SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

For the fiscal year ended: December 31, 2004
or

For the transition period from            to

Commission File Number: 333-107569-03

ARCH WESTERN RESOURCES, LLC

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

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

Securities registered pursuant to Section 12(g) of the Act: None

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes o No þ

     At March 1, 2005, Arch Western’s common equity consisted solely of undenominated membership interests. 99.5 percent of such membership interests are held by Arch Western Acquisition Corporation. The other 0.5% is held by a subsidiary of BP p.l.c.

Documents incorporated by reference:

     None.

TABLE OF CONTENTS

PART I

ITEM 1. BUSINESS

General

     Arch Western Resources, LLC (“Arch Western” “we”, “us” or the “Company”) mines and processes compliance and low-sulfur coal from mines located in the western United States. As of December 31, 2004, the Company had four operating mines and controlled approximately 2.6 billion tons of proven and probable coal reserves. Arch Western sold 86.3 million tons of coal in 2004. The Company sells substantially all of its coal to producers of electric power.

     Ninety-nine percent of the membership interests in Arch Western are held by Arch Western Acquisition Corporation, a wholly-owned subsidiary of Arch Coal, Inc. (“Arch Coal”). The remaining 1% is held by a subsidiary of BP p.l.c. The principal operating units of Arch Western are Thunder Basin Coal Company, L.L.C., which operates the Black Thunder mine in the Powder River Basin in Wyoming and owns the idle Coal Creek mine in the same region; Mountain Coal Company, L.L.C., which operates the West Elk mine in Colorado; Canyon Fuel Company, LLC (“Canyon Fuel”), which operates three mines in Utah, one of which was idled during 2004; and Arch of Wyoming, LLC, which operated two mines in the Hanna Basin of Wyoming which are now in reclamation mode. Arch Western owns 100% of the membership interests of Thunder Basin Coal Company, L.L.C., Mountain Coal Company, L.L.C. and Arch of Wyoming, LLC. Arch Western owns a 65% membership interest in Canyon Fuel, with the remaining 35% membership interest owned by Arch Coal.

Business

     Arch Western is one of the largest and most productive operators of compliance and low sulfur coal mines in the United States. The Company sold 86.3 million tons of coal in 2004, all of which was compliance and low sulfur coal. Arch Western has a total of four operating mines. Its largest mine, Black Thunder, is located in Wyoming in the Powder River Basin, the largest and fastest-growing U.S. coal-producing region. The Company is also the largest producer of coal in the Western Bituminous Region, where it operates one underground mine in Colorado and two underground mines in Utah. As of December 31, 2004 the Company controlled approximately 2.6 billion tons of proven and probable compliance and low sulfur coal reserves.

     The Company sells substantially all of its coal to producers of electric power, most of whom are large, investment grade utilities. For the year ended December 31, 2004, it derived 22% of its total coal revenues from sales to its largest customers, Southern Company and Tennessee Valley Authority, and 59% of its total revenues from sales to its ten largest customers.

     The coal industry is intensely competitive. The Company competes with four major coal producers in the Powder River Basin area and effectively competes with a large number of eastern and western coal producers in the markets that it serves. Excess industry capacity, which has occurred in the past, tends to result in reduced prices for coal. In addition to competition from other coal producers, the Company also competes with producers of alternative fuels used to produce electric power, such as natural gas, petroleum, nuclear and hydropower.

     The most important factors on which the Company competes are coal price at the mine, coal quality characteristics, transportation costs from the mine to the customer and the reliability of supply. Demand for coal and the prices that the Company will be able to obtain for its coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for approximately 91% of domestic coal consumption in recent years. These coal consumption patterns are influenced by factors beyond the Company’s control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of coal, alternative fuels such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power. Demand for its low sulfur coal and the prices that Arch Western will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances in order to meet Clean Air Act requirements.

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Operations

     As of December 31, 2004, the Company operated a total of four mines, all located in the western United States. The Company uses three distinct extraction techniques: continuous mining, longwall mining, and dragline mining. Coal is transported from the Company’s mining complexes to customers by means of railroad cars or trucks, or a combination of these means of transportation. As is customary in the industry, virtually all the Company’s coal sales are made F.O.B. mine or loadout, meaning that customers are responsible for the cost of transporting purchased coal to their facilities.

     The Company manages its production sources to supply coal within two of the major low sulfur coal producing basins in the United States — the Powder River Basin and the Western Bituminous region. These geographically distinct areas are characterized by similar geology, coal transportation routes to consumers, regulatory environments and coal quality. These regional similarities have caused market and contract pricing environments to develop by coal basin and form the basis for the Company’s segmentation of its operations.

     Coal prices are influenced by a number of factors and vary dramatically by region. As a result of these regional characteristics, prices of coal within a given major coal producing basin tend to be relatively consistent. The two principal components of the price of coal within a region are the price of coal at the mine, which is influenced by market conditions (supply and demand) and by mine operating costs, coal quality, and transportation costs involved in moving coal from the mine to the point of use. In addition to supply and demand factors, the price of coal at the mine is influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Underground mining, which is the mining method the Company uses in the Western Bituminous region, is generally more expensive than surface mining, which is the mining method the Company uses in the Powder River Basin. This is the case because of the higher capital costs, including costs for modern mining equipment and construction of extensive ventilation systems and higher labor costs due to lower productivity that are associated with underground mining.

     In addition to the cost of mine operations, the price of coal is also a function of quality characteristics such as heat value, sulfur, ash and moisture content. Higher carbon and lower ash content generally result in higher prices. The coal from the Western Bituminous region typically has a sulfur content of 0.50% to 1% and a heat content of between 10,500 and 12,500 Btus per pound. Powder River Basin coal generally has lower relative sulfur content between the Company’s regions, with a sulfur content of between 0.20% and 0.35%, and lower relative heat content, which typically is between 8,200 and 9,000 Btus per pound.

     The following map shows the locations of the Company’s significant mining operations:

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     The following table provides the location and a summary of information regarding the Company’s principal mining complexes and the total sales associated with these operations for the prior three years:

	(1)	Captive mines are mines which the Company owns and operates on land owned or leased by it.
	(2)	Utilizes 164-cubic-yard, 130-cubic-yard, 106-cubic-yard, 78-cubic-yard and 45-cubic-yard draglines and 85-cubic-yard, 73-cubic-yard, 68-cubic-yard, 55-cubic-yard and 53-cubic-yard shovels.
	(3)	The Company idled its mining operations at Coal Creek during the third quarter of 2000 because of unfavorable conditions existing in the market environment.
	(4)	The Company owns a 65% interest in Canyon Fuel with the remaining 35% owned by Arch Coal. Amounts shown represent 100% of Canyon Fuel’s sales volume for all periods presented. The Skyline mine was idled in 2004.
	(5)	This complex was put into reclamation mode in 2004.

     Black Thunder. The Black Thunder mine is located in Campbell County, Wyoming on approximately 24,150 acres. Mining the approximately 68-foot coal seam are five draglines and eleven shovels. There is no washing plant at Black Thunder. The coal is crushed through one of three crushing facilities. Coal from these crushing facilities is conveyed into silos or a slot storage facility. Coal is shipped through three loadouts on trains operated by Burlington Northern and Union Pacific.

     Coal Creek. The Coal Creek mine is located in Campbell County, Wyoming on approximately 7,030 acres. Coal Creek has been idle since July 2000. The Coal Creek mine is located on a joint rail line operated by Burlington Northern and Union Pacific.

     West Elk. The West Elk mine is an underground operation located in Gunnison County, Colorado on approximately 11,900 acres. The coal is mined by three continuous miners in support of a longwall. The loadout facility at the mine is serviced by the Union Pacific Railroad.

     Skyline. Canyon Fuel’s Skyline mine is an underground longwall mine located in Carbon County and Emery County, Utah on approximately 9,650 acres. The loadout facility at Skyline is serviced by the Union Pacific Railroad. The Skyline mine was idled during 2004.

     SUFCO. Canyon Fuel’s SUFCO mine, an underground longwall mine, is located in Sevier County, Juab County and Emery County, Utah on approximately 26,700 acres. Two continuous miners support the longwall. All of the coal

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produced from the mine is crushed at a facility located at the mine and trucked either directly to customers or to a train loadout located approximately 80 miles from the mine. The Union Pacific Railroad serves this loadout.

     Dugout Canyon. Canyon Fuel’s Dugout Canyon mine is an underground longwall mine located in Carbon, County, Utah on approximately 7,800 acres. Two continuous miners support the longwall operation. The coal produced is crushed at the mine and trucked to a third party loadout served by the Union Pacific Railroad.

Transportation

     Coal from the mines of the Company’s subsidiaries is transported by rail and truck.

Regulations Affecting Coal Mining

      The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:

•	the discharge of materials into the environment;
•	employee health and safety;
•	mine permits and other licensing requirements;
•	reclamation and restoration of mining properties after mining is completed;
•	management of materials generated by mining operations;
•	surface subsidence from underground mining;
•	water pollution;
•	legislatively mandated benefits for current and retired coal miners;
•	air quality standards;
•	protection of wetlands;
•	endangered plant and wildlife protection;
•	limitations on land use;
•	storage of petroleum products and substances that are regarded as hazardous under applicable laws; and
•	management of electrical equipment containing polychlorinated biphenyls, or PCBs.

      In addition, the electric generating industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on our mining operations or our customers’ ability to use coal and may require the Company or its customers to significantly change operations or to incur substantial costs.

      While it is not possible to quantify the expenditures the Company incurs to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. The Company posts performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

      Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of the Company’s coal. These regulations can take a variety of forms, as explained below.

      The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standard for ozone. In particular, coal-fired power plants will be affected by state regulations designed to achieve attainment of the ambient air quality standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead.

      In July 1997, the EPA adopted more stringent ambient air quality standards for particulate matter and ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality

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standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. In April 2004, the EPA issued final nonattainment designations for the eight-hour ozone standard, and, in December 2004, issued the final nonattainment standard for PM25. States will have to reuse their State Implementation Plans to require electric power generators to further reduce nitrogen oxide and particulate matter emissions, particularly in designated nonattainment areas. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and our development of new mines. This in turn may result in decreased production and a corresponding decrease the Company’s revenues. Although the future scope of these ozone and particulate matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines.

      The EPA has also initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA’s regional haze program could affect the future market for coal.

      Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities for alleged violations of the Clean Air Act. The EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. We supply coal to some of the currently affected utilities, and it is possible that other of our customers will be sued. These lawsuits could require the utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely impact their demand for coal.

      New regulations concerning the routine maintenance provisions of the New Source Review program were published in October 2003. Fourteen states, the District of Columbia and a number of municipalities filed lawsuits challenging these regulations, and in December 2003 the Court stayed the effectiveness of these rules. Oral argument was heard on this matter in January 2005. In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, EPA issued enforcement notices to several electric utility companies.

      In January 2004, the EPA proposed two new rules pursuant to the Clean Air Act that, once final, may require additional controls and impose more stringent requirements at coal-fired power generation facilities. First, EPA is seeking to lower nickel and mercury emissions at new and existing sources by requiring the use of Maximum Achievable Control Technology (“MACT”) or by implementing a nationwide “cap and trade” program. Second, EPA has proposed to require the submission of State Implementation Plans by 29 states and the District of Columbia to include control measures to reduce the emissions of sulfur dioxide and/or nitrogen oxides, pursuant to the eight-hour ozone and PM25 standards established pursuant to the Clean Air Act. The EPA has stated that it will issue new rules in 2005. Should either or both of these proposed rules become final, additional costs may be associated with operating coal-fired power generation facilities that may render coal a less attractive fuel source.

      Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants of greater than 25 megawatt capacity. Affected electric

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utilities can comply with these requirements by:

•	burning lower sulfur coal, either exclusively or mixed with higher sulfur coal;
•	installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal;
•	reducing electricity generating levels; or
•	purchasing or trading emissions credits.

      Specific emissions sources receive these credits, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows its holder to emit one ton of sulfur dioxide.

      In addition to emissions control requirements designed to control acid rain and to attain the national ambient air quality standards, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009. These controls are likely to require significant new improvements in controls by power plant owners. The most prominently targeted pollutant is mercury, which is already the subject of a proposed rule, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources.

      Other proposed initiatives may have an effect upon coal operations. One such proposal is the Bush Administration’s recently announced Clear Skies Initiative. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury from power plants. Other so-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of air pollutants. Were such initiatives enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.

      Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease.

      Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, the Company is 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 the Company 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.

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      Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel.

      Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, the Company 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, the Company may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

      Regulatory authorities exercise considerable discretion in the timing of permit issuance. Also, private individuals and the public at large possess rights to comment on and otherwise engage in the permitting process, including by filing a lawsuit against the Company or the issuing agency. Accordingly, the permits the Company needs for its mining operations may not be issued, or, if issued, may not be issued in a timely fashion, or may involve requirements that may be changed or interpreted in a manner which restricts its ability to conduct our mining operations or to do so profitably.

      In order to obtain mining permits and approvals from state regulatory authorities, mine operators 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 the Company submits the necessary permit applications at least one year before it plans to begin mining a new area. In the Company’s experience, permits generally are approved several months to a year after a completed application is submitted. In the past, the Company has generally obtained its mining permits without significant delay. However, it cannot be sure that we will not experience difficulty in obtaining mining permits in the future.

      Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the activities of mine operators, including the Company, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations.

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      Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

      Surety Bonds. Federal and state laws require the Company to obtain surety bonds to guarantee performance or payment of certain long-term obligations including mine closure and reclamation costs, federal and state workers’ compensation benefits, coal leases and other miscellaneous obligations. It has become increasingly difficult for the Company to secure new surety bonds or retain existing bonds without the posting of collateral. In addition, surety bond costs have increased and the market terms of such bonds have generally become more unfavorable.

      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 the Company 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 the Company’s 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, the Company does not believe there are any species protected under the Endangered Species Act that would materially and adversely affect its ability to mine coal from its properties in accordance with current mining plans.

      Other Environmental Laws Affecting the Company. The Company is 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. The Company believes that it is in substantial compliance with all applicable environmental laws.

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Glossary of Selected Mining Terms

     Assigned Reserves. Recoverable coal reserves that have been designated for mining by a specific operation.

     Btu — British Thermal Unit. A measure of the energy required to raise the temperature of one pound of water one degree Fahrenheit.

     Compliance Coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, which is equivalent to .72% sulfur per pound of 12,000 Btu coal. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the federal Clean Air Act.

     Continuous Miner. A machine used in underground mining to cut coal from the seam and load it into conveyors or into shuttle cars in a continuous operation.

     Continuous Mining. One of two major underground mining methods now used in the United States (also see Longwall Mining”). This process utilizes a continuous miner. The continuous miner removes or “cuts” the coal from the seam. The loosened coal then falls on a conveyor for removal to a shuttle car or larger conveyor belt system.

     Dragline. A large machine used in the surface mining process to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket suspended from the end of a long boom. The bucket, which is suspended by cables, is able to scoop up great amounts of overburden as it is dragged across the excavation area.

     Dragline Mining. A method of mining where large capacity draglines remove overburden to expose the coal seams.

     Longwall Mining. One of two major underground coal mining methods now used in the United States (see also “Continuous Mining”). This method employs a rotating drum, which is pulled mechanically back and forth across a face of coal that is usually several hundred feet long. The loosened coal falls onto a conveyor for removal from the mine. Longwall operations include a hydraulic roof support system that advances as mining proceeds, allowing the roof to fall in a controlled manner in areas already mined.

     Low-Sulfur Coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.

     Probable Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart; therefore, the degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

     Proven Reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for

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inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.

     Reclamation. The restoration of land and environmental values to a mining site after the coal is extracted. Reclamation operations are usually underway where the coal has already been taken from a mine, even as mining operations are taking place elsewhere at the site. The process commonly includes “recontouring” or shaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers.

     Recoverable Reserves. The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.

     Reserves. That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

     Shovel/Truck Mining. An open cast method of mining that uses large shovels to remove overburden, which is used to backfill pits after coal removal.

     Steam Coal. Coal used in steam boilers to produce electricity.

     Surface Mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.

     Tons. References to a “ton” mean a “short” or net tonne, which is equal to 2,000 pounds.

     Unassigned Reserves. Recoverable coal reserves that have not yet been designated for mining by a specific Company operation.

     Underground Mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.

Employees

     As of March 1, 2005, the Company employed a total of approximately 1,850 persons (including 100% of Canyon Fuel’s employees), none of whom are represented by a union.

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Management

     Arch Western’s managing member is an indirect wholly-owned subsidiary of Arch Coal. As a result, Arch Coal’s management is effectively Arch Western’s management.

     The following is a list of Arch Coal’s executive officers, their ages and their positions and offices held with Arch Coal during the last five years.

     Bradley M. Allbritten, 47, is Vice President — Marketing of Arch Coal and has served in such capacity since August 2002. From March 2000 to February 2003, Mr. Allbritten was Arch Coal’s Vice President — Human Resources. Mr. Allbritten served as Arch Coal’s Director of Human Resources from February 1999 through February 2000. From January 1995 to February 1999, Mr. Allbritten served as Human Resources Manager for Atlantic Richfield Company.

     C. Henry Besten, Jr., 56, is Senior Vice President — Strategic Development of Arch Coal and has served in such capacity since December 2002. Mr. Besten is also President of Arch Coal’s Arch Energy Resources, Inc. subsidiary and has served in that capacity since July 1997. From July 1997 to December 2002, Mr. Besten served as Vice President — Strategic Marketing of Arch Coal. Mr. Besten also served as Acting Chief Financial Officer of Arch Coal from December 1999 to November 2000.

     John W. Eaves, 47, is Executive Vice President and Chief Operating Officer of Arch Coal and has served in such capacity since December 2002. From February 2000 to December 2002, Mr. Eaves served as Senior Vice President — Marketing of Arch Coal and from September 1995 to December 2002 as President of Arch Coal’s Arch Western Sales Company, Inc. subsidiary. Mr. Eaves also served as Vice President — Marketing of Arch Coal from July 1997 through February 2000. Mr. Eaves serves on the board of directors of ADA-ES, Inc.

     Sheila B. Feldman, 50, is Vice President — Human Resources of Arch Coal and has served in such capacity since February 2003. From 1997 to February 2003, Ms. Feldman was the Vice President — Human Resources and Public Affairs of Solutia Inc.

     Robert G. Jones, 48, is Vice President — Law, General Counsel and Secretary of Arch Coal and has served in such capacity since March 2000. Mr. Jones served Arch Coal as Assistant General Counsel from July 1997 through February 2000 and as Senior Counsel from August 1993 to July 1997.

     Steven F. Leer, 52, is President and Chief Executive Officer and a Director of Arch Coal and has served in such capacity since 1992. Mr. Leer serves on the boards of the Norfolk Southern Corporation, the Western Business Roundtable and the Mineral Information Institute. Mr. Leer is past chairman and continues to serve on the boards of the Center for Energy and Economic Development, the National Coal Council and the National Mining Association.

     Robert J. Messey, 59, is Senior Vice President and Chief Financial Officer of Arch Coal and has served in such capacity since December 2000. Prior to joining Arch Coal, Mr. Messey served as Vice President of Financial Services of Jacobs Engineering Group Inc. from January 1999 and, prior to that, served as Senior Vice President and Chief Financial Officer of Sverdrup Corporation from 1992. Mr. Messey serves on the board of directors of Baldor Electric Company.

     David B. Peugh, 50, is Vice President — Business Development of Arch Coal and has served in such capacity since 1993.

The following is a list of Arch Coal’s directors, their ages and biographical information.

     James R. Boyd, 58, Arch Coal’s Chairman of the Board, has been a director of Arch Coal since 1990. He served as Senior Vice President and Group Operating Officer of Ashland Inc., a multi-industry company with operations in chemicals, motor oil, car care products and highway construction, from 1989 until his retirement in January 2002. Mr. Boyd is also a director of the Farmers Bank of Lynchburg, Tennessee.

     Frank M. Burke, Jr., 65, has been a director of Arch Coal since September 2000. He has served as Chairman, Chief Executive Officer and Managing General Partner of Burke, Mayborn Company, Ltd., a private investment and consulting company, since 1984. Mr. Burke is also a director of Kaneb Services, LLC, Xanser Corporation, Kaneb Pipe

11

Line Company (general partner of Kaneb Pipe Line Partners, LP), a member of the Board of Managers of Dorchester Minerals Management GP LLC (general partner of Dorchester Minerals, L.P.) and Crosstex Energy GP, LLC (general partner of Crosstex Energy, L.P.), a director of Crosstex Energy Inc. and a member of the National Petroleum Council.

     Patricia F. Godley, 56, has been a director of Arch Coal since 2004. Since 1998, Ms. Godley has been a partner with the law firm of Van Ness Feldman, practicing in the areas of economic and environmental regulation of electric utilities and natural gas companies. From 1994 until 1998, Ms. Godley served as the Assistant Secretary for Fossil Energy at the U.S. Department of Energy. Ms. Godley is also a director of the United States Energy Association and State Law Resources, Inc.

     Douglas H. Hunt, 51, has been a director of Arch Coal since 1995 and, since May 1995, has served as Director of Acquisitions of Petro-Hunt, L.L.C., a private oil and gas exploration and production company.

     Thomas A. Lockhart, 69, has been a director of Arch Coal since February 2003 and a member of the Wyoming State House of Representatives since 2000. Mr. Lockhart worked for PacificCorp, an electric utility, for over 30 years and retired in 1998 as a Vice President. Mr. Lockhart is also a director of Blue Cross Blue Shield of Wyoming and First Interstate Bank of Casper, Wyoming.

     A. Michael Perry, 68, has been a director of Arch Coal since 1998. He served as Chairman of Bank One, West Virginia, N.A. from 1993 and as its Chief Executive Officer from 1983 to his retirement in June 2001. Mr. Perry is also a director of Champion Industries, Inc.

     Robert G. Potter, 65, became a director of Arch Coal in April 2001. He was Chairman and Chief Executive Officer of Solutia Inc., a producer and marketer of a variety of high performance chemical-based materials, from 1997 until his retirement in 1999. Mr. Potter served for 32 years with Monsanto Company prior to its spin-off of Solutia in 1997, most recently as the Chief Executive of its chemical businesses. Mr. Potter is a Director of Stepan Company and of certain private companies of which he is also an investor.

     Theodore D. Sands, 59, has been a director of Arch Coal since 1999 and, since February 1999, has served as President of HAAS Capital, LLC, a private consulting and investment company. Mr. Sands served as Managing Director, Investment Banking for the Global Metals/ Mining Group of Merrill Lynch & Co. from 1982 until February 1999. Mr. Sands is also a director of Protein Sciences Corporation and Terra Nitrogen Corporation.

ITEM 2. PROPERTIES

     The Company estimates that it owned or controlled, as of December 31, 2004, approximately 2.6 billion tons of proven and probable recoverable reserves. Recoverable reserves include only saleable coal and do not include coal which would remain unextracted, such as for support pillars, and processing losses, such as washery losses. Reserve estimates are prepared by the Company’s engineers and geologists and reviewed and updated periodically. Total recoverable reserve estimates and reserves dedicated to mines and complexes change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings and other factors. The following tables present the Company’s estimated assigned and unassigned recoverable coal reserves at December 31, 2004:

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Total Assigned Reserves
(tonnage in millions)

		Total
		Assigned												Sulfur Content																																Past Reserve
		Recoverable												(lbs. Per million Btus)												As Received				Reserve Control								Mining Method								Estimates
		Reserves				Proven				Probable				< 1.2				1.2-2.5				> 2.5				Btu per lb.(1)				Leased				Owned				Surface				Underground				2002				2003
Wyoming (2)			1,840				1,791				49				1,782				58				—				8,804				1,840				—				1,840				—				1,089				1,025
Utah			112				59				53				112				—				—				11,652				110				2				—				112				125				116
Colorado			80				59				21				79				1				—				11,879				77				3				—				80				112				85
Total			2,032				1,909				123				1,973				59				—				9,087				2,027				5				1,840				192				1,326				1,226

Total Unassigned Reserves
(tonnage in millions)

     As of December 31, 2004, approximately 90,000 acres of the Company’s total of approximately 191,600 acres of coal land were leased by a subsidiary of Arch Coal from the federal government. The Company has subleased those federal lands from that subsidiary of Arch Coal on terms that are substantially identical to those of the underlying lease. In addition, approximately 101,600 acres were leased by the Company from state governments and from private lessors. These leases have terms expiring between 2005 and 2025, subject to readjustment or extension and to earlier termination for failure to meet development requirements. Under current mining plans, all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewal periods.

     Reserves at properties leased by the Company to other coal operators represent an immaterial amount of its coal reserves and are included in its reserve figures set forth in this Annual Report in accordance with the SEC’s Industry Guide 7. All of the identified coal reserves held by the Company have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 95.5% consist of compliance coal. Accordingly, its reserves are primarily suitable for the domestic steam coal markets.

     The Company’s federal coal leases are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover its principal reserves in Wyoming and other reserves in Utah and Colorado. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at ten-year intervals thereafter. Annual rents under its federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2004, the Company leased or had applied to lease approximately 11,900 acres of federal land in Colorado, approximately 41,000 acres in Utah and approximately 37,050 acres in Wyoming.

     Title to coal properties that the Company leases or purchases and the boundaries of such properties generally are verified at the time of leasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completely verified until such time as the Company prepares to mine such

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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.

     The Company must obtain permits from applicable state regulatory authorities before it begins to mine reserves. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and other impacts on the environment, the construction of overburden fills and water containment areas and reclamation of the area after coal extraction. The Company is required to post bonds to secure its performance under its permits. As is typical in the coal industry, the Company strives to obtain mining permits within a time frame that allows the Company to mine reserves as planned on an uninterrupted basis. The Company generally begins preparing applications for permits for areas that the Company intends to mine up to three years in advance of their expected issuance date. Regulatory authorities have considerable discretion in the timing of permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

     The Company’s reported coal reserves are those that could be economically and legally extracted or produced at the time of their determination. In determining whether its reserves meet this standard, the Company takes into account, among other things, its 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 obtain mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. The Company has obtained, or the Company has a very high probability of obtaining, all required permits or government approvals with respect to its reserves. The Company is not currently aware of matters which would significantly hinder its ability to obtain future mining permits or governmental approvals with respect to its reserves.

     The Company periodically engages third parties to review its reserve estimates. The most recent third party review of its reserve estimates was conducted by Weir International Mining Consultants in April 2003.

     The net book value of the Company’s coal reserves at December 31, 2004 was $522.7 million.

ITEM 3. LEGAL PROCEEDINGS

     The information required by this Item is contained in the “Contingencies — Legal Contingencies” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on Form 10-K and is incorporated herein by reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     There is no market for Arch Western’s common equity.

ITEM 6. SELECTED FINANCIAL DATA

Arch Western Selected Consolidated Financial and Operating Data

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

     In this Annual Report, statements that are not reported financial results or other historical information are “forward-looking statements.” Forward-looking statements give current expectations or forecasts of future events and are not guarantees of future performance. They are based on our management’s expectations that involve a number of business risks and uncertainties, any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements.

     Forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts. They use words such as “anticipate,” “estimate,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. In particular, these include statements relating to:

	•	our expectation of continued growth in the demand for our coal by the domestic electric generation industry;
	•	our belief that legislation and regulations relating to the Clean Air Act and other proposed environmental initiatives and the relatively higher costs of competing fuels will increase demand for our compliance and low sulfur coal;
	•	our expectations regarding incentives to generators of electricity to minimize their fuel costs as a result of electric utility deregulation;
	•	our expectation that we will continue to have adequate liquidity from cash flow from operations;
	•	a variety of market, operational, geologic, permitting, labor and weather related factors;
	•	our expectations regarding any synergies to be derived from the Triton acquisition; and
	•	the other risks and uncertainties which are described below under “Contingencies” and “Certain Trends and Uncertainties,” including, but not limited to, the following:

	•	A reduction in consumption by the domestic electric generation industry may cause our profitability to decline.
	•	Extensive environmental laws and regulations could cause the volume of our sales to decline.
	•	The coal industry is highly regulated, which restricts our ability to conduct mining operations and may cause our profitability to decline.
	•	We may not be able to obtain or renew our surety bonds on acceptable terms.
	•	Unanticipated mining conditions may cause profitability to fluctuate.
	•	Intense competition and excess industry capacity in the coal producing regions has adversely affected our revenues and may continue to do so in the future.
	•	Deregulation of the electric utility industry may cause customers to be more price-sensitive, resulting in a potential decline in our profitability.
	•	Our profitability may be adversely affected by the status of our long-term coal supply contracts.
	•	Decreases in purchases of coal by our largest customers could adversely affect our revenues.
	•	Unavailability of coal reserves would cause our profitability to decline.
	•	Disruption in, or increased costs of, transportation services could adversely affect our profitability.

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	•	Numerous uncertainties exist in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower revenues, higher costs or decreased profitability.
	•	Title defects or loss of leasehold interests in our properties could result in unanticipated costs or an inability to mine these properties.
	•	Some of our agreements limit our ability to manage our operations exclusively.
	•	Our expenditures for postretirement medical and pension benefits have increased since 2002 and could further increase in the future.
	•	Our inability to comply with restrictions imposed by our credit facilities and other debt arrangements could result in a default under these agreements.
	•	Our estimated financial results may prove to be inaccurate.

     We cannot guarantee that any forward-looking statements will be realized, although we believe that we have been prudent in our plans and assumptions. Achievement of future results is subject to risks, uncertainties and assumptions that may prove to be inaccurate. Should known or unknown risks or uncertainties materialize, or should underlying assumptions prove to be inaccurate, actual results could vary materially from those anticipated, estimated or projected.

     We undertake no obligation to publicly update forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. You are advised, however, to consider any additional disclosures that we or Arch Coal may make on related subjects in future filings with the SEC. You should understand that it is not possible to predict or identify all factors that could cause our actual results to differ. Consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties.

Overview

     We were formed as a joint venture on June 1, 1998 when Arch Coal acquired the U.S. coal operations of Atlantic Richfield Company and combined these operations with Arch Coal’s western operations. Our common membership interests are owned 99.5% by Arch Coal and ..5% by an affiliate of BP p.l.c., the successor to Atlantic Richfield Company. The BP p.l.c. affiliate also holds a .5% preferred membership interest. Arch Western Acquisition Corporation, a wholly owned subsidiary of Arch Coal, acts as our managing member.

     We are a producer and marketer of low-sulfur coal, which we supply principally to domestic electric utilities and independent power producers. We operate large, modern mines in the western United States. These mines are among the most productive in the regions in which they operate and are supported by an extensive reserve base totaling 2.6 billion tons.

     We derive approximately 67% of our revenues from long-term supply contracts (defined as having terms of one year or greater). These supply agreements typically have terms of one to three years, although certain contracts have much longer durations. The remainder of our coal sales result from sales on the spot market.

     We operate four mines — a surface mine in the Powder River Basin, an underground longwall mine in Colorado and two underground longwall mines in Utah (through our 65% ownership interest in Canyon Fuel Company, LLC). In addition, we have announced plans to begin development work on another longwall mine at the currently idle Skyline complex in Utah.

     Coal is the dominant fuel source for electric generation in the United States. Coal was the fuel source for 51% of the electricity generated in the United States in 2004. Furthermore, coal has significant advantages that should enable it to maintain or even increase market share over the course of the next two decades. First, coal is a low-cost fuel for electric generation, averaging less than one-third the cost of natural gas or crude oil per megawatt hour of generation. In addition, there is significant excess capacity at existing coal-based power plants, and this excess capacity represents a very low-cost source of electricity to the grid. At present, coal-based power plants are operating at an average utilization rate of 71%. We believe that there is significant potential to increase those utilization rates and thus drive increased coal demand. The U.S. Energy Information Administration projects that coal’s share of electric generation will increase to 52% by the year 2025.

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     The principal driver for U.S. coal demand is growth in domestic power generation. Domestic power needs are expected to grow over the next several years as the economy grows and the U.S. economy becomes increasingly electrified. The U.S. Energy Information Administration projects that power demand will continue to climb at a rate of 1.9% annually over the course of the next two decades.

     As energy demand grows, we believe that coal is well-positioned to supply much of this demand, as competing fuels that have played a prominent role in meeting the nation’s growing power demand in recent years are starting to be confronted with obstacles that could impede their future growth.

     America’s fleet of nuclear power plants, which is the second leading source of electric generation in the U.S. with a roughly 20% share, is operating near its effective capacity. Nuclear output has remained relatively flat since peaking in 2001. It appears unlikely that any new nuclear capacity will be constructed in the next five to 10 years.

     Natural gas, the source of roughly 17% of U.S. electricity supply, is facing growing concerns about the ability to increase North American production sufficiently to keep pace with demand. While imports of liquefied natural gas (“LNG”) are expected to alleviate some of this supply pressure in the future, it will likely be several years before LNG will play a meaningful role in U.S. electric generation.

     That means that coal will continue to act as the dominant fuel source for electric generation in the years ahead. In addition, we believe that low-sulfur coal will benefit disproportionately from future coal demand growth. Utilities have sought to comply with the sulfur dioxide standards contained in Phase II of the Clean Air Act by shifting increasingly to lower sulfur coals rather than building expensive scrubbing capacity. At present, less than 30% of eastern coal-based power generation is equipped with scrubbers. Until more scrubbing capacity is added, we believe that low-sulfur coal will have a significant advantage in the marketplace.

     Our management has positioned the company to benefit from these trends by focusing on cost containment and growth in our core operating regions.

     In recent quarters, operating costs have risen due in part to higher costs associated with medical benefits, workers’ compensation, insurance, explosives, diesel fuel, steel and surety bonding. We are focused on offsetting any future cost increases with cost savings and productivity improvements elsewhere. During 2005, we plan to capture operating synergies; continue our efforts to extend best practices across all mines; implement process improvements; apply cutting-edge maintenance programs; and invest in advanced technologies where appropriate and prudent.

     We currently anticipate that much or our future growth will be organic in nature. As demand for coal grows, we will evaluate the expansion of our existing operations and the development of new mines on our existing reserve base.

     Results of Operations

     Significant Developments

     On August 20, 2004, Arch Coal acquired (1) Vulcan Coal Holdings, L.L.C., which owns all of the common equity of Triton Coal Company, LLC (“Triton”), and (2) all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Upon acquisition, Arch Coal contributed the assets and liabilities of Triton’s North Rochelle mine (excluding coal reserves) to us. Upon contribution, we integrated the operations of the North Rochelle mine with our existing Black Thunder mine in the Powder River Basin.

     On July 31, 2004, Arch Coal purchased the 35% interest in Canyon Fuel Company, LLC (“Canyon Fuel”) not owned by us. Through July 31, 2004, our interest in Canyon Fuel was accounted for on the equity method as a result of certain super-majority voting rights in the Canyon Fuel joint venture agreement. Upon Arch Coal’s acquisition of the 35% interest, Canyon Fuel’s joint venture agreement was amended to eliminate the super-majority voting rights. As a result, for periods subsequent to July 31, 2004, we consolidated 100% of the results of Canyon Fuel in our financial statements and recorded minority interest for Arch Coal’s 35% interest in Canyon Fuel. Amounts included in the accompanying consolidated financial statements for Canyon Fuel represent amounts recorded under the equity method of accounting

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through July 31, 2004 and amounts consolidated in our financial statements subsequent to that date.

     Items Affecting Comparability of Reported Results

     The comparison of our operating results for the years ending December 31, 2004, 2003 and 2002 are affected by the following significant items:

     Severance Costs — Skyline Mine. During 2004, Canyon Fuel, which was accounted for under the equity method through July 31, 2004, began the process of idling its Skyline Mine (the idling process was completed in May 2004), and incurred severance costs totaling $3.2 million. Our share of these costs totals $2.1 million and is reflected in income from equity investments.

     Gain from land sale. During 2004, we assigned our rights and obligations on a parcel of land to a third party resulting in a gain of $5.8 million. The gain is reflected in other operating income.

     Retroactive Royalty Rate Adjustments. During 2004 and 2002, we filed a royalty rate reduction request with the Bureau of Land Management (“BLM”) for our West Elk mine in Colorado. The BLM notified us that we would receive a royalty rate reduction for a specified number of tons representing retroactive portions for the respective years totaling $2.7 million and $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in both years. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments.

     Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps. On June 25, 2003, we repaid our term loans with the proceeds from the offering of senior notes. In connection with the repayment of the term loans, we recognized expenses related to the write-off of loan fees and other debt extinguishment costs. Additionally, we had designated certain interest rate swaps as hedges of the variable rate interest payments due under the term loans. Pursuant to the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”), historical mark-to-market adjustments related to these swaps through June 25, 2003 were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the contractual terms of the swap agreements. For the years ending December 31, 2004 and 2003, we recognized expenses of $13.6 million and $7.0 million, respectively, related to the amortization of previously deferred mark-to-market adjustments. Additionally, in 2004 and 2003, we incurred expenses of $0.7 million and $4.7 million, respectively, related to early debt extinguishment costs.

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     Long-term incentive compensation plan expense. During the fourth quarter of 2003, Arch Coal’s Board of Directors approved awards under a four-year performance unit plan that began in 2000. Amounts accrued by us for the plan (included in cost of coal sales) totaled $2.2 million in 2003.

     Severance Tax Recoveries. During 2003, we were notified by the State of Wyoming of a favorable ruling relating to our calculation of coal severance taxes. The ruling resulted in a refund of previously paid taxes and the reversal of previously accrued taxes payable. The impact on the year ended December 31, 2003 was a gain of $2.5 million, which is reflected in cost of coal sales in the accompanying Consolidated Statements of Operations.

Revenues

(Amounts in thousands, except
per ton amounts)

     Coal sales revenues. The increase in coal sales resulted from the combination of higher pricing, increased sales volumes and the addition of the North Rochelle mining operations and the consolidation of Canyon Fuel.

     Sales volumes increased in both of our operating regions. The Powder River Basin volumes increased 19.9%, while Western Bituminous volumes increased 61.9% over 2003. These increases were primarily due to additional volumes from the Black Thunder mine following the contribution of the North Rochelle assets and to the inclusion of Canyon Fuel volumes.

     Per ton realizations increased in both the Powder River Basin and Western Bituminous region by 14.1% and 13.3%, respectively, due to higher contract prices in both regions. The per ton realizations were affected in the Powder River Basin by contracts that were contributed to us through Arch Coal’s acquisition of the North Rochelle operations. These contracts have higher pricing on average than our historical contracts.

Costs and Expenses

(Amounts in thousands, except per ton
amounts)

     Cost of coal sales. The increase in cost of coal sales is primarily due to the increase in coal sales revenues discussed above. Specific factors contributing to the increase are as follows:

	•	Consolidation of Canyon Fuel added $61.7 million for the months of August through December 2004.
	•	Excluding Canyon Fuel, production taxes and coal royalties (which are incurred as a percentage of coal sales realization) increased $48.1 million.
	•	Excluding Canyon Fuel, repairs and maintenance costs increased $15.3 million due partially to the property, plant and equipment additions resulting from the contribution of North Rochelle during the third quarter of 2004.

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	•	Poor rail performance during 2004 resulted in missed shipments and disruptions in production. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs.
	•	We experienced higher supply costs, primarily related to explosives (an increase of $6.4 million) and diesel fuel (an increase of $10.9 million).
	•	Costs for operating supplies increased $8.3 million due primarily to increased commodity and steel prices during the year.
	•	Incentive compensation costs increased $3.7 million for amounts expected to be earned under Arch Coal’s annual and long-term incentive plans based on operating results for the year ended December 31, 2004.

     Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property, plant and equipment additions resulting from the consolidation of Canyon Fuel and the contribution of North Rochelle during the third quarter of 2004.

     Regional Analysis:

Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.

     Powder River Basin — On a per-ton basis, operating costs in the Powder River Basin increased primarily due to increased production taxes and coal royalties ($46.0 million, or $0.31 per ton) and repairs and maintenance charges ($16.9 million, or $0.11 per ton) and to the higher explosives and diesel fuel costs discussed above. Additionally, average costs were higher due to the integration of the North Rochelle mine into our Black Thunder mine.

     Western Bituminous Region — Operating cost per ton at our Western Bituminous operations increased primarily due to increased repairs and maintenance costs, increased production taxes and coal royalties and disruptions in production caused by poor rail performance. The consolidation of the Canyon Fuel mines in July 2004 offset some of the per ton operating cost increases as the Canyon Fuel operations have slightly lower costs as compared to our other Western Bituminous operations.

     Selling, general and administrative expenses. Selling, general and administrative expenses represent expenses allocated to us from Arch Coal. The cost increase for the year ended 2004 compared to the prior year is a result of increased legal and professional fees and increases in compensation-related expenses at Arch Coal.

Other Operating Income

(Amounts in thousands)

     Income from equity investment. The decline in income from our equity investment results from the consolidation of Canyon Fuel into our financial statements subsequent to July 31, 2004, lower production and sales levels at Canyon Fuel during the period when we accounted for our investment under the equity method, and additional costs related to idling the Skyline Mine, including the severance costs noted above.

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     Other operating income. Other operating income consists of income from sources other than coal sales. The increase results primarily from a $5.8 million gain recognized from a land sale offset partially by a $3.7 million decrease in administration charges and production payments received from Canyon Fuel (these payments ceased as of the July 31, 2004 consolidation of Canyon Fuel in our financial statements).

Interest Expense, Net

(Amounts in thousands)

     Interest expense. The increase in interest expense results from a higher average interest rate in the first six months of 2004 as compared to the same period in 2003 as well as a higher amount of average borrowings from August through December 2004 as compared to the prior year. In 2004, the Company’s outstanding borrowings consist primarily of fixed rate borrowings, while borrowings in the first half of 2003 were primarily variable rate borrowings. Short-term interest rates in 2003 were lower than the fixed rate borrowing that makes up the majority of average debt balances in 2004.

     Interest income. Our cash transactions are managed by Arch Coal. Cash paid to or from us that is not considered a distribution or a contribution is recorded as a receivable from Arch Coal. The receivable balance earns interest from Arch Coal at the prime interest rate. The increase in interest income results primarily from a higher average receivable balance in 2004 as compared to 2003.

Other non-operating income and expense

(Amounts in thousands)

     Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. As described above, our results of operations for the years ended December 31, 2004 and 2003 include expenses of $13.6 million and $7.0 million, respectively, related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Additionally, we incurred expenses of $0.7 million and $4.7 million for early debt extinguishment costs in 2004 and 2003, respectively.

Net income before cumulative effect of accounting change

(Amounts in thousands)

     The increase in net income before cumulative effect of accounting change is due primarily to higher coal sales revenues and the effects of the North Rochelle contribution.

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Year Ended December 31, 2003, Compared to Year Ended December 31, 2002

     Operating results for 2003 versus 2002 and discussion of the 2003 results are provided below.

Revenues

(Amounts in thousands, except per
ton amounts)

     Coal sales revenues. The increase in coal sales in 2003 was the result of higher average pricing on coal shipped during 2003 as compared to 2002.

     Sales volumes decreased in both of our operating regions resulting from lower production at our Black Thunder mine in the Powder River Basin and our West Elk mine in the Western Bituminous Region.

     Per ton realizations increased due to higher contract prices in both regions (a 7.5% increase in the Powder River Basin and a 2.8% increase in Western Bituminous).

Costs and Expenses

(Amounts in thousands, except per ton
amounts)

     Cost of coal sales. The increase in cost of coal sales resulted from increased coal sales revenues, as certain of our costs (including severance and other production taxes and coal royalties) are incurred as a percentage of coal sales realization. Additionally, 2003 cost of coal sales reflect an increase in the cost of diesel fuel and explosives (which combined to result in increased costs of approximately $4.8 million), and the above-mentioned long-term incentive compensation charge.

     Depreciation, depletion and amortization. The decrease is primarily due to a decline in depletion in 2003 as compared to 2002 that relates to a decrease in overall sales volumes of 4.1%. The decrease also relates to a decline in the amortization of coal supply agreements in 2003 as compared to 2002. This was primarily the result of the expiration of a contract that was fully amortized in 2002. Amortization of $0.8 million was recognized on this contract in 2002.

     Regional Analysis:

     Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.

22

     Powder River Basin — On a per-ton basis, operating costs in the Powder River Basin increased due to increased repairs and maintenance charges ($3.0 million, or $0.08 per ton) and to the higher explosives and diesel fuel costs discussed above.

     Western Bituminous Region — Operating cost per ton at our Western Bituminous operations increased primarily due to increased operating supplies ($2.2 million, or $0.43 per ton) and repairs and maintenance costs ($1.8 million, or $0.37 per ton).

     Selling, general and administrative expenses. Selling, general and administrative expenses represent expenses allocated to us from Arch Coal. The cost increase for the year ended 2003 compared to the prior year is a result of an increase in compensation-related expenses at Arch Coal.

Other Operating Income

(Amounts in thousands)

     Income from equity investment. During 2003, Canyon Fuel, our equity investment, improved its operating margins, as reduced operating costs more than offset slightly lower realizations. Additionally, 2002 operating results were negatively impacted by a weak market environment for Utah coal throughout 2002 and by adverse geologic issues at one of Canyon Fuel’s mines.

Interest Expense, Net

(Amounts in thousands)

     Interest expense. The increase in interest expense results from higher outstanding debt levels and higher interest rates on outstanding borrowings. In 2003, we repaid our $675 million term loans with the proceeds from the issuance of the senior notes. The senior notes bear interest at a fixed rate of 6.75%, while term loans bore interest at a variable rate. Variable rates in 2002 were lower than the fixed rate in 2003.

     Interest income primarily from Arch Coal, Inc. The increase in interest income primarily from Arch Coal results from a higher average balance on the note receivable from Arch Coal.

Other non-operating expense

     Amounts reported as non-operating consist of expenses resulting from our financing activities other than interest. As described above, our results of operations for 2003 include expenses of $4.7 million related to debt extinguishment costs and $7.0 million related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. We did not incur any expenses for debt extinguishment or termination of hedge accounting in 2002.

Net Income Before Cumulative Effect of Accounting Change

(Amounts in thousands)

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     Increased net income before cumulative effect of accounting change results primarily from increased income from our equity investment in 2003 as compared to 2002, offset by the non-operating charges incurred in 2003.

Cumulative Effect of Accounting Change

     Effective January 1, 2003, we adopted FAS 143, Accounting for Asset Retirement Obligations, which requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of FAS 143 resulted in a cumulative effect loss as of January 1, 2003 of $18.3 million.

Disclosure and Internal Controls

     An evaluation was performed under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2004. Based on that evaluation, our management, including the CEO and CFO, concluded that the disclosure controls and procedures were effective as of such date. There have been no significant changes in our internal controls or in other factors that could significantly affect internal controls subsequent to December 31, 2004.

Outlook

     Railroad Transportation Disruptions. During 2004, rail service disruptions resulted in missed shipments in both of our operating regions. In addition, we were periodically forced to curtail production at the Black Thunder mine in Wyoming due to high inventory levels stemming from insufficient rail service. Inventory levels increased more than 99% to 14.9 million tons as of December 31, 2004.

     The railroad disruptions, which initially resulted from inadequate staffing at the railroads, equipment shortages and an unexpected increase in overall rail shipments, improved somewhat during the third and fourth quarters. We anticipate continued challenges, with gradual improvement in rail service in the first half of 2005. We are working with our customers and the railroads in an effort to address these issues in a timely manner.

     Expenses Related to Interest Rate Swaps. We had designated certain interest rate swaps as hedges of the variable rate interest payments due under Arch Western’s term loans. Pursuant to the requirements of FAS 133, historical mark-to-market adjustments related to these swaps through June 25, 2003 of $27.0 million were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the original contractual terms of the swap agreements. As of December 31, 2004, the remaining deferred amounts will be recognized as expense in the following periods: $12.7 million in 2005; $7.9 million in 2006; and $3.1 million in 2007.

Liquidity and Capital Resources

     The following is a summary of cash provided by or used in each of the indicated types of activities during the years ended December 31, 2004, 2003, and 2002:

     Cash used in operating activities during 2004 was $203.5 million, compared to cash provided by operating activities of $66.4 million during 2003. The decrease is primarily due to an increase in our receivable from Arch Coal. This receivable balance increased primarily due to borrowings we made that were loaned to Arch Coal. This decrease is also a result of increased cash used for working capital purposes. Trade accounts receivable increased $5.1 million (excluding amounts contributed with the North

24

Rochelle assets) in 2004 due primarily to higher sales levels during the period, as revenues have increased approximately 47% in 2004 as compared to 2003. Additionally, inventory increased $5.0 million (excluding amounts contributed with the North Rochelle assets) in 2004. Cash provided by operating activities in 2003 declined slightly as compared to 2002 despite higher income before the cumulative effect of accounting change. The decline was the result of significant cash expenditures for reclamation at our Black Thunder and Arch of Wyoming mines.

     Cash used in investing activities for the year ended December 31, 2004 consists of capital expenditures of $78.3 million and additions to prepaid royalties of $14.6 million. Cash used in investing activities for the year ended December 31, 2003 consisted of capital expenditures of $27.3 million and additions to prepaid royalties of $12.7 million. The increase in capital expenditures was primarily at our Black Thunder Mine, which was comprised of equipment from the North Rochelle integration and certain assets that were bought out of lease arrangements. Cash used in investing activities in 2003 declined from 2002 levels as we limited capital expenditures in light of the weak coal market that existed during much of 2003, while capital expenditures in 2002 included the scheduled purchase of assets from an operating lease and the replacement of several pieces of mobile equipment at Black Thunder.

     Cash provided by financing activities in 2004 consists primarily of proceeds from the issuance of senior notes of $261.9 million (as described more fully below). Cash provided by financing activities in 2003 represents the net proceeds resulting from the issuance of the $700.0 million of senior notes and the repayment of our term loans (as described below). Cash used in financing activities during 2002 represents costs associated with the debt refinancing that occurred in the first quarter of 2002.

     Our cash transactions are managed by Arch Coal. Cash paid to or from us that is not considered a distribution or a contribution is recorded in an Arch Coal receivable account. At December 31, 2004, 2003 and 2002, the receivable from Arch Coal was $677.9 million, $351.9 million and $333.8, respectively. The receivable is interest bearing and is payable on demand by us. However, we do not intend to demand payment of the receivable within the next year. Therefore, the receivable is classified on the consolidated balance sheets as long-term.

     On August 20, 2004, we borrowed $100.0 million under our term loan facility, which was established on September 19, 2003. The $100.0 million was loaned to Arch Coal to help fund the Triton acquisition that occurred on August 20, 2004.

     On October 22, 2004, Arch Western Finance issued $250 million of 6-3/4% senior notes due 2013 at a price of 104.75% of par, pursuant to Rule 144A under the Securities Act of 1933, as amended. The notes form a single series with Arch Western Finance’s existing 6-3/4% senior notes due 2013, except that the new notes are subject to certain transfer restrictions and are not fully fungible with the existing notes. We have an exchange offer underway for the notes. After completion of the exchange offer, the notes will be fully fungible with the previously issued notes. The net proceeds of the offering were used to repay and retire the outstanding indebtedness under our $100.0 million term loan maturing in 2007, with the remainder loaned to Arch Coal.

     On June 25, 2003, Arch Western Finance completed the offering of $700 million of senior notes and utilized the proceeds of the offering to repay our term loans. The senior notes bear a fixed rate of interest of 6.75% and are due in full on July 1, 2013. Interest on the senior notes is payable on January 1 and July 1 each year commencing January 1, 2004. The senior notes are guaranteed by us and certain of our subsidiaries and are secured by a security interest in our receivable from Arch Coal. The terms of the senior notes contain restrictive covenants that limit our ability to, among other things, incur additional debt, sell or transfer assets, and make investments.

     We generally satisfy our working capital requirements and fund our capital expenditures and debt-service obligations with cash generated from operations and, if necessary cash from Arch Coal. We believe that cash generated from operations will be sufficient to meet our working capital requirements and anticipated capital expenditures for the next several years. Our ability to fund planned capital expenditures and meet our debt-service obligations will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry, and by financial, business and other factors, some of which are beyond our control.

     Capital expenditures were $78.3 million, $27.3 million and $51.4 million for 2004, 2003 and 2002, respectively. Capital expenditures are made to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We anticipate that our capital expenditures will be approximately $140 million in total for 2005. This estimate includes capital expenditures related to development work at the North Lease mine in Utah at the currently idled Skyline complex. Also, this estimate assumes no other acquisitions, significant expansions of our existing mining operations or additions to our reserve base. We anticipate that we will fund these capital expenditures with cash generated from operations.

     The terms of our LLC Agreement provide for a preferred return distribution in an amount equal to 4% of the preferred

25

capital account balance, which was $2.4 million for each of the years ended December 31, 2004, 2003 and 2002. Preferred distributions made during the years ended December 31, 2004, 2003 and 2002 were $0.1 million in each year. Except for the preferred return distribution, distributions may generally be made at such times and in such amounts as our managing member determines. We made no distributions other than the preferred return in the years ended December 31, 2004, 2003 and 2002.

     We are exposed to market risk associated with interest rates. At December 31, 2004, all of our outstanding debt bore interest at fixed rates.

     We are also exposed to commodity price risk related to our purchase of diesel fuel. We have historically entered into forward purchase contracts to reduce volatility in the price of diesel fuel for our operations.

     The discussion below presents the sensitivity of the market value of our financial instruments to selected changes in interest 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 interest rates and prices chosen. The major accounting policies for these instruments are described in Note 2 to our consolidated financial statements.

     At December 31, 2004, our debt portfolio consisted entirely of fixed rate debt. As such, a change in interest rates on the fixed rate debt impacts the net financial instrument position but has no impact on interest incurred or cash flows. The sensitivity analysis related to our fixed rate debt assumes an instantaneous 100-basis-point move in interest rates from their levels at December 31, 2004, with all other variables held constant. A 100-basis-point increase in market interest rates would result in a $58.3 million decrease in the fair value of the fixed portion of the debt at December 31, 2004.

Off-Balance Sheet Arrangements

     We do not have any off-balance sheet arrangements.

Contractual Obligations

     The following is a summary of our significant contractual obligations as of December 31, 2004:

     Royalty leases represent non-cancelable royalty lease agreements. Unconditional purchase obligations represent amounts committed for purchases of materials and supplies, payments for services, and capital expenditures.

Contingencies

Reclamation

     The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. We accrue for the costs of final mine closure reclamation in accordance with the provisions of FAS 143, which was adopted as of January 1, 2003. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Other costs of final mine closure 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 final mine closure reclamation 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

26

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. As of December 31, 2004, we had accrued $140.6 million for reclamation liabilities.

Legal Contingencies

     We are party to claims and lawsuits with respect to various matters. We provide for costs related to contingencies, including environmental matters, when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity. As of December 31, 2004, we have not accrued for any legal contingencies.

Losses

     Because the coal mining industry is subject to significant regulatory oversight and affected by the possibility of adverse pricing trends or other industry trends beyond our control, we may suffer losses in the future if legal and regulatory rulings, mine idlings and closures, adverse pricing trends or other factors affect our ability to mine and sell coal profitably.

Critical Accounting Policies

     Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Our management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from the estimates used under different assumptions or conditions. Note 2 to our consolidated financial statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.

Asset Retirement Obligations

     Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon historical internal or third-party costs, depending on how the work is expected to be performed. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of FAS 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:

•	Discount rate — FAS 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of FAS 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
•	Third-party margin — FAS 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities with internal resources. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.

     On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates

27

and productivity assumptions, to reflect current experience. At December 31, 2004, we had recorded asset retirement obligation liabilities of $140.6 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2004, we estimate that the aggregate undiscounted cost of final mine closure is approximately $290.2 million.

Employee Benefit Plans

     We have non-contributory defined benefit pension plans covering certain of our salaried and non-union hourly employees. Benefits are generally based on the employee’s age and compensation. We fund the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes. For the year ended December 31, 2004, we contributed $9.1 million to the plan. We account for our defined benefit plans in accordance with FAS 87, Employer’s Accounting for Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis.

     The calculation of our net periodic benefit costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be “critical accounting estimates.” Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.

•	The expected long-term rate of return on plan assets is an assumption reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan’s investment targets are 65% equity, 30% fixed income securities and 5% cash. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine pension expense was 8.5% and 9.0% for the years ended December 31, 2004 and 2003, respectively, which is less than the plan’s actual life-to-date returns. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into the future. The impact of lowering the expected long-term rate of return on plan assets from 8.5% to 8.0% for 2004 would have been an increase to expense of approximately $0.3 million.
•	The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic pension cost. In estimating that rate, Statement No. 87 requires rates of return on high quality, fixed income investments. We utilize a bond portfolio model that includes bonds that are rated “AA” or higher with maturities that match the expected benefit payments under the plan. The discount rates used to determine pension expense for 2004 and 2003 were 6.5% and 7.0%, respectively. The impact of lowering the discount rate from the 6.5% utilized in 2004 to an assumed 6.0% would have resulted in an approximate $0.4 million increase in expense in 2004.

     The differences generated in changes in assumed discount rates and returns on plan assets are amortized into earnings over a five-year period.

     For the measurement of our year-end pension obligation for 2004 (and pension expense for 2005), we maintained our long-term rate of return assumption at 8.5% and changed our discount rate to 6.0%.

     We also currently provide certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. Our current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid. We account for our other postretirement benefits in accordance with FAS 106, Employer’s Accounting for Postretirement Benefits Other Than Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis.

     Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. These assumptions include the discount rate and the future medical cost trend rate.

•

The discount rate assumption reflects the rates available on high-quality fixed-income debt instruments at year-end and is calculated in the same manner as discussed above for the pension plan. The discount rate used to calculate the postretirement benefit expense for 2004 and 2003 was 6.5% and 7.0%, respectively. Had the discount rate been

28

	lowered from 6.5% to 6.0% in 2004, we would have incurred additional expense of $0.6 million.
•	Future medical trend rate represents the rate at which medical costs are expected to increase over the life of the plan. The health care cost trend rate is determined based upon our historical changes in health care costs as well as external data regarding such costs. We have implemented many effective programs that have resulted in actual increases in medical costs to fall far below the double-digit increases experienced by most companies in recent years. The postretirement expense in 2004 was based on an assumed medical inflationary rate of 8.0%, trending down in half percent increments to 5%, which represents the ultimate inflationary rate for the remainder of the plan life. This assumption was based on our then current three-year historical average of per capita increases in health care costs. A change in the future medical trend rate in 2004 would not have had a material impact on the expense recognized because the employer contribution cap was reached.

For the measurement of our year-end other postretirement obligation for 2004 (and other postretirement expense for 2005), we maintained our medical inflationary rate assumption at 8.0% (trending down to 5% by 2011) and changed our discount rate to 6.0%.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Reference is made to Part II, Item 7 of this Annual Report on Form 10-K for the information required by Item 7A.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The consolidated financial statements of Arch Western required by this Item are include in this Annual Report on Form 10-K beginning on page F-1.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     None.

ITEM 9A. CONTROLS AND PROCEDURES

     Reference is made to Part II, Item 7 of this Annual Report on Form 10-K for the information required by Item 9A.

ITEM 9B. OTHER INFORMATION

     None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     Reference is made to Part I, Item 1 of this Annual Report on Form 10-K under the caption “Management” for the information required by Item 10 which is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

     Arch Western’s managing member is an indirect wholly-owned subsidiary of Arch Coal. As a result, Arch Coal’s management is effectively Arch Western’s management. Arch Coal reports on the executive compensation of its management.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     None.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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     None.

ITEM 14. PRINCIPAL ACCOUNTANTS FEES AND SERVICES

     Ernst & Young LLP is Arch Western’s independent registered public accounting firm. Arch Western’s audit fees are determined as part of the overall audit fees for Arch Coal and are approved by Arch Coal’s Audit Committee of its Board of Directors. Arch Coal reports on the fees and services of its principal accountants in its Annual Report on Form 10-K.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1)

The following consolidated financial statements of Arch Western Resources, LLC and subsidiaries are filed as part of this Report:

		Consolidated Statements of Operations — Years Ended December 31, 2004, 2003 and 2002
		Consolidated Balance Sheets — December 31, 2004 and 2003
		Consolidated Statements of Non-Redeemable Members’ Equity — Years Ended December 31, 2004, 2003 and 2002
		Consolidated Statements of Cash Flows — Years Ended December 31, 2004, 2003 and 2002
		Notes to Consolidated Financial Statements

	(a)(2)	The following consolidated financial statement schedule of Arch Western Resources, LLC and subsidiaries is included in this Report at the page indicated:
		II — Valuation and Qualifying Accounts at page S-1 .
		All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted
	(a)(3)	Exhibits filed as part of this Report are as follows:

3.1	Certificate of Formation (incorporated herein by reference to Exhibit 3.3 to the Form S-4 (File No. 333-107569) filed on August 1, 2003 by Arch Western Finance, LLC, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., and Thunder Basin Coal Company, L.L.C.).
3.2	Limited Liability Company Agreement (incorporated herein by reference to Exhibit 3.4 to the Form S-4 (File No. 333-107569) filed on August 1, 2003 by Arch Western Finance, LLC, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., and Thunder Basin Coal Company, L.L.C.).
4.1	Indenture, dated June 25, 2003, by and among Arch Western Finance, LLC, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C. Thunder Basin Coal Company, L.L.C. and The Bank of New York, as trustee (incorporated herein by reference to Exhibit 4.1 to the Form S-4 (File No. 333-107569) filed on August 1, 2003 by Arch Western Finance, LLC, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., and Thunder Basin Coal Company, L.L.C.).
4.2	First Supplemental Indenture, dated October 22, 2004, by and among Arch Western Finance, LLC, Arch Western Resources, LLC, Arch Western Bituminous Group, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., Thunder Basin Coal Company, L.L.C., Triton Coal Company, LLC and The Bank of New York, as trustee (incorporated herein by reference to Exhibit 4.4 to the Current Report on Form 8-K filed by Arch Coal, Inc. and Arch Western Resources, LLC on October 23, 2004).
4.3	Form of 6 3/4% Senior Notes due 2013 (included in Exhibit 4.1).
4.4	Form of Guarantee of 6 3/4% Senior Notes due 2013 (included in Exhibit 4.1).
4.5	Registration Rights Agreement, dated October 22, 2004, among Arch Coal, Inc., Arch Western

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	Resources, LLC, Arch Western Finance, LLC, Triton Coal Company, LLC, Arch Western Bituminous Group, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C. and Thunder Basin Coal Company, L.L.C. and Citigroup Global Markets Inc., J.P. Morgan Securities Inc. and Morgan Stanley & Co. Incorporated, as representatives of the initial purchasers named therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Arch Coal, Inc. and Arch Western Resources, LLC on October 23, 2004).
21	Subsidiaries of the Company (filed herewith)
23.1	Consent of Ernst & Young LLP (filed herewith)
31.1	Rule 13a-14(a)/15d-14(a) Certification of Steven F. Leer (filed herewith)
31.2	Rule 13a-14(a)/15d-14(a) Certification of Robert J. Messey (filed herewith)
32.1	Section 1350 Certification of Steven F. Leer (filed herewith)
32.2	Section 1350 Certification of Robert J. Messey (filed herewith)

Upon written or oral request to the Company’s Secretary, a copy of any of the above exhibits will be furnished at cost.

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SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

     Each of the undersigned directors and officers of Arch Western Resources, LLC, a Delaware limited liability company, hereby constitutes and appoints Robert G. Jones and Janet L. Horgan, and each of them, his true and lawful attorneys-in-fact and agent, with full power to act without the other, to sign Arch Western Resources, LLC's Annual Report on Form 10-K for the year ended December 31, 2004, to be filed with the Securities and Exchange Commission under the provisions of the Securities Exchange Act of 1934, as amended; to file such Annual Report and the exhibits thereto and any and all other documents in connection therewith, including without limitation, amendments thereto, with the Securities and Exchange Commission; and to do and perform any and all other acts and things requisite and necessary to be done in connection with the foregoing as fully as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

     Pursuant to the requirements of the Securities and Exchange Act of 1934, as amended, this Annual Report on Form 10-K has been signed by the following persons in the capacities and on the dates indicated.

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INDEX TO FINANCIAL STATEMENTS

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Members
Arch Western Resources, LLC

     We have audited the accompanying consolidated balance sheets of Arch Western Resources, LLC (the Company) as of December 31, 2004 and 2003, and the related consolidated statements of operations, non-redeemable members’ equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and 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 Western Resources, LLC at December 31, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States.

     As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003.

St. Louis, Missouri
February 23, 2005

F-2

ARCH WESTERN RESOURCES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of the consolidated financial statements.

F-3

ARCH WESTERN RESOURCES, LLC

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of the consolidated financial statements.

F-4

ARCH WESTERN RESOURCES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of the consolidated financial statements.

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ARCH WESTERN RESOURCES, LLC

CONSOLIDATED STATEMENTS OF NON-REDEEMABLE MEMBERS’ EQUITY

The accompanying notes are an integral part of the consolidated financial statements.

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ARCH WESTERN RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Formation of the Company

     On June 1, 1998, Arch Coal, Inc. (“Arch Coal”) acquired the Colorado and Utah coal operations of Atlantic Richfield Company (“ARCO”) and simultaneously combined the acquired ARCO operations and Arch Coal’s Wyoming operation with ARCO’s Wyoming operations in a new joint venture named Arch Western Resources, LLC (“the Company”). ARCO was acquired by BP p.l.c. (formerly BP Amoco) in 2000. Arch Coal has a 99.5% common membership interest in the Company, while BP p.l.c. has a 0.5% common membership interest and a 0.5% preferred membership interest in the Company. Net profits and losses are allocated only to the common membership interests on the basis of 99.5% to Arch Coal and 0.5% to BP p.l.c. In accordance with the membership agreement of the Company, no profit or loss is allocated to the preferred membership interest of BP p.l.c. Except for a Preferred Return, distributions to members are allocated on the basis of 99.5% to Arch Coal and 0.5% to BP p.l.c. The Preferred Return entitles BP p.l.c. to receive an annual distribution from the common membership interests equal to 4% of the preferred capital account balance at the end of the year. The Preferred Return is payable at the Company’s discretion.

     Under the terms of the agreement, BP p.l.c. has a put right which allows BP p.l.c., at any time after the seventh year of the agreement, to cause Arch Coal to purchase its members’ interest. (See additional discussion in “Redeemable Equity Interests” in Note 3.) In addition, Arch Coal has a call right which allows Arch Coal to purchase BP p.l.c.’s members’ interest as long as it pays damages as set forth in the agreement between the members. It is the members’ intention at this point to continue the joint venture.

     In connection with the formation of the Company, Arch Coal agreed to indemnify BP p.l.c. against certain tax liabilities in the event that such liabilities arise as a result of certain actions taken by Arch Coal or the Company prior to June 1, 2013. The provisions of the indemnification agreement may restrict the Company’s ability to sell or dispose of certain properties, repurchase certain of its equity interests, or reduce its indebtedness.

     The Company mines and markets steam coal from surface and deep mines for sale to utility and industrial customers in the United States and certain export markets. The Company’s principal subsidiaries are Thunder Basin Coal Company, L.L.C., which operates a surface coal mine and owns one idle mine in the Powder River Basin in Wyoming; Mountain Coal Company, L.L.C., which operates one underground coal mine in Colorado; and Arch of Wyoming LLC, which operated two surface coal mines in the Hanna Basin in Wyoming. Both Arch of Wyoming mines were put into reclamation mode in 2004. In addition to these wholly owned operating units, the Company has a 65% interest in Canyon Fuel Company, LLC (“Canyon Fuel”). Canyon Fuel operates two underground mines and owns one idle mine in Utah. Through July 31, 2004, the Company’s interest in Canyon Fuel was accounted for on the equity method as a result of certain super-majority voting rights in the Canyon Fuel joint venture agreement. On July 31, 2004, Arch Coal purchased the remaining 35% interest in Canyon Fuel not owned by the Company. Upon Arch Coal’s acquisition of the 35% interest, Canyon Fuel’s joint venture agreement was amended to eliminate the super-majority voting rights. As a result, for periods subsequent to July 31, 2004, the Company has consolidated 100% of the results of Canyon Fuel in its financial statements and recorded minority interest for Arch Coal’s 35% interest in Canyon Fuel.

2. Accounting Policies

Principles of Consolidation

     The consolidated financial statements include the accounts of Arch Western Resources and its subsidiaries. All subsidiaries except Canyon Fuel are wholly owned. Intercompany transactions and accounts have been eliminated in consolidation. The membership interests in the Utah coal operations, Canyon Fuel, are owned 65% by Arch Western and 35% by Arch Coal. Canyon Fuel is now consolidated in the Company’s financial statements with a minority interest recorded for Arch Coal’s 35% interest.

Accounting Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent

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assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Accounting Change

     On January 1, 2003, The Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“FAS 143”). FAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time the obligations are incurred. Upon initial recognition of a liability, the cost should also be capitalized as part of the carrying amount of the related long-lived asset and allocated to expense over the useful life of the asset. Previously, the Company accrued for the expected costs of these obligations over the estimated useful mining life of the property. See additional discussion in Note 13, “Asset Retirement Obligations.”

Cash and Cash Equivalents

     Cash and cash equivalents are stated at cost. Cash equivalents consist of highly liquid investments with an original maturity of three months or less when purchased.

Inventories

     Inventories consist of the following:

     Coal and supplies inventories are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs and operating overhead. The Company has recorded a valuation allowance for slow-moving and obsolete supplies inventories of $12.4 million and $8.7 million at December 31, 2004 and 2003, respectively.

Coal Acquisition Costs and Prepaid Royalties

     The costs to obtain coal lease rights are capitalized and amortized primarily by the units-of-production method over the estimated recoverable reserves. Amortization occurs either as the Company mines on the property or as others mine on the property through subleasing transactions.

     Rights to leased coal lands are often acquired through royalty payments. Where royalty payments represent prepayments recoupable against production, they are capitalized, and amounts expected to be recouped within one year are classified as a current asset. As mining occurs on these leases, the prepayment is charged to cost of coal sales.

Coal Supply Agreements

     Acquisition costs allocated to coal supply agreements (sales contracts) are capitalized and amortized on the basis of coal to be shipped over the term of the contract. Value is allocated to coal supply agreements based on discounted cash flows attributable to the difference between the above or below-market contract price and the then-prevailing market price. The net book value of the Company’s above-market coal supply agreements was $11.1 million and $4.9 million at December 31, 2004 and 2003, respectively. These amounts are recorded in other assets in the accompanying Consolidated Balance Sheets. The net book value of all below-market coal supply agreements was $29.2 million at December 31, 2004. This amount is recorded in other noncurrent liabilities in the accompanying Consolidated Balance Sheets. Amortization expense on all above-market coal supply agreements was $1.8 million, $0.4 million and $1.2 million in 2004, 2003 and 2002, respectively. Amortization income on all below-market coal supply agreements was $4.1 million in 2004. Based on expected shipments related to these contracts, the Company expects to record annual amortization expense on the above-market coal supply agreements and annual amortization income on the below-market coal supply agreements in each of the next five years as reflected in the table below.

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During 2003, the Company wrote off $27.3 million of cost and accumulated amortization for contracts that were fully amortized.

Exploration Costs

     Costs related to locating coal deposits and determining the economic mineability of such deposits are expensed as incurred.

Property, Plant and Equipment

     Plant and Equipment

     Plant and equipment are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures which extend the useful lives of existing plant and equipment or increase the productivity of the asset are capitalized. Except for loadouts, plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, which range from three to twenty-eight years. Loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimum level of depreciation.

     Leased plant and equipment meeting certain criteria is capitalized and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed on the straight-line method over the term of the lease.

Deferred Mine Development

     Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited. Additionally, the asset retirement obligation asset has been recorded as a component of deferred mine development.

     Coal Lands and Mineral Rights

     The Company’s coal reserves are controlled through leasing arrangements. Amounts paid to acquire such lease rights are capitalized and depleted over the life of those reserves that are proven and probable. Depletion of coal lease rights is computed using the units-of-production method and the rights are assumed to have no residual value. The leases are generally long-term in nature (original terms range from 10 to 50 years), and substantially all of the leases contain provisions that allow for automatic extension of the lease term as long as mining continues. The net book value of the Company’s leased coal interests was $522.7 million and $389.1 million at December 31, 2004 and 2003, respectively. This increase is due to the addition of leased coal interests resulting from the consolidation of Canyon Fuel.

Asset Impairment

     If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.

Revenue Recognition

     Coal sales revenues include sales to customers of coal produced at Company operations and coal purchased from other companies. The Company recognizes revenue from coal sales at the time title passes to the customer. Transportation costs that are billed by the Company and reimbursed to the transportation provider (pass through costs) are included in coal sales and cost of coal sales.

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