ITEM 1. BUSINESS.
Overview
We are the fourth largest coal producer in the United States, based on tons produced. We operate a diverse group of thirteen mines located in Wyoming, Pennsylvania and West Virginia. For the year ended December 31, 2007, we sold 73.6 million tons of coal, including 71.8 million tons that were produced and processed at our operations. As of December 31, 2007, we had approximately 1.6 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 are primarily a supplier of steam coal to U.S. 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 89% of our coal sales revenue in 2007. We also sell metallurgical coal to steel producers; metallurgical sales accounted for 3% of our coal sales volume and 11% of our coal sales revenue in 2007.
As of January 25, 2008, we had a total sales backlog of over 272 million tons of coal, and our coal supply agreements have remaining terms ranging from less than one year to 14 years. For 2007, we sold approximately 79% of our sales volume under long-term coal supply agreements. We consider sales commitments with a duration of longer than twelve months as a “long-term” contract as opposed to spot sales agreements with a duration of twelve months or less. As of January 25, 2008, we had sales and price commitments for approximately 94% of our planned 2008 shipments, approximately 68% of our planned 2009 shipments, approximately 35% of our planned 2010 shipments and approximately 13% of our planned 2011 shipments.
Competitive Strengths
We believe that the following competitive strengths enhance our prominent market position in the United States:
We are the fourth largest coal producer based on tons produced in the United States and have significant coal reserves. Based on 2007 production of 71.8 million tons, we are the fourth largest coal producer in the United States. As of December 31, 2007, we controlled approximately 1.6 billion tons of proven and probable coal reserves. Based on these reserve estimates and our actual rate of production during the year ended December 31, 2007, we have a total reserve life of approximately 22 years.
We have a diverse portfolio of coal-mining operations and reserves. We operate a total of 13 mines in the Powder River Basin, Northern Appalachia and Central Appalachia, selling coal to dozens of domestic and foreign electric utilities, steel producers and industrial users. We are the only producer with significant operations and major reserve blocks in both the Powder River Basin and Northern Appalachia, two U.S. coal production regions for which future demand is expected to increase. We believe that this geographic diversity provides us with a significant competitive advantage, allowing us to source coal from multiple regions to meet the needs of our customers and reduce their transportation costs.
We operate highly productive mines and have had strong EBITDA margins. We believe our focus on productivity has helped contribute to our strong EBITDA margins for fiscal years ended 2005, 2006 and 2007. Our strategic investment in equipment and technology has increased the efficiency of our operations, which we believe reduces our costs and provides us with a competitive advantage. Maintaining our low-cost position enables us to maximize our profitability in all coal pricing environments.
We are a recognized industry leader in safety and environmental performance. Our focus on safety and environmental performance results in a lower likelihood of disruption of production at our mines, which leads to higher productivity and improved financial performance. We operate some of the nation’s safest mines, with 2007 total injury incident rates, as tracked by the Mine Safety and Health Administration (“MSHA”), below industry averages.
We have long-standing relationships and long-term contracts with many of the largest coal-burning utilities in the United States. We supply coal to numerous power plants operated by a diverse group of electricity generators across the country. We believe we have a reputation for reliability and superior customer service that has enabled us to solidify our customer relationships.
Our management team has a track record of success during our long operating history. Our management team has a proven record of generating free cash flow, increasing productivity, reducing costs, developing and maintaining long-standing customer relationships and effectively positioning us for future growth and profitability. We operated as a stand-alone subsidiary of privately held RAG Coal International AG from 1999 until becoming an independent company on July 30, 2004. Our senior executives have an average of approximately 26 years of experience in the coal industry, including an average of 17 years of experience operating our assets when owned by us and our predecessors.
Business Strategy
Our objective is to increase shareholder value through sustained earnings and cash flow growth. Our key strategies to achieve this objective are described below:
Maintaining our commitment to operational excellence as a low-cost producer. We seek to maintain our productivity leadership with an emphasis on lowering costs by continuing to invest selectively in new equipment and advanced technologies, such as our previous investments in underground diesel equipment, increased longwall face widths and a larger shield system. We will continue to focus on profitability and efficiency by leveraging our significant economies of scale, large fleet of mining equipment, information technology systems and coordinated purchasing and land management functions. In addition, we continue to focus on productivity through our culture of workforce involvement by leveraging our strong base of experienced, well-trained employees.
Capitalizing on favorable industry dynamics through a balanced approach to selling our coal. The fundamentals of the current U.S. coal market are among the strongest in the past decade resulting in a favorable coal pricing environment which, based on current forward coal prices, we believe will continue for the foreseeable future. We employ a balanced approach to selling our coal, including the use of long-term sales commitments for a portion of our future production while maintaining uncommitted planned production to capitalize on favorable future pricing environments.
Selectively expanding our production and reserves. Given our broad scope of operations and expertise in mining in major coal-producing regions in the United States, we believe that we are well-situated to capitalize on the expected continued growth in U.S. and international coal consumption by evaluating growth opportunities, including (i) expansion of production capacity at our existing mining operations, (ii) further development of existing significant reserve blocks in Northern Appalachia and Central Appalachia, and (iii) potential strategic acquisition opportunities that arise in the United States or internationally. We will prudently act to expand our reserves when appropriate. For example, we increased our reserve position by obtaining mining rights to federal coal reserves adjoining our current operations in Wyoming through the Lease By Application (“LBA”) process.
Continuing to provide a mix of coal types and qualities to satisfy our customers’ needs. By having operations and reserves in three major coal producing regions, we are able to source coal from multiple mines to meet the needs of our domestic and international customers. Our broad geographic scope and mix of coal qualities provide us with the opportunity to work with many leading electricity generators, steel companies and other industrial customers across the country.
Continuing to focus on excellence in safety and environmental stewardship. We intend to maintain our recognized leadership in operating some of the safest mines in the United States and in achieving environmental excellence. Our ability to minimize lost-time injuries and environmental violations improves our operating efficiency, which directly improves our cost structure and financial performance.
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. The combined coal mining businesses were consolidated under Cyprus Amax Coal Company at the time of the 1993 merger.
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 (renamed RAG Coal International AG (“RAG”)). After the closing of this transaction in 1999, our parent holding company was RAG American Coal Holding, Inc.
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. Foundation Coal Holdings, Inc. was the surviving entity in this merger. On December 9, 2004, Foundation Coal Holdings, Inc. completed an initial public offering of 24,121,900 shares of common stock and became the entity we refer to herein as the “Public Parent.”
On September 19, 2005, Foundation Coal Holdings, Inc. completed a secondary offering and partial exercise of the over-allotment shares in which its sponsors, First Reserve IX, L.P. (“First Reserve”), The Blackstone Group (“Blackstone”) and AMCI III, LLC sold an aggregate of 10,260,500 shares of common stock. Foundation Coal Holdings, Inc. did not sell any shares of common stock through this offering, nor did Foundation Coal Holdings, Inc. receive any proceeds from the sale.
On January 24, 2006, all of the remaining shares of common stock of Foundation Coal Holdings, Inc. were distributed by affiliates of the Public Parent’s sponsors, Blackstone and First Reserve, to their limited and other partners.
Coal Mining Techniques
We use four different mining techniques to extract coal from the ground: longwall mining, room-and-pillar mining, truck-and-shovel mining and truck and front-end loader mining.
Longwall Mining
We utilize longwall mining techniques at our Cumberland and Emerald mines in Pennsylvania. Longwall mining is the most productive and safest underground mining method used 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 the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface. Continuous miners are used to develop access to long rectangular blocks of coal which are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive and most effective for large blocks of medium to thick coal seams. High capital costs associated with longwall mining demand large, contiguous reserves. Ultimate seam recovery of in-place reserves using longwall mining is much higher than the room-and-pillar mining underground technique. All of the raw coal mined at our longwall mines is washed in preparation plants to remove rock and impurities.
Room-and-Pillar Mining
Our Kingston, Laurel Creek and Rockspring mines in West Virginia utilize room-and-pillar mining methods. In this type of mining, main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof. Shuttle cars and battery coal haulers are used to transport coal to the conveyor belt for transport to the surface. This method is more flexible and often used to mine smaller coal blocks or thin seams. Ultimate seam recovery of in-place reserves is typically less than that achieved with longwall mining. All of this production is also washed in preparation plants before it becomes saleable clean coal.
Truck-and-Shovel Mining and Truck and Front-End Loader Mining
We utilize truck-and-shovel mining methods in both of our mines in the Powder River Basin. We utilize the truck and front-end loader method at our surface mines in West Virginia (the “Pioneer mines”). These methods are similar and involve using large, electric or hydraulic-powered shovels or diesel-powered front-end loaders to remove earth and rock (overburden) covering a coal seam which is later used to refill the excavated coal pits after the coal is removed. The loading equipment places the coal into haul trucks for transportation to a preparation plant or loadout area. Ultimate seam recovery of in-place reserves on average exceeds 90%. This surface-mined coal rarely needs to be cleaned in a preparation plant before sale. Productivity depends on overburden and coal thickness (strip ratio), equipment utilized and geologic factors.
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 a trillion tons. The United States is one of the world’s largest producers of coal and has approximately 27% of global coal reserves, representing over 200 years of supply based on current usage rates. According to the U.S. Department of Energy, the energy content of the United States coal reserves exceeds that of all the known oil supplies in the world.
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 1.2 billion tons in 2007. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators.
(1)
Preliminary data estimates for 2007 are based on data published in the EIA’s Quarterly Coal Report through the third quarter of 2007 and output from the EIA’s National Energy Modeling System.
(2)
Projected 2010-2025 Data per EIA Annual Energy Outlook 2008
Much of the nation’s power generation infrastructure is coal-fired. As a result, coal has consistently maintained a 49% 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. Through October 2007, non-hydropower renewable power generation accounted for only 2.4% of all the electricity generated in the United States, and wind and solar power-the renewable energy sources that may provide more environmental benefits-represented less than 1% of United States power generation.
Coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting power generation, technological developments, transportation costs, and the location, availability and cost of other fuels such as natural gas, nuclear and hydroelectric power.
Coal’s primary advantages are its relatively low cost and availability compared to other fuels used to generate electricity. Using 2006 Federal Energy Regulatory Commission Form 1 filings as a basis, Global Energy Advisors (“GEA”), 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 2007, as follows:
* Includes: electricity generation from solar, wind, agriculture byproducts, biomass, geothermal, landfill gas, wood waste and other waste products.
Coal Production. United States coal production was approximately 1.1 billion tons in 2007. The following table, derived from data prepared by the EIA, sets forth production statistics in each of the major coal producing regions for the periods indicated (totals may not foot due to rounding).
(1)
Preliminary data estimates for 2007 are based on data published in the EIA’s Quarterly Coal Report through the third quarter of 2007 and output from the EIA’s National Energy Modeling System.
(2)
Projected 2010-2025 Data per EIA Annual Energy Outlook 2007 Reference Case.
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. Physical and chemical characteristics of coal are very important 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. Some of 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 responsible for further transportation.
Transportation costs 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 20%. 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 some are served by two competing rail carriers. Rail competition is important because rail costs can constitute up to 75% of the delivered cost of coal in certain 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 two of 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, sub-bituminous and metallurgical coal.
Heat Value
The heat value of coal is commonly measured in British thermal units, or “Btus.” 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 Midwestern regions of the United States tends to have a higher heat value than coal found in the western United States.
Bituminous coal has a heat value that ranges from 10,500 to 14,000 Btu/lb. 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/lb. 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 Btus 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 Btus.
Most of our sub-bituminous coal typically has 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. 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 permit the user to emit a ton of sulfur dioxide per allowance. 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 89,000 megawatts by 2010. Additional scrubbing will provide new market opportunities for our noncompliance coals. All new coal-fired generation plants built in the United States are expected to use some type of clean coal-burning technology.
Operations
As of December 31, 2007, we operated a total of 13 mines located in Wyoming, Pennsylvania and West Virginia. 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, 2007.
BNSF = BNSF Railway
CSX = CSX Transportation
RJCC = R.J. Corman Railroad Company
NS = Norfolk Southern Railway Company
UP = Union Pacific Railroad Company
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 1.5 million tons of metallurgical coal. The tonnage shown in the two categories labeled purchased and resold includes 0.8 million tons of metallurgical coal.
(1)
The Wabash mine was placed on long-term idle status as of April 4, 2007. Tons sold shown is for the period January 1, 2007 through April 3, 2007.
The following map outlines our operations, coal sales revenue, tons sold and reserves as of December 31, 2007:
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 588.7 million tons of coal reserves in the Powder River Basin, the largest and fastest growing U.S. 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 51.6 million tons of coal in 2007, or 72% of our total production volume. The two mines employ approximately 580 salaried and hourly employees. Our Powder River Basin mines have produced over one billion 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 26.6 million tons of coal in 2007. The mine sells 100% of raw coal mined and no washing is necessary. Belle Ayr has approximately 286.3 million tons of reserves. The reserves at Belle Ayr will sustain projected production for approximately 11 years if market conditions warrant. We plan to apply to lease several hundred million tons of surface mineable, unleased federal coal that adjoins Belle Ayr’s property under the LBA process. If we prevail in the bidding process and obtain these leases we will be able to extend the life of the mine. Belle Ayr has the advantage of shipping its coal on both of the major western railroads, the BNSF Railway 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 25.0 million tons of coal in 2007. The mine sells 100% of the raw coal mined and no washing is necessary. Eagle Butte has approximately 302.4 million tons of reserves. The reserves will sustain projected production levels for 12 years if market conditions warrant. On February 20, 2008, our affiliate successfully bid on a new Federal coal lease adjacent to the western boundary of the Eagle Butte mine. This Federal coal lease, containing an estimated 255 million tons, is expected to be awarded during the first quarter of 2008 and will be able to extend the mine’s life by approximately 10 additional years, based on the mine’s 2007 rate of production. Coal from Eagle Butte is shipped on the BNSF Railway to power plants located throughout the West, Midwest and the South. The mine also ships a small portion by truck.
Pennsylvania Operations
We control approximately 742.0 million tons of contiguous reserves in Northern Appalachia. Approximately 178.9 million tons are assigned to active mines. Approximately 563.1 million tons are unassigned. A portion of these unassigned reserves is accessible through our currently active mines. Our Pennsylvania mines are located in the southwestern part of the state, 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 13.0 million tons in 2007 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 7.2 million tons of coal in 2007. As of December 31, 2007, Cumberland had assigned reserves of 98.2 million tons. 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 670 salaried and hourly employees.
Emerald Mine
The Emerald mining complex, located approximately two miles south of Waynesburg, Pennsylvania, was established in 1977. As of December 31, 2007, Emerald had assigned reserves of approximately 80.7 million tons. Emerald shipped 5.8 million tons of coal in 2007. 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 Railway or CSX Transportation. The mine also has the option to ship a portion of its coal by truck. Approximately 615 salaried and hourly employees work at Emerald.
West Virginia Operations
Our subsidiaries operate four mining facilities 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 mines operate two surface mines utilizing truck/loader systems to extract coal from multiple seams. Our West Virginia operations have approximately 76.8 million tons of reserves that are assigned to current operations and approximately 113.9 million tons of reserves that are unassigned and are being held for future development. Except for the two surface mines, 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 2007, our West Virginia mines collectively sold 8.5 million tons of produced and purchased coal. Our West Virginia mines ship coal by rail, primarily via either the Norfolk Southern Railway or CSX Transportation 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 loading facility on the Big Sandy River in Boyd County, Kentucky.
Our West Virginia operations have approximately 935 non-union salaried and hourly 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 (“NLRB”). If the NLRB finds that the UMWA was properly elected, approximately 275 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 2007, the Kingston complex shipped 1.1 million tons and as of December 31, 2007 had approximately 10.6 million tons of reserves of which approximately 7.4 million tons are assigned and approximately 3.2 million tons are unassigned. Kingston sells coal primarily into the metallurgical market for domestic steel plants. The coal is trucked to the Kanawha River for shipment by barge or to CSX Transportation or the Norfolk Southern Railway loadouts for shipment by rail.
Laurel Creek Mines
The Laurel Creek mining complex consists of four underground mines. The #1 and #5 mines operate in the Coalburg Seam. The #4 mine operates in the 5 block seam and the #6 mine operates in the Cedar Grove seam. The preparation plant is located in Logan and Mingo Counties. In 2007, the mines shipped 1.6 million tons and as of December 31, 2007 had approximately 11.7 million tons of assigned reserves and approximately 9.6 million tons of unassigned reserves. The coal is shipped by truck primarily to our Rivereagle dock, other third-party docks or our rail siding on CSX Transportation.
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 2.6 million tons of coal in 2007. Assigned and unassigned coal reserves totaled approximately 38.7 million tons and 22.7 million tons, respectively. Rockspring has a mine site rail loadout. The coal is transported on the Norfolk Southern Railway, primarily to southeastern utilities. The mine can also ship a portion of its production by truck.
Pioneer Mines
Pioneer Fuel Corporation operates two surface mines, Paynter Branch which is located in Wyoming County and Pax surface mine which is located in Raleigh County. These mines utilize front-end loaders with trucks to mine multiple seams. The Pioneer mines shipped 1.6 million tons of steam and metallurgical coal in 2007. As of December 31, 2007, the mines had assigned reserves of approximately 19.0 million tons with an additional 14.4 million tons of unassigned reserves. Based on 2007 production rates, we expect that the Pax mine has sufficient reserves to last approximately 12 years. The Paynter Branch mine will complete mining activities on the permitted area in 2008. Coal from Paynter Branch is shipped by truck to our on-site rail loading facility on the Norfolk Southern Railway and then on to domestic utilities and exported to metallurgical coal customers. Coal from Pax is shipped to customers primarily via rail, with coal being trucked from the mine to our on-site train loading facility served by CSX Transportation/R.J. Corman Railroad. Pax coal may also be trucked to the Kanawha River for shipment by barge.
Illinois Operations
Wabash Mine
The Wabash mine, a room-and-pillar operation, located in Wabash County, Illinois was placed on long-term idle status on April 4, 2007 due to a combination of factors, including aged underground infrastructure, softening market conditions, escalating labor and operating costs and higher value uses for capital. Remaining reserves at the property total 63.6 million tons in the Illinois No. 5 and No. 6 seams. The mine and related facilities are fully permitted. Idle facilities include a preparation plant and rail loading facility on the Norfolk Southern Railway. If market conditions warrant, the mine could be re-opened with relatively less capital investment than would be required to develop a new underground mine.
Long-Term Coal Supply Agreements
As of January 25, 2008, we had a total sales backlog of over 272 million tons of coal, and our coal supply agreements have remaining terms ranging from less than one year to 14 years. For 2007, we sold approximately 79% of our sales volume under long-term coal supply agreements with a term greater than twelve months. In 2007, we sold coal to over 100 electricity generating and industrial plants. Our primary customer base is in the United States. We expect to continue selling a significant portion of our coal under long-term supply agreements. Our strategy is to selectively renew, or enter into new, long-term supply contracts when we can do so at prices we believe are favorable. As of January 25, 2008, we had sales and price commitments for approximately 94% of our planned 2008 shipments, approximately 68% of our planned 2009 shipments, approximately 35% of our planned 2010 shipments and approximately 13% of our planned 2011 shipments. To the extent we do not renew or replace expiring long-term coal supply agreements, our future sales will be exposed to market fluctuations.
The terms and conditions of our coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, contract provisions vary by customer, including price adjustment features, coal quality requirements, future regulatory changes (including changes in environmental laws) affecting us or our customers, pass-through of new government impositions, and force majeure provisions.
Quality and volumes for the coal are stipulated in coal supply agreements, and in some instances buyers have the ability to vary the timing of shipments. Our coal supply agreements generally 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 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 labor strikes or lockouts, equipment failures, regulatory issues, adverse mining conditions, unanticipated plant outages, or serious transportation problems that affect us or our customers. Disputes may arise regarding whether force majeure has been properly declared by us or our customers, and resulting shortfalls may result in significant damages claims by or against us based on differences between contract prices and market prices.
Sales and Marketing
Our sales, marketing, and trading affiliate, Foundation Energy Sales, Inc., employs staff to handle trading, transportation, market research, contract administration, and related risk and credit management activities. Our sales team has an average of over 20 years of experience in the areas of coal sales and procurement, trading, and transportation. Through our sales, trading and marketing entities, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, trade coal and emission allowances and provide transportation related services.
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 responsible for further transportation. 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 2007, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation, Norfolk Southern Railway, BNSF Railway and Union Pacific Railroad Company. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by barge and truck. All coal from our Belle Ayr mine in Wyoming is shipped by two competing railroads, the BNSF Railway and the Union Pacific Railroad Company, while rail shipments from our Eagle Butte operation move via the BNSF Railway. The Pioneer, Kingston, Laurel Creek and Rockspring mines in West Virginia are serviced by rail, primarily by a combination of the Norfolk Southern Railway and CSX Transportation, as well as by truck and barge. In Pennsylvania, the Emerald mine is serviced by the Norfolk Southern Railway and CSX Transportation and the Cumberland mine is primarily serviced by barge. We move the coal from the Cumberland mine approximately 17 miles to the river for loading into barges on a captive railroad line we own and operate.
We believe we enjoy good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation and distribution employees.
Suppliers
We spend more than $500 million per year to procure goods and services in support of our business activities, excluding 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, 2007, we and our subsidiaries had approximately 3,000 employees. As of December 31, 2007, pursuant to two distinct collective bargaining agreements that expire in 2011, the UMWA represented approximately 34% of our affiliates’ employees, who produced approximately 19% of our coal sales volume during the fiscal year ended December 31, 2007. Relations with organized labor are important to our success, and we believe our relations with our employees are satisfactory.
ENVIRONMENTAL AND OTHER REGULATORY MATTERS
Federal, state and local authorities regulate the United States coal mining and oil and gas industries with respect to matters such as: employee health and safety; permitting and licensing requirements; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of properties after mining or other activity has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, protection of surface and groundwater; surface subsidence from underground mining; the effects on surface and groundwater quality and availability, noise, and competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, pipelines, roads and public facilities. These ordinances, regulations and legislation (and judicial or agency interpretations thereof) have had, and will continue to have, a significant effect on our production costs and our competitive position. New laws and regulations, as well as future interpretations or different 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. We intend to respond to these regulatory requirements and interpretations thereof at the appropriate time by implementing necessary modifications to facilities or operating procedures. When appropriate, we may also challenge actions in regulatory or court proceedings. Future legislation, regulations, interpretations or enforcement may also cause coal to become a less attractive fuel source due to factors such as investments necessary to use coal or taxes imposed upon its use. As a result, future legislation, regulations, interpretations or enforcement may adversely affect our mining or other operations, cost structure or the ability of our customers to use coal.
We endeavor to conduct our mining and other operations in compliance with all applicable federal, state, and local laws and regulations. However, violations occur from time to time. None of the violations identified 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 or other 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 one of the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. Regulation has a significant effect on our operating costs.
Since early 2006 and continuing to the present, as a result of the 2006 Sago mine incident in West Virginia, the 2007 Crandall Canyon mine incident in Utah, and other incidents in the coal mining industry, legislative and regulatory bodies at the state and federal levels including MSHA have promulgated or proposed various new statutes, regulations and policies relating to mine safety and mine emergency issues. Although some new laws, regulations and policies are in place, these legislative and regulatory efforts are still ongoing. At this time, it is not possible to predict the full effect that the new or proposed statutes, regulations and policies will have on our operating costs, but it will increase our costs and those of our competitors. Some, but not all, of these additional costs may be passed on to customers.
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 passed on to the purchaser 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 will increase, as will the amounts of those rewards.
As of December 31, 2007, all of our various payment obligations for federal black lung benefits to claimants entitled to such benefits are made from a fully funded tax exempt trust established for that purpose. Based on actuarial reports and required funding levels, from time to time we may have to supplement the trust corpus to cover the anticipated liabilities going forward.
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 Benefit Fund into which employers who are “signatory operators” are obligated to pay annual premiums for beneficiaries. The Combined Benefit Fund covers a fixed group of individuals who retired before July 1, 1976, and the average age of the retirees in this fund is over 80 years of age. Premiums paid in 2007 for our obligations to the Combined Benefit Fund were approximately $1.0 million. The Coal Act also created a second benefit fund, the 1992 UMWA Benefit Plan (“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. Premiums paid in 2007 for our obligation to the 1992 Plan were approximately $1.8 million. These per beneficiary premiums for both the Combined Benefit Fund and the 1992 Plan are adjusted annually based on various criteria such as the number of beneficiaries and the anticipated health benefit costs.
On December 20, 2006, the Tax Relief and Health Care Act of 2006 became law and will have the impact of reducing or eliminating the premium obligation of companies due to the expanded transfers from the Abandoned Mine Land Fund (“AML”). The additional transfer of funds from AML will incrementally eliminate by 2010, to the extent the new transfers are adequate, the unassigned beneficiary premium under the Combined Benefit Fund effective October 1, 2007. The additional transfers will also reduce incrementally the pre-funding and assigned beneficiary premium to cover the cost of beneficiaries for which no individual company is responsible (“orphans”) under the 1992 Plan beginning January 1, 2008. For the first time, the 1993 Benefit Plan (all of the beneficiaries of which are orphans) will begin receiving a subsidy from a new federal transfer that will ultimately cover the entire cost of the population included in the plan as of December 31, 2006. Under the Combined Benefit Fund, the 1992 Plan and the 1993 Plan, if the federal transfers are inadequate to cover the cost of the “orphan” component, the current or former signatories, of the UMWA wage agreement will remain liable for any shortfall.
Environmental Laws
We and our customers are subject to various federal, state and local environmental laws. Some of the more material of these laws and issues, discussed below, place stringent requirements on our coal mining and other operations, and on the ability of our customers to use coal. Federal, state and local regulations require regular monitoring of our mines and other facilities to ensure compliance with these many laws and regulations.
Mining Permits and Necessary Approvals
Numerous governmental permits, licenses or approvals are required for mining, oil and gas operations, 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 or other 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 or even denials of permits altogether. In particular, issuance of Army Corps of Engineers (“COE”) permits in Central Appalachia allowing placement of material in valleys have been slowed in recent years due to ongoing litigation over the requirements for obtaining such permits.
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 that impact the surface. 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 federal 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, among other actions, 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 several 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.
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. Many comments to this proposed rule, both for and against, have been filed during 2007 and the contents of the final rule cannot be predicted at this time. 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.
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 when SMCRA came into effect. The current fee is $0.315 per ton on surface-mined coal and $0.135 on deep-mined coal from 2008 to 2012, with reductions to $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from 2013 to 2021.
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 are at this time, and may still continue to be, subject to current and future legal challenges in courts and the actual timing of implementation may remain uncertain. Some of the more material Clean Air Act requirements that may directly or indirectly affect our operations include the following:
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Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 megawatts. The affected electricity generators have sought to meet these requirements mainly by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. The adoption of the Clean Air Interstate Rule (“CAIR”) in 2005 created tighter limits for sulfur dioxide and nitrogen oxides for the states covered under CAIR than currently exist under Title IV. (See “Clean Air Interstate Rule” for more information.) The cap-and-trade program under the CAIR utilizes the same allowance allocation policy developed under Title IV of the Clean Air Act. States not governed by the CAIR will continue to be subject to the regulations of Title IV. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. Initially, we believe that implementation of Phase II 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. As utilities continue invest the capital to add scrubbers and other devices to comply with Title IV, CAIR, the Clean Air Mercury Rule (discussed below) and other provisions of the law, demand for lower sulfur coals may drop.
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Fine Particulate Matter and Ozone. The Clean Air Act requires the Environmental Protection Agency (“EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. In 1997, the EPA revised the NAAQS for particulate matter and ozone. Although previously subject to legal challenge, these revisions were subsequently upheld but implementation was delayed for several years. For ozone, these changes include replacement of the existing one-hour average standard with a more stringent eight-hour average standard in Phase 1 of the Ozone Rule. In April 2004, the EPA announced that counties in 31 states and the District of Columbia failed to meet the new eight-hour standard for ozone. On November 8, 2005, the EPA finalized Phase 2 of the Ozone Rule, which establishes the final compliance requirements and timelines upon which state, local, and tribal government will base their state implementation plans for areas designated as non-attainment. 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 finalized in December 2005, and counties in 21 states and the District of Columbia were classified as non-attainment areas. At the same time, the EPA also proposed changes to the current national air quality monitoring requirements for all criteria pollutants including particulates and revisions to the national air quality standards for fine particulate pollution, proposing more stringent requirements for this pollutant. These newly proposed standards were incorporated into the EPA’s final rule on particulate matter issued in October 2006. These standards also include making new state non-attainment designations in 2010 based on 2007-2009 air quality data; requiring these states to meet the EPA’s new PM standards by 2015. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. On March 29, 2007, the EPA issued a final rule defining requirements for state plans to clean the air in 39 areas where particle pollution levels do not meet national air quality standards. Future regulation and enforcement of these new ozone and PM2.5 standards will affect many power plants, especially coal-fired plants and all plants in “non-attainment” areas.
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Ozone. Significant additional emissions control expenditures may be required at many 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 may continue to become more demanding in the years ahead.
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NOx SIP Call. The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. Under Phase I of the program, the EPA is requiring 90,000 tons of nitrogen oxides reductions from power plants in 22 states east of the Mississippi River and the District of Columbia beginning in May 2004. Phase II of the program, which became effective in June 2004, requires a further reduction of about 100,000 tons of nitrogen oxides per year by May 2007. Installation of additional control measures, such as selective catalytic reduction devices, required under the final rules will make it more costly to operate coal-fired electricity generating plants, thereby making coal a less attractive fuel.
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Clean Air Interstate Rule. In 2004, the EPA proposed new rules for further reducing emissions of sulfur dioxide and nitrogen oxides. The final CAIR was issued by the EPA in 2005. The rule calls for power plants in Texas and 27 states bordering or east of the Mississippi River, and the District of Columbia, to reduce emission levels of sulfur dioxide and nitrous oxide. 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. These state measures will be at least as stringent as those imposed by CAIR. The stringency of the caps may require many coal-fired sources to install additional pollution control equipment to comply. This increased sulfur emission removal capability caused by the proposed rule could result in decreased demand for low sulfur coal, potentially driving down prices for low sulfur coal.
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Clean Air Mercury Rule. In December 2000, the EPA decided to list coal-fired power plants as a category of sources subject to regulation under section 112 of the Clean Air Act. In January 2004, the EPA proposed a mercury reduction rule for controlling mercury emissions from power plants and requested comments on two approaches for reducing mercury currently emitted each year by coal-fired power plants in the United States. After reconsidering its prior decision to regulate power plant emissions of mercury under section 112, EPA reversed its prior “listing” decision and issued its final Clean Air Mercury Rule, or “CAMR”, in March 2005. In doing so, the EPA rejected the 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 EPA adopted, which was challenged in federal court by several states and others, set a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide pursuant to section 111 of the Clean Air Act. This “cap-and-trade” approach is similar to the approach under the CAIR rule discussed above. If implemented, the CAMR approach, which allows mercury emissions trading, when combined with the CAIR regulations, was forecast to 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 and was scheduled to begin 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 was set at 15 tons per year beginning in 2018. Under the EPA approach, each state would be allocated a budget of mercury emissions and required to submit a plan on meeting its budget for mercury reductions. Each state is not required to adopt the cap-and-trade approach, but instead 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. In November 2006, states were required to file their state implementation plans (“SIP”) with the EPA for mercury compliance but only 21 states submitted plans. This prompted the EPA to designate a federal implementation plan (“FIP”) to be applied to states that did not file a SIP. The FIP basically requires all states without an EPA approved SIP to participate in the national cap-and-trade program. Assuming the EPA’s CAMR approach were to proceed, there remains some uncertainty as to how the various state implementation plans will interact with the FIP as not all the SIP’s allow for trading as does the federal plan. On February 8, 2008, the United States Court of Appeals for the District of
Columbia Circuit struck down the EPA’s regulations for reducing mercury emissions from coal-fired power plants. The court held that the EPA violated the Clean Air Act by reversing its prior decision to list coal-fired power plants as a source of emissions subject to regulation under Clean Air Act section 112. According to the court, once EPA initially determined under section 112(n)(1) of the Clean Air Act that it was “appropriate and necessary” to regulate those plants under the Clean Air Act’s hazardous air pollutant program, the agency could not reverse its own decision under that same provision. Rather, the court held that section 112(c)(9) of the Act affords the exclusive mechanism to remove any source from the list of sources regulated under the hazardous air pollutant program. That provision requires a more exacting finding to remove sources, including a determination that no adverse environmental effect will result from emissions from any source. Because the effect of the court’s ruling is to maintain power plants on the list of hazardous air pollutant sources subject to regulation under section 112, the court concluded that regulation of mercury emissions from existing coal-fired plants under section 111 is prohibited, thereby invalidating the CAMR’s regulatory approach. At this time it is not known whether EPA will appeal the decision or seek to promulgate new regulations.
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Carbon Dioxide. In 2003, certain states sued the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant under the Clean Air Act and to issue a new NAAQS for carbon dioxide. Previously, the EPA had established that carbon dioxide is not a criteria pollutant and therefore cannot be regulated under the Clean Air Act. In 2005, a federal court upheld the EPA’s position that it was not required to regulate carbon dioxide as a pollutant. In April 2007 in Massachusetts v. Environmental Protection Agency the United States Supreme Court case ruled in a 5-4 decision the Clean Air Act does give EPA the authority to regulate tailpipe emissions of greenhouse gases. In addition, the majority held that "greenhouse gases fit well within the Clean Air Act’s capacious definition of air pollutant." The EPA is now required to review its contention that it has discretion in regulating carbon dioxide and other greenhouse gas emissions - specifically, its current rationale for not regulating was found to be inadequate, and the agency must articulate a reasonable basis in order to avoid regulation. The ruling does not force the environmental agency to regulate auto emissions, but it would almost certainly face further legal action if it failed to do so. The ultimate actions of the EPA as a result of this Supreme Court decision may affect the demand for coal. In addition, there are several new state programs to limit CO2 emissions and others have been proposed. There are also pending before Congress several proposals to limit CO2 emissions and other proposals may be forthcoming. Various House and Senate committees are conducting hearings into the issues surrounding climate change and the effects of CO2 emissions. Congress, or one or more states, at some point, are likely to regulate the release of carbon dioxide emissions as part of any green house gas initiatives that are proposed in the future. See “Climate Change” for further information.
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Regional Haze. The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. The original regional haze rule required designated facilities meet the EPA’s BART standard, which requires installation of the Best Available Retrofit Technology to reduce emissions that contribute to visibility problems. In December 2006, this rule was modified to allow states the flexibility to evaluate the use of cap-and-trade programs when these programs would result in greater progress toward the EPA’s visibility goals. 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.
Climate Change
One major by-product of burning coal and all other fossil fuels 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 (the “Protocol”) to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases. With Russia’s ratification, the Protocol received sufficient support to become binding on all those countries that have ratified it. 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. In 2002, President Bush reaffirmed U.S. support for the United Nations Framework Convention on Climate Change, but the U.S. Senate did not ratify the Protocol because, among other reasons, it did not require emissions reduction from all countries. The Protocol expires in 2012. Many of the countries which did ratify the Protocol are not on target to meet the mandated reductions in carbon dioxide. In addition, many developing nations which also emit greenhouse gases are not covered by the Protocol. As such, a new or modified international protocol to regulate carbon dioxide emissions will likely be proposed in the future.
As part of the United Nations Framework Convention on Climate Change, representatives from 187 nations met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The United States participated in the conference. The convention adopted what is called the “Bali Action Plan.” The Bali Action Plan contains no binding commitments, but concludes that “deep cuts in global emissions will be required” and provides a timetable for two years of talks to shape the first formal addendum to the 1992 United Nations Framework Convention on Climate Change treaty since the Kyoto Protocol. The ultimate outcome of the Bali Action Plan, and any treaty or other arrangement ultimately adopted by the United States or other countries, may have a material adverse impact the global supply and demand for coal. This is particularly true if cost effective technology for the capture and sequestration of carbon dioxide is not sufficiently developed.
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 at the state and federal level. 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. 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. 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. Currently several state groups are working on regional plans to address climate and energy issues. The 110th Congress has been active in promoting greenhouse gas legislation with several separate bills already being presented and others possible. There are a number of uncertainties regarding these and additional initiatives which may be proposed. In addition to the timing for implementing any new legislation, open issues include matters such as the applicable baseline of emissions to be permitted, initial allocations of any emission allowances, required emissions reductions, availability of offsets to emissions such as planting trees or capturing methane emitted during mining, the extent to which additional states will adopt the programs, and whether they will be linked with programs in other states or countries. Increased efforts to control greenhouse gas emissions could result in reduced demand 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. The CWA 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 are at this time, and may still continue to be, subject to current and future amendments or legal challenges in courts and the actual timing of implementation may remain uncertain. Some of the more material CWA issues that may directly or indirectly affect our operations are discussed below.
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 disposal 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. The COE only has jurisdiction over the “navigable waters” of the United States, and outside these waters there is arguably no need to procure a 404 permit. The United States Supreme Court ruled in Rapanos v. United States in 2006 that upper reaches of steams which are intermittent or do not flow might not be jurisdictional waters requiring 404 permits. The case did not involve disposal of mining refuse, but has implications for the mining industry. Subsequently, in June 2007 the COE and EPA issued a joint guidance document to attempt to develop a policy that will apply the jurisdictional standards imposed by the Supreme Court. The guidance requires a case-by-case analysis of whether the area to be filled has a sufficient nexus to downstream navigable waters so as to require 404 permits. How the COE field offices will apply this new guidance, and to what extent decisions made pursuant to it will be challenged, are still open questions.
The COE issuance of 404 permits is subject to the National Environmental Policy Act (“NEPA”). NEPA defines the procedures by which a federal agency must run its permitting programs. The law says that a federal agency must take a “hard look” at any activity that may “significantly affect the quality of the human environment.” This “hard look” is accomplished through an Environmental Impact Statement (“EIS”), a very lengthy data collection and review process. After the EIS is complete, only then can the 404 permit application be considered. However, the law also allows an initial Environmental Assessment (“EA”) to be completed to determine if a project will have a significant impact on the environment. To date the COE has typically used the less detailed EA process to determine the impacts from impoundments, fills and other activities associated with coal mining. In general, the preliminary findings show that these types of mining related activities will not have a significant effect on the environment, and as such a full EIS is not required. Should a full EIS be required for every permit, significant permitting delays could affect mining costs or cause operations to be idled or closed.
In March 2007, the U.S. District Court for the Southern District of West Virginia issued a decision concerning 404 permitting for fills. The court held that widely used pre-mining assessments of areas to be impacted required by the COE and conducted by the permit applicants are inadequate and do not accurately assess the nature of the headwater areas being filled. As such, the court found the COE erred in its finding of no significant impact from this activity. Based on this conclusion, the court went on to find that proposed mitigation to offset the adverse impacts of the area to be filled also are not supported by adequate data. Due to this decision, the COE is assessing the protocol for evaluating the pre-mining stream conditions, as well as procedures used in the measurement of the success of mitigation. That effort to revise the protocol and associated findings is ongoing and may be challenged as it is applied to newly issued permits. Until this process is completed, preparing and submitting new permit applications is somewhat hindered. The March 2007 decision has been appealed to the Fourth Circuit Court of Appeals. In June 2007, the same federal district court ruled on other pending motions. One relates to NPDES permitting for discharges between the toes of the valley fills and the downstream sediment ponds used for settling and flow control. Historically, NPDES permits were not required for the point right at the toe of the valley fill. The area between this toe and the sediment pond was considered part of a “waste treatment” area. Waste treatment areas have an exclusion from NPDES permits. In the past, after the water flowed to the sediment pond and settled, an NPDES permit has been obtained for the discharge from the sediment pond. The judge has ruled that the stream from the toe of the fill to the pond is not a water treatment area subject to the exclusion. This ruling would require NPDES permits at the base of the fill. At this location it would be difficult to meet discharge limitations likely to be imposed on a typical NPDES permit in the region. This decision has also been appealed to the Fourth Circuit Court of Appeals.
In December 2007, a similar case was filed in the U.S. District Court for the Western District of Kentucky challenging a single permit issued by the COE in Leslie County. That permit has been suspended by the COE so that it can reconsider the permit decision to address comments of the environmental group that filed the lawsuit. Although we do not have operations in Kentucky, the decision in this matter may affect permits in states where we do have operations.
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 COE appealed the decision to the United States Court of Appeals for the Fourth Circuit. In November 2005, the Fourth Circuit Court of Appeals overturned the July 2004 decision, thereby allowing the continued use of the NWP 21 permitting process, but remanded remaining challenges to the NWP 21 to the district court. Resolution of those additional challenges is still pending before that court. A similar challenge to the Nationwide 21 permit process was filed in Kentucky. Although we have no current operations in Kentucky, similar suits may be filed in other jurisdictions where we do operate.
The Clean Water Act requires that all of our operations obtain NPDES permits for discharges of water from all of our mining operations. All NPDES permits require regular monitoring and reporting of one or more parameters on all discharges from permitted outfalls. When a water discharge occurs and one or more parameters are outside the approved limits permitted in an NPDES permit, these exceedances of permit limits are voluntarily reported to the pertinent agency. The agency may impose penalties for each such release in excess of permitted amounts. If factors such as heavy rains or geologic conditions cause persistent releases in excess of amounts allowed under NPDES permits, costs of compliance can be material, fines may be imposed, or operations may have to be idled until remedial actions are possible.
Recently, there have been renewed efforts by USEPA to examine the coal industry’s record of compliance with these limits. That enhanced scrutiny recently resulted in an agreement by one coal operator to pay a $20 million penalty for over 4,000 alleged NPDES permit violations.
The Clean Water Act has specialized sections that address NPDES permit conditions for discharges to waters in which State-issued water quality standards are violated and where the quality exceeds the levels established by those standards. For those waters where conditions violate State water quality standards, states or USEPA are required to prepare a Total Maximum Daily Load by
which new discharge limits are imposed on existing and future discharges in an effort to restore the water quality of the receiving streams. Likewise, when water quality in a receiving stream is better than required, states are required to adopt an “antidegradation policy” by which further “degradation” of the existing water quality is reviewed and possibly limited. In the case of both the TMDL and antidegradation review, the limits in our NPDES discharge permits could become more stringent, thereby potentially increasing our treatment costs and making it more difficult to obtain new surface mining permits.
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 coal construction wastes as hazardous wastes would increase our customers’ operating costs and potentially reduce their demand for coal. In addition, contamination caused by the past disposal of ash can lead to material liability which could reduce demand for coal.
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.
Additional Information
We file annual, quarterly and current reports, amendments to these reports and other information with the United States Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, at www.foundationcoal.com, or the SEC’s website at www.sec.gov. All documents we file are also available at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549.
GLOSSARY OF SELECTED TERMS
Ash. Impurities consisting of iron, alumina and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.
Assigned reserves. Coal that has been committed to be mined at operating facilities or idled facilities which have been operated in the past.
Bituminous coal. A 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, southern West Virginia and a portion of eastern Tennessee.
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 problems in our cities. The 1990 amendments broadened and strengthened the original law to address specific problems 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. Its production results in a number of useful byproducts.
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 Btus 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 Btus 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 smog.
Northern Appalachia. Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.
Overburden. Layers of earth 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 remove impurities and prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur 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 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 30% by weight, and its heat content ranges from 7,800 to 9,500 Btus 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 layer of soil (see “Overburden”). About 67% of total U.S. 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 document.
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 or idled facilities.
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 and conveyor to the surface. Underground mines account for about 33% of annual U.S. coal production.
Unit train. A train of 100 or more cars carrying a single product. A typical coal unit train can carry at least 10,000 tons of coal in a single shipment.
ITEM 1A.
ITEM 1A. RISK FACTORS.
RISK FACTORS
Risks Relating to Our Business
A substantial or extended decline in coal prices or demand could reduce our revenues and the value of our coal reserves.
The prices we charge for coal depend upon factors beyond our control, including, but not limited to:
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the supply of, and demand for, domestic and foreign coal due to weather or other factors;
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the demand for electricity;
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domestic and foreign demand for steel and the continued financial viability of the domestic and/or foreign steel industry;
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the proximity to, capacity of, and cost of transportation facilities;
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domestic and foreign governmental regulations and taxes;
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air emission and other regulatory standards for coal-fired power plants;
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costs of transportation of our coal relative to our competitors;
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regulatory, administrative and court decisions;
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the price and availability of alternative fuels, including the effects of technological developments;
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the effect of worldwide energy conservation measures; and
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disruptions in delivery or changes in pricing from third party vendors of goods and services which are necessary for our operations, such as fuel, steel products, explosives and tires.
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.
Changes in market conditions, factors influencing the demand for coal, and increased production costs could adversely affect our revenues.
Continued demand for our coal, most of which is sold to plants in North America, and the prices that we will be able to obtain could be adversely affected by factors such as changes in coal consumption patterns. Consumption by the domestic utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel supplies including nuclear, natural gas, oil and renewable energy sources. 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 Interstate Rule and Clean Air Mercury Rule 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. Higher costs for transporting coal also can have a detrimental impact on coal market demand. Our results are highly dependent upon the prices we receive for our coal. Decreased demand for coal, both domestically and internationally, could cause spot prices and the prices we are able to negotiate on long-term contracts to decline. The lower prices could negatively affect our cash flows, results of operations or financial condition, if we are unable to increase productivity and/or decrease costs in order to maintain our margins. Our revenues also may be adversely affected if production cost increases, including higher costs for labor, materials and equipment, outpace coal market price increases or erode our margins for coal sold under long-term coal supply agreements with pre-determined pricing.
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 and parts availability, replacement or repair, prices and availability for fuel, steel, explosives, tires and other supplies, fires, variations in thickness of the layer, or 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.
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 and state regulators may order certain of our mines to be temporarily closed or operations therein modified, which would adversely affect our ability to meet our contracts or projected costs.
MSHA and state regulators may order certain of our mines to be temporarily closed due to an investigation of an accident resulting in property damage or injuries, or due to other incidents such as fires, roof falls, water flow, equipment failure or ventilation concerns. In addition, regulators may order changes to mine plans or operations due to their interpretation or application of existing or new laws or regulations. Any required changes to mine plans or operations may result in temporary idling of production or addition of costs.
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. 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 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 continue to adjust to the regulations of the Clean Air Act, the Clean Air Mercury Rule, the Clean Air Interstate Rule, possible regulation of greenhouse gas emissions and other regulatory changes with respect to plant emissions, 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 supply contracts may result in economic penalties upon the failure to meet specifications.
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. With respect to sulfur, the price of S02 allowances in the market is sometimes used to adjust the price we receive for coal and the market price for these allowances may fluctuate and cause us not to receive the anticipated revenues.
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.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
We derived 53% of our total coal revenues from sales to our 10 largest customers for the year ended December 31, 2007, with the largest customer accounting for approximately 13% of our coal revenues for that year. At December 31, 2007, we had 32 coal supply agreements with those 10 customers that expire at various times from 2008 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 2007, none 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.
Overcapacity in the coal industry, both domestically and internationally, may affect the price we receive for our coal. For example, during the 1970s and early 1980s, increased demand for coal and attractive pricing brought new investors to the coal industry and promoted the development of new mines. These factors resulted in added production capacity throughout the industry, which led to increased competition and lower coal prices. Continued coal pricing at relatively high levels, compared to historical levels, could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future.
The demand for U.S. 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 U.S. 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 U.S. 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 and discharges to water; plant and wildlife protection; the reclamation and restoration of properties after mining or other activity has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface and groundwater; surface subsidence from underground mining; noise; and the effects of operations 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 mining and other operations.
Numerous governmental permits and approvals are required under these laws and regulations for mining and other 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 and groundwater 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 legislative initiatives in the U.S. 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 and other operation, 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 or different 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 occur at our operations from time to time and may result in significant costs to us to correct such violations, as well as civil or criminal penalties and limitations or shutdowns of our 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 enforcement 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 “Business-Environmental and Other Regulatory Matters” for a discussion of some of the 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.
Our operations can also impact flows and water quality in surface water bodies and remedial measures may be required, such as grouting cracks 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 and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. 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 existing and new coal-fired power plants to attain applicable ambient air quality standards. In addition, state regulatory schemes for electricity pricing may be administered to not permit recovery of investments in emissions control equipment. As a result, these generators may switch to fuels that generate less of these emissions, possibly reducing the likelihood that generators will keep existing coal-fired power plants in service or build new coal-fired power plants. Any of these developments may reduce demand for our coal.
For example, the final Clean Air Interstate Rule (“CAIR”) was issued by the EPA in 2005. The rule calls for power plants in Texas and 27 states bordering or east of the Mississippi River, and the District of Columbia, to reduce emission levels of sulfur dioxide and nitrous oxide. 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. These state measures will be at least as stringent as those imposed by CAIR. 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. Also, in March 2005, the EPA finalized a Clean Air Mercury Rule for controlling mercury emissions from power plants by imposing a two-step approach to reducing, between now and 2018, the total mercury emissions allowed from coal-fired power plants nationwide. The approach adopted 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 many took that approach. Alternatively, a state can elect to meet a specific state emissions budget through measures of the state’s choosing. On February 8, 2008, the United States Court of Appeals for the District of Columbia Circuit struck down EPA’s regulations for reducing mercury emissions from coal-fired power plants. The effect of the court’s ruling is to maintain power plants on the list of hazardous air pollutant sources subject to regulation under section 112 of the Clean Air Act and to invalidate the EPA’s “cap-and-trade” approach to regulation of mercury emissions. At this time it is not known whether the EPA will appeal the decision or seek to promulgate new standards governing power plant mercury emissions. Regulation of power plant emissions under the Clean Air Act and future standards imposed by state and federal authorities 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 and results of operations or cash flow.
Current and future proposals may be introduced 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 emissions such as carbon dioxide. 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. Current and possible future governmental programs are or may be in place to require the purchase and trading of allowances associated with the emission of various substances such as sulfur dioxide, nitrous oxide, mercury and carbon dioxide. Changes in the markets for and prices of allowances could have a material effect on demand for and prices received for our coal.
The United States and more than 160 other nations are signatories to the 1992 United Nations Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide which is a major by-product of burning coal. 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 which expires in 2012 has received sufficient support from enough nations to enter into force and will become binding on all those countries that have ratified it.
As part of the United Nations Framework Convention on Climate Change, representatives from 187 nations met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The United States participated in the conference. The convention adopted what is called the “Bali Action Plan.” The Bali Action Plan contains no binding commitments, but concludes that “deep cuts in global emissions will be required” and provides a timetable for two years of talks to shape the first formal addendum to the 1992 United Nations Framework Convention on Climate Change treaty since the Kyoto Protocol. The ultimate outcome of the Bali Action Plan, and any treaty or other arrangement ultimately adopted by the United States or other countries, may have a material adverse impact the global supply and demand for coal. This is particularly true if cost effective technology for the capture and sequestration of carbon dioxide is not sufficiently developed.
Although the Protocol is still not binding on the United States and the Bali Action Plan is just commencing, and because no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of global agreements 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 or subsequent global agreements. From time to time Congress may consider various proposals to tax or otherwise limit greenhouse gas emissions. In addition, some states and municipalities 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. 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 some of the 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.
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 our primary rail, barge or truck carriers that transport our produced coal and we are unable to make alternative transportation arrangements to ship our coal, our business could be adversely affected.
West Virginia legislation, which raised coal truck weight limits, includes 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 will 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 reserves. 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 now own or subsequently 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 various 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, engineering 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, 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. In addition, from time to time the rights of third parties for competing uses of adjacent, overlying, or underlying lands such as for oil and gas activity, coalbed methane, production, pipelines, roads, easements and public facilities may affect our ability to operate as planned if our title is not superior or arrangements cannot be negotiated. Title to much of our leased properties and fee 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 or competing interests cannot be resolved. In order to obtain leases or other rights to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs or leave un-mined the affected reserves. In addition, we may not be able to successfully purchase or 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 mineral reserves through acquisitions of businesses and assets, mergers, joint ventures or other transactions. Such transactions involve various inherent risks, such as:
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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;
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the potential loss of key customers, management and employees of an acquired business;
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the inability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction;
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problems that could arise from the integration of the acquired business; and
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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 the acquired businesses.
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 unfunded status (the excess of projected benefit obligation over plan assets) of these obligations, as reflected in Note 13 to our consolidated financial statements at December 31, 2007, included $529.1 million of postretirement obligations, $28.6 million of defined benefit pension obligations, $34.7 million of workers’ compensation obligations and $12.4 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 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 indebtedness. As of December 31, 2007, our total indebtedness was $599.8 million. In addition, as of December 31, 2007, we had $172.6 million of letters of credit outstanding and additional borrowings available under our revolving credit facility of $327.4 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:
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making it more difficult to self-insure and obtain surety bonds or letters of credit;
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limiting our ability to enter into new long-term sales contracts;
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increasing our vulnerability to general adverse economic and industry conditions;
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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 working capital, capital expenditures, research and development or other general corporate uses;
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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;
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making it more difficult for us to pay interest and satisfy our debt obligations;
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limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and
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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 Secured Credit Facility.
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 Secured Credit Facility and the indenture under which our 7.25% Senior Notes 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 from 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 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 Corporation 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 Secured Credit Facility and our indenture impose restrictions that may limit our operating and financial flexibility.
The Senior Secured Credit Facility, our indenture governing the 7.25% 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 Secured Credit Facility. 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 Secured Credit Facility 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, United Mine Workers of America (“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, 2007, we had outstanding surety bonds of $278.9 million, which includes $263.8 million secured reclamation obligations; $6.2 million secured coal lease obligations; $7.1 million secured self-insured workers’ compensation obligations; and $1.8 million secured miscellaneous 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 and coal lease 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:
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lack of availability, higher expense or unfavorable market terms of new surety bonds; and
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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, as of December 31, 2007, we had $172.6 million of letters of credit in place for the following purposes: $37.2 million for workers’ compensation, including collateral for workers’ compensation bonds; $8.0 million for UMWA retiree health care obligations; $112.2 million for collateral for reclamation surety bonds; and $15.2 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 Secured Credit Facility 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 2007, our total contributions to these plans and other contractual payments under our UMWA wage agreement were approximately $9.5 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 2007, we contributed $11.3 million to our pension plans. We currently expect to make contributions in 2008 of approximately $8.0 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 for those years could be higher than we expect.
As of December 31, 2007, our annual measurement date, our pension plans were underfunded by $28.6 million (based on the actuarial assumptions used for SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”). 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 U.S. 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, 2007, the UMWA represented approximately 34% of our affiliate’s employees, who produced approximately 19% of our coal sales volume during the fiscal year ended December 31, 2007. The mines represented by the UMWA include Emerald and Cumberland longwall mines in Pennsylvania. These subsidiaries have distinct collective bargaining agreements. 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 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. The two existing collective bargaining agreements with the UMWA expire at the end of the fourth quarter of 2011. If the applicable subsidiaries are unable to reach a mutually acceptable replacement agreement, it could adversely affect their productivity, increase their costs and disrupt shipments, or result in the closure of the mine due to a strike by the workers or a lockout by local management.
Wage agreements between three affiliates of the Company and the UMWA expired on or shortly after March 31, 2007. Specifically, the wage agreement for Wabash expired at 11:59 p.m. on March 31, 2007 and the UMWA wage agreements with Cumberland Coal Resources, LP (“Cumberland”) and Emerald Coal Resources, LP (“Emerald”) expired at 11:59 p.m. on April 1, 2007. Negotiations between these respective subsidiaries and the UMWA commenced in early January of 2007 but intensified in late March of 2007 and continued through April 3, 2007. Emerald Coal Resources, LP and Cumberland Coal Resources, LP reiterated their willingness to sign the 2007 National Bituminous Coal Operators Association (“BCOA”) UMWA wage agreement. Wabash would not sign the BCOA agreement. The hourly workforce continued to work without a formal agreement of the parties under the terms of the expired wage agreement until 12:01 a.m. on April 4, 2007 at which time, alleging unfair labor practices by Wabash, Emerald and Cumberland, the UMWA represented hourly workforces went on strike at the Wabash, Emerald and Cumberland mines. Subsequent to the commencement of a UMWA strike on April 4, 2007, Wabash announced the idling of the mine in southern Illinois. The mine had become economically unviable at that time as a result of a combination of factors, including aged infrastructure, softening market conditions and the prospect of a new higher cost labor contract with the UMWA.
On April 10, 2007, negotiations between the UMWA and the three subsidiaries resumed. In the early evening of April 12, 2007, it was announced that the UMWA and the three subsidiaries had reached agreement and that the workforces at Emerald and Cumberland would return to work. Wabash remained idled and the effects of the idling had been negotiated with the UMWA.
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 National Labor Relation Board (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. In 2006, the NLRB ordered 5 of the 9 ballots to be opened. All were votes against the UMWA. This resulted in a revised tally of 110 for UMWA representation and 108 against the UMWA. The 4 remaining unopened ballots are determinative. By Order dated October 12, 2006, the Regional Director transferred the case back to the Board for further consideration of the remaining determinative challenged ballots. In April 2007, the NLRB ruled that three of the four ballots are to be opened and the fourth should not be opened or counted. This decision has been appealed. If it is ultimately determined that the UMWA was validly elected, approximately 275 employees 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.
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 U.S. 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.
Provisions in our Public Parent’s certificate of incorporation and bylaws may discourage a takeover attempt even if doing so might be beneficial to our Public Parent’s shareholders.
Provisions contained in our Public Parent’s certificate of incorporation and bylaws could make it more difficult for a third party to acquire us. Provisions of our Public Parent’s certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for our Public Parent’s shareholders to effect certain corporate actions. For example, our Public Parent’s certificate of incorporation authorizes our Public Parent’s board of directors to determine the rights, preferences,
privileges and restrictions of unissued series of preferred stock of the Public Parent, without any vote or action by our Public Parent’s shareholders. Thus, our Public Parent’s board of directors 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 Public Parent’s common stock. These rights may have the effect of delaying or deterring a change of control of our Public Parent. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our Public Parent’s common stock.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES.
Coal Reserves
Periodically, we retain outside experts to independently verify our coal reserves. 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. In the first quarter of 2006 we retained outside experts to independently verify additional economically viable reserves. “As received” means measuring coal in its natural state and not after it is dried in a laboratory setting. We have recalculated all reserves on an “as received” basis. Our reserves were approximately 1.6 billion tons as of December 31, 2007.
Of the 1.6 billion tons, approximately 0.9 billion tons are assigned reserves that we expect to be mined at operations in the future. Approximately 0.7 billion tons are unassigned reserves that we are holding for future development. All of our reserves in Wyoming are assigned. We have substantial unassigned reserves in Pennsylvania, West Virginia and Illinois.
Over 50% 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 40% of our reserves are classified as compliance coal which meets the 1.2 lb SO 2 /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 reserves are 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 annually 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 reserves. 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 database 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 U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. Each lease requires diligent development of the lease within ten 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 to 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 royalties, rentals and any lease bonus payments to Wyoming. Effective October 1, 2008, the Federal Government will remit 48% of royalties, rentals and any lease bonus payments to Wyoming.
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 saleable 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.
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, 2007.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
None.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
Foundation Coal Corporation does not have any independent external operations, assets or liabilities, other than through its operating subsidiaries. The selected consolidated financial data as of and for the twelve months ended December 31, 2007, 2006 and 2005 and as of and for the period from April 23, 2004 (date of incorporation) through December 31, 2004 have been derived from the audited consolidated financial statements of Foundation Coal Corporation. From its incorporation on April 23, 2004 and prior to the acquisition of RAG American Coal Holdings, Inc. on July 30, 2004, Foundation Coal Corporation did not have any assets, liabilities or results of operations. Therefore, the selected historical consolidated financial data for the period from January 1, 2004 through July 29, 2004 and as of and for the twelve months ended December 31, 2003 have been derived from the audited consolidated financial statements of RAG American Coal Holding, Inc., the predecessor to Foundation Coal Corporation, which have been audited by Ernst & Young LLP, an independent registered public accounting firm. 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 period from April 23, 2004 to December 31, 2004 reflects preliminary purchase price allocations in preparing the financial data which was finalized during the twelve months ended December 31, 2005. The audited consolidated financial statements as of and for the twelve months ended December 31, 2007, 2006 and 2005 are included elsewhere in this Annual Report on Form 10-K.
The following provides a description of the basis of presentation during all periods presented:
“Successor”-Represents the consolidated financial position of Foundation Coal Corporation and consolidated subsidiaries as of December 31, 2007, 2006, 2005 and 2004 and the consolidated results of operations and cash flows for the twelve months ended December 31, 2007, 2006, 2005 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004. Foundation Coal Corporation had no significant activities until the acquisition on July 30, 2004. Therefore, the results of operations and cash flows for the period from April 23, 2004 (date of incorporation) through December 31, 2004 reflect only the activity for the five month operating period ended December 31, 2004.
“Predecessor”-Represents the consolidated results of operations and cash flows of RAG American Coal Holdings, Inc. for all periods prior to the acquisition of RAG American Coal Holdings, Inc. on July 30, 2004.
You should read the following data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and with the financial information included elsewhere in this Annual Report on 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. See Note 24 to the consolidated financial statements for additional details of other revenue.
(2)
Write-down of long-lived assets in 2005 of $1.6 million as a result of a change in mine plan at the Northern Appalachia business unit. In 2006, $1.4 million and $29.4 million were written off related to deferred mining royalties at the Central Appalachia business unit and certain long-lived assets at the Wabash mine, respectively.
(3)
In the Predecessor period in 2004, 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. In the Successor period in 2004, a $0.5 million mark-to-market gain was recorded on interest rate swaps not yet designated as cash flow hedges. Expense in 2006 relates to a non-cash mark-to-market loss for the period for which the swaps did not qualify for cash flow hedge accounting. 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)
Represents arbitration and litigation settlements recorded in 2003.
(7)
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 (“SFAS”) 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.
(8)
Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”).
(9)
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), 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 Operation-Liquidity and Capital Resources-Covenant Compliance”.
EBITDA is calculated and reconciled to income (loss) from continuing operations in the table below.
(10)
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. The amount for the Successor in 2004 includes the mark-to-market gain on interest rate swaps not yet designated as cash flow hedges prior to December 31, 2004. In 2006, the amount includes the mark-to-market loss for the period during which the swaps did not qualify for cash flow hedge accounting. See Note 3 above.
b
Represents the portion of pension, other postretirement 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 and prior to the implementation of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry on January 1, 2006, the cost associated with removal of overburden to uncover coal reserves was deferred until the related coal is mined and charged to Cost of coal sales when the coal is sold. All partially and fully uncovered coal valued at the Acquisition date was sold by December 31, 2005. For the twelve months ended December 31, 2005 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004, Depreciation, depletion and amortization included the value of overburden removal performed prior to the Acquisition date, which would have been included in Cost of coal sales if incurred subsequent to the Acquisition date.
e
Represents compensation expense attributable to stock options and restricted stock units.
(11)
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 $0.5 million in the period January 1, 2004 to July 29, 2004 and $1.6 million in 2003. In 2007, amount primarily represents contract termination costs of $5.2 million incurred in connection with the idling of the Wabash mine.
b
Represents the cost of a one-time bonus awarded to certain employees in connection with the Acquisition.
c
Represents the cost of a long-term incentive plan instituted by the Predecessor 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
In 2004, amount 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. In 2006, amount represents a loss of longwall shields at the Emerald mine due to geological conditions. In 2007, amount primarily represents employee termination costs of $9.3 million incurred in connection with the idling of the Wabash mine.
(12)
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.
(13)
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 the deficiency of $142.4 million for the seven months ended July 29, 2004.
PART II
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION.
Overview
We are the fourth largest coal producer in the United States, operating eight mining complexes that consist of thirteen individual coal mines. Our mining operations are located in southwest Pennsylvania, southern West Virginia and the southern Powder River Basin region of Wyoming. Four of our operations are surface mines, two of our operations are underground mines using highly efficient longwall mining technology and the remaining seven operations 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 10.7% and 9.3% of our 2007 and 2006 coal sales revenues, respectively, were derived 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, Dry Systems Technologies equipment and filters and natural gas.
From July 1, 1999 through July 29, 2004, we were known as RAG American Coal Holding, Inc. and 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.
Foundation Coal Holdings, LLC (“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. A Stock Purchase Agreement was signed on May 24, 2004.
On April 23, 2004, Foundation Coal Corporation (“FCC” or the “Company”) was formed as a wholly owned subsidiary of LLC. FCC issued 100 shares of common stock with a par value of $0.01 to LLC. LLC was formed as a Delaware limited liability company, which, as described below, later contributed its shares of FCC and merged into Foundation Coal Holdings, Inc.
LLC, through its subsidiary, FCC, and pursuant to the Stock Purchase Agreement, completed an acquisition of 100% of the outstanding common shares of RAG American Coal Holding, Inc. and its subsidiaries from RAG on July 30, 2004 (the “Acquisition”).
LLC merged on August 17, 2007 into its subsidiary, Foundation Coal Holdings, Inc., a Delaware corporation that was formed on July 19, 2004. Foundation Coal Holdings, Inc. was the surviving entity in this merger. Accordingly, the Company became an indirect wholly owned subsidiary of Foundation Coal Holdings, Inc. On December 9, 2004, Foundation Coal Holdings, Inc. completed an initial public offering of 24,121,900 shares of common stock and became the entity we refer to herein as the “Public Parent.”
Results of Operations
Twelve Months Ended December 31, 2007 Compared to Twelve Months Ended December 31, 2006
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 revenues for the twelve months ended December 31, 2007 increased by $12.5 million, or 1% compared to coal sales revenues for the twelve months ended December 31, 2006. Tons sold decreased by less than 1% period-over-period and average coal sales realization per ton increased 1% period-over-period. The consolidated weighted-average sales realization per ton for the twelve months ended December 31, 2007 reflected a higher proportion of lower value Powder River Basin shipments compared to the same period in 2006.
Coal sales revenues in Northern Appalachia for the twelve months ended December 31, 2007 decreased by $14.0 million, or 2.6% compared to coal sales revenues for the twelve months ended December 31, 2006 due primarily to a combination of lower coal sales volumes from lower tons shipped and lower coal quality premium/penalty revenue, partially offset by higher base revenue. Coal sales revenue realization per ton in Northern Appalachia increased 3.4% period-over-period due to higher base revenue realization per ton, partially offset by lower coal quality premium/penalty revenue. Coal sales volumes in Northern Appalachia decreased by 0.8 million tons period-over-period as a result of decreased production and shipments from both mines. Tons sold at the Cumberland mine decreased 5.0% in the twelve months ended December 31, 2007 compared to the prior year period due to the nine day strike by the UMWA that began shortly after the wage agreement expired on April 1, 2007 and the scheduled longwall move that took place in the second quarter of 2007, inclusive of receiving an unanticipated regulatory ruling that delayed the restart of longwall production subsequent to the completion of the move. Emerald production and shipments were lower in 2007 compared to 2006 due to the nine day strike by the UMWA and geological challenges encountered in the third quarter which hindered mining activities and slowed production. Tons sold at the Emerald mine decreased 6.8% in the twelve months ended December 31, 2007 compared to the prior year period.
Coal sales revenues in Central Appalachia for the twelve months ended December 31, 2007 increased $1.3 million, or less than 1% compared to coal sales revenues for the twelve months ended December 31, 2006 primarily as a result of higher base revenues that were partially offset by lower coal quality premium/penalty revenues. Coal sales revenue realization per ton increased 4.9% period-over-period as a result of higher base revenue and lower coal quality premium/penalty revenue per ton. Coal sales volumes declined by 0.4 million tons, or 4.4% in the twelve months ended December 31, 2007 compared to the prior year period. Coal sales volumes in Central Appalachia decreased at all mining operations except for the Pax surface mine and from Laurel Creek’s underground mines. Production in Central Appalachia was adversely impacted by reduced mining activities at the Rockspring mine in June 2007 to address regulatory issues related to new standards established for underground seals.
Coal sales revenues in the Powder River Basin for the twelve months ended December 31, 2007 increased $50.1 million, or 12.0% compared to coal sales revenues for the twelve months ended December 31, 2006. Coal sales revenue realization per ton sold increased 8.2% due to higher base revenue related to increased shipments under higher priced contracts in 2007, partially offset by lower coal quality premium/penalty revenue. Coal sales volumes in the Powder River Basin increased by 1.7 million tons, or 3.4% to a record twelve month shipment level of 51.6 million tons primarily due to an 8.2% increase in both production and shipments from the Belle Ayr mine, partially offset by lower period-over-period production and shipments at the Eagle Butte mine.
Coal sales revenues in the Illinois Basin for the twelve months ended December 31, 2007 decreased substantially compared to coal sales revenues for the twelve months ended December 31, 2006 due to the April 4, 2007 idling of the Wabash mine in southern Illinois.
Revenues from purchased coal activities by our trading group remained flat in the twelve months ended December 31, 2007 compared to the prior year period. Coal is purchased for physical delivery to customers.
Other revenues for the twelve months ended December 31, 2007 increased by $6.8 million (22.6%) compared to the twelve months ended December 31, 2006. The increase was due to: (a) increased gains on the sale of assets ($4.3 million); (b) higher coalbed methane sales ($1.3 million); (c) increased miscellaneous other revenues ($3.6 million); (d) increased natural gas revenues ($3.0 million); partially offset by (e) lower synfuel fees ($1.1 million); (f) lower transloading and plant processing fees ($1.8 million); (g) decreased royalty revenues ($1.4 million); and (h) decreased revenues from the sale of equipment and filters by Dry Systems Technologies ($1.1 million).
Costs and Expenses
Cost of coal sales. Cost of coal sales increased $20.6 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006, primarily due to: (a) increases in labor and benefit costs as a result of both compensation increases and hiring of additional personnel ($20.8 million); (b) increases in royalties due to mining a higher proportion of coal subject to federal royalty ($1.7 million); (c) higher repair and maintenance and operating supply costs ($7.5 million); (d) increases in outside services ($3.9 million); (e) increased property, sales and production taxes ($7.6 million); (f) increased longwall move expenses ($2.1 million); and increased miscellaneous other expenses ($4.6 million) partially offset by (h) decreased transportation and loading costs ($4.3 million); decreased purchased coal costs as a result of lower purchased coal volumes ($17.6 million); and (i) a period-over-period decrease in inventory charges to expense related to an overall higher ratio of tons produced vs. tons sold in the twelve months ended December 31, 2007 compared to the prior year period ($5.7 million). Cost of coal sales per ton was $15.37 for the twelve months ended December 31, 2007 compared to $15.03 per ton for the twelve months ended December 31, 2006.
Selling, general and administrative expenses. Selling, general and administrative expenses for the twelve months ended December 31, 2007 increased $8.0 million compared to the twelve months ended December 31, 2006. Period-over-period increases were due to: (a) higher expenses incurred for employee compensation and benefit related expenses ($6.6 million); (b) higher consulting fees primarily related to implementation activities for our enterprise resource planning (“ERP”) software that do not qualify as capital expenditures ($2.5 million); partially offset by (c) lower miscellaneous overhead expenses including legal and insurance expenses ($1.1 million).
Accretion on asset retirement obligations. Accretion on asset retirement obligations is a result of accounting for asset retirement obligations under Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). Accretion represents the increase in the asset retirement liability to reflect the change in the liability for the passage of time because the initial liability is recorded at present value. Higher accretion expense in 2007 was due to increased asset retirement obligation estimates.
Write-down of long-lived assets. In the fourth quarter of 2006, the company recognized a $30.8 million non-cash asset impairment charge which included $29.4 million to write down the carrying value of certain impaired assets at its Wabash mine and $1.4 million to write-off a non-recoverable prepaid royalty in Central Appalachia in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets (“SFAS No. 144”).
Depreciation, depletion and amortization. Depreciation, depletion and amortization includes depreciation of plant and equipment, cost depletion of amounts assigned to owned and leased mineral rights, amortization of mine development costs, internal use software and leasehold improvements. Depreciation, depletion and amortization expense increased $18.8 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006, primarily due to increased cost depletion and higher depreciation and amortization. Cost depletion increased by $1.7 million due to increased production period-over-period. Depreciation and amortization increased by $17.1 million in the twelve months of 2007 mainly due to capital additions to plant and equipment during the twelve months ended December 31, 2007 and the depreciation of the recently placed in service ERP software, which began depreciation at the beginning of the second quarter of 2007. Also contributing to higher depreciation expense in the twelve months ended December 31, 2007 was the completion of an overland conveyor belt that was placed into service in the third quarter of 2007 at the Powder River Basin.
Coal supply agreement amortization. Application of purchase accounting in 2004 resulted in the 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 date of Acquisition of mining assets by the Company in 2004. Coal supply agreement amortization decreased $9.7 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006. Amortization of the liability for below market priced coal supply agreements during the twelve months ended December 31, 2007 was $14.1 million of credit to expense compared to $33.5 million of credit to expense in the comparable period of the prior year. Amortization of the asset for above market priced coal supply agreements during the twelve months ended December 31, 2007 was $10.7 million of expense compared to $20.4 million of expense in the comparable period of the prior year. As shipments on coal supply agreements valued in purchase accounting are completed, the period-over-period impact of the amortization on both the asset and liability balances will continue to diminish until approximately 2010 when shipments associated with these coal supply agreements are estimated to be complete.
Employee and contract termination costs and other. As discussed below in the section entitled “Wage Negotiations with the UMWA and Idling of the Company’s Illinois Basin Mining Operation,” the UMWA wage agreement for Wabash expired at 11:59 p.m. on March 31, 2007. The Company would not sign a new agreement for Wabash and the hourly workforce continued to work without a formal agreement of the parties under the terms of the expired wage agreement until 12:01 a.m. on April 4, 2007 at which time the UMWA represented hourly workforces went on strike. On the same day, Wabash announced the idling of the mine in southern Illinois. As a result of the Wabash mine idling, the Company recognized employee termination costs of $6.0 million and $1.3 million in accordance with the provisions of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (“SFAS No. 146”) and the provisions of SFAS No. 112, Employers’ Accounting for Postemployment Benefits (“SFAS No. 112”), respectively. During the twelve months ended December 31, 2007, the Company also recognized $2.0 million of direct and incremental costs related to additional benefit claims for certain severed employees. These employee termination costs are included in Employee and contract termination costs and other in the Consolidated Statements of Operations and Comprehensive Income for the twelve month period ended December 31, 2007.
Wabash was the seller under two coal supply agreements supplied from the Wabash mine with Duke Energy Indiana, Inc. Wabash continued to ship coal under the coal supply agreements through April 3, 2007, just prior to the mine idling. Each agreement contained force majeure language excusing the seller from supplying coal in the event of a work stoppage. On April 3, 2007, Wabash and Duke Energy Indiana, Inc. executed a Termination Agreement and Mutual Release buying-out, subject to certain conditions, all obligations under their two contracts in exchange for a cash payment of $5.7 million which was paid by the Company on April 5, 2007. The Company believes there will be no further obligations of Wabash under these two contracts. As a result, the Company recognized $5.2 million of net contract termination costs in accordance with the provisions of SFAS No. 146. These costs are included in Employee and contract termination costs and other in the Consolidated Statements of Operations and Comprehensive Income for the twelve month period ended December 31, 2007.
Segment Analysis
Utilizing data published by Argus Media, the following graph sets forth representative steam coal prices in various U.S. markets summarized for the monthly periods from January 1, 2006 through December 31, 2007. The prices are not necessarily representative of the coal prices actually obtained by the Company. Changes in coal prices have an impact over time on the Company’s average sales realization per ton and, ultimately, its consolidated financial results.
Source: Argus Media as published in Coal Daily
CAPP - Central Appalachia
ILB - Illinois Basin
Pitt 8 - Pittsburgh 8 Seam (Northern Appalachia)
PRB - Powder River Basin
* of sulfur dioxide (SO2) per MMBtu
Powder River Basin- Income from operations increased $28.4 million period-over-period due to increased revenues of $50.6 million, partially offset by increased production costs of $22.2 million. As explained in the revenue section above, the increased revenues resulted from a 3% increase in tons sold and an 8% increase in average coal sales realization per ton. Assuming acceptable market conditions exist, we expect future increases in tons sold at the Belle Ayr mine primarily due to the expansion of its annual capacity. Production costs increased $22.2 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006, reflecting higher period-over-period cost of sales of $28.3 million, an increase in other miscellaneous expenses of $1.4 million, partially offset by lower depreciation, depletion and amortization costs of $7.5 million.
The $28.3 million increase in cost of sales referred to above resulted from an increase in cash costs ($28.2 million) and increased miscellaneous other expenses ($0.1 million). The $28.2 million period-over-period increase in cash costs were primarily in the following areas: (a) excise taxes and coal production taxes, which respond to changes in coal sales revenues ($9.2 million); (b) supply and service costs primarily consisting of operating supply costs, explosives, diesel fuel and outside services ($12.4 million); (c) labor and employee benefits ($4.0 million); (d) rental expense ($1.7 million); (e) increased royalty costs due to mining a higher amount of coal that is subject to federal royalties ($1.0 million); partially offset by (f) miscellaneous expenses ($0.1 million). Cost of coal sales per ton increased 5.7% period-over-period.
Lower total depreciation, depletion and amortization costs of $7.5 million related primarily to a period-over-period $10.1 million reduction in charges for the amortization of coal supply agreements, as shipments on a number of coal supply agreements valued in purchase accounting were completed, partially offset by higher depreciation and depletion of $2.6 million as a result of higher capital expenditures during the prior twelve months and increased production period-over-period. Also contributing to the higher depreciation expense was the completion of an overland conveyor belt that was placed into service during the three months ended September 30, 2007.
Northern Appalachia- Income from operations decreased by $52.2 million period-over-period due to decreased revenues of $7.1 million and increased production costs of $45.1 million. As explained in the revenue section above, the decreased revenues resulted from a 6% period-over-period decrease in tons sold, partially offset by a 3% increase in average sales realization per ton. Coal sales volumes decreased primarily as a result of decreased production and shipments from both mines. Cumberland production and shipments were lower in 2007 due to the nine day strike by the UMWA that began shortly after the wage agreement expired on April 1, 2007 and the scheduled longwall move that took place in the second quarter of 2007 inclusive of receiving an unanticipated regulatory ruling that delayed the restart of longwall production subsequent to the completion of the move. Emerald production and shipments were lower in the 2007 period due to the nine day strike by the UMWA and geological challenges encountered during the third quarter of 2007 which hindered mining activities and slowed production. Tons sold at the Emerald mine decreased 7% in the twelve months ended December 31, 2007 compared to the prior year.
Total production costs increased $45.1 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006, reflecting higher period-over-period cost of sales of $27.8 million, higher depreciation, depletion and amortization costs of $16.2 million and higher miscellaneous other costs of $1.1 million.
The $27.8 million period-over-period increase in cost of sales referred to above was the result of increased cash costs $35.1 million, partially offset by decreased purchased coal expense ($3.4 million), lower miscellaneous other costs ($1.1 million) and decreased inventory charges to expense related to a higher ratio of tons produced vs. tons sold in the twelve months ended December 31, 2007 compared to the prior year ($2.8 million). The $35.1 million increase in cash costs were primarily incurred in the following areas: (a) higher labor and employee benefit costs, due to a higher number of employees and period-over-period wage and benefit increases, due primarily to the new UMWA wage agreement ($27.8 million); (b) higher supply and service costs primarily consisting of operating supply costs from increased usage of roof bolts, miner bits and water handling requirements, repairs and maintenance costs due to the timing of rebuilding longwall and other mining equipment and outside services ($10.1 million); (c) higher longwall move expenses ($2.1 million); partially offset by (d) lower transportation and loading costs ($3.9 million); and (e) lower miscellaneous expenses ($1.0 million). Cost of coal sales per ton increased by 15.2% period-over-period principally reflecting the effect of the UMWA strike and difficult geological conditions described above.
Higher total depreciation, depletion and amortization costs of $16.2 million related primarily to: (a) a period-over-period reduction in the credit associated with the amortization of coal supply agreements as shipments on a number of coal supply agreements valued in purchase accounting were completed ($9.9 million); (b) increased depreciation primarily related to a batch weigh system, longwall shields, face conveyors and other mining equipment ($6.7 million); and (c) lower depletion expense ($0.4 million) as a result of lower production by both mines during 2007.
Central Appalachia- Income from operations decreased by $13.6 million period-over-period due to increased revenues of $2.8 million that were offset by increased production costs of $16.4 million. As explained in the revenue section above, the increase in revenues resulted from a 5% increase in average sales realization per ton, partially offset by a 4% period-over-period decrease in tons sold. Total coal sales revenues for the twelve months ended December 31, 2007 remained flat compared to the twelve months ended December 31, 2006. Coal sales volumes in Central Appalachia decreased by 0.4 million tons (4%) period-over-period primarily from decreased shipments from all West Virginia mining operations except for the Pax surface mine and from Laurel Creek’s underground mines. Production in Central Appalachia was adversely impacted by reduced mining activities at the Rockspring mine in June 2007 to address regulatory issues related to new standards established for underground seals.
The increase in production costs of $16.4 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006 consisted of higher depreciation, depletion and amortization ($19.3 million), partially offset by decreased cost of sales of ($2.4 million) and decreased miscellaneous other costs ($0.5 million). The $2.4 million decrease in cost of sales was a result of increased cash costs ($13.0 million), offset by a reduction in purchased coal expense ($12.2 million), decreased miscellaneous other expenses ($0.4 million) and a period-over-period decrease in inventory charges to expense related to a higher ratio of tons produced vs. tons sold in the twelve months ended December 31, 2007 compared to the prior year ($2.8 million).
The $13.0 million period-over-period increase in cash costs referred to above was primarily due to increases in the following areas: (a) labor and fringe benefits ($7.2 million); (b) supply and service costs primarily consisting of repairs and maintenance costs, operating supplies, utility, explosives, fuel costs and outside services ($4.7 million); (c) higher royalty expense ($1.2 million); (d) higher transportation and loading costs ($2.6 million); partially offset by (f) lower contract mining costs ($2.4 million); and (g) lower other miscellaneous costs ($0.3 million). Cost of coal sales per ton increased approximately 3.9% period-over-period.
The $19.3 million increase in depreciation, depletion and amortization consisted of higher depreciation of $7.5 million related to increased capital expenditures during the prior twelve months, higher reserve depletion of $1.6 million related to increased production period-over-period in mines that carry a higher depletion rate and a reduced credit to expense for amortization of coal supply agreements of $10.2 million as shipments on a number of coal supply agreements valued in purchase accounting were completed.
Other- Includes the Company’s Illinois Basin operation, including the idled Wabash mine, which ceased operations in the second quarter of 2007; expenses associated with closed mines; its Dry Systems Technologies; its coal trading operations and selling, general and administrative expenses not charged out to the Powder River Basin, Northern Appalachia or Central Appalachia mines. During the twelve months ended December 31, 2007, the Other segment reported a loss from operations of $88.1 million compared to a loss from operations of $102.1 million in the twelve months ended December 31, 2006. The decreased period-over-period loss from operations of $14.0 million was primarily due to the absence of long-lived asset impairment charges in 2007, partially offset by employee and contract termination costs incurred as a result of the idling of the Wabash mine and higher selling, general and administrative expenses.
Interest Expense, Net
Interest expense, net for the twelve months ended December 31, 2007 was lower than the twelve months ended December 31, 2006 due primarily to decreased amortization of deferred financing costs and lower surety bond and letter of credit fees. Interest expense related to the amortization of deferred financing costs in the twelve months ended December 31, 2006 included a $9.2 million write-off of unamortized deferred financing costs recorded as a result of the Company’s amendment to its debt agreement in July 2006. In 2007, the Company wrote off $0.2 million of unamortized deferred financing costs associated with the prepayment of $25.1 million of the term loan. The remaining reduction in the amortization of deferred financing cost period-over-period was caused by a lower deferred financing asset balance being amortized due to the aforementioned write-off in 2006. The reduction in surety bond and letter of credit fees was primarily attributable to fewer letters of credit outstanding.
Income Tax Benefit (Expense)
For the twelve months ended December 31, 2007, income taxes were provided at an effective benefit rate of 30.2%. For the twelve months ended December 31, 2006 income taxes were provided at an effective rate of 10.9%. The most significant reason for the increase in income tax benefit for 2007 is due to the decrease in production and operating income at the Company’s Emerald mine, which increased the impact of the permanent differences for excess depletion deductions on the effective tax rate. In addition, the Cumberland mine generated additional permanent differences for percentage depletion in 2007 compared to 2006.
Expected Coal Production
As of January 25, 2008, uncommitted and unpriced tonnage was 6%, 32%, 65% and 87% of planned shipments in 2008, 2009, 2010 and 2011 respectively.
In 2008 through 2011, the Company expects coal shipments within the following ranges (millions of tons):
Based on its committed and priced planned shipments as of January 25, 2008, the Company expects its committed and priced tonnage from its Eastern mines, encompassing Northern Appalachia and Central Appalachia, to realize $46.99, $44.62 and $47.24 per ton in 2008, 2009 and 2010, respectively. The Company does not have any committed and priced shipments from its Eastern mines in 2011. The Company also expects its committed and priced tonnage from the Powder River Basin to realize $9.95, $10.18, $10.55 and $10.85 per ton in 2008, 2009, 2010 and 2011, respectively. These expected per ton average realizations include forecast sulfur dioxide and British thermal units premiums based on contract terms, projected coal qualities and historical realized premiums.
Twelve Months Ended December 31, 2006 Compared to Twelve Months Ended December 31, 2005
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 revenues for the twelve months ended December 31, 2006 increased by 11% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of a 7% increase in tons sold and a 4% increase in average coal sales realization per ton.
Coal sales revenues in Northern Appalachia for the twelve months ended December 31, 2006 increased by 12% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of an 11% increase in average coal sales realization per ton and a 1% increase in tons sold. Revenue realization per ton sold in Northern Appalachia increased in 2006 due to the substitution of higher priced contracts which took effect in late 2005 and early 2006 for lower priced contracts that expired offset by lower coal quality premiums. Coal sales volumes in Northern Appalachia increased by 0.1 million tons (1%) period-over-period mainly as a result of increased shipments and production from the Cumberland mine, partially offset by decreased shipments and production from the Emerald mine due to difficult mining conditions experienced throughout the year. Emerald had two scheduled longwall moves during 2006 compared to one scheduled longwall move during 2005, the result of which contributed to lower period-over-period production and sales. Cumberland had one scheduled longwall move in both 2006 and 2005.
Coal sales revenues in Central Appalachia for the twelve months ended December 31, 2006 increased by 10% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of an 11% increase in average coal sales realization per ton offset by a 1% decrease in tons sold. Coal sales realization per ton sold in Central Appalachia increased in 2006 due to a combination of: (a) substitution of higher priced contracts which took effect in late 2005 and early 2006 for lower priced contracts that expired; and (b) higher coal quality premiums. Coal sales volumes in Central Appalachia decreased by 0.1 million tons (1%) period-over-period as a result of decreased shipments and production from all our mining operations with the exception of the Pax surface mine and the Laurel Creek mines. Central Appalachia production and shipments were higher in the first quarter of 2006 compared to 2005 due to shipments of purchased coal utilized on selected steam coal contracts. However, in the remaining three quarters of the year, overall production was lower in 2006 compared to 2005 a result of difficult mining conditions experienced throughout the year, resulting in lower shipments and sales volumes. The Pax surface mine, which replaced the Simmons Fork mine
that depleted its reserves in 2004, began production in the fourth quarter of 2004. In 2005 and 2006, Pax produced 0.6 million tons and 0.9 millions tons, respectively. Period-over-period production increases at Pax occurred as mine development progressed to its current state of completion. Pax is expected to produce at an annual rate of approximately 1.0 million tons per year before the integration of the mining assets of Pax South discussed in Significant Property Transactions below.
Coal sales revenues in the Powder River Basin for the twelve months ended December 31, 2006 increased by 29% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of a 12% increase in average coal sales realization per ton and a 14% increase in tons sold. Base revenue realization per ton increased by 11% period-over-period while coal quality premium/penalty revenue increased 33% period-over-period. Coal sales realization per ton increased due to the commencement of shipments under higher priced contracts and higher coal quality premiums. Coal sales volumes in the Powder River Basin increased by 6.3 million tons (14%) to a record shipment level of 49.9 million tons primarily due to a 26% increase in both production and shipments from the Belle Ayr mine where annual production capacity was increased by 5.0 million tons effective January 1, 2006. Eagle Butte production and shipments increased 5% period-over-period primarily due to favorable second and third quarter of 2006 operating results.
Coal sales revenues in the Illinois Basin for the twelve months ended December 31, 2006 decreased by 31% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of a 31% decrease in tons sold, while average coal sales realization per ton remained consistent between years. Base revenue realization per ton increased slightly period-over-period while coal quality premium/penalty revenue decreased period-over-period. Coal sales volumes from the Illinois Basin decreased by 0.5 million tons (31%), reflecting 32% lower production from the Wabash mine due to the diversion of scheduled operating shifts to maintain the mine’s underground infrastructure and the mine’s compliance with federal and state regulations, coupled with a lower clean coal recovery percentage as compared to the same period in 2005.
Purchased coal activities by our trading group decreased by approximately 0.7 million tons (83%), compared to the same period in 2005, due to decreased trade activities and the timing of purchased coal transactions. Coal is purchased for physical delivery to customers.
Other revenues for the twelve months ended December 31, 2006 increased by $5.6 million (23%) compared to the twelve months ended December 31, 2005. The increase was primarily due to increased royalty income ($2.4 million) and increased miscellaneous revenues from our Dry Systems Technologies subsidiary ($3.0 million).
Costs and Expenses
(1)
Excluding the credit related to deferral of costs associated with overburden removal in the year ended December 31, 2005, cost of coal sales increased approximately 14%.
Cost of coal sales. The cost of coal sales increased $174.7 million for the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005 primarily due to: (a) increases in labor costs as a result of both compensation increases and hiring of additional personnel ($34.3 million); (b) increases in repair and maintenance supplies, consumables and commodity supply costs, most notably diesel fuel, and large equipment tires and explosives ($88.9 million); (c) increases in royalties and coal production taxes as a result of higher revenues ($21.8 million); (d) decreases in purchased coal costs as a result of lower purchased coal volumes ($15.7 million); (e) an accounting change, effective January 1, 2006, requiring expensing of overburden removal costs ($42.9 million); (f) an increase to expense from decreased coal inventories in 2006 compared to increased coal inventories in 2005 ($11.0 million); (g) a decrease in longwall move expense ($5.1 million); (h) a decrease in expenses associated with contractor mining ($5.4 million); and (i) increases in other miscellaneous expenses ($2.0 million). Production costs increased partly due to higher
period-over-period production. Cost of coal sales per ton was $15.03 for the twelve months ended December 31, 2006 compared to $13.64 per ton for the twelve months ended December 31, 2005. The $13.64 cost of coal sales per ton for the twelve months ended December 31, 2005 includes a $42.9 million credit related to the deferral of cost associated with overburden removal. Subsequent to the Company’s adoption of Emerging Issues Task Force (“EITF”) Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry (“EITF Issue 04-6”), on January 1, 2006, such costs were no longer deferred. Cost of coal sales per ton was $14.26 after adjusting for the impact of the accounting change for overburden removal costs, an increase of approximately 5%.
Selling, general and administrative expenses. Selling, general and administrative expenses for the twelve months ended December 31, 2006 was $50.7 million compared to $48.4 million for the twelve months ended December 31, 2005. period-over-period increases were due to additional expenses incurred for employee expenses ($3.2 million) and outside services ($0.1 million), partially offset by lower insurance expenses and reduced sales commissions (combined $1.0 million).
Accretion on asset retirement obligations. Accretion on asset retirement obligations 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. Slightly higher accretion expense in 2006 was due to increased asset retirement obligation estimates at closed mines.
Write-down of long-lived assets. In the fourth quarter of 2006, the company recognized a $30.8 million non-cash asset impairment charge which included $29.4 million to write down the carrying value of certain impaired assets at its Wabash mine and $1.4 million to write-off a non-recoverable prepaid royalty in Central Appalachia in accordance with SFAS No. 144. In the fourth quarter of 2005, the company recognized a $1.6 million non-cash asset impairment charge related to development costs that were attributable to expanding certain undeveloped areas of mining districts in the Company’s Northern Appalachia business unit. As a result of a change in the Company’s mine plan, these costs were no longer considered recoverable.
Depreciation, depletion and amortization. Depreciation, depletion and amortization includes depreciation of plant and equipment, cost depletion of amounts assigned to coal lands and mining rights and amortization of mine development costs and leasehold improvements. Depreciation, depletion and amortization expense decreased $28.0 million for the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005, primarily due to lower cost depletion partially offset by higher depreciation and amortization. Cost depletion declined by $44.2 million due to a combination of: (a) lack of depletion expense in 2006 pertaining to purchase accounting values assigned to partially and fully uncovered coal at the Powder River Basin surface mines as these assets were fully depleted during 2005; and (b) final purchase accounting adjustments recorded in 2005 that reduced the values assigned to coal lands and mining rights, partly offset by higher production in the Powder River Basin during 2006. Depreciation and amortization increased by $16.2 million in 2006 mainly due to capital additions to plant & equipment during the twelve months ended December 31, 2006.
Amortization of coal supply agreements. 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 date of Acquisition. Coal supply agreement amortization decreased $71.8 million for the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005. Amortization of the liability for below market priced coal supply agreements during the twelve months ended December 31, 2006 was $33.5 million of credit to expense compared to $109.9 million of credit to expense in the comparable period of the prior year. Amortization of the asset for above market priced coal supply agreements during the twelve months ended December 31, 2006 was $20.4 million of expense compared to $25.0 million of expense in the comparable period of the prior year. During the twelve months ended December 31, 2006, shipments on a number of coal supply agreements valued in purchase accounting were completed.
Segment Analysis
Utilizing data published by Argus Media, the following graph sets forth representative steam coal prices in various U.S. markets summarized for the monthly periods from January 1, 2005 through December 31, 2006. The prices are not necessarily representative of the coal prices actually obtained by the Company. Changes in coal prices have an impact over time on the Company’s average sales realization per ton and, ultimately, its consolidated financial results.
Source: Argus Media as published in Coal Daily
CAPP - Central Appalachia
ILB - Illinois Basin
Pitt 8 - Pittsburgh 8 Seam (Northern Appalachia)
PRB - Powder River Basin
* of sulfur dioxide (SO2) per MMBtu
Powder River Basin-Income from operations increased $23.4 million period-over-period due to increased revenues of $92.7 million, partly offset by increased production costs of $69.3 million. As explained in the revenue section above, the increased revenues resulted from a 14% increase in tons sold from record 2006 shipments and a 12% increase in average sales realization per ton. The increase in tons sold is primarily due to the expansion of annual capacity at the Belle Ayr mine and favorable second and third quarter of 2006 operating results at the Eagle Butte mine which resulted in a total period-over-period increase in production and shipments of 15% and 14%, respectively. Increased production costs were primarily in the following areas: (a) royalties, excise taxes and coal production taxes, which respond to changes in coal sales revenues ($14.5 million); (b) diesel fuel and utilities ($13.3 million); (c) repairs and maintenance ($6.8 million); (d) large equipment tires and other operating supplies ($6.0 million); (e) explosives ($4.7 million); (f) labor and employee benefits ($7.8 million); (g) other supplies and services ($1.4 million); and (h) depreciation and amortization ($6.2 million). Certain production cost increases occurred due to higher period-over-period production. There was a period-over-period $4.6 million reduction in amortization of coal supply agreements as shipments on a number of supply agreements valued in purchase accounting were completed. Production costs in the twelve months ended December 31, 2005 included a $42.9 million credit for overburden removal costs added to work-in-process inventory offset by $31.8 million in higher cost depletion expense in the prior year mainly relating to depletion of partially and fully uncovered coal established in purchase accounting. With the implementation of EITF Issue 04-6, effective January 1, 2006, the Powder River Basin mines are no longer recognizing work-in-process inventory for uncovered coal. Cost of coal sales per ton, after adjusting for the impact of the accounting change for overburden removal costs, increased approximately 6% period-over-period for reasons discussed above.
Northern Appalachia-Despite higher revenue of $57.4 million, income from operations decreased by $30.7 million period-over-period due to increased cost of coal sales of $89.8 million offset by $1.7 million of miscellaneous income. Increased revenues resulted from a 1% increase in tons sold and an 11% increase in average sales realization per ton. The increase in sales was primarily due to a 9% increase in shipments from the Cumberland mine as production in all but the third quarter of 2006 increased over 2005 quarters as a result of good mining conditions and strong longwall productivity. The production decline in the third quarter of 2006, compared to 2005, resulted from a scheduled longwall move which shut down longwall mining operations for an approximate two week period during the 2006 quarter. Cumberland had a longwall move in the fourth quarter of 2005. Production from the Emerald mine declined 12% period-over-period, impacted by difficult mining conditions and equipment problems experienced throughout the year which resulted in a 7% decline in shipments. Increased cost of coal sales consisted primarily of $89.8 million of higher production costs, represented by increases in the following areas: (a) labor and employee benefit costs ($10.0 million); (b) repairs and maintenance costs ($7.5 million); (c) other materials, supplies and services ($12.9 million); (d) insurance premiums ($1.2 million); (e) diesel fuel and utilities ($2.0 million); (f) depreciation and amortization ($4.2 million); (g) reduced credit for amortization of coal supply agreements ($48.0 million); (h) operating supplies ($4.9 million); and (i) royalties, excise taxes and coal production taxes, which correspond to changes in coal sales revenues ($1.0 million), partly offset by reduced cost depletion of $8.5 million and lower longwall move costs ($5.1 million). Cost of coal sales per ton increased approximately 14% period-over-period.
Central Appalachia-Income from operations decreased by $39.0 million period-over-period due to increased cost of coal sales of $52.2 million, increased depreciation and amortization expense of $5.4 million, a reduced credit to expense for amortization of coal supply agreements of $23.2 million and a pre-tax charge of $1.4 million to write-down prepaid royalties associated with certain mining leases, partly offset by increased revenues of $38.5 million and reduced cost depletion expense of $3.7 million. The increase in revenues resulted from an 11% increase in average sales realizations per ton resulting from the roll-off of lower priced coal sales agreements from 2005. Tons sold decreased slightly despite increased tons that were purchased and resold and period-over-period 68% and 64% increases in production and shipments, respectively, at the Pax surface mine due to the completion of mine development. Higher cost of coal sales were primarily due to increases in the following areas: (a) labor and fringe benefits ($10.4 million); (b) materials, supplies and services, led by increases for maintenance and repairs, diesel fuel, explosives and contract trucking ($24.2 million); (c) purchased coal ($8.3 million); and (d) royalties and severance taxes ($6.7 million). Cost of coal sales per ton increased approximately 16% period-over-period.
Other-Includes the Company’s Wabash mine, located in the Illinois Basin, expenses associated with closed mines, its coal trading operations and selling general and administrative expenses not charged-out to the Powder River Basin, Northern Appalachia or Central Appalachia mines. During the twelve months ended December 31, 2006, the Other segment reported a loss from operations of $102.1 million compared to a loss from operations of $51.9 million in the twelve months ended December 31, 2005. The increased period-over-period loss from operations of $50.2 million was primarily a result of an increased operating loss at the Wabash mine due to: (a) an approximate 30% decline in production and shipments, as described in the revenue section above; (b) higher cost of coal sales; (c) a $29.4 million write-down of the carrying value of long-lived assets; and (d) a reduced credit to expense from amortization coal supply agreements. The operating losses attributable to closed mines were less by $3.7 million in 2006 compared to 2005. The change in selling, general and administrative expenses not charged out to the other operating segments was de minimis period-over-period.
Interest Expense, Net
Interest expense, net for the twelve months ended December 31, 2006 includes a $9.2 million non-cash write-off of unamortized deferred financing costs recorded as a result of the Company’s amendment to its debt agreement as more fully described in the Liquidity and Capital Resources section below. Excluding this charge, interest expense, net for the twelve months ended December 31, 2006, was lower than the twelve months ended December 31, 2005 due primarily to lower surety bond and letter of credit fees and higher interest income resulting from interest on invested cash balances. The reduction in surety bond and letter of credit fees was primarily attributable to fewer letters of credit outstanding. Debt related interest expense for the twelve months ended December 31, 2006 was slightly higher than the debt related interest expense for the twelve months ended December 31, 2005 due to an approximate 125 basis point increase in the interest rate on variable rate debt, partly offset by the impact of repaying $50.0 million of variable rate debt in the second half of 2005.
Income Tax Expense
For the twelve months ended December 31, 2006, income taxes were provided at an effective rate of 10.9%. For the twelve months ended December 31, 2005 income taxes were provided at an effective rate of approximately 34.3%. The reduction in effective income tax rate period-over-period is primarily due to an increase in the percentage depletion at the Cumberland mine due to fully depleting its tax basis in coal reserves late in 2005. Because of excess depletion adjustments for tax purposes above the tax basis of the coal reserves, percentage depletion from Cumberland, which was treated as a temporary difference in the effective income tax rate used during 2005, is treated as a permanent difference in the effective income tax rate for 2006. In addition, the Emerald mine and the Central Appalachia mines generated increased percentage depletion, which is treated as a permanent difference, during 2006.
Significant Property Transactions
In the fourth quarter of 2007, Foundation PA Coal Terminal, LLC, an indirect wholly owned subsidiary of the Company, purchased a river dock facility in Fayette County, Pennsylvania for $1.4 million. The purchased assets consisted of land and barge loadout facility equipment that are recorded in Owned surface lands and Plant, equipment and mine development costs, net in the Consolidated Balance Sheets as of December 31, 2007. The purchase price was allocated to the assets based upon estimates of fair value.
In the third quarter of 2006, Pioneer Fuel Corporation, an indirect wholly owned subsidiary of the Company, purchased mining assets from Appalachian Fuels, LLC for $15.4 million. The purchased assets consisted of approximately 7.3 million tons of reserves, land and mining equipment. The acquired reserves are located adjacent to and will be integrated with the existing Pax surface operations and jointly managed. The acquired mine, referred to as Pax South, is expected to produce up to 720,000 tons per year, after it reaches full capacity, and to provide other synergies to existing properties. In accordance with terms set forth in the asset purchase agreements, $1.0 million of the purchase price was withheld for contingencies, but will be remitted to Appalachian Fuels eighteen months after the acquisition date if no contingencies materialize. The purchase price was allocated to the assets and asset retirement obligation acquired/assumed based upon estimates of fair value. In a separate transaction, coal stockpiles containing an estimated 8,300 tons were also acquired from Appalachian Fuels, LLC for $0.2 million.
Liquidity and Capital Resources
Sources and Uses of Cash
Our primary sources of cash have been from sales of our coal production and, to a much lesser extent, purchased coal to customers, cash from sales of non-core assets and miscellaneous revenues.
Our primary uses of cash have been our cash costs of coal production, 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 payable. Our ability to service debt 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 generally fund all of our capital expenditure requirements with cash generated from operations. Historically, we have engaged in minimal financing of assets such as through operating leases.
The following is a summary of cash provided by or used in each of the indicated categories of activities during the twelve months ended December 31, 2007 and 2006, respectively.
Cash provided by operating activities increased $13.9 million for the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006, primarily due to a $17.5 million increase in cash flows from working capital changes, partially offset by a $3.6 million decrease in non-cash add-backs to net income period-over-period. Working capital changes consisted primarily of (a) a $28.2 million cash flow increase from changes in trade accounts receivable; (b) a $6.3 million cash flow increase from changes in prepaid expenses and other current assets; and (c) a $13.4 million cash flow increase from changes in accrued expenses and other liabilities. These cash flow increases were partially offset by decreases in cash flows related to inventories, net and other non-current assets ($5.7 million) and trade accounts payable and other non-current liabilities ($24.7 million).
Cash used in investing activities decreased $34.4 million in the twelve months ended December 31, 2007 compared to the twelve months ended December 31, 2006, primarily due to: (a) a $27.5 million decrease in capital expenditures and mine asset acquisitions; and (b) a $6.9 million increase in asset sales proceeds. Capital expenditures in the twelve months ended December 31, 2007 totaled $174.4 million which included $62.3 million for the following projects: (a) an overland coal conveyor at the Belle Ayr mine in the Powder River Basin; (b) the acquisition of longwall components and upgrades to the rail loading facility at Emerald; (c) capital expenditures related to our coal gas recovery projects; and (d) the acquisition and implementation of company wide ERP software. Capital expenditures in the twelve months ended December 31, 2006 totaled $187.2 million, including a total of $99.0 million of expenditures related to the following projects: (a) an overland coal conveyor at the Belle Ayr mine in the Powder River Basin; (b) equipment for and development of the Pax surface mine and related rail loading facility in Central Appalachia; (c) upgrades to the rail loading facility at Emerald; (d) construction of a new slope, overland coal conveyor and related coal handling facilities at the Wabash mine in Illinois; (e) progress payments toward the purchase of a second longwall at the Emerald mine; and (f) the acquisition and implementation of company wide ERP software.
Cash used in financing activities during the twelve months ended December 31, 2007 consisted of: (a) cash dividends paid to the Public Parent of $44.3 million for the repurchase of common stock in accordance with an authorized stock repurchase program of the Public Parent and for the payment of ordinary dividends on the Public Parent’s common equity; (b) $26.8 million for repayments of long-term debt; and (c) returns of capital to the Public Parent of $1.1 million; offset by (d) $4.6 million of capital contributions from the Public Parent; (e) $4.1 million of other cash inflows; and (f) $3.3 million in excess income tax benefit from issuance of stock-based awards. Cash used in financing activities during the twelve months ended December 31, 2006 consisted of: (a) cash dividends paid to the Public Parent of $21.0 million for the repurchase of common stock in accordance with an authorized stock repurchase program of the Public Parent and for the payment of ordinary dividends on the Public Parent’s common equity; (b) $8.4 million for repayments of long- term debt; (c) $4.5 million of cash payments for deferred financing fees; and (d) returns of capital to the Public Parent of $2.4 million; offset by (e) $9.5 million in excess income tax benefit from issuance of stock-based awards; (f) $7.6 million of capital contributions from the Public Parent; and (g) $2.3 million in cash proceeds from the settlement of interest rate swaps.
The following is a summary of cash provided by or used in each of the indicated categories of activities during the twelve months ended December 31, 2006 and 2005, respectively.
Cash provided by operating activities increased in the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005 due to lower net income more than offset by increased non-cash adjustments to income and smaller changes in operating working capital, principally trade accounts receivable and inventories.
Cash used in investing activities increased in the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005 primarily from an increase in capital expenditures and the acquisition of mining assets. Capital expenditures in the twelve months ended December 31, 2006 totaled $187.2 million, including a total of $99.0 million of expenditures related to the following projects: (a) an overland coal conveyor at the Belle Ayr mine in the Powder River Basin; (b) equipment for and development of the Pax surface mine and related rail loading facility in Central Appalachia; (c) upgrades to the rail loading facility at Emerald; (d) construction of a new slope, overland coal conveyor and related coal handling facilities at the Wabash mine in Illinois; (e) progress payments toward the purchase of a second longwall at the Emerald mine; and (f) the acquisition and implementation of company wide ERP software. Capital expenditures for the twelve months ended December 31, 2005 totaled $140.2 million, including a total of $49.8 million of expenditures related to the following projects: (a) expansion of the Belle Ayr mine in the Powder River Basin; (b) development of the Pax surface mine in Central Appalachia; (c) addition of a continuous mining unit to the Kingston mine in Central Appalachia; (d) the widening of the Emerald mine longwall face to 1,450 feet from 1,250 feet; and (e) upgrades to the rail loading facility at Emerald.
Cash used in financing activities during the twelve months ended December 31, 2006 consisted of: (a) cash dividends paid to the Public Parent of $21.0 million for the repurchase of common stock in accordance with an authorized stock repurchase program of the Public Parent and for the payment of ordinary dividends on the Public Parent’s common equity; (b) $8.4 million for repayments of long-term debt; (c) $4.5 million of cash payments for deferred financing fees; and (d) returns of capital to the Public Parent of $2.4 million; offset by (e) $9.5 million in excess income tax benefit from issuance of stock-based awards; (f) $7.6 million of capital contributions from the Public Parent; and (g) $2.3 million in cash proceeds from the settlement of interest rate swaps. Cash used in financing activities during the twelve months ended December 31, 2005 consisted of: (a) $50.0 million for repayments of long-term debt; offset by (b) $0.3 million in excess income tax benefit from issuance of stock-based awards.
Liquidity and Long-Term Debt
Our primary source of liquidity will continue to be cash from sales of our coal production and to a much lesser extent, sales of purchased coal to customers. We have borrowing availability under our revolving credit facility, subject to certain conditions.
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 Secured Credit Facility will enable us to meet our working capital, capital expenditure, debt service and other funding requirements for at least the next twelve months.
As of December 31, 2007, we have outstanding $599.8 million in aggregate indebtedness, with an additional $327.4 million of available borrowings under our revolving credit facility after giving effect to $172.6 million of letters of credit outstanding as of December 31, 2007. Our liquidity requirements will be significant due to debt service requirements and projected capital expenditures.
Bank Debt Refinancing
Our Senior Secured Credit Facility consists of a revolving credit facility and a term loan facility.
During 2006, the Company completed an $835.0 million amended and restated Senior Secured Credit Facility (the “facility”) agreement consisting of a five-year $335.0 million Term Loan A and a five-year $500.0 million revolving credit facility. The facility, which matures on July 11, 2011, bears interest at an applicable margin, plus the lenders’ base rate or LIBOR at the Company’s option, and requires the Company to pay a commitment fee to the lenders for the unutilized portion of the commitment under the revolving credit facility based on a quarterly leverage ratio calculation. The revolving credit facility provides for up to $500.0 million for borrowings on same-day notice, referred to as swingline loans, LIBOR loans or letters of credit up to a maximum of the unutilized portion of the revolver. Costs capitalized in connection with the facility were $4.5 million and are being amortized over the term of the related indebtedness of five years, using the effective interest method. The Company wrote-off $9.2 million of unamortized deferred financing costs in the twelve months ended December 31, 2006, which is included in Interest expense in the Consolidated Statements of Operations and Comprehensive Income, as a result of the replacement of the original Senior Secured Credit Facility. The facility replaces the previous Senior Secured Credit Facility and provides more favorable pricing and financial flexibility.
On December 31, 2007 and December 29, 2006, the Company voluntarily prepaid $25.1 million and $8.4 million, respectively, of the outstanding balance of the term loan facility due in 2008/2009 and 2007, respectively, and wrote-off an additional $0.2 million and $0.1 million of unamortized deferred financing costs in the twelve months ended December 31, 2007 and 2006, respectively.
Borrowings under our Senior Secured Credit Facility bear interest at a floating rate plus an applicable margin. The highest applicable margin for borrowings under both the revolving credit facility and the term loan facility is 0.75% with respect to base rate borrowings and 1.75% with respect to LIBOR borrowings. Based on our leverage ratio as of December 31, 2007, the applicable margins on both the revolving credit facility and the term loan facility were 0.25% and 1.25%, respectively.
In addition to paying interest on outstanding principal under the Senior Secured Credit Facility, we are required to pay a commitment fee to the lenders under the revolving credit facility in respect of the unutilized commitments, beginning at a rate equal to 0.375% per annum of the unused commitment. Based on our leverage ratio as of December 31, 2007, our rate was 0.25%. We also pay customary letter of credit fees.
The Senior Secured Credit Facility requires us to prepay outstanding term loans, subject to certain exceptions, in certain situations. Any mandatory prepayments would be applied to the remaining scheduled installments of the term loan facility on a pro rata basis. Optional prepayments would be applied to the term loan facility at our direction. If prepaid, there may be a charge for any breakage costs.
At the inception of the facility, we were required to repay installments on the term loans in quarterly principal amounts of $4.2 million beginning in September 2007, stepping up to $8.4 million in September 2009, with the remaining balance of $242.9 million due on the July 11, 2011 maturity date. Because we prepaid $25.1 million of outstanding principal on December 30, 2007, we are not required to make a quarterly principal payment until September 2009.
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 Secured Credit Facility contains 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 7.25% 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. Financial covenants include an interest coverage ratio test, a leverage ratio test and a limit on capital expenditures.
The indenture governing our outstanding 7.25% Senior Notes limits 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 us by Foundation Coal Corporation of $25.0 million, plus, for payment of dividends, an amount up to 5% per calendar year of the net proceeds received by Foundation Coal Corporation from the IPO. Foundation Coal Corporation will have the ability, subject to certain exceptions as set forth in the indenture, to incur additional indebtedness if it meets certain conditions, including having greater than a 2.0 to 1.0 fixed charge coverage ratio.
Interest Rate Swaps
On September 30, 2004, the Company entered into pay-fixed, receive-variable interest rate swap agreements on a notional amount of $85.0 million. These swap agreements essentially converted $85.0 million of the Company’s variable rate borrowings under the then existing facility to fixed rate borrowings for a three year period that began on September 30, 2004. The maturity date on the swap agreements was September 28, 2007. The Company designated these interest rate swaps as cash flow hedges of the variable interest payments and recorded the quarterly changes in the fair value of the instruments in Other noncurrent assets with an offsetting unrealized gain, net of tax expense, in Accumulated other comprehensive income (loss).
In connection with the July 7, 2006 closing of the facility, the Company terminated the swap agreements. On the date the Company made the decision to terminate the interest rate swaps the interest rate swaps no longer qualified for cash flow hedge accounting treatment and accordingly, any change in the market value of the interest rate swaps affected net income. On July 11, 2006, the Company monetized the $2.4 million derivative asset included in Other noncurrent assets in the Company’s consolidated financial statements at June 30, 2006 and recognized a $0.1 million mark-to-market loss on the swaps. The $1.8 million unrealized gain from the change in the market value of the interest rate swaps recorded in Accumulated other comprehensive income (loss) was being recognized into income on a prorated basis over the remaining term of the original interest rate swap agreement through September 28, 2007, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and related amendments. At December 31, 2006, the unamortized unrealized gain was $1.1 million, which was fully offset against Interest expense during the twelve months ended December 31, 2007.
Other
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 Lease by Application (“LBA”) bids to procure federal coal, 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. There can be no assurance that such additional indebtedness and/or equity capital will be available on terms acceptable to us, if at all.
On February 20, 2008, an affiliate of the Company successfully bid on a new Federal coal lease adjacent to the western boundary of the Eagle Butte mine located north of Gillette, Wyoming. This Federal coal lease, containing an estimated 255 million tons, is expected to be awarded within thirty days. The lease bonus bid was $180.5 million to be paid in five equal annual installments of $36.1 million.
Covenant Compliance
The Company is required to comply with certain financial covenants which are considered material terms of the Senior Secured Credit Facility and the indenture governing the Company’s outstanding 7.25% Senior Notes. Information about the financial covenants is material to an investor’s understanding of the Company’s financial condition and liquidity. The breach of covenants in
the Senior Secured Credit Facility that are tied to ratios based on Adjusted EBITDA, as defined below, could result in a default under the Senior Secured Credit Facility 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 Secured Credit Facility and indenture, the Company’s ability to engage in activities such as incurring additional indebtedness, making investments and paying dividends is also tied to ratios based on Adjusted EBITDA.
Covenants and required levels as defined by the Senior Secured Credit Facility and the indenture governing the outstanding 7.25% Senior Notes are:
(1)
The Senior Secured Credit Facility requires the Company to maintain an Adjusted EBITDA to cash interest ratio at a minimum of 2.5x and a total debt less unrestricted cash to Adjusted EBITDA ratio starting at a maximum of 4.0x in each case for the most recent twelve month period. Failure to satisfy these ratio requirements would constitute a default by the Company under the Senior Secured Credit Facility. If lenders under the Senior Secured Credit Facility fail to waive any such default, repayment obligations under the Senior Secured Credit Facility could be accelerated, which would also constitute a default under the indenture. Covenants reflect the definition and levels required by the July 7, 2006 amended and restated Senior Secured Credit Facility.
(2)
The ability for the Company 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 Secured Credit Facility. EBITDA, a measure used by management to evaluate its ongoing operations for internal planning and forecasting purposes, is defined as net income (loss) plus interest expense, net of interest income, income tax expense (benefit), depreciation, depletion and amortization and charges for early extinguishment of debt. EBITDA is not a financial measure recognized under United States generally accepted accounting principles 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. The amounts shown for EBITDA as presented, may differ from amounts calculated and may not be comparable to other similarly titled measures used by other companies.
As of December 31, 2007, the Company was in compliance with all required financial covenants of the Senior Secured Credit Facility.
(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)
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; overburden removal, if incurred subsequent to the acquisition date, would have been included in cost of coal sales.
(b)
Represents compensation expense attributable to restricted stock units and stock options.
(c)
Represents the write-down of long-lived assets in 2006 of $1.4 million and $29.4 million related to deferred mining royalties at the Central Appalachia business unit and certain long-lived assets at the Wabash mine, respectively, and in 2005 of $1.6 million as a result of a change in the mine plan at the Northern Appalachia business unit.
(3)
We are also required to adjust EBITDA, as defined above, for the following unusual expenses:
(a)
In 2006, represents arbitration awards, litigation and contract settlements, net of related legal and tax fees. In 2007, amount primarily represents contract termination costs of $5.2 million incurred in connection with the idling of the Wabash mine.
(b)
In 2007, amount primarily represents employee and contract termination costs of $9.3 million incurred in connection with the idling of the Wabash mine.
(4)
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.
Cash interest for the twelve months ended December 31, 2007 is calculated as follows:
(a)
Under terms of the Credit Agreement, interest expense is adjusted for all debt incurred or permanently repaid during a reporting period. The interest adjustment is calculated as if the debt had been incurred or repaid at the beginning of the twelve month period.
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) certain non-cash expenses or charges arising as a result of the application of purchase accounting in acquisitions; (c) business optimization expenses or other restructuring charges; (d) non-cash impairment charges resulting from the application of SFAS No. 142, Goodwill and Other Intangible Assets or SFAS No. 144; (e) amortization of intangibles pursuant to SFAS No. 141, Business Combinations; and (f) 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 Consolidated Statements of Operations and Comprehensive Income. Other non-cash interest expense above is comprised of: (a) imputed interest expense on an equipment purchase obligation recorded on a present value basis; (b) imputed interest expense on a minimum royalty obligation recorded on a present value basis; and (c) imputed interest expense on a contract settlement liability recorded on a present value basis.
Contractual Obligations
The following is a summary of our significant future contractual obligations by year as of December 31, 2007.
(1)
The variable interest rate on debt is 5.11%, reflecting a LIBOR estimate based on the 39 month swap rate as of December 31, 2007, plus a margin of 1.25%.
We expect to use cash flows provided by operating activities to invest in the range of $180.0 million to $190.0 million in capital expenditures during calendar year 2008 of which $120.0 million to $130.0 million is to maintain production and replace mining equipment. The additional $60.0 million is expected to be directed toward improvements in productivity and selective expansions of production. Approximately $52.8 million of the 2008 capital expenditures are included in unconditional purchase commitments shown above. The remaining 2008 unconditional purchase commitments consist of $54.3 million for purchased coal in normal quantities for delivery to customers and $4.0 million pertaining to forward contracts to purchase explosives in normal quantities for use at our surface mines. We expect to contribute approximately $8.0 million to our defined benefit retirement plans and to pay approximately $25.1 million of retiree health care benefits, gross of Medicare Part D subsidies, in calendar year 2008. We also expect to incur approximately $7.4 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 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 $278.9 million as of December 31, 2007, of which $263.8 million secured reclamation obligations; $6.2 million secured coal lease obligations; $7.1 million secured self-insured workers’ compensation obligations; and $1.8 million for other miscellaneous obligations. In addition, we had $172.6 million of letters of credit in place for the following purposes: $37.2 million for workers’ compensation, including collateral for workers’ compensation bonds; $8.0 million for UMWA retiree health care obligations; $112.2 million for collateral for reclamation surety bonds; and $15.2 million for other miscellaneous obligations. In the last few years, 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.
Wage Negotiations with the UMWA and Idling of the Company’s Illinois Basin Mining Operation
Wage agreements between three affiliates of the Company and the UMWA expired on or shortly after March 31, 2007. Specifically, the wage agreement for Wabash expired at 11:59 p.m. on March 31, 2007 and the UMWA wage agreements with Cumberland Coal Resources, LP (“Cumberland”) and Emerald Coal Resources, LP (“Emerald”) expired at 11:59 p.m. on April 1, 2007. Negotiations between these respective subsidiaries and the UMWA commenced in early January of 2007 but intensified in late March of 2007 and continued through April 3, 2007. Emerald Coal Resources, LP and Cumberland Coal Resources, LP reiterated their willingness to sign the 2007 National Bituminous Coal Operators Association (“BCOA”) UMWA wage agreement. Wabash would not sign the BCOA agreement. The hourly workforce continued to work without a formal agreement of the parties under the terms of the expired wage agreement until 12:01 a.m. on April 4, 2007 at which time, alleging unfair labor practices by Wabash, Emerald and Cumberland, the UMWA represented hourly workforces went on strike at the Wabash, Emerald and Cumberland mines. Subsequent to the commencement of a UMWA strike on April 4, 2007, Wabash announced the idling of the mine in southern Illinois. The mine had become economically unviable at that time as a result of a combination of factors, including aged infrastructure, softening market conditions and the prospect of a new higher cost labor contract with the UMWA.
On April 10, 2007, negotiations between the UMWA and the three subsidiaries resumed. In the early evening of April 12, 2007, it was announced that the UMWA and the three subsidiaries had reached agreement and that the workforces at Emerald and Cumberland would return to work. Wabash remained idled and the effects of the idling had been negotiated with the UMWA. The collective bargaining agreements with the UMWA at Cumberland and Emerald expire at the end of the fourth quarter of 2011.
During the twelve months ended December 31, 2007, as a result of the Wabash mine idling, the Company recognized employee termination costs of $6.0 million and $1.3 million in accordance with the provisions of SFAS No. 146 and the provisions of SFAS No. 112, respectively. Termination costs resulting from one-time benefit arrangements include medical insurance continuance costs and severance to salaried employees. During the twelve months ended December 31, 2007, the Company also recognized $2.0 million of other direct and incremental costs related to additional benefit claims for certain severed employees. These employee termination costs are recorded as Employee and contract termination costs and other in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2007.
At March 31, 2007, Wabash was the seller under two coal supply agreements supplied from the mine with Duke Energy Indiana, Inc. Wabash continued to ship coal under the coal supply agreements through April 3, 2007, just prior to the mine idling. Each agreement contained force majeure language excusing the seller from supplying coal in the event of a work stoppage. On April 3, 2007, Wabash and Duke Energy Indiana, Inc. executed a Termination Agreement and Mutual Release buying-out, subject to certain conditions, all obligations under their two contracts in exchange for a cash settlement that the Company paid on April 5, 2007. The Company believes there will be no further obligations of Wabash under these two contracts. During the twelve months ended December 31, 2007, the Company recognized $5.2 million of net contract termination costs in accordance with the provisions of SFAS No. 146. These contract termination costs are recorded as Employee and contract termination costs and other in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2007.
Certain Trends and Uncertainties
Our long-term outlook for the coal markets in the United States remains positive. The Energy Information Administration in its Annual Energy Outlook - 2008 forecasts that coal-fired electrical generation will increase by an average annual growth rate of 1.1% through 2015. Through November 2007, electric power generation from coal is estimated to have increased 1.5% from the comparable period of 2006. Strong demand for coal and coal-based electricity generation in the U. S. is being driven by various factors such as the growing economy, increasing population, public demands for low electricity costs, relatively high prices for the alternative fossil fuels of gas and oil for electricity generation, the inability for renewable energy sources such as wind and solar to become the base load source of electric power, geopolitical risks for continuing to import large quantities of global oil and natural gas resources, and the relatively abundant steam coal reserves located within the United States.
According to the U. S. Department of Energy, National Energy Technology Laboratory, Tracking New Coal-Fired Power Plants, dated October 10, 2007, there are approximately 12,500 megawatts of new coal-fired electrical generation under construction in the United States. There is an additional approximately 10,700 megawatts of new coal-fired electrical generating capacity permitted and expected to be constructed. This new capacity will increase the annual coal consumption for electrical generation by an estimated eighty million tons, much of which is expected to be supplied from the Powder River Basin in Wyoming. Approximately 48,000 megawatts of additional coal-fired electrical generation has been announced and is in the early stages of permitting and development.
During 2007 coal exports from the United States increased significantly in response to strong worldwide demand for coal. The largest increases in international coal demand are from the rapidly growing and industrializing economies of China and India. In the last two years, China as evolved from a net exporter to a net importer of coal. Due partly to infrastructure constraints in Australia and South Africa, the seaborne coal trade has struggled to keep up with these increases in demand. Seaborne coal shipments traditionally destined for Europe and South America have been diverted to Asia creating opportunities to increase exports from the United States, particularly into Europe. Coal export volumes increased approximately 15% in 2007 compared to 2006. Export volumes for 2008 are forecast to increase by at least an additional 20% to levels last seen in the early 1990’s. The surge in demand for exports, combined with recent weather-related coal production outages in Queensland, Australia and South Africa as well as the harshest Chinese winter in the last fifty years, has increased prompt prices for metallurgical and steam coals produced in the Eastern United States by an estimated 100% and 50%, respectively, since the beginning of 2008. The actual and anticipated increases in coal exports have also tightened fundamentals in the domestic steam and metallurgical coal markets leading to increased market activity and prices in all regions.
According to the World Energy Outlook 2007 (“WEO”), global primary energy demand grows by more than half over the next quarter of a century, with coal rising most in absolute terms and fossil fuel accounting for most of the increase between now and 2030. China and India have contributed more than half the increase in global demand for energy, and over 80% for coal, since 2000. The WEO estimates these two growing economies will contribute more than 40% of the increase in global energy demand through 2030. China and India account for 78% of the growth of coal use in power generation. The WEO has a general conclusion that dependence on coal for power rises strongly in emerging economies, while it stagnates in the more developed nations.
Ultimately, the global demand for and use of coal may be limited by any global treaties which place restrictions on carbon dioxide emissions. As part of the United Nations Framework Convention on Climate Change, representatives from 187 nations met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The United States participated in the conference. The convention adopted what is called the “Bali Action Plan.” The Bali Action Plan contains no binding commitments, but concludes that “deep cuts in global emissions will be required” and provides a timetable for two years of talks to shape the first formal addendum to the 1992 United Nations Framework Convention on Climate Change treaty since the Kyoto Protocol. The ultimate outcome of the Bali Action Plan, and any treaty or other arrangement ultimately adopted by the United States or other countries, may have a material adverse impact on the global supply and demand for coal. This is particularly true if cost effective technology for the capture and sequestration of carbon dioxide is not sufficiently developed.
Proposed coal-fired electric generating facilities that do not include technologies to capture and store carbon dioxide are facing increasing opposition from environmental groups as well as state and local governments who are concerned with global climate change and uncertain financial impacts of potential greenhouse gas regulations. Coal fired generating plants incorporating carbon dioxide capture and storage technologies are more expensive to build than conventional pulverized coal generating plants and the technologies are still in the developmental stages. This dynamic may cause power generating companies to cut back on plans to build coal-fired plants in favor of alternative forms of baseload electrical generation in the near-term. Nevertheless, the level of interest in new coal-fired generating facilities remains strong. In combination with heightened interest in coal gasification and coal liquefaction, this level of interest is a potential indicator of increasing demand for coal in the United States.
Based on weekly production reporting through December 29, 2007 from the National Mining Association, Appalachian production trails the comparable period of 2006 by approximately 3.3% partially as a result of capacity idling due to weak market conditions prevailing in most of 2007. Coal producers in Northern Appalachia and the Powder River Basin continue to report deferrals of previously announced mine expansion projects. Through December 29, 2007, Western coal production has declined approximately 0.3% from the comparable period of the prior year. Judicial decisions in Central Appalachia with respect to permits to construct valley fills at surface mines are likely to slow the process of obtaining surface mining permits in that region with resultant uncertainties for producers. In addition, implementation of the Mine Improvement and New Emergency Response Act of 2006 and new state mine safety statutes has placed increased regulatory burdens on the coal industry with resultant cost increases and production constraints. The combination of strong demand for coal-fired electric power and production declines and uncertainties, particularly in Central Appalachia, has led to forecasts of declines in stockpiles at coal-fired electric generating plants over the next year. For reasons described above, spot market prices for Central Appalachian and Powder River Basin coals increased by 89% and 51%, respectively, as of January 25, 2008, compared to the same date one year earlier. Long-term, the delicate balance of coal supply and increasing coal demand is expected to result in strong, but volatile, fundamentals for the U. S. coal industry.
Our revenues depend on the price at which we are able to sell our coal. The current pricing environment for U. S. steam coal production is strong in relation to historical pricing levels, and has strengthened, notably in the past several weeks, in comparison to pricing levels prevailing in the first three quarters of 2007. Prices for high quality metallurgical coal, used to manufacture coke for steelmaking, have remained strong in response to increased worldwide demand for steel and production and transportation constraints in exporting metallurgical coal from Australia. As of January 25, 2008, we have committed and priced 94% and 68% respectively, of our planned shipment ranges for 2008 and 2009. In the longer term, decreases 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 affect our revenues and our ability to generate cash flows. In addition, our results of operations depend on the cost of coal production. We continue to experience increased operating costs for fuel and explosives, steel products, tires, health care, wages, salaries, contract coal haulage services and contract labor.
We may also experience difficult geologic conditions, delays in obtaining permits, labor shortages, unforeseen equipment problems and shortages of critical materials such as tires and explosives that may limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceed our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See the Special Note Regarding Forward-Looking Statements contained elsewhere in this Annual Report on Form 10-K for additional considerations regarding our outlook.
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 2 to the consolidated financial statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.
Asset Retirement Obligations
Our asset retirement obligations arise from the federal 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:
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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.
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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, 2007, we had recorded asset retirement obligation liabilities of $154.1 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 $247.3 million at December 31, 2007 payable through 2036.
Employee Benefit Plans
We have two non-contributory defined benefit retirement plans covering certain of our salaried and non-union hourly employees. We also have an unfunded non-qualified Supplemental Executive Retirement Plan covering certain of our senior-level salaried 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 twelve months ended December 31, 2007 and 2006, we contributed $11.3 million and $12.2 million, respectively, into the plans. We account for our defined benefit retirement plans in accordance with SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”) which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the twelve months ended December 31, 2007, 2006 and 2005, we recorded pension expense of $7.0 million, $7.2 million and $5.2 million, respectively.
The calculation of the net periodic benefits costs (pension expense) and projected benefit obligation 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.
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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/private equity, 22% fixed income, 13% other 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 periodic pension expense was 8%, 8% and 8.5% for the twelve months ended December 31, 2007, 2006 and 2005, respectively. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into expense in future periods.
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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, Employers’ Accounting for Pensions, requires rates of return on high quality, fixed income investments. The discount rate used to determine pension expense was 5.9%, 5.6% and 6.0% for the twelve months ended December 31, 2007, 2006, and 2005, respectively. Actuarial liabilities related to our defined benefit plans were remeasured as of April 1, 2007 in connection with the idling of the Wabash mine. The discount rate was increased to 6.0% at that time. The discount rate was increased to 6.25% at the December 31, 2007 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 twelve months ended December 31, 2007 by approximately $0.4 million and decrease the projected benefit obligation at December 31, 2007 by approximately $13.1 million. The corresponding effects of a one half of one percentage-point decrease in the discount rate would be approximately a $1.2 million increase in the net periodic pension cost and approximately a $14.1 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 dependents. 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. 158 which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the twelve months ended December 31, 2007, 2006 and 2005, we recorded postretirement benefit expense of $38.5 million, $39.3 million and $37.0 million, respectively.
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.
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The discount rate assumption reflects the rates available on high quality fixed income debt instruments 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 5.9%, 5.6% and 6.0% for the twelve months ended December 31, 2007, 2006 and 2005, respectively. Actuarial liabilities related to our postretirement benefit plans were remeasured as of April 1, 2007 in connection with the idling of the Wabash mine. The discount rate was increased to 6.0% at that time. The discount rate was increased to 6.25% at the December 31, 2007 measurement date. A one half percentage-point increase in the discount rate would decrease the postretirement benefit expense for the twelve months ended December 31, 2007 by approximately $ 0.3 million and decrease the accumulated postretirement benefit obligation at December 31, 2007 by approximately $32.3 million. The corresponding effects of a one-half of one percentage-point decrease in the discount rate would be approximately a $0.2 million increase in the postretirement benefit expense and approximately a $34.4 million increase in the accumulated postretirement benefit obligation.
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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 for the twelve months ended December 31, 2007, 2006 and 2005 was based on an assumed initial health care inflationary rate of 9.0% for all years, decreasing to 5.0% in 2011, 2010 and 2009, respectively, which represents the ultimate health care cost trend rate for the remainder of the plan life. A one-percentage point increase in the 5.0% assumed ultimate health care cost trend rate would increase the service and interest cost components of the postretirement benefit expense for the twelve months ended December 31, 2007 by $6.7 million and increase the accumulated postretirement benefit obligation at December 31, 2007 by $72.6 million. A one-percentage point decrease in the 5% assumed ultimate health care cost trend rate would decrease the service and interest cost components of the postretirement benefit expense for the twelve months ended December 31, 2007 by $5.4 million and decrease the accumulated postretirement benefit obligation at December 31, 2007 by $60.3 million.
Income Taxes
We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes (“SFAS No. 109”), 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. At December 31, 2007, we had a full valuation allowance for deferred tax assets arising from Alternative Minimum Tax (“AMT”) credits and a valuation allowance to reduce the value of our net deferred tax asset to an AMT tax rate. We believe that we will continue to be an AMT tax payer indefinitely. If future taxable income is different 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 mineral reserves. Many of these uncertainties are beyond our control. As a result, estimates of economically recoverable mineral 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:
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geological and mining conditions;
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historical production from similar areas with similar conditions;
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the assumed effects of regulations and taxes by governmental agencies;
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assumptions governing future prices;
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competing property rights such as surface rights, oil and gas rights, deeper or shallower coal rights and easements;
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ability to permit specific reserves for a particular type of mining;
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future operating, development and reclamation costs; and
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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
See Note 2 to the Consolidated Financial Statements in ITEM 8.
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 January 25, 2008, we had sales commitments for approximately 94% of our planned 2008 shipments. As of January 25, 2008, uncommitted and unpriced tonnage was 32%, 65% and 87% of planned shipments in 2009, 2010 and 2011, respectively.
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.
Interest Rate Risk
Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. We have exposure to changes in interest rates through our bank term loan and our revolving credit facility. To achieve risk mitigation objectives, we have in the past managed our interest rate exposure through the use of interest rate swaps.
The interest rate on the outstanding principal of our Senior Secured Credit Facility was 6.29% as of December 31, 2007. A hypothetical 1% increase in interest rates during 2007 would have increased interest expense by $3.3 million.
As we continue to monitor the interest rate environment in concert with our risk mitigation objectives, consideration is being given to future interest rate risk reduction strategies.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
FOUNDATION COAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
INDEX
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations and Comprehensive Income
Consolidated Statements of Stockholder Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholder
Foundation Coal Corporation (an indirect wholly owned subsidiary of Foundation Coal Holdings, Inc.)
We have audited the accompanying consolidated balance sheets of Foundation Coal Corporation and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations and comprehensive income, stockholder equity, and cash flows for each of the three years in the period ended December 31, 2007. 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 audits 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 Foundation Coal Corporation and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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 2, on January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), Share-Based Payment, and the provisions of EITF Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry. Also, as discussed in Note 2, on December 31, 2006, the Company adopted the provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. As discussed in Note 2, on January 1, 2007, the Company adopted the provisions of FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.
/s/ Ernst & Young LLP
March 19, 2008
Baltimore, Maryland
Unless the context otherwise indicates, as used in this Annual Report on Form 10-K the terms “we”, “our”, “us” and similar terms refer to Foundation Coal Corporation and its consolidated subsidiaries. Foundation Coal Corporation is an indirect wholly owned subsidiary of Foundation Coal Holdings, Inc. For purposes of this filing, Foundation Coal Holdings, Inc. is referred to as the “Public Parent.”
Foundation Coal Corporation and Subsidiaries
Consolidated Balance Sheets
(Dollars in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
Foundation Coal Corporation and Subsidiaries
Consolidated Statements of Operations and Comprehensive Income
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
Foundation Coal Corporation and Subsidiaries
Consolidated Statements of Stockholder Equity
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
Foundation Coal Corporation and Subsidiaries
Consolidated Statements of Cash Flows
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Dollars in thousands)
Note 1. Description of Business
The Public Parent and its indirect subsidiary, Foundation Coal Corporation (the “Company” or “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”). The Public Parent, 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.
At December 31, 2007, union representation accounted for approximately 34% of the Company’s employees. Labor contracts for the Pennsylvania mines, Emerald and Cumberland, with the United Mine Workers of America (“UMWA”) were signed in 2007 and expire on December 31, 2011. The contract for the Wabash mine expired on March 31, 2007.
Note 2. Summary of 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 of America. The preparation of the Company’s consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of 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 and assumptions relate to coal reserves that are the basis for future cash flow estimates and units-of-production depreciation, depletion and amortization calculations; environmental and reclamation obligations; asset impairments; postemployment, postretirement and other employee benefit liabilities; valuation allowances for deferred income taxes; reserves for contingencies and litigation and the fair value and accounting treatment of certain financial instruments. Management bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may differ significantly from these estimates. In addition, different assumptions or conditions could reasonably be expected to yield different results.
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.
Inventories and Stripping Costs
Coal inventories are valued at the lower of average cost or market. Market represents the estimated future sales price of the product based on prevailing and long-term prices, less the estimated preparation and selling costs.
Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.
The Company adopted Emerging Issues Task Force (“EITF”) Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry (“EITF Issue 04-6”) on January 1, 2006. EITF Issue 04-6 addresses the accounting for stripping costs incurred during the production phase of a mine, concluding that these costs are considered variable production costs and under a full absorption costing system are considered a component of inventory to be recognized in cost of coal sales in the same period as the revenue from the sale of the inventory. Capitalization of post-production stripping costs is appropriate only to the extent inventory exists at the end of a reporting period. The guidance requires application through recognition of a cumulative effect adjustment to opening retained earnings in the period of adoption, with no charge to current earnings for prior periods. Accordingly, prior period results have not been restated. At December 31, 2005, stripping costs associated with coal that had not been extracted was $60,406 which were classified on the Consolidated Balance Sheets as a component of work-in-process inventory referred to as deferred overburden. The effect on the consolidated financial statements upon adoption of EITF Issue 04-6 resulted in a cumulative effect adjustment which reduced opening retained earnings, as of January 1, 2006, by $39,264, net of tax of $21,142, thereby removing the $60,406 current asset previously classified on the Consolidated Balance Sheets as a component of work-in-process (deferred overburden) inventory.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Prepaid Expenses
Prepaid expenses consist primarily of deferred longwall move costs, advance mining royalties, prepaid taxes and prepaid insurance premiums. The Company defers the direct costs, including labor and supplies, associated with moving longwall equipment and the related equipment refurbishment costs in Prepaid expenses. 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 Other noncurrent assets.
Owned and leased mineral rights
Costs to obtain coal lands and leased mineral rights are capitalized based on the fair value at acquisition and amortized to operations as depletion expense using the units-of-production method. Only proven and probable reserves are included in the depletion base. Depletion expense is included in Depreciation, depletion and amortization on the accompanying Consolidated Statements of Operations and Comprehensive Income.
Plant, Equipment and Mine Development Costs
Costs of developing new mines or significantly expanding the capacity of or extending the lives of existing mines are capitalized and amortized using the units-of-production method over proven and probable reserves directly benefiting from the capital expenditure. 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.
The Company capitalizes certain costs incurred in the development of internal-use software, including external direct material and service costs, and employee payroll and payroll-related costs in accordance with the American Institute of Certified Public Accountants’ Statement of Position 98-1, “Accounting for the Costs of Computer Software Developed for or Obtained for Internal Use.” All capitalized internal-use software costs are amortized using the straight-line method over the estimated useful life not to exceed 7 years.
Asset Retirement Obligations
Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), 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, a 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 reviews its estimated future cash flows annually for its asset retirement obligations.
Coal Supply Agreements
Coal supply agreements represent the fair value assigned at the Acquisition 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 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 2007, the amortization of coal supply agreements was a ($3,414) net credit, which consisted of a $10,699 expense related to the amortization of contract assets and a ($14,113) credit related to the amortization of contract liabilities. As of December 31, 2007, total accumulated
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
amortization of the contract assets and contract liabilities was $77,041 and $245,718, respectively. As of December 31, 2006, total accumulated amortization of the contract assets and contract liabilities was $66,342 and $231,605, respectively. Based on expected future shipments under these agreements, amortization of the asset for above market contracts is anticipated to be approximately $8,061, $6,561 and $6,022 for the years ended December 31, 2008, 2009 and 2010, respectively. Amortization of the liability for below market contracts is anticipated to be approximately ($6,374), ($2,090) and ($953) for the years ended December 31, 2008, 2009 and 2010, 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 undiscounted 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.
Income Taxes
Income taxes are accounted for under the asset and liability method in accordance with SFAS No. 109, Accounting for Income Taxes (“SFAS No. 109”). 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 the respective tax bases for such assets and liabilities. 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.
In June 2006, the Financial Accounting Standards Board (“the FASB”) issued FASB Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s consolidated financial statements in accordance with SFAS No. 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires an entity to recognize the financial statement impact of a tax position when it is more-likely-than-not that the position will be sustained upon examination. If the tax position meets the more-likely-than-not recognition threshold, the tax effect is recognized at the largest amount of the benefit that is greater than fifty percent likely of being realized upon ultimate settlement. FIN 48 requires that a liability created for unrecognized tax benefits shall be presented as a liability and not combined with deferred tax liabilities or assets.
The Company adopted FIN 48 on January 1, 2007. The cumulative effect of the adoption of FIN 48 was zero. The Company’s gross tax-effected unrecognized tax benefits at the date of adoption for unrecognized tax benefits were $9,671. At December 31, 2007, the Company had gross tax-effected unrecognized tax benefits of $10,108, of which, $1,869, if recognized would impact the effective rate. The Company recognizes interest and penalties accrued related to unrecognized tax benefits as a component of tax expense. The total amount of accrued interest and penalties was $251 and $1,340 as of January 1, 2007 and December 31, 2007, respectively.
The Company files income tax returns in the U.S. federal jurisdiction and various states. Our United States federal tax obligations have been settled through the year 2003, although certain carry forward tax attributes that were generated prior to 2002 may still be adjusted upon examination by tax authorities if they either have been or will be used in periods subsequent to 2002.
In the third quarter of 2007, the Company received notification from the Internal Revenue Service (“IRS”) that a federal income tax audit was to commence for the 2005 tax year and as of December 31, 2007, the audit process was underway. No issues have been raised by the IRS that the Company believes would have a material impact on its consolidated financial statements.
The Company has not received a notification from any state income tax authority regarding an audit that is planned to be scheduled, nor did it have an outstanding state tax examination in process at December 31, 2007.
A valuation allowance is provided to reduce deferred tax assets if, in management’s judgment, it is more-likely-than-not that some portion of the deferred tax assets will not be realized.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Advance Mining Royalties
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. Deferred advance mining royalties are recorded in Prepaid expenses and Other noncurrent assets on the Consolidated Balance Sheets.
Revenue Recognition
The Company recognizes revenue when it has evidence of an agreement with a customer, the product has been delivered to the customer, the sales price is fixed and determinable and collectibility is reasonably assured. Delivery 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 undiscounted ultimate losses incurred on known claims plus a provision for incurred but not reported claims. This probable ultimate liability is re-determined semi-annually and resultant adjustments are expensed. These obligations are included in the Consolidated Balance Sheets as Accrued expenses and other current liabilities and Other noncurrent liabilities.
Pension, Other Postretirement Plans and Pneumoconiosis 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. 87”); SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (“SFAS No. 106”); and SFAS No. 112, Employers’ Accounting for Postemployment Benefits (“SFAS No. 112”), respectively, as amended by SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”), in the year that the recognition provisions of SFAS No. 158 are initially applied. 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.
In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize the overfunded or underfunded status of a defined benefit pension and other postretirement plans (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income. SFAS No. 158 requires the Company to initially recognize the funded status of a defined benefit pension and other postretirement plans and to provide the required disclosures as of the end of the first fiscal year ending after December 15, 2006. Additionally, for fiscal years ending after December 15, 2008, the Company is required to measure plan assets and benefit obligations as of the date of the Company’s fiscal year-end statement of financial position rather than at an interim period. On December 31, 2006, the Company adopted the recognition and disclosure provisions of SFAS No. 158. On December 31, 2007, the Company adopted the measurement date provisions of SFAS No. 158, measuring plan assets and benefit obligations as of December 31, 2007. See Note 13 for further discussion of the effect of adopting SFAS No. 158 on the Company’s consolidated financial statements.
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 for purposes of accounting for its black lung liabilities and assets.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
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 (“SFAS No. 133”) (as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities). 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 statement of financial position and measure those instruments at fair value. Any 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 a 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 and records all changes in fair value in income.
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 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
Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123(R)”), using the modified prospective transition method. Under the modified prospective transition method, compensation cost recognized includes: (a) compensation cost for all stock-based awards granted prior to but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123, Accounting for Stock-Based Compensation, (“SFAS No. 123”); and (b) compensation cost for all stock-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results from prior periods have not been restated. For all grants, the amount of compensation expense to be recognized is adjusted for an estimated forfeiture rate which is based on historical data. Compensation expense for awards with cliff vesting provisions is recognized on a straight-line basis from the measurement date through the vesting date.
Prior to the adoption of SFAS No. 123(R), the Company recorded compensation expense for all employee stock-based compensation plans using the intrinsic value method prescribed by Accounting Principles Board (“APB”) 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 market price of the underlying stock on the date of grant exceeds the exercise or acquisition price of the stock or stock-based award. The Company adopted the disclosure-only provisions of SFAS No. 123, as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of FASB Statement No. 123, for the periods prior to January 1, 2006. Under APB No. 25, compensation expense for restricted stock performance units was initially based on the fair market value of the underlying stock on the date of grant. The amount of unearned compensation was subsequently adjusted each period to reflect changes in the fair market value of the underlying stock. Compensation expense for restricted stock performance units is amortized over the vesting period.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
For the twelve months ended December 31, 2005, the Company applied the intrinsic value based method of accounting for options prescribed by APB No. 25. Accordingly, no compensation expense was recognized for these options since all options granted have an exercise price equal to the market value of the underlying stock on the grant date. If compensation expense had been recognized based on the estimate of the fair value of each option granted in accordance with the provisions of SFAS No. 123 as amended by SFAS No. 148, the Company’s net income would have been reduced to the following pro forma amounts as follows:
Pro forma compensation expense recognized under SFAS No. 123 does not consider potential forfeitures. This computational difference creates incomparability between the pro forma stock compensation presented above and the stock compensation recognized in 2007 and 2006. However, the impact of estimated forfeitures on such compensation expense is immaterial.
Comprehensive Income
In addition to net income, comprehensive income includes changes to Accumulated other comprehensive income (loss) such as: adjustments to unrecognized gains and losses and amortization of employee benefit plan costs; the effective portion of changes in fair value of derivative instruments that qualify as cash flow hedges; and adjustments to minimum pension liabilities prior to the adoption of the recognition provisions of SFAS No. 158.
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 5 to 10 years, using the effective interest method.
New Pronouncements
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (“SFAS No. 160”). This standard outlines the accounting and reporting for ownership interest in a subsidiary held by parties other than the parent. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Company expects to adopt SFAS No. 160 on January 1, 2009 and has not yet determined the impact from the adoption of this new accounting pronouncement on its consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS No. 141(R)”). This standard establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No.141(R) is effective for acquisitions for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS No. 141(R) changes the accounting after the acquisition date for reductions in valuation allowances established in purchase price allocation related to an acquired entity’s deferred assets. Effective from the date of adoption of SFAS No. 141(R), the effects of reductions in valuation allowances established in purchase accounting that are outside of the measurement period are reported as adjustments to income tax expense. The Company expects to apply the provisions of SFAS No. 141(R) to acquisitions made on or after January 1, 2009 and has not yet determined the impact from the adoption of this new accounting pronouncement on its consolidated financial statements.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Liabilities Including an amendment of FASB Statement No. 115 (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company expects to adopt SFAS No. 159 on January 1, 2008. The Company has evaluated the impact of adopting SFAS No. 159 and has determined that it will not elect the fair value option under SFAS No.159 for any financial instruments that are not required to be presented at fair value under generally accepted accounting principles.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This statement clarifies how to measure fair value as permitted under other accounting pronouncements but does not require any new fair value measurements. SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. On February 12, 2008, the FASB issued Final FASB Staff Position (“FSP”) No. Financial Accounting Standard (“FAS”) 157-2, Effective Date of FASB Statement No. 157 (“FSP No. 157-2”). FSP No. 157-2, which was effective upon issuance, delays the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. The Company expects to adopt SFAS No. 157 on January 1, 2008 and 2009 for financial assets and financial liabilities and nonfinancial assets and nonfinancial liabilities, respectively. The Company does not believe that the adoption of SFAS No. 157 will have a material effect on the Company’s consolidated financial statements.
Note 3. Employee and Contract Termination Costs
Employee Termination Costs
Wage agreements between three affiliates of the Company and the UMWA expired on or shortly after March 31, 2007. Specifically, the UMWA wage agreement for Wabash Mine Holding Company (“Wabash”) expired at 11:59 p.m. on March 31, 2007 and the UMWA wage agreements with Cumberland Coal Resources, LP (“Cumberland”) and Emerald Coal Resources, LP (“Emerald”) expired at 11:59 p.m. on April 1, 2007. Negotiations between these respective subsidiaries and the UMWA commenced in early January of 2007 but intensified in late March of 2007 and continued through April 3, 2007. Emerald Coal Resources, LP and Cumberland Coal Resources, LP reiterated their willingness to sign the 2007 National Bituminous Coal Operators Association (“BCOA”) UMWA wage agreement. Wabash would not sign the BCOA agreement. The hourly workforce continued to work without a formal agreement of the parties under the terms of the expired wage agreement until 12:01 a.m. on April 4, 2007 at which time, alleging unfair labor practices by Wabash, Emerald and Cumberland, the UMWA represented hourly workforces went on strike at the Wabash, Emerald and Cumberland mines. On the same day, Wabash announced the idling of the mine in southern Illinois. The mining operation had become economically unviable at that time as a result of a combination of factors, including aging infrastructure, softening market conditions and the prospect of a new higher cost labor contract with the UMWA.
On April 10, 2007, negotiations between the UMWA and the three subsidiaries resumed. In the early evening of April 12, 2007, it was announced that the UMWA and the three subsidiaries had reached agreement and that the workforces at Emerald and Cumberland would return to work. The Wabash mine remained idled and the effects of the idling had been negotiated with the UMWA.
During the twelve months ended December 31, 2007, as a result of the Wabash mine idling, the Company recognized employee termination costs of $5,968 and $1,326 in accordance with the provisions of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (“SFAS No. 146”) and the provisions of SFAS No. 112, respectively. Termination costs resulting from one-time benefit arrangements in accordance with SFAS No. 146 include medical insurance continuance costs and one-time retention pay to salaried employees. During the twelve months ended December 31, 2007, the Company also recognized $1,991 of direct and incremental costs related to additional benefit claims for certain severed employees. These employee termination costs are recorded as Employee and contract termination costs and other in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2007. Wabash is included in the Company’s Other segment. See Note 21.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
During the twelve months ended December 31, 2007, the Company made cash payments related to employee termination costs of $7,080. At December 31, 2007, the Company’s liability for employee termination costs included in Accrued expenses and other current liabilities in the Consolidated Balance Sheets was $214, comprised of medical and severance benefits. See Note 10. The Company’s liability for other benefit costs associated with severed employees included in Other noncurrent liabilities was $1,991 at December 31, 2007. See Note 12.
Contract Termination Costs
Wabash was the seller under two coal supply agreements supplied from the Wabash mine with Duke Energy Indiana, Inc. Wabash continued to ship coal under the coal supply agreements through April 3, 2007, just prior to the mine idling. Each agreement contained force majeure language excusing the seller from supplying coal in the event of a work stoppage. On April 3, 2007, Wabash and Duke Energy Indiana, Inc. executed a Termination Agreement and Mutual Release buying-out, subject to certain conditions, all obligations under their two contracts in exchange for a cash payment of $5,734 which was paid by the Company on April 5, 2007. The Company believes there will be no further obligations of Wabash under these two contracts. During the twelve months ended December 31, 2007, the Company recognized $5,171 of net contract termination costs in accordance with the provisions of SFAS No. 146. These contract termination costs are recorded as Employee and contract termination costs and other in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2007.
Note 4. Write-down of Long-Lived Assets
In the fourth quarter of 2006, the Company recognized an asset impairment charge to write-down the carrying value of assets at its Wabash mine (“Wabash assets”) to their estimated fair value and to write-off a prepaid royalty in Central Appalachia in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets. These impairment charges are recorded as Write-down of long-lived assets on the Consolidated Statements of Operations and Comprehensive Income. At the Wabash mine, the Company wrote down assets included in Inventories, net; Owned surface lands; Plant, equipment and mine development costs, net and Owned and leased mineral rights, net, in the Consolidated Balance Sheets by $1,517, $439, $21,686 and $5,730, respectively. The Company noted impairment indicators with respect to the Wabash assets and the on-going recoverability of the carrying value of the assets in the fourth quarter of 2006 based primarily upon its analysis of recent financial results. Analysis of these financial indicators as well as other non-financial indicators lead to management’s decision, late in the fourth quarter of 2006, to discontinue additional capital expenditures related to an ongoing mine recapitalization and development project. In testing the recoverability of the carrying value of the Wabash assets and in assessing their fair value, the Company utilized a combination of cash flow projections, third party appraisals and other evidence of fair value, including an assessment of the assets’ value in the open market. The Wabash assets are included in the Company’s Other segment. See Note 21. In Central Appalachia, as a result of a change in the Company’s mine plan, the Company wrote-off $1,410 of prepaid royalties previously recorded in Other noncurrent assets. These royalties were associated with a lease under which future mining was determined to be not probable. This determination was made in the fourth quarter of 2006.
In the fourth quarter of 2005, as a result of a change in the Company’s mine plan, the Company recorded a write-down related to development costs incurred during 2003 through 2004 that were attributable to expanding certain undeveloped areas of mining districts in the Company’s Northern Appalachia business unit. These costs were included in Other noncurrent assets as prepaid longwall development costs. The write-down of $1,633 is included in the Consolidated Statements of Operations and Comprehensive Income as Write-down of long-lived assets.
Note 5. Significant Property Transactions
In the fourth quarter of 2007, Foundation PA Coal Terminal, LLC, an indirect wholly owned subsidiary of the Company, purchased the LaBelle river dock facility in Fayette County, Pennsylvania for $1,371. The purchased assets consisted of land and barge loadout facility equipment that are recorded in Owned surface lands and Plant, equipment and mine development costs, net, respectively, in the Consolidated Balance Sheets. The purchase price was allocated to the assets based upon estimates of fair value.
In the third quarter of 2006, Pioneer Fuel Corporation, an indirect wholly owned subsidiary of the Company, purchased mining assets from Appalachian Fuels, LLC for $15,400. The purchased assets consisted of approximately 7.3 million tons of reserves, land and mining equipment that are recorded in Owned and leased mineral rights, net; Owned surface lands and Plant, equipment and mine development costs, net, respectively, in the Consolidated Balance Sheets. The acquired reserves are located adjacent to and have been integrated with and are jointly managed with the existing Pax surface operations. In accordance with terms set forth in the asset
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
purchase agreement, $1,000 of the purchase price was withheld for contingencies, but will be remitted to Appalachian Fuels eighteen months after the acquisition date if no contingencies materialize. The purchase price was allocated to the assets and asset retirement obligation acquired/assumed based upon estimates of fair value.
In a separate transaction, coal stockpiles containing an estimated 8,300 tons were also acquired from Appalachian Fuels, LLC in 2006 for $232 and was recorded in Inventories, net in the Consolidated Balance Sheets at the date of acquisition.
Note 6. Inventories
Inventories consisted of the following at:
Saleable coal represents coal stockpiles ready for shipment to a customer. Raw coal represents coal that requires further processing prior to shipment.
Note 7. Prepaid Expenses
Prepaid expenses consisted of the following at:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Note 8. Plant, Equipment, Mine Development Costs and Owned and Leased Mineral Rights
Plant, equipment, mine development costs and owned and leased mineral rights consisted of the following at:
Note 9. Other Noncurrent Assets
Other noncurrent assets consisted of the following at:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Note 10. Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consisted of the following at:
Note 11. Long-Term Debt
Long-term debt consisted of the following at:
As a result of a voluntary prepayment of $25,125 on the outstanding balance of the term loan facility discussed below, there are no scheduled debt maturities until September 2009. Future minimum payments related to the Company’s long-term debt as of December 31, 2007 are as follows:
Senior Secured Credit Facility
On July 7, 2006, the Company completed an $835,000 amended and restated Senior Secured Credit Agreement (the “new facility”), consisting of a five-year $335,000 Term Loan A and a five-year $500,000 revolving credit facility. The new facility, which expires in July 2011, bears interest at an applicable margin, plus the lenders’ base rate or LIBOR at the Company’s option, and requires the Company to pay a commitment fee to the lenders for the unutilized portion of the commitment under the revolving credit facility based on a quarterly leverage ratio calculation. The revolving credit facility provides for up to $500,000 of borrowings for base rate loans, LIBOR loans or letters of credit up to a maximum of the unutilized portion of the revolver. As of December 31, 2007 and 2006, the Company had $327,377 and $331,176, respectively, of available borrowings under its revolving credit facility after giving effect to $172,623 and $168,824 of letters of credit outstanding. The new facility replaces the facility entered into on July 30, 2004 that consisted of a $470,000 term loan facility and a $350,000 revolving credit facility (the “original facility”). Costs capitalized
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
in connection with the new facility were $4,457. The Company wrote-off $9,209 of unamortized deferred financing costs as a result of the replacement of the original facility with the new facility, based upon the provisions of EITF Issue No. 96-19, Debtor’s Accounting for a Modification or Exchange of Debt Instruments, and EITF Issue No. 98-14, Debtor’s Accounting for Changes in Line-of-Credit or Revolving-Debt Arrangements. Remaining debt issuance costs are being amortized over the term of the related indebtedness of five years, using the effective interest method. On December 31, 2007, the Company prepaid scheduled principal repayments of $16,750 and $8,375 due in 2008 and the first two quarters of 2009, respectively, on the outstanding balance of the term loan facility. In conjunction with the prepayment, the Company wrote-off $246 of unamortized deferred financing costs associated with the new facility. On December 29, 2006, the Company prepaid the scheduled principal repayments of $8,375 due in 2007 on the outstanding balance of the term loan facility and wrote-off $102 of unamortized deferred financing costs associated with the new facility. At December 31, 2007, the interest rate on the outstanding principal under the new facility was approximately 6.29%.
The terms of the original facility required the Company to maintain at least 50% of its outstanding debt at a fixed rate. To comply with the terms of the original facility, as further described in Note 16, on September 30, 2004, the Company entered into several 3-year interest rate swap agreements all with identical terms, in which it paid fixed interest and received variable interest on a notional amount of $85,000 of its term loan. Under these swap agreements, the Company received a variable rate of 3-month US dollar LIBOR and paid a fixed rate of 3.26%. Settlement of interest payments occurred quarterly. In connection with the closing of the $835,000 amended and restated Senior Secured Credit Agreement on July 7, 2006, the Company terminated the interest rate swaps, as further described in Note 16.
The 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 ratios 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 covenants at December 31, 2007 and 2006.
7.25% Senior Notes
On July 30, 2004, the Company completed an offering of $300,000 of 7.25% 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 7.25% Senior Notes (the “Notes”) with identical terms were 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 Company’s other senior unsecured indebtedness. Interest on the Notes is payable on February 1st and August 1st of each year, beginning on February 1, 2005. The terms of the Notes contain restrictive covenants that limit the Company’s ability to, among other things, incur additional debt, pay dividends, sell or transfer assets, and make certain investments. The Notes are redeemable, at the Company’s option, after August 1, 2009 at a redemption price equal to 100% of the principal amount plus an applicable premium. On November 26, 2007, the Company repurchased Notes with a face value of $1,715 and wrote off $41 of unamortized deferred financing costs.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Note 12. Other Noncurrent Liabilities
Other noncurrent liabilities consisted of the following at:
During 2005, the Company’s Northern Appalachia business unit took delivery of one hundred new longwall shields to remedy a warranty issue associated with shields currently used in its underground mining operations. The Company entered into a purchase commitment for the shields in the amount of $21,685 and in accordance with the payment terms, periodic progress payments to the manufacturer were not scheduled to start until the fourth quarter of 2007, with scheduled completion within one year. In 2005, the Company recorded a deferred equipment purchase commitment liability representing the present value of the future payments due in accordance with the terms of the purchase commitment. Interest expense was imputed and recognized in a manner consistent with the established payment terms. In the fourth quarter of 2007, the Company made payments of approximately $21,309, which fully satisfied all interest and principal payments related to the deferred equipment purchase commitment liability for the longwall shields.
Note 13. Employee Benefit Plans
As disclosed in Note 2, the Company adopted the recognition and disclosure provisions of SFAS No. 158 on December 31, 2006. In addition, the Company adopted the measurement date provisions of SFAS No. 158, effective December 31, 2007. Accordingly, the Company uses a December 31 measurement date for its pension and postretirement plans. Prior to 2007, the Company used a September 30 measurement date for its pension and postretirement plans. The adoption of the measurement date provisions of SFAS No. 158 did not have a material effect on the consolidated financial statements.
The following table summarizes the effects of the adoption on the Consolidated Balance Sheet at December 31, 2006:
Included in Accrued expenses and other current liabilities at December 31, 2006 are current postretirement benefits of $21,420. The adoption of SFAS No. 158 increased the Company’s liability for pension and black lung liabilities included in Other noncurrent liabilities by $2,865 and $3,455, respectively. There are $45,387 of pension liabilities and $11,305 of black lung liabilities included in Other noncurrent liabilities at December 31, 2006.
Actuarial liabilities related to the Company’s defined benefit pension and postretirement benefit plans were re-measured in the quarter ended June 30, 2007 in connection with the curtailment event which occurred with respect to the idling of the Wabash mine, as further discussed in Note 3. The curtailment gains of $5,703 were recorded in Other comprehensive income because the curtailment gains did not exceed the unrecognized net losses recorded in Accumulated other comprehensive income related to these plans.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
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. The Company also sponsors a non-qualified Supplemental Executive Retirement Plan. 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 recommended by consulting actuaries based upon the ERISA funding standards. Plan assets consist of equity and fixed income securities, real estate funds, private equity participations and alternative investment funds.
The following table provides components of net periodic benefit cost for the indicated fiscal periods:
Other changes in plan assets and benefit obligations recognized in other comprehensive income are as follows:
The estimated amount that will be amortized from accumulated other comprehensive income into net period benefit cost in 2008 is as follows:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The following tables set forth the plans’ benefit obligations, fair value of plan assets and funded status for the indicated fiscal periods:
(1)
Represents the benefit obligation at September 30, 2006.
(2)
Represents benefit expenses and benefit payments of $1,794 and ($2,351), respectively, from September 30, 2006 to December 31, 2006.
Gross amounts recognized in accumulated other comprehensive income consisted of the following as of:
The following table presents information applicable to plans with accumulated benefit obligations in excess of plan assets as of:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Under SFAS No. 158, the current portion of the Company’s pension liability is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next twelve months exceeds the fair value of plan assets. However, even though the plan may be underfunded, if there are sufficient plan assets to make expected benefit payments to plan participants in the succeeding twelve months, no current liability should be recognized. Accordingly, at December 31, 2007 and 2006, there was $0 for current pension liability reflected in Accrued expenses and other current liabilities. The noncurrent portion of the Company’s pension liability as reflected in Other noncurrent liabilities at December 31, 2007 and 2006 was $28,564 and $45,387, 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:
(1)
Actuarial liabilities and net periodic benefit cost related to the Company’s defined benefit and postretirement health care and life insurance plans were remeasured as of April 1, 2007 in connection with the idling of the Wabash mine, as discussed in Note 3. The discount rate was increased to 6.00% at that time.
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 2008, the Company will utilize an expected long-term return on plan assets of 8.00%.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
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. The plans’ target allocation for 2008 and the actual asset allocation as reported at December 31, 2007 and 2006 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 2% of the target allocation.
For the twelve months ended December 31, 2007 and 2006, $11,316 and $12,163, respectively, of cash contributions were made to the defined benefit retirement plans. The Company expects to contribute approximately $8,000 to the defined benefit retirement plans in 2008.
All of our hourly employees in Pennsylvania 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 $9,549, $1,394 and $1,370, for the twelve months ended December 31, 2007, 2006 and 2005, 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 $6,486, $5,730 and $4,899, for the twelve months ended December 31, 2007, 2006 and 2005, 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 (the “MMA”) was enacted in the United States. The MMA 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 accounting for the MMA, the Company follows FSP No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. The MMA reduced the Company’s net periodic postretirement medical and life insurance benefit cost for the twelve months ended December 31, 2007 and 2006 by approximately $4,588 and $5,000, respectively.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The Centers for Medicare and Medicaid Services issued final regulations related to the MMA on January 21, 2005. The Company has elected to continue to provide primary prescription drug benefits to Medicare eligible participants and to apply for federal subsidy payments under the MMA beginning January 1, 2006. Federal subsidies recorded in 2007 and 2006 were $1,789 and $1,608, respectively.
The following table provides components of net periodic benefit cost for the indicated fiscal periods:
Other changes in plan assets and benefit obligations recognized in other comprehensive income are as follows:
No amounts are estimated to be amortized from accumulated other comprehensive income into net periodic benefit cost in 2008.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The following tables set forth the plans’ benefit obligations, fair value of plan assets and funded status for the indicated fiscal periods:
(1)
Represents the benefit obligation at September 30, 2006.
(2)
Represents benefit expenses and employer contributions of $9,825 and ($4,440), respectively, from September 30, 2006 to December 31, 2006.
Gross amounts recognized in accumulated other comprehensive income consisted of the following as of:
The weighted-average assumptions used to determine the benefit obligation as of the end of each year were as follows:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The weighted-average assumptions used to determine net periodic benefit cost were as follows:
(1)
Actuarial liabilities and net periodic benefit cost related to the Company’s defined benefit and postretirement health care and life insurance plans were remeasured as of April 1, 2007 in connection with the idling of the Wabash mine, as discussed in Note 3. The discount rate was increased to 6.00% at that time.
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, 2007:
The Company’s postretirement medical and life insurance plans are unfunded. For the twelve months ended December 31, 2007, 2006 and 2005, the Company paid $19,773, $19,240 and $20,157, respectively, in postretirement medical and life insurance benefits, net of federal subsidies received under the MMA. The Company expects to contribute approximately $25,063 to its postretirement medical and life insurance plans in 2008.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The following represents expected future benefit payments for the next ten years, which reflect expected future service, as appropriate, and the expected federal subsidy related to the MMA:
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 twelve months ended December 31, 2007, 2006 and 2005 was $2,759, $2,519 and $1,809, 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 $7,957 as of December 31, 2007.
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, 2007 and 2006, the discounted accumulated postemployment benefit liability for these plans consisted of a current amount of $1,106 and $891, respectively, included in Accrued expenses and other current liabilities (wages and employee benefits) and a noncurrent amount of $3,891 and $3,765, 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 twelve months ended December 31, 2007, 2006 and 2005, total claims expense of $37,743, $36,798 and $31,087, respectively, was incurred, which represents the claims processed and an estimate for claims incurred but not reported.
Pneumoconiosis 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 (the “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, 2007 is 6.25%. The assumed annual investment rate of return on the Trust assets is 4.50%. The rate of compensation is assumed to increase at an annual rate of 3.50%.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The following tables set forth the accumulated black lung benefit obligations, fair value of plan assets and funded status for the indicated fiscal periods:
(1)
Represents the benefit obligation at September 30, 2006.
(2)
Represents benefit expenses and benefit payments of $411 and ($351), respectively, from September 30, 2006 to December 31, 2006.
Gross amounts recognized in accumulated other comprehensive income consisted of the following as of:
The following table provides components of net periodic benefit cost for the indicated fiscal periods:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Other changes in plan assets and benefit obligations recognized in other comprehensive income are as follows:
The estimated amount that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2008 is as follows:
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 undiscounted 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 semi-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 $37,249 and surety bonds in the amount of $7,104.
The liability for self-insured workers’ compensation benefits at December 31, 2007 and 2006 was $34,718 and $31,487, respectively, including a current portion of $10,450 and $8,140, respectively, which is included in Accrued expenses and other current liabilities. Workers’ compensation expense for the twelve months ended December 31, 2007, 2006 and 2005, was $15,156, $13,259 and $14,219, respectively, and is included in Cost of coal sales in the Consolidated Statements of Operations and Comprehensive Income.
Note 15. Stock-Based Compensation
On July 30, 2004, the Public Parent’s Board of Directors (“the Board”) 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 Public Parent to grant key employees, directors and consultants of the Company non-qualified stock options (“options”), stock appreciation rights, restricted stock 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 Public Parent’s common stock on the date of grant. The Plan is currently authorized for the issuance of awards for up to 5,978,483 shares of common stock of the Public Parent. At December 31, 2007, 2,221,696 shares of the Public Parent’s common stock were available for grant under the Plan.
Prior to January 1, 2006, the Company accounted for its stock-based compensation plans under the recognition and measurement provisions of APB No. 25, and related interpretations, as permitted by SFAS No. 123. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123(R), using the modified prospective transition method.
The Company has two types of stock-based awards: restricted stock units and options. Total compensation related to the stock-based awards recognized in Selling, general and administrative expenses for the twelve months ended December 31, 2007 was $6,178, consisting of $4,730 and $1,448 for restricted stock units and options, respectively. Total compensation related to stock-based awards recognized in Selling, general and administrative expenses for the twelve months ended December 31, 2006 was $2,765,
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
consisting of $1,398 and $1,367 for restricted stock units and options, respectively. For the twelve months ended December 31, 2005, compensation expense of $1,509 was recognized as a component of Selling, general and administrative expenses for restricted stock units.
No expense related to options was charged against income in periods prior to January 1, 2006, as the Company elected to apply the provisions of APB No. 25 to those periods as permitted by SFAS No. 123 and 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 Public Parent’s common stock was estimated by the Board to be approximately $4.87 per share on the date of grant. As the Public Parent’s common stock was not then publicly traded, this fair market value was based on the per share price of the Public Parent’s common stock paid at the time of the Acquisition, which was completed just prior to the grant of the options.
The excess tax benefit from stock-based awards was $3,292, $9,486 and $342 during the twelve months ended December 31, 2007, 2006 and 2005, respectively.
Below is a summary of the key terms and methods of valuation for the Company’s stock-based compensation awards granted by the Public Parent to employees of the Company:
Restricted Stock Units
At December 31, 2005, 180,948 restricted stock performance units (“performance units”) were outstanding. The units are earned ratably each December 31 over the vesting period upon achievement of certain annual performance targets. Performance targets related to specific tranches of these performance units are established prior to each annual reporting cycle. The units earned in each annual performance cycle vest subject to continued employment with the Company through the vesting dates, which occur through 2009, at which time shares of the Public Parent’s common stock equal to the number of performance units earned will be distributed. Also, at December 31, 2005, 15,000 restricted stock time units (“time units”) were outstanding. These time units vest subject to continued employment with the Company through the vesting date at which time shares of the Public Parent’s common stock will be distributed. The weighted-average grant-date fair value of restricted stock units granted in 2005 for which the measurement date had occurred at December 31, 2005 was $33.08 per unit.
During the twelve months ended December 31, 2006, the Company granted 248,884 performance units and 35,840 time units to certain key employees. These performance units are earned each December 31, contingent upon the achievement of certain annual performance targets. Performance targets related to specific tranches of these performance units are established prior to each annual reporting cycle. The units earned in each annual performance cycle vest subject to continued employment with the Company through the vesting dates, which occur through 2010, at which time shares of the Public Parent’s common stock equal to the number of performance units earned will be distributed. The time units vest over various periods through June 30, 2009. The weighted-average grant-date fair value of restricted stock units granted in 2006 for which the measurement date had occurred was $43.67 per unit.
During the twelve months ended December 31, 2007, the Company granted 27,710 performance units and 36,770 time units to certain key employees. These performance units are earned each December 31, contingent upon the achievement of certain annual performance targets. Performance targets related to specific tranches of these performance units are established in the RSU agreement for grants to members of senior management or prior to each annual reporting cycle for grants to members of management. The units earned vest subject to continued employment with the Company through the vesting dates, which occur through 2010, at which time shares of the Public Parent’s common stock equal to the number of performance units earned will be distributed. The time units vest over various periods through 2010. The fair value of restricted stock units that vested during the twelve months ended December 31, 2007 was $297.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The following is a summary of the Company’s restricted stock unit activity during the twelve months ended December 31, 2007:
(1)
The weighted-average grant-date fair value reflects the value of restricted stock units for which the measurement date has occurred.
The measurement date for each tranche of performance units is the date on which the annual performance targets are approved relating to such tranche (the “measurement date”). Compensation cost for each tranche is measured based upon the average market price of the Public Parent’s common stock at the measurement date. There are no market or performance conditions that could cause an employee to forfeit an award prior to the measurement date for each specific tranche. At December 31, 2007, the measurement date had not occurred for 39,635 performance units. Compensation expense is recognized ratably from the measurement date of each tranche through the vesting date at which time the number of shares of the Public Parent’s common stock which have been earned will be distributed.
Unrecognized compensation expense for time and performance units for which the measurement date has occurred is $9,322. These costs are expected to be recognized over a weighted-average period of 1.3 years. The amount of compensation expense related to performance units that will be recognized in future periods is determined by the achievement of performance targets.
Non-qualified Stock Options
On August 10, 2004, options to acquire 3,536,432 shares of the Public Parent’s common stock were issued to eight members of senior management of the Company. No options were granted during 2007 or 2006. Of the total options granted, there were 982,343 options 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 options 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 achievement of certain annual performance targets. During 2007 and 2006, respectively, 415,039 and 383,113 of the options granted at the $8.53 per-share exercise price vested on an accelerated basis as a result of achieving certain performance targets.
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:
As the Public Parent lacked a sufficient trading history at the date the fair value of options was estimated in 2004, the Public Parent’s volatility was based on the volatility of other companies in the mining industry. The weighted-average grant-date fair value of the options was $2.45.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The following is a summary of all option activity during the twelve months ended December 31, 2007:
The total intrinsic value, the difference between the exercise price and the market price on the date of exercise, of all options exercised during the twelve months ended December 31, 2007, 2006 and 2005 was $20,412, $34,183 and $1,410, respectively.
During 2007, 574,669 options vested. The weighted-average grant-date fair value of options vested during 2007 was $2.45.
A summary of the Company’s options outstanding at December 31, 2007 follows:
Total unrecognized compensation expense from options was $1,465 as of December 31, 2007, which is expected to be recognized over a weighted-average period of 2.2 years.
Note 16. Derivative Instruments and Hedging Activities
The Company’s objectives for holding or issuing derivative instruments are to mitigate its exposure to variability in the prices of certain operating supplies and to interest rate risk. The Company’s strategy for minimizing exposure to variability is to enter into pay-fixed, receive-variable financial swaps.
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 was for three years. Under these swaps, the Company received a variable rate of three month US dollar LIBOR and paid a fixed rate of 3.26%. Settlement of interest payments occurred 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 original facility. These swap agreements essentially converted $85,000 of the Company’s variable rate borrowings under the original facility to fixed rate borrowings beginning September 30, 2004. The Company designated these interest rate swaps at inception as cash flow hedges of the variable interest payments due on $85,000 of its variable rate debt through September 2007 under SFAS No. 133. In connection with the closing of the Senior Secured Credit Facility on July 7, 2006, the Company terminated the interest rate swaps. On the date the Company made the decision to terminate the interest rate swaps, the interest rate swaps no longer qualified for cash flow hedge accounting treatment and accordingly, any change in the market value of the interest rate swaps affected net income. On July 11, 2006, the Company monetized the $2,371 derivative asset included in Other noncurrent assets in the Consolidated Balance Sheets at June 30, 2006 and recognized a $112 mark-to-market loss on the swaps in Other income (expense). The $1,841 unrealized gain from the change in the market value of the interest rate swaps recorded in Accumulated other comprehensive income (loss) was being amortized into income on a prorated basis over the remaining term of the original interest rate swap agreement through September 28, 2007, in accordance with SFAS No. 133 and related amendments. At December 31, 2006, the unamortized unrealized gain on the swaps was $1,114, which was fully amortized as an offset against Interest expense during the twelve months ended December 31, 2007.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
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, trade accounts receivable, 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, 2007 and 2006.
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.
The estimated fair values of financial instruments are as follows at:
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 to protect the public health and environment and believes its operations are in material 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. Estimated future reclamation costs are based principally on legal and regulatory requirements.
The following table describes all changes to the Company’s asset retirement obligations from December 31, 2006 through December 31, 2007:
(1)
Primarily represents revisions in estimated cash flows of $14,407 at the Belle Ayr mine and the Eagle Butte mine in the second quarter of 2007 and liabilities incurred of $2,798 associated with the acquisition of the LaBelle river dock facility in the fourth quarter of 2007. See Note 5.
The current portions of the asset retirement obligation liabilities of $4,649 and $2,940 at December 31, 2007 and 2006, respectively, are included in Accrued expenses and other current liabilities. See Note 10. The noncurrent portion of the Company’s asset retirement obligation liabilities of $149,414 and $122,076 at December 31, 2007 and 2006, respectively, are included in Other noncurrent liabilities. See Note 12. There were no assets that were legally restricted for purposes of settling asset retirement obligations at December 31, 2007 or 2006. At December 31, 2007, regulatory obligations for asset retirements are secured by surety bonds in the amount of $263,772. These surety bonds are partially collateralized by letters of credit issued by the Company.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Expected future cash payments to settle asset retirement obligations are as follows at December 31, 2007:
(1)
The difference between total expected payments of $247,262 and the liability of $154,063 recorded in the Consolidated Balance Sheets represents the application of an inflation rate and a discount rate. The discount rate used in the fourth quarter of 2007 was 5.98%.
Note 19. Income Taxes
Income taxes consisted of the following:
Income tax expense from continuing operations consisted of the following:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
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:
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 $48,540 and $42,292 at December 31, 2007 and December 31, 2006, respectively. During 2007, the valuation allowance increased by $6,248. The increase in the valuation allowance primarily relates to alternative minimum tax credits generated in 2007 which the Company does not believe that it will more-likely-than-not be able to utilize. Management believes that it is more-likely-than-not that the Company will be an AMT taxpayer indefinitely. In
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
addition, the Company has recorded a valuation allowance for the difference between the federal regular tax rate and alternative minimum tax rate attributable to the Company’s net deferred tax asset. Other changes include establishing a valuation allowance for certain state deferred tax assets, including net operating losses, based on current information.
Subsequently recognized tax benefits relating to the valuation allowance for deferred tax assets as of December 31, 2007 will be allocated as follows:
As disclosed in Note 2, the Company adopted the provisions of FIN 48 as of January 1, 2007. The cumulative effect of the adoption of FIN 48 was zero. At December 31, 2007, we had gross tax-affected unrecognized tax benefits of $10,108 of which $1,869, if recognized, would impact the effective tax rate.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
It is reasonably possible that a reduction of approximately $3,068 of unrecognized tax benefits, which is primarily related to interest deductions, may occur within twelve months as a result of the expiration of the statute of limitations with respect to these matters.
We conduct business throughout the United States and, as a result, the Company or one or more of our subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions, including Pennsylvania and West Virginia. The Company also has significant Wyoming operations where there is no state income tax. The Company’s U.S. federal, Pennsylvania and West Virginia statute of limitations has generally closed for tax years prior to 2004, 2002 and 2004, respectively, except to the extent where there were net operating losses carried forward and utilized in open tax years.
The Company recognizes interest and penalties accrued related to unrecognized tax benefits as a component of tax expense. During the years ended December 31, 2007, 2006 and 2005, we recorded interest related to unrecognized tax benefits of approximately $1,089, $251 and $0. Total accrued interest at December 31, 2007 and 2006 was approximately $1,340 and $251, respectively.
As of December 31, 2007, the Company has no federal net operating loss carryforwards and has $162,179 of state net operating loss carryforwards that primarily expire from 2016 to 2027.
State franchise tax expense for the twelve months ended December 31, 2007 and December 31, 2006 was $1,836 and $1,389, respectively. State franchise taxes are included in Cost of coal sales in the Consolidated Statements of Operations and Comprehensive Income.
Note 20. Stockholder Equity and Accumulated Other Comprehensive Income (Loss)
Stockholder Equity
The Company has 100 authorized shares of $0.01 par value common stock, all of which were outstanding at December 31, 2007 and 2006.
During the twelve months ended December 31, 2007, the Company paid cash dividends of $44,321 through FC 2 Corp. to the Public Parent for payment of ordinary dividends to common shareholders of the Public Parent and for the repurchase of common stock in accordance with a stock repurchase program authorized by the Board of Directors of the Public Parent.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
The Senior Secured Credit Facility currently limits cash available to pay ordinary cash dividends on the common stock of the Public Parent to $45,000 for any consecutive four-quarter period.
The Company’s Public Parent has an authorized a stock repurchase program (the “Repurchase Program”), authorizing the Public Parent to repurchase shares of its common stock. The Repurchase Program is funded by the Company to the Public Parent through intercompany dividends. The Public Parent may repurchase its common stock from time to time, as determined by authorized officers of the Public Parent, up to an aggregate amount of $100,000. During the twelve months ended December 31, 2007 and December 31, 2006, the Company expended $35,262 and $11,889 under the Repurchase Program, respectively. At December 31, 2007, $52,849 of funds remained under the Repurchase Program.
Accumulated Other Comprehensive Income (Loss)
Components of accumulated other comprehensive income (loss), net of tax, consisted of the following at:
Note 21. Segment Information
The Company produces primarily steam coal from surface and deep mines for sale to utility and industrial customers, which is distributed by rail, barge and/or truck. The Company operates only in the United States with operating mines in three of the major coal basins. The Company has four reportable business segments: Northern Appalachia, consisting of two underground mines in southwestern Pennsylvania, Central Appalachia, consisting of seven underground mines and two surface mines in southern West Virginia and the Powder River Basin, consisting of two surface mines in Wyoming. Other includes an idled 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 income (loss) from operations.
Operating segment results for the twelve months ended December 31, 2007 were as follows:
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Operating segment results for the twelve months ended December 31, 2006 were as follows:
Operating segment results for the twelve months ended December 31, 2005 were as follows:
Reconciliation of segment income from operations to consolidated income before income tax expense is as follows:
Note 22. Related Party Transactions
Prior to an in-kind distribution made by First Reserve on January 24, 2006 and the sale of common shares of the Public Parent completed by First Reserve and AMCI III on September 19, 2005, Alpha Coal Sales, LLC was related to the Company through indirect common ownership. First Reserve and AMCI III beneficially own a controlling interest in the parent entity of Alpha Coal Sales, LLC. Coal sales to this affiliate during 2005 totaled $27,870.
On September 14, 2005, First Reserve, AMCI IIII, the Company’s Public Parent and certain other shareholders of the Company’s Public Parent entered into an underwriting agreement with Morgan Stanley & Co. Incorporated as representative of several underwriters (the “Underwriters”) providing for the sale by First Reserve and AMCI III of 4,250,000 and 1,500,000 shares of common stock of the Public Parent, respectively, to the Underwriters. On September 19, 2005, First Reserve and AMCI III completed the sale of these shares of common stock of the Public Parent in a public offering. As a result, First Reserve and AMCI III’s ownership interests in the Company’s Public Parent were reduced to less than nine percent and three percent, respectively.
On October 26, 2005, Hans J. Mende, AMCI III’s president, resigned from the Board of the Company’s Public Parent. Mr. Mende was one of First Reserve’s designees to the Board of the Company’s Public Parent pursuant to the stockholders’ agreement among the Company’s Public Parent, affiliates of Blackstone, First Reserve, AMCI III and other identified parties.
On January 24, 2006, 4,154,045 shares of common stock of the Company’s Public Parent were distributed by First Reserve to First Reserve’s limited and other partners. The 4,154,045 shares that were distributed represented all of the remaining shares of the Company’s Public Parent owned by First Reserve.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Note 23. Lease Commitments
The Company leases office facilities, equipment and land under certain operating lease agreements that expire through 2017 and have various renewal options.
Minimum future rental commitments under noncancelable operating 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 Revenue
Other revenue consisted of the following:
Note 25. Closed Mining Locations
The Company owns five mining 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. Carrying values, which have been adjusted to fair value less costs to sell, include amounts for land and equipment of $1,425 and $2,108 as of December 31, 2007 and 2006, 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 Owned surface lands and Plant, equipment and mine development costs, net.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Note 26. Concentration of Credit Risk and Major Customers
The Company markets its coal principally to electric utilities in the United States. As of December 31, 2007 and 2006, trade accounts receivable from electric utilities totaled approximately $80,888 and $95,905, 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 relevant economic indices or the contract may include year-to-year specified price changes. Qualities and volumes for the coal are stipulated in coal supply agreements. For the twelve months ended December 31, 2007, the Company’s 10 largest customers accounted for approximately 53% of total coal sales with the largest customer being approximately 13%. The Northern Appalachia, Central Appalachia and Powder River Basin segments all reported revenue from the largest customer. For the twelve months ended December 31, 2006, the Company’s 10 largest customers accounted for approximately 49% of total coal sales with the largest customer being approximately 10%. For the twelve months ended December 31, 2005, the Company’s 10 largest customers accounted for approximately 53% of total coal sales with the largest customer being approximately 14%.
Note 27. Commitments and Contingencies
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 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 consolidated financial statements when it is at least reasonably possible that a loss will be incurred and the loss is material. Additionally, see Note 18 regarding Asset Retirement Obligations.
Guarantees
Neweagle Industries, Inc., Neweagle Coal Sales Corp., Laurel Creek Co., Inc. and Rockspring Development, Inc. (“Sellers”) are indirect wholly owned 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 Company 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 Company and Arch acknowledged the continuing validity and effect of said Agreement & Release.
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 related to the obligations of affiliated entities, which are not reflected in the accompanying Consolidated Balance Sheets. Management does not expect any material losses to result from these guarantees and other off-balance sheet instruments and, therefore, is of the opinion that their fair value is zero.
Contingencies
Extensive regulation of the impacts of mining on the environment and of maintaining workplace safety, and related litigation, has had or may have a significant effect on the Company’s costs of production and results of operations. Further regulations, legislation or litigation in these areas may also cause the Company’s sales or profitability to decline by increasing costs or by hindering the Company’s ability to continue mining at existing operations or to permit new operations.
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 consolidated financial position, consolidated results of operations or consolidated cash flows.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Letters of Credit
At December 31, 2007, the Company had $172,623 of letters of credit outstanding under its revolving credit facility.
Note 28. Unaudited Supplementary Data
The following is a summary of selected quarterly financial information (unaudited):
(1)
Includes $2,314 of employee termination costs associated with the idling of the Wabash mine. See Note 3.
(2)
Includes $9,731 of employee and contract termination costs associated with the idling of the Wabash mine. See Note 3.
(3)
Includes $2,252 of employee termination costs associated with the idling of the Wabash mine. See Note 3.
(1)
In the fourth quarter of 2006, $1,410 and $29,372 were written off related to deferred mining royalties at the Central Appalachia business unit and certain long-lived assets at the Wabash mine, respectively. See Note 4.
(2)
In the third quarter of 2006, deferred financing costs of $9,209 were written off as a result of the replacement of the original facility with the new facility. See Note 11.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Note 29. Supplemental Guarantor and Non-Guarantor Financial Information
On July 30, 2004, the Company’s indirect wholly owned subsidiary, Foundation PA Coal Company (the “Issuer” or “Non-Guarantor Subsidiary”), issued $300,000 aggregate principal amount of Notes that mature on August 1, 2014. In accordance with the indenture governing the Notes, the Guarantor Subsidiaries (“Guarantor Subsidiaries”) are each of the direct and indirect wholly owned subsidiaries of the Company, other than the Issuer. The Guarantor Subsidiaries have fully and unconditionally guaranteed the Notes, jointly and severally, on a senior unsecured basis. Separate consolidated financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to holders of the Notes.
Supplemental Condensed Consolidating Balance Sheet
December 31, 2007
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Supplemental Condensed Consolidating Balance Sheet
December 31, 2006
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Supplemental Condensed Consolidating Statement of Operations
For the Twelve Months Ended December 31, 2007
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Supplemental Condensed Consolidating Statement of Operations
For the Twelve Months Ended December 31, 2006
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Supplemental Condensed Consolidating Statement of Operations
For the Twelve Months Ended December 31, 2005
(1)
Represents tax expense of Issuer for the period January 1, 2005 through July 31, 2005. In August 2005, Foundation American Coal Holding and the Issuer were merged with newly created single member limited liability companies. As a result of the mergers, the entities were effectively liquidated into the Public Parent, pursuant to Internal Revenue Code Section 332 for both federal and state tax purposes. Subsequent to the mergers, the income/(loss) and related apportionment factors of these entities were combined with FCC and are included in the income tax expense of FCC.
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Supplemental Condensed Consolidating Statements of Cash Flows
Twelve Months Ended December 31, 2007
Twelve Months Ended December 31, 2006
Foundation Coal Corporation and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
(Dollars in thousands)
Supplemental Condensed Consolidating Statement of Cash Flows
Twelve Months Ended December 31, 2005
Note 30. Subsequent Events
On February 8, 2008, the Company acquired a 49% interest in Target Drilling, Inc., a privately-held contract drilling company headquartered in Jefferson Hills, Pennsylvania for $9,185.
On February 20, 2008, an affiliate of the Company successfully bid on a new Federal coal lease adjacent to the western boundary of the Eagle Butte mine located north of Gillette, Wyoming. This Federal coal lease, containing an estimated 255 million tons, is expected to be issued in the first quarter of 2008. The lease bonus bid was $180,500 to be paid in five equal annual installments of $36,100. The first payment of $36,100 was made in February 2008, with annual payments through 2012.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A(T).
ITEM 9A(T). 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 (the “Act”), as amended, is recorded, processed, evaluated, summarized and reported accurately within the time periods specified in the Securities and Exchange Commission’s 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.
As of the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(e) and 15d-15(e). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective and are designed to (a) ensure that information required to be disclosed by us in reports we file or submit under the Act are recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms; and (b) ensure that information required to be disclosed by us in reports filed or submitted under the Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There has been no change in the Company’s internal control over financial reporting during the most recent fiscal quarter that has materially affected, or that is reasonably likely to materially affect the Company’s internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
The Company’s internal control over financial reporting includes, those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control-Integrated Framework.”
Based on our assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2007.
This report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this report.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Omitted.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Omitted.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
Omitted.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Omitted.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
Fees of Independent Registered Accounting Firm
For work performed in regard to fiscal years 2007 and 2006, the Company paid Ernst & Young LLP the following fees for services, as categorized:
(1)
For fiscal year 2007, includes fees for audit services relating to the annual audit of the Company’s consolidated financial statements, the audit of the effectiveness of internal control over financial reporting of the Public Parent, audits of stand alone financial statements of certain subsidiaries, quarterly reviews, accounting consultations and certain information technology audit services. For fiscal year 2006, includes fees for audit services relating to the annual audit of the Company’s consolidated financial statements, the audit of management’s assessment of internal control over financial reporting of the Public Parent and the effectiveness of internal control over financial reporting of the Public Parent, audits of stand alone financial statements of certain subsidiaries, quarterly reviews, accounting consultations, registration statements and assistance with and review of documents filed with the United States Securities and Exchange Commission.
(2)
For fiscal years 2007 and 2006, includes fees for employee benefit plan audits.
(3)
There were no tax fees incurred.
(4)
There were no other fees incurred.
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 Corporation and Subsidiaries
Schedule II-Valuation and Qualifying Accounts
(Dollars in thousands)
(1)
Reserves utilized
(2)
Net change in reserve for obsolescence based on carrying value of the material and supplies inventory and the length of time the items are maintained in the inventory.
(3)
During 2007 and 2006, the Company recorded a valuation allowance of $6,248 and $7,624, respectively, that primarily relates to alternative minimum tax credits generated, which the Company does not believe that it will more-likely-than-not be able to utilize and for the difference between the federal regular tax rate and alternative minimum tax rate attributable to the Company’s net deferred tax asset. Other changes in the valuation allowance were the result of recognizing the gross value of certain state deferred tax assets, including net operating losses, that required a valuation allowance.
(4)
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 July 29, 2004 Acquisition date. During the twelve months ended December 31, 2005, the valuation allowance was further increased by $17,499, consisting of $6,469 specific to the 2005 provision and $11,030 resulting from the Company recording final purchase accounting adjustments in 2005 related to the July 30, 2004 Acquisition.
15(a)(3) Exhibits.
EXHIBIT INDEX
* Filed herewith
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: March 19, 2008
FOUNDATION COAL CORPORATION
(Registrant)
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, Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
/s/ JAMES L. ANDERSON, JR.
James L. Anderson, Jr.
Vice President, Corporate Controller and Director