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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-31240

Foundation Coal Corporation
(Exact Name of Registrant as Specified in Its Charter)

        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 ý    No o

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

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

        The Registrant's common equity is not publicly traded. The common stock of the Registrant's ultimate parent, Foundation Coal Holdings, Inc., began trading on the New York Stock Exchange on December 9, 2004. As such, Foundation Coal Holdings, Inc. has not completed its second fiscal quarter in which its common equity was publicly traded. As of March 7, 2005, the aggregate market value of Foundation Coal Holdings, Inc.'s voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, was approximately $633,589,000. There were 44,627,047 shares of common stock outstanding on March 7, 2005.

TABLE OF CONTENTS

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This Form 10-K contains forward-looking statements that are not statements of historical fact and may involve a number of risks and uncertainties. These statements relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable. These statements may also relate to our future prospects, developments and business strategies.

        We have used the words "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "predict," "project" and similar terms and phrases, including references to assumptions, in this Form 10-K to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

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market demand for coal, electricity and steel;



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future economic or capital market conditions;



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weather conditions or catastrophic weather-related damage;



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our production capabilities;



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the consummation of financing, acquisition or disposition transactions and the effect thereof on our business;



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our plans and objectives for future operations and expansion or consolidation;



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our relationships with, and other conditions affecting, our customers;



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timing of reductions or increases in customer coal inventories;



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long-term coal supply arrangements;



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risks in coal mining;



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environmental laws, including those directly affecting our coal mining and production, and those affecting our customers' coal usage;



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competition;



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railroad, barge, trucking and other transportation performance and costs;



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our assumptions concerning economically recoverable coal reserve estimates;



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employee workforce factors;



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regulatory and court decisions;



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future legislation and changes in regulations or governmental policies or changes in interpretations thereof;



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changes in postretirement benefit and pension obligations;



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our liquidity, results of operations and financial condition; and



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other factors, including those discussed in "Risk Factors—Risk Relating to our Business" and "Risk Factors—Risks Related to our Common Stock" in "Item 7. Management's Discussion and Analysis of Consolidated Financial Condition and Results of Operations."

        You should keep in mind that any forward-looking statement made by us in this Form 10-K or elsewhere speaks only as of the date on which we make it. New risks and uncertainties come up from time to time, and it is impossible for us to predict these events or how they may affect us. We have no duty to, and do not intend to, update or revise the forward-looking statements in this Form 10-K after the date of this Form 10-K, except as may be required by law. In light of these risks and uncertainties, you should keep in mind that any forward-looking statement made in this Form 10-K or elsewhere might not occur.

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PART I

        To aid readers unfamiliar with the terms commonly used in the coal industry, a glossary of selected terms is provided at the end of Item 1. Business.

        Unless the context otherwise indicates, as used in this 10-K the terms "we", "our", "us" and similar terms refer to Foundation Coal Corporation and its consolidated subsidiaries.

ITEM 1. BUSINESS

Overview

        We are the fifth largest coal producer in the United States. We operate a diverse group of thirteen mines located in Wyoming, Pennsylvania, West Virginia and Illinois. For the year ended December 31, 2004, we sold 63.5 million tons of coal, including 61.2 million tons that were produced and processed at our operations. As of December 31, 2004, we had approximately 1.8 billion tons of proven and probable coal reserves. We are also involved in marketing coal produced by others to supplement our own production and, through blending, provide our customers with coal qualities beyond those available from our own production. We purchased and resold 2.3 million tons of coal in 2004.

        We are primarily a supplier of steam coal to United States utilities for use in generating electricity. We also sell steam coal to industrial plants. Steam coal sales accounted for 97% of our coal sales volume and 92% of our coal sales revenue in 2004. We also sell metallurgical coal to steel producers; metallurgical sales accounted for 3% of our coal sales volume and 8% of our coal sales revenue in 2004.

        As of December 31, 2004, we had a total sales backlog of over 350 million tons of coal, and our coal supply agreements have remaining terms ranging from one to seventeen years. For 2004, we sold approximately 70% of our sales volume under long-term coal supply agreements. As of December 31, 2004, we had sales commitments for approximately 98% of our planned 2005 production, approximately 85% of our planned 2006 production and approximately 65% of our planned 2007 production.

History

        Foundation Coal Corporation is a Delaware corporation that was formed in 2004.

Business Environment

        Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel for the generation of electric power. World-wide recoverable coal reserves are estimated to be approximately 1.1 trillion tons. The United States is one of the world's largest producers of coal and has approximately 25% of global coal reserves, representing approximately 250 years of supply based on current usage rates. Coal is the most abundant fossil fuel in the United States, representing approximately 95% of the nation's total fossil fuel reserves.

        Coal Markets.    Coal is primarily consumed by utilities to generate electricity. It is also used by steel companies to make steel products and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In general, coal is characterized by end use as either steam coal or metallurgical coal. Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coke, which is used in the production of steel. Over the past quarter century, total annual coal consumption in the United States has nearly doubled to approximately 1.1 billion tons in 2003. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators.

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        The following table sets forth demand trends for United States coal by consuming sector as projected by the Energy Information Administration ("EIA") for the periods indicated.

        The nation's power generation infrastructure is largely coal-fired. As a result, coal has consistently maintained a 50% to 53% market share during the past 10 years, principally because of its relatively low cost, reliability and abundance. Coal is the lowest cost fossil-fuel used for base-load electric power generation, being considerably less expensive than natural gas or oil. Coal-fired generation is also competitive with nuclear power generation especially on a total cost per megawatt-hour basis. The production of electricity from existing hydroelectric facilities is inexpensive, but its application is limited both by geography and susceptibility to seasonal and climatic conditions. Non-hydropower renewable power generation accounts for only 1.4% of all the electricity generated in the United States, and wind and solar power—the alternative fuel sources that provide the greatest environmental benefits—represent only 0.3% of United States power generation and are generally not economically competitive with existing technologies.

        Coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting power generation, technological developments and the location, availability and cost of other fuels such as natural gas, nuclear and hydroelectric power.

        Coal's primary advantage is its relatively low cost compared to other fuels used to generate electricity. Platts Coal Trader ("Platts"), a commonly used authoritative resource for industry commodity pricing, has estimated the average total production costs of electricity, using coal and competing generation alternatives, in 2004 as follows:

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        Coal Production.    United States coal production was approximately 1.1 billion tons in 2003. The following table, derived from data prepared by the EIA, sets forth production statistics in each of the four major coal producing regions for the periods indicated.

Note: 2003-2025 Data per EIA Annual Energy Outlook 2005. Data excludes waste coal delivered to Independent Power Producers.

        Coal Regions.    Coal is mined from coal fields throughout the United States, with the major production centers located in the Western United States, Northern and Central Appalachia and the Illinois Basin. The quality of coal varies by region. Heat value and sulfur content are the two most important coal characteristics in measuring quality and determining the best end use of particular coal types.

        Competition.    The coal industry is intensely competitive. The most important factors on which we compete are coal price at the mine, coal quality and characteristics, transportation costs from the mine to the customer and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which are influenced by factors beyond our control. These factors include the demand for electricity, which is significantly dependent upon economic activity and 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.

        Transportation Cost.    Coal used for domestic consumption is generally sold free on board at the mine, and the purchaser normally bears the transportation costs. Export coal, however, is usually sold at the loading port, and coal producers are responsible for shipment to the export coal-loading facility, with the buyer paying the ocean freight.

        Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs. Transportation can be a large component of a purchaser's total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. According to the National Mining Association ("NMA"), railroads account for nearly two-thirds of total United States coal shipments, while river barge movements account for an additional 13%. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to markets served by water. Most coal mines are served by a single rail company, but much of the Wyoming Powder River Basin is served by two competing rail carriers, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. Rail competition in this major coal-producing region is important because rail costs constitute up to 75% of the delivered cost of Powder River Basin coal in eastern markets.

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Coal Characteristics

        In general, coal of all geological composition is characterized by end use as either steam coal or metallurgical coal. Heat value and sulfur content are the most important variables in the profitable marketing and transportation of steam coal, while ash, sulfur and various coking characteristics are important variables in the profitable marketing and transportation of metallurgical coal. We mine, process, market and transport bituminous and sub-bituminous coal, characteristics of which are described below.

        Heat Value.    The heat value of coal is commonly measured in British thermal units per pound, or ("Btu"). A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal found in the eastern and mid-western regions of the United States tends to have a higher heat value than coal found in the western United States.

        Bituminous coal is a "soft" coal with a heat value that ranges from 10,500 to 14,000 Btu's. This coal is located primarily in our mines in Northern and Central Appalachia and in the Illinois Basin, and is the type most commonly used for electric power generation in the United States. Bituminous coal is used for utility and industrial steam purposes, and includes metallurgical coal, a feed stock for coke, which is used in steel production.

        Sub-bituminous coal has a heat value that ranges from 7,800 to 9,500 Btu's. Our sub-bituminous reserves are located in Wyoming. Sub-bituminous coal is used almost exclusively by electric utilities and some industrial consumers.

        Sulfur Content.    Sulfur content can vary from seam to seam and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu's and complies with the requirements of the Clean Air Act. Low sulfur coal is coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btu's.

        Sub-bituminous coal typically has a lower sulfur content than bituminous coal, but some of our bituminous coal in West Virginia also has a low sulfur content.

        High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by 50% to 90%. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal, or by purchasing emission allowances on the open market, which credits allow the user to emit a ton of sulfur dioxide. More than 15,000 megawatts of coal-based generating capacity has been retrofitted with scrubbers since the beginning of Phase I of the Clean Air Act. Furthermore, utilities have announced plans to scrub an additional 30,000 megawatts by 2010. Additional scrubbing will provide new market opportunities for our mid sulfur coal. All new coal-fired generation plants built in the United States will use clean coal-burning technology.

Operations

        As of December 31, 2004, we operated a total of 13 mines located in Wyoming, Pennsylvania, West Virginia and Illinois. We currently own most of the equipment utilized in our mining operations. The

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following table provides summary information regarding our principal mining complexes as of December 31, 2004.

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Our Simmons Fork mining complex ceased coal production on September 22, 2004. Our Pax Ewing Fork ("Pax") mining complex commenced coal production on July 1, 2004.

Note: The tonnage shown for each mine represents coal mined, processed and shipped from our active operations. Kingston and Pioneer tons sold include a total of 1.2 million tons of metallurgical coal. The tonnage shown in the two categories labeled purchased and resold includes quantities of coal that were purchased and resold and includes 0.7 million tons of metallurgical coal.

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        The following map shows the locations of our operations.

        The following provides a description of the operating characteristics of the principal mines and reserves of each of our mining operations.

Wyoming Operations

        We control approximately 720.4 million tons of coal reserves in the Powder River Basin, the largest and fastest growing United States coal-producing region. Our subsidiaries, Foundation Coal West, Inc. and Foundation Wyoming Land Company, own and manage two sub-bituminous, low sulfur, non-union surface mines that sold 41.7 million tons of coal in 2004, or 66% of our total coal sales volume. The two mines employ approximately 481 salaried and hourly employees. Our Powder River Basin mines have produced over 856 million tons of coal since 1972.

Belle Ayr Mine

        The Belle Ayr mine, located approximately 18 miles southeast of Gillette, Wyoming, extracts coal from the Wyodak-Anderson Seam, which averages 75 feet thick, using the truck-and-shovel mining method. Belle Ayr shipped 18.7 million tons of coal in 2004. The mine sells 100% of raw coal mined. Belle Ayr has approximately 350.2 million tons of reserves. The reserve base at Belle Ayr will sustain projected levels of production for approximately 14 years. Several hundred million tons of surface mineable unleased federal coal adjoins the mine's property and can be leased to extend the mine's life. Belle Ayr has the advantage of shipping its coal on both of the major western railroads, the Burlington Northern Santa Fe Railroad and the Union Pacific Railroad.

Eagle Butte Mine

        The Eagle Butte mine, located approximately eight miles north of Gillette, Wyoming, extracts coal from the Roland and Smith Seams, which total 100 feet thick, using the truck-and-shovel mining method. Eagle Butte shipped 23.0 million tons of coal in 2004. The mine sells 100% of the raw coal mined. No washing is necessary. Eagle Butte has approximately 370.2 million tons of reserves. The reserves will sustain projected production levels for 15 years. Several hundred million tons of surface mineable unleased federal coal adjoins the western boundary of the mine property. We have applied to lease approximately 240 million tons of this coal. The Lease by Application (LBA) sale is scheduled for 2007. If we prevail in the bidding process and obtain this lease, we will be able to extend the mine's life by at least an additional 10 years, based on the mine's 2004 rate of production. Coal from Eagle Butte

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is shipped on the Burlington Northern Santa Fe Railroad to power plants located throughout the Midwest and the South.

Pennsylvania Operations

        Our affiliates control approximately 805.8 million tons of contiguous reserves in Northern Appalachia. Approximately 194.7 million tons are assigned to active mines. Approximately 611.1 million tons are unassigned. A portion of these unassigned reserves is accessible through our currently active mines. Our Pennsylvania mines are located in southwestern Pennsylvania, approximately 60 miles south of Pittsburgh. Both mines operate in the Pittsburgh No. 8 Seam, the dominant coal-producing seam in the region, which is six to eight feet thick on these properties. The Pennsylvania operations consist of the Cumberland and the Emerald mining complexes, which collectively shipped 10.7 million tons in 2004 using longwall mining systems supported by continuous mining methods. The mines sell high Btu, medium sulfur coal primarily to eastern utilities. The hourly work force at each mine is represented by the United Mine Workers of America ("UMWA").

Cumberland Mine

        The Cumberland mining complex, located approximately 12 miles south of Waynesburg, Pennsylvania, was established in 1977. Cumberland shipped 5.2 million tons of coal in 2004. As of December 31, 2004, Cumberland had an assigned reserve base of 58.8 million tons, with the ability to access an additional 46.7 million tons of controlled reserves contiguous to the mining complex. All of the coal at Cumberland is processed through a preparation plant before being loaded onto Cumberland's owned and operated railroad for transportation to the Monongahela River dock site. At the dock site, coal is then loaded into barges for transportation to river-served utilities or to other docks for subsequent rail shipment to non-river-served utilities. The mine can also ship a portion of its production via truck. Cumberland has approximately 579 employees.

        In January 2004, the Mine Safety and Health Administration ("MSHA") determined that, based on a revised interpretation of existing federal regulations, a ventilation plan previously approved by MSHA for a longwall panel at Cumberland did not comply with applicable federal regulations. In response, we idled the Cumberland longwall in February 2004, issued force majeure notices to our customers, and began revising the ventilation system to minimize any future business disruption. By early May 2004, we had developed additional entries to an existing air shaft, and on May 7, 2004, after obtaining the approval of MSHA, we resumed longwall operations. Cumberland is currently producing at pre-shutdown run-rates and has not experienced any ventilation issues since resuming operations. See "Risk Factors—MSHA may order certain of our mines to be temporarily closed, which would adversely affect our ability to meet our customers' demands." and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Emerald Mine

        The Emerald mining complex, located approximately two miles south of Waynesburg, Pennsylvania, was established in 1977. As of December 31, 2004, Emerald had an assigned reserve base of approximately 89.2 million tons of coal reserves. Emerald shipped 5.5 million tons of coal in 2004. Emerald has the ability to store clean coal and blend variable sulfur products to meet customer requirements. All of Emerald's coal is processed through a preparation plant before being loaded into unit trains operated by the Norfolk Southern Railroad or the CSX Railroad. The mine also has the option to ship a portion of its coal by truck. Approximately 570 employees work at Emerald.

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West Virginia Operations

        Our subsidiaries operate four mining complexes located in West Virginia in the Central Appalachia region: Kingston, Laurel Creek, Rockspring and Pioneer. The Kingston, Laurel Creek and Rockspring facilities are all underground mining complexes that use room-and-pillar mining technology to develop and extract coal. The Pioneer complex operates two surface mines utilizing truck/loader systems to extract coal from multiple seams. Our West Virginia operations have approximately 81.6 million tons of reserves that are assigned to current operations and approximately 124.5 million tons of reserves that are unassigned and are being held for future development. Except for the two surface complexes, all of the raw coal is processed through preparation plants before transportation to market. Production from the mines is typically low sulfur, high Btu coal. In 2004, our West Virginia mines collectively sold 7.9 million tons of coal. Our West Virginia mines ship coal by either the Norfolk Southern Railroad or the CSX Railroad or by barge on the Kanawha and Big Sandy Rivers. These operations serve a diversified customer base, including regional and national customers. We also own and operate the Rivereagle river loading facility on the Big Sandy River in Boyd County, Kentucky.

        Our West Virginia operations have approximately 742 non-union employees. In November 2003, a UMWA election was held at the Rockspring mining facility, the outcome of which is pending a decision of the National Labor Relations Board (the "NLRB"). If the NLRB finds that the UMWA was properly elected, approximately 255 employees at the Rockspring facility would become UMWA members.

Kingston Mines

        The Kingston complex consists of two mines, Kingston #1 and Kingston #2, located in Fayette County and Raleigh County, respectively. Kingston #1 mines the Glen Alum Seam and Kingston #2 mines the Douglas Seam. In 2004, the Kingston complex shipped 1.0 million tons and as of December 31, 2004 had approximately 10.2 million tons of reserves, of which approximately 7.0 million tons are assigned and approximately 3.2 million tons are unassigned. Kingston sells coal primarily to the metallurgical market for domestic steel plants. The coal is trucked to the Kanawha River for shipment by barge or to a rail siding on the CSX Railroad or the Norfolk Southern Railroad for shipment by rail.

Laurel Creek Mines

        The Laurel Creek mining complex consists of three underground mines, Coalburg, East Fork and 5 Block, and a preparation plant located in Logan and Mingo Counties. In 2004 the East Fork mine was operated by third-party contract miners; in January 2005 the contract miner was replaced by Laurel Creek employees. In 2004, the mines shipped 1.7 million tons and as of December 31, 2004 had approximately 13.5 million tons of assigned reserves and approximately 15.4 million tons of unassigned reserves. The coal is shipped by truck primarily to our Rivereagle dock, other third-party docks or a rail siding on the CSX Railroad.

Rockspring Mine

        Rockspring Development, Inc. operates a large multiple section mining complex in Wayne County called Camp Creek that produces coal from the Coalburg Seam. The complex shipped 3.1 million tons of coal in 2004. Assigned and unassigned coal reserves totaled approximately 48.0 million tons and 22.7 million tons, respectively. Rockspring has a mine site rail loadout. The coal is transported on the Norfolk Southern Railroad, primarily to southeastern utilities. The mine can also ship a portion of its production by truck.

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Pioneer Mines

        Pioneer Fuel Corporation operates two active surface mines, Paynter Branch which is located in Wyoming County, and Pax which is located in Raleigh County. These mines utilize front-end loaders with trucks to mine multiple seams. The Simmons Fork mine was depleted and ceased coal production in September 2004. Pioneer shipped 1.3 million tons of primarily steam coal in 2004. As of December 31, 2004, the mines had assigned reserves of approximately 13.3 million tons with an additional 19.4 million tons of unassigned reserves. Based on 2004 production rates, we expect that the Paynter Branch mine has sufficient reserves to last approximately six years. The Pax Surface Mine commenced operations in July 2004 and will reach full production levels in 2005. We expect that the Pax mine has sufficient reserves to last approximately nine years. Coal from Paynter Branch is shipped by truck to a loading facility on the Norfolk Southern Railroad and then on to domestic utilities and exported to metallurgical coal customers. Coal from Pax is trucked to the Kanawha River for shipment by barge or may be transported by truck to an on-site loading facility utilized by Paynter Branch for rail shipment on the Norfolk Southern Railroad.

Illinois Operations

Wabash Mine

        The Wabash Mine is a room-and-pillar operation located in Wabash County, Illinois in the Illinois Basin just east of Keenesburg. The mine produced 1.7 million tons of steam coal in 2004. The mine has 27.4 million tons of reserves. After cleaning in the preparation plant, the coal is shipped via the Norfolk Southern Railroad to power plants located in the Illinois Basin, in particular to the PSI Gibson Station in Owensville, Indiana, one of the largest power plants in the United States Pursuant to our long-term supply agreement with the PSI Gibson Station, we supply the PSI Gibson Station with approximately 1.5 million tons of coal per year until the end of 2006.

        The hourly work force at the Wabash Mine is represented by the UMWA. Wabash has approximately 250 employees.

Long-Term Coal Supply Agreements

        The terms of our coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly by customer, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions.

        Some of our long-term contracts provide for a predetermined adjustment to the stipulated base price at times specified in the agreement or at other periodic intervals. In addition, most of our contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our costs related to performance of the agreement. Additionally, some of our contracts contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities.

        Price reopener provisions are present in some of our long-term contracts. These provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to terminate the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers.

        Quality and volumes for the coal are stipulated in coal supply agreements, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat

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content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.

        Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. Many of our contracts contain similar clauses covering changes in environmental laws. We may negotiate an option to supply coal that complies with new environmental requirements to avoid contract termination.

        In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines as long as the replacement coal meets quality specifications and will be sold at the same delivered cost.

Sales and Marketing

        Through our sales, trading and marketing entities, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances, and provide transportation-related services. As of December 31, 2004, we had 15 employees in our sales, marketing, trading and transportation operations, including personnel dedicated to performing market research, contract administration and distribution and transportation functions.

Transportation

        Coal consumed domestically is usually sold at the mine, and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port.

        We depend upon rail, barge, trucking and other systems to deliver coal to markets. In 2004, our produced coal was transported from the mines to the customer by rail, with the primary rail carriers being the CSX, Norfolk Southern, Burlington Northern Sante Fe and the Union Pacific. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by barge or truck. All coal from our Belle Ayr Mine in Wyoming is shipped by two competing railroads, the Burlington Northern Santa Fe Railroad and the Union Pacific Railroad, while output from our Eagle Butte operation moves via the Burlington Northern Santa Fe Railroad. The Wabash Mine in Illinois is serviced by the Norfolk Southern Railroad. The Pioneer, Kingston, Laurel Creek and Rockspring Mines in West Virginia are serviced by a combination of the Norfolk Southern Railroad and the CSX Railroad, as well as by truck and barge. In Pennsylvania, the Emerald Mine is serviced by the Norfolk Southern Railroad and the CSX Railroad and the Cumberland Mine is serviced by barge.

Suppliers

        We spend more than $350.0 million per year to procure goods and services in support of our business activities, including capital expenditures. Principal commodities include maintenance and repair parts and services, electricity, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies and lubricants. We use suppliers for a significant portion of our equipment rebuilds and repairs both on- and off-site, as well as construction and reclamation activities and to support computer systems.

        Each of our regional mining operations has developed its own supplier base consistent with local needs. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods, and to support the business units. The supplier base has been relatively stable for many years, but there has been some

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consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Employees

        As of December 31, 2004, we and our subsidiaries had approximately 2,750 employees. As of December 31, 2004, the UMWA represented approximately 41% of our employees, who produced approximately 20% of our coal sales volume during the year ended December 31, 2004. Relations with organized labor are important to our success and we believe our relations with our employees are satisfactory. Three mining operations (Cumberland, Emerald and Wabash) are signatories to the UMWA collective wage agreement negotiated between the Bituminous Coal Operators Association (the "BCOA") and the UMWA in 2002. While our operations are not part of the BCOA, we have historically executed collective wage agreements patterned after the industry negotiated collective wage agreement with additional memoranda of understanding to handle local issues. The three wage agreements with the UMWA expire in early 2007, approximately three months after the industry-negotiated collective wage agreement expiration date of December 31, 2006.

Environmental and other Regulatory Matters

Regulation

        Federal, state and local authorities regulate the United States coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining, and the effects of mining on surface and groundwater quality and availability. These regulations and legislation have had, and will continue to have, a significant effect on our production costs and our competitive position. Future legislation, regulations or orders, as well as future interpretations or different enforcement of existing laws, regulations or orders, may require substantial increases in equipment and operating costs to us and delays, interruptions, or a termination of operations, the extent of which we cannot predict. We intend to respond to these regulatory requirements at the appropriate time by implementing necessary modifications to facilities or operating procedures. Future legislation, regulations or orders may also cause coal to become a less attractive fuel source. As a result, future legislation, regulations or orders may adversely affect our mining operations, cost structure or the ability of our customers to use coal.

        We endeavor to conduct our mining operations in compliance with all applicable federal, state, and local laws and regulations. However, because of extensive and complex regulatory requirements, violations occur from time to time. None of the violations or the monetary penalties assessed upon us in recent years has been material. It is possible that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

Mine Safety and Health

        The Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977 impose stringent safety and health standards on all aspects of mining operations. Also, most of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is

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perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of United States industry. Regulation has a significant effect on our operating costs.

Black Lung

        Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. This tax is expressly passed on to the purchaser or included in the sales price under many of our coal supply agreements.

        In December 2000, the Department of Labor amended regulations implementing the federal black lung laws to, among other things, establish a presumption in favor of a claimant's treating physician and limit a coal operator's ability to introduce medical evidence regarding the claimant's medical condition. The number of claimants who are awarded benefits may increase, as well as the amounts of those awards.

Coal Industry Retiree Health Benefit Act of 1992

        The Coal Industry Retiree Health Benefit Act of 1992 (the "Coal Act") provides for the funding of health benefits for certain UMWA retirees and their spouses or dependants. The Coal Act established the Combined Fund into which employers who are "signatory operators" are obligated to pay annual premiums for beneficiaries. The Combined Fund covers a fixed group of individuals who retired before July 1, 1976, and the average age of the retirees in this fund is approximately 80 years. Our premium obligations to the Combined Fund are approximately $1,500,000 per year. The Coal Act also created a second benefit fund, the 1992 Plan, for miners who retired between July 1, 1976 and September 30, 1994, and whose former employers are no longer in business to provide them retiree medical benefits. Companies with 1992 Plan liabilities also pay premiums into this plan. Our payment obligations to the 1992 Plan are approximately $700,000 per year.

Environmental Laws

Mining Permits and Necessary Approvals

        Numerous governmental permits, licenses or approvals are required for mining and related operations. When we apply for these permits and approvals, we may be required to present data to federal, state or local authorities pertaining to the effect or impact our operations 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. These requirements may also be added to, modified or re-interpreted from time to time. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding mining permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

        In order to obtain mining permits and approvals from state regulatory authorities we must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit our necessary permit applications several months, or even years, before we plan to begin mining a new area. In the past, we have generally obtained our mining permits in time so as to be able to run our

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operations as planned. However, we cannot be sure that we will not experience difficulty or delays in obtaining mining permits in the future.

Surface Mining Control and Reclamation Act

        The Surface Mining Control and Reclamation Act of 1977 (the "SMCRA"), which is administered by the Office of Surface Mining Reclamation and Enforcement (the "OSM"), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under the act, the state becomes the regulatory authority with primacy and issues the permits, but OSM maintains oversight. SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act ("RCRA") and Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund").

        SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. The permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, the state programs, and the complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land.

        Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits may take six months to two years or even longer to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

        Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed prior to 1977. The current fee is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. There are proposals to modify this fee and the administration of the Abandoned Mine Land Fund, but any change is not expected to have a material adverse impact on our financial results.

Surety Bonds

        Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers' compensation costs, obligations under federal coal leases and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis. In recent years surety bond premium costs have increased and the market

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terms of surety bonds have generally become more unfavorable. In addition, the number of companies willing to issue surety bonds has decreased. We cannot predict the ability to obtain or the cost of bonds in the future.

Clean Air Act

        The Clean Air Act, the Clean Air Act Amendments and the corresponding state laws that regulate the emissions of materials into the air, affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds emitted by coal-fueled electricity generating plants. Power plants will likely have to continue to install pollution control technology and upgrades. Power plants may be able to recover the costs for these upgrades in the prices they charge for power, but this is not a certainty and state public utility commissions often control such rate matters. The Clean Air Act provisions and associated regulations are complex, lengthy and often being assessed for revisions or additions. In addition, one or more of the pertinent state or federal regulations issued as final may still continue to be subject to legal challenges in courts and the actual timing of implementation may remain uncertain. Some of the more material Clean Air Act requirements that may directly or indirectly affect our operations include the following:

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Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 megawatts. The affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur eastern coals, and more demand for western coals, as coal-fired power plants continue to comply with the more stringent restrictions of Title IV.



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Fine Particulate Matter and Ozone. The Clean Air Act requires the Environmental Protection Agency ("EPA") to set standards, referred to as National Ambient Air Quality Standards ("NAAQS"), for certain pollutants. Areas that are not in compliance (referred to as "non-attainment areas") with these standards must take steps to reduce emissions levels. In 1997, the EPA revised the NAAQS for particulate matter and ozone. Although previously subject to legal challenge, these revisions were subsequently upheld but implementation was delayed for several years. For ozone, these changes include replacement of the existing one-hour average standard with a more stringent eight-hour average standard. On April 15, 2004, the EPA announced that counties in 32 states fail to meet the new eight-hour standard for ozone. States that fail to meet the new standard will have until June 2007 to develop plans for pollution control measures that allow them to come into compliance with the standards. For particulates, the changes include retaining the existing standard for particulate matter with an aerodynamic diameter less than or equal to 10 microns ("PM10"), and adding a new standard for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns ("PM2.5"). State fine particulate non-attainment designations were due on February 15, 2004, and 18 states and the District of Columbia recommended counties to be classified as non-attainment areas. The EPA has indicated it will finalize the implementation rule in 2005. Following identification of non-attainment areas, each individual state will identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Under the

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Clean Air Act, individual states have up to twelve years from the date of designation to secure emissions reductions from sources contributing to the problem. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of these new ozone and PM2.5 standards will affect many power plants, especially coal-fired plants and all plants in "non-attainment" areas.

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Ozone. Significant additional emissions control expenditures will be required at coal-fired power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. 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.



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NOx SIP Call. The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. Under Phase I of the program, the EPA is requiring 90,000 tons of nitrogen oxides reductions from power plants in 22 states east of the Mississippi River and the District of Columbia beginning in May 2004. Phase II of the program, which became effective June 21, 2004, requires a further reduction of about 100,000 tons of nitrogen oxides per year by May 1, 2007. Installation of additional control measures, such as selective catalytic reduction devices, required under the final rules will make it more costly to operate coal-fired electricity generating plants, thereby making coal a less attractive fuel.



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Clear Skies Initiative. New Legislation has been proposed, commonly referred to as the Clear Skies Initiative, that could require dramatic reductions in nitrous oxide, sulfur dioxide, and mercury emissions by power plants through "cap-and-trade" programs similar to the existing Acid Rain regulations and current NOx budget programs. If passed, this law would apply on a nationwide basis. Congress is also considering several competing bills. It is currently not possible to predict what, if any, new regulatory requirements will ultimately evolve out of these initiatives during the current Congress or in the future.



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Clean Air Interstate Rule. On January 30, 2004, the EPA proposed new rules for reducing emissions of sulfur dioxide and nitrogen oxides. The final Clean Air Interstate Rule (CAIR) was issued by the EPA on March 10, 2005. The rule calls for power plants in 28 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrous oxide. CAIR does not apply on a national basis as would the Clear Skies Initiative. At full implementation, CAIR is estimated by the EPA to cut regional sulfur dioxide emissions by more than 70% from the 2003 levels, and to cut nitrogen oxide emissions by more then 60% from 2003 levels. States must achieve the required emission reductions using one of two compliance options. The first alternative is for the state to require power plants to participate in an EPA administered "cap-and-trade" system that caps emissions in two stages. This cap and trade approach is similar to the system now in effect under other regulations controlling air pollution. Alternatively, a state can elect to meet a specific state emissions budget through measures of the state's choosing. The stringency of the caps may require many coal-fired sources to install additional pollution control equipment to comply. This increased sulfur emission removal capability caused by the proposed rule could result in decreased demand for low sulfur coal, potentially driving down prices for low sulfur coal.



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Clean Air Mercury Rule. On January 30, 2004, the EPA also proposed a mercury reduction rule for controlling mercury emissions from power plants. The proposal sought comments on two approaches for reducing mercury currently emitted each year by coal-fired power plants in the United States. The comment period ended on June 29, 2004. EPA issued its final Clean Air Mercury Rule on March 15, 2005. The EPA has rejected one approach which would require

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coal-fired power plants to install pollution controls known as "maximum achievable control technologies," or "MACT," under section 112 of the Clean Air Act. The approach adopted uses other provisions of the Clean Air Act and sets a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. This "cap-and-trade" approach is similar to the approach under the CAIR rule discussed above. This approach, which allows mercury emissions trading, when combined with the CAIR regulations, will reduce mercury emissions by nearly 70% from current levels once facilities reach a final mercury cap which takes effect in 2018. Current mercury emissions from United States power plants are about 48 tons per year. The first phase cap is 38 tons beginning in 2010. EPA estimates that much of this reduction will come as a "co-benefit" of the pollution control devices installed under the CAIR regulations. The final cap is set at 15 tons per year beginning in 2018. Each state has been allocated a budget of mercury emissions and must submit a plan on meeting its budget for mercury reductions. The states are not required to adopt the cap-and-trade approach, but EPA expects most to take that approach. Alternatively, a state can elect to meet a specific state emissions budget through measures of the state's choosing. The stringency of the caps may require many coal-fired sources to install additional pollution control equipment to comply. This increased mercury emission removal capability caused by the proposed rule could result in decreased demand for certain coals either due to higher mercury levels or more difficulty in removing the inherent mercury.

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Carbon Dioxide. In February 2003, a number of states notified the EPA that they planned to sue the agency to force it to set new source performance standards for utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In June 2003, three of these states sued the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant and to issue a new NAAQS for carbon dioxide. Other states, cities or organizations may bring additional such suits. If these lawsuits result in the issuance of a court order requiring the EPA to set emission limitations for carbon dioxide and/or lower emission limitations for sulfur dioxide and particulate matter, it could reduce the amount of coal our customers would purchase from us. To date, no decision has been rendered in this case, although both sides have submitted arguments to the court. There are also various federal, state and local legislative initiatives aimed at tracking or regulating, both on a mandatory or voluntary basis, the release of carbon dioxide from generating power and other commercial activity. Any one or more of these initiatives, if passed, may impact the demand for coal.



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Regional Emissions Trading: Eleven northeast and mid-atlantic states are working cooperatively to develop a regional cap and trade program that would initially cover carbon dioxide emissions from power plants in the region. The states intend to develop a model rule in 2005. There are a number of uncertainties regarding this initiative, including the applicable baseline of emissions to be permitted, initial allocations, required emissions reductions, availability of offsets, the extent to which states will adopt the program, whether it will be linked with programs in other states or in Canadian provinces, and the timing for implementation of the program. There can be no assurance at this time that a carbon dioxide cap and trade program, if implemented by the states where our customers operate, will not affect the future market for coal in this region.



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Regional Haze. The EPA has 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, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.

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Clean Water Act

        The Clean Water Act of 1972 (the "CWA") and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System ("NPDES"). Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water.

        Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams and may in certain instances include man-made conveyances that have a hydrologic connection to a stream or wetland. Presently, under the Stream Buffer Zone Rule, mining disturbances are prohibited within 100 feet of streams if negative effects on water quality are expected. OSM has proposed changes to this rule, which would make exemptions available if mine operators take steps to reduce the amount of waste and its effect on nearby waters. Legislation in Congress has been introduced in the past and may be introduced in the future in an attempt to preclude placing any mining material in streams. Such legislation would have a material adverse impact on future ability to conduct certain types of mining.

        The Army Corps of Engineers (the "COE") is empowered to issue nationwide permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the United States District Court for the Southern District of West Virginia seeking to invalidate nationwide permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed individual permits. On July 8, 2004, the court issued an order enjoining the further issuance of Nationwide 21 permits and rescinded certain listed permits where construction of valley fills and surface impoundments had not commenced. On August 13, 2004, the court extended the ruling to all Nationwide 21 permits within the Southern District of West Virginia. The United States Department of Justice appealed the decision to the United States Court of Appeals for the Fourth Circuit. The appeal is pending. (See the discussion in Legal Proceedings—Army Corps Section 404 Permit Litigation for a summary of the impact to date of this case on us.) A similar suit was filed in January 2005 in the United States District Court for the Eastern District of Kentucky. Although we have no current operations in Kentucky, similar suits may be filed in other jurisdictions.

        Total Maximum Daily Load ("TMDL") regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments. Some of our operations currently discharge effluents into stream segments that have been designated as impaired. The adoption of new TMDL related effluent limitations for our coal mines could require more costly water treatment and could adversely affect our coal production.

        Under the CWA, states must conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state's anti-degradation regulations would prohibit the diminution of water quality in these streams. Several environmental groups and individuals recently challenged, and in part successfully, West Virginia's anti-degradation

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policy. In general, waters discharged from coal mines to high quality streams will be required to meet or exceed new "high quality" standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits, and could aversely affect our coal production.

        Federal and state laws and regulations can also impose measures to be taken to minimize and\or avoid altogether stream impacts caused by both surface and underground mining. Temporary stream impacts from mining are not uncommon, but when such impacts occur there are procedures we follow to remedy any such impacts. These procedures have generally been effective and we work closely with applicable agencies to implement them. Our inability to remedy any temporary stream impacts in the future, and the application of existing or new laws and regulations to disallow any stream impacts, could adversely affect our operating and financial results.

Endangered Species Act

        The Federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Resource Conservation and Recovery Act

        The Resource Conservation and Recovery Act ("RCRA") affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

        Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill. The agency also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. Most state hazardous waste laws also exempt coal combustion waste, and instead treat it as either a solid waste or a special waste. Any costs associated with handling or disposal of hazardous wastes would increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of ash can lead to material liability.

Federal and State Superfund Statutes

        Superfund and similar state laws affect coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment

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and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. In addition, mining operations may have reporting obligations under the Emergency Planning and Community Right to Know Act and the Superfund Amendments and Reauthorization Act.

Climate Change

        One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the "Protocol"), which establishes a binding set of emission targets for greenhouse gases. With Russia's approval, the Protocol now has sufficient support and became binding on all those countries that have ratified it on February 16, 2005. Four industrialized nations have refused to ratify the Protocol—Australia, Liechtenstein, Monaco, and the United States. Although the targets vary from country to country, if the United States were to ratify the Protocol, the United States would be required to reduce greenhouse gas emissions to 93% of 1990 levels from 2008 to 2012.

        Future regulation of greenhouse gases in the United States could occur pursuant to future United States treaty obligations, statutory or regulatory changes under the Clean Air Act, or otherwise. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases reduction targets which provide for certain incentives if targets are met. Some states, such as Massachusetts, have already issued regulations regulating greenhouse gas emissions from large power plants. Further, in 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Increased efforts to control greenhouse gas emissions, including the future ratification of the Protocol by the, United States could result in reduced demand for coal.

GLOSSARY OF SELECTED TERMS

        Ash.    Impurities consisting of iron, alumina and other incombustible matter that are contained in coal. Ash can affect the burning characteristics of coal.

        Assigned reserves.    Coal that has been committed to be mined at operating facilities.

        Bituminous coal.    The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btus per pound. It is dense and black and often has well-defined bands of bright and dull material.

        British thermal unit, or "Btu."    A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

        Central Appalachia.    Coal producing area in eastern Kentucky, Virginia and southern West Virginia.

        Clean Air Act Amendments.    A comprehensive set of amendments to the federal law governing the nation's air quality. The Clean Air Act was originally passed in 1970 to address significant air pollution concerns in our cities. The 1990 amendments broadened and strengthened the original law to address specific concerns such as acid deposition, urban smog, hazardous air pollutants and stratospheric ozone depletion.

        Coal seam.    Coal deposits occur in layers. Each layer is called a "seam."

        Coke.    A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel.

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        Compliance coal.    Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, as required by Phase II of the Clean Air Act.

        Continuous miner. A machine which constantly extracts coal while loading. This is to be distinguished from a conventional mining unit which must stop the extraction process in order for loading to commence.

        Continuous mining.    Any coal mining process which tears the coal from the face mechanically and loads continuously, thus eliminating the separate cycles of cutting, drilling, shooting and loading. This is to be distinguished from conventional mining, an older process in which these operations are cyclical.

        Fossil fuel.    Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material.

        High Btu coal.    Coal which has an average heat content of 12,500 Btu per pound or greater.

        Illinois Basin.    Coal producing area in Illinois, Indiana and western Kentucky.

        Lignite.    The lowest rank of coal with a high moisture content of up to 45% by weight and heating value of 6,500 to 8,300 Btus per pound. It is brownish black and tends to oxidize and disintegrate when exposed to air.

        Longwall mining.    The most productive underground mining method in the United States. A rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface.

        Low Btu coal.    Coal which has an average heat content of 9,500 Btu per pound or less.

        Low sulfur coal.    Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btu.

        Medium sulfur coal.    Coal which, when burned, emits between 1.6 and 4.5 pounds of sulfur dioxide per million Btu.

        Metallurgical coal.    The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as "met" coal, its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal typically has a particularly high Btu but low ash and sulfur content.

        Mid Btu coal.    Coal which has an average heat content of between 9,500 and 12,500 Btus per pound.

        Nitrogen oxide (NOx).    A gas formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to acid rain.

        Northern Appalachia.    Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

        Overburden.    Layers of soil and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

        Pillar.    An area of coal left to support the overlying strata in a mine; sometimes left permanently to support surface structures.

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        Powder River Basin.    Coal producing area in northeastern Wyoming and southeastern Montana. This is the largest known source of coal reserves and the largest producing region in the United States.

        Preparation plant.    Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal's sulfur and ash content.

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

        Proven reserves.    Reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

        Reclamation.    The process of restoring land and the environment to their original state following mining activities. The process commonly includes "recontouring" or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

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

        Roof.    The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

        Room-and-Pillar Mining.    Method of underground mining in which the mine roof is supported mainly by coal pillars left at regular intervals. Rooms are placed where the coal is mined.

        Scrubber (flue gas desulfurization system).    Any of several forms of chemical/physical devices which operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal. Although effective in substantially reducing sulfur from combustion gases, scrubbers require about 6% to 7% of a power plant's electrical output and thousands of gallons of water daily to operate.

        Steam coal.    Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

        Sub-bituminous coal.    Dull coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 35% by weight, and its heat content ranges from 7,800 to 9,500 Btu per pound of coal.

        Sulfur.    One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

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        Surface mine.    A mine in which the coal lies near the surface and can be extracted by removing the covering layers of Overburden. About 60% of total United States coal production comes from surface mines.

        Tons.    A "short" or net ton is equal to 2,000 pounds. A "long" or British ton is equal to 2,240 pounds; a "metric" tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Form 10-K.

        Truck-and-Shovel mining and Truck and Front-End Loader mining.    Similar forms of mining where large shovels or front-end loaders are used to remove overburden, which is used to backfill pits after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the preparation plant or rail loadout.

        Unassigned reserves.    Coal at suspended locations and coal that has not been committed to be mined at operating facilities, and that would require new mine development, mining equipment or plant facilities before operations could begin on the property.

        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. Most underground mines are located east of the Mississippi River and account for about 40% of annual United States coal production.

        Unit train.    A train of 100 or more cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.

        Western Bituminous Region.    Coal producing area in western Colorado and eastern Utah.

ITEM 2. PROPERTIES

Coal Reserves

        Periodically, we retain outside experts to independently verify our coal reserve base. The most recent review was completed during the first quarter of 2004 and covered all of our reserves. The results verified our reserve estimates, with minor adjustments, and included an in-depth review of our procedures and controls. Some of the coal reserves assessed in 2004 were calculated using what is commonly referred to as a "dry basis" instead of an "as received" basis. "As received" means measuring coal in its natural state and not after it is dried in a laboratory setting. Since that time, we have recalculated all reserves on an "as received" basis. Our reserve base was approximately 1.8 billion tons as of December 31, 2004.

        Of the 1.8 billion tons, approximately 1.0 billion tons are assigned reserves that we expect to be mined at operations that were active as of December 31, 2004. Approximately 0.8 billion tons are unassigned reserves that we are holding for future development and, in most instances, would require new mining equipment, development work and possibly preparation facilities before we could commence coal mining. All of our reserves in Wyoming and Illinois are assigned. We have substantial unassigned reserves in Pennsylvania and West Virginia.

        Approximately 58% of our reserves are classified as high Btu coal (coal delivered with an average heat value of 12,500 Btu per pound or greater) and are located in Pennsylvania and West Virginia. Approximately 44% of our reserves are classified as compliance coal which meets the 1.2 lb SO₂/mmBtu standard of Phase II of the Clean Air Act. Our compliance reserves are located in Wyoming and West Virginia.

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        The table below summarizes the locations, coal reserves in millions of tons and primary ownership of the coal reserves. Tonnage is on an as-received, wet basis and the quality figures represent an approximate reserve average.

(1)

Proven and probable coal reserves are classified as follows:

Proven reserves—Reserves for which (i) 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 (ii) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

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

        We believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our current reserve base is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

        Our reserve estimate is based on geological data assembled and analyzed by our staff of geologists and engineers. Reserve estimates are periodically updated to reflect past coal production, new drilling information and other geological or mining data. Acquisitions or sales of coal properties will also change the reserve base. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will plant processing efficiency tests. We maintain reserve information in secure computerized data bases, as well as in hard copy. The ability to update and/or modify the reserve base is restricted to a few individuals and the modifications are documented.

        Our mines in Wyoming are subject to federal coal leases that are administered by the United States Department of Interior under the Federal Coal Leasing Amendment Act of 1976. Each lease has a maximum term of 100 years and requires diligent development of the lease within the first 10 years of the lease award with a required coal extraction of 1.0% of the reserves within that 10-year period. At the end of the 10-year development period, the mines are required to maintain continuous operations, as defined in the applicable leasing regulations. All of our federal leases are in full compliance with these regulations. We pay the federal government an annual rent of $3.00 per acre and production royalties of 12.5% of gross proceeds on surface mined coal. The federal government remits half of the production royalty payments to Wyoming after deducting administrative expenses.

        Certain of our mines in Pennsylvania, West Virginia and Illinois are subject to private coal leases. Private coal leases normally have a stated term and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either

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as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease rental or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically.

        Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

ITEM 3. LEGAL PROCEEDINGS

        From time to time, we are involved in legal proceedings arising in the ordinary course of business. We believe we have recorded adequate accruals for these liabilities and that there is no individual case or group of related cases pending that is likely to have a material adverse effect on our financial condition, results of operations or cash flows. We discuss our significant legal proceedings below.

West Virginia Flooding Litigation

        Three of our subsidiaries were named as defendants in six separate complaints filed in Raleigh and Wyoming Counties, West Virginia, in late 2001, alleging personal injury and property damage caused by flooding on or about July 8, 2001. Similar suits may be filed in the future based on this or subsequent weather events. The general alleged basis for the lawsuits is that coal mining, oil and gas drilling and timbering operations altered the topography in the area to such an extent that flooding resulting from heavy rains caused more severe damage than would have otherwise resulted. Numerous similar complaints were filed by approximately 500 plaintiffs against over 100 defendants, in a total of seven southern West Virginia counties. All such civil actions have been referred by the West Virginia Supreme Court to a three-judge panel, sitting in Raleigh County, pursuant to the court's mass litigation rule.

        On December 9, 2004, the West Virginia Supreme Court issued an opinion addressing certain questions of law certified to it by the three-judge panel. Among other rulings, the Supreme Court decision held that plaintiffs may not proceed under a strict liability theory, as had been asserted in their complaints. The court also held that where damages can be shown to have been caused by an unusual act of nature combined with the conduct of a defendant, the defendant should be given an opportunity to show by clear and convincing evidence that it caused only a portion of those damages, in order to avoid incurring liability for all damages.

        Pursuant to an existing order, no formal discovery has taken place in any of these cases, and the filing of cross-claims, counterclaims and third-party actions was stayed. In March 2005 the three judge panel issued a scheduling order indicating that six different trials will be held, one for each watershed impacted. Each trial will be held in two phases with the liability phase being held first, and then a damages phase. The first trial is currently scheduled to commence in March 2006. This will relate to flooding in the Upper Guyandotte River watershed in which our affiliates have operations.

        The claims against these entities are covered by insurance. Common defense counsel and experts are representing numerous defendants and costs are being shared. While the outcome of this litigation is unknown, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flow.

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Army Corps Section 404 Permit Litigation

        On October 23, 2003, several citizens groups sued the COE in the United States District Court for the Southern District of West Virginia seeking to invalidate "nationwide" permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators, including one of our subsidiaries, from additional use of existing nationwide permit approvals until they obtain more detailed "individual" permits. On July 8, 2004, the court issued an order enjoining the further issuance of nationwide permits and requiring individual permits to be obtained in their place. The order also precludes activity on areas covered by certain existing nationwide permits. The United States Department of Justice appealed the decision to the United States Court of Appeals for the Fourth Circuit. The appeal is pending. A similar suit was filed in January 2005 in the United States District Court for the Eastern District of Kentucky. Although we have no current operations in Kentucky, similar suits may be filed in other jurisdictions.

        Because of the decision, one nationwide permit already issued to a subsidiary of ours developing the new Pax Surface Mine in Raleigh County, West Virginia was converted to an individual permit. That conversion application was open to public comment and comments were received. We responded to the comments in a timely manner and approval of the permit is anticipated. Also because of this decision, a then pending nationwide permit application for a second permit at the Pax Surface Mine was converted to an individual permit application. Public comments were received and we responded to those comments in a timely manner as well. That permit was issued on January 7, 2005. Although the new Pax Surface Mine and other mines may experience additional permit requirements and potential delays in permit approvals, based on the information available to us at this time, we believe our existing operations will not be adversely impacted in a material manner.

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

        No matters were submitted to a vote of security holders during the fourth quarter of the year ended December 31, 2004.

PART II

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

        The Company's common stock is not publicly traded. The common stock of our ultimate parent, Foundation Coal Holdings, Inc., trades on the New York Stock Exchange under the symbol "FCL".

        The following table sets forth, for the periods indicated, the range of high and low prices for the common stock of Foundation Coal Holdings, Inc. obtained from the New York Stock Exchange.

        As of March 7, 2005, there were approximately 25 holders of record of the common stock of Foundation Coal Holdings, Inc. and an additional 13,112 stockholders whose shares were held for them in street name or nominee accounts.

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Equity Compensation Plan Information

        This table provides information about our parent company's common stock subject to equity compensation plans as of December 31, 2004.

*

Our parent Company Foundation Coal Holdings, Inc. has one active equity compensation plan, the Foundation Coal Holdings, Inc. 2004 Stock Incentive Plan, as amended, and approved by stockholders on December 8, 2004.

Dividend Policy

        We are a privately held company and we do not have plans to pay dividends. From time to time we may pay dividends up to our parent affilated entities subject to the restrictions in our Senior Credit Facilities.

        We did not repurchase any of our common stock in 2004 and have no plans to do so in the foreseeable future.

Recent Sales of Unregistered Securities

        Not applicable. The registrant has not sold any unregistered equity securities within the past three years.

ITEM 6. SELECTED FINANCIAL DATA

        From its incorporation on April 23, 2004 and prior to the acquisition of RAG American Coal Holdings, Inc. on July 30, 2004, Foundation Coal Corporation did not have any assets, liabilities or results of operations. Therefore, the selected historical consolidated financial data as of and for the years ended December 31, 2003, 2002 and 2001 and for the period from January 1, 2004 to July 29, 2004 have been derived from the audited consolidated financial statements of RAG American Coal Holding, Inc., the predecessor to Foundation Coal Corporation, which have been audited by Ernst & Young LLP, an independent registered public accounting firm. The selected historical consolidated financial data as of and for the year ended December 31, 2000 were derived from the consolidated financial statements of RAG American Coal Holding, Inc., which have been prepared on a basis consistent with the audited consolidated financial statements as of and for the year ended December 31, 2003. The selected historical consolidated financial data as of and for the period from April 23, 2004 to December 31, 2004 have been derived from the audited consolidated financial statements of Foundation Coal Corporation. In the opinion of management, such consolidated financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for those periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period. The successor balance sheet data and adjustments used in preparing the financial data reflect our preliminary purchase price allocation, which may change upon further evaluation by management and finalization of the appraisal valuation that we have obtained. The audited consolidated financial statements as of and for the years ended December 31, 2003 and 2002 and for the period from January 1, 2004 to July 29, 2004 and as of and for the period from April 23, 2004 to December 31, 2004, are included elsewhere in this Form 10-K.

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        You should read the following data in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with the financial information included elsewhere in this Form 10-K, including the consolidated financial statements and related notes thereto.

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(1)

Other revenues include gains on disposition of assets and other non-coal sales revenues. In 2001, other revenues included $11.5 million related to the termination of a royalty agreement in conjunction with the closure of Willow Creek and $2.6 million for management services provided to an affiliate of RAG AG. See note 24 to the consolidated financial statements for additional details of other revenue.

(2)

Asset impairment charges in 2001 consisted of $8.6 million for the write-off of a 5% investment in Los Angeles Export Terminal, Inc. which we disposed of effective December 31, 2003 and $8.0 million for the write-off of the Red Ash plant in West Virginia. Asset impairment charges in 2002 consisted of $7.0 million for the write-down of a 55% investment in a Wyoming coal bed methane joint venture; this joint venture is accounted for under the proportional consolidation method.

(3)

Expenses resulting from loss on termination of hedge accounting for interest rate swaps represents a non-cash charge equal to the fair value of our pay-fixed receive-variable interest rate swaps on February 29, 2004, the date the swaps ceased to qualify for hedge accounting as a result of the required repayment of the related notes due to the sale of our Colorado operations. An additional non-cash mark-to-market gain of $5.8 million was incurred in the period February 29 to April 27, 2004. The swap was settled on April 27, 2004. See note 16 to the consolidated financial statements for additional information.

(4)

Contract settlement consists of a non-cash charge arising from settlement of a guarantee claim with the South Carolina Public Service Authority by means of entering into a multi-year coal supply agreement at prices below the then prevailing market prices for new coal supply agreements of similar duration.

(5)

Consists of cash prepayment penalties in connection with prepayment of substantially all remaining long-term indebtedness of the Predecessor.

(6)

Minority interests consisted of a 20% interest in Neweagle Industries, Inc. that was purchased by us on September 30, 2000 for a net cash purchase price of $21.4 million and a 15% interest in Plateau Mining Corporation, the subsidiary that owned and operated Willow Creek, that was purchased by us on December 10, 2001 for $11.5 million. These acquisitions of minority interests were accounted for using the purchase method of accounting.

(7)

Represents arbitration and litigation settlements recorded in 2002 and 2003.

(8)

On November 25, 1998 and July 31, 2000, underground mine fires occurred at the Willow Creek mine in Utah. After the second fire, we decided not to reopen the mine. We had both property damage and business interruption insurance coverage for the losses associated with these fires. Insurance proceeds in excess of the book value of net assets and closure costs of $7.7 million in 2000 and $31.2 million in 2001 were recognized as other income.

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(9)

On February 29, 2004, RAG Coal International AG, the parent of RAG American Coal Holding, Inc. signed an agreement to sell the active Twentymile mine and certain inactive or closed properties in Colorado and Wyoming to a third party. Accordingly, the results of the Colorado operations are shown as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). The sale closed on April 15, 2004. Proceeds from the sale were used to repay certain debt and accrued interest and to settle related interest rate swaps.

(10)

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143").

(11)

EBITDA, a measure used by management to measure performance, is defined as income (loss) from continuing operations, plus interest expense, net of interest income, income tax expense (benefit), depreciation, depletion and amortization, and amortization of coal supply agreements. Our management believes EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. EBITDA is not a recognized term under GAAP and does not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. Because not all companies use identical calculations, this presentation of EBITDA may not be comparable to other similarly titled measures of other companies.

Additionally, EBITDA is not intended to be a measure of cash flow available for management's discretionary use, as it does not reflect certain cash requirements such as interest payments, tax payments and debt service requirements. The amounts shown for EBITDA as presented herein differ from the amounts calculated under the definition of EBITDA used in our debt instruments. The definition of EBITDA used in our debt instruments is further adjusted for certain cash and non-cash charges and is used to determine compliance with financial covenants and our ability to engage in certain activities such as incurring additional debt and making certain payments. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Covenant Compliance".

EBITDA is calculated and reconciled to income (loss) from continuing operations in the table below.

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(12)

Income (loss) from continuing operations and EBITDA, as defined above, were impacted by the following non-cash charges (income):

(a)

The amount for the Predecessor includes $48.9 million of expense resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps less $5.8 million mark-to-market adjustment. See note (3) above. Under the terms of the stock purchase agreement, we did not assume any existing interest rate swaps. The amount for the Successor includes the mark-to-market loss on interest rate swaps not yet designated as cash flow hedges prior to December 31, 2004.



(b)

Represents the portion of pension, other post-retirement and black lung expense resulting from amortization of unrecognized actuarial losses, prior service costs and transition obligations.



(c)

Represents incremental cost of sales recorded in the period arising from the preliminary estimate of profit added to inventory in purchase accounting.



(d)

In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially and fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-acquisition overburden removal efforts is included in depreciation, depletion and amortization. Subsequent to the acquisition date, the cost associated with removal of overburden to uncover coal reserves is deferred until the related coal is mined and charged to cost of coal sales when the coal is sold. Until coal valued as partially or fully uncovered at the acquisition date is fully depleted, depreciation, depletion and amortization will include the value of overburden removal performed prior to the acquisition date which if incurred subsequent to the acquisition date would have been included in cost of coal sales.

(13)

Income (loss) from continuing operations and EBITDA, as defined above, were also impacted by the following unusual (income) expense:

(a)

Represents arbitration awards and litigation settlements, net of related legal and tax fees. Legal and tax fees associated with these settlements were $1.0 million in 2001, $6.8 million in 2002, $1.6 million in 2003, and $0.5 million in the period January 1 to July 29, 2004.

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(b)

Represents the cost of a one-time bonus awarded to certain employees in connection with the Transaction.



(c)

Represents the cost of a long-term incentive plan instituted by the Seller in 2001 that was terminated prior to closing as required by the change in control provisions in the plan agreement. We have implemented a management equity program that will not result in a cash cost to us.



(d)

Represents $2.6 million from management services provided to an affiliate of RAG Coal International AG in 2001 by the Predecessor. Represents a $1.8 million bonus paid to senior management related to the IPO and a $2.0 million sponsor monitoring fee recorded by the Successor. This latter item was terminated in connection with the IPO.

(14)

Represents the estimated impact on EBITDA of the temporary idling of our Cumberland mine in the first half of 2004 as a result of a revised interpretation of mine ventilation laws by MSHA. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information.

(15)

For purposes of this computation, "earnings" consist of pre-tax income from continuing operations (excluding minority interest and equity in earnings of affiliates) plus fixed charges. "Fixed charges" consist of interest expense on all indebtedness plus amortization of deferred costs of financing and the interest component of lease rental expense. Earnings were insufficient to cover fixed charges by $36.7 million for the year ended December 31, 2000 and $142.4 million for the period January 1 to July 29, 2004.

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Overview

        We are the fifth largest coal company in the United States operating nine mining complexes that consist of thirteen individual coal mines. Our mining operations are located in southwest Pennsylvania, southern West Virginia, southern Illinois and the southern Powder River Basin region of Wyoming. Three of our mining complexes are surface mines, two of our complexes are underground mines using highly efficient longwall mining technology and the remaining four complexes are underground mines that utilize continuous miners. In addition to mining coal, we also purchase coal from other producers and utilize it with our own production in coal brokering and trading activities.

        Our primary product is steam coal, sold primarily to electric power generators located in the United States. Approximately 8% of our pro-forma 2004 sales revenue was made from the sale of metallurgical coal to the domestic and export metallurgical coal markets where it is used to make coke for steel production.

        While the majority of our revenues are derived from the sale of coal, we also realize revenues from coal production royalties, override royalty payments from a coal supply agreement now fulfilled by another producer, fees from the processing of our production by a synfuel facility, fees to transload coal through our Rivereagle facility on the Big Sandy River and revenues from the sale of coalbed methane.

        From July 1, 1999 through July 29, 2004, we were a stand-alone wholly owned subsidiary of RAG Coal International AG ("RAG") headquartered in Essen, Germany. In October 2003, RAG announced its intention to divest its international mining subsidiaries. In addition to RAG American Coal Holding, Inc., these international mining subsidiaries consisted of operations in Australia and Venezuela. On February 29, 2004, RAG announced the sale of four of our subsidiaries, collectively known as the RAG Colorado Business Unit, to a third party. The subsidiaries comprising the RAG Colorado Business Unit owned an underground longwall mine located in Routt County, Colorado, an idled underground longwall mine located in Moffat County, Colorado and surface lands located in northwest Colorado and southern Wyoming. The transaction closed on April 15, 2004. In the financial statements for the period January 1 through July 29, 2004 and for the years ended December 31, 2002 and 2003, the RAG Colorado Business Unit has been classified as a discontinued operation.

        On May 24, 2004, RAG, entered into a definitive agreement with Foundation Coal Corporation, which was owned by affiliates of First Reserve, Blackstone and AMCI, to sell all of its operations

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except the Colorado Business Unit which was sold on April 15, 2004. The transaction closed on July 30, 2004.

Results of Continuing Operations

Basis of Presentation:

        RAG American Coal Holding, Inc. and its subsidiaries, excluding the subsidiaries comprising the Colorado Business Unit which were sold on April 15, 2004, were acquired by Foundation Coal Corporation on July 30, 2004. Due to the change in ownership, and the resultant application of purchase accounting, the historical financial statements of the Predecessor and the Successor included in this Form 10-K have been prepared on different bases for the periods presented and are not comparable.

        The following provides a description of the basis of presentation during all periods presented:

        Successor—Represents the consolidated financial position of Foundation Coal Corporation as of December 31, 2004 and our consolidated results of operations and cash flows for the period from April 23 through December 31, 2004. Our ultimate parent, Foundation Coal Holdings, Inc., had no significant activities until the acquisition of RAG American Coal Holding, Inc. on July 30, 2004. Hereinafter, the period from April 23 through December 31, 2004 is referred to as the "five month operating period ended December 31, 2004." Our consolidated financial position at December 31, 2004 and our consolidated results of operations for the five month operating period ended December 31, 2004 reflect our preliminary estimates of purchase price allocation based on preliminary appraisals prepared by independent valuation specialists and preliminary employee benefit valuations prepared by independent actuaries. Deferred income taxes have been provided in the consolidated balance sheet based on our best estimates of the tax versus book basis of the assets acquired and liabilities assumed, as adjusted to estimated fair values. The amounts that we may record based on the final assessment and determination of fair values may differ significantly from the information presented in the consolidated balance sheet as of December 31, 2004 and the consolidated statement of operations for the five month operating period then ended. The application of purchase accounting to the acquired assets of RAG American Coal Holding, Inc. resulted in increases to owned and leased mineral rights, surface lands, coal inventories, and the asset arising from recognition of asset retirement obligations. It resulted in decreases to plant and equipment and current deferred taxes. In addition, the historical cost assigned to deferred overburden in the acquired asset balance sheet was eliminated. The values assigned to uncovered and partially covered coal lands considered the stage of the mining process in which these two groups of coal lands were at the acquisition date. The application of purchase accounting to the acquired liabilities of RAG American Coal Holding, Inc. resulted in increases to postretirement health care obligations, pension obligations, black lung obligations, asset retirement obligations and noncurrent deferred taxes. Separate assets or liabilities were established to reflect the valuation of above or below market coal supply agreements in relation to market price curves. With regard to consolidated results of operations for the five month operating period ended December 31, 2004, the principal effects of the application of purchase accounting, in comparison to reporting for historical periods, were to decrease the cost of coal sold due to lower expenses for postretirement health care and pensions, to decrease the cost of coal sold for net deferrals of deferred overburden costs, to decrease net amortization expense for coal supply agreements which is now a credit, because our contracts at acquisition represented a net liability, to increase the cost of depletion expense for owned and leased mineral rights and to increase the cost of coal sold for the increase in value of coal inventories from cost to market.

        Predecessor—Represents the consolidated financial position, results of operations and cash flows for RAG American Coal Holding, Inc. for each of the two years ended December 31, 2002 and 2003, and for the period January 1 through July 29, 2004, respectively. These consolidated financial

35

statements are based on the historical assets, liabilities, sales and expenses of the Predecessor for these periods. During the period January 1 through July 29, 2004, RAG American Coal Holding, Inc. reported a loss from continuing operations before income tax expense of $142.4 million. This result included $64.8 million in pre-tax charges related to prepayment of RAG American Coal Holding, Inc.'s long term debt and settlement of related interest rate swaps in preparation for the sale of RAG American Coal Holding, Inc. and a $26.0 million pre-tax non-cash charge related to settlement of a guarantee by entering into a new multi-year coal supply agreement at prices below then prevailing market prices for new contracts of similar duration. Also during the period January 1 through July 29, 2004, RAG American Coal Holding, Inc. recognized a pre-tax gain of $25.7 million from the sale of the RAG Colorado Business Unit.

        Combined pro-forma—To facilitate trend analysis, throughout management's discussion and analysis, we discuss "combined pro-forma" results for 2004. Combined pro-forma amounts are determined by adding the historical amounts of the Predecessor for the period January 1, 2004 through July 29, 2004 with the corresponding amounts of the Successor for the five month operating period ended December 31, 2004. Combined pro-forma amounts are not recognized measures under GAAP and do not purport to be alternatives to GAAP operating measures. Combined pro-forma amounts are not indicative of the operating results of Foundation Coal Corporation because of the significant difference in basis between the Successor and Predecessor caused by the acquisition on July 29, 2004 and its impact on income from operations. Management believes that the discussion of combined pro-forma operating results is important to the readers of the financial statements to understand key operating trends over the normal operating cycle of one year.

Period January 1, 2004 through July 29, 2004 Compared to the Year Ended December 31, 2003 for RAG American Coal Holding, Inc. plus comments and comparisons to the five month operating period ended December 31, 2004 for Foundation Coal Corporation.

        Coal sales realization per ton sold represents the average revenue realized on each ton of coal sold. It is calculated by dividing coal sales revenues by tons sold.

Revenues

        Coal sales volumes and coal sales revenues reported for the period January 1 through July 29, 2004 and the five month operating period ended December 31, 2004 are reported on a comparable basis, and represent, in combination, the pro-forma results for the year ended December 31, 2004. On a combined pro-forma basis, tons sold and coal sales revenues for 2004 were 63.5 million tons and $980.9 million, respectively, compared with 67.2 million tons and $976.0 million in the year ended December 31, 2003. The decrease in tons sold in 2004 as compared to 2003 is primarily due to lower production and sales from the Cumberland and Emerald mines in Northern Appalachia. From February 17 through May 7, the longwall mining equipment at the Cumberland mine was idled due to alleged violations resulting from a revised interpretation of regulations issued by MSHA regarding the

36

ventilation system in the mine. In response, we revised the ventilation system to minimize any future business disruption, and on May 7, 2004, we resumed longwall operations at the Cumberland mine. Mainly as a result of the idle period for its longwall coupled with reduced shipments due to high water conditions from the hurricanes in September and October 2004, Cumberland's tons sold and coal sales revenues were 1.2 million tons and $28.7 million, respectively, lower in 2004 compared to the corresponding period of 2003. Emerald, sold 1.3 million tons less in 2004 compared to the corresponding period of 2003 primarily due to mining delays attributable to adverse geological problems consisting of sandstone intrusions from the roof into the coal seam in the longwall panel mined during the period February through October 2004, which slowed mining by forcing the machinery to cut harder material and causing less stable roof conditions. While Emerald achieved record production in the month of December 2004, shipments for that month did not keep pace with production due to constrained rail capacity. The coal sales revenue effect of these lower 2004 shipments from Emerald were partly offset by increased average realizations per ton.

        The Powder River Basin and Central Appalachia also had reduced combined pro-forma tons sold in 2004 compared with 2003 totaling 1.2 million tons. In Central Appalachia, the Pioneer mine complex produced and sold less tons as the Simmons Fork surface mine completed mining and began the transition to the Pax surface mine. In the Powder River Basin, Eagle Butte produced and sold less tons due to a combination of poor rail service and limited attractively priced short term sales opportunities. Combined pro-forma 2004 coal sales revenues in both the Powder River Basin and Central Appalachia increased from 2003 as higher average realizations more than offset the lower tons sold.

        Total combined pro-forma coal sales revenues increased 0.5% year-to-year as a 6.5% increase in average realizations, due to improved pricing in all regions in which Foundation Coal operates, was largely offset by a 5.5% decrease in tons sold, largely as a result of reduced production from our Northern Appalachia longwall mines as described above.

        Other revenues reported for the period January 1 through July 29, 2004 and the five month operating period ended December 31, 2004 were reported on a comparable basis, and represent, in combination, the combined pro-forma results for the year ended December 31, 2004. On a combined pro-forma basis, other revenues in 2004 are $3.7 million less than 2003. An additional $3.7 million of losses on settlement of coal sales contracts and $4.2 million less from gains on asset sales in 2004 plus a $1.4 million gain from settlement of an asset retirement obligation in 2003 were partly offset by increased 2004 synfuel fees of $2.7 million and increased 2004 coalbed methane revenues of $3.9 million.

Costs and Expenses

        Cost of coal sales.    The cost of coal sales for the five month operating period ended December 31, 2004 (which represents operations from July 30 through December 31, 2004) included approximately

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$15.3 million less in deferred overburden charges and $8.8 million less in postretirement medical, pension and black lung benefit expenses as a result of purchase accounting compared with a comparable length period of the Predecessor. In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially and fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-acquisition overburden removal efforts, is included in depreciation, depletion and amortization. Subsequent to the acquisition date, the costs associated with removal of overburden to uncover coal reserves is inventoried as work-in-process until the related coal is mined and the inventoried cost charged to cost of coal sales when the coal is sold. Until coal valued as partially or fully uncovered at the acquisition date is fully depleted, depreciation, depletion and amortization will include the value of overburden removal performed prior to the acquisition date which if incurred subsequent to the acquisition date would have been included in cost of coal sales. As a result of revaluing pension and post employment benefit liabilities at the acquisition date under purchase accounting, unamortized actuarial losses which were being amortized in expense by the Predecessor were eliminated. As a result, pension and post retirement benefit costs of the Successor are expected to be lower than that of the Predecessor. Cost of coal sales for the five month operating period ended December 31, 2004 also included approximately $3.8 million of additional charges from sale of inventories revalued to market in purchase accounting than for a comparable length period of the Predecessor. These effects from the application of purchase accounting to the Successor basis of reporting cost of coal sales net to $20.3 million of reduced expense. Otherwise the cost of coal sales are reported on a comparable basis for the period January 1 through July 29, 2004 and for the five month operating period ended December 31, 2004. The combined pro-forma 2004 cost of coal sales was $830.3 million compared to $798.4 million in 2003.

        This increase is the net impact of the $15.3 million less in deferred overburden charges as a result of purchase accounting, the elimination of $8.8 million in amortization of actuarial losses in pension and post retirement medical expenses, the additional cost of sales of $3.8 million relating to inventory revalued at the acquisition date and an increase of $52.2 million, or 6.5%, mainly due to higher mine operating costs in the areas of retiree health care, workers' compensation, repairs and maintenance, mine operating supplies, wages, salaries, contract labor and coal trucking along with increased costs for purchased coal. The increased costs of mine operating supplies and repair and maintenance parts is largely attributable to commodity price increases, particularly for steel products and diesel fuel.

        Selling, general and administrative expenses.    Selling, general and administrative expenses for the period January 1 through July 29, 2004 included $1.8 million in bonus expenses related to the sale of RAG American Coal Holding, Inc. The five month operating period ended December 31, 2004 included $1.7 million of bonus expenses paid to senior management related to the IPO, $2.0 million of sponsor monitoring fees, and $1.3 million of expense arising from adjustment of the incurred-but-not-reported (IBNR) medical benefits liability. Combined pro-forma selling, general and administrative expenses for 2004 were $52.1 million compared to $45.3 million for the Predecessor in 2003. The increase is primarily due to the IPO and acquisition related costs discussed above. Increases in compensation, employee relocation expenses and professional service fees in the combined pro-forma 2004 period are offset by lower sales commissions and reduced consulting expenses compared to 2003.

        Accretion on asset retirement obligation.    Accretion on asset retirement obligation is a component of accounting for asset retirement obligations under SFAS No. 143. Accretion represents the increase in the asset retirement liability to reflect the change in the liability for the passage of time. We adopted SFAS No. 143 effective January 1, 2003. The impact of adopting SFAS No. 143 is discussed below. Application of purchase accounting increased accretion of asset retirement obligations by approximately $0.4 million in the five month operating period ended December 31, 2004 compared with a comparable

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length period of the Predecessor. Combined pro-forma accretion in asset retirement obligation for 2004 was $7.3 million compared with $7.0 million for the Predecessor for 2003.

        Depreciation, depletion and amortization.    In comparison to historical reporting of the Predecessor, depreciation depletion and amortization for the five month operating period ended December 31, 2004 reflects increased cost depletion of owned and leased mineral rights as a result of the purchase accounting in which higher values have been assigned to owned and leased mineral rights. In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially and fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-acquisition overburden removal efforts, is included in depreciation, depletion and amortization. Subsequent to the acquisition date, the costs associated with removal of overburden to uncover coal reserves is inventoried as work-in-process until the related coal is mined and the inventoried cost charged to cost of coal sales when the coal is sold. Until coal valued as partially or fully uncovered at the acquisition date is fully depleted, depreciation, depletion and amortization will include the value of overburden removal performed prior to the acquisition date which if incurred subsequent to the acquisition date would have been included in cost of coal sales. Cost depletion for the five month operating period includes $23.5 million related to the production of fully and partially uncovered coal which received a higher value than other owned and leased mineral rights at the acquisition date. Absent this application of purchase accounting the amortization of costs associated with fully and partially uncovered coal would have been included in and increased cost of coal sales. Combined pro-forma depreciation, depletion and amortization for 2004 was $146.0 million compared with $99.8 million for the Predecessor in 2003. The increase is the result of the higher basis in assets subject to depreciation depletion and amortization, primarily coal reserves as a result of recording these assets at fair value at the acquisition date. The Successor expects that depreciation, depletion and amortization in future years will continue to be higher than that of the Predecessor due to the higher asset bases.

        Coal supply agreement amortization.    Application of purchase accounting resulted in recognition of a significant liability for below market priced coal supply agreements as well as a significant asset for above market priced coal supply agreements, both in relation to market prices at the acquisition date. Amortization of the liability for below market priced coal supply agreements during the five month operating period ended December 31, 2004 totals $88.2 million of credit to expense. Amortization of the asset for above market priced coal supply agreements during the same period totals $20.9 million of charges to expense. Coal supply agreement amortization of the Predecessor was only related to above market coal supply agreements in existence at the time of the acquisition of certain mining properties in 1999. Amortization of the liability for below market priced coal supply agreements is expected to be approximately $116 million and $42 million in the years ended December 31, 2005 and 2006, respectively. Amortization of the asset for above market priced coal supply agreements is expected to be approximately $27 million and $20 million for the years ended December 31, 2005 and 2006, respectively.

Segment Analysis

        Powder River Basin—Income from operations for the period January 1 through July 29, 2004 was $30.7 million. Income from operations for the five month operating period ended December 31, 2004, was $3.5 million, and was reduced by approximately $20 million from the application of purchase accounting. The application of purchase accounting resulted in higher cost depletion and amortization of coal supply agreements partially offset by a reduction in cost of coal sales arising from the deferral of overburden removal costs. Combined pro-forma income from operations for the Powder River Basin for 2004 was $34.2 million compared to $47.7 million for the Predecessor in 2003. This decrease is due

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to the net of the impact of purchase accounting previously discussed and higher average sales realizations, partly offset by lower tons sold and increases in mine operating expenses.

        Northern Appalachia—Losses from operations for the period January 1 through July 29, 2004 were $10.4 million primarily due to the previously described idling of the longwall at the Cumberland mine from February 17 through May 7, 2004. Income from operations for the five month operating period ended December 31, 2004, was $49.4 million which benefited by approximately $38 million from the application of purchase accounting. This benefit was primarily from amortization of a liability established for below term market priced coal supply agreements, which is reported as a credit in amortization of coal supply agreements, partly offset by increased cost depletion and additional cost of coal sales from recording coal inventories at fair value at the acquisition date. Combined pro-forma income from operations for Northern Appalachia for 2004 was $39.1 million compared to $29.0 million for the Predecessor in 2003. The net impact of the effects of purchase accounting, the idle period for the Cumberland longwall and lower production from Emerald as a result of longwall mining delays from periodic adverse geological problems encountered in mining the first longwall panel of a new mining district between February and October 2004 account for this change. Though it is uncertain, we expect to encounter similar geological conditions in future panels to be mined at Emerald. In response to these conditions, we have made changes to our equipment and operating plan at Emerald that we believe will mitigate the impact of these adverse geologic conditions.

        Central Appalachia—Losses from operations for the period January 1 through July 29, 2004 were $9.8 million primarily due to production shortfalls associated with adverse geological problems at the Kingston and Rockspring mines, the depletion of reserves at one of the Pioneer surface mines, significant increases in operating costs in the areas of health care, mine operating supplies, workers' compensation, wages, salaries, contract labor, equipment repairs and maintenance and coal trucking coupled with litigation settlement charges of $2.7 million. Higher average sales realizations at all mines partly offset the reduced production and higher costs. Income from operations for the five month operating period ended December 31, 2004, was $21.8 million. Income for this five month operating period was benefited by approximately $22.0 million from the application of purchase accounting. This benefit from the application of purchase accounting was primarily from amortization of a liability established for below term market priced coal supply agreements which is reported as a credit in amortization of coal supply agreements, partly offset by higher cost depletion and additional cost of coal sales from recording coal inventories at fair value at the acquisition date. Combined pro-forma income from operations for Central Appalachia for 2004 was $12.0 million compared to $5.7 million for the Predecessor in 2003. This change in income from operations was the net impact of the effects purchase accounting and the same factors cited above for the period January 1 through July 29, 2004.

Other Income (Loss)

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        Litigation settlements.    In February 2003, we received a cash settlement from a litigation claim arising from inaccuracies in financial statements represented as correct by Cyprus Amax Minerals Company in connection with the sale to RAG of Cyprus Amax Coal Company in June 1999.

        Contract Settlement.    In July 2004, the Predecessor reached a settlement agreement with South Carolina Public Service Authority ("Santee Cooper") in which Santee Cooper agreed to relinquish any claims under a guarantee in exchange for a multi-year coal supply agreement from our Pennsylvania operations at prices below then prevailing market prices for new contracts of similar duration. The guarantee related to a multi-year supply agreement between Santee Cooper and a former subsidiary that the Predecessor sold to Horizon NR LLC in 1998. The Predecessor recorded a non-cash charge of $26.0 million in the period January 1 through July 29, 2004 based on the present value of the difference between the agreed upon contract prices and market prices for new contracts of similar duration.

        Expense resulting from termination of hedge accounting for interest rate swaps and unrealized gain (loss) on interest rate swap.    As a result of the execution of a definitive stock purchase agreement to sell the RAG Colorado Business Unit during the first quarter of 2004, it became probable that the Predecessor's variable rate bank debt would be repaid early rather than held to maturity. Therefore, pay-fixed, receive-variable interest rate swaps that had previously been designated as a hedge against the variable interest payments on this debt no longer qualified for hedge accounting under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Financial Instruments and Hedging Activities ("SFAS No. 133"). The fair value of the interest rate swaps on the date it became probable that the future variable interest payments being hedged by the swap would no longer be made was charged to "Loss on termination of hedge accounting for interest rate swaps" with a corresponding gain reported in other comprehensive income. The amount of the mark-to-market change in the fair value of the interest rate swaps for the portion of the year following the determination that they did not qualify for hedge accounting was recorded as an unrealized gain. The interest rate swaps were settled when the variable rate bank debt was repaid on April 27, 2004.