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
Amoco Minerals Company was incorporated in Delaware on September 2, 1969, as a subsidiary of Amoco Corporation. The name was changed to Cyprus Minerals Company on May 24, 1985 and then spun-off from Amoco Corporation in July of 1985.
Cyprus Minerals Company merged with and into AMAX, Inc., a New York corporation, on November 15, 1993, with Cyprus Minerals Company being the surviving corporation under the name Cyprus Amax Minerals Company.
On June 30, 1999, Cyprus Amax Minerals Company and its subsidiary, Amax Energy Inc., sold the stock of Cyprus Amax Coal Company and all of its subsidiaries consisting of its remaining coal properties to RAG International Mining GmbH (now RAG Coal International AG ("RAG")).
Foundation Coal Holdings, LLC was formed on February 9, 2004, by a group of investors for the purpose of acquiring the United States coal properties owned by RAG Coal International AG. A Stock Purchase Agreement was signed on May 24, 2004.
Foundation Coal Holdings, LLC, through its subsidiary, Foundation Coal Corporation, and pursuant to the Stock Purchase Agreement, completed the acquisition of 100% of the outstanding common shares of RAG American Coal Holding, Inc. and its subsidiaries from RAG Coal International AG, on July 30, 2004 (the "Transaction").
Foundation Coal Holdings, LLC, merged on August 17, 2004 into its subsidiary, Foundation Coal Holdings, Inc., a Delaware corporation that was formed on July 19, 2004. On December 9, 2004, we completed our Initial Public Offering (the "IPO").
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.
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:
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.
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 following table provides summary information regarding our principal mining complexes as of December 31, 2004.
*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.
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
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.
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.
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
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
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
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
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
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:
•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.
•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
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.
•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.
•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.
•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.
•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.
•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
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.
•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.
•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.
•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.
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
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
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.
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.
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.
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.
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.
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 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.
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.
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.
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.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock 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 obtained from the New York Stock Exchange.
As of March 7, 2005, there were approximately 25 holders of record of the Common Stock and an additional 13,112 stockholders whose shares were held for them in street name or nominee accounts.
Equity Compensation Plan Information
This table provides information about our common stock subject to equity compensation plans as of December 31, 2004.
*We have 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
Immediately prior to the consummation of our initial public offering (as described below), we declared four dividends, which were payable to our stockholders of record on December 8, 2004 (the "existing stockholders").
•The first dividend was a cash dividend of approximately $1 million, which was paid on December 29, 2004 to our existing stockholders out of interest earned on the net proceeds from our initial public offering.
•The second dividend was a cash dividend of approximately $433 million paid on January 4, 2005, to non-management stockholders, which was paid out of a portion of the net proceeds from our initial public offering. Existing stockholders that were members of management received a dividend of 231,621 shares of common stock instead of cash.
•The third dividend was a cash dividend of approximately $11.1 million, which we paid on January 4, 2005 to our existing stockholders with all of the proceeds we received from the shares sold pursuant to the underwriters' option to purchase additional shares in connection with our initial public offering.
•The fourth dividend was a stock dividend of 3,029,600 shares of our common stock, which we issued to our existing stockholders on January 10, 2005, the terms of which required that shortly after the expiration of the underwriters' option to purchase additional shares we issue to our existing stockholders the number of shares equal to (x) the number of additional shares the underwriters had an option to purchase in connection with our initial public offering minus (y) the actual number of shares the underwriters purchased from us pursuant to that option.
On February 15, 2005, our Board of Directors (the "Board") declared an initial quarterly dividend at a rate of $.04 per share payable on March 28, 2005 to stockholders of record on March 7, 2005. We expect our Board to continue to declare quarterly dividends at such rate for the foreseeable future. The Board will determine the amount of any future dividends from time to time based on (a) our results of operations and the amount of our surplus available to be distributed, (b) dividend availability and restrictions under our credit agreement and indenture, (c) the dividend rate being paid by comparable companies in the coal industry, (d) our liquidity needs and financial condition and (e) other factors that our board of directors may deem relevant. Foundation PA Coal Company's Senior Credit Facilities and indenture governing the 7 1/4% Senior Notes currently limit the amount that Foundation Coal Corporation, in the case of the indenture, and its direct parent, in the case of the Senior Credit Facilities, can pay as dividends to us. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources" for more detail on such limits.
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
We have issued securities in the following transactions, which were exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"), as a transaction by an issuer not involving any public offering thereunder. There were no underwriters involved in connection with the sale of these securities.
In July 2004, Foundation Coal Holdings, Inc. (the "issuer") was formed and issued 100 shares of its common stock to Foundation Coal Holdings, LLC. On August 10, 2004, the issuer declared a 196,000 for one stock split in the form of a stock dividend payable in shares of common stock to stockholders of record on August 10, 2004. The stock split resulted in Foundation Coal Holdings, LLC owning 19,600,000 shares of the issuer's common stock. Foundation Coal Holdings, LLC merged with and into the issuer on August 17, 2004, and each membership interest in Foundation Coal Holdings,
LLC was exchanged for one share of common stock of the issuer. The securities were issued pursuant to Rule 506 of the Securities Act of 1933.
On December 8, 2004, the Company completed an IPO of 23,610,000 shares of common stock. Net proceeds from the offering, after deducting underwriting discounts and offering expenses, were approximately $481.1 million. On December 8, 2004 immediately preceding the IPO, the Board approved, authorized and declared a 0.879639 for one reverse stock split of all the 19,600,000 common shares issued and outstanding thereby reducing common shares outstanding to approximately 17,240,900 shares. The Board then approved the declaration of two separate cash dividends of $0.058 and $25.41 per share, respectively, of common stock issued and outstanding for shareholders of record. The Company used approximately $434.0 million of the net proceeds from the Offering to pay the dividends to its stockholders. The Company used the remaining net proceeds of approximately $47.1 million to repay a portion of the indebtedness outstanding on the loans under the term loan facility and for other general corporate purposes. The underwriting agreement provided for up to 3,541,500 shares of common stock to be reserved for the satisfaction of an over-allotment option allowing the underwriters an option to purchase additional shares. 511,900 shares were sold pursuant to this underwriters' option generating net proceeds, after deducting underwriting discounts and estimated offering expenses, of approximately $10.6 million. The Company used these proceeds and cash on hand to pay an additional dividend to its existing stockholders in the amount of $11.1 million. The remaining over-allotment shares not purchased were declared in the form of a stock dividend to the stockholders immediately prior to the initial public offering.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Foundation Coal Holdings, Inc. does not have any independent external operations, assets or liabilities, other than through its operating subsidiaries. From its formation on February 9, 2004 and prior to the acquisition of RAG American Coal Holdings, Inc. on July 30, 2004, Foundation Coal Holdings, Inc. 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 Holdings, Inc., 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 February 9, 2004 to December 31, 2004 have been derived from the audited consolidated financial statements of Foundation Coal Holdings, Inc. 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 February 9, 2004 to December 31, 2004, are included elsewhere in this Form 10-K.
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.
(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.
(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.
(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.
(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.
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 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 a subsidiary of Foundation Coal Holdings, Inc. 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 Holdings, Inc. as of December 31, 2004 and our consolidated results of operations and cash flows for the period from February 9 through December 31, 2004. 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 February 9, 2004 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 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 Holdings, Inc. 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 Holdings, Inc.
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 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 $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 preacquisition 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 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-precess 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 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)
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 SFAS No. 133 Accounting for Derivative Financial Instruments and Hedging Activities. 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.
On September 30, 2004, we entered into receive variable, pay fixed interest rate swap agreements on a notional amount of $85 million for three years. Under these swaps, we receive a variable rate of 3 month US dollar LIBOR and pay a fixed rate of 3.26%. For the five month operating period ended December 31, 2004, we recorded a gain on these swaps of $0.5 million. These interest rate swaps were designated as cash flow hedges of the variable interest payments due on $85 million of our variable rate debt through September 2007 under SFAS No 133 at December 31, 2004 upon completion of the effectiveness testing and related documentation.
Early debt extinguishment costs. In July 2004, the Predecessor incurred cash prepayment penalties of $21.7 million in connection with prepayment of substantially all remaining long-term indebtedness as required under the terms of the stock purchase agreement between Foundation Coal Corporation and RAG Coal International AG.
Interest Expense, Net
In addition to the abbreviated length of the period January 1 through July 29, 2004, the decline in net interest expense between the two Predecessor periods was a result of lower outstanding bank debt levels in 2004 due to repayment of two bank term loans in April of 2004. The interest expense for the Successor period reflects approximately five months interest expense on the $470.0 million senior secured term loan B and the $300.0 million senior unsecured 10-year 71/4% Senior Notes, $4.4 million of non-cash amortization of deferred financing costs and $4.4 million of surety bond and letter of credit fees. We incurred this indebtedness to purchase RAG American Coal Holding, Inc. and subsidiaries.
Income Tax Expense (Benefit)
In the period January 1 through July 29, 2004, a deferred income tax benefit was recognized at a blended federal and state income tax rate of 36%, and substantially all of the net operating losses carryforwards were realized as a result of the Transaction. The valuation allowance of $4.6 million previously established against the deferred tax assets associated with certain net operating loss carryforwards was released as a credit to income tax expense in the period January 1, 2004 through July 29, 2004. The remaining valuation allowance of $1.0 million was eliminated at the July 30, 2004 acquisition date. In the five month operating period ended December 31, 2004, income tax expense was accrued at a blended federal and state income tax rate of 48.4%. This effective income tax rate exceeds the federal statutory tax rate of 35% because of state deferred income tax expense associated with the financial reporting credit to amortization of coal supply agreements, partial utilization of regular tax net operating losses that were recognized as a deferred tax asset in purchase accounting and establishment of a valuation allowance against Alternative Minimum Tax credits. In the year ended December 31,
2003, the income from the litigation settlement allowed the recognition of percentage depletion benefits that reduced the blended federal and state income tax rate applied to income from continuing operations to approximately 0%.
Income from Discontinued Operations After Income Taxes
Income from discontinued operations consists of income from the RAG Colorado Business Unit, which primarily includes the results of operations of the Twentymile mine located in Routt County, Colorado. The increase in income from discontinued operations before income taxes in the period January 1 through July 29, 2004 was mainly due to the gain from sale of this business unit on April 15, 2004. Income from the discontinued operations, excluding the gain, was lower in the period January 1 through July 29, 2004 as compared to 2003 as a direct result of the sale timing which occurred three and one-half months into 2004.
Cumulative Effect of Accounting Change
Effective January 1, 2003, we adopted SFAS No. 143, which requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time obligations are incurred. Upon initial recognition of a liability, that cost is capitalized to the related long-lived asset and allocated to expense over the useful life of the asset. The asset retirement obligations are initially recorded at their present value and accreted to reflect the increase in the liability for the passage of time. Application of SFAS No. 143 resulted in a non-cash charge due to the cumulative effect of an accounting change as of January 1, 2003 of $3.6 million, net of tax. Prior to the adoption of SFAS No. 143, we utilized a cost accumulation method that accrued the expected mine closure expense over the coal reserves that each property was expected to mine.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002-Predecessor
Revenues
Coal sales revenues increased in 2003 as compared to 2002 as a result of both increases in the coal sales realization per ton and in the volumes of tonnage sold. Specific events contributing to the increases were as follows:
•Expansion of the Rockspring mine in West Virginia to annual production and sales of 2.9 million tons in 2003 compared with 2.2 million tons in 2002, resulting in additional coal sales of $19 million;
•Development of a second underground coal mine at the Kingston complex in West Virginia that increased coal sales revenue by $12 million in 2003; and
•Increased activity in purchasing and reselling coal. In 2003, sales of purchased coal increased by approximately $35 million compared with 2002.
Average coal sales revenues per ton increased at all but two of our mines as a result of improved general market conditions and scheduled price increases contained within multi-year contracts entered into in 2001.
In addition to the effects of changes in average coal sales realizations at each mining location, consolidated average coal sales realizations as reported above were impacted by the mix of coals produced in the East versus coal produced in the West. During 2003, 36.5% of our tons sold were from our eastern operations, as compared with 34.2% during 2002.
Other revenues increased in 2003 compared to 2002 by $5.4 million primarily due to a combination of higher royalty income ($1.1 million), higher synfuel fees ($1.2 million), a gain from settlement of asset retirement obligations at the Utah locations for less than the amount originally provided for under SFAS No. 143 ($1.4 million), and higher gains on disposal of surplus assets ($1.4 million).
Costs and Expenses
Cost of coal sales. During 2003, cost of coal sales increased mainly due to a combination of additional purchased coal expense attributable to increased volumes of purchased coal, increased health care costs, higher accruals for defined benefit retirement plans and increased mine operating costs mainly in Northern Appalachia, Central Appalachia and the Illinois Basin.
Selling, general and administrative expenses. In 2003, selling, general and administrative expenses were comparable in total to 2002. Lower legal fees in 2003 due to the settlement of the Phelps Dodge litigation were largely offset by higher charges for the long-term incentive plan, increased pension and medical expenses and increased sales commissions.
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.
Depreciation, depletion and amortization. The year-to-year increase in depreciation, depletion and amortization of $8.2 million was mainly at our Central Appalachia operations as a result of the expansion of the Rockspring and Kingston mines during 2002. An additional factor was the replacement of the Cumberland longwall in mid-2002.
Amortization of coal supply agreements. The year-to-year increase in amortization of coal supply agreements was mainly at our Powder River Basin operations where contract shipments increased in 2003 compared to 2002.
Asset impairment charges. Asset impairment charges in 2002 resulted from reducing our investment in a joint operating agreement relating to coalbed methane production in Wyoming to its estimated fair value. Lower than expected gas volumes and prices in 2002 led to a reassessment of the recoverability of this investment and the resulting impairment charge.
Segment Analysis
Powder River Basin-Income from operations increased in 2003 compared to 2002 primarily due to higher average realizations. Results in 2002 included a $7.0 million impairment charge to write down our investment in a coal-bed methane joint venture.
Northern Appalachia-Income from operations decreased in 2003 compared to 2002 due to a combination of lower production and higher cost of coal sales. Higher cost of coal sales resulted from a combination of reductions in coal inventories and increases in mine operating expenses, primarily in the areas of labor, health care, pensions, workers' compensation and outside services.
Central Appalachia-Income from operations increased in 2003 compared to 2002 due to higher production and sales from the Rockspring and Kingston mines, higher synfuel fees and higher average realizations, partly offset by increased expenses, mainly in the areas of purchased coal, trucking, repairs and maintenance and mine operating supplies.
Other Income
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.
Arbitration award. Plateau Mining Corporation ("PMC"), one of our subsidiaries, prevailed in an arbitration claim arising from a dispute over payments under an income tax sharing arrangement that existed between PMC and Cyprus Amax Minerals Company at the time of RAG American Coal Holding, Inc.'s acquisition of Cyprus Amax Coal Company.
Interest Expense, Net
Interest Expense. The decline in interest expense in 2003 was the result of lower average outstanding bank debt levels in 2003 as a result of scheduled principal payments. Variable rate interest expense is hedged by pay-fixed, receive-variable interest rate swaps. The fair value of these swaps is recognized on the balance sheet and changes in the fair value, net of income taxes, are recorded as a component of other comprehensive income. In 2002, the change in the fair value of the swaps resulted in a $22.4 million charge, net of income taxes, to other comprehensive income. In 2003, the corresponding gain, net of income taxes, was $8.4 million.
Interest Income. Interest income in 2002 includes $8.9 million in interest awarded on the PMC income tax arbitration award discussed above. The full amount of this interest was recorded when received.
Income Tax Expense (Benefit)
In 2003, the income tax benefit of percentage depletion in excess of the tax basis of coal reserves, which is treated as a permanent income tax difference, was $8.2 million higher than in 2002 as a result of two of our mines not having any tax basis in coal reserves in 2003. During 2002, income tax expense was increased by $1.9 million because of a deduction to financial reporting income before income taxes that was treated as investment in the stock of a subsidiary for income tax purposes. The remaining decrease was due to lower income from continuing operations before income taxes in 2003.
Income from Discontinued Operations After Income Taxes
Income from discontinued operations consists of income from the RAG Colorado Business Unit, which primarily includes the results of operations of the Twentymile mine located in Routt County, Colorado. During 2003, the volume of coal sales from the Twentymile mine increased by 13% compared with 2002. This increase in sales volume was the main reason for the increase in income from discontinued operations before income taxes between the two years.
Cumulative Effect of Accounting Change
Effective January 1, 2003, we adopted SFAS No. 143, which requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time obligations are incurred. Upon initial recognition of a liability, that cost is capitalized to the related long-lived asset and allocated to expense over the useful life of the asset. The asset retirement obligations are initially recorded at their present value and accreted to reflect the increase in the liability for the passage of time. Application of SFAS No. 143 resulted in a non-cash charge due to the cumulative effect of an accounting change as of January 1, 2003 of $3.6 million, net of tax. Prior to the adoption of SFAS No. 143, we utilized a cost accumulation method that accrued the expected mine closure expense over the coal reserves that each property was expected to mine.
Liquidity and Capital Resources
Our primary sources of cash have been sales of our coal production and purchased coal to customers, plus cash from sales of non-core assets. During the period from 2002 through 2003, we also generated significant cash from a litigation settlement ($43.5 million in 2003) and an arbitration award ($40.0 million in 2002).
Our primary uses of cash have been our cash costs of coal production, the cash cost of purchased coal, capital expenditures, interest costs, cash payments for employee benefit obligations such as defined benefit pensions and retiree health care benefits, cash outlays related to post mining asset retirement obligations and support of working capital requirements such as coal inventories and trade accounts receivable. Our ability to service our debt (principal and interest) and acquire new productive assets for use in our operations has been and will be dependent upon our ability to generate cash from our operations. We normally fund all of our capital expenditure requirements with cash generated from operations. During the past three years, we have engaged in minimal financing of assets such as through operating leases.
In the Predecessor periods, cash balances in excess of our day-to-day operating requirements were placed on deposit with RAG where cash balances could be aggregated to earn better investment returns. This cash on deposit was available to us on a one day turn-around. Increases in the cash on deposit with RAG have been classified under financing activities as uses of cash in the consolidated cash flow statements. Decreases in cash on deposit with RAG have been classified under financing activities as cash provided. As of December 31, 2003 and 2002 we had access to cash balances in excess of those amounts pledged to banks of $240.7 million and $88.3 million, respectively.
The following is a summary of cash provided by or used in each of the indicated categories of activities during the year ended December 31, 2003, the period January 1 through July 29, 2004 (both
of these periods labeled as Predecessor) and the five month operating period ended December 31, 2004 (this period labeled as Successor):
(1)Represent the (increase)/ decrease in the balance of cash on deposit with RAG.
(2)The borrowing in the period January 1 through July 29, 2004 represented a short-term advance from RAG that was repaid from a portion of $904.9 million that Foundation Coal paid to RAG to acquire RAG American Coal Holdings, Inc and subsidiaries. Cash provided by operating activities from continuing operations in the period January 1 through July 29, 2004 decreased as compared to 2003 due to reduced production and sales at the Cumberland mine as previously discussed along with significant payments of accrued interest associated with repayment of the Predecessor's long-term debt. The 2004 period was also approximately five months shorter in duration. The cash provided by operating activities in 2003 included $43.5 million from a cash litigation settlement previously discussed. Cash provided by operating activities for the five month operating period ended December 31, 2004 increased in comparison to the January 1 through July 29, 2004 period primarily due to improved operating performance, lower interest payments and the timing of accounts receivable collections.
Cash used in investing activities for continuing operations decreased in the period January 1 through July 29, 2004 from the year ended December 31, 2003 mainly due to lower capital expenditures, attributable to the abbreviated 2004 reporting period. Capital expenditures during the five month operating period ended December 31, 2004 were approximately 12% less on a annualized basis than capital expenditures during the January 1 through July 29, 2004 period. This reduction is due to lower capital expenditures in the Powder River Basin, Northern Appalachia and Central Appalachia partly offset by increased capital expenditures at the Wabash Mine during the five month operating period.
Cash used in financing activities primarily represents repayment of all long-term debt of the Predecessor including cash prepayment penalties coupled with settlement of the interest rate swaps. These repayments utilized the proceeds from the sale of the Colorado Business Unit, cash previously reported as cash on deposit with Predecessor, cash pledged and $306.0 million of cash advanced by RAG that we repaid from a portion of the cash acquisition price that Foundation Coal paid to RAG.
The sale of the RAG Colorado Business Unit to a third party closed on April 15, 2004. The cash proceeds from the sale, prior to final purchase price adjustments, were $182.7 million. Purchase price adjustments totaled $0.5 million. With this receipt, we realized a pre-tax gain on sale of the discontinued operation of $25.7 million. The proceeds were deposited into an escrow account at DZ Bank. In addition, $221.4 million of our cash on deposit with RAG was also deposited into this escrow account. On April 27, 2004, the escrow account balance of $404.2 million, including interest earned on the account of $0.1 million, was used to: (a) repay the Tranche A Notes due to DZ Bank and Dresdner in the combined amount of $358.0 million; (b) pay accrued interest on these notes in the amount of $1.5 million; and (c) settle the pay-fixed, receive-variable interest rate swaps for a payment of $44.7 million as mentioned above.
The remaining Predecessor long-term debt, accrued interest and related prepayment penalties totaling approximately $305.9 million were repaid on July 28, 2004 utilizing $306.0 million of cash advanced by RAG. This advance was repaid using a portion of the cash acquisition price that Foundation Coal Corporation paid to RAG.
The cash acquisition price including transaction costs of $986.9 million paid by us for RAG American Coal Holding, Inc. and subsidiaries was funded by $830.0 million of Successor long-term debt, consisting of $470.0 million of senior secured term Loan B, $300.0 million of 71/4% Senior Notes, and $60.0 million of drawings under the $350.0 million revolving credit facility, and $196.0 million of cash equity contributed by the shareholders. The $60 million drawing under the revolving credit facility was fully repaid on the first business day after the acquisition utilizing cash of the acquired subsidiaries. The $28.6 million of costs associated with arranging the long term debt used to fund the acquisition, is included in the cash outflows for "Financing Activities-Other."
On December 8, 2004, Foundation Coal Holdings, Inc sold 23.6 million common shares in an IPO resulting in proceeds net of underwriting discount of $487.0 million. Cash expenses of the IPO in the amount of $5.8 million are included in the cash outlays for "Financing Activities-Other" in the above table. On December 21, 2004, an additional 0.5 million common shares were issued pursuant to the underwriters' exercise of a portion of their overallotment option resulting in proceeds net of underwriting discount of $10.5 million. Approximately, $47.1 million of IPO proceeds along with cash on hand were used to prepay $85 million of the senior secured term loan in December 2004.
On December 8, 2004, Foundation Coal Holdings, Inc. declared dividends on common stock totaling $439.0 million to the pre-IPO shareholders, including members of Foundation Coal Holdings, Inc.'s senior management. The members of senior management elected to take their portion of the dividend, totaling $5.1 million, in shares of common stock. Dividends of $1.0 million were paid in December 2004. The remaining $432.9 million of cash dividends were paid in January 2005. The stock dividend was declared on December 8, 2004 and was distributed to senior management on January 4, 2005. The Company paid an additional dividend of $11.1 million to the pre-IPO shareholders from the proceeds of the underwriters' exercise of a portion of the overallotment option plus cash on hand. This dividend was also declared on December 8, 2004 and was paid on January 4, 2005.
The portion of the underwriters' overallotment option that was not exercised, consisting of 3.0 million common shares was distributed to the pre-IPO shareholders as a stock dividend in January 2005.
The following is a summary of cash provided by or used of the Predecessor in each of the indicated categories of activities during the past two years:
(1)Represents the (increase)/decrease in the balance of cash on deposit with RAG. Cash provided by operating activities from continuing operations in 2003 increased as compared to 2002 mainly due to reductions in trade accounts receivable, reductions in coal inventories, collection of a royalty receivable, monetization of emissions allowances and higher cash earnings, partly offset by an increase in the level of contribution to our defined benefit retirement plans. Cash provided by operating activities from continuing operations in 2003 included a $43.5 million cash litigation settlement described above. Cash provided by operating activities from continuing operations in 2002 included the $40.0 million arbitration award described above.
Cash used in investing activities for continuing operations decreased in 2003 from 2002 levels mainly due to lower capital expenditures. Capital expenditures in 2002 included the replacement of the Cumberland longwall at a cost of $36.1 million.
Cash used in financing activities represented scheduled principal payments on the Predecessors' bank term loans and the capital lease. Scheduled principal repayment in 2003 and 2002 were comparable.
Our primary source of liquidity will continue to be cash from sales of our coal production and purchased coal to customers. We have availability under our revolving credit facility, subject to certain conditions.
As of December 31, 2004, we have outstanding $685.0 million in aggregate indebtedness, with an additional $148.2 million of available borrowings under our revolving credit facility (after giving effect to $201.8 million of letters of credit outstanding as of December 31, 2004). Our liquidity requirements will be significant, primarily due to debt service requirements. Of the $26.7 million of interest expense for the five month operating period ended December 31, 2004, approximately $21.6 million has or will be paid in cash.
Based on our current levels of operations, we believe that remaining cash on hand, cash flow from operations and available borrowings under the revolving credit portion of our Senior Credit Facilities will enable us to meet our working capital, capital expenditure, debt service and other funding requirements for at least the next twelve months.
Our Senior Credit Facilities consist of a revolving credit facility and a term loan facility. Our revolving credit facility provides for loans in a total principal amount of up to $350.0 million, less outstanding letters of credit, which will be available for general corporate purposes, subject to certain
conditions, and will mature in five years. The term loan facility consists of a $470.0 million term loan facility with a maturity of seven years.
Borrowings under our Senior Credit Facilities bear interest at a floating base rate plus an applicable margin. The initial applicable margin for borrowings under the revolving credit facility is 1.50% with respect to base rate borrowings and 2.50% with respect to LIBOR borrowings. The initial applicable margin for borrowings under the term loan facility is 1.00% with respect to base rate borrowings and 2.00% with respect to LIBOR borrowings. The applicable margin for borrowings under the revolving credit facility and the term loan facility may be reduced subject to our attaining certain leverage ratios.
In addition to paying interest on outstanding principal under the Senior Credit Facilities, we will be required to pay a commitment fee to the lenders under the revolving credit facility in respect of the unutilized commitments at a rate equal to 0.50% per annum. We will also pay customary letter of credit fees.
The Senior Credit Facilities require us to prepay outstanding term loans, subject to certain exceptions, in certain situations. Any mandatory prepayments other than from excess cash flow would be applied to the remaining installments of the term loan facility on a pro rata basis. Mandatory prepayments from excess cash flow would be applied to the term loan facility at our direction. If pre-paid, there would be a charge for unamortized deferred issuance costs.
We are required to repay installments on the loans in quarterly principal amounts of 0.25% of their funded total principal amount for the first six years and nine months, with the remaining amount payable on the date that is seven years from the date of the closing of the senior secured credit facility. In prepaying $85 million in December 2004, we eliminated quarterly principal installments for the life of the loan.
Principal amounts outstanding under the revolving credit facility will be due and payable in full at maturity, five years from the date of the closing of the senior secured credit facility.
The Senior Credit Facilities contain a number of covenants that, among other things, restrict, subject to certain exceptions, the ability of certain of our subsidiaries, and the ability of each guarantor under the credit facility to incur additional indebtedness or issue preferred stock, repay other indebtedness (including the 71/4% Senior Notes), pay dividends and distributions or repurchase our capital stock, make investments, loans or advances, make certain acquisitions, engage in mergers or consolidations, enter into sale and leaseback transactions and enter into hedging agreements.
We have amended our credit agreement to permit the payment of certain dividends. Our credit agreement now permits the payment to us by our subsidiary, FC2 Corp., for use by us to pay dividends on our common stock after the IPO in an amount not to exceed $12.5 million in any consecutive four quarter period, which amount may increase to $30.0 million and $45.0 million upon reaching leverage ratios, as set forth in the credit agreement, of 3.0 to 1.0 and 2.0 to 1.0, respectively. Accordingly, we expect that the terms of our credit agreement will permit us to pay dividends at a quarterly dividend rate that will be between $.04 and $.05 per share for the foreseeable future.
In addition, the Senior Credit Facilities require FC2 Corp. to maintain the following financial covenants: a maximum total leverage ratio, a minimum interest coverage ratio and a maximum capital expenditures limitation.
The indenture governing our outstanding 71/4% Senior Notes limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness, pay dividends on or make other distributions or repurchase our capital stock, make certain investments, limit dividends or other payments by its restricted subsidiaries to us, and sell certain assets or merge with or into other companies. Our indenture permits the payment to FC2 Corp. by Foundation Coal Corporation of $25.0 million, plus an amount up to 5% per calendar year of the net proceeds received by Foundation Coal Corporation from the IPO. Foundation Coal Corporation will also have the ability to pay dividends over time using a formula based on 50% of consolidated net income, as set forth in the indenture, if it meets certain conditions, including having greater than a 2.0 to 1.0 fixed charge coverage ratio.
Subject to certain exceptions, the indenture governing our outstanding 71/4% Senior Notes permit us and our restricted subsidiaries to incur additional indebtedness, including secured indebtedness.
As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets, including LBA bids, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements, which may be binding or nonbinding, that are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreements if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both.
Covenant Compliance
We believe that our Senior Credit Facilities and the indenture governing our outstanding 71/4% Senior Notes are material agreements, that the covenants are material terms of these agreements and that information about the covenants is material to an investor's understanding of our financial condition and liquidity. The breach of covenants in the Senior Credit Facilities that are tied to ratios based on Adjusted EBITDA, as defined below, could result in a default under the Senior Credit Facilities and the lenders could elect to declare all amounts borrowed due and payable. Any such acceleration would also result in a default under our indenture. Additionally, under the Senior Credit Facilities and indenture, our ability to engage in activities such as incurring additional indebtedness, making investments and paying dividends is also tied to ratios based on Adjusted EBITDA.
Covenant levels and pro forma ratios for the four quarters ended December 31, 2004 are as follows:
(1)The Senior Credit Facilities require us to maintain an Adjusted EBITDA to cash interest ratio starting at a minimum of 1.75x and a total debt to Adjusted EBITDA ratio starting at a maximum of 6.0x in each case for the most recent four quarter period. Failure to satisfy these ratio requirements would constitute a default under the Senior Credit Facilities. If lenders under the
Senior Credit Facilities failed to waive any such default, repayment obligations under the Senior Credit Facilities could be accelerated, which would also constitute a default under the indenture.
(2)Our ability to incur additional debt and make certain restricted payments under our indenture, subject to specified exceptions, is tied to an Adjusted EBITDA to fixed charge ratio of at least 2.0 to 1. Adjusted EBITDA is defined as EBITDA further adjusted to exclude non-recurring items, non-cash items and other adjustments permitted in calculating covenant compliance under the indenture, and the Senior Credit Facilities, as shown in the table below. We believe that the inclusion of supplementary adjustments to EBITDA applied in presenting Adjusted EBITDA is appropriate to provide additional information to investors to demonstrate compliance with financing covenants.
(1)EBITDA is calculated in the table below:
(2)We are required to adjust EBITDA, as defined above, for the following non-cash charges (income):
(a)Includes $48.9 million of expense resulting in the period January 1 to July 29, 2004 from loss on termination of hedge accounting for interest rate swaps less $5.8 million mark-to-market adjustment. Under the terms of the stock purchase agreement, we did not assume any existing interest rate swaps. For the five month operating period ended December 31, 2004 includes the mark-to-market gain on interest rate swaps not yet designated as cash flow hedges.
(b)Represents incremental cost of sales recorded in the period arising from the preliminary estimate of manufacturing profit added to inventory in purchase accounting.
(c)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 or 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 acquisiton date would have been included in cost of coal sales.
(d)For 2002, this amount represents reclamation expense recorded prior to the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143").
(e)Represents the portion of pension, other post retirement and black lung expense resulting from the amortization of unrecognized actuarial losses, prior service costs and transition obligations. Unrecognized actuarial losses, prior service costs and transition obligations were eliminated when the pension, other post retirement and black lung obligations were fair valued in purchase accounting.
(3)We are also required to adjust EBITDA, as defined above, for the following unusual (income) expense:
(a)Represents arbitration awards, litigation and contract settlements, net of related legal and tax fees.
(b)Represents the cost of a one-time bonus awarded to certain employees in connection with the sale of RAG American Coal holding, Inc.
(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 $2.0 million from a sponsor monitoring fee and $1.8 million from a bonus related to the IPO in the period July 30 to December 31, 2004. In addition, other items that are permitted adjustments in calculating covenant compliance under the indenture governing the 71/4% Senior Notes and the Senior Credit Facilities, including directors' fees, reimbursements of certain union dues by the Seller, black lung settlement charges and costs related to moving our human resources organization from Colorado to Maryland, incurred primarily in the years ended December 31, 2002 and 2003 and in the period January 1 through July 29, 2004, net to an immaterial amount.
(4)Represents the adjustment required for the estimated impact 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.
(5)We are also required to make adjustments to EBITDA for items such as incremental insurance costs and franchise taxes not included in income tax expense.
Pro-forma cash interest for the four quarters ended December 31, 2004 is calculated as follows:
In future periods, adjustments to EBITDA that could be used to calculate compliance with the debt covenants are: (a) accretion on asset retirement obligations, (b) credits from deferral of overburden removal costs, (c) any non-cash expenses or charges arising as a result of the application of purchase accounting in acquisitions, (d) business optimization expenses or other restructuring charges, (e) non-cash impairment charges resulting from the application of SFAS No. 142 or SFAS No. 144, (f) amortization of intangibles pursuant to SFAS No. 141, and (g) any long term incentive plan accruals or any non-cash compensation expense realized from grants of stock appreciation or similar rights, stock options or other rights to officers, directors and employees.
In future periods, cash interest is expected to be calculated by adding back amortization of deferred debt issuance costs and deducting cash interest income from the interest expense reported in the Statement of Operations.
Contractual Obligations
The following is a summary of our significant future contractual obligations by year as of December 31, 2004:
We expect to invest in the range of $150.0 to $160.0 million in capital expenditures during calendar year 2005 of which approximately $100.0 million is to maintain production and replace mining equipment. The additional $50.0 to $60.0 million is expected to be directed toward selective expansions of production and improvements in productivity. Approximately $34 million of expected 2005 capital expenditures are included in unconditional purchase commitments shown above. The remaining 2005 unconditional purchase commitments and $3 million of the 2006-2007 unconditional purchase commitments relate to forward contracts to purchase diesel fuel and explosives in normal quantities for use at our surface mines. The remaining unconditional purchase commitments, totaling $4.4 million in 2006-2007 and $17.2 million in 2008-2009, relate to a contractual commitment to purchase underground mining equipment. We expect to contribute approximately $6.0 million to our defined benefit retirement plans and to pay approximately $21.0 million of retiree health care benefits in calendar year
2005. We also expect to incur approximately $9.0 million per year for surety bond premiums and letters of credit fees. We believe that cash balances plus cash generated by operations will be sufficient to meet these obligations plus fund requirements for working capital and capital expenditures without incurring additional borrowings.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets. However, the underlying obligations that they secure, such as asset retirement obligations, self-insured workers' compensation liabilities, royalty obligations and certain retiree medical obligations, are reflected in our consolidated balance sheets.
We are required to provide financial assurance in order to perform the post-mining reclamation required by our mining permits, pay our federal production royalties, pay workers' compensation claims under self-insured workers' compensation laws in the various states, pay federal black lung benefits, pay retiree health care benefits to certain retired UMWA employees and perform certain other obligations.
In order to provide the required financial assurance, we generally use surety bonds for post-mining reclamation and royalty payment obligations and bank letters of credit for self-insured workers' compensation obligations and UMWA retiree health care obligations. Federal black lung benefits are paid from a dedicated trust fund that has sufficient assets to fund these obligations for the next several years. Bank letters of credit are also used to collateralize a portion of the surety bonds.
We had outstanding surety bonds with a total face amount of $267.2 million as of December 31, 2004, of which $244.1 million secured reclamation obligations, $10.7 million secured coal lease obligations and $10.4 million secured self-insured workers' compensation obligations. In addition, we had $201.8 million of letters of credit in place for the following purposes: $36.5 million for workers' compensation, including collateral for workers' compensation bonds; $24.0 million for UMWA retiree health care obligations; $130.6 million for collateral for reclamation surety bonds, $6.0 million for minimum royalty payment obligations for a closed mine in Utah; and $4.7 million for other miscellaneous obligations. Recently, surety bond costs have increased, while the market terms under which surety bonds can be obtained have generally become less favorable to all mining companies. In the event that additional surety bonds become unavailable, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral.
Certain Trends and Uncertainties
Our revenues depend on the price at which we are able to sell our coal. The current pricing environment for United States coal is strong. Any decrease in coal prices due to, among other reasons, the supply of domestic and foreign coal, the demand for electricity and the price and availability of alternative fuels for electricity generation could adversely affect our revenues and our ability to generate cash flows. In addition, our results of operations depend on the cost of coal production. We are experiencing increased operating costs for fuel and explosives, steel products, health care, wages, salaries, contract labor, and increased interest expenses for surety bonds and letters of credit. In addition, historically low interest rates have had a negative impact on expenses related to our actuarially determined employee-related liabilities.
Critical Accounting Estimates
Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from the estimates used. Note 3 to the Consolidated Financial Statements provide a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:
Asset Retirement Obligations
Our asset retirement obligations arise from the federal SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Reclamation activities that are performed outside of the normal mining process are accounted for as asset retirement obligations in accordance with the provisions of SFAS No. 143. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based on historical or third-party costs, both of which are stated at fair value. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of SFAS No. 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed below:
•Discount rate-SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives adjusted for our credit standing.
•Third party margin-SFAS No. 143 requires the measurement of an obligation to be based on the amount a third party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of performing these activities with internal resources. This margin was estimated based upon discussion with contractors that perform reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is settled.
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revision to cost estimates and productivity assumptions, in each case to reflect current experience.
At December 31, 2004, after applying purchase accounting, we had recorded asset retirement obligation liabilities of $104.6 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, we estimate that the aggregate undiscounted cost of final mine closure is approximately $209.8 million at December 31, 2004 payable through 2032.
Employee Benefit Plans
We have two non-contributory defined benefit retirement plans covering certain of our salaried and non-union hourly employees. Benefits are based on either the employee's compensation prior to retirement or stated amounts for each year of service with us. Funding of these plans is in accordance with the requirements of the ERISA, which can be deducted for federal income tax purposes. For the years ended December 31, 2004, 2003 and 2002, we contributed $18.0 million, $20.0 million and $9.0 million, respectively, into the plans. We account for our defined benefit retirement plans in accordance with SFAS No. 87, Employer's Accounting for Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the year ended December 31, 2003, we recorded pension expense of $11.7 million. For the period January 1 through July 29, 2004, we recorded pension expense of $7.1 million. In the Successor financial statements for the five month operating period ended December 31, 2004, after applying purchase accounting, we recorded pension expense of approximately $2.6 million.
The calculation of the net periodic benefits costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be "critical accounting estimates." These assumptions are used by our independent actuaries to make the underlying calculations. Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.
•The expected long-term rate of return on plan assets is an assumption of the rate of return on plan assets reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan's investment targets are 55% equity, 22% fixed income, 5% private equity, 8% absolute return funds and 10% real estate mutual funds. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine pension expense was 8.5% for the period January 1 through July 29, 2004 and for the five month operating period ended December 31, 2004, and 9.0% for each of the years ended December 31, 2003, and 2002. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into the future.
•The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic pension cost. In estimating that rate, SFAS No. 87 requires rates of return on high quality, fixed income investments. The discount rate used to determine pension expense was 6.25% for the period January 1 through July 29, 2004 and for the five month operating period ended December 31, 2004, and 7.00%, and 7.25% for the years ended December 31, 2003, and 2002, respectively. The discount rate was reduced to 6.00% at the September 30, 2004 measurement date. The differences resulting from actual versus assumed discount rates and returns on plan assets are amortized into pension expense over the remaining average service life of the active plan participants. A one half percentage-point increase in the discount rate would decrease the net periodic pension cost for the five month operating period ended December 31, 2004 by approximately $0.2 million and decrease the projected benefit obligation at December 31, 2004 by approximately $10.3 million. The corresponding effects of a one half of one percentage-point decrease in the discount rate would be an approximately $0.2 million increase in the net periodic pension cost and an approximately $11.0 million increase in the projected benefit obligation.
We also currently provide certain postretirement medical and life insurance coverage for eligible employees. These obligations are unfunded. Covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependants. Postretirement medical and life plans for salaried employees and non-represented hourly employees are contributory, with retiree contributions adjusted annually, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for members of the UMWA is not contributory. We account for our other postretirement benefits in accordance with SFAS No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the year ended December 31, 2003, we recorded postretirement benefit expense of $41.7 million. For the period January 1 through July 29, 2004, we recorded postretirement benefit expense of $25.5 million. In the Successor financial statements for the five month operating period ended December 31, 2004, after applying purchase accounting and incorporating Medicare Part D, we recorded postretirement benefit expense of approximately $14.4 million.
Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. The differences resulting from actual experience versus actuarial assumptions are deferred as unrecognized actuarial gains or losses and amortized into expense in future periods. These assumptions include the discount rate and the future medical cost trend rate.
•The discount rate assumption reflects the rates available on high quality fixed income debt instruments at July 30, 2004 and September 30, 2004 and 2003 and is calculated in the same manner as discussed above for the defined benefit retirement plans. The discount rate used to calculate the postretirement benefit expense was 6.25% for the period January 1 through July 29, 2004 and for the five-month operating period ended December 31, 2004, and 7.00% and 7.25% for the years ended December 31, 2003, and 2002, respectively. The discount rate was reduced to 6.00% at the September 30, 2004 measurement date. A one half percentage-point increase in the discount rate would decrease the postretirement benefit expense for the five month operating period ended December 31, 2004 by approximately $0.4 million and decrease the accumulated postretirement benefit obligation at December 31, 2004 by approximately $35.8 million. The corresponding effects of a one-half of one percentage-point decrease in the discount rate would be an approximately $0.5 million increase in the postretirement benefit expense and an approximately $38.6 million increase in the accumulated postretirement benefit obligation.
•The future health care cost trend rate represents the rate at which health care costs are expected to increase over the life of the plan. The health care cost trend rate assumptions are determined primarily based upon our historical rate of change in retiree health care costs. We have implemented many effective retiree health care cost containment measures that have resulted in actual increases in our retiree health care costs to fall far below the double-digit annual increases experienced by many companies and cited in most external studies. The postretirement expense in the five-month operating period ended December 31, 2004 was based on an assumed heath care inflationary rate of 8.00% in the five month operating period decreasing to 5.00% in 2010, which represents the ultimate health care cost trend rate for the remainder of the plan life. The postretirement expense in 2003 and the period January 1, 2004 through July 29, 2004 was based on an assumed health care inflationary rate of 6.00% in 2003 decreasing to 4.75% in 2008. The comparable actuarial assumption in 2002 was an initial rate of 5.75% in 2002, decreasing to 4.75% in 2005. A one-percentage point increase in the 5.00% assumed ultimate health care cost trend rate would increase the service and interest cost components of the postretirement benefit expense for the five-month operating period ended December 31, 2004 by $2.4 million and increase the accumulated postretirement benefit obligation at December 31, 2004 by $70.2 million. A one-percentage point decrease in the 5.00%
assumed ultimate health care cost trend rate would decrease the service and interest cost components of the postretirement benefit expense for the five month operating period ended December 31, 2004 by $1.9 million and decrease the accumulated postretirement benefit obligation at December 31, 2004 by $57.1 million.
Income Taxes
We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes, which requires the recognition of deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors including the expected level of future taxable income and available tax planning strategies. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, we may record a change to the valuation allowance through income tax expense in the period such determination is made.
Mineral Rights
There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves. Many of these uncertainties are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff and independent third party consultants. Some of the factors and assumptions that impact economically recoverable reserve estimates include:
•geological and mining conditions;
•historical production from similar areas with similar conditions;
•the assumed effects of regulations and taxes by governmental agencies;
•assumptions governing future prices;
•future operating, development and reclamation costs; and
•mining technology improvements.
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows may vary substantially. Actual production, revenue and expenditures with respect to reserves may materially vary from estimates.
Recent Accounting Pronouncements
The FASB issued Emerging Issues Task Force Issue No. 04-2, Whether Mineral Rights Are Tangible or Intangible Assets ("EITF 04-2"). In this issue, the Task Force reached the consensus that mineral rights are tangible assets. This consensus differed from the requirements of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets which characterize mineral rights as intangible assets. As a result, the FASB amended SFAS No. 141 and SFAS No. 142 to eliminate this inconsistency. The Company accounts for leased coal mineral interests as tangible assets in owned and leased mineral rights, net of accumulated depletion as presented on the consolidated balance sheet, and in accordance with EITF 04-2.
In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4 ("SFAS No. 151"). The Statement amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). The provisions of this statement are effective for fiscal years beginning after June 15, 2005. We do not expect the adoption of this statement to have a material impact on our financial statements.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment ("SFAS No. 123R"), which replaces SFAS No. 123, and supersedes APB No. 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair value at the grant date beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. SFAS No. 123R generally requires companies to measure the cost of employee services received in exchange for an award of equity instruments (such as stock options and restricted stock) based on the grant-date fair value of the award, and to recognize that cost over the period during which the employee is required to provide service (usually the vesting period of the award). Under SFAS No. 123R, we must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at date of adoption. The transition provisions of SFAS No. 123R allow adoption on a "modified prospective" basis or a "modified retrospective" basis. The "modified prospective" method requires compensation expense be recorded for all share-based payments granted after the effective date and for the unvested portion of stock awards granted prior to the effective date at the beginning of the first quarter of adoption of SFAS 123R. The "modified retrospective" method requires compensation expense be recorded in the manner discussed above and permits restatement for all periods for which SFAS No. 123 was effective. The impact of adopting SFAS No. 123R can not be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had the Company adopted SFAS No. 123R during the prior period, the impact of that standard would have approximated the impact of SFAS No. 123 as described in Note 3 to the consolidated financial statements under "Stock-Based Compensation." When SFAS No. 123R is adopted, we may elect to change the valuation method or assumptions and such changes could have a material impact on the amount of stock-based compensation the Company records.
In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions ("SFAS No. 153"). The statement amends the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged and further eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. Provisions of this statement are effective for fiscal periods beginning after June 15, 2005. We do not expect the adoption of this statement to have a material impact on its financial statements.
In March 2005, the Emerging Issues Task Force reached consensus on Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry ("EITF No. 04-6") concluding that post-production stripping costs are a component of mineral inventory costs subject to the provisions of the American Institute of Certified Public Accountants Accounting Research Bulletin No. 43, Restatement and Revision of Accounting Research Bulletins, Chapter 4, Inventory Pricing, ("ARB No. 43"). Based upon this consensus, post production stripping costs are considered costs of the extracted minerals under a full absorption costing system and are recognized as a component of inventory to be recognized in costs of sales in the same period as the revenue from the sale of the inventory. In addition, capitalization of such costs would be appropriate only to the extent inventory exists at the end of a reporting period. The guidance in this consensus will be effective for financial statements issued for fiscal years beginning after December 15, 2005, with early adoption permitted. We are currently evaluating this consensus and have not determined its impact to the consolidated financial statements.
RISK FACTORS
Risks Relating to Our Business
A substantial or extended decline in coal prices could reduce our revenues and the value of our coal reserves.
The prices we charge for coal depend upon factors beyond our control, including:
•the supply of, and demand for, domestic and foreign coal;
•the demand for electricity;
•domestic and foreign demand for steel and the continued financial viability of the domestic and/or foreign steel industry;
•the proximity to, capacity of, and cost of transportation facilities;
•domestic and foreign governmental regulations and taxes;
•air emission and other regulatory standards for coal-fired power plants;
•regulatory, administrative and court decisions that may impact our business;
•costs of transportation or our coal relative to our competitors;
•the price and availability of alternative fuels, including the effects of technological developments; and
•the effect of worldwide energy conservation measures.
Our results of operations are dependent upon the prices we charge for our coal as well as our ability to improve productivity and control costs. Any decreased demand would cause spot prices to decline and require us to increase productivity and decrease costs in order to maintain our margins. If we are not able to maintain our margins, our operating results could be adversely affected. Therefore, price declines may adversely affect operating results for future periods and our ability to generate cash flows necessary to improve productivity and invest in operations.
Any adverse change in coal consumption patterns by North American electric power generators or steel producers could result in weaker demand and possibly lower prices for our production, which would reduce our revenues.
During 2004, sales of steam coal accounted for approximately 97% of our total coal sales volume and 92% of our coal sales revenue, and the vast majority of our sales of steam coal were to United States electric power generators. Domestic electric power generation accounted for approximately 92% of all United States coal consumption in 2004, according to the EIA. The amount of coal consumed for United States electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power, technological developments and environmental and other governmental regulations. Many of the recently constructed electric power sources have been gas-fired, by virtue of lower construction costs and reduced environmental risks. Gas-based generation from existing and newly constructed gas-based facilities has the potential to displace coal-based generation, particularly from older, less efficient coal generators. In addition, the increasingly stringent requirements of the Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired power plants. Any reduction in coal demand from the electric generation and steel sectors could create short-term market imbalances, leading to lower demand for, and price of, our products, thereby reducing our revenue.
Our profitability may decline due to unanticipated mine operating conditions and other factors that are not within our control.
Our mining operations are influenced by changing conditions that can affect production levels and costs at particular mines for varying lengths of time and as a result can diminish our profitability. Weather conditions, equipment availability, replacement or repair, prices for fuel, steel, explosives and other supplies, fires, variations in thickness of the seam of coal, amounts of overburden, partings, rock and other natural materials, accidental mine water discharges and other geological conditions have had, and can be expected in the future to have, a significant impact on our operating results. For example, in September and October 2004, our Emerald mine in Greene County, Pennsylvania experienced adverse geological conditions, consisting of sandstone intrusions from the roof into the coal seam in the panel being mined, which slowed mining by forcing the machinery to cut harder material and causing less stable roof conditions. These conditions prevented normal longwall production and thus reduced the quantity of coal available for shipment pursuant to this mine's contractual obligations. Emerald declared a force majeure with its customers in September. Emerald personnel completed production on the longwall panel that experienced the geological problems. The longwall was moved to the next panel and normal production resumed in early November. It is possible that one or more customers may dispute this claim of force majeure and challenge any tonnage shortfall as not being excused. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could be material.
Decreases in our profitability as a result of the factors described above could materially adversely impact our quarterly or annual results. These risks may not be covered by our insurance policies.
MSHA may order certain of our mines to be temporarily closed, which would adversely affect our ability to meet our customers' demands.
MSHA may order certain of our mines to be temporarily closed. For example, in January 2004, MSHA determined that, based on a revised interpretation of existing federal regulations, a ventilation plan previously approved by MSHA for a longwall panel at our Cumberland mine in Pennsylvania 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 at the Cumberland mine. The shutdown of the Cumberland longwall resulted in lost production of an estimated 1.4 million tons and reduced EBITDA for the first quarter of 2004 by an estimated $20.2 million and the second quarter of 2004 by an estimated $10.9 million. The mine is currently producing at pre-shutdown run-rates. Such a closure or other interruption could occur in the future. In addition, our customers may challenge our issuance of force majeure notices in connection with such closures. If these challenges are successful, we could be obligated to make up lost shipments, to reimburse customers for the additional costs to purchase replacement coal, or, in some cases, to terminate certain sales contracts.
Our profitability may be adversely affected by the status of our long-term coal supply contracts, and changes in purchasing patterns in the coal industry may make it difficult for us to extend existing contracts or enter into long-term supply contracts, which could adversely affect the capability and profitability of our operations.
We sell a significant portion of our coal under long-term coal supply agreements, which we define as contracts with a term greater than 12 months. The prices for coal shipped under these contracts are set, although sometimes subject to adjustment, and thus may be below the current market price for similar-type coal at any given time, depending on the time frame of contract execution or initiation. As a consequence of the substantial volume of our sales that are subject to these long-term agreements,
we have less coal available with which to capitalize on higher coal prices if and when they arise. In addition, in some cases, our ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to exercise options to purchase higher volumes allowable under some contracts.
When our current contracts with customers expire or are otherwise renegotiated, our customers may decide not to extend or enter into new long-term contracts or, in the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms. For additional information relating to these contracts, see "Business-Long Term Coal Supply Agreements."
As electric utilities adjust to the acid rain regulations of the Clean Air Act, the utility mercury reductions rule, the Clean Air Interstate Rule, and the possible deregulation of their industry, they could become increasingly less willing to enter into long-term coal supply contracts and instead may purchase higher percentages of coal under short-term supply contracts. To the extent the industry shifts away from long-term supply contracts, it could adversely affect us and the level of our revenues. For example, fewer electric utilities will have a contractual obligation to purchase coal from us, thereby increasing the risk that we will not have a market for our production. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased or less predictable revenues.
Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions or may result in economic penalties upon the failure to meet specifications.
Price adjustment, "price reopener" and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Some of our coal supply contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price, sometimes between a pre-set "floor" and "ceiling". In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.
Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers for the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or, in the extreme, termination of the contracts.
Consequently, due to the risks mentioned above with respect to long-term contracts, we may not achieve the revenue or profit we expect to achieve from these sales commitments. In addition, we may not be able to successfully convert these sales commitments into long-term contracts.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
We derived 56% of our total coal revenues from sales to our 10 largest customers for the year ended December 31, 2004, with no single customer accounting for more than 9% of our coal revenues for that year. At December 31, 2004, on a combined pro forma basis, we had 24 coal supply agreements with those 10 customers that expire at various times from 2005 to 2020. Negotiations to extend existing agreements or enter into new long-term agreements with those and other customers
may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply agreements, or at all. If any of our top customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our revenues and profitability could suffer materially.
Disruption in supplies of coal produced by third parties and contractors could temporarily impair our ability to fill our customers' orders or increase our costs.
In addition to marketing coal that is produced from our controlled reserves, we purchase and resell coal produced by third parties from their controlled reserves to meet customer specifications and, in certain circumstances, we also at times utilize contractors to operate our mines or loading facilities. Disruption in our supply of third-party coal and contractor-produced coal could temporarily impair our ability to fill our customers' orders or require us to pay higher prices in order to obtain the required coal from other sources. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers, and other factors beyond our control could affect the availability, pricing and quality of coal produced by contractors for us. Any increase in the prices we pay for third-party coal or contractor-produced coal could increase our costs and therefore lower our earnings. During 2004, less than one percent of the coal we produced was mined by contract miners.
Competition within the coal industry may adversely affect our ability to sell coal.
Coal with lower production costs shipped East from Western coal mines and from offshore sources has resulted in increased competition for coal sales in the Appalachian region. This competition could result in a decrease in our market share in this region and a decrease in our revenues.
Demand for our high sulfur coal and the price that we can obtain for it is impacted by, among other things, the changing laws with respect to allowable emissions and the price of emission allowances. Significant increases in the price of those allowances could reduce the competitiveness of high sulfur coal at plants not equipped to reduce sulfur dioxide emissions. Competition from low sulfur coal and possibly natural gas could result in a decrease in our high-sulfur coal market share and revenues from those operations.
The demand for United States coal exports is dependent upon a number of factors outside of our control, including the overall demand for electricity in foreign markets, currency exchange rates, ocean freight rates, the demand for foreign-produced steel both in foreign markets and in the United States market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments, and environmental and other governmental regulations. If foreign demand for United States coal were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in downward pressure on domestic coal prices.
The government extensively regulates our mining operations, which imposes significant actual and potential costs on us, and future regulations could increase those costs or limit our ability to produce coal.
Our operations are subject to a variety of federal, state and local environmental, health and safety, transportation, labor and other laws and regulations. Examples include those relating to employee health and safety, emissions to air, discharges to water, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the storage, treatment and disposal of wastes, remediation of contaminated soil, surface and groundwater, surface subsidence from underground mining and the effects of mining on surface water and groundwater quality and availability. In addition, we are subject to significant legislation mandating certain benefits for current
and retired coal miners. We incur substantial costs to comply with government laws and regulations that apply to our operations.
Numerous governmental permits and approvals are required under these laws and regulations for mining operations. Many of our permits are subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits. Many of our permits governing discharges to or impacts upon surface streams will be subject to new and more stringent conditions to address various new water quality requirements that permitting authorities are now required to address when those permits are renewed over the next several years. Although we have no estimates at this time, our costs to satisfy such conditions could be substantial. We may also be required under certain permits to provide authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. In recent years, the permitting required under the Clean Water Act to address filling streams and other valleys with wastes from mountaintop coal mining operations and preparation plant refuse disposal has been the subject of extensive litigation by environmental groups against coal mining companies and environmental regulatory authorities, as well as regulatory changes by the United States EPA and the COE and legislative initiatives in the United States Congress. It is unclear at this time how the issues will ultimately be resolved, but for this as well as other issues that may arise involving permits necessary for coal mining, such requirements could prove costly and time-consuming, and could delay commencing or continuing exploration or production operations. New laws and regulations, as well as future interpretations and more rigorous enforcement of existing laws and regulations, 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.
Because of extensive and comprehensive regulatory requirements, violations of laws, regulations and permits during mining operations occur at our operations from time to time and may result in significant costs to correct such violations, as well as civil or criminal penalties and limitations or shutdowns of operations.
Extensive regulation of these matters has had and will continue to have a significant effect on our costs of production and competitive position. Further regulations, legislation or orders may also cause our sales or profitability to decline by hindering our ability to continue our mining operations, by increasing our costs or by causing coal to become a less attractive fuel source. See "Environmental and Other Regulatory Matters" for a discussion of environmental and other regulations affecting our business.
Our operations may substantially impact the environment or cause exposure to hazardous substances, and our properties may have significant environmental contamination, any of which could result in material liabilities to us.
We use, and in the past have used, hazardous materials and generate, and in the past have generated, hazardous wastes. In addition, many of the locations that we own or operate were used for coal mining and/or involved hazardous materials usage before we were involved with those locations as well as after. We may be subject to claims under federal and state statutes, and/or common law doctrines, for toxic torts, natural resource damages, and other damages as well as the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we or predecessor entities owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. We have from time to time been subject to claims arising out of contamination at our own and other facilities and may incur such liabilities in the future.
Mining operations can also impact flows and water quality in surface water bodies and remedial measures may be required, such as grouting in or lining of stream beds, to prevent or minimize such impacts. We are currently involved with state environmental authorities concerning impacts or alleged impacts of our mining operations on water flows in several surface streams. We are studying, or addressing, those impacts and we have not finally resolved those matters. Many of our mining operations take place in the vicinity of streams, and similar impacts could be asserted or identified at other streams in the future. The costs of our efforts at the streams we are currently addressing, and at any other streams that may be identified in the future, could be significant.
We maintain extensive coal slurry impoundments at a number of our mines. Such impoundments are subject to regulation. Slurry impoundments maintained by other coal mining operations have been known to fail, releasing large volumes of coal slurry. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries, property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. We have commenced measures to modify our method of operation at one surface impoundment containing slurry wastes in order to reduce the risk of releases to the environment from it, a process that will take several years to complete. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
These and other impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations and environmental conditions at our properties, could result in costs and liabilities that would materially and adversely affect us.
Extensive environmental regulations affect our customers and could reduce the demand for coal as a fuel source and cause our sales to decline.
The Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. Such regulations may require significant emissions control expenditures for coal-fired power plants to attain applicable ambient air quality standards. As a result, these generators may switch to fuels that generate less of these emissions, possibly reducing future demand for the construction of coal-fired power plants. If state regulatory schemes for electricity pricing are administered to not permit recovery of investments in emissions control equipment, the demand for our coal may be impacted.
For example, under the Clean Air Interstate Rule issued by the EPA announced new regulations further reductions of sulfur dioxide and nitrogen oxides from coal-fired power plants. Installation of additional pollution control equipment required by this rule could result in a decrease in the demand for low sulfur coal, potentially driving down prices for low sulfur coal. Further, also in March 2005 the EPA finalized a Utility Mercury Reductions Rule for controlling mercury emissions from power plants which could require coal-fired power plants to install new pollution controls or comply with a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. These standards and future standards could have the effect of making coal-fired plants unprofitable, thereby decreasing demand for coal. Some of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser's plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition, results of operations or cash flow.
Several proposals are pending in Congress and various states designed to further reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power plants, and certain ones could regulate
additional air pollutants. If such initiatives are enacted into law, power plant operators could choose other fuel sources to meet their requirements, thereby reducing the demand for coal.
The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention agreed to the Kyoto Protocol (the "Protocol") which is a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, if the United States were to ratify the Protocol, our nation would be required to reduce emissions to 93% of 1990 levels over a five-year period from 2008 through 2012. The United States has not ratified the Protocol. The Protocol has received sufficient support from enough nations to enter into force and will become binding on all those countries that have ratified it. Although the Protocol is still not binding on the United States, and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. Countries that have to reduce emissions may use less coal affecting demand for United States export coal. There could be pressure on companies in the United States to reduce emissions if they want to trade with countries that are part of the Protocol. In addition, some states in the United States have adopted or may adopt in the future regulations on greenhouse gas emissions. Some states and municipal entities have commenced litigation in different jurisdictions seeking to have certain utilities, including some of our customers, reduce their emission of carbon dioxide. If successful, there could be limitation on the amount of coal our customers could utilize. Future regulation of greenhouse gas emissions may be implemented as part of or distinct from the Protocol. Any of these measures could affect coal demand at utilities in the United States. See "Business-Environmental and Other Regulatory Matters" for a discussion of environmental and other regulations affecting our business.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or impairing our ability to supply coal to our customers.
Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer's purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources.
On the other hand, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, coordination of the many eastern loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. More recently, however, lower rail rates from the western coal producing areas to markets served by eastern United States producers have created major competitive challenges for eastern producers. The increased competition could have a material adverse effect on the business, financial condition and results of operations of our Pennsylvania, West Virginia and Illinois operations.
Some of our mines depend on a single transportation carrier or a single mode of transportation. Disruption of any of these transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair our ability to supply coal to our customers. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues.
If there are disruptions of the transportation services provided by the primary rail or barge carriers that transport our produced coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.
West Virginia legislation, which raised coal truck weight limits include provisions supporting enhanced enforcement. The legislation went into effect on October 1, 2003 and implementation began on January 1, 2004. It is possible that other states in which our coal is transported by truck modify their laws to limit truck weight limits. Such legislation could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.
Because our profitability is substantially dependent on the availability of an adequate supply of coal reserves that can be mined at competitive costs, the unavailability of these types of reserves would cause our profitability to decline.
We have not yet applied for all of the permits required, or developed the mines necessary, to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our planned development projects and acquisition activities may not result in significant additional reserves and we may not have continuing success developing new mines or expanding existing mines beyond our existing reserve base. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must receive various governmental permits. We may be unable to obtain the permits necessary for us to operate profitably in the future. Some of these permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen.
Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves through acquisitions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.
We face numerous uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs or decreased profitability.
We base our reserve information on engineering, economic and geological data assembled and analyzed by our staff, which includes engineers and geologists, and which is periodically reviewed by outside firms. The reserve estimates as to both quantity and quality are annually updated to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, such as geological and mining conditions which may not be fully identified by available exploration data or which may differ from experience in current operations, historical production from the area compared with
production from other similar producing areas, the assumed effects of regulation and taxes by governmental agencies and assumptions concerning coal prices, operating costs, mining technology improvements, final permit requirements, severance and excise tax, development costs and reclamation costs, all of which may vary considerably from actual results.
For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. These estimates thus may not accurately reflect our actual reserves. Any inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.
Defects in title or loss of any leasehold interests in our properties could limit our ability to mine these properties or result in significant unanticipated costs.
We conduct a significant part of our mining operations on properties that we lease. A title defect or the loss of any lease could adversely affect our ability to mine the associated reserves. Title to most of our leased properties and mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. Our right to mine some of our reserves has in the past been, and may again in the future be, adversely affected if defects in title or boundaries exist. In order to obtain leases to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease.
Acquisitions that we may undertake would involve a number of inherent risks, any of which could cause us not to realize the benefits anticipated to result.
Our strategy includes opportunistically expanding our operations and coal reserves through acquisitions of businesses and assets, mergers, joint ventures or other transactions. Such transactions involve various inherent risks, such as:
•uncertainties in assessing the value, strengths and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of, acquisition or other transaction candidates;
•the potential loss of key customers, management and employees of an acquired business;
•the ability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction;
•problems that could arise from the integration of the acquired business; and
•unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale.
Any one or more of these and other factors could cause us not to realize the benefits anticipated to result from the acquisition of businesses or assets or could result in unexpected liabilities associated with these acquisition candidates.
Expenditures for benefits for non-active employees could be materially higher than we have anticipated, which could increase our costs and adversely affect our financial results.
We are responsible for certain long-term liabilities under a variety of benefit plans and other arrangements with active and inactive employees. The funded status (the excess of projected benefit obligation over plan assets) of these obligations, as reflected in notes 12, 13 and 14 to our consolidated financial statements at December 31, 2004, included $483.0 million of postretirement obligations, $50.6 million of defined benefit pension obligations, $28.7 million of workers' compensation obligations and $5.0 million of self insured pneumoconiosis obligations. These obligations have been estimated based on assumptions including actuarial estimates, assumed discount rates, estimates of mine lives, expected returns on pension plan assets and changes in health care costs. We could be required to expend greater amounts than anticipated. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse affect on our financial results. Several states in which we operate consider changes in workers' compensation laws from time to time, which, if enacted, could adversely affect us.
The inability of the sellers of companies we have acquired to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations and financial position.
In our acquisition and disposition agreements, the respective sellers and buyers, and in some cases, their parent companies, agreed to retain responsibility for and indemnify us against damages resulting from certain third-party claims or other liabilities. These third-party claims and other liabilities include, without limitation, employee liabilities, costs associated with various litigation matters related to the mines involved, and certain environmental liabilities. The failure of any seller or buyer and, if applicable, its parent company, to satisfy its obligations with respect to claims and retained liabilities covered by the relevant agreements could have an adverse effect on our results of operations and financial position because claimants may successfully assert that we are liable for those claims and/or retained liabilities. In addition, certain obligations of the sellers to indemnify us will terminate or have already terminated upon expiration of the applicable indemnification period and will not cover damages in excess of the applicable coverage limit. The assertion of third-party claims after the expiration of the applicable indemnification period or in excess of the applicable coverage limit, or the failure of any seller to satisfy its indemnification obligations with respect to breaches of its representations and warranties, could have an adverse effect on our results of operations and financial position.
Our substantial leverage could harm our business by limiting our available cash and our access to additional capital, and could force us to sell material assets or operations to attempt to meet our debt service obligations.
Our financial performance could be affected by our substantial indebtedness. As of December 31, 2004, our total indebtedness was $685.0 million. In addition, we had $201.8 million of letters of credit outstanding and additional borrowings available under our new revolving credit facility of $148.2 million. We may also incur additional indebtedness in the future.
The degree to which we are leveraged could have important consequences, including, but not limited to:
•making it more difficult to self insure and obtain surety bonds or letters of credit;
•limiting our ability to enter into new long-term sales contracts;
•increasing our vulnerability to general adverse economic and industry conditions;
•requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of
the cash flow to fund land acquisitions, working capital, capital expenditures, research and development or other general corporate uses;
•limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development, debt service requirements or other general corporate requirements;
•making it more difficult for us to pay interest and satisfy our debt obligations;
•limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and
•placing us at a competitive disadvantage compared to less leveraged competitors.
In addition, our indebtedness subjects us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us. Furthermore, substantially all of our material assets secure our indebtedness under our Senior Credit Facilities.
If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations or our requirements under our other long term liabilities. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our Senior Credit Facilities and the indenture under which our corporate bonds were issued restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.
If our business does not generate sufficient cash for operations, we may not be able to repay our indebtedness.
Our ability to pay principal and interest on and to refinance our debt depends upon the operating performance of our subsidiaries, which will be affected by, among other things, general economic, financial, competitive, legislative, regulatory and other factors, some of which are beyond our control. In particular, economic conditions could cause the price of coal to fall, our revenue to decline, and hamper our ability to repay our indebtedness.
Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us under our credit facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms, on terms acceptable to us or at all.
Despite our current leverage, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our indebtedness do not prohibit Foundation Coal Holdings, Inc. or our subsidiaries from doing so. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
The covenants in our Senior Credit Facilities and our indenture impose restrictions that may limit our operating and financial flexibility.
The Senior Credit Facilities, our indenture governing the 71/4% Senior Notes and the instruments governing our other indebtedness contain a number of significant restrictions and covenants that limit the ability of our subsidiaries to enter into certain financial arrangements or engage in specified transactions, including the payment of certain dividends.
Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in our being unable to comply with our financial covenants contained in our Senior Credit Facilities. If we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
Failure to maintain required surety bonds could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease the coal. Failure to maintain capacity for required letters of credit could limit our available borrowing capacity under our Senior Credit Facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements.
We are required to provide financial assurance to secure our obligations to reclaim lands used for mining, to pay federal and state workers' compensation benefits, to secure coal lease obligations and to satisfy other miscellaneous obligations. We generally use surety bonds to secure reclamation and coal lease obligations. We generally use letters of credit to assure workers' compensation benefits, UMWA retiree medical benefits and as collateral for surety bonds. Miscellaneous obligations are secured using both surety bonds and letters of credit.
As of December 31, 2004, we had outstanding surety bonds of $267.2 million, of which $244.1 million secured reclamation obligations, $10.7 million secured coal lease obligations and $10.4 million secured self-insured workers' compensation obligations. The premium rates and terms of the surety bonds are subject to annual renewals. It has become increasingly difficult for us to secure new surety bonds or renew bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would affect our ability to secure reclamation, coal lease obligations and self insured workers' compensation obligations, which could adversely affect our ability to mine or lease the coal. That failure could result from a variety of factors including the following:
•lack of availability, higher expense or unfavorable market terms of new surety bonds; and
•restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of the indenture or new credit facilities.
In addition, at December 31, 2004, we had $201.8 million of letters of credit in place for the following purposes: $36.5 million for workers' compensation, including collateral for workers' compensation bonds; $24.0 million for UMWA retiree health care obligations; $130.5 million for collateral for reclamation surety bonds; $6.0 million for minimum royalty payment obligations for a closed mine in Utah; and $4.7 million for other miscellaneous obligations. Obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing
capacity under the Senior Credit Facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements.
Due to our participation in multi-employer pension plans, we may have exposure under those plans that extend beyond what our obligation would be with respect to our employees.
We contribute to two multi-employer defined benefit pension plans administered by the UMWA. In 2004, our total contributions to these plans and other contractual payments under our UMWA wage agreement were approximately $1.3 million.
In the event of a partial or complete withdrawal by us from any plan which is underfunded, we would be liable for a proportionate share of such plan's unfunded vested benefits. Based on the limited information available from plan administrators, which we cannot independently validate, we believe that our portion of the contingent liability in the case of a full withdrawal or termination would be material to our financial position and results of operations. In the event that any other contributing employer withdraws from any plan which is underfunded, and such employer (or any member in its controlled group) cannot satisfy its obligations under the plan at the time of withdrawal, then we, along with the other remaining contributing employers, would be liable for our proportionate share of such plan's unfunded vested benefits.
In addition, if a multi-employer plan fails to satisfy the minimum funding requirements, the Internal Revenue Service, pursuant to Section 4971 of the Internal Revenue Code (the "Code") will impose an excise tax of 5% on the amount of the accumulated funding deficiency. Under Section 413(c)(5) of the Code, the liability of each contributing employer, including us, will be determined in part by each employer's respective delinquency in meeting the required employer contributions under the plan. The Code also requires contributing employers to make additional contributions in order to reduce the deficiency to zero, which may, along with the payment of the excise tax, have a material adverse impact on our financial results.
Our pension plans are currently underfunded and we may have to make significant cash payments to the plans, reducing the cash available for our business.
We sponsor pension plans in the United States for salaried and non-union hourly employees. In 2004, we contributed $15.9 million to our pension plans. We currently expect to make an additional contribution in 2005 of approximately $6.0 million. If the performance of the assets in our pension plans does not meet our expectations, or if other actuarial assumptions are modified, our contributions could be higher than we expect.
As of December 31, 2004, our pension plans were underfunded by $50.6 million (based on the actuarial assumptions used for FAS 87 purposes). Our pension plans are subject to the Employee Retirement Income Security Act of 1974 ("ERISA"). Under ERISA, the Pension Benefit Guaranty Corporation, or PBGC, has the authority to terminate an underfunded pension plan under limited circumstances. In the event our United States pension plans are terminated for any reason while the plans are underfunded, we will incur a liability to the PBGC that may be equal to the entire amount of the underfunding.
Our financial condition could be negatively affected if we fail to maintain satisfactory labor relations.
As of December 31, 2004, the UMWA represented approximately 41% of our employees, who produced approximately 20% of our coal sales volume during 2004. Because of the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our non-unionized competitors may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced
productivity and higher labor costs. Our existing collective bargaining agreements with the UMWA expire in 2007. If some or all of the affected employees strike, it could adversely affect our productivity, increase our costs and disrupt shipments.
In November 2003, the UMWA held an election at our Rockspring mining facility in West Virginia. The UMWA challenged nine unopened ballots as being improperly cast by supervisors. The outcome of the election will depend on the decision of the NLRB with respect to the nine challenged ballots, which ballots will not be opened until final resolution of the challenge. On February 5, 2004, the Regional Director of the NLRB ruled that only five of the nine challenged ballots could be counted. Both parties appealed to the full NLRB, and we are currently awaiting a decision. If it is ultimately determined that the UMWA was validly elected, approximately 255 employees, or approximately 10% of our total workforce, will become UMWA members. In the event the Rockspring mining facility becomes unionized, we will bargain in good faith towards an acceptable collective bargaining agreement. If we are unable to do so, there could be strikes or other work stoppages detrimental to the normal operation of the Rockspring mining facility.
A shortage of skilled labor in the mining industry could pose a risk to achieving improved labor productivity and competitive costs, which could adversely affect our profitability.
Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In the event the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal.
Our ability to operate our Company effectively could be impaired if we lose key personnel.
We manage our business with a number of key personnel. We do not have "key person" life insurance to cover our executive officers. The loss of certain of these key individuals could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. Key personnel may not continue to be employed by us or we may not be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.
Mining in Central Appalachia and Northern Appalachia is more complex and involves more regulatory constraints than mining in the other areas, which could affect the mining operations and cost structures of these areas.
The geological characteristics of Central Appalachia and Northern Appalachia coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, as compared to mines in the Powder River Basin, permitting, licensing and other environmental and regulatory requirements are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and customers' ability to use coal produced by, our mines in Central Appalachia and Northern Appalachia.
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties. These new power plant owners may
have credit ratings that are below investment grade. If there is deterioration of the creditworthiness of electric power generator customers or trading counterparties, our business could be adversely affected. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.
Our large stockholders may have significant influence on our company, including control over decisions that require the approval of stockholders, whether or not such decision is believed by the other stockholders to be in their own best interests.
We have three large stockholders that collectively beneficially own approximately 45% of our common stock. As a result, these stockholders have some degree of control over our decisions to enter into any corporate transaction and have the ability to prevent any transaction that requires the approval of equity holders regardless of whether or not other equity holders believe that any such transaction is in their own best interests. For example certain provisions in our amended and restated certificate of incorporation and bylaws may be amended only by a vote of at least 75% of the voting power of all of the outstanding shares of our stock entitled to vote. See "Anti-Takeover Effects of Certain Provisions of Our Amended and Restated Certificate of Incorporation and Bylaws" risk factor below.
Our large stockholders may have conflicts of interest with us in the future.
Our three large stockholders are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. These other investments may create competing financial demands on these stockholders or potential conflicts of interest and require efforts consistent with applicable law to keep the other businesses separate from our operations. These stockholders may also pursue acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us. So long as these stockholders continue to own a significant amount of our equity, even if such amount is less than 50%, they will continue to be able to strongly influence or effectively control our decisions.
If we do not implement all required corporate governance and accounting practices and policies, our shareholders will not be afforded all of the protections available to shareholders of other companies and we may be unable to provide the required financial information in a timely and reliable manner.
Prior to our IPO in December 2004, as a privately-held company, we were not subject to any of the corporate governance and financial reporting practices and policies required of a publicly-traded company. The controls and procedures that we implemented may not comply with all of these practices and policies. Implementation of these practices and policies could disrupt our business, distract our management and employees and increase our costs. If we fail to develop and maintain effective controls and procedures, we may be unable to provide the required financial information in a timely and reliable manner.
Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.
Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against United States targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of
time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations.
Risks Related to Our Common Stock
Future sales of our shares could depress the market price of our common stock.
The market price of our common stock could decline as a result of sales of a large number of shares of common stock in the market or the perception that such sales could occur. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.
Our executive officers, directors and all of the shareholders of Foundation Coal Holdings, Inc. existing prior to our IPO (Blackstone FCH Capital Partners IV L.P., Blackstone Family Investment Partnership IV, First Reserve Fund IX, L.P. and AMCI Acquisition, LLC otherwise referred to as the "Sponsors") have agreed with the underwriters not to sell, dispose of or pledge any shares of our common stock or securities convertible into or exchangeable for shares of our common stock, subject to specified exceptions, during the period from December 8, 2004 continuing through 180 days after that date, except with the prior written consent of Morgan Stanley & Co. Incorporated and Citigroup Global Markets Inc.
As of March 7, 2005, we had 44,627,047 shares of common stock outstanding. Of those shares, 24,121,900 shares offered in our Initial Public Offering on December 8, 2004 are freely traded. With the exception of the shares held by Messrs. Crowley and Richards, the remaining 20,505,147 shares held by our officers, directors, and Sponsors will be eligible for resale from time to time after the expiration of the 180-day lock-up period, subject to contractual and Securities Act restrictions. None of those shares may currently be resold under Rule 144(k) without regard to volume limitations and no shares may currently be sold subject to the volume, manner of sale and other conditions of Rule 144. However, after the expiration of the 180-day lock-up period, the Sponsors and their affiliates, which collectively beneficially own 20,034,726 shares, will have the ability to cause us to register the resale of their remaining shares.
Anti-Takeover Effects of Certain Provisions of Our Amended and Restated Certificate of Incorporation and Bylaws
Certain provisions of our amended and restated certificate of incorporation and bylaws, which are summarized in the following paragraphs, may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt that a stockholder might consider in its best interest, including those attempts that might result in a premium over the market price for the shares held by stockholders.
Removal of Directors; Vacancies
Our amended and restated certificate of incorporation and the bylaws provide that (i) prior to the date on which our initial stockholders cease to own at least 40% of all the then outstanding shares of stock, directors may be removed for any reason upon the affirmative vote of holders of at least a majority of the voting power of all the then outstanding shares of stock entitled to vote generally in the election of directors, voting together as a single class and (ii) on and after the date the Sponsors cease to own at least 40% of all the then outstanding shares of stock directors may be removed only upon the affirmative vote of holders of at least 75% of the voting power of all the then outstanding shares of stock entitled to vote generally in the election of directors, voting together as a single class. In addition,
our amended and restated bylaws also provide that, except as set forth in the stockholders agreement, any vacancies on our Board will be filled only by the affirmative vote of a majority of the remaining directors, although less than a quorum.
Provisions in our certificate of incorporation and bylaws may discourage a takeover attempt even if doing so might be beneficial to our shareholders.
Provisions contained in our certificate of incorporation and bylaws could make it more difficult for a third party to acquire us. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for shareholders to effect certain corporate actions. For example, our certificate of incorporation authorizes our Board to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock, without any vote or action by our shareholders. Thus, our Board can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our common stock. These rights may have the effect of delaying or deterring a change of control of our Company. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Commodity Price Risk
We manage our commodity price risk for coal sales through the use of long-term coal supply agreements rather than through the use of derivative instruments. As of December 31, 2004, we had sales commitments for approximately 98% of our planned 2005 production. Some of the products used in our mining activities, such as diesel fuel, explosives and steel products, are subject to price volatility. Through our suppliers, we utilize forward purchase contracts to manage the exposure related to this volatility.
Credit Risk
Our credit risk is primarily with electric power generators and, to a lesser extent, steel producers. Most electric power generators to whom we sell have investment grade credit ratings. Our policy is to independently evaluate each customer's creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.
Counterparty risk with respect to interest rate swaps is not considered to be significant based upon the creditworthiness of the participating financial institutions.
Interest Rate Risk
Historically, we have had exposure to changes in interest rates on a portion of our existing level of indebtedness under the Predecessor. This exposure had been completely hedged for the life of the debt using pay-fixed, receive-variable interest rate swaps. From July 30, 2004 forward, we have exposure to changes in interest rates on our bank term loan and our revolving credit facility. As described below, we have used interest rate swaps to manage this risk.
We entered into swap contracts for the purpose of complying with certain financial covenants in our senior secured credit facility that require fixing the interest rate for at least three years on a
minimum of 50% of our total outstanding debt. The swap contracts cover $85 million to September 2007. The following table summarizes our outstanding swap contracts at December 31, 2004.
Notional Amount
Term
Floating Rate
Fixed Rate
$20 million
September 2004 - September 2007
3-month LIBOR
3.26
%
$25 million
September 2004 - September 2007
3-month LIBOR
3.26
%
$20 million
September 2004 - September 2007
3-month LIBOR
3.26
%
$20 million
September 2004 - September 2007
3-month LIBOR
3.26
%
As of December 31, 2004, after giving effect to the $85 million of interest rate swaps that were entered into, we had $300 million of variable rate indebtedness, representing approximately 44% of our outstanding indebtedness. A 1% change in interest rates would affect the interest expense on such indebtedness by $3.0 million. At December 31, 2004, the fair value of these swap agreements was an unrealized gain of $0.5 million. During the five month operating period ended December 31, 2004 these swaps were not designated as hedges.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
FOUNDATION COAL HOLDINGS, INC AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
INDEX
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
RAG American Coal Holding, Inc.
We have audited the accompanying consolidated balance sheets of RAG American Coal Holding, Inc. and subsidiaries (a wholly owned subsidiary of RAG Coal International AG) as of December 31, 2003, and the related consolidated statements of operations and comprehensive income, stockholder's equity and cash flows for each of the two years in the period ended December 31, 2003 and the consolidated statements of operations and comprehensive income and cash flows for the period from January 1, 2004 through July 29, 2004 (date of sale). Our audits also included the financial statement schedule listed in the Index at Item 15 (a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of RAG American Coal Holding, Inc. at December 31, 2003, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2003, and for the period from January 1, 2004 through July 29, 2004 (date of sale) in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 18 to the consolidated financial statements, on January 1, 2003, the Company changed its method of accounting for asset retirement obligations.
/s/ Ernst & Young LLP
March 29, 2005
Baltimore, Maryland
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Foundation Coal Holdings, Inc. (Successor in interest to Foundation Coal Holdings, LLC)
We have audited the consolidated balance sheet of Foundation Coal Holdings, Inc. (Successor in interest to Foundation Coal Holdings, LLC) and subsidiaries as of December 31, 2004, and the related consolidated statements of operations and comprehensive income, stockholders' equity and cash flows for the period from February 9, 2004 (date of formation) through December 31, 2004. Our audit also included the financial statement schedule listed in the Index at Item 15 (a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Foundation Coal Holdings, Inc. at December 31, 2004, and the consolidated results of its operations and its cash flows for the period from February 9, 2004 (date of formation) through December 31, 2004 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
March 29, 2005
Baltimore, Maryland
Foundation Coal Holdings, Inc. and Subsidiaries
(Successor in interest to Foundation Coal Holdings, LLC)
Consolidated Balance Sheets
The accompanying notes are an integral part of these financial statements.
Foundation Coal Holdings, Inc. and Subsidiaries
(Successor in interest to Foundation Coal Holdings, LLC)
Statements of Consolidated Operations and Comprehensive Income (Loss)
The accompanying notes are an integral part of these financial statements.
Foundation Coal Holdings, Inc. and Subsidiaries
(Successor in interest to Foundation Coal Holdings, LLC)
Statements of Consolidated Stockholders' Equity
(in thousands, except unit and share data)
The accompanying notes are an integral part of these financial statements.
Foundation Coal Holdings, Inc. and Subsidiaries
(Successor in interest to Foundation Coal Holdings, LLC)
Statements of Consolidated Cash Flows
The accompanying notes are an integral part of these financial statements.
Foundation Coal Holdings, Inc. and Subsidiaries
(Successor in interest to Foundation Coal Holdings, LLC)
Notes to Consolidated Financial Statements
(Dollars in thousands, except per share data)
Note 1. Description of Business and Basis of Presentation
Foundation Coal Holdings, Inc. and its indirect subsidiary, Foundation Coal Corporation ("FCC"), were formed to acquire the North American coal mining assets of RAG American Coal Holding, Inc., which acquisition closed on July 30, 2004 ("the acquisition"). Foundation Coal Holdings, Inc. through its operating subsidiaries engages in the extraction, cleaning and selling of coal to electric utilities, steel companies, coal brokers, and industrial users primarily in the United States.
RAG American Coal Holding, Inc., a wholly owned subsidiary of RAG Coal International AG ("RAG"), which is an indirect owned subsidiary of RAG Aktiengesellschaft ("RAG AG"), was incorporated in Delaware on October 31, 1974. RAG American Coal Holding, Inc. had two primary operating units: Riverton Coal Production, Inc. and subsidiaries ("RCP") and RAG American Coal Company and subsidiaries ("RACC").
On February 29, 2004, RACC signed a definitive Stock Purchase Agreement to sell RAG Coal AG's Colorado operations which included Twentymile Coal Company, RAG Empire Corporation, RAG Shoshone Coal Corporation and Colorado Yampa Coal Company (collectively referred to as the RAG Colorado Business Unit) to a subsidiary of Peabody Energy Corporation. This transaction closed on April 15, 2004. Accordingly, all references to Foundation Coal Holdings, Inc., exclude the RAG Colorado Business Unit which is accounted for and presented in the accompanying financial statements as discontinued operations. Prior period financial statements have also been restated to reflect the RAG Colorado Business Unit as a discontinued operation (see Note 28).
The following provides a description of the basis of presentation during all periods presented:
"Successor"-Represents the consolidated financial position of Foundation Coal Holdings, Inc. and consolidated subsidiaries as of December 31, 2004 and consolidated results of operations and cash flows for the period from February 9, 2004 (date of formation) through December 31, 2004. Foundation Coal Holdings, Inc. had no significant activities until the acquisition on July 30, 2004. Therefore, the results of operations and cash flows for the period from February 9, 2004 (date of formation) through December 31, 2004 reflect only the activity for the five month period ended December 31, 2004. The financial position as of December 31, 2004 and results of operations and cash flows for the period from February 9, 2004 (date of formation) through December 31, 2004 reflect preliminary purchase accounting for the acquisition.
"Predecessor"-Represents the consolidated results of operations and cash flows of RAG American Coal Holding, Inc. for all periods prior to the acquisition. This presentation reflects the historical basis of accounting.
The consolidated financial statements as of and for the period ended December 31, 2004 reflect the acquisition under the purchase method of accounting, in accordance with the Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations, discussed in greater detail in Note 4.
Unless otherwise indicated, "the Company" as used throughout the remainder of these notes to the consolidated financial statements refers to both the Successor and the Predecessor.
At December 31, 2004, union representation accounted for approximately 41% of the Company's employees and 20% of production. Labor contracts for the Pennsylvania mines, Emerald and Cumberland, with the United Mine Workers' of America (UMWA) were signed in 2002 and expire in 2007. The UMWA contract for the Wabash mine was signed in March 2003 and expires in 2007.
Note 2. Change in Ownership
Formation
Foundation Coal Holdings, LLC ("LLC") was formed on February 9, 2004 as a Delaware limited liability company. The original members of LLC were First Reserve Fund IX, L.P. and Blackstone Capital Partners IV LP. Each member was granted 50 units in exchange for nominal consideration in the form of management and capital formation advisory services. The purpose of the formation of LLC was to pursue the acquisition of the North American coal mining assets of RAG.
On April 23, 2004, LLC formed FCC as a wholly owned subsidiary. FCC issued 100 shares of common stock with a par value of $0.01 to LLC.
On May 24, 2004, FCC signed a Stock Purchase Agreement dated May 24, 2004 (the "Stock Purchase Agreement") whereby FCC agreed to acquire all of the direct and indirect subsidiaries engaged in coal mining in North America then owned by RAG.
Through July 29, 2004, neither LLC, FCC nor Foundation Coal Holdings, Inc., (collectively the "Successor") had any additional significant activities.
Recapitalization
On July 30, 2004, LLC amended and restated its Limited Liability Operating Agreement. As part of the Amended and Restated Limited Liability Operating Agreement the following Members were granted membership interests in exchange for cash capital contributions as follows:
The management members were senior managers of RAG American Coal Holding, Inc., the operating company of RAG's North American Operations. These senior managers continued as senior managers of Foundation Coal Holdings, Inc.
Foundation Coal Holdings, Inc. and FC2 Corp. ("FC2") were incorporated in Delaware on July 19, 2004. On July 30, 2004, LLC contributed the shares of its subsidiary FCC to Foundation Coal Holdings, Inc. in exchange for 100 shares of common stock of Foundation Coal Holdings, Inc. Foundation Coal Holdings, Inc. then contributed the shares of FCC into FC2 in exchange for 100 shares of common stock of FC2. Upon the completion of these exchange transactions, Foundation Coal Holdings, Inc., FC2 and FCC were direct or indirect wholly owned subsidiaries of LLC.
On July 30, 2004, FCC completed the acquisition of the direct and indirect subsidiaries engaged in coal mining in North America then owned by RAG.
On August 10, 2004, the Company effected a 196,000 for one stock split of common stock. All share and per share amounts in these consolidated financial statements and related notes reflect the stock split.
On August 17, 2004, LLC was merged with and into Foundation Coal Holdings, Inc. As a result of the merger, the members of LLC received one share of Foundation Coal Holdings, Inc.'s common stock for each unit of membership interest in LLC and Foundation Coal Holdings, Inc. became the successor in interest to LLC.
Acquisition of RAG
On July 30, 2004, the Company, through its indirect wholly owned subsidiary, FCC and pursuant to the terms of the Stock Purchase Agreement acquired 100% of the outstanding common shares of all of the direct and indirect subsidiaries of RAG engaged in coal mining in North America for a purchase price of approximately $967,300 (which is net of a $8,005 purchase price adjustment that was received in October 2004) plus associated transaction costs of approximately $19,618 (see Note 4).
Initial Public Offering of Common Stock
On December 8, 2004, the Company completed an initial public offering ("IPO" or "Offering") of 23,610,000 shares of common stock. Net proceeds from the offering, after deducting underwriting discounts and offering expenses, were approximately $481,100. On December 8, 2004 immediately preceding the IPO, the Board of Directors (the "Board") approved, authorized and declared a 0.879639 for one reverse stock split of all the 19,600,000 common shares issued and outstanding thereby reducing common shares outstanding to approximately 17,240,900 shares. The Board then approved the declaration of two separate cash dividends of $0.058 and $25.41 per share, respectively, of common stock issued and outstanding for shareholders of record. The Company used approximately $434,000 of the net proceeds from the Offering to pay the dividends to its stockholders. The Company used the remaining net proceeds of approximately $47,100 to repay a portion of the indebtedness outstanding on the loans under the term loan facility and for other general corporate purposes. The Underwriting Agreement provided for up to 3,541,500 shares of common stock to be reserved for the satisfaction of an over-allotment option allowing the underwriters an option to purchase additional shares. Pursuant to this underwriters' option 511,900 shares were sold generating net proceeds, after deducting underwriting discounts and estimated offering expenses, of approximately $10,560. The Company used these proceeds and cash on hand to pay an additional dividend to its existing stockholders in the amount of $11,142. The Board declared a stock dividend for the remaining over-allotment shares not purchased by the underwriters to the stockholders of record immediately prior to the IPO. All per share amounts in these consolidated financial statements and related notes reflect the stock dividend.
Note 3. Summary of Significant Accounting Policies
Unless otherwise indicated, the Company and the Predecessor follow the same significant accounting policies.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates
The Company's consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of the Company's consolidated financial statements requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of management estimates relate to the purchase price allocation; quantity and quality of mineral reserves; asset retirement obligations; employee and retiree benefit liabilities; future cash flows associated with assets; useful lives for depreciation, depletion, and amortization; recoverability of deferred tax assets; fair value of financial instruments and the determination of the fair value of share-based payments. Due to the prospective nature of these estimates, actual results could differ from those estimated.
Cash and Cash Equivalents
Cash and cash equivalents consist of all cash balances and highly liquid investments with an original maturity of three months or less. Because of the short maturity of these investments, the carrying amounts approximate their fair value. Cash and cash equivalents are invested in high-quality commercial paper and money market funds. At December 31, 2003 the amount in cash on deposit of $233,023 represented cash balances placed under a centralized cash management program with the Predecessor's parent in excess of amounts required by the Company for day-to-day operations. Cash pledged against predecessor outstanding debt represents cash pledged to satisfy a leverage ratio covenant on outstanding debt which required a minimum pledge of $20,000 at all times (see Note 10).
Inventories
Coal inventories acquired in the acquisition are stated at their fair value at the acquisition date. As of December 31, 2004 all coal inventory acquired in the acquisition has been sold, therefore the excess of the fair value of coal inventories over the Predecessor's historical cost of $3,753 was charged to cost of coal sales in the period ended December 31, 2004. Coal inventories produced subsequent to the acquisition are stated at the lower of cost or net realizable value. Net realizable value represents the estimated future sales price of the product based on prevailing and long-term prices, less the estimated preparation and selling costs. Coal inventories are valued at the lower of average cost or market.
Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.
The cost of removing overburden subsequent to the acquisition in advance of coal extraction at the Wyoming surface mines is deferred and is classified as work-in-process inventory. The overburden removal process is generally 12 months or less in advance of coal extraction. In instances where the overburden removal process is greater than 12 months, the Company classifies the deferred costs as a non-current asset.
Other Current Assets
Other current assets consist primarily of prepaid expenses, including deferred longwall move costs and advance mining royalties. The Company defers the direct costs, including labor and supplies, associated with moving longwall equipment and the related equipment refurbishment costs in other current assets. These deferred costs are amortized on a units-of-production basis over the life of the
subsequent panel of coal mined by the longwall equipment. Deferred costs that are anticipated to be amortized into production within one year are included in current assets. All other deferred costs are included in noncurrent assets.
Plant, Equipment and Mine Development Costs
Costs to obtain coal lands and leased mineral rights are capitalized and amortized to operations on the units-of-production method utilizing only proven and probable reserves in the depletion base. Costs of developing new mines or significantly expanding the capacity of or extending the lives of existing mines are capitalized and principally amortized using the units-of-production method over proven and probable reserves directly benefiting from the capital expenditure. The Predecessor principally amortized mine development costs using the straight-line method over the period during which each capitalized expenditure benefited production. The Company and its Predecessor believe that the straight-line method approximates the units-of-production method. Mobile mining equipment and other fixed assets are stated at cost and depreciated on a straight-line basis over the estimated useful lives ranging from 1 to 20 years or on a units-of-production basis. Leasehold improvements are amortized over their estimated useful lives or the term of the lease, whichever is shorter. Major repairs and betterments that significantly extend original useful lives or improve productivity are capitalized and depreciated over the period benefited. Maintenance and repairs are generally expensed as incurred.
Asset Retirement Obligations
SFAS No. 143, Accounting for Asset Retirement Obligations, addresses a uniform methodology for accounting for estimated reclamation and abandonment costs. The Company's asset retirement obligations consist principally of costs to reclaim acreage disturbed at surface operations and estimated costs to reclaim support acreage and perform other related functions at underground mines. SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which the legal obligation associated with the retirement of the tangible long-lived asset is incurred. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, the gain or loss upon settlement is incurred. The Company estimates its asset retirement obligation liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of future cash flows required for a third party to perform the necessary reclamation work. The Company annually reviews its estimated future cash flows for its asset retirement obligations.
The Predecessor adopted SFAS No. 143 on January 1, 2003 as more fully described in Note 18 to the consolidated financial statements. Prior to adoption, the Predecessor estimated future reclamation costs based principally on legal and regulatory requirements. Such costs were accrued and charged ratably over the expected operating lives of the mines using the units-of-production method based on proven and probable reserves.
Coal Supply Agreements
Coal supply agreements represent the fair value assigned at the acquistion date for acquired sales contracts. These sales contracts are valued at the present value of the difference between the expected
contract revenues from the acquired contract, net of royalties and taxes imposed on sales revenues, and the net contract revenues derived from applying market prices at the contract acquisition date for new contracts of similar duration and coal qualities. Using this approach to valuation, certain contracts, where the expected contract price is above market at the acquisition date, have a positive value and are classified as assets. Certain other contracts, where the expected contract price is below market at the acquisition date, have a negative value and are classified as liabilities. The asset or liability is amortized over the term of the contracts based on the tons of coal shipped under each contract. During the last 5 months of 2004 the amortization of coal supply agreements was a ($67,238) net credit, which consisted of a $20,957 expense related to the amortization of contract assets and a ($88,195) credit related to the amortization of contract liabilities. Based on expected future shipments under these agreements, amortization of the asset for above market contracts is anticipated to be approximately $27,000, $20,000, $11,000, $7,000 and $6,000 for the years ended December 31, 2005, 2006, 2007, 2008 and 2009, respectively. Amortization of the liability for below market contracts is anticipated to be approximately ($116,000), ($42,000), ($15,000), ($4,000) and ($1,000) for the years ended December 31, 2005, 2006, 2007, 2008 and 2009, respectively.
Asset Impairment and Disposal of Long-lived Assets
The Company reviews and evaluates its long-lived assets and certain identifiable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.
As a result of lower than expected gas production volumes and prices, the Company recorded an asset impairment charge of $7,042 in 2002 to reduce its investment in the Powder River Basin's coal bed methane joint venture to its estimated fair value of $280 based on a discounted cash flow analysis.
Income Taxes
Income taxes are accounted for under the asset and liability method in accordance with SFAS No. 109, Accounting for Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date.
The Predecessor filed and the Company expects to file a consolidated United States federal income tax return including its subsidiaries. No written tax sharing agreements exist with its subsidiaries. The Predecessor will be required to file its final tax returns for the period ended July 29, 2004. The Company adopted a December 31, 2004 tax year. Certain state income tax returns are not impacted by the acquisition. The Company has accounted for the impact of the acquisition on the income tax provision reflected in the financial statements. The finalization of the purchase price
allocation and the filing of the Predecessor's final return and the Company's initial return may have an impact on tax estimates in future periods.
Advance Mining Royalties
Rights to leased mineral rights are often acquired through royalty payments. Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoverable against future production. These advance payments are deferred and charged to operations as the coal reserves are mined. In instances where advance payments are not expected to be recoverable against future production, no asset is recognized and the scheduled future payments are expensed as incurred. Advance mining royalties are deferred and recorded in other current and noncurrent assets.
Revenue Recognition
Revenue is recognized on coal sales when title passes to the customer, in accordance with the terms of the sales agreement, which generally occurs when the coal is loaded into transport carriers for shipment to the customer.
Freight Revenue and Costs
Shipping and handling costs paid to third-party carriers and invoiced to coal customers are recorded and included in cost of coal sales, and coal sales revenue, respectively.
Workers' Compensation
The Company is primarily self-insured for workers' compensation claims in the various states in which it operates. The liability for workers' compensation claims is an actuarially determined estimate of the ultimate losses incurred on known claims plus a provision for incurred but not reported claims. This probable ultimate liability is re-determined annually and resultant adjustments are expensed. These obligations are included in the consolidated balance sheets as other current and noncurrent liabilities.
Pension, and Other Postretirement Plans and Pneumoconiosis (Black Lung) Benefits
Pension benefits, postretirement benefits, and postemployment benefits are reflected in the Company's consolidated financial statements and accounted for in accordance with SFAS No. 87, Employers' Accounting for Pensions; SFAS No. 106 and SFAS No. 112, Employers' Accounting for Postemployment Benefits, respectively. The pension and postretirement benefits are accounted for over the estimated service lives of the employees. The cost of providing certain postemployment benefits is generally recognized when the employee becomes entitled to the benefit.
The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung. The Company is largely self-insured for these benefits and funds benefit payments through a Section 501 (c) (21) tax-exempt trust fund. Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. The Company follows SFAS No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions for purposes of accounting for its black lung liabilities and assets.
Derivative Instruments and Hedging Activities
Derivative instruments and hedging activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activity (as amended by SFAS No. 138). SFAS No. 133 establishes accounting and reporting standards for derivative instruments and hedging activities and requires that entities recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. Those fair value adjustments are to be included either in the determination of net income or as a component of other comprehensive income, depending on the nature of the transaction.
On the date the derivative contract is entered into, the Company generally designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge), a hedge of a forecasted transaction, or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as fair-value or cash-flow hedges to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively.
Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair-value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk are recorded in income. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until income is affected by the variability in cash flows of the designated hedged item.
Stock-Based Compensation
The Company records compensation expense for all employee stock-based compensation plans using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB No. 25") and related interpretations. Under APB No. 25, compensation expense is recorded over the vesting period to the extent that the fair value of the underlying stock on the date of grant exceeds the exercise or acquisition price of the stock or stock-based award. We have adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock-Based Compensation, ("SFAS No. 123"), as amended by SFAS No. 148 Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of FASB Statement No. 123 ("SFAS No. 148").
The following table illustrates the effect on net earnings as if the Company applied the fair value recognition provisions of SFAS No. 123. The Predecessor had no stock option plans; therefore, no Predecessor information is presented.
For purposes of determining the pro forma amounts in the above disclosure, the fair market value of option grants was estimated on the date of the grant using the Black-Scholes option-pricing model using the following assumptions: weighted-average risk-free interest rate of 3.94%; dividend yield of 0.7%; expected option life of eight years; and volatility of 55% (see Note 15). As the Company's common stock only recently became publicly traded, the Company's volatility was based on other companies in the mining industry.
These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period, and additional options may be granted in the future. Compensation expense for awards with cliff vesting provisions is recognized on a straight-line basis.
Earnings (Loss) Per Common Share
Basic earnings or (loss) per share is computed by dividing net income (loss) by the weighted-average number of outstanding common shares for the period. Diluted earnings per share reflects the potential dilution that could occur if securities that may require the issuance of common shares in the future were converted. Diluted earnings per share is computed by increasing the weighted-average number of outstanding common shares to include the additional common shares that would be outstanding after conversion and adjusting net income for changes that would result from the conversion. Only those securities that result in a reduction in earnings per share are included in the calculation. See Note 20 for the dilutive impact of stock options on the earnings per share calculation.
On December 8, 2004, the Board declared stock dividends totalling 3,261,224 shares to be distributed in January 2005. All earnings per share information in these consolidated financial statements and related notes reflect the shares associated with this stock dividend.
Comprehensive Income (Loss)
In addition to net income (loss), comprehensive income (loss) includes all changes in equity during a period, such as adjustments to minimum pension liabilities and the effective portion of changes in fair value of derivative instruments that qualify as cash flow hedges.
Debt Issuance Costs
Costs incurred in connection with the issuance of the certain debt facilities were capitalized and are being amortized over a weighted average term, reflective of the lives of the related indebtedness ranging between 7 to 10 years, on a straight-line basis which approximates results obtained under the effective interest method.
New Pronouncements
The FASB issued Emerging Issues Task Force Issue No. 04-2, Whether Mineral Rights Are Tangible or Intangible Assets ("EITF 04-2"). In this issue, the Task Force reached the consensus that mineral rights are tangible assets. This consensus differed from the requirements of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets which characterize mineral rights as intangible assets. As a result, the FASB amended SFAS No. 141 and SFAS No. 142 to eliminate this inconsistency. The Company accounts for leased coal mineral interests as tangible assets in owned and leased mineral rights, net of accumulated depletion as presented on the consolidated balance sheet, and in accordance with EITF 04-2.
In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4 ("SFAS No. 151"). The Statement amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). The provisions of this statement are effective for fiscal years beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on its financial statements.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment ("SFAS No. 123R"), which replaces SFAS No. 123, and supersedes APB No. 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair value at the grant date beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. SFAS No. 123R generally requires companies to measure the cost of employee services received in exchange for an award of equity instruments (such as stock options and restricted stock) based on the grant-date fair value of the award, and to recognize that cost over the period during which the employee is required to provide service (usually the vesting period of the award). Under SFAS No. 123R, the Company must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at date of adoption. The transition provisions of SFAS No. 123R allow adoption on a "modified prospective" basis or a "modified retrospective" basis. The "modified prospective" method requires compensation expense be recorded for all share-based payments granted after the effective date and for the unvested portion of stock awards granted prior to the effective date at the beginning of the first quarter of adoption of SFAS 123R. The "modified retrospective" method requires compensation expense be recorded in the manner discussed above and permits restatement for all periods for which SFAS No. 123 was effective. The impact of adopting SFAS No. 123R can not be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had the Company adopted SFAS No. 123R during the prior period, the impact of that standard would have approximated the impact of SFAS No. 123 as described above under "Stock-Based Compensation." When SFAS No. 123R is adopted, the Company may elect to change the valuation method or
assumptions and such changes could have a material impact on the amount of stock-based compensation the Company records.
In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions ("SFAS No. 153"). The statement amends the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged and further eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. Provisions of this statement are effective for fiscal periods beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on its financial statements.
In March 2005, the Emerging Issues Task Force reached consensus on Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry ("EITF No. 04-6") concluding that post-production stripping costs are a component of mineral inventory costs subject to the provisions of the American Institute of Certified Public Accountants Accounting Research Bulletin No. 43, Restatement and Revision of Accounting Research Bulletins, Chapter 4, Inventory Pricing, ("ARB No. 43"). Based upon this consensus, post production stripping costs are considered costs of the extracted minerals under a full absorption costing system and are recognized as a component of inventory to be recognized in costs of sales in the same period as the revenue from the sale of the inventory. In addition, capitalization of such costs would be appropriate only to the extent inventory exists at the end of a reporting period. The guidance in this consensus will be effective for financial statements issued for fiscal years beginning after December 15, 2005, with early adoption permitted. The Company is currently evaluating this consensus and has not determined its impact to the consolidated financial statements.
Reclassifications
Certain amounts in prior periods presented have been reclassified to conform to the 2004 presentation.
Note 4. Acquisition of RAG
On July 30, 2004, the Company, through its indirect wholly owned subsidiary, FCC and pursuant to the terms of the Stock Purchase Agreement acquired 100% of the outstanding common shares of all of the direct and indirect subsidiaries of RAG engaged in coal mining in North America for a purchase price of approximately $967,300 (which is net of a $8,005 purchase price adjustment that was received in October 2004) plus associated transaction costs of approximately $19,618. In conjunction with the acquisition, the Company issued new 71/4% Senior Notes due 2014 (the "Notes") and entered into a new senior secured credit facility consisting of a term loan facility and revolving credit facility (the "Senior Credit Facility"), the net proceeds of which were used to finance the acquisition and to provide for on-going working capital requirements.
The purchase price along with the associated transaction costs were funded by:
•$196,000 of cash from shareholder's equity contributed to the Company and its subsidiaries FC2 and FCC by LLC;
•$300,000 of cash proceeds from the Notes issued by Foundation PA Coal Company ("Foundation PA") described below;
•$530,000 of cash proceeds from the Senior Credit Facility issued by Foundation PA, consisting of $470,000 from the term loan and a $60,000 draw from the revolving credit facility, both discussed below. The $60,000 draw from the revolving credit facility was repaid with available cash subsequent to the acquisition.
In connection with the debt financing, the Company incurred $28,573 of debt issuance costs.
The Stock Purchase Agreement contains customary seller representations and warranties of RAG, customary buyer representations and warranties of FCC and customary covenants and other agreements between RAG and FCC.
The Stock Purchase Agreement provides for indemnification for losses relating to specified events, circumstances and matters. RAG has agreed to indemnify FCC from certain liabilities, including:
•any losses arising from the inaccuracy of any representation or the breach of any warranty of RAG contained in the Stock Purchase Agreement;
•any losses arising from breaches or defaults in the performance of any covenant undertaking or other agreement or obligation of RAG pursuant to the Stock Purchase Agreement;
•any liabilities (including costs and expenses) arising out of or related to any debt of any of the companies acquired by FCC outstanding as of the closing of the acquisition;
•any liabilities of certain entities operating in Colorado that were sold by RAG American Coal Company, LLC, formerly RAG's indirect subsidiary to a third party under a stock purchase agreement dated as of February 29, 2004, including liabilities resulting from their operations, properties or assets, and any liabilities under that stock purchase agreement and from the spin-off of certain assets and liabilities from certain employee benefit plans of RAG American Coal Company, LLC in connection therewith; and
•certain tax liabilities, including liabilities for taxes related to pre-closing tax periods.
The Stock Purchase Agreement does not allow FCC to make a claim for indemnification for any loss relating to a breach of a representation, warranty or covenant unless the losses for any claim or series of related claims exceed $1,500 (other than for losses relating to certain specified representations and warranties and covenants). RAG's indemnification obligations with respect to breaches of representations, warranties and covenants are subject to a deductible for the first $15 million in damages (other than for losses relating to certain specified representations, warranties and covenants not subject to the deductible). After FCC has incurred damages as a result of breaches of representations, warranties and covenants contained in the Stock Purchase Agreement that are subject to the deductible in excess of the deductible, RAG is required to indemnify FCC for the amount by which such claims for indemnity or damages exceed the deductible up to a $200,000 cap (other than for losses relating to certain specified representations, warranties and covenants not subject to the cap).
In connection with the acquisition Blackstone, First Reserve and AMCI (the "Sponsors") entered into a transaction fee and monitoring agreement with FCC relating to certain monitoring, advisory and consulting services under the monitoring agreement. In addition, FCC paid a transaction and advisory fee to the Sponsors in an aggregate amount of $11,700 upon the completion of the acquisition. This payment was included in the direct costs associated with the acquisition. Under the monitoring agreement, FCC agreed to pay to the Sponsors an aggregate annual monitoring fee of approximately $2,000, and reimbursed the Sponsors for their out-of-pocket expenses. The Company therefore paid the
Sponsors $2,000, which is included in selling, general and administrative expenses for the period ended December 31, 2004. As a result of the IPO, the monitoring agreement terminated and the Sponsors received a termination payment equal to $2,000, which was included in the offering expenses and charged to additional paid-in capital during the period ended December 31, 2004. FCC agreed to indemnify the Sponsors and their respective affiliates, directors, officers and representatives for any and all losses relating to the services contemplated by the transaction and monitoring fee agreement and the engagement of the Sponsors pursuant to, and the performance by them of the services contemplated by, the transaction and monitoring fee agreement.
The acquisition was designed to create a platform for growth and for delivering superior returns to shareholders. As a result of the acquisition and the IPO, the Company believes that it will be able to increase earnings and cash flows by taking advantage of current favorable industry market dynamics to maximize opportunities from our existing operations as well as to selectively expand existing operations and potentially further develop its coal reserves. Maintaining its commitment to operational excellence, productivity and cost improvement is also a key strategy in its efforts to increase earnings and cash flows. The results of operations of the acquired business will be included in the Company's statement of operations from the date of acquisition forward.
The acquisition was accounted for using the purchase method of accounting whereby identifiable assets acquired and liabilities assumed were recorded at their fair market values as of the date of acquisition. The purchase price allocation is preliminary and will be finalized once the independent third-party appraisal is completed. The Company expects completion of these appraisals during the first half of 2005. The final purchase price allocation may differ from the initial allocation presented below.
The following table summarizes the preliminary purchase price allocation based on fair values of the assets acquired and liabilities assumed at the date of acquisition:
Cash and cash equivalents, accounts receivable, other current assets and accounts payable and accrued expenses were stated at historical carrying values. Given the short-term nature of these assets
and liabilities, it was determined that these historical carrying values approximate fair value. The Company's projected pension, post-retirement and post-employment benefit obligations and assets have been reflected in the current allocation of purchase price at the projected benefit obligation less plan assets at fair market value, based on independent actuaries engaged by the Company. Deferred income taxes have been provided in the consolidated balance sheet based on the Company's best estimates of the tax versus book basis of the assets acquired and liabilities assumed, as adjusted to estimated fair values. Owned surface lands, inventory, plant, equipment, mine development costs, owned and leased mineral rights and coal supply agreements have been recorded at estimated fair value based on work performed by independent valuation specialists as of the date of the acquisition.
The purchase price allocation was completed based upon preliminary analysis provided by an independent appraisal performed by a reputable consulting firm well known in the industry. Certain judgments and estimates by the Company regarding future cash flows from individual mine sites and other plans are integral to the valuations performed by the valuation specialists.
The following pro forma data reflect the consolidated results of operations of the Company as if the acquisition had taken place on January 1, 2004 and 2003, respectively. The pro forma information incorporates the accounting for the acquisition, incuding but not limited to, the application of purchase accounting for coal supply agreements, owned and leased mineral rights, employee benefit liabilities and property, plant and equipment. The pro forma information may not be indicative of actual results.
Pro forma basic and diluted common shares outstanding include all shares issued in connection with the formation of the Company, the Company's initial public offering and stock dividends declared as if they were issued or declared as of the beginning of each period presented. All stock options were granted at or above fair value and as such, are not considered to have a dilutive effect on the pro forma earnings per share computation.
Note 5. Inventories
Inventories consisted of the following at December 31:
Saleable coal represents coal stockpiles ready for shipment to a customer. Raw coal represents coal that requires further processing prior to shipment. Work-in-process consists of costs incurred to remove overburden above an unmined coal seam as part of the surface mining process and generally includes labor, supplies, operating overhead and equipment costs charged to operations as coal from the seam is sold.
Note 6. Other Current Assets
Other current assets consisted of the following at December 31:
Note 7. Property, Plant, Equipment and Owned and Leased Mineral Rights
Property, plant, equipment and owned and leased mineral rights consisted of the following at December 31:
Plant and equipment held under capital leases consisted of the following at December 31:
Depreciation, depletion and amortization expense of the Predecessor included $1,499, $1,054, and $566 for depreciation of assets held under capital leases for the years ended December 31, 2002, 2003 and the seven months ended July 29, 2004, respectively.
Note 8. Other Noncurrent Assets
Other noncurrent assets consisted of the following at December 31:
Note 9. Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consisted of the following at December 31:
Note 10. Long-Term Debt
Long-term debt consisted of the following:
As a result of the voluntary prepayment of $85,000 of the outstanding balance of the term loan facility discussed below, there are no scheduled debt maturities for 2005 through 2009. A $385,000 balloon installment is due at the July 30, 2011 maturity date of the Senior Credit Facility. The $300,000 71/4% Senior Notes are due July 30, 2014.
Successor:
Senior Credit Facility
On July 30, 2004, in connection with the acquisition as described in Note 4, the Company's subsidiary, Foundation PA Coal Company, entered into a Senior Credit Facility that consisted of a $470,000 term loan facility and a $350,000 revolving credit facility. The revolving credit facility, which expires in July 2009, bears interest based on an applicable margin plus the lenders base rate or LIBOR, at the Company's option. The revolving credit facility provides for up to $250,000 of letters of credit and for borrowings on same-day notice, referred to as swingline loans. The Senior Credit Facility required certain prepayments; however, on December 31, 2004, the Company voluntarily prepaid $85,000 of the outstanding balance of the term loan facility which eliminated any future payments prior to maturity. The voluntary payment consisted of $31,725 for all of the scheduled quarterly principal payments due on the term loan and $53,275 representing a portion of the balloon installment due at the July 30, 2011 maturity date. The Senior Credit Facility also requires the Company to pay a commitment fee to the lenders for the unutilized portion of the commitment equal to 0.50% per annum, which may be reduced upon the achievement of certain leverage ratios.
The terms of the Senior Credit Facility require the Company to maintain at least 50% of its outstanding debt at a fixed rate. To comply with the terms of the Senior Credit Facility, as further described in Note 16, on September 30, 2004, Foundation PA Coal Company (the "Issuer") entered into several 3-year interest rate swap agreements all with identical terms, in which it pays fixed interest
and receives variable interest on a notional amount of $85,000 of its term loan. Under these swaps, the Issuer receives a variable rate of 3-month US dollar LIBOR and pays a fixed rate of 3.26%. Settlement of interest payments occurs quarterly.
71/4% Senior Notes
On July 30, 2004, Foundation PA Coal Corporation, a wholly owned subsidiary of the Company, completed an offering of $300,000 of 71/4% Senior Notes due 2014 in a private placement transaction not subject to the registration requirements under the Securities Act of 1933. In December 2004, $300,000 of 71/4% Notes with identical terms was registered under the Securities Act of 1933 and all of the previously issued Notes were exchanged for these registered Notes. The Notes are guaranteed on a senior unsecured basis, by FCC, and rank equally with all of the Foundation PA Coal Corporation's other senior unsecured indebtedness. Interest on the Notes is payable on February 1 and August 1 of each year, beginning on February 1, 2005. The terms of the Notes contain restrictive covenants that limit Foundation PA Coal Corporation's ability to, among other things, incur additional debt, pay dividends, sell or transfer assets, and make certain investments. The Notes are redeemable prior to August 1, 2009 at a redemption price equal to 100% of the principal amount plus an applicable premium.
Terms of the Company's credit facilities contain financial and other covenants that limit the ability of the Company to among other things, effect acquisitions or dispositions and borrow additional funds and require the Company to, among other things, maintain various financial rations and comply with various other financial covenants, including maximum total leverage ratio, minimum interest coverage ratio and a maximum capital expenditures limitation. Failure by the Company to comply with such covenants could result in an event of default, which, if not cured or waived, could have a material adverse effect on the Company. The Company was in compliance with all financial covenants at December 31, 2004.
Predecessor:
Prior to the acquisition, the Predecessor paid off its outstanding long term indebtedness and incurred a loss on early extinguishment of debt in July of 2004 in the amount of $21,724. The outstanding long term indebtedness consisted of two Tranche A Notes, one each with DZ Bank and Dresdner Bank, a Tranche B note with KFW, term notes with both West LB and Deutsche Bank and a note payable to RAG Immobilien, an affiliated company.
The two Tranche A Notes were floating rate loans bearing interest at six-month LIBOR plus an applicable margin which matured in various amounts through July 30, 2009. The Predecessor had two interest rate swap agreements whereby it received, on a notional amount equal to the outstanding Tranche A balance, six-month LIBOR and paid 6.55% for the full term of the Tranche A Notes. Prior to February 29, 2004, these interest rate swaps were designated as hedges of the cash flows associated with the variable interest rates. On February 29, 2004, this interest rate hedge was undesignated and on April 27, 2004 was closed and settled with a cash payment. The Tranche B note was a fixed rate loan bearing interest at 7.03% that matured in various amounts through July 30, 2009. The notes were secured by substantially all the shares of Predecessor and its subsidiaries. The Tranche A and B Notes were subject to various affirmative and negative covenants, including minimum equity, equity to assets, debt service coverage, and leverage ratio requirements. The leverage ratio covenant permitted the
Predecessor to pledge cash against its outstanding indebtedness in order to satisfy the covenant with a minimum required pledge at all times of $20,000.
In April 2004, the two Tranche A Notes were paid off using proceeds from the sale of the RAG Colorado Business Unit and cash previously reported as cash on deposit with the Predecessor and pledged cash.
The Predecessor had term notes outstanding with both West LB and Deutsche Bank in equal amounts of $19,810 as of December 31, 2003. The term notes each had 2 tranches with interest at fixed rates of 7.22% and 7.57% and were payable in total annual installments of $9,460, with a final balloon payment due September 30, 2005.
The Predecessor had a note payable outstanding with RAG Immobilien, an affiliated company, for $38,000 at December 31, 2003 bearing interest at the fixed rate of 6.85%. Principal and accrued interest on the note were due September 30, 2005. As of December 31, 2003, accrued interest payable related to this note to RAG Immobilien was $18,093. For the years ended December 31, 2002 and 2003, the Company incurred interest expense of $3,366 and $3,596, respectively, on this note. For the seven months ended July 29, 2004, the Company incurred interest expense of $2,192.
Note 11. Other Noncurrent Liabilities
Other noncurrent liabilities consisted of the following at December 31:
Note 12. Employee Benefit Plans
Retirement Plans
The Company and certain of its subsidiaries sponsor two defined benefit pension plans which cover many of the salaried and nonunion represented hourly employees. Benefits are based on either the employee's compensation prior to retirement or stated amounts for each year of service with the Company.
Annual funding contributions to the plans are made as determined by consulting actuaries based upon the ERISA minimum funding standards. Plan assets consist of cash and cash equivalents, equity and fixed income securities, real estate mutual funds, private equity participations and participation in a hedge fund of funds.
The following table provides components of net periodic benefit cost for the indicated fiscal periods:
The following tables set forth the plans' benefit obligations, fair value of plan assets and funded status for the indicated fiscal periods:
Amounts recognized in the consolidated balance sheets consisted of the following as of:
Employer contributions payable to the plans at December 31, 2003 and 2004 of $26,300 and $5,944 respectively, are included in accrued expenses and other current liabilities.
The following table presents information applicable to plans with accumulated benefit obligations in excess of plan assets as of:
The provisions of SFAS No. 87 require the recognition of an additional minimum pension liability and related intangible asset to the extent that the accumulated benefit obligation exceeds plan assets. As of December 31, 2003 and 2004, the Company has recorded $45,118 and $518, respectively, to reflect the minimum pension liability. The current portion of the Company's pension liability, representing employer contributions payable to the plans, reflected in accrued expenses and other current liabilities at December 31, 2003 and 2004 was $26,300 and $5,944, respectively. The noncurrent portion of the Company's pension liability as reflected in other noncurrent liabilities at December 31, 2003 and 2004 was $25,787 and $43,987, respectively.
The weighted-average actuarial assumptions used in determining the benefit obligations at the end of each year were as follows:
The weighted-average actuarial assumptions used to determine net periodic benefit cost for each year were as follows:
The expected long-term return on plan assets is established at the beginning of each year by the Company's Benefits Committee in consultation with the plans' actuaries and outside investment advisor. This rate is determined by taking into consideration the plans' target asset allocation, expected long-term rates of return on each major asset class by reference to long-term historic ranges, inflation assumptions and the expected additional value from active management of the plans' assets. For the determination of net periodic benefit cost in 2005, the Company will utilize an expected long-term return on plan assets of 8.50%.
Assets of the two plans are commingled in the Foundation Coal Defined Benefit Plans Master Trust ("Master Trust") and are invested in accordance with investment guidelines that have been established by the Company's Benefits Committee in consultation with the Master Trust's outside investment advisor. As reported at December 31, 2003 and 2004, the plans' actual asset allocation and the target allocation for 2005 are as follows:
The asset allocation targets have been set with the expectation that the plans' assets will fund the plans' expected liabilities within an appropriate level of risk. In determining the appropriate target asset allocations the Benefits Committee has relied in part upon an Asset/Liability Study performed by the Master Trust's outside investment advisor. This study considers the demographics of the plans' participants, the funding status of each plan, the Company's contribution philosophy, the Company's business and financial profile and other associated risk factors. The plans' assets are periodically rebalanced among the major asset categories to maintain the asset allocation within a range of approximately plus or minus 5% of the target allocation.
During the seven months ended July 29, 2004 and for the period from February 9, 2004 (date of formation) through December 31, 2004, $6,345 and $9,541, respectively, of cash contributions were made to the defined benefit retirement plans.
All of our hourly employees in Pennsylvania and Illinois represented by the UMWA are covered under multi-employer defined benefit pension plans administered by the UMWA. Company contributions to these multi-employer plans and other contractual payments under the UMWA wage agreement, which are expensed when paid, are based primarily on hours worked and amounted to $333, $1,139, $610 and $672 for the years ended December 31, 2002, 2003, the seven months ended July 29, 2004 and for the period from February 9, 2004 (date of formation) through December 31, 2004, respectively.
The Company and certain of its subsidiaries maintain several defined contribution and profit sharing plans that cover a portion of its employees. Generally, under the terms of the plans, employees make voluntary contributions through payroll deductions and the Company makes matching and/or discretionary contributions, as defined by each plan. The Company's expense related to these plans was $4,764, $4,120, $2,496 and $1,737 for the years ended December 31, 2002, 2003, the seven months ended July 29, 2004 and for the period from February 9, 2004 (date of formation) through December 31, 2004, respectively.
Postretirement Health Care and Life Insurance Benefits
The Company sponsors plans that provide postretirement medical and life insurance benefits to many of our employees. The medical plans provide benefits for most employees who reach normal, or in certain cases, early retirement age while employed by the Company. The postretirement medical plans for salaried and nonunion represented hourly employees are contributory, with annual adjustments to retiree contributions and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan covering union employees is established by collective bargaining and is noncontributory.
In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 was enacted in the United States (the "Act"). The Act introduces a prescription drug benefit under Medicare Part D as well as a federal subsidy to sponsors of postretirement medical benefit plans such as the Company's plan as long as the provided benefits are actuarially equivalent to Medicare Part D. In the second quarter of 2004, the FASB finalized guidance with respect to accounting for the effects of the Act issued in FSP No. FAS 106-2. As of December 31, 2004, the Company has accounted for the effects of the Act in its measurement of its accumulated postretirement benefit obligation under purchase accounting and the effect of the offset to net periodic postretirement benefit costs. The Act reduced the Company's accumulated postretirement benefit obligation as of December 31, 2004 by approximately $68,700 and its
net periodic postretirement medical and life insurance benefit cost for the period from February 9, 2004 (date of formation) through December 31, 2004 by approximately $2,200.
The following table provides components of net periodic benefit cost for the indicated fiscal periods:
The following tables set forth the plans' benefit obligations, fair value of plan assets and funded status for the indicated fiscal periods:
The weighted-average assumptions used to determine the benefit obligation as of the end of each year were as follows:
The weighted-average assumptions used to determine net periodic benefit cost were as follows:
The following presents information about the weighted-average annual rate of increase in the per capita cost of covered benefits (i.e., health care cost trend rate):
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in the assumed health care cost trend rates would have the following effects as of and for the year ended December 31, 2004:
The Company's postretirement medical and life insurance plans are unfunded. During the seven months ended July 29, 2004 and for the period from February 9, 2004 (date of formation) through December 31, 2004, the Company paid $11,441 and $9,038, respectively, in postretirement medical and life insurance benefits.
The following represents expected future benefit payments, which reflect expected future service, as appropriate:
The Coal Industry Retiree Health Benefit Act of 1992 (Coal Act) provides for the funding of medical and death benefits for certain retired members of the UMWA through premiums to be paid by assigned operators (former employers). The Company treats its obligations under the Coal Act as participation in a multi-employer plan and recognizes the expense as premiums are paid. Expense
relative to premiums paid for the years ended December 31, 2002, 2003 and for the seven months ended July 29, 2004 and for the period from February 9, 2004 (date of formation) through December 31, 2004 was $533, $648, $529 and 606, respectively. As required under the Coal Act the Company's obligation to pay retiree medical benefits to its UMWA retirees is secured by letters of credit in the amount of $24,021 as of December 31, 2004.
Other Employee Benefit Plans
The Company has a number of postemployment plans covering severance, disability income and continuation of health care and life insurance benefits for disabled employees. At December 31, 2003 and 2004, the accumulated postemployment benefit liability for these plans consisted of a current amount of $1,675 and $1,489, respectively, included in accrued expenses and other current liabilities (wages and employee benefits) and a noncurrent amount of $7,677 and $6,365, respectively, included in other noncurrent liabilities.
The Company provides health care coverage for all of its employees under a number of plans. The Company is self-insured for the cost of these benefits. During the years ended December 31, 2002, 2003, for the seven months ended July 29, 2004 and for the period from February 9, 2004 (date of formation) through December 31, 2004, total claims expense of $20,355, $27,772, $15,919 and $12,808, respectively, was incurred, which represents the claims processed and an estimate for claims incurred but not reported.
Note 13. Pneumoconiosis (Black Lung) Expense and Trust
The Company is self-insured with respect to black lung medical and disability benefits to its employees and their dependants under the Federal Coal Mine Health and Safety Act of 1969, as amended, and various state workers' compensation statutes. The Company pays black lung benefits through the tax-exempt Foundation Coal Black Lung Benefits Trust (Trust). Assets of the Trust are invested solely in United States Treasury Notes and Bonds.
The present value of accumulated black lung obligations is calculated annually by an independent actuary. This calculation is based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and interest rates. These assumptions are derived from Company experience and credible outside sources.
Black lung expense is calculated using the service cost methodology of SFAS No. 106. Actuarial gains and losses and prior service costs are amortized over the remaining service lives of the active miners. The discount rate used to calculate the present value of accumulated benefits at December 31, 2004 is 6.00%. The assumed annual investment rate of return on the Trust assets is 6.00%. Benefits are assumed to increase at an annual rate of 3.50%.
The Company adopted the service cost method of accounting effective January 1, 2002. In previous years, the Company recognized an asset for the excess of fund assets over the present value of expected black lung benefits and expense related to black lung obligations. The pretax cumulative effect resulting from this change to a preferable accounting method was treated as a transition asset, to be amortized over the remaining service lives of the active miners.
The annual actuarial measurement date of the plan is September 30.
The following tables set forth the accumulated black lung benefit obligations, fair value of plan assets and funded status for the indicated fiscal periods:
The following table provides components of net periodic benefit cost (credit) for the indicated fiscal periods:
Note 14. Workers' Compensation Benefits
The Company is largely self-insured for workers' compensation claims. The liability for workers' compensation claims is an actuarially determined estimate of the ultimate losses to be incurred on such claims based on the Company's experience, and includes a provision for incurred but not reported losses. Adjustments to the probable ultimate liability are made annually based on subsequent developments and experience and are included in operations as they are determined. These obligations are secured by letters of credit in the amount of $36,502 and surety bonds in the amount of $10,427.
The liability for self-insured workers' compensation benefits at December 31, 2003 and 2004 was $25,174 and $28,655, respectively, including a current portion of $7,236 and $9,717, respectively, which is included in accrued expenses and other current liabilities. Workers' compensation expense for the years ended December 31, 2002, 2003, and for the seven months ended July 29, 2004 and for the period from February 9, 2004 (date of formation) through December 31, 2004 was $5,727, $12,157, $10,383 and $6,374, respectively, and is included in cost of coal sales in the consolidated statements of operations. 2002 workers' compensation expense includes $2,906 that represents the incurred but not reported actuarial estimate resulting from going self-insured at certain subsidiaries of RCP during 2002. In 2002, the Company entered into a settlement with the State of West Virginia for the existing self-insured workers' compensation liabilities at its closed Maple Meadow mine, resulting in a pretax gain from an accrual reversal of $5,595 which was recorded as an offset to workers' compensation expense.
Note 15. Stock-Based Compensation
On July 30, 2004, the Company's board of directors adopted the Foundation Coal Holdings, Inc. 2004 Stock Incentive Plan ("the Plan"), which is designed to assist the Company in recruiting and
retaining key employees, directors and consultants. The Plan permits the Company to grant to its key employees, directors and consultants stock options, stock appreciation rights, restricted stock grants or other stock-based awards. The shares under the Plan may be issued at an exercise price of no less than 100% of the fair market value of the Company's common stock on the date of grant. The Plan currently provides for the issuance of up to 5,978,483 shares of common stock. At December 31, 2004 options to acquire 3,536,432 shares of common stock had been issued to eight members of senior management of the Company; however, the Company intends to provide for additional grants to other key employees. Of the total options granted, there were 982,343 shares granted at an exercise price of $4.87 per share, which are subject to continued employment, vest and become exercisable on each December 31 beginning December 31, 2004 and ending on December 31, 2008. Additionally, there were 2,554,089 shares granted at an exercise price of $8.53 per share, which are subject to continued employment, vest and become exercisable on the eighth anniversary of the date of grant and provide for partial accelerated vesting each calendar year through December 31, 2008 upon the achievement of certain annual performance targets.
No stock-based employee compensation expense has been reflected in net earnings, as all options granted under this plan have been at an exercise price equal to or greater than the Company's estimate of the market value of the underlying stock on the date of grant. The fair market value of the Company's common stock was estimated by the board of directors to be approximately $4.87 per share at the time of the grants. As the Company's common stock was not then publicly traded, this fair market value was based on the per share price of the Company's common stock paid at the time of the acquisition, which was completed just prior to the grant of the options.
The following table summarizes the stock option activity for the year ended December 31, 2004:
The following table summarizes information about stock options outstanding at December 31, 2004, with exercise prices equal to the fair market value on the date of grant:
Note 16. Derivative Instruments and Hedging Activities
The Company's initial objective for holding or issuing derivative instruments is to mitigate its exposure to interest rate risk. The Company's strategy for minimizing interest rate exposure on variable rate debt is to lock into fixed rates of interest with pay-fixed, receive-variable interest rate swaps.
The Predecessor entered into an interest rate swap agreement effective June 20, 1999 to manage its exposure to fluctuations in interest rates relating to its outstanding variable rate debt. The contract's notional amount was $434,000 at inception, and declines semi-annually over the life of the contract in proportion to the Predeessor's outstanding balance on its related debt. Under the terms of the contract, the Predecessor will pay a fixed rate of 6.55% and receive six-month LIBOR which resets every 180 days. The maturity date of the contract is July 30, 2009. The interest rate swap agreement was designated as a cash flow hedge, and was designed to be entirely effective by matching the terms of the swap agreement with the debt. The base rate for both the debt and the swap is LIBOR and the instruments have the same renewal dates over the lives of the instruments.
As of December 31, 2003, the fair value of this cash flow hedge was $45,710 and was recorded as a noncurrent liability and the offsetting unrealized loss of $28,820, net of tax benefit, as of December 31, 2003, was recorded in accumulated other comprehensive income. The hedge continued to be fully effective in accordance with SFAS No. 133 until February 29, 2004.
Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. The market risk associated with interest-rate contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. In connection with the definitive Stock Purchase Agreement for the sale of the RAG Colorado Business Unit entered into on February 29, 2004, the Predecessor notified the holders of the variable rate notes of their intention to repay the notes. At this time, the interest rate swaps no longer qualified for hedge accounting treatment and in April 2004, the Predecessor settled the interest rate swaps. The total pre-tax charge related to settlement of the interest rate swaps was $48,854. Between February 29, 2004 and April 27, 2004, mark-to-market gains on the interest rate swaps were $5,804 and were included in other income.
On September 30, 2004, the Company entered into pay-fixed, receive-variable interest rate swap agreements on a notional amount of $85,000. The term of these swaps is for three years. Under these swaps, the Company receives a variable rate of three month US dollar LIBOR and pays a fixed rate of 3.26%. Settlement of interest payments occurs quarterly. The Company was required to enter into these swaps in order to maintain at least 50% of its outstanding debt at a fixed rate as required by the Senior
Credit Facility. These swap agreements essentially convert $85,000 of the Company's variable rate borrowings under the Senior Credit Facility to fixed rate borrowings for a three year period beginning September 30, 2004. The Company intends to designate these interest rate swaps as cash flow hedges of the variable interest payments due on $85,000 of its variable rate date through September 2007 under SFAS No 133, Accounting for Derivative Financial Instruments and Hedging Activities upon completion of the effectiveness testing and related documentation. At December 31, 2004, the fair value and carrying value of these swaps was a gain of $530.
By using derivative financial instruments to hedge exposures to changes in interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk for the Company. When the fair value of a derivative contract is negative, the Company owes the counterparty and, therefore, it does not possess credit risk. The Company minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties.
The Company uses short and long-term contracts to buy and sell coal. These contracts generally have fixed pricing and do not provide for net settlement and therefore are not considered derivative financial instruments.
Note 17. Fair Value of Financial Instruments
The estimated fair values of financial instruments under SFAS No. 107, Disclosures About Fair Value of Financial Instruments, are determined based on relevant market information. These estimates involve uncertainty and cannot be determined with precision. The following methods and assumptions are used to estimate the fair value of each class of financial instrument.
Cash and cash equivalents, cash on deposit with the Predecessor, cash pledged, trade accounts receivables, trade accounts payable, accrued expenses and other current liabilities: The carrying amounts approximate fair value because of the short maturity of these instruments.
Prepaid SO2 allowances: SO2 allowances are purchased by the Company to satisfy coal sales contractual obligations. The fair value is estimated based on current market prices as of December 31, 2003 and 2004.
Long-term receivables: The fair value is estimated based on expected future cash flows discounted at 4% in 2003 and 5.5% in 2004. The fair value is estimated based on the credit risk associated with the debtors.
Long-term debt: The fair value of long-term debt is estimated based on a current market rate of interest offered to the Company for debt of similar maturities.
Interest rate swap: The fair values of interest rate swap contracts were based on benchmark transactions entered into on terms substantially similar to those entered into by the Company. Based on these estimates as of December 31, 2003 and 2004, the Company would have paid $45,710 or received $530, respectively, if its interest rate swaps were terminated.
The estimated fair values of financial instruments at December 31 are as follows:
Note 18. Asset Retirement Obligations
The Company's mining activities are subject to various federal and state laws and regulations governing the protection of the environment. These laws and regulations are continually changing and are generally becoming more restrictive. The Company conducts its operations so as to protect the public health and environment and believes its operations are in compliance with all applicable laws and regulations. The Company has made, and expects to make in the future, expenditures to comply with such laws and regulations, but cannot predict the amount of such future expenditures. Estimated future reclamation costs are based principally on legal and regulatory requirements.
Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. As a result, the Company recognized a reduction in liabilities of $10,088; a decrease in mining properties and mineral rights, net of accumulated depletion, of $12,460 related to amounts recorded in previous asset purchase transactions from assumption of pre-acquisition reclamation liabilities; a decrease in net deferred tax liability of $891; and a cumulative effect of a change in accounting, net of tax of $1,481.
The following table describes all changes to the Company's asset retirement obligation ("ARO") from January 1, 2003, the date of adoption, through December 31, 2003:
On a pro-forma basis, assuming the application of SFAS No. 143 in 2002, the asset retirement obligation at January 1, and December 31, 2002 would have been $86,919 and $88,746, respectively.
The following table describes all changes to the Company's ARO from the acquisition date of July 30, 2004, through December 31, 2004:
The current portions of the asset retirement obligation liabilities of $6,399 and $4,398 at December 31, 2003 and 2004, respectively, are included in accrued expenses and other current liabilities. There were no assets that were legally restricted for purposes of settling asset retirement obligations at December 31, 2004 or 2003, respectively.
Note 19. Income Taxes
Total income tax expense (benefit) consisted of the following:
Income tax expense from continuing operations consisted of the following:
The following is a reconciliation between the amount determined by applying the United States federal income tax rate of 35% to income before income taxes and the actual income tax expense:
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consisted of the following at December 31:
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent on the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based on the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management has established a valuation allowance of $10,574 and $5,643 at December 31, 2004 and 2003, respectively. The established valuation allowance is specifically for Alternative Minimum Tax ("AMT") credits as the Company does not consider it more likely than not that the credits will be utilized. At the July 30, 2004 acquisition date, the Company recorded a valuation allowance of $7,552. The valuation allowance was increased by $3,022 subsequent to the acquisition date.
As of December 31, 2004, the Company has $56,071 of unused net operating loss carryforwards available for United States federal income tax purposes, which expire through 2023 and $10,574 million of alternative minimum tax credits which do not expire. In addition, the Company had $25,748 of state net operating loss carryforwards primarily expiring from 2014 to 2023. As a result of the ownership change experienced by the Company in 2004, the utilization of the net operating loss carryforwards is subject to an annual limitation.
State franchise tax expense for the years ended December 31, 2002, 2003, for the seven months ended July 29, 2004 and for the period from February 29, 2004 (date of formation) through December 31, 2004 was $808, $1,533, $484, and $708, respectively. State franchise taxes are included in cost of coal sales in the combined statements of operations.
Note 20. Stockholders' Equity and Earnings Per Share
Refer to Note 2 for discussion regarding the 2004 formation, recapitalization, change in ownership and initial public offering of the Company.
Common Stock
The Company has 100,000,000 authorized shares of $0.01 par value common stock of which approximately 41,363,000 shares were outstanding at December 31, 2004. Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. The holders of common stock do not have cumulative voting rights in the election of directors. Holders of common stock are entitled to ratably receive dividends if, as and when dividends are declared from time to time by the Board. Upon liquidation, dissolution or winding up, any business combination or a sale or disposition of all or substantially all of the assets, the holders of common stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and accrued but unpaid dividends and liquidation preferences on any outstanding preferred stock. The common stock has no preemptive or conversion rights and is not subject to further calls or assessment by the Company. There are no redemption or sinking fund provisions applicable to the common stock.
Preferred Stock
In addition to the common stock, the Board is authorized to issue up to 10,000,000 of $0.01 par value shares of preferred stock of which there were no issued and outstanding shares at December 31, 2004. The Board is authorized to determine the terms and rights, including the number of authorized shares, whether dividends (if any) will be cumulative or non-cumulative and the dividend rate, redemption or sinking fund provisions, conversion terms, prices and rates, and amounts payable on shares in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Company. The Board of Directors may also determine restrictions on the issuance of shares and the voting rights (if any) of the holders.
Stock Dividends
On December 8, 2004, the Board declared a stock dividend of 3,029,600 shares to be distributed in January 2005 to all shareholders of record on December 8, 2004. Additionally, the Board declared a stock dividend of 231,624 shares to be distributed in January 2005 to members of management. All earnings per share information in the consolidated financial statements and notes have appropriately reflected these stock dividends.
Earnings per Share
The following table provides a reconciliation of weighted average shares outstanding used in the basic and diluted earnings per share computations for the periods presented:
Note 21. Segment Information:
The Company produces primarily steam coal from surface and deep mines for sale to utility and industrial customers. The Company operates only in the United States with mines in all of the major coal basins. The Company has three reportable business segments: Northern Appalachia, consisting of two underground mines in southwestern Pennsylvania, Central Appalachia, consisting of 6 underground mines and two surface mines in southern West Virginia and the Powder River Basin, consisting of two surface mines in Wyoming. Corporate, Other and Eliminations includes an underground mine in Illinois, centralized sales functions, corporate overhead, business development activities, expenses for closed mines and the elimination of intercompany transactions. The Company evaluates the performance of its segments based on operating income.
Successor:
Operating segment results for the period from February 9, 2004 (date of formation) through December 31, 2004 were as follows:
Predecessor:
Operating segment results for the seven months ended July 29, 2004 were as follows:
Operating segment results for the year ended December 31, 2003 were as follows:
Operating segment results for the year ended December 31, 2002 were as follows:
Reconciliation of segment income from operations to consolidated income (loss) before income tax expense (benefit) is as follows:
Note 22. Related Party Transactions
Predecessor
The Company purchases longwall mining equipment for its underground mines, along with related repair parts and services, from DBT America, Inc. which is also a wholly owned subsidiary of RAG Coal International AG, the parent of the Predecessor. Such purchases are made on a competitive basis and management believes the transactions were concluded on similar terms to those prevailing among unaffiliated parties. During the years ended December 31, 2002, 2003, and the seven months ended July 29, 2004, purchases from DBT America, Inc. totaled $44,043, $20,268, and $11,138, respectively, including capital equipment purchases of $36,437, $15,070, and $9,391. At December 31, 2002 and 2003, the Company owed DBT America, Inc. $4,576 and $932, respectively, which amount is included in trade accounts payable and accrued expenses and other current liabilities. During 2003 the Company sold DBT America, Inc. $741 of used equipment and parts and had a receivable due from DBT America, Inc. of $2 at December 31, 2003. During 2004, the Company sold land and a building to DBT America, Inc. from one of the closed operations for $600.
CoalARBED International Trading (a general partnership), RAG Trading Americas Corporation and RAG Verkauf are related to the Company through indirect common ownership. Coal sales to these affiliates totaled $16,028, $17,024, and $13,358 for the years ended December 31, 2002, 2003, and for the seven months ended July 29, 2004, respectively. At December 31, 2002 and 2003, the Company had trade receivables of $2,507 and $1,046 due from these affiliates.
Riverton Coal Production ("RCP") collected $355, $472, and $200 in 2002, 2003, and 2004, respectively, from RAG Coal International AG pursuant to an agreement to reimburse premiums paid to the UMWA Combined Benefit Fund. The agreement ended July 29, 2004.
Related party affiliation with the aforementioned entities ceased at the transaction date of July 29, 2004.
Successor
Alpha Coal Sales, LLC is related to the Company through indirect common ownership. First Reserve and AMCI beneficially own a controlling interest in the parent entity of Alpha Coal Sales, LLC. Coal sales to this affiliate during 2004 totaled $9,704. The Company further had trade receivables of $667 at December 31, 2004.
Note 23. Lease and Mineral Royalty Obligations
Certain of the Company's mineral leases require minimum annual royalty payments, whereas others require royalty payments only at the time of production or shipment. A substantial amount of the coal mined by the Company is produced from reserves leased from the owner of the coal. The Company also leases certain office facilities under various operating lease agreements that expire through 2010 and have various renewal options.
Accrued minimum royalties that are not recoverable from future coal production consisted of the following at December 31:
Minimum future rental commitments and royalties under noncancelable leases are set forth in the table below:
Rent expense and mineral royalties charged to cost of coal sales were as follows:
Note 24. Other Revenues
Other revenues and income consisted of the following:
Note 25. Assets Held For Sale
The Company owns six locations that were closed in prior years due to geologic conditions or depletion of economic reserves. All these locations are currently in final reclamation at varying stages. Management has determined that these locations meet the held for sale criteria in SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Carrying values, which have been adjusted to fair value less costs to sell, include amounts for land and equipment of $3,964 and $6,019 as of December 31, 2003, and 2004, respectively. Timing of the sales for this land and equipment will depend on completion of reclamation and subsequent regulatory release and real estate and used equipment markets. These amounts are included in property, plant and equipment, net.
Note 26. Concentration or Credit Risk and Major Customers
The Company markets its coal principally to electric utilities in the United States. As of December 31, 2003 and 2004, trade accounts receivable from electric utilities totaled approximately $48,040 and $55,230, respectively. Credit is extended based on an evaluation of the customer's financial condition and collateral is generally not required. Credit losses are provided for in the consolidated financial statements and historically have been minimal. The Company is committed under long-term
contracts to supply coal that meets certain quality requirements at specified prices. The prices for some multi-year contracts are adjusted based on economic indices or the contract may include year-to-year specified price changes. Quantities sold under some contracts may vary from year to year within certain limits at the option of the customer. For the years ended December 31, 2002 and 2003, the Company's 10 largest customers accounted for 51% and 54% of total coal sales, respectively. For Predecessor and Successor periods in 2004, the Company's 10 largest customers accounted for approximately 56% of total coal sales with the largest customer being approximately 9%. The largest customer accounted for approximately 11% of total coal sales in 2003.
Note 27. Contingencies and Commitments
General
The Company follows SFAS No. 5, "Accounting for Contingencies," in determining its accruals and disclosures with respect to loss contingencies. Accordingly, estimated losses from loss contingencies and legal expenses associated with the contingency are accrued by a charge to income when information available prior to issuance of the financial statements indicates that it is probable that an asset had been impaired or a liability had been incurred and the amount of the loss can be reasonably estimated. If a loss contingency is not probable or reasonably estimable, disclosure of the loss contingency is made in the financial statements when it is at least reasonably possible that a loss may be incurred.
Asset Retirement Obligations (formerly Reclamation and Mine Closure)
At December 31, 2004, the Company's accruals for reclamation and mine closure totaled $104,600. The portion of the costs expected to be incurred within a year of $4,398 at December 31, 2004 is included in accrued expenses and other current liabilities. At December 31, 2004, these regulatory obligations are secured by surety bonds in the amount of $244,111. These surety bonds are partially collateralized by letters of credit issued by the Company.
Guarantees
Our former parent company, Cyprus Amax Minerals Company, remains a guarantor with regard to the following obligation included in the consolidated financial statements of the Company:
Future minimum royalties payable under leases through the first quarter 2006 to Blackhawk Coal Company, an affiliate of American Electric Power.
Under the terms of the Stock Purchase Agreement, dated May 12, 1999 between RAG Coal International AG and Cyprus Amax Mineral Company, the Predecessor guaranteed Cyprus Amax' performance under this obligation by issuing an irrevocable letter of credit to secure the minimum royalty payments still due. The Company assumed this guarantee in the acquisition. The amount of this letter of credit is reduced as the Company makes the scheduled payments. As of December 31, 2004 the letter of credit amount was $6,000.
Neweagle Industries, Inc. ("Neweagle") is a wholly-owned indirect subsidiary of the Company. Starting in early 2001, Neweagle supplied and sold coal to Arch Coal Sales Company, Inc. ("Arch Sales") pursuant to a Conditional Coal Supply Agreement dated October 1, 1996 (CCSA). This coal was in turn resold by Arch Sales under a separate and distinct Coal Sales Agreement dated October 1, 1989 ("Rocky Mount Contract") with Cogentrix of Rocky Mount, Inc. ("Cogentrix") as the buyer. On March 23, 2003, the Predecessor (now known as Foundation American Coal Holding, Inc.) conditionally issued to Arch Sales a Guaranty and Indemnity ("Guaranty") of Neweagle's performance under the CCSA, and also agreed to indemnify Arch Sales and its affiliates and other parties for any
liability related to the Rocky Mount Contract. As part of a global settlement of litigation relating to numerous issues between affiliates of the Predecessor and Arch Sales, a Mutual Release and Settlement Agreement ("MRSA") was executed and effective November 12, 2004. Pursuant to the MRSA, the CCSA and the Guaranty were terminated. Also pursuant to the MRSA, Neweagle agreed to continue selling and supplying coal to Arch in the quantities required under the Rocky Mount Contract for re-sale by Arch to Cogentrix thereunder. The MRSA also was executed by the Predecessor, (now known as Foundation American Coal Holding, Inc.) As a signatory to the MRSA, Foundation American Coal Holding, Inc. and Neweagle agreed to indemnify, defend, and save harmless Arch and its affiliates from any non-performance, default or breach of (i) Neweagle's obligation to supply coal to Arch Sales under the MSRA and (ii) for so long as the MRSA remains in force, any default, breach, or non-fulfillment of Arch Sales contract obligations under the Rocky Mount Contract as a result of acts or omissions (other than by Cogentrix) occurring on or after November 12, 2004.
Neweagle Industries, Inc., Neweagle Coal Sales Corp., Laurel Creek Co., Inc. and Rockspring Development, Inc. ("Sellers") are wholly-owned indirect subsidiaries of the Company. The Sellers sell coal to Birchwood Power Partners, L.P. ("Birchwood") under a Coal Supply Agreement dated July 22, 1993 (Birchwood Contract). Laurel Creek Co., Inc. and Rockspring Development, Inc. were parties to the Birchwood Contract since its inception, at which time those entities were not affiliated with Neweagle Industries, Inc., Neweagle Coal Sales Corp., or the Company. Effective January 31, 1994, the Birchwood Contract was assigned to Neweagle Industries, Inc. and Neweagle Coal Sales Corp. by AgipCoal Holding USA, Inc. and AgipCoal Sales USA, Inc., which at the time were affiliates of Arch Coal, Inc. Despite this assignment, Arch Coal, Inc. ("Arch") and its affiliates have separate contractual obligations to provide coal to Birchwood if Sellers fail to perform. Pursuant to an Agreement & Release dated September 30, 1997, the Predecessor (now known as Foundation American Coal Holding, Inc.) agreed to defend, indemnify, and hold harmless Arch and its subsidiaries from and against any claims arising out of any failure of Sellers to perform under the Birchwood Contract. By acknowledgement dated February 16, 2005, the Predecessor and Arch acknowledged the continuing validity and effect of the Agreement & Release dated September 30, 1997.
In the normal course of business, the Company is a party to guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, performance or surety bonds and other guarantees and indemnities, which are not reflected in the accompanying consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and likelihood of performance being required. In the Company's past experience, no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments and, therefore, is of the opinion that their fair value is zero.
Sales Commitments
A subsidiary of the Company has a contract to sell coal to a merchant power plant that it historically has supplied by purchasing coal from independent producers. The sales contract extends through 2019, with quarterly index price adjustments and market price re-openers every three years. Starting in 2000, as a result of significant increases in coal prices and a below-market contract price until a mid-2002 price re-opener, the Company's purchased coal cost was expected to exceed its contract price resulting in losses. An initial loss provision of $3,300 was recognized in 2000. Additional loss provisions of $1,362 and $1,500 were recorded in 2001 and 2002, respectively. At December 31, 2002, the accrued losses on this contract were $92. This amount was recorded in accrued expenses and other current liabilities.
During 2003, the Company recorded net losses of $1,228 associated with this contract. During 2004 the Company satisfied this contract from its own production and purchased coal. The Company did not incur net losses in 2004 supplying this agreement.
Contingencies
In November 2002, Horizon NR, LLC ("Horizon") filed a petition in bankruptcy seeking a reorganization. Due to certain contractual relationships with Horizon, the outcome of the proceeding had potential implications for the Company. Under a Stock Purchase and Sale agreement (the "SPA") dated May 28, 1998, Horizon was obligated to indemnify the Company for claims against the Company arising out of the business of entities that the Company sold to Horizon. In one such case, South Carolina Public Service Authority ("Santee Cooper") sought a ruling on the enforceability of an alleged guarantee by the Company of future obligations under a coal contract under which a subsidiary of Horizon was the seller. Horizon rejected the contract with Santee Cooper in the bankruptcy, but was to indemnify the Company for any claim based on this alleged guaranty. In July, 2004, the Predecessor reached an agreement with Santee Cooper in which they relinquished any claims based on the alleged guarantee of the Horizon subsidiary's future obligations, in exchange for a multi-year coal supply agreement from the Predecessor's Pennsylvania operations at prices below then prevailing market prices for new contracts of similar duration. The Predecessor recorded expense of $26,015 during the seven months ended 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. The Company assumed this agreement in the acquisition.
Horizon substantially honored its obligations under the SPA through June 30, 2004, but ultimately planned to reject the SPA in bankruptcy. As part of the Horizon bankruptcy proceeding, the Predecessor and its pertinent subsidiaries negotiated a Settlement Agreement and Mutual Release which addressed numerous open issues between the parties, including the impacts of the rejection of the SPA. That agreement was approved by the bankruptcy court on September 30, 2004. Based on the terms of that agreement and the information available at this time, management believes that any remaining contingencies related to the Horizon bankruptcy will not have a material adverse effect on the Company's financial position, results of operations or cash flows.
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 hundreds of 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 do have operations.
The claims against our entities are covered by insurance. Common defense counsel and experts are representing numerous defendants and costs are being shared. While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flow.
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 StatesDistrict 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.
Extensive regulation of the impacts of mining on the environment and related litigation has had and may have a significant effect on our costs of production and competitive position. Further regulations, legislation or litigation may also cause our sales or profitability to decline by hindering our ability to continue our mining operations, by increasing our costs, or by causing coal to become a less attractive fuel source.
Prior Acquisition Related Employee Liabilities Litigation Settlement
A dispute arose relating to a prior acquisition by the Predecessor over material inaccuracies in the financial statements and supporting data and calculations relating to various employee liabilities of an acquisition completed in 1999. A claim was filed in 2000 to recover additional liabilities not disclosed during the due diligence related to this 1999 acquisition and resultant purchase by the Predecessor. The Predecessor entered into a settlement agreement with the seller in February of 2003, whereby the Predecessor received $43,500 to fully settle this dispute. The amount of the settlement was recorded as other income in the twelve month period ended December 31, 2003.
Legal Proceedings
The Company is involved in various claims and other legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company's financial position, results of operations or cash flows.
Note 28. Discontinued Operations
On April 15, 2004, the Predecessor sold its wholly owned Colorado Business Unit comprised of the active Twentymile mine and certain inactive or closed properties located in Colorado and Wyoming to a subsidiary of Peabody Energy Corporation. The cash proceeds from the sale, prior to final purchase price adjustments, were $182,670. These proceeds were deposited to an escrow account at DZ Bank. In addition, $221,416 of the Predecessor's cash on deposit with the Predecessor was also deposited into this escrow account. On April 27, 2004, the escrow account balance of $404,162, including interest earned on the account of $76, was used to: (a) repay the Tranche A Notes due to DZ Bank and Dresdner Bank Luxembourg S.A. (Dresdner) in the combined amount of $358,000; (b) pay accrued interest on these notes in the amount of $1,495; and (c) settle the pay-fixed, receive-variable interest rate swaps for a payment of $44,667.
On July 13, 2004, the Predecessor received an additional $534 representing the final purchase price adjustments. With this receipt, the Company realized a pre-tax gain on sale of the Colorado Business Unit of $25,696.
Historically the Predecessor has not allocated interest expense to its operating units. In accordance with EITF 87-24, Allocation of Interest to Discontinued Operations, the Company allocated a portion of its consolidated interest expense to discontinued operations of the Colorado Business Unit. This allocation was based upon the proportion of the net assets of the discontinued operation in relation to total consolidated assets. Interest allocated for the periods presented was $4,661 and $3,682 for the years ended December 31, 2002 and 2003, respectively, and $643 for the period January 1 through July 29, 2004.
Summarized operating information of the Predecessor's discontinued operations of the Colorado Business Unit is as follows:
Note 29. Balance Sheet Classification and Accounting for Long-Term Debt and Pay-Fixed, Receive-Variable Interest Rate Swaps.
The arrangements to sell the RAG Colorado Business Unit to a subsidiary of Peabody Energy Corporation required RAG American Coal Company to repay the Tranche A Notes due to DZ Bank and Dresdner. Therefore, the full amount of these notes, $179,000 for each bank, were paid in April 2004 with proceeds from the sale of the Colorado Business Unit and cash on deposit with the Predecessor.
Since these notes were not held to their full maturity, the associated pay-fixed, receive-variable interest rate swap ceased to qualify for hedge accounting under SFAS No. 133. This change in accounting was effective February 29, 2004. On that date, the pre-tax fair value of the swap of $48,854 was charged to expense resulting from termination of hedge accounting for interest rate swaps with a corresponding gain in other comprehensive income. Between February 29, 2004 and April 27, 2004, the change in the fair value of the interest rate swaps, a gain of $5,804, was recognized as other income.
Note 30. Unaudited Supplementary Data
Quarterly Data
The following is a summary of selected quarterly financial information (unaudited):
(1)Revenue less cost of coal sales, selling general and administrative expenses, accretion on asset retirement obligation, depreciation, depletion and amortization and amortization of coal supply agreements. Note 31. Subsequent Events (Dated as of March 29, 2005)
On February 15, 2005, the Board of Directors of the Company declared a quarterly dividend of $0.04 per share on the Company's common stock payable on March 28, 2005 to shareholders of record on March 7, 2005.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934, as amended, is recorded, processed, evaluated, summarized and reported accurately within the time periods specified in the Securities and Exchange Commission's (SEC) rules and forms. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. An evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operations of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based upon that evaluation as of the end of the period covered by this report, the CEO and CFO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic SEC filings. The conclusions of the CEO and CFO from this evaluation were communicated to the Audit Committee. In connection with this evaluation, there were no breaches of such controls that would require disclosure to the Audit Committee or our auditors.
Changes in Disclosure Controls. There were no significant changes in our disclosure controls or in other factors that could significantly affect these disclosure controls in the last fiscal quarter of 2004. Management is not aware of any material weaknesses; therefore, there were no corrective actions to be taken.
Sarbanes-Oxley Act of 2002 Section 404. During the year ended December 31, 2004, we did not meet the definition of an Accelerated Filer because we have been a public company subject to the reporting requirements of Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended, for less than twelve months and we have not previously filed an Annual Report on Form 10-K. We are required to comply with the final Section 404 Rule of the Sarbanes-Oxley Act of 2002 in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The sections of our 2005 Proxy Statement entitled "Nominees for Directors," "Director Independence," "Board and its Committees," "Executive Officers," "Section 16(a) Beneficial Ownership Reporting Compliance," and "Code of Business Conduct and Ethics" are incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The sections of our 2005 Proxy Statement entitled "Director Compensation," "Compensation Committee Interlocks and Insider Participation," "Executive Compensation and Related Information-Summary Compensation Table," "Executive Compensation and Related Information-Option Grants,"
"Executive Compensation and Related Information-Option Exercises," "Executive Compensation and Related Information-Employment Agreements and Termination and Change in Control Provision," "Executive Compensation and Related Information-Pension Plan Information," "Board and Its Committees Compensation Committee Report," and "Stock Ownership-Stock Performance Graph" are incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The sections of our 2005 Proxy Statement entitled "Executive Compensation and Related Information-Equity Compensation Plan Information," and "Stock Ownership-Ownership by largest holders, directors and officers" are incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The section of our 2005 Proxy Statement entitled "Related Party Transactions-Certain Relationships and Related Transactions" is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The section of our 2005 Proxy Statement entitled "Fees of Independent Accountants" is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
15(a)(1) Consolidated Financial Statements
The financial statements filed as part of this report are included in the Index to the Financial Statements under Item 8 of this Annual Report on Form 10-K.
15(a)(2) Financial Statement Schedules. Except as set forth below, all other schedules are omitted because they are not required or because the information is provided elsewhere in the consolidated financial statements and notes thereto.
Foundation Coal Holdings, Inc.
Schedule II-Valuation and Qualifying Accounts
(1)Reserves utilized
(2)Net change in reserve for obsolesence based on carrying value of the material and supplies inventory and the length of time the items are maintained in the inventory.
(3)At the July 30, 2004 acquisition date, the Company recorded a valuation allowance of $7,552 for AMT credits that the Company does not consider more likely than not will be utilized. The valuation allowance was increased by $3,022 subsequent to the acquisition date and is included in the balance at December 31, 2004. The previous valuation allowance of $4,561, which pertained to certain net operating loss carryforwards, was released in the seven months ended July 29, 2004 as substantially all the net operating loss carryforwards were realized by a subsidiary of RAG American Coal Holding, Inc. The remaining balance of $1,082 at July 29, 2004 was eliminated at the July 30, 2004 acquisition date. 15(a)(3) Exhibits.
EXHIBIT INDEX
Exhibit No.
Description of Exhibit
2.1*
Stock Purchase Agreement, dated as of May 24, 2004, between RAG Coal International AG and Foundation Coal Corporation (formerly known as American Coal Acquisition Corp.)
2.2*
Agreement and Plan of Merger, dated as of August 9, 2004, between Foundation Coal Holdings, LLC and Foundation Coal Holdings, Inc.
3.1*
Form of Amended and Restated Certificate of Incorporation of Foundation Coal Holdings, Inc.
3.2*
Form of Amended and Restated By-laws of Foundation Coal Holdings, Inc.
4.1*
Form of certificate of Foundation Coal Holdings, Inc. common stock
4.2*
Amended and Restated Stockholders Agreement, dated as of October 4, 2004, by and among Foundation Coal Holdings, Inc., Blackstone FCH Capital Partners IV, L.P., Blackstone Family Investment Partnership IV-A L.P., First Reserve Fund IX, L.P., AMCI Acquisition, LLC and the management stockholders parties thereto
10.1*
Credit Agreement, dated as of July 30, 2004, among FC2 Corp. and Foundation Coal Corporation, as Parent Guarantors, Foundation PA Coal Company, as Borrower, the Lenders party thereto, Citicorp North America, Inc., as Administrative Agent and Collateral Agent, UBS AG, Stamford Branch, Bear Stearns Corporate Lending Inc. and Natexis Banques Populaires, as co-Documentation Agents, Citigroup Global Markets Inc. and Credit Suisse First Boston, as Co-Syndication Agents and Citigroup Global Markets Inc. and Credit Suisse First Boston, as Joint Lead Arrangers and Joint Book Managers
10.1.1*
Amendment No. 1 to Credit Agreement, dated as of November 12, 2004, among FC2 Corp., Foundation Coal Corporation, Foundation PA Coal Company, Citicorp North America, Inc. and the Lenders party thereto
10.2*
Guarantee and Collateral Agreement, dated as of July 30, 2004, among FC2 Corp., Foundation Coal Corporation, Foundation PA Coal Company as Borrower, the Subsidiary Parties party thereto and Citicorp North America, Inc., as Collateral Agent
10.3*
Registration Rights Agreement dated as of July 30, 2004, by and between Foundation Coal Holdings, LLC., a Delaware corporation (the "Company"), the Sponsor Stockholders, the Investor Stockholders and the Management Stockholders and any other Person that shall from and after the date hereof acquire or otherwise be the transferee
10.4*
Senior Notes Indenture, dated as of July 30, 2004, among Foundation PA Coal Company, the Guarantors named therein and The Bank of New York, as Trustee
10.5*
Foundation Coal Holdings, Inc. 2004 Stock Incentive Plan
10.6*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and James F. Roberts
10.7*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and Frank J. Wood
10.8*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and James J. Bryja
10.9*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and John R. Tellmann
10.10*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and Greg A. Walker
10.11*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and Klaus-Dieter Beck
10.12*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and James A. Olsen
10.13*
Employment Agreement, dated July 30, 2004, by and between Foundation Coal Corporation and Michael R. Peelish
10.14*
Federal Coal Lease WYW-0317682: Belle Ayr Mine
10.15*
Federal Coal Lease WYW-78629: Belle Ayr Mine
10.16*
Federal Coal Lease WYW-80954: Belle Ayr Mine
10.17*
Federal Coal Lease WYW-0313773: Eagle Butte Mine
10.18*
Federal Coal Lease WYW-78631: Eagle Butte Mine
10.19*
Federal Coal Lease WYW-124783: Eagle Butte Mine
10.20*
Employment Agreement, dated January 1, 2002, by and between RAG American Coal Holding, Inc. and Thomas Lien; Change of Control Agreement, dated January 1, 2002, by and between RAG American Coal Holding, Inc. and Thomas Lien
12.1
Statement re computation of Ratio of Earnings to Fixed Charges**
21.1*
List of Subsidiaries
23.1**
Consent of Ernst & Young LLP
24**
Powers of Attorney
31.1**
Certification of periodic report by Foundation Coal Holdings, Inc's Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2**
Certification of periodic report by Foundation Coal Holdings, Inc's Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification of periodic report by Foundation Coal Holdings, Inc's Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of periodic report by Foundation Coal Holdings, Inc's Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*Previously filed as an exhibit to the Company's Registration Statement on Form S-1 (File No. 333-118427) and incorporated by reference.
**Filed herewith.
SIGNATURES
Name
Title
/s/ JAMES F. ROBERTS James F. Roberts
President, Chief Executive Officer
and Director (Principal Executive
Officer)
/s/ FRANK J. WOOD Frank J. Wood
Senior Vice President and Chief
Financial Officer (Principal Financial
and Accounting Officer)
* Joshua H. Astrof
Director
* David I. Foley
Director
* Alex T. Krueger
Director
* William E. Macaulay
Chairman of the Board and Director
* Prakash A. Melwani
Director
* Hans J. Mende
Director
* William J. Crowley, Jr.
Director
* Joel Richards, III
Director
/s/ GREG A. WALKER Greg A. Walker, Attorney-in-fact
DOCUMENTS INCORPORATED BY REFERENCE
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
PART I
GLOSSARY OF SELECTED TERMS
PART II
RISK FACTORS
FOUNDATION COAL HOLDINGS, INC AND SUBSIDIARIES CONSOLIDATED FINANCIAL STATEMENTS INDEX
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
Foundation Coal Holdings, Inc. and Subsidiaries (Successor in interest to Foundation Coal Holdings, LLC) Consolidated Balance Sheets
Foundation Coal Holdings, Inc. and Subsidiaries (Successor in interest to Foundation Coal Holdings, LLC) Statements of Consolidated Operations and Comprehensive Income (Loss)
Foundation Coal Holdings, Inc. and Subsidiaries (Successor in interest to Foundation Coal Holdings, LLC) Statements of Consolidated Cash Flows
Foundation Coal Holdings, Inc. and Subsidiaries (Successor in interest to Foundation Coal Holdings, LLC) Notes to Consolidated Financial Statements (Dollars in thousands, except per share data)
PART III
PART IV
Foundation Coal Holdings, Inc. Schedule II-Valuation and Qualifying Accounts
EXHIBIT INDEX
SIGNATURES