $24.9 million from 2005. We spent $43.9 million during 2006 under a share repurchase program authorized by the board of directors in September 2006. The program, which replaces a program adopted in 2001, provides for the purchase of up to 14.0 million shares of common stock.
Cash used in financing activities during 2005 consists primarily of net payments on our revolving credit facility of $25.0 million, net payments on our long-term debt of $2.4 million and dividend payments of $27.6 million, offset partially by $31.9 million in proceeds from the issuance of common stock under our employee stock incentive plan. Cash provided by financing activities in 2004 consists primarily of proceeds from the issuance of senior notes of $261.9 million and proceeds from the issuance of common stock through a public offering of $230.5 million described below. Additionally, financing activities in 2004 also include net borrowings under our revolving credit facility of $25.0 million, proceeds of $37.0 million from the issuance of common stock under our employee stock incentive plan and dividend payments of $24.0 million.
We believe that cash generated from operations, borrowing under our credit facilities, sales of assets and debt and equity offerings will be sufficient to meet working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next several years.
On June 23, 2006, we amended our credit facility to change the pricing grid upon which the interest rate on borrowings under the credit facility is determined and to extend the maturity date from December 22, 2009 to June 23, 2011. As amended, borrowings under the credit facility bear interest at a floating rate based on LIBOR determined by reference to our leverage ratio, as calculated in accordance with the credit agreement. In addition, the amendment to the credit facility increased the maximum amount of borrowings available to us from $700.0 million to $800.0 million and also revised certain negative covenants and other provisions to provide us with greater flexibility to pursue strategic investments. On October 3, 2006, we entered into a further amendment to the credit facility to eliminate the dollar limitation on the amount of payments we are permitted to make annually with respect to our outstanding capital stock and instead to limit our ability to make those payments by requiring us to comply with certain specified financial ratios, calculated in accordance with the credit agreement, at the time such payments are made. Our credit facility is secured by substantially all of our assets, as well as our ownership interests in substantially all of our subsidiaries, except our ownership interests in Arch Western Resources, LLC and its subsidiaries.
Financial covenants contained in our revolving credit facility consist of a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. The leverage ratio requires that we not permit the ratio of total net debt (as defined in the facility) at the end of any calendar quarter to EBITDA (as defined in the facility) for the four quarters then ended to exceed a specified amount. The interest coverage ratio requires that we not permit the ratio of EBITDA (as defined) at the end of any calendar quarter to interest expense for the four quarters then ended to be less than a specified amount. The senior secured leverage ratio requires that we not permit the ratio of total net senior secured debt (as defined) at the end of any calendar quarter to EBITDA (as defined) for the four quarters then ended to exceed a specified amount. We were in compliance with all financial covenants at December 31, 2006.
On June 23, 2006, we amended our receivable securitization program to increase the program from $100.0 million to $150.0 million and change the fees on amounts funded under the program to rates based on our leverage ratio. Under the terms of the accounts receivable securitization program, eligible trade receivables consist of trade receivables generated by our operating subsidiaries. Although the participants in the program bear the risk of non-payment of purchased receivables, we have agreed to indemnify the participants with respect to various matters. The participants under the program will be entitled to receive payments reflecting a specified discount on amounts funded under the program, including drawings under letters of credit, calculated on the basis of the base rate or commercial paper rate, as applicable. We will pay facility fees, program fees and letter of credit fees (based on amounts of outstanding letters of credit) at rates that vary with our leverage ratio.
Under the program, we are subject to certain affirmative, negative and financial covenants customary for financings of this type, including restrictions related to, among other things, liens, payments, merger or consolidation and amendments to the agreements underlying the receivables pool. The administrator may terminate the program upon the occurrence of certain events that are customary for facilities of this type (with customary grace periods, if applicable), including, among other things, breaches of covenants,
inaccuracies of representations and warranties, bankruptcy and insolvency events, changes in the rate of default or delinquency of the receivables above specified levels, a change of control and material judgments. A termination event would permit the administrator to terminate the program and enforce any and all rights, subject to cure provisions, where applicable. Additionally, the program contains cross-default provisions, which would allow the administrator to terminate the program in the event of non-payment of other material indebtedness when due and any other event which results in the acceleration of the maturity of material indebtedness.
At December 31, 2006, debt amounted to $1,173.8 million, or 46% of capital employed, compared to $982.4 million, or 45% of capital employed, at December 31, 2005. Based on the level of consolidated indebtedness and prevailing interest rates at December 31, 2006, debt service obligations for 2007, which include the maturities of principal and interest expense, are estimated to be $119.5 million.
We filed a shelf registration statement on Form S-3 with the SEC on March 14, 2006 that allows us to offer and sell from time to time an unlimited amount of unsecured debt securities consisting of notes, debentures, and other debt securities, common stock, preferred stock, warrants, and/or units. Related proceeds could be used for general corporate purposes, including repayment of other debt, capital expenditures, possible acquisitions and any other purposes that may be stated in any prospectus supplement.
On October 28, 2004, we completed a public offering of 14,375,000 shares of our common stock, including the underwriters full over-allotment option, at a price of $16.93 per share. We used the net proceeds of the offering, totaling $230.5 million after the underwriters discount and expenses, to repay borrowings under our revolving credit facility incurred to finance our acquisition of Triton and the first annual payment for the Little Thunder federal coal lease. We used the remaining proceeds for general corporate purposes, including the development of the Mountain Laurel longwall mine in Central Appalachia.
On October 22, 2004, two subsidiaries of Arch Western, as co-obligors, issued $250 million of 63/4% senior notes due 2013 at a price of 104.75% of par. The net proceeds of the offering were used to repay and retire the outstanding indebtedness under Arch Westerns $100.0 million term loan maturing in 2007, to repay indebtedness under our revolving credit facility and for general corporate purposes.
Ratio of Earnings to Fixed Charges
The following table sets forth our ratios of earnings to combined fixed charges and preference dividends for the periods indicated:
The following is a summary of our significant contractual obligations as of December 31, 2006:
Royalty leases represent non-cancelable royalty lease agreements, as well as federal lease bonus payments due under the Little Thunder lease. Remaining payments due under the Little Thunder lease will be paid in three equal annual installments of $122.2 million in years 2007 through 2009. Unconditional purchase obligations represent amounts committed for purchases of materials and supplies, payments for services, purchased coal, and capital expenditures.
Our consolidated balance sheet reflects a liability of $216.6 million for the fair value of asset retirement obligations that arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The determination of the fair value of asset retirement obligations involves a number of estimates, as discussed in the section entitled Critical Accounting Policies beginning on page 65, including the timing of payments to satisfy asset retirement obligations. The timing of payments to satisfy asset retirement obligations is based on numerous factors, including mine closure dates. You should see the notes to our consolidated financial statements for more information about our asset retirement obligations.
The table above also excludes certain other obligations reflected in our consolidated balance sheet, including estimated funding for pension and postretirement benefit obligations, for which the timing of payments may vary based on changes in the fair value of plan assets (for pension obligations) and actuarial assumptions and payments under our self-insured workers compensation program. You should see the section entitled Critical Accounting Policies beginning on page 65 for more information about these assumptions. We expect to make contributions of $1.7 million to our pension plans in 2007. You should see the notes to our consolidated financial statements for more information about the amounts we have recorded for workers compensation and pension and postretirement benefit obligations.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
We use a combination of surety bonds, corporate guarantees (e.g., self bonds) and letters of credit to secure our financial obligations for reclamation, workers compensation, postretirement benefits, coal lease obligations and other obligations as follows as of December 31, 2006:
We have agreed to continue to provide surety bonds and letters of credit for the reclamation, workers compensation and retiree healthcare obligations of the properties we sold to Magnum in order to facilitate an orderly transition. Magnum is required to reimburse us for costs related to the surety bonds and letters of credit until it can replace these items. If the surety bonds and letters of credit related to the reclamation obligations are not replaced by Magnum within two years of the transaction, then Magnum must post a letter of credit in our favor in the amounts of the obligations. Letters of credit related to workers compensation obligations were replaced by Magnum during the fourth quarter of 2006. At December 31, 2006, we had $92.0 million of surety bonds related to properties sold to Magnum.
In addition, we have agreed to guarantee the performance of Magnum with respect to certain coal sales contracts sold to Magnum, the longest of which extends to the year 2017, and certain operating leases, the longest of which ends in 2011. Under the coal sales contracts, the customers must approve the assignment of the contracts to Magnum. Until the contracts are assigned, we are purchasing the coal from Magnum to sell to these customers at the same price it is charging the customers for the sale. One customer agreed to the assignment in the second quarter of 2006, under the agreement that we would continue to guarantee Magnums performance until the end of 2006. If Magnum is unable to supply the coal for these coal sales contracts, then we would be required to purchase coal on the open market or supply the contract from our existing operations. If we were required to purchase coal to supply the contracts over their duration at market prices effective at December 31, 2006, the cost of the purchased coal would exceed the sales price under the contracts by $97.1 million. If we were required to perform under our guarantee of the operating lease agreements, we would be required to make $15.3 million of lease payments. We believe that it is remote that we would be required to perform under these guarantees. However, if we would have to perform under these guarantees, it could potentially have a material adverse effect on our business, results of operations and financial condition.
In connection with the acquisition of the coal operations of Atlantic Richfield Company, which we refer to as ARCO, and the simultaneous combination of the acquired ARCO operations and our Wyoming operations into the Arch Western joint venture, we agreed to indemnify the other member of Arch
Western against certain tax liabilities in the event that such liabilities arise prior to June 1, 2013 as a result of certain actions taken, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. If we were to become liable, the maximum amount of potential future tax payments was $173.7 million at December 31, 2006, of which none is recorded as a liability on our financial statements. Since the indemnification is dependent upon the initiation of activities within our control and we do not intend to initiate such activities, it is remote that we will become liable for any obligation related to this indemnification. However, if such indemnification obligation were to arise, it could potentially have a material adverse effect on our business, results of operations and financial condition.
In addition, tax reporting applied to this transaction by the other member of Arch Western was being audited by the Internal Revenue Service, which we refer to as the IRS. We do not believe that we are bound by the outcome of this audit. Nevertheless, we anticipate that following the conclusion of the audit of the other member, we will soon begin negotiations with the IRS as to adjustments, if any, of Arch Westerns tax reporting. The outcome of these negotiations when settled could result in adjustments to the basis of the partnership assets, and it is possible we may be required to adjust our deferred income taxes associated with our investment in Arch Western. Given the uncertainty of how an adverse outcome would affect our deferred income tax position, coupled with potential offsetting tax positions that we may be able to take, we are not able to reasonably determine the resulting outcome of this issue. However, any change that impacts us related to an IRS negotiation may result in a non-cash decrease in deferred income tax assets associated with our investment in Arch Western and could fall within a range of zero to $41.0 million.
Reclamation. SMCRA and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. We accrue for the costs of reclamation in accordance with the provisions of Statement No. 143. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground mines. Other costs of reclamation common to surface and underground mining are related to reclaiming refuse and slurry ponds, eliminating sedimentation and drainage control structures, and dismantling or demolishing equipment or buildings used in mining operations. The establishment of the asset retirement obligation liability is based upon permit requirements and requires various estimates and assumptions, principally associated with costs and productivities.
We review our entire environmental liability periodically and make necessary adjustments, including permit changes and revisions to costs and productivities, to reflect current experience. Our management believes it is making adequate provisions for all expected reclamation and other associated costs.
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. At the time the plaintiffs attempted to supplement their complaint to add the permit issued by the Corps to our operating subsidiaries, the lawsuit had been tried to completion and was awaiting a decision by the court. The motions to supplement the complaint and add the newly issued permits name only the Corps as the defendant and ask that the Corps be ordered to rescind the permits.
Our operating subsidiaries are seeking to intervene in the suit to protect their interests in being allowed to operate under the issued permits. They have requested that the court dismiss the motions to supplement as improperly attempting to join the facts and legal theories of our permits with the existing case. Their motions are now before the court for decision.
While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe these matters will be resolved without a material adverse effect on our financial condition or results of operations or liquidity.
West Virginia Flooding Litigation. We have been served, among others, including a former subsidiary whom we have agreed to defend, in 15 separate complaints filed and served in Wyoming, McDowell, Fayette, Kanawha, Raleigh, Boone and Mercer Counties, West Virginia. These cases collectively include approximately 3,100 plaintiffs who are seeking to recover from more than 180 defendants 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 courts 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, the jury returned a verdict concerning certain preliminary matters against the two, non-settling defendants in the first phase of the first watershed, in which we were not involved. We were previously named in cases involving the Coal River watershed. On January 18, 2007, the court dismissed the plaintiffs claims. The plaintiffs have four months from the entry of the order to appeal. We are also named in the Tug Fork and remaining Upper Guyandotte watershed trial groups. These groups will also proceed to trial in phases. A trial date has not yet been set.
While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or liquidity.
We are a party to numerous other claims and lawsuits and are subject to numerous other contingencies with respect to various matters. We provide for costs related to contingencies, including environmental, legal and indemnification matters, when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of
these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.
Critical Accounting Policies
We prepare our financial statements in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Additionally, these estimates and judgments are discussed with our audit committee on a periodic basis. Actual results may differ from the estimates used under different assumptions or conditions. We have provided a description of all significant accounting policies in the notes to our consolidated financial statements. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:
Our asset retirement obligations arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. Our asset retirement obligations are initially recorded at fair value, or the amount at which the obligations could be settled in a current transaction between willing parties. This involves determining the present value of estimated future cash flows on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage and reclamation costs and assumptions regarding productivity. We estimate disturbed acreage based on approved mining plans and related engineering data. Since we plan to use internal resources to perform reclamation activities, our estimate of reclamation costs involves estimating third-party profit margins, which we base on our historical experience with contractors that perform certain types of reclamation activities. We base productivity assumptions on historical experience with the equipment that we expect to utilize in the reclamation activities. In order to determine fair value, we must also discount our estimates of cash flows to their present value. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the actual cost of reclamation and the fair value will be recorded as a gain or loss when the obligation is settled. We expect our actual cost to reclaim our properties will be less than the amount reflected as an asset retirement obligation. At December 31, 2006, we had recorded asset retirement obligation liabilities of $216.6 million, including amounts classified as a current liability. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2006, we estimate that the aggregate undiscounted cost of final mine closure is approximately $528.4 million.
As of January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, which we refer to as Statement No. 123R, which requires all public companies to measure compensation cost in the income statement for all share-based payments (including employee stock options) at fair value. We adopted Statement No. 123R using the modified-prospective method. Under this method, compensation cost for share-based payments to employees is based on their grant-date fair value from the beginning of the fiscal period in which the recognition provisions are first applied. Measurement and recognition of compensation cost for awards that were granted prior to, but not vested as of, the date Statement No. 123R was adopted are based on the same estimate of the grant-date fair value and the same recognition method used previously under Statement No. 123. We use the Black-Scholes option pricing model for options and a lattice model at the grant date for the portion of share-based payments with performance and market conditions that is paid out in stock to determine the fair value. As of December 31, 2006, a $1 increase in our stock price would have resulted in additional expense of $0.1 million for the year ended December 31, 2006.
We use derivative financial instruments to manage exposures to commodity prices and interest rates. Derivative financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or other comprehensive income if they qualify for cash flow hedge accounting. Amounts in other comprehensive income are reclassified to earnings when the hedged transaction affects earnings. Any ineffective portion of a cash flow hedges change in fair value is recognized immediately in earnings.
We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking various hedge transactions. We evaluate the effectiveness of our hedging relationships both at the hedge inception and on an ongoing basis.
We have non-contributory defined benefit pension plans covering certain of our salaried and hourly employees. Benefits are generally based on the employees age and compensation. We fund the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes. We contributed $19.3 million in cash and stock to the plans during the year ended December 31, 2006 and contributed $20.0 million in cash and stock to the plans during the year ended December 31, 2005. We account for our defined benefit plans in accordance with Statement of Financial Accounting Standards No. 87, Employers Accounting for Pensions, as amended by Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, which we refer to as Statement No. 87 and Statement No. 158. Statement No. 158 requires that the actuarially-determined funded status of the plans be recorded in the balance sheet, which resulted in an increase to accumulated other comprehensive loss of $11.9 million at December 31, 2006.
In June 2006, the disposition of certain Central Appalachia operations in 2005 resulted in withdrawals that constituted a settlement of our pension benefit obligation for which we recognized expense of $3.2 million.
The calculation of our net periodic benefit costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be critical accounting estimates. Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.
The differences generated in changes in assumed discount rates and returns on plan assets are amortized into earnings over a five-year period.
For the measurement of our year-end pension obligation for 2006 (and pension expense for 2007), we increased our long-term rate of return assumption from 8.25% to 8.50% and changed our discount rate to 5.90%.
We also currently provide certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for retirees who were members of the United Mine Workers of America is not contributory. Our current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid. We account for our other postretirement benefits in accordance with Statement of Financial Accounting Standards No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions, as amended by
Statement No. 158. Statement No. 158 requires that the actuarially-determined funded status of the plans be recorded in the balance sheet.
In 2005, the disposition of the Central Appalachia operations to Magnum constituted a settlement of our postretirement benefit obligation for which we recognized a loss of $59.2 million. The only remaining participants in the postretirement benefit plan have their benefits capped at current levels.
Actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. The discount rate assumption reflects the rates available on high-quality fixed-income debt instruments at year-end and is calculated in the same manner as discussed above for the pension plan. The discount rate used to calculate the postretirement benefit expense was 5.8% for 2006 and 6.0% for 2005. Had the discount rate been lowered by 0.5% in 2006, we would have incurred additional expense of $0.9 million.
For the measurement of our year-end other postretirement obligation for 2006 and postretirement expense for 2007, we changed our discount rate to 5.9%. Because postretirement costs for remaining participants are capped at current levels, future changes in healthcare costs have no future effect on the plan benefits.
On December 31, 2006, we adopted Statement No. 158, which requires that an employer recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its balance sheet and to recognize changes in the funded status though comprehensive income when they occur.
We provide for deferred income taxes for temporary differences arising from differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance may be recorded to reflect the amount of future tax benefits that management believes are not likely to be realized. In determining the appropriate valuation allowance, we take into account expected future taxable income and available tax planning strategies. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, we may record additional valuation allowance through income tax expense in the period such determination is made.
Accounting Standards Issued and Not Yet Adopted
In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, which we refer to as FIN 48. FIN 48 prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. While we expect there will be some impact of recognizing tax positions previously unrecognized under Statement of Financial Accounting Standards No. 5, Accounting for Contingencies, we are still analyzing FIN 48 to determine what the impact of adoption will be as of the implementation date of January 1, 2007.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, which we refer to as Statement No. 157. Statement No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Statement No. 157 applies under other accounting pronouncements that require or permit fair value measurements.
Statement No. 157 is effective prospectively for fiscal years beginning after November 15, 2007, and interim periods within that fiscal year. We are still analyzing Statement No. 157 to determine what the impact of adoption will be.
We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. At December 31, 2006, based on current expectations of production over the next three years, we expect production available for repricing of approximately 11 million to 16 million tons in 2007, 75 million to 85 million tons in 2008 and 110 million to 120 million tons in 2009.
We are exposed to price risk related to the value of sulfur dioxide emission allowances that are a component of quality adjustment provisions in many of our coal supply contracts. We have purchased put options and entered into swap contracts to reduce volatility in the price of sulfur dioxide emission allowances. These contracts serve to protect us from any possible downturn in the price of sulfur dioxide emission allowances. The put option agreements grant us the right to sell a certain quantity of sulfur dioxide emission allowances at a specified price on a specified date. The swap agreements fix the price we receive for sulfur dioxide emission allowances by allowing us to receive a fixed sulfur dioxide allowance price and pay a floating sulfur dioxide allowance price. We may also purchase call options to mitigate the risk of changes in the fair value of a contract that contains a fixed price for sulfur dioxide emission allowances.
We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. We enter into forward physical purchase contracts and heating oil swaps and options to reduce volatility in the price of diesel fuel for our operations. The swap agreements essentially fix the price paid for diesel fuel by requiring us to pay a fixed heating oil price and receive a floating heating oil price. The call options protect against increases in diesel fuel by granting us the right to participate in increases in heating oil prices. The changes in the floating heating oil price highly correlate to changes in diesel fuel prices. Accordingly, the derivatives qualify for hedge accounting and the changes in the fair value of the derivatives are recorded through other comprehensive income.
We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2006, substantially all of our outstanding debt bore interest at fixed rates. In the past, we have utilized interest rate swap agreements to modify the interest characteristics of our floating-rate debt. We had no swaps outstanding as of December 31, 2006.
The discussion below presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen. The major accounting policies for these instruments are described in the notes to our consolidated financial statements.
With respect to our sulfur dioxide emission allowance put option and swap positions, as well as our heating oil swap positions, a change in price of the underlying products impacts our net financial instrument position. At December 31, 2006, a $100 decrease in the price of sulfur dioxide emission allowances would result in a $0.4 million increase in the fair value of the financial position of our sulfur dioxide emission
allowance put option and swap agreements, and a $100 increase would result in a $0.2 million increase in the fair value of the call options. At December 31, 2006, a $0.05 per gallon increase in the price of heating oil would result in a $0.9 million increase in the fair value of the financial position of our heating oil swap agreements.
The consolidated financial statements and consolidated financial statement schedule of Arch Coal, Inc. and subsidiaries are included in this Annual Report on Form 10-K beginning on page F-1.
We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2006. Based on that evaluation, our management, including our chief executive officer and chief financial officer, concluded that the disclosure controls and procedures were effective as of such date. There were no changes in internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
We incorporate by reference the report of independent registered public accounting firm and managements report on internal control over financial reporting included on pages F-2 and F-5, respectively, of this Annual Report on Form 10-K.
We incorporate by reference the information under the heading Code of Conduct appearing in the section entitled Corporate Governance, the information under the headings Nominees for a Three-Year Term That Will Expire in 2010, Directors Whose Terms Will Expire in 2008, Directors Whose Term Will Expire in 2009 and Board Meetings and Committees Audit Committee appearing in the section entitled Election of Directors and the information appearing under the heading Section 16(a) Beneficial Ownership Reporting Compliance appearing in the section entitled Ownership of Arch Coal Common Stock in our proxy statement to be distributed to stockholders in connection with the 2007 annual meeting. You should also see the list of our executive officers and related information under Executive Officers beginning on page 25.
We submitted our most recent chief executive officer certification to the New York Stock Exchange on May 1, 2006.
We incorporate by reference the information under the heading Director Compensation appearing in the section entitled Election of Directors and the information under the headings Compensation Discussion and Analysis, Summary Compensation Table, Grants of Plan-Based Awards for the Year Ended December 31, 2006, Outstanding Equity Awards at December 31, 2006, Option Exercises and Stock Vested for the Year Ended December 31, 2006, Pension Benefits, Nonqualified Deferred Compensation and Potential Payments Upon Termination of Employment or Change-in-Control appearing in the section entitled Compensation of Executive Officers in our proxy statement to be distributed to stockholders in connection with the 2007 annual meeting.
We incorporate by reference the information appearing under the headings Ownership by Directors and Executive Officers and Ownership by Others appearing in the section entitled Ownership of Arch Coal Common Stock in our proxy statement to be distributed to stockholders in connection with the 2007 annual meeting.
Securities Authorized for Issuance Under Equity Compensation Plans
The Arch Coal, Inc. 1997 Stock Incentive Plan, which has been approved by our stockholders, is the sole plan under which we are authorized to issue shares of our common stock to employees. The following table shows the number of shares of common stock to be issued upon exercise of options outstanding at December 31, 2006, the weighted average exercise price of those options, and the number of shares of common stock remaining available for future issuance at December 31, 2006, excluding shares to be issued upon exercise of outstanding options. No warrants or rights had been issued under the plan as of December 31, 2006.
We incorporate by reference the information under the headings Overview and Director Independence appearing in the section entitled Corporate Governance in our proxy statement to be distributed to stockholders in connection with the 2007 annual meeting.
We incorporate by reference the information under the heading Independent Registered Public Accounting Firm appearing in the section entitled Additional Information in our proxy statement to be distributed to stockholders in connection with the 2007 annual meeting.
The consolidated financial statements and consolidated financial statement schedule of Arch Coal, Inc. and subsidiaries are included in this Annual Report on Form 10-K beginning on page F-1.
You should see the exhibit index for a list of exhibits included in this Annual Report on Form 10-K.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements of Arch Coal, Inc. and subsidiaries and reports of independent registered public accounting firm follow.
Index to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Arch Coal, Inc.
We have audited managements assessment, included in the accompanying Managements Report on Internal Control over Financial Reporting, that Arch Coal, Inc. (the Company) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Arch Coal Inc.s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on managements assessment and an opinion on the effectiveness of the Companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating managements assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorization of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that Arch Coal, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion Arch Coal, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Arch Coal, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders equity, and cash flows for each of the three years in the period ended December 31, 2006, of Arch Coal, Inc. and our report dated February 26, 2007, expressed an unqualified opinion thereon.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Arch Coal, Inc.
We have audited the accompanying consolidated balance sheets of Arch Coal, Inc. and subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in item 15. These financial statements and schedule are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arch Coal, Inc. and subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for share-based payments effective January 1, 2006. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for stripping costs effective January 1, 2006. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for pension and other postretirement benefits effective December 31, 2006.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Arch Coal, Inc.s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2007, expressed an unqualified opinion thereon.
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Arch Coal, Inc. (the Company) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Securities Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Companys management, including its principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria set forth in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, management concluded that the Companys internal control over financial reporting is effective as of December 31, 2006.
Managements assessment of the effectiveness of the Companys internal control over financial reporting as of December 31, 2006 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included on page F-2.
REPORT OF MANAGEMENT
The management of Arch Coal, Inc. (the Company) is responsible for the preparation of the consolidated financial statements and related financial information in this annual report. The financial statements are prepared in accordance with accounting principles generally accepted in the United States and necessarily include some amounts that are based on managements informed estimates and judgments, with appropriate consideration given to materiality.
The Company maintains a system of internal accounting controls designed to provide reasonable assurance that financial records are reliable for purposes of preparing financial statements and that assets are properly accounted for and safeguarded. The concept of reasonable assurance is based on the recognition that the cost of a system of internal accounting controls should not exceed the value of the benefits derived. The Company has a professional staff of internal auditors who monitor compliance with and assess the effectiveness of the system of internal accounting controls.
The Audit Committee of the Board of Directors, comprised of independent directors, meets regularly with management, the internal auditors, and the independent auditors to discuss matters relating to financial reporting, internal accounting control, and the nature, extent and results of the audit effort. The independent auditors and internal auditors have full and free access to the Audit Committee, with and without management present.
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of the consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of the consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Three Years Ended December 31, 2006
The accompanying notes are an integral part of the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS